10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

AMENDMENT NO. 1

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended August 31, 2013

OR

o TRANSITION REPORT PURSUANT TO 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, CO	80651
(Address of principal executive offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock	NYSE MKT

Securities registered pursuant to Section 12(g) of the Act:
 _______________

(Title of class)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No x

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.

Persons who respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number.

Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations 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 filing). Yes x  No o

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

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

The aggregate market value of the voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on February 28, 2013, was approximately $309 million.  Shares of the registrant’s common stock held by each officer and director and each person known to the registrant to own 10% or more of the outstanding voting power of the registrant have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not a determination for other purposes.

As of October 31, 2013, the Registrant had 74,391,364 issued and outstanding shares of common stock.

Explanatory Note

This Amendment No. 1 to the Synergy Resources Corporation Annual Report on Form 10-K for the year ended August 31, 2013, reflects changes made in response to comments received from the staff of Securities and Exchange Commission.  In response to the comments, we amended our original report to (1) expand our disclosures related to proved undeveloped reserves in the discussion about oil and gas properties in Item 1; (2) expand our disclosure about market risk included in Item 7A; (3) clarified our references to exhibits related to our amended and restated credit agreement and the employment agreements for Ed Holloway and William E. Scaff; (4) filed as an exhibit the underlying drilling contract with Ensign United States Drilling, Inc. that was dated April 19, 2013; (5) in Note 1 to Financial Statements, clarified the description of our policy regarding the ceiling test; and (6) in Note 16 to the Financial Statements expanded our disclosure to provide explanations for the significant changes in reserve quantities.

Except as described above, this amendment does not revise or restate the financial statements or other disclosures included in the original Form 10-K.  This amendment does not reflect events occurring after the filing of the original Form 10-K or modify or update disclosures related to subsequent events.  Accordingly, this amendment should be read in conjunction with our filings with the SEC subsequent to the filing of the original Form 10-K.

PART I

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 1.  BUSINESS

Overview

 We are an oil and gas operator in Colorado and are focused on the acquisition, development, exploitation, exploration and production of oil and natural gas properties primarily located in the Denver-Julesburg Basin (“D-J Basin”) in northeast Colorado.  We have concentrated on drilling and completing wells located in the Wattenberg Field, an area within the D-J Basin, which has a prolific production history.  We serve as the operator for most of our wells and focus our efforts on those prospects in which we have a significant net revenue interest.  As of October 31, 2013, we had 374,000gross and 245,000 net acres under lease, substantially all of which are located in the D-J Basin.  Of this acreage, 12,550 gross acres are held by production.

 We commenced active operations in the D-J Basin in 2008.  Between September 1, 2008 and August 31, 2013, we completed, participated or otherwise acquired an interest in 293 gross (224 net) producing oil and gas wells.  We are the operator of 218 wells and participate with other operators in 75 wells.  In addition to the wells that had reached productive status at the end of our fiscal year, there are 16 gross (8 net) wells in various stages of drilling or completion as of August 31, 2013.  There have been no dry holes.  

1

At August 31, 2013, our estimated net proved oil and gas reserves, as prepared by our independent reserve engineering firm, Ryder Scott Company, L.P., were 7.0 MMBbls of oil and condensate and 40.7 Bcf of natural gas.

Business Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves and cash flow through acquisitions, development, exploitation, exploration and divestiture of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures in a combination of lower risk development and exploitation activities and higher potential exploration prospects. Key elements of our business strategy include the following:

· Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience.  All of our current wells are located within the D-J Basin and our undeveloped acreage is located either in or adjacent to the D-J Basin.  Focusing our operations in this area leverages our management, technical and operational experience in the basin.

· Develop and exploit existing oil and natural gas properties.  Since inception our principal growth strategy has been to develop and exploit our acquired and discovered properties to add proved reserves.  In the Wattenberg Field, we target three formations, the Niobrara, the Codell, and the J-Sand.  We selectively target the zones most likely to yield the greatest return on investment, and leave certain zones “behind pipe” for future extraction.  However our future plans will focus on horizontal development of our assets in the Wattenberg Field as we believe horizontal development can increase the potential recovery of hydrocarbons significantly when compared to conventional vertical drilling.  We consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential wells.  There is enough similarity between wells in the Field that the exploitation process is generally repeatable.

· Complete selective acquisitions.  We seek to acquire undeveloped and producing oil and gas properties, primarily in the D-J Basin and certain adjacent areas.  We will seek acquisitions of undeveloped and producing properties that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation opportunities.

· Retain control over the operation of a substantial portion of our production. As operator on a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled or existing wells to be recompleted.  This allows us to modify our capital spending as our financial resources allow and market conditions support.

· Maintain financial flexibility while focusing on controlling the costs of our operations.  We intend to finance our operations through a mixture of debt and equity capital as market conditions allow.  Our management has historically been a low cost operator in the D-J Basin and we continue to focus on operating efficiencies and cost reductions.

· Use the latest technology to maximize returns.  Drilling horizontal wells is expected to significantly increase our future production and the value of our asset base.  Latest industry practices are drilling horizontal wells in the Wattenberg Field in increasing density and technical advancements in completing these wells is leading to enhanced productivity.  We have identified an additional 600 potential horizontal wells in the Niobrara and Codell formations on existing Wattenberg acreage and over 125 potential horizontal well locations in the Greenhorn and Niobrara formations in the Northern D-J Basin acreage.  Of these locations, 71 are in the drilling permit process.

2

Competitive Strengths

We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:

· Management experience.  Our key management team possesses an average of thirty years of experience in oil and gas exploration and production, primarily within the D-J Basin.  

· Balanced oil and natural gas reserves and production.  At August 31, 2013, approximately 51% of our estimated proved reserves were oil and condensate and 49% were natural gas and liquids, measured upon a BTU equivalent basis.  We believe this balanced commodity mix will provide diversification of sources of cash flow and will lessen the risk of significant and sudden decreases in revenue from short-term commodity price movements.

· Ability to recomplete D-J Basin wells numerous times throughout the life of a well.  We have experience with and knowledge of D-J Basin wells that have been recompleted up to three times since initial drilling.  This provides us with numerous high return recompletion investment opportunities on our current and future wells and the ability to manage the production through the life of a well.

· Low cost operator.  We have successfully demonstrated our ability to drill wells for lower costs than our major competitors and to successfully integrate acquired assets without incurring significant increases in overhead.

3

Recent Developments

We expanded our business during the fiscal year ended August 31, 2013.  We increased our producing wells, our reserves, and our undeveloped acreage.  Significant developments are described below.

As an operator, we began our transition from vertical drilling to horizontal drilling.

During the first half of the fiscal year, we continued our active vertical well drilling program.  We substantially completed our 2013 plans for drilling vertical wells during the second quarter.  From September 1, 2012, through December 31, 2012, we drilled 27 new vertical wells and brought all of them into productive status during the first half of the fiscal year.

During the year, our efforts shifted to horizontal wells.  In May 2013 drilling operations commenced on the first horizontal well at our Renfroe prospect.  By the end of August, we had substantially completed all five wells planned for the initial phase the Renfroe pad.  All wells commenced production during the first week in September.  The wells were included in the reserve report as of August 31, 2013, where they were classified as proved non-producing wells.  Drilling operations on our second horizontal prospect, the Leffler, commenced during the fiscal fourth quarter and continued into the first fiscal quarter of 2014.  Drilling operations for the six wells initially planned for the Leffler prospect were substantially concluded by the end of October and the wells are scheduled for completion activities during November and December 2013.

Our first horizontal wells are being drilled under a contract with Ensign United States Drilling, Inc.  The contract, as amended, covers the use of one rig to drill a total of 25 wells.  Pricing is on a turn-key basis, with pricing adjustments based upon well location, target formation, and other technical details.  Assuming that the rig continues to drill approximately two horizontal wells per month, we anticipate completion of the current contract during the summer of 2014.

We continued our participation with other operators in vertical and horizontal wells in which we own a partial interest.  During 2012, we participated in 5 gross (1 net) horizontal wells that commenced production.  During 2013, the number of non-operated horizontal wells that commenced production increased to 11 gross (2.4 net).  In addition, as of August 31, 2013, we were participating in 8 gross (1 net) horizontal wells that were in various stages of drilling or completion.  Furthermore, by the end of October, we had received either an AFE (Authorization for Expenditure) or a preliminary drilling notification on 70 horizontal wells that may be drilled in 2014 and future years.  Our participation with other operators in vertical wells also increased during 2013, as 10 gross (3.7 net) wells commenced production.

On December 5, 2012, we completed an acquisition of assets from Orr Energy LLC.  The assets included 36 producing oil and gas wells along with a number of undeveloped leases.  We assumed operational responsibility on 35 of the producing wells.  Purchase consideration included cash of $29 million and 3,128,422 shares of our restricted common stock.  Our evaluation of the net assets indicates that the fair value of the acquisition approximates $42 million.  Revenues and expenses from the Orr properties were consolidated with our operations commencing on December 5, 2012.

As a result of our drilling activities, our acquisition activities, and our participation activities, we increased our proved reserve quantities by 30% during the year.  The August 31, 2013, reserve report indicated that we had estimated proved reserves of 7.0 million barrels of oil and 40.7 billion cubic feet of gas.  The estimated present value of future cash flows before tax (discounted at 10%) was $236 million.

On March 13, 2013, we completed an Exploration Agreement with Vecta Oil and Gas, Ltd., whereby we substantially increased our exposure in the Northern DJ basin area which has seen increasing drilling activity by other oil and gas companies.  Vecta, a firm which has considerable technical acumen in geology and geophysics, will provide their scientific expertise while we provide our expertise as oil and gas operators.  The Vecta deal fits our strategy on several fronts.  First, it expanded our net acreage in the area by nearly forty percent while spreading our risk across a larger section of the play.  Secondly, it allowed us to do so at competitive prices, as our average cost per acre for more than 19,000 acres in the Northern DJ Basin is approximately $400 per acre.  The leases have an average remaining term of three years and contain renewal options that will allow us to extend the term of the leases for another two or three years at a cost of less than $100 per acre.    Lastly, the area has potential for multiple pay formations, including the Greenhorn, Niobrara, D Sand and J Sand.

4

In November 2012, we modified our borrowing arrangement with Community Banks of Colorado, successor in interest to Bank of Choice, to increase the maximum allowable borrowings.  The new revolving line of credit increases the maximum lending commitment to $150 million.  Maximum borrowings are subject to reduction based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports.  Based upon the semi-annual redetermination derived from the February 28, 2013 reserve report, the borrowing base limitation was increased from $47 million to $75 million.  The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios.  The borrowing arrangement is collateralized by certain of our assets, including producing properties.

In December, we utilized a portion of the financing available through this arrangement to fund the acquisition of the Orr assets.  We currently have approximately $38 million available for future borrowings if needed.  Additional borrowings, if any, are expected to be used to fund acquisitions, expenditures for well drilling and development, and to provide working capital.

Interest 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.  At our option, interest rates will be referenced to the Prime Rate plus a margin of 0% to 1%, or the London InterBank Offered Rate plus a margin of 2.5% to 3.25%.  The maturity date for the arrangement is November 28, 2016.

During June 2013, we completed the sale of 13.2 million shares of our common stock at a price to the public of $6.25 per share for net proceeds totaling approximately $78.3 million after deduction of discounts, commissions and expenses.  The public offering of additional shares of our common stock was underwritten by a syndicate of investment bank led by Johnson Rice LLC.

We commenced our commodity derivative program beginning January 1, 2013.  Using swaps and collars, we contracted for approximately 340,000 barrels of oil through June 30, 2015.  The average price of our swap positions is approximately $96 per barrel for the remainder of calendar year 2013, $92 per barrel for calendar year 2014, and $86 per barrel for the first half of calendar year 2015.  Since we designed our commodity derivative activity to protect our cash flow during periods of oil price declines, the high average prices experienced during 2013 created a realized loss of $0.4 million for the year, and an unrealized decrease in the fair value of our commodity derivatives of $2.6 million.

We announced two pending transactions to acquire mineral interests.  In the aggregate, the agreements cover the acquisition of interests in 59 gross producing wells that we will operate, plus various other assets.  Subject to satisfactory completion of due diligence activities and all other conditions precedent, closings are scheduled for the first quarter of fiscal year 2014.  The transactions contemplate aggregate consideration of $37 million, including approximately $7 million payable in the form of shares of restricted common stock.  All amounts are subject to customary closing and post-closing adjustments.

In early September there was a devastating flood in Colorado.  The impact to our operations and assets will not be significant to our financial statement.  We had 20 well sites that were shut-in as a result of the flood.  We were able to quickly repair the damage and all the wells were brought back on-line during the first quarter.

5

Well and Production Data

During the periods presented below, we drilled or participated in the drilling of a number of wells that reached productive status in each respective fiscal year.  We did not drill any exploratory wells nor did we drill any dry holes during these years.  The following table excludes wells that are in the drilling or completion phase and had not reached the point at which they are capable of producing oil and gas.

	Years Ended August 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive:
Oil		48		32		64		52		31		22
Gas		—		—		—		—		—		—
Nonproductive		—		—		—		—		—		—

 Excluded from the table above are wells that had not reached productive status as of August 31, 2013.  As such, there were 16 gross (7.5 net) wells in progress that were not included in the above well counts. Except for one well, these wells are all located in, or adjacent to, the Wattenberg Field of the D-J Basin.  One well is located in Yuma County.

 The following table shows our net production of oil and gas, average sales prices and average production costs for the periods presented:

	Years Ended August 31,
	2013		2012		2011
Production:
Oil (Bbls)		421,265		235,691		89,917
Gas (Mcf)		2,107,603		1,109,057		450,831
BOE (Bbls)		772,532		420,534		165,055
Average sales price:
Oil ($/Bbl1)	$	85.95	$	87.59	$	83.07
Gas ($/Mcf2)	$	4.75	$	3.90	$	5.12
BOE	$	59.83	$	59.37	$	59.24
Average production cost per BOE3	$	4.42	$	2.73	$	2.13

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.

Production costs are substantially similar among our wells as all of our wells are in the Wattenberg Field and employ the same methods of recovery.  Production costs generally include pumping fees, maintenance, repairs, labor, utilities and administrative overhead.  Taxes on production, including ad valorem and severance taxes, are excluded from production costs.

We are not obligated to provide a fixed and determined quantity of oil or gas to any third party in the future.  During the last three fiscal years, we have not had, nor do we now have, any long-term supply or similar agreement with any government or governmental authority.

6

Oil and Gas Properties

We evaluate undeveloped oil and gas prospects and participate in drilling activities on those prospects, which, in the opinion of our management, are favorable for the production of oil or gas.  If, through our review, a geographical area indicates geological and economic potential, we will attempt to acquire leases or other interests in the area.  We may then attempt to sell portions of our leasehold interests in a prospect to third parties, thus sharing the risks and rewards of the exploration and development of the prospect with the other owners.  One or more wells may be drilled on a prospect, and if the results indicate the presence of sufficient oil and gas reserves, additional wells may be drilled on the prospect.

We may also:

· acquire a working interest in one or more prospects from others and participate with the other working interest owners in drilling, and if warranted, completing oil or gas wells on a prospect, or

· purchase producing oil or gas properties.

Our activities are primarily dependent upon available financing.

Title to properties we acquire may be subject to royalty, overriding royalty, working and other similar interests and contractual arrangements customary in the oil and gas industry, and subject to liens for current taxes not yet due and to other encumbrances.  As is customary in the industry, in the case of undeveloped properties little investigation of record title will be made at the time of acquisition (other than a preliminary review of local records).  However, drilling title opinions may be obtained before commencement of drilling operations.

The following table shows, as of October 31, 2013, by state, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells:

	Productive Wells				Developed Acreage				Undeveloped Acreage1
State	Gross		Net		Gross		Net		Gross		Net
Colorado		307		230		11,306		9,372		231,140		103,214
Nebraska		—		—		—		—		141,771		141,451
Wyoming		—		—		—		—		1,143		472
Total		307		230		11,306		9,372		374,054		245,137

            1  Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.

The following table shows, as of October 31, 2013, the status of our gross acreage:

State	Held by Production		Not Held by Production
Colorado		12,550		229,896
Nebraska		—		141,771
Wyoming		—		1,143
Total		12,550		372,810

 Acres that are Held by Production remain in force so long as oil or gas is produced from the well on the particular lease.  Leased acres which are not Held By Production require annual rental payments to maintain the lease until the first to occur of the following: the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage.  At the time oil or gas is produced from wells drilled on the leased acreage, the lease is considered to be Held by Production.

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 The following table shows the years our leases, which are not Held By Production, will expire, unless a productive oil or gas well is drilled on the lease.

Leased Acres	Expiration of Lease
34,616	2014
73,376	2015
42,023	2016
222,795	After 2016

 The overriding royalty interests that we own are not material to our business.

Proved Reserve Estimates

 Ryder Scott Company, L.P. (“Ryder Scott”) prepared the estimates of our proved reserves, future productions and income attributable to our leasehold interests for the year ended August 31, 2013.  Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years.  The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by teams of geoscientists and engineers employed at Ryder Scott.  The office of Ryder Scott that prepared our reserves estimates is registered in the state of Texas (License #F-1580).  Ryder Scott prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for our wells.  Additionally, authorizations for expenditure, geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to Ryder Scott engineers for consideration in estimating our underground accumulations of crude oil and natural gas.

The report of Ryder Scott dated October 16, 2013, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99 to this report.

Ed Holloway, our  Co-Chief Executive Officer, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission.  Mr. Holloway has over thirty years of experience in oil and gas exploration and development.

 Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology.  Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.

 Estimates of volumes of proved reserves at year end are presented in barrels (Bbls) for oil and for, natural gas, in thousands of cubic feet (Mcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.

 The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include decline curve analysis, which utilized extrapolations of historical production and pressure data available through August 31, 2013, in those cases where this data was considered to be definitive.  The data used in this analysis was obtained from public data sources and were considered sufficient for calculating producing reserves.

 The proved non-producing and undeveloped reserves were estimated by the analogy method.  The analogy method uses pertinent well data obtained from public data sources that were available through August 2013.

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 Below are estimates of our net proved reserves at August 31, 2013, all of which are located in Colorado:

	Oil		Gas
	(Bbls)		(Mcf)
Proved:
Producing		1,894,222		11,513,428
Nonproducing		2,765,183		14,352,580
Undeveloped		2,387,870		14,823,823
Total		7,047,275		40,689,831

Below are estimates of our present value of estimated future net revenues from such reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities – Oil and Gas.  The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions.  The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the years ended August 31, 2013, 2012 and 2011.  The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels.  No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead.  Present values were computed by discounting future net revenues by 10% per year.

As of August 31, 2013, 2012 and 2011, our standardized oil and gas measurements were as follows (in thousands):

	Proved - August 31, 2013
	Developed									Total
	Producing			Nonproducing			Undeveloped			Proved
Future gross revenue	$	206,065		$	286,207		$	256,758		$	749,030
Deductions		(46,410	)		(78,691	)		(129,541	)		(254,642	)
Future net cash flow		159,655			207,516			127,217			494,388
Discounted future net cash flow (pre-tax)	$	92,888		$	104,392		$	38,836		$	236,116
Standardized measure of discounted future
net cash flows (after tax)										$	181,732

	Proved - August 31, 2012
	Developed									Total
	Producing			Nonproducing			Undeveloped			Proved
Future gross revenue	$	120,802		$	173,144		$	243,516		$	537,462
Deductions		(21,099	)		(48,536	)		(116,798	)		(186,433	)
Future net cash flow		99,703			124,608			126,718			351,029
Discounted future net cash flow (pre-tax)	$	57,797		$	56,196		$	34,890		$	148,883
Standardized measure of discounted future
net cash flows (after tax)										$	102,505

	Proved - August 31, 2011
	Developed									Total
	Producing			Nonproducing			Undeveloped			Proved
Future gross revenue	$	71,027		$	18,819		$	145,392		$	235,238
Deductions		(14,298	)		(5,647	)		(61,736	)		(81,681	)
Future net cash flow		56,729			13,172			83,656			153,557
Discounted future net cash flow (pre-tax)	$	33,947		$	6,996		$	30,815		$	71,758
Standardized measure of discounted future
net cash flows (after tax)										$	57,550

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For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2013, generated increases in projected future gross revenue from proved reserves of $211.6 million and future net cash flow of $143.3 million from August 31, 2012.  During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $87.2 million.  Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2013, of approximately $104.3 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.

For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2012, generated increases in projected future gross revenue from proved reserves of $302.2 million and future net cash flow of $197.4 million from August 31, 2011.  During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $77.1 million.  Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2012, of approximately $33 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.

In general, the volume of production from our oil and gas properties declines as reserves are depleted.  Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.  Accordingly, volumes generated from our future activities are highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.

Proved Undeveloped Reserves
	Net Reserves, Boe
	At August 31, 2013
Beginning of Year		4,939,735
Converted to proved developed		(185,246	)
Additions from capital program		481,463
Acquisitions (sales)		674,531
Revisions (pricing and engineering)		(1,051,976	)
End of year		4,858,507

At August 31, 2013, our proved undeveloped reserves were 4,858,507 Boe. None of the proved undeveloped reserves have been in this category for more than 5 years and all are scheduled to be drilled within five years of their initial discovery.  During 2013, 185,246 Boe or 4% of our proved undeveloped reserves (6 wells) were converted into proved developed reserves requiring $3.6 million of drilling and completion capital expenditures.  Executing our 2013 capital program resulted in the addition of 481,463 Boe in proved undeveloped reserves (5 wells).

The transition from vertical drilling to horizontal drilling resulted in a conversion rate of less than 20% of proved undeveloped reserves to proved developed reserves for the year.  In addition, the negative revision of 1,051,976 Boe is primarily the result from eliminating previously planned vertical proved undeveloped locations while planning for horizontal development.

In 2014, our drilling plans are expected to convert over 20% of our proved undeveloped reserves into proved developed reserves.  Cash proceeds of $78.3 million received from the sale of equity in June 2013 are being used to accelerate our drilling program in 2014.

Government Regulation

Various state and federal agencies regulate the production and sale of oil and natural gas.  All states in which we plan to operate impose restrictions on the drilling, production, transportation and sale of oil and natural gas.

The Colorado Oil and Gas Conservation Commission (“COGCC”) is the primary regulator of exploration and production of oil and gas resources in the area in which we operate.  Via the permitting and inspection process, COGCC regulates oil and gas operators and, among other criteria, enforces specifications regarding the mechanical integrity of wells as well as the prevention and mitigation of adverse environmental impacts.

The Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas.  FERC’s jurisdiction over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce.

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FERC has pursued policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. We do not know what effect FERC’s other activities will have on the access to markets, the fostering of competition and the cost of doing business.

Our sales of oil and natural gas liquids will not be regulated and will be at market prices. The price received from the sale of these products will be affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines.

Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production and related operations. Most states require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil and gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and gas is produced from our properties. The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with those laws.

 As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment.  The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue.  These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.

 The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities.  Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both.  In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in their interpretation could have a significant impact on us, as well as the oil and natural gas industry in general.

  The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites.  It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize imposition of substantial fines and penalties for noncompliance.  Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products.  In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

   Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters.  The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States.  For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility.  Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us.  In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas.  The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations.  We are required to maintain such permits or meet general permit requirements.  The EPA and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions.  These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit.  Most agencies recognize the unique qualities of oil and natural gas exploration and production operations.  A number of agencies have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit pollutants.  We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.

   The EPA recently amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act (the “SDWA”) to exclude hydraulic fracturing from the definition of “underground injection.”  However, the U.S. Senate and House of Representatives are currently considering the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”), which will amend the SDWA to repeal this exemption.  If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, which could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements.

   The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.  While no federal law is presently in place, some states have enacted laws pertaining to chemical disclosure.  In December 2011, the State of Colorado approved regulation requiring parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process.  The regulation went into effect in April 2012 and requires the reporting of additives used.

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On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes.  These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.

Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources.  In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2012 for emissions occurring in 2011.

Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (the “ACESA”) which would establish an economy-wide cap-and-trade program to reduce United States emissions of greenhouse gases including carbon dioxide and methane that may contribute to the warming of the Earth’s atmosphere and other climatic changes.  If it becomes law, ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050.  Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere.  These allowances would be expected to escalate significantly in cost over time.  The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas.

Climate change has emerged as an important topic in public policy debate regarding our environment.  It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases, which may ultimately pose a risk to society and the environment.  Products produced by the oil and natural gas exploration and production industry are a source of certain greenhouse gases, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

Hydraulic Fracturing

We operate in the Wattenberg Field of the D-J Basin where the rock formations are typically tight and it is a common practice to utilize hydraulic fracturing to allow for or increase hydrocarbon production.  Hydraulic fracturing involves the process of forcing a mixture of fluid and white sand into a formation to create pores and fractures, thus creating a passageway for the release of oil and gas.  All of our producing wells were hydraulic fractured and we expect to employ the technique extensively in future wells that we drill and complete.

We outsource all hydraulic fracturing services to service providers with significant experience, and which we deem to be competent and responsible.  Our service providers supply all personnel, equipment and materials needed to perform each stimulation, including the mixtures that are injected into our wells.  These mixtures primarily consist of water and sand, with nominal amounts of other ingredients used as accelerants and proppants.  The additional ingredients are designed to improve the resulting porosity of the shale and include food based compounds commonly found in consumer products.  This mixture is injected into our wells at pressures of 4,500-6,000 psi at injection rates that that range between 25-55 barrels of mixture per minute.  On average, a single stage stimulation will utilize approximately 4,500 barrels of water and 150,000 pounds of sand.

We require our service companies to carry adequate insurance covering incidents that could occur in connection with their activities.  Our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the respective geographic location.  We have not had any incidents, citations or lawsuits relating to any environmental issues resulting from hydraulic fracture stimulation and we are not presently aware of any such matters.

In recent years, environmental opposition to hydraulic fracturing has increased, and various governmental and regulatory authorities are considering the adequacy of current regulations.  In Colorado, the primary regulator is the Colorado Oil and Gas Conservation Commission, which requires parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process.  Some municipalities are considering, or have adopted, more stringent regulations, including the prohibition of hydraulic fracturing within their city limits.  We continue to monitor these developments, as we consider the process to be critical to our success.

Competition and Marketing

We are faced with strong competition from many other companies and individuals engaged in the oil and gas business, many of which are very large, well established energy companies with substantial capabilities and established earnings records.  We may be at a competitive disadvantage in acquiring oil and gas prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs.  It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business.

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Exploration for and production of oil and gas are affected by the availability of pipe, casing and other tubular goods and certain other oil field equipment including drilling rigs and tools.  We depend upon independent drilling contractors to furnish rigs, equipment and tools to drill our wells.  Higher prices for oil and gas may result in competition among operators for drilling equipment, tubular goods and drilling crews, which may affect our ability expeditiously to drill, complete, recomplete and work-over wells.

The market for oil and gas is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted.  These factors include the proximity of wells to, and the capacity of, natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation.  In addition, there is always the possibility that new legislation may be enacted, which would impose price controls or additional excise taxes upon crude oil or natural gas, or both.  Oversupplies of natural gas can be expected to recur from time to time and may result in the gas producing wells being shut-in.  Imports of natural gas may adversely affect the market for domestic natural gas.

The market price for crude oil is significantly affected by policies adopted by the member nations of Organization of Petroleum Exporting Countries ("OPEC").  Members of OPEC establish prices and production quotas among themselves for petroleum products from time to time with the intent of controlling the current global supply and consequently price levels.  We are unable to predict the effect, if any, that OPEC or other countries will have on the amount of, or the prices received for, crude oil and natural gas.

Gas prices, which were once effectively determined by government regulations, are now largely influenced by competition.  Competitors in this market include producers, gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as residual fuel oil.  Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry.

Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term contracts priced at spot market prices.

General

Our offices are located at 20203 Highway 60, Platteville, CO  80651.  Our office telephone number is (970) 737-1073 and our fax number is (970) 737-1045.

The Platteville office and equipment yard is rented to us pursuant to a lease with HS Land & Cattle, LLC, a firm controlled by Ed Holloway and William E. Scaff, Jr., two of our officers.  The 2013 lease, which expired on July 1, 2013, required monthly payments of $10,000.  The 2014 lease, which will expire on July 1, 2014, requires monthly payments of $15,000. The 2014 lease increased rentable area to the leased premises, including a field operations office.

As of October 31, 2013, we had 16 full time employees.

Neither we, nor any of our properties, are subject to any pending legal proceedings.

Available Information

We make available on our website, www.syrginfo.com, under “Investor Relations, SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”).

The “Investor Relations, News / Events” pages on our website contain press releases and investor presentations with more recent information than may have been available at the time of the most recent filing with the SEC.

Our Code of Ethics and Board of Directors Committee Charters (Audit and Compensation Committees) are also available on our website under “Investor Relations, Corporate Governance.”

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ITEM 1A.  RISK FACTORS

Investors should be aware that any purchase of our securities involves certain risks, including those described below, which could adversely affect the value of our common stock.  We do not make, nor have we authorized any other person to make, any representation about the future market value of our common stock.  In addition to the other information contained in this annual report, the following factors should be considered carefully in evaluating an investment in our securities.

Laws and Regulations

Our operations will be affected from time to time and in varying degrees by political developments and federal and state laws and regulations regarding the development, production and sale of crude oil and natural gas.  These regulations require permits for drilling of wells and also cover the spacing of wells, the prevention of waste, and other matters.  Rates of production of oil and gas have for many years been subject to federal and state conservation laws and regulations.

In addition, the production of oil or gas may be interrupted or terminated by governmental authorities due to ecological and other considerations.  Compliance with these regulations may require a significant capital commitment by and expense to us and may delay or otherwise adversely affect our operations.

From time to time legislation has been proposed relating to various conservation and other measures designed to decrease dependence on foreign oil.  No prediction can be made as to what additional legislation may be proposed or enacted.  Oil and gas producers may face increasingly stringent regulation in the years ahead and a general hostility towards the oil and gas industry on the part of a portion of the public and of some public officials.  Future regulation will probably be determined by a number of economic and political factors beyond our control or the oil and gas industry.

Our activities are subject to existing federal and state laws and regulations governing environmental quality and pollution control.  Compliance with environmental requirements and reclamation laws imposed by federal, state, and local governmental authorities may necessitate significant capital outlays and may materially affect our earnings.  It is impossible to predict the impact of environmental legislation and regulations (including regulations restricting access and surface use) on our operations in the future although compliance may necessitate significant capital outlays, materially affect our earning power or cause material changes in our intended business.  In addition, we may be exposed to potential liability for pollution and other damages.

Dry holes and non-productive wells

Oil and gas exploration is not an exact science, and involves a high degree of risk.  The primary risk lies in the drilling of dry holes or drilling and completing wells, which, though productive, do not produce gas and/or oil in sufficient amounts to return the amounts expended and produce a profit.  Hazards, such as unusual or unexpected formation pressures, downhole fires, blowouts, loss of circulation of drilling fluids and other conditions are involved in drilling and completing oil and gas wells and, if such hazards are encountered, completion of any well may be substantially delayed or prevented.  In addition, adverse weather conditions can hinder or delay operations, as can shortages of equipment and materials or unavailability of drilling, completion, and/or work-over rigs.  Even though a well is completed and is found to be productive, water and/or other substances may be encountered in the well, which may impair or prevent production or marketing of oil or gas from the well.

Exploratory drilling involves substantially greater economic risks than development drilling because the percentage of wells completed as producing wells is usually less than in development drilling.  Exploratory drilling itself can be of varying degrees of risk and can generally be divided into higher risk attempts to discover a reservoir in a completely unproven area or relatively lower risk efforts in areas not too distant from existing reservoirs.  While exploration adjacent to or near existing reservoirs may be more likely to result in the discovery of oil and gas than in completely unproven areas, exploratory efforts are nevertheless high risk activities.

Although the completion of oil and gas wells is, to a certain extent, less risky than drilling for oil and gas, the process of completing an oil or gas well is nevertheless associated with considerable risk.  In addition, even if a well is completed as a producer, the well for a variety of reasons may not produce oil or gas in quantities sufficient to repay our investment in the well.

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The acquisition, exploration and development of oil and gas properties, and the production and sale of oil and gas are subject to many factors not under our control.  These factors include, among others, general economic conditions, proximity to pipelines, oil import quotas, supply, demand, and price of other fuels and the regulation of production, refining, transportation, pricing, marketing and taxation by various governmental authorities.

Supply and demand

Buyers of our gas, if any, may refuse to purchase gas from us in the event of oversupply.  If we drill wells that are productive of natural gas, the quantities of gas that we may be able to sell may be too small to pay for the expenses of operating the wells.  In such a case, the wells would be "shut-in" until such time, if ever, that economic conditions permit the sale of gas in quantities which would be profitable.

Insurable risks, defects, and hazards

Interests that we may acquire in oil and gas properties may be subject to royalty and overriding royalty interests, liens incident to operating agreements, liens for current taxes and other burdens and encumbrances, easements and other restrictions, any of which may subject us to future undetermined expenses.  We do not intend to purchase title insurance, title memos, or title certificates for any leasehold interests we will acquire.

It is possible that at some point we will have to undertake title work involving substantial costs.  In addition, it is possible that we may suffer title failures resulting in significant losses.

The drilling of oil and gas wells involves hazards such as blowouts, unusual or unexpected formations, pressures or other conditions, which could result in substantial losses or liabilities to third parties.  Although we intend to acquire adequate insurance, or to be named as an insured under coverage acquired by others (e.g., the driller or operator), we may not be insured against all such losses because insurance may not be available, premium costs may be deemed unduly high, or for other reasons.  Accordingly, uninsured liabilities to third parties could result in the loss of our funds or property.

Opposition to Hydraulic Fracturing

Hydraulic fracturing, the process used for releasing oil and gas from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.  While companies have been using the technique for decades, as drilling expands to more populated areas, environmentalists raise concern about the effects on the population’s health and drinking water.

In April of this year, the Obama administration proposed the first national standards to control air pollution from gas wells stimulated by hydraulic fracturing.  The EPA published claims that the new regulations would ensure pollution is controlled without slowing natural gas production, actually resulting in more product for fuel suppliers to bring to market.  The proposal would restrict the venting of gases during the well completion phase, and require the implementation of a new technology to reduce emissions of pollutants during completion of wells.  Implementation of the pollution-reducing equipment for so-called “green completions” is required by January 2015.

Locally, some counties and municipalities are attempting to impose more stringent regulations than those required by the Colorado Oil and Gas Conservation Commission.  Litigation has been initiated to determine the legality of these attempts.  Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, state and/or local levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements.  Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and gas resources from shale formations which are not commercial without the use of hydraulic fracturing.  This could have an adverse effect on our business.

Related Party Transactions

 Our transactions with related parties may cause conflicts of interests that may adversely affect us.  Ed Holloway and William E. Scaff, Jr., both of whom are officers, directors and principal shareholders, control two entities, Petroleum Exploration & Management, LLC ("PEM") and HS Land & Cattle, LLC (“HSLC”), with whom we do business.  We presently lease the Platteville office space and equipment storage yard from HSLC at a rate of $15,000 per month.  During 2011, we purchased all of the operating oil and gas assets owned by PEM.    Material transactions with related parties are approved by our independent directors.

We believe that the transactions and agreements that we have entered into with these affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third parties.  However, these relationships could create, or appear to create, potential conflicts of interest when our board of directors is faced with decisions that could have different implications for us and these affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public's perception of us, as well as our relationship with other companies and our ability to enter into new relationships in the future, which could have a material adverse effect on our ability to do business.

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Funding

Our failure to obtain capital may significantly restrict our proposed operations.  We may need additional capital to fund our capital expenditure plans.  We do not know what the terms of any future capital raising may be but any future sale of our equity securities would dilute the ownership of existing stockholders and could be at prices substantially below the price investors paid for their shares of our common stock. Our failure to obtain the capital required will result in the slower implementation of our business plan.  There can be no assurance that we will be able to obtain the necessary capital.

We will need to consistently generate positive cash flow or obtain additional financing to consistently yield sufficient cash for the growth of our operations and to execute our strategic business plan.

Market for our Common Stock

Although our common stock has been listed on the NYSE MKT since July 27, 2011, the trading in our stock has, at times, been limited and sporadic.  Additionally, the trading price of our common stock may fluctuate widely in response to various factors, some of which are beyond our control.  Factors that could negatively affect our share price include, but are not limited to:

·   actual or anticipated fluctuations in our quarterly results of operations;

·   liquidity;

·   sales of common stock by our shareholders;

·   changes in oil and natural gas prices;

·   changes in our cash flow from operations or earnings estimates;

·   publication of research reports about us or the oil and natural gas exploration and production industry generally;

·   increases in market interest rates which may increase our cost of capital;

·   changes in applicable laws or regulations, court rulings and enforcement and legal actions;

·   changes in market valuations of similar companies;

·   adverse market reaction to any indebtedness we incur in the future;

·   additions or departures of key management personnel;

·   actions by our shareholders;

·   political opposition to the oil and gas industry

·   commencement of or involvement in litigation;

·   news reports relating to trends, concerns, technological or competitive developments, regulatory changes and other related issues in our industry;

·   speculation in the press or investment community regarding our business;

·   general market and economic conditions; and

·   domestic and international economic, legal and regulatory factors unrelated to our performance.

Shares issuable upon the exercise of outstanding warrants and options may substantially increase the number of shares available for sale in the public market and may depress the price of our common stock.  We have outstanding options and warrants which could potentially allow the holders to acquire a substantial number of shares of our common stock.  Until the options and warrants expire, the holders will have an opportunity to profit from any increase in the market price of our common stock without assuming the risks of ownership.  Holders of options and warrants may exercise these securities at a time when we could obtain additional capital on terms more favorable than those provided by the options or warrants.  The exercise of the options and warrants will dilute the voting interest of the current owners of our outstanding shares by adding a substantial number of additional shares of common stock.

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Reliance on Key Personnel

We are dependent upon the contributions of our senior management team and other key employees for our success.  If one or more of these executives, or other key employees, were to cease to be employed by us, our progress could be adversely affected.  In particular, we may have to incur costs to replace senior executive officers or other key employees who leave, and our ability to execute our business strategy could be impaired if we are unable to replace such persons in a timely manner.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.  PROPERTIES

See Item 1 of this report.

ITEM 3.  LEGAL PROCEEDINGS

None.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the NYSE MKT under the symbol “SYRG”.

Trading of our stock on the NYSE Amex (predecessor to the NYSE MKT) began on July 27, 2011.  Prior to listing on the NYSE Amex, our stock traded on the OTC Bulletin Board.  Shown below is the range of high and low sales prices for our common stock as reported by the NYSE MKT since September 1, 2011. 

Quarter Ended	High	Low
November 30, 2011	$3.75	$2.20
February 29, 2012	$3.72	$2.42
May 31, 2012	$3.65	$2.52
August 31, 2012	$3.10	$2.40

Quarter Ended	High	Low
November 30, 2012	$4.74	$2.70
February 28, 2013	$7.00	$3.75
May 31, 2013	$7.78	$6.14
August 31, 2013	$9.43	$6.23

As of October 31, 2013, the closing price of our common stock on the NYSE MKT was $10.36.

As of October 31, 2013, we had 74,391,364 outstanding shares of common stock and 149 shareholders of record.  The number of beneficial owners of our common stock is in excess of 4,600.

Since inception, we have not paid any cash dividends on common stock.  Cash dividends are restricted under the terms of our credit facility and we presently intend to continue the policy of using retained earnings for expansion of our business.

Our articles of incorporation authorize our board of directors to issue up to 10,000,000 shares of preferred stock.  The provisions in the articles of incorporation relating to the preferred stock allow our directors to issue preferred stock with multiple votes per share and dividend rights, which would have priority over any dividends paid with respect to the holders of our common stock.  The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in certain transactions such as mergers or tender offers if these transactions are not favored by our management.

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Additional Shares Which May be Issued

The following table lists additional shares of our common stock, which may be issued as of October 31, 2013, upon the exercise of outstanding options or warrants or the issuance of shares for oil and gas leases.

	Number of Shares	Note Reference
Shares issuable upon the exercise of Series C warrants	4,782,750	A
Shares issuable upon the exercise of Series D warrants     (also described as Placement Agent warrants)	63,989	A
Shares issuable upon exercise of investor relations warrants	25,000	B
Shares issuable upon exercise of options held by our officers and employees	1,954,000	C

A.           We issued 9,000,000 Series C warrants in connection with the sale of 180 Units at a price of $100,000 per Unit to private investors during fiscal year 2010.  Each Unit consisted of one $100,000 note and 50,000 Series C warrants.   Each Series C warrant entitles the holder to purchase one share of our common stock at a price of $6.00 per share at any time prior to December 31, 2014.  As of October 31, 2013, 4,217,250 warrants had been exercised.  We received cash proceeds of $25.3 million from the exercise of the warrants.

In connection with the unit offering, we also sold to the placement agent, for a nominal price, warrants to purchase 1,125,000 shares of our common stock at a price of $1.60 per share (these warrants are sometimes described as Series D warrants).  The placement agent’s warrants expire on December 31, 2014.  As of October 31, 2013, warrants to purchase 1,061,011 shares had been exercised by their holders.

B.           During the fiscal year ended August 31, 2012, we entered into an agreement with an investor relations firm and agreed to issue warrants to the firm.  Each warrant entitles the holder to purchase one share of common stock at a price of $2.69 at any time prior to December 31, 2015.  As of October 31, 2013, 25,000 warrants had been exercised.

C.           See Item 11 of this report for information regarding shares issuable upon exercise of options held by our officers and employees.

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Comparison of Cumulative Return

The performance graph below compares the cumulative total return of our common stock over the five-year period ended August 31, 2013 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the companies with a Standard Industrial Code ("SIC") of 1311. The SIC Code 1311 is a weighted composite of 254 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on September 1, 2008 and in the S&P 500 Index and the SIC Code on the same date. The results shown in the graph below are not necessarily indicative of future performance.

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ITEM 6.       SELECTED FINANCIAL DATA

The selected financial data presented in this item has been derived from our audited financial statements that are either included in this report or in reports previously filed with the U.S. Securities and Exchange Commission.  The information in this item should be read in conjunction with the financial statements and accompanying notes and other financial data included in this report.

	For the Years Ended August 31,
	2013		2012		2011			2010			2009
Results of Operations (in thousands):
Revenues	$	46,223	$	24,969	$	10,002		$	2,158		$	94
Net income (loss)		9,581		12,124		(11,600	)		(10,794	)		(12,352	)
Net income (loss) per common share:
Basic	$	0.17	$	0.26	$	(0.45	)	$	(0.88	)	$	(1.14	)
Diluted	$	0.16	$	0.25	$	(0.45	)	$	(0.88	)	$	(1.14	)
Certain Balance Sheet Information (in thousands):
Total Assets	$	291,236	$	120,731	$	63,698		$	24,842		$	4,833
Working Capital		50,608		10,875		685			6,237			2,249
Total Liabilities		88,016		19,619		14,590			25,859			1,844
Equity (Deficit)		203,220		101,112		49,108			(1,017	)		2,988
Certain Operating Statistics:
Production:
Oil (Bbls)		421,265		235,691		89,917			21,080			1,730
Gas (Mcf)		2,107,603		1,109,057		450,831			141,154			4,386
Total production in BOE		772,532		420,534		165,056			44,606			2,461
Average sales price per BOE	$	59.83	$	59.38	$	59.24		$	48.39		$	38.25
LOE per BOE	$	4.42	$	2.89	$	2.94		$	1.94		$	4.70
DDA per BOE	$	17.26	$	14.29	$	16.62		$	15.52		$	39.54

The fluctuation in results of operations and financial position is due in part to acquisitions of producing oil and gas properties coupled with the aggressive drilling program we executed during 2011, 2012 and 2013.

See Note 17 to the Financial Statements included as part of this report for our quarterly financial data.

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ITEM 7. 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 explain certain items regarding the financial condition as of August 31, 2013, and the results of operations for the years ended August 31, 2013, 2012 and 2011.  It should be read in conjunction with the “Selected Financial Data” and the accompanying audited financial statements and related notes thereto contained in this Annual Report on Form 10-K.

This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties.  See the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.  Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements.  Factors that might cause such differences include, but are not limited to, those discussed in the subsection entitled “Risk Factors” above, which are incorporated herein by reference.  We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

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. Substantially all of our producing wells are either in or adjacent to the Wattenberg Field, which has a history as one of the most prolific production areas in the country.  In addition to the approximately 22,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold significant undeveloped acreage positions in (i) the northern extension area of the D-J Basin, (ii) in an area around Yuma County that produces dry gas, and (iii) in western Nebraska.  While we do not expect to devote significant resources to the exploration and development of our holdings outside of the Wattenberg Field in the near future, we recently participated in a well in Yuma County that is producing dry gas and we expect to drill two test wells in the northern extension area.

Since commencing active operations in September 2008, we have undergone significant growth.  Our growth was primarily driven by (i) our activities as an operator where we drill and complete productive oil and gas wells; (ii) our participation as a part owner in wells drilled by other operating companies; and (iii) our acquisition of producing oil wells from other individuals or companies.  As disclosed in the following table, as of August 31, 2013, we have completed, acquired, or participated in 293 gross (224 net) successful oil and gas wells.  We have not drilled or participated in any dry holes.

	PRODUCTIVE WELLS
	OPERATED WELLS				NON-OPERATED WELLS
	Completed				Participated				Acquired				Total
Years ended:	Gross		Net		Gross		Net		Gross		Net		Gross		Net
August 31, 2009		-				2		1		-				2		1
August 31, 2010		36		28		-		-		-				36		28
August 31, 2011		20		19		11		3		72		51		103		73
August 31, 2012		51		48		13		4		4		4		68		56
August 31, 2013		27		26		21		6		36		34		84		66
Total		134		121		47		14		112		89		293		224

In addition to the 293 wells that had reached productive status as of August 31, 2013, we were the operator of seven horizontal wells in progress, including five wells on the Renfroe prospect that commenced production during the first week of September, and we were participating as a non-operator in nine gross (one net) wells that were in various stages of the drilling or completion process.  Wells in progress represent wells during the period of time between spud date and date of first production.  Generally, horizontal wells are expected to require 120 to 150 days to drill, complete and connect to the gathering system.  All of the wells in progress at August 31, 2013, are expected to commence production during our first or second fiscal quarter of 2014.

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As of August 31, 2013, we:

·   were the operator of 218 wells that were producing oil and gas and we were participating as a non-operating working interest owner in 75 producing wells;

·   held approximately 374,000 gross acres and 245,000 net acres under lease;

·   had estimated proved reserves of 7.0 million barrels (“Bbls”) of oil and 40.7 billion cubic feet (“Bcf”) of gas;

·   on a BOE basis, increased our estimated proved reserves by 30% during fiscal 2013; and

·   on a PV-10 basis, increased our estimated proved reserves by 59% during fiscal 2013

Our basic strategy for continued growth includes additional drilling activities and acquisition of existing wells in well-defined areas that provide significant cash flow and rapid return on investment.  We attempt to maximize our return on assets by drilling in low risk areas and by operating wells in which we have a majority net revenue interest.  Our drilling efforts are focused on the Wattenberg Field as it yields consistent results.  Until 2012, all of our wells were low risk vertical wells.  During 2012, we began to participate with other operators in horizontal wells.  The success of those wells, as well as the success of numerous other horizontal wells drilled in this area, convinced us to shift our strategy from vertical wells to horizontal wells.  During 2013, we spent the first half of the year drilling vertical wells and spent the second half of the year drilling horizontal wells.  Our plans for 2014 contemplate drilling or participating in 25 horizontal wells.  Our horizontal wells will primarily target the Niobrara and Codell formations.

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.

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Results of Operations

Material changes of certain items in our statements of operations included in our financial statements for the periods presented are discussed below.

For the year ended August 31, 2013, compared to the year ended August 31, 2012

For the year ended August 31, 2013, we reported net income of $9.6 million, or $0.17 per basic share, $0.16 per diluted share, compared to net income of $12.1 million, or $0.26 per basic share and $0.25 per diluted share for the period ended August 31, 2012.  The decline in net income for 2013 reflects significant non-cash charges for an unrealized loss of $2.6 million on our commodity derivatives and a provision for deferred income taxes of $6.9 million.

There was an improvement in operating income, which increased from $11.8 million in 2012 to $19.5 million.  Our 66% improvement in operating profitability was driven by our successful drilling program and integration of producing wells added in the Orr Energy acquisition. The significant variances between the two years were primarily caused by increased revenues and expenses associated with a greater number of producing wells.  The following discussion expands upon significant items of inflow and outflow that affected results of operations

Oil and Gas Production and Revenues – For the year ended August 31, 2013, we recorded total revenues of $46.2 million compared to $25.0 million for the year ended August 31, 2012, an increase of $21.2 million or 85%.  We experienced an overall 84% annual increase in production quantities from the prior year having realized a full year of production from wells at the beginning of the year, and the addition of wells, including new wells drilled as well as those acquired with the December 2012 Orr Energy acquisition.

	Years Ended August 31,
	2013		2012
Production:
Oil (Bbls1)		421,265		235,691
Gas (Mcf2)		2,107,603		1,109,057
Total production in BOE3		772,532		420,534
Revenues (in thousands):
Oil	$	36,206	$	20,644
Gas		10,017		4,325
Total	$	46,223	$	24,969
Average sales price:
Oil (Bbls1)	$	85.95	$	87.59
Gas (Mcf2)	$	4.75	$	3.90
BOE3	$	59.83	$	59.38

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.

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As of August 31, 2013, we owned interests in 293 producing wells.  Net oil and gas production averaged 2,117 BOE per day in 2013, as compared with 1,149 BOE per day for 2012, a year over year increase of 84% in BOEPD production.  The significant increase in production from the prior year reflects 84 additional wells that went into productive status during 2013 and a full year of production from the 68 wells that were added over the course of fiscal year 2012.  Production for the fourth fiscal quarter of 2013 averaged 2,479 BOE per day.

Revenues are sensitive to changes in commodity prices.  From 2012 to 2013, our realized annual average sales price per barrel of oil decreased 2%; however, we experienced an increase of 22% in our realized annual average sales price per Mcf of natural gas.  Overall on a BOE basis, 99% of the increase in oil and gas revenues was attributed to increased volumes and 1% was attributed to the increase of BOE prices received.

Lease Operating Expenses (“LOE”) and Production Taxes – Direct operating costs of producing oil and natural gas and taxes on production and properties are summarized as follows (in thousands):

	Years Ended August 31,
Lease Operating Expenses	2013		2012
Lifting costs	$	3,198	$	1,146
Work-over		219		66
Total LOE	$	3,417	$	1,212
LOE per BOE	$	4.42	$	2.88

	Years Ended August 31,
Production Taxes	2013		2012
Severance and ad valorem taxes	$	4,237	$	2,436
Production taxes per BOE	$	5.48	$	5.79

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.  From 2012 to 2013, 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 9.2% in 2013 and 9.8% 2012.

Depletion, Depreciation and Amortization (“DDA”) – The following table summarizes the components of DDA.  Depletion expense more than doubled, primarily as a result of growth in production and producing properties from 2012 to 2013.

	Years ended August 31,
(in thousands)	2013		2012
Depletion	$	13,046	$	5,838
Depreciation and amortization		290		172
Total DDA	$	13,336	$	6,010
DDA expense per BOE	$	17.26	$	14.29

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 fiscal year 2013, our depletable reserve base was 14,829,487 BOE.  Fiscal year 2013 production represented 5.2% of the reserve base.

Depletion expense per BOE increased 21% from 2012 to 2013.  For the fiscal year ended August 31, 2013, depletion of oil and gas properties was $17.26 per BOE compared to $14.29 for the fiscal year ended August 31, 2012.  The increase in the DD&A rate was primarily the result of the allocation of the purchase price to proved properties related to the December 2012 acquisition of Orr Energy.  Acquired proved reserves are valued at fair market value on the date of the acquisition, which contributes to a higher amortization base, as compared to our historical cost of acquiring leaseholds and developing our properties.  To date, the fair value of our acquired reserves has been higher than our historical cost of developing our properties even though the resulting EURs are equivalent.  Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties.  We believe that, although initially acquisitions increase our DD&A rate per BOE over the development of the acquired properties, the resulting rates will decline with the drilling of horizontal wells and the addition of the related reserves.

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General and Administrative (“G&A”) –The following table summarizes general and administration expenses incurred and capitalized during the last two years:

	Years Ended August 31,
(in thousands)	2013			2012
G&A costs incurred	$	6,325		$	3,902
Capitalized costs		(637	)		(345	)
Total G&A	$	5,688		$	3,557
G&A Expense per BOE	$	7.36		$	8.46

General and administrative 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 16 employees, and use consultants, advisors, and contractors to perform certain tasks when it is cost-effective.  We maintain our corporate office in Platteville, CO partially to avoid higher rents in other areas.

Although G&A costs have increased as we grow the business we strive to maintain an efficient overhead structure.  For the fiscal year ended August 31, 2013, G&A was $7.36 per BOE compared to $8.46 for the fiscal year ended August 31, 2012.

Our G&A expense for 2013 includes share based compensation of $1,362,000.  The comparable amount for 2012 was $473,000.  Share 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 agreement, 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 general and administrative expenses and capitalized into the full cost pool.  The increase in capitalized costs from 2012 to 2013 reflects our increasing activities to acquire leases and develop the properties.

Other Income (Expense) – Neither interest expense nor interest income had a significant impact on our results of operations for 2013.  Substantially all of the interest costs incurred under our credit facility were classified as costs related to our unevaluated assets or wells in progress and were eligible for capitalization into the full cost pool.

Beginning in 2013, we entered into commodity derivative contracts for the future sale of oil.  We designed our derivative activity to protect our cash flow during periods of oil price declines.  Using swaps and collars, we have hedged 340,000 barrels of future production for the next 22 months.  Generally, contracts are based upon a reference price indexed to trading of West Texas Intermediate Crude Oil on the NYMEX.  During the year ended August 31, 2013, the average index prices were higher than our average contract prices, and we realized a loss of $0.4 million for the year.  As of August 31, 2013, the weighted average future index prices were $101.81 per barrel, approximately $7.64 higher than our contract price, creating an unrealized loss of $2.6 million at the end of the year.

Our commodity derivative contracts are revalued at fair value for each reporting period, and changes in the value of the contracts can have a significant impact on reported results of operations

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Income Taxes – We reported income tax expense of $6.9 million for the fiscal year ended August 31, 2013.  All of the tax liability will be deferred into future years, and it does not appear that any federal or state payments will be required for 2013.  During 2012, we reported a net deferred tax benefit of $332,000, essentially representing a future refund, to record the benefit arising from the net operating loss carry-forward (NOL).

For tax purposes, we have a NOL of $41 million which will begin to expire, if not utilized, in year 2031.  For book purposes, the NOL is $31 million, as there is a difference of $10 million related to deductions for stock based compensation.

For 2013, we reported an effective tax rate of 42%.  Our estimated effective tax rate for future periods, based upon current tax laws, is 37%.  The difference reflects several differences between book income and tax income, including adjustments for statutory depletion and an adjustment to the stock based compensation component included in our inventory of deferred tax assets.  During 2013, we reversed the timing difference created for the future deduction of stock based compensation when the underlying options expired.  Potential tax deductions for compensation are eliminated whenever options expire without exercise.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  During 2013 and 2012, 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 in 2012 we eliminated our entire valuation allowance of $4.9 million.  Prior to 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.

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For the year ended August 31, 2012, compared to the year ended August 31, 2011

For the year ended August 31, 2012, we reported net income of $12.1 million, or $0.26 per share, $0.25 per diluted share, compared to a net loss of $(11.6) million, or $(0.45) per basic and diluted share for the period ended August 31, 2011.

Our rapid improvement in profitability was driven by our successful drilling program. The significant variances between the two years are (i) increased revenues and expenses associated with more producing wells, (ii) the cessation of certain interest and other non-cash expenses, and (iii) the effect of income taxes. As further explained below, our net loss for 2011 resulted from non-cash charges related to the convertible promissory notes and the derivative conversion liability. The following discussion also expands upon items of inflow and outflow that affect operating income.

Oil and Gas Production and Revenues – For the year ended August 31, 2012, we recorded total revenues of $24.9 million compared to $10.0 million for the year ended August 31, 2011, an increase of $14.9 million or 150%.  We experienced an overall 151% annual increase in production from the prior year having realized a full year of production from wells at the beginning of the year, and the addition of wells, including new wells drilled as well as those acquired.  Although there was significant commodity price fluctuation during the year, overall pricing on a BOE basis was not significantly different from 2011 to 2012.  For the fiscal year ended August 31, 2012, our gas / oil ratio (“GOR”) on a BOE basis was 44/56 compared to 45/55 for the fiscal year ended August 31, 2011.

	Years Ended August 31,
	2012		2011
Production:
Oil (Bbls1)		235,691		89,917
Gas (Mcf2)		1,109,057		450,831
Total production in BOE3		420,534		165,056
Revenues (in thousands):
Oil	$	20,644	$	7,470
Gas		4,325		2,308
Total	$	24,969	$	9,778
Average sales price:
Oil (Bbls1)	$	87.59	$	83.07
Gas (Mcf2)	$	3.90	$	5.12
BOE3	$	59.38	$	59.24

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 August 31, 2012, we had 191 producing wells.  Net oil and gas production averaged 1,149 BOE per day in 2012, as compared with 452 BOE per day for 2011, a year over year increase of 154% in BOEPD production.  The significant increase in production from the prior year reflects 52 additional wells that went into productive status since August 31, 2011 and a full year of production from the 111 wells that were added over the course of fiscal year 2011.  Production for the fourth fiscal quarter of 2012 averaged 1,270 BOE per day.

Revenues are sensitive to changes in commodity prices.  From 2011 to 2012, our realized annual average sales price per barrel of oil rose 5%; however, we experienced a decline of 24% in our realized annual average sales price per Mcf of natural gas.  There was a 45% and 130% swing in the price of crude and natural gas from the respective low to high prices during the twelve month period ended August 31, 2012.  Barrel and Mcf prices at year end were up 2% and down 9%, respectively, from twelve month average.  We did not utilize any commodity price hedges during either year, but expect to do so in the future.

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, downward price pressure could have a negative effect on revenues reported in future periods.

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Lease Operating Expenses (“LOE”) and Production Taxes – Direct operating costs of producing oil and natural gas and taxes on production and properties are reported as lease operating expenses as follows:

	Years ended August 31,
(in thousands)	2012		2011
Production costs	$	1,146	$	351
Work-over		66		87
Other		—		46
Lifting cost		1,212		484
Severance and ad valorem taxes		2,436		956
Total LOE	$	3,648	$	1,440
Per BOE:
Production costs	$	2.73	$	2.13
Work-over		0.16		0.53
Other		—		0.28
Lifting cost		2.89		2.94
Severance and ad valorem taxes		5.79		5.79
Total LOE per BOE	$	8.68	$	8.73

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.  From 2011 to 2012, 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 10% in both 2012 and 2011.

Depletion, Depreciation and Amortization (“DDA”) – The following table summarizes the components of DDA.  Depletion expense more than doubled, primarily as a result of growth in production and producing properties from 2011 to 2012.

	Years ended August 31,
(in thousands)	2012		2011
Depletion	$	5,838	$	2,743
Depreciation and amortization		172		95
Total DDA	$	6,010	$	2,838
DDA expense per BOE	$	14.29	$	17.19

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 fiscal year 2012, our depletable reserve base was 5,321,502 barrels of oil and 34,555,031 Mcf of natural gas.  Fiscal year 2012 production represented 4% and 3% of those reserve bases, respectively.

Depletion expense per BOE declined 17% from 2011 to 2012.  For the fiscal year ended August 31, 2012, depletion of oil and gas properties was $14.29 per BOE compared to $17.19 for the fiscal year ended August 31, 2011.  During 2012, 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.

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General and Administrative (“G&A”) – The following table summarizes the components of general and administration expenses:

	Years Ended August 31,
(in thousands)	2012			2011
Cash based compensation	$	1,901		$	1,261
Share based compensation		473			627
Professional fees		953			716
Insurance		136			78
Other general and administrative		439			428
Capitalized general and administrative		(345	)		(206	)
Total G&A	$	3,557		$	2,904
G&A Expense per BOE	$	8.46		$	17.59

Although G&A costs increased during 2012, they increased at a lower rate than the overall growth of our business, as we strive to maintain an efficient overhead structure.  For the fiscal year ended August 31, 2012, G&A was $8.46 per BOE compared to $17.59 for the fiscal year ended August 31, 2011.

Cash based compensation and benefits include payments to employees and directors. 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 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 the Sarbanes–Oxley Act, as we have progressed from a smaller reporting company to an accelerated filer under SEC definitions.  The listing on the NYSE: MKT 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 the properties.

Operating Income (Loss) – For the year ended August 31, 2012, we generated operating income of $11.7 million, compared to $2.8 million for the year ended August 31, 2011.  This tri-fold increase in operating income resulted primarily from the increasing contribution of wells brought into production during the last two years, which includes wells drilled under the 2012 and 2011 drilling programs, the acquisition of producing properties from PEM and other parties, and increased production from older wells that were recompleted using newer hydraulic fracturing techniques.  Increased revenues more than offset increased costs incurred by us to accomplish these objectives.

Other Income (Expense) – Other income for the fiscal year ended August 31, 2012 was $37,000, consisting solely of interest income.  Interest cost of $208,000 was incurred during 2012, all of which was capitalized as part of the cost of oil and gas properties.  For the fiscal year ended August 31, 2011, we reported several significant items of expense in addition to interest income of $56,000.  These other expenses reported in 2011 primarily related to our convertible promissory notes, including net interest expense of $590,000, accretion of debt discount of $2.6 million, amortization of debt issuance costs of $1.6 million, and a change in the fair value of the derivative conversion liability of $10.2 million.  During 2011, interest expense was also recorded on the related party note and the bank line of credit in the amounts of $74,000 and $41,000, respectively.  Of these expenses, we capitalized interest and amortization of $710,000.

The convertible promissory notes contained a conversion feature which was considered an embedded derivative and recorded as a liability at its initial estimated fair value.  This derivative conversion liability was then marked-to-market over time, with the resulting change in fair value recorded as a non-cash item in the statement of operations.  All expenses related to the convertible promissory notes ceased mid-year 2011, as all noteholders converted their holdings into equity.

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Income Taxes – We reported income tax expense of $4.6 million offset by a tax benefit of $4.9 million for the fiscal year ended August 31, 2012, resulting in a net income tax benefit of $332,000 and a corresponding net deferred tax asset in the same amount.  For all reporting periods prior to 2012, no income tax expense or benefit was reported, as all tax assets or liabilities were effectively offset by a valuation allowance.

The income tax benefit is a one-time event representing the expected value of the future deduction of the net operating loss carry-forward generated during our start-up years.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  During the current fiscal year, 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 we eliminated our entire valuation allowance of $4.9 million.  Prior to 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.

During 2012 management concluded that positive indicators outweighed negative indicators and that it was appropriate to release the valuation allowance.  Although we reported net losses every year since inception through August 31, 2011, we attributed all of the net losses for the 2011 and 2010 fiscal years to a single discrete item.  The discrete item was the fair value accounting treatment of the components of the 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, those expenses will not recur, and it is appropriate to exclude them from a consideration of future profitability.  Secondly, we had begun to report net income and had significantly increased oil and gas reserve values.  Lastly, we completed a debt financing arrangement and an equity financing arrangement that allowed us to continue with our operating plan.  Accordingly, we believed that it was appropriate to release the valuation allowance related to the deferred tax asset created by the net operating loss carryover.

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Liquidity and Capital Resources

Our primary source of liquidity since inception has been net cash provided by sales and other issuances of equity and debt securities.  Our secondary sources of capital have been 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 that cash on hand plus cash flows from operations plus available borrowings under our revolving credit facility will provide sufficient liquidity.  However, unforeseen events may require us to obtain additional equity or debt financing.  We have on file with the SEC an effective universal shelf registration statement that we may use for future securities offerings.  Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.

During the year, we completed the sale of common stock for net proceeds of $78.2 million.  The underwritten offering, which closed on June 19, 2013, was comprised of 13,225,000 shares of common stock at a price to the public of $6.25 per share.

In November 2012, we modified our borrowing arrangements.  The new revolving line of credit increases the maximum lending commitment to $150 million, subject to the limitations of a borrowing base calculation.  The bank group providing the facility is led by Community Banks of Colorado, a division of NBH Bank, NA.

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios.  The borrowing arrangement is collateralized by certain of our assets, including producing properties.  The maximum lending commitment is subject to reduction based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports.  Based upon the semi-annual redetermination derived from the February 28, 2013 reserve report, the borrowing base was increased from $47 million to $75 million.

In December, we utilized a portion of the financing available through this arrangement to fund the acquisition of assets from Orr Energy.  We currently have approximately $38 million available for future borrowings if needed.  Additional borrowings, if any, are expected to be used to fund acquisitions, expenditures for well drilling and development, and to provide working capital.

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.  At our option, interest rates will be referenced to the Prime Rate plus a margin of 0% to 1%, or the London InterBank Offered Rate plus a margin of 2.5% to 3.25%.  The maturity date for the arrangement is November 28, 2016.

We engage in the use of commodity derivatives in connection with anticipated crude oil sales to mitigate the impact of commodity price volatility.  During the year ended August 31, 2013, we realized a cash loss from commodity derivatives of $0.4 million.

At August 31, 2013, we had cash and cash equivalents of $19.5 million, short term investments of $60.0 million, and an outstanding balance of $37 million under our revolving credit facility.

Our sources and (uses) of funds for the fiscal years ended August 31, 2013, 2012 and 2011, are summarized below (in thousands):

	Years Ended August 31,
	2013			2012			2011
Cash provided by operations	$	32,120		$	21,252		$	7,916
Capital expenditures		(80,469	)		(46,751	)		(30,247	)
Property conveyances		-			71			8,382
Cash used by other investing activities		(60,000	)		-			-
Cash provided by equity financing activities		74,528			37,421			16,691
Net borrowings		34,000			(2,200	)		-
Net increase in cash and equivalents	$	179		$	9,793		$	2,742

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Net cash provided by operations has improved during each of the last three years.  The significant improvement reflects the operating contribution from new wells that were drilled and producing wells that were acquired.

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.  

A reconciliation of the differences between cash payments and the “all-inclusive” amounts is summarized in the following table (in thousands):

		Years Ended August 31,
		2013			2012			2011
Cash payments for capital expenditures		$	80,469		$	46,751		$	30,247
Accrued costs, beginning of period			(5,733	)		(4,967	)		(3,466	)
Accrued costs, end of period			25,491			5,733			4,967
Non-cash acquisitions, common stock			16,684			1,985			9,939
Non-cash acquisitions, debt financing			-			-			5,200
Other			1,233			300			351
	All inclusive capital expenditures	$	118,144		$	49,802		$	47,238

During the fiscal year ended August 31, 2013, we engaged in drilling or completion activities on 48 wells.  In addition, we invested $42.5 million in the acquisition of mineral assets from Orr Energy.  Approximately $35.2 million of our capital expenditures for the fiscal year ended August 31, 2013, represent drilling and completion cost on wells on which production commenced during the year.  As of August 31, 2013, we had recorded costs of $25.9 million on 16 wells in progress.  Our mineral lease acquisition program incurred costs of $12.3 million during the year, $3.2 million of which were acquired in exchange for our common stock.

Our primary need for cash for the fiscal year ending August 31, 2014, will be to fund our drilling and acquisition programs.  Our cash requirements are expected to increase significantly as we implement our horizontal drilling program.  Each horizontal well is estimated to cost $4.5 million, compared to the estimated cost of a vertical well of $0.8 million.  Under the preliminary plans for our 2014 capital budget, we estimate capital expenditures of approximately $157.1 million, consisting of drilling and completion costs for wells which we operate, our pro-rata share of the costs on wells drilled by other operators, and the costs of acquiring properties.  It is our plan to drill 24 net horizontal wells during the year and to participate in 5 net non-operated horizontal wells at a total cost of $112.5 million.  We expect to drill or participate in 6 vertical wells.  Leasing activities are expected to cost $5.0 million, and the acquisition of producing properties is budgeted for $30.0 million.  Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.  The amount, timing and allocation of capital expenditures is generally within our control, as participations are a limited portion of our operations.  Fluctuations in prices for oil and natural gas could cause us to defer or accelerate our spending.

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.

For 2014, we believe that the cash flow from operations plus proceeds from the sale of common stock during June 2013 plus additional borrowings available under our revolving line of credit facility will be sufficient to meet our liquidity needs during the fiscal year

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Contractual Commitments

The following table summarizes our contractual obligations as of August 31, 2013 (in thousands):

	Less than  One Year		One to  Three Years		Three to Five Years		Total
Rig Contract1	$	19,900	$	—		—	$	19,900
Revolving credit facility		—		37,000		—		37,000
Operating Leases		150		—		—		150
Employment Agreements		1,164		1,697		—		2,861
Total	$	21,214	$	38,697		—	$	59,911

1 As of August 31, 2013, we had agreed with Ensign United States Drilling, Inc. to use one drilling rig to drill a total of 25 wells.  As of August 31, 2013, six wells had been drilled.  We estimate that we will utilize the rig through June 30, 2014.  Total payments due to Ensign will depend upon a number of variables, including the target formations and other technical details.  We estimate that the total commitment for the 25 wells will approximate $25.6 million and that the portion of the obligation to be recorded during fiscal 2014 will approximate $19.9 million.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonable likely to have a current or future material effect on our financial condition, changes in financial condition, results of operations, liquidity or capital resources.

Non-GAAP Financial Measures

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 U.S. 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 U.S. 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.

See Reconciliation of Non-GAAP Financial Measures below for a detailed description of this measure as well as a reconciliation to the nearest U.S. GAAP measure.

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Reconciliation of Non-GAAP Financial Measures

Adjusted EBITDA. We define adjusted EBITDA as net income adjusted to exclude the impact of interest expense, interest income, income tax expense, DDA (depreciation, depletion 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 its nearest GAAP measure.

	Years Ended August 31,
	2013			2012			2011
Adjusted EBITDA:
Net income (loss)	$	9,581		$	12,124		$	(11,600	)
Depreciation, depletion and amortization		13,336			6,010			2,838
Change in fair value of derivative conversion liability		-			-			10,230
Provision for income tax		6,870			(332	)		-
Stock based compensation		1,362			473			627
Commodity derivative change		2,649			-			-
Interest expense		97			-			4,247
Interest income		(47	)		(38	)		(56	)
Adjusted EBITDA	$	33,848		$	18,237		$	6,286

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Trend and Outlook

In early September, 2013, Northern Colorado experienced flooding that covered a wide area and caused extensive damage.  Significant damage was done to the area’s infrastructure, such as roads, bridges, and water treatment facilities, as well as to numerous structures within the flood zone.    Approximately 20 of our well sites were directly affected by the flood waters.  However, the damage to our facilities was not severe, and there were no hydrocarbon spills at our sites.  Most of the wells were repaired within a few weeks and all of the sites are expected to return to service during our first fiscal quarter. The cost of repairs will not have a significant impact on our financial statements.  However, the extent of the flooding throughout our production area was so vast that it impacted our daily operations, even on well sites that were not directly affected by the flood.  For several days, it was difficult to gather and transport hydrocarbons, and sales from our legacy vertical wells for the month of September decreased by 35% from the month of August.  The new horizontal wells which reached productive status during the first week of September were less affected by the flood, and production from those wells is expected to meet our initial expectations for the quarter.

During fiscal year 2012, the Wattenberg Field experienced elevated line pressure in the natural gas and liquids gathering system.  Issues with high line pressure continued during 2013.  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 the pipeline.  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 is the success of horizontal wells that have recently been drilled.  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.  The pace of horizontal drilling in the Wattenberg is accelerating and it appears that it will be some time before the gathering system will have sufficient capacity to eliminate the high line pressure issues.

We are taking steps to mitigate high line pressures.  Where it was cost beneficial, we installed compressors to aid the wellhead equipment in its injection of gas into the system.  Compression equipment at the wellhead has proven beneficial, especially at pad sites with multiple vertical wells.  Along with our mid-stream service provider, we are evaluating the installation of larger diameter pipe to improve the gas gathering capacity.

In addition, companies that operate the gas gathering pipelines are making significant capital investments to increase system capacity.  As publicly disclosed, DCP Midstream Partners (“DCP”) is currently implementing a multi-year facility expansion capable of significantly increasing the long-term gathering and processing capacity in the Wattenberg Field.  DCP is the principle third party provider that we employ to gather production from our wells.  A significant improvement in the system will occur as a new processing plant in LaSalle, CO comes on line. The LaSalle, CO plant will have an estimated capacity of 110 million cubic feet per day.  The grand opening for the LaSalle plant was held in October, 2013 and the plant is expected to reach full operational status during our first and second fiscal quarters.  DCP has also announced the building of the Lucerne Plant II, northeast of Greeley in Weld County, with a maximum capacity of 230 mmcf/d, which is estimated to begin operations in 2015.  At this time, we do not know how long it will take for the mitigation efforts to remedy the problem.

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, (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 from more sources or on better terms, and lessens the difficulty of obtaining 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.

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A 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 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

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.

The following paragraphs provide a discussion of our more significant accounting policies, estimates and judgments.  We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements.  See Note 1 of the Notes to the Financial Statements for a detailed discussion of the nature of our accounting practices and additional accounting policies and estimates made by management.

Oil and Gas Sales:  We derive revenue primarily from the sale of produced crude oil and natural gas.  Revenues from production on properties in which we share an economic interest with other owners are recognized on the basis of our interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between 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.

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.  There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our 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 our oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Oil and Gas Properties:  We use the full cost method of accounting for costs related to our 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.

Asset Retirement Obligations (“ARO”):  We are subject to legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an 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 our credit adjusted risk free interest rate.  Estimates are periodically reviewed and adjusted to reflect changes.

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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, we capitalize 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 capitalized cost decreases over the useful life of the asset, recognized as depletion.

Stock-Based Compensation:  We recognize all equity-based compensation as stock-based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date.  The expense is recognized over the vesting period of the grant.

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.

We consider many factors in our 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.

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Recent Accounting Pronouncements

We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on U.S. 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 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.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our primary market risk exposure results from volatility in the prices 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.  The volatility of oil prices affects our results to a greater degree than the volatility of gas prices, as approximately 78% of 2013 revenues were from the sale of oil.  Although pricing for oil and natural gas production has been less volatile in recent years, we expect volatility to increase in the future.  During the last three years, the average realized prices per barrel of oil have ranged from $88 to $83.  Similarly, the average realized prices per mcf have ranged from $5 to $4.  However, a longer term view reveals that since 2008 the price of oil has ranged from $145 per bbl to $33 per bbl and the price of gas has ranged from $13 per mcf to $2 per mcf.

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 40% and no more than 80% of expected hydrocarbon production, generally over a period of two years.  We do not enter into derivative contracts for speculative or trading purposes.  As of August 31, 2013, we had open crude oil derivatives in a liability position with a fair value of $2.6 million.  A hypothetical shift of 10% in crude oil prices would change the fair value of our position by $2.9 million.  As of August 31, 2013, we had no open natural gas positions.

There was no material change in the underlying commodity price risk from 2012 to 2013.  However, as the use of derivative contracts commenced during 2013, there was no similar derivative risk during 2012.

Interest Rate Risk - At August 31, 2013, we had debt outstanding under our bank credit facility totaling $37.0 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).  At August 31, 2013, we were incurring interest at a rate of 2.7%, based upon LIBOR plus a margin 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 3.7%, our interest payments would increase by approximately $0.4 million.

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 from 2012 to 2013.

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.  As our use of commodity derivative contracts commenced during 2013, there was no similar risk during 2012.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See the financial statements and accompanying notes included with this report.

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

None

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ITEM 9A.  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 Co-Chief Executive Officer and Chief 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-K.  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-K, 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 Co-Chief Executive Officer as well as our Chief Financial Officer to allow timely decisions regarding required disclosure.

Based on that evaluation, our management concluded that, as of August 31, 2013, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

During the fourth quarter of fiscal year ended August 31, 2013, we took measures to bolster our internal control processes pertaining to financial reporting.  Such measures included the implementation of additional procedures related to the valuation of commodity derivatives.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting.  As defined by the Securities and Exchange Commission, internal control over financial reporting is a process designed by, or under the supervision of two key personnel, our Co-Chief Executive Officer and our Chief Financial Officer and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with U.S. generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Ed Holloway, our Co-Chief Executive Officer, and Frank L. Jennings, our Chief Financial Officer, evaluated the effectiveness of our internal control over financial reporting as of August 31, 2013 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO Framework.  Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls.  Based on this evaluation, management concluded that our internal control over financial reporting was effective as of August 31, 2013.

Attestation Report of Registered Public Accounting Firm

The attestation report required under this Item 9A is set forth under the caption "Report of Independent Registered Public Accounting Firm", which is included with the financial statements and supplemental data required by Item 8.

ITEM 9B.  OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our officers and directors are listed below.  Our directors are generally elected at our annual shareholders' meeting and hold office until the next annual shareholders' meeting or until their successors are elected and qualified.  Our executive officers are elected by our directors and serve at their discretion.

Name	Age	Position
Edward Holloway	61	Co-Chief Executive Officer and Director
William E. Scaff, Jr.	56	Co-Chief Executive Officer, Treasurer and Director
Frank L. Jennings	62	Chief Financial Officer
Rick A. Wilber	66	Director
Raymond E. McElhaney	57	Director
Bill M. Conrad	57	Director
R.W. Noffsinger, III	39	Director
George Seward	63	Director

Edward Holloway – Mr. Holloway has been an officer and director since September 2008 and was an officer and director of our predecessor between June 2008 and September 2008.  Mr. Holloway co-founded Cache Exploration Inc., an oil and gas exploration and development company.  In 1987, Mr. Holloway sold the assets of Cache Exploration to LYCO Energy Corporation.  He rebuilt Cache Exploration and sold the entire company to Southwest Production a decade later.  In 1997, Mr. Holloway co-founded, and since that date has co-managed, Petroleum Management, LLC, a company engaged in the exploration, operations, production and distribution of oil and natural gas.  In 2001, Mr. Holloway co-founded, and since that date has co-managed, Petroleum Exploration and Management, LLC, a company engaged in the acquisition of oil and gas leases and the production and sale of oil and natural gas.  Mr. Holloway holds a degree in Business Finance from the University of Northern Colorado and is a past president of the Colorado Oil and Gas Association.

William E. Scaff, Jr. – Mr. Scaffhas been an officer and director since September 2008 and was an officer and director of our predecessor between June 2008 and September 2008.  Between 1980 and 1990, Mr. Scaff oversaw financial and credit transactions for Dresser Industries, a Fortune 50 oilfield equipment company.  Immediately after serving as a regional manager with TOTAL Petroleum between 1990 and 1997, Mr. Scaff co-founded, and since that date co-managed, Petroleum Management, LLC, a company engaged in the exploration, operations, production and distribution of oil and natural gas.  In 2001, Mr. Scaff co-founded, and since that date has co-managed, Petroleum Exploration and Management, LLC, a company engaged in the acquisition of oil and gas leases and the production and sale of oil and natural gas.  Mr. Scaff holds a degree in Finance from the University of Colorado.

Frank L. Jennings – Mr. Jennings began his service as our Chief Financial Officer on a part-time basis in June 2007.  In March 2011, he joined us on a full-time basis.  From 2001 until 2011, Mr. Jennings was an independent consultant providing financial accounting services, primarily to smaller public companies.  From 2006 until 2011, he also served as the Chief Financial Officer of Gold Resource Corporation (AMEX:GORO).  From 2000 to 2005, he served as the Chief Financial Officer and a director of Global Casinos, Inc., a publicly traded corporation, and from 1994 to 2001 he served as Chief Financial Officer of American Educational Products, Inc. (NASDAQ:AMEP), before it was purchased by Nasco International.  After his graduation from Austin College with a degree in economics and from Indiana University with an MBA in finance, he joined the Houston office of Coopers & Lybrand.  He also spent four years as the manager of internal audit for The Walt Disney Company.

Rick A. Wilber – Mr. Wilber has been one of our directors since September 2008.  Since 1984, Mr. Wilber has been a private investor in, and a consultant to, numerous development stage companies.  In 1974, Mr. Wilber was co-founder of Champs Sporting Goods, a retail sporting goods chain, and served as its President from 1974-1984.  He has been a Director of Ultimate Software Group Inc. since October 2002 and serves as a member of its audit and compensation committees.  Mr. Wilber was a director of Ultimate Software Group between October 1997 and May 2000.  He served as a director of Royce Laboratories, Inc., a pharmaceutical concern, from 1990 until it was sold to Watson Pharmaceuticals, Inc. in April 1997 and was a member of its compensation committee.

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Raymond E. McElhaney – Mr. McElhaney has been one of our directors since May 2005.  Since January 2013, he has been the President of a private financial Company, Longhorn Investments, LLC. Until December 2012, he was the President of MCM Capital Management Inc., a privately held financial management company.  Mr. McElhaney is a seasoned executive with numerous appointments, directorships and consulting roles with both private and public companies in a variety of industries and business sectors.  Mr. McElhaney has a strong background in oil and gas exploration and management and was a former Officer and Director of Wyoming Oil and Minerals and a Director of United States Exploration, Inc., both publically traded companies. Mr. McElhaney was a managing partner in the Waco Pipeline, a natural gas gathering system. Over the course of his career, Mr. McElhaney has advised companies on M&A and equity deals, commercial finance transactions, stock offerings, spinoffs and joint venture arrangements. Mr. McElhaney has been involved as an owner breeder of Thoroughbred race horses since 1981. Mr. McElhaney received his Bachelor of Science Degree in Business Administration from the University of Northern Colorado in 1978.

Bill M. Conrad – Mr. Conrad has been one of our directors since May 2005 and prior to the acquisition of Predecessor Synergy was our Vice President and Secretary.  Mr. Conrad has been involved in several aspects of the oil and gas industry over the past 30 years.  From February 2002 until June 2005, Mr. Conrad served as president and a director of Wyoming Oil & Minerals, Inc., and from 2000 until April 2003, he served as vice president and a director of New Frontier Energy, Inc.  Since June 2006, Mr. Conrad has served as a director of Gold Resource Corporation, a publicly traded corporation engaged in the mining industry.  In 1990, Mr. Conrad co-founded MCM Capital Management Inc. and has served as its vice president until December 2012.

R.W. “Bud” Noffsinger, III – Mr. Noffsinger was appointed as one of our directors in September 2009.  Mr. Noffsinger has been the President/ CEO of RWN3 LLC, a company involved with investment securities, since February 2009.  Previously, Mr. Noffsinger was the President (2005 to 2009) and Chief Credit Officer (2008 to 2009) of First Western Trust Bank in Fort Collins, Colorado.  Prior to his association with First Western, Mr. Noffsinger was a manager with Centennial Bank of the West (now Guaranty Bank and Trust).  Mr. Noffsinger’s focus at Centennial was client development and lending in the areas of commercial real estate, agriculture and natural resources.  Mr. Noffsinger is a graduate of the University of Wyoming and holds a Bachelor of Science degree in Economics with an emphasis on natural resources and environmental economics.

George Seward – Mr. Seward was appointed as one of our directors on July 8, 2010. Mr. Seward cofounded Prima Energy in 1980 and served as its Secretary until 2004, when Prima was sold to Petro-Canada for $534,000,000.  At the time of the sale, Prima had 152 billion cubic feet of proved gas reserves and was producing 55 million cubic feet of gas daily from wells in the D-J Basin in Colorado and the Powder River Basin of Wyoming and Utah.  Since March 2006 Mr. Seward has been the President of Pocito Oil and Gas, a limited production company, with operations in northeast Colorado, southwest Nebraska and Barber County, Kansas.  Mr. Seward has also operated a diversified farming operation, raising wheat, corn, pinto beans, soybeans and alfalfa hay in southwestern Nebraska and northeast Colorado, since 1982.

We believe Messrs. Holloway, Scaff, McElhaney, Conrad and Seward are qualified to act as directors due to their experience in the oil and gas industry.  We believe Messrs. Wilber and Noffsinger are qualified to act as directors as result of their experience in financial matters.

Rick Wilber, Raymond McElhaney, Bill Conrad and R.W. Noffsinger, are considered independent as that term is defined Section 803.A of the NYSE MKT Rules.

The members of our compensation committee are Rick Wilber, Raymond McElhaney, Bill Conrad, and R.W. Noffsinger.  The members of our Audit Committee are Raymond McElhaney, Bill Conrad and R.W. Noffsinger.  Mr. Noffsinger acts as the financial expert for the Audit Committee of our board of directors.

We have adopted a Code of Ethics applicable to all employees.

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ITEM 11.  EXECUTIVE COMPENSATION

The following table shows the compensation paid or accrued to our executive officers during each of the three years ended August 31, 2013 (in thousands).

Name and Principal Position	Fiscal Year	Salary1		Bonus2		Stock Awards3		Option Awards4		All Other Compensation5		Total
Ed Holloway,	2013	$	330		200		—		—		10	$	540
Co-Chief Executive	2012	$	300		100		—		—		10	$	410
Officer	2011	$	300		100		—		—		10	$	410
William E. Scaff, Jr.,	2013	$	330		200		—		—		10	$	540
Co-Chief Executive Officer	2012	$	300		100		—		—		10	$	410
and Treasurer	2011	$	300		100		—		—		10	$	410
Frank L Jennings,	2013	$	180		—		—		—		7	$	187
Chief Financial Officer	2012	$	180		—		—		—		5	$	185
	2011	$	88		—		220		404		—	$	712

1 The dollar value of base salary (cash and non-cash) earned.

2 The dollar value of bonus (cash and non-cash) earned.

3 The fair value of stock issued for services computed in accordance with ASC 718 on the date of grant.

4 The fair value of options granted computed in accordance with ASC 718 on the date of grant.

5 All other compensation received that we could not properly report in any other column of the table.

The compensation to be paid to Mr. Holloway, Mr. Scaff and Mr. Jennings will be based upon their employment agreements, which are described below.  All material elements of the compensation paid to these officers is discussed below.

On June 1, 2010, the Company entered into employment agreements with Mr. Holloway and Mr. Scaff.  The employment agreements, which expired on May 31, 2013, provide that the Company will pay Mr. Holloway and Mr. Scaff each a monthly salary of $25,000 and require both Mr. Holloway and Mr. Scaff to devote approximately 80% of their time to the Company’s business.  In addition, for every 50 net vertical wells that begin producing oil and/or gas after June 1, 2010, whether as the result of the Company’s successful drilling efforts or acquisitions, the Company would issue to each of Mr. Holloway and Mr. Scaff, a cash payment of $100,000 or shares of common stock in an amount equal to $100,000 divided by the average closing price of the Company’s common stock for the 20 trading days prior to the date the 50th well began producing.

Effective June 1, 2013 the Company entered into new employment agreements with Ed Holloway, Synergy’s Co-Chief Executive Officer, and William E. Scaff, Jr., Synergy’s Co-Chief Executive Officer and Treasurer.  The employment agreements, which expire on May 31, 2016, provide that the Company will pay Mr. Holloway and Mr. Scaff each an annual salary of $420,000 and require Mr. Holloway and Mr. Scaff to devote approximately 80% of their time to the Company.  In addition, for every 50 wells that begin producing oil and/or gas after June 1, 2013, whether as the result of the Company’s successful drilling efforts or acquisitions, the Company will pay each of Mr. Holloway and Mr. Scaff $100,000, up to a maximum $300,000 during any 12 month period, provided that:

· each horizontal well that meets the criteria above will count toward seven wells (as adjusted to reflect the Company’s net working interest in each horizontal well), and

· the unpaid balance pertaining to any wells included in the previous “50 well bonus program” that first began producing commercial quantities of oil and/or gas as a result of the successful drilling efforts, or as the result of a completed acquisition by the Company, during the three year period ended May 31, 2013, will be counted toward the 50 net well limit applicable for the period beginning June 1, 2013.

The employment agreements will terminate upon the death of Mr. Holloway or Mr. Scaff, their disability or for cause, as the cause may be.  If the employment agreement is terminated for any of these reasons, the employee or his legal representatives, as the case may be, will be paid the salary provided by the employment agreement through the date of termination.

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The employment agreements with Mr. Holloway and Mr. Scaff will also will terminate if a Change of Control has occurred.  In the event of a Change in Control, Mr. Holloway and Mr. Scaff can resign as an employee of Synergy and Synergy will pay Mr. Holloway and Mr. Scaff the greater of twelve months of salary or the amount due under their employment agreements.  Whether or not Mr. Holloway of Mr. Scaff resigns as a result of a Change in Control event, all options or bonus shares of Synergy held by Mr. Holloway and Mr. Scaff will become fully vested.

The new employment agreements with Mr. Holloway and Mr. Scaff were approved by our Compensation Committee and Board of Directors.

On June 23, 2011 our directors approved an employment agreement with Frank L. Jennings, our Chief Financial Officer.  The employment agreement provides that we will pay Mr. Jennings a monthly salary of $15,000 and issue to Mr. Jennings:

· 50,000 shares of our restricted common stock; and

· options to purchase 150,000 shares of our common stock.  The options are exercisable at a price of $4.40 per share, vest over three years in 50,000 share increments beginning March 6, 2012, and expire on March 7, 2021.

The employment agreement expires on March 7, 2014 and requires Mr. Jennings to devote all of his time to our business.

Generally, if an officer resigns within 90 days of a relocation (or demand for relocation) of his place of employment to a location more than 35 miles from his then current place of employment, the employment agreement will be terminated and the officer will be paid the salary provided by the employment agreement through the date of termination and the unvested portion of any stock options held by the officer will vest immediately.

In the event there is a change in control, the employment agreements allows an officer to resign from his position and receive a lump-sum payment equal to 12 months’ salary.  In addition, the unvested portion of any stock options held by the officer will vest immediately.  For purposes of the employment agreement, a change in the control means: (1) our merger with another entity if after such merger our shareholders do not own at least 50% of the voting capital stock of the surviving corporation; (2) the sale of substantially all of our assets; (3) the acquisition by any person of more than 50% of our common stock; or (4) a change in a majority of our directors which has not been approved by our incumbent directors.

The employment agreements mentioned above will terminate upon the employee’s death, or disability or may be terminated by us for cause.  If the employment agreement is terminated for any of these reasons, the employee, or his legal representatives as the case may be, will be paid the salary provided by the employment agreement through the date of termination.

For purposes of the employment agreements, “cause” is defined as:

(i) the conviction of the employee of any crime or offense involving, or of fraud or moral turpitude, which significantly harms us;

(ii) the refusal of the employee to follow the lawful directions of our board of directors;

(iii) the employee’s negligence which shows a reckless or willful disregard for reasonable business practices and significantly harms us;  or

(iv) a breach of the employment agreement by the employee.

Executive officer compensation, as provided above, is structured to be competitive both in its design and in the total compensation offered.  The Compensation Committee of the Board of Directors determines the compensation of our officers.  The Committee’s philosophy on officer compensation is to align executive and shareholder interests. The philosophy’s objective is to provide fair compensation based upon the individual’s position, experience and individual performance.

Our current policy is that the various elements of the compensation package are not interrelated in that gains or losses from past equity incentives are not factored into the determination of other compensation.

A goal of the compensation program is to provide executive officers with a reasonable level of security through base salary and benefits. We want to ensure that the compensation programs are appropriately designed to encourage executive officer retention and motivation to create shareholder value. The Compensation Committee believes that our stockholders are best served when we can attract and retain talented executives by providing compensation packages that are competitive but fair.

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The key components of our executive compensation program include annual base salaries and long-term incentive compensation consisting of stock options. It is our policy to target compensation (i.e., base salary, stock option grants and other benefits) at approximately the median of comparable companies in the oil and gas exploration and development industry. Accordingly, data on compensation practices followed by other companies in the oil and gas exploration and development industry is considered.

Base salaries generally have been targeted to be competitive when compared to the salary levels of persons holding similar positions in other oil and gas exploration and development companies and other publicly traded companies of comparable size.

Stock option grants help to align the interests of our officers with those of its shareholders. Options grants are made under the Company’s Stock Option Plan.

We believe that grants of stock options:

●      Enhance the link between the creation of shareholder value and long-term executive incentive compensation;

●      Provide focus, motivation and retention incentive; and

●      Provide competitive levels of total compensation.

Our long-term incentive program includes of periodic grants of stock options with an exercise price equal to the fair market value of our common stock on the date of grant. Decisions made regarding the timing and size of option grants take into account our performance and that of the employee, “competitive market” practices, and the size of the option grants made in prior years. The weighting of these factors varies and is subjective.

In addition to cash and equity compensation programs, executive officers participate in the health insurance programs available to our other employees.

All executive officers are eligible to participate in the Company’s 401(k) plan on the same basis as all other employees. We matche participant’s contribution in cash, not to exceed 4% of the participant’s total compensation.

Employee Pension, Profit Sharing or other Retirement Plans.  Effective November 1, 2010, we adopted a defined contribution retirement plan, qualifying under Section 401(k) of the Internal Revenue Code and covering substantially all of our employees.  We match participant’s contributions in cash, not to exceed 4% of the participant’s total compensation.  Other than this 401(k) Plan, we do not have a defined benefit pension plan, profit sharing or other retirement plan.

Stock Option and Bonus Plans

We have three stock award plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan.  Each plan authorizes the issuance of shares of our common stock to persons that exercise options granted pursuant to the Plan.  Our employees, directors, officers, consultants and advisors are eligible to receive such awards, provided that bona fide services be rendered by such consultants or advisors and such services must not be in connection with promoting our stock or the sale of securities in a capital-raising transaction.  The option exercise price is determined by our directors, though generally is based upon the closing market price of our shares on the date of grant.

Summary. The following is a summary of options granted or shares issued pursuant to the Plans as of October 31, 2013.  Each option represents the right to purchase one share of our common stock.

Name of Plan	Total Shares Reserved Under Plans		Reserved for Outstanding Options		Shares Issued as Stock Bonus		Remaining Options/Shares Under Plans
2011 Non-Qualified Stock Option Plan		5,000,000		1,954,000		—		2,910,000
2011 Incentive Stock Option Plan		2,000,000		—		—		2,000,000
2011 Stock Bonus Plan		2,000,000		—		185,000		1,815,000

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Options

In connection with the acquisition of a corporation in 2008, we issued options to the persons shown below in exchange for options previously issued by that corporation.  The terms of the options we issued are identical to the terms of the previously issued options.  The options were not granted pursuant to our 2005 Plans.  During 2013, the options were modified to extend the expiration date to August 31, 2013.  On August 27, 2013, the options were exercised.

Among other provisions, the options contained a net settlement provision that allowed for exercise of the options on a cashless basis.  Under net settlement terms, the option holder is deemed to exercise options and simultaneously tender the shares back to us in settlement of amounts owed for payment of the exercise price and to satisfy statutory payroll tax withholding requirements.  Thus, under a net settlement transaction, the option holder immediately surrenders a number of shares to which they are otherwise entitled, and the net number of shares issued is less than the options exercised.

The following table shows information concerning the options exercised during the fiscal year ended August 31, 2013 by the person named below:

Name	Date of Exercise	Shares Acquired On Exercise			Value Realized (in thousands)
Ed Holloway	August 27, 2013		486,978	1	$	7,530
William E. Scaff, Jr.	August 27, 2013		486,978	1	$	7,530

1 Represents net shares acquired upon the cashless exercise of 1 million options.  Pursuant to the net settlement provision, the option holder immediately tendered 513,022 shares to satisfy statutory tax withholding and payment of option exercise price.

The following table shows information concerning our outstanding options as of October 31, 2013.

	Shares underlying unexercised  Option which are:				Exercise	Expiration
Name	Exercisable		Unexercisable		Price	Date
Frank L. Jennings	100,000		50,000	$	4.40	3/7/21
Employees	358,000	1	1,446,000		1	1

1 Options were issued to several employees pursuant to our Non-Qualified Stock Option Plan.  The exercise price of the options varies between $2.40 and $10.67 per share.  The options expire at various dates between December 2018 and October, 2023.

The following table shows the weighted average exercise price of the outstanding options granted pursuant to our Non-Qualified Stock Option Plan or otherwise as of August 31, 2013.

Plan Category	Available Securities to be Issued Upon Exercise of Outstanding Options		Weighted-Average Exercise Price of Outstanding Options
Non-Qualified Stock Option Plan		1,820,000	$	4.88

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Compensation of Directors During Year Ended August 31, 2013 (in thousands)

Name	Fees Earned or  Paid in Cash		Stock  Awards1		Option  Awards2		Total
Rick Wilber	$	—		54		—	$	54
Raymond McElhaney		29		33		—		62
Bill Conrad		64		—		—		64
R.W. Noffsinger		64		—		—		64
George Seward		56		—		—		56
	$	213		87		—	$	300

1 The fair value of stock issued for services computed in accordance with ASC 718.

2 The fair value of options granted computed in accordance with ASC 718 on the date of grant.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table shows, as of October 31, 2013, information with respect to those persons owning beneficially 5% or more of our common stock and the number and percentage of outstanding shares owned by each of our directors and officers and by all officers and directors as a group.  Unless otherwise indicated, each owner has sole voting and investment powers over his shares of common stock.

Name	Number of Shares1			Percent of Class2
Ed Holloway		3,247,887	3		4.3	%
William E. Scaff, Jr.		3,247,887	4		4.3	%
Frank L. Jennings		174,000			0.2	%
Rick A. Wilber		685,011			0.9	%
Raymond E. McElhaney		275,725			0.4	%
Bill M. Conrad		247,225			0.3	%
R.W. Noffsinger, III		288,425			0.4	%
George Seward		1,949,692			2.6	%
All officers and directors as a group (8 persons)		10,115,852			13.4	%

1 Share ownership includes shares issuable upon the exercise of options and warrants, all of which are exercisable on or by January 31, 2014, held by the persons listed below.

Name	Shares Issuable Upon Exercise of Options and Warrants		Option or Warrant Exercise Price			Expiration Date
Frank L. Jennings		100,000		$	4.40	3/7/2021

2 Computed based upon 74,391,364 shares of common stock outstanding as of October 31, 2013 plus adjustments for shares issuable upon exercise of options and warrants.

3 Shares are held of record by various trusts and limited liability companies controlled by Mr. Holloway.

4 Shares are held of record by various trusts and limited liability companies controlled by Mr. Scaff.

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ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

Any transaction between us and related parties must be approved by a majority of our disinterested directors.

Two of our officers, Ed Holloway and William Scaff, Jr., control three entities with which we have entered into agreements.  These entities are Petroleum Management, LLC (“PM”), Petroleum Exploration and Management, LLC (“PEM”), and HS Land and Cattle, LLC (“HSLC”).

We acquired all of the working oil and gas assets owned by PEM in a transaction that closed on May 24, 2011.  In total, we acquired interests in 88 gross (40 net) oil and gas wells in the Wattenberg Field, and interests in oil and gas leases covering approximately 6,968 gross acres in the Wattenberg Field and the Eastern D-J Basin.  These oil and gas interests were acquired from Petroleum Exploration and Management, LLC (“PEM”), a company owned by Ed Holloway and William E. Scaff, Jr., two of our officers, for approximately $19.0 million.  The transaction was approved by the disinterested directors and by a vote of the shareholders, with Mr. Holloway and Mr. Scaff not voting.  The purchase was funded with a combination of cash, restricted shares and a note payable.  In November 2011, we used proceeds from the bank credit facility to repay the entire principal balance on the related party notes of $5.2 million and accrued interest summing to approximately $142,000.

In October 2010, and following the approval of our directors, we acquired oil and gas properties from PM and PEM, for approximately $1.0 million.  The oil and gas properties consisted of a 100% working interest (80% net revenue interest) in eight oil and gas wells plus additional land, leases and equipment located in the Wattenberg Field.

We had a letter agreement with PM and PEM which provided us with the option to acquire working interests in oil and gas leases owned by these firms and covering lands on the D-J basin.  The oil and gas leases covered 640 acres in Weld County, Colorado and, subject to certain conditions, would be transferred to us for payment of $1,000 per net mineral acre. The working interests in the leases we could acquire varied, but the net revenue interest in the leases, could not be less than 75%.  Under this letter agreement, through February 2010 we acquired leases covering 640 gross (360 net) acres from PM and PEM for $360,000.

Pursuant to the terms of an Administrative Services Agreement, through June 30, 2010, PM provided us with office space and equipment storage in Platteville, Colorado, as well as secretarial, word processing, telephone, fax, email and related services for a fee of $20,000 per month.  From July 1, 2010 until June 30, 2013 we have leased the office space and equipment storage yard from HSLC at a rate of $10,000 per month.  Commencing July 1, 2013, we leased corporate offices, field offices, and an equipment yard from HSLC at a rate of $15,000 per month.

During the year ended August 31, 2012, we acquired oil and gas leases from George Seward, a member of our board of directors.  In total, we purchased lease interests covering 61,397 gross (51,127 net) undeveloped acres, located in eastern Colorado and western Nebraska, in exchange for 188,137 shares of our common stock.  Based on the market price of our common stock on the transaction dates, these acquisitions were valued at $491,000.

Effective January 1, 2012, we commenced processing revenue distribution payments to all persons that own a mineral interest in the wells which we operate.  Payments to mineral interest owners included payments to entities controlled by three of our directors, Ed Holloway, William Scaff Jr, and George Seward.  The royalty payments made to directors or their affiliates totaled $304,000 for the year ended August 31, 2013 and $196,000 for the year ended August 31, 2012.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

For each of the three years ended August 31, 2013, 2012 and 2011, EKS&H, LLLP (Formerly known as Ehrhardt Keefe Steiner & Hottman P.C.) served as our independent registered public accounting firm (in thousands).

	Year Ended		Year Ended		Year Ended
	August 31, 2013		August 31, 2012		August 31, 2011
Audit Fees	$	201	$	210	$	120
Audit-Related Fees		84		7		36
Tax Fees		65		41		44
All Other Fees		25		—		—

Audit fees represent amounts billed for professional services rendered for the audit of our annual financial statements and the reviews of the financial statements included in our Form 10-Q and Form 10-K reports.  Audit-related fees include amounts billed for the review of our registration statement on Form S-3 and the audits of acquisitions. All other fees represent due diligence activities performed on our behalf.  Prior to contracting with EKS&H to render audit or non-audit services, each engagement was approved by our audit committee.

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PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibits

3.1.1  Articles of Incorporation 1

3.1.2  Amendment to Articles of Incorporation 1                                                                                

3.1.3  Bylaws 2

3.1.4  Amendment to Articles of Incorporation 17

4.1  Stock Bonus Plan 15

4.2  Non-Qualified Stock Option Plan 15

4.3  Incentive Stock Option Plan15

10.1  Employment Agreement with Ed Holloway 3

10.2  Employment Agreement with William E. Scaff, Jr. 3

10.3  Administrative Services Agreement 4

10.4  Agreement regarding Conflicting Interest Transactions 4

10.5 Consulting Services Agreement with Raymond McElhaney and Bill Conrad 5

10.6.1 Form of Convertible Note 5

10.6.2 Form of Subscription Agreement 5

10.6.3 Form of Series C Warrant 5

10.7 Purchase and Sale Agreement with Petroleum Exploration and Management, LLC (wells, equipment and well bore leasehold assignments)5

10.8 Purchase and Sale Agreement with Petroleum Management, LLC (operations and leasehold) 5

10.9 Purchase and Sale Agreement with Chesapeake Energy 5

10.10 Lease with HS Land & Cattle, LLC 5

10.11 Employment Agreement with Frank L. Jennings 6

10.12 Purchase and Sale Agreement with Petroleum Exploration and Management, LLC 7

10.13 Loan Agreement with Bank of Choice (presently known as Guarantee Bank of Colorado) 8

10.14 Purchase and Sale Agreement with DeClar Oil & Gas, Inc. and Wolf Point Exploration, LLC 9

10.15 Amendment to Line of Credit Agreement10

10.16 Amendment #2 to Loan Agreement 12

50

10.17 Purchase and Sale Agreement with ORR ENERGY LLC (Weld County, Colorado oil and gas property) 12

10.18 Exploration Agreement dated March 1, 2013 (Morgan and Weld Counties Colorado, properties) 13

10.19 Amendment to  Drilling Contract with Ensign United States Drilling, Inc. 14

10.20 (Reserved)

10.21 Amended and Restated Credit Agreement dated November 28, 2012.16

10.22 Third Amendment to Credit Agreement. 18

10.23 Fourth Amendment to Credit Agreement, together with Third Amended and Restated Deed of Trust, Mortgage, Security Agreement and Financing Statement 20

10.24 Employment Agreement with Frank Jennings 20

10.25 Employment Agreement with Craig Rasmuson 20

10.26 Employment Agreement with Valerie Dunn 20

10.27 Drilling contract with Ensign United States Drilling, Inc.

14	Code of Ethics (as amended) 11
23.1	Consent of  EKS&H LLLP 17

31 Rule 13a-14(a) Certifications

32 Section 1350 Certifications

99.1 Report of Ryder Scott Company, L.P. 17

99.2 Ryder Scott report regarding oil and gas reserves as of February 28, 2014 21

101 Interactive Data Files

1 Incorporated by reference to the same exhibit filed with the Company’s registration statement on Form SB-2, File #3333-146561.

2 Incorporated by reference to the same exhibit filed with the Company’s registration statement on Form SB-2, File #333-146561.

3 Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K filed on June 7, 2013.

4 Incorporated by reference to the same exhibit filed with the Company’s transition report on Form 10-K for the year ended August 31, 2008.

5 Incorporated by reference to the same exhibit filed with the Company’s report on Form 10-K/A filed on June 3, 2011.

6 Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K filed on June 24, 2011.

7 Incorporated by reference to Exhibit 10.12 filed with the Company’s report on Form 8-K filed on August 5, 2011.

8 Incorporated by reference to Exhibit 10.13 filed with the Company’s report on Form 8-K filed on December 2, 2011.

9 Incorporated by reference to Exhibit 10.14 filed with the Company’s report on Form 8-K filed on February 23, 2012.

10 Incorporated by reference to Exhibit 10.15 filed with the Company’s report on Form 8-K filed on April 25, 2012.

11 Incorporated by reference to Exhibit 14 filed with the Company’s report on Form 8-K filed on July 22, 2011.

12 Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K filed on October 25, 2012.

13 Incorporated by reference to Exhibit 10.18 filed with the Company’s report on Form 10-Q for the period ended February 28, 2013.

14 Incorporated by reference to Exhibit 10.19 filed with the Company’s 8-K report dated July 24, 2013.

15   Incorporated by reference to same exhibit filed with the Company’s registration statement on Form S-8, File #333-191684.

16 Incorporated by reference to Exhibit 10.21 filed with the Company’s report on Form 8-K on December 3, 2012.

17 Incorporated by reference to Exhibit 3.1.4 and 99.1 filed with the Company’s report on Form 10-K on November 14, 2013.

18 Incorporated by reference to Exhibit 10.22 filed with the Company’s report on Form 8-K filed on December 26, 2013.

19 Incorporated by reference to Exhibit 10.23 filed with the Company’s report on Form 8-K filed on June 10, 2014.

20 Incorporated by reference to Exhibits 10.24, 10.25 and 10.26 filed with the Company’s report on Form 8-K filed on June 10, 2014.

21 Incorporated by reference to Exhibit 99.2 filed with the Company’s report on Form 8-K filed on April 29, 2014.

51

SYNERGY RESOURCES CORPORATION

INDEX TO FINANCIAL STATEMENTS

Index to Financial Statements	F-1
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of August 31, 2013 and 2012	F-3
Statements of Operations for the years ended August 31, 2013, 2012 and 2011	F-4
Statements of Changes in Shareholders’ Equity  for the years ended August 31, 2013, 2012 and 2011	F-5
Statements of Cash Flows for the years ended August 31, 2013, 2012 and 2011	F-6
Notes to Financial Statements	F-7

F-1

To the Board of Directors and Shareholder

Synergy Resources Corporation

Platteville, Colorado

We have audited the accompanying balance sheets of Synergy Resources Corporation (the “Company”) as of August 31, 2013 and 2012, and the related statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three year period ended August 31, 2013.  We have also audited the Company’s internal control over financial reporting as of August 31, 2013, based on criteria established in Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management report. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Synergy Resources Corporation as of August 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three year period ended August 31, 2013 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, Synergy Resources Corporation maintained, in all material respects, effective internal control over financial reporting as of August 31, 2013, based on criteria established in the 1992 Internal Control – Integrated Framework, issued by COSO.

/s/ EKS&H LLLP

November 13, 2013

Denver, Colorado

●   DENVER   ●  FORT COLLINS   ●   BOULDER    ●

www.EKSH.com

F-2

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

 (in thousands, except share data) 

	August 31,			August 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	19,463		$	19,284
Short-term investments		60,018			—
Accounts receivable:
Oil and gas sales		7,361			3,606
Joint interest billing		4,700			3,268
Inventory		194			178
Other current assets		239			132
Total current assets		91,975			26,468
Property and equipment:
Evaluated oil and gas properties, net		132,979			59,936
Unevaluated oil and gas properties		64,715			32,484
Other property and equipment, net		271			282
Property and equipment, net		197,965			92,702
Deferred tax asset, net		—			332
Other assets		1,296			1,230
Total assets	$	291,236		$	120,732
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	949		$	1,499
Well costs payable		25,491			5,733
Revenue payable		6,081			4,160
Production taxes payable		6,277			3,805
Other accrued expenses		254			395
Commodity derivative		2,315			—
Total current liabilities		41,367			15,592
Revolving credit facility		37,000			3,000
Commodity derivative		334			—
Deferred tax liability, net		6,538			—
Asset retirement obligations		2,777			1,027
Total liabilities		88,016			19,619
Commitments and contingencies (See Note 14)
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:
70,587,723 and 51,409,340 shares issued and outstanding,
respectively		71			52
Additional paid-in capital		216,383			123,876
Accumulated deficit		(13,234	)		(22,815	)
Total shareholders' equity		203,220			101,113
Total liabilities and shareholders' equity	$	291,236		$	120,732

The accompanying notes are an integral part of these financial statements 

F-3

SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

 (in thousands, except share and per share data)

	For the Years Ended August 31,
	2013			2012			2011
Oil and gas revenues	$	46,223		$	24,969		$	10,002
Expenses
Lease operating expenses		3,417			1,212			484
Production taxes		4,237			2,436			956
Depreciation, depletion,
and amortization		13,336			6,010			2,838
General and administrative		5,688			3,557			2,904
Total expenses		26,678			13,215			7,182
Operating income		19,545			11,754			2,820
Other income (expense)
Change in fair value of derivative
conversion liability		-			-			(10,229	)
Commodity derivative realized loss		(395	)		-			-
Commodity derivative unrealized loss		(2,649	)		-			-
Interest expense, net		(97	)		-			(4,247	)
Interest income		47			38			56
Total other income (expense)		(3,094	)		38			(14,420	)
Income before income taxes		16,451			11,792			(11,600	)
Deferred income tax provision (benefit)		6,870			(332	)		-
Net income (loss)	$	9,581		$	12,124		$	(11,600	)
Net income (loss) per common share:
Basic	$	0.17		$	0.26		$	(0.45	)
Diluted	$	0.16		$	0.25		$	(0.45	)
Weighted average shares outstanding:
Basic		57,089,362			46,587,558			26,009,283
Diluted		59,088,761			48,359,905			26,009,283

The accompanying notes are an integral part of these financial statements

F-4

SYNERGY RESOURCES CORPORATION

 STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

 for the years ended August 31, 2013, 2012 and 2011

(in thousands, except share data)

		Number of Common		Par Value		Additional			Accumulated  Earnings			Total Shareholders' Equity
		Shares		Common Stock		Paid - In Capital			(Deficit)			(Deficit)
Balance, August 31, 2010			13,510,981	$	14	$	22,309		$	(23,339	)	$	(1,016	)
Shares issued pursuant to conversion of debt and accrued interest at $1.60 per share, net of $1,052,917 unamortized debt discount	9,979,376				10		14,904			—			14,914
Reclassification of derivative conversion liability to equity pursuant to early conversion of debt			—		—		19,554			—			19,554
Shares issued in exchange for mineral leases and services			1,999,838		2		5,668			—			5,670
Shares issued in exchange for oil and gas assets, related party			1,381,818		1		4,697			—			4,698
Shares issued for cash at $2.00 per share pursuant to the November 30, 2010 offering memorandum, net of offering costs of  $1,309,279			9,000,000		9		16,682			—			16,691
Shares issued pursuant to conversion of Series D warrants on a cashless basis			226,199		—		—			—			—
Stock based compensation							197						197
Net (loss)			—		—		—			(11,600	)		(11,600	)
Balance, August 31, 2011			36,098,212	$	36	$	84,011		$	(34,939	)	$	49,108
Shares issued in exchange for mineral leases and services			669,765		1		1,998			—			1,999
Shares issued for cash at $2.75 per share pursuant to the October 7, 2011 offering memorandum, net of offering costs of $2,028,215			14,636,363		15		37,407			—			37,422
Stock based compensation			5,000		—		460			—			460
Net income			—		—		—			12,124			12,124
Balance, August 31, 2012			51,409,340	$	52	$	123,876		$	(22,815	)	$	101,113
Shares issued for Orr Energy acquisition			3,128,422		3		13,515						13,518
Shares issued in exchange for mineral assets			687,122		1		3,165						3,166
Shares issued for cash at $6.25 per share pursuant to the June 13, 2013 offering memorandum, net of offering costs of $4.4 million			13,225,000		13		78,230						78,243
Shares issued for exercise of warrants			1,052,698		1		3,274						3,275
Taxes paid on stock option exercise			—		—		(6,990	)					(6,990	)
Shares issued for exercise of  stock option			1,030,057		1		(1	)					—
Stock based compensation			55,084		—		1,314						1,314
Net income										9,581			9,581
Balance, August 31, 2013			70,587,723	$	71	$	216,383		$	(13,234	)	$	203,220

The accompanying notes are an integral part of these financial statements

F-5

SYNERGY RESOURCES CORPORATION

 STATEMENTS OF CASH FLOWS

(in thousands)

	For the Years Ended August 31,
	2013			2012			2011
Cash flows from operating activities:
Net income (loss)	$	9,581		$	12,124		$	(11,600	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation, and amortization		13,336			6,010			2,838
Amortization of debt issuance cost		-			-			1,588
Accretion of debt discount		-			-			2,664
Provision for deferred taxes		6,870			(332	)		-
Stock-based compensation		1,362			473			627
Valuation decrease in commodity derivatives		2,649			-			-
Change in fair value of derivative liability		-			-			10,229
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales		(3,756	)		(1,597	)		(991	)
Joint interest billing		(1,432	)		(685	)		(424	)
Inventory		(16	)		282			(72	)
Accounts payable
Trade		(550	)		(155	)		1,550
Revenue		1,921			4,161			-
Production taxes		2,472			2,279			350
Accrued expenses		(141	)		(1,291	)		1,317
Other		(176	)		(17	)		(160	)
Total adjustments		22,539			9,128			19,516
Net cash provided by operating activities		32,120			21,252			7,916
Cash flows from investing activities:
Acquisition of property and equipment		(80,469	)		(46,751	)		(30,247	)
Short-term investments		(60,000	)
Net proceeds from sales of oil and gas properties		-			71			8,382
Net cash used in investing activities		(140,469	)		(46,680	)		(21,865	)
Cash flows from financing activities:
Proceeds from sale of stock		82,656			40,250			18,000
Offering costs		(4,413	)		(2,829	)		(1,309	)
Proceeds from exercise of warrants		3,275			3,000			-
Shares withheld for payment of employee payroll taxes		(6,990	)		-			-
Net proceeds from revolving credit facility		34,000			-			-
Principal repayment of related party notes payable		-			(5,200	)		-
Net cash provided by financing activities		108,528			35,221			16,691
Net increase in cash and equivalents		179			9,793			2,742
Cash and equivalents at beginning of period		19,284			9,491			6,749
Cash and equivalents at end of period	$	19,463		$	19,284		$	9,491
Supplemental Cash Flow Information (See Note 15)

The accompanying notes are an integral part of these financial statements

F-6

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

August 31, 2013, 2012 and 2011

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.

Basis of Presentation:  The Company has adopted August 31st as the end of its fiscal year.  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”).

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 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.

Short-Term Investments:  As part of its cash management strategies, the Company invests in short-term interest bearing deposits such as certificates of deposits with maturities of less than one year.

Inventory:    Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market

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.

F-7

Wells in progress represent the costs associated with the drilling of oil and gas wells that have yet to be completed as of August 31, 2013.  Since the wells had not been completed as of August 31, 2013, they were classified within unevaluated oil and gas properties and were withheld from the depletion calculation and the ceiling test. The costs for these wells will be transferred into proved property when the wells commence production 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 depreciation, depletion, 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 and reflected as additional accumulated depreciation, depletion and amortization.  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.  No provision for impairment was required for the twelve months ended August 31, 2013 or 2012.

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).

	For the Years Ended August 31,
	2013		2012		2011
Capitalized overhead	$	637	$	345	$	206

Well Costs Payable:  The cost 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 (“AFE”).

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.

F-8

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.

Derivative Conversion Liability:  The Company accounted for the embedded conversion features in its convertible promissory notes, issued during fiscal year 2010, in accordance with the guidance for derivative instruments, which requires a periodic valuation of their fair value and a corresponding recognition of liabilities associated with such derivatives.  The recognition of derivative conversion liabilities related to the issuance of convertible debt was applied first to the proceeds of such issuance as a debt discount at the date of the issuance.  All subsequent increases or decreases in the fair value of derivative conversion liabilities were recognized as a charge or credit to other income (expense) in results of operations.  In connection with the conversion of convertible promissory notes into shares of the Company’s common stock, derivative conversion liabilities were reclassified to additional paid-in-capital.  The amounts recognized in the financial statements follow.

	For the Years Ended August 31,
	(in thousands)
	2013		2012		2011
Non-cash expense recognized related to the change in
the fair value of derivative conversion liabilities	$	-	$	-	$	10,229
Derivative conversion liabilities recognized in additional
paid-in-capital	$	-	$	-	$	19,554

Debt Issuance Costs:  Debt issuance costs incurred in connection with executing convertible promissory notes between December 29, 2009, and March 12, 2011 were classified as a long-term asset.  However, as a result of the conversion of all outstanding convertible promissory notes into shares of the Company’s common stock, all debt issuance costs were recognized as a component of interest expense through August 31, 2011.

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 using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between 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 and Operating Region:    The Company operates exclusively within the United States of America.  Except for cash and short-term investments, all of the Company’s assets are employed in and all of its revenues are derived from the oil and gas industry.   The table below presents the percentages of oil and gas revenue resulting from purchases by major customers.

	For the Years Ended August 31,
	2013	2012	2011
Company A	50%	68%	75%
Company B	15%	11%	21%

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

F-9

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 total receivable balances as of each of the fiscal year ends presented are shown in the following table:

	As of August 31,
	2013	2012	2011
Company A	24%	35%	31%
Company B	23%	30%	31%
Company C	12%	*	13%
* less than 10%

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 below 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 August 31, 2013.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of August 31, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.  For further information, see Note 12 below.

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.

F-10

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps or “no premium” collars to reduce the effect of price changes on a portion of our future oil 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. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. We value our 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.  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. For additional discussion, please refer to Note 7—Commodity Derivative Instruments.

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.

	For the Years Ended August 31,
	2013		2012		2011
Weighted-average shares outstanding - basic		57,089,362		46,587,558		26,009,283
Potentially dilutive common shares from:
Stock options		1,881,682		1,380,861		-
Warrants		117,717		391,486		-
Weighted-average shares outstanding - diluted		59,088,761		48,359,905		26,009,283

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

	For the Years Ended August 31,
	2013		2012		2011
Potentially dilutive common shares from:
Stock options		670,000		2,495,000		4,645,000
Warrants		8,500,000		14,098,000		14,931,067
Total		9,170,000		16,593,000		19,576,067

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.  There were various updates recently issued by the Financial Accounting Standards Board, 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 consolidated financial position, results of operations or cash flows. 

F-11

2.   Property and Equipment

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

	As of August 31,
	2013			2012
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	38,826		$	27,070
Wells in progress		25,889			5,414
Subtotal, unevaluated costs		64,715			32,484
Evaluated costs:
Producing and non-producing		155,755			69,667
Total capitalized costs		220,470			102,151
Less, accumulated depletion		(22,776	)		(9,731	)
Oil and gas properties, net		197,694			92,420
Other property and equipment		544			436
Less, accumulated depreciation		(273	)		(154	)
Other property and equipment, net		271			282
Total property and equipment, net	$	197,965		$	92,702

Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value.  The reviews as of each of the fiscal year ends presented, 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 each of the fiscal year ends presented, similarly revealed no impairment of oil and gas assets.

Costs Incurred:  Costs incurred in oil and gas property acquisition, exploration and development activities for the fiscal years presented were (in thousands):

	For the Years Ended August 31,
	2013		2012		2011
Acquisition of property:
Unproved	$	12,295	$	9,145	$	9,198
Proved		43,143		459		21,251
Exploration costs		-		-		-
Development costs		61,128		39,739		14,997
Asset retirement obligation		1,578		300		351
Total costs incurred	$	118,144	$	49,643	$	45,797

F-12

Capitalized Costs Excluded from Amortization:  The following table summarizes costs related to unevaluated properties that have been excluded from amounts subject to depletion, depreciation, and amortization at August 31, 2013 (in thousands).  There were no individually significant properties or significant development projects included in the Company’s unevaluated property balance.  The Company regularly evaluates these costs to determine whether impairment has occurred.  The majority of these costs are expected to be evaluated and included in the amortization base within three years.

	Period Incurred								Total as of
									August 31,
	2013		2012		2011		Prior		2013
Unproved leasehold acquisition costs	$	11,757	$	9,636	$	16,585	$	848	$	38,826
Unevaluated development costs		25,889		-		-		-	$	25,889
Total unevaluted costs	$	37,646	$	9,636	$	16,585	$	848	$	64,715

3.   Acquisition

On October 23, 2012, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Orr Energy, LLC (“Orr”), for its interests in 36 producing oil and gas wells and approximately 3,933 gross (3,196 net) mineral acres (the “Orr Assets”). On December 5, 2012, the Company closed the transaction for a combination of cash and stock.  Orr received 3,128,422 shares of the Company’s common stock valued at $13.5 million and cash consideration of approximately $29.0 million. Transaction costs related to the acquisition were approximately $109,000, all of which were recorded in the statement of operations within the general and administrative expenses line item for the twelve months ended August 31, 2013.   No material costs were incurred for the issuance of the shares of common stock.

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 December 5, 2012.  The following table summarizes the purchase price and final allocations of the fair value of the assets acquired and liabilities assumed (in thousands):

Purchase Price	December 5, 2012
Consideration Given
Cash	$	29,012
Synergy Resources Corp. Common Stock *		13,515
Total consideration given	$	42,527
Allocation of Purchase Price
Proved oil and gas properties	$	43,143
Unproved oil and gas properties		466
Total fair value of oil and gas properties acquired		43,609
Working capital	$	(842	)
Asset retirement obligation		(240	)
Fair value of net assets acquired	$	42,527
Working capital acquired was estimated as follows:
Accounts receivable		521
Accrued liabilities and expenses		(1,363	)
Total working capital	$	(842	)

*   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 5, 2012. (3,128,422 shares at $4.32 per share)

F-13

Pro Forma Financial Information

As stated above, on December 5, 2012, the Company completed an acquisition of oil and gas properties from Orr Energy.  Below are the combined results of operations for the twelve months ended August 31, 2013 and 2012 as if the acquisition had occurred on September 1, 2011 (in thousands, except per share data).

The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock, additional depreciation expense, costs directly attributable to the acquisition and costs incurred as a result of the Orr Energy acquisition. 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.

	For the years ended August 31,
	(Unaudited)
	2013		2012
Oil and Gas Revenues	$	47,760	$	32,188
Net income	$	10,118	$	14,870
Earnings per common share
Basic	$	0.17	$	0.30
Diluted	$	0.17	$	0.29

4.   Depletion, depreciation and amortization (“DDA”)

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

	For the Years Ended August 31,
	2013		2012		2011
Depletion	$	13,046	$	5,838	$	2,743
Depreciation and amortization		290		172		95
Total DDA Expense	$	13,336	$	6,010	$	2,838

Capitalized costs of evaluated 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.

F-14

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 its 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 fiscal years presented, the Company used the following assumptions:

	For the Years Ended August 31,
	2013	2012
Inflation rate	3.9 - 4.0%	3.9 - 4.0%
Estimated asset life	24.0 - 40.0 years	24.0 - 27.6 years
Credit adjusted risk free interest rate	8.0 - 11.2%	11.2 - 11.7%

The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands).  The revisions recognized during 2013 were primarily from increases in the undiscounted abandonment cost estimates.

	As of August 31,
	2013		2012
Beginning asset retirement obligation	$	1,027	$	644
Liabilities incurred		376		300
Liabilities assumed		240		-
Liabilities settled		-		-
Accretion expense		172		83
Revisions in previous estimates		962		-
	$	2,777	$	1,027

6.   Revolving Credit Facility

On November 28, 2012, the Company entered into an amended revolving credit facility (“LOC”) with a bank syndicate.  The LOC is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit.  The terms provide for $150 million in the maximum amount of borrowings available to the Company, subject to a borrowing base limitation.  Community Banks of Colorado acts as the administrative agent for the bank syndicate with respect to the LOC.  The credit facility expires on November 28, 2016.

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin of 0% to 1%, or London Interbank Offered Rate (LIBOR) plus a margin of 2.50% to 3.25%.  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 year ended August 31, 2013, was 3.2%.  As of August 31, 2013, the interest rate on the outstanding balance was 2.7%, representing LIBOR plus a margin of 2.5%.

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 base limitation is generally subject to redetermination on a semi-annual basis.  The most recent redetermination increased the borrowing base to $75 million based upon the reserve report as of February 28, 2013.  As of August 31, 2013, the unused borrowing base available for future borrowing totaled approximately $38 million.

F-15

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain customary financial ratios.  On a quarterly basis, the Company must maintain (a) an adjusted current ratio greater than 1.0, (b) a ratio of earnings before interest, taxes, depletion, amortization and exploration expense (EBITDAX) greater than 3.5 times interest and fees, (c) a ratio of total funded debt less than 3.5 times EBITDAX, and (d) a ratio of total funded debt less than 0.5 times total capitalization.  Furthermore, terms of the LOC require the Company to maintain hedge contracts covering future production quantities that are included in the borrowing base.  The Company is required to hedge no less than 45% and no more than 80% of scheduled production for a rolling 24 months.

7.   Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below.  The Company has utilized swaps or “no premium” collars to reduce the effect of price changes on a portion of its future oil 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 one counterparty.  The Company has netting arrangements with the counterparty 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 commodity derivative line on the statements of operations.  The Company’s valuation estimate takes into consideration the counterparty’s credit worthiness, the Company’s credit worthiness, 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.

F-16

The Company’s commodity derivative contracts as of August 31, 2013 are summarized below:

Contract Type	Basis (1)	Quantity (Bbl/month)	Strike Price ($/Bbl)	Term
Collar	NYMEX	3,014	$87.00 - $102.50	Sept 1, 2013 - Dec 31, 2013
Collar	NYMEX	1,840	$85.00 - $98.50	Jan 1, 2014 - Dec 31, 2014
Collar	NYMEX	7,000	$80.00 - $92.50	Jan 1, 2015 - Jun 30, 2015
Contract Type	Basis (1)	Quantity (Bbl/month)	Swap Price ($/Bbl)	Term
Swap	NYMEX	3,014	$91.70	Sept 1, 2013 - Dec 31, 2013
Swap	NYMEX	6,000	$96.35	Sept 1, 2013 - Dec 31, 2013  (2)
Swap	NYMEX	8,000	$94.45	Sept 1, 2013 - Dec 31, 2013
Swap	NYMEX	15,000	$98.00	Sept 1, 2013 - Dec 31, 2013
2013 Total/Average		32,014	$95.13
Swap	NYMEX	1,840	$90.80	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	2,000	$90.11	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	5,000	$90.50	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	15,000	$98.00	Jan 1, 2014 - Feb 28, 2014
2014 Total/Average		23,840	$92.35
(1) NYMEX refers to WTI quoted prices on the New York Mercantile Exchange
(2) In connection with entering into these swaps with premium hedged prices, the counterparty has the right, but not the obligation to extend the swap to January 1, 2014 through December 31, 2014 at the current strike price and quantity.  This option expires on December 31, 2013.

 The following table details the fair value of the derivatives recorded in the applicable balance sheet, by category (in thousands):

		As of August 31,
Underlying Commodity	Balance Sheet Location	2013		2012
Crude Oil derivative contract	Current liabilities	$	2,315	$	-
Crude Oil derivative contract	Noncurrent liabilities	$	334	$	-

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

	For the Years Ended August 31,
	2013		2012		2011
Unrealized loss on commodity derivatives	$	2,649	$	-	$	-
Realized loss on commodity derivatives		395		-		-
Total loss	$	3,044	$	-	$	-

F-17

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 developed 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 developed 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 are 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. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis during the reporting periods after initial recognition.

The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 5—Asset Retirement Obligations, and for the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3—Acquisitions.

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.

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 level 3 inputs. 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.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recuring basis as of  August 31, 2013 and 2012 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at August 31, 2013
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	-	$	-	$	-
Commodity derivative liability	$	-	$	2,649	$	-	$	2,649
	Fair Value Measurements at August 31, 2012
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	-	$	-	$	-
Commodity derivative liability	$	-	$	-	$	-	$	-

F-18

Commodity Derivative Instruments

The Company determines its estimate of the fair value of 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 rating. 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 that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At August 31, 2013, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using 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 and accounts receivable, 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.

9.   Interest Expense

The components of interest expense are (in thousands):

	For the Years Ended August 31,
	2013			2012			2011
Revolving bank credit facility at a variable rate	$	1,067		$	108		$	41
Convertible promissory notes at 8%		-			-			590
Related party note payable at 5.25%		-			68			74
Accretion of debt discount		-			-			2,664
Amortization of debt issuance costs		160			32			1,588
Less, interest capitalized		(1,130	)		(208	)		(710	)
Interest expense, net	$	97		$	-		$	4,247

F-19

10.   Shareholders’ Equity

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

	For the Years Ended August 31,
	2013		2012		2011
Preferred stock, shares authorized		10,000,000		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil		nil
Common stock, shares authorized		100,000,000		100,000,000		100,000,000
Common stock, par value	$	0.001	$	0.001	$	0.001
Common stock, shares issued and outstanding		70,587,723		51,409,340		36,098,212

Preferred Stock 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.

The following shares of common stock were issued during the fiscal years presented:

Sale of common stock

In June 2013, the Company completed the sale of common stock in an underwritten public offering led by Johnson Rice LLC.

In fiscal year 2012, the Company completed the sale of common stock in an underwritten public offering led by Northland Capital Markets.

In fiscal year 2011, the Company completed the sale of common stock to private investors.

Certain details of each transaction are shown in the following table.  Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering.

	For the Years Ended August 31,
	2013		2012		2011
Number of common shares sold		13,225,000		14,363,363		9,000,000
Offering price per common share	$	6.25	$	2.75	$	2.00
Net proceeds (in thousands)	$	78,243	$	37,422	$	16,691

F-20

Common stock issued for acquisition of mineral interests and services

During the fiscal years presented, the Company issued common shares in exchange for mineral property interests and to individuals as compensation for services provided to the Company.  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 Years Ended August 31,
	2013		2012		2011
Number of common shares issued for mineral property leases		687,122		669,765		1,864,838
Number of common shares issued for Orr Energy acquisition		3,128,422		-		-
Total common shares issued		3,815,544		669,765		1,864,838
Average price per common share	$	4.37	$	3.12	$	3.04
Aggregate value of shares issues (in thousands)		16,684	$	2,090	$	5,670

Common stock warrants

The Company has issued warrants to purchase common stock.  The relevant terms of the warrants are described in the following paragraphs.

Series A – During the year ended August 31, 2009, the Company issued 4,098,000 Series A warrants, each of which was immediately exercisable.  Each Series A warrant entitled the holder to purchase one share of common stock for $6.00 per share.  All of the Series A warrants expired on December 31, 2012.

Series B – During the year ended August 31, 2009, the Company issued 1,000,000 Series B warrants, each of which was immediately exercisable.  Each Series B warrant entitled the holder to purchase one share of common stock for $10.00 per share.  All of the Series B warrants expired on December 31, 2012.

Series C – During the year ended August 31, 2010, the Company issued 9,000,000 Series C warrants in connection with a unit offering.  Each unit included one convertible promissory note with a face value of $100,000 and 50,000 Series C warrants.  Each Series C warrant entitles the holder to purchase one share of common stock for $6.00 per share.  The Series C warrants will expire, if not previously exercised, on December 31, 2014.  During the year ended August 31, 2013, 500,000 warrants were exercised.

Series D – During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for a unit offering.  Each Series D warrant entitles the holder to purchase one share of common stock for $1.60 per share, and contains a net settlement provision that provides for exercise of the warrants on a cashless basis.  The Series D warrants will expire, if not previously exercised, on December 31, 2014.  During each of the three years ended August 31, 2013, the following warrants were exercised: 627,799 during fiscal 2013, nil during fiscal 2012, and 355,399 during fiscal 2011.

Sales Agent Warrants – During the year ended August 31, 2009, the Company issued 31,733 warrants to the sales agent for an equity offering.  Each Sales Agent Warrant entitled the holder to purchase two shares of common for $1.80 per share.  The Sales Agent Warrants had an expiration date of December 31, 2012, and all of the warrants were exercised during the year ended August 31, 2013.

Investor Relations Warrants – During the year ended August 31, 2012, the Company issued 100,000 warrants to a firm providing investor relations services.  Each Investor Relations Warrant entitles the holder to purchase one share of common stock for $2.69 per share, and contains a net settlement provision that provides for exercise of the warrants on a cashless basis.  The warrants were to become exercisable in equal quarterly installments over a one year period.  During the year ended August 31, 2013, warrants to purchase 50,000 shares became exercisable and warrants to purchase 50,000 shares were forfeited due to early termination of the agreement.  Also during the year ended August 31, 2013, 25,000 warrants were exercised.

F-21

The following table summarizes activity for common stock warrants for the fiscal years presented:

	Number of Shares Issuable Upon Warrant Exercise		Weighted Average Exercise Price Per Share
Outstanding, August 31, 2010		15,286,466	$	5.92
Exercised		355,399	$	1.60
Outstanding, August 31, 2011		14,931,067	$	6.02
Granted		100,000	$	2.69
Exercised		-	$	-
Outstanding, August 31, 2012		15,031,067	$	6.02
Exercised		1,216,265	$	3.44
Forfeited / Expired		5,148,000	$	6.74
Outstanding, August 31, 2013		8,666,802	$	5.92

The following table summarizes information about the Company’s issued and outstanding common stock warrants as of August 31, 2013:

Description	Number of Shares		Exercise Price		Remaining Contractual Life (in years)		Exercise Price times number of shares
Series C		8,500,000	$	6.00		1.30	$	51,000,000
Series D		141,802	$	1.60		1.30	$	226,883
Investor Relations		25,000	$	2.69		2.30	$	67,250
Total		8,666,802					$	51,294,133

Conversion of Promissory Notes into Shares of Common Stock

During the year ended August 31, 2011, convertible promissory notes with a face value of $15,908,000 were converted into 9,942,500 shares of common stock at a rate of $1.60 per share.  In addition, 36,876 shares of common stock were issued in payment of accrued interest, also at a rate of $1.60 per share.

The notes had been issued during the fiscal year ended August 31, 2010, as part of the Company’s sale of 180 units, each of which consisted of a convertible promissory note in the face amount of $100,000 and bearing interest at an annual rate of 8%.  Some of the notes were converted into common shares during the year ended August 31, 2010, and all of the remaining outstanding notes were converted during the year ended August 31, 2011.

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 expense was classified as a component within General and Administrative expense on the Statement of Operations.

F-22

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

	For the Years Ended August 31,
	2013		2012		2011
Stock options	$	1,039	$	443	$	197
Restricted stock grants		277		17		430
Investor relations warrants		46		13		-
	$	1,362	$	473	$	627

General Description of Stock Option and Other Stock Award Plans

The Company has three stock award plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan.  The plans adopted during 2011 replaced a non-qualified stock option plan and a stock bonus plan originally adopted during 2005 (the “2005 Plans”).  No additional options or shares will be issued under the 2005 Plans.

Each plan authorizes the issuance of shares of the Company's common stock to persons that exercise options granted pursuant to the Plan.  Employees, directors, officers, consultants and advisors are eligible to receive such awards, provided that bona fide services be rendered by such consultants or advisors and such services must not be in connection with promoting our stock or the sale of securities in a capital-raising transaction.  The option exercise price is determined by the Board of Directors, though is generally the closing market price of Company stock on the date of grant.

As of August 31, 2013, there were 5,000,000 shares authorized for issuance under the non-qualified plan and 2,000,000 shares authorized for each of the incentive stock option and stock bonus plans.

During the respective fiscal years, the Company granted the following non-qualified stock options:

	For the Years Ended August 31,
	2013		2012		2011
Number of options to purchase common shares		1,025,000		275,000		425,000
Weighted average exercise price	$	6.05	$	2.96	$	3.79
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	3-5 years		4-5 years		4-5 years
Fair Value (in thousands)	$	4,179	$	519	$	990

F-23

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

	For the Years Ended August 31,
	2013			2012			2011
Expected term	6.2 years			6.5 years			6.0 - 6.5 years
Expected volatility		77	%		56.7 - 69.4	%		53.2 - 69.4	%
Risk free rate		0.89-2.11	%		1.01-1.42	%		1.48-2.63	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Forfeiture rate		0.0	%		0.0 - 0.7	%		0.0	%

During the year end August 31, 2013, the Compensation Committee modified the terms of the stock options to acquire 2,000,000 shares of common stock with an original expiration date of June 2013 to August 2013. The effect of the modification resulted in an immaterial expense to stock based compensation.   Effective August 27, 2013, the options were exercised on a cashless basis.  As part of the net settlement provisions of a cashless exercise, the Company withheld 1,026,043 shares with a value of $8.7 million, which was used to satisfy payment of the exercise price and $6.7 million to pay to the appropriate government entity to satisfy the required minimum payroll taxes.

The following table summarizes activity for stock options for the fiscal years presented:

	Number of Shares			Weighted Average Exercise Price
Outstanding, August 31, 2010		4,220,000		$	5.36
Granted		425,000		$	3.79
Exercised		-		$	-
Outstanding, August 31, 2011		4,645,000		$	5.21
Granted		275,000		$	2.96
Exercised		-		$	-
Forfeited		(5,000	)	$	3.40
Outstanding, August 31, 2012		4,915,000		$	5.09
Granted		1,025,000		$	6.05
Exercised		(2,120,000	)	$	1.10
Expired		(2,000,000	)	$	10.00
Outstanding, August 31, 2013		1,820,000		$	4.88

The following table summarizes information about issued and outstanding stock options as of August 31, 2013:

	Outstanding Options		Vested Options
Number of shares		1,820,000		373,000
Weighted average remaining contractual life	8.7 years		7.7 years
Weighted average exercise price	$	4.88	$	3.71
Aggregate intrinsic value (in thousands)	$	8,160	$	2,107

F-24

The estimated unrecognized compensation cost from unvested stock options as of August 31, 2013, which will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at August 31, 213
Unrecognized compensation expense (in thousands)	$	4,452
Remaining vesting phase	3.4 years

12.   Income Taxes

The income tax provision (benefit) is comprised of the following (in thousands):
 

	As of August 31,
	2013		2012			2011
Current:
Federal	$	-	$	-		$	-
State		-		-			-
Total current income tax		-		-			-
Deferred:
Federal	$	6,367	$	4,219		$	4,266
State		503		360			354
Total deferred income tax		6,870		4,579			4,620
Valuation allowance		-		(4,911	)		(4,620	)
Income tax provision (benefit)	$	6,870	$	(332	)	$	-

            A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is follows (in thousands):

	As of August 31,
	2013			2012			2011
Federal income tax at statutory rate	$	5,594		$	4,009		$	3,944
State income taxes, net of federal tax		503			360			354
Statutory depletion		(929	)		-			-
Stock based compensation		1,911			-			-
Other		(209	)		210			322
Change in valuation allowance		-			(4,911	)		(4,620	)
Income tax provision (benefit)	$	6,870		$	(332	)	$	-
Effective rate expressed as a percentage		42	%		3	%		0	%

The Company reported a change in valuation allowance of $4,911,000 for the year ended August 31, 2012.  In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carry-forwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. In 2012, the Company determined that the weight of the evidence indicated that it would more likely than not be able to realize its deferred tax asset, and the entire valuation allowance was released.

F-25

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the fiscal year ends presented follow (in thousands):

	As of August 31,
	2013		2012
Deferred tax assets:
Net operating loss carry-forward	$	11,485	$	12,643
Stock-based compensation		515		4,070
Statutory depletion		929		-
Unrealized loss on commodity derivative		982		-
Other		3		3
Gross deferred tax assets	$	13,914	$	16,716
Deferred tax liabilities:
Basis of oil and gas properties		20,452		16,384
Gross deferred tax liabilities		20,452		16,384
Deferred tax liability (asset), net	$	6,538	$	(332	)

At August 31, 2013 the Company has a net operating loss carry-forward for federal and state tax purposes of approximately $41.3 million that could be utilized to offset taxable income of future years.  For financial reporting purposes the company has net operating losses of approximately $31 million.  The difference of $10.3 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable.  The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated.  Substantially all of the carry-forward will commence expiring in 2031, 2032, and 2033.

The realization of the deferred tax assets related to the NOL carry-forwards is dependent on the Company’s ability to generate sufficient future taxable income within the applicable carryforward periods. As of August 31, 2013, the Company believes it will be able to generate sufficient future taxable income within the carryforward periods, and accordingly believes that it is more likely than not that its net deferred income tax assets will be fully realized.

The ability of the Company to utilize its NOL carry-forwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carry-forwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carry-forwards. The Company completed a study of the impact of the Code Section 382 limitation on future payments and determined that the statutory provisions were unlikely to limit the Company's ability to realize future tax benefits.

As of August 31, 2013, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position.  Given the substantial NOL carry-forwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carry-forwards, and would not result in significant interest expense or penalties.  Substantially of the Company's tax returns filed since inception are still subject to examination by tax authorities.

13.   Related Party Transactions and Commitments

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

F-26

Acquisition of Oil and Gas Assets from PEM:  During the year ended August 31, 2011, the Company completed two transactions under which it acquired oil and gas assets from PEM, as outlined below.

In May 2011, PEM sold all of its operating oil and gas assets (excluding passive assets such as royalty interests) to the Company.  Pursuant to the terms of the Purchase and Sale Agreement, as approved by its shareholders, the Company acquired a working interest in operating oil and gas wells and certain other mineral assets in a transaction that closed on May 24, 2011.  The purchase price consisted of a combination of cash, 1,381,818 shares of restricted common stock, and a note payable, as detailed in the table below (in thousands)  In November 2011, the Company utilized proceeds from the LOC (Note 6) to repay the entire principal balance and accrued interest.

	For the Years Ended August 31,
	2013		2012		2011
Consideration for certain mineral assets:
Cash payments for certain mineral assets	$	-	$	-	$	10,000
Value of restricted shares of common stock		-		-		4,698
Promissory note		-		-		5,200
Total	$	-	$	-	$	19,898
Subsequent settlement of amounts owing:
Repayment of promissory note	$	-	$	5,200	$	-
Payment of interest on promissory note		-		142		-
Total	$	-	$	5,342	$	-

In a separate transaction that closed in October 2010, the Company acquired with cash certain mineral assets located in the Wattenberg Field of the D-J Basin, from PM and PEM.  The assets acquired included working interests in certain operating oil and gas wells, drill sites, and miscellaneous equipment for a purchase price of $1,017,435.

Other Related Party Transactions:  In addition to the transactions described above, the Company undertook various activities with PM and PEM that are related to the development and operation of oil and gas properties.  The Company occasionally purchased services and certain oil and gas equipment, such as tubular goods and surface equipment, from PM.  The Company reimbursed PM for the original cost of such services and equipment.  Prior to the asset acquisition transaction that closed on May 24, 2011, PEM was a joint working interest owner of certain wells operated by the Company.  PEM was charged for its pro-rata share of costs and expenses incurred on its behalf by the Company, and similarly, PEM was credited for its pro-rata share of revenues collected on its behalf.  Effective with the closing of the asset acquisition, the related party transactions of this nature have ceased.

The following table summarizes the transactions with PM and PEM during the fiscal years presented (in thousands):

	For the Years Ended August 31,
	2013		2012		2011
Beginning balance due to PM	$	-	$	-	$	539
Purchase of equipment from PM		-		-		2
Payments to PM for equipment		-		-		(541	)
Ending balance due to PM for equipment	$	-	$	-	$	-
Beginning balance due from PEM	$	-	$	-	$	868
Joint interest costs billed to PEM		-		-		396
Amounts collected from PEM		-		-		(1,264	)
Ending balance due from PEM	$	-	$	-	$	-

F-27

Facilities and Services Agreements:  The Company leases office space and an equipment storage yard in Platteville, Colorado, under a twelve month lease agreement with HSLC. The lease is renewable annually.  Under this agreement, the Company incurred the following expenses to HSLC for the fiscal years presented (in thousands):

	For the Years Ended August 31,
	2013		2012		2011
Rent expense	$	130	$	120	$	120

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, as follows:

	For the Years Ended August 31,
	2013		2012		2011
Restricted shares of common stock		-		188,137		40,000
Value of restriced shares of common stock (in thousands)	$	-	$	491	$	164

Effective January 1, 2012, the Company commenced processing its own oil and gas revenues.  Payments to royalty 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 fiscal years presented (in thousands):
 

	For the Years Ended August 31,
	2013		2012		2011
Total Royalty Payments	$	304	$	196		N/A

14.   Other Commitments and Contingencies

Effective July 18, 2013, the Company amended its drilling contract with Ensign United States Drilling, Inc. to utilize a drilling rig for the drilling of 25 horizontal wells.  Total payments due to Ensign will depend upon a number of variables, including the target formation and other technical details.  The Company estimates that this commitment will result in its use of the rig until June 2014, and that total drilling costs will approximate $25.6 million.  As of August 31, 2013, the Company had accrued costs of $5.7 million and estimates that its remaining obligations under this contract approximate $19.9 million.
 

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 (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 September 30, 2013, the Company had agreed to participate in 13 new horizontal wells, with aggregate costs to its interest estimated at $5.2 million.  It is the Company’s policy to accrue costs on a non-operated well when it receives notice that active drilling operations have commenced.  For these 13 wells, no costs were accrued at August 31, 2013, as active drilling operations had not begun.  In addition, the Company had been notified by other operators that it may have an interest in 54 potential wells.  As of September 30, 2013, the Company had not yet committed to participate in the future wells and had not determined its potential working interest or cost obligation. 

F-28

15.   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 fiscal years presented (in thousands):

	For the Years Ended August 31,
Supplemental cash flow information:	2013		2012		2011
Interest paid	$	995	$	74	$	788
Income taxes paid		-		-		-
Non-cash investing and financing activities:
Accrued well costs	$	25,491	$	5,733	$	4,967
Assets acquired in exchange for common stock		16,684		1,985		9,938
Assets acquired in exchange for note payable		-		-		5,200
Asset retirement costs and obligations		1,578		300		351
Conversion of promissory notes into common stock		-		-		15,908

16.   Unaudited Oil and Gas Reserves Information

Oil and Natural Gas Reserve Information:  Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made).  Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Proved oil and natural gas reserve information as of the fiscal year ends presented, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company LP.  Reserve information for the properties was prepared in accordance with guidelines established by the SEC.

The reserve estimates prepared as of each of the fiscal year ends presented were prepared in accordance with “Modernization of Oil and Gas Reporting” published by the SEC.  The recent guidance included updated definitions of proved developed and proved undeveloped oil and gas reserves, oil and gas producing activities and other terms.  Proved oil and gas reserves were calculated based on the prices for oil and gas during the 12 month period before the respective reporting date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period, rather than the year-end spot prices, which had been used in prior years.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years.  The recent guidance broadened the types of technologies that may be used to establish reserve estimates.

F-29

The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and gas reserve quantities and changes therein for each of the fiscal years presented:

	Oil (Bbl)			Gas (McF)			Boe
Balance, August 31, 2010		676,685			4,481,051			1,423,527
Revision of previous estimates		323,704			611,516			425,623
Purchase of reserves in place		967,302			8,466,714			2,378,421
Extensions, discoveries, and other additions		191,931			1,152,708			384,049
Sale of reserves in place		-			-			-
Production		(89,917	)		(450,831	)		(165,056	)
Balance, August 31, 2011		2,069,705			14,261,158			4,446,564
Revision of previous estimates		429,783			3,298,906			979,601
Purchase of reserves in place		33,328			706,842			151,135
Extensions, discoveries, and other additions		2,788,686			16,288,125			5,503,374
Sale of reserves in place		-			-			-
Production		(235,691	)		(1,109,057	)		(420,534	)
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140
Revision of previous estimates		(194,236	)		(2,923,919	)		(681,556	)
Purchase of reserves in place		1,000,664			7,360,752			2,227,456
Extensions, discoveries, and other additions		1,576,301			4,914,627			2,395,406
Sale of reserves in place		-			-			-
Production		(421,265	)		(2,107,603	)		(772,532	)
Balance, August 31, 2013		7,047,275			40,689,831			13,828,914
Proved developed and undeveloped reserves:
Developed at August 31, 2011		783,821			5,578,067			1,713,499
Undeveloped at August 31, 2011		1,285,884			8,683,091			2,733,066
Balance, August 31, 2011		2,069,705			14,261,158			4,446,565
Developed at August 31, 2012		2,823,604			17,380,806			5,720,405
Undeveloped at August 31, 2012		2,262,207			16,065,168			4,939,735
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140
Developed at August 31, 2013		4,659,405			25,866,008			8,970,406
Undeveloped at August 31, 2013		2,387,870			14,823,823			4,858,507
Balance, August 31, 2013		7,047,275			40,689,831			13,828,913

F-30

Notable changes in proved reserves for the year ended August 31, 2013 included:

· Purchases of reserves in place.  In 2013, purchases of minerals in place of 2.2 million Boe were attributable to the acquisition of 36 producing oil and gas wells and undeveloped acreage from Orr Energy, LLC.  Please see the Acquisitions footnote for further information.

· Revision of previous estimates.  In 2013, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 681,556 Boe as the Company’s drilling schedule was adjusted to reflect the elimination of previously planned vertical drilling locations as the development focus shifted from vertical to horizontal drilling.

· Extensions and discoveries.  In 2013, total extensions and discoveries of 2.4 million Boe were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.

Notable changes in proved reserves for the year ended August 31, 2012 included:

· Purchases of reserves in place.  In 2012, purchases of minerals in place of 151,135 Boe were attributable to the acquisition of additional working interests in existing wells that the Company already operates.

· Revision of previous estimates.  In 2012, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 979,601 Boe.  Included in these revisions were 451,000 Boe of upward adjustments caused by higher crude oil and natural gas prices, and 528,601 Boe of net upward adjustments attributable to reservoir analysis and well performance.

· Extensions and discoveries.  In 2012, total extensions and discoveries of 5.5 million Boe were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.

Notable changes in proved reserves for the year ended August 31, 2011 included:

· Purchases of reserves in place.  In 2011, purchases of minerals in place of 2.4 million Boe were attributable to the acquisition of 88 producing oil and gas wells and undeveloped acreage from Petroleum Exploration and Management, LLC.

· Revision of previous estimates.  In 2011, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 425,623 Boe.  The significant increase in previous estimates is due to the more extensive production data on wells on which had limited data in the previous reserve report.  The wells drilled in the previous year had limited production history for the wells coming online towards the end of the year.  As such, the estimated reserves were based on this limited production history.  With a full year of production history available in the current year, the reserve amounts were updated to reflect the more accurate production information.

· Extensions and discoveries.  In 2011, total extensions and discoveries of 384,049 Boe were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their related proved undeveloped locations added during the year increased the Company’s proved reserves.

F-31

Standardized Measure of Discounted Future Net Cash Flows:  The following analysis is a standardized measure of future net cash flows and changes therein related to estimated proved reserves.  Future oil and gas sales have been computed by applying average prices of oil and gas during each of the fiscal years presented.  Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs.  The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs.  Future income tax expenses were calculated by applying year-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and gas reserves, less the tax basis of properties involved and tax credits and loss carry-forwards relating to oil and gas producing activities.  All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows.  Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and gas reserves.  Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas, and changes in governmental regulations or taxation.

The following table sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in the ASC (in thousands):

	For the Years Ended August 31,
	2013			2012			2011
Future cash inflow	$	749,030		$	537,462		$	235,239
Future production costs		(146,352	)		(85,612	)		(41,278	)
Future development costs		(108,290	)		(100,821	)		(40,404	)
Future income tax expense		(113,545	)		(109,349	)		(30,738	)
Future net cash flows		380,843			241,680			122,819
10% annual discount for estimated timing of cash flows		(199,111	)		(139,175	)		(65,269	)
Standardized measure of discounted future net cash flows	$	181,732		$	102,505		$	57,550

There have been significant fluctuations in the posted prices of oil and natural gas during the last three years.  Prices actually received from purchasers of the Company’s oil and gas are adjusted from posted prices for location differentials, quality differentials, and BTU content. Estimates of the Company’s reserves are based on realized prices.

The following table presents the prices used to prepare the reserve estimates, based upon 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 respective reporting period presented:

	Oil (Bbl)		Gas (Mcf)
August 31, 2011 (Average)	$	84.90	$	5.07
August 31, 2012 (Average)	$	86.68	$	3.76
August 31, 2013 (Average)	$	86.40	$	4.40

Changes in the Standardized Measure of Discounted Future Net Cash Flows:  The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	For the Years Ended August 31,
	2013			2012			2011
Standardized measure, beginning of year	$	102,505		$	57,550		$	13,022
Sale and transfers, net of production costs		(38,569	)		(21,321	)		(8,337	)
Net changes in prices and production costs		(4,550	)		(6,023	)		15,484
Extensions, discoveries, and improved recovery		70,191			69,073			13,693
Changes in estimated future development costs		(6,006	)		(42,578	)		(20,471	)
Development costs incurred during the period		5,106			39,739			16,252
Revision of quantity estimates		(14,214	)		21,058			15,424
Accretion of discount		35,103			15,379			3,245
Net change in income taxes		(7,850	)		(30,832	)		(12,012	)
Purchase of reserves in place		40,016			460			21,250
Standardized measure, end of year	$	181,732		$	102,505		$	57,550

F-32

17.   Unaudited Quarterly Financial Data

The Company’s quarterly financial information for the years ended August 31, 2013 and 2012 is as follows (in thousands, except share data):

	For the Year Ended August 31, 2013
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	8,314	$	10,921		$	12,314	$	14,674
Expenses		4,768		6,439			7,449		8,022
Operating income		3,546		4,482			4,865		6,652
Other income (expense)		7		(146	)		451		(3,406	)
Income before income taxes		3,553		4,336			5,316		3,246
Income tax provision (4)		1,315		1,604			1,701		2,250
Net income	$	2,238	$	2,732		$	3,615	$	996
Net income per common share: (1)
Basic	$	0.04	$	0.05		$	0.07	$	0.02
Diluted	$	0.04	$	0.05		$	0.06	$	0.01
Weighted average shares outstanding:
Basic		51,661,704		54,900,326			55,238,098		66,283,325
Diluted		53,616,182		56,481,752			58,918,586		70,176,105

	For the Year Ended August 31, 2012
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	4,479	$	6,219		$	7,522	$	6,750
Expenses		2,860		3,344			3,676		3,336
Operating income		1,619		2,875			3,846		3,414
Other income (expense)		8		3			17		10
Income before income taxes		1,627		2,878			3,863		3,424
Income tax provision (benefit) (2, 3)		-		(3,241	)		1,432		1,477
Net income	$	1,627	$	6,119		$	2,431	$	1,947
Net income per common share: (1)
Basic	$	0.05	$	0.13		$	0.05	$	0.04
Diluted	$	0.04	$	0.12		$	0.05	$	0.04
Weighted average shares outstanding:
Basic		36,098,212		47,445,178			51,292,810		51,409,340
Diluted		37,845,212		49,229,042			53,174,792		53,072,619

1   The sum of net income per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

2   No income tax was recognized during the three months ended November 30, 2011 as the provision for tax at the effective rate was offset by a change in the valuation allowance.

3   For the three months ended February 29, 2012, the entire valuation allowance of $4.9 million was released and a net deferred tax benefit of $3.2 million was recorded.

4   For the three months ended August 31, 2013, income taxes were provided at a higher than expected rate due to a downward adjustment in the deferred tax asset related to the expiration of underlying stock options.

F-33

18.   Subsequent Events

Agreements to Acquire Oil and Gas Properties

Subsequent to August 31, 2013, the Company conducted due diligence activities for the purpose of acquiring oil and gas properties, including interests in 68 producing oil and gas wells, and various other assets.  All of the producing wells are located in the Wattenberg Field.

One agreement, signed on August 27, 2013, covers interests in 47 oil and gas wells, including 38 wells operated by the seller, plus leases covering approximately 3,639 gross (1,006 net) acres, and certain other assets.  The preliminary purchase price, subject to ordinary closing adjustments, is $17.5 million, consisting of cash consideration of $13.1 million, plus issuance of shares of the Company’s restricted common stock with a value of $4.4 million.

The other agreement, signed on September 16, 2013, covers interests in 21 producing oil and gas wells operated by the seller, plus leases covering approximately 800 net acres.  The preliminary purchase price, subject to ordinary closing adjustments, is $20.5 million, consisting of cash consideration of $17.8 million plus issuance of shares of the Company’s restricted common stock with a value of $2.7 million.

Both agreements are subject to satisfactory completion of due diligence activities and other conditions normal for a transaction of this nature.  Both closings are expected to occur during November.

Exercise of Series C Warrants

Subsequent to August 31, 2013, the Company issued approximately 4.3 million shares pursuant to the exercise of Series C warrants and received proceeds of approximately $25.7 million.

F-34

SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Exchange Act, the Registrant has caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 19th day of June, 2014.

SYNERGY RESOURCES CORPORATION

/s/ Ed Holloway

Ed Holloway,  Co-Chief Executive Officer

(Principal Executive Officer)

/s/ William E. Scaff, Jr.

William E. Scaff, Jr., Co-Chief Executive Officer

(Principal Executive Officer)

52

Pursuant to the requirements of the Securities Exchange Act of l934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ed Holloway	Co-Chief Executive Officer and Director	June 19, 2014
Ed Holloway
/s/ Frank L. Jennings	Chief Financial Officer	June 19, 2014
Frank L. Jennings
/s/ William E. Scaff, Jr.	Co-Chief Executive Officer, Treasurer and Director	June 19, 2014
William E. Scaff, Jr.
/s/ Rick Wilber	Director	June 19, 2014
Rick Wilber
/s/ Raymond E. McElhaney	Director	June 19, 2014
Raymond E. McElhaney
/s/ Bill M. Conrad	Director	June 19, 2014
Bill M. Conrad
	Director
R. W. Noffsinger, III
	Director
George Seward

53

EX-10.27

Exhibit 10.27

P.O.Box17805

Denver, CO 80217

tel (303) 292-1206

fax (800) 886-3898

www.ensignenergy .com

April 19, 2013

Synergy Resources Corporation

20203 Hwy 60

Platteville, CO 80651

Attn: Mr. Ed Holloway and Mr. Bill Scaff

Re:  Drilling Contract -Ensign USD Rig 17 Horizontal4-wellDrillingProgram Weld County, Colorado

Dear Mr. Holloway and Mr. Scaff:

Please find enclosed two copies of the Drilling Contract covering your referenced program.  Upon execution of both copies, please return one copy to my attention at your earliest convenience.

Ensign looks forward to the opportunity of assisting you to fulfill your drilling program goals.

Should you have any questions or concerns, please call me at (303)292-1206.

Sincerely,

/s/ Brandon Lorenz

Brandon Lorenz

Drilling Manager

BL/hh Enclosures

"Performance Excellence - Second to None"

      United States Drilling DRILLING CONTRACT

This Contract is made and entered into on the date hereinafter set forth by and between the parties herein designated as "Operator" and "Contractor."

OPERATOR:	Synergy Resources Corporation
Address:	20203 Hwy 60 Platteville, CO 8065 l

OPERATOR:	Ensign United States Drilling Inc.
Address:	1700 Broadway, Suite 777 Denver, CO 80290

IN CONSIDERATION of the mutual promises, conditions and agreements herein contained and the specifications and special .provisions set forth in Exhibit "A" and Exhibit "B" attached hereto and made a part hereof (the "Contract"), Operator engages Contractor as an independent contractor to drill the hereinafter designated well in search of oil or gas on a Turnkey Basis.

For purposes hereof, the term "Turnkey" or "Turnkey Basis" means Contractor shall furnish equipment, labor, and perform services as herein provided to drill a well, as specified by Operator, to the Turnkey Depth. Subject to terms and conditions hereof, payment to Contractor at a stipulated price is

earned upon attaining such Turnkey Depth and completion of the other obligations of Contractor hereunder. While drilling on a Turnkey Basis, Contractor shall direct, supervise and control drilling operations and assumes certain liabilities to the extent specifically provided herein. Notwithstanding that this is   a Turnkey Contract, Contractor and_ Operator recognize that certain portions of the operations as hereinafter designated, may be performed on a Daywork Basis.

For purposes hereof, the term "Daywork" or "Daywork Basis" means Contractor shall furnish equipment, labor, and perform services as herein Provided, for a specified sum per day under the direction, supervision and control of Operator (inclusive of any employee, agent, consultant, or Subcontractor engaged by Operator to direct drilling operations). When operating on a Daywork Basis, Contractor shall be fully paid at the applicable Rates of payment and assumes only the obligations and liabilities stated herein as being applicable during Daywork operations. Except for such obligations and liabilities specifically assumed by Contractor, Operator shall be solely responsible and assumes liability for all consequences of operations by both parties while on a Daywork Basis, including results and all other risks or liabilities incurred in or incident to such operations.

1. LOCATION OF WELL

Well name and number:                        Horizontal  4 well program         (B.L.)     (W.S.)

Parish/County :       Weld             State:       CO          Field Name:  __________________________

Well location and land description:                T2-6NR64-68W                       

The above is for well and contract identification only and Contractor assumes no liability whatsoever for a proper survey or location stake on Operator's lease.

2.  COMMENCEMENT DATE:

2.1.  Contractor agrees to use reasonable efforts to commence operations for the drilling of the well by the     15      day  of   May     , 20    13       or   _______________________.

2.2 Notwithstanding any provision in this Contract to the contrary, in the event Operator fails, for any reason (including, but not limited to, Force Majeure), to permit Contractor to commence operations for the drilling of the well by Contractor may, at its option, elect to terminate this Contract, and Contractor's right to compensation shall be as set forth herein.

3.  FURNISHED ITEMS:

All items to be furnished by OPERATOR pursuant to Exhibit A and any additional material, equipment, special tools, supplies and services not specifically required to be furnished by CONTRACTOR but proper to the drilling and completion of the well shall be timely furnished at the drill site by the OPERATOR at OPERATOR'S cost. Time lost because of the failure of OPERATOR to furnish timely any items required to be furnished by OPERATOR according to Exhibit A, shall be paid for at daywork rates applicable when the time is lost.

4.  OPERATOR agrees:

(a) To pay CONTRACTOR for the work performed, services rendered, rig time, and the materials, equipment and supplies furnished by CONTRACTOR according to the rates specified in Exhibit A. Daywork rates and the daywork provisions of this contract shall apply to any work requested by OPERATOR and performed by CONTRACTOR when the work exceeds the limits provided for in Exhibit A Payment due hereunder shall be made within thirty (30) days of receipt of CONTRACTOR'S invoices. Amounts not paid within said time shall bear interest from the due date at the rate of fifteen percent (15%) per annum not to exceed the legal rate of interest.

(b) OPERATOR shall reimburse CONTRACTOR for the cost of material, equipment, work or services which are to be furnished by OPERATOR as provided herein but which for convenience are actually furnished by CONTRACTOR. Such charges shall be subject to an additional charge by CONTRACTOR of 15% of such costs for arranging or handling such material, equipment, work or services.

(c) To protect, indemnify and save CONTRACTOR harmless from and against all claims, demands and causes of action of every kind and character arising in favor of OPERATOR'S employees, its subcontractors, or third parties on account of bodily injuries, death or damages to property.

(d)  To carry Comprehensive General Bodily Injury and Property Damage Insurance with limits of at least $1,000,000 aggregate and to carry Workers ' Compensation Insurance with limits not less than required by the laws of the State in which the well is to be drilled.

(e) To reimburse CONTRACTOR for additional costs incurred due to engaging CONTRACTOR to drill within the boundaries of any Colorado cities which impose additional taxes ("Home Rule Cities") on the value of the specialized drilling equipment or on the amounts charged under the drilling contract.

(f) To prepare a sound location adequate in size and capable of properly supporting the drilling rig, unless otherwise provided herein.

5.  CONTRACTOR  agrees:

(a) To perform all work to be conducted by it under the terms of this Agreement and the specifications set forth in Exhibit A in accordance with good drilling practices in the area in which the well is to be drilled.

(b) To pay all claims for labor, material, services, and supplies furnished by CONTRACTOR hereunder to allow no lien or charge to be filed on the lease, the well, the land on which the well is to be drilled or other property of OPERATOR, for labor, material, services or supplies furnished by any employee, SUBCONTRACTOR, or agent of the CONTRACTOR and if such lien is filed, to indemnity, protect, and save OPERATOR harmless from and against all such claims and liens.

(c) To protect, indemnify and save OPERATOR harmless from and against all claims, demands and causes of action of every kind and character arising in favor of CONTRACTOR'S employees, or its subcontractors on account of bodily injuries, death or damages to property.

(d) To carry Comprehensive General Bodily Injury and Property Damage Insurance with limits of at least $1,000,000 aggregate and to carry Workers' Compensation Insurance with limits not less than required by the laws of the State in which the well is to be drilled.

6.  RESPONSIBILITY FOR LOSS OR DAMAGE:

(a)  CONTRACTOR'S SURFACE EQUIPMENT :CONTRACTOR shall be liable, regardless of whether the work is on a turnkey, footage or daywork basis, for damages to or destruction of CONTRACTOR'S equipment when located on the surface, including but not limited to all drilling tools, machinery and appliances for use above the surface, regardless of when or how such damage or destruction occurs, except OPERATOR shall reimburse CONTRACTOR for any such loss or damage thereto caused by negligence, carelessness, recklessness, or intentional acts or omissions of OPERATOR or OPERATOR'S agents, or employees.

(b)  CONTRACTOR's "IN-HOLE" EQUIPMENT - TURNKEY OR FOOTAGE BASIS: CONTRACTOR shall be liable, for damage to or destruction of CONTRACTOR'S in-hole equipment while work is being performed on a turnkey or footage basis including but not limited to drill pipe, drill collars, and tool

United States Drilling

joints; except OPERATOR shall reimburse CONTRACTOR for any such loss or damage thereto caused by negligence, carelessness, recklessness, or intentional acts or omissions of OPERATOR or OPERATOR'S agents, or employees.

(c)  CONTRACTOR'S "IN-HOLE" EQUIPMENT - DAYWORK BASIS: OPERATOR shall be liable, for damage to or destruction of CONTRACTOR's in-hole equipment including but not limited to drill pipe, drill collars, and tool joints, while work is being performed on a daywork basis, and

OPERATOR shall,reimburse CONTRACTOR for any such loss.                                                                                                ·           ·

(d)  OPERATOR'S EQUIPMENT: OPERATOR shall be liable for damage to or destruction of OPERATOR'S equipment or equipment of OPERATOR'S SUBCONTRACTOR, including but not limited to casing, tubing, well head equipment, and tankage, and CONTRACTOR shall be under no liability to reimburse OPERATOR for any such loss other than CONTRACTOR’S gross negligence or willful misconduct.

(e)  THE HOLE - TURNKEY BASIS: CONTRACTOR shall be liable while work is being performed on a turnkey basis and before the well reaches contract depth, for any loss or damage to the hole, except for consequential damages, and except loss or damage thereto caused by negligence, carelessness, recklessness or intentional acts or omissions of OPERATOR or OPERATOR'S agents, or employees. As to such loss OPERATOR shall be liable.

(f) THE HOLE - FOOTAGE BASIS: CONTRACTOR shall be liable while work is being performed on a footage basis and before the well reaches contract depth, for any loss or damage to the hole except for consequential damages, attributable to CONTRACTOR'S operations; except loss or damage to the hole by reason of the failure of casing or equipment furnished by OPERATOR or by reason of the failure of  a cementing job or by reason of any negligence, carelessness, recklessness or intentional acts or omissions of OPERATOR or OPERATOR'S agents or employees. As to such loss OPERATOR shall be liable. If CONTRACTOR  is liable for the loss. or damage and if the hole is not in condition to be carried to the contract depth provided for in Exhibit A, CONTRACTOR shall plug and abandon the hole and if requested by OPERATOR, commence a new hole at the terms and conditions of this contract. In such case, CONTRACTOR shall not be entitled to any payment or compensation for its expenditures in connection with the abandoned ,hole, except for daywork earned for which CONTRACTOR would have been compensated had such hole not been lost and abandoned.

(g)  THE HOLE - DAYWORK BASIS: OPERATOR shall be liable for any loss or damage to the hole while work .is being performed on a daywork basis.

(h)  MATERIALS FURNISHED BY OPERATOR : OPERATOR shall be liable for any personal injuries and for any damage or loss caused in whole or in part to the hole or to any property, equipment or material, of  CONTRACTOR, because of defective materials furnished by or through OPERATOR

Damages or reimbursement as herein required shall be on the basis of actual replacement cost as if delivered at the drill site.

7.  DIFFICULT OR HAZARDOUS DRILLING:

(a) In the event, pyrite, quartzite, granite, igneous rock or other impenetrable substance is encountered while drilling on the footage basis, and the footage   drilled during each 24-hour period multiplied by the footage rate does not at least equal the applicable daywork rate plus the CONTRACTOR'S cost of bits, mud and water used during the 24 hour period, all subsequent drilling operations shall be conducted on :a daywork basis at the - applicable daywork rate, with OPERATOR furnishing the bits, mud, and water, until normal drilling operations. and procedures can be resumed. No footage charge shall be made for footage drilled while on daywork rates; If such conditions are encountered while drilling on the turnkey basis,  all subsequent drilling operations shall be conducted on a daywork basis at the applicable daywork rate, with OPERATOR furnishing the bits, mud, and water until normal drilling operations and procedures can be resumed. The turnkey charge shall be adjusted by a negotiated amount to reflect the portion of the drilling operation drilled at daywork rates.

(b)  In the event water flow, domal, steeply dipping or faulted formation, abnormal pressure, underground mine or cavern, heaving formation, salt or other conditions are encountered which makes drilling abnormally difficult or hazardous, causes sticking of drill pipe or casing, or other difficulty occurs which precludes drilling ahead under reasonably normal procedures, CONTRACTOR shall, in all such cases, without undue delay, exert reasonable efforts to overcome such difficulty, When such condition is encountered, further operations shall be conducted on a daywork basis at the applicable daywork rate, with OPERATOR furnishing the bits, mud and water, until such conditions have been overcome and normal drilling operations can be resumed. OPERATOR shall assume the .risk of loss or damage to the hole and to CONTRACTOR'S equipment in the hole from the time such condition is encountered. If.the drilling is being   performed on a footage basis, no charge shall be made for footage drilled while on daywork rates. Ifdrilling is being performed on a turnkey basis, the daywork charge incurred hereunder shall be a separate charge to the OPERATOR and the turnkey charge shall be adjusted by a negotiated amount to reflect the portion of the drilling operations drilled at daywork rates.

(c)  In the event loss of circulation is encountered, CONTRACTOR shall, without undue delay, exert reasonable effort to overcome such condition. When such condition is encountered, OPERATOR shall assume and bear the risk of loss or damage to the hole and to CONTRACTOR'S equipment in the hole. Should such conditions persist in spite of CONTRACTOR'S efforts to overcome it, then after the period of time specified in Exhibit A under "Lost Circulation" is consumed in such efforts, further operations shall be conducted on a daywork basis at the applicable daywork rate, with OPERATOR furnishing the bits, mud and water until such condition has been overcome and normal drilling operations can be resumed. If the drilling is being performed on a footage basis, no footage charge shall be made for footage drilled while on daywork rates. If the drilling is performed on a turnkey basis, the daywork charge incurred hereunder shall be separate charge to the OPERATOR and the turnkey charge shall be adjusted by a negotiated amount to reflect the portion of the drilling operation drilled at daywork rates.

8.  POLLUTION  OR CONTAMINATION:

Notwithstanding anything to the contrary contained herein, it is understood and agreed by and between CONTRACTOR and OPERATOR that the responsibility for pollution or contamination shall be as follows:

(a)  CONTRACTOR shall assume all responsibility for, including control and removal of, and shall protect, defend and indemnify OPERATOR from and against all Claims, demands and causes of action of every kind and character arising from pollution or contamination, which originates above: the surface of the land or water from spills of fuels, lubricants, motor oils, pipe dope, paints, solvents, ballast, bilge and garbage, except unavoidable pollution from reserve pits, wholly in CONTRACTOR's possession and control and directly associated with CONTRACTOR's equipment and facilities.

(b)  OPERATOR shall assume all responsibility for, including control and removal of, and shall protect, defend and indemnify CONTRACTOR and its suppliers, CONTRACTORs and SUBCONTRACTORs of any tier from and against all claims, demands, and causes of action of every kind and character arising directly or indirectly from all other pollution or contamination which may occur during the conduct of operations hereunder, including, but not limited to, that which may result from the reserve pits, fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas, water or other substance, as well as the use or disposition of all drilling fluids, including, but not limited to, oil emulsion, oil base or chemically treated drilling fluids, contaminated cuttings or cavings, lost circulation and fish recovery materials and fluids. OPERATOR shall release CONTRACTOR and its suppliers, CONTRACTORs and SUBCONTRACTORs of any tier of any liability for the foregoing.

(c)  In the event a third party commits an act or omission which results in pollution or contamination for which either CONTRACTOR or OPERATOR, for whom such party is performing work, is held to be legally liable, the responsibility therefore shall be considered, as between CONTRACTOR and OPERATOR, to be the same as if the party for whom the work is performed had performed the same and all the obligations respecting protection, defense, indemnity and limitation of responsibility and liability, as set forth in (a) and (b) above, shall be specifically applied.

9.  INDEPENDENT   CONTRACTOR:

CONTRACTOR is an Independent CONTRACTOR with respect to performance of work hereunder. Neither CONTRACTOR'S nor OPERATOR'S employees, agents,or representatives shall be deemed to be that of the other. OPERATOR'S representative or representatives shall have access to the premises for the purpose  of observing tests or inspecting the work and shall be empowered to act for OPERATOR in all matters relating to CONTRACTOR'S performance of the work. On a daywork basis the OPERATOR shall have the right and responsibility to exercise those controls and direct the operations to the extent necessary to accomplish the result desired by the OPERATOR with such control and direction of the OPERATOR limited to the custom in the industry in the area in which the work is  performed, to the safety of the CONTRACTOR'S equipment or to the safety of personnel at the drill site.

l 0. COMPLIANCE WITH LAW:

CONTRACTOR and OPERATOR respectively agree to comply with all laws, rules and regulations, federal, state and 111unicipal, which are now or may become applicable to operations covered by this Agreement or arising out of the performance of such operations. The contact is to be interpreted by the substantive laws of the State of Colorado in effect at the time of the execution of this Agreement. CONTRACTOR agrees, in its performance of this Agreement, to comply with all of the provisions of Part 11, Section 202(1) to (7), inclusive, of Executive Order 11 246 (30F.R. 12319), and any present or future amendments, supplements, substitutes or revisions thereof, and with the Equal Opportunity claims prescribed in 41 CFR 60-1.4, the Affirmative Action Clause prescribed in 41 CFR 60-250.4, the Affirmative Action Clause prescribed in 41 CFR 60-741.4 and the Certification of Compliance with Environmental Laws prescribed in 40 CFR 15.20 which are hereby incorporated by reference in this Agreement.

United States Drilling

11. FORCE MAJEURE:

CONTRACTOR shall not be liable to OPERATOR for any delays, damages, or any failure to perform caused by reason of Federal or State laws of the rules, regulations or orders of any governmental agency purporting to exercise authority or control respecting the operations covered hereby, or because of strikes, or causes beyond the control of the CONTRACTOR. Delays due to the above causes, or any of them, shall not be deemed to be a breach of, or :failure 1;o perform under, this Agreement.

12.  ACCESS TO SITE:

OPERATOR shall secure for CONTRACTOR rights of ingress and egress to the location on which the well is to be drilled. Should CONTRACTOR be denied free and easy access to or from the location, or should CONTRACTOR be prevented from performance of the drilling contemplated by this Agreement by any order of court or by order of any governmental agency or body or because of any reason not within the control of CONTRACTOR, time lost because of such order or because of such reason shall be paid by OPERATOR at the applicable daywork rates.

13.  WORK STOPPAGE:

If OPERATOR directs stoppage of work prior to reaching a depth which is less than 100% of the contract depth specified in Exhibit A, CONTRACTOR shall discontinue the drilling of the well and shall abandon or complete the same as directed. If CONTRACTOR has not reached the percentage of contract depth provided above, OPERATOR will compensate CONTRACTOR for all CONTRACTOR'S costs and expenses as shall be determined by the books and records of the CONTRACTOR maintained in accordance with its established practices, plus 20% on account of profit unless the parties shall agree upon another basis prior to stoppage of work.

14.  DEFAULT:

In the event OPERATOR defaults .in any payment or fails to perform any condition herein required or if a proceeding ii) bankruptcy or receivership is instituted against or by OPERATOR or if CONTRACTOR shall feel unsafe or insecure.in the ability of  OPERATOR to p  perform, then CONTRACTOR may suspend its performance until security deemed adequate to CONTRACTOR is given to assure performance by OPERATOR, or CONTRACTOR may terminate this Agreement. The right of CONTRACTOR to either suspend or terminate is cumulative. In the event of termination of this Agreement pursuant to this Paragraph 14, OPERATOR WILL compensate CONTRACTOR for all CONTRACTOR'S costs and expenses as shall be determined by the books and records of the CONTRACTOR maintained in accordance with its established practices plus twenty percent (20%) on account of profit, unless the parties shall agree upon another basis prior to stoppage of work.

15.  COST INCREASE:

In the event the cost to CONTRACTOR of a) labor, including benefits, b) supplies, services, repair parts or materials, and/or c) fuel increase from the date of this Agreement to the date when such labor is performed or supplies, services, repair parts, materials or fuel are furnished to CONTRACTOR at the location described in the Exhibit A, then the amount agreed to be paid by OPERATOR to CONTRACTOR shall be increased by the amount of such increase in costs to CONTRACTOR attributable to such of the above items as are furnished to or used by CONTRACTOR in connections with the drilling of the well.

16. WRITTEN WAIVER:

None of the requirements of this Agreement shall be considered as waived by either party unless the waiver is in writing, and signed by the persons executing this Agreement, or other duly authorized agent representative of the party.

17.  SPECIAL PROVISIONS:

See attached Exhibits Al and B1  and C which must be executed by both parties.

18. TURNKEY  COMMITMENTS AND  LIABILITY:

Upon completion by Contractor of all operations to be performed by it under the Turnkey Basis as Specified in Exhibit "A", Contractor shall notify Operator of such completion by noting the date and hour of such completion upon the daily drilling  Report form. No later than twenty-four (24) hours after Operator's receipt of such notification, Operator shall advise Contractor in writing of any Objections it may have with respect to Contractor's performance hereunder. Operator's failure to so object to Contractor's performance within the Specified period shall be conclusive proof of Operator's acceptance of the well and Contractor's performance hereunder. Upon acceptance of the work by Operator pursuant to Subparagraph 18 hereinabove, all risk of loss with respect to the well drilled hereunder and goods and services provided by Contractor shall pass to Operator. Contractor shall have no liability for any defects in such completed operations. Notwithstanding anything else Contained herein to the contrary, Operator accepts all materials, supplies, equipment and services furnished or performed by Contractor as is and Where is. CONTRACTOR MAKES NO WARRANTY, EXPRESS OR IMPLIED, AS TO THE MERCHANTABILITY, OR FITNESS OF ANY MATERIALS, SUPPLIES OR EQUIPMENT FOR ANY PURPOSE. NO WARRANTY OF GOOD AND WORKMANLIKE PERFORMANCE IS GIVEN BY THE CONTRACTOR BY VIRTUE OF THIS CONTRACT FOR ANY PERFORMANCE ACCEPTED BY OPERATOR.

19.  GOVERNING LAW:

This contract shall be construed and governed under the laws of the State of Colorado.

20.  EXECUTION:

This Agreement shall not be binding upon CONTRACTOR until executed by OPERATOR and a duplicate original executed by OPERATOR is returned to and received by CONTRACTOR.

WITNESS the signatures of the parties hereto in DUPLICATE ORIGINALS, this        19th         day of     April     , 2013.

OPERATOR: Synergy Resources Corporation		CONTRACTOR: Ensign United States Drilling Inc.
By:	William E. Schaff Jr.	By:	/s/ Brandon Lorenz
Print Name:	William E. Scaff, Jr.	Print Name:	Brandon Lorenz
Title:	Vice President	Title:	Drilling Manager

Exhibit A1

OPERATOR: Synergy Resources Corporation       Address:  20203 Hwy 60                       Platteville, CO 80651   Contract Type: TurnkeyRig Number - 17 Crew Size - 5 Depth - 12000 feet into the Niobrara Horizontal formation Deviation Limit - Per Directional Plan degrees Hole Size 13-1/2"/8-3/4"/6-1/8" Date of Bid: 4/19/2013   WELL NAME:  NIOBRARA HORIZONTAL   Location: -T2-6N -R64-68W   County: Weld   State: CO.

	Furnished by
Materials and Supplies	Operator		Contractor		Remarks
Wells Permits		X
Stake Location		X
Surface Damages & Right of Way		X
Road, Location & Maintenance		X
Mud Pits, EARTH or STEEL				X	Per Inventory
Reserve Pits		X
Backfill Pits		X
Surface Casing - 9-5/6" & Intermediate Casing - 7"				X
Rig Time to Run				X
Cementing end Cementing Services				X	Halliburton
W.O.C. Time prior to Drilling Plug				X	Min 6 hrs
Power Tongs				X
Production Casing - 4.5", 11.6 #/ft, N-80		X
Rig Time to Run				X	• See Note
Cementing and Cementing Services		X
W.O.C. Time				X	• See Note
Power Tongs, Casing Crews, Lay-Down Machine, and Crews				X
Fuel				X
Boiler Fuel				X
Water - Source				X
Hauling or Pump, Free Tanks, Transfer Pumps				X
After Cum. Hrs. Lost Circ.		X			0 Cum
Mud (Mud up depth per Contractor)				X	Baroid - subject to change based on performance
After ___0 ___ cum. hrs lost circulation		X			0 Cum
Coring-RigTime,3rdPart		X
ReamingCored Hole		X
Testing - Rig Time				X	• See Note
BOPTest				X
3rdPartyServices		X
Logging - Rig time				X	• See Note
3rdPartyServices		X
LostCirculation		X
After initial ___/___ cum. hrs. furnished bv Contractor		X			0/0
Plugging - Rig Time				X	• See Note
3rdPartyServices		X
WellHead		X
DirectionalServices+Trailer				X
W.O.O.oranyOperatorSuppliedServices		X
Circulate Samples				X	• See Note
Daywork RepairTime:  ___ hrs. / job ___ hrs. / well				X
RentalDrillPipeDS-36S-135				X
Mob-Demob, Move Rig, Moving Permits				X	See Exhibit B1
Trash,Sanilet,Trenching,CampGenerator				X
▪Note: Contractor will provide 48 hrs daywork at TD

A TURNKEY AMOUNT of $1094300 for work performed on a turnkey basis as herein provided.

Daywork Rates per 24 Hour day:

$28000 With Drill Pipe             $ 28000 Without Drill Pipe

$28000 Standby with crews   $25200 Standby without crews

Boiler Rate: $35 per hour.

Drill Stem Test - Daywork terms apply to waiting on service company to get into operating position and/or waiting on daylight to open or pull Drill Stem Test.

(Abnormal pressure as used in this Contract shall mean any pressure for which a mud excess of 11 lb/gal. is used to gain control of saidpressure.)

See Attached Exhibit B1
Operator	ENSIGNUNITEDSTATES Dirlling Inc.
/s/ William E. Scaff Jr.	/s/ Brandon Lorenz

This is a bid and not a contract until executed by both parties and made a part of the Drilling Contract.

Exhibit B1

1.  Contract term is for 4 wells commencing about May 15, 2012 for Ensign Rig 17.

2.  Any labor increase will be charged to Operator at actual cost. Any wage scale over standard Ensign payscale (including processing charges) will be rebilled to the Operator

3.  Mobilization Trucking in excess of $15,000 will be rebilled at cost. A $5,000 credit shall be given to Operator on skid moves (well to well moves within a pad) when the rig skids up to 50 feet between well centers.  Moving equipment other than regular moving trucks (i.e. bulldozers/CATS) required to effectively skid  the rigs shall be provided by the Operator. If no other location to take the rig after completion of a well, Operator to pay demob to Ensign LaSalle Truck Yard.

4.  Standby, waiting on location, well permits or weather will be charged at 90% of dayrate.

5.  Ensign will provide mud cleaning services (Close Loop) and chemicals at the expense of the Contractor. Operator will be responsible for cleaning, hauling and disposing or all water, drilling fluids, and solids for each well.

6.  Ensign United States Drilling Inc. will not be liable for any problems associated with Operator's casing unless the problem is due to gross negligence or willful misconduct of Ensign United States Drilling Inc.

7.  Prior to the rig setting surface casing, Operator is required to supply a wellhead to NU BOP onto. Integrity of the wellhead provided must be suitable for BOP test or if head does not meet Ensign's standards, a new head will be provided for you by ENSIGN at approximately $600 (rebilled at cost).

8.  Any services charges in excess of the limits listed in Exhibit A will be rebilled to Operator.

9.  Drill Stem Tests:

The initial opening of a drill stem test tool will take place during daylight hours.

Drill stem tests will be reversed out prior to pulling test tool.

ENSIGN Drilling may allow Operator to pull test free and remove 1500 feet of pipe prior to reversing out.

10.All rig modifications necessary to install additional equipment or to drill the Operator's Program will be at the expense of the Operator. This includes, but not limited to, rig time, labor, materials, any third party charges, and any repair to Contractor's equipment associated with said modification. At Contractor's discretion, the Operator will restore the rig to its original condition when said modifications are no longer necessary, at the Operator's expense.  Prior to initiating any rig modification for Operator, Operator must approve the expenditure .

11.  No PDC bits to be run on ENSIGN owned drill pipe or other drill pipe without the use of a mud motor.

12.  Pumps will be limited to 80% of the manufacturer's specifications. Ensign shall provide a second 1OOOHP pump.

13.  Tubulars will be limited to 80% of manufacturer's specifications.

14.  Forklifts used on Ensign rigs will have grapples on forks. Forklift operator shall be certified.

15.  Operator agrees that Operator's personnel as well as third party services shall be subject to Ensign's policies and regulations regarding safety (including full use of PPE), environmental and health, including drug and alcohol use. Operations may be suspended if no corrective action is taken.

16.  The drill sting including BHA but excluding Contractor's directional tools and all related handling tools used to drill the lateral will be provided by the Operator. If Operator wishes to have Contractor provide such Items, the cost of the related Items will be billed to the Operator

17.  Directional Stipulations:

Directional costs are based on conventional directional services from surface to TD. TD is end of lateral section. Included is Gamma services through the curve and the lateral section.

Ensign reserves the right to reject any well plan.

18.  In line with Ensign's policy to conduct SAFE operations and horizontal well requirements, this rig operating in the Wattenberg Field-DJ Basin.

whether on Turnkey or Daywork, shall mud-up and weight-up to 9.2ppg 200 feet above the Teepee Buttes formation and to 1O.Oppg before the Sharon Spring formation. Should the top of the Teepee Buttes formation be unknown, the mud-up and weight-up depth shall be 1,000 feet above the top of the Niobrara formation.

19.  24 hour Rig Manager. Rig Manager and Drillers will have Well Control Certificates.

20. Drilling Stipulations:

(a). Curve Section - Before beginning to drill the curve section of the well, Synergy Resources shall provide Ensign a TYD +/- 5 feet to land the curve section. Both parties shall provide written approval of subject well plan, with email acceptance as approved method of acceptance.

(b). Trip time for BHA changes to achieve newly revised TYO shall be on the Operator.

(c). Subject to Ensign following well plan to 7" casing landing point, and should the TYO be changed during drilling of the curve section, and that Ensign cannot achieve the new TVD due to excessive doglegs, sidetracks shall be performed on daywork. Excessive doglegs are defined as those greater than 16"1120 feet. However, if no changes are made to the agreed to well plan, and Ensign must exceed these limits to land the curve, then sidetracks will be done on turnkey.

(d). Lateral Section - Any geological side tracks shall be performed on Daywork.

(e). Contractor shall be responsible for sidetracks and/or redrills as a result of failure or Contractor’s equipment, downhole tools, and personnel, which are operating within specifications of accepted well plan by Operator and Contractor.

(f). When abnormal, difficult or hazardous drilling conditions occur operations shall commence under a daywork basis and at daywork rates. Refer to Section 7 of the Tumkey Contract.

the Turnkey Contract.

Operator By: /s/ William E. Scaff Jr.
ENSIGN United States Drilling Inc.   /s/ Brandon Lorenz

Exhibit A-1

OPERATOR: Synergy Resources Corporation     Address: 20203 Hwy 60                      Platteville, CO 80651   Contract Type: Turnkey Rig Number - 17 Crew Size - 5 Depth - 12000 feet into the Codel Horizontal formation Deviation Limit - Per Directional Plan degrees Hole Size 13-1/2"/8-3/4"/6-1/8" Date of Bid: 4/19/2013   WELL NAME: CODELL HORIZONTAL   Location: -T2-6N -R64-68W   County: Weld   State: CO.  

	Furnished by
Materials and Supplies	Operator		Contractor		Remarks
Wells Permits		X
Stake Location		X
Surface Damages & Right of Way		X
Road, Location & Maintenance		X
Mud Pits, EARTH or STEEL				X	Per Inventory
Reserve Pits		X
Backfill Pits		X
Surface Casing - 9-5/8" & Intermediate Casing - 7"				X
Rig Time to Run				X
Cementing end Cementing Services				X	Halliburton
W.O.C. Time prior to Drilling Plug				X	Min 8 hrs
Power Tongs				X
Production Casing - 4.5", 11.6 #/ft, N-80		X
Rig Time to Run				X	• See Note
Cementing and Cementing Services		X
W.O.C. Time				X	• See Note
Power Tongs, Casing Crews, Lay-Down Machine, and Crews				X
Fuel				X
Boiler Fuel				X
Water - Source				X
Hauling or Pump, Free Tanks, Transfer Pumps				X
After Cum. Hrs. Lost Circ.		X			0 Cum
Mud (Mud up depth per Contractor)				X	Baroid - subject to change based on performance
After ___0 ___ cum. hrs lost circulation		X			0 Cum
Coring-RigTime,3rdPart		X
ReamingCored Hole		X
Testing - Rig Time				X	• See Note
BOPTest				X
3rdPartyServices		X
Logging - Rig time				X	• See Note
3rdPartyServices		X
LostCirculation		X
After initial ___/___ cum. hrs. furnished bv Contractor		X			0/0
Plugging - Rig Time				X	• See Note
3rd Party Services		X
WellHead		X
DirectionalServices+Trailer				X
W.O.O.oranyOperatorSuppliedServices		X
Circulate Samples				X	• See Note
Daywork RepairTime: ___ hrs. / job ___ hrs. / well				X
RentalDrillPipeDS-38S-135				X
Mob-Demob, Move Rig, Moving Permits				X	See Exhibit B1
Trash,Sanilet,Trenching,CampGenerator				X
▪ Note: Contractor will provide 48 hrs daywork at TD

A TURNKEY AMOUNT of $1139100 for work performed on a turnkey basis as herein provided.

Daywork Rates per 24 Hour day:

$28000 With Drill Pipe          $ 28000 Without Drill Pipe

$28000 Standby with crews $25200 Standby without crews

Boiler Rate: $35 per hour.

Drill Stem Test - Daywork terms apply to waiting on service company to get into operating position and/or waiting on daylight to open or pull Drill Stem Test.

(Abnormal pressure as used in this Contract shall mean any pressure for which a mud excess of 9.5 lb/gal. is used to gain control of saidpressure.)

See Attached Exhibit B1
Operator	ENSIGNUNITEDSTATES Dirlling Inc.
/s/ William E. Scaff Jr.	/s/ Brandon Lorenz

This is a bid and not a contract until executed by both parties and made a part of the Drilling Contract.

Exhibit B1

1.  Contract term is for 4 wells commencing about May 15, 2012 for Ensign Rig 17.

2.  Any labor increase will be charged to Operator al actual cost. Any wage scale over standard Ensign payscale (including processing charges) will be rebilled to the Operator.

3.  Mobilization Trucking in excess of $15,000 will be rebilled at cost. A $5,000 credit shall be given to Operator on skid moves (well to well moves within a pad) when the rig skids up to 50 feet between well centers.  Moving equipment other than regular moving trucks (i.e. bulldozers/CATS) required to effectively skid the rigs shall be provided by the Operator. If no other location to take the rig after completion of a well , Operator to pay demob to Ensign l.aSaile Truck Yard.

4.  Standby, waiting on location, well permits or weather will be charged at 90% of dayrate.

5.   Ensign well provide mud cleaning services {Close Loop) and chemicals at the expense of the Contractor. Operator will be responsible for cleaning, hauling and disposing of all water, drilling fluids, and solids for each well.

6.  Ensign United States Drilling Inc. will not be liable for any problems associated with Operator's casing unless the problem is due to gross negligence or willful misconduct of Ensign United States Drilling Inc.

7.  Prior to the rig setting surface casing, Operator is required to supply a wellhead to NU BOP onto. Integrity of the wellhead provided must be suitable for BOP test or if head does not meet Ensign's standards, a new head will be provided for you by ENSIGN at approximately $600 (rebilled at cost).

8.  Any services charges in excess of the limits listed in Exhibit A will be rebilled to Operator.

9.  Drill Stem Tests:

The initial opening of a drill stem test tool will take place during daylight hours.

Drill stem tests will be reversed out prior to pulling test tool.

ENSIGN Drilling may allow Operator to pull test free and remove 1500 feet of pipe prior to reversing out.

10.  All rig modifications necessary to install additional equipment or to drill the Operator's Program will be at the expense of the Operator. This includes, but not limited to, rig time, labor, materials, any third party charges, and any repair to Contractor's equipment associated with said modification. At Contractor's discretion, the Operator will restore the rig to Its original condition when said modifications are no longer necessary, at the Operator's expense.  Prior to initiating any rig modification for Operator, Operator must approve the expenditure.

11.  No PDC bits to be run on ENSIGN owned drill pipe or other drill pipe without the use of a mud motor.

12.  Pumps will be limited to 80% of the manufacturer's specifications. Ensign shall provide a second 1OOOHP pump.

13.  Tubulars will be limited to 80% of manufacturer's specifications.

14.  Forklifts used on Ensign rigs will have grapples on forks . Forklift operator shall be certified.

15.  Operator agrees that Operator's personnel as wen as third party services shall be subject to Ensign's policies and regulations regarding safety (including full use of PPE), environmental and health, including drug and alcohol use. Operations may be suspended if no corrective action is taken.

16.  The drill sting including BHA but excluding Contractor's directional tools and all related handling tools used to drill the lateral will be provided by the Operator. If Operator wishes to have Contractor provide such items, the cost of the related items will be billed to the Operator

17.  Directional Stipulations :

Directional costs are based on conventional directional services from surface to TD. TD is end of lateral section. Included is Gamma services through the curve and the lateral section.

Ensign reserves the right to reject any well plan.

18.  In line with Ensign's policy to conduct SAFE operations and horizontal well requirements, this rig operating in the Wattenberg Field-DJ Basin, whether on Turnkey or Daywork, shall mud-up and weight-up to 9.2ppg 200 feet above the Teepee Buttes formation and to 1O.Oppg before the Sharon Spring formation. Should the top of the Teepee Buttes formation be unknown, the mud-up and weight-up depth shall be 1,000 feet above the top of the Niobrara formation.

19.  24 hour Rig Manager. Rig Manager and Drillers will have Well Control Certificates.

20.  Drilling Stipulations:

(a). Curve Section - Before beginning to drill the curve section of the well, Synergy Resources shall provide Ensign a TVD +/- 5 feet to land the curve section.

Both parties shall provide written approval of subject well plan, with email acceptance as approved method of acceptance.

(b). Trip time for BHA changes to achieve newly revised TVD shall be on the Operator.

(c). Subject to Ensign following well plan to 7" casing landing point, and should the TVD be changed during drilling of the curve section, and that Ensign cannot achieve the new TVD due to excessive doglegs, sidetracks shall be performed on daywork. Excessive doglegs are defined as those greater than 16"/120 feet. However, if no changes are made to the agreed to well plan, and Ensign must exceed these limits to land the curve ,then sidetracks will be done on turnkey.

(d). Lateral Section - Any geological side tracks shall be performed on Daywork.

(e). Contractor shall be responsible for sidetracks and/or redrills as a result of failure or Contractor's equipment, downhole tools, and personnel, which are operating within specifications of accepted well plan by Operator and Contractor.

(f). When abnormal, difficult or hazardous drilling conditions occur operations shall commence under a daywork basis and at daywork rates. Refer to Section 7 of

the Turnkey Contract.

the Turnkey Contract.

Operator By: /s/ William E. Scaff Jr.
ENSIGN United States Drilling Inc.   /s/ Brandon Lorenz

NOTE: THIS AGREEMENT CONTAINS PROVISIONS WHICH INDEMNIFY AND/OR RELEASE THE INDEMNIFIED AND/OR RELEASED PARTY FROM THE CONSEQUENCES OF ITS OWN NEGLIGENCE AND OTHER LEGAL FAULT.

ENSIGN DIRECTIONAL  SERVICES TERMS AND CONDITIONS UNDER  ENSIGN  TURNKEY  CONTRACT-EXHIBIT  C

Ensign United States Drilling, Inc., ("ENSIGN") under Turnkey Contract Dated April  19, 2013.  will  also  provide  services  by ENSIGN DIRECTIONAL SERVICES ("DIRECTIONAL SERVICES") to its Operators (each an "OPERATOR"), which are further governed by the terms and conditions stated herein and any additional terms proposed or agreed to in writing by an  authorized representative of the Operator and Ensign (these terms and conditions and any such additional terms collectively referred to herein as the "Agreement'). Any additions to or modifications of these terms and conditions, or any terms and conditions contained in OPERATOR's order inconsistent herewith, shall not bind ENSIGN unless accepted in writing by an authorized representative of ENSIGN.

I.    LIABILITIES, RELEASES AND INDEMNIFICATION:

Liabilities, releases and indemnification terms shall be as stated under the Turnkey Contract, with the addition of:

OPERATOR shall release, defend, indemnify and hold ENSIGN harmless from and against any Claims arising out of, or related to, subsurface trespass arising out of directional drilling operations or other operations performed by ENSIGN DIRECTIONAL or its employees, OPERATOR or its employees, or other contractors or their employees. OPERATOR shall furnish ENSIGN DIRECTIONAL with a well location plan (certified by OPERATOR as correct) setting out the surface location of the well, the lease, license, or property boundary lines, and the bottom hole location of OPERATOR's directionally drilled well. If in the course of drilling the well, it becomes evident to ENSIGN DIRECTIONAL that the certified plan is in error, ENSIGN DIRECTIONAL shall at once notify OPERATOR of the error, and OPERATOR shall be responsible to regulate all directional drilling factors so that OPERATOR's well bottom hole location will be situated on OPERATOR's property, license, or leasehold at total depth of the well being drilled.

While on a Daywork basis under the direction and control of OPERATOR, any loss or damage to in-hole property of ENSIGN DIRECTIONAL or ENSIGN subcontractors shall be borne by OPERATOR.

2.  OPERATOR WARRANTY/BINDING  AUTHORITY

If OPERATOR is not the sole owner of the mineral interests, the well or the field, OPERATOR's request for Services, Equipment or Products shall constitute OPERATOR's warranty that OPERATOR is the duly constituted agent of each and every owner and has full authority to represent the interests of the same with respect to all decisions taken throughout the provision of any Services, Equipment or Products hereunder.

OPERATOR will defend, release, indemnify and hold ENSIGN harmless from and against all Claims resulting from the allegation by any person that OPERATOR has misrepresented or lacked sufficient authority to represent such person as warranted by OPERATOR in this Article.

3.  PATENTS

ENSIGN DIRECTIONAL warrants that the use or sale of Equipment or Products hereunder will not infringe patents of others by reason of the use or sale of such Equipment or Products per se, and hereby agrees to hold OPERATOR harmless against judgment for damages for infringement of any such patent, provided that OPERATOR shall promptly notify ENSIGN DIRECTIONAL in writing upon receipt of any claim for infringement, or upon the filing of any such suit for infringement, whichever first occurs, and shall afford ENSIGN DIRECTIONAL full opportunity, at ENSIGN DIRECTIONAL's option and expense, to answer such claim or threat of suit, assume the control of the defense of such suit, and settle or compromise same in any way ENSIGN DIRECTIONAL sees fit. ENSIGN DIRECTIONAL does not warrant that such Equipment or Products: (a) will not infringe any such patent when not of ENSIGN DIRECTIONAL's manufacture , or specially made, in whole or in part, to the OPERATOR's design specifications; or (b) if used or sold in combination with other materials or apparatus or used in the practice of processes , will not, as a result of such combination or use, infringe any such patent, and ENSIGN DIRECTIONAL shall not be liable and does not indemnify OPERATOR for damages or losses of any nature whatsoever resulting from actual or alleged patent infringement arising pursuant to (a) and (b) above. THIS PARAGRAPH STATES THE ENTIRE RESPONSIBILITY OF ENSIGN DIRECTIONAL CONCERNING PATENT INFRINGEMENT.

4.  CONFIDENTIALITY

Each party shall maintain all data and information obtained from the other party in strict confidence, subject only to disclosure required by law or legal process. In the event that ENSIGN DIRECTIONAL owns copyrights to, patents to, or has filed patent applications on, any technology related to the Services, Products or Equipment furnished by ENSIGN DIRECTIONAL hereunder, and if ENSIGN DIRECTIONAL makes any improvements on such technology, then such improvements shall not fall within the confidentiality obligations included herein, and ENSIGN DIRECTIONAL shall own all such improvements, including drawings, specifications, calculations and other documents . The design, construction, application and operation of ENSIGN DIRECTIONAL's Services, Equipment and Products embody proprietary and confidential information. OPERATOR shall maintain this information in strict confidence and shall not disclose it to others, subject only to disclosure required by law or legal process.

1

5.  LIENS. ATTACHMENTS  AND ENCUMBRANCES

Should OPERATOR commit a material breach of any terms and conditions of this Agreement, become bankrupt, insolvent, go into receivership or should any creditor or other person attach or levy OPERATOR's property or equipment, ENSIGN DIRECTIONAL shall immediately have the right, without notice and without liability for trespass or damages, to retake and remove any of its Products or Equipment wherever it may be found. OPERATOR shall release, defend, indemnify and hold ENSIGN  DIRECTIONAL Indemnities harmless  from any and all liens and encumbrances against Products or Equipment furnished hereunder and shall return same promptly to ENSIGN DIRECTIONAL free of any liens or encumbrances.

6. DISPUTE RESOLUTION

Except for a dispute,  controversy, or claim (a "Dispute") arising out of this  Agreement  from  Services,  Equipment  or  Products provided , or to be provided, by ENSIGN DIRECTIONAL , the parties will attempt to resolve any Dispute between them which results from this Agreement in a spirit of cooperation. Accordingly, the parties agree to engage in good faith negotiations to reach a rapid and equitable solution. If the parties are unable to resolve a dispute through direct negotiation, they will use the services of a mediator. Each party will bear its own expenses and an equal share of the costs of the mediators and the body administering the mediation.

7.   GENERAL

Failure of OPERATOR or ENSIGN DIRECTIONAL to enforce any of the terms and conditions of this Agreement shall not prevent a subsequent enforcement of such terms and conditions or be deemed a waiver of any subsequent breach . Should any provision of this Agreement, or a portion thereof, be unenforceable or in conflict with governing country, state, province, or local Jaws, then the validity of the remaining provisions, and portions thereof, shall not be affected by such unenforceability or conflict, and this Agreement shall be construed as if such provisions, or portion thereof, were not contained herein. This Agreement contains all representations of the parties and supersedes all prior oral or written agreements or representations. OPERATOR acknowledges that it has not relied on any representations other than those contained in this Agreement. This Agreement shall not be varied, supplemented, qualified, or interpreted by any prior course of dealing between the parties or by any usage of trade and may only be amended by an agreement executed by both parties .

2

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Ed Holloway, certify that;

1.           I have reviewed this annual report on Form 10-K/A 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 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:  June 19, 2014	By:	/s/ Ed Holloway
		Ed Holloway, Co-Chief Executive Officer (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, William E. Scaff, Jr, certify that;

1.           I have reviewed this annual report on Form 10-K/A 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 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: June 19, 2014	By:	/s/ William E. Scaff, Jr.,
		William E. 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 annual report on Form 10-K/A 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 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:  June 19, 2014	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Principal Financial and Accounting Officer

EX-32

Exhibit 32

In connection with the annual report of Synergy Resources Corporation, (the “Company”) on Form 10-K/A for the fiscal year ended August 31, 2013 as filed with the Securities Exchange Commission on the date hereof (the “Report”) Ed Holloway and William E. Scaff, Jr, the Principal 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:

(1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; 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: June 19, 2014	By:	/s/ Ed Holloway
		Ed Holloway, Co-Chief Executive Officer (Principal Executive Officer)
Date: June 19, 2014	By:	/s/ William E. Scaff, Jr.
		William E. Scaff, Jr., Co-Chief Executive Officer (Principal Executive Officer)
Date: June 19, 2014	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Principal Financial and Accounting Officer

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Supplemental Schedule of Information to the Statements of Cash Flows (Tables)

12 Months Ended

Aug. 31, 2013

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

Schedule of Supplemental Information to the Statements of Cash Flows

	For the Years Ended August 31,
Supplemental cash flow information:	2013		2012		2011
Interest paid	$	995	$	74	$	788
Income taxes paid		-		-		-
Non-cash investing and financing activities:
Accrued well costs	$	25,491	$	5,733	$	4,967
Assets acquired in exchange for common stock		16,684		1,985		9,938
Assets acquired in exchange for note payable		-		-		5,200
Asset retirement costs and obligations		1,578		300		351
Conversion of promissory notes into common stock		-		-		15,908

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Nov. 01, 2012
Beginning asset retirement obligation	$ 1,027	$ 644	$ 1,026,796
Liabilities incurred	376	300
Liabilities assumed	240
Liabilities settled
Accretion expense	172	83
Revisions in previous estimates	962
Ending asset retirement obligation	$ 2,777	$ 1,027	$ 1,026,796
Minimum [Member]
Inflation rate	3.90%	3.90%
Estimated asset life	24 years	24 years
Credit adjusted risk free interest rate	8.00%	11.20%
Maximum [Member]
Inflation rate	4.00%	4.00%
Estimated asset life	40 years	27 years 7 months 6 days
Credit adjusted risk free interest rate	11.20%	11.70%

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Property and Equipment (Schedule of Costs Incurred) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Acquisition of property:
Unproved	$ 12,295	$ 9,145	$ 9,198
Proved	43,143	459	21,251
Exploration costs
Development costs	61,128	39,739	14,997
Asset retirement obligation	1,578	300	351
Total costs Incurred	$ 118,144	$ 49,643	$ 45,797

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Supplemental Schedule of Information to the Statements of Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Supplemental cash flow information:
Interest paid	$ 995	$ 74	$ 788
Income taxes paid
Non-cash investing and financing activities:
Accrued well costs	25,491	5,733	4,967
Assets acquired in exchange for common stock	16,684	1,985	9,938
Assets acquired in exchange for note payable			5,200
Asset retirement costs and obligations	1,578	300	351
Conversion of promissory notes into common stock			$ 15,908

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Revolving Credit Facility (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Feb. 28, 2013
Line of Credit Facility [Line Items]
Total borrowing capacity	$ 150,000
Current limited borrowing capacity on revolving credit facility	$ 38,000	$ 75,000
Credit facility, expiration date	Nov. 28, 2016
Minimum adjusted current ratio	1.0
Minimum EBITDAX times interest and fees	3.5
Maximum funded debt to EBITDAX	3.5
Maximum funded debt to total capitalization	0.5
Minimum hedge percentage of scheduled production for a rolling 24 months, as required by revolving credit facility covenants	45.00%
Maximum hedge percentage of scheduled production for a rolling 24 months, as required by revolving credit facility covenants	80.00%
Revolving credit facility, additional rate over LIBOR	2.50%
Minimum annual interest rate	3.20%
Period end prime rate	2.70%
Minimum [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, additional rate over Prime	0.00%
Revolving credit facility, additional rate over LIBOR	2.50%
Maximum [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, additional rate over Prime	1.00%
Revolving credit facility, additional rate over LIBOR	3.25%

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Organization and Summary of Significant Accounting Policies (Schedule of Potentially Dilutive Securities) (Details)	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Potentially dilutive securities	9,170,000	16,593,000	19,576,067
Stock options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Potentially dilutive securities	670,000	2,495,000	4,645,000
Warrants [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Potentially dilutive securities	8,500,000	14,098,000	14,931,067

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Fair Value Measurements (Tables)

12 Months Ended

Aug. 31, 2013

Fair Value Measurements [Abstract]

Schedule of Assets and Liabilities Measured on a Recurring Basis

	Fair Value Measurements at August 31, 2013
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	-	$	-	$	-
Commodity derivative liability	$	-	$	2,649	$	-	$	2,649
	Fair Value Measurements at August 31, 2012
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	-	$	-	$	-
Commodity derivative liability	$	-	$	-	$	-	$	-

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Unaudited Oil and Gas Reserves Information (Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves) (Details)	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Oil (Bbl) [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price per unit used to prepare reserve estimates, based upon average prices	86.40	86.68	84.90
Gas (Mcf) [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price per unit used to prepare reserve estimates, based upon average prices	4.40	3.76	5.07

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Commodity Derivative Instruments (Schedule of Fair Value of Derivatives) (Details) (Commodity Contract [Member], USD $) In Thousands, unless otherwise specified	Aug. 31, 2013	Aug. 31, 2012
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability	$ 2,315
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative liability	$ 334

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Unaudited Quarterly Financial Data (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Aug. 31, 2013		May 31, 2013		Feb. 28, 2013		Nov. 30, 2012		Aug. 31, 2012		May 31, 2012		Feb. 29, 2012		Nov. 30, 2011		Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Unaudited Quarterly Financial Data [Abstract]
Revenues	$ 14,674		$ 12,314		$ 10,921		$ 8,314		$ 6,750		$ 7,522		$ 6,219		$ 4,479
Expenses	8,022		7,449		6,439		4,768		3,336		3,676		3,344		2,860		26,678	13,215	7,182
Operating income	6,652		4,865		4,482		3,546		3,414		3,846		2,875		1,619		19,545	11,754	2,820
Other income	(3,406)		451		(146)		7		10		17		3		8		(3,094)	38	(14,420)
Income before income taxes	3,246		5,316		4,336		3,553		3,424		3,863		2,878		1,627		16,451	11,792	(11,600)
Deferred income tax provision (benefit)	(2,250)	[1]	(1,701)	[1]	(1,604)	[1]	(1,315)	[1]	(1,477)	[2],[3]	(1,432)	[2],[3]	3,241	[2],[3]		[2],[3]	(6,870)	332
Net income (loss)	996		3,615		2,732		2,238		1,947		2,431		6,119		1,627		9,581	12,124	(11,600)
Net income (loss) per common share:
Basic	$ 0.02	[4]	$ 0.07	[4]	$ 0.05	[4]	$ 0.04	[4]	$ 0.04	[4]	$ 0.05	[4]	$ 0.13	[4]	$ 0.05	[4]	$ 0.17	$ 0.26	$ (0.45)
Diluted	$ 0.01	[4]	$ 0.06	[4]	$ 0.05	[4]	$ 0.04	[4]	$ 0.04	[4]	$ 0.05	[4]	$ 0.12	[4]	$ 0.04	[4]	$ 0.16	$ 0.25	$ (0.45)
Weighted average shares outstanding:
Basic	66,283,325		55,238,098		54,900,326		51,661,704		51,409,340		51,292,810		47,445,178		36,098,212		57,089,362	46,587,558	26,009,283
Diluted	70,176,105		58,918,586		56,481,752		53,616,182		53,072,619		53,174,792		49,229,042		37,845,212		59,088,761	48,359,905	26,009,283
Valuation allowance													$ 4,900

[1] For the three months ended August 31, 2013, income taxes were provided at a higher than expected rate due to a downward adjustment in the deferred tax asset related to the expiration of underlying stock options.

[2] No income tax was recognized during the three months ended November 30, 2011 as the provision for tax at the effective rate was offset by a change in the valuation allowance.

[3] For the three months ended February 29, 2012, the entire valuation allowance of $4.9 million was released and a net deferred tax benefit of $3.2 million was recorded.

[4] The sum of net income per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

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Subsequent Events (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended		12 Months Ended			3 Months Ended	1 Months Ended
	Dec. 05, 2012 acre		Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011	Nov. 13, 2013 Subsequent Event [Member]	Aug. 27, 2013 Subsequent Event [Member] Agreement One [Member] acre	Aug. 27, 2013 Subsequent Event [Member] Agreement One [Member] Operated By Seller [Member]	Sep. 16, 2013 Subsequent Event [Member] Agreement Two [Member] acre	Sep. 16, 2013 Subsequent Event [Member] Agreement Two [Member] Operated By Seller [Member]
Subsequent Event [Line Items]
Number of wells						68	47	38		21
Mineral acres, gross	3,933						3,639
Mineral acres, net	3,196						1,006		800
Purchase price	$ 42,527						$ 17,500		$ 20,500
Cash	29,012						13,100		17,800
Issuance of shares	13,515	[1]					4,400		2,700
Shares issued, exercise of warrants			3,275			4,300,000
Proceeds from warrant exercises			$ 3,275	$ 3,000		$ 25,700

[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 5, 2012. (3,128,422 shares at $4.32 per share)

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Unaudited Oil and Gas Reserves Information (Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year) (Details)	12 Months Ended
	Aug. 31, 2013 bbl	Aug. 31, 2012 bbl	Aug. 31, 2011 bbl
Oil (Bbl) [Member]
Proved developed and undeveloped reserves:
Balance	5,085,811	2,069,705	676,685
Revisions of previous estimates	(194,236)	429,783	323,704
Purchase of reserves in place	1,000,664	33,328	967,302
Extensions, discoveries, and other additions	1,576,301	2,788,686	191,931
Sale of reserves in place
Production	(421,265)	(235,691)	(89,917)
Balance	7,047,275	5,085,811	2,069,705
Proved developed reserves:
Proved developed reserves	4,659,405	2,823,604	783,821
Proved undeveloped reserves:
Proved undeveloped reserves	2,387,870	2,262,207	1,285,884
Gas (Mcf) [Member]
Proved developed and undeveloped reserves:
Balance	33,445,974	14,261,158	4,481,051
Revisions of previous estimates	(2,923,919)	3,298,906	611,516
Purchase of reserves in place	7,360,752	706,842	8,466,714
Extensions, discoveries, and other additions	4,914,627	16,288,125	1,152,708
Sale of reserves in place
Production	(2,107,603)	(1,109,057)	(450,831)
Balance	40,689,831	33,445,974	14,261,158
Proved developed reserves:
Proved developed reserves	25,866,008	17,380,806	5,578,067
Proved undeveloped reserves:
Proved undeveloped reserves	14,823,823	16,065,168	8,683,091
Boe [Member]
Proved developed and undeveloped reserves:
Balance (Boe)	10,660,140	4,446,564	1,423,527
Revisions of previous estimates (Boe)	(681,556)	979,601	425,623
Purchase of reserves in place (Boe)	2,227,456	151,135	2,378,421
Extensions, discoveries, and other additions (Boe)	2,395,406	5,503,374	384,049
Sale of reserves in place
Sales of reserves in place (Boe)
Production (Boe)	(772,532)	(420,534)	(165,056)
Balance (Boe)	13,828,914	10,660,140	4,446,564
Proved developed reserves:
Proved developed reserves (Boe)	8,970,406	5,720,405	1,713,499
Proved undeveloped reserves:
Proved undeveloped reserves (Boe)	4,858,507	4,939,735	2,733,066

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Subsequent Events

12 Months Ended

Aug. 31, 2013

Subsequent Events [Abstract]

Subsequent Events

18.   Subsequent Events

Agreements to Acquire Oil and Gas Properties

Subsequent to August 31, 2013, the Company conducted due diligence activities for the purpose of acquiring oil and gas properties, including interests in 68 producing oil and gas wells, and various other assets.  All of the producing wells are located in the Wattenberg Field.

One agreement, signed on August 27, 2013, covers interests in 47 oil and gas wells, including 38 wells operated by the seller, plus leases covering approximately 3,639 gross (1,006 net) acres, and certain other assets.  The preliminary purchase price, subject to ordinary closing adjustments, is $17.5 million, consisting of cash consideration of $13.1 million, plus issuance of shares of the Company's restricted common stock with a value of $4.4 million.

The other agreement, signed on September 16, 2013, covers interests in 21 producing oil and gas wells operated by the seller, plus leases covering approximately 800 net acres.  The preliminary purchase price, subject to ordinary closing adjustments, is $20.5 million, consisting of cash consideration of $17.8 million plus issuance of shares of the Company's restricted common stock with a value of $2.7 million.

Both agreements are subject to satisfactory completion of due diligence activities and other conditions normal for a transaction of this nature.  Both closings are expected to occur during November.

Exercise of Series C Warrants

Subsequent to August 31, 2013, the Company issued approximately 4.3 million shares pursuant to the exercise of Series C warrants and received proceeds of approximately $25.7 million.

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Acquisition (Narrative) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended	12 Months Ended
	Dec. 05, 2012 acre	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Acquisition [Abstract]
Number of wells	36
Mineral acres, gross	3,933
Mineral acres, net	3,196
Shares issued for Orr Energy acquisition, shares	3,128,422	3,128,422
Shares issued for Orr Energy acquistion	$ 13,515	$ 13,518
Cash	29,012
Transaction costs	$ 109

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Organization and Summary of Significant Accounting Policies (Schedule of Capitalized Overhead) (Details) (USD $) In Thousands, unless otherwise specified	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Organization and Summary of Significant Accounting Policies [Abstract]
Capitalized overhead	$ 637	$ 345	$ 206

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Unaudited Oil and Gas Reserves Information (Narrative) (Details)		12 Months Ended
	Dec. 05, 2012	Aug. 31, 2013 Boe [Member] Boe	Aug. 31, 2012 Boe [Member] Boe	Aug. 31, 2011 Boe [Member] Boe	Aug. 31, 2012 Boe [Member] Upward Adjustments Attributable To Higher Prices [Member] Boe	Aug. 31, 2012 Boe [Member] Upward Adjustments Attributable To Reservoir Analysis And Well Performance [Member] Boe
Reserve Quantities [Line Items]
Purchase of reserves in place (Boe)		2,227,456	151,135	2,378,421
Number of wells	36			88
Revisions of previous estimates (Boe)		(681,556)	979,601	425,623	451,000	528,601
Extensions, discoveries, and other additions (Boe)		2,395,406	5,503,374	384,049

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Income Taxes (Tables)

12 Months Ended

Aug. 31, 2013

Income Taxes [Abstract]

Schedule of Components of Income Taxes

	As of August 31,
	2013		2012			2011
Current:
Federal	$	-	$	-		$	-
State		-		-			-
Total current income tax		-		-			-
Deferred:
Federal	$	6,367	$	4,219		$	4,266
State		503		360			354
Total deferred income tax		6,870		4,579			4,620
Valuation allowance		-		(4,911	)		(4,620	)
Income tax provision (benefit)	$	6,870	$	(332	)	$	-

Schedule of Reconciliation of Income Taxes

	As of August 31,
	2013			2012			2011
Federal income tax at statutory rate	$	5,594		$	4,009		$	3,944
State income taxes, net of federal tax		503			360			354
Statutory depletion		(929	)		-			-
Stock based compensation		1,911			-			-
Other		(209	)		210			322
Change in valuation allowance		-			(4,911	)		(4,620	)
Income tax provision (benefit)	$	6,870		$	(332	)	$	-
Effective rate expressed as a percentage		42	%		3	%		0	%

Schedule of Deferred Tax Assets and Liabilities

	As of August 31,
	2013		2012
Deferred tax assets:
Net operating loss carry-forward	$	11,485	$	12,643
Stock-based compensation		515		4,070
Statutory depletion		929		-
Unrealized loss on commodity derivative		982		-
Other		3		3
Gross deferred tax assets	$	13,914	$	16,716
Deferred tax liabilities:
Basis of oil and gas properties		20,452		16,384
Gross deferred tax liabilities		20,452		16,384
Deferred tax liability (asset), net	$	6,538	$	(332	)

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Acquisition (Schedule of Pro Forma Results) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012
Acquisition [Abstract]
Oil and Gas Revenues	$ 47,760	$ 32,188
Net income	$ 10,118	$ 14,870
Earnings per common share
Basic	$ 0.17	$ 0.30
Diluted	$ 0.17	$ 0.29

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Income Taxes (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Operating Loss Carryforwards [Line Items]
Net operating loss	$ 41,300
Net operating loss carryforwards	31,000
Compensation expense	10,300
Change in valuation allowance		$ (4,911)	$ (4,620)
Minimum [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, expiration date	Dec. 31, 2031
Maximum [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, expiration date	Dec. 31, 2033

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Shareholders' Equity (Common Stock Transactions) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended	12 Months Ended
	Dec. 05, 2012	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011	Aug. 31, 2010
Shareholders' Equity [Abstract]
Preferred stock, shares authorized		10,000,000	10,000,000	10,000,000
Preferred stock, par value per share		$ 0.01	$ 0.01	$ 0.01
Preferred stock, shares issued		0	0	0
Preferred stock, shares outstanding		0	0	0
Common stock, shares authorized		100,000,000	100,000,000	100,000,000
Common stock, par value per share		$ 0.001	$ 0.001	$ 0.001
Common stock, shares issued		70,587,723	51,409,340	36,098,212
Common stock, shares outstanding		70,587,723	51,409,340	36,098,212	13,510,981
Sale of common stock
Number of shares acquired		13,225,000	14,363,363	9,000,000
Offering price per common share		$ 6.25	$ 2.75	$ 2.00
Net proceeds		$ 78,243	$ 37,422	$ 16,691
Common stock issued for acquisition of mineral interests
Number of common shares issued for mineral property leases		687,122	669,765	1,864,838
Number of common shares issued for Orr Energy acquisition	3,128,422	3,128,422
Total common shares issued		3,815,544	669,765	1,864,838
Average price per common share		$ 4.37	$ 3.12	$ 3.04
Aggregate value of shares issues		$ 16,684	$ 2,090	$ 5,670

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Property and Equipment (Schedule of Capitalized Costs) (Details) (USD $) In Thousands, unless otherwise specified	Aug. 31, 2013	Aug. 31, 2012
Unevaluated costs, not subject to amortization:
Unevaluated oil and gas properties	$ 64,715	$ 32,484
Evaluated costs:
Producing and non-producing	155,755	69,667
Total capitalized costs	220,470	102,151
Less, accumulated depletion	(22,776)	(9,731)
Oil and gas properties, net	197,694	92,420
Other property and equipment:
Other property and equipment, gross	544	436
Less, accumulated depreciation	(273)	(154)
Other property and equipment, net	271	282
Property and equipment, net	197,965	92,702
Vehicles [Member]
Other property and equipment:
Other property and equipment, gross		163,904
Leasehold Improvements [Member]
Other property and equipment:
Other property and equipment, gross		71,651
Office Equipment [Member]
Other property and equipment:
Other property and equipment, gross		156,893
Land [Member]
Other property and equipment:
Other property and equipment, gross		43,750
Lease acquisition and other costs [Member]
Unevaluated costs, not subject to amortization:
Unevaluated oil and gas properties	38,826	27,070
Wells in progress [Member]
Unevaluated costs, not subject to amortization:
Unevaluated oil and gas properties	$ 25,889	$ 5,414

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Property and Equipment

12 Months Ended

Aug. 31, 2013

Property and Equipment [Abstract]

Property and Equipment

2.   Property and Equipment

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

	As of August 31,
	2013			2012
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	38,826		$	27,070
Wells in progress		25,889			5,414
Subtotal, unevaluated costs		64,715			32,484
Evaluated costs:
Producing and non-producing		155,755			69,667
Total capitalized costs		220,470			102,151
Less, accumulated depletion		(22,776	)		(9,731	)
Oil and gas properties, net		197,694			92,420
Other property and equipment		544			436
Less, accumulated depreciation		(273	)		(154	)
Other property and equipment, net		271			282
Total property and equipment, net	$	197,965		$	92,702

Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value.  The reviews as of each of the fiscal year ends presented, 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 each of the fiscal year ends presented, similarly revealed no impairment of oil and gas assets.

Costs Incurred:  Costs incurred in oil and gas property acquisition, exploration and development activities for the fiscal years presented were (in thousands):

	For the Years Ended August 31,
	2013		2012		2011
Acquisition of property:
Unproved	$	12,295	$	9,145	$	9,198
Proved		43,143		459		21,251
Exploration costs		-		-		-
Development costs		61,128		39,739		14,997
Asset retirement obligation		1,578		300		351
Total costs incurred	$	118,144	$	49,643	$	45,797

Capitalized Costs Excluded from Amortization:  The following table summarizes costs related to unevaluated properties that have been excluded from amounts subject to depletion, depreciation, and amortization at August 31, 2013 (in thousands).  There were no individually significant properties or significant development projects included in the Company's unevaluated property balance.  The Company regularly evaluates these costs to determine whether impairment has occurred.  The majority of these costs are expected to be evaluated and included in the amortization base within three years.

	Period Incurred								Total as of
									August 31,
	2013		2012		2011		Prior		2013
Unproved leasehold acquisition costs	$	11,757	$	9,636	$	16,585	$	848	$	38,826
Unevaluated development costs		25,889		-		-		-	$	25,889
Total unevaluted costs	$	37,646	$	9,636	$	16,585	$	848	$	64,715

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Shareholders' Equity (Common Stock Warrants) (Details) (USD $)	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011	Aug. 31, 2010	Aug. 31, 2009 Series A [Member]	Aug. 31, 2009 Series B [Member]	Aug. 31, 2013 Series C [Member]	Aug. 31, 2010 Series C [Member]	Aug. 31, 2013 Series D [Member]	Aug. 31, 2012 Series D [Member]	Aug. 31, 2011 Series D [Member]	Aug. 31, 2010 Series D [Member]	Aug. 31, 2009 Sales Agent Warrants [Member]	Aug. 31, 2013 Investor Relation Warrants [Member]	Aug. 31, 2012 Investor Relation Warrants [Member]
Class of Warrant or Right [Line Items]
Exercise Price					6,000	10,000	6,000	6,000	1.60			1,600	1,800	2,690	2,690
Number of Shares	8,666,802						8,500,000		141,802					25,000
Remaining Contractual Life (in years)							1 year 3 months 18 days		1 year 3 months 18 days					2 years 3 months 18 days
Exercise Price times number of shares	$ 51,294,133,000						$ 51,000,000,000	$ 50,000,000	$ 226,883,000					$ 67,250,000
Outstanding	15,031,067	14,931,067	15,286,466
Granted		100,000												50,000
Exercised	1,216,265		355,399				500,000		627,799		355,399			25,000
Forfeited/Expired	5,148,000													50,000
Outstanding	8,666,802	15,031,067	14,931,067	15,286,466
Weighted average exercise price, outstanding	$ 6.02	$ 6.02	$ 5.92
Weighted average exercise price, granted		$ 2.69
Weighted average exercise price, exercised	$ 3.44	$ 0.00	$ 1.60
Weighted average exercise price, forfeited/expired	$ 6.74
Weighted average exercise price, outstanding	$ 5.92	$ 6.02	$ 6.02	$ 5.92
Number of warrants issued					4,098,000	1,000,000		9,000,000				1,125,000	31,733		100,000
Number of shares of common stock per warrant					1	1		1				1	2		1
Face value of debt instrument				100,000,000				100,000,000
Amount of note converted			$ 15,908,000
Conversion of notes payable, shares			9,942,500
Shares issued in payment of accrued interest			36,876
Debt conversion, price per share			$ 1.60
Interest rate	8.00%			8.00%
Number of units sold				180

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Organization and Summary of Significant Accounting Policies (Schedule of Derivative Conversion Liability) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Organization and Summary of Significant Accounting Policies [Abstract]
Non-cash expense recognized related to the change in the fair value of derivative conversion liabilities			$ 10,229
Derivative conversion liabilities recognized in additional paid-in-capital			$ 19,554

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Acquisition (Tables)

12 Months Ended

Aug. 31, 2013

Acquisition [Abstract]

Schedule of Fair Value of Acquisition

Purchase Price	December 5, 2012
Consideration Given
Cash	$	29,012
Synergy Resources Corp. Common Stock *		13,515
Total consideration given	$	42,527
Allocation of Purchase Price
Proved oil and gas properties	$	43,143
Unproved oil and gas properties		466
Total fair value of oil and gas properties acquired		43,609
Working capital	$	(842	)
Asset retirement obligation		(240	)
Fair value of net assets acquired	$	42,527
Working capital acquired was estimated as follows:
Accounts receivable		521
Accrued liabilities and expenses		(1,363	)
Total working capital	$	(842	)

*   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 5, 2012. (3,128,422 shares at $4.32 per share)

Schedule of Pro Forma Results

	For the years ended August 31,
	(Unaudited)
	2013		2012
Oil and Gas Revenues	$	47,760	$	32,188
Net income	$	10,118	$	14,870
Earnings per common share
Basic	$	0.17	$	0.30
Diluted	$	0.17	$	0.29

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Property and Equipment (Tables)

12 Months Ended

Aug. 31, 2013

Property and Equipment [Abstract]

Schedule of Capitalized Costs

	As of August 31,
	2013			2012
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	38,826		$	27,070
Wells in progress		25,889			5,414
Subtotal, unevaluated costs		64,715			32,484
Evaluated costs:
Producing and non-producing		155,755			69,667
Total capitalized costs		220,470			102,151
Less, accumulated depletion		(22,776	)		(9,731	)
Oil and gas properties, net		197,694			92,420
Other property and equipment		544			436
Less, accumulated depreciation		(273	)		(154	)
Other property and equipment, net		271			282
Total property and equipment, net	$	197,965		$	92,702

Schedule of Costs Incurred

	For the Years Ended August 31,
	2013		2012		2011
Acquisition of property:
Unproved	$	12,295	$	9,145	$	9,198
Proved		43,143		459		21,251
Exploration costs		-		-		-
Development costs		61,128		39,739		14,997
Asset retirement obligation		1,578		300		351
Total costs incurred	$	118,144	$	49,643	$	45,797

Schedule of Capitalized Costs Excluded from Amortization

	Period Incurred								Total as of
									August 31,
	2013		2012		2011		Prior		2013
Unproved leasehold acquisition costs	$	11,757	$	9,636	$	16,585	$	848	$	38,826
Unevaluated development costs		25,889		-		-		-	$	25,889
Total unevaluted costs	$	37,646	$	9,636	$	16,585	$	848	$	64,715

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Commodity Derivative Instruments (Schedule of Commodity Derivative Contracts) (Details)	12 Months Ended
	Aug. 31, 2013 bbl
Swap [Member] | 2013 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	32,014
Strike/Swap Price ($/Bbl)	95.13
Swap [Member] | 2014 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	23,840
Strike/Swap Price ($/Bbl)	92.35
Contract One [Member] | Collar [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	3,014
Term, minimum	Sep. 01, 2013
Term, maximum	Dec. 31, 2013
Contract One [Member] | Collar [Member] | Minimum [Member]
Derivatives, Fair Value [Line Items]
Strike/Swap Price ($/Bbl)	87.00
Contract One [Member] | Collar [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Strike/Swap Price ($/Bbl)	102.50
Contract One [Member] | Swap [Member] | 2013 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	3,014
Strike/Swap Price ($/Bbl)	91.70
Term, minimum	Sep. 01, 2013
Term, maximum	Dec. 31, 2013
Contract One [Member] | Swap [Member] | 2014 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	1,840
Strike/Swap Price ($/Bbl)	90.80
Term, minimum	Jan. 01, 2014
Term, maximum	Dec. 31, 2014
Contract Two [Member] | Collar [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	1,840
Term, minimum	Jan. 01, 2014
Term, maximum	Dec. 31, 2014
Contract Two [Member] | Collar [Member] | Minimum [Member]
Derivatives, Fair Value [Line Items]
Strike/Swap Price ($/Bbl)	85.00
Contract Two [Member] | Collar [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Strike/Swap Price ($/Bbl)	98.50
Contract Two [Member] | Swap [Member] | 2013 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	6,000
Strike/Swap Price ($/Bbl)	96.35
Term, minimum	Sep. 01, 2013	[1]
Term, maximum	Dec. 31, 2013	[1]
Contract Two [Member] | Swap [Member] | 2014 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	2,000
Strike/Swap Price ($/Bbl)	90.11
Term, minimum	Jan. 01, 2014
Term, maximum	Dec. 31, 2014
Contract Three [Member] | Collar [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	7,000
Term, minimum	Jan. 01, 2015
Term, maximum	Jun. 30, 2015
Contract Three [Member] | Collar [Member] | Minimum [Member]
Derivatives, Fair Value [Line Items]
Strike/Swap Price ($/Bbl)	80.00
Contract Three [Member] | Collar [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Strike/Swap Price ($/Bbl)	92.50
Contract Three [Member] | Swap [Member] | 2013 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	8,000
Strike/Swap Price ($/Bbl)	94.45
Term, minimum	Sep. 01, 2013
Term, maximum	Dec. 31, 2013
Contract Three [Member] | Swap [Member] | 2014 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	5,000
Strike/Swap Price ($/Bbl)	90.50
Term, minimum	Jan. 01, 2014
Term, maximum	Dec. 31, 2014
Contract Four [Member] | Swap [Member] | 2013 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	15,000
Strike/Swap Price ($/Bbl)	98.00
Term, minimum	Sep. 01, 2013
Term, maximum	Dec. 31, 2013
Contract Four [Member] | Swap [Member] | 2014 [Member]
Derivatives, Fair Value [Line Items]
Quantity (Bbl/month)	15,000
Strike/Swap Price ($/Bbl)	98.00
Term, minimum	Jan. 01, 2014
Term, maximum	Feb. 28, 2014

[1] In connection with entering into these swaps with premium hedged prices, the counterparty has the right, but not the obligation to extend the swap to January 1, 2014 through December 31, 2014 at the current strike price and quantity. This option expires on December 31, 2013.

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Organization and Summary of Significant Accounting Policies (Schedule of Major Customers) (Details)	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012		Aug. 31, 2011
Company A [Member] | Oil and Gas Revenues [Member]
Concentration Risk [Line Items]
Risk percentage	50.00%	68.00%		75.00%
Company A [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Risk percentage	24.00%	35.00%		31.00%
Company B [Member] | Oil and Gas Revenues [Member]
Concentration Risk [Line Items]
Risk percentage	15.00%	11.00%		21.00%
Company B [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Risk percentage	23.00%	30.00%		31.00%
Company C [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Risk percentage	12.00%	0.00%	[1]	13.00%

[1] less than 10%

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

12 Months Ended

Aug. 31, 2013

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

Schedule of Depreciation, Depletion and Amortization Expense

	For the Years Ended August 31,
	2013		2012		2011
Depletion	$	13,046	$	5,838	$	2,743
Depreciation and amortization		290		172		95
Total DDA Expense	$	13,336	$	6,010	$	2,838

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Asset Retirement Obligations (Tables)

12 Months Ended

Aug. 31, 2013

Asset Retirement Obligations [Abstract]

Schedule of Assumptions Used To Determine the Fair Value of Asset Removal Obligations

	For the Years Ended August 31,
	2013	2012
Inflation rate	3.9 - 4.0%	3.9 - 4.0%
Estimated asset life	24.0 - 40.0 years	24.0 - 27.6 years
Credit adjusted risk free interest rate	8.0 - 11.2%	11.2 - 11.7%

Schedule of Changes in Asset Retirement Obligations

	As of August 31,
	2013		2012
Beginning asset retirement obligation	$	1,027	$	644
Liabilities incurred		376		300
Liabilities assumed		240		-
Liabilities settled		-		-
Accretion expense		172		83
Revisions in previous estimates		962		-
	$	2,777	$	1,027

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Organization and Summary of Significant Accounting Policies

12 Months Ended

Aug. 31, 2013

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.

Basis of Presentation:  The Company has adopted August 31st as the end of its fiscal year.  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").

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 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.

Short-Term Investments:  As part of its cash management strategies, the Company invests in short-term interest bearing deposits such as certificates of deposits with maturities of less than one year.

Inventory:     Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market

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.

Wells in progress represent the costs associated with the drilling of oil and gas wells that have yet to be completed as of August 31, 2013.  Since the wells had not been completed as of August 31, 2013, they were classified within unevaluated oil and gas properties and were withheld from the depletion calculation and the ceiling test. The costs for these wells will be transferred into proved property when the wells commence production 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 depreciation, depletion, 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 and reflected as additional accumulated depreciation, depletion and amortization.  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.  No provision for impairment was required for the twelve months ended August 31, 2013 or 2012.

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).

	For the Years Ended August 31,
	2013		2012		2011
Capitalized overhead	$	637	$	345	$	206

Well Costs Payable:  The cost 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 ("AFE").

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.

Derivative Conversion Liability:  The Company accounted for the embedded conversion features in its convertible promissory notes, issued during fiscal year 2010, in accordance with the guidance for derivative instruments, which requires a periodic valuation of their fair value and a corresponding recognition of liabilities associated with such derivatives.  The recognition of derivative conversion liabilities related to the issuance of convertible debt was applied first to the proceeds of such issuance as a debt discount at the date of the issuance.  All subsequent increases or decreases in the fair value of derivative conversion liabilities were recognized as a charge or credit to other income (expense) in results of operations.  In connection with the conversion of convertible promissory notes into shares of the Company's common stock, derivative conversion liabilities were reclassified to additional paid-in-capital.  The amounts recognized in the financial statements follow.

	For the Years Ended August 31,
	(in thousands)
	2013		2012		2011
Non-cash expense recognized related to the change in
the fair value of derivative conversion liabilities	$	-	$	-	$	10,229
Derivative conversion liabilities recognized in additional
paid-in-capital	$	-	$	-	$	19,554

Debt Issuance Costs:  Debt issuance costs incurred in connection with executing convertible promissory notes between December 29, 2009, and March 12, 2011 were classified as a long-term asset.  However, as a result of the conversion of all outstanding convertible promissory notes into shares of the Company's common stock, all debt issuance costs were recognized as a component of interest expense through August 31, 2011.

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 using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between 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 and Operating Region:     The Company operates exclusively within the United States of America.  Except for cash and short-term investments, all of the Company's assets are employed in and all of its revenues are derived from the oil and gas industry.   The table below presents the percentages of oil and gas revenue resulting from purchases by major customers.

	For the Years Ended August 31,
	2013	2012	2011
Company A	50%	68%	75%
Company B	15%	11%	21%

The Company sells production to a small number of customers, as is customary in the industry.  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 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 total receivable balances as of each of the fiscal year ends presented are shown in the following table:

	As of August 31,
	2013	2012	2011
Company A	24%	35%	31%
Company B	23%	30%	31%
Company C	12%	*	13%
* less than 10%

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 below 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 August 31, 2013.  The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of August 31, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.  For further information, see Note 12 below.

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 or "no premium" collars to reduce the effect of price changes on a portion of our future oil 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. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. We value our 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.  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. For additional discussion, please refer to Note 7-Commodity Derivative Instruments.

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.

	For the Years Ended August 31,
	2013		2012		2011
Weighted-average shares outstanding - basic		57,089,362		46,587,558		26,009,283
Potentially dilutive common shares from:
Stock options		1,881,682		1,380,861		-
Warrants		117,717		391,486		-
Weighted-average shares outstanding - diluted		59,088,761		48,359,905		26,009,283

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

	For the Years Ended August 31,
	2013		2012		2011
Potentially dilutive common shares from:
Stock options		670,000		2,495,000		4,645,000
Warrants		8,500,000		14,098,000		14,931,067
Total		9,170,000		16,593,000		19,576,067

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.  There were various updates recently issued by the Financial Accounting Standards Board, 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 consolidated financial position, results of operations or cash flows. 

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Commodity Derivative Instruments (Tables)

12 Months Ended

Aug. 31, 2013

Commodity Derivative Instruments [Abstract]

Schedule of Commodity Derivative Contracts

Contract Type	Basis (1)	Quantity (Bbl/month)	Strike Price ($/Bbl)	Term
Collar	NYMEX	3,014	$87.00 - $102.50	Sept 1, 2013 - Dec 31, 2013
Collar	NYMEX	1,840	$85.00 - $98.50	Jan 1, 2014 - Dec 31, 2014
Collar	NYMEX	7,000	$80.00 - $92.50	Jan 1, 2015 - Jun 30, 2015
Contract Type	Basis (1)	Quantity (Bbl/month)	Swap Price ($/Bbl)	Term
Swap	NYMEX	3,014	$91.70	Sept 1, 2013 - Dec 31, 2013
Swap	NYMEX	6,000	$96.35	Sept 1, 2013 - Dec 31, 2013  (2)
Swap	NYMEX	8,000	$94.45	Sept 1, 2013 - Dec 31, 2013
Swap	NYMEX	15,000	$98.00	Sept 1, 2013 - Dec 31, 2013
2013 Total/Average		32,014	$95.13
Swap	NYMEX	1,840	$90.80	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	2,000	$90.11	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	5,000	$90.50	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	15,000	$98.00	Jan 1, 2014 - Feb 28, 2014
2014 Total/Average		23,840	$92.35
(1) NYMEX refers to WTI quoted prices on the New York Mercantile Exchange
(2) In connection with entering into these swaps with premium hedged prices, the counterparty has the right, but not the obligation to extend the swap to January 1, 2014 through December 31, 2014 at the current strike price and quantity.  This option expires on December 31, 2013.

Schedule of Fair Value of Derivatives

		As of August 31,
Underlying Commodity	Balance Sheet Location	2013		2012
Crude Oil derivative contract	Current liabilities	$	2,315	$	-
Crude Oil derivative contract	Noncurrent liabilities	$	334	$	-

Schedule of Gain (Loss) Recognized in Statements of Operations

	For the Years Ended August 31,
	2013		2012		2011
Unrealized loss on commodity derivatives	$	2,649	$	-	$	-
Realized loss on commodity derivatives		395		-		-
Total loss	$	3,044	$	-	$	-

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Unaudited Oil and Gas Reserves Information (Tables)

12 Months Ended

Aug. 31, 2013

Unaudited Oil and Gas Reserves Information [Abstract]

Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year

	Oil (Bbl)			Gas (McF)			Boe
Balance, August 31, 2010		676,685			4,481,051			1,423,527
Revision of previous estimates		323,704			611,516			425,623
Purchase of reserves in place		967,302			8,466,714			2,378,421
Extensions, discoveries, and other additions		191,931			1,152,708			384,049
Sale of reserves in place		-			-			-
Production		(89,917	)		(450,831	)		(165,056	)
Balance, August 31, 2011		2,069,705			14,261,158			4,446,564
Revision of previous estimates		429,783			3,298,906			979,601
Purchase of reserves in place		33,328			706,842			151,135
Extensions, discoveries, and other additions		2,788,686			16,288,125			5,503,374
Sale of reserves in place		-			-			-
Production		(235,691	)		(1,109,057	)		(420,534	)
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140
Revision of previous estimates		(194,236	)		(2,923,919	)		(681,556	)
Purchase of reserves in place		1,000,664			7,360,752			2,227,456
Extensions, discoveries, and other additions		1,576,301			4,914,627			2,395,406
Sale of reserves in place		-			-			-
Production		(421,265	)		(2,107,603	)		(772,532	)
Balance, August 31, 2013		7,047,275			40,689,831			13,828,914
Proved developed and undeveloped reserves:
Developed at August 31, 2011		783,821			5,578,067			1,713,499
Undeveloped at August 31, 2011		1,285,884			8,683,091			2,733,066
Balance, August 31, 2011		2,069,705			14,261,158			4,446,565
Developed at August 31, 2012		2,823,604			17,380,806			5,720,405
Undeveloped at August 31, 2012		2,262,207			16,065,168			4,939,735
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140
Developed at August 31, 2013		4,659,405			25,866,008			8,970,406
Undeveloped at August 31, 2013		2,387,870			14,823,823			4,858,507
Balance, August 31, 2013		7,047,275			40,689,831			13,828,913

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	For the Years Ended August 31,
	2013			2012			2011
Future cash inflow	$	749,030		$	537,462		$	235,239
Future production costs		(146,352	)		(85,612	)		(41,278	)
Future development costs		(108,290	)		(100,821	)		(40,404	)
Future income tax expense		(113,545	)		(109,349	)		(30,738	)
Future net cash flows		380,843			241,680			122,819
10% annual discount for estimated timing of cash flows		(199,111	)		(139,175	)		(65,269	)
Standardized measure of discounted future net cash flows	$	181,732		$	102,505		$	57,550

Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves

	Oil (Bbl)		Gas (Mcf)
August 31, 2011 (Average)	$	84.90	$	5.07
August 31, 2012 (Average)	$	86.68	$	3.76
August 31, 2013 (Average)	$	86.40	$	4.40

Schedule of Changes in the Standardized Measure for Discounted Cash Flows

	For the Years Ended August 31,
	2013			2012			2011
Standardized measure, beginning of year	$	102,505		$	57,550		$	13,022
Sale and transfers, net of production costs		(38,569	)		(21,321	)		(8,337	)
Net changes in prices and production costs		(4,550	)		(6,023	)		15,484
Extensions, discoveries, and improved recovery		70,191			69,073			13,693
Changes in estimated future development costs		(6,006	)		(42,578	)		(20,471	)
Development costs incurred during the period		5,106			39,739			16,252
Revision of quantity estimates		(14,214	)		21,058			15,424
Accretion of discount		35,103			15,379			3,245
Net change in income taxes		(7,850	)		(30,832	)		(12,012	)
Purchase of reserves in place		40,016			460			21,250
Standardized measure, end of year	$	181,732		$	102,505		$	57,550

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Depletion, depreciation and amortization ("DDA") (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Depletion, depreciation and amortization ("DDA") [Abstract]
Depletion	$ 13,046	$ 5,838	$ 2,743
Depreciation and amortization	290	172	95
Total DDA expense	$ 13,336	$ 6,010	$ 2,838

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Unaudited Oil and Gas Reserves Information (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Unaudited Oil and Gas Reserves Information [Abstract]
Future cash inflows	$ 749,030	$ 537,462	$ 235,239
Future production costs	(146,352)	(85,612)	(41,278)
Future development costs	(108,290)	(100,821)	(40,404)
Future income tax expense	(113,545)	(109,349)	(30,738)
Future net cash flows	380,843	241,680	122,819
10% annual discount for estimated timing of cash flows	(199,111)	(139,175)	(65,269)
Standardized measure of discounted future net cash flows	$ 181,732	$ 102,505	$ 57,550

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BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Aug. 31, 2013	Aug. 31, 2012
Current assets:
Cash and cash equivalents	$ 19,463	$ 19,284
Short term investments	60,018
Accounts receivable:
Oil and gas sales	7,361	3,606
Joint interest billing	4,700	3,268
Inventory	194	178
Other current assets	239	132
Total current assets	91,975	26,468
Property and equipment:
Evaluated oil and gas properties, net	132,979	59,936
Unevaluated oil and gas properties	64,715	32,484
Other property and equipment, net	271	282
Property and equipment, net	197,965	92,702
Deferred tax asset, net		332
Other assets	1,296	1,230
Total assets	291,236	120,732
Current liabilities:
Trade accounts payable	949	1,499
Well costs payable	25,491	5,733
Revenue payable	6,081	4,160
Production taxes payable	6,277	3,805
Other accrued expenses	254	395
Commodity derivative	2,315
Total current liabilities	41,367	15,592
Revolving credit facility	37,000	3,000
Commodity derivative	334
Deferred tax liability, net	6,538
Asset retirement obligations	2,777	1,027
Total liabilities	88,016	19,619
Commitments and contingencies (See Note 14)
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: 70,587,723 and 51,409,340 shares issued and outstanding, respectively	71	52
Additional paid-in capital	216,383	123,876
Accumulated deficit	(13,234)	(22,815)
Total shareholders' equity	203,220	101,113
Total liabilities and shareholders' equity	$ 291,236	$ 120,732

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Organization and Summary of Significant Accounting Policies (Schedule of Earnings Per Share) (Details)	3 Months Ended								12 Months Ended
	Aug. 31, 2013	May 31, 2013	Feb. 28, 2013	Nov. 30, 2012	Aug. 31, 2012	May 31, 2012	Feb. 29, 2012	Nov. 30, 2011	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Weighted average shares outstanding:
Weighted-average shares outstanding - basic	66,283,325	55,238,098	54,900,326	51,661,704	51,409,340	51,292,810	47,445,178	36,098,212	57,089,362	46,587,558	26,009,283
Potentially dilutive common shares from:
Stock options									1,881,682	1,380,861
Warrants									117,717	391,486
Weighted-average shares outstanding - diluted	70,176,105	58,918,586	56,481,752	53,616,182	53,072,619	53,174,792	49,229,042	37,845,212	59,088,761	48,359,905	26,009,283

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STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (Parenthetical) (USD $)	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY [Abstract]
Unamortized discount on shares issued pursuant to conversion of debt and accrued interest			$ 1,052,917
Price per share for shares issued for cash	$ 6.25	$ 2.75	$ 2.00
Offering costs	$ 4,400,000	$ 2,028,215	$ 1,309,279

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Fair Value Measurements (Details) (Recurring [Member], USD $) In Thousands, unless otherwise specified	Aug. 31, 2013	Aug. 31, 2012
Financial Assets:
Commodity derivative asset
Financial Liabilities:
Commodity derivative liability	2,649
Level 1 [Member]
Financial Assets:
Commodity derivative asset
Financial Liabilities:
Commodity derivative liability
Level 2 [Member]
Financial Assets:
Commodity derivative asset
Financial Liabilities:
Commodity derivative liability	2,649
Level 3 [Member]
Financial Assets:
Commodity derivative asset
Financial Liabilities:
Commodity derivative liability

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Shareholders' Equity (Tables)

12 Months Ended

Aug. 31, 2013

Shareholders' Equity [Abstract]

Schedule of Classes of Stock

	For the Years Ended August 31,
	2013		2012		2011
Preferred stock, shares authorized		10,000,000		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil		nil
Common stock, shares authorized		100,000,000		100,000,000		100,000,000
Common stock, par value	$	0.001	$	0.001	$	0.001
Common stock, shares issued and outstanding		70,587,723		51,409,340		36,098,212

Schedule of Common Stock Sold in Public Offering

	For the Years Ended August 31,
	2013		2012		2011
Number of common shares sold		13,225,000		14,363,363		9,000,000
Offering price per common share	$	6.25	$	2.75	$	2.00
Net proceeds (in thousands)	$	78,243	$	37,422	$	16,691

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

	For the Years Ended August 31,
	2013		2012		2011
Number of common shares issued for mineral property leases		687,122		669,765		1,864,838
Number of common shares issued for Orr Energy acquisition		3,128,422		-		-
Total common shares issued		3,815,544		669,765		1,864,838
Average price per common share	$	4.37	$	3.12	$	3.04
Aggregate value of shares issues (in thousands)		16,684	$	2,090	$	5,670

Schedule of Outstanding Common Stock Warrant Activity

	Number of Shares Issuable Upon Warrant Exercise		Weighted Average Exercise Price Per Share
Outstanding, August 31, 2010		15,286,466	$	5.92
Exercised		355,399	$	1.60
Outstanding, August 31, 2011		14,931,067	$	6.02
Granted		100,000	$	2.69
Exercised		-	$	-
Outstanding, August 31, 2012		15,031,067	$	6.02
Exercised		1,216,265	$	3.44
Forfeited / Expired		5,148,000	$	6.74
Outstanding, August 31, 2013		8,666,802	$	5.92

Schedule of Issued and Outstanding Common Stock Warrants

Description	Number of Shares		Exercise Price		Remaining Contractual Life (in years)		Exercise Price times number of shares
Series C		8,500,000	$	6.00		1.30	$	51,000,000
Series D		141,802	$	1.60		1.30	$	226,883
Investor Relations		25,000	$	2.69		2.30	$	67,250
Total		8,666,802					$	51,294,133

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Income Taxes (Schedule of Reconciliation of Income Taxes) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended																12 Months Ended
	Aug. 31, 2013		May 31, 2013		Feb. 28, 2013		Nov. 30, 2012		Aug. 31, 2012		May 31, 2012		Feb. 29, 2012		Nov. 30, 2011		Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Income Taxes [Abstract]
Federal income tax at statutory rate																	$ 5,594	$ 4,009	$ 3,944
State income taxes, net of federal benefit																	503	360	354
Statutory depletion																	(929)
Stock based compensation																	1,911
Other																	(209)	210	322
Change in valuation allowance																		(4,911)	(4,620)
Income tax provision (benefit)	$ 2,250	[1]	$ 1,701	[1]	$ 1,604	[1]	$ 1,315	[1]	$ 1,477	[2],[3]	$ 1,432	[2],[3]	$ (3,241)	[2],[3]		[2],[3]	$ 6,870	$ (332)
Effective rate expressed as a percentage																	42.00%	3.00%	0.00%

[1] For the three months ended August 31, 2013, income taxes were provided at a higher than expected rate due to a downward adjustment in the deferred tax asset related to the expiration of underlying stock options.

[2] No income tax was recognized during the three months ended November 30, 2011 as the provision for tax at the effective rate was offset by a change in the valuation allowance.

[3] For the three months ended February 29, 2012, the entire valuation allowance of $4.9 million was released and a net deferred tax benefit of $3.2 million was recorded.

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Supplemental Schedule of Information to the Statements of Cash Flows

12 Months Ended

Aug. 31, 2013

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

Supplemental Schedule of Information to the Statements of Cash Flows

15.   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 fiscal years presented (in thousands):

	For the Years Ended August 31,
Supplemental cash flow information:	2013		2012		2011
Interest paid	$	995	$	74	$	788
Income taxes paid		-		-		-
Non-cash investing and financing activities:
Accrued well costs	$	25,491	$	5,733	$	4,967
Assets acquired in exchange for common stock		16,684		1,985		9,938
Assets acquired in exchange for note payable		-		-		5,200
Asset retirement costs and obligations		1,578		300		351
Conversion of promissory notes into common stock		-		-		15,908

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Stock-Based Compensation (Tables)

12 Months Ended

Aug. 31, 2013

Stock-Based Compensation [Abstract]

Schedule of Stock-based Compensation Expenses Recognized

	For the Years Ended August 31,
	2013		2012		2011
Stock options	$	1,039	$	443	$	197
Restricted stock grants		277		17		430
Investor relations warrants		46		13		-
	$	1,362	$	473	$	627

Schedule of Employee Stock Options Granted During the Period

	For the Years Ended August 31,
	2013		2012		2011
Number of options to purchase common shares		1,025,000		275,000		425,000
Weighted average exercise price	$	6.05	$	2.96	$	3.79
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	3-5 years		4-5 years		4-5 years
Fair Value (in thousands)	$	4,179	$	519	$	990

Schedule of Assumptions Used In Valuing Stock Options

	For the Years Ended August 31,
	2013			2012			2011
Expected term	6.2 years			6.5 years			6.0 - 6.5 years
Expected volatility		77	%		56.7 - 69.4	%		53.2 - 69.4	%
Risk free rate		0.89-2.11	%		1.01-1.42	%		1.48-2.63	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Forfeiture rate		0.0	%		0.0 - 0.7	%		0.0	%

Schedule of Stock Option Activity

	Number of Shares			Weighted Average Exercise Price
Outstanding, August 31, 2010		4,220,000		$	5.36
Granted		425,000		$	3.79
Exercised		-		$	-
Outstanding, August 31, 2011		4,645,000		$	5.21
Granted		275,000		$	2.96
Exercised		-		$	-
Forfeited		(5,000	)	$	3.40
Outstanding, August 31, 2012		4,915,000		$	5.09
Granted		1,025,000		$	6.05
Exercised		(2,120,000	)	$	1.10
Expired		(2,000,000	)	$	10.00
Outstanding, August 31, 2013		1,820,000		$	4.88

Schedule of Issued and Outstanding Stock Options

	Outstanding Options		Vested Options
Number of shares		1,820,000		373,000
Weighted average remaining contractual life	8.7 years		7.7 years
Weighted average exercise price	$	4.88	$	3.71
Aggregate intrinsic value (in thousands)	$	8,160	$	2,107

Schedule of Estimated Unrecognized Compensation Cost From Unvested Stock Options

	Unvested Options at August 31, 213
Unrecognized compensation expense (in thousands)	$	4,452
Remaining vesting phase	3.4 years

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Unaudited Quarterly Financial Data

12 Months Ended

Aug. 31, 2013

Unaudited Quarterly Financial Data [Abstract]

Unaudited Quarterly Financial Data

17.   Unaudited Quarterly Financial Data

The Company's quarterly financial information for the years ended August 31, 2013 and 2012 is as follows (in thousands, except share data):

	For the Year Ended August 31, 2013
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	8,314	$	10,921		$	12,314	$	14,674
Expenses		4,768		6,439			7,449		8,022
Operating income		3,546		4,482			4,865		6,652
Other income (expense)		7		(146	)		451		(3,406	)
Income before income taxes		3,553		4,336			5,316		3,246
Income tax provision (4)		1,315		1,604			1,701		2,250
Net income	$	2,238	$	2,732		$	3,615	$	996
Net income per common share: (1)
Basic	$	0.04	$	0.05		$	0.07	$	0.02
Diluted	$	0.04	$	0.05		$	0.06	$	0.01
Weighted average shares outstanding:
Basic		51,661,704		54,900,326			55,238,098		66,283,325
Diluted		53,616,182		56,481,752			58,918,586		70,176,105

	For the Year Ended August 31, 2012
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	4,479	$	6,219		$	7,522	$	6,750
Expenses		2,860		3,344			3,676		3,336
Operating income		1,619		2,875			3,846		3,414
Other income (expense)		8		3			17		10
Income before income taxes		1,627		2,878			3,863		3,424
Income tax provision (benefit) (2, 3)		-		(3,241	)		1,432		1,477
Net income	$	1,627	$	6,119		$	2,431	$	1,947
Net income per common share: (1)
Basic	$	0.05	$	0.13		$	0.05	$	0.04
Diluted	$	0.04	$	0.12		$	0.05	$	0.04
Weighted average shares outstanding:
Basic		36,098,212		47,445,178			51,292,810		51,409,340
Diluted		37,845,212		49,229,042			53,174,792		53,072,619

1   The sum of net income per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

2   No income tax was recognized during the three months ended November 30, 2011 as the provision for tax at the effective rate was offset by a change in the valuation allowance.

3   For the three months ended February 29, 2012, the entire valuation allowance of $4.9 million was released and a net deferred tax benefit of $3.2 million was recorded.

4   For the three months ended August 31, 2013, income taxes were provided at a higher than expected rate due to a downward adjustment in the deferred tax asset related to the expiration of underlying stock options.

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Related Party Transactions and Commitments (Details) (USD $)	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011	Aug. 31, 2010
Related Party Transaction [Line Items]
Cash payments for certain mineral assets	$ 80,469,000	$ 46,751,000	$ 30,247,000
Repayment of promissory note		5,200,000
Payment of interest on promissory note		68,000	74,000
Joint interest billing	4,700,000	3,268,000
Petroleum Exploration and Management, LLC [Member]
Related Party Transaction [Line Items]
Cash payments for certain mineral assets			10,000,000
Value of restricted shares of common stock			4,698,000
Promissory note			5,200,000
Repayment of promissory note		5,200,000
Payment of interest on promissory note		142,000
Payments to related party		5,342,000
Balance due to related party			19,898,000	868,000
Joint interest billing			396,000
Amounts collected from related party			(1,264,000)
Petroleum Management, LLC [Member]
Related Party Transaction [Line Items]
Purchase of equipment from related party			2,000
Payments to related party			(541,000)
Balance due to related party				539,000
HS Land & Cattle, LLC [Member]
Related Party Transaction [Line Items]
Rent expense	130,000	120,000	120,000
Petroleum Management, LLC and Petroleum Exploration and Management, LLC [Member]
Related Party Transaction [Line Items]
Cash payments for certain mineral assets			1,017,435
Board of Directors Member [Member]
Related Party Transaction [Line Items]
Restricted shares of common stock		188,137	40,000
Value of restricted shares of common stock		491,000	164,000
Royalty expense	$ 304,000	$ 196,000

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STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Cash flows from operating activities:
Net income (loss)	$ 9,581	$ 12,124	$ (11,600)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	13,336	6,010	2,838
Amortization of debt issuance costs			1,588
Accretion of debt discount			2,664
Provision for deferred taxes	6,870	(332)
Stock-based compensation	1,362	473	627
Valuation decrease in commodity derivatives	2,649
Change in fair value of derivative liability			10,229
Accounts receivable
Oil and gas sales	(3,756)	(1,597)	(991)
Joint interest billing	(1,432)	(685)	(424)
Inventory	(16)	282	(72)
Accounts payable
Trade	(550)	(155)	1,550
Revenue	1,921	4,161
Production taxes	2,472	2,279	350
Accrued expenses	(141)	(1,291)	1,317
Other	(176)	(17)	(160)
Total adjustments	22,539	9,128	19,516
Net cash provided by operating activities	32,120	21,252	7,916
Cash flows from investing activities:
Acquisition of property and equipment	(80,469)	(46,751)	(30,247)
Short-term investments	(60,000)
Net proceeds from sales of oil and gas properties		71	8,382
Net cash used in investing activities	(140,469)	(46,680)	(21,865)
Cash flows from financing activities:
Proceeds from sale of stock	82,656	40,250	18,000
Offering costs	(4,413)	(2,829)	(1,309)
Proceeds from exercises of warrants	3,275	3,000
Shares withheld for payment of employee payroll taxes	(6,990)
Net proceeds from revolving credit facility	34,000
Principal repayment of related party notes payable		(5,200)
Net cash provided by financing activities	108,528	35,221	16,691
Net increase in cash and equivalents	179	9,793	2,742
Cash and equivalents at beginning of period	19,284	9,491	6,749
Cash and equivalents at end of period	$ 19,463	$ 19,284	$ 9,491

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BALANCE SHEETS (Parenthetical) (USD $)	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011	Aug. 31, 2010
BALANCE SHEETS [Abstract]
Preferred stock, par value per share	$ 0.01	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000	10,000,000
Preferred stock, shares issued	0	0	0
Preferred stock, shares outstanding	0	0	0
Common stock, par value per share	$ 0.001	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000	100,000,000
Common stock, shares issued	70,587,723	51,409,340	36,098,212
Common stock, shares outstanding	70,587,723	51,409,340	36,098,212	13,510,981

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Shareholders' Equity

12 Months Ended

Aug. 31, 2013

Shareholders' Equity [Abstract]

Shareholders' Equity

10.   Shareholders' Equity

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

	For the Years Ended August 31,
	2013		2012		2011
Preferred stock, shares authorized		10,000,000		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil		nil
Common stock, shares authorized		100,000,000		100,000,000		100,000,000
Common stock, par value	$	0.001	$	0.001	$	0.001
Common stock, shares issued and outstanding		70,587,723		51,409,340		36,098,212

Preferred Stock 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.

The following shares of common stock were issued during the fiscal years presented:

Sale of common stock

In June 2013, the Company completed the sale of common stock in an underwritten public offering led by Johnson Rice LLC.

In fiscal year 2012, the Company completed the sale of common stock in an underwritten public offering led by Northland Capital Markets.

In fiscal year 2011, the Company completed the sale of common stock to private investors.

Certain details of each transaction are shown in the following table.  Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering.

	For the Years Ended August 31,
	2013		2012		2011
Number of common shares sold		13,225,000		14,363,363		9,000,000
Offering price per common share	$	6.25	$	2.75	$	2.00
Net proceeds (in thousands)	$	78,243	$	37,422	$	16,691

Common stock issued for acquisition of mineral interests and services

During the fiscal years presented, the Company issued common shares in exchange for mineral property interests and to individuals as compensation for services provided to the Company.  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 Years Ended August 31,
	2013		2012		2011
Number of common shares issued for mineral property leases		687,122		669,765		1,864,838
Number of common shares issued for Orr Energy acquisition		3,128,422		-		-
Total common shares issued		3,815,544		669,765		1,864,838
Average price per common share	$	4.37	$	3.12	$	3.04
Aggregate value of shares issues (in thousands)		16,684	$	2,090	$	5,670

Common stock warrants

The Company has issued warrants to purchase common stock.  The relevant terms of the warrants are described in the following paragraphs.

Series A - During the year ended August 31, 2009, the Company issued 4,098,000 Series A warrants, each of which was immediately exercisable.  Each Series A warrant entitled the holder to purchase one share of common stock for $6.00 per share.  All of the Series A warrants expired on December 31, 2012.

Series B - During the year ended August 31, 2009, the Company issued 1,000,000 Series B warrants, each of which was immediately exercisable.  Each Series B warrant entitled the holder to purchase one share of common stock for $10.00 per share.  All of the Series B warrants expired on December 31, 2012.

Series C - During the year ended August 31, 2010, the Company issued 9,000,000 Series C warrants in connection with a unit offering.  Each unit included one convertible promissory note with a face value of $100,000 and 50,000 Series C warrants.  Each Series C warrant entitles the holder to purchase one share of common stock for $6.00 per share.  The Series C warrants will expire, if not previously exercised, on December 31, 2014.  During the year ended August 31, 2013, 500,000 warrants were exercised.

Series D - During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for a unit offering.  Each Series D warrant entitles the holder to purchase one share of common stock for $1.60 per share, and contains a net settlement provision that provides for exercise of the warrants on a cashless basis.  The Series D warrants will expire, if not previously exercised, on December 31, 2014.  During each of the three years ended August 31, 2013, the following warrants were exercised: 627,799 during fiscal 2013, nil during fiscal 2012, and 355,399 during fiscal 2011.

Sales Agent Warrants - During the year ended August 31, 2009, the Company issued 31,733 warrants to the sales agent for an equity offering.  Each Sales Agent Warrant entitled the holder to purchase two shares of common for $1.80 per share.  The Sales Agent Warrants had an expiration date of December 31, 2012, and all of the warrants were exercised during the year ended August 31, 2013.

Investor Relations Warrants - During the year ended August 31, 2012, the Company issued 100,000 warrants to a firm providing investor relations services.  Each Investor Relations Warrant entitles the holder to purchase one share of common stock for $2.69 per share, and contains a net settlement provision that provides for exercise of the warrants on a cashless basis.  The warrants were to become exercisable in equal quarterly installments over a one year period.  During the year ended August 31, 2013, warrants to purchase 50,000 shares became exercisable and warrants to purchase 50,000 shares were forfeited due to early termination of the agreement.  Also during the year ended August 31, 2013, 25,000 warrants were exercised.

The following table summarizes activity for common stock warrants for the fiscal years presented:

	Number of Shares Issuable Upon Warrant Exercise		Weighted Average Exercise Price Per Share
Outstanding, August 31, 2010		15,286,466	$	5.92
Exercised		355,399	$	1.60
Outstanding, August 31, 2011		14,931,067	$	6.02
Granted		100,000	$	2.69
Exercised		-	$	-
Outstanding, August 31, 2012		15,031,067	$	6.02
Exercised		1,216,265	$	3.44
Forfeited / Expired		5,148,000	$	6.74
Outstanding, August 31, 2013		8,666,802	$	5.92

The following table summarizes information about the Company's issued and outstanding common stock warrants as of August 31, 2013:

Description	Number of Shares		Exercise Price		Remaining Contractual Life (in years)		Exercise Price times number of shares
Series C		8,500,000	$	6.00		1.30	$	51,000,000
Series D		141,802	$	1.60		1.30	$	226,883
Investor Relations		25,000	$	2.69		2.30	$	67,250
Total		8,666,802					$	51,294,133

Conversion of Promissory Notes into Shares of Common Stock

During the year ended August 31, 2011, convertible promissory notes with a face value of $15,908,000 were converted into 9,942,500 shares of common stock at a rate of $1.60 per share.  In addition, 36,876 shares of common stock were issued in payment of accrued interest, also at a rate of $1.60 per share.

The notes had been issued during the fiscal year ended August 31, 2010, as part of the Company's sale of 180 units, each of which consisted of a convertible promissory note in the face amount of $100,000 and bearing interest at an annual rate of 8%.  Some of the notes were converted into common shares during the year ended August 31, 2010, and all of the remaining outstanding notes were converted during the year ended August 31, 2011.

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Document and Entity Information (USD $)
In Thousands, except Share data, unless otherwise specified

12 Months Ended

Aug. 31, 2013

Oct. 31, 2013

Feb. 28, 2013

Document and Entity Information [Abstract]

Document Type

10-K

Amendment Flag

true

Amendment Description

Explanatory Note

This Amendment No. 1 to the Synergy Resources Corporation Annual Report on Form 10-K for the year ended August 31, 2013, reflects changes made in response to comments received from the staff of Securities and Exchange Commission.  In response to the comments, we amended our original report to (1) expand our disclosures related to proved undeveloped reserves in the discussion about oil and gas properties in Item 1; (2) expand our disclosure about market risk included in Item 7A; (3) clarified our references to exhibits related to our amended and restated credit agreement and the employment agreements for Ed Holloway and William E. Scaff; (4) filed as an exhibit the underlying drilling contract with Ensign United States Drilling, Inc. that was dated April 19, 2013; (5) in Note 1 to Financial Statements, clarified the description of our policy regarding the ceiling test; and (6) in Note 16 to the Financial Statements expanded our disclosure to provide explanations for the significant changes in reserve quantities.

Except as described above, this amendment does not revise or restate the financial statements or other disclosures included in the original Form 10-K.  This amendment does not reflect events occurring after the filing of the original Form 10-K or modify or update disclosures related to subsequent events.  Accordingly, this amendment should be read in conjunction with our filings with the SEC subsequent to the filing of the original Form 10-K.

Document Period End Date

Aug. 31, 2013

Entity Registrant Name

SYNERGY RESOURCES CORP

Entity Central Index Key

0001413507

Current Fiscal Year End Date

--08-31

Document Fiscal Period Focus

FY

Document Fiscal Year Focus

2013

Entity Filer Category

Accelerated Filer

Entity Common Stock, Shares Outstanding

74,391,364

Entity Public Float

$ 309,000

Entity Well-known Seasoned Issuer

No

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

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Stock-Based Compensation

12 Months Ended

Aug. 31, 2013

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 expense 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):

	For the Years Ended August 31,
	2013		2012		2011
Stock options	$	1,039	$	443	$	197
Restricted stock grants		277		17		430
Investor relations warrants		46		13		-
	$	1,362	$	473	$	627

General Description of Stock Option and Other Stock Award Plans

The Company has three stock award plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan.  The plans adopted during 2011 replaced a non-qualified stock option plan and a stock bonus plan originally adopted during 2005 (the "2005 Plans").  No additional options or shares will be issued under the 2005 Plans.

Each plan authorizes the issuance of shares of the Company's common stock to persons that exercise options granted pursuant to the Plan.  Employees, directors, officers, consultants and advisors are eligible to receive such awards, provided that bona fide services be rendered by such consultants or advisors and such services must not be in connection with promoting our stock or the sale of securities in a capital-raising transaction.  The option exercise price is determined by the Board of Directors, though is generally the closing market price of Company stock on the date of grant.

As of August 31, 2013, there were 5,000,000 shares authorized for issuance under the non-qualified plan and 2,000,000 shares authorized for each of the incentive stock option and stock bonus plans.

During the respective fiscal years, the Company granted the following non-qualified stock options:

	For the Years Ended August 31,
	2013		2012		2011
Number of options to purchase common shares		1,025,000		275,000		425,000
Weighted average exercise price	$	6.05	$	2.96	$	3.79
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	3-5 years		4-5 years		4-5 years
Fair Value (in thousands)	$	4,179	$	519	$	990

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

	For the Years Ended August 31,
	2013			2012			2011
Expected term	6.2 years			6.5 years			6.0 - 6.5 years
Expected volatility		77	%		56.7 - 69.4	%		53.2 - 69.4	%
Risk free rate		0.89-2.11	%		1.01-1.42	%		1.48-2.63	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Forfeiture rate		0.0	%		0.0 - 0.7	%		0.0	%

During the year end August 31, 2013, the Compensation Committee modified the terms of the stock options to acquire 2,000,000 shares of common stock with an original expiration date of June 2013 to August 2013. The effect of the modification resulted in an immaterial expense to stock based compensation.   Effective August 27, 2013, the options were exercised on a cashless basis.  As part of the net settlement provisions of a cashless exercise, the Company withheld 1,026,043 shares with a value of $8.7 million, which was used to satisfy payment of the exercise price and $6.7 million to pay to the appropriate government entity to satisfy the required minimum payroll taxes.

The following table summarizes activity for stock options for the fiscal years presented:

	Number of Shares			Weighted Average Exercise Price
Outstanding, August 31, 2010		4,220,000		$	5.36
Granted		425,000		$	3.79
Exercised		-		$	-
Outstanding, August 31, 2011		4,645,000		$	5.21
Granted		275,000		$	2.96
Exercised		-		$	-
Forfeited		(5,000	)	$	3.40
Outstanding, August 31, 2012		4,915,000		$	5.09
Granted		1,025,000		$	6.05
Exercised		(2,120,000	)	$	1.10
Expired		(2,000,000	)	$	10.00
Outstanding, August 31, 2013		1,820,000		$	4.88

The following table summarizes information about issued and outstanding stock options as of August 31, 2013:

	Outstanding Options		Vested Options
Number of shares		1,820,000		373,000
Weighted average remaining contractual life	8.7 years		7.7 years
Weighted average exercise price	$	4.88	$	3.71
Aggregate intrinsic value (in thousands)	$	8,160	$	2,107

The estimated unrecognized compensation cost from unvested stock options as of August 31, 2013, w hich will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at August 31, 213
Unrecognized compensation expense (in thousands)	$	4,452
Remaining vesting phase	3.4 years

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STATEMENTS OF OPERATIONS (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Revenues:
Oil and gas revenues	$ 46,223	$ 24,969	$ 10,002
Expenses:
Lease operating expenses	3,417	1,212	484
Production taxes	4,237	2,436	956
Depletion, depreciation and amortization	13,336	6,010	2,838
General and administrative	5,688	3,557	2,904
Total expenses	26,678	13,215	7,182
Operating income	19,545	11,754	2,820
Other income (expense):
Change in fair value of derivative conversion liability			(10,229)
Commodity derivative realized loss	(395)
Commodity derivative unrealized loss	(2,649)
Interest expense, net	(97)		(4,247)
Interest income	47	38	56
Total other income (expense)	(3,094)	38	(14,420)
Income before income taxes	16,451	11,792	(11,600)
Deferred income tax provision (benefit)	6,870	(332)
Net income (loss)	$ 9,581	$ 12,124	$ (11,600)
Net income (loss) per common share:
Basic	$ 0.17	$ 0.26	$ (0.45)
Diluted	$ 0.16	$ 0.25	$ (0.45)
Weighted average shares outstanding:
Basic	57,089,362	46,587,558	26,009,283
Diluted	59,088,761	48,359,905	26,009,283

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Asset Retirement Obligations

12 Months Ended

Aug. 31, 2013

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 its 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 fiscal years presented, the Company used the following assumptions:

	For the Years Ended August 31,
	2013	2012
Inflation rate	3.9 - 4.0%	3.9 - 4.0%
Estimated asset life	24.0 - 40.0 years	24.0 - 27.6 years
Credit adjusted risk free interest rate	8.0 - 11.2%	11.2 - 11.7%

The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands).  The revisions recognized during 2013 were primarily from increases in the undiscounted abandonment cost estimates.

	As of August 31,
	2013		2012
Beginning asset retirement obligation	$	1,027	$	644
Liabilities incurred		376		300
Liabilities assumed		240		-
Liabilities settled		-		-
Accretion expense		172		83
Revisions in previous estimates		962		-
	$	2,777	$	1,027

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Depletion, depreciation and amortization ("DDA")

12 Months Ended

Aug. 31, 2013

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):

	For the Years Ended August 31,
	2013		2012		2011
Depletion	$	13,046	$	5,838	$	2,743
Depreciation and amortization		290		172		95
Total DDA Expense	$	13,336	$	6,010	$	2,838

Capitalized costs of evaluated 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.

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Unaudited Oil and Gas Reserves Information

12 Months Ended

Aug. 31, 2013

Unaudited Oil and Gas Reserves Information [Abstract]

Unaudited Oil and Gas Reserves Information

16.   Unaudited Oil and Gas Reserves Information

Oil and Natural Gas Reserve Information:  Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made).  Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Proved oil and natural gas reserve information as of the fiscal year ends presented, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company LP.  Reserve information for the properties was prepared in accordance with guidelines established by the SEC.

The reserve estimates prepared as of each of the fiscal year ends presented were prepared in accordance with "Modernization of Oil and Gas Reporting" published by the SEC.  The recent guidance included updated definitions of proved developed and proved undeveloped oil and gas reserves, oil and gas producing activities and other terms.  Proved oil and gas reserves were calculated based on the prices for oil and gas during the 12 month period before the respective reporting date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period, rather than the year-end spot prices, which had been used in prior years.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years.  The recent guidance broadened the types of technologies that may be used to establish reserve estimates.

The following table sets forth information regarding the Company's net ownership interests in estimated quantities of proved developed and undeveloped oil and gas reserve quantities and changes therein for each of the fiscal years presented:

	Oil (Bbl)			Gas (McF)			Boe
Balance, August 31, 2010		676,685			4,481,051			1,423,527
Revision of previous estimates		323,704			611,516			425,623
Purchase of reserves in place		967,302			8,466,714			2,378,421
Extensions, discoveries, and other additions		191,931			1,152,708			384,049
Sale of reserves in place		-			-			-
Production		(89,917	)		(450,831	)		(165,056	)
Balance, August 31, 2011		2,069,705			14,261,158			4,446,564
Revision of previous estimates		429,783			3,298,906			979,601
Purchase of reserves in place		33,328			706,842			151,135
Extensions, discoveries, and other additions		2,788,686			16,288,125			5,503,374
Sale of reserves in place		-			-			-
Production		(235,691	)		(1,109,057	)		(420,534	)
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140
Revision of previous estimates		(194,236	)		(2,923,919	)		(681,556	)
Purchase of reserves in place		1,000,664			7,360,752			2,227,456
Extensions, discoveries, and other additions		1,576,301			4,914,627			2,395,406
Sale of reserves in place		-			-			-
Production		(421,265	)		(2,107,603	)		(772,532	)
Balance, August 31, 2013		7,047,275			40,689,831			13,828,914
Proved developed and undeveloped reserves:
Developed at August 31, 2011		783,821			5,578,067			1,713,499
Undeveloped at August 31, 2011		1,285,884			8,683,091			2,733,066
Balance, August 31, 2011		2,069,705			14,261,158			4,446,565
Developed at August 31, 2012		2,823,604			17,380,806			5,720,405
Undeveloped at August 31, 2012		2,262,207			16,065,168			4,939,735
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140
Developed at August 31, 2013		4,659,405			25,866,008			8,970,406
Undeveloped at August 31, 2013		2,387,870			14,823,823			4,858,507
Balance, August 31, 2013		7,047,275			40,689,831			13,828,913

Notable changes in proved reserves for the year ended August 31, 2013 included:

· Purchases of reserves in place.  In 2013, purchases of minerals in place of 2.2 million Boe were attributable to the acquisition of 36 producing oil and gas wells and undeveloped acreage from Orr Energy, LLC.  Please see the Acquisitions footnote for further information.

· Revision of previous estimates.   In 2013, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 681,556 Boe as the Company's drilling schedule was adjusted to reflect the elimination of previously planned vertical drilling locations as the development focus shifted from vertical to horizontal drilling.

· Extensions and discoveries.  In 2013, total extensions and discoveries of 2.4 million Boe were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company's proved reserves.

Notable changes in proved reserves for the year ended August 31, 2012 included:

· Purchases of reserves in place.  In 2012, purchases of minerals in place of 151,135 Boe were attributable to the acquisition of additional working interests in existing wells that the Company already operates.

· Revision of previous estimates.   In 2012, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 979,601 Boe.  Included in these revisions were 451,000 Boe of upward adjustments caused by higher crude oil and natural gas prices, and 528,601 Boe of net upward adjustments attributable to reservoir analysis and well performance.

· Extensions and discoveries.  In 2012, total extensions and discoveries of 5.5 million Boe were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company's proved reserves.

Notable changes in proved reserves for the year ended August 31, 2011 included:

· Purchases of reserves in place.  In 2011, purchases of minerals in place of 2.4 million Boe were attributable to the acquisition of 88 producing oil and gas wells and undeveloped acreage from Petroleum Exploration and Management, LLC.

· Revision of previous estimates.  In 2011, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 425,623 Boe.  The significant increase in previous estimates is due to the more extensive production data on wells on which had limited data in the previous reserve report.  The wells drilled in the previous year had limited production history for the wells coming online towards the end of the year.  As such, the estimated reserves were based on this limited production history.  With a full year of production history available in the current year, the reserve amounts were updated to reflect the more accurate production information.

· Extensions and discoveries.  In 2011, total extensions and discoveries of 384,049 Boe were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their related proved undeveloped locations added during the year increased the Company's proved reserves.

Standardized Measure of Discounted Future Net Cash Flows:  The following analysis is a standardized measure of future net cash flows and changes therein related to estimated proved reserves.  Future oil and gas sales have been computed by applying average prices of oil and gas during each of the fiscal years presented.  Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs.  The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs.  Future income tax expenses were calculated by applying year-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and gas reserves, less the tax basis of properties involved and tax credits and loss carry-forwards relating to oil and gas producing activities.  All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows.  Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company's oil and gas reserves.  Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas, and changes in governmental regulations or taxation.

The following table sets forth the Company's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in the ASC (in thousands):

	For the Years Ended August 31,
	2013			2012			2011
Future cash inflow	$	749,030		$	537,462		$	235,239
Future production costs		(146,352	)		(85,612	)		(41,278	)
Future development costs		(108,290	)		(100,821	)		(40,404	)
Future income tax expense		(113,545	)		(109,349	)		(30,738	)
Future net cash flows		380,843			241,680			122,819
10% annual discount for estimated timing of cash flows		(199,111	)		(139,175	)		(65,269	)
Standardized measure of discounted future net cash flows	$	181,732		$	102,505		$	57,550

There have been significant fluctuations in the posted prices of oil and natural gas during the last three years.  Prices actually received from purchasers of the Company's oil and gas are adjusted from posted prices for location differentials, quality differentials, and BTU content. Estimates of the Company's reserves are based on realized prices.

The following table presents the prices used to prepare the reserve estimates, based upon 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 respective reporting period presented:

	Oil (Bbl)		Gas (Mcf)
August 31, 2011 (Average)	$	84.90	$	5.07
August 31, 2012 (Average)	$	86.68	$	3.76
August 31, 2013 (Average)	$	86.40	$	4.40

Changes in the Standardized Measure of Discounted Future Net Cash Flows:  The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	For the Years Ended August 31,
	2013			2012			2011
Standardized measure, beginning of year	$	102,505		$	57,550		$	13,022
Sale and transfers, net of production costs		(38,569	)		(21,321	)		(8,337	)
Net changes in prices and production costs		(4,550	)		(6,023	)		15,484
Extensions, discoveries, and improved recovery		70,191			69,073			13,693
Changes in estimated future development costs		(6,006	)		(42,578	)		(20,471	)
Development costs incurred during the period		5,106			39,739			16,252
Revision of quantity estimates		(14,214	)		21,058			15,424
Accretion of discount		35,103			15,379			3,245
Net change in income taxes		(7,850	)		(30,832	)		(12,012	)
Purchase of reserves in place		40,016			460			21,250
Standardized measure, end of year	$	181,732		$	102,505		$	57,550

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Income Taxes

12 Months Ended

Aug. 31, 2013

Income Taxes [Abstract]

Income Taxes

12.   Income Taxes

The income tax provision (benefit) is comprised of the following (in thousands):
 

	As of August 31,
	2013		2012			2011
Current:
Federal	$	-	$	-		$	-
State		-		-			-
Total current income tax		-		-			-
Deferred:
Federal	$	6,367	$	4,219		$	4,266
State		503		360			354
Total deferred income tax		6,870		4,579			4,620
Valuation allowance		-		(4,911	)		(4,620	)
Income tax provision (benefit)	$	6,870	$	(332	)	$	-

            A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is follows (in thousands):

	As of August 31,
	2013			2012			2011
Federal income tax at statutory rate	$	5,594		$	4,009		$	3,944
State income taxes, net of federal tax		503			360			354
Statutory depletion		(929	)		-			-
Stock based compensation		1,911			-			-
Other		(209	)		210			322
Change in valuation allowance		-			(4,911	)		(4,620	)
Income tax provision (benefit)	$	6,870		$	(332	)	$	-
Effective rate expressed as a percentage		42	%		3	%		0	%

The Company reported a change in valuation allowance of $4,911,000 for the year ended August 31, 2012.  In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carry-forwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. In 2012, the Company determined that the weight of the evidence indicated that it would more likely than not be able to realize its deferred tax asset, and the entire valuation allowance was released.

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the fiscal year ends presented follow (in thousands):

	As of August 31,
	2013		2012
Deferred tax assets:
Net operating loss carry-forward	$	11,485	$	12,643
Stock-based compensation		515		4,070
Statutory depletion		929		-
Unrealized loss on commodity derivative		982		-
Other		3		3
Gross deferred tax assets	$	13,914	$	16,716
Deferred tax liabilities:
Basis of oil and gas properties		20,452		16,384
Gross deferred tax liabilities		20,452		16,384
Deferred tax liability (asset), net	$	6,538	$	(332	)

At August 31, 2013 the Company has a net operating loss carry-forward for federal and state tax purposes of approximately $41.3 million that could be utilized to offset taxable income of future years.  For financial reporting purposes the company has net operating losses of approximately $31 million.  The difference of $10.3 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable.  The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated.  Substantially all of the carry-forward will commence expiring in 2031, 2032, and 2033.

The realization of the deferred tax assets related to the NOL carry-forwards is dependent on the Company's ability to generate sufficient future taxable income within the applicable carryforward periods. As of August 31, 2013, the Company believes it will be able to generate sufficient future taxable income within the carryforward periods, and accordingly believes that it is more likely than not that its net deferred income tax assets will be fully realized.

The ability of the Company to utilize its NOL carry-forwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the "Code"). The utilization of such carry-forwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company's taxable income that can be offset by these carry-forwards. The Company completed a study of the impact of the Code Section 382 limitation on future payments and determined that the statutory provisions were unlikely to limit the Company's ability to realize future tax benefits.

As of August 31, 2013, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company's tax position.  Given the substantial NOL carry-forwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carry-forwards, and would not result in significant interest expense or penalties.  Substantially of the Company's tax returns filed since inception are still subject to examination by tax authorities.

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Fair Value Measurements

12 Months Ended

Aug. 31, 2013

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 developed 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 developed 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 are 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. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis during the reporting periods after initial recognition.

The Company's non-recurring fair value measurements include asset retirement obligations, please refer to Note 5-Asset Retirement Obligations, and for the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3-Acquisitions.

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.

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 level 3 inputs. 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.

The following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recuring basis as of  August 31, 2013 and 2012 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at August 31, 2013
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	-	$	-	$	-
Commodity derivative liability	$	-	$	2,649	$	-	$	2,649
	Fair Value Measurements at August 31, 2012
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	-	$	-	$	-
Commodity derivative liability	$	-	$	-	$	-	$	-

Commodity Derivative Instruments

The Company determines its estimate of the fair value of 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 rating. 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 that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At August 31, 2013, derivative instruments utilized by the Company consist of both "no premium" collars and swaps. The crude oil derivative markets are highly active. Although the Company's derivative instruments are valued using 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 and accounts receivable, 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 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011	Aug. 31, 2010
Interest Expense [Abstract]
Revolving bank credit facility at a variable rate	$ 1,067	$ 108	$ 41
Convertible promissory notes at 8%			590
Related party note payable at 5.25%		68	74
Accretion of debt discount			2,664
Amortization of debt issuance costs	160	32	1,588
Less, interest capitalized	(1,130)	(208)	(710)
Interest expense, net	$ 97		$ 4,247
Interest rate	8.00%			8.00%
Related party note, interest rate	5.25%

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Revolving Credit Facility

12 Months Ended

Aug. 31, 2013

Revolving Credit Facility [Abstract]

Revolving Credit Facility

6.   Revolving Credit Facility

On November 28, 2012, the Company entered into an amended revolving credit facility ("LOC") with a bank syndicate.  The LOC is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit.  The terms provide for $150 million in the maximum amount of borrowings available to the Company, subject to a borrowing base limitation.  Community Banks of Colorado acts as the administrative agent for the bank syndicate with respect to the LOC.  The credit facility expires on November 28, 2016.

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin of 0% to 1%, or London Interbank Offered Rate (LIBOR) plus a margin of 2.50% to 3.25%.  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 year ended August 31, 2013, was 3.2%.  As of August 31, 2013, the interest rate on the outstanding balance was 2.7%, representing LIBOR plus a margin of 2.5%.

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 base limitation is generally subject to redetermination on a semi-annual basis.  The most recent redetermination increased the borrowing base to $75 million based upon the reserve report as of February 28, 2013.  As of August 31, 2013, the unused borrowing base available for future borrowing totaled approximately $38 million.

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain customary financial ratios.  On a quarterly basis, the Company must maintain (a) an adjusted current ratio greater than 1.0, (b) a ratio of earnings before interest, taxes, depletion, amortization and exploration expense (EBITDAX) greater than 3.5 times interest and fees, (c) a ratio of total funded debt less than 3.5 times EBITDAX, and (d) a ratio of total funded debt less than 0.5 times total capitalization.  Furthermore, terms of the LOC require the Company to maintain hedge contracts covering future production quantities that are included in the borrowing base.  The Company is required to hedge no less than 45% and no more than 80% of scheduled production for a rolling 24 months.

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Commodity Derivative Instruments

12 Months Ended

Aug. 31, 2013

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 or "no premium" collars to reduce the effect of price changes on a portion of its future oil 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 one counterparty.  The Company has netting arrangements with the counterparty 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 commodity derivative line on the statements of operations.  The Company's valuation estimate takes into consideration the counterparty's credit worthiness, the Company's credit worthiness, 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 August 31, 2013 are summarized below:

Contract Type	Basis (1)	Quantity (Bbl/month)	Strike Price ($/Bbl)	Term
Collar	NYMEX	3,014	$87.00 - $102.50	Sept 1, 2013 - Dec 31, 2013
Collar	NYMEX	1,840	$85.00 - $98.50	Jan 1, 2014 - Dec 31, 2014
Collar	NYMEX	7,000	$80.00 - $92.50	Jan 1, 2015 - Jun 30, 2015
Contract Type	Basis (1)	Quantity (Bbl/month)	Swap Price ($/Bbl)	Term
Swap	NYMEX	3,014	$91.70	Sept 1, 2013 - Dec 31, 2013
Swap	NYMEX	6,000	$96.35	Sept 1, 2013 - Dec 31, 2013  (2)
Swap	NYMEX	8,000	$94.45	Sept 1, 2013 - Dec 31, 2013
Swap	NYMEX	15,000	$98.00	Sept 1, 2013 - Dec 31, 2013
2013 Total/Average		32,014	$95.13
Swap	NYMEX	1,840	$90.80	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	2,000	$90.11	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	5,000	$90.50	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX	15,000	$98.00	Jan 1, 2014 - Feb 28, 2014
2014 Total/Average		23,840	$92.35
(1) NYMEX refers to WTI quoted prices on the New York Mercantile Exchange
(2) In connection with entering into these swaps with premium hedged prices, the counterparty has the right, but not the obligation to extend the swap to January 1, 2014 through December 31, 2014 at the current strike price and quantity.  This option expires on December 31, 2013.

 The following table details the fair value of the derivatives recorded in the applicable balance sheet, by category (in thousands):

		As of August 31,
Underlying Commodity	Balance Sheet Location	2013		2012
Crude Oil derivative contract	Current liabilities	$	2,315	$	-
Crude Oil derivative contract	Noncurrent liabilities	$	334	$	-

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

	For the Years Ended August 31,
	2013		2012		2011
Unrealized loss on commodity derivatives	$	2,649	$	-	$	-
Realized loss on commodity derivatives		395		-		-
Total loss	$	3,044	$	-	$	-

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Interest Expense

12 Months Ended

Aug. 31, 2013

Interest Expense [Abstract]

Interest Expense

9.   Interest Expense

The components of interest expense are (in thousands):

	For the Years Ended August 31,
	2013			2012			2011
Revolving bank credit facility at a variable rate	$	1,067		$	108		$	41
Convertible promissory notes at 8%		-			-			590
Related party note payable at 5.25%		-			68			74
Accretion of debt discount		-			-			2,664
Amortization of debt issuance costs		160			32			1,588
Less, interest capitalized		(1,130	)		(208	)		(710	)
Interest expense, net	$	97		$	-		$	4,247

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Income Taxes (Schedule of Components of Income Taxes) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended																12 Months Ended
	Aug. 31, 2013		May 31, 2013		Feb. 28, 2013		Nov. 30, 2012		Aug. 31, 2012		May 31, 2012		Feb. 29, 2012		Nov. 30, 2011		Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Current:
Federal
State
Total current income tax
Deferred:
Federal																	6,367	4,219	4,266
State																	503	360	354
Total deferred income tax																	6,870	4,579	4,620
Valuation allowance																		(4,911)	(4,620)
Income tax provision (benefit)	$ 2,250	[1]	$ 1,701	[1]	$ 1,604	[1]	$ 1,315	[1]	$ 1,477	[2],[3]	$ 1,432	[2],[3]	$ (3,241)	[2],[3]		[2],[3]	$ 6,870	$ (332)

[1] For the three months ended August 31, 2013, income taxes were provided at a higher than expected rate due to a downward adjustment in the deferred tax asset related to the expiration of underlying stock options.

[2] No income tax was recognized during the three months ended November 30, 2011 as the provision for tax at the effective rate was offset by a change in the valuation allowance.

[3] For the three months ended February 29, 2012, the entire valuation allowance of $4.9 million was released and a net deferred tax benefit of $3.2 million was recorded.

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Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Aug. 31, 2013	Aug. 31, 2012
Deferred tax assets:
Net operating loss carry-forward	$ 11,485	$ 12,643
Stock-based compensation	515	4,070
Statutory depletion	929
Unrealized loss on commodity derivative	982
Other	3	3
Gross deferred tax assets	13,914	16,716
Deferred tax liabilities:
Basis of oil and gas properties	20,452	16,384
Gross deferred tax liabilities	20,452	16,384
Deferred tax liability (asset), net	$ 6,538	$ (332)

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Stock-Based Compensation (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Stock-Based Compensation [Abstract]
Term	10 years	10 years	10 years
Assumptions used in valuing stock options:
Expected term	6 years 2 months 12 days	6 years 5 months
Expected volatility	77.00%
Expected dividend yield	0.00%	0.00%	0.00%
Forfeiture rate	0.00%		0.00%
Stock-based compensation expense	$ 1,362	$ 473	$ 627
Fair value	4,179	519	990
Summary of activity for stock options:
Outstanding	4,915,000	4,645,000	4,220,000
Granted	1,025,000	275,000	425,000
Exercised	(2,120,000)
Forfeited	(2,000,000)	(5,000)
Outstanding	1,820,000	4,915,000	4,645,000
Outstanding, weighted average exercise price	$ 5.09	$ 5.21	$ 5.36
Granted, weighted-average exercise price	$ 6.05	$ 2.96	$ 3.79
Exercised, weighted-average exercise price	$ 1.10	$ 0.00	$ 0.00
Forfeited, weighted average exercise price	$ 10.00	$ 3.40
Outstanding, weighted average exercise price	$ 4.88	$ 5.09	$ 5.21
Weighted average remaining contractual life	8 years 8 months 12 days
Aggregate intrinsic value	8,160
Vested Options:
Number of shares	373,000
Weighted average remaining contractual life	7 years 8 months 12 days
Weighted average exercise price	$ 3.71
Aggregate intrinsic value	2,107
Unrecognized compensation expense	4,452
Remaining vesting phase	3 years 4 months 24 days
Number of shares acquired	2,000,000
Shares withheld, shares	1,026,043
Shares withheld, value	8,700
Minimum payroll taxes	6,700
Non Qualified Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized	5,000,000
Incentive Stock Option And Stock Bonus Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized	2,000,000
Employee Stock Option [Member]
Assumptions used in valuing stock options:
Stock-based compensation expense	1,039	443	197
Restricted Stock [Member]
Assumptions used in valuing stock options:
Stock-based compensation expense	277	17	430
Warrant [Member]
Assumptions used in valuing stock options:
Stock-based compensation expense	$ 46	$ 13
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	4 years	4 years
Assumptions used in valuing stock options:
Expected term			6 years
Expected volatility		56.70%	53.20%
Risk-free interest rate	0.89%	1.01%	1.48%
Forfeiture rate		0.00%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	5 years	5 years	5 years
Assumptions used in valuing stock options:
Expected term			6 years 5 months
Expected volatility		69.40%	69.40%
Risk-free interest rate	2.11%	1.42%	2.63%
Forfeiture rate		0.70%

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Interest Expense (Tables)

12 Months Ended

Aug. 31, 2013

Interest Expense [Abstract]

Schedule of the Components of Interest Expense

	For the Years Ended August 31,
	2013			2012			2011
Revolving bank credit facility at a variable rate	$	1,067		$	108		$	41
Convertible promissory notes at 8%		-			-			590
Related party note payable at 5.25%		-			68			74
Accretion of debt discount		-			-			2,664
Amortization of debt issuance costs		160			32			1,588
Less, interest capitalized		(1,130	)		(208	)		(710	)
Interest expense, net	$	97		$	-		$	4,247

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Acquisition (Schedule of Fair Value of Acquisition) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended		12 Months Ended
	Dec. 05, 2012		Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Purchase Price
Cash	$ 29,012
Synergy Resources Corp. Common Stock	13,515	[1]
Total consideration given	42,527
Allocation of Purchase Price
Proved oil and gas properties	43,143
Unproved oil and gas properties	466
Total fair value of oil and gas properties acquired	43,609
Working capital	(842)
Asset retirement obligation	(240)
Fair value of net assets acquired	42,527
Working capital acquired was estimated as follows:
Accounts receivable	521
Accrued liabilities and expenses	(1,363)
Total working capital	$ (842)
Shares issued for Orr Energy acquisition, shares	3,128,422		3,128,422
Closing stock price	$ 4.32

[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 5, 2012. (3,128,422 shares at $4.32 per share)

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Other Commitments and Contingencies

12 Months Ended

Aug. 31, 2013

Other Commitments and Contingencies [Abstract]

Other Commitments and Contingencies

14.   Other Commitments and Contingencies

Effective July 18, 2013, the Company amended its drilling contract with Ensign United States Drilling, Inc. to utilize a drilling rig for the drilling of 25 horizontal wells.  Total payments due to Ensign will depend upon a number of variables, including the target formation and other technical details.  The Company estimates that this commitment will result in its use of the rig until June 2014, and that total drilling costs will approximate $25.6 million.  As of August 31, 2013, the Company had accrued costs of $5.7 million and estimates that its remaining obligations under this contract approximate $19.9 million.
 

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 (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 September 30, 2013, the Company had agreed to participate in 13 new horizontal wells, with aggregate costs to its interest estimated at $5.2 million.  It is the Company's policy to accrue costs on a non-operated well when it receives notice that active drilling operations have commenced.  For these 13 wells, no costs were accrued at August 31, 2013, as active drilling operations had not begun.  In addition, the Company had been notified by other operators that it may have an interest in 54 potential wells.  As of September 30, 2013, the Company had not yet committed to participate in the future wells and had not determined its potential working interest or cost obligation. 

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Organization and Summary of Significant Accounting Policies (Policy)

12 Months Ended

Aug. 31, 2013

Organization and Summary of Significant Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation:  The Company has adopted August 31st as the end of its fiscal year.  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").

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 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.

Short-Term Investments

Short-Term Investments:  As part of its cash management strategies, the Company invests in short-term interest bearing deposits such as certificates of deposits with maturities of less than one year.

Inventory

Inventory:     Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market

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 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.

Wells in progress represent the costs associated with the drilling of oil and gas wells that have yet to be completed as of August 31, 2013.  Since the wells had not been completed as of August 31, 2013, they were classified within unevaluated oil and gas properties and were withheld from the depletion calculation and the ceiling test. The costs for these wells will be transferred into proved property when the wells commence production 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 depreciation, depletion, 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 and reflected as additional accumulated depreciation, depletion and amortization.  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.  No provision for impairment was required for the twelve months ended August 31, 2013 or 2012.

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).

	For the Years Ended August 31,
	2013		2012		2011
Capitalized overhead	$	637	$	345	$	206

Well Costs Payable

Well Costs Payable:  The cost 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 ("AFE").

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.

Derivative Conversion Liability

Derivative Conversion Liability:  The Company accounted for the embedded conversion features in its convertible promissory notes, issued during fiscal year 2010, in accordance with the guidance for derivative instruments, which requires a periodic valuation of their fair value and a corresponding recognition of liabilities associated with such derivatives.  The recognition of derivative conversion liabilities related to the issuance of convertible debt was applied first to the proceeds of such issuance as a debt discount at the date of the issuance.  All subsequent increases or decreases in the fair value of derivative conversion liabilities were recognized as a charge or credit to other income (expense) in results of operations.  In connection with the conversion of convertible promissory notes into shares of the Company's common stock, derivative conversion liabilities were reclassified to additional paid-in-capital.  The amounts recognized in the financial statements follow.

	For the Years Ended August 31,
	(in thousands)
	2013		2012		2011
Non-cash expense recognized related to the change in
the fair value of derivative conversion liabilities	$	-	$	-	$	10,229
Derivative conversion liabilities recognized in additional
paid-in-capital	$	-	$	-	$	19,554

Debt Issuance Costs

Debt Issuance Costs:  Debt issuance costs incurred in connection with executing convertible promissory notes between December 29, 2009, and March 12, 2011 were classified as a long-term asset.  However, as a result of the conversion of all outstanding convertible promissory notes into shares of the Company's common stock, all debt issuance costs were recognized as a component of interest expense through August 31, 2011.

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 using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between 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 and Operating Region

Major Customers and Operating Region:     The Company operates exclusively within the United States of America.  Except for cash and short-term investments, all of the Company's assets are employed in and all of its revenues are derived from the oil and gas industry.   The table below presents the percentages of oil and gas revenue resulting from purchases by major customers.

	For the Years Ended August 31,
	2013	2012	2011
Company A	50%	68%	75%
Company B	15%	11%	21%

The Company sells production to a small number of customers, as is customary in the industry.  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 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 total receivable balances as of each of the fiscal year ends presented are shown in the following table:

	As of August 31,
	2013	2012	2011
Company A	24%	35%	31%
Company B	23%	30%	31%
Company C	12%	*	13%
* less than 10%

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 below 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 August 31, 2013.  The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of August 31, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.  For further information, see Note 12 below.

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 or "no premium" collars to reduce the effect of price changes on a portion of our future oil 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. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. We value our 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.  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. For additional discussion, please refer to Note 7-Commodity Derivative Instruments.

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.

	For the Years Ended August 31,
	2013		2012		2011
Weighted-average shares outstanding - basic		57,089,362		46,587,558		26,009,283
Potentially dilutive common shares from:
Stock options		1,881,682		1,380,861		-
Warrants		117,717		391,486		-
Weighted-average shares outstanding - diluted		59,088,761		48,359,905		26,009,283

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

	For the Years Ended August 31,
	2013		2012		2011
Potentially dilutive common shares from:
Stock options		670,000		2,495,000		4,645,000
Warrants		8,500,000		14,098,000		14,931,067
Total		9,170,000		16,593,000		19,576,067

Recent Accounting Pronouncements

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.  There were various updates recently issued by the Financial Accounting Standards Board, 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 consolidated financial position, results of operations or cash flows. 

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Property and Equipment (Schedule of Capitalized Costs Excluded from Amortization) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011	Aug. 31, 2010
Property, Plant and Equipment [Line Items]
Total unevaluated costs	$ 37,646	$ 9,636	$ 16,585	$ 848
Unevaluated costs, not subject to amortization	64,715	32,484
Lease acquisition and other costs [Member]
Property, Plant and Equipment [Line Items]
Total unevaluated costs	11,757	9,636	16,585	848
Unevaluated costs, not subject to amortization	38,826	27,070
Wells in progress [Member]
Property, Plant and Equipment [Line Items]
Total unevaluated costs	25,889
Unevaluated costs, not subject to amortization	$ 25,889	$ 5,414

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Unaudited Quarterly Financial Data (Tables)

12 Months Ended

Aug. 31, 2013

Unaudited Quarterly Financial Data [Abstract]

Schedule of Unaudited Quarterly Financial Data

	For the Year Ended August 31, 2013
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	8,314	$	10,921		$	12,314	$	14,674
Expenses		4,768		6,439			7,449		8,022
Operating income		3,546		4,482			4,865		6,652
Other income (expense)		7		(146	)		451		(3,406	)
Income before income taxes		3,553		4,336			5,316		3,246
Income tax provision (4)		1,315		1,604			1,701		2,250
Net income	$	2,238	$	2,732		$	3,615	$	996
Net income per common share: (1)
Basic	$	0.04	$	0.05		$	0.07	$	0.02
Diluted	$	0.04	$	0.05		$	0.06	$	0.01
Weighted average shares outstanding:
Basic		51,661,704		54,900,326			55,238,098		66,283,325
Diluted		53,616,182		56,481,752			58,918,586		70,176,105

	For the Year Ended August 31, 2012
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	4,479	$	6,219		$	7,522	$	6,750
Expenses		2,860		3,344			3,676		3,336
Operating income		1,619		2,875			3,846		3,414
Other income (expense)		8		3			17		10
Income before income taxes		1,627		2,878			3,863		3,424
Income tax provision (benefit) (2, 3)		-		(3,241	)		1,432		1,477
Net income	$	1,627	$	6,119		$	2,431	$	1,947
Net income per common share: (1)
Basic	$	0.05	$	0.13		$	0.05	$	0.04
Diluted	$	0.04	$	0.12		$	0.05	$	0.04
Weighted average shares outstanding:
Basic		36,098,212		47,445,178			51,292,810		51,409,340
Diluted		37,845,212		49,229,042			53,174,792		53,072,619

1   The sum of net income per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

2   No income tax was recognized during the three months ended November 30, 2011 as the provision for tax at the effective rate was offset by a change in the valuation allowance.

3   For the three months ended February 29, 2012, the entire valuation allowance of $4.9 million was released and a net deferred tax benefit of $3.2 million was recorded.

4   For the three months ended August 31, 2013, income taxes were provided at a higher than expected rate due to a downward adjustment in the deferred tax asset related to the expiration of underlying stock options.

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STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Accumulated Earnings (Deficit) [Member]
Balance at Aug. 31, 2010	$ (1,016)	$ 14	$ 22,309	$ (23,339)
Balance, shares at Aug. 31, 2010	13,510,981	13,510,981
Shares issued pursuant to conversion of debt and accrued interest	14,914	10	14,904
Shares issued pursuant to conversion of debt and accrued interest, shares		9,979,376
Reclassification of derivative conversion liability to equity pursuant to early conversion of debt	19,554		19,554
Shares issued for Orr Energy acquisition, shares
Shares issued in exchange for mineral leases and services	5,670	2	5,668
Shares issued in exchange for mineral leases and services, shares	1,864,838	1,999,838
Shares issued in exchange for oil and gas assets, related party	4,698	1	4,697
Shares issued in exchange for oil and gas assets, related party, shares	1,864,838	1,381,818
Shares issued for cash, net of offering costs	16,691	9	16,682
Shares issued for cash, net of offering costs, shares	9,000,000	9,000,000
Shares issued pursuant to conversion of Series D warrants on a cashless basis
Shares issued pursuant to conversion of Series D warrants on a cashless basis, shares		226,199
Stock based compensation	197		197
Stock based compensation, shares
Net income (loss)	(11,600)			(11,600)
Balance at Aug. 31, 2011	49,108	36	84,011	(34,939)
Balance, shares at Aug. 31, 2011	36,098,212	36,098,212
Reclassification of derivative conversion liability to equity pursuant to early conversion of debt
Shares issued for Orr Energy acquisition, shares
Shares issued in exchange for mineral leases and services	1,999	1	1,998
Shares issued in exchange for mineral leases and services, shares	669,765	669,765
Shares issued in exchange for oil and gas assets, related party, shares	669,765
Shares issued for cash, net of offering costs	37,422	15	37,407
Shares issued for cash, net of offering costs, shares	14,363,363	14,636,363
Stock based compensation	460		460
Stock based compensation, shares		5,000
Net income (loss)	12,124			12,124
Balance at Aug. 31, 2012	101,113	52	123,876	(22,815)
Balance, shares at Aug. 31, 2012	51,409,340	51,409,340
Reclassification of derivative conversion liability to equity pursuant to early conversion of debt
Shares issued for Orr Energy acquistion	13,518	3	13,515
Shares issued for Orr Energy acquisition, shares	3,128,422	3,128,422
Shares issued in exchange for mineral leases and services	3,166	1	3,165
Shares issued in exchange for mineral leases and services, shares	3,815,544	687,122
Shares issued in exchange for oil and gas assets, related party, shares	687,122
Shares issued for cash, net of offering costs	78,243	13	78,230
Shares issued for cash, net of offering costs, shares	13,225,000	13,225,000
Shares issued for exercise of warrants	3,275	1	3,274
Shares issued for exercise of warrants, shares		1,052,698
Taxes paid on stock option exercise	(6,990)		(6,990)
Shares issued for exercise of stock option		1	(1)
Shares issued for exercise of stock option, shares		1,030,057
Stock based compensation	1,314		1,314
Stock based compensation, shares		55,084
Net income (loss)	9,581			9,581
Balance at Aug. 31, 2013	$ 203,220	$ 71	$ 216,383	$ (13,234)
Balance, shares at Aug. 31, 2013	70,587,723	70,587,723

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Acquisition

12 Months Ended

Aug. 31, 2013

Acquisition [Abstract]

Acquisition

3.   Acquisition

On October 23, 2012, the Company entered into a definitive purchase and sale agreement ("the Agreement"), with Orr Energy, LLC ("Orr"), for its interests in 36 producing oil and gas wells and approximately 3,933 gross (3,196 net) mineral acres (the "Orr Assets"). On December 5, 2012, the Company closed the transaction for a combination of cash and stock.  Orr received 3,128,422 shares of the Company's common stock valued at $13.5 million and cash consideration of approximately $29.0 million. Transaction costs related to the acquisition were approximately $109,000, all of which were recorded in the statement of operations within the general and administrative expenses line item for the twelve months ended August 31, 2013.   No material costs were incurred for the issuance of the shares of common stock.

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 December 5, 2012.  The following table summarizes the purchase price and final allocations of the fair value of the assets acquired and liabilities assumed (in thousands):

Purchase Price	December 5, 2012
Consideration Given
Cash	$	29,012
Synergy Resources Corp. Common Stock *		13,515
Total consideration given	$	42,527
Allocation of Purchase Price
Proved oil and gas properties	$	43,143
Unproved oil and gas properties		466
Total fair value of oil and gas properties acquired		43,609
Working capital	$	(842	)
Asset retirement obligation		(240	)
Fair value of net assets acquired	$	42,527
Working capital acquired was estimated as follows:
Accounts receivable		521
Accrued liabilities and expenses		(1,363	)
Total working capital	$	(842	)

*   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 5, 2012. (3,128,422 shares at $4.32 per share)

Pro Forma Financial Information

As stated above, on December 5, 2012, the Company completed an acquisition of oil and gas properties from Orr Energy.  Below are the combined results of operations for the twelve months ended August 31, 2013 and 2012 as if the acquisition had occurred on September 1, 2011 (in thousands, except per share data).

The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock, additional depreciation expense, costs directly attributable to the acquisition and costs incurred as a result of the Orr Energy acquisition. 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.

	For the years ended August 31,
	(Unaudited)
	2013		2012
Oil and Gas Revenues	$	47,760	$	32,188
Net income	$	10,118	$	14,870
Earnings per common share
Basic	$	0.17	$	0.30
Diluted	$	0.17	$	0.29

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Commodity Derivative Instruments (Schedule of Gain (Loss) Recognized in Statements of Operations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Commodity Derivative Instruments [Abstract]
Unrealized loss on commodity derivatives	$ 2,649
Realized loss on commodity derivatives	395
Total loss	$ 3,044

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Other Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended		12 Months Ended
	Sep. 30, 2013	Jul. 18, 2013	Aug. 31, 2013
Other Commitments and Contingencies [Abstract]
Number of new wells under commitment	13	25
Expected future costs	$ 5,200	$ 25,600	$ 19,900
Accrued costs			$ 5,700
Potential new wells under commitment	54

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Organization and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Aug. 31, 2013

Organization and Summary of Significant Accounting Policies [Abstract]

Schedule of Capitalized Overhead

	For the Years Ended August 31,
	2013		2012		2011
Capitalized overhead	$	637	$	345	$	206

Schedule of Derivative Conversion Liability

	For the Years Ended August 31,
	(in thousands)
	2013		2012		2011
Non-cash expense recognized related to the change in
the fair value of derivative conversion liabilities	$	-	$	-	$	10,229
Derivative conversion liabilities recognized in additional
paid-in-capital	$	-	$	-	$	19,554

Schedule of Major Customers

	For the Years Ended August 31,
	2013	2012	2011
Company A	50%	68%	75%
Company B	15%	11%	21%

	As of August 31,
	2013	2012	2011
Company A	24%	35%	31%
Company B	23%	30%	31%
Company C	12%	*	13%
* less than 10%

Schedule of Earnings Per Share

	For the Years Ended August 31,
	2013		2012		2011
Weighted-average shares outstanding - basic		57,089,362		46,587,558		26,009,283
Potentially dilutive common shares from:
Stock options		1,881,682		1,380,861		-
Warrants		117,717		391,486		-
Weighted-average shares outstanding - diluted		59,088,761		48,359,905		26,009,283

Schedule of Potentially Dilutive Securities

	For the Years Ended August 31,
	2013		2012		2011
Potentially dilutive common shares from:
Stock options		670,000		2,495,000		4,645,000
Warrants		8,500,000		14,098,000		14,931,067
Total		9,170,000		16,593,000		19,576,067

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Unaudited Oil and Gas Reserves Information (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Aug. 31, 2013	Aug. 31, 2012	Aug. 31, 2011
Unaudited Oil and Gas Reserves Information [Abstract]
Standardized measure, beginning of year	$ 102,505	$ 57,550	$ 13,022
Sale and transfers, net of production costs	(38,569)	(21,321)	(8,337)
Net changes in prices and production costs	(4,550)	(6,023)	15,484
Extensions, discoveries, and improved recovery	70,191	69,073	13,693
Changes in estimated future development costs	(6,006)	(42,578)	(20,471)
Development costs incurred during the period	5,106	39,739	16,252
Revision of quantity estimates	(14,214)	21,058	15,424
Accretion of discount	35,103	15,379	3,245
Net change in income taxes	(7,850)	(30,832)	(12,012)
Purchase of reserves in place	40,016	460	21,250
Standardized measure, end of year	$ 181,732	$ 102,505	$ 57,550

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Related Party Transactions and Commitments (Tables)

12 Months Ended

Aug. 31, 2013

Related Party Transactions and Commitments [Abstract]

Schedule of Mineral Assets Acquired From Related Party

	For the Years Ended August 31,
	2013		2012		2011
Consideration for certain mineral assets:
Cash payments for certain mineral assets	$	-	$	-	$	10,000
Value of restricted shares of common stock		-		-		4,698
Promissory note		-		-		5,200
Total	$	-	$	-	$	19,898
Subsequent settlement of amounts owing:
Repayment of promissory note	$	-	$	5,200	$	-
Payment of interest on promissory note		-		142		-
Total	$	-	$	5,342	$	-

Schedule of Other Related Party Transactions

	For the Years Ended August 31,
	2013		2012		2011
Beginning balance due to PM	$	-	$	-	$	539
Purchase of equipment from PM		-		-		2
Payments to PM for equipment		-		-		(541	)
Ending balance due to PM for equipment	$	-	$	-	$	-
Beginning balance due from PEM	$	-	$	-	$	868
Joint interest costs billed to PEM		-		-		396
Amounts collected from PEM		-		-		(1,264	)
Ending balance due from PEM	$	-	$	-	$	-

Schedule of Rent Expense

	For the Years Ended August 31,
	2013		2012		2011
Rent expense	$	130	$	120	$	120

Schedule of Share-based Compensation Provided to Related Party

	For the Years Ended August 31,
	2013		2012		2011
Restricted shares of common stock		-		188,137		40,000
Value of restriced shares of common stock (in thousands)	$	-	$	491	$	164

Schedule of Royalty Expense

	For the Years Ended August 31,
	2013		2012		2011
Total Royalty Payments	$	304	$	196		N/A

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Related Party Transactions and Commitments

12 Months Ended

Aug. 31, 2013

Related Party Transactions and Commitments [Abstract]

Related Party Transactions and Commitments

13.   Related Party Transactions and Commitments

Two of the Company's executive officers control three entities that have entered into agreements to provide various goods, services, facilities, and oil and gas properties to the Company.  The entities are Petroleum Management, LLC ("PM"), 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 completed two transactions under which it acquired oil and gas assets from PEM, as outlined below.

In May 2011, PEM sold all of its operating oil and gas assets (excluding passive assets such as royalty interests) to the Company.  Pursuant to the terms of the Purchase and Sale Agreement, as approved by its shareholders, the Company acquired a working interest in operating oil and gas wells and certain other mineral assets in a transaction that closed on May 24, 2011.  The purchase price consisted of a combination of cash, 1,381,818 shares of restricted common stock, and a note payable, as detailed in the table below (in thousands)  In November 2011, the Company utilized proceeds from the LOC (Note 6) to repay the entire principal balance and accrued interest.

	For the Years Ended August 31,
	2013		2012		2011
Consideration for certain mineral assets:
Cash payments for certain mineral assets	$	-	$	-	$	10,000
Value of restricted shares of common stock		-		-		4,698
Promissory note		-		-		5,200
Total	$	-	$	-	$	19,898
Subsequent settlement of amounts owing:
Repayment of promissory note	$	-	$	5,200	$	-
Payment of interest on promissory note		-		142		-
Total	$	-	$	5,342	$	-

In a separate transaction that closed in October 2010, the Company acquired with cash certain mineral assets located in the Wattenberg Field of the D-J Basin, from PM and PEM.  The assets acquired included working interests in certain operating oil and gas wells, drill sites, and miscellaneous equipment for a purchase price of $1,017,435.

Other Related Party Transactions:  In addition to the transactions described above, the Company undertook various activities with PM and PEM that are related to the development and operation of oil and gas properties.  The Company occasionally purchased services and certain oil and gas equipment, such as tubular goods and surface equipment, from PM.  The Company reimbursed PM for the original cost of such services and equipment.  Prior to the asset acquisition transaction that closed on May 24, 2011, PEM was a joint working interest owner of certain wells operated by the Company.  PEM was charged for its pro-rata share of costs and expenses incurred on its behalf by the Company, and similarly, PEM was credited for its pro-rata share of revenues collected on its behalf.  Effective with the closing of the asset acquisition, the related party transactions of this nature have ceased.

The following table summarizes the transactions with PM and PEM during the fiscal years presented (in thousands):

	For the Years Ended August 31,
	2013		2012		2011
Beginning balance due to PM	$	-	$	-	$	539
Purchase of equipment from PM		-		-		2
Payments to PM for equipment		-		-		(541	)
Ending balance due to PM for equipment	$	-	$	-	$	-
Beginning balance due from PEM	$	-	$	-	$	868
Joint interest costs billed to PEM		-		-		396
Amounts collected from PEM		-		-		(1,264	)
Ending balance due from PEM	$	-	$	-	$	-

Facilities and Services Agreements:  The Company leases office space and an equipment storage yard in Platteville, Colorado, under a twelve month lease agreement with HSLC. The lease is renewable annually.  Under this agreement, the Company incurred the following expenses to HSLC for the fiscal years presented (in thousands):

	For the Years Ended August 31,
	2013		2012		2011
Rent expense	$	130	$	120	$	120

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, as follows:

	For the Years Ended August 31,
	2013		2012		2011
Restricted shares of common stock		-		188,137		40,000
Value of restriced shares of common stock (in thousands)	$	-	$	491	$	164

Effective January 1, 2012, the Company commenced processing its own oil and gas revenues.  Payments to royalty 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 fiscal years presented (in thousands):
 

	For the Years Ended August 31,
	2013		2012		2011
Total Royalty Payments	$	304	$	196		N/A