10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended May 31, 2015

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

For the transition period from _____ to _______

Commission File Number: 001-35245

SYNERGY RESOURCES CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Colorado	20-2835920
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

20203 Highway 60, Platteville, Colorado  80651

(Address of Principal Executive Offices)  (Zip Code)

Registrant's telephone number including area code:  (970) 737-1073

N/A

Former name, former address, and former fiscal year, if changed since last report

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.                        

Yes ☒     No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   

Yes ☒     No ☐

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

Large accelerated filer    ☒	Accelerated filer    ☐
Non-accelerated filer    ☐	Smaller reporting company   ☐

Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐     No ☒

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 105,025,453 shares outstanding as of July 6, 2015.

SYNERGY RESOURCES CORPORATION

Index

		Page
Part I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Balance Sheets as of May 31, 2015 (unaudited) and August 31, 2014	2
	Statements of Operations for the three and nine months ended May 31, 2015 and May 31, 2014 (unaudited)	3
	Statements of Cash Flows for the nine months ended May 31, 2015 and May 31, 2014 (unaudited)	4
	Notes to Financial Statements (unaudited)	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	55
SIGNATURES		56

1

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

(in thousands, except share data)

ASSETS	May 31,2015		August 31,2014
	(unaudited)
Current assets:
Cash and cash equivalents	$	190,205	$	34,753
Accounts receivable:
Oil and gas sales		14,781		16,974
Joint interest billing and other		18,487		15,398
Commodity derivative		4,268		365
Other current assets		1,311		750
Total current assets		229,052		68,240
Oil and gas properties, full cost method:
Proved properties, net		407,576		275,018
Unproved properties and properties under development, not being amortized		170,639		95,278
Other property and equipment, net		4,811		9,104
Property and equipment, net		583,026		379,400
Commodity derivative		4,615		54
Other assets		2,767		848
Total assets	$	819,460	$	448,542
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	1,027	$	1,747
Well costs payable		26,491		71,849
Revenue payable		18,786		14,487
Production taxes payable		17,120		14,376
Other accrued expenses		457		817
Commodity derivative		-		302
Total current liabilities		63,881		103,578
Revolving credit facility		141,000		37,000
Commodity derivative		-		307
Deferred tax liability, net		34,670		21,437
Asset retirement obligations		7,772		4,730
Total liabilities		247,323		167,052
Commitments and contingencies (See Note 13)
Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding		-		-
Common stock - $0.001 par value, 200,000,000 shares authorized:
105,025,453 and 77,999,082 shares issued and outstanding, respectively		105		78
Additional paid-in capital		533,091		265,793
Retained earnings		38,941		15,619
Total shareholders' equity		572,137		281,490
Total liabilities and shareholders' equity	$	819,460	$	448,542

The accompanying notes are an integral part of these financial statements.

2

SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

 (unaudited; in thousands, except share and per share data)

	Three Months EndedMay 31,						Nine Months EndedMay 31,
	2015			2014			2015			2014
Oil and gas revenues	$	26,033		$	25,672		$	92,284		$	67,966
Expenses
Lease operating expenses		3,570			2,303			10,300			5,382
Production taxes		2,249			2,376			8,570			6,647
Depletion, depreciation
amortization and accretion		16,397			7,796			48,357			21,106
Full cost ceiling impairment		3,000			-			3,000			-
General and administrative		3,886			1,938			12,075			6,876
Total expenses		29,102			14,413			82,302			40,011
Operating income (loss)		(3,069	)		11,259			9,982			27,955
Other income (expense)
Commodity derivative realized gain (loss)		7,136			(826	)		20,935			(1,415	)
Commodity derivative unrealized (loss) gain		(8,298	)		(179	)		5,578			652
Interest expense		(116	)		-			(116	)		-
Interest income		33			22			61			70
Total other income (expense)		(1,245	)		(983	)		26,458			(693	)
Income (loss) before income taxes		(4,314	)		10,276			36,440			27,262
Income tax provision (benefit)		(1,833	)		3,116			13,118			8,841
Net income (loss)	$	(2,481	)	$	7,160		$	23,322		$	18,421
Net income (loss) per common share:
Basic	$	(0.02	)	$	0.09		$	0.26		$	0.24
Diluted	$	(0.02	)	$	0.09		$	0.25		$	0.24
Weighted-average shares outstanding:
Basic		104,234,519			77,176,420			91,105,035			75,689,903
Diluted		104,234,519			79,008,619			91,804,253			77,299,456

The accompanying notes are an integral part of these financial statements.

3

SYNERGY RESOURCES CORPORATION

 STATEMENTS OF CASH FLOWS

 (unaudited, in thousands)

	Nine Months EndedMay 31,
	2015			2014
Cash flows from operating activities:
Net income	$	23,322		$	18,421
Adjustments to reconcile net income to net
cash provided by operating activities:
Depletion, depreciation and amortization		48,357			21,106
Full cost ceiling impairment		3,000			-
Provision for deferred taxes		13,118			8,841
Stock-based compensation		3,330			1,569
Valuation increase in commodity derivatives		(5,578	)		(652	)
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales		2,193			(7,505	)
Joint interest billing and other		(3,089	)		(4,037	)
Unamortized premiums paid for derivatives		(3,494	)		-
Inventory		-			(211	)
Accounts payable
Trade		(720	)		188
Revenue		4,299			3,448
Production taxes		2,744			4,707
Accrued expenses		(360	)		49
Other		(180	)		821
Total adjustments		63,620			28,324
Net cash provided by operating activities		86,942			46,745
Cash flows from investing activities:
Acquisition of property and equipment		(241,903	)		(112,155	)
Short-term investments		-			60,018
Net proceeds from sales of oil and gas properties		3,696			704
Net cash used in investing activities		(238,207	)		(51,433	)
Cash flows from financing activities:
Cash proceeds from sale of stock		200,100			-
Stock offering costs		(9,255	)		-
Proceeds from exercise of warrants		15,367			33,380
Gross proceeds from revolving credit facility		104,000			-
Finance fee for revolving credit facility		(2,300	)		-
Shares withheld for payment of employee payroll taxes		(1,195	)		(176	)
Net cash provided by financing activities		306,717			33,204
Net increase in cash and cash equivalents		155,452			28,516
Cash and cash equivalents at beginning of period		34,753			19,463
Cash and cash equivalents at end of period	$	190,205		$	47,979
Supplemental Cash Flow Information (See Note 14)

The accompanying notes are an integral part of these financial statements.

4

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2015

(unaudited)

1. Organization and Summary of Significant Accounting Policies

Organization:    Synergy Resources Corporation ("the Company") is engaged in oil and gas acquisition, exploration, development and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado.  The Company's common stock is listed and traded on the NYSE MKT under the symbol "SYRG."

Basis of Presentation:    The Company has adopted August 31^st as the end of its fiscal year.  The Company does not utilize any special purpose entities.  The Company operates in one business segment and all of its operations are located in the United States of America.

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial information.

Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  The balance sheet as of August 31, 2014 was derived from the Company's Annual Report on Form 10-K for the year ended August 31, 2014.  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, 2014.

In management's opinion, the unaudited financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

Reclassifications:    Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation.  The reclassifications had no effect on net income, working capital or equity previously reported.

Use of Estimates:    The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves and goodwill, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain.  Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  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 these estimates.

Cash and Cash Equivalents:    The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

5

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, 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 properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs of oil and gas properties are depleted using the units-of-production method based upon estimates of proved reserves.  For depletion purposes, the volume of petroleum 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.

Properties under development represent the costs associated with the development of oil and gas properties that have yet to be proved as of May 31, 2015.  Since the properties were not classified as proved as of May 31, 2015, they were classified within unproved oil and gas properties and were withheld from the depletion calculation and ceiling test.  The costs for these properties will be transferred into proved properties when they are proved and will become subject to depletion and the ceiling test calculation in subsequent periods.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is an impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the book value of oil and gas properties.  The capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion, depreciation, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unproved properties not being amortized, plus the lower of cost or estimated fair value of unproven properties being amortized.  Prices are held constant for the productive life of each well.  Net cash flows are discounted at 10%.  If net capitalized costs exceed this limit, the excess is charged to expense.  The calculation of future net cash flows assumes continuation of current economic conditions.  Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials.

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.

6

The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of the Company's oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest:    The Company capitalizes interest on expenditures made in connection with acquisition of mineral interests and development projects that are not subject to current amortization.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 9 for additional information.

Capitalized Overhead:    A portion of the Company's overhead expenses are directly attributable to acquisition and development activities.  Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Capitalized Overhead	$	486	$	300	$	1,623	$	921

Well Costs Payable:    The costs of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings ("JIB").  For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the authorization for expenditure.

Other Property and 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.

Asset Retirement Obligations:    The Company's activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company's credit adjusted risk-free interest rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed or an asset is placed in service.  When the ARO is initially recorded, the Company capitalizes the cost (asset retirement cost or "ARC") by increasing the carrying value of the related asset.  ARCs related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the net capitalized cost decreases over the useful life of the asset, as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation for valuing the full cost pool.

7

Business Combinations:  The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations.  Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values.  The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable.  The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill.  Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

Oil and Gas Sales:    The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties.  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 pro-rata interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and lease operating costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued 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 thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser.  Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:   The Company sells production to a small number of customers, as is customary in the industry.  As a result, during the three and nine month periods ended May 31, 2015 and 2014, certain of the Company's customers represented 10% or more of its oil and gas revenue ("major customers").  For the three months ended May 31, 2015, the Company had three major customers, which represented 58%, 15% and 10% of its revenue during the period. For the three months ended May 31, 2014, the Company had four major customers, which represented 45%, 13%, 12% and 12% of its revenue during the period. For the nine months ended May 31, 2015, the Company had two major customers, which represented 62% and 11% of its revenue during the period. For the nine months ended May 31, 2014, the Company had three major customers, which represented 45%, 15% and 10% of its revenue during the period.

Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions so warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company's existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners whom are liable for their proportionate share of well costs.  The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:

Major Customers	As of May 31, 2015	As of August 31, 2014
Company A	29%	37%
Company B	12%	(1)

⁽¹⁾ Balance was less than 10% of total receivable balances during the period.

8

Lease Operating Expenses:    Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or 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.

Stock-Based Compensation:    The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date, calculated using the Black-Scholes-Merton option pricing model.  The expense is recognized over the vesting period of the grant.  See Note 11 for additional information.

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 significant uncertain tax positions were identified as of any date on or before May 31, 2015.  The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of May 31, 2015, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Financial Instruments:    The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.  A substantial portion of the Company's financial instruments consist of cash and cash equivalents, short-term investments, accounts receivable, trade accounts payable, accrued expenses, and obligations under the revolving line of credit facility, all of which are considered to be representative of their fair value due to the short-term and highly liquid nature of these instruments.

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

As discussed in Note 5, the Company incurred asset retirement obligations during the periods presented, 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.

Commodity Derivative Instruments:    The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or "no premium" collars to reduce the effect of price changes on a portion of its future oil and gas production.  The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures.  The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7.

9

Earnings Per Share Amounts:    Basic earnings per share includes no dilution and is computed by dividing net income or loss by the weighted-average number of shares outstanding during the period.  Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company.  The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method.  Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.

The following table sets forth the share calculation of diluted earnings per share:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Weighted-average shares outstanding-basic		104,234,519		77,176,420		91,105,035		75,689,903
Potentially dilutive common shares from:
Stock options	Anti-dilutive			515,530		699,218		432,170
Warrants		-		1,316,669		-		1,177,383
		-		1,832,199		699,218		1,609,553
Weighted-average shares outstanding - diluted		104,234,519		79,008,619		91,804,253		77,299,456

As a result of the net loss reported for the three months ended May 31, 2015, the calculation of basic and diluted Earnings per Share used the same number of weighted-average common shares outstanding in the denominator, as the inclusion of common share equivalents was anti-dilutive.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above; as such securities had an anti-dilutive effect on earnings per share:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Employee stock options		4,101,500		478,000		2,710,500		503,000

Recent Accounting Pronouncements:    We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03"), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. For public business entities, the ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years.  Entities should apply the new guidance on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.  Upon transition, entities are required to comply with the applicable disclosures for a change in an accounting principle.  The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

10

In January 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items" ("ASU 2015-01"), which eliminates from US GAAP the concept of extraordinary items, while retaining certain presentation and disclosure guidance for items that are unusual in nature or occur infrequently.  The standard is effective prospectively for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted provided the guidance is applied from the beginning of the fiscal year of adoption.  Adoption of ASU 2015-01 is not expected to have a material effect on the Company's financial position, results of operations, or cash flows.

In November 2014, the FASB issued Accounting Standards Update 2014-16, "Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity" ("ASU 2014-16"), which clarifies how to evaluate the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share.  Specifically, ASU 2014-16 requires that an entity consider all relevant terms and features in evaluating the nature of the host contract and clarifies that the nature of the host contract depends upon the economic characteristics and the risks of the entire hybrid financial instrument.  An entity should assess the substance of the relevant terms and features, including the relative strength of the debt-like or equity-like terms and features given the facts and circumstances, when considering how to weight those terms and features.  ASU 2014-16 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

In May 2014, the FASB issued Accounting Standards Update 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2016 including interim periods within that period. Early adoption is not permitted. The Company is currently evaluating which transition approach to use and the impact of the adoption of this standard on its consolidated financial statements.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's reported financial position, results of operations or cash flows.

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2. Property and Equipment and Full Cost Ceiling Impairment

The capitalized costs related to the Company's oil and gas producing activities were as follows (in thousands):

	As of			As of
	May 31, 2015			August 31, 2014
Oil and gas properties, full cost method:
Unproved properties, not subject to amortization:
Lease acquisition and other costs	$	139,012		$	41,531
Properties under development		31,627			53,747
Subtotal		170,639			95,278
Proved producing and non-producing properties		513,677			329,926
Total capitalized costs		684,316			425,204
Less, accumulated depletion		(103,101	)		(54,908	)
Less, full cost ceiling impairment		(3,000	)		-
Oil and gas properties, net		578,215			370,296
Land		4,478			3,898
Other property and equipment		867			5,961
Less, accumulated depreciation		(534	)		(755	)
Other property and equipment, net		4,811			9,104
Total property and equipment, net	$	583,026		$	379,400

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value.

For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs.  Under the ceiling test, the value of the Company's reserves are calculated using the average of the published spot prices for West Texas Intermediate (WTI) oil (per barrel) as of the first day of each of the previous twelve months, as well as the average of the published spot prices for Henry Hub (per MMBtu) as of the first day of each of the previous twelve months, each adjusted by lease or field for quality, transportation fees and regional price differentials.  The ceiling test used realized prices of $64.26 per barrel and $4.14 per MMBtu.  The prices used at May 31, 2015, were approximately 16% lower than the prices used at February 28, 2015.

Using these prices, the Company's net capitalized costs of oil and natural gas properties exceeded the ceiling amount by $3.0 million at May 31, 2015, resulting in immediate recognition of a ceiling test impairment.

The Company also reviews the fair value of its unproved properties.  The reviews for the three months and nine months ended May 31, 2015 and 2014 indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment in either period.

In addition, during the nine months ended May 31, 2015, certain amounts previously recorded were reclassified from one category to another without changing the total amounts recorded as property and equipment.  Specifically, costs associated with the disposal well and related equipment were reclassified from other property and equipment into producing oil and gas properties to more closely reflect use of the disposal well to process flow-back water from oil and gas operations.  Similarly, accumulated depreciation associated with the disposal well was reclassified from accumulated depreciation to accumulated depletion.  The updated classification for the disposal well, related equipment, and accumulated depreciation did not require a change to previously reported depletion, depreciation, and amortization expense ("DDA").  Secondly, as discussed in Note 3, the analysis of assets acquired in the 2014 business combination transactions with Apollo and Trilogy was completed and fair values associated with probable horizontal well development were reclassified from proved properties into unproved properties.

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3. Acquisitions

During the nine months ended May 31, 2015 and 2014, the Company acquired certain oil and gas and other assets, as described below.

Bayswater transaction

On December 15, 2014, the Company completed the acquisition of certain assets from three independent oil and gas companies (collectively known as "Bayswater") for a total purchase price of $125.1 million, net of customary closing adjustments.  The purchase price was composed of $74.2 million in cash and $48.4 million in restricted common stock plus the assumption of certain liabilities.

The Bayswater acquisition encompassed 5,040 gross (4,053 net) acres with rights to the Codell and Niobrara formations, and 2,400 gross (1,739 net) acres with rights to other formations including the Sussex, Shannon and J-Sand.  Additionally, the Company acquired non-operated working interests in 17 horizontal wells and 73 operated vertical wells as well as working interests in 11 non-operated vertical wells.  The working interests in the horizontal wells range from 6% to 40% while the working interests in the vertical wells range from 5% to 100%.

The following allocation of the purchase price is preliminary and includes significant use of estimates.  The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition.  Accordingly, the allocation will change as additional information becomes available and is assessed and the impact of such changes may be material.  The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	December 15, 2014
Consideration Given
Cash	$	74,221
Synergy Resources Corp. Common Stock (1)		48,434
Liabilities assumed, including asset retirement obligations		2,467
Total consideration given	$	125,122
Allocation of Purchase Price
Proved oil and gas properties (2)	$	51,400
Unproved oil and gas properties		73,722
Total fair value of oil and gas properties acquired	$	125,122

(1) The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 (4,648,136 shares at $10.42 per share).

(2) Proved oil and gas properties were measured primarily using an income approach.  The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement.  The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 10%, and assumptions on the timing and amount of future development and operating costs.

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The following table presents the pro forma combined results of operations for the three and nine months ended May 31, 2015 as if the Bayswater transaction had occurred on September 1, 2013, the first day of our 2014 fiscal year.  The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Three Months EndedMay 31,					Nine Months endedMay 31,
	2015			2014		2015		2014
Oil and Gas Revenues	$	26,033		$	26,766	$	99,157	$	71,550
Net income	$	(2,481	)	$	6,889	$	25,102	$	17,997
Earnings per common share
Basic	$	(0.02	)	$	0.08	$	0.26	$	0.22
Diluted	$	(0.02	)	$	0.08	$	0.26	$	0.22

Apollo and Trilogy transactions

During the year ended August 31, 2014, the Company closed on two transactions that qualified as Business Combinations under ASC 805.  The initial accounting treatment of the transactions was based upon the preliminary analysis of the assets acquired.  During the first fiscal quarter of 2015, the Company completed its analysis and finalized the allocation of purchase price to the assets acquired.  The following tables present the final fair values.

On September 16, 2013, the Company entered into a definitive purchase and sale agreement with Trilogy Resources, LLC ("Trilogy"), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the "Trilogy Assets"). On November 12, 2013, the Company closed the transaction for a combination of cash and stock.  Trilogy received 301,339 shares of the Company's common stock valued at $2.9 million and cash consideration of approximately $15.9 million.  No material transaction costs were incurred in connection with this acquisition.

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The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 12, 2013.  The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	November 12, 2013
Consideration Given
Cash	$	15,902
Synergy Resources Corp. Common Stock *		2,896
Total consideration given	$	18,798
Allocation of Purchase Price
Proved oil and gas properties	$	11,514
Unproved oil and gas properties	$	7,725
Total fair value of oil and gas properties acquired		19,239
Working capital	$	(83	)
Asset retirement obligation		(358	)
Fair value of net assets acquired	$	18,798
Working capital acquired was estimated as follows:
Accounts receivable		536
Accrued liabilities and expenses		(619	)
Total working capital	$	(83	)
*  The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)

On August 27, 2013, the Company entered into a definitive purchase and sale agreement ("the Agreement"), with Apollo Operating, LLC ("Apollo"), for its interests in 38 producing oil and gas wells, partial interest (25%) in one water disposal well (the "Disposal Well"), and approximately 3,639 gross (1,000 net) mineral acres ("the Apollo Operating Assets"). On November 13, 2013, the Company closed the transaction for a combination of cash and stock.  Apollo received cash consideration of approximately $11.0 million and 550,518 shares of the Company's common stock valued at $5.2 million.  Following the acquisition of the Apollo Operating Assets, the Company acquired all other remaining interests in the Disposal Well (the "Related Interests") through several transactions with the individual owners of such interests. The Company acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of the Company's common stock, valued at $0.2 million.  No material transaction costs were incurred in connection with this acquisition.

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The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 13, 2013. The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	November 13, 2013
Consideration Given
Cash	$	14,688
Synergy Resources Corp. Common Stock *		5,432
Total consideration given	$	20,120
Allocation of Purchase Price
Proved oil and gas properties	$	13,284
Unproved oil and gas properties	$	7,577
Total fair value of oil and gas properties acquired		20,861
Working capital	$	(507	)
Asset retirement obligation		(234	)
Fair value of net assets acquired	$	20,120
Working capital acquired was estimated as follows:
Accounts receivable		662
Accrued liabilities and expenses		(1,169	)
Total working capital	$	(507	)

* The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08).

The motivation for both the Trilogy and Apollo acquisitions was the expectation that each was accretive to cash flow and earnings per share.  The acquisitions qualify as a business combination, and as such, the Company estimated the fair value of each property as of the acquisition date (the date on which the Company obtained control of the properties). Fair value measurements utilize assumptions of market participants. To determine the fair value of the oil and gas assets, the Company used an income approach based on a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. The Company determined the appropriate discount rates used for the discounted cash flow analyses by using a weighted-average cost of capital from a market participant perspective plus property-specific risk premiums for the assets acquired. The Company estimated property-specific risk premiums taking into consideration the Gas to Oil Ratio ("GOR") of the related reserves, among other items.  Given the unobservable nature of the significant inputs, they are deemed to be Level 3 in the fair value hierarchy. The working capital assets acquired were determined to be at fair value due to their short-term nature.

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The preliminary analysis and allocation of the purchase price focused on the values inherent in the proved producing wells and the associated proved undeveloped reserves.  All of the producing wells acquired in the transactions were vertical wells and the initial estimates allocated 100% of the fair value to proved properties associated with vertical well development.  The final analysis also considered the additional value provided by the virtue of the ability to drill horizontal wells in the acquired acreage.  Adding horizontal wells to the development plan required a further evaluation as to the classification of the horizontal reserves, as reserves classified as proved under a vertical well drilling plan may be classified differently under a horizontal drilling plan.  In the subject acres, the horizontal well reserves are classified as unproved even though the vertical well reserves are proved.  Thus, the final analysis attributed $15.3 million of fair value to unproved horizontal properties and $24.8 million of fair value to proved properties.

Differences between the preliminary allocation and final allocation of acquired fair value have been treated as a change in accounting estimate, and no retroactive adjustments were made to the previously reported financial statements.  Furthermore, since the reclassification of $15.3 million from proved properties subject to amortization to unproved properties not subject to amortization represents approximately 2% of the full cost amortization base, no prior period adjustment was recorded during the current year.

4. Depletion, depreciation and amortization ("DDA")

Depletion, depreciation and amortization consisted of the following (in thousands):

	Three Months Ended May 31,				Nine Months ended May 31,
	2015		2014		2015		2014
Depletion	$	16,200	$	7,569	$	47,849	$	20,550
Depreciation and amortization		197		227		508		556
Total DDA Expense	$	16,397	$	7,796	$	48,357	$	21,106

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter.  For the three months ended May 31, 2015, production of 738,357 barrels of oil equivalent ("BOE") represented 1.7% of the estimated total proved reserves.  For the nine months ended May 31, 2015, production of 2,188,737 BOE represented 4.9% of the estimated total proved reserves.

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5. Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to their original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost.  For the purpose of determining the fair value of ARO incurred during the periods, the Company used the following assumptions:

	For The Nine Months Ended May 31,
	2015	2014
Inflation rate	3.9%	3.9 - 4.0%
Estimated asset life	25.0 - 39.0 years	20.0 - 40.0 years
Credit adjusted risk free interest rate	8.0%	8.0%

The following table summarizes the change in asset retirement obligations associated with the Company's oil and gas properties (in thousands):

Asset retirement obligations, August 31, 2014	$	4,730
Liabilities incurred		744
Liabilities assumed		1,913
Accretion expense		385
Asset retirement obligations, May 31, 2015	$	7,772

6. Revolving Credit Facility

On December 15, 2014, simultaneously with the completion of the acquisition of certain oil and gas assets from Bayswater Exploration and Development, LLC, et. al., the Company amended its revolving credit facility ("LOC").  Under the amendment, the maximum loan commitment was increased to $500 million from $300 million and the borrowing base was increased to $230 million from $110 million.  The number of banks participating in the LOC increased to eight with SunTrust Bank as the Joint Lead Arranger / Administrative Agent and KeyBank, National Association as the Joint Lead Arranger / Syndication Agent.  The maturity date of the facility was extended to December 15, 2019.

Concurrent with the amendment, the Company increased its borrowings to approximately $146 million.  Proceeds from the additional borrowings were used to fund the Bayswater acquisition.

On June 2, 2015, the LOC was further amended in connection with the regularly scheduled semi-annual redetermination.  The borrowing base was reduced to $175 million and the covenant requiring maintenance of a minimum current ratio was replaced with a covenant requiring the maintenance of a minimum liquidity amount of $25,000,000.  On June 11, 2015, the Company reduced its outstanding borrowings under the LOC to $87 million.

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Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5%.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate ("LIBOR") plus a margin.  The interest rate margin, as well as other bank fees, varies with utilization of the LOC.  The average annual interest rate for borrowings during the three months and nine months ended May 31, 2015 was 2.5%.

Certain of the Company's assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the arrangement.  The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves.  The borrowing base limitation is subject to scheduled redeterminations on a semi-annual basis.  In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared.  As of July 1, 2015, based upon a borrowing base of $175 million and an outstanding principal balance of $87 million, the unused borrowing base available for future borrowing totaled approximately $88 million.  The next semi-annual redetermination is scheduled for November 2015.

The arrangement contains covenants that, among other things, restrict the payment of dividends.  In addition, the LOC generally requires an overall hedge position that covers a rolling 24 months of estimated future production with a minimum position of no less than 45% and a maximum position of no more than 85% of hydrocarbon production as projected in the semi-annual reserve report.

Furthermore, the LOC requires the Company to maintain certain financial and liquidity ratio compliance covenants.  Under the requirements, as most recently amended, the Company, on a quarterly basis, must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; and (b) maintain a minimum liquidity, defined as cash and cash equivalents plus the unused availability under the total commitments, of not less than $25 million.  As of May 31, 2015, the most recent compliance date, the Company was in compliance with all loan covenants.

7. Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below.  The Company has utilized swaps, puts or "no premium" collars to reduce the effect of price changes on a portion of its future oil and gas production.  A swap requires a payment to the counterparty if the settlement price exceeds the strike price and the same counterparty is required to make a payment if the settlement price is less than the strike price.  A collar requires a payment to the counterparty if the settlement price is above the ceiling price and requires the counterparty to make a payment if the settlement price is below the floor price.  The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk.  While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements.  The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.  The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  The Company's derivative contracts are currently with four counterparties.  Two of the counterparties are a participating lender in the Company's credit facility.  The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination.  The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities.  Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments.  Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the statements of operations.  The Company's cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty.  Actual cash settlements can occur at either scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity.  These settlements under the commodity derivative contracts are reflected as operating activities in the Company's statements of cash flows.

The Company's valuation estimate takes into consideration the counterparty's creditworthiness, the Company's creditworthiness, and the time value of money.  The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view.  Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

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The Company's commodity derivative contracts as of May 31, 2015 are summarized below:

Settlement Period	Derivative Instrument	Average Volumes(BBls/MMBtu per month)		AverageFixed Price		Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Jun 1, 2015 - Jun 30, 2015	Collar		2,500		-	$	80.00	$	95.75
Jun 1, 2015 - Dec 31, 2015	Put		40,000		-	$	50.00		-
Jun 1, 2015 - Oct 31, 2015	Put		5,200		-	$	50.00		-
Jun 1, 2015 - Dec 31, 2015	Put		10,000		-	$	55.00		-
Jan 1, 2016 - May 31, 2016	Collar		10,000		-	$	75.00	$	96.00
Jan 1, 2016 - May 31, 2016	Collar		5,000		-	$	80.00	$	100.75
Jun 1, 2016 - Aug 31, 2016	Collar		15,000		-	$	80.00	$	100.05
Jan 1, 2016  - Aug 31, 2016	Swap		5,000	$	88.55		-		-
Sep 1, 2016 - Dec 31, 2016	Swap		20,000	$	88.10		-		-
Jan 1, 2016  - Oct 31, 2016	Swap		6,400	$	78.96		-		-
Jan 1, 2016 - Dec 31, 2016	Put		25,000		-	$	50.00		-
Jan 1, 2017 - Apr 30, 2017	Put		20,000		-	$	50.00		-
May 1, 2017 - Aug 31, 2017	Put		20,000		-	$	55.00		-
Natural Gas - NYMEX Henry Hub
Jun 1, 2015 - Dec 31, 2015	Collar		72,000		-	$	4.15	$	4.49
Jan 1, 2016 - May 31, 2016	Collar		60,000		-	$	4.05	$	4.54
Jun 1, 2016 - Aug 31, 2016	Collar		60,000		-	$	3.90	$	4.14
Natural Gas - CIG Rocky Mountain
Jun 1, 2015 - Dec 31, 2015	Collar		100,000		-	$	2.20	$	3.05
Jan 1, 2016 - Dec 31, 2016	Collar		100,000		-	$	2.65	$	3.10
Jan 1, 2017 - Apr 30, 2017	Collar		100,000		-	$	2.80	$	3.95
May 1 2017 - Aug 31, 2017	Collar		110,000		-	$	2.50	$	3.05

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Offsetting of Derivative Assets and Liabilities

As of May 31, 2015 and 2014, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions.  In general, the terms of the Company's agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency.  The Company's agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty.  The Company's accounting policy is to offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying balance sheets and the potential of master netting arrangements on the fair value of the Company's derivative contracts (in thousands):

		As of May 31, 2015
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	4,487	$	(219	)	$	4,268
Derivative contracts	Noncurrent assets	$	4,994	$	(379	)	$	4,615
Derivative contracts	Current liabilities	$	219	$	(219	)	$	-
Derivative contracts	Noncurrent liabilities	$	379	$	(379	)	$	-

		As of August 31, 2014
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	903	$	(538	)	$	365
Derivative contracts	Noncurrent assets	$	718	$	(664	)	$	54
Derivative contracts	Current liabilities	$	840	$	(538	)	$	302
Derivative contracts	Noncurrent liabilities	$	971	$	(664	)	$	307

The amount of gain (loss) recognized in the statements of operations related to derivative financial instruments was as follows (in thousands):

	Three Months EndedMay 31,						Nine Months endedMay 31,
	2015			2014			2015		2014
Realized gain (loss) on commodity derivatives	$	7,136		$	(826	)	$	20,935	$	(1,415	)
Unrealized gain (loss) on commodity derivatives		(8,298	)		(179	)		5,578		652
Total gain (loss)	$	(1,162	)	$	(1,005	)	$	26,513	$	(763	)

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Realized gains and losses include cash received from the monthly settlement of hedge contracts at their scheduled maturity date along with the proceeds from early liquidation of in-the-money hedge contracts.  During the third quarter of 2015, the Company liquidated oil hedges with an average price of $80.61 and covering 188,500 barrels and received cash settlements of approximately $5.0 million.  The following table summarizes hedge realized gains and losses during the periods presented (in thousands):

	Three Months EndedMay 31,					Nine Months endedMay 31,
	2015		2014			2015		2014
Monthly settlement	$	2,100	$	(826	)	$	9,618	$	(1,415	)
Early liquidation		5,036		-			11,317		-
Total realized gain (loss)	$	7,136	$	(826	)	$	20,935	$	(1,415	)

Credit-Related Contingent Features

During the nine months ended May 31, 2015, the Company added a fourth counterparty to its derivative transactions.  The additional counterparty is a member of the Company's credit facility syndicate and the Company's obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company's producing oil and gas properties.

8. Fair Value Measurements

ASC Topic 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

· Level 1: Quoted prices available in active markets for identical assets or liabilities;

· Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

· Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company's non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company's credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.  See Note 5 for additional information.

The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using primarily unobservable inputs.  Inputs are reviewed by management on an annual basis. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs. See Note 3 for additional information.

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The following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of May 31, 2015 and August 31, 2014 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at May 31, 2015
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	8,883	$	-	$	8,883
Commodity derivative liability	$	-	$	-	$	-	$	-

	Fair Value Measurements at August 31, 2014
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	419	$	-	$	419
Commodity derivative liability	$	-	$	609	$	-	$	609

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company's own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers the counterparty to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At May 31, 2015, derivative instruments utilized by the Company consist of puts, "no premium" collars and swaps. The crude oil and natural gas derivative markets are highly active. Although the Company's derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities.  The carrying amount of the Company's credit facility approximated fair value as it bears interest at variable rates over the term of the loan.

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9. Interest Expense

The components of interest expense are (in thousands):

	Three Months Ended May 31,						Nine Months Ended May 31,
	2015			2014			2015			2014
Revolving credit facility	$	915		$	252		$	2,191		$	749
Amortization of debt issuance costs		252			118			607			312
Less, interest capitalized		(1,051	)		(370	)		(2,682	)		(1,061	)
Interest expense, net	$	116		$	-		$	116		$	-

10. Shareholders' Equity

The Company's classes of stock are summarized as follows:

	As of May 31,		As of August 31,
	2015		2014
Preferred stock, shares authorized		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized		200,000,000		200,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding		105,025,453		77,999,082

Stock Offering

During the nine months ended May 31, 2015, the Company completed a public offering of 18,613,952 shares of its common stock at a price to the public of $10.75 per share.  On February 2, 2015, the Company received net proceeds of approximately $190.8 million after deducting underwriting discounts, commissions and other offering expenses.

Common stock issued for acquisition of mineral property interests

During the nine months ended May 31, 2015, the Company issued shares of common stock in exchange for mineral property interests.  The value of each transaction was determined using the market price of the Company's common stock on the date of each transaction.

	For the nine months ended May 31, 2015
Number of common shares issued for mineral property leases		995,672
Number of common shares issued for acquisitions		4,648,136
Total common shares issued		5,643,808
Average price per common share	$	10.45
Aggregate value of shares issued (in thousands)	$	58,968

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Common stock warrants

During the nine months ended May 31, 2015, holders exercised outstanding warrants to purchase 2,562,473 shares of common stock.  The Company received cash proceeds of $15.4 million.  The following table summarizes activity for common stock warrants for the nine month period ended May 31, 2015:

	Number of Warrants			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,562,473		$	6.00
Granted		-		$	-
Exercised		(2,562,473	)	$	6.00
Expired		-		$	-
Outstanding, May 31, 2015		-		$	-

11. Stock-Based Compensation

In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity-based compensation in the form of stock options, restricted stock grants, and warrants.  The Company records an expense related to equity compensation by pro-rating the estimated fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company's common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model.  For the periods presented, all stock-based compensation was classified as a component within general and administrative expense on the statement of operations.

The amount of stock-based compensation expense is as follows (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Stock options	$	715	$	445	$	1,792	$	1,312
Employee stock grants		686		257		1,538		257
	$	1,401	$	702	$	3,330	$	1,569

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During the three and nine months ended May 31, 2015 and 2014, the Company granted the following employee stock options:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Number of options to purchase common shares		1,892,500		90,000		2,302,500		353,000
Weighted-average exercise price	$	11.57	$	10.51	$	11.64	$	9.92
Term (in years)		10.0		10.0		10.0		10.0
Vesting Period (in years)		5		5		5		5
Fair Value (in thousands)	$	10,500	$	633	$	12,940	$	2,362

The assumptions used in valuing stock options granted during each of the nine months presented were as follows:

	Nine Months Ended May 31,
	2015			2014
Expected term	6.5 years			6.5 years
Expected volatility		47	%		73	%
Risk free rate		1.77	%		1.97% - 2.02	%
Expected dividend yield		0.00	%		0.00	%
Forfeiture rate		3.3	%		0.00	%

The following table summarizes activity for stock options for the nine months ended May 31, 2015:

	Number of Shares			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,167,000		$	5.94
Granted		2,302,500		$	11.64
Exercised		(258,000	)	$	3.81
Forfeited		(110,000	)	$	(4.97	)
Outstanding, May 31, 2015		4,101,500		$	9.30

The following table summarizes information about issued and outstanding stock options as of May 31, 2015:

	Outstanding Options		Vested Options
Number of shares		4,101,500		888,100
Weighted-average remaining contractual life	8.8 years		6.9 years
Weighted-average exercise price		$9.30		$5.34
Aggregate intrinsic value (in thousands)		$9,547		$5,480

The estimated unrecognized compensation cost from unvested stock options as of May 31, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at May 31, 2015
Unrecognized compensation expense (in thousands)	$15,038
Remaining vesting phase	4.3 years

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12. Related Party Transactions

Whenever the Company engages in transactions with its officers, directors, or other related parties, the terms of the transaction are reviewed by the disinterested directors.  All transactions must be on terms no less favorable to the Company than similar transactions with unrelated parties.

Lease Agreement:  The Company leases its headquarters, a field office, and an equipment storage yard under a twelve-month lease agreement with HS Land & Cattle, LLC ("HSLC").  HSLC is controlled by Ed Holloway and William Scaff, Jr., the Company's Co-Chief Executive Officers.  The current lease terminates on June 30, 2015.  Historically, the lease has been renewed annually.  Under this agreement, the Company incurred the following expenses to HSLC for the periods presented (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Rent expense	$	45	$	45	$	135	$	135

Revenue Distribution Processing:  Effective January 1, 2012, the Company commenced processing revenue distribution payments to all persons that own a mineral interest in wells that it operates.  Payments to mineral interest owners included payments to entities controlled by three of the Company's directors: Ed Holloway, William Scaff Jr, and George Seward.   The following table summarizes the royalty payments made to directors or their affiliates for the periods presented (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Total Royalty Payments	$	14	$	58	$	95	$	191

13. Other Commitments and Contingencies

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business.  It is the opinion of management that none of the current matters of contention are reasonably likely to have a material adverse impact on its business, financial position, results of operations or cash flows.

During the nine months ended May 31, 2015, the Company modified its contract drilling obligations with Ensign United States Drilling, Inc.  Two of the three rigs under contract fulfilled the terms of their contracts and were released, and one rig was contracted to continue drilling on a day-rate pricing basis.  The new contract has a term of less than one year.

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company owns a working interest (a "non-operated well").  The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs.  As of May 31, 2015, the Company was participating in the drilling and completion of 12 gross (0.7 net) new horizontal wells.  It is the Company's policy to accrue costs on a non-operated well when it receives notice that active drilling operations have commenced.  Accordingly, the May 31, 2015 financial statements include recorded costs of $3.6 million for these wells.

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14. Supplemental Schedule of Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the financial statements for the nine months ended May 31, 2015 and 2014 (in thousands):

	Nine Months Ended
	May 31,
	2015		2014
Supplemental cash flow information:
Interest paid	$	2,200	$	750
Income taxes paid		110		-
Non-cash investing and financing activities:
Accrued well costs	$	26,491	$	47,489
Assets acquired in exchange for common stock		58,968		11,185
Asset retirement costs and obligations		2,657		1,367

15. Subsequent Events

Subsequent to May 31, 2015, the Company repaid $54 million in outstanding borrowings, bringing the total outstanding principal balance on its LOC from $141 million at May 31, 2015 to $87 million at July 1, 2015.

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Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding our financial condition as of May 31, 2015, and the results of our operations for the three and nine months ended May 31, 2015 and 2014. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in our Form 10-K for the fiscal year ended August 31, 2014.

Overview

We are a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin ("D-J Basin") of Colorado.  The D-J Basin generally extends from the Denver metropolitan area throughout northeast Colorado into Wyoming, Nebraska, and Kansas.  It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand.  The area known as the Wattenberg Field covers the western flank of the D-J Basin, particularly in Weld County, Colorado, and is considered one of the premier oil and gas resource plays in the United States.  The area has produced oil and gas for over fifty years and benefits from a relatively low development cost structure.

Substantially all of our producing wells are either in or adjacent to the Wattenberg Field.  We operate over 90% of our proved reserves and 97% of our fiscal 2015 capital budget is focused on the Wattenberg Field.  This gives us both operational focus and development flexibility to maximize returns on our leasehold position.

As of May 31, 2015, we hold approximately 452,000 gross acres and 345,000 net acres under lease.   We currently hold approximately 89,000 net acres in the "Greater Wattenberg Area."  This position consists of approximately 35,000 net acres in the "core Wattenberg Area" and 54,000 net acres in what we call the "North East Extension Area."  In addition, we hold approximately 185,000 net acres in Southwest Nebraska, a conventional oil-prone prospect, and approximately 65,000 net acres in far eastern Colorado, an existing shallow dry-gas field.

Since commencing active operations in September 2008, we have undergone significant growth.  From inception through May 31, 2015, we have completed, acquired, or participated in 558 gross (385 net) successful oil and gas wells.  Our early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations but, in May 2013, we shifted our efforts to horizontal well development.  Horizontal wells, while taking longer to drill and complete and costing significantly more than vertical wells, have provided superior returns on our capital.

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The following table provides details about our ownership interests with respect to vertical and horizontal producing wells:

Vertical Wells
Operated Wells				Non- Operated Wells				Totals
Gross		Net		Gross		Net		Gross		Net
	344		301		74		22		418		323
Horizontal Wells
Operated Wells				Non- Operated Wells				Totals
Gross		Net		Gross		Net		Gross		Net
	52		50		88		12		140		62

In addition to the producing wells summarized in the preceding table, as of May 31, 2015, we were the operator of 28 wells in progress and we were participating as a non-operating working interest owner in 12 wells in progress.

During the first nine months of fiscal 2015, crude oil prices have declined by approximately 37%.  Price declines, especially of this magnitude, can impact many aspects of our operations.  For a more complete deliberation concerning the potential impacts from declining commodity prices, please see our discussions in "Drilling and Completion Operations," "Market Conditions," "Oil and Gas Commodity Contracts," and "Trends and Outlook."

Strategy
 

Our basic strategy encompasses the continuation of horizontal drilling within our Wattenberg leasehold as well as targeting asset acquisitions in well-defined, lower-risk areas that can provide significant cash flows and rapid returns on capital.  Drilling in lower-risk areas, maintaining high operating interests, and focusing on cost control enables us to achieve attractive well economics in most commodity price environments.  Our drilling efforts have been, and for the foreseeable future will continue to be, focused on the Wattenberg Field as its geologic and economic characteristics best fit our strategic goals.

We believe the most important aspect of our business that we can control is the cost associated with finding and developing our reserves, and that our cost-focused strategy is prudent irrespective of the prevailing commodity price environment.  Historically, we have been one of the most cost efficient producers in the Wattenberg Field, enabling us to provide attractive returns on capital.  Management's experience in the Wattenberg Field has shown that, in times of lower commodity prices, cost optimization and control is critical if the reserves are to be developed economically.  Our profitability, and ultimately the return on our assets and equity, is driven by how well we can manage costs relative to the prices we receive for our crude oil and natural gas.

In addition to our focus on cost optimization and low-risk development drilling, our strategy includes the use of commodity derivative contracts to mitigate a portion of  our exposure to potentially adverse market changes in commodity prices and the associated impact on our expected future cash flows.  We do not, however, utilize commodity derivative contracts for speculative purposes.  For more information, see "Oil and Gas Commodity Contracts."

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Historically, our cash flow from operations has not been sufficient to fund our rapid growth plans and we supplemented our capital resources with proceeds from the sale of equity and convertible securities.  We also arranged for a bank credit facility to fund additional capital needs.  During the three and nine month periods ended May 31, 2015, the primary sources of our capital resources were cash on hand at the beginning of the year, cash flow from operations, cash proceeds from the early liquidation of in-the-money commodity contracts, proceeds from our revolving credit facility, proceeds from the exercise of outstanding warrants and proceeds from our February equity issuance.  In the future, we plan to finance an increasing percentage of our growth with internally generated funds.  Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain.  For more information, see "Liquidity and Capital Resources."

Significant Developments

Impairment of full cost pool

Each quarter, we perform a ceiling test as prescribed by SEC regulations for entities following the full cost method of accounting.  This test determines a limit on the book value of oil and gas properties using a formula to estimate future net cash flows from oil and gas reserves.  This formula is dependent on several factors and assumes future oil and natural gas prices to be equal to an unweighted arithmetic average of oil and natural gas prices derived from each the 12 months prior to the reporting period.  As of May 31, 2015, this calculation indicated that the ceiling amount had declined, largely from the recent decline in oil and natural gas prices.  Since the ceiling amount was $3.0 million less than the net book value of oil and gas properties, we immediately recorded a ceiling test impairment.  This full cost ceiling impairment is recognized as a charge to earnings and may not be reversed in future periods, even if oil and natural gas prices subsequently increase.

Because the ceiling calculation requires rolling twelve month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 will be a lower ceiling amount each quarter.  This will result in ongoing impairments until prices stabilize or improve over a twelve month period.  At May 31, 2015, our ceiling test formula was calculated based upon SEC pricing of $64.26 per barrel and $4.14 per MMBtu.  Current pricing trends indicate that the formula for August 31, 2015, will be based upon SEC pricing that is approximately 15% less.  The decline in SEC pricing will likely result in a ceiling test impairment in the fourth quarter.

Acquisition of Mineral Assets from Bayswater on December 15, 2014

On December 15, 2014, the Company completed the acquisition of certain assets from three independent oil and gas companies (collectively known as "Bayswater").  Consideration paid to Bayswater, after customary closing and post-closing adjustments, consisted of approximately $74.2 million in cash and $48.4 million in stock plus the assumption of certain liabilities.

The Bayswater acquisition encompasses 5,040 gross (4,053 net) acres with rights to the Codell and Niobrara formations, and 2,400 gross (1,739 net) acres with rights to other formations including the Sussex, Shannon and J-Sand.  Additionally, we acquired working interests in 17 non-operated horizontal wells, 73 operated vertical wells, and 11 non-operated vertical wells.  

While we do not have any drilling commitments relative to the properties acquired from Bayswater, and importantly all leases are held by production, we are evaluating the economic return potential for future development efforts on this leasehold.  The leasehold and geology is conducive to mid- and extended-reach horizontal laterals, which are exhibiting shallower decline curves in the area, and we believe could generate higher overall returns on capital.  In addition, there are numerous offset Codell horizontal wells near our acreage with attractive production profiles.  We anticipate this acreage will provide a multi-year drilling inventory and, when fully developed, expect these assets to be accretive to cash flow and earnings per share.

For accounting purposes, the Bayswater acquisition was treated as a business combination and the assets acquired will be recorded at fair value.  We expect to complete our evaluation of fair value during our fourth fiscal quarter.  In these interim financial statements for May 31, 2015, we recorded our preliminary estimates.  Final amounts may vary from the preliminary estimates.

Fifth and Sixth Amendments to Revolving Credit Facility ("LOC") on December 15, 2014 and June 2, 2015, respectively

On December 15, 2014, we closed on the Fifth Amendment to Amended and Restated Credit Agreement ("Fifth Amendment").  The terms of the Fifth Amendment included an expansion of the bank syndicate to eight members,  an increase in the loan commitment from $300 million to $500 million, and an increase in our borrowing base from $110 million to $230 million.  On June 2, 2015, we closed on the Sixth Amendment in connection with the regular semi-annual redetermination.  The Sixth Amendment provides for a borrowing base of $175 million.  The facility continues to bear a minimum interest rate on borrowings of 2.5%, with the effective rate varying with utilization, and expires on December 15, 2019.

Amounts borrowed from the banks will be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. 

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Completion of Public Stock Offering on February 2, 2015

During our second fiscal quarter, we completed a public offering of 18,613,952 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to the public of $10.75 per share.  On February 2, 2015, we received net proceeds of approximately $190.8 million after deducting underwriting discounts, commissions and other offering expenses.  We intend to use the net proceeds to fund additional asset acquisitions in the Wattenberg Field, to pay down outstanding indebtedness under our revolving credit facility and for general corporate purposes, including working capital.  For more information, see "Liquidity and Capital Resources."

Increased Working Interest in Greenhorn AMI on February 12, 2015 and May 22, 2015

On February 12, 2015, we agreed with Vecta Oil & Gas, Ltd. ("Vecta") to amend our Joint Exploration Agreement dated March 1, 2013.  Under the amendment, Vecta conveyed to us assignments for an undivided 30% working interest in the DJ Basin Greenhorn Area of Mutual Interest (AMI) covering approximately 13,530 net acres.  In consideration, we agreed to pay Vecta the equivalent of $250 per net mineral acre.  Total consideration of $3.4 million was paid in the form of 287,642 restricted shares of our common stock based on a per share price of $11.76.  On May 22, 2015, we agreed to purchase the 35% working interest in the DJ Basin Greenhorn AMI owned by Vecta's affiliate, Foreland Investments LP (Foreland).  The consideration for 15,789 net acres conveyed by Foreland was $250 per net mineral acre.  Total consideration of $3.95 million was paid in the form of 323,745 restricted shares of our common stock based on a per share price of $12.19.  Successfully closing both transactions provided us with a 100% working interest in the DJ Basin Greenhorn AMI of approximately 56,000 net acres in the NE Wattenberg Extension Area.

Early Liquidation of In-The-Money Commodity Contracts

During the three and nine months ended May 31, 2015, we liquidated a portion of our deep in-the-money commodity contracts and purchased crude oil put contracts with $50/bbl and $55/bbl strike prices.  These transactions allowed us to monetize what would have otherwise been unrealized gains, thereby increasing cash flow, while at the same time maintaining a hedge on a greater portion of our expected future production.  In addition to working with our existing counterparties, we purchased a portion of the put contracts on the Chicago Mercantile Exchange, which we believe will enhance the liquidity of our overall position.

Drilling and Completion Operations

Our drilling and completion schedule has a material impact on our production forecast and a corresponding impact on our expected future cash flows.

As commodity prices have fallen over the preceding three fiscal quarters, we have been able to reduce drilling and completion costs by approximately 25%. We think we can achieve even lower costs in the future, but believe at current drilling and completion cost levels and with current prevailing commodity prices, we can achieve reasonable well-level rates of return going forward.   As of May 31, 2015, we have no plans to curtail any activities.  However, should commodity prices weaken, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent.    If management believes the well-level internal rate of return will be at or below our weighted-average cost of capital, we can choose to delay completions and/or forego drilling altogether.

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Drilling Activity

During our fiscal third quarter ended May 31, 2015, we completed drilling operations on our Cannon pad and began drilling our Conrad well, our first horizontal well targeting the Greenhorn formation in our North East Extension Area.  After successfully completing the drilling of the Conrad well in June, ahead of schedule and on budget, we moved our contracted rig to the Bestway pad.  This pad is expected to consist of four mid-length (7,000 foot) lateral wells including one targeting the Codell formation, one targeting the Niobrara C formation, one targeting the Niobrara B formation, and one targeting the Niobrara A formation.  Drilling operations on the Bestway pad are expected to conclude in August and we anticipate moving our contracted rig to the southern portion of the Wattenberg Field to begin our fiscal 2016 drilling program in September.

Completion Activity

During the three months ended May 31, 2015, we began completion operations on our 13-well Kiehn/Weis pad and all the wells were brought online. The 13 wells consist of six Niobrara C, one Niobrara A, and six Codell wells. Eight of the wells are oriented south-to-north on the Kiehn portion of the pad, while the five wells on the Weis portion of the pad are oriented east-to-west. All the wells are exhibiting low gas-to-oil ratio characteristics.  We estimate the average Drill and Completion (D&C) cost of the thirteen wells will be approximately $3.5 million per well.

Completion activities on our eight-well Gies pad began in late fiscal 3^rd quarter.  All eight wells are utilizing sliding sleeve completion designs with four using Halliburton's "Access (Biovert) Frac" fluids and the others using hybrid gel and slickwater fluids.  The Gies wells commenced production subsequent to May 31, 2015.

Completion activities on the 11-well Cannon pad began in June with first production expected in late July.  This pad consists of six Codell and five Niobrara C wells, and is oriented east-to-west.  Total D&C costs are expected to be between $2.9 million to $3.3 million per well.

Completion activities on our Wiedeman pad, which includes four Extended Reach Lateral (ERL) wells, have been delayed by a legal dispute over ownership issues and by remediation of an existing offset vertical well within the spacing unit owned by a third party.

For the Conrad well targeting the Greenhorn formation, our engineers are finalizing the completion design and completion activities are scheduled to occur during the fourth quarter.

Other Operations

We continue to be opportunistic as it relates to acquisition and divestiture efforts.  We continue to enter into land and working interest swaps to increase our overall leasehold control.  For example, in December 2014, while maintaining operational control of 40 vertical wells, we divested approximately 600 net acres for approximately $3.7 million.  This divestiture allowed us to not only increase cash on hand, but also avoid participating in the drilling of several wells we deemed non-economic given the expected costs relative to the then-current commodity prices.  Likewise, during the three months ended May 31, 2015, we consummated several asset and acreage swaps, resulting in a higher working interest in several of our operated pads as well as a higher working interest in yet-to-be-developed leaseholds.  While these transactions lowered our expected non-operated production volumes in the quarter, they also resulted in an estimated $14 million reduction in our non-operated capital expenditures.  We anticipate the net result will be a higher ultimate return on our capital employed.

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In western Nebraska, we have entered into a joint exploration agreement with a Denver-based private operating company to drill up to ten wells in an AMI covering approximately 8,000 acres. 

In Yuma and Washington Counties, Colorado, we maintain leases covering over 63,000 acres in an area that has historically produced dry gas from the Niobrara formation.  We continue to evaluate the economics of this play to determine when or if it might be economic to develop further.

Production

Our production increased from 7,745 barrels of oil equivalent ("BOE") per day for the fiscal quarter ending February 28, 2015 to 8,026 BOE per day for the fiscal quarter ending May 31, 2015.    The additional production volumes from recently completed wells more than offset the natural decline of our existing wells and the loss of non-operated production due to asset swaps. The increase was achieved despite continuing mid-stream constraints, high line pressures in the northern portion of the Wattenberg Field, and the loss of production from shut-in wells due to offset operator completion activities.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow.  The market prices for crude oil and natural gas are inherently volatile.  To provide historical perspective, the following table presents the average annual New York Mercantile Exchange ("NYMEX") prices for oil and natural gas for each of the last five fiscal years.

	Years Ended August 31,
	2014		2013		2012		2011		2010
Average NYMEX prices
Oil (per bbl)	$	100.39	$	94.58	$	94.88	$	91.79	$	76.65
Natural gas (per mcf)	$	4.38	$	3.55	$	2.82	$	4.12	$	4.45

For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices weighted to reflect monthly sales volumes) as well as the differential between the Reference Price and the wellhead prices realized by us.

	Three Months Ended						Nine Months Ended
	May 31,						May 31,
Oil (NYMEX WTI)	2015			2014			2015			2014
Reference Price	$	55.23		$	101.44		$	64.97		$	99.79
Realized Price	$	45.77		$	90.91		$	54.88		$	90.13
Differential	$	(9.46	)	$	(10.53	)	$	(10.09	)	$	(9.66	)
Gas (NYMEX Henry Hub)
Reference Price	$	2.90		$	4.71		$	3.32		$	4.45
Realized Price	$	3.16		$	5.15		$	3.76		$	5.34
Differential	$	0.26		$	0.44		$	0.44		$	0.89

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX.  The negative differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments.  We continue to negotiate with crude oil purchasers to obtain better differentials.  With regard to the sale of natural gas and liquids, we are able to sell production at prices greater than the prices posted for dry gas, primarily because prices we receive include payment for the natural gas liquids produced with the gas.

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There has been a significant decline in the price of oil since the summer of 2014.  As reflected in published data, the price for West Texas Intermediate (WTI) oil settled at $95.96/bbl on Friday, August 29, 2014, the last trading day of our 2014 fiscal year.  The price of WTI then declined 48% during the first six months of our fiscal year, settling at $49.76/bbl on Friday, February 27, 2015.  The price of oil settled at $60.30/bbl on Friday, May 29, 2015, signaling a modest price recovery during our third fiscal quarter.  The third quarter price remains approximately 37% below the benchmark price at the start of our 2015 fiscal year.  Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production.

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and the calculation of the "ceiling test" required under the accounting principles for companies following the "full cost" method of accounting.  We review our oil and gas properties for impairment at each quarterly reporting period.  For the third quarter, the ceiling test resulted in an impairment of $3.0 million, and future impairments may occur.

RESULTS OF OPERATIONS

For the three months ended May 31, 2015, compared to the three months ended May 31, 2014

For the three months ended May 31, 2015, we reported a net loss of $2.5 million compared to net income of $7.2 million during the three months ended May 31, 2014, driven in part by a $3.0 million full cost ceiling impairment, as discussed previously under the heading "Significant Developments."  Loss per basic and diluted share was $0.02 for the three months ended May 31, 2015 compared to net income of $0.09 per basic and diluted share for the three months ended May 31, 2014.  Other significant differences between the two periods include the rapid growth in reserves, producing wells and daily production totals, as well as the impact of changing prices on our revenues and our commodity hedge positions.  The following discussion expands upon significant items of inflow and outflow that affected results of operations.

Oil and Gas Production and Revenues – For the three months ended May 31, 2015 we recorded total oil and gas revenues of $26.0 million compared to $25.7 million for the three months ended May 31, 2014, an increase of $0.3 million or 1.4%.

Year over year, we added 36 net horizontal wells, including 3 (net) Bayswater horizontal wells, increasing our reserves, producing wells and daily production totals.  Although the three months ended May 31, 2015 yielded almost twice as much BOE production compared to the three months ended May 31, 2014, our revenues during the 2015 quarter increased only modestly as a result of declining oil prices.

Net oil and gas production for the three months ended May 31, 2015 averaged 8,026 BOE per day. For the three months ended May 31, 2014, production averaged 4,120 BOE per day, a year-over-year increase of 95%.  As a further comparison, average BOE production was 7,745 per day during the quarter ended February 28, 2015, a quarter-over-quarter increase of 4%.  When the price of oil declined in 2014, we temporarily postponed the final completion of certain wells under development.  The majority of the temporarily delayed wells has either commenced production or is expected to commence production during the third and fourth quarters.    

Our revenues are sensitive to changes in commodity prices.  As shown in the following table, there has been a decrease of nearly 48% in average realized prices between the periods presented.  This decline in average sales prices mostly offset the effects of increased production.

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The following table presents actual realized prices, without the effect of hedge transactions.  The impact of hedge transactions is presented later in this discussion.

Key production information is summarized in the following table:

	Three Months Ended May 31,
	2015		2014		Change
Production:
Oil (Bbls1)		448,906		232,571		93	%
Gas (Mcf2)		1,736,702		879,062		98	%
Total production in BOE3		738,357		379,081		95	%
Revenues (in thousands):
Oil	$	20,546	$	21,143		-3	%
Gas		5,487		4,529		21	%
	$	26,033	$	25,672		1	%
Average sales price:
Oil	$	45.77	$	90.91		-50	%
Gas	$	3.16	$	5.15		-39	%
BOE	$	35.26	$	67.72		-48	%

¹ "Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.

² "Mcf" refers to one thousand cubic feet of natural gas.

³ "BOE" refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

Lease Operating Expenses ("LOE") – Direct operating costs of producing oil and natural gas are reported as follows (in thousands):

	Three Months Ended
	May 31,
	2015		2014
Production Costs	$	3,533	$	2,252
Workover		37		51
Total LOE	$	3,570	$	2,303
Per BOE:
Production costs	$	4.79	$	5.94
Workover		0.05		0.13
Total LOE	$	4.84	$	6.07

Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.  During the third quarter of fiscal 2015, we continued to experience elevated production cost per BOE in connection with additional costs to operate horizontal wells.  Production from certain wells was intermittently restricted during the quarter as midstream infrastructure providers struggled to increase the efficiency and capacity of the gas gathering system.  We continue to work diligently to mitigate production difficulties within the Wattenberg Field.

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Production taxes – During the three months ended May 31, 2015, production taxes were $2.2 million, or $3.04 per BOE, compared to $2.4 million, or $6.27 per BOE, during the three months ended May 31, 2014.  Taxes tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes were 8.6% and 9.3% for the three months ended May 31, 2015 and 2014, respectively.

Depletion, Depreciation, and Amortization ("DDA") – The following table summarizes the components of DDA:

	Three Months Ended
	May 31,
(in thousands)	2015		2014
Depletion	$	16,200	$	7,569
Depreciation and amortization		197		227
Total DDA	$	16,397	$	7,796
DDA expense per BOE	$	22.21	$	20.57

For the three months ended May 31, 2015, depletion of oil and gas properties was $22.21 per BOE compared to $20.57 per BOE for the three months ended May 31, 2014.  The increase in the DDA rate was the result of an increase in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves.  Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate.  For both 2015 and 2014, production represented 1.7% of the reserve base.  Since DDA expense represents amortization of historical costs, our recently implemented reductions in well costs are not fully reflected in the rate.

Full cost ceiling impairment – During the three months ended May 31, 2015, we recognized an impairment of $3.0 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.  See "Oil and Gas Properties, including Ceiling Test," included in the discussion of Critical Accounting Policies below.

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General and Administrative ("G&A") –The following table summarizes G&A expenses incurred and capitalized during the periods presented:

	Three Months Ended
	May 31,
(in thousands)	2015			2014
G&A costs incurred	$	4,372		$	2,238
Capitalized costs		(486	)		(300	)
Total G&A	$	3,886		$	1,938
G&A Expense per BOE	$	5.26		$	5.11

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others.  In an effort to minimize overhead costs, we employ a total staff of 36 employees and use consultants, advisors, and contractors to perform certain tasks when it is cost effective.

Although G&A costs have increased as we grow the business, we strive to maintain an efficient overhead structure.  For the quarter ended May 31, 2015, G&A was $5.26 per BOE compared to $5.11 per BOE for the quarter ended May 31, 2014.

Our G&A expense for the quarter ended May 31, 2015 includes stock-based compensation of $1.4 million compared to $0.7 million for the quarter ended May 31, 2014.  Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes.  It is a non-cash charge, which, for stock options, is calculated using the Black-Scholes-Merton option pricing model to estimate the fair value of options.  Amounts are pro-rated over the vesting terms of the option agreements, which are generally three to five years.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties.  Those costs are reclassified from G&A expenses and capitalized into the full cost pool.  The increase in capitalized costs from 2014 to 2015 reflects our increasing activities to acquire leases and develop the properties.

Commodity derivative gains (losses) – As more fully described in the paragraphs titled "Oil and Gas Commodity Contracts" and "Hedge Activity Accounting," located in "Liquidity and Capital Resources," we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas.  For the quarter ended May 31, 2015, we realized a cash settlement gain of $7.1 million, including gains of $2.1 million from the settlement of contracts at their scheduled maturity dates and gains of $5.0 million from the early liquidation of "in-the-money" contracts.  For the prior year quarter ended May 31, 2014, we realized a cash settlement loss of $826,000.

In addition, for the quarter ended May 31, 2015, we recorded an unrealized loss of $8.3 million to recognize the mark-to-market change in fair value of our commodity contracts for the quarter ended May 31, 2015.  In comparison, in the quarter ended May 31, 2014, we reported an unrealized loss of $179,000.  Unrealized gains and losses are non-cash items.

Income taxes – We reported income tax benefit of $1.8 million for the three months ended May 31, 2015, calculated at an effective tax rate of 42%.  During the comparable prior year period, we reported income tax expense of $3.0 million, calculated at an effective tax rate of 30%.  For both periods, we anticipate that the tax liability will be substantially deferred into future years. During both fiscal years the effective tax rate differed from the federal and state statutory rate primarily by the impact of deductions for percentage depletion.

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For the nine months ended May 31, 2015, compared to the nine months ended May 31, 2014

For the nine months ended May 31, 2015, we reported net income of $23.3 million compared to net income of $18.4 million during the nine months ended May 31, 2014.  Net income per basic and diluted share were $0.26 and $0.25, respectively, for the nine months ended May 31, 2015 compared to earnings per share of $0.24 per basic and diluted share for the nine months ended May 31, 2014.    Revenues increased $24.3 million during the nine months ended May 31, 2015 compared to the comparable period ended May 31, 2014 due to rapid growth in reserves, producing wells and daily production totals, as discussed previously.  As of May 31, 2015, we had 558 gross producing wells, compared to 388 gross producing wells as of May 31, 2014.  However, although our production more than doubled during the comparable periods, our revenues during the 2015 period increased only 35.8% as a result of declining oil and gas prices. The impact of changing prices on our commodity hedge positions also drove significant differences in our results of operations between the two periods.

The following discussion expands upon significant items of inflow and outflow that affected results of operations.

Oil and Gas Production and Revenues – For the nine months ended May 31, 2015, we recorded total oil and gas revenues of $92.3 million compared to $68.0 million for the nine months ended May 31, 2014, an increase of $24.3 million or 35.8%.

During the nine months ended May 31, 2015, our BOE production was 114% higher than during the same period in 2014, largely as a result of increases in the number of gross producing wells.  However, our revenues are sensitive to changes in commodity prices.  As shown in the following table, there has been a decrease of approximately 37% in average realized BOE prices between the periods presented.  These price declines have had a direct impact on the amount of revenue we have been able to achieve, despite our production growth.

The following table presents actual realized prices, without the effect of hedge transactions.  The impact of hedge transactions is presented later in this discussion.

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Key production information is summarized in the following table:

	Nine Months Ended May 31,
	2015		2014		Change
Production:
Oil (Bbls1)		1,328,031		605,471		119	%
Gas (Mcf2)		5,164,238		2,508,311		106	%
Total production in BOE3		2,188,737		1,023,523		114	%
Revenues (in thousands):
Oil	$	72,880	$	54,569		34	%
Gas		19,404		13,397		45	%
	$	92,284	$	67,966		36	%
Average sales price:
Oil	$	54.88	$	90.13		-39	%
Gas	$	3.76	$	5.34		-30	%
BOE	$	42.16	$	66.40		-37	%

¹ "Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.

² "Mcf" refers to one thousand cubic feet of natural gas.

³ "BOE" refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

Lease Operating Expenses ("LOE") – Direct operating costs of producing oil and natural gas are reported as follows (in thousands):

	Nine Months Ended
	May 31,
	2015		2014
Production Costs	$	10,227	$	5,252
Workover		73		130
Total LOE	$	10,300	$	5,382
Per BOE:
Production costs	$	4.68	$	5.13
Workover		0.03		0.14
Total LOE	$	4.71	$	5.27

Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.

During the first nine months of fiscal 2015, we continued to experience elevated production cost per BOE in connection with additional costs to operate horizontal wells.  Production from certain wells was intermittently restricted during the period as midstream infrastructure providers struggled to increase the efficiency and capacity of the gas gathering system.  We continue to work diligently to mitigate production difficulties within the Wattenberg Field.

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Production taxes – During the nine months ended May 31, 2015, production taxes were $8.6 million, or $3.92 per BOE, compared to $6.6 million, or $6.49 per BOE, during the nine months ended May 31, 2014.  Taxes tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes were approximately 9.3% and 9.8% for the nine months ended May 31, 2015 and 2014, respectively.

Depletion, Depreciation, and Amortization ("DDA") – The following table summarizes the components of DDA:

	Nine Months Ended
	May 31,
(in thousands)	2015		2014
Depletion	$	47,849	$	20,550
Depreciation and amortization		508		556
Total DDA	$	48,357	$	21,106
DDA expense per BOE	$	22.09	$	20.62

For the nine months ended May 31, 2015, depletion of oil and gas properties was $22.09 per BOE compared to $20.62 for the nine months ended May 31, 2014.  The increase in the DDA rate was the result of an increase in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves.  Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate.  For the nine months ended May 31, 2015, production represented 4.9% of the reserve base compared to 4.5% for the nine months ended May 31, 2014.  Since DDA expense represents the amortization of historical costs, our recently implemented reductions in well costs are not fully reflected in the rate.

Full cost ceiling impairment – During the nine months ended May 31, 2015, we recognized an impairment of $3.0 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.  See "Oil and Gas Properties, including Ceiling Test," included in the discussion of Critical Accounting Policies below.

General and Administrative ("G&A") –The following table summarizes G&A expenses incurred and capitalized during the periods presented:

	Nine Months Ended
	May 31,
(in thousands)	2015			2014
G&A costs incurred	$	13,698		$	7,797
Capitalized costs		(1,623	)		(921	)
Total G&A	$	12,075		$	6,876
G&A expense per BOE	$	5.52		$	6.72

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Our G&A expense for the nine months ended May 31, 2015 includes stock-based compensation of $3.3 million compared to $1.6 million for the nine months ended May 31, 2014.  As discussed previously, stock-based compensation is a non-cash charge related to options we grant for compensatory purposes and is based on a calculated value using the Black-Scholes-Merton option pricing model. See also Note 11 to our financial statements.

As discussed previously, pursuant to the full cost accounting method for oil and gas properties, we capitalize into the full cost pool all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties.  The increase in capitalized costs between the 2014 and 2015 periods reflects our increasing activities to acquire leases and develop the properties.

Commodity derivative gains (losses) – As more fully described in the paragraphs titled "Oil and Gas Commodity Contracts" and "Hedge Activity Accounting" located in "Liquidity and Capital Resources," we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas.  For the nine months ended May 31, 2015, we realized a cash settlement gain of $20.9 million, including gains of $11.3 million from the settlement of contracts at their scheduled maturity dates and gains of $9.6 million from the early liquidation of "in-the-money" contracts.   In comparison, in the nine months ended May 31, 2014, we realized a cash settlement loss of $1.4 million.

In addition, for the nine months ended May 31, 2015, we recorded an unrealized gain of $5.6 million to recognize the mark-to-market change in fair value of our commodity contracts for the period.   In comparison, in the nine months ended May 31, 2014, we reported an unrealized gain of $0.7 million.  Unrealized gains and losses are non-cash items.

Income taxes – We reported income tax expense of $13.1 million for the nine months ended May 31, 2015, calculated at an effective tax rate of 36%.  During the comparable prior year period, we reported income tax expense of $8.8 million, calculated at an effective tax rate of 32%.  For both periods, it appears that the tax liability will be substantially deferred into future years. During both fiscal years the effective tax rate differed from the federal and state statutory rate primarily by the impact of deductions for percentage depletion.

For tax purposes, we have a net operating loss ("NOL") carryover of $42.7 million, which is available to offset future taxable income.  The NOL will begin to expire, if not used, in 2031.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  During 2015 and 2014, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carry-forward, and have therefore included it in our inventory of deferred tax assets.

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LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of capital have been net cash provided by the sale of equity and debt securities, cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities.  Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties.  Our future success in growing proved reserves and production will be highly dependent on capital resources available to us.

We believe our capital resources, including cash on hand, amounts available under our revolving credit facility, and cash flow from operating activities, will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months.  To the extent actual operating results differ from our anticipated results, or available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted.  Terms of future financings may be unfavorable and we cannot assure investors that funding will be available on acceptable terms.

Sources and Uses

Our sources and uses of capital are heavily influenced by the prices we receive for our production.  Over the past year, the NYMEX—WTI oil price ranged from a high of $108 per Bbl to a recent low of $43 per Bbl, while the NYMEX—Henry Hub natural gas price ranged from a high of $ 4.71 per MMBtu to a recent low of $2.50 per MMBtu. These markets will likely continue to be volatile in the future.  To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments.  This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.  Additionally, we believe our conservative use of leverage and corresponding strong balance sheet helps mitigate the potentially negative impact from lower commodity prices.

At May 31, 2015, we had cash and cash equivalents of $190.2 million and an outstanding balance of $141.0 million under our revolving credit facility.  Our sources and (uses) of funds for the nine months ended May 31, 2015 and 2014 are summarized below (in thousands):

	Nine Months Ended
	May 31,
	2015			2014
Cash provided by operations	$	86,942		$	46,745
Net acquisition of oil and gas properties and equipment		(238,207	)		(111,451	)
Short-term investments		-			60,018
Equity financing activities		205,017			33,204
Net borrowings		101,700			-
Net increase in cash and cash equivalents	$	155,452		$	28,516

Net cash provided by operating activities was $86.9 million and $46.7 million for the nine months ended May 31, 2015 and 2014, respectively.  The significant improvement in cash from operating activities reflects the operating contribution from new wells that were drilled and producing wells that were acquired.

During the nine months ended May 31, 2015, we received cash proceeds of $15.4 million from the exercise of Series C warrants.  As of May 31, 2015, all Series C warrants had been exercised.

During the nine months ended May 31, 2015, we also received cash proceeds of approximately $190.8 million (after underwriting discounts, commissions and expenses) from our public offering of 18,613,952 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to the public of $10.75 per share.  We plan to use these proceeds to fund additional asset acquisitions in the Wattenberg Field which may become available from time to time, to pay down outstanding indebtedness under our revolving credit facility and for corporate purposes, including working capital.

During the first nine months of our 2015 fiscal year, we drew net proceeds of $101.7 million under our revolving credit facility, including $66.2 million drawn concurrently with the December 15, 2014 Bayswater acquisition.  Subsequent to May 31, 2015, we repaid $54 million on this revolving credit facility, reducing the total outstanding principal balance to $87 million at July 1, 2015.

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Credit Arrangements

We maintain a borrowing arrangement with a banking syndicate.  The arrangement, in the form of a revolving credit facility, was most recently amended with the Sixth Amendment to the credit facility on June 2, 2015.  The arrangement  provides for a maximum loan commitment of $500 million; however, the maximum amount we can borrow at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesser of the maximum loan commitment or the borrowing base.  The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the line of credit.  For the most part, the value of the collateral will be derived utilizing estimated future cash flows from our proved oil and gas reserves, discounted by 10%.  Amounts borrowed under the facility are secured by substantially all of our producing wells and developed oil and gas leases.  

As of July 1, 2015, our borrowing base was $175 million and we had $87 million outstanding under the facility.  The maturity date of the borrowing arrangement is December 15, 2019.

Interest on our revolving line of credit accrues at a variable rate, which will equal or exceed the minimum rate of 2.5%.  The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization.

Reconciliation of Cash Payments to Capital Expenditures

Capital expenditures reported in the statement of cash flows are calculated on a strict cash basis, which differs from the "all-inclusive" basis used to calculate other amounts reported in our financial statements.  Specifically, cash payments for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made.  On the "all-inclusive" basis, capital expenditures totaled $254.6 million and $146.5 million for the nine months ended May 31, 2015 and 2014, respectively.  A reconciliation of the differences between cash payments and the "all-inclusive" amounts is summarized in the following table (in thousands):

	Nine Months Ended
	May 31,
	2015			2014
Cash payments for capital expenditures	$	238,207		$	112,155
Accrued costs, beginning of period		(71,849	)		(25,491	)
Accrued costs, end of period		26,491			47,489
Non-cash acquisitions, common stock		58,968			11,185
Other		2,781			1,117
All-inclusive capital expenditures	$	254,598		$	146,455

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Capital Expenditures

The majority of capital expenditures during the nine months ended May 31, 2015, were associated with the acquisition of the Bayswater assets and the costs of drilling and completing wells that we operate.  As of May 31, 2015, we had drilled, completed and brought into productive status 19 wells in our 2015 drilling program.  In addition, we had drilled 28 gross (26 net) wells that had not been brought into productive status.  Approximately 20 of the wells in progress are scheduled to commence production before August 31, 2015.

With respect to our ownership interest in wells operated by other companies, we participated in drilling and completion activities on 45 gross (4.7 net) wells.

Capital Requirements

Our primary need for cash will be to fund our drilling and acquisition programs for the remainder of the fiscal year ending August 31, 2015, and the fiscal year ending August 31, 2016. Our cash requirements have increased significantly since May 2013, when we implemented our horizontal drilling program.  Standard-length horizontal wells we drilled early in the fiscal year are estimated to cost between $3.5 million and $3.8 million each.  However, as commodity prices have dropped, we have negotiated lower costs from our service providers and revised our completion design and we are now budgeting that the remaining standard length lateral wells to be drilled this fiscal year will cost between $2.9 million and $3.5 million each.  In order to maximize the efficient use of our capital, we have reduced the amount of non-operated working interests in wells operated by others, either by swapping interests when appropriate or by outright selling of interests. 

Our updated fiscal 2015 plan anticipates drilling and completing 39 operated wells and exiting 2015 with 12 wells in various stages of completion.  We expect that we will participate in 5 net non-operated wells.  Our total fiscal 2015 budget remains at $270 million, with $190 million to $195 million allocated to drilling activities.

Our preliminary capital expenditure plan for 2016 includes spending $220 million to $240 on operated horizontal wells, $15 million to $25 million on non-operated wells, and $10 million to $15 million for additional leasehold and seismic activities.

As has been our historical practice, we regularly review capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success.  Our level of exploration, development and acreage expenditures is largely discretionary and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.

Oil and Gas Commodity Contracts

We use derivative contracts to hedge against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production.  We typically enter into contracts covering between 45% and 85% of anticipated production from our proved developed producing reserves, as projected in our most recent semi-annual reserve report, for a period of 24 months.  At May 31, 2015, we had open positions covering 1.1 million barrels of oil and 3.7 million mcf of natural gas.  We do not use derivative instruments for speculative purposes.

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Our commodity derivative instruments may include but are not limited to "collars", "swaps", and "put" positions. Our hedging strategy, including how much anticipated production we hedge, whether we hedge oil and/or natural gas, and at what prices we hedge, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential.  In addition, our use of hedging contracts is subject to stipulations set forth in our credit facility as amended.

During periods of significant price declines, for settled contracts structured as "collars", we will receive settlement payments from the contracts' counterparties for the difference between the contracted "floor" price and the average posted price for the contract period.  For settled "swaps," we will receive the difference between the contracted swap price and the average posted price for the contract period.  For settled "put" contracts, we will receive the difference between the put's strike price and the average posted price for the contract period.  If we decide to liquidate an "in-the-money" position prior to settlement date, we will receive the approximate fair value of the contract at that time.  These realized gains increase our reported net income for the period in which they are recognized.

Conversely, during periods of significant price increases, upon settlement we would be obligated to pay the counterparties the difference between the contract's "ceiling" and/or swap price and the average posted price for the contract period.  If liquidated prior to settlement, we would pay the approximate fair market value to close the position at that time.  Losses associated with puts that expire out-of-the-money are simply the original premium paid for the contract and are recognized upon expiration.  These realized losses reduce our reported net income for the period in which they are recognized.

The fair values of our open, but not yet settled, derivative contracts are estimated by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. We compare the valuations calculated by us to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate.

The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity.  If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa.  Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and by association, the fair value of our commodity derivative contracts.  These unrealized gains and losses will also impact our net income in the period recorded.

Hedge Activity Accounting

We do not designate our commodity contracts as accounting hedges.  Accordingly, we use mark-to-market accounting to value the portfolio at the end of each reporting period.  Mark-to-market accounting can create non-cash volatility in our reported earnings during periods of commodity price volatility.  We have experienced such volatility in the past and are likely to experience it in the future.  Mark-to-market accounting treatment results in volatility of our results as unrealized gains and losses from derivatives are reported. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

At May 31, 2015, we estimated that the fair value of our various commodity derivative contracts was a net asset of $8.9 million.  We value these contracts using fair value methodology that considers various inputs including a) quoted forecast prices, b) time value, c) volatility factors, d) counterparty risk, and e) other relevant factors.  The fair value of these contracts as estimated at May 31, 2015 may differ significantly from the realized values at their respective settlement dates.

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Non-GAAP Financial Measures

In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP").  A summary of these measures is described below.

Adjusted EBITDA

We use "adjusted EBITDA," a non-GAAP financial measure for internal managerial purposes, when evaluating period-to-period comparisons.  This measure is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows reported in accordance with US GAAP.  The non-GAAP financial measure that we use may not be comparable to measures with similar titles reported by other companies.  Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations.  We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.

We define adjusted EBITDA as net income adjusted to exclude the impact of interest expense, interest income, income tax expense, DDA (depletion, depreciation and amortization), stock-based compensation, and the plus or minus change in fair value of derivative assets or liabilities. We believe adjusted EBITDA is relevant because it is a measure of cash flow available to fund our capital expenditures and service our debt and is a widely used industry metric which may provide comparability of our results with our peers. 

The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to net income, its nearest GAAP measure:

	Three Months Ended May 31,						Nine Months Ended May 31,
(in thousands)	2015			2014			2015			2014
Adjusted EBITDA:
Net (loss) income	$	(2,481	)	$	7,160		$	23,322		$	18,421
Depletion, depreciation and amortization		16,397			7,796			48,357			21,106
Full cost ceiling impairment		3,000			-			3,000			-
Provision (benefit) for income tax		(1,833	)		3,116			13,118			8,841
Stock-based compensation		1,401			702			3,330			1,569
Commodity derivative hedge		8,298			179			(5,578	)		(652	)
Interest income, net		83			(22	)		55			(70	)
Adjusted EBITDA	$	24,865		$	18,931		$	85,604		$	49,215

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TRENDS AND OUTLOOK

Oil prices traded as high as $107/bbl in June 2014, and have since declined more than 40%.  A continuing decline in oil and gas prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic returns, (iv) may cause us to allow leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration,  (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may cause a ceiling test impairment.   However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our substantial capital requirements, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from larger companies.  Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.

Horizontal well development within the field is still relatively new and the geology is enabling operators to utilize higher density drilling within designated spacing units.  We are currently spacing our well bores to allow for up to 24 wells per 640 acre section and we are testing drilling patterns that could lead to an even higher number of wells per section.  We are also testing longer lateral wells, utilizing different amounts of proppant per hydraulic fractionation stage, employing different completion fluids and comparing "plug-and-perf" completions to "sliding-sleeve" completions in order to determine the most cost efficient well designs for the formations we are developing.

The recent decline in commodity prices has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs.  On average, we have been able to reduce drilling and completion costs by approximately 25% over the first three quarters of fiscal 2015 due to a combination of optimizing well designs, moving to day-rate drilling, lower contract rates for drilling rigs, and lower completion costs.  This focus on cost reduction has supported well-level economics in spite of the severe price drop in crude oil and natural gas.  We believe at current drilling and completion cost levels and with current prevailing commodity prices, we can achieve reasonable well-level rates of return going forward.

Our production continues to be adversely impacted by high natural gas gathering line pressures, especially in the northern area of the Wattenberg Field.  This problem has persisted since 2012 and has grown along with the expansion of horizontal drilling in the area.  High line pressure restricts our ability to produce crude oil and natural gas.  As line pressures increase, it becomes more difficult to inject gas produced by our wells into gathering pipelines.  When line pressure is greater than the operating pressure of our wellhead equipment, the wellhead equipment is unable to inject gas into the pipeline, and our production is restricted or shut-in.  Since our wells produce a mixture of crude oil and natural gas, restrictions in gas production also restrict oil production.  

Although various factors can cause increased line pressure, a significant factor in our area of the Wattenberg Field is the success of horizontal wells that have been drilled over the last several years.  As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle.  Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells.  

We are continuing our efforts to mitigate the adverse impact of high line pressures.  Where it is cost effective, we install wellhead compression to enhance our ability to inject gas into the gathering system.  Additionally, along with our midstream service provider, we are evaluating and in some instances installing larger gathering pipelines to our operated pads.

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Over the longer term, midstream companies that operate the gas gathering pipelines have continued to make significant capital investments to increase system capacity.  As publicly disclosed, DCP Midstream Partners ("DCP"), the principal third-party provider that we employ to gather production from our wells, brought online a 160 MMcf/d gas processing plant in La Salle, CO (the O'Connor plant), which is part of an eight-plant system owned by the DCP enterprise with approximately 600 MMcf/d capacity.  DCP has also announced the building of the Lucerne II plant, northeast of Greeley in Weld County, with a maximum capacity of approximately 200 MMcf/d.  The Lucerne II plant recently began operations and is expected to be fully operational during our fourth quarter.  We believe this additional processing capacity will help lower line pressures in the northern area of the Wattenberg Field where we have several operated pads and anticipate further completion activity in the near future.  However, we do not know if this new capacity will completely mitigate the problem and does not help alleviate increasing line pressures in the west and/or south portions of the field.

The success of horizontal drilling techniques in the D-J Basin has also significantly increased quantities of oil produced in the region.  Local crude oil refineries do not have sufficient capacity to process all of the oil available and the imbalance of supply and demand is increasing the transportation of oil out of the D-J Basin via pipeline and rail.  This imbalance has also impacted the prices paid by oil purchasers in the basin, leading to generally wider differentials between the wellhead prices we realize and the crude oil prices posted on NYMEX.  However, as commodity prices have contracted and transportation options have increased, we anticipate price differentials may narrow in the coming quarters and we continue to explore various alternatives with other oil purchasers to ensure we realize the highest net prices available.  In all cases, we believe we will continue to have sufficient take-away capacity for all of our oil production.  Further details regarding posted prices and average realized prices are discussed in the section entitled "Market Conditions," presented in this Item 2. 

Other than the foregoing, we do not know of any trends, events or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues, expenses, liquidity or capital resources.

CRITICAL ACCOUNTING POLICIES

We prepare our financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the critical accounting policies.

During the nine months ended May 31, 2015, there was a significant decline in the price of oil and there are no indications that it will reverse in the near future.  The declines are the most significant price volatility experienced during the last three years.  Accordingly, the description of certain critical accounting policies was updated to reflect the potential impact of these changing commodity prices on our financial statements.  The goal of this disclosure is to highlight some areas where increased price volatility and updated economic assumptions will interact with existing accounting policies.  Please note that there have been no changes in the underlying accounting policies since August 31, 2014, our fiscal year end.  

Oil and Gas Reserves:  Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.   Numerous assumptions are used in the reserve estimation process.  Various engineering and geologic criteria are interpreted to derive volumetric estimates, and financial assumptions are made with regard to realized pricing, costs to be incurred to develop and operate the properties, and future tax regimes

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In spite of the imprecise nature of reserves estimates, they are a critical component of our financial statements.  The determination of the depletion component of our depletion, depreciation and amortization expenses ("DDA"), as well as the ceiling test calculation, is highly dependent on estimates of proved oil and natural gas reserves. For example, if estimates of proved reserves decline, our DDA rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events. Lower prices can also make it uneconomical to drill wells or produce from properties with high operating costs.

Oil and Gas Properties, including Ceiling Test:  There are two alternative methods of accounting for enterprises involved in the oil and gas industry: the successful efforts method and the full cost method.  We use the full cost method of accounting.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of dry holes, abandoned leases, delay rentals and overhead costs directly related to acquisition, exploration, and development activities) are capitalized into a single full cost pool.  

Under the successful efforts method, exploration costs, including the cost of exploratory wells that do not increase proved reserves, the cost of geological and geophysical activities, seismic costs, and lease rentals, are charged to expense as incurred.  Depletion of oil and gas properties and the evaluation for impairment are generally calculated on a narrowly defined asset basis compared to an aggregated "pool" basis under the full cost method.  The conveyance of oil and gas assets generally results in recognition of gain or loss.  In comparison, the conveyance or abandonment of full cost properties does not generally result in the recognition of gain or loss.  Under full cost accounting, recognition of gain or loss is only allowable when the transaction would significantly alter the relationship between capitalized costs and proved reserves.

Our calculation of DDA expense incorporates all the costs capitalized under full cost accounting plus the estimate of costs to be incurred to develop proved reserves.  The sum of historical and future costs are allocated to our estimated quantities of proved oil and gas reserves and depleted using the units-of-production method.  Changes in commodity prices, as well as associated changes in costs that are affected by commodity prices, can have a significant impact on the estimates used in our calculations.

Companies that use full cost accounting perform a ceiling test each quarter.  The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10.  The test compares capitalized costs in the full cost pool, less accumulated DDA and related deferred income taxes, to a calculated ceiling amount.  The calculated ceiling amount is equal to the sum of the present value (using a 10% discount factor) of future net revenues, plus unproved property costs and pre-production costs not being amortized, plus the lower of cost or estimated fair value of unproved properties included in costs being amortized, less related income tax effects.  If the net capitalized costs exceed the ceiling amount, the excess must be charged to expense in recognition of the impairment.

Under the ceiling test, the estimate of future revenues is calculated using a current price (as defined in the SEC rules to include data points over a trailing 12-month period).  Thus, the full impact of a sudden price decline is not recognized immediately.  As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves.  The use of a 12-month average will tend to spread the impact of the change on the financial statements over several reporting periods.

During the three months ended May 31, 2015, our ceiling test resulted in an impairment of $3 million, which was driven by the previously discussed declines in the price of oil and gas.  A further decline in oil and gas prices, or an increase in oil and gas prices that is insufficient to overcome the impact of price declines in the year-ago periods on the ceiling test calculation, could result in additional ceiling test impairments in future periods.

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Oil and Gas Sales:  Our proportionate interests in transactions are recorded as revenue when products are delivered to the purchasers.  This method can require estimates of volumes, ownership interests, and settlement prices.  Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.  Historically, such differences have not been material.  During periods of increased price volatility, it will be more difficult to estimate final settlement prices, and retroactive price adjustments pertaining to prior periods could become significant.

Commodity Derivative Instruments: Our use of commodity derivative instruments helps us mitigate the cash flow impact of short-term commodity price volatility.  We typically enter into contracts covering a portion of our expected oil and gas production over 24 months.  We record realized gains and losses for contracts that settle during the reporting periods.  Contracts either settle at their scheduled maturity date or settle prior to their scheduled maturity date as a result of our decision to early liquidate an open position.  Realized gains and losses represent cash transactions.  Under our hedge strategy we typically receive cash payments when the posted price for the settlement period is less than the hedge price.  Conversely, when the posted price for the settlement period is greater than the hedge price, we typically disburse a cash payment to the counterparty.  Thus, realized gains and losses tend to offset increases or decreases in our revenue stream that are caused by changing prices.

In comparison, unrealized gains and losses are related to positions that have not yet settled and do not represent cash transactions.  At each reporting date, we estimate the fair value of the open (not settled) commodity contract positions and record a gain or loss based upon the change in fair value since the previous reporting date.  The fair values are an approximation of the contracts' values as if we sold them on the reporting date.  Since these amounts represent a calculated value for a hypothetical transaction, the actual value realized at the cash settlement date may be significantly different.

With the current downward trend in commodity prices, we expect to report reduced oil and gas revenues and to report partially offsetting realized gains in our hedge transactions.  During any reporting period in which the commodity prices decline, we expect to report unrealized gains on our open commodity derivative contracts.  However, during any period in which the downward trend reverses, we expect to report unrealized losses.  Looking forward, we expect current contracts to be settled or liquidated over the next 24 months.  We expect to periodically enter into new hedges at then current prices.  Newer hedges at lower prices will reduce the amount of potential price protection provided by the newer contracts.

Business Combinations:  The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations.  Under the acquisition method, assets acquired and liabilities assumed are measured at their fair values, which requires the use of significant judgment since some of the acquired assets and liabilities do not have fair values that are readily determinable.  Different techniques may be used to determining fair values, including market prices (when available), appraisals, comparisons to transactions for similar assets and liabilities, and present values of estimated future cash flows, among others.  Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Once the fair values of the assets acquired and the liabilities assumed are determined, the excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill.  Conversely, the excess, if any, of the fair value of assets acquired and liabilities assumed over the purchase price of the acquired entity is recognized immediately in earnings as a gain from bargain purchase.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This report contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes", "expects", "anticipates", "intends", "plans", "estimates", "should", "likely" or similar expressions, indicates a forward-looking statement.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:

• volatility of oil and natural gas prices;

• operating hazards that result in losses;

• uncertainties in the estimates of proved reserves;

• effect of seasonal weather conditions and wildlife restrictions on our operations;

• our need to expand our oil and natural gas reserves;

• our ability to obtain adequate financing;

• availability and capacity of gathering systems and pipelines for our production;

• effect of local and regional factors on oil and natural gas prices;

• incurrence of ceiling test write-downs;

• our inability to control operations on properties we do not operate;

• our ability to market our production;

• the strength and financial resources of our competitors;

• identifying future acquisitions;

• uncertainty in global economic conditions;

• legal and/or regulatory compliance requirements;

• the amount of our indebtedness and ability to maintain compliance with debt covenants;

• our need for capital;

• key executives allocating a portion of their time to other business interests; and

• effectiveness of our disclosure controls and our internal controls over financial reporting.

Item 3.  Quantitative and Qualitative Disclosures About Market Risks

Commodity Price Risk - Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas.  The volatility of oil prices affects our results to a greater degree than the volatility of gas prices, as approximately 79% of our revenue during the first nine months of fiscal 2015 was from the sale of oil.  A $10 per barrel change in our realized oil price would have resulted in a $4.5 million change in revenues during our third fiscal quarter, while a $0.50 per mcf change in our realized gas price would have resulted in a $0.9 million change in our natural gas revenues in our third fiscal quarter.

During the last several months, the price of oil has declined significantly.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, the strength of the US dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.

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We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and gas production.  We use derivative contracts to cover no less than 45% and no more than 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years.  We do not enter into derivative contracts for speculative or trading purposes.  As of May 31, 2015, we had open crude oil derivatives in a net asset position with a fair value of $8.9 million.  A hypothetical upward or downward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would change the fair value of our position by $.7 million.  

Interest Rate Risk - At May 31, 2015, we had debt outstanding under our bank credit facility totaling $141.0 million.  Interest on our bank credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate ("LIBOR") plus an applicable margin.  At May 31, 2015, we were incurring interest at a rate of 2.5%.  We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase.  A decrease in the variable interest rates would not have a significant impact on us, as the bank credit facility has a minimum interest rate of 2.5%.  If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease.  We estimate that if market interest rates increase by 1% to an annual percentage rate of 3.5%, our interest payments would increase by approximately $1.4 million per year.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year and we have not undertaken any activities to mitigate potential interest rate risk.  There was no material change in interest rate risk during the quarter ended May 31, 2015.

Counterparty Risk – As described in the discussion about Commodity Price Risk, we enter into commodity derivative agreements to mitigate short-term price volatility.  These derivative financial instruments present certain counterparty risks.  We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows.  We do not require collateral or other security to be furnished by counterparties.  We seek to manage the counterparty risk associated with these contracts by limiting transactions to well capitalized, well established and well known counterparties that have been approved by our senior officers.  There can be no assurance, however, that our practice effectively mitigates counterparty risk. 

Our exposure to counterparty risk has increased during the last few months as the amounts due to us from counterparties has increased.

Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Co-Chief Executive Officers and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act") as of the end of the period covered by this report on Form 10-Q (the "evaluation date").  Based on such evaluation, our Co-Chief Executive Officers and Chief Financial Officer concluded that, as of the evaluation date, our disclosure controls and procedures were effective.
 

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

Item 1.  Legal Proceedings.

On June 1, 2015, the Company filed a complaint in the District Court of Weld County, Colorado, against Briller, Inc., R.W.L. Enterprises and Robert W. Loveless (together, the "Defendants") arising from a dispute concerning the validity of certain leases covering properties in Weld County.  On June 23, 2015, the Defendants removed the case to the Federal District Court of Colorado and filed an answer and counterclaims against the Company and two officers of the Company.  The essence of the Defendants' counterclaims is that the Company unlawfully drilled wells through properties leased by the Defendants and extracted oil and gas from these properties causing physical damage and economic damages measured by the value of hydrocarbons to be produced of approximately $42 million.  Although the Company believes Defendants' counterclaims are without merit, it is not possible at this time to predict the outcome of this matter.

Item 1A. Risk Factors.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we will receive for our oil and natural gas will significantly affect our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. For example, over the past year, the NYMEX—WTI oil price ranged from a high of $107.95 per Bbl to a low of $43.39 per Bbl, while the NYMEX—Henry Hub natural gas price ranged from a high of $4.71 per MMBtu to a low of $2.50 per MMBtu. These markets will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will depend on numerous factors beyond our control. These factors include the following:

• worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries, or OPEC;

• the price and quantity of imports of foreign oil and natural gas;

• political conditions in or hostilities in oil-producing and natural gas-producing regions and related sanctions, including current conflicts in the Middle East and conditions in Africa, South America, Russia and Ukraine;

• the level of global oil and domestic natural gas exploration and production;

• the level of global oil and domestic natural gas inventories;

• prevailing prices on local oil and natural gas price indexes in the areas in which we operate;

• localized supply and demand fundamentals and gathering, processing and transportation availability;

• weather conditions and natural disasters;

• domestic and foreign governmental regulations;

• authorization of exports from the United States of liquefied natural gas or oil;

• speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

• price and availability of competitors' supplies of oil and natural gas;

• technological advances affecting energy consumption; and

• the price and availability of alternative fuels.

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Lower oil and natural gas prices will reduce our cash flows and our borrowing ability. Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may, in turn, limit our ability to develop our exploration and production plans. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and may cause the value of our estimated proved reserves at future reporting dates to decline compared to our estimated proved reserves at our most recent reporting period. Specifically, a decline in the value of our reserves may reduce the borrowing base available to us under the Facility, and, should the value of our reserves decline below our recorded costs as measured by the ceiling test, we would be required to record a non-cash impairment charge in our financial statements. Additionally, an extended decline in commodity prices could lead us to reduce our capital expenditure budget and scale back our drilling and development plans.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Item 6.  Exhibits

a.  Exhibits

31.1 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Ed Holloway

31.2 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for William Scaff, Jr.

31.3 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Frank L. Jennings.

32 Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 for Ed Holloway, William Scaff, Jr. and Frank L. Jennings.

101 INSXBRL Instance Document

101 SCHXBRL Schema Document

101 CALXBRL Calculation Linkbase Document

101 DEFXBRL Definition Linkbase Document.

101 LABXBRL Label Linkbase Document

101 PREXBRL Presentation Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SYNERGY RESOURCES CORPORATION
Date:  July 10, 2015	By:	/s/ Ed Holloway
		Ed Holloway, Co-Chief Executive Officer (Principal Executive Officer)

Date:  July 10, 2015	By:	/s/ William Scaff, Jr.
		William Scaff, Jr., Co-Chief Executive Officer (Principal Executive Officer)

Date:  July 10, 2015	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Chief Financial Officer (Principal Financial Officer)

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EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Ed Holloway, certify that;

1. I have reviewed this quarterly report on Form 10-Q of Synergy Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  July 10, 2015	By:	/s/ Ed Holloway
		Ed Holloway, Co-Chief Executive Officer (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, William Scaff, Jr., certify that;

1. I have reviewed this quarterly report on Form 10-Q of Synergy Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  July 10, 2015	By:	/s/ William Scaff, Jr.
		William Scaff, Jr., Co-Chief Executive Officer (Principal Executive Officer)

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, Frank L. Jennings, certify that;

1. I have reviewed this quarterly report on Form 10-Q of Synergy Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  July 10, 2015	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Chief Financial Officer (Principal Financial Officer)

EX-32

Exhibit 32

In connection with the quarterly report of Synergy Resources Corporation, (the "Company") on Form 10-Q for the quarter ended May 31, 2015 as filed with the Securities Exchange Commission on the date hereof (the "Report") Ed Holloway and William Scaff, Jr., the Co-Chief Executive Officers of the Company, and Frank L. Jennings, the Principal Financial Officer of the Company, certify pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.

Date:  July 10, 2015	By:	/s/ Ed Holloway
		Ed Holloway, Co-Chief Executive Officer (Principal Executive Officer)

Date:  July 10, 2015	By:	/s/ William Scaff, Jr.
		William Scaff, Jr., Co-Chief Executive Officer (Principal Executive Officer)

Date:  July 10, 2015	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Chief Financial Officer (Principal Financial Officer)

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Acquisitions (Schedule of Pro Forma Results) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014
Acquisitions [Abstract]
Oil and Gas Revenues	$ 26,033	$ 26,766	$ 99,157	$ 71,550
Net income	$ (2,481)	$ 6,889	$ 25,102	$ 17,997
Earnings per common share
Basic	$ (0.02)	$ 0.08	$ 0.26	$ 0.22
Diluted	$ (0.02)	$ 0.08	$ 0.26	$ 0.22

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Other Commitments and Contingencies (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	May. 31, 2015	May. 31, 2015	May. 31, 2014
Long-term Purchase Commitment [Line Items]
Accrued well costs	$ 3,600	$ 26,491	$ 47,489

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Fair Value Measurements (Details) - Recurring [Member] - USD ($) $ in Thousands	May. 31, 2015	Aug. 31, 2014
Financial Assets:
Commodity derivative asset	$ 8,883	$ 419
Financial Liabilities:
Commodity derivative liability		$ 609
Level 1 [Member]
Financial Assets:
Commodity derivative asset
Financial Liabilities:
Commodity derivative liability
Level 2 [Member]
Financial Assets:
Commodity derivative asset	$ 8,883	$ 419
Financial Liabilities:
Commodity derivative liability		$ 609
Level 3 [Member]
Financial Assets:
Commodity derivative asset
Financial Liabilities:
Commodity derivative liability

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Supplemental Schedule of Information to the Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	May. 31, 2015	May. 31, 2015	May. 31, 2014
Supplemental cash flow information:
Interest paid		$ 2,200	$ 750
Income taxes paid		110
Non-cash investing and financing activities:
Accrued well costs	$ 3,600	26,491	$ 47,489
Assets acquired in exchange for common stock		58,968	11,185
Asset retirement costs and obligations		$ 2,657	$ 1,367

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Commodity Derivative Instruments (Schedule of Gain (Loss) Recognized in Statements of Operations) (Details)	3 Months Ended		9 Months Ended
	May. 31, 2015 USD ($) bbl	May. 31, 2014 USD ($)	May. 31, 2015 USD ($)	May. 31, 2014 USD ($)
Commodity Derivative Instruments [Abstract]
Realized gain (loss) on commodity derivatives	$ 7,136,000	$ (826,000)	$ 20,935,000	$ (1,415,000)
Unrealized gain (loss) on commodity derivatives	(8,298,000)	(179,000)	5,578,000	652,000
Total gain (loss)	$ (1,162,000)	$ (1,005,000)	$ 26,513,000	$ (763,000)
Average price of liquidated swaps	80.61
Number of barrels in liquidation | bbl	188,500

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Organization and Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014	Aug. 31, 2014
Organization and Summary of Significant Accounting Policies [Abstract]
Net cash flows, discount rate	10.00%		10.00%
Capitalized overhead	$ 486	$ 300	$ 1,623	$ 921
Minimum [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment, useful life			5 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment, useful life			7 years
Company A [Member] | Oil and Gas Revenues [Member]
Concentration Risk [Line Items]
Risk percentage	58.00%	45.00%	62.00%	45.00%
Company A [Member] | Tenant accounts receivable [Member]
Concentration Risk [Line Items]
Risk percentage			29.00%		37.00%
Company B [Member] | Oil and Gas Revenues [Member]
Concentration Risk [Line Items]
Risk percentage	15.00%	13.00%	11.00%	15.00%
Company B [Member] | Tenant accounts receivable [Member]
Concentration Risk [Line Items]
Risk percentage			12.00%
Company C [Member] | Oil and Gas Revenues [Member]
Concentration Risk [Line Items]
Risk percentage	10.00%	12.00%		10.00%
Company D [Member] | Oil and Gas Revenues [Member]
Concentration Risk [Line Items]
Risk percentage		12.00%

XML

Depletion, depreciation and amortization ("DDA") (Tables)

9 Months Ended

May. 31, 2015

Depletion, depreciation and amortization ("DDA") [Abstract]

Schedule of Depletion, Depreciation and Amortization

	Three Months Ended May 31,				Nine Months ended May 31,
	2015		2014		2015		2014
Depletion	$	16,200	$	7,569	$	47,849	$	20,550
Depreciation and amortization		197		227		508		556
Total DDA Expense	$	16,397	$	7,796	$	48,357	$	21,106

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Shareholders' Equity (Common Stock Transactions) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	9 Months Ended
	Feb. 28, 2015	May. 31, 2015	Aug. 31, 2014
Classes of stock
Preferred stock, shares authorized		10,000,000	10,000,000
Preferred stock, par value		$ 0.01	$ 0.01
Preferred stock, shares issued		0	0
Preferred stock, shares outstanding		0	0
Common stock, shares authorized		200,000,000	200,000,000
Common stock, par value		$ 0.001	$ 0.001
Common stock, shares issued		105,025,453	77,999,082
Common stock, shares outstanding		105,025,453	77,999,082
Common stock issued for acquisition of mineral property interests
Number of common shares issued for mineral property leases		995,672
Number of common shares issued for acquisitions		4,648,136
Total common shares issued	18,613,952	5,643,808
Average price per common share	$ 10.75	$ 10.45
Aggregate value of shares issued	$ 190,800	$ 58,968

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Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) $ in Thousands	9 Months Ended
	May. 31, 2015 USD ($)
Asset Retirement Obligations [Abstract]
Asset retirement obligations, August 31, 2014	$ 4,730
Liabilities incurred	744
Liabilities assumed	1,913
Accretion expense	385
Asset retirement obligations, May 31, 2015	$ 7,772

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Acquisitions (Narrative) (Details) $ in Thousands		1 Months Ended					9 Months Ended
		Dec. 15, 2014 USD ($) a shares	Nov. 30, 2013 USD ($) shares	Nov. 13, 2013 USD ($) a shares	Nov. 12, 2013 USD ($) a shares	Aug. 27, 2013 USD ($)	May. 31, 2015 USD ($) shares	Aug. 31, 2014 USD ($)
Business Acquisition [Line Items]
Business acquisition, shares issued | shares							4,648,136
Fair value attributed to unproved properties							$ 15,300
Fair value attributed to proved properties							$ 513,677	$ 329,926
Percentage of full cost amortization							2.00%
Vertical Wells [Member]
Business Acquisition [Line Items]
Percent of entity acquired							100.00%
Horizontal Wells [Member]
Business Acquisition [Line Items]
Fair value attributed to proved properties							$ 24,800
Trilogy Resources [Member]
Business Acquisition [Line Items]
Number of wells					21
Mineral acres, net | a					800
Business acquisition, shares issued | shares					301,339
Cash					$ 15,902
Total purchase price					18,798
Synergy Resources Corp. Common Stock	[1]				$ 2,896
Apollo Operating [Member]
Business Acquisition [Line Items]
Number of wells				38
Mineral acres, gross | a				3,639
Mineral acres, net | a				1,000
Business acquisition, shares issued | shares			20,626	550,518
Business acquisition, shares issued, value			$ 200			$ 5,200
Cash			$ 3,700	$ 14,688		$ 11,000
Percent of entity acquired				25.00%
Total purchase price				$ 20,120
Synergy Resources Corp. Common Stock	[2]			$ 5,432
Bayswater [Member]
Business Acquisition [Line Items]
Business acquisition, shares issued | shares		4,648,136
Cash		$ 74,221
Synergy Resources Corp. Common Stock	[3]	$ 48,434
Bayswater [Member] | Codell And Niobrara [Member]
Business Acquisition [Line Items]
Mineral acres, gross | a		5,040
Mineral acres, net | a		4,053
Bayswater [Member] | Sussex Shannon And JSands [Member]
Business Acquisition [Line Items]
Mineral acres, gross | a		2,400
Mineral acres, net | a		1,739
Bayswater [Member] | Vertical Wells [Member]
Business Acquisition [Line Items]
Number of wells		73
Bayswater [Member] | Horizontal Wells [Member]
Business Acquisition [Line Items]
Number of wells		17
Bayswater [Member] | Non-operated Vertical Wells [Member]
Business Acquisition [Line Items]
Number of wells		11
Bayswater [Member] | Minimum [Member] | Vertical Wells [Member]
Business Acquisition [Line Items]
Percent of entity acquired		5.00%
Bayswater [Member] | Minimum [Member] | Horizontal Wells [Member]
Business Acquisition [Line Items]
Percent of entity acquired		6.00%
Bayswater [Member] | Maximum [Member] | Vertical Wells [Member]
Business Acquisition [Line Items]
Percent of entity acquired		100.00%
Bayswater [Member] | Maximum [Member] | Horizontal Wells [Member]
Business Acquisition [Line Items]
Percent of entity acquired		40.00%

[1] The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)

[2] The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08).

[3] The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 (4,648,136 shares at $10.42 per share).

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Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 1,401	$ 702	$ 3,330	$ 1,569
Term	10 years	10 years	10 years	10 years
Vesting Period	5 years	5 years	5 years	5 years
Fair value	$ 10,500	$ 633	$ 12,940	$ 2,362
Summary of activity for stock options:
Outstanding, August 31, 2014			2,167,000
Granted	1,892,500	90,000	2,302,500	353,000
Exercised			(258,000)
Forfeited			(110,000)
Outstanding, May 31, 2015	4,101,500		4,101,500
Outstanding, weighted average exercise price			$ 5.94
Granted, weighted average exercise price	$ 11.57	$ 10.51	11.64	$ 9.92
Exercised, weighted average exercise price			3.81
Forfeited, weighted average exercise price			(4.97)
Outstanding, weighted average exercise price	$ 9.30		$ 9.30
Weighted average remaining contractual life			8 years 9 months 18 days
Aggregate intrinsic value	$ 9,547		$ 9,547
Assumptions used in valuing stock options:
Expected term			6 years 6 months	6 years 6 months
Expected volatility			47.00%	73.00%
Risk free rate			1.77%
Risk-free rate, minimum				1.97%
Risk-free rate, maximum				2.02%
Expected dividend yield			0.00%	0.00%
Forfeiture rate			3.30%	0.00%
Vested Options:
Number of shares	888,100		888,100
Weighted average remaining contractual life			6 years 10 months 24 days
Weighted average exercise price	$ 5.34		$ 5.34
Aggregate intrinsic value	$ 5,480		$ 5,480
Unrecognized compensation expense	15,038		$ 15,038
Remaining vesting phase			4 years 3 months 18 days
Stock options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	715	$ 445	$ 1,792	$ 1,312
Restricted stock grants [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 686	$ 257	$ 1,538	$ 257

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Commodity Derivative Instruments (Schedule of Hedge Realized Gains (Losses)) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014
Commodity Derivative Instruments [Abstract]
Monthly settlement	$ 2,100	$ (826)	$ 9,618	$ (1,415)
Early liquidation	5,036		11,317
Total realized gain (loss)	$ 7,136	$ (826)	$ 20,935	$ (1,415)

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Depletion, depreciation and amortization ("DDA")

9 Months Ended

May. 31, 2015

Depletion, depreciation and amortization ("DDA") [Abstract]

Depletion, depreciation and amortization ("DDA")

4. Depletion, depreciation and amortization ("DDA")

Depletion, depreciation and amortization consisted of the following (in thousands):

	Three Months Ended May 31,				Nine Months ended May 31,
	2015		2014		2015		2014
Depletion	$	16,200	$	7,569	$	47,849	$	20,550
Depreciation and amortization		197		227		508		556
Total DDA Expense	$	16,397	$	7,796	$	48,357	$	21,106

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter.  For the three months ended May 31, 2015, production of 738,357 barrels of oil equivalent ("BOE") represented 1.7% of the estimated total proved reserves.  For the nine months ended May 31, 2015, production of 2,188,737 BOE represented 4.9% of the estimated total proved reserves.

 

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Revolving Credit Facility (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	May. 31, 2015	May. 31, 2015	Jul. 01, 2015	Jun. 11, 2015	Jun. 02, 2015	Dec. 15, 2014	Nov. 30, 2014
Line of Credit Facility [Line Items]
Total borrowing commitment						$ 500	$ 300
Borrowing base			$ 175			$ 230	$ 110
Amount outstanding	$ 146	$ 146		$ 87
Remaining borrowing capacity			$ 88
Credit facility, expiration date		Dec. 15, 2019
Minimum hedge percentage of scheduled production for a rolling 24 months, as required by revolving credit facility covenants	45.00%	45.00%
Maximum hedge percentage of scheduled production for a rolling 24 months, as required by revolving credit facility covenants	85.00%	85.00%
Revolving credit facility, additional rate over variable		2.50%
Average interest rate	2.50%	2.50%
Minimum EBITDAX times interest and fees	4.0	4.0
Minimum liquidity					$ 25

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Interest Expense (Tables)

9 Months Ended

May. 31, 2015

Interest Expense [Abstract]

Schedule of the Components of Interest Expense

	Three Months Ended May 31,						Nine Months Ended May 31,
	2015			2014			2015			2014
Revolving credit facility	$	915		$	252		$	2,191		$	749
Amortization of debt issuance costs		252			118			607			312
Less, interest capitalized		(1,051	)		(370	)		(2,682	)		(1,061
Interest expense, net	$	116		$	-		$	116		$	-

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Fair Value Measurements (Tables)

9 Months Ended

May. 31, 2015

Fair Value Measurements [Abstract]

Schedule of Assets and Liabilities Measured on a Recurring Basis

	Fair Value Measurements at May 31, 2015
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	8,883	$	-	$	8,883
Commodity derivative liability	$	-	$	-	$	-	$	-

	Fair Value Measurements at August 31, 2014
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	419	$	-	$	419
Commodity derivative liability	$	-	$	609	$	-	$	609

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Subsequent Events (Details) - USD ($) $ in Millions	1 Months Ended
	Jul. 10, 2015	Jul. 01, 2015	Jun. 11, 2015	May. 31, 2015
Subsequent Event [Line Items]
Amount outstanding			$ 87	$ 146
Subsequent Event [Member]
Subsequent Event [Line Items]
Repayment of credit facility	$ 54
Amount outstanding		$ 87		$ 141

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Commodity Derivative Instruments (Schedule of Commodity Derivative Contracts) (Details) - May. 31, 2015	bbl MMBTU $ / shares
Contract One [Member] | Collar [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	2,500
Average Fixed Price
Floor Price	80.00
Celing Price	95.75
Contract One [Member] | Collar [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | MMBTU	72,000
Average Fixed Price
Floor Price	4.15
Celing Price	4.49
Contract One [Member] | Swap [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	5,000
Average Fixed Price	88.55
Floor Price
Celing Price
Contract One [Member] | Put [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	40,000
Average Fixed Price
Floor Price	50.00
Celing Price
Contract Two [Member] | Collar [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	10,000
Average Fixed Price
Floor Price	75.00
Celing Price	96.00
Contract Two [Member] | Collar [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | MMBTU	60,000
Average Fixed Price
Floor Price	4.05
Celing Price	4.54
Contract Two [Member] | Swap [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	20,000
Average Fixed Price	88.10
Floor Price
Celing Price
Contract Two [Member] | Put [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	5,200
Average Fixed Price
Floor Price	50.00
Celing Price
Contract Three [Member] | Collar [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	5,000
Average Fixed Price
Floor Price	80.00
Celing Price	100.75
Contract Three [Member] | Collar [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | MMBTU	60,000
Floor Price	3.90
Celing Price	4.14
Contract Three [Member] | Swap [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	6,400
Average Fixed Price	78.96
Floor Price
Celing Price
Contract Three [Member] | Put [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	10,000
Average Fixed Price
Floor Price	55.00
Celing Price
Contract Four [Member] | Collar [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	15,000
Average Fixed Price
Floor Price	80.00
Celing Price	100.05
Contract Four [Member] | Collar [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | MMBTU	100,000
Average Fixed Price
Floor Price	2.20
Celing Price	3.05
Contract Four [Member] | Put [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	25,000
Average Fixed Price
Floor Price	50.00
Celing Price
Contract Five [Member] | Collar [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | MMBTU	100,000
Average Fixed Price
Floor Price	2.65
Celing Price	3.10
Contract Five [Member] | Put [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	20,000
Average Fixed Price
Floor Price	50.00
Celing Price
Contract Six [Member] | Collar [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | MMBTU	100,000
Average Fixed Price
Floor Price	2.80
Celing Price	3.95
Contract Six [Member] | Put [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | bbl	20,000
Average Fixed Price
Floor Price	55.00
Contract Seven [Member] | Collar [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Average Volumes (BBls/MMBtu per month) | MMBTU	110,000
Floor Price	2.50
Celing Price	3.05

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Shareholders' Equity (Tables)

9 Months Ended

May. 31, 2015

Shareholders' Equity [Abstract]

Schedule of Classes of Stock

	As of May 31,		As of August 31,
	2015		2014
Preferred stock, shares authorized		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding		nil		nil
Common stock, shares authorized		200,000,000		200,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding		105,025,453		77,999,082

Schedule of Common Stock Issued for Acquisition of Mineral Interests and Services

	For the nine months ended May 31, 2015
Number of common shares issued for mineral property leases		995,672
Number of common shares issued for acquisitions		4,648,136
Total common shares issued		5,643,808
Average price per common share	$	10.45
Aggregate value of shares issued (in thousands)	$	58,968

Schedule of Outstanding Common Stock Warrant Activity

	Number of Warrants			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,562,473		$	6.00
Granted		-		$	-
Exercised		(2,562,473	)	$	6.00
Expired		-		$	-
Outstanding, May 31, 2015		-		$	-

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Stock-Based Compensation (Tables)

9 Months Ended

May. 31, 2015

Stock-Based Compensation [Abstract]

Schedule of Stock-based Compensation Expense Recognized

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Stock options	$	715	$	445	$	1,792	$	1,312
Employee stock grants		686		257		1,538		257
	$	1,401	$	702	$	3,330	$	1,569

Schedule of Employee Stock Options Granted During the Period

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Number of options to purchase common shares		1,892,500		90,000		2,302,500		353,000
Weighted-average exercise price	$	11.57	$	10.51	$	11.64	$	9.92
Term (in years)		10.0		10.0		10.0		10.0
Vesting Period (in years)		5		5		5		5
Fair Value (in thousands)	$	10,500	$	633	$	12,940	$	2,362

Schedule of Assumptions Used In Valuing Stock Options

	Nine Months Ended May 31,
	2015			2014
Expected term	6.5 years			6.5 years
Expected volatility		47	%		73	%
Risk free rate		1.77	%		1.97% - 2.02	%
Expected dividend yield		0.00	%		0.00	%
Forfeiture rate		3.3	%		0.00	%

Summary of Stock Option Activity Under Stock Option and Incentive Plans

	Number of Shares			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,167,000		$	5.94
Granted		2,302,500		$	11.64
Exercised		(258,000	)	$	3.81
Forfeited		(110,000	)		(4.97
Outstanding, May 31, 2015		4,101,500		$	9.30

Schedule of Issued and Outstanding Stock Options

	Outstanding Options		Vested Options
Number of shares		4,101,500		888,100
Weighted-average remaining contractual life		8.8 years		6.9 years
Weighted-average exercise price		$9.30		$5.34
Aggregate intrinsic value (in thousands)		$9,547		$5,480

Schedule of Estimated Unrecognized Compensation Cost From Unvested Stock Options

	Unvested Options at May 31, 2015
Unrecognized compensation expense (in thousands)	$15,038
Remaining vesting phase	4.3 years

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Acquisitions

9 Months Ended

May. 31, 2015

Acquisitions [Abstract]

Acquisitions

3. Acquisitions

During the nine months ended May 31, 2015 and 2014, the Company acquired certain oil and gas and other assets, as described below.

Bayswater transaction

On December 15, 2014, the Company completed the acquisition of certain assets from three independent oil and gas companies (collectively known as "Bayswater") for a total purchase price of $125.1 million, net of customary closing adjustments.  The purchase price was composed of $74.2 million in cash and $48.4 million in restricted common stock plus the assumption of certain liabilities.

The Bayswater acquisition encompassed 5,040 gross (4,053 net) acres with rights to the Codell and Niobrara formations, and 2,400 gross (1,739 net) acres with rights to other formations including the Sussex, Shannon and J-Sand.  Additionally, the Company acquired non-operated working interests in 17 horizontal wells and 73 operated vertical wells as well as working interests in 11 non-operated vertical wells.  The working interests in the horizontal wells range from 6% to 40% while the working interests in the vertical wells range from 5% to 100%.

The following allocation of the purchase price is preliminary and includes significant use of estimates.  The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition.  Accordingly, the allocation will change as additional information becomes available and is assessed, and the impact of such changes may be material.  The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	December 15, 2014
Consideration Given
Cash	$	74,221
Synergy Resources Corp. Common Stock (1)		48,434
Liabilities assumed, including asset retirement obligations		2,467
Total consideration given	$	125,122
Allocation of Purchase Price
Proved oil and gas properties (2)	$	51,400
Unproved oil and gas properties		73,722
Total fair value of oil and gas properties acquired	$	125,122

(1)

The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 (4,648,136 shares at $10.42 per share).

(2)

Proved oil and gas properties were measured primarily using an income approach.  The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement.  The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 10%, and assumptions on the timing and amount of future development and operating costs.

The following table presents the pro forma combined results of operations for the three and nine months ended May 31, 2015 as if the Bayswater transaction had occurred on September 1, 2013, the first day of our 2014 fiscal year.  The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Three Months Ended May 31,					Nine Months ended May 31,
	2015			2014		2015		2014
Oil and Gas Revenues	$	26,033		$	26,766	$	99,157	$	71,550
Net income	$	(2,481	)	$	6,889	$	25,102	$	17,997
Earnings per common share
Basic	$	(0.02	)	$	0.08	$	0.26	$	0.22
Diluted	$	(0.02	)	$	0.08	$	0.26	$	0.22

Apollo and Trilogy transactions

During the year ended August 31, 2014, the Company closed on two transactions that qualified as Business Combinations under ASC 805.  The initial accounting treatment of the transactions was based upon the preliminary analysis of the assets acquired.  During the first fiscal quarter of 2015, the Company completed its analysis and finalized the allocation of purchase price to the assets acquired.  The following tables present the final fair values.

On September 16, 2013, the Company entered into a definitive purchase and sale agreement with Trilogy Resources, LLC ("Trilogy"), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the "Trilogy Assets"). On November 12, 2013, the Company closed the transaction for a combination of cash and stock.  Trilogy received 301,339 shares of the Company's common stock valued at $2.9 million and cash consideration of approximately $15.9 million.  No material transaction costs were incurred in connection with this acquisition.

 

The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 12, 2013.  The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	November 12, 2013
Consideration Given
Cash	$	15,902
Synergy Resources Corp. Common Stock *		2,896
Total consideration given	$	18,798
Allocation of Purchase Price
Proved oil and gas properties	$	11,514
Unproved oil and gas properties	$	7,725
Total fair value of oil and gas properties acquired		19,239
Working capital	$	(83	)
Asset retirement obligation		(358	)
Fair value of net assets acquired	$	18,798
Working capital acquired was estimated as follows:
Accounts receivable		536
Accrued liabilities and expenses		(619	)
Total working capital	$	(83	)

*  The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)

On August 27, 2013, the Company entered into a definitive purchase and sale agreement ("the Agreement"), with Apollo Operating, LLC ("Apollo"), for its interests in 38 producing oil and gas wells, partial interest (25%) in one water disposal well (the "Disposal Well"), and approximately 3,639 gross (1,000 net) mineral acres ("the Apollo Operating Assets"). On November 13, 2013, the Company closed the transaction for a combination of cash and stock.  Apollo received cash consideration of approximately $11.0 million and 550,518 shares of the Company's common stock valued at $5.2 million.  Following the acquisition of the Apollo Operating Assets, the Company acquired all other remaining interests in the Disposal Well (the "Related Interests") through several transactions with the individual owners of such interests. The Company acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of the Company's common stock, valued at $0.2 million.  No material transaction costs were incurred in connection with this acquisition.

The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 13, 2013. The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	November 13, 2013
Consideration Given
Cash	$	14,688
Synergy Resources Corp. Common Stock *		5,432
Total consideration given	$	20,120
Allocation of Purchase Price
Proved oil and gas properties	$	13,284
Unproved oil and gas properties	$	7,577
Total fair value of oil and gas properties acquired		20,861
Working capital	$	(507	)
Asset retirement obligation		(234	)
Fair value of net assets acquired	$	20,120
Working capital acquired was estimated as follows:
Accounts receivable		662
Accrued liabilities and expenses		(1,169	)
Total working capital	$	(507	)

* The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08).

The motivation for both the Trilogy and Apollo acquisitions was the expectation that each was accretive to cash flow and earnings per share.  The acquisitions qualify as a business combination, and as such, the Company estimated the fair value of each property as of the acquisition date (the date on which the Company obtained control of the properties). Fair value measurements utilize assumptions of market participants. To determine the fair value of the oil and gas assets, the Company used an income approach based on a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. The Company determined the appropriate discount rates used for the discounted cash flow analyses by using a weighted-average cost of capital from a market participant perspective plus property-specific risk premiums for the assets acquired. The Company estimated property-specific risk premiums taking into consideration the Gas to Oil Ratio ("GOR") of the related reserves, among other items.  Given the unobservable nature of the significant inputs, they are deemed to be Level 3 in the fair value hierarchy. The working capital assets acquired were determined to be at fair value due to their short-term nature.

 

The preliminary analysis and allocation of the purchase price focused on the values inherent in the proved producing wells and the associated proved undeveloped reserves.  All of the producing wells acquired in the transactions were vertical wells and the initial estimates allocated 100% of the fair value to proved properties associated with vertical well development.  The final analysis also considered the additional value provided by the virtue of the ability to drill horizontal wells in the acquired acreage.  Adding horizontal wells to the development plan required a further evaluation as to the classification of the horizontal reserves, as reserves classified as proved under a vertical well drilling plan may be classified differently under a horizontal drilling plan.  In the subject acres, the horizontal well reserves are classified as unproved even though the vertical well reserves are proved.  Thus, the final analysis attributed $15.3 million of fair value to unproved horizontal properties and $24.8 million of fair value to proved properties.

Differences between the preliminary allocation and final allocation of acquired fair value have been treated as a change in accounting estimate, and no retroactive adjustments were made to the previously reported financial statements.  Furthermore, since the reclassification of $15.3 million from proved properties subject to amortization to unproved properties not subject to amortization represents approximately 2% of the full cost amortization base, no prior period adjustment was recorded during the current year.

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Related Party Transactions (Tables)

9 Months Ended

May. 31, 2015

Related Party Transactions [Abstract]

Schedule of Rent Expense

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Rent expense	$	45	$	45	$	135	$	135

Schedule of Royalty Expense

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Total Royalty Payments	$	14	$	58	$	95	$	191

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Depletion, depreciation and amortization ("DDA") (Details) $ in Thousands	3 Months Ended		9 Months Ended
	May. 31, 2015 USD ($) Boe	May. 31, 2014 USD ($)	May. 31, 2015 USD ($) Boe	May. 31, 2014 USD ($)
Depletion, depreciation and amortization ("DDA") [Abstract]
Depletion	$ 16,200	$ 7,569	$ 47,849	$ 20,550
Depreciation and amortization	197	227	508	556
Total DDA Expense	$ 16,397	$ 7,796	$ 48,357	$ 21,106
Production of BOE | Boe	738,357		2,188,737
Percentage of total reserves	1.70%		4.90%

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Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014
Related Party Transaction [Line Items]
Rent expense	$ 45	$ 45	$ 135	$ 135
Royalty expense	$ 14	$ 58	$ 95	$ 191

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BALANCE SHEETS - USD ($) $ in Thousands	May. 31, 2015	Aug. 31, 2014
Current assets:
Cash and cash equivalents	$ 190,205	$ 34,753
Accounts receivable:
Oil and gas sales	14,781	16,974
Joint interest billing and other	18,487	15,398
Commodity derivative	4,268	365
Other current assets	1,311	750
Total current assets	229,052	68,240
Oil and gas properties, full cost method:
Proved properties, net	407,576	275,018
Unproved properties and properties under development, not being amortized	170,639	95,278
Other property and equipment, net	4,811	9,104
Property and equipment, net	583,026	379,400
Commodity derivative	4,615	54
Other assets	2,767	848
Total assets	819,460	448,542
Current liabilities:
Trade accounts payable	1,027	1,747
Well costs payable	26,491	71,849
Revenue payable	18,786	14,487
Production taxes payable	17,120	14,376
Other accrued expenses	$ 457	817
Commodity derivative		302
Total current liabilities	$ 63,881	103,578
Revolving credit facility	$ 141,000	37,000
Commodity derivative		307
Deferred tax liability, net	$ 34,670	21,437
Asset retirement obligations	7,772	4,730
Total liabilities	$ 247,323	$ 167,052
Commitments and contingencies (See Note 13)
Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding
Common stock - $0.001 par value, 200,000,000 shares authorized: 105,025,453 and 77,999,082 shares issued and outstanding, respectively	$ 105	$ 78
Additional paid-in capital	533,091	265,793
Retained earnings	38,941	15,619
Total shareholders' equity	572,137	281,490
Total liabilities and shareholders' equity	$ 819,460	$ 448,542

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Commodity Derivative Instruments (Schedule of Fair Value of Derivatives) (Details) - Commodity Contract [Member] - USD ($) $ in Thousands	May. 31, 2015	Aug. 31, 2014
Current Assets [Member] | Gross Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative asset	$ 4,487	$ 903
Current Assets [Member] | Gross Amount Offset [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative asset	(219)	(538)
Current Assets [Member] | Net Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative asset	4,268	365
Noncurrent Assets [Member] | Gross Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative asset	4,994	718
Noncurrent Assets [Member] | Gross Amount Offset [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative asset	(379)	(664)
Noncurrent Assets [Member] | Net Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative asset	4,615	54
Current Liabilities [Member] | Gross Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability	219	840
Current Liabilities [Member] | Gross Amount Offset [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability	$ (219)	(538)
Current Liabilities [Member] | Net Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability		302
Noncurrent Liabilities [Member] | Gross Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability	$ 379	971
Noncurrent Liabilities [Member] | Gross Amount Offset [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability	$ (379)	(664)
Noncurrent Liabilities [Member] | Net Amount [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability		$ 307

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Organization and Summary of Significant Accounting Policies

9 Months Ended

May. 31, 2015

Organization and Summary of Significant Accounting Policies [Abstract]

Organization and Summary of Significant Accounting Policies

1. Organization and Summary of Significant Accounting Policies

Organization:    Synergy Resources Corporation ("the Company") is engaged in oil and gas acquisition, exploration, development and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado.  The Company's common stock is listed and traded on the NYSE MKT under the symbol "SYRG."

Basis of Presentation:    The Company has adopted August 31^st as the end of its fiscal year.  The Company does not utilize any special purpose entities.  The Company operates in one business segment and all of its operations are located in the United States of America.

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial information.

Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  The balance sheet as of August 31, 2014 was derived from the Company's Annual Report on Form 10-K for the year ended August 31, 2014.  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, 2014.

In management's opinion, the unaudited financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

Reclassifications:    Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation.  The reclassifications had no effect on net income, working capital or equity previously reported.

Use of Estimates:     The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves and goodwill, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain.  Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  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 these estimates.

Cash and Cash Equivalents:    The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, 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 properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs of oil and gas properties are depleted using the units-of-production method based upon estimates of proved reserves.  For depletion purposes, the volume of petroleum 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.

Properties under development represent the costs associated with the development of oil and gas properties that have yet to be proved as of May 31, 2015.  Since the properties were not classified as proved as of May 31, 2015, they were classified within unproved oil and gas properties and were withheld from the depletion calculation and ceiling test.  The costs for these properties will be transferred into proved properties when they are proved and will become subject to depletion and the ceiling test calculation in subsequent periods.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is an impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the book value of oil and gas properties.  The capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion, depreciation, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unproved properties not being amortized, plus the lower of cost or estimated fair value of unproven properties being amortized.  Prices are held constant for the productive life of each well.  Net cash flows are discounted at 10%.  If net capitalized costs exceed this limit, the excess is charged to expense.  The calculation of future net cash flows assumes continuation of current economic conditions.  Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials.

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.

The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of the Company's oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest:    The Company capitalizes interest on expenditures made in connection with acquisition of mineral interests and development projects that are not subject to current amortization.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 9 for additional information.

Capitalized Overhead:    A portion of the Company's overhead expenses are directly attributable to acquisition and development activities.  Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Capitalized Overhead	$	486	$	300	$	1,623	$	921

Well Costs Payable:    The costs of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings ("JIB").  For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the authorization for expenditure.

Other Property and 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.

Asset Retirement Obligations:    The Company's activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company's credit adjusted risk-free interest rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed or an asset is placed in service.  When the ARO is initially recorded, the Company capitalizes the cost (asset retirement cost or "ARC") by increasing the carrying value of the related asset.  ARCs related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the net capitalized cost decreases over the useful life of the asset, as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation for valuing the full cost pool.

Business Combinations:  The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations.  Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values.  The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable.  The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill.  Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

Oil and Gas Sales:    The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties.  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 pro-rata interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and lease operating costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued 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 thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser.  Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:    The Company sells production to a small number of customers, as is customary in the industry.  As a result, during the three and nine month periods ended May 31, 2015 and 2014, certain of the Company's customers represented 10% or more of its oil and gas revenue ("major customers").  For the three months ended May 31, 2015, the Company had three major customers, which represented 58%, 15% and 10% of its revenue during the period. For the three months ended May 31, 2014, the Company had four major customers, which represented 45%, 13%, 12% and 12% of its revenue during the period. For the nine months ended May 31, 2015, the Company had two major customers, which represented 62% and 11% of its revenue during the period. For the nine months ended May 31, 2014, the Company had three major customers, which represented 45%, 15% and 10% of its revenue during the period.

Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions so warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company's existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners whom are liable for their proportionate share of well costs.  The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:

Major Customers	As of May 31, 2015			As of August 31, 2014
Company A		29	%		37	%
Company B		12	%		(1	)

⁽¹⁾ Balance was less than 10% of total receivable balances during the period.

Lease Operating Expenses:    Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or 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.

Stock-Based Compensation:    The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date, calculated using the Black-Scholes-Merton option pricing model.  The expense is recognized over the vesting period of the grant.  See Note 11 for additional information.

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 significant uncertain tax positions were identified as of any date on or before May 31, 2015.  The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of May 31, 2015, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Financial Instruments:    The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.  A substantial portion of the Company's financial instruments consist of cash and cash equivalents, short-term investments, accounts receivable, trade accounts payable, accrued expenses, and obligations under the revolving line of credit facility, all of which are considered to be representative of their fair value due to the short-term and highly liquid nature of these instruments.

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

As discussed in Note 5, the Company incurred asset retirement obligations during the periods presented, 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.

Commodity Derivative Instruments:    The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or "no premium" collars to reduce the effect of price changes on a portion of its future oil and gas production.  The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures.  The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7.

Earnings Per Share Amounts:    Basic earnings per share includes no dilution and is computed by dividing net income or loss by the weighted-average number of shares outstanding during the period.  Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company.  The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method.  Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.

The following table sets forth the share calculation of diluted earnings per share:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Weighted-average shares outstanding-basic		104,234,519		77,176,420		91,105,035		75,689,903
Potentially dilutive common shares from:
Stock options	Anti-dilutive			515,530	699,218			432,170
Warrants		-		1,316,669		-		1,177,383
		-		1,832,199		699,218		1,609,553
Weighted-average shares outstanding - diluted		104,234,519		79,008,619		91,804,253		77,299,456

As a result of the net loss reported for the three and nine months ended May 31, 2015, the calculation of basic and diluted Earnings per Share used the same number of weighted-average common shares outstanding in the denominator, as the inclusion of common share equivalents was anti-dilutive.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above; as such securities had an anti-dilutive effect on earnings per share:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Employee stock options		4,101,500		478,000		2,710,500		503,000

Recent Accounting Pronouncements:    We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03"), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. For public business entities, the ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years.  Entities should apply the new guidance on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.  Upon transition, entities are required to comply with the applicable disclosures for a change in an accounting principle.  The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

In January 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items" ("ASU 2015-01"), which eliminates from US GAAP the concept of extraordinary items, while retaining certain presentation and disclosure guidance for items that are unusual in nature or occur infrequently.  The standard is effective prospectively for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted provided the guidance is applied from the beginning of the fiscal year of adoption.  Adoption of ASU 2015-01 is not expected to have a material effect on the Company's financial position, results of operations, or cash flows.

In November 2014, the FASB issued Accounting Standards Update 2014-16, "Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity" ("ASU 2014-16"), which clarifies how to evaluate the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share.  Specifically, ASU 2014-16 requires that an entity consider all relevant terms and features in evaluating the nature of the host contract and clarifies that the nature of the host contract depends upon the economic characteristics and the risks of the entire hybrid financial instrument.  An entity should assess the substance of the relevant terms and features, including the relative strength of the debt-like or equity-like terms and features given the facts and circumstances, when considering how to weight those terms and features.  ASU 2014-16 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

In May 2014, the FASB issued Accounting Standards Update 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2016 including interim periods within that period. Early adoption is not permitted. The Company is currently evaluating which transition approach to use and the impact of the adoption of this standard on its consolidated financial statements.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's reported financial position, results of operations or cash flows.

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Property and Equipment and Full Cost Ceiling Impairment (Schedule of Capitalized Costs of Property And Equipment) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014	Aug. 31, 2014
Unproved properties, not subject to amortization:
Unproved properties, not subject to amortization	$ 170,639		$ 170,639		$ 95,278
Proved producing and non-producing properties:
Proved producing and non-producing properties	513,677		513,677		329,926
Total capitalized costs	684,316		684,316		425,204
Less, accumulated depletion	(103,101)		(103,101)		$ (54,908)
Less, ceiling test impairment	(3,000)		(3,000)
Oil and gas properties, net	578,215		578,215		$ 370,296
Other property and equipment:
Other property and equipment, gross	867		867		5,961
Less, accumulated depreciation	(534)		(534)		(755)
Other property and equipment, net	4,811		4,811		9,104
Property and equipment, net	583,026		583,026		379,400
Land [Member]
Other property and equipment:
Other property and equipment, gross	4,478		4,478		3,898
Lease acquisition and other costs [Member]
Unproved properties, not subject to amortization:
Unproved properties, not subject to amortization	139,012		139,012		41,531
Properties under development [Member]
Unproved properties, not subject to amortization:
Unproved properties, not subject to amortization	$ 31,627		$ 31,627		$ 53,747

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Organization and Summary of Significant Accounting Policies (Tables)

9 Months Ended

May. 31, 2015

Organization and Summary of Significant Accounting Policies [Abstract]

Schedule of Capitalized Overhead Expenses

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Capitalized Overhead	$	486	$	300	$	1,623	$	921

Schedule of Customers With Balances Greater Than 10% of Total Receivables

Major Customers	As of May 31, 2015			As of August 31, 2014
Company A		29	%		37	%
Company B		12	%		(1	)

Reconciliation of Weighted-average Shares Outstanding Basic and Diluted

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Weighted-average shares outstanding-basic		104,234,519		77,176,420		91,105,035		75,689,903
Potentially dilutive common shares from:
Stock options	Anti-dilutive			515,530	699,218			432,170
Warrants		-		1,316,669		-		1,177,383
		-		1,832,199		699,218		1,609,553
Weighted-average shares outstanding - diluted		104,234,519		79,008,619		91,804,253		77,299,456

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Employee stock options		4,101,500		478,000		2,710,500		503,000

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Property and Equipment and Full Cost Ceiling Impairment (Narrative) (Details) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	May. 31, 2015 USD ($) $ / shares	May. 31, 2014 USD ($)	May. 31, 2015 USD ($) $ / shares	May. 31, 2014 USD ($)	Aug. 31, 2014 USD ($)
Reserve Quantities [Line Items]
Price per unit, percentage change	16.00%		16.00%
Full cost ceiling impairment | $	$ 3,000		$ 3,000
Oil [Member]
Reserve Quantities [Line Items]
Price per unit	64.26		64.26
Natural Gas [Member]
Reserve Quantities [Line Items]
Price per unit	4.14		4.14

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Acquisitions (Tables)

9 Months Ended

May. 31, 2015

Business Acquisition [Line Items]

Schedule of Pro Forma Results

	Three Months Ended May 31,					Nine Months ended May 31,
	2015			2014		2015		2014
Oil and Gas Revenues	$	26,033		$	26,766	$	99,157	$	71,550
Net income	$	(2,481	)	$	6,889	$	25,102	$	17,997
Earnings per common share
Basic	$	(0.02	)	$	0.08	$	0.26	$	0.22
Diluted	$	(0.02	)	$	0.08	$	0.26	$	0.22

Trilogy Resources [Member]

Business Acquisition [Line Items]

Schedule of Fair Value of Acquisition

Purchase Price	November 12, 2013
Consideration Given
Cash	$	15,902
Synergy Resources Corp. Common Stock *		2,896
Total consideration given	$	18,798
Allocation of Purchase Price
Proved oil and gas properties	$	11,514
Unproved oil and gas properties	$	7,725
Total fair value of oil and gas properties acquired		19,239
Working capital	$	(83	)
Asset retirement obligation		(358	)
Fair value of net assets acquired	$	18,798
Working capital acquired was estimated as follows:
Accounts receivable		536
Accrued liabilities and expenses		(619	)
Total working capital	$	(83	)

*  The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)

Apollo Operating [Member]

Business Acquisition [Line Items]

Schedule of Fair Value of Acquisition

Purchase Price	November 13, 2013
Consideration Given
Cash	$	14,688
Synergy Resources Corp. Common Stock *		5,432
Total consideration given	$	20,120
Allocation of Purchase Price
Proved oil and gas properties	$	13,284
Unproved oil and gas properties	$	7,577
Total fair value of oil and gas properties acquired		20,861
Working capital	$	(507	)
Asset retirement obligation		(234	)
Fair value of net assets acquired	$	20,120
Working capital acquired was estimated as follows:
Accounts receivable		662
Accrued liabilities and expenses		(1,169	)
Total working capital	$	(507	)

* The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08).

Bayswater [Member]

Business Acquisition [Line Items]

Schedule of Fair Value of Acquisition

Purchase Price	December 15, 2014
Consideration Given
Cash	$	74,221
Synergy Resources Corp. Common Stock (1)		48,434
Liabilities assumed, including asset retirement obligations		2,467
Total consideration given	$	125,122
Allocation of Purchase Price
Proved oil and gas properties (2)	$	51,400
Unproved oil and gas properties		73,722
Total fair value of oil and gas properties acquired	$	125,122

(1)

The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 (4,648,136 shares at $10.42 per share).

(2)

Proved oil and gas properties were measured primarily using an income approach.  The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement.  The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 10%, and assumptions on the timing and amount of future development and operating costs.

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Property and Equipment and Full Cost Ceiling Impairment

9 Months Ended

May. 31, 2015

Property and Equipment and Full Cost Ceiling Impairment [Abstract]

Property and Equipment and Full Cost Ceiling Impairment

2. Property and Equipment and Ceiling Test Impairment

The capitalized costs related to the Company's oil and gas producing activities were as follows (in thousands):

	As of			As of
	May 31, 2015			August 31, 2014
Oil and gas properties, full cost method:
Unproved properties, not subject to amortization:
Lease acquisition and other costs	$	139,012		$	41,531
Properties under development		31,627			53,747
Subtotal		170,639			95,278
Proved producing and non-producing properties		513,677			329,926
Total capitalized costs		684,316			425,204
Less, accumulated depletion		(103,101	)		(54,908	)
Less, ceiling test impairment		(3,000	)		-
Oil and gas properties, net		578,215			370,296
Land		4,478			3,898
Other property and equipment		867			5,961
Less, accumulated depreciation		(534	)		(755	)
Other property and equipment, net		4,811			9,104
Total property and equipment, net	$	583,026		$	379,400

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value.

For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs.  Under the ceiling test, the value of the Company's reserves are calculated using the average of the published spot prices for West Texas Intermediate (WTI) oil (per barrel) as of the first day of each of the previous twelve months, as well as the average of the published spot prices for Henry Hub (per MMBtu) as of the first day of each of the previous twelve months, each adjusted by lease or field for quality, transportation fees and regional price differentials.  The ceiling test used realized prices of $64.26 per barrel and $4.14 per MMBtu.  The prices used at May 31, 2015, were approximately 16% lower than the prices used at February 28, 2015.

Using these prices, the Company's net capitalized costs of oil and natural gas properties exceeded the ceiling amount by $3.0 million at May 31, 2015, resulting in immediate recognition of a ceiling test impairment.

The Company also reviews the fair value of its unproved properties.  The reviews for the three months and nine months ended May 31, 2015 and 2014 indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment in either period.

In addition, during the nine months ended May 31, 2015, certain amounts previously recorded were reclassified from one category to another without changing the total amounts recorded as property and equipment.  Specifically, costs associated with the disposal well and related equipment were reclassified from other property and equipment into producing oil and gas properties to more closely reflect use of the disposal well to process flow-back water from oil and gas operations.  Similarly, accumulated depreciation associated with the disposal well was reclassified from accumulated depreciation to accumulated depletion.  The updated classification for the disposal well, related equipment, and accumulated depreciation did not require a change to previously reported depletion, depreciation, and amortization expense ("DDA").  Secondly, as discussed in Note 3, the analysis of assets acquired in the 2014 business combination transactions with Apollo and Trilogy was completed and fair values associated with probable horizontal well development were reclassified from proved properties into unproved properties.

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BALANCE SHEETS (Parenthetical) - $ / shares	May. 31, 2015	Aug. 31, 2014
BALANCE SHEETS [Abstract]
Preferred stock, par value per share	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value per share	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	105,025,453	77,999,082
Common stock, shares outstanding	105,025,453	77,999,082

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Related Party Transactions

9 Months Ended

May. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

12. Related Party Transactions

Whenever the Company engages in transactions with its officers, directors, or other related parties, the terms of the transaction are reviewed by the disinterested directors.  All transactions must be on terms no less favorable to the Company than similar transactions with unrelated parties.

Lease Agreement:  The Company leases its headquarters, a field office, and an equipment storage yard under a twelve month lease agreement with HS Land & Cattle, LLC ("HSLC").  HSLC is controlled by Ed Holloway and William Scaff, Jr., the Company's Co-Chief Executive Officers.  The current lease terminates on June 30, 2015.  Historically, the lease has been renewed annually.  Under this agreement, the Company incurred the following expenses to HSLC for the periods presented (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Rent expense	$	45	$	45	$	135	$	135

Revenue Distribution Processing:  Effective January 1, 2012, the Company commenced processing revenue distribution payments to all persons that own a mineral interest in wells that it operates.  Payments to mineral interest owners included payments to entities controlled by three of the Company's directors, Ed Holloway, William Scaff Jr, and George Seward.   The following table summarizes the royalty payments made to directors or their affiliates for the periods presented (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Total Royalty Payments	$	14	$	58	$	95	$	191

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Document and Entity Information - shares	9 Months Ended
	May. 31, 2015	Jul. 06, 2015
Document And Entity Information Abstract
Document Type	10-Q
Amendment Flag	false
Document Period End Date	May 31, 2015
Entity Registrant Name	SYNERGY RESOURCES CORP
Entity Central Index Key	0001413507
Current Fiscal Year End Date	--08-31
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2015
Entity Filer Category	Large Accelerated Filer
Entity Units Outstanding		105,025,453

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Other Commitments and Contingencies

9 Months Ended

May. 31, 2015

Other Commitments and Contingencies [Abstract]

Other Commitments and Contingencies

13. Other Commitments and Contingencies

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business.  It is the opinion of management that none of the current matters of contention are reasonably likely to have a material adverse impact on its business, financial position, results of operations or cash flows.

During the nine months ended May 31, 2015, the Company modified its contract drilling obligations with Ensign United States Drilling, Inc.  Two of the three rigs under contract fulfilled the terms of their contracts and were released, and one rig was contracted to continue drilling on a day-rate pricing basis.  The new contract has a term of less than one year.

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company owns a working interest (a "non-operated well").  The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs.  As of May 31, 2015, the Company was participating in the drilling and completion of 12 gross (0.7 net) new horizontal wells.  It is the Company's policy to accrue costs on a non-operated well when it receives notice that active drilling operations have commenced.  Accordingly, the May 31, 2015 financial statements include recorded costs of $3.6 million for these wells.

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STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014
STATEMENTS OF OPERATIONS [Abstract]
Oil and gas revenues	$ 26,033	$ 25,672	$ 92,284	$ 67,966
Expenses
Lease operating expenses	3,570	2,303	10,300	5,382
Production taxes	2,249	2,376	8,570	6,647
Depletion, depreciation, and amortization	16,397	$ 7,796	48,357	$ 21,106
Full cost ceiling impairment	3,000		3,000
General and administrative	3,886	$ 1,938	12,075	$ 6,876
Total expenses	29,102	14,413	82,302	40,011
Operating income (loss)	(3,069)	11,259	9,982	27,955
Other income (expense)
Commodity derivative realized gain (loss)	7,136	(826)	20,935	(1,415)
Commodity derivative unrealized (loss) gain	(8,298)	$ (179)	5,578	$ 652
Interest expense	(116)		(116)
Interest income	33	$ 22	61	$ 70
Total other income (expense)	(1,245)	(983)	26,458	(693)
Income (loss) before income taxes	(4,314)	10,276	36,440	27,262
Income tax provision (benefit)	(1,833)	3,116	13,118	8,841
Net income (loss)	$ (2,481)	$ 7,160	$ 23,322	$ 18,421
Net income (loss) per common share:
Basic	$ (0.02)	$ 0.09	$ 0.26	$ 0.24
Diluted	$ (0.02)	$ 0.09	$ 0.25	$ 0.24
Weighted-average shares outstanding:
Basic	104,234,519	77,176,420	91,105,035	75,689,903
Diluted	104,234,519	79,008,619	91,804,253	77,299,456

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Commodity Derivative Instruments

9 Months Ended

May. 31, 2015

Commodity Derivative Instruments [Abstract]

Commodity Derivative Instruments

7. Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below.  The Company has utilized swaps, puts or "no premium" collars to reduce the effect of price changes on a portion of its future oil and gas production.  A swap requires a payment to the counterparty if the settlement price exceeds the strike price and the same counterparty is required to make a payment if the settlement price is less than the strike price.  A collar requires a payment to the counterparty if the settlement price is above the ceiling price and requires the counterparty to make a payment if the settlement price is below the floor price.  The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk.  While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements.  The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.  The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  The Company's derivative contracts are currently with four counterparties.  Two of the counterparties are a participating lender in the Company's credit facility.  The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination.  The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

 

The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities.  Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments.  Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the statements of operations.  The Company's cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty.  Actual cash settlements can occur at either scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity.  These settlements under the commodity derivative contracts are reflected as operating activities in the Company's statements of cash flows.

The Company's valuation estimate takes into consideration the counterparty's creditworthiness, the Company's creditworthiness, and the time value of money.  The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view.  Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

 

The Company's commodity derivative contracts as of May 31, 2015 are summarized below:

Settlement Period	Derivative Instrument	Average Volumes(BBls/MMBtu per month)		AverageFixed Price		Floor Price		Celing Price
Crude Oil - NYMEX WTI
Jun 1, 2015 - Jun 30, 2015	Collar		2,500		-	$	80.00	$	95.75
Jun 1, 2015 - Dec 31, 2015	Put		40,000		-	$	50.00		-
Jun 1, 2015 - Oct 31, 2015	Put		5,200		-	$	50.00		-
Jun 1, 2015 - Dec 31, 2015	Put		10,000		-	$	55.00		-
Jan 1, 2016 - May 31, 2016	Collar		10,000		-	$	75.00	$	96.00
Jan 1, 2016 - May 31, 2016	Collar		5,000		-	$	80.00	$	100.75
Jun 1, 2016 - Aug 31, 2016	Collar		15,000		-	$	80.00	$	100.05
Jan 1, 2016  - Aug 31, 2016	Swap		5,000	$	88.55		-		-
Sep 1, 2016 - Dec 31, 2016	Swap		20,000	$	88.10		-		-
Jan 1, 2016  - Oct 31, 2016	Swap		6,400	$	78.96		-		-
Jan 1, 2016 - Dec 31, 2016	Put		25,000		-	$	50.00		-
Jan 1, 2017 - Apr 30, 2017	Put		20,000		-	$	50.00		-
May 1, 2017 - Aug 31, 2017	Put		20,000		-	$	55.00
Natural Gas - NYMEX Henry Hub
Jun 1, 2015 - Dec 31, 2015	Collar		72,000		-	$	4.15	$	4.49
Jan 1, 2016 - May 31, 2016	Collar		60,000		-	$	4.05	$	4.54
Jun 1, 2016 - Aug 31, 2016	Collar		60,000			$	3.90	$	4.14
Natural Gas - CIG Rocky Mountain
Jun 1, 2015 - Dec 31, 2015	Collar		100,000		-	$	2.20	$	3.05
Jan 1, 2016 - Dec 31, 2016	Collar		100,000		-	$	2.65	$	3.10
Jan 1, 2017 - Apr 30, 2017	Collar		100,000		-	$	2.80	$	3.95
May 1 2017 - Aug 31, 2017	Collar		110,000			$	2.50	$	3.05

Offsetting of Derivative Assets and Liabilities

As of May 31, 2015 and 2014, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions.  In general, the terms of the Company's agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency.  The Company's agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty.  The Company's accounting policy is to offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying balance sheets and the potential of master netting arrangements on the fair value of the Company's derivative contracts (in thousands):

		As of May 31, 2015
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	4,487	$	(219	)	$	4,268
Derivative contracts	Noncurrent assets	$	4,994	$	(379	)	$	4,615
Derivative contracts	Current liabilities	$	219	$	(219	)	$	-
Derivative contracts	Noncurrent liabilities	$	379	$	(379	)	$	-

		As of August 31, 2014
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	903	$	(538	)	$	365
Derivative contracts	Noncurrent assets	$	718	$	(664	)	$	54
Derivative contracts	Current liabilities	$	840	$	(538	)	$	302
Derivative contracts	Noncurrent liabilities	$	971	$	(664	)	$	307

The amount of gain (loss) recognized in the statements of operations related to derivative financial instruments was as follows (in thousands):

	Three Months EndedMay 31,						Nine Months endedMay 31,
	2015			2014			2015		2014
Realized gain (loss) on commodity derivatives	$	7,136		$	(826	)	$	20,935	$	(1,415
Unrealized gain (loss) on commodity derivatives		(8,298	)		(179	)		5,578		652
Total gain (loss)	$	(1,162	)	$	(1,005	)	$	26,513	$	(763

Realized gains and losses include cash received from the monthly settlement of hedge contracts at their scheduled maturity date along with the proceeds from early liquidation of in-the-money hedge contracts.  During the third quarter of 2015, the Company liquidated oil hedges with an average price of $80.61 and covering 188,500 barrels and received cash settlements of approximately $5.0 million.  The following table summarizes hedge realized gains and losses during the periods presented (in thousands):

	Three Months EndedMay 31,					Nine Months endedMay 31,
	2015		2014			2015		2014
Monthly settlement	$	2,100	$	(826	)	$	9,618	$	(1,415
Early liquidation		5,036		-			11,317		-
Total realized gain (loss)	$	7,136	$	(826	)	$	20,935	$	(1,415

Credit-Related Contingent Features

During the nine months ended May 31, 2015, the Company added a fourth counterparty to its derivative transactions.  The additional counterparty is a member of the Company's credit facility syndicate and the Company's obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company's producing oil and gas properties.

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Revolving Credit Facility

9 Months Ended

May. 31, 2015

Revolving Credit Facility [Abstract]

Revolving Credit Facility

6. Revolving Credit Facility

On December 15, 2014, simultaneously with the completion of the acquisition of certain oil and gas assets from Bayswater Exploration and Development, LLC, et. al., the Company amended its revolving credit facility ("LOC").  Under the amendment, the maximum loan commitment was increased to $500 million from $300 million and the borrowing base was increased to $230 million from $110 million.  The number of banks participating in the LOC increased to eight with SunTrust Bank as the Joint Lead Arranger / Administrative Agent and KeyBank, National Association as the Joint Lead Arranger / Syndication Agent.  The maturity date of the facility was extended to December 15, 2019.

Concurrent with the amendment, the Company increased its borrowings to approximately $146 million.  Proceeds from the additional borrowings were used to fund the Bayswater acquisition.

On June 2, 2015, the LOC was further amended in connection with the regularly scheduled semi-annual redetermination.  The borrowing base was reduced to $175 million and the covenant requiring maintenance of a minimum current ratio was replaced with a covenant requiring the maintenance of a minimum liquidity amount of $25,000,000.  On June 11, 2015, the Company reduced its outstanding borrowings under the LOC to $87 million.

 

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5%.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate ("LIBOR") plus a margin.  The interest rate margin, as well as other bank fees, varies with utilization of the LOC.  The average annual interest rate for borrowings during the three months and nine months ended May 31, 2015 was 2.5%.

Certain of the Company's assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the arrangement.  The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves.  The borrowing base limitation is subject to scheduled redeterminations on a semi-annual basis.  In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared.  As of July 1, 2015, based upon a borrowing base of $175 million and an outstanding principal balance of $87 million, the unused borrowing base available for future borrowing totaled approximately $88 million.  The next semi-annual redetermination is scheduled for November 2015.

The arrangement contains covenants that, among other things, restrict the payment of dividends.  In addition, the LOC generally requires an overall hedge position that covers a rolling 24 months of estimated future production with a minimum position of no less than 45% and a maximum position of no more than 85% of hydrocarbon production as projected in the semi-annual reserve report.

Furthermore, the LOC requires the Company to maintain certain financial and liquidity ratio compliance covenants.  Under the requirements, as most recently amended, the Company, on a quarterly basis, must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; and (b) maintain a minimum liquidity, defined as cash and cash equivalents plus the unused availability under the total commitments, of not less than $25 million.  As of May 31, 2015, the most recent compliance date, the Company was in compliance with all loan covenants.

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Property and Equipment and Full Cost Ceiling Impairment (Tables)

9 Months Ended

May. 31, 2015

Property and Equipment and Full Cost Ceiling Impairment [Abstract]

Schedule of Capitalized Costs of Property and Equipment

	As of			As of
	May 31, 2015			August 31, 2014
Oil and gas properties, full cost method:
Unproved properties, not subject to amortization:
Lease acquisition and other costs	$	139,012		$	41,531
Properties under development		31,627			53,747
Subtotal		170,639			95,278
Proved producing and non-producing properties		513,677			329,926
Total capitalized costs		684,316			425,204
Less, accumulated depletion		(103,101	)		(54,908	)
Less, ceiling test impairment		(3,000	)		-
Oil and gas properties, net		578,215			370,296
Land		4,478			3,898
Other property and equipment		867			5,961
Less, accumulated depreciation		(534	)		(755	)
Other property and equipment, net		4,811			9,104
Total property and equipment, net	$	583,026		$	379,400

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Supplemental Schedule of Information to the Statements of Cash Flows

9 Months Ended

May. 31, 2015

Supplemental Schedule of Information to the Statements of Cash Flows [Abstract]

Supplemental Schedule of Information to the Statements of Cash Flows

14. Supplemental Schedule of Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the financial statements for the nine months ended May 31, 2015 and 2014 (in thousands):

	Nine Months Ended
	May 31,
	2015		2014
Supplemental cash flow information:
Interest paid	$	2,200	$	750
Income taxes paid		110		-
Non-cash investing and financing activities:
Accrued well costs	$	26,491	$	47,489
Assets acquired in exchange for common stock		58,968		11,185
Asset retirement costs and obligations		2,657		1,367

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Shareholders' Equity

9 Months Ended

May. 31, 2015

Shareholders' Equity [Abstract]

Shareholders' Equity

10. Shareholders' Equity

The Company's classes of stock are summarized as follows:

	As of May 31,		As of August 31,
	2015		2014
Preferred stock, shares authorized		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding		nil		nil
Common stock, shares authorized		200,000,000		200,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding		105,025,453		77,999,082

Stock Offering

During the nine months ended May 31, 2015, the Company completed a public offering of 18,613,952 shares of its common stock at a price to the public of $10.75 per share.  On February 2, 2015, the Company received net proceeds of approximately $190.8 million after deducting underwriting discounts, commissions and other offering expenses.

Common stock issued for acquisition of mineral property interests

During the nine months ended May 31, 2015 the Company issued shares of common stock in exchange for mineral property interests.  The value of each transaction was determined using the market price of the Company's common stock on the date of each transaction.

	For the nine months ended May 31, 2015
Number of common shares issued for mineral property leases		995,672
Number of common shares issued for acquisitions		4,648,136
Total common shares issued		5,643,808
Average price per common share	$	10.45
Aggregate value of shares issued (in thousands)	$	58,968

Common stock warrants

During the nine months ended May 31, 2015, holders exercised outstanding warrants to purchase 2,562,473 shares of common stock.  The Company received cash proceeds of $15.4 million.  The following table summarizes activity for common stock warrants for the nine month period ended May 31, 2015:

	Number of Warrants			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,562,473		$	6.00
Granted		-		$	-
Exercised		(2,562,473	)	$	6.00
Expired		-		$	-
Outstanding, May 31, 2015		-		$	-

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Fair Value Measurements

9 Months Ended

May. 31, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

8. Fair Value Measurements

ASC Topic 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

• Level 1: Quoted prices available in active markets for identical assets or liabilities;

• Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

• Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company's non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company's credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.  See Note 5 for additional information.

The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using primarily unobservable inputs.  Inputs are reviewed by management on an annual basis. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs. See Note 3 for additional information.

 

The following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of May 31, 2015 and August 31, 2014 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at May 31, 2015
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	8,883	$	-	$	8,883
Commodity derivative liability	$	-	$	-	$	-	$	-

	Fair Value Measurements at August 31, 2014
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	419	$	-	$	419
Commodity derivative liability	$	-	$	609	$	-	$	609

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company's own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers the counterparty to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At May 31, 2015, derivative instruments utilized by the Company consist of puts, "no premium" collars and swaps. The crude oil and natural gas derivative markets are highly active. Although the Company's derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities.  The carrying amount of the Company's credit facility approximated fair value as it bears interest at variable rates over the term of the loan.

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Interest Expense

9 Months Ended

May. 31, 2015

Interest Expense [Abstract]

Interest Expense

9. Interest Expense

The components of interest expense are (in thousands):

	Three Months Ended May 31,						Nine Months Ended May 31,
	2015			2014			2015			2014
Revolving credit facility	$	915		$	252		$	2,191		$	749
Amortization of debt issuance costs		252			118			607			312
Less, interest capitalized		(1,051	)		(370	)		(2,682	)		(1,061
Interest expense, net	$	116		$	-		$	116		$	-

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Stock-Based Compensation

9 Months Ended

May. 31, 2015

Stock-Based Compensation [Abstract]

Stock-Based Compensation

11. Stock-Based Compensation

In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity-based compensation in the form of stock options, restricted stock grants, and warrants.  The Company records an expense related to equity compensation by pro-rating the estimated fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company's common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model.  For the periods presented, all stock-based compensation was classified as a component within general and administrative expense on the statement of operations.

The amount of stock-based compensation expense is as follows (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Stock options	$	715	$	445	$	1,792	$	1,312
Employee stock grants		686		257		1,538		257
	$	1,401	$	702	$	3,330	$	1,569

 

During the three and nine months ended May 31, 2015 and 2014, the Company granted the following employee stock options:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Number of options to purchase common shares		1,892,500		90,000		2,302,500		353,000
Weighted-average exercise price	$	11.57	$	10.51	$	11.64	$	9.92
Term (in years)		10.0		10.0		10.0		10.0
Vesting Period (in years)		5		5		5		5
Fair Value (in thousands)	$	10,500	$	633	$	12,940	$	2,362

The assumptions used in valuing stock options granted during each of the nine months presented were as follows:

	Nine Months Ended May 31,
	2015			2014
Expected term	6.5 years			6.5 years
Expected volatility		47	%		73	%
Risk free rate		1.77	%		1.97% - 2.02	%
Expected dividend yield		0.00	%		0.00	%
Forfeiture rate		3.3	%		0.00	%

The following table summarizes activity for stock options for the nine months ended May 31, 2015:

	Number of Shares			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,167,000		$	5.94
Granted		2,302,500		$	11.64
Exercised		(258,000	)	$	3.81
Forfeited		(110,000	)		(4.97
Outstanding, May 31, 2015		4,101,500		$	9.30

The following table summarizes information about issued and outstanding stock options as of May 31, 2015:

	Outstanding Options		Vested Options
Number of shares		4,101,500		888,100
Weighted-average remaining contractual life		8.8 years		6.9 years
Weighted-average exercise price		$9.30		$5.34
Aggregate intrinsic value (in thousands)		$9,547		$5,480

The estimated unrecognized compensation cost from unvested stock options as of May 31, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at May 31, 2015
Unrecognized compensation expense (in thousands)	$15,038
Remaining vesting phase	4.3 years

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Organization and Summary of Significant Accounting Policies (Earnings Per Share) (Details) - shares	3 Months Ended		9 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average shares outstanding - basic	104,234,519	77,176,420	91,105,035	75,689,903
Potentially dilutive common shares from:
Potentially dilutive common shares		1,832,199	699,218	1,609,553
Weighted-average shares outstanding - diluted	104,234,519	79,008,619	91,804,253	77,299,456
Potentially dilutive common shares having anti-dilutive effect on earnings per share	4,101,500	478,000	2,710,500	503,000
Warrant [Member]
Potentially dilutive common shares from:
Warrants		1,316,669		1,177,383
Stock Options [Member]
Potentially dilutive common shares from:
Stock options		515,530	699,218	432,170

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Shareholders' Equity (Common Stock Warrants) (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	May. 31, 2015	May. 31, 2014
Class of Warrant or Right [Line Items]
Outstanding, August 31, 2014	2,562,473
Granted
Exercised	(2,562,473)
Expired
Outstanding, May 31, 2015
Weighted average exercise price, August 31, 2014	$ 6.00
Weighted average exercise price, granted
Weighted average exercise price, exercised	$ 6.00
Weighted average exercise price, expired
Weighted average exercise price, May 31, 2015
Proceeds from exercise of warrants	$ 15,367	$ 33,380

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Organization and Summary of Significant Accounting Policies (Policies)

9 Months Ended

May. 31, 2015

Organization and Summary of Significant Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation:    The Company has adopted August 31^st as the end of its fiscal year.  The Company does not utilize any special purpose entities.  The Company operates in one business segment and all of its operations are located in the United States of America.

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial information.

Interim Financial Information

Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  The balance sheet as of August 31, 2014 was derived from the Company's Annual Report on Form 10-K for the year ended August 31, 2014.  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, 2014.

In management's opinion, the unaudited financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

Reclassifications

Reclassifications:    Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation.  The reclassifications had no effect on net income, working capital or equity previously reported.

Use of Estimates

Use of Estimates:     The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves and goodwill, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain.  Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  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 these estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents:    The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Oil and Gas Properties

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, 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 properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs of oil and gas properties are depleted using the units-of-production method based upon estimates of proved reserves.  For depletion purposes, the volume of petroleum 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.

Properties under development represent the costs associated with the development of oil and gas properties that have yet to be proved as of May 31, 2015.  Since the properties were not classified as proved as of May 31, 2015, they were classified within unproved oil and gas properties and were withheld from the depletion calculation and ceiling test.  The costs for these properties will be transferred into proved properties when they are proved and will become subject to depletion and the ceiling test calculation in subsequent periods.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is an impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the book value of oil and gas properties.  The capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion, depreciation, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unproved properties not being amortized, plus the lower of cost or estimated fair value of unproven properties being amortized.  Prices are held constant for the productive life of each well.  Net cash flows are discounted at 10%.  If net capitalized costs exceed this limit, the excess is charged to expense.  The calculation of future net cash flows assumes continuation of current economic conditions.  Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials.

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.

The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of the Company's oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest

Capitalized Interest:    The Company capitalizes interest on expenditures made in connection with acquisition of mineral interests and development projects that are not subject to current amortization.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 9 for additional information.

Capitalized Overhead

Capitalized Overhead:    A portion of the Company's overhead expenses are directly attributable to acquisition and development activities.  Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands):

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Capitalized Overhead	$	486	$	300	$	1,623	$	921

Well Costs Payable

Well Costs Payable:    The costs of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings ("JIB").  For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the authorization for expenditure.

Other Property and Equipment

Other Property and 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.

Asset Retirement Obligations

Asset Retirement Obligations:    The Company's activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company's credit adjusted risk-free interest rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed or an asset is placed in service.  When the ARO is initially recorded, the Company capitalizes the cost (asset retirement cost or "ARC") by increasing the carrying value of the related asset.  ARCs related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the net capitalized cost decreases over the useful life of the asset, as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation for valuing the full cost pool.

Business Combinations

Business Combinations:  The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations.  Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values.  The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable.  The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill.  Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

Oil and Gas Sales

Oil and Gas Sales:    The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties.  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 pro-rata interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and lease operating costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued 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 thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser.  Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers

Major Customers:    The Company sells production to a small number of customers, as is customary in the industry.  As a result, during the three and nine month periods ended May 31, 2015 and 2014, certain of the Company's customers represented 10% or more of its oil and gas revenue ("major customers").  For the three months ended May 31, 2015, the Company had three major customers, which represented 58%, 15% and 10% of its revenue during the period. For the three months ended May 31, 2014, the Company had four major customers, which represented 45%, 13%, 12% and 12% of its revenue during the period. For the nine months ended May 31, 2015, the Company had two major customers, which represented 62% and 11% of its revenue during the period. For the nine months ended May 31, 2014, the Company had three major customers, which represented 45%, 15% and 10% of its revenue during the period.

Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions so warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company's existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners whom are liable for their proportionate share of well costs.  The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:

Major Customers	As of May 31, 2015			As of August 31, 2014
Company A		29	%		37	%
Company B		12	%		(1	)

⁽¹⁾ Balance was less than 10% of total receivable balances during the period.

Lease Operating Expenses

Lease Operating Expenses:    Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or 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.

Stock-Based Compensation

Stock-Based Compensation:    The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date, calculated using the Black-Scholes-Merton option pricing model.  The expense is recognized over the vesting period of the grant.  See Note 11 for additional information.

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 significant uncertain tax positions were identified as of any date on or before May 31, 2015.  The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of May 31, 2015, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Financial Instruments

Financial Instruments:    The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.  A substantial portion of the Company's financial instruments consist of cash and cash equivalents, short-term investments, accounts receivable, trade accounts payable, accrued expenses, and obligations under the revolving line of credit facility, all of which are considered to be representative of their fair value due to the short-term and highly liquid nature of these instruments.

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

As discussed in Note 5, the Company incurred asset retirement obligations during the periods presented, 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.

Commodity Derivative Instruments

Commodity Derivative Instruments:    The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or "no premium" collars to reduce the effect of price changes on a portion of its future oil and gas production.  The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures.  The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7.

Earnings Per Share Amounts

Earnings Per Share Amounts:    Basic earnings per share includes no dilution and is computed by dividing net income or loss by the weighted-average number of shares outstanding during the period.  Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company.  The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method.  Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.

The following table sets forth the share calculation of diluted earnings per share:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Weighted-average shares outstanding-basic		104,234,519		77,176,420		91,105,035		75,689,903
Potentially dilutive common shares from:
Stock options	Anti-dilutive			515,530	699,218			432,170
Warrants		-		1,316,669		-		1,177,383
		-		1,832,199		699,218		1,609,553
Weighted-average shares outstanding - diluted		104,234,519		79,008,619		91,804,253		77,299,456

As a result of the net loss reported for the three and nine months ended May 31, 2015, the calculation of basic and diluted Earnings per Share used the same number of weighted-average common shares outstanding in the denominator, as the inclusion of common share equivalents was anti-dilutive.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above; as such securities had an anti-dilutive effect on earnings per share:

	Three Months Ended May 31,				Nine Months Ended May 31,
	2015		2014		2015		2014
Employee stock options		4,101,500		478,000		2,710,500		503,000

Recent Accounting Pronouncements

Recent Accounting Pronouncements:    We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03"), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. For public business entities, the ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years.  Entities should apply the new guidance on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.  Upon transition, entities are required to comply with the applicable disclosures for a change in an accounting principle.  The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

In January 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items" ("ASU 2015-01"), which eliminates from US GAAP the concept of extraordinary items, while retaining certain presentation and disclosure guidance for items that are unusual in nature or occur infrequently.  The standard is effective prospectively for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted provided the guidance is applied from the beginning of the fiscal year of adoption.  Adoption of ASU 2015-01 is not expected to have a material effect on the Company's financial position, results of operations, or cash flows.

In November 2014, the FASB issued Accounting Standards Update 2014-16, "Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity" ("ASU 2014-16"), which clarifies how to evaluate the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share.  Specifically, ASU 2014-16 requires that an entity consider all relevant terms and features in evaluating the nature of the host contract and clarifies that the nature of the host contract depends upon the economic characteristics and the risks of the entire hybrid financial instrument.  An entity should assess the substance of the relevant terms and features, including the relative strength of the debt-like or equity-like terms and features given the facts and circumstances, when considering how to weight those terms and features.  ASU 2014-16 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

In May 2014, the FASB issued Accounting Standards Update 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2016 including interim periods within that period. Early adoption is not permitted. The Company is currently evaluating which transition approach to use and the impact of the adoption of this standard on its consolidated financial statements.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's reported financial position, results of operations or cash flows.

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Asset Retirement Obligations (Tables)

9 Months Ended

May. 31, 2015

Asset Retirement Obligations [Abstract]

Schedule of Fair Value Assumptions

	For The Nine Months Ended May 31,
	2015		2014
Inflation rate		3.9%		3.9 - 4.0%
Estimated asset life		25.0 - 39.0 years		20.0 - 40.0 years
Credit adjusted risk free interest rate		8.0%		8.0%

Schedule of Asset Retirement Obligations

Asset retirement obligations, August 31, 2014	$	4,730
Liabilities incurred		744
Liabilities assumed		1,913
Accretion expense		385
Asset retirement obligations, May 31, 2015	$	7,772

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Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	May. 31, 2015	May. 31, 2014	May. 31, 2015	May. 31, 2014
Interest Expense [Abstract]
Revolving credit facility	$ 915	$ 252	$ 2,191	$ 749
Amortization of debt issuance costs	252	118	607	312
Less, interest capitalized	(1,051)	$ (370)	(2,682)	$ (1,061)
Interest expense, net	$ 116		$ 116

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Asset Retirement Obligations (Schedule of Fair Value Assumptions) (Details)	9 Months Ended
	May. 31, 2015	May. 31, 2014
Inflation rate	3.90%
Credit adjusted risk free interest rate	8.00%	8.00%
Minimum [Member]
Inflation rate		3.90%
Estimated asset life	25 years	20 years
Maximum [Member]
Inflation rate		4.00%
Estimated asset life	39 years	40 years

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STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	May. 31, 2015	May. 31, 2014
Cash flows from operating activities:
Net income	$ 23,322	$ 18,421
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization	48,357	$ 21,106
Full cost ceiling impairment	3,000
Provision for deferred taxes	13,118	$ 8,841
Stock-based compensation	3,330	1,569
Valuation increase in commodity derivatives	(5,578)	(652)
Accounts receivable
Oil and gas sales	2,193	(7,505)
Joint interest billing and other	(3,089)	$ (4,037)
Unamortized premiums paid for derivatives	$ (3,494)
Inventory		$ (211)
Accounts payable
Trade	$ (720)	188
Revenue	4,299	3,448
Production taxes	2,744	4,707
Accrued expenses	(360)	49
Other	(180)	821
Total adjustments	63,620	28,324
Net cash provided by operating activities	86,942	46,745
Cash flows from investing activities:
Acquisition of property and equipment	$ (241,903)	(112,155)
Short-term investments		60,018
Net proceeds from sales of oil and gas properties	$ 3,696	704
Net cash used in investing activities	(238,207)	$ (51,433)
Cash flows from financing activities:
Cash proceeds from sale of stock	200,100
Stock offering costs	(9,255)
Proceeds from exercise of warrants	15,367	$ 33,380
Gross proceeds from revolving credit facility	104,000
Finance fee for revolving credit facility	(2,300)
Shares withheld for payment of employee payroll taxes	(1,195)	$ (176)
Net cash provided by financing activities	306,717	33,204
Net increase in cash and cash equivalents	155,452	28,516
Cash and cash equivalents at beginning of period	34,753	19,463
Cash and cash equivalents at end of period	$ 190,205	$ 47,979

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Asset Retirement Obligations

9 Months Ended

May. 31, 2015

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

5. Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to their original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost.  For the purpose of determining the fair value of ARO incurred during the periods, the Company used the following assumptions:

	For The Nine Months Ended May 31,
	2015		2014
Inflation rate		3.9%		3.9 - 4.0%
Estimated asset life		25.0 - 39.0 years		20.0 - 40.0 years
Credit adjusted risk free interest rate		8.0%		8.0%

The following table summarizes the change in asset retirement obligations associated with the Company's oil and gas properties (in thousands):

Asset retirement obligations, August 31, 2014	$	4,730
Liabilities incurred		744
Liabilities assumed		1,913
Accretion expense		385
Asset retirement obligations, May 31, 2015	$	7,772

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Commodity Derivative Instruments (Tables)

9 Months Ended

May. 31, 2015

Commodity Derivative Instruments [Abstract]

Schedule of Commodity Derivative Contracts

Settlement Period	Derivative Instrument	Average Volumes(BBls/MMBtu per month)		AverageFixed Price		Floor Price		Celing Price
Crude Oil - NYMEX WTI
Jun 1, 2015 - Jun 30, 2015	Collar		2,500		-	$	80.00	$	95.75
Jun 1, 2015 - Dec 31, 2015	Put		40,000		-	$	50.00		-
Jun 1, 2015 - Oct 31, 2015	Put		5,200		-	$	50.00		-
Jun 1, 2015 - Dec 31, 2015	Put		10,000		-	$	55.00		-
Jan 1, 2016 - May 31, 2016	Collar		10,000		-	$	75.00	$	96.00
Jan 1, 2016 - May 31, 2016	Collar		5,000		-	$	80.00	$	100.75
Jun 1, 2016 - Aug 31, 2016	Collar		15,000		-	$	80.00	$	100.05
Jan 1, 2016  - Aug 31, 2016	Swap		5,000	$	88.55		-		-
Sep 1, 2016 - Dec 31, 2016	Swap		20,000	$	88.10		-		-
Jan 1, 2016  - Oct 31, 2016	Swap		6,400	$	78.96		-		-
Jan 1, 2016 - Dec 31, 2016	Put		25,000		-	$	50.00		-
Jan 1, 2017 - Apr 30, 2017	Put		20,000		-	$	50.00		-
May 1, 2017 - Aug 31, 2017	Put		20,000		-	$	55.00
Natural Gas - NYMEX Henry Hub
Jun 1, 2015 - Dec 31, 2015	Collar		72,000		-	$	4.15	$	4.49
Jan 1, 2016 - May 31, 2016	Collar		60,000		-	$	4.05	$	4.54
Jun 1, 2016 - Aug 31, 2016	Collar		60,000			$	3.90	$	4.14
Natural Gas - CIG Rocky Mountain
Jun 1, 2015 - Dec 31, 2015	Collar		100,000		-	$	2.20	$	3.05
Jan 1, 2016 - Dec 31, 2016	Collar		100,000		-	$	2.65	$	3.10
Jan 1, 2017 - Apr 30, 2017	Collar		100,000		-	$	2.80	$	3.95
May 1 2017 - Aug 31, 2017	Collar		110,000			$	2.50	$	3.05

Schedule of Fair Value of Derivatives

		As of May 31, 2015
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	4,487	$	(219	)	$	4,268
Derivative contracts	Noncurrent assets	$	4,994	$	(379	)	$	4,615
Derivative contracts	Current liabilities	$	219	$	(219	)	$	-
Derivative contracts	Noncurrent liabilities	$	379	$	(379	)	$	-

		As of August 31, 2014
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	903	$	(538	)	$	365
Derivative contracts	Noncurrent assets	$	718	$	(664	)	$	54
Derivative contracts	Current liabilities	$	840	$	(538	)	$	302
Derivative contracts	Noncurrent liabilities	$	971	$	(664	)	$	307

Schedule of Gain (Loss) Recognized in Statements of Operations

	Three Months EndedMay 31,						Nine Months endedMay 31,
	2015			2014			2015		2014
Realized gain (loss) on commodity derivatives	$	7,136		$	(826	)	$	20,935	$	(1,415
Unrealized gain (loss) on commodity derivatives		(8,298	)		(179	)		5,578		652
Total gain (loss)	$	(1,162	)	$	(1,005	)	$	26,513	$	(763

Schedule of Hedge Realized Gains (Losses)

	Three Months EndedMay 31,					Nine Months endedMay 31,
	2015		2014			2015		2014
Monthly settlement	$	2,100	$	(826	)	$	9,618	$	(1,415
Early liquidation		5,036		-			11,317		-
Total realized gain (loss)	$	7,136	$	(826	)	$	20,935	$	(1,415

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Acquisitions (Schedule of Fair Value of Acquisition) (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended					9 Months Ended
		Dec. 15, 2014	Nov. 30, 2013	Nov. 13, 2013	Nov. 12, 2013	Aug. 27, 2013	May. 31, 2015	May. 31, 2014
Working capital acquired was estimated as follows:
Business acquisition, shares issued							4,648,136
Discount rate							8.00%	8.00%
Trilogy Resources [Member]
Preliminary Purchase Price
Cash					$ 15,902
Synergy Resources Corp. Common Stock	[1]				2,896
Total consideration given					18,798
Preliminary Allocation of Purchase Price
Proved oil and gas properties					11,514
Unproved oil and gas properties					7,725
Total fair value of oil and gas properties acquired					19,239
Working capital					(83)
Asset retirement obligation					(358)
Fair value of net assets acquired					18,798
Working capital acquired was estimated as follows:
Accounts receivable					536
Accrued liabilities and expenses					(619)
Total working capital					$ (83)
Business acquisition, shares issued					301,339
Closing stock price					$ 9.61
Apollo Operating [Member]
Preliminary Purchase Price
Cash			$ 3,700	$ 14,688		$ 11,000
Synergy Resources Corp. Common Stock	[2]			5,432
Total consideration given				20,120
Preliminary Allocation of Purchase Price
Proved oil and gas properties				13,284
Unproved oil and gas properties				7,577
Total fair value of oil and gas properties acquired				20,861
Working capital				(507)
Asset retirement obligation				(234)
Fair value of net assets acquired				20,120
Working capital acquired was estimated as follows:
Accounts receivable				662
Accrued liabilities and expenses				(1,169)
Total working capital				$ (507)
Business acquisition, shares issued			20,626	550,518
Closing stock price			$ 10.08	$ 9.49
Bayswater [Member]
Preliminary Purchase Price
Cash		$ 74,221
Synergy Resources Corp. Common Stock	[3]	48,434
Liabilities assumed, including asset retirement obligations		2,467
Total consideration given		125,122
Preliminary Allocation of Purchase Price
Proved oil and gas properties	[4]	51,400
Unproved oil and gas properties		73,722
Total fair value of oil and gas properties acquired		$ 125,122
Working capital acquired was estimated as follows:
Business acquisition, shares issued		4,648,136
Closing stock price		$ 10.42
Discount rate		10.00%

[1] The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)

[2] The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08).

[3] The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 (4,648,136 shares at $10.42 per share).

[4] Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 10%, and assumptions on the timing and amount of future development and operating costs.

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Subsequent Events

9 Months Ended

May. 31, 2015

Subsequent Events [Abstract]

Subsequent Events

15. Subsequent Events

Subsequent to May 31, 2015, the Company repaid $54 million in outstanding borrowings, bringing the total outstanding principal balance on its LOC from $141 million at May 31, 2015 to $87 million at July 1, 2015.