SRC Energy Inc. - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - SRC Energy Inc.	Financial_Report.xls
EX-32 - EXHIBIT 32 - SRC Energy Inc.	ex32.htm
EX-31.2 - EXHIBIT 31.2 - SRC Energy Inc.	ex31x2.htm
EX-31.1 - EXHIBIT 31.1 - SRC Energy Inc.	ex31x1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended May 31, 2012

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

Commission File Number: 001-35245

SYNERGY RESOURCES CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Colorado		20-2835920
(State 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

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 x No o

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 x No o

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.

	Larger accelerated filer o	Accelerated filer x
	Non-accelerated filer o	Smaller reporting company o

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

The number of common shares outstanding as of June 29, 2012: 51,409,340.

SYNERGY RESOURCES CORPORATION

FORM 10-Q

Index

		Page
Part I – FINANCIAL INFORMATION

Item 1.	Financial Statements

	Balance Sheets as of May 31, 2012 (unaudited) and August 31, 2011	3

	Statements of Operations for the three months and nine months ended May 31, 2012 and May 31, 2011 (unaudited)	4

	Statements of Cash Flows for the nine months ended May 31, 2012 and May 31, 2011 (unaudited)	5

	Notes to Financial Statements (unaudited)	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	33

Part II - OTHER INFORMATION

Item 6.	Exhibits	33

SIGNATURES		34

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

	As of			As of
	May 31,			August 31,
	2012			2011
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	27,764,540		$	9,490,506
Accounts receivable:
Oil and gas sales		3,032,602			2,185,051
Joint interest billing		3,084,476			2,406,473
Inventory		192,985			459,592
Other current assets		38,388			89,336
Total current assets		34,112,991			14,630,958

Property and equipment:
Oil and gas properties, full cost method, net		80,703,025			48,614,857
Other property and equipment, net		298,735			283,207
Property and equipment, net		81,001,760			48,898,064

Deferred tax asset, net		1,809,000			—
Other assets		236,524			168,863

Total assets	$	117,160,275		$	63,697,885

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade	$	606,790		$	1,653,193
Well costs		5,877,714			4,967,368
Revenue payable and other accrued expenses		7,744,661			2,125,852
Notes payable, related party		—			5,200,000
Total current liabilities		14,229,165			13,946,413

Revolving credit facility		3,000,000			—
Asset retirement obligations		916,258			643,459
Total liabilities		18,145,423			14,589,872

Commitments and contingencies (See Note 10)

Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding		—			—
Common stock - $0.001 par value, 100,000,000 shares authorized:
51,409,340 and 36,098,212 shares issued and outstanding
as of May 31, 2012 and August 31, 2011, respectively		51,409			36,098
Additional paid-in capital		123,726,382			84,011,496
Accumulated deficit		(24,762,939	)		(34,939,581	)
Total shareholders' equity		99,014,852			49,108,013

Total liabilities and shareholders' equity	$	117,160,275		$	63,697,885

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

SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended							Nine Months Ended
		May 31,			May 31,			May 31,		May 31,
		2012			2011			2012		2011

Revenues:
Oil and gas revenues		$	7,521,833		$	2,921,910		$	18,219,672	$	6,399,193
Total revenues			7,521,833			2,921,910			18,219,672		6,399,193

Expenses:
Lease operating expenses			1,159,472			668,683			2,720,206		1,131,837
Depletion, depreciation and amortization			1,833,506			830,639			4,599,585		2,062,825
General and administrative			682,412			875,316			2,559,250		1,960,006
Total expenses			3,675,390			2,374,638			9,879,041		5,154,668

Operating income			3,846,443			547,272			8,340,631		1,244,525

Other income (expense):
Change in fair value of derivative conversion liability			—			86,192			—		(10,229,229	)
Interest expense, net			—			(950,860	)		—		(4,246,945	)
Interest income			16,320			25,784			27,011		41,675
Total other income (expense)			16,320			(838,884	)		27,011		(14,434,499	)

Income (loss) before income taxes			3,862,763			(291,612	)		8,367,642		(13,189,974	)

Income tax (expense) benefit			(1,432,000	)		—			1,809,000		—
Net income (loss)		$	2,430,763		$	(291,612	)	$	10,176,642	$	(13,189,974	)

Net income (loss) per common share:
Basic		$	0.05		$	(0.01	)	$	0.23	$	(0.58	)
Diluted		$	0.05		$	(0.01	)	$	0.22	$	(0.58	)

Weighted average shares outstanding:
Basic			51,292,810			32,813,298			44,968,566		22,713,785
Diluted			53,174,792			32,813,298			46,775,994		22,713,785

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

SYNERGY RESOURCES CORPORATION

STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended
	May 31, 2012			May 31, 2011

Cash flows from operating activities:
Net income (loss)	$	10,176,642		$	(13,189,974	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation and amortization		4,599,585			2,062,825
Amortization of debt issuance cost		—			1,587,799
Accretion of debt discount		—			2,664,138
Provision for deferred taxes		(1,809,000	)		—
Stock-based compensation		323,032			563,518
Change in fair value of derivative liability		—			10,229,229
Changes in operating assets and liabilities:
Accounts receivable		(1,525,554	)		(1,915,218	)
Inventory		266,607			(318,878	)
Accounts payable		(1,046,402	)		1,275,804
Accrued expenses		6,109,812			875,636
Other		(16,713	)		(9,997	)
Total adjustments		6,901,367			17,014,856
Net cash provided by operating activities		17,078,009			3,824,882

Cash flows from investing activities:
Acquisition of property and equipment		(34,025,758	)		(21,163,392	)
Proceeds from sales of oil and gas properties		—			4,995,817
Net cash used in investing activities		(34,025,758	)		(16,167,575	)

Cash flows from financing activities:
Cash proceeds from sale of stock		40,249,998			18,000,000
Offering costs		(2,828,215	)		(1,309,279	)
Net proceeds from/(repayments of) revolving credit facility		3,000,000			—
Principal repayment of related party notes payable		(5,200,000	)		—
Net cash provided by financing activities		35,221,783			16,690,721

Net increase in cash and equivalents		18,274,034			4,348,028

Cash and equivalents at beginning of period		9,490,506			6,748,637

Cash and equivalents at end of period	$	27,764,540		$	11,096,665

Supplemental Cash Flow Information (See Note 12)

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

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

1. Organization and Summary of Significant Accounting Policies

Organization: Synergy Resources Corporation (“the Company”) is engaged in oil and gas acquisitions, exploration, development and production activities, primarily in the Denver-Julesburg Basin of Colorado.

Basis of Presentation: The Company’s fiscal year end is August 31st. The Company does not utilize any special purpose entities.

At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

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 United States Securities and Exchange Commission (“SEC”). 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, 2011.

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 loss, 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 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. 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.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

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 expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas 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 unit-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 unevaluated 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.

Under the full cost method of accounting, capitalized costs are subject to an impairment test known as a ceiling test. For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, cannot exceed an amount (the cost center ceiling) equal to the sum of i) the present value of estimated future net cash flows from proved oil and gas reserves, computed by applying current prices, as defined, to estimated future production, less estimated future expenditures to be incurred in developing and producing the proved reserves using a discount factor of 10 percent and assuming continuation of existing economic conditions; plus ii) the cost of properties not being amortized; plus iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; less d) income tax effects related to differences between the future net revenues and value and the tax bases of the related assets. If amounts recorded as capitalized costs, less accumulated amortization and related deferred income taxes, exceed the cost center ceiling, the excess is considered an impairment that is immediately charged to expense. Once an impairment expense is recorded, it cannot be reinstated in future periods, even if subsequent events increase the cost center ceiling. For purposes of the ceiling test calculation, current prices are defined 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. Prices are adjusted for basis or location differentials. Unless sales contracts specify otherwise, prices are held constant for the productive life of each well. Similarly, current costs are assumed to remain constant over the entire calculation period.

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, which totaled $85,885 and $254,157 for the three months and nine months ended May 31, 2012, respectively, were capitalized in the full cost pool. The comparable capitalized overhead was $46,673 and $154,621 for the three and nine months ended May 31, 2011, respectively.

Accounts Payable - Well Costs: 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, generally based on the Authorization for Expenditure (“AFE”) or drilling reports.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

Oil and Gas Reserves: The determination of depreciation, depletion and amortization expense, 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 the estimates of the proved oil and natural gas reserves. Oil and natural gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are often different from the quantities of oil and natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

Fair Value Measurements: The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, 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.

Major Customers and Operating Region: The Company operates exclusively within the United States of America. Except for cash and equivalent investments, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry.

The Company’s oil and gas production is purchased by a few customers. The table below presents the percentages of oil and gas revenue that was purchased by major customers.

	Three Months Ended			Nine Months Ended
	May 31, 2012		May 31, 2011	May 31, 2012	May 31, 2011

Company A		73%	77%	72%	77%
Company B		12%	21%	13%	20%

The Company sells production to a small number of customers, as is customary in the industry. Yet, 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.

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. For the three and nine months ended May 31, 2011, all potentially dilutive securities have an anti-dilutive effect on earnings per share.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

For the three and nine months ended May 31, 2012, a reconciliation of weighted-average shares outstanding is as follows:

	Three Months Ended				Nine Months Ended
	May 31, 2012		May 31, 2011		May 31, 2012		May 31, 2011
Weighted-average shares outstanding - basic		51,292,810		32,813,298		44,968,566		22,713,785
Potentially dilutive common shares from:
Stock options		1,458,261		—		1,406,516		—
Warrants		423,722		—		400,912		—
		1,881,982		—		1,807,428		—
Weighted-average shares outstanding - diluted		53,174,792		32,813,298		46,775,994		22,713,785

Recent Accounting Pronouncements: The Company evaluates the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on the Company.

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

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

2. Accounts Receivable

Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners whom have been billed 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 The Company’s total receivable balances as of May 31, 2012 and August 31, 2011, are shown in the following table:

Accounts Receivable	May 31,		August 31,
from Major Customers:	2012		2011
Company A	34	%	31%
Company B	28	%	31%
Company C	8	%	13%

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

3. Property and Equipment

Capitalized costs of property and equipment at May 31, 2012 and August 31, 2011, consisted of the following:

	May 31, 2012			August 31, 2011
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	16,620,409		$	9,942,908
Wells in progress		7,667,876			4,813,749
Subtotal, unevaluated costs		24,288,285			14,756,657

Evaluated costs:
Producing and non-producing		64,785,771			37,750,737
Total capitalized costs		89,074,056			52,507,394
Less, accumulated depletion		(8,371,031	)		(3,892,537	)
Oil and gas properties, net		80,703,025			48,614,857

Other property and equipment:
Vehicles		163,904			163,904
Leasehold improvements		70,351			35,490
Office equipment		148,252			105,089
Land		43,750			43,750
Less, accumulated depreciation		(127,522	)		(65,026	)
Other property and equipment, net		298,735			283,207

Total property and equipment, net	$	81,001,760		$	48,898,064

Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value. The reviews as of May 31, 2012 and 2011, indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment. The full cost ceiling test, explained in Note 1, and, as performed as of May 31, 2012 and 2011, similarly revealed no impairment of oil and gas assets.

4. Depletion, depreciation and amortization

Depletion, depreciation and amortization for the three and nine months ended May 31, 2012 and 2011, consisted of the following:

	Three Months Ended				Nine Months Ended
	May 31, 2012		May 31, 2011		May 31, 2012		May 31, 2011
Depletion	$	1,788,912	$	803,756	$	4,478,494	$	1,999,311
Depreciation		22,896		17,700		62,496		39,438
Amortization		21,698		9,138		58,595		24,076
Total	$	1,833,506	$	830,639	$	4,599,585	$	2,062,825

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate. For the three months and nine months ended May 31, 2012, depletion of oil and gas properties was $14.34 and $15.26 per barrel of oil equivalent (“BOE”), respectively. The comparable depletion expense was $18.70 and $18.28 per BOE for the three months and nine months ended May 31, 2011, respectively.

5. Interest Expense

The components of interest expense recorded for the three months and nine months ended May 31, 2012 and May 31, 2011, consisted of:

	Three Months Ended						Nine Months Ended
	May 31, 2012			May 31, 2011			May 31, 2012			May 31, 2011
Revolving bank credit facility at 3.25%	$	38,306		$	—		$	83,088		$	—
Convertible promissory notes at 8%		—			20,083			—			589,539
Related party note payable at 5.25%		—			—			68,063			—
Accretion of debt discount					762,136			—			2,664,138
Amortization of debt issuance costs		—			422,528			—			1,587,799
Less, interest capitalized		(38,306	)		(253,887	)		(151,151	)		(594,530	)
Interest expense, net	$	—		$	950,860		$	—		$	4,246,945

6. Revolving Bank Credit Facility

In November 2011, the Company entered into a revolving line of credit facility (“LOC”) with Bank of Choice, which provided for borrowings up to $15 million. In April 2012, the borrowing arrangement was amended to allow for a borrowing capacity to $20 million.

Under the LOC, interest is payable monthly and accrues at the bank’s prime rate, subject to a minimum rate of 3.25%. At May 31, 2012, the bank’s prime rate was 3.25%. The Company must maintain certain customary financial ratios, for which the Company was fully in compliance as of May 31, 2012. Certain of the Company’s assets, including substantially all developed properties, 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 commitment is not currently reduced by the borrowing base calculation. The LOC matures on November 30, 2014. As of May 31, 2012, the amount of additional borrowings available under the LOC was $17 million.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

7. Income Taxes

The effective tax rate for the three months ended May 31, 2012, was 37.1%, which differs from the statutory federal income tax rate because of the inclusion of state income taxes. The effective tax rate for the nine months ended May 31, 2012, was a benefit of (21.6)%, which differs from the statutory federal income tax rate because of the inclusion of state income taxes and the change in the valuation allowance. Neither a tax expense nor tax benefit was recognized for either the three or nine months ended May 31, 2011.

As of August 31, 2011, the Company had a deferred tax asset of $0, net of the valuation allowance of $4,911,000. As of that date and until the second quarter of this fiscal year, which ended on February 29, 2012, a full valuation allowance had been provided against deferred tax assets, as it was more likely than not that the Company’s net deferred tax asset would not be realized in the foreseeable future. Consequently, the Company was unable to recognize any income tax benefit in such prior periods. However, the Company has now reported net income for four consecutive quarters and has secured debt and equity financing arrangements that allow for execution of its operating plan. Accordingly, the Company released the entire valuation allowance and holds a net deferred tax asset of $1,809,000 as of May 31, 2012.

As of the quarter ended May 31, 2012, the Company had no unrecognized tax benefits (or associated ASC 740-10-25 liabilities) for ASC 740-10-25 purposes. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s ASC 740-10-25 position during the third quarter of 2012. Given the substantial net operating loss carry forwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated as any such adjustments would very likely simply adjust net operating loss carryforwards.

8. Shareholders’ Equity

Preferred Stock: The Company is authorized to issue 10,000,000 shares of preferred stock with a par value of $0.01 per share. These shares may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares.

Common Stock: The Company is authorized to issue 100,000,000 shares of common stock with a par value of $0.001 per share.

Issued and Outstanding: The total issued and outstanding common stock at May 31, 2012 and August 31, 2011, was 51,409,340 and 36,098,212 common shares, respectively. The following shares of common stock were issued during the nine months ended May 31, 2012:

Sale of common stock

On December 30, 2011, the Company completed the sale of 14,636,363 shares of common stock in a public offering of common stock at a public offering price of $2.75 per share. The underwriters were Northland Capital Markets, C.K. Cooper & Company, and GVC Capital, LLC. Net proceeds to the Company were $37.4 million after deductions for the underwriting discounts, commissions and expenses of the offering.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

Common stock issued for acquisition of mineral interests

During the nine months ended May 31, 2012, the Company issued 481,628 common shares in exchange for mineral property interests. The aggregate value of these transactions was $1,494,378, which was determined using the market price of the Company’s common stock.

Common stock issued for services

During the nine months ended May 31, 2012, the Company issued a total of 188,137 shares of common stock, with a fair market value of $491,003, to individuals as compensation for services provided to the Company.

Common stock warrants

As of May 31, 2012, there were various warrants outstanding to purchase 14,931,067 shares of common stock. The following table summarizes information about the Company’s issued and outstanding common stock warrants as of May 31, 2012:


Exercise Price	Description	Number of Shares		Remaining Contractual Life (in years)		Exercise Price times Number of Shares
$1.60	Series D		769,601		2.55	$	1,231,362
$1.80	Sales Agent Warrants		63,466		0.55		114,239
$6.00	Series A		4,098,000		0.55		24,588,000
$6.00	Series C		9,000,000		2.55		54,000,000
$10.00	Series B		1,000,000		0.55		10,000,000
			14,931,067		1.85	$	89,933,601

The following table summarizes activity for common stock warrants for the nine month period ended May 31, 2012:

	Number of Warrants		Weighted Average Exercise Price
Outstanding, August 31, 2011		14,931,067		$6.02
Granted		—		—
Exercised		—		—
Outstanding, May 31, 2012		14,931,067		$6.02

Information about stock options is contained in Note 9.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

9. Stock-Based Compensation

During the nine months ended May 31, 2012, the Company granted employee stock options to purchase 150,000 shares of common stock at a weighted exercise price of $2.95 and a term of ten years. The options vest over four or five years. These options were determined to have a fair value of $280,367 using the assumptions outlined below.

Expected term (in years)	6.50
Expected volatility	69.43	%
Risk free rate	1.12% - 1.35	%
Expected dividend yield	0.00	%
Forfeiture rate	0.00	%

The Company records an expense related to stock options by pro-rating the estimated fair value of the option grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”). For the grant of various stock options that are currently in the vesting phase, the Company recorded stock-based compensation expense of $107,924 and $323,032 for the three months and nine months ended May 31, 2012, respectively. The comparable stock-based compensation expense for the three months and nine months ended May 31, 2011 was $82,547 and $563,518, respectively.

The estimated unrecognized compensation cost from unvested stock options as of May 31, 2012, was approximately $1,044,470, which will be recognized ratably over the remaining vesting phase, which is 2.78 years.

The following table summarizes activity for stock options for the period from August 31, 2011 to May 31, 2012:

	Number of Warrants		Weighted Average Exercise Price
Outstanding, August 31, 2011		4,645,000		$ 5.21
Granted		150,000		$ 2.95
Exercised		—		—
Outstanding, May 31, 2012		4,795,000		$ 5.14

The following table summarizes information about issued and outstanding stock options as of May 31, 2012:

	Outstanding Options		Vested Options
Number of shares		4,795,000		4,184,000
Weighted average remaining contractual life	2.3 years		1.3 years
Weighted average exercise price	$	5.14	$	5.40
Aggregate intrinsic value	$	3,460,700	$	3,437,540

10. Other Commitments and Contingencies

Effective May 30, 2012, the Company entered into a drilling contract with Ensign United States Drilling, Inc. to use a drilling rig through December 31, 2012. Total payments due to Ensign will depend upon a number of variables, including the number of wells drilled, the target formation, and other technical details. The Company estimates that the total commitment for the seven month period will approximate $5.5 million.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company will own a working interest. 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, 2012, the Company had received participation notices in approximately 8 future wells. It is the Company’s policy to commence recording costs of non-operated wells upon the earlier of receiving a joint interest billing invoice or notice that the drilling process has begun.

11. Related Party Transactions and Commitments

Two of the Company’s executive officers control two entities that have entered into agreements to provide various goods, services, facilities, and oil and gas properties to the Company. The entities are Petroleum Exploration and Management, LLC (“PEM”) and HS Land & Cattle, LLC (“HSLC”).

Acquisition of Oil and Gas Assets from PEM: During the year ended August 31, 2011, the Company acquired oil and gas assets from PEM in two separate transactions.

In May 2011, the Company acquired operating (working interest) oil and gas wells, and other oil and gas assets, from PEM. The purchase price consisted of a cash payment of $10,000,000, the issuance of 1,381,818 restricted shares of common stock, and a promissory note in the principal amount of $5,200,000. In November 2011 the Company utilized proceeds from the LOC (Note 6) to repay the entire principal balance and accrued interest of $142,110.

In October 2010, the Company acquired certain mineral assets located in the Wattenberg Field of the D-J Basin, from PEM for $1,017,435 in cash. The assets acquired included operating (working interest) oil and gas wells, certain drill sites, and miscellaneous equipment.

Other Related Party Transactions: The Company leases office space and an equipment storage yard from HSLC in Platteville, Colorado for $10,000 per month. The twelve month lease arrangement with HSLC commenced July 1, 2010 and was renewed on July 1, 2011, for another year. Under these leases, the Company paid HSLC $30,000 and $90,000 during the three months and nine months ended May 31, 2012, respectively. The comparable payments for the prior fiscal year were $30,000 and $90,000 for the three months and nine months ended May 31, 2011, respectively.

During 2010, the Company initiated a program to acquire mineral interests in several Colorado and Nebraska counties that are considered the eastern portion of the D-J Basin. George Seward, a member of the Company’s board of directors, agreed to lead that program. The Company agreed to compensate the persons, including Mr. Seward, to assist the Company with the acquisitions at a specific rate per qualifying net mineral acre. The compensation is paid in the form of restricted shares of the Company’s common stock. The Company recorded aggregate compensation of $595,785 for services provided by Mr. Seward for the nine months ended May 31, 2012. During the nine months ended May 31, 2012, the Company issued 188,137 shares of restricted common stock to Mr. Seward as partial payment under this program.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

May 31, 2012

(unaudited)

12. 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, 2012 and 2011, respectively:

	Nine Months Ended
	May 31, 2012		May 31, 2011
Supplemental cash flow information:
Interest paid	$	225,197	$	746,651
Income taxes paid		—		—

Non-cash investing and financing activities:
Accrued well costs	$	5,877,714	$	2,242,117
Assets acquired in exchange for common stock	$	1,494,378	$	7,603,698
Assets acquired in exchange for note payable	$	—	$	5,200,000
Asset retirement costs and obligations	$	214,204	$	242,357
Reclass derivative liability to equity		—	$	18,646,413
Conversion of promissory notes into common stock		—	$	15,908,000

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

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding the financial condition as of May 31, 2012, and the results of operations for the three months and nine months ended May 31, 2012, and 2011. 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 the Form 10-K for the fiscal year ended August 31, 2011.

The Prospectus Supplement filed on December 16, 2011 (designated as 424B5 on the SEC’s EDGAR system) should also be considered, as the Prospectus Supplement includes risk factors which pertain to our business and the market for our common stock.

Overview

Synergy Resources Corporation (“we,” “our,” “us” or “the Company”) is 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. All of our producing wells are in the Wattenberg Field, which has a well-developed infrastructure and adequate pipeline and trucking capacity. During 2011, we expanded our undeveloped acreage holdings in eastern Colorado and western Nebraska, and may commence development activities in these areas.

Since commencing active operations in September 2008, we have undergone significant growth. As disclosed in the following table, we have completed, acquired, or participated in 170 producing oil and gas wells.

			Acquired	Participated	Wells
Year	Drilled	Completed	Acquired	Participated	in Progress

2009	—	—	—	2	—
2010	36	22	—	—	14
2011	14	28	72	11	6
2012 1	40	29	4	2	19
Total	90	79	76	15

Represents activity for the nine months ended May 31, 2012.

As of May 31, 2012, we:

·	were the operator of 11 wells that were in the completion process and we were participating as a non-operating working interest owner in 8 wells that were in progress;

·	held approximately 220,009 gross acres and 186,215 net acres under lease; and

·	had estimated proved reserves of 3.6 million barrels (“Bbls”) of oil and 24.8 billion cubic feet (“Bcf”) of gas.

Estimated proved reserves increased 74% during the first nine months of the fiscal year, primarily as a result of the success achieved under the 2012 drilling program.

Strategy

Our strategy for continued growth includes additional drilling activities, acquisition of existing wells, and recompletion of wells to more rapidly access and/or extend reserves through improved hydraulic stimulation techniques. We attempt to maximize our return on assets by drilling and operating wells in which we have a majority net revenue interest. We attempt to limit our risk by drilling in proven areas. To date, we have not drilled any dry holes. All wells drilled prior to 2012 are relatively low-risk vertical or directional wells. However, the increased pace of horizontal drilling activity in the D-J Basin by numerous operators has provided us with the opportunity to witness best practices in the industry first hand. Consequently, we agreed to participate in our first horizontal well, which began drilling operations in January 2012 and commenced production in March 2012. We subsequently agreed to participate in additional horizontal wells and expect that four of them will commence production during the current year. We are preparing to drill and operate horizontal wells for our own account during our 2013 fiscal year.

Historically, our cash flow from operations was not sufficient to fund our growth plans and we relied on proceeds from the sale of debt and equity securities. Our cash flow from operations is increasing, and 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.

Recent Developments

In late summer of 2011, we commenced drilling operations with a rig under contract to us from Ensign United States Drilling, Inc. During the 43 weeks from August 1, 2011, through May 31, 2012, the rig drilled 40 wells, 29 of which reached productive status by May 31, 2012. Completion activities are underway on 11 wells, most of which are expected to reach productive status during our fourth fiscal quarter. In June 2012, the rig commenced drilling under a new contract with Ensign which terminates on December 31, 2012.

In November 2011, we entered into a revolving line of credit facility with Bank of Choice, and amended the agreement in April 2012 to increase the borrowing commitment. The new revolving line of credit provides us a borrowing capacity up to $20 million. This line of credit accrues interest at the greater of 3.25% annually or the bank’s prime rate, and matures on November 30, 2014.

During December 2011 we completed the sale of 14.6 million shares of our common stock at $2.75 per share for net proceeds totaling approximately $37.4 million after deduction of discounts, commissions and expenses. The public offering of additional shares of our common stock was underwritten by Northland Capital Markets, C. K. Cooper & Company, and GVC Capital LLC.

We own a 25% working interest in the Wake E24-77HN, a horizontal well located in Weld County, which is being operated by Noble Energy. Drilling commenced in January and oil production commenced on March 2, 2012. Since January, we have participated in or received notice regarding eight additional horizontal wells in the Niobrara to be drilled by various operators.

During the third quarter, we closed on the acquisition of interests in mineral leases in Weld, Morgan and Larimer Counties, Colorado and also purchased from some minority partners their working interests in existing wells. The interests were acquired with $2.3 million in cash and 261,482 shares of our common stock. Initial exploration activities on the prospect will focus on the potential for horizontal drilling in the Niobrara and Greenhorn formations.

In June 2012, we completed a mid-year reserve analysis. The evaluation was prepared with an effective date of February 29, 2012, and reflects development activity during the first six months of the fiscal year. The report shows that, as of February 29, 2012, we had estimated proved reserves of 3.492 million barrels of oil and 23.798 billion cubic feet of gas. The estimated present value before tax (discounted at 10%) is $122.576 million. Compared to the annual reserve report prepared at August 31, 2011, quantities increased by 68% and value increased by 71%.

RESULTS OF OPERATIONS

For the three months ended May 31, 2012, compared to the three months ended May 31, 2011

For the three months ended May 31, 2012, we reported net income of $2,430,763 compared with a net loss of $(291,612) for the three months ended May 31, 2011. Earnings per basic and diluted share were $0.05 for the three months ended May 31, 2012, compared to a loss of $(0.01) per basic and diluted share for the three months ended May 31, 2011. The comparison between the two years was primarily influenced by i) increased revenues and expenses associated with more producing wells, ii) the cessation of interest and other expenses related to the convertible promissory notes that were converted into equity during the comparable prior year period, and iii) the income tax expense recognized in the current period.

Oil and Gas Production and Revenues – For the three months ended May 31, 2012, we recorded total oil and gas revenues of $7,521,833 compared to $2,921,910 for the three months ended May 31, 2011, an increase of $4,599,923 or 157%. Our growth in revenue resulted from the increase in production volume of 190% over the comparative period resulting primarily from new wells, offset by a decrease in our realized average selling price per BOE of 11%, as shown in the table below. For the three months ended May 31, 2012, our gas / oil ratio (“GOR”) on a BOE basis was 45/55. During the comparable prior period, our GOR was 46/54.

	Three Months Ended
	May 31, 2012		May 31, 2011		Change
Production:
Oil (Bbls1)		69,230		23,371	196%
Gas (Mcf2)		333,200		117,647	183%
BOE3		124,763		42,979	190%

Revenues:
Oil	$	6,314,144	$	2,293,945	175%
Gas		1,207,689		627,965	92%
Total	$	7,521,833	$	2,921,910	157%

Average sales price:
Oil (Bbl1)	$	91.21	$	98.15	(7)%
Gas (Mcf2)	$	3.62	$	5.34	(32)%
BOE3	$	60.29	$	67.98	(11)%

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.

As of May 31, 2012, we had 170 producing wells. Net oil and gas production for the three months ended May 31, 2012 averaged 1,356 BOE per day compared to 467 for the three months ended May 31, 2011. The significant increase in production from the comparable period in the prior year reflects 106 additional wells that went into productive status since May 31, 2011.

Revenues are sensitive to changes in commodity prices. Since the comparable quarter of the previous year, we saw declines of 7% and 32% in prices of crude oil and natural gas, respectively. Subsequent to May 31, 2012, the posted price for crude oil sold in the United States continued to decline. Between May 31 and June 26, 2012, quoted prices for crude oil fell 8% and quoted prices for natural gas rose 15%. While our balanced production mix of oil and gas and the high liquid content of our gas help to mitigate the negative effect of volatility in commodity prices, this downward price pressure could have a negative effect on revenues reported for future quarters.

Lease Operating Expenses – Direct operating costs of producing oil and natural gas and taxes on production and properties are reported as lease operating expenses as follows:

	Three Months Ended
	May 31, 2012		May 31, 2011
Severance and ad valorem taxes	$	703,146	$	290,663
Work-over		—		291,499
Production costs		351,973		86,521
Retroactive billing adjustment		104,353		—
Total lease operating expenses	$	1,159,472	$	668,683

Per BOE:
Severance and ad valorem taxes	$	5.64	$	6.76
Work-over		—		6.78
Production costs		2.82		2.01
Retroactive billing adjustment		0.83		—
Total per BOE	$	9.29	$	15.55

Lease operating and work-over costs tend to fluctuate with the number of producing wells, and, to a lesser extent, on variations in oil field service costs and changes in the production mix of crude oil and natural gas. During the comparative periods presented above, we experienced an increase in production cost per BOE in connection with additional costs to bolster output from some of our older wells. Taxes, the largest component of lease operating expenses, generally move with the value of oil and gas sold. As a percent of revenues, taxes averaged 9% for the three months ended May 31, 2012 and 10% for the three months ended May 31, 2011. During 2012, we recognized an additional expense for retroactive billing adjustments on non-operated wells.

Depreciation, Depletion, and Amortization (“DDA”) – We recognized $1,788,912 of depletion of oil and gas properties for the three months ended May 31, 2012, compared to $803,756 for the comparable prior year period. The expense more than doubled, primarily as a result of growth in production and properties from May 31, 2011 to May 31, 2012.

Capitalized costs of evaluated 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 three months ended May 31, 2012, utilizing the new engineering reserve report, estimated net proved reserves of 7,756,563 BOE were the basis of the depletion rate calculation, compared to reserves of 1,366,340 BOE for the three months ended May 31, 2011. The calculation also considered production volumes of 124,763 BOE for the current quarter compared to 42,979 BOE in the depletion rate calculation for the comparable prior year period.

For the three months ended May 31, 2012, depletion of oil and gas properties was $14.34 per BOE compared to $18.70 for the three months ended May 31, 2011. During the current year we have been able to increase reserves and production faster than the increase in capitalized costs, which caused the decline in the expense per BOE. One of the factors contributing to the trend was the reduction of costs in the full cost pool resulting from the accounting for proceeds received from the sale of undeveloped interests in 2011, which was estimated to reduce depletion expense by approximately $1.80 per BOE.

General and Administrative – The following table summarizes the components of general and administration expenses:

	Three Months Ended,
	May 31, 2012			May 31, 2011
Compensation and benefits	$	389,851		$	491,516
Stock option expense		107,924			82,547
Professional fees		173,182			176,140
Insurance		32,967			26,416
Other general and administrative		64,373			145,370
Capitalized general and administrative		(85,885	)		(46,673	)
Totals	$	682,412		$	875,316

Cash based compensation and benefits includes both employees and directors. Overall compensation expense has increased for 2012 as a whole, (see the Nine Month Discussion), as a result of salaries for the additional four employees hired during the year to accommodate the expansion of our business. However, the three months ended May 31, 2012 is $101,665 less than the expense reported in the comparable prior period because of certain differences in the timing of compensation earned in connection with well completions. Share based compensation is associated with compensation in the form of either stock options or common stock grants for employees, directors and service providers. The amount of expense recorded for stock options is calculated by using the Black-Scholes-Merton option pricing model, while the amount of expense recorded for common stock grants is calculated based upon the closing market value of the shares on the date of grant.

Professional fees have increased as we have grown our business. The two primary factors driving this increase are the additional accounting and auditing fees incurred in connection with operating as a public company, and the additional professional services required to meet the compliance requirements of Sarbanes-Oxley as we have progressed from a smaller reporting company to an accelerated filer. The listing on the New York Stock Exchange Amex also contributed to costs in excess of those reported in the comparable prior year period when our stock was listed on the OTC Bulletin Board.

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 general and administrative expenses and capitalized into the full cost pool. The increase in capitalized costs from 2011 to 2012 reflects our increasing activities to acquire leases and develop properties.

Other Income (Expense) – Other income for the three months ended May 31, 2012 was $16,320, consisting solely of interest income. For the three months ended May 31, 2011, we reported several significant items of expense in addition to interest income of $25,784. These other expenses reported in 2011 related to our convertible promissory notes, including net interest expense of $20,083, accretion of debt discount of $762,136, amortization of debt issuance costs of $422,528, and a change in the fair value of the derivative conversion liability of $86,192. All expenses related to the convertible promissory notes ceased during the reporting period ended May 31, 2011, as all noteholders converted their holdings into equity on or prior to March 31, 2011.

Income Taxes – We reported income tax expense for the three months ended May 31, 2012, at an effective tax rate of 37.1% and have recognized a net deferred tax asset of $1,809,000. During the current fiscal year, specifically during the period ended February 29, 2012, we concluded that it was more likely than not that our net deferred tax asset would be realized, and we released our entire valuation allowance of $4,911,000. The one-time tax benefit was recognized during the quarter ended February 29, 2012. Future reporting periods are expected to report income tax expense at our effective tax rate. For all reporting periods prior to February 29, 2012, including the period ended May 31, 2011, no income tax expense or benefit was reported, as all tax assets or liabilities were effectively offset by a valuation allowance.

For the nine months ended May 31, 2012, compared to the nine months ended May 31, 2011

For the nine months ended May 31, 2012, we reported net income of $10,176,642 compared with a net loss of $(13,189,974) during the nine months ended May 31, 2011. Earnings per diluted share were $0.22 for the nine months ended May 31, 2012, compared to a loss of $(0.58) per diluted share for the nine months ended May 31, 2011. The comparison between the two years was primarily influenced by i) increased revenues and expenses associated with the more producing wells, ii) the cessation of interest and other expenses related to the convertible promissory notes that were converted into equity during the comparable prior year period, and iii) the income tax benefit recognized in the current period.

Oil and Gas Production and Revenues – For the nine months ended May 31, 2012, we recorded total oil and gas revenues of $18,219,672 compared to $6,399,193 for the nine months ended May 31, 2011, an increase of $11,820,479 or 185%. Our growth in revenue was the result of an increase in our production volume of 168% over the comparative period resulting primarily from new wells, coupled with an increase in our average selling price per BOE of 6%, as shown in the table below. For the nine months ended May 31, 2012 and 2011, our GOR on a BOE basis was 45/55.

	Nine Months Ended
	May 31, 2012		May 31, 2011		Change
Production:
Oil (Bbls1)		160,995		59,749		169%
Gas (Mcf2)		794,691		297,668		167%
BOE3		293,444		109,360		168%

Revenues:
Oil	$	14,646,084	$	5,079,629		188%
Gas		3,573,588		1,319,564		171%
Total	$	18,219,672	$	6,399,193		185%

Average sales price:
Oil (Bbl1)	$	90.97	$	85.02		7%
Gas (Mcf2)	$	4.50	$	4.43		1%
BOE3	$	62.09	$	58.51		6%

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.

As of May 31, 2012, we had 170 producing wells. Net oil and gas production for the nine months ended May 31, 2012 was 293,444 BOE, or 1,071 BOE per day compared to 401 for the nine months ended May 31, 2011. The significant increase in production from the comparable period in the prior year reflects 106 additional wells that went into productive status since May 31, 2011.

Revenues are sensitive to changes in commodity prices. Since the comparable period in the prior year, we have seen increases of 7% and 1% in prices of crude oil and natural gas, respectively. Yet, during the third quarter, we experienced declines of 7% and 32% in prices of crude oil and natural gas, respectively. Subsequent to May 31, 2012, the posted price for crude oil sold in the United States continued to decline. Between May 31 and June 29, 2012, quoted prices for crude oil fell 8% and quoted prices for natural gas rose 15%.

While our balanced production mix of oil and gas and the high liquid content of our gas help to mitigate the negative effect of volatility in commodity prices, this downward price pressure could have a negative effect on revenues reported for future quarters.

Lease Operating Expenses – Direct operating costs of producing oil and natural gas and taxes on production and properties are reported as lease operating expenses as follows:

	Nine Months Ended
	May 31, 2012		May 31, 2011
Severance and ad valorem taxes	$	1,672,129	$	636,470
Work-over		40,813		291,499
Production costs		891,975		203,868
Retroactive billing adjustment		115,290		—
Total lease operating expenses	$	2,720,206	$	1,131,837

Per BOE:
Severance and ad valorem taxes	$	5.70	$	5.82
Work-over		0.14		2.67
Production costs		3.04		1.86
Retroactive billing adjustment		0.39		—
Total per BOE	$	9.27	$	10.35

Lease operating and work-over costs tend to fluctuate with the number of wells on production, and, to a lesser extent, on variations in oil field service costs and changes in the production mix of crude oil and natural gas. During the comparative periods presented above, we experienced an increase in production cost per BOE in connection with additional costs to bolster output from some of our older wells. Taxes, the largest component of lease operating expenses, generally move with the value of oil and gas sold. As a percent of revenues, taxes averaged 9% for the nine months ended May 31, 2012 and 10% for the nine months ended May 31, 2011. During 2012, we recognized an additional expense for retroactive billing adjustments on non-operated wells.

Depreciation, Depletion, and Amortization (“DDA”) – We recognized $4,478,494 of depletion of oil and gas properties comprises for the nine months ended May 31, 2012, compared to $1,999,311 for the comparable prior year period. The expense more than doubled, primarily as a result of growth in production and properties for the nine month period.

Capitalized costs of evaluated 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, 2012, production volumes more than doubled that of the comparable period in the prior year, 293,443 BOE, compared to 109,360 BOE, and estimated net proved reserves more than quadrupled from those at May 31, 2011.

For the nine months ended May 31, 2012, depletion of oil and gas properties was $15.26 per BOE, compared to $18.28 per BOE for the nine months ended May 31, 2011. During the current year we have been able to increase reserves and production faster than the increase in capitalized costs, which caused the decline in the expense per BOE. One of the factors contributing to the trend was the reduction of costs in the full cost pool resulting from the accounting for proceeds received from the sale of undeveloped interests during in 2011, which was estimated to reduce depletion by approximately $1.80 per BOE.

General and Administrative – The following table summarizes the components of general and administration expenses:

	Nine Months Ended
	May 31, 2012			May 31, 2011
Compensation and benefits	$	1,387,256		$	947,405
Stock option expense		306,032			248,518
Professional fees		690,882			338,815
Insurance		103,196			59,242
Other general and administrative		326,041			520,647
Capitalized general and administrative		(254,157	)		(154,621	)
Totals general and administrative expense	$	2,559,250		$	1,960,006

Cash based compensation and benefits includes both employees and directors. The increase of $439,851 from 2011 to 2012 reflects salaries for the additional four employees hired during the year to accommodate the expansion of our business. Share based compensation is associated with compensation in the form of either stock options or common stock grants for employees, directors and service providers. The amount of expense recorded for stock options is calculated by using the Black-Scholes-Merton option pricing model. The amount of expense recorded for common stock grants is calculated based upon the closing market value of the shares on the date of grant.

Professional fees have increased as we grow our business. The two primary factors driving this increase are the additional accounting and auditing fees incurred in connection with operating as a public company, and the additional professional services required to meet the compliance requirements of Sarbanes-Oxley, as we have progressed from a smaller reporting company to an accelerated filer. The listing on the New York Stock Exchange Amex also contributed to costs in excess of those reported in the comparable prior year period when our stock was listed on the OTC Bulletin Board.

Other Income (Expense) – Other income for the nine months ended May 31, 2012 was $27,011, consisting solely of interest income. For the nine months ended May 31, 2011, we reported several significant items of expense in addition to interest income of $41,675. These other expenses reported in 2011 related to our convertible promissory notes, including net interest expense of $589,539, accretion of debt discount of $2,664,138, amortization of debt issuance costs of $1,587,799, and a change in the fair value of the derivative conversion liability of $10,229,229. All expenses related to the convertible promissory notes ceased during the reporting period ended May 31, 2011, as all noteholders converted their holdings into equity on or prior to March 31, 2011.

Income Taxes – We reported an income tax benefit for the nine months ended May 31, 2012, at an effective tax rate of (21.6)% and have recognized a net deferred tax asset of $1,809,000. The tax calculation consists of a benefit of $4,911,000 offset by an expense of $3,102,000. During the current fiscal year, specifically during the period ended February 29, 2012, concluded that it was more likely than not that our net deferred tax asset would be realized, and we released our entire valuation allowance of $4,911,000. The one-time tax benefit was recognized during the quarter ended February 29, 2012. Future reporting periods are expected to report income tax expense at our effective tax rate. For all reporting periods prior to February 29, 2012, including the period ended May 31, 2011, no income tax expense or benefit was reported, as all tax assets or liabilities were effectively offset by a valuation allowance.

LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the nine months ended May 31, 2012 and 2011, are shown below:

	Nine Months Ended
	May 31, 2012			May 31, 2011

Cash provided by operations	$	17,078,009		$	3,824,882
Acquisition of oil and gas properties, and equipment		(34,025,758	)		(21,163,392	)
Sales of oil and gas properties, and equipment		—			4,995,817
Net proceeds from sale of stock		37,421,783			16,690,721
Net borrowings		(2,200,000	)		—
Net increase in cash	$	18,274,034		$	4,348,028

Net cash provided by operating activities was $17,078,009 and $3,824,882 for the nine months ended May 31, 2012 and 2011, respectively. The change reflects significant growth in operating contribution from the additional wells that were producing during 2012 as compared to 2011. In addition to our analysis using amounts included in the cash flow statement, we evaluate operations using a non-GAAP measure called “adjusted cash flow from operations,” which adjusts for cash flow items that merely reflect the timing of certain cash receipts and expenditures. Adjusted cash flow from operations was $13,290,259 and $3,917,535 for the nine months ended May 31, 2012 and 2011, respectively.

The cash flow statement reports actual cash expenditures for capital expenditures, which differs from total capital expenditures on a full accrual basis. Specifically, cash paid 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 a full accrual basis, capital expenditures totaled $36,644,685 and $27,944,740 for the nine months ended May 31, 2012 and 2011, respectively, compared to cash payments of $34,025,758 and $21,163,392, respectively.

A reconciliation of the differences is summarized in the following table:

	Nine Months Ended
	May 31, 2012			May 31, 2011

Cash payments	$	34,025,758		$	21,163,392
Non-cash payments		1,494,378			12,803,698
Accrued costs, beginning of period		(4,967,369	)		(3,446,439	)
Accrued costs, end of period		5,877,714			2,242,117
Proceeds from the sale of properties		—			(4,995,817	)
Asset retirement obligations		214,204			242,357
Other		—			(64,568	)
Capital expenditures	$	36,644,685		$	27,944,740

During the nine months ended May 31, 2012, we engaged in drilling or completion activities on 40 wells which we operate. During the period 29 of the wells reached productive status. Completion activities were underway on 11 wells, most of which are expected to reach productive status during our fourth fiscal quarter.

Most of our capital expenditures for the nine months ended May 31, 2012, represent drilling and completion cost on wells in progress. In addition, we incurred costs of $6.1 million on the acquisition of mineral leases, $1,494,378 of which were acquired in exchange for our common stock.

In November 2011, we modified our borrowing arrangement with Bank of Choice to increase the maximum allowable borrowings and to reduce the interest rate. In April 2012, the agreement was amended to further increase the borrowing base. The revolving line of credit provides us a borrowing capacity to $20 million. Outstanding borrowings accrue interest at the greater of 3.25% annually or the bank’s prime rate, which was also 3.25% at May 31, 2012. The maturity date for the arrangement is November 30, 2014. The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios, for which the we were fully in compliance as of May 31, 2012. The borrowing arrangement is collateralized by certain of our assets, including producing properties. Maximum borrowings are subject to reduction based upon a borrowing base calculation. As of May 31, 2012, the borrowing base calculation was not restrictive. We utilized a portion of the financing available through this arrangement to retire amounts outstanding under our related party note payable.

On December 30, 2011, we completed the sale of 14.6 million shares of common stock in a public offering at a price of $2.75 per share. We netted $37,421,783 in proceeds, after deductions for the underwriting discounts, commissions and expenses of the offering.

We do not currently engage in any commodity hedging activities, although we may do so in the future.

We believe that the proceeds from our equity offering, plus cash flow from operations, plus additional borrowings available under our revolving line of credit will be sufficient to meet our liquidity needs during the remainder of this fiscal year.

As of August 31, 2011, we had a net deferred tax asset of $4,911,000. For reporting periods prior to February 29, 2012, management concluded that it was more likely than not that our net deferred tax asset would not be realized in the foreseeable future and accordingly, a full valuation allowance was provided against the net deferred tax asset. Effective February 29, 2012, management concluded that positive indicators outweighed negative indicators, and that it was appropriate to release the valuation allowance, primarily for the three following reasons. First, all of the net losses for the two prior fiscal years can be attributed to a single discrete item. The discrete item was the fair value accounting treatment of the components of the 8% convertible promissory notes issued in 2010, which created non-cash expenses for accretion of debt discount, amortization of issuance costs, and change in fair value of derivative liability. As all of the convertible notes were converted prior to March 31, 2011, those expenses will not recur, and it is appropriate to exclude them from a consideration of future profitability. Second, we had reported three consecutive quarters of net income and six consecutive quarters of operating income. Third, we completed a debt financing arrangement and an equity financing arrangement that allow us to continue with our operating plan. Accordingly, we believe that it is appropriate to release the valuation allowance related to the deferred tax asset created by the net operating loss carryover.

Our primary need for cash during the remainder of fiscal 2012 and for the fiscal year ending August 31, 2013, will be to fund our drilling and acquisition programs. For the remainder of fiscal 2012, we expect that spending for drilling operated and non-operated wells will exceed our original budget of $37.9 million. Furthermore, we expect to spend more than $4 million on the program to recomplete and stimulate older wells. This program had a 2012 budget of $3 million. Similarly, we expect to spend more than $5 million on the acquisition of undeveloped properties. The original budget for the acquisition of non-producing properties was $3.7 million. We had also planned to spend approximately $17.5 million on the acquisition of producing properties. We have not acquired significant producing properties and may not do so during the remainder of the fiscal year.

Under the preliminary plans for our 2013 capital budget, we currently estimate capital expenditures of approximately $55 million for additional drilling, participating in drilling, and acquiring properties. As an operator, we plan to spend approximately $15 million to drill 25 vertical wells and approximately $17 million to drill 4 horizontal wells. An additional $12 million has been estimated as our portion of the cost of vertical and horizontal wells in which we will participate as a non-operator. We also plan recompletion costs approximating $1.5 million on 10 wells that indicate good potential for additional hydraulic stimulation. Under our proposed acquisition program, acquisition of undeveloped acreage and proved properties is expected to require funds of $8 million. Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.

We plan to generate profits by producing oil and natural gas from wells that we drill or acquire. For the near term, we believe that we have sufficient liquidity to fund our needs. However, to meet all of our long-term goals, we may need to raise some of the funds required to drill new wells through the sale of our securities, from loans from third parties or from third parties willing to pay our share of drilling and completing the wells. We may not be successful in raising the capital needed to drill or acquire oil or gas wells. Any wells which may be drilled by us may not produce oil or gas in commercial quantities.

Contractual Commitments

In addition to the commitments disclosed in our Annual Report on Form 10-K for the year ended August 31, 2011, and in Quarterly Reports on Form 10-Q for the periods ended November 30, 2011 and February 29, 2012, and amounts recorded in our financial statements as of and for the nine months ended May 31, 2012, we have the following additional obligations related to future periods.

Effective May 30, 2012, we entered into a drilling contract with Ensign United States Drilling, Inc. to utilize a drilling rig through December 31, 2012. Total payments due to Ensign will depend upon a number of variables, including the number of wells drilled, the target formation, and other technical details. We estimate that the total commitment for the seven month period will approximate $5.5 million.

From time to time, we receive notice from other operators of their intent to drill and operate a well in which we will own a working interest. We have the option to participate in the well and assume the obligation for its pro-rata share of the costs. As of May 31, 2012, we have received participation notices in approximately 8 future wells. It is our policy to commence recording costs of non-operated wells upon the earlier of receiving a joint interest billing invoice or notice that the drilling process has begun.

Non-GAAP Financial Measures

We use "adjusted cash flow from operations" and "adjusted EBITDA," non-GAAP financial measures, for internal managerial purposes, when evaluating period-to-period comparisons. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, net income, nor as a liquidity measure or indicator of cash flows or an indicator of operating performance reported in accordance with U.S. GAAP. The non-GAAP financial measures 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. See Reconciliation of Non-GAAP Financial Measures below for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure.

Reconciliation of Non-GAAP Financial Measures

Adjusted cash flow from operations. We define adjusted cash flow from operations as the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables and payables. We believe it is important to consider adjusted cash flow from operations as well as cash flow from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during the period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next.

Adjusted EBITDA. We define adjusted EBITDA as net income (loss) plus net interest expense, income taxes, and depreciation, depletion and amortization for the period plus/minus the change in fair value of our derivative conversion liability. We believe adjusted EBITDA is relevant because it is a measure of cash available to fund our capital expenditures and service our debt and is a metric used by some industry analysts to provide a comparison of our results with our peers.

The following table presents a reconciliation of each of our non-GAAP financial measures to its nearest GAAP measure.

	Nine Months Ended
	May 31, 2012			May 31, 2011
Adjusted cash flow from operations:
Adjusted cash flow from operations	$	13,290,259		$	3,917,535
Changes in assets and liabilities		3,787,750			(92,653	)
Net cash provided by operating activities	$	17,078,009		$	3,824,882

Adjusted EBITDA:
Adjusted EBITDA	$	13,263,248		$	3,870,868
Interest and related items, net		27,011			(4,205,270	)
Change in fair value of derivative conversion liability		—			(10,229,229	)
Provision for income tax benefit		1,809,000			—
Depletion, depreciation and amortization		(4,599,585	)		(2,062,825	)
Stock based compensation		(323,032	)		(563,518	)
Net income (loss)	$	10,176,642		$	(13,189,974	)

TREND AND OUTLOOK

The 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, v) competition from larger companies and vi) prices for oil and gas. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.

It is expected that our principal source of cash flow will be from the production and sale of oil and gas reserves, which are depleting assets. Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing more easily or on better terms, and lessens the difficulty of obtaining debt financing. However, price increases heighten the competition for oil and gas prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels.

A decline in oil and gas prices i) will reduce our cash flow which in turn will reduce the funds available for exploring for 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 terms, iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, and v) may result in marginally productive oil and gas wells being abandoned as non-commercial. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

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 or expenses.

CRITICAL ACCOUNTING POLICIES

There have been no material changes in our critical accounting policies since our last fiscal year, which ended on August 31, 2011. A detailed discussion of the nature of our accounting practices can be found in the section titled “Critical Accounting Policies” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended August 31, 2011.

Pursuant to our income tax accounting policy, we concluded that it was more likely than not that we would be able to utilize the future tax benefits of our net operating loss carryover. An expanded discussion of our policy, our conclusion, and factors that effected our conclusion is present below.

Income Taxes: Deferred income taxes are recorded for timing differences between items of income or expense reported in the financial statements and those reported for income tax purposes using the asset/liability method of accounting for income taxes. Deferred income taxes and tax benefits are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, and for tax loss and credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. We provide for deferred taxes for the estimated future tax effects attributable to temporary differences and carry-forwards when realization is more likely than not. If we conclude that it is more likely than not that some portion, or all, of the net deferred tax asset will not be realized, the balance of net deferred tax assets is reduced by a valuation allowance.

The realization of the deferred tax assets related to the net operating loss carry-forwards is dependent upon our ability to generate future taxable income. The ability of the Company to utilize net operating loss carry-forwards may be further limited by other provisions of the Internal Revenue Code. For reporting periods prior to the second fiscal quarter, which ended on February 29, 2012, management concluded that it was more likely than not that our net deferred tax asset would not be realized in the foreseeable future and accordingly, a full valuation allowance was provided against the net deferred tax asset. Effective February 29, 2012, management concluded that positive indicators outweighed negative indicators, and that it was appropriate to release the valuation allowance.

Management considers many factors in its evaluation of deferred tax assets, including the following sources of taxable income that may be available under the tax law to realize a portion or all of a tax benefit for deductible timing differences and carry forwards:

	●	Future reversals of existing taxable temporary differences,
	●	Taxable income in prior carry back years, if permitted,
	●	Tax planning strategies, and
	●	Future taxable income exclusive of reversing temporary differences and carry forwards.

After evaluating positive and negative evidence available as of the reporting date, including recent earnings history, we concluded that it was more likely than not that we will utilize our net operating loss carry forwards.

We follow the provisions of the ASC regarding uncertainty in income taxes. No significant uncertain tax positions were identified as of any date on or before May 31, 2012. Given the substantial net operating loss carry-forwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated as any such adjustments would very likely simply adjust the net operating loss carry-forwards.

Recent Accounting Pronouncements

We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and their impact on us.

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires us to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. We are is required to implement this guidance effective for the first quarter of fiscal 2014 and do not expect the adoption of ASU 2011-11 to have a material impact on our financial statements.

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

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:

	•	The success of our exploration and development efforts;
	•	The price of oil and gas;

	•	The worldwide economic situation;
	•	Any change in interest rates or inflation;

	•	The willingness and ability of third parties to honor their contractual commitments;
	•	Our ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital;

	•	Our capital costs, as they may be affected by delays or cost overruns;
	•	Our costs of production;

	•	Environmental and other regulations, as the same presently exist or may later be amended;
	•	Our ability to identify, finance and integrate any future acquisitions; and

•

The volatility of our stock price.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk - Our primary market risk exposure results from the price we receive for our oil and natural gas production. Realized commodity pricing for our production is primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. Pricing for oil and natural gas production has been volatile and unpredictable in recent years, and we expect this volatility to continue in the foreseeable future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable commodity index price.

Interest Rate Risk - At May 31, 2012, we had debt outstanding under our bank credit facility totaling $3,000,000. Interest on our bank credit facility accrues at the greater of 3.25% or the prime rate, which was also 3.25% at May 31, 2012. While we are currently incurring interest at the floor of 3.25%, we are exposed to interest rate risk on the bank credit facility if the prime rate exceeds the floor. If interest rates increase, our interest expense would increase and our available cash flow would decrease.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of May 31, 2012, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended May 31, 2012, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II

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 Frank L. Jennings.

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

101

The following materials from the Company’s quarterly report on Form 10-Q for the period ended May 31, 2012, formatted in XBRL (Extensible Business Reporting Language): i) the Balance Sheets, ii) the Statements of Operations, iii) the Statements of Cash Flows, and v) Notes to Financial Statements, tagged as blocks of text.

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 9, 2012	By:	/s/ Ed Holloway
		Ed Holloway, President and Principal Executive Officer


Date: July 9, 2012	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Principal Financial and Accounting Officer

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