syrg_10q-053113.htm

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.

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).

	May 31, 2013			August 31, 2012
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	19,211		$	19,284
Accounts receivable:
Oil and gas sales		6,262			3,606
Joint interest billing		3,901			3,268
Inventory		252			178
Commodity derivative, current		320			-
Other current assets		57			131
Total current assets		30,003			26,467

Property and equipment
Evaluated oil and gas properties, net		129,839			59,936
Unevaluated oil and gas properties		42,695			32,484
Other property and equipment, net		276			282
Property and equipment, net		172,810			92,702

Deferred tax asset, net		-			332
Commodity derivative		48			-
Other assets		680			1,230

Total assets	$	203,541		$	120,731

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Trade accounts payable	$	5,456		$	1,499
Well costs payable		6,625			5,733
Revenue payable		6,400			4,160
Production taxes payable		5,571			3,805
Other accrued expenses		267			395
Total current liabilities		24,319			15,592

Revolving credit facility		44,486			3,000
Deferred tax liability, net		4,288			-
Asset retirement obligations		2,694			1,027
Total liabilities		75,787			19,619
Commitments and contingencies (See Note 13)

Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding		-			-
Common stock - $0.001 par value, 100,000,000 shares authorized:
55,700,330 and 51,409,340 shares issued and outstanding, respectively		56			51
Additional paid-in capital		141,929			123,876
Accumulated deficit		(14,231	)		(22,815	)
Total shareholders' equity		127,754			101,112

Total liabilities and shareholders' equity	$	203,541		$	120,731

	Three Months Ended						Nine Months Ended
	May 31,			May 31,			May 31,			May 31,
	2013			2012			2013			2012

Oil and gas revenues	$	12,314		$	7,522		$	31,549		$	18,220

Expenses
Lease operating expenses		1,048			456			2,352			1,048
Production taxes		1,067			703			2,975			1,672
Depreciation, depletion,
and amortization		3,820			1,834			9,316			4,600
General and administrative		1,514			682			4,013			2,559
Total expenses		7,449			3,675			18,656			9,879

Operating income		4,865			3,847			12,893			8,341

Other income (expense)
Commodity derivative gain		540			-			386			-
Interest expense, net		(94	)		-			(94	)		-
Interest income		5			16			20			27
Total other income		451			16			312			27

Income before income taxes		5,316			3,863			13,205			8,368

Deferred income tax (provision) benefit		(1,701	)		(1,432	)		(4,620	)		1,809
Net income	$	3,615		$	2,431		$	8,585		$	10,177

Net income per common share:
Basic	$	0.07		$	0.05		$	0.16		$	0.23
Diluted	$	0.06		$	0.05		$	0.15		$	0.22

Weighted average shares outstanding:
Basic		55,238,098			51,292,810			53,283,695			44,968,566
Diluted		58,918,586			53,174,793			55,623,990			46,775,994

	Nine Months Ended
	May 31, 2013			May 31, 2012
Cash flows from operating activities:
Net income	$	8,585		$	10,177
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization		9,316			4,600
Provision (benefit) for deferred taxes		4,620			(1,809	)
Stock-based compensation		994			323
Valuation (increase) decrease in commodity derivatives		(368	)		-
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales		(2,656	)		(1,220	)
Joint interest billing		(633	)		(306	)
Inventory		(74	)		267
Accounts payable
Trade		3,957			(1,047	)
Revenue		2,240			3,944
Production taxes		1,766			2,016
Accrued expenses		(128	)		150
Other		624			(17	)
Total adjustments		19,658			6,901
Net cash provided by operating activities		28,243			17,078

Cash flows from investing activities:
Acquisition of property and equipment		(70,269	)		(34,026	)
Net cash used in investing activities		(70,269	)		(34,026	)

Cash flows from financing activities:
Proceeds from sale of stock		-			40,250
Offering costs		-			(2,828	)
Proceeds from exercise of warrants		467
Proceeds from revolving credit facility		41,486			3,000
Payment of related party note payable		-			(5,200	)
Net cash provided by financing activities		41,953			35,222

Net increase (decrease) in cash and cash equivalents		(73	)		18,274

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

Cash and cash equivalents at end of period	$	19,211		$	27,765

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

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, 2012.

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.

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.

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 nine months ended May 31, 2013 or May 31, 2012.

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

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

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 4 for additional information.

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.

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.

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.

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 12 for additional information.

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				Nine Months Ended
	May 31,		May 31,		May 31,		May 31,
	2013		2012		2013		2012

Weighted-average shares outstanding-basic		55,238,098		51,292,810		53,283,695		44,968,566
Potentially dilutive common shares from:
Stock Options		2,338,711		1,458,261		2,084,956		1,406,516
Warrants		1,341,777		423,722		255,339		400,912
		3,680,488		1,881,983		2,340,295		1,807,428
Weighted-average shares outstanding - diluted		58,918,586		53,174,793		55,623,990		46,775,994

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.

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

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

As discussed in Note 7, 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.

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.


	As of May 31, 2013			As of August 31, 2012
	(in thousands)			(in thousands)
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	36,070		$	27,070
Wells in progress		6,625			5,414
Subtotal, unevaluated costs		42,695			32,484

Evaluated costs:
Producing and non-producing		148,693			69,667
Total capitalized costs		191,388			102,151
Less, accumulated depletion		(18,854	)		(9,731	)
Oil and gas properties, net		172,534			92,420

Other property and equipment:
Vehicles		200			164
Leasehold improvements		71			71
Office equipment		203			157
Land		44			44
Less, accumulated depreciation		(242	)		(154	)
Other property and equipment, net		276			282

Total property and equipment, net	$	172,810		$	92,702

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 and nine months ended May 31, 2013 and 2012 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 and nine months ended May 31, 2013 and 2012, similarly revealed no impairment of oil and gas assets.

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

The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of December 5, 2012. The following table summarizes the 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	December 5, 2012
Consideration Given
Cash	$	29,012
Synergy Resources Corp. Common Stock *		13,515

Total consideration given	$	42,527

Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	43,143
Unproved oil and gas properties		466
Total fair value of oil and gas properties acquired		43,609

Working capital	$	(842	)
Asset retirement obligation		(240	)

Fair value of net assets acquired	$	42,527

Working capital acquired was estimated as follows:
Accounts receivable		521
Accrued liabilities and expenses		(1,363	)

Total working capital	$	(842	)

The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock, additional depreciation expense, costs directly attributable to the acquisition and costs incurred as a result of the Orr Energy acquisition. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Three Months Ended				Nine Months Ended
	(in thousands)				(in thousands)
	May 31,		May 31,		May 31,		May 31,
	2013		2012		2013		2012

Oil and Gas Revenues	$	12,314	$	9,182	$	33,086	$	24,034

Net income	$	3,615	$	3,298	$	9,124	$	12,226

Earnings per common share
Basic	$	0.07	$	0.06	$	0.17	$	0.25
Diluted	$	0.06	$	0.06	$	0.16	$	0.24

	Three Months Ended						Nine Months Ended
	(in thousands)						(in thousands)
	May 31			May 31			May 31			May 31
	2013			2012			2013			2012

Revolving bank credit facility at a variable rate	$	381		$	38		$	756		$	83
Related party note payable at 5.25%		-			-			-			68
Amortization of debt issuance costs		40			-			110			-
Less, interest capitalized		(327	)		(38	)		(772	)		(151	)
Interest expense, net	$	94		$	-		$	94		$	-

On November 28, 2012, the Company entered into an amendment to its revolving credit facility (“LOC”) with Community Banks of Colorado, successor in interest to Bank of Choice. The amended agreement adds CoBiz banks, dba Colorado Business Bank, and Amegy Bank National Association, as lenders (collectively the “banks”). The amended terms include an increase to $150 million in the maximum amount of borrowings available to the Company, subject to a borrowing base limitation. Community Banks of Colorado acts as the administrative agent for the banks with respect to the LOC. The credit facility expires on November 28, 2016.

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate. The interest rate pricing grid includes pricing differentials based upon LOC utilization. For each borrowing, the Company designates its choice from the pricing grid, which can be either the Prime Rate plus a margin of 0% to 1%, or London Interbank Offered Rate (LIBOR) plus a margin of 2.75% to 3.25%. The average interest rate incurred during the nine months ended May 31, 2013, was 3.3%. As of May 31, 2013, the interest rate on the outstanding balance was 3.5%, representing LIBOR plus 3.0%.

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain customary financial ratios. Certain of the Company’s assets, including substantially all developed properties, have been designated as collateral under the arrangement. The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves. The borrowing base limitation is generally subject to redetermination on a semi-annual basis. The borrowing base was recently increased from $47 million to $75 million based upon the reserve report as of February 28, 2013. At the same time, Texas Capital Bank, N. A, was added to the LOC as an additional lender.

Terms of the LOC require the Company to maintain hedge contracts covering future production quantities that are included in the borrowing base. Subsequent to an initial transition period, the Company is required to hedge a minimum of 45% of scheduled production for a rolling 24 months. The Company is not allowed to hedge more than 80% of scheduled production. Information about the Company’s hedging position is presented in Note 8.

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to its original use. The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. The revisions recognized during 2013 were primarily from increases in the undiscounted abandonment cost estimates.

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

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

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

Contract Type

Basis (1)

Quantity

(Bbl/month)

Strike Price

($/Bbl)

Term

Collar

NYMEX

3,014

$87.00 - $102.50

Jun 1, 2013 - Dec 31, 2013

Collar

NYMEX

1,840

$85.00 - $98.50

Jan 1, 2014 - Dec 31, 2014

Collar

NYMEX

7,000

$80.00 - $92.50

Jan 1, 2015 - Jun 30, 2015

Contract Type

Basis (1)

Quantity

(Bbl/month)

Swap Price

($/Bbl)

Term

Swap

NYMEX

3,014

$91.70

Jun 1, 2013 - Dec 31, 2013

Swap

NYMEX

6,000

$96.35

Jun 1, 2013 - Dec 31, 2013

(2)

Swap

NYMEX

8,000

$94.45

Jun 1, 2013 - Dec 31, 2013

2013 Total/Average

17,014

$94.17

Swap

NYMEX

1,840

$90.80

Jan 1, 2014 - Dec 31, 2014

Swap

NYMEX

2,000

$90.11

Jan 1, 2014 - Dec 31, 2014

Swap

NYMEX

5,000

$90.50

Jan 1, 2014 - Dec 31, 2014

2014 Total/Average

8,840

$90.47

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

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

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

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

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

The 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 May 31, 2013, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as level 2.

The Company leases office space and an equipment yard from HS Land & Cattle, LLC (“HSLC”) in Platteville, Colorado for $10,000 per month. The twelve month lease arrangement with HSLC is renewable annually on July 1. Under the lease arrangement, the Company paid HSLC $30,000 and $90,000 during each of the three and nine months ended May 31, 2013 and 2012. HSLC is controlled by two of the Company’s executive officers.

	As May 31,		As August 31,
	2013		2012
Preferred stock, shares authorized		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding		-		-
Common stock, shares authorized		100,000,000		100,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding		55,700,330		51,409,340

	Number of Warrants			Weighted Average Exercise Price
Outstanding, August 31, 2012		15,031,067		$	6.02
Granted		-			-
Exercised		(548,185	) *	$	1.94
Expired		(5,148,000	)	$	6.78
Outstanding, May 31, 2013		9,334,882		$	5.81

* Warrants exercised include 435,719 warrants exercised on a cashless basis in exchange for 329,992 shares of common stock, which reduced the net cash proceeds to the Company to $0.85 per warrant.

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.

	Three Months ended				Nine Months ended
	May 31		May 31		May 31		May 31
	2013		2012		2013		2012
Number of options to purchase common shares		535,000		50,000		890,000		150,000
Weighted average exercise price	$	6.68		3.25	$	5.82	$	2.95
Term (in years)		10.0		10		10.0		10
Vesting Period (in years)		5		5		5		4-5
Fair Value (in thousands)	$	2,371		102	$	3,482	$	280

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company will own a working interest. The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs. As of May 31, 2013, the Company was participating in six horizontal wells and two vertical wells that were in various stages of drilling or completion. Costs accrued for these eight wells in progress totaled $2.4 million. Also as of May 31, 2013, the Company had agreed to participate in 14 future horizontal wells and five future vertical wells and expects that its share of future costs will be approximately $6.2 million.

In addition, the Company has been notified by other operators of their non-binding intent to drill 41 horizontal wells and 2 vertical wells in which the Company may own an interest. As of May 31, 2013, the Company had not yet committed to participate in these potential wells. Since drilling plans frequently change, the Company does not begin to track its working interest or cost obligation of potential wells until it has committed to participate in the well.

Effective April 25, 2013, the Company entered into a turn-key drilling contract with Ensign United States Drilling, Inc. (Ensign) to drill a minimum four horizontal wells. Drilling commenced on May 16, 2013 and is expected to be completed by fiscal year-end. Total payments due to Ensign will depend upon a number of variables, including the location of wells drilled, the target formation, and other technical details. The Company estimates that this contract will cover the drilling of five horizontal wells with total drilling costs of approximately $5.5 million.

	Nine Months ended
	(in thousands)
	May,		May,
	2013		2012
Supplemental cash flow information:
Interest paid	$	756	$	225
Income taxes paid		-		-

Non-cash investing and financing activities:
Well costs payable	$	6,625	$	5,878
Assets acquired in exchange for common stock		16,594		1,494
Asset retirement costs and obligations		1,562		214

On June 19, 2013, the Company closed on the sale of 13,225,000 shares of common stock pursuant to an underwriting agreement with Johnson Rice & Company LLC, acting severally on behalf of itself and the other underwriters. The public offering price was $6.25 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $78.3 million. Proceeds from the offering are expected to partially fund the Company’s capital expenditures for fiscal year 2014.

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding the financial condition as of May 31, 2013, and the results of operations for the three months and nine months ended May 31, 2013 and 2012. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in the Company’s Form 10-K for the fiscal year ended August 31, 2012.

Synergy Resources Corporation (“we,” “our,” “us” or “the Company”) is a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin (“D-J Basin”) of Colorado. Substantially all of our producing wells are either in or adjacent to the Wattenberg Field, which has a history as one of the most prolific production areas in the country. In addition to the approximately 17,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold significant undeveloped acreage positions in (i) the northern extension area of the D-J Basin, (ii) in an area around Yuma County that produces dry gas, and (iii) in western Nebraska. While we do not expect to devote significant resources to the exploration and development of our holdings outside of the Wattenberg Field in the near future, we recently participated in a well in Yuma County that is producing dry gas and we expect to drill two test wells in the northern extension area during the next seven months.

Since commencing active operations in September 2008, we have undergone significant growth. As disclosed in the following table, as of May 31, 2013, we have drilled, acquired, or participated in 294 gross oil and gas wells. A total of 285 wells had reached productive status at May 31, 2013 and there were nine wells at various stages of the drilling and completion process. We have not drilled any non-productive wells.

Our strategy for continued growth includes additional drilling activities, acquisition of existing wells, and recompletion of wells to more rapidly access and/or extend reserves through improved hydraulic stimulation techniques. We attempt to maximize our return on assets by drilling and operating wells in which we have a majority net revenue interest. We attempt to limit our risk by drilling in proven areas.

Historically, we are a company that has drilled vertical wells. All wells that we drilled, participated in, or acquired prior to 2012 were relatively low-risk vertical wells. Newer technology allows extraction of hydrocarbon deposits by drilling horizontal wells. The new technology is evolving rapidly. In 2012, we began to participate with other operators in horizontal wells. As of May 31, 2013, nine of those wells had reached productive status. Our participation in those wells allowed us to evaluate the new technology and formulate plans for horizontal wells that we would drill and operate.

Our most recent analysis indicates that the return from horizontal wells exceeds the return from vertical wells. We plan to transition our primary emphasis from vertical drilling to horizontal drilling during the remainder of the fiscal year. During May 2013, drilling operations commenced on the first horizontal well at our Renfroe prospect.

Our capital expenditure budget for 2013 anticipated participation in ten horizontal wells operated by others and included plans to drill and operate four horizontal wells for our own account. During the nine months ended May 31, 2013, we had participated in ten wells (including both wells that had reached productive status and wells that were still in process), and we had agreed to participate in 14 additional wells, most of which will commence drilling operations after the conclusion of our fiscal year. We expect to drill five wells on the Renfroe prospect by August 31, 2013.

During our start-up years, 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.

As an operator, we began our transition from vertical drilling to horizontal drilling. During May 2013 drilling operations commenced on the first horizontal well at our Renfroe prospect. By the end of June, we had completed the drilling phase for two wells and were drilling the third horizontal well on the Renfroe pad where we initially expect to drill five wells.

During the first half of the fiscal year, we continued our active vertical well drilling program. We substantially completed our 2013 plans for drilling vertical wells during the second quarter. During the third quarter, our efforts shifted to horizontal wells to be drilled during the remaining months of the fiscal year. From September 1, 2012, through May 31, 2013, we drilled 27 new vertical wells and brought all of them into productive status. In addition, the ten vertical wells that were in progress at August 31, 2012 reached productive status. With regard to activity on wells in which we participate as a non-operating interest owner, 21 wells were drilled (including ten horizontal wells) and 21 wells reached productive status (including six horizontal wells) during the nine month period. Eight non-operated wells were in various stages of drilling or completion at May 31, 2013.

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

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

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

In December, we utilized a portion of the financing available through this arrangement to fund the acquisition of the Orr assets. We currently have approximately $30 million available for future borrowings if needed. Additional borrowings, if any, are expected to be used to fund acquisitions, expenditures for well drilling and development, and to provide working capital.

Interest accrues at a variable rate, which will equal or exceed the minimum rate of 2.5%. The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization. At our option, interest rates will be referenced to the Prime Rate plus a margin of 0% to 1%, or the London InterBank Offered Rate plus a margin of 2.5% to 3.25%. The maturity date for the arrangement is November 28, 2016.

We commenced our commodity hedging program beginning January 1, 2013. As of May 31, 2013, we have hedged approximately 310,000 barrels of oil through June 30, 2015. We use both commodity swaps and collars. Our hedge positions generated a gain of $540,000 during the quarter, consisting of realized gains of $38,000 and net unrealized gains of $502,000. Our commodity hedge positions are revalued at fair value for each reporting period, and can have a significant impact on reported results of operations.

For the three months ended May 31, 2013, we reported net income of $3.6 million compared to $2.4 million during the three months ended May 31, 2012. Earnings per basic share were $0.07 for the three months ended May 31, 2013 compared to $0.05 for the three months ended May 31, 2012. Earnings per diluted share were $0.06 for the three months ended May 31, 2013 compared to $0.05 for the three months ended May 31, 2012. The comparison between the two periods was primarily influenced by increasing revenues and expenses associated with the increased number of producing wells including the effect of income taxes. As of May 31, 2013 we had 285 gross producing wells (223 wells net), compared to 170 gross producing wells (130 wells net) as of May 31, 2012.

Oil and Gas Production and Revenues – For the three months ended May 31, 2013 we recorded total oil and gas revenues of $12.3 million compared to $7.5 million for the three months ended May 31, 2012, an increase of $4.8 million or 64%. Our growth in revenue was the result of an increase in our production volume of 66% during the intervening period. For the quarter, our gas/oil ratio (“GOR”) was 44/56. During the comparable prior period, our GOR was 46/54.

Our revenues are sensitive to changes in commodity prices. As shown in the following table, average realized prices have declined by 7.9% for oil and increased 31.5% for natural gas. To mitigate the impact of short term price fluctuations, we engage in commodity swap and collar transactions. The following table presents actual realized prices, without the effect of hedge transactions.

	Three Months Ended
	May 31,		May 31,
	2013		2012		Change
Production:
Oil (Bbls)		115,225		69,230		66.4	%
Gas (McF)		553,909		333,200		66.2	%
BOE (Bbls)		207,543		124,763		66.3	%

Revenues (in thousands):
Oil	$	9,677	$	6,314		53.3	%
Gas		2,637		1,208		118.3	%
Total	$	12,314	$	7,522		63.7	%

Average sales price:
Oil	$	83.98	$	91.21		(7.9	%)
Gas	$	4.76	$	3.62		31.5	%
BOE (Bbls)	$	59.33	$	60.29		(1.6	%)

Net oil and gas production for the three months ended May 31, 2013 was 207,543 BOE, or 2,256 BOE per day. For the three months ended May 31, 2012, production averaged 1,356 BOE per day, a year over year increase of 66%. As a further comparison, average BOE production was 2,067 per day during the quarter ended February 28, 2013, a quarter over quarter increase of 9%. The significant increases in production from the comparable prior periods reflect the additional wells that began production over the past twelve months and production from the wells acquired in the Orr transaction. The Orr wells provided approximately 326 BOE per day during the quarter.

The increased production as described in the preceding paragraph has been achieved despite production difficulties encountered on our older vertical wells. Our vertical wells have generally been affected by pressure and capacity issues in the gathering system and we have been unable to produce at full capacity. See the section titled “Trend and Outlook” for additional information.

	Three Months Ended
	(in thousands)
	May 31,		May 31,
	2013		2012
Production Costs	$	993	$	352
Work-Over		55		-
Other		-		104
Lifting cost		1,048		456
Severance and ad valorem taxes		1,067		703
Total LOE	$	2,115	$	1,159

Per BOE:
Production costs	$	4.78	$	2.82
Work-Over		0.27		-
Other		-		0.83
Lifting cost		5.05		3.65
Severance and ad valorem taxes		5.14		5.64
Total LOE	$	10.19	$	9.29

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% for the three months ended May 31, 2013 and 9% for the three months ended May 31, 2012.

On a BOE basis, production costs increased approximately 70% for the quarter ended May 31, 2013 compared to the quarter ended May 31, 2012. The increase is primarily due to costs incurred to mitigate production difficulties within the Wattenberg Field. We incurred additional costs to provide wellhead compression at some well locations. In addition, we began a work-over program to improve pressures and flows from older wells.

The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves. The capitalized costs of evaluated oil and gas properties are depleted using the units-of-production method based on estimated reserves. Production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate. For the three months ended May 31, 2013, production volumes of 207,543 BOE and estimated net proved reserves of 13,630,953 BOE were the basis of the depletion rate calculation. For the three months ended May 31, 2012, production volumes of 124,763 BOE and estimated net proved reserves of 7,756,563 BOE were the basis of the depletion rate calculation. Depletion expense per BOE increased approximately 25% primarily as a result of additional DDA associated with newly acquired assets.

	Three Months Ended
	(in thousands)
	May 31,			May 31,
	2013			2012
Cash based compensation	$	646		$	390
Stock based compensation		611			108
Professional fees		318			173
Insurance		54			33
Other general and administrative		74			64
Capitalized general and administrative		(189	)		(86	)
Totals	$	1,514		$	682

G&A Expense per BOE	$	7.29		$	6.87

Cash based compensation includes payments to employees. Stock based compensation includes compensation paid to employees, directors and service providers in the form of either stock options, warrants, or restricted stock grants. The amount of expense recorded for stock options and warrants is calculated by using the Black-Scholes-Merton option pricing model. The amount of expense recorded for common stocks grants is calculated based upon the closing market value of the shares. The increase in compensation expense from 2012 to 2013 reflects the expansion of our business, including the addition of new employees. As of May 31, 2013, we employed 16 persons on a full-time basis, compared to 11 persons as of May 31, 2012.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties. Those costs are reclassified from general and administrative expenses and capitalized into the full cost pool. The increase in capitalized costs from 2012 to 2013 reflects our increasing activities to acquire leases and develop the properties.

Income taxes – We reported income tax expense of $1.7 million for the three months ended May 31, 2013, representing an effective tax rate of 32%. During the comparable prior year period, we reported income tax expense of $1.4 million, representing an effective tax rate of 37%. We reduced the estimated effective tax rate during 2013 to reflect the expected tax benefit from statutory depletion.

For the nine months ended May 31, 2013, we reported net income of $8.6 million compared to net income of $10.2 million for the nine months ended May 31, 2012. Earnings per basic and diluted share were $0.16 and $0.15, respectively, for the nine months ended May 31, 2013, compared to $0.23 per basic and $0.22 per diluted share for the nine months ended May 31, 2012. The comparison between the two years was primarily influenced by increasing revenues and expenses associated with the increased number of producing wells, as well as the effect of deferred income taxes. As of May 31, 2013 we had 285 gross producing wells (223 wells net), compared to 170 gross producing wells (130 wells net) as of May 31, 2012. The 2013 period included tax expense of $4.6 million while the 2012 period included a tax benefit of $1.8 million, for a net difference of $6.4 million. A full explanation of income taxes is provided later in this section.

Oil and Gas Production and Revenues – For the nine months ended May 31, 2013 we recorded total oil and gas revenues of $31.5 million compared to $18.2 million for the nine months ended May 31, 2012, an increase of $13.3 million or 73%. Our growth in revenue was the result of an increase in our production volume of 86% over the comparative period, and a decrease in our average selling price per BOE of 7%. For the nine months ended May 31, 2013, our gas/oil ratio (“GOR”) was 46/54. During the comparable prior period, our GOR was 45/55.

Our revenues are sensitive to changes in commodity prices. As shown in the following table, average realized prices have declined by 8.5% for oil and increased 2.7% for natural gas. To mitigate the impact of short term price fluctuations, we engage in commodity swap and collar transactions. The following table presents actual realized prices, without the effect of hedge transactions.

	Nine Months Ended
	May 31,		May 31,
	2013		2012		Change
Production:
Oil (Bbls)		296,220		160,995		84.0	%
Gas (McF)		1,489,624		794,691		87.4	%
BOE (Bbls)		544,490		293,444		85.6	%

Revenues (in thousands)
Oil	$	24,662	$	14,646		68.4	%
Gas		6,887		3,574		92.7	%
Total	$	31,549	$	18,220		73.2	%

Average sales price:
Oil		83.25	$	90.97		(8.5	%)
Gas		4.62	$	4.50		2.7	%
BOE (Bbls)		57.94	$	62.09		(6.7	%)

	Nine Months Ended
	(in thousands)
	May 31,		May 31,
	2013		2012
Production Costs	$	2,153	$	892
Work-Over		199		41
Other		-		115
Lifting cost		2,352		1,048
Severance and ad valorem taxes		2,975		1,672
Total LOE	$	5,327	$	2,720

Per BOE:
Production costs	$	3.95	$	3.04
Work-Over		0.37		0.14
Other		-		0.39
Lifting cost		4.32		3.57
Severance and ad valorem taxes		5.46		5.70
Total LOE	$	9.78	$	9.27

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% for the nine months ended May 31, 2013 and 9% for the nine months ended May 31, 2012.

On a BOE basis, production costs increased approximately 30% for the nine months ended May 31, 2013 compared to the nine months ended May 31, 2012. The increase is primarily due to costs incurred to mitigate production difficulties within the Wattenberg field. We incurred additional costs to provide wellhead compressors at some locations. In addition, we began a work-over program to improve pressures and flows from older wells.

The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves. The capitalized costs of evaluated oil and gas properties are depleted using the units-of-production method based on estimated reserves. Production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate. For the nine months ended May 31, 2013, production volumes of 544,491 BOE and estimated net proved reserves of 12,973,700 BOE were the basis of the depletion rate calculation. For the nine months ended May 31, 2012, production volumes of 293,444 BOE and estimated net proved reserves of 5,705,333 BOE were the basis of the depletion rate calculation. Depletion expense per BOE increased approximately 9% primarily as a result of additional DDA associated with newly acquired assets.

	Nine Months Ended
	(in thousands)
	May 31,			May 31,
	2013			2012
Cash based compensation	$	1,856		$	1,370
Stock based compensation		994			323
Professional fees		894			691
Insurance		142			103
Other general and administrative		542			326
Capitalized general and administrative		(415	)		(254	)
Totals	$	4,013		$	2,559

G&A Expense per BOE	$	7.37		$	8.72

Income taxes – We reported income tax expense of $4.6 million for the nine months ended May 31, 2013, representing an effective tax rate of 35%. Our estimated tax rate for 2013 has been reduced from 37% to 35% to reflect the expected tax benefit from statutory depletion. During the comparable prior year period, we reported a tax benefit of $1.8 million. During 2012, we recognized the one-time tax benefit from taxable losses generated during our early years of operations. Those early losses created a net operating loss carryover.

	Nine Months Ended
	(in thousands)
	May 31,			May 31,
	2013			2012
Cash provided by operations	$	28,243		$	17,078
Acquisition of oil and gas properties and equipment		(70,269	)		(34,026	)
Cash provided by equity financing activities		467			37,422
Net borrowings		41,486			(2,200	)
Net increase in cash and cash equivalents	$	(73	)	$	18,274

Net cash provided by operating activities was $28.2 million and $17.0 million for the nine months ended May 31, 2013 and 2012, respectively. In addition to our analysis using amounts included in the cash flow statement, we evaluate operations using a non-GAAP measure called “adjusted EBITDA,” which adjusts for cash flow items that merely reflect the timing of certain cash receipts and expenditures. Adjusted EBITA was $23.2 million and $13.3 million for the nine months ended May 31, 2013 and 2012, respectively.

The cash flow statement reports actual cash expenditures for capital expenditures, which differs from total capital expenditures on a full accrual basis. Specifically, cash paid for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On a full accrual basis, capital expenditures totaled $89.3 million and $36.7 million for the nine months ended May 31, 2013 and 2012, respectively, compared to cash payments of $70.3 million and $34.0 million, respectively. A reconciliation of the differences is summarized in the following table:

	Nine Months Ended
	(in thousands)
	May 31,			May 31,
	2013			2012
Cash payments	$	70,269		$	34,026
Accrued costs, beginning of period		(5,733	)		(4,967	)
Accrued costs, end of period		6,625			5,878
Properties acquired in exchange for common stock		16,594			1,494
Asset retirement obligations		1,562			214
Capital expenditures	$	89,317		$	36,645

Our capital budget for fiscal 2013 contemplated spending of $82.1 million, exclusive of assets acquired in exchange for common stock. Since the 2013 capital budget was prepared, we increased our drilling activities for both operated and non-operated wells. During the nine months ended May 31, 2013, we spent $70.3 million and expect to spend approximately $29.0 million during the fourth quarter. Included in nine month spending was $29.1 million for the acquisition of producing properties, $6.6 million for leasing activities, $20.8 million to drill and / or complete 37 operated wells, and $8.9 million for drilling and completion activities on non-operated wells. Fourth quarter spending is estimated at $6.5 million for non-operated wells and $22.5 million for five horizontal wells planned for the Renfroe prospect.

Funds for our capital expenditures were provided primarily by cash balances on hand, cash flow from operations, and additional borrowing under our revolving line of credit. Our net borrowings for the year were $41.5 million, most of which were used to partially fund the acquisition of operating assets from Orr Energy

Our primary need for cash for the fiscal year ending August 31, 2014, will be to fund our drilling and acquisition programs. Our cash requirements are expected to increase significantly as we implement our horizontal drilling program. Each horizontal well is estimated to cost $4.5 million, compared to the estimated cost of a vertical well of $0.8 million. Under the preliminary plans for our 2014 capital budget, we estimate capital expenditures of approximately $157.1 million, consisting of drilling and completion costs for wells which we operate, our pro-rata share of the costs on wells drilled by other operators, and the costs of acquiring properties. It is our plan to drill 20 net horizontal wells during the year and to participate in 5 net non-operated horizontal wells at a total cost of $112.5 million. We expect to drill or participate in 12 vertical wells at a total cost of $9.6 million. Leasing activities are expected to cost $5.0 million, and the acquisition of producing properties is budgeted for $30.0 million. Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.

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.

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.

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

	Nine Months Ended
	(in thousands)
	May 31,			May 31,
	2013			2012
Adjusted EBITDA:
Net income	$	8,585		$	10,177
Depreciation, depletion and amortization		9,316			4,600
Provision for income tax		4,620			(1,809	)
Stock based compensation		994			323
Commodity derivative change		(368	)		-
Interest Expense		94			-
Interest income		(20	)		(27	)
Adjusted EBITDA	$	23,221		$	13,264

Since calendar year 2012, the Wattenberg Field experienced elevated line pressure in the natural gas and liquids gathering system. Issues with high line pressure are continuing during 2013. High line pressure restricts our ability to produce crude oil and natural gas. As line pressures increase, it becomes more difficult to inject gas produced by our wells into the pipeline. When line pressure is greater than the operating pressure of our wellhead equipment, the wellhead equipment is unable to inject gas into the pipeline, and our production is restricted or shut-in. Since our wells produce a mixture of crude oil and natural gas, restrictions in gas production also restrict oil production. Although various factors can cause increased line pressure, a significant factor in our area is the success of horizontal wells that have recently been drilled. As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle. Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells. The pace of horizontal drilling in the Wattenberg is accelerating and it appears that it will be some time before the gathering system will have sufficient capacity to eliminate the high line pressure issues.

We are taking steps to mitigate high line pressures. Where possible, we have installed compressors to aid the wellhead equipment in its injection of gas into the system. 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. A significant improvement in the system will occur in the summer of 2013 when a new processing plant in LaSalle, CO comes on line. The LaSalle, CO plant will have an estimated capacity of 110 million cubic feet per day. 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, estimated to begin operations in 2014. At this time, we do not know how long it will take for the mitigation efforts to remedy the problem.

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

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

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.

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.

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

Interest Rate Risk - At May 31, 2013, we had debt outstanding under our bank credit facility totaling $44.5 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 May 31, 2013, the interest rate was 3.5%, based upon LIBOR plus a margin of 3%. We are currently incurring interest at a rate of 3.5%, 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.

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.

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of May 31, 2013, our disclosure controls and procedures were effective.

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

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

		Page
Part I – FINANCIAL INFORMATION

Item 1.	Financial Statements

	Balance Sheets as of May 31, 2013 (unaudited) and August 31, 2012	3

	Statements of Operations for the three months and nine months ended May 31, 2013 and May 31, 2012 (unaudited)	4

	Statements of Cash Flows for the nine months ended May 31, 2013 and May 31, 2012 (unaudited)	5

	Notes to Financial Statements (unaudited)	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

Item 4.	Controls and Procedures	38

Part II - OTHER INFORMATION

Item 6.	Exhibits	39

SIGNATURES		40

(in thousands)
Asset retirement obligations, August 31, 2012	$	1,027
Liabilities incurred		360
Liabilities assumed		240
Liabilities settled		-
Change in estimate		962
Accretion		105
Asset retirement obligations, May 31, 2013	$	2,694

	For the nine months ended May 31, 2013
Number of common shares issued for mineral property leases		674,026
Number of common shares issued for Orr Energy acquisition		3,128,422
Total common shares issued		3,802,448

Average price per common share	$	4.36
Aggregate value of shares issued (in thousands)	$	16,594

Major Customers	As of May 31, 2013	As of August 31, 2012
Company A	28%	35%
Company B	22%	30%

		As of		As of
Derivatives	Balance Sheet Location	May 31, 2013 (in thousands)		August 31, 2012 (in thousands)
Asset
Commodity derivatives	Current assets	$	320	$	-
Commodity derivatives	Noncurrent assets	$	48	$	-

	Fair Value Measurements at May 31, 2013
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative asset	$	-	$	368	$	-	$	368

Exercise Price		Description	Number of Shares		Remaining Contractual Life (in years)		Exercise Price times Number of Shares
	$1.60	Series D		324,882		1.6		519,811
	$2.69	Investor Relations Warrants		50,000		2.7		134,500
	$6.00	Series C		8,960,000		1.6		53,760,000
				9,334,882		1.6	$	54,414,311

	Number of Shares		Weighted Average Exercise Price
Outstanding, August 31, 2012		4,915,000		$5.09
Granted		890,000		$5.82
Exercised		-		-
Outstanding, May 31, 2013		5,805,000		$5.20

	Outstanding Options		Vested Options
Number of shares	5,805,000		4,399,500
Weighted average remaining contractual life	2.7 years		0.7 years
Weighted average exercise price	$	5.20	$	5.32
Aggregate intrinsic value (in thousands)	$	15,580	$	12,929

		Unvested Options at May 31, 2013
Unrecognized compensation expense (in thousands)		$ 4,072
Remaining vesting phase		3.4 years

	Operated				Participated
Year	Drilled		Completed		Drilled		Completed		Acquired
2009		-		-		2		2		-
2010		36		22		-		-		-
2011		20		28		11		11		72
2012		51		47		13		5		4
2013		28		37		21		21		36
Total		135		134		47		39		112

	SYNERGY RESOURCES CORPORATION

Date: July 9, 2013	By:	/s/ Ed Holloway
		Ed Holloway, President and Principal Executive Officer

Date: July 9, 2013	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Principal Financial and Accounting Officer