UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended February 28, 2014

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

For the transition period from _____ to _______

Commission File Number: 001-35245

SYNERGY RESOURCES CORPORATION

(Exact Name of Registrant as Specified in its Charter)

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

20203 Highway 60, Platteville, Colorado  80651

(Address of Principal Executive Offices)  (Zip Code)

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

N/A

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

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

Yes x    No o

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

 Yes x    No o

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

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

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

           Yes o    No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 77,185,147 shares outstanding as of March 31, 2014.

SYNERGY RESOURCES CORPORATION

Index

		Page
Part I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Balance Sheets as of February 28, 2014 (unaudited)  and August 31, 2013	3
	Statements of Operations for the three months and six months ended February 28, 2014 and February 28, 2013 (unaudited)	4
	Statements of Cash Flows for the six months ended February 28, 2014 and February 28, 2013  (unaudited)	5
	Notes to Financial Statements (unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45
Part II - OTHER INFORMATION
Item 6.	Exhibits	46
SIGNATURES		47

2

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

(in thousands, except share data

ASSETS	February 28, 2014			August 31,  2013
	(unaudited)
Current assets:
Cash and cash equivalents	$	34,380		$	19,463
Short-term investments		20,028			60,018
Accounts receivable:
Oil and gas sales		11,981			7,361
Joint interest billing		5,696			4,700
Inventory		506			194
Other current assets		292			239
Total current assets		72,883			91,975
Property and equipment
Evaluated oil and gas properties, full cost method, net		209,747			132,979
Unevaluated oil and gas properties		57,519			64,715
Other property and equipment, net		8,751			271
Property and equipment, net		276,017			197,965
Other assets		646			1,296
Total assets	$	349,546		$	291,236
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	396		$	949
Well costs payable		17,966			25,491
Revenue payable		9,244			6,081
Production taxes payable		11,986			6,277
Other accrued expenses		289			254
Commodity derivative		1,675			2,315
Total current liabilities		41,556			41,367
Revolving credit facility		37,000			37,000
Commodity derivative		143			334
Deferred tax liability, net		12,263			6,538
Asset retirement obligations		3,933			2,777
Total liabilities		94,895			88,016
Commitments and contingencies (See Note 12)
Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding		-			-
Common stock - $0.001 par value, 100,000,000 shares authorized:
76,685,709 and 70,587,723 shares issued and outstanding, respectively		77			71
Additional paid-in capital		256,547			216,383
Accumulated deficit		(1,973	)		(13,234	)
Total shareholders' equity		254,651			203,220
Total liabilities and shareholders' equity	$	349,546		$	291,236

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

3

SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

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

	Three Months Ended						Six Months Ended
	February 28,			February 28,			February 28,			February 28,
	2014			2013			2014			2013
Oil and gas revenues	$	23,028		$	10,921		$	42,294		$	19,235
Expenses
Lease operating expenses		1,806			781			3,079			1,304
Production taxes		2,255			1,094			4,271			1,908
Depreciation, depletion,
and amortization		7,719			3,176			13,310			5,496
General and administrative		1,770			1,388			4,938			2,499
Total expenses		13,550			6,439			25,598			11,207
Operating income		9,478			4,482			16,696			8,028
Other income (expense)
Commodity derivative realized loss		(191	)		(20	)		(589	)		(20	)
Commodity derivative unrealized gain (loss)		(1,805	)		(134	)		831			(134	)
Interest income		17			8			48			15
Total other income (expense)		(1,979	)		(146	)		290			(139	)
Income before income taxes		7,499			4,336			16,986			7,889
Deferred income tax provision		2,338			1,604			5,725			2,919
Net income	$	5,161		$	2,732		$	11,261		$	4,970
Net income per common share:
Basic	$	0.07		$	0.05		$	0.15		$	0.09
Diluted	$	0.07		$	0.05		$	0.15		$	0.09
Weighted average shares outstanding:
Basic		76,203,938			54,900,326			74,934,940			53,272,213
Diluted		77,990,416			56,481,752			76,843,593			54,713,361

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

4

SYNERGY RESOURCES CORPORATION

 STATEMENTS OF CASH FLOWS

 (unaudited, in thousands)

	Six Months Ended
	February 28, 2014			February 28, 2013
Cash flows from operating activities:
Net income	$	11,261		$	4,970
Adjustments to reconcile net income to net
cash provided by operating activities:
Depletion, depreciation and amortization		13,310			5,496
Provision for deferred taxes		5,725			2,919
Stock-based compensation		867			383
Valuation (increase) in commodity derivatives		(831	)		134
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales		(4,620	)		(2,291	)
Joint interest billing		(996	)		(490	)
Inventory		(312	)		(74	)
Accounts payable
Trade		(553	)		595
Revenue		3,163			2,514
Production taxes		5,709			2,898
Accrued expenses		35			(40	)
Other		596			661
Total adjustments		22,093			12,705
Net cash provided by operating activities		33,354			17,675
Cash flows from investing activities:
Acquisition of property and equipment		(87,497	)		(57,579	)
Short-term investments		39,990			-
Net cash used in investing activities		(47,507	)		(57,579	)
Cash flows from financing activities:
Proceeds from exercise of warrants		29,104			407
Proceeds from revolving credit facility		-			38,486
Shares withheld for payment of employee payroll taxes		(34	)		-
Net cash provided by financing activities		29,070			38,893
Net increase (decrease) in cash and cash equivalents		14,917			(1,011	)
Cash and cash equivalents at beginning of period		19,463			19,284
Cash and cash equivalents at end of period	$	34,380		$	18,273

Supplemental Cash Flow Information (See Note 14)

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

5

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

February 28, 2014

(unaudited)

1.   Organization and Summary of Significant Accounting Policies

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

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.

In this filing we use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

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

Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading, and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, 2013.

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

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

Use of Estimates:    The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves, and 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.

6

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

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

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

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.  Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves.  For depletion purposes, the volume of petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.  Investments in unevaluated properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

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 unevaluated properties not being amortized, plus the lower of cost or estimated fair value of unevaluated 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 either the three or six months ended February 28, 2014 or February 28, 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.

7

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 showing in the table below were capitalized in the full cost pool (in thousands):

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Capitalized Overhead	$	304	$	123	$	621	$	226

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

Other Property and Equipment:  Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market.  Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years.

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

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

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.

8

Major Customers and Operating Region:    The Company operates exclusively within the United States of America.  Except for cash and equivalent investments, all of the Company’s assets are employed in and all of its revenues are derived from the oil and gas industry.   The table below presents the percentages of oil and gas revenue resulting from purchases by major customers.

	Three Months Ended						Six Months Ended
	February 28,			February 28,			February 28,			February 28,
Major Customers	2014			2013			2014			2013
Company A		32	%		58	%		51	%		61	%
Company B		20	%		14	%		15	%		14	%
Company C		18	%		13	%		10	%		-

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

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

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

Major Customers	As of February 28, 2014		As of August 31, 2013
Company A		17%		24%
Company B		15%		23%
Company C		12%		12%

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 respective grants.  See Note 11 for additional information.

9

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

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Weighted-average shares outstanding-basic		76,203,938		54,900,326		74,934,940		53,272,213
Potentially dilutive common shares from:
Stock Options		512,399		1,292,599		532,095		1,180,219
Warrants		1,274,079		288,827		1,376,558		260,929
		1,786,478		1,581,426		1,908,653		1,441,148
Weighted-average shares outstanding - diluted		77,990,416		56,481,752		76,843,593		54,713,361

The following potentially dilutive securities, which could dilute future earnings per share, were excluded from the calculation because they were anti-dilutive:

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Warrants		-		8,970,000		-		8,970,000
Employee stock options		886,333		2,355,000		829,160		2,450,000
Total		886,333		11,325,000		829,160		11,420,000

Income Taxes:    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 due to 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 exist.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of February 28, 2014, the Company has not recognized any interest or penalties related to uncertain tax benefits.

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

10

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 its future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures.  The Company compares the valuations it calculates to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7—Commodity Derivative Instruments.

Recent Accounting Pronouncements:  The Company evaluates the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on the Company.  There were various updates recently issued by the Financial Accounting Standards Board, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's consolidated financial position, results of operations or cash flows. 

11

2.   Property and Equipment

Capitalized costs of property and equipment at February 28, 2014, and August 31, 2013, consisted of the following (in thousands):

	As of			As of
	February 28, 2014			August 31, 2013
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	39,463		$	38,826
Wells in progress		18,056			25,889
Subtotal, unevaluated costs		57,519			64,715
Evaluated costs:
Producing and non-producing		245,505			155,755
Total capitalized costs		303,024			220,470
Less, accumulated depletion		(35,758	)		(22,776	)
Oil and gas properties, net		267,266			197,694
Land		3,348			44
Other property and equipment		5,848			500
Less, accumulated depreciation		(445	)		(273	)
Other property and equipment, net		8,751			271
Total property and equipment, net	$	276,017		$	197,965

Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value. The reviews for the three months ended February 28, 2014 and 2013 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 for the three months ended February 28, 2014 and 2013, similarly revealed no impairment of oil and gas assets.

12

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)

13

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, 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 million and 550,518 shares of Synergy’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 Synergy’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).

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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 three and six months ended February 28, 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.

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Oil and Gas Revenues	$	23,028	$	13,043	$	44,659	$	24,004
Net income	$	5,161	$	3,573	$	12,091	$	6,820
Earnings per common share
Basic	$	0.07	$	0.06	$	0.16	$	0.13
Diluted	$	0.07	$	0.06	$	0.16	$	0.12

15

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

Depletion, depreciation and amortization for the three and six months ended February 28, 2014 and 2013, consisted of the following (in thousands):

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Depletion	$	7,491	$	3,117	$	12,981	$	5,379
Depreciation and amortization		228		59		329		117
Total DDA Expense	$	7,719	$	3,176	$	13,310	$	5,496

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

Asset retirement obligations primarily represent the estimated present value of the amounts to be incurred in future periods to plug, abandon and remediate our producing properties at the end of their productive lives.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost.  For the purpose of determining the fair value of ARO incurred during the periods, the Company used the following assumptions:

	For the Six Months Ended February 28,
	2014	2013
Inflation rate	3.9 - 4.0%	3.9 - 4.0%
Estimated asset life	20.0 - 40.0 years	24.0 - 27.6 years
Credit adjusted risk free interest rate	8.0%	11.2%

The following table summarizes the change in asset retirement obligations for the six months ended February 28, 2014 (in thousands):

Asset retirement obligations, August 31, 2013	$	2,777
Liabilities incurred		428
Liabilities assumed		572
Liabilities settled		-
Accretion		156
Asset retirement obligations, February 28, 2014	$	3,933

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 December 20, 2013, the terms provide for $300 million ($150 million prior to December 20, 2013) in the maximum amount of borrowings available to the Company, subject to a borrowing base limitation.  Community Banks of Colorado acts as the administrative agent for the bank syndicate with respect to the LOC.  The credit facility expires on November 28, 2016.

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Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin of 0% to 1%, or the London Interbank Offered Rate (LIBOR) plus a margin of 2.50% to 3.25%.  The interest rate margin, as well as other bank fees, varies with utilization of the LOC.  The average annual interest rate for borrowings during the six months ended February 28, 2014, was 2.7%.  As of February 28, 2014, the interest rate on the outstanding balance was 2.66%, representing LIBOR plus a margin of 2.5%.

Certain of the Company’s assets, including substantially all developed properties, have been designated as collateral under the arrangement.  The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves.  The borrowing base limitation is 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 December 2013 increased the borrowing base to $90 million from $75 million.  As of February 28, 2014, based upon a borrowing base of $90 million and an outstanding principal balance of $37 million, the unused borrowing base available for future borrowing totaled approximately $53 million.

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain customary financial ratios.  On a quarterly basis, the Company must maintain (a) an adjusted current ratio greater than 1.0, (b) a ratio of earnings before interest, taxes, depletion, amortization and exploration expense (EBITDAX) greater than 3.5 times interest and fees, (c) a ratio of total funded debt less than 3.5 times EBITDAX, and (d) a ratio of total funded debt less than 0.5 times total capitalization.  Furthermore, terms of the LOC require the Company to maintain hedge contracts covering future production quantities that are included in the borrowing base.  The most recent amendment to 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 80% of hydrocarbon production.  As of February 28, 2014, the most recent compliance date, the Company was in compliance with all loan covenants.

7.   Commodity Derivative Instruments

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

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  The Company’s derivative contracts are currently with two counterparties.  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.

17

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities.  Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments.  Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the commodity derivative line on the statements of operations.  The Company’s valuation estimate takes into consideration the counterparty’s credit worthiness, the Company’s credit worthiness, and the time value of money.  The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view.  Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

The Company’s commodity derivative contracts as of February 28, 2014 are summarized below:

Collars	Basis (1)	Quantity (Bbl/month)		Strike Price ($/Bbl)
Mar 1, 2014 - Dec 31, 2014	NYMEX		1,840		$85.00 - $98.50
Mar 1, 2014 - Dec 31, 2014	NYMEX		20,000		$87.00 - $96.25
Jan 1, 2015 - Jun 30, 2015	NYMEX		7,000		$80.00 - $92.50
Jan 1, 2015 - Jun 30, 2015	NYMEX		2,500		$80.00 - $95.75
Jul 1, 2015 - Dec 31, 2015	NYMEX		9,000		$80.00 - $92.25
Swaps	Basis (1)	Average Quantity (Bbl/month)		Average Swap Price ($/Bbl)
Mar 1, 2014 - Dec 31, 2014	NYMEX		22,240		$95.17

(1) NYMEX refers to WTI quoted prices on the New York Mercantile Exchange

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

		As of February 28, 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
Crude oil derivative contract	Current assets	$	425	$	(425	)	$	-
Crude oil derivative contract	Noncurrent assets	$	348	$	(348	)	$	-
Crude oil derivative contract	Current liabilities	$	2,100	$	(425	)	$	1,675
Crude oil derivative contract	Noncurrent liabilities	$	491	$	(348	)	$	143

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		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
Crude oil derivative contract	Current assets	$	28	$	(28	)	$	-
Crude oil derivative contract	Noncurrent assets	$	182	$	(182	)	$	-
Crude oil derivative contract	Current liabilities	$	2,343	$	(28	)	$	2,315
Crude oil derivative contract	Noncurrent liabilities	$	516	$	(182	)	$	334

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

	Three Months Ended						Six Months Ended
	February 28,			February 28,			February 28,			February 28,
	2014			2013			2014			2013
Realized gain (loss) on commodity derivatives		(191	)		(20	)		(589	)		(20	)
Unrealized gain (loss) on commodity derivatives	$	(1,805	)	$	(134	)	$	831		$	(134	)
Total gain (loss)	$	(1,996	)	$	(154	)	$	242		$	(154	)

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

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

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

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The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of  February 28, 2014 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at February 28, 2014
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative	$	-	$	-	$	-	$	-
Financial Liabilities:
Commodity derivative	$	-	$	1,818	$	-	$	1,818

Commodity Derivative Instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At February 28, 2014, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as level 2.

Fair Value of Financial Instruments

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

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9.   Interest Expense

The components of interest expense recorded for the three and six months ended February 28, 2014 and 2013, consisted of the following (in thousands):

	Three Months Ended						Six Months Ended
	February 28,			February 28,			February 28,			February 28,
	2014			2013			2014			2013
Revolving credit facility	$	246		$	345		$	497		$	375
Amortization of debt issuance costs		100			50			194			70
Less, interest capitalized		(346	)		(395	)		(691	)		(445	)
Interest expense, net	$	-		$	-		$	-		$	-

10.   Shareholders’ Equity

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

	As of February 28,		As August 31,
	2014		2013
Preferred stock, shares authorized		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized		100,000,000		100,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding		76,685,709		70,587,723

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.

Common stock issued for acquisition of mineral interests

During the six months ended February 28, 2014, the Company issued common shares 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 Six Months Ended February 28, 2014
Number of common shares issued for mineral property leases		243,179
Number of common shares issued for acquisitions		851,857
Total common shares issued		1,095,036
Average price per common share	$	9.24
Aggregate value of shares issued (in thousands)	$	10,122

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The following table summarizes information about the Company’s issued and outstanding common stock warrants as of February 28, 2014:

Exercise Price		Description	Number of Shares		Remaining Contractual Life (in years)		Exercise Price times Number of Shares (in thousands)
	$6.00	Series C		3,664,739		0.8		$21,988

The following table summarizes activity for common stock warrants for the six month period ended February 28, 2014:

	Number of Warrants			Weighted Average Exercise Price
Outstanding, August 31, 2013		8,666,802		$	5.92
Granted		-		$	-
Exercised		(5,002,063	)	$	5.86
Expired		-		$	-
Outstanding, February 28, 2014		3,664,739		$	6.00

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.

The amount of stock based compensation expense recorded for the three and six months ended February 28, 2014 and 2013 is shown in the table below (in thousands):

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Stock options	$	447	$	154	$	867	$	279
Restricted stock grants		-		46		-		58
Investor relations warrants		-		15		-		46
	$	447	$	215	$	867	$	383

For the periods presented, all stock based compensation expense was classified as a component within General and Administrative expenses on the Statements of Operations.

22

During the three and six months ended February 28, 2014 and 2013, the Company granted the following employee stock options:

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Number of options to purchase common shares		113,000		125,000		263,000		355,000
Weighted average exercise price	$	9.38	$	5.65	$	9.72	$	4.52
Term (in years)		10.0		10.0		10.0		10.0
Vesting Period (in years)		5		5		5		5
Fair Value (in thousands)	$	711	$	490	$	1,725	$	1,111

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

	Six Months Ended
	February 28, 2014			February 28, 2013
Expected Term	6.5 years			6.4 years
Expected Volatility		74	%		78.7	%
Risk free rate		1.97	%		1.06	%
Expected dividend yield		0.00	%		0.00	%
Forfeiture rate		0.00	%		0.00	%

The following table summarizes activity for stock options for the six months ended February 28, 2014:

	Number of Shares			Weighted Average Exercise Price
Outstanding, August 31, 2013		1,820,000		$	4.88
Granted		263,000		$	9.72
Exercised		(16,000	)	$	4.26
Outstanding, February 28, 2014		2,067,000		$	5.27

The following table summarizes information about issued and outstanding stock options as of February 28, 2014:

	Outstanding Options		Vested Options
Number of shares		2,067,000		553,000
Weighted average remaining contractual life	8.4 years		7.4 years
Weighted average exercise price	$	5.50	$	4.02
Aggregate intrinsic value (in thousands)	$	10,530	$	3,633

The estimated unrecognized compensation cost from unvested stock options as of February 28, 2014, which will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at February 28, 2014
Unrecognized compensation expense (in thousands)	$	5,306
Remaining vesting phase	3.5 years

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12.   Commitments and Contingencies

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company will own a working interest.  The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs.  As of February 28, 2014 the Company was participating in 12 horizontal and 5 directional wells that were in various stages of drilling or completion.  Costs accrued for these 17 wells in progress totaled $5.3 million.

Effective December 18, 2013, the Company amended its turn-key drilling contract with Ensign United States Drilling, Inc. (Ensign).  Under the contract, the Company secured the use of one automated drilling rig for one year.  Drilling operations under the contract commenced in early January 2014.  Total payments due to Ensign will depend upon a number of variables, including the depth of wells drilled, the target formation, and other technical details.  The Company estimates that during the remaining term of this contract, the rig will drill 20 horizontal wells with total drilling costs of approximately of $19 million.

13.   Related Party Transaction

The Company leases office space and an equipment yard from HS Land & Cattle, LLC (“HSLC”) in Platteville, Colorado.  HSLC is controlled by two of the Company’s executive officers.    Effective July 1, 2013, the monthly rent was increased to $15,000 from $10,000 to include additional areas leased by the Company, including a field operations office.  The twelve month lease arrangement with HSLC is renewable annually on July 1.   The following table summarizes the lease payments made to directors or their affiliates for the three and six months ended February 28, 2014 and 2013 (in thousands):

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Lease payments	$	45	$	30	$	90	$	60

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 three and six months ended February 28, 2014 and 2013 (in thousands):
 

	Three Months Ended				Six Months Ended
	February 28,		February 28,		February 28,		February 28,
	2014		2013		2014		2013
Total Royalty Payments	$	51	$	31	$	133	$	76

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

The following table supplements the cash flow information presented in the financial statements for the six months ended February 28, 2014 and 2013 (in thousands):

	Six Months Ended
	February 28,		February 28,
	2014		2013
Supplemental cash flow information:
Interest paid	$	501	$	294
Income taxes paid		-		-
Non-cash investing and financing activities:
Well costs payable	$	17,966	$	5,539
Assets acquired in exchange for common stock		10,122		14,284
Asset retirement costs and obligations		1,000		522

15.   Subsequent Events

Subsequent to February 28, 2014, the Company issued 375,500 shares of common stock pursuant to the exercise of Series C warrants.  The Company received cash proceeds of $2,253,000.

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

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding our financial condition as of February 28, 2014, and our results of operations for the three and six months and ended February 28, 2014 and 2013. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in our Form 10-K for the fiscal year ended August 31, 2013.

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”).  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.

In addition to the approximately 25,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold significant undeveloped acreage positions in (i) an area directly to the north and east of the Wattenberg Field that is considered the northern extension area, (ii) in an area around Yuma County that produces dry gas, and (iii) in western Nebraska.  While we do not expect to devote significant resources to the exploration and development of our holdings outside of the Wattenberg Field in the near future, we’ve begun an analysis of data obtained from a test well that was drilled in the northern extension area and continue to investigate developments in western Nebraska.

Since commencing active operations in September 2008, we have undergone significant growth.  Our growth was primarily driven by (i) our activities as an operator where we drill and complete productive oil and gas wells; (ii) our participation as a part owner in wells drilled by other operating companies; and (iii) our acquisition of producing oil wells from other individuals or companies.  As disclosed in the following table, as of February 28, 2014, we have completed, acquired, or participated in 376 gross (270 net) successful oil and gas wells.

	PRODUCTIVE WELLS
	OPERATED WELLS				NON-OPERATED WELLS
	Completed				Participated				Acquired				Total
Years ended:	Gross		Net		Gross		Net		Gross		Net		Gross		Net
August 31, 2009		-		-		2		1		-		-		2		1
August 31, 2010		36		28		-		-		-		-		36		28
August 31, 2011		20		19		11		3		72		51		103		73
August 31, 2012		51		48		13		4		4		4		68		56
August 31, 2013		27		26		21		6		36		34		84		66
February 28, 2014 (YTD)		11		11		11		1		61		34		83		46
Total		145		132		58		15		173		123		376		270

Early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations.  In May 2013 development efforts were shifted to horizontal wells.  Horizontal wells are significantly more expensive and take longer to drill and complete than vertical wells, but ultimately yield a greater return.  The eleven wells completed during the six months ended February 28, 2014 were horizontal wells at the Renfroe and Leffler prospects.  Substantially all of the wells planned for the remainder of fiscal 2014 are horizontal wells.

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In addition to the 376 wells that had reached productive status as of February 28, 2014, we were the operator of eight horizontal wells in progress, including wells on the Phelps and Union prospects. We were participating as a non-operator in ten gross (one net) horizontal wells that were in various stages of the drilling or completion process.  Wells in progress represent wells during the period of time when they are being drilled or completed.  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.  All of the wells in progress at February 28, 2014, are expected to commence production during the next six months.

As of February 28, 2014 we:

· were the operator of 11 horizontal wells that were producing oil and gas and we were participating as a non-operating working interest owner in 26 horizontal producing wells;

· were the operator of 278 vertical wells that were producing oil and gas and we were participating as a non-operating working interest owner in 61 vertical producing wells;

· held approximately 414,000 gross acres and 291,000 net acres under lease;

· had estimated proved reserves of 8.8 million barrels (“Bbls”) of oil and 55.2 billion cubic feet (“Bcf”) of gas;

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 are focused on the Wattenberg Field as it yields consistent results.  During 2013, we transitioned the focus of our efforts from vertical wells to horizontal wells.  Our plans for 2014 contemplate drilling or participating in 39 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.  Our cash flow from operations is increasing, and we plan to finance an increasing percentage of our growth with internally generated funds.  Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain.

Significant Developments

As an operator, we commenced production from the Renfroe prospect during September.  For us, the Renfroe prospect marked the successful transition to horizontal drilling for wells which we operate.  Previously, we focused our operational efforts on drilling vertical wells.  Drilling operations began at the Renfroe site during May 2013 and all wells began production during September 2013.  Production volumes from these five wells from the date of first production until February 28, 2014 (on an 8/8 ths basis), were approximately 155,000 bbls of oil and 428,000 mcf of gas, an average production rate of 250 BOE per day for each well.  Drilling and completion costs averaged $3.6 million per well.  The cash flow earned by these wells during their first six months averaged $2.4 million per well, or 66% of the initial investment.

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During the November quarter, we focused our drilling and completion efforts on the Leffler prospect.  The well pad location for Leffler is approximately 1.5 miles from the Renfroe location.  Six wells were drilled and completed on the Leffler pad, at an average cost of $3.6 million per well.  Production commenced during the quarter and volumes  from these six wells from the date of first production until February 28, 2014 (on an 8/8ths basis) were 59,443 bbls of oil and 146,041 mcf of gas.  Early production at Leffler was delayed by operational issues at the Eaton gas processing plant that purchases gas produced by these wells.  We expect these wells to reach full production capacity during our third fiscal quarter.

As a point of reference, we have interests in 15 net horizontal producing wells.  Eleven of the wells are operated by us and the remainder consists of our proportionate share in wells operated by other companies.  The combined production from those 15 horizontal wells is approximately equal to the production from all the other vertical wells combined.

After drilling the Leffler, the rig moved to the Phelps prospect, where it drilled six wells.  The rig was released in March.  Hydraulic fracturing, gas line connection and other completion activities of the Phelps location is scheduled for March and April, with full production expected in May.

Based upon our initial success with horizontal drilling at the Renfroe and Leffler prospects, we negotiated another drilling contract with Ensign United States Drilling, Inc. (“Ensign”), to use one automated drilling rig (Rig #131) for one year, commencing in January, 2014.  We expect Rig #131 to drill 24 horizontal wells for us during calendar year 2014.  It commenced drilling wells on the Union prospect in January and is expected to complete work at that location in April, when it is scheduled to begin work at the Kelly Farms prospect.

In March, we contracted with Ensign for use of Rig #134 for drilling the Eberle prospect.  The first of six wells was spud on March 22.

In November we completed two significant acquisitions that included producing properties.  On November 12, 2013, we completed an acquisition of assets from Trilogy Resources, LLC.  The assets included 21 producing oil and gas wells along with leases covering 800 net acres.  We assumed operational responsibility on the 21 producing wells.  Purchase consideration included cash of $16.0 million and 301,339 shares of restricted common stock.

On November 13, 2013, we completed an acquisition of assets from Apollo Operating, LLC.  The assets included interests in 38 wells operated by Apollo and approximately 1,000 net acres.  Operational responsibility for the 38 wells was transferred to us.  Other assets included in the transaction were smaller ownership interests in wells not operated by Apollo, including six wells drilled and operated by us, and a 25% interest in a Class II disposal well.  Purchase consideration included cash of $11.0 million and 550,518 shares of restricted common stock.

Based upon the initial evaluation of the assets acquired, substantially all of the purchase consideration will be allocated to oil and gas properties. Revenues and expenses from the acquired properties were consolidated with our operations commencing on the closing dates in November.

In separate transactions with the other owners of the disposal well, we acquired their interests in the assets.  Total consideration paid for the well approximated $5 million.  During the quarter ended February 28, 2014, oil and gas production from the acquired properties, including the disposal well, averaged 464 BOE per day.

We continue to improve our borrowing arrangement with a bank syndicate led by Community Banks of Colorado.  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.

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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.  We have entered into contracts for 2014 with various oil purchasers that we believe will provide sufficient take-away capacity for all of our oil production.  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 presented in our discussion about market conditions.

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 calendar years.

	2013		2012		2011		2010		2009
Average NYMEX prices
Oil (per bbl)	$	97.98	$	94.05	$	94.88	$	79.48	$	61.95
Natural Gas (per mcf)	$	3.73	$	2.75	$	4.00	$	4.37	$	3.94

For the various 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.

	Three Months Ended						Six Months Ended
	February 28,			February 28,			February 28,			February 28,
Oil (NYMEX WTI)	2014			2013			2014			2013
Average NYMEX Price	$	97.69		$	92.64		$	98.96		$	91.46
Realized Price	$	86.82		$	84.20		$	89.64		$	82.79
Differential	$	(10.87	)	$	(8.44	)	$	(9.32	)	$	(8.67	)
Gas (NYMEX Henry Hub)
Average NYMEX Price	$	4.98		$	3.33		$	4.31		$	3.29
Realized Price	$	5.93		$	4.77		$	5.44		$	4.54
Differential	$	0.95		$	1.44		$	1.13		$	1.25

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RESULTS OF OPERATIONS

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

For the three months ended February 28, 2014, compared to the three months ended February 28, 2013

For the three months ended February 28, 2014, we reported net income of $5.2 million compared to $2.7 million during the three months ended February 28, 2013.  Earnings per basic and diluted share were $0.07 for the three months ended February 28, 2014 compared to $0.05 for the three months ended February 28, 2013.  Significant differences between the two quarters include the rapid growth in reserves, producing wells, and daily production totals.  The impact of changing prices on our commodity hedge position also was significant to the comparison between periods.  As of February 28, 2014 we had 376 gross producing wells, compared to 220 gross producing wells as of February 28, 2013.

Oil and Gas Production and Revenues – For the three months ended February 28, 2014 we recorded total oil and gas revenues of $23.0 million compared to $10.9 million for the three months ended February 28, 2013, an increase of $12.1 million or 111%.  Our growth in revenue was the primarily the result of an increase in our production volume of 90% during the intervening period.

Our revenues are also sensitive to changes in commodity prices.  As shown in the following table, average realized prices have increased by 3% for oil and 24% for natural gas.  The following table presents actual realized prices, without the effect of hedge transactions.  The impact of hedge transactions is presented later in this discussion.

Key production information is summarized in the following table:

	Three Months Ended
	February 28,		February 28,
	2014		2013		Change
Production:
Oil (Bbls)		204,622		100,964		103%
Gas (McF)		887,494		512,069		73%
BOE (Bbls)		352,537		186,039		90%
Revenues (in thousands):
Oil	$	17,765	$	8,478		110%
Gas		5,263		2,443		115%
Total	$	23,028	$	10,921		111%
Average sales price:
Oil	$	86.82	$	84.20		3%
Gas	$	5.93	$	4.77		24%
BOE (Bbls)	$	65.32	$	58.70		11%

 “Bbl” refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.  “Mcf” refers to one thousand cubic feet.  A BOE (i.e. barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

Net oil and gas production for the three months ended February 28, 2014 was 352,537 BOE, or 3,917 BOE per day. For the three months ended February 28, 2013, production averaged 2,067 BOE per day, a year over year increase of 90%.  As a further comparison, average BOE production was 3,208 per day during the quarter ended November 30, 2013, a quarter over quarter increase of 22%.  The significant increases in production from the comparable prior periods reflect the additional wells that began production over the past three months, including production from the six horizontal wells at the Leffler prospect.

Production from horizontal wells significantly affects our daily production totals.  During 2014, production from 15 (net) horizontal wells was approximately 50% of our total production.  During the comparable 2013 period, production from horizontal wells was less than 10% of our total production.

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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):

	Three Months Ended
	February 28,		February 28,
	2014		2013
Production Costs	$	1,797	$	637
Work-Over		9		144
Lifting cost		1,806		781
Severance and ad valorem taxes		2,255		1,094
Total LOE	$	4,061	$	1,875
Per BOE:
Production costs	$	5.10	$	3.42
Work-Over		0.03		0.77
Lifting cost		5.13		4.19
Severance and ad valorem taxes		6.40		5.88
Total LOE	$	11.53	$	10.07

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 percent of revenues, taxes averaged 9.8% for the three months ended February 28, 2014 and 10% for the three months ended February 28, 2013.
 

On a BOE basis, production costs increased approximately 49% for the quarter ended February 28, 2014 compared to the quarter ended February 28, 2013.  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 the quarter, we incurred some additional costs related to the integration of the newly acquired producing properties.  In particular, the acquisition of the disposal well added about $0.50 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.

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Depreciation, Depletion, and Amortization (“DDA”) – DDA expense is summarized in the following table (in thousands):

	Three Months Ended
	February 28,		February 28,
	2014		2013
Depletion	$	7,491	$	3,117
Depreciation and amortization		228		59
Total DDA	$	7,719	$	3,176
DDA expense per BOE	$	21.90	$	17.07

For the three months ended February 28, 2014, depletion of oil and gas properties was $21.90 per BOE compared to $17.07 for the three months ended February 28, 2013.  The increase in the DD&A 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 the three months ended February 28, 2014, production represented 1.9% of the reserve base compared to 1.3% for the three months ended February 28, 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 intial reserves estimated for horizontal development prospects have been prepared using 160 acre spacing, compared to 20 acre spacing for vertical well development.  The larger spacing units reduce the Expected Ultimate Recovery (“EUR”) of oil and gas in place.  As more experience is gained with the development of horizontal sections, we believe that spacing units will decrease, effectively increasing the EUR for each section.

In addition to a change in the ratio of production to EUR, our DD&A rate was affected by the increasing costs of mineral leases 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 acquistion 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 acquisitions of Trilogy Resources, LLC and Apollo Operating, LLC 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.

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

	Three Months Ended
	February 28,			February 28,
(in thousands)	2014			2013
G&A costs incurred	$	2,074		$	1,511
Capitalized costs		(304	)		(123	)
Totals	$	1,770		$	1,388
G&A Expense per BOE	$	5.02		$	7.46

General and administrative includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others.  In an effort to minimize overhead costs, we employ a total staff of 26 employees, and use consultants, advisors, and contractors to perform certain tasks when it is cost-effective.

Although G&A costs have increased as we grow our business, we strive to maintain an efficient overhead structure.  For the quarter ended February 28, 2014, G&A was $5.02 per BOE compared to $7.46 for the quarter ended February 28, 2013.

Our G&A expense for the quarter ended February 28, 2014 includes share based compensation of $0.4 million compared to $0.2 million for the quarter ended February 28, 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 general and administrative 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.

Interest income (expense) – Neither interest expense nor interest income had a significant impact on our results of operations for the periods presented.  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 paragraphs titled “Oil and Gas Commodity Contracts” and “Hedge Activity Accounting” located in the Liquidity and Capital Resources section of this report, we use commodity contracts to mitigate the risks inherent in the price volatility of oil.  For the quarter ended February 28, 2014, we realized a cash settlement loss of $191,000 related to contracts that settled during the quarter.  For the quarter that ended February 28, 2013, the realized loss was $20,000.

In addition, we recorded an unrealized loss of $1.8 million to recognize the mark-to-market change in fair value of our futures contracts as of February 28, 2014.  Unrealized gains and losses are non-cash items.  In comparison, the unrealized loss reported for the quarter ended February 28, 2013, was $134,000.

Income taxes – We reported income tax expense of $2.3 million for the three months ended February 28, 2014, calculated at an effective tax rate of 33.7%.  During the comparable prior year period, we reported income tax expense of $1.6 million, calculated at an effective tax rate of 37%.  For both periods, it appears that the tax liability will be deferred into future years.  We were not required to remit any material federal or state income tax payments during 2013, and we do not anticipate doing so during 2014.

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During fiscal year 2014, we estimate that the effective tax rate will be 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 in excess of $41 million, which is available to offset future taxable income.  The NOL will begin to expire, if not used, in 2031.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  During 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.

For the six months ended February 28, 2014, compared to the six months ended February 28, 2013

For the six months ended February 28, 2014, we reported net income of $11.3 million compared to net income of $4.9 million for the six months ended February 28, 2013.  Earnings per basic and diluted share were $0.15 for the six months ended February 28, 2014, compared to $0.09 per basic and diluted share for the six months ended February 28, 2013.  Significant differences between the two periods include the rapid growth in reserves, producing wells, and daily production totals.  The impact of changing prices on our commodity hedge position also was significant to the comparison between periods.  As of February 28, 2014 we had 376 gross producing wells, compared to 220 gross producing wells as of February 28, 2013.

Oil and Gas Production and Revenues – For the six months ended February 28, 2014 we recorded total oil and gas revenues of $42.3 million compared to $19.2 million for the six months ended February 28, 2013, an increase of $23.1 million or 120%.  Our growth in revenue was the result of an increase in our production volume of 91% over the comparative period, and an increase in our average selling price per BOE of 15%.

Our revenues are sensitive to changes in commodity prices.  As shown in the following table, there has been an increase of 15% in average realized prices between the two periods.  The following table presents actual realized prices, without the effect of hedge transactions.  The impact of hedge transactions is presented later in this discussion.

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Key production information is summarized in the following table:

	Six Months Ended
	February 28,		February 28,
	2014		2013		Change
Production:
Oil (Bbls)		372,900		180,995		106	%
Gas (McF)		1,629,249		935,715		74	%
BOE (Bbls)		644,441		336,948		91	%
Revenues (in thousands)
Oil	$	33,425	$	14,985		123	%
Gas		8,869		4,250		109	%
Total	$	42,294	$	19,235		120	%
Average sales price:
Oil		89.64	$	82.79		8	%
Gas		5.44	$	4.54		20	%
BOE (Bbls)		65.63	$	57.09		15	%

“Bbl” refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.  “Mcf” refers to one thousand cubic feet.  A BOE (i.e. barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

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):

	Six Months Ended
	February 28,		February 28,
	2014		2013
Production Costs	$	3,000	$	1,160
Work-Over		79		144
Lifting cost		3,079		1,304
Severance and ad valorem taxes		4,271		1,908
Total LOE	$	7,350	$	3,212
Per BOE:
Production costs	$	4.66	$	3.44
Work-Over		0.12		0.43
Lifting cost		4.78		3.87
Severance and ad valorem taxes		6.63		5.66
Total LOE	$	11.41	$	9.53

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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 percent of revenues, taxes averaged 10% for the six months ended February 28, 2014 and 10% for the six months ended February 28, 2013.

On a BOE basis, production costs increased approximately 35% for the period ended February 28, 2014 compared to the period ended February 28, 2013.  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 the period, we incurred some additional costs related to the integration of the newly acquired producing properties.  In particular, the acquisition of the disposal well 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.

Depreciation, Depletion, and Amortization (“DDA”) – DDA expense is summarized in the following table:

	Six Months Ended
	(in thousands)
	February 28,		February 28,
	2014		2013
Depletion	$	12,981	$	5,379
Depreciation and amortization		329		117
Total DDA	$	13,310	$	5,496
DDA expense per BOE	$	20.65	$	16.31

For the six months ended February 28, 2014, depletion of oil and gas properties was $20.65 per BOE compared to $16.31 for the six months ended February 28, 2013.  The increase in the DD&A 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 the six months ended February 28, 2014, production represented 3.5% of the reserve base compared to 2.3% for the six months ended February 28, 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 160 acre spacing, compared to 20 acre spacing for vertical well development.  The larger spacing units reduce the Expected Ultimate Recovery (“EUR”) of oil and gas in place.  As more experience is gained with the development of horizontal sections, we believe that spacing units will decrease, effectively increasing the EUR for each section.

In addition to a change in the ratio of production to EUR, our DD&A rate was affected by the increasing costs of mineral leases 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 acquisitions 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 acquisitions of Trilogy Resources, LLC and Apollo Operating, LLC 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.

36

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

	Six Months Ended
	February 28,			February 28,
(in thousands)	2014			2013
G&A costs incurred	$	5,559		$	2,725
Capitalized costs		(621	)		(226	)
Totals	$	4,938		$	2,499
G&A Expense per BOE	$	7.66		$	7.42

General and administrative includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others.  In an effort to minimize overhead costs, we employ a total staff of 26 employees, and use consultants, advisors, and contractors to perform certain tasks when it is cost-effective.

Although G&A costs have increased as we grow our business, we strive to maintain an efficient overhead structure.  For the six months ended February 28, 2014, G&A was $7.66 per BOE compared to $7.46 for the six months ended February 28, 2013.

Our G&A expense for the six months ended February 28, 2014 includes share based compensation of $0.9 million compared to $0.4 million for the six months ended February 28, 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 general and administrative 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.

Interest income (expense) – Neither interest expense nor interest income had a significant impact on our results of operations for the periods presented.  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 paragraphs titled “Oil and Gas Commodity Contracts” and “Hedge Activity Accounting” located in the Liquidity and Capital Resources section of this report, we use commodity contracts to mitigate the risks inherent in the price volatility of oil.  For the six months ended February 28, 2014, we realized a cash settlement loss of $589,000 related to contracts that settled during the period.  For the six months that ended February 28, 2013, the realized loss was $20,000.

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In addition, we recorded an unrealized gain of $831,000 to recognize the mark-to-market change in fair value of our futures contracts for the six months ended February 28, 2014.  Unrealized gains and losses are non-cash items.  In comparison, the unrealized loss reported for the six months ended February 28, 2013, was $134,000.

Income taxes – We reported income tax expense of $5.7 million for the six months ended February 28, 2014, calculated at an effective tax rate of 34.2%.  During the comparable prior year period, we reported income tax expense of $2.9 million, calculated at an effective tax rate of 37%.  For both periods, it appears that the tax liability will be deferred into future years.  We were not required to remit any material federal or state income tax payments during 2013, and we do not anticipate doing so during 2014.

During fiscal year 2014, we estimate that the effective tax rate will be 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 in excess of $41 million, which is available to offset future taxable income.  The NOL will begin to expire, if not used, in 2031.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  During 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.

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LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses

Our sources and (uses) of funds for the six months ended February 28, 2014, and 2013 are summarized below (in thousands):

	Six Months Ended
	February 28,			February 28,
	2014			2013
Cash provided by operations	$	33,354		$	17,675
Acquisition of oil and gas properties and equipment		(87,497	)		(57,579	)
Proceeds from short-term investments		39,990			-
Equity financing activities		29,070			407
Net borrowings		-			38,486
Net increase in cash and cash equivalents	$	14,917		$	(1,011	)

Net cash provided by operating activities was $33.3 million and $17.7 million for the six months ended February 28, 2014 and 2013, respectively.  We received $29.1 million from the exercise of Series C warrants at $6.00 per share.

Credit Arrangements

We currently maintain a revolving credit facility that provides for maximum borrowings of $300 million, subject to a borrowing base limitation.  As of February 28, 2014, the borrowing base limit was $90 million and there were borrowings of $37 million outstanding.  Community Banks of Colorado serves as the administrative agent for the six banks participating in the facility.  The facility has a maturity date of November 28, 2016.

Although we have historically used the facility to fund the acquisition of producing properties, funds are available for general corporate purposes.  Availability under the facility is subject to a borrowing base that is set semi-annually by the lenders, with an option for additional redeterminations in certain circumstances.  The amount of the borrowing base set by the lenders depends upon several factors, but is primarily based upon an assessment of future cash flows for proved properties.

The facility is primarily collateralized by our oil and gas assets.  The agreement imposes limitations on us, and requires lender approval for certain actions, such as the payment of cash dividends.  Certain covenants, customary to this type of facility, require us to maintain certain financial ratios.  We are in compliance with all covenants at February 28, 2014.

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Reconciliation of Cash Flow

The cash flow statement reports actual cash expenditures for capital expenditures using a strict cash flow basis, which differs from the “all-inclusive” basis used to calculate other amounts reported in our financial statements.  Specifically, cash payments for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made.  On the “all-inclusive” basis, capital expenditures totaled $91.2 million and $72.1 million for the six months ended February 28, 2014 and 2013, respectively, compared to cash payments of $87.5 million and $57.6 million, respectively.  A reconciliation of the differences is summarized in the following table (in thousands):

	Six Months Ended
	February 28,			February 28,
	2014			2013
Cash payments for capital expenditures	$	87,497		$	57,579
Accrued costs, beginning of period		(25,491	)		(5,733	)
Accrued costs, end of period		17,966			5,539
Non-cash acquisitions, common stock		10,122			14,284
Other		1,112			522
All inclusive capital expenditures	$	91,206		$	72,191

Capital Expenditures

During the six months ended February 28, 2014, we engaged in drilling or completion activities on 14 horizontal wells that we will operate, including six wells on the Leffler prospect that commenced production during the second fiscal quarter, five wells on the Phelps prospect, and three wells on the Union prospect.  We also drilled a test well at the Buffalo Run prospect to examine the potential for production from the Niobrara, Codell, Greenhorn, and D-Sand formation.  Core samples from the test well are currently being analyzed.  We participated in drilling and completion activities on 2 net non-operated wells.  In addition, we invested $33.8 million in the acquisition of mineral assets from Trilogy Resources LLC and Apollo Operating LLC, including approximately $8.3 million paid in the form of common stock.  Other expenditures included $5.2 million for a disposal well and $9.5 for the acquisition of lands, leases, and other mineral assets.

Capital Requirements

Our primary need for cash for the remainder of the fiscal year ending August 31, 2014, will be to fund our drilling and acquisition programs.  Our cash requirements have increased significantly as we implement our horizontal drilling program.  Each horizontal well is estimated to cost between $3.5 million and $4.0 million, depending on the length of the lateral wellbore, the number of stages, and other variables.  In comparison, the cost of a vertical well approximated $0.7 million.  Under the revised plans for our 2014 capital budget, we estimate capital expenditures of approximately $189 million, consisting of drilling and completion costs for wells which we operate, our pro-rata share of the costs on wells drilled by other operators, and the costs of acquiring properties.  It is our plan to drill 34 net horizontal wells during the year and to participate in 5 net non-operated horizontal wells at a total cost of $150 million.  We expect to drill or participate in 5 vertical wells at a total cost of $4 million.  Leasing activities will ultimately be slightly greater than the original budget of $5.0 million, and we acquired a disposal well that was not anticipated in the original budget.  The acquisition of producing properties was budgeted for $30 million, and we have spent about $34 million.  However, approximately $10 million of our acquisitions have been for stock instead of cash, and we are still targeting capital expenditures of $189 million that will require cash.  Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.

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

For 2014, we believe that available capital resources, including cash and short term investment on hand plus cash flow from operations plus additional borrowings available under our revolving line of credit facility, will be sufficient to meet our liquidity needs during the fiscal year.

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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 position will generally cover a substantial portion of our forecasted production for a period of 24 months.  We typically enter into contracts covering between 40% and 80% of anticipated production levels.  As of February 28, 2014, all of our derivative contracts related to crude oil, and we had no contracts covering natural gas production. 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 quarter ended February 28, 2014, we reported an unrealized commodity activity loss of $1.8 million.  Unrealized gains and losses are non-cash items.  We also reported a realized loss of $191,000, representing the cash settlement cost for contracts settled during the period.

At February 28, 2014, we had net derivative liabilities of $1.8 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 February 28, 2014 may differ significantly from the realized values at their respective settlement dates.

Use of Non-GAAP Financial Measures

We use "adjusted EBITDA" as a non-GAAP financial measure when management evaluates our performance.  This non-GAAP measure of financial performance is not defined under U.S. GAAP and should be considered in addition to, not as a substitute for, indicators of financial performance reported in accordance with U.S. GAAP.  We may use non-GAAP financial measures that are not comparable to measures with similar titles reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.  In our reports, we provide a Reconciliation of Non-GAAP Financial Measures that includes a detailed description of these measures as well as a reconciliation of each to its most similar U.S. GAAP measure.

Reconciliation of Non-GAAP Financial Measures

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

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The following table presents a reconciliation of our non-GAAP financial measure to its nearest GAAP measure (in thousands).

	Three Months Ended						Six Months Ended
	February 28,			February 28,			February 28,			February 28,
	2014			2013			2014			2013
Adjusted EBITDA:
Net income	$	5,161		$	2,732		$	11,261		$	4,970
Depreciation, depletion and amortization		7,719			3,176			13,310			5,496
Income tax expense		2,338			1,604			5,725			2,919
Stock based compensation		448			215			867			383
Change in fair value - derivatives		1,805			134			(831	)		134
Interest income		(17	)		(8	)		(48	)		(15	)
Adjusted EBITDA	$	17,454		$	7,853		$	30,284		$	13,887

TREND AND OUTLOOK

In early September, 2013, Northern Colorado experienced flooding that covered a wide area and caused extensive damage.  Significant damage was done to the area’s infrastructure, such as roads, bridges, and water treatment facilities, as well as to numerous structures within the flood zone.  Approximately 20 of our well sites were directly affected by the flood waters.  However, the damage to our facilities was not severe, and there were no hydrocarbon spills at our sites.  Most of the wells were repaired within a few weeks and all of the sites were  returned to service during our first fiscal quarter.  The cost of repairs did not have a significant impact on our financial statements.

During fiscal year 2012, the Wattenberg Field experienced elevated line pressure in the natural gas and liquids gathering system.  Issues with high line pressure continue to impact the system.  High line pressure restricts our ability to produce crude oil and natural gas.  As line pressures increase, it becomes more difficult to inject gas produced by our wells into the pipeline.  When line pressure is greater than the operating pressure of our wellhead equipment, the wellhead equipment is unable to inject gas into the pipeline, and our production is restricted or shut-in.  Since our wells produce a mixture of crude oil and natural gas, restrictions in gas production also restrict oil production.  Although various factors can cause increased line pressure, a significant factor in our area is the success of horizontal wells that have recently been drilled.  As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle.  Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells.  The pace of horizontal drilling in the Wattenberg is accelerating and it appears that it will be some time before the gathering system will have sufficient capacity to eliminate the high line pressure issues.

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

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

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.  We have entered into contracts for 2014 with various oil purchasers that we believe will provide sufficient take-away capacity for all of our oil production.  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.

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

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

A decline in oil and gas prices (i) will reduce our cash flow which in turn will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, and (v) may result in marginally productive oil and gas wells being abandoned as non-commercial.  However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

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

CRITICAL ACCOUNTING POLICIES

There have been no changes in our critical accounting policies since August 31, 2013, and a detailed discussion of the nature of our accounting practices can be found in the section titled “Critical Accounting Policies”  in Part II, Item 7 of our Annual Report on Form 10-K for the year ended August 31, 2013.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

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

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

• The success of our exploration and development efforts;

• The price of oil and gas;

• The worldwide economic situation;

• Any change in interest rates or inflation;

• The willingness and ability of third parties to honor their contractual commitments;

• Our ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital;

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

• Our costs of production;

• Environmental and other regulations, as the same presently exist or may later be amended;

• Our ability to identify, finance and integrate any future acquisitions;

• The volatility of our stock price, and

• Changes to tax policy

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

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

Interest Rate Risk - At February 28, 2014 we had debt outstanding under our bank credit facility totaling $37.0 million.  Interest on our bank credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate (LIBOR).  At February 28, 2014, the interest rate was 2.66%, based upon LIBOR plus a margin of 2.5%.  We are currently incurring interest at a rate of 2.66%, and we are exposed to interest rate risk on the bank credit facility if the variable reference rates increase.  If interest rates increase, our interest expense would increase and our available cash flow would decrease.

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Counterparty Risk –Effective January 1, 2013, we entered into commodity swap agreements. These derivative financial instruments present certain market and counterparty risks. We seek to manage the counterparty risk associated with these contracts by limiting transactions to long standing and established counterparties.  We are exposed to potential losses if a counterparty fails to perform according to the terms of the agreement. We do not require collateral or other security to be furnished by counterparties to our derivative financial instruments. There can be no assurance, however, that our practice effectively mitigates counterparty risk. The failure of any of the counterparties to our hedging arrangements to fulfill their obligations to us could adversely affect our results of operations and cash flows.

Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q.  Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.  Based on that evaluation, our management concluded that, as of February 28, 2014, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended February 28, 2014, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II

Item 6.                 Exhibits

a.  Exhibits

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

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

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

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

101.INS XBRL Instance Document

101.SCH XBRL Schema Document

101.CAL XBRL Calculation Linkbase Document

101.DEF XBRL Definition Linkbase Document

101.LAB XBRL Label Linkbase Document

101.PRE XBRL Presentation Linkbase Document

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SIGNATURES

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

	SYNERGY RESOURCES CORPORATION
Date:  April 4, 2014	By:	/s/ Ed Holloway
		Ed Holloway, Co-Chief Executive Officer

Date: April 4, 2014	By:	/s/ William Scaff, Jr.,
		William Scaff, Jr., Co-Chief Executive Officer

Date: April 4, 2014	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Principal Financial and Accounting Officer

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