SEC Info - Synergy Resources Corp - ‘ARS/A’ for 12/31/14

BUSINESS

Overview

We are an oil and natural gas operator 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. For the prospects in which we own a minority mineral interest, we participate with other companies that drill and operate wells.

We commenced active operations in the D-J Basin in 2008. For the first four years of active operations, our focus was primarily on participating in and completing vertical wells. Beginning in fiscal 2013, our focus shifted towards drilling and completing horizontal wells. Our use of the term horizontal well includes wells where the productive length of the wellbore is drilled more or less horizontal to the earth’s surface, to intersect the target formation on a parallel basis. In contrast, the term vertical well includes directional wells that are drilled at an angle toward a target area and where the productive length of the wellbore intersects the target formation on a perpendicular basis. The productive length of the wellbore in a horizontal well is much greater than the productive length of a vertical well, which results in a longer wellbore and a higher completion volume. As of August 31, 2014, we had completed, participated in or otherwise acquired an interest in 404 gross (284 net) producing oil and gas wells, of which 334 gross (250 net) were vertical wells and 70 gross (34 net) were horizontal wells. We are the operator of 300 producing wells and participate with other operators in 104 producing wells. In addition to the wells that had reached productive status at the end of our fiscal year, there are 53 gross (14 net) wells in various stages of drilling or completion as of August 31, 2014.

Our daily production increased significantly during fiscal 2014 as new horizontal wells commenced productive operations. Our average production rate for fiscal 2014 was 4,290 barrels of oil equivalent per day (“BOED”). During fiscal 2013, our average production rate was 2,117 BOED. More significantly, our production rate for the fourth quarter of 2014 was 5,894 BOED, compared to 2,479 BOED during the fourth quarter of 2013. By the end of 2014, over 80% of our daily production was from horizontal wells. At the beginning of 2014, less than 10% of our production was from horizontal wells.

During fiscal 2014, we also continued to increase our estimated reserves and mineral leasehold acres. At August 31, 2014, our estimated net proved oil and gas reserves, as prepared by our independent reserve engineering firm, Ryder Scott Company, L.P., were 16.3 MMBbls of oil and condensate and 95.2 Bcf of natural gas. As of August 31, 2014, we had 451,000 gross and 309,000 net acres under lease, substantially all of which are located in the D-J Basin. We further classify our acreage into specific areas, including Wattenberg Field (46,000 gross and 31,000 net acres), Northern Extension Area (122,000 gross and 26,000 net acres), Eastern Colorado (90,000 gross and 64,000 net acres), and Western Nebraska (185,000 gross and 183,000 net acres).

In addition to the approximately 31,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold approximately 26,000 undeveloped acres in an area directly to the north and east of the Wattenberg Field that is considered the Northern Extension area. We are currently permitting twelve wells targeting the Greenhorn formation on our leasehold in this area and plan to spud the first well in early calendar year 2015. We have a significant leasehold of undeveloped acreage in western Nebraska. We have entered into a joint exploration agreement with a private operating company based in Denver to drill up to ten wells in this area. We expect drilling activities to commence in Nebraska before December 31, 2014. We also have mineral assets in Yuma and Washington Counties, Colorado that are in an area that has a history of dry gas production from the Niobrara formation.

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.

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Develop and exploit existing oil and natural gas properties. Since inception our principal growth strategy has been to develop and exploit our acquired and leased properties to add proved reserves. In the Wattenberg Field, we target three benches of the Niobrara, and the Codell formations for horizontal drilling and production. Our plans focus on horizontal development of our assets in the Wattenberg Field as we believe horizontal drilling is the most efficient manner to recover the potential hydrocarbons. 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.

Improve hydrocarbon recovery through increased well density. Use best available geological practices to determine optimum recovery area for each well. We have identified 932 potential horizontal wells in the Niobrara and Codell formations on existing Wattenberg acreage based on 21 wells per 640 acre sections and over 800 potential horizontal well locations in the Greenhorn and Niobrara formations in the Northern Wattenberg extension area in the D-J Basin.

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 strive to be, and have historically been, a low-cost operator in the D-J Basin. Central to our operating strategy is maintaining low debt levels, low general and administrative costs and low well completion costs, each of which is enabled by our ability to stay highly involved in our development, our emphasis on short time horizons for returns on our investment, as well as our focus on operating efficiencies and cost reductions. We intend to finance our operations through a mixture of cash from operations, debt and equity capital as market conditions allow.

Use the latest technology to maximize returns. Beginning in fiscal 2013, we shifted our emphasis away from drilling vertical wells towards drilling horizontal wells. In doing so, we have significantly increased our production and the value of our asset base. While horizontal drilling requires higher up-front costs, these wells ultimately have a higher return on investment. 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 are currently utilizing both “sliding sleeve” and “plug and perf liner” technologies to stimulate multi-stage horizontal wells. Production results from each technique are analyzed and the conclusions from each analysis are factored into future well design, considering the interactions between wellbore conditions, lateral length, timing and economics. Similarly, we evaluate the use of different completion fluids ranging from slick-water to gelled fluids, and different combinations thereof.

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. During 2014 we drilled one test well that was immediately plugged and abandoned. Results from the test well were encouraging and our 2015 plans include additional drilling in that area. We also drilled 11 horizontal wells that are classified as exploratory. Although the wells were drilled in an area that contained productive vertical wells, the area had not been proved on a horizontal basis. Therefore, the new wells met the definition of exploratory wells.

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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 as of August 31, 2014.

	Years Ended August 31,
	2014		2013		2012
	Gross	Net	Gross	Net	Gross	Net
Development Wells:
Productive:
Oil	47	22	48	32	64	52
Gas	2	1	—	—	—	—
Nonproductive	—	—	—	—	—	—
Exploratory Wells:
Productive:
Oil	11	10	—	—	—	—
Gas	—	—	—	—	—	—
Nonproductive	1	—	—	—	—	—

There were 53 gross (14.2 net) wells in progress that were not included in the above well counts. All of the oil wells are located in, or adjacent to, the Wattenberg Field of the D-J Basin. Two gas wells are located in Yuma County, Colorado.

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,
	2014		2013		2012
Production:
Oil (Bbls¹)		941,218		421,265		235,691
Gas (Mcf²)		3,747,074		2,107,603		1,109,057
BOE³		1,565,729		772,532		420,534

Average sales price:
Oil ($/Bbl)	$	89.98	$	85.95	$	87.59
Gas ($/Mcf)	$	5.21	$	4.75	$	3.90
BOE	$	66.56	$	59.83	$	59.37

Average production cost per BOE	$	5.10	$	4.42	$	2.73

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 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 experienced an increase in production costs as we transitioned to horizontal wells. In their initial months, horizontal wells have been more expensive to operate. We expect the operating costs to stabilize as the wells mature.

We are not currently obligated to provide a fixed and determined quantity of oil or gas to any third party. 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.

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Oil and Gas Properties, Wells, Operations and Acreage

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.

We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

·	royalties and other burdens and obligations, express or implied, under oil and gas leases;

·	overriding royalties and other burdens created by us or our predecessors in title;

·	a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles;

·	back-ins and reversionary interests existing under purchase agreements and leasehold assignments;

·	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and communitization agreements, declarations and orders; and

·	easements, restrictions, rights-of-way and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind that we own.

The following table shows, as of October 10, 2014, 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		404		284		16,312		12,155		252,642		116,131
Nebraska		—		—		—		—		185,988		183,589
Wyoming		—		—		—		—		1,143		472
Kansas		—		—		—		—		840		840
Total		404		284		16,312		12,155		440,613		301,032

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 oil and natural gas regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.

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The following table shows, as of October 10, 2014, the status of our gross acreage:

State	Held by Production		Not Held by Production

Colorado		16,312		252,642
Nebraska		—		185,988
Wyoming		—		1,143
Kansas		—		840
Total		16,312		440,613

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 may 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.

The following table shows the calendar years during which 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

75,196		2015
45,079		2016
42,693		2017
277,645		After 2017

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

Oil and Gas Reserves

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, 2014. 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.

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.

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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, 2014, 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 31, 2014.

Below are estimates of our net proved reserves at August 31, 2014, all of which are located in Colorado:

	Oil		Gas		BOE
	(Bbls)		(Mcf)
Proved:
Producing		4,537,061		25,921,459		8,857,304
Nonproducing		2,079,421		12,240,142		4,119,445
Undeveloped		9,708,471		57,016,746		19,211,262
Total		16,324,953		95,178,347		32,188,011

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, 2014, 2013 and 2012. 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.

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As of August 31, 2014, 2013 and 2012, our standardized oil and gas measurements were as follows (in thousands):

	Proved - August 31, 2014
	Developed									Total
	Producing			Nonproducing			Undeveloped			Proved
Future gross revenue	$	511,252		$	234,452		$	1,094,283		$	1,839,987
Deductions		(141,145	)		(78,393	)		(587,999	)		(807,537	)
Future net cash flow		370,107			156,059			506,284			1,032,450
Discounted future net cash flow (pre-tax)	$	250,749		$	76,593		$	206,356		$	533,698
Standardized measure of discounted future
net cash flows (after tax)										$	402,699


	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

For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2014, generated increases in projected future gross revenue from proved reserves of $1.1 billion and future net cash flow of $538.1 million from August 31, 2013. 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 $297.5 million. Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2014, of approximately $185 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, 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.

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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
Beginning September 1, 2012		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	)
Ending August 31, 2013		4,858,507
Converted to proved developed		(586,974	)
Additions from capital program		13,436,253
Acquisitions (sales)		1,522,445
Revisions (pricing and engineering)		(18,969	)
Ending August 31, 2014		19,211,262

At August 31, 2014, our proved undeveloped reserves were 19,211,262 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 2014, 586,974 Boe or 12% of our proved undeveloped reserves (5 horizontal wells) were converted into proved developed reserves requiring $14.9 million of drilling and completion capital expenditures. Executing our 2014 capital program resulted in the addition of 13,436,253 Boe in proved undeveloped reserves.

During 2014, a large percentage of our drilling budget was allocated to exploratory wells. During 2015, we expect to allocate a larger percentage to developmental wells. Additionally, to assist with our 2015 drilling schedule, we added a third rig in September 2014.

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.

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New Developments

On October 29, 2014, we entered into an agreement with three independent oil and gas companies to acquire oil and gas properties consisting of:

·	non-operated working interests in seventeen horizontal wells, ten of which are in production (including 4 mid-reach laterals) and 7 of which are in progress of completion;

·	73 operated and 11 non-operated vertical wells;

·	35 permit applications for operated horizontal wells (including 20 extended reach laterals);

·	5,040 gross acres (4,053 net) with rights to the Codell and Niobrara formations;

·	2,400 gross acres (1,739 net) with rights to other formations, including the Sussex Shannon and J-Sands;

·	3D seismic data; and

·	Miscellaneous equipment.

Working interests in the vertical wells range from 6% to 40%. Working interests in the vertical wells range from 5% to 100%. The producing oil and gas properties are located in the Wattenberg Field, which is part of the Denver-Julesburg Basin.

Preliminary estimates indicate that the undeveloped acreage will provide locations to drill 94 horizontal wells. The purchase price for the oil and gas properties, subject to ordinary closing adjustments, will be $125,000,000. The purchase price will be payable in cash of $87,500,000 and $37,500,000 in restricted shares of the Company's common stock. The closing of the acquisition is subject to the completion of title reviews by Synergy and other conditions which are normal for a transaction of this nature. Closing is anticipated on or around December 15, 2014.

Concurrent with entering into the purchase agreement, we entered into a new credit line, for which the initial borrowing base is $230 million. The borrowing base may increase or decrease in the future based upon the value of the collateral (subject to a maximum borrowing base of $500 million), which will secure any amounts borrowed under the line of credit. The interest rate on outstanding borrowings will be based upon a pricing grid, which escalates with utilization and establishes a minimum rate of 2.5%.

Also on October 29, 2014, our compensation committee approved amendments to the employment agreements of Ed Holloway and William E. Scaff, our Co-Chief Executive Officers, providing that the annual base salary for each of these officers will be increased to $999,900, effective November 1, 2014.

MARKET FOR COMMON STOCK

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 for the past two fiscal years.

Quarter Ended	High	Low
November 30, 2013	$11.40	$8.86
February 29, 2014	$10.69	$8.11
May 31, 2014	$12.96	$9.70
August 31, 2014	$14.11	$10.13

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

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As of October 10, 2014, the closing price of our common stock on the NYSE MKT was $10.19.

As of October 10, 2014, we had 79,293,688 outstanding shares of common stock and 131 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.

The performance graph below compares the cumulative total return of our common stock over the five-year period ended August 31, 2014, 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, 2009 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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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,
	2014			2013		2012		2011			2010
Results of Operations (in thousands):
Revenues	$	104,219		$	46,223	$	24,969	$	10,002		$	2,158
Net income (loss)		28,853			9,581		12,124		(11,600	)		(10,794	)

Net income (loss) per common share:
Basic	$	0.38		$	0.17	$	0.26	$	(0.45	)	$	(0.88	)
Diluted	$	0.37		$	0.16	$	0.25	$	(0.45	)	$	(0.88	)

Certain Balance Sheet Information (in thousands):
Total Assets	$	448,542		$	291,236	$	120,731	$	63,698		$	24,842
Working Capital		(35,338	)		50,608		10,875		685			6,237
Total Liabilities		167,052			88,016		19,619		14,590			25,859
Equity (Deficit)		281,490			203,220		101,112		49,108			(1,017	)

Certain Operating Statistics:
Production:
Oil (Bbls)		941,218			421,265		235,691		89,917			21,080
Gas (Mcf)		3,747,074			2,107,603		1,109,057		450,831			141,154
Total production in BOE		1,565,729			772,532		420,534		165,056			44,606
Average sales price per BOE	$	66.56		$	59.83	$	59.38	$	59.24		$	48.39
LOE per BOE	$	5.10		$	4.42	$	2.89	$	2.94		$	1.94
DDA per BOE	$	21.05		$	17.26	$	14.29	$	16.62		$	15.52

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 2012, 2013 and 2014.

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

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, 2014, and the results of operations for the years ended August 31, 2014, 2013 and 2012. 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.

This section and other parts of this Annual Report contain forward-looking statements that involve risks and uncertainties. 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. Readers of this Annual Report are encouraged to review our Annual Report on 10-K in its entirety, and specifically Item 1A “Risk Factors,” before making investment decisions. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

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Overview

We are a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin (“D-J Basin”) of Colorado. The D-J Basin generally extends from the Denver metropolitan area throughout northeast Colorado into Wyoming, Nebraska and Kansas. It contains hydrocarbon bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand and D-Sand. The area known as the Wattenberg Field covers the western flank of the D-J basin, particularly in Weld County. The area has produced oil and gas for over fifty years and has a history as one of the most prolific production areas in the country. Substantially all of our producing wells are either in or adjacent to the Wattenberg Field.

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 of August 31, 2014, we have completed, acquired, or participated in 404 gross (284 net) successful oil and gas wells. We drilled one exploratory test well during fiscal 2014, which was immediately plugged and abandoned. The following tables summarize activity with respect to operated and non-operated vertical and horizontal wells during the last three years:

	VERTICAL WELLS
	OPERATED WELLS				NON-OPERATED WELLS
	Completed				Participated				Acquired				Total
Years ended:	Gross		Net		Gross		Net		Gross		Net		Gross		Net

August 31, 2012		51		48		8		3		4		4		63		55
August 31, 2013		27		26		10		4		36		34		73		64
August 31, 2014		1		1		5		1		60		35		66		37

Total		79		75		23		8		100		73		202		156

	HORIZONTAL WELLS
	OPERATED WELLS				NON-OPERATED WELLS
	Completed				Participated				Acquired				Total
Years ended:	Gross		Net		Gross		Net		Gross		Net		Gross		Net

August 31, 2012		-		-		5		1		-		-		5		1
August 31, 2013		-		-		11		2		-		-		11		2
August 31, 2014		31		29		23		2		-		-		54		31

Total		31		29		39		5		-		-		70		34

As is evident in the tables above, we have undergone a shift in focus with respect to the types of wells we are completing. Whereas early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations, in May 2013, development efforts have shifted to horizontal wells. Horizontal wells are significantly more expensive and take longer to drill and complete than vertical wells, but ultimately generally yield a greater return. We substantially completed five Renfroe wells during 2013 and they commenced production during September 2013. During fiscal 2014, we also commenced production from 26 wells in the Leffler, Phelps, Union, Eberle and Kelly Farms prospects.

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In addition to the 404 wells that had reached productive status as of August 31, 2014, we were the operator of 10 horizontal wells in progress. Two of those wells, including one well on the Eberle prospect and one well on the Phelps prospect, commenced production early in September 2014. We were participating as a non-operator in 43 gross (6 net) horizontal wells that were in various stages of the drilling or completion process. Generally, horizontal wells on a six well pad are expected to require 120 to 150 days to drill, complete and connect to the gathering system.

As of August 31, 2014, we:

·	were the operator of 31 horizontal wells that were producing oil and gas and we were participating as a non-operating working interest owner in 39 horizontal producing wells;

·	were the operator of 269 vertical wells that were producing oil and gas and we were participating as a non-operating working interest owner in 65 producing wells;

·	were the operator of 10 wells in progress and we were participating as a non-operating working interest owner in 43 wells in progress;

·	held approximately 451,000 gross acres and 309,000 net acres under lease; and

·	had estimated proved reserves of 16.3 million barrels (“Bbls”) of oil and 95.2 billion cubic feet (“Bcf”) of gas.

During our fiscal year ended August 31, 2014, we increased our estimated proved reserves by 133% on a BOE equivalent basis and increased our estimated proved reserves by 126% on a PV-10 basis. During the last three months of the fiscal year ended August 31, 2014, we commenced production on three pads in the Wattenberg field, which significantly increased our BOE production. Our consolidated daily production from our producing wells increased during fiscal 2014 from 2,479 BOED as of August 31, 2013 to 5,894 BOED as of August 31, 2014.

Strategy

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 have been, and for the foreseeable future will continue to be, focused on the Wattenberg Field as it yields consistent results. Our drilling strategy has shifted during the past two years to focus our efforts towards drilling horizontal wells. During the year ended August 31, 2014, we drilled or participated in 31 net horizontal wells and substantially ceased completion and re-completion of our vertical wells. Our plans for 2015 contemplate drilling or participating in 41 to 48 net horizontal wells.

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. We had also arranged for a bank credit facility to fund our liquidity needs. During fiscal 2014, our primary source of capital resources was cash on hand at the beginning of the year, cash flow from operations and proceeds from the exercise of warrants. We plan to continue to finance an increasing percentage of our growth with internally generated funds. Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain. For more information, see “Liquidity and Capital Resources.”

2014 Operational and Financial Summary

We continued to expand our business during the fiscal year ended August 31, 2014. During the year, we:

·	increased production and sale of hydrocarbons by 123%;

·	commenced production from 31 new company operated horizontal wells;

·	commenced production from 3 (net) non-operated wells;

·	acquired producing properties and undeveloped acreage in two significant acquisitions described below under “2014 acquisitions” and

·	increased reserves by 133%.

These activities were funded with cash on hand at the beginning of the year and cash flow from operations. Significant developments are described in greater detail later in this document.

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Drilling operations

As an operator, we successfully transitioned from a focus on vertical drilling to horizontal drilling. Horizontal wells are significantly more expensive and take longer to drill and complete than vertical wells, but ultimately yield a greater return. As we transitioned toward horizontal drilling, we substantially ceased completion and re-completion of our vertical wells. Accordingly, our cost structure for both our capitalized well costs and our monthly operating costs has transformed significantly over the last two years.

After initiating horizontal drilling in May 2013, production from our first five horizontal wells at our Renfroe location began in September 2013. Subsequently, we drilled, completed and initiated production at the following locations: Leffler (6 wells), Phelps (5 wells), Union (6 wells), Eberle (5 wells) and Kelly Farms (4 wells). As of August 31, 2014, one additional well at Phelps and one additional well at Eberle had been drilled but not reached first production. Both wells began producing during September 2014.

Additionally, as of August 31, 2014, we had two locations where drilling operations are in progress. We have drilled four wells at the Weld 152 location and four wells at the Kiehn location. These eight wells are waiting on completion.

Our horizontal wells are currently being drilled under contracts with Ensign United States Drilling, Inc. (“Ensign”). The initial contract, as amended, covered the use of one rig to drill a total of 25 wells. To date, pricing is on a turn-key basis, with pricing adjustments based upon well location, target formation, and other technical details. Based upon our initial success with horizontal drilling at the Renfroe and Leffler prospects, we negotiated another drilling contract with Ensign to use one automated drilling rig for one year, commencing in January 2014. We contracted a third Ensign rig in September 2014 to drill eight wells on our Wiedeman pad, which is expected to finish in January 2015. At the conclusion of each contract, we have the option to continue use of the rigs. As currently structured, our capital expenditure plans for fiscal 2015 contemplate the use of two rigs for the entire year and use of the third rig for part of the year.

As a result of our drilling, acquisition and participation activities, we increased our estimated proved reserve quantities by 133% during the year. Our August 31, 2014, reserve report indicated that we had estimated proved reserves of 16.3 million barrels of oil and 95.2 billion cubic feet of gas. The estimated present value of future cash flows before tax (discounted at 10%) was $534 million.

During the last three months of the fiscal year ended August 31, 2014, we commenced production on three pads in the Wattenberg field, which significantly increased our daily production rate. Our consolidated daily production from producing wells increased during fiscal 2014 from 2,479 BOED as of August 31, 2013 to 5,894 BOED as of August 31, 2014.

2014 acquisitions

During the year, we completed two significant producing property acquisitions. On November 12, 2013, we acquired 21 net producing oil and gas wells along with leases covering 800 net acres from Trilogy Resources, LLC. Total consideration for the Trilogy assets included $16.0 million in cash and 301,339 shares of restricted common stock. On November 13, 2013, we acquired 38 operated wells (13 net) producing oil and gas wells along with leases covering 1,000 net acres from Apollo Operating LLC. The Apollo assets included non-operating interests in six wells we had drilled and completed and a 25% working interest in a Class II disposal well. Total consideration for the Apollo assets included $11.0 million in cash and 550,518 shares of restricted common stock. In several subsequent transactions, we acquired the remaining 75% interests in the Class II disposal well for cash and stock consideration aggregating $3.9 million.

On November 13, 2013, we acquired 38 wells (13 net) producing oil and gas wells along with leases covering 800 net acres from Apollo Operating LLC. The Apollo assets included non-operating interest in six wells we had drilled and completed and a 25% working interest in a Class II disposal well. Total consideration for the Apollo assets included $11.0 million in cash and 550,518 shares of restricted common stock.

Subsequently, in a separate transaction, we acquired the remaining 75% interests in the Class II disposal well for approximately approximated $3.9 million.

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Financing updates

We continue to improve our borrowing arrangement with a bank syndicate led by Community Banks of Colorado. Maximum borrowings are subject to adjustment based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports. 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 2013 and June 2014, we modified our borrowing arrangement to increase the maximum allowable borrowings. In December 2013, the arrangement was modified to increase the maximum lending commitment to $300 million from $150 million, to increase the borrowing base to $90 million, and to increase the number of banks involved in the borrowing arrangement. Based upon the semi-annual redetermination derived from the February 28, 2014 reserve report, the arrangement was further modified in June 2014 to increase the borrowing base to $110 million, to adjust the financial ratio compliance requirements, and to extend the maturity date to May 29, 2019. The next scheduled redetermination is currently in progress and will adjust the borrowing arrangement based upon our August 31, 2014 reserve report.

Interest accrues at a variable rate equal to or greater than a 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 0.5% to 1.5%, or the London InterBank Offered Rate plus a margin of 1.75% to 2.75%.

Commodity contracts

We utilize swaps and collars to reduce the effect of price changes on a portion of our future oil and gas production. Our objective in using derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. Using swaps and collars, we have contracted for approximately 1.1 million barrels of oil and 1.7 million mcf of gas through December 31, 2016. Since we designed our commodity derivative activity to protect our cash flow during periods of oil and gas price declines, the high average prices experienced during 2014 created a realized loss of $2.1 million for the year. The decline in posted prices at the end of our fiscal year created an unrealized increase in the fair value of our commodity derivatives of $2.5 million.

Market conditions

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

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

For the periods presented in this report, the following table presents the average NYMEX price as well as the differential between the NYMEX prices and the wellhead prices realized by us.

Fiscal years ended:	August 31,
	2014			2013			2012
Oil (NYMEX WTI)
Average NYMEX Price	$	100.39		$	94.58		$	94.88
Realized Price	$	89.98		$	85.95		$	87.59
Differential	$	(10.41	)	$	(8.63	)	$	(7.29	)

Gas (NYMEX Henry Hub)
Average NYMEX Price	$	4.38		$	3.55		$	2.82
Realized Price	$	5.21		$	4.75		$	3.90
Differential	$	0.83		$	1.20		$	1.08

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The negative differential has increased during our 2014 fiscal year. However, we are able to sell gas at prices greater than the posted prices, primarily because prices we receive include payment for the natural gas liquids produced with the gas.

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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, 2014, compared to the year ended August 31, 2013

For the year ended August 31, 2014, we reported net income of $28.9 million compared to net income of $9.6 million for the twelve months ended August 31, 2013. Earnings per basic and diluted share were $0.38 per basic and $0.37 per diluted share for the year ended August 31, 2014 compared to $0.17 per basic and $0.16 per diluted share during the same period one year prior. Rapid growth in reserves, producing wells and daily production totals, as well as the impact of changing prices on our commodity hedge positions drove this increase. The significant variances between the two years were primarily caused by increased revenues and expenses associated with production from 31 new horizontal wells and the acquisition of producing properties included in the Trilogy and Apollo transactions. 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, 2014, we recorded total oil and gas revenues of $104.2 million compared to $46.2 million for the year ended August 31, 2013, an increase of $58.0 million or 125%.

As of August 31, 2014, we owned interests in 404 producing wells. Net oil and gas production averaged 4,290 BOE per day in fiscal 2014, compared to 2,117 BOE per day for 2013, a year-over-year increase of 103% in BOEPD production. The significant increase in production from the prior year reflects our increased well count and shift to horizontal wells.

Our rate of growth was even more pronounced at the end of our fiscal year. During the fourth quarter of 2014, we completed 15 new horizontal wells. Production for the fourth fiscal quarter of 2014 averaged 5,894 BOE per day.

Our revenues are sensitive to changes in commodity prices. As shown in the following table, there has been an increase of 11% in average realized sales prices between 2013 and 2014. The following table presents actual realized prices, without the effect of hedge transactions. The impact of hedge transactions is presented later in this discussion.

Key production information is summarized in the following table:

	Years Ended August 31,
	2014		2013
Production:
Oil (Bbls¹)		941,218		421,265
Gas (Mcf²)		3,747,074		2,107,603

Total production in BOE³		1,565,729		772,532

Revenues (in thousands):
Oil	$	84,693	$	36,206
Gas		19,526		10,017
	$	104,219	$	46,223
Average sales price:
Oil	$	89.98	$	85.95
Gas	$	5.21	$	4.75
BOE	$	66.56	$	59.83

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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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 (in thousands):

	Years Ended August 31,
	2014		2013
Production costs	$	7,794	$	3,198
Work-over		197		219
Lifting cost		7,991		3,417
Severance and ad valorem taxes		9,667		4,237
Total LOE	$	17,658	$	7,654

Per BOE:
Production costs	$	4.98	$	4.14
Work-over		0.12		0.28
Lifting cost		5.10		4.42
Severance and ad valorem taxes		6.17		5.48
Total LOE	$	11.27	$	9.90

Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas. Taxes make up the largest single component of direct costs and tend to increase or decrease primarily based on the value of oil and gas sold. As a percentage of revenues, taxes averaged 9.3% in 2014 and 9.2% in 2013.

From 2013 to 2014, we experienced an increase in production cost per BOE in connection with additional costs to bolster output from some of our older wells as well as additional costs to operate horizontal wells. We continue to work diligently to mitigate production difficulties within the Wattenberg Field. Additional wellhead compression has been added at some well locations and older equipment has been replaced or refurbished. During 2014, we incurred additional costs related to the integration of the newly acquired producing properties. In particular, the acquisition of a disposal well in one of the acquisitions added to our average cost per BOE, as the disposal well has a slightly different cost profile than our other wells. As expected, horizontal wells are more costly to operate than vertical wells, especially during the early stages of production. Finally, costs incurred to comply with new environmental regulations are significant.

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

	Years ended August 31,
(in thousands)	2014		2013
Depletion	$	32,132	$	13,046
Depreciation and amortization		826		290
Total DDA	$	32,958	$	13,336

DDA expense per BOE	$	21.05	$	17.26

For the year ended August 31, 2014, depletion of oil and gas properties was $21.05 per BOE compared to $17.26 for the year ended August 31, 2013. The increase in the DDA rate was the result of an increase in both the ratio of reserves produced and the total costs capitalized in the full cost pool. 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 2014, production represented 4.6% of our reserve base compared to 5.2% for the year ended August 31, 2013. A contributing factor to the change in the ratio was the inclusion of additional horizontal wells in the calculation. Consistent with the expected decline curve for wells targeting the Niobrara and Codell formations, we expect horizontal wells to exhibit robust production during the first few weeks, decline rapidly over the first six months, and eventually stabilize over an expected life in excess of 30 years. However, the initial reserve estimates for horizontal wells have not incorporated all of the reserves that may ultimately be recovered. The initial reserves estimated for horizontal development prospects have been prepared using an average of 80 acre spacing, compared to 20 acre spacing for vertical well development. As we gain more experience with the development of horizontal sections, we believe that spacing units will decrease, effectively increasing the EUR for each section.

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In addition to a change in the ratio of production to EUR, our DDA rate was affected by the increasing costs of mineral leases, included as proven properties, and the costs associated with the acquisition of producing properties. Leasing costs in the D-J Basin continue to increase with the success of horizontal development. For acquisition of producing properties, substantially all of the costs are allocated to proved reserves and included in the full cost pool. The allocation of the purchase price related to the November 2013 Trilogy and Apollo acquisitions was at a higher cost per BOE than our historical cost of acquiring leaseholds and developing our properties. Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties. Both of these acquisitions include areas that have the potential for future development. Successful development of these areas that increased proved reserves would have the impact of reducing cost per BOE.

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

	Years Ended August 31,
(in thousands)	2014			2013
G&A costs incurred	$	11,369		$	6,325
Capitalized costs		(1,230	)		(637	)
Total G&A	$	10,139		$	5,688

G&A Expense per BOE	$	6.48		$	7.36

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. In an effort to minimize overhead costs, we employ a total staff of 29 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, 2014, G&A was $6.48 per BOE compared to $7.36 for the fiscal year ended August 31, 2013, primarily as a result of the increase in BOE produced during fiscal 2014.

Our G&A expense for 2014 includes share-based compensation of $3.0 million, compared to $1.4 million in 2013. 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 G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from 2013 to 2014 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 2014 or 2013. The interest costs that we incurred under our credit facility were eligible for capitalization into the full cost pool. We capitalize interest costs that are related to the cost of assets during the period of time before they are placed into service.

Commodity derivative gains (losses) – As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” and “Hedge Activity Accounting” located in “Liquidity and Capital Resources,” we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas. In the year ended August 31, 2014, we realized a cash settlement loss of $2.1 million related to contracts that settled during the period. For the year ended August 31, 2013, we realized a cash settlement loss of $0.4 million.

In addition, we recorded an unrealized gain of $2.5 million to recognize the mark-to-market change in fair value of our futures contracts for the year ended August 31, 2014. In comparison, in the year ended August 31, 2013 we reported an unrealized loss of $2.6 million. Unrealized gains and losses are non-cash items.

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Income Taxes – We reported income tax expense of $15.0 million for the fiscal year ended August 31, 2014, calculated at an effective tax rate of 34%. During the comparable prior year, we reported income tax expense of $6.9 million, calculated at an effective tax rate of 42%. For both periods, it appears that the tax liability will be substantially deferred into future years. During fiscal year 2014, the effective tax rate was reduced from the federal and state statutory rate by the impact of deductions for percentage depletion.

For tax purposes, we have a net operating loss (“NOL”) carryover for federal purposes of $33.2 million and for state tax purposes of approximately $41.1 million, which is available to offset future taxable income and will expire, if not utilized, beginning in year 2031. For book purposes, the NOL is $22.5 million, as there is a difference of $10.7 million related to deductions for stock based compensation.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome. During 2014 and 2013, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carry-forward, and have therefore included it in our inventory of deferred tax assets.

Liquidity and Capital Resources

Historically, we have been reliant on net cash provided by sales and other issuances of equity and debt securities as a source of liquidity. We have also relied on 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, in the near future, the combination of cash on hand, cash flows from operations and 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.

Sources and Uses

At August 31, 2014, we had cash and cash equivalents of $34.8 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, 2014, 2013 and 2012, are summarized below (in thousands):

	Years Ended August 31,
	2014			2013			2012
Cash provided by operations	$	74,905		$	32,120		$	21,252
Capital expenditures		(155,602	)		(80,469	)		(46,751	)
Property conveyances		-			-			71
Cash used by other investing activities		60,722			(60,000	)		-
Cash provided by equity financing activities		35,265			74,528			37,421
Net borrowings		-			34,000			(2,200	)
Net increase in cash and equivalents	$	15,290		$	179		$	9,793

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. The increase in net cash provided by operations allowed us to become less reliant on equity sales for financing our capital expenditures in fiscal 2014.

Credit Arrangements

In December 2013 and June 2014, we modified our borrowing arrangements. The new revolving line of credit increases the maximum lending commitment to $300 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 primarily 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, 2014 reserve report, the borrowing base was increased to $110 million.

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We currently have approximately $73 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 0.5% to 1.5%, or the London InterBank Offered Rate plus a margin of 1.75% to 2.75%. The amended maturity date for the arrangement is May 29, 2019.

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Capital Requirements

Our primary need for cash will be to fund our drilling and acquisition programs for the fiscal year ending August 31, 2015. Our cash requirements have increased significantly as we implement our horizontal drilling program. Each horizontal well is estimated to cost between $3.6 million and $5.5 million, depending on the length of the lateral wellbore, the number of stages, and other variables. Our preliminary capital expenditure plan for fiscal 2015 provides for spending of $200 million to $225 million for drilling and leasing activities. We are planning to drill 35 to 40 operated wells with costs ranging from $3.6 million to $5.5 million and to participate in six to eight (net) non-operated wells at a per well cost of $4.5 million to $5.0 million. Finally, leasing and other activities are planned at $10 million to $15 million. Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.

We plan to generate profits by producing oil and natural gas from wells that we drill or acquire. For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, proceeds from the exercise of warrants, and additional borrowings available under our revolving credit facility. 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 our revolving credit facility 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.

Oil and Gas Commodity Contracts

We use derivative contracts to hedge against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production. Our hedge positions will generally cover a substantial portion of our forecasted production for a period of 24 months. We typically enter into contracts covering between 45% and 85% of anticipated production levels. During the year ended August 31, 2014, we realized a cash loss from commodity derivatives of $2.1 million. Our contracts during fiscal 2014 covered crude oil sales of 470,670 bbls and natural gas sales of 390,000 mcf. At October 10, 2014, we had open positions covering of 1.1 million bbls of oil and 1.7 million mcf of natural gas. We do not use derivative instruments for trading purposes.

Hedge Activity Accounting

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

During the year ended August 31, 2014, we reported an unrealized commodity activity gain of $2.5 million. Unrealized gains and losses are non-cash items. We also reported a realized loss of $2.1 million, representing the cash settlement cost for contracts settled during the period.

At August 31, 2014, we estimate that the fair value of our various commodity derivative contracts was a net asset of $0.2 million. We value these contracts using fair value methodology that considers various inputs including a) quoted forecast prices, b) time value, c) volatility factors, d) counterparty risk, and e) other relevant factors. The fair value of these contracts as estimated at August 31, 2014 may differ significantly from the realized values at their respective settlement dates.

Page | 22

Our commodity derivative contracts as of October 10, 2014 as summarized below:

	Hedge Volumes				Average Collar Prices ⁽¹⁾				Average Swap Prices ⁽¹⁾
Month	Oil (Bbl)		Gas (MMBtu)		Average Oil (Bbl) Price		Average Gas (MMBtu) Price		Average Oil (Bbl) Price		Average Gas (MMBtu) Price
Oct 1 to Dec 31, 2014		214,040		330,000		$87.00 -$96.25		$4.07 - $4.18		$88.49		$4.58
Jan 1 to Dec 31, 2015		596,000		864,000		$81.52-$96.89		$4.15 - $4.49		$85.29		N/A
Jan 1 to Dec 31, 2016		304,000		480,000		$77.92 - $98.51		$3.99 - $4.39		$85.02		N/A

⁽¹⁾ Hedge price is at NYMEX WTI and NYMEX Henry Hub.

Contractual Commitments

The following table summarizes our contractual obligations as of August 31, 2014 (in thousands):

	Less than One Year		One to Three Years		Three to Five Years		Total
Rig Contract¹	$	24,000	$	—		—	$	24,000
Revolving credit facility		—		—		37,000		37,000
Operating Leases		200		88		—		288
Employment Agreements		1,755		1,850		—		3,605
Total	$	25,955	$	1,938		37,000	$	64,893

Represents an estimate of the remaining commitment under three contracts with Ensign United States Drilling, Inc. for the use of three rigs. Actual amounts will vary as a result of a number of variables, including target formations, measured depth, and other technical details.

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.

Trend and Outlook

In fiscal 2014, we focused our capital expenditures on drilling and completing horizontal wells and increasing our leasehold in the Wattenberg Field. Since September 2013 through September 2014 we have increased our leasehold by 81% in the Wattenberg Field. We have done so through organic leasing efforts and the asset purchases discussed earlier. Our operated rig count has expanded from one rig to three rigs in the past twelve months. All of the rigs are drilling multi-well pads in the Wattenberg Field. Our focus on the Wattenberg is driven by the increasingly compelling results derived from higher density of wells drilled per spacing unit and the optimization of completion techniques. We are currently spacing our well bores to allow for up to 24 wells per section of 640 acres and we are testing drilling patterns that could lead to an even higher number of wells per section. We are also testing longer lateral wells and utilizing different amounts of proppant in order to determine the most efficient recovery of the hydrocarbons in place.

The Wattenberg Field continues to experience elevated line pressure in the natural gas and liquids gathering system, a problem that has persisted since 2012 and has grown along with the expansion of horizontal drilling in the area. High line pressure restricts our ability to produce crude oil and natural gas. As line pressures increase, it becomes more difficult to inject gas produced by our wells into 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 of the Wattenberg Field is the success of horizontal wells that have been drilled over the last several years. As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle. Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells. The pace of horizontal drilling in the Wattenberg Field continues to accelerate and it appears that it will be some time before the gathering system will have sufficient capacity to eliminate the high line pressure issues.

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We have taken and are continuing to take steps to mitigate high line pressures. Where it was cost beneficial, we have 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 continue to make significant capital investments to increase system capacity. As publicly disclosed, DCP Midstream Partners (“DCP”), the principal third party provider that we employ to gather production from our wells, brought online a 160 Mcf/d gas processing plant in La Salle, CO (the O’Connor plant), which is part of an 8 plant system owned by the DCP enterprise with approximately 600 MMcf/d capacity. The addition of this plant to our area has served primarily to curb the increasing pressure issues, but has not resolved the high line pressure problems in the region. DCP has also announced the building of the Lucerne Plant II, northeast of Greeley in Weld County, with a maximum capacity of approximately 200 mmcf/d. The Lucerne Plant II is estimated to begin operations in the first quarter of 2015. At this time, we do not know how long it will take for the mitigation efforts to remedy the problem.

The success of horizontal drilling techniques in the D-J Basin has significantly increased quantities of oil and natural gas produced in the region. Local refineries do not have sufficient capacity to process all of the crude oil available. The imbalance of supply and demand in the area is expected to result in an increase in oil transported from the D-J Basin to other markets, generally via pipeline or railroad car. The imbalance is having an impact on prices paid by oil purchasers and increased the differential between crude oil prices posted on NYMEX and the average prices realized by us. Further details regarding posted prices and average realized prices are discussed in the section entitled “market conditions,” presented in this Item 7. We continue to explore various alternatives with various oil purchasers, including a local refiner and an oil pipeline, that we believe will provide sufficient take-away capacity for all of our oil production.

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 future 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.

Since oil prices peaked in June 2014, oil prices have declined more than 23%. A continuing decline in oil and gas prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic 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.

Page | 24

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.

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.

Commodity Derivative Instruments: We have 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 and gas production. Our commodity derivative instruments are measured at fair value. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. 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.

Page | 25

To the Board of Directors and Shareholders

Synergy Resources Corporation

Platteville, Colorado

We have audited the accompanying balance sheets of Synergy Resources Corporation (the Company) as of August 31, 2014 and 2013, 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, 2014. We also have audited the Company’s internal control over financial reporting as of August 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) 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’s Report on Internal Control over Financial Reporting. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended August 31, 2014, 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, 2014, based on criteria established in Internal Control – Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ EKS&H LLLP

October 28, 2014

Denver, Colorado

● DENVER ● FORT COLLINS ● BOULDER ●

www.EKSH.com

Page | F - 2

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

(in thousands, except share data)

	August 31,		August 31,
ASSETS	2014		2013
Current assets:
Cash and cash equivalents	$	34,753	$	19,463
Short-term investments		—		60,018
Accounts receivable:
Oil and gas sales		16,974		7,361
Joint interest billing		15,398		4,700
Inventory		310		194
Commodity derivative		365		—
Other current assets		440		239
Total current assets		68,240		91,975

Property and equipment:
Evaluated oil and gas properties, net		275,018		132,979
Unevaluated oil and gas properties		95,278		64,715
Other property and equipment, net		9,104		271
Property and equipment, net		379,400		197,965

Commodity derivative		54		—
Other assets		848		1,296

Total assets	$	448,542	$	291,236

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	1,747	$	949
Well costs payable		71,849		25,491
Revenue payable		14,487		6,081
Production taxes payable		14,376		6,277
Other accrued expenses		817		254
Commodity derivative		302		2,315
Total current liabilities		103,578		41,367

Revolving credit facility		37,000		37,000
Commodity derivative		307		334
Deferred tax liability, net		21,437		6,538
Asset retirement obligations		4,730		2,777
Total liabilities		167,052		88,016

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, 200,000,000 shares authorized:
77,999,082 and 70,587,723 shares issued and outstanding,
respectively		78		71
Additional paid-in capital		265,793		216,383
Retained earnings (accumulated deficit)		15,619		(13,234	)
Total shareholders' equity		281,490		203,220

Total liabilities and shareholders' equity	$	448,542	$	291,236

The accompanying notes are an integral part of these financial statements

Page | F - 3

SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	For the Years Ended August 31,
	2014			2013			2012

Oil and gas revenues	$	104,219		$	46,223		$	24,969

Expenses
Lease operating expenses		7,991			3,417			1,212
Production taxes		9,667			4,237			2,436
Depreciation, depletion,
and amortization		32,958			13,336			6,010
General and administrative		10,139			5,688			3,557
Total expenses		60,755			26,678			13,215

Operating income		43,464			19,545			11,754

Other income (expense)
Commodity derivative realized loss		(2,138	)		(395	)		-
Commodity derivative unrealized gain (loss)		2,459			(2,649	)		-
Interest expense, net		-			(97	)		-
Interest income		82			47			38
Total other income (expense)		403			(3,094	)		38

Income before income taxes		43,867			16,451			11,792

Deferred income tax provision (benefit)		15,014			6,870			(332	)
Net income	$	28,853		$	9,581		$	12,124

Net income per common share:
Basic	$	0.38		$	0.17		$	0.26
Diluted	$	0.37		$	0.16		$	0.25

Weighted average shares outstanding:
Basic		76,214,737			57,089,362			46,587,558
Diluted		77,808,054			59,088,761			48,359,905

The accompanying notes are an integral part of these financial statements

Page | F - 4

SYNERGY RESOURCES CORPORATION

STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

for the years ended August 31, 2014, 2013 and 2012

(in thousands, except share data)


	Number of Common		Par Value		Additional			Accumulated Earnings			Total Shareholders'
	Shares		Common Stock		Paid - In Capital			(Deficit)			Equity

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
Payment of tax withholdings using withheld shares		—		—		(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

Shares issued in exchange for mineral assets		357,901		—		2,856			—			2,856
Shares issued for Trilogy and Apollo acquisitions		872,483		1		8,327			—			8,328
Shares issued for exercise of warrants		6,063,801		6		35,628			—			35,634
Shares issued under stock bonus plan		89,875		—		1,201						1,201
Shares issued for exercise of stock options		27,299		—		—			—			—
Stock based compensation for vested options		—		—		1,767			—			1,767
Payment of tax withholdings using withheld shares		—		—		(369	)					(369
Net income									28,853			28,853
Balance, August 31, 2014		77,999,082	$	78	$	265,793		$	15,619		$	281,490

The accompanying notes are an integral part of these financial statements

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SYNERGY RESOURCES CORPORATION

STATEMENTS OF CASH FLOWS

(in thousands)


	For the Years Ended August 31,
	2014			2013			2012
Cash flows from operating activities:
Net income	$	28,853		$	9,581		$	12,124
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation, and amortization		32,958			13,336			6,010
Provision for deferred taxes		15,014			6,870			(332	)
Stock-based compensation		2,968			1,362			473
Valuation decrease in commodity derivatives		(2,459	)		2,649			-
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales		(9,613	)		(3,756	)		(1,597	)
Joint interest billing		(10,698	)		(1,432	)		(685	)
Inventory		(116	)		(16	)		282
Accounts payable
Trade		798			(550	)		(155	)
Revenue		8,406			1,921			4,161
Production taxes		8,099			2,472			2,279
Accrued expenses		448			(141	)		(1,291	)
Other		247			(176	)		(17	)
Total adjustments		46,052			22,539			9,128
Net cash provided by operating activities		74,905			32,120			21,252

Cash flows from investing activities:
Acquisition of property and equipment		(155,602	)		(80,469	)		(46,751	)
Short-term investments		60,018			(60,000	)		-
Net proceeds from sales of oil and gas properties		704			-			71
Net cash used in investing activities		(94,880	)		(140,469	)		(46,680	)

Cash flows from financing activities:
Proceeds from sale of stock		-			82,656			40,250
Offering costs		-			(4,413	)		(2,829	)
Proceeds from exercise of warrants		35,634			3,275			3,000
Shares withheld for payment of employee payroll taxes		(369	)		(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		35,265			108,528			35,221

Net increase in cash and equivalents		15,290			179			9,793

Cash and equivalents at beginning of period		19,463			19,284			9,491

Cash and equivalents at end of period	$	34,753		$	19,463		$	19,284

Supplemental Cash Flow Information (See Note 15)

The accompanying notes are an integral part of these financial statements

Page | F - 6

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

August 31, 2014, 2013 and 2012

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.

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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, 2014. Since the wells had not been completed as of August 31, 2014, 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, 2014 or 2013.

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,
	2014		2013		2012
Capitalized overhead	$	1,230	$	637	$	345

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. The Class II disposal well is depreciated based on a units of production method using barrels of water disposed.

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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.

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,
	2014	2013	2012
Company A	54%	50%	68%
Company B	13%	15%	11%

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.

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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,
	2014	2013	2012
Company A	37%	24%	35%
Company B	*	23%	30%
Company C	*	12%	*

* 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, 2014. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of August 31, 2014, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 12 for further information.

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 and gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. 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.

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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,
	2014		2013		2012
Weighted-average shares outstanding - basic		76,214,737		57,089,362		46,587,558
Potentially dilutive common shares from:
Stock options		479,222		1,881,682		1,380,861
Warrants		1,114,095		117,717		391,486
Weighted-average shares outstanding - diluted		77,808,054		59,088,761		48,359,905

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,
	2014		2013		2012
Potentially dilutive common shares from:
Stock options		533,000		670,000		2,495,000
Warrants		-		8,500,000		14,098,000
Total		533,000		9,170,000		16,593,000

Recent Accounting Pronouncements:

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

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2014-09 (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. The ASU allows for the use of either the full or modified retrospective transition method, and the standard will be effective for us in the first quarter of our fiscal year 2018; early adoption is not permitted. The Company is currently evaluating which transition approach to use and the impact of the adoption of this standard on its consolidated financial statements.

In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”) in January 2013. These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivative contracts. The new disclosure requirements, which are effective for interim and annual periods beginning on or after January 1, 2013, were implemented by the Company on September 1, 2013. The implementation of ASU 2011-11 and ASU 2013-01 had no impact on the Company’s financial position or results of operations. See Note 7 for the Company’s derivative disclosures.

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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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,
	2014			2013
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	41,531		$	38,826
Wells in progress		53,747			25,889
Subtotal, unevaluated costs		95,278			64,715

Evaluated costs:
Producing and non-producing		329,926			155,755
Total capitalized costs		425,204			220,470
Less, accumulated depletion		(54,908	)		(22,776	)
Oil and gas properties, net		370,296			197,694

Land		3,898			44
Other property and equipment		5,961			500
Less, accumulated depreciation		(755	)		(273	)
Other property and equipment, net		9,104			271

Total property and equipment, net	$	379,400		$	197,965

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,
	2014		2013		2012
Acquisition of property:
Unproved	$	15,002	$	12,295	$	9,145
Proved		33,795		43,143		459
Exploration costs		43,089		-		-
Development costs		111,238		61,128		39,739
Other property and equipment		9,315		-		-
Asset retirement obligation		1,610		1,578		300
Total costs incurred	$	214,049	$	118,144	$	49,643

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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, 2014 (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
							2011		August 31,
	2014		2013		2012		and prior		2014
Unproved leasehold acquisition costs	$	15,002	$	11,021	$	6,159	$	9,349	$	41,531
Unevaluated development costs		53,747		-		-		-	$	53,747
Total unevaluated costs	$	68,749	$	11,021	$	6,159	$	9,349	$	95,278

3.	Acquisitions

On September 16, 2013, the Company entered into a definitive purchase and sale agreement, with Trilogy Resources, LLC (“Trilogy”), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the “Trilogy Assets”). On November 12, 2013, the Company closed the transaction for a combination of cash and stock. Trilogy received 301,339 shares of the Company’s common stock valued at $2.9 million and cash consideration of approximately $16.0 million. No material transaction costs were incurred in connection with this acquisition.

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

Preliminary Purchase Price	November 12, 2013
Consideration Given
Cash	$	16,008
Synergy Resources Corp. Common Stock *		2,896

Total consideration given	$	18,904

Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	19,374
Total fair value of oil and gas properties acquired		19,374

Working capital	$	(119	)
Asset retirement obligation		(351	)

Fair value of net assets acquired	$	18,904

Working capital acquired was estimated as follows:
Accounts receivable		500
Accrued liabilities and expenses		(619	)

Total working capital	$	(119	)

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

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

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

Preliminary Purchase Price	November 13, 2013
Consideration Given
Cash	$	14,679
Synergy Resources Corp. Common Stock *		5,432

Total consideration given	$	20,111

Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	16,009
Disposal Well	$	5,220
Total fair value of oil and gas properties acquired		21,229

Working capital	$	(883	)
Asset retirement obligation		(235	)

Fair value of net assets acquired	$	20,111

Working capital acquired was estimated as follows:
Accounts receivable		380
Accrued liabilities and expenses		(1,263	)

Total working capital	$	(883	)

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

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

Pro Forma Financial Information

As stated above, on November 12 and 13, 2013, the Company completed acquisitions of oil and gas properties from Trilogy Resources, LLC and Apollo Operating, LLC. Below are the combined results of operations for the twelve months ended August 31, 2014 and 2013 as if the acquisitions had occurred on September 1, 2012 (in thousands).

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 acquisitions and costs incurred as a result of the Trilogy and Apollo acquisitions. 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)
	2014		2013

Oil and Gas Revenues	$	106,584	$	55,633

Net income	$	29,681	$	13,191

Earnings per common share
Basic	$	0.39	$	0.23
Diluted	$	0.38	$	0.22

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.

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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.

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

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

	For the Years Ended August 31,
	2014		2013		2012
Depletion	$	32,132	$	13,046	$	5,838
Depreciation and amortization		826		290		172
Total DDA Expense	$	32,958	$	13,336	$	6,010

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.

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,
	2014	2013
Inflation rate	3.90%	3.9 - 4.0%
Estimated asset life	25.0 - 39.0 years	24.0 - 40.0 years
Credit adjusted risk free interest rate	8%	8.0 - 11.2%

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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,
	2014		2013
Beginning asset retirement obligation	$	2,777	$	1,027
Liabilities incurred		1,024		376
Liabilities assumed		586		240
Accretion expense		343		172
Revisions in previous estimates		-		962
	$	4,730	$	2,777

6.	Revolving Credit Facility

The Company maintains a 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. As most recently amended on June 4, 2014, the terms provide for $300 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 May 29, 2019.

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5%. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin of 0.5% to 1.5%, or the London Interbank Offered Rate (LIBOR) plus a margin of 1.75% to 2.75%. 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 twelve months ended August 31, 2014, was 2.7%. As of August 31, 2014, the interest rate on the outstanding balance was 2.5%, representing the minimum rate.

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 subject to scheduled redeterminations on a semi-annual basis. In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared. The most recent redetermination in June 2014 increased the borrowing base to $110 million from $90 million. As of August 31, 2014, based upon a borrowing base of $110 million and an outstanding principal balance of $37 million, the unused borrowing base available for future borrowing totaled approximately $73 million. The next scheduled redetermination will occur in November 2014 and will reflect the value of oil and gas reserves computed as of August 31, 2014.

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

As amended on June 4, 2014, the arrangement revised the financial ratio compliance covenants. Under the amended requirements, on a quarterly basis, the Company must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX to be greater than or equal to 4.0 to 1.0; and (b) not, as of the last day of the fiscal quarter, permit its adjusted current ratio, as defined, to be less than 1.0 to 1.0. As of August 31, 2014 and during the year ended, the most recent compliance date, the Company was in compliance with all loan covenants.

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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 and gas production. A swap requires a payment to the counterparty if the settlement price exceeds the strike price and the same counterparty is required to make a payment if the settlement price is less than the strike price. A collar requires a payment to the counterparty if the settlement price is above the ceiling price and requires the counterparty to make a payment if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

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

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the commodity derivative line on the statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the Counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s statements of cash flows.

The Company’s commodity derivative contracts as of August 31, 2014 are summarized below:

Settlement Period	Derivative Instrument	Average Volumes (BBls/MMBtu per month)		Average Fixed Price		Floor Price		Celling Price
Crude Oil - NYMEX WTI
Sep 1, 2014 - Dec 31, 2014	Collar		1,840		-	$	85.00	$	98.50
Sep 1, 2014 - Dec 31, 2014	Collar		20,000		-	$	87.00	$	96.25
Sep 1, 2014 - Dec 31, 2014	Swap		18,340	$	94.50		-		-

Jan 1, 2015 - Jun 30, 2015	Collar		7,000		-	$	80.00	$	92.50
Jan 1, 2015 - Jun 30, 2015	Collar		2,500		-	$	80.00	$	95.75
Jul 1, 2015 - Dec 31, 2015	Collar		9,000		-	$	80.00	$	92.25
Jan 1, 2015 - Dec 31, 2015	Collar		4,500		-	$	80.00	$	99.40
Jan 1, 2015 - Dec 31, 2015	Collar		6,000		-	$	85.00	$	101.30

Jan 1, 2016 - May 31, 2016	Collar		10,000		-	$	75.00	$	96.00
Jan 1, 2016 - May 31, 2016	Collar		5,000		-	$	80.00	$	100.75
Jun 1, 2016 - Aug 31, 2016	Collar		15,000		-	$	80.00	$	100.05

Natural Gas - NYMEX Henry Hub
Sep 1, 2014 - Dec 31, 2014	Swap		80,000	$	4.58	$	-	$	-
Sep 1, 2014 - Dec 31, 2014	Collar		30,000		-	$	4.07	$	4.18
Jan 1, 2015 - Dec 31, 2015	Collar		72,000		-	$	4.15	$	4.49
Jan 1, 2016 - May 31, 2016	Collar		60,000		-	$	4.05	$	4.54
Jun 1, 2016 - Aug 31, 2016	Collar		60,000			$	3.90	$	4.14

Subsequent to August 31, 2014, the Company entered into the following commodity derivative contracts:


Settlement Period	Derivative Instrument	Average Volumes (BBls/MMBtu per month)		Average Fixed Price
Crude Oil - NYMEX WTI
Oct 1, 2014 - Dec 31, 2014	Swap		15,000	$	90.85
Nov 1, 2014 - Dec 31, 2014	Swap		25,000	$	80.04

Jan 1, 2015 - Jun 30, 2015	Swap		20,000	$	90.10
Jul 1, 2015 - Dec 31, 2015	Swap		15,500	$	89.52
Jan 1, 2015 - Oct 31 2015	Swap		14,600	$	78.65

Jan 1, 2016 - Aug 31, 2016	Swap		5,000	$	88.55
Sept 1. 2016 - Dec 2016	Swap		20,000	$	88.10
Jan 1, 2016 - Oct 2016	Swap		6,400	$	78.96

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Offsetting of Derivative Assets and Liabilities

As of August 31, 2014 and 2013, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency. They Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying balance sheets.

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

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

		As of August 31, 2013
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	28	$	(28	)	$	-
Derivative contracts	Noncurrent assets	$	182	$	(182	)	$	-
Derivative contracts	Current liabilities	$	2,343	$	(28	)	$	2,315
Derivative contracts	Noncurrent liabilities	$	516	$	(182	)	$	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,
	2014			2013			2012
Realized (loss) on commodity derivatives	$	(2,138	)	$	(395	)		-
Unrealized gain (loss) on commodity derivatives		2,459			(2,649	)		-
Total gain (loss)	$	321		$	(3,044	)	$	-

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Credit Related Contingent Features

As of August 31, 2014, one of the three counterparties was a member of the Company’s credit facility syndicate. The Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with one counterparty which is not a member of the credit facility is based on an unsecured basis and does not require posting of collateral. The agreement with one counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.

8.	Fair Value Measurements

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

·	Level 1: Quoted prices 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.

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 primarily unobservable inputs. Inputs are reviewed by management on an annual basis. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of August 31, 2014 and 2013 by level within the fair value hierarchy (in thousands):

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

	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

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Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers 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, 2014, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents 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,
	2014			2013			2012

Revolving bank credit facility	$	986		$	1,067		$	108
Amortization of debt issuance costs		448			160			32
Other		-			-			68
Less, interest capitalized		(1,434	)		(1,130	)		(208	)
Interest expense, net	$	-		$	97		$	-

10.	Shareholders’ Equity

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

	For the Years Ended August 31,
	2014		2013		2012
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		200,000,000		100,000,000		100,000,000
Common stock, par value	$	0.001	$	0.001	$	0.001
Common stock, shares issued and outstanding		77,999,082		70,587,723		51,409,340

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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:

Sales 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.

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,
	2014		2013		2012
Number of common shares sold		-		13,225,000		14,363,363
Offering price per common share	$	-	$	6.25	$	2.75
Net proceeds (in thousands)	$	-	$	78,243	$	37,422

Common stock issued for acquisition of mineral property interests

During the fiscal years presented, the Company issued shares of common stock in exchange for mineral property interests. The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.

	For the Years Ended August 31,
	2014		2013		2012
Number of common shares issued for mineral property leases		357,901		687,122		669,765
Number of common shares issued for acquisitions		872,483		3,128,422		-
Total common shares issued		1,230,384		3,815,544		669,765

Average price per common share	$	9.09	$	4.37	$	3.12
Aggregate value of shares issues (in thousands)	$	11,184	$	16,684	$	2,090

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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 each of the three years ended August 31, 2014, the following warrants were exercised: 5,938,585, during fiscal 2014, 500,000 during fiscal 2013, and nil during fiscal 2012.

Series D – During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for the Series C 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, 2014, the following warrants were exercised: 140,744 during fiscal 2014, 627,799 during fiscal 2013, and nil during fiscal 2012.

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 with the firm. During each of the three years ended August 31, 2014, the following warrants were exercised: 25,000 during fiscal 2014, 25,000 during fiscal 2013, and nil during fiscal 2012.

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, 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
Exercised		6,104,329	$	5.88
Forfeited / Expired		-	$	-
Outstanding, August 31, 2014		2,562,473	$	6.00

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The following table summarizes information about the Company’s issued and outstanding common stock warrants as of August 31, 2014:

Number of Shares		Exercise Price		Remaining Contractual Life (in years)		Exercise Price times number of shares
	2,561,415	$	6.00		0.33	$	15,368,490
	1,058	$	1.60		0.33	$	1,693
	2,562,473					$	15,370,183

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,
	2014		2013		2012
Stock options	$	1,767	$	1,039	$	443
Restricted stock grants		1,201		277		17
Investor relations warrants		-		46		13
	$	2,968	$	1,362	$	473

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, 2014, 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.

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

	For the Years Ended August 31,
	2014		2013		2012
Number of options to purchase common shares		433,000		1,025,000		275,000
Weighted average exercise price	$	10.37	$	6.05	$	2.96
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	5 years		3-5 years		4-5 years
Fair Value (in thousands)	$	3,009	$	4,179	$	519

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

	For the Years Ended August 31,
	2014			2013			2012
Expected term	6.7 years			6.2 years			6.5 years
Expected volatility		73	%		77	%		56.7 - 69.4	%
Risk free rate		1.8 - 2.3	%		0.9 - 2.1	%		1.0-1.4	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Forfeiture rate		0.0	%		0.0	%		0.0 - 0.7	%

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

	Number of Shares			Weighted Average Exercise Price
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
Granted		433,000		$	10.37
Exercised		(61,000	)	$	3.71
Forfeited		(25,000	)	$	10.32
Outstanding, August 31, 2014		2,167,000		$	5.94

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The following table summarizes information about issued and outstanding stock options as of August 31, 2014:

	As of August 31, 2014

	Outstanding Options		Vested Options
Number of shares		2,167,000		797,500
Weighted average remaining contractual life	8 years		7.2 years
Weighted average exercise price	$	5.94	$	4.55
Aggregate intrinsic value (in thousands)	$	16,287	$	7,103

The estimated unrecognized compensation cost from unvested stock options as of August 31, 2014, which will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at August 31, 2014
Unrecognized compensation expense (in thousands)	$	5,410,960
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,
	2014		2013		2012
Current:
Federal	$	4	$	-	$	-
State		111		-		-
Total current income tax	$	115	$	-	$	-

Deferred:
Federal	$	13,748	$	6,367	$	4,219
State		1,151		503		360
Total deferred income tax	$	14,899	$	6,870	$	4,579

Valuation allowance		-		-		(4,911	)
Income tax provision (benefit)	$	15,014	$	6,870	$	(332	)

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

	As of August 31,
	2014			2013			2012
Federal income tax at statutory rate	$	14,915		$	5,594		$	4,009
State income taxes, net of federal tax		1,341			503			360
Statutory depletion		(1,266	)		(929	)		-
Stock based compensation		-			1,911			-
Other		24			(209	)		210
Change in valuation allowance		-			-			(4,911	)
Income tax provision (benefit)	$	15,014		$	6,870		$	(332	)
Effective rate expressed as a percentage		34	%		42	%		3	%

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 is presented in the following table (in thousands):

	As of August 31,
	2014		2013
Deferred tax assets:
Net operating loss carry-forward	$	8,589	$	11,485
Stock-based compensation		1,115		515
Statutory depletion		2,194		929
Unrealized loss on commodity derivative		70		982
Other		4		3
Gross deferred tax assets	$	11,972	$	13,914

Deferred tax liabilities:
Basis of oil and gas properties		33,409		20,452
Gross deferred tax liabilities		33,409		20,452
Deferred tax liability (asset), net	$	21,437	$	6,538

At August 31, 2014 the Company has a net operating loss carry-forward for federal tax purposes of approximately $33.2 million and state tax purposes of approximately $41.1 million that could be utilized to offset taxable income of future years. For financial reporting purposes the Company has net operating losses of approximately $22.5 million and $30.4 million for federal and state, respectively. The difference of $10.7 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, 2014, 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.

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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, 2014, 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

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

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

	For the Years Ended August 31,
	2014		2013		2012
Rent expense	$	180	$	130	$	120

Mineral Leasing Program: 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,
	2014		2013		2012
Shares of restricted common stock		15,883		31,454		188,137
Value of common stock (in thousands)	$	106	$	105	$	491

Mineral Leases Acquired from Director: Mr. Seward owns mineral interests in several Colorado and Nebraska counties. He agreed to lease his interests to the Company in exchange for restricted shares of common stock. The following table discloses the acquisition of mineral leases from Mr. Seward during each of the fiscal years presented:

	For the Years Ended August 31,
	2014		2013		2012
Mineral acres leased		4,844		2,263		-
Shares of restricted common stock		40,435		22,202		-
Value of common stock (in thousands)	$	313,000	$	91,000	$	-

Page | F - 28

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

	For the Years Ended August 31,
	2014		2013		2012
Total Royalty Payments	$	292	$	304	$	196

14.	Other Commitments and Contingencies

As of August 31, 2014, the Company was using three rigs under contracts with Ensign United States Drilling, Inc. The Company estimates that its minimum future obligation to Ensign under the terms of the existing contracts will aggregate $24 million, based upon its current drilling schedule and time required to drill each well. All of the contracts are based upon turn-key pricing and have termination dates during the first half of fiscal year 2015. At the option of the Company, the drilling commitments can be extended into future months, although pricing terms may be modified. Actual payments due to Ensign will depend upon a number of variables, including the surface location, the target formation, measured depth of well and other technical details.

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 August 31, 2014, the Company was participating in 43 gross (6 net) new horizontal wells, with aggregate costs to its interest estimated at $26.9 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. Accordingly, the August 31, 2014 financial statements include costs of $26.9 million for these wells.

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:	2014		2013		2012
Interest paid	$	989	$	995	$	74
Income taxes paid		-		-		-

Non-cash investing and financing activities:
Accrued well costs	$	71,849	$	25,491	$	5,733
Assets acquired in exchange for common stock		11,184		16,684		1,985
Asset retirement costs and obligations		1,610		1,578		300

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.

Page | F - 29

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, 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
Revision of previous estimates		83,592			3,046,893			591,408
Purchase of reserves in place		1,028,200			5,956,437			2,020,939
Extensions, discoveries, and other additions		9,141,836			49,288,543			17,356,592
Sale of reserves in place		(34,732	)		(56,282	)		(44,113	)
Production		(941,218	)		(3,747,074	)		(1,565,729	)
Balance, August 31, 2014		16,324,953			95,178,348			32,188,011


Proved developed and undeveloped reserves:
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

Developed at August 31, 2014		6,616,482			38,161,602			12,976,749
Undeveloped at August 31, 2014		9,708,471			57,016,746			19,211,262
Balance, August 31, 2014		16,324,953			95,178,348			32,188,011

Page | F - 30

Notable changes in proved reserves for the year ended August 31, 2014 included:

·	Purchases of reserves in place. In 2014, purchases of minerals in place of 2.0 million Boe were attributable to the acquisition of producing oil and gas wells and undeveloped acreage from Trilogy Resources, LLC and Apollo Operating, LLC. Please see the Acquisitions footnote for further information.

Revision of previous estimates. In 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 591,408 Boe. The prices for the 2014 oil and gas reserves are based on the 12 month arithmetic average for the first of month price September 1, 2013 through August 31, 2014. The 2014 crude oil price of $89.48 per barrel (West Texas Intermediate Cushing) was $3.08 higher than the 2013 crude oil price of $86.40 per barrel. The 2014 natural gas price of $5.03 per mcf (Henry Hub) was $0.63 higher than the 2013 price of $4.40 per mcf.

Extensions and discoveries. In 2014, total extensions and discoveries of 17.4 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, 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.

Page | 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,
	2014			2013			2012
Future cash inflow	$	1,839,987		$	749,030		$	537,462
Future production costs		(395,019	)		(146,352	)		(85,612	)
Future development costs		(412,517	)		(108,290	)		(100,821	)
Future income tax expense		(252,925	)		(113,545	)		(109,349	)
Future net cash flows		779,526			380,843			241,680
10% annual discount for estimated timing of cash flows		(376,827	)		(199,111	)		(139,175	)
Standardized measure of discounted future net cash flows	$	402,699		$	181,732		$	102,505

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, 2012 (Average)	$	86.68	$	3.76
August 31, 2013 (Average)	$	86.40	$	4.40
August 31, 2014 (Average)	$	89.48	$	4.20

Page | F - 32

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,
	2014			2013			2012
Standardized measure, beginning of year	$	181,732		$	102,505		$	57,550
Sale and transfers, net of production costs		(86,808	)		(38,569	)		(21,321	)
Net changes in prices and production costs		15,828			(4,550	)		(6,023	)
Extensions, discoveries, and improved recovery		300,087			70,191			69,073
Changes in estimated future development costs		(20,817	)		(6,006	)		(42,578	)
Development costs incurred during the period		15,000			5,106			39,739
Revision of quantity estimates		4,589			(14,214	)		21,058
Accretion of discount		23,612			35,103			15,379
Net change in income taxes		(76,616	)		(7,850	)		(30,832	)
Divestitures of reserves		(925	)		-			-
Purchase of reserves in place		47,017			40,016			460
Standardized measure, end of year	$	402,699		$	181,732		$	102,505

Page | F - 33

17.	Unaudited Quarterly Financial Data

The Company’s quarterly financial information for the years ended August 31, 2014 and 2013 is as follows (in thousands, except share data):

	For the Year Ended August 31, 2014
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	19,266	$	23,028		$	25,672		$	36,253
Expenses		12,048		13,550			14,413			20,744
Operating income		7,218		9,478			11,259			15,509
Other income (expense)		2,269		(1,979	)		(983	)		1,096
Income before income taxes		9,487		7,499			10,276			16,605
Income tax provision		3,387		2,338			3,116			6,173
Net income	$	6,100	$	5,161		$	7,160		$	10,432
Net income per common share:⁽¹⁾
Basic	$	0.08	$	0.07		$	0.09		$	0.13
Diluted	$	0.08	$	0.07		$	0.09		$	0.13
Weighted average shares outstanding:
Basic		73,674,865		76,203,938			77,176,420			77,771,916
Diluted		76,044,605		77,990,416			79,008,619			79,698,720

	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⁽²⁾		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

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	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.

18.	Subsequent Events

Index to Financial Statements	F-1

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheets as of August 31, 2014 and 2013	F-3

Statements of Operations for the years ended August 31, 2014, 2013 and 2012	F-4

Statements of Changes in Shareholders’ Equity for the years ended August 31, 2014, 2013 and 2012	F-5

Statements of Cash Flows for the years ended August 31, 2014, 2013 and 2012	F-6

Notes to Financial Statements	F-7

Synergy Resources Corp – ‘ARS/A’ for 12/31/14

On: Wednesday, 12/31/14, at 3:26pm ET · Effective: 12/31/14 · For: 12/31/14 · Accession #: 1079973-14-652 · File #: 1-35245

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Officers and Directors Edward Holloway Co-Chief Executive Officer and Director William E. Scaff, Jr. Co-Chief Executive Officer, Treasurer and Director Frank L. Jennings Chief Financial Officer Craig Rasmuson Chief Operating Officer Valerie Dunn Controller and Secretary Rick A. Wilber Director Private Investor Raymond E. McElhaney Director President, Longhorn Investments, LLC Bill Conrad Director Chairman and Director, Gold Resource Corporation R.W. Noffsinger, III Director Chief Executive Officer, RWN3 LLC George Seward Director President, Pocito Oil and Gas Jack Aydin Director Private Investor		Corporate Headquarters Synergy Resources Corporation 20203 Highway 60 Platteville, CO 80651 USA Telephone: (970) 737-1073 Facsimile: (970) 737-1045 www.syrginfo.com Independent Auditors EKS&H LLLP Denver, Colorado Counsel Hart & Hart LLP Denver, Colorado Transfer Agent and Registrar Corporate Stock Transfer, Inc. 3200 Cherry Creek Drive South, Suite 430 Denver, Colorado 80209 (303) 282-4800		Stock Profile Synergy’s common stock is traded on the NYSE MKT exchange under the symbol SYRG. SEC Form 10-K A copy of Synergy’s annual report to the Securities and Exchange Commission on Form 10-K is available without charge upon written request to: Corporate Communications Synergy Resources Corporation 20203 Highway 60 Platteville, CO 80651 USA

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Synergy Resources Corp – ‘ARS/A’ for 12/31/14

On: Wednesday, 12/31/14, at 3:26pm ET · Effective: 12/31/14 · For: 12/31/14 · Accession #: 1079973-14-652 · File #: 1-35245

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Amendment to Annual Report to Security Holders
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