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, 2013

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: 55,226,616 shares outstanding as of April 1, 2013.

SYNERGY RESOURCES CORPORATION

Index

		Page
Part I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Balance Sheets as of February 28, 2013 (unaudited) and August 31, 2012	3
	Statements of Operations for the three months and six months ended February 28, 2013 and February 29, 2012 (unaudited)	4
	Statements of Cash Flows for the six months ended February 28, 2013 and February 29, 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	37
Item 4.	Controls and Procedures	38
Part II - OTHER INFORMATION
Item 6.	Exhibits	38
SIGNATURES		39

2

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

(in thousands, except share data)

ASSETS	February 28, 2013			August 31,  2012
	(unaudited)
Current assets:
Cash and cash equivalents	$	18,273		$	19,284
Accounts receivable:
Oil and gas sales		5,897			3,606
Joint interest billing		3,758			3,268
Inventory		252			178
Commodity derivative		124			-
Other current assets		137			131
Total current assets		28,441			26,467
Property and equipment
Evaluated oil and gas properties, net		126,821			59,936
Unevaluated oil and gas properties		32,334			32,484
Other property and equipment, net		304			282
Property and equipment, net		159,459			92,702
Deferred tas axxet, net		-			332
Other assets		563			1,230
Total assets	$	188,463		$	120,731
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Trade accounts payable	$	2,094		$	1,499
Well costs payable		5,539			5,733
Revenue payable		6,674			4,160
Production taxes payable		6,703			3,805
Other accrued expenses		355			395
Total current liabilities		21,365			15,592
Revolving credit facility		41,486			3,000
Commodity derivative		257			-
Deferred tax liability, net		2,587			-
Asset retirement obligations		1,610			1,027
Total liabilities		67,305			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:
55,226,616 and 51,409,340 shares issued and outstanding,
respectively		55			51
Additional paid-in capital		138,949			123,876
Accumulated deficit		(17,846	)		(22,815	)
Total shareholders' equity		121,158			101,112
Total liabilities and shareholders' equity	$	188,463		$	120,731

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 29		February 28			February 29
	2013			2012		2013			2012
Oil and gas revenues	$	10,921		$	6,219	$	19,235		$	10,698
Expenses
Lease operating expenses		781			291		1,304			592
Production taxes		1,094			564		1,908			969
Depreciation, depletion,
and amortization		3,176			1,552		5,496			2,766
General and administrative		1,388			937		2,499			1,877
Total expenses		6,439			3,344		11,207			6,204
Operating income		4,482			2,875		8,028			4,494
Other income (expense)
Commodity derivative loss		(154	)		-		(154	)		-
Interest Income		8			3		15			11
Total other income (expense)		(146	)		3		(139	)		11
Income before income taxes		4,336			2,878		7,889			4,505
Deferred income tax (provision) benefit		(1,604	)		3,241		(2,919	)		3,241
Net income	$	2,732		$	6,119	$	4,970		$	7,746
Net income per common share:
Basic	$	0.05		$	0.13	$	0.09		$	0.19
Diluted	$	0.05		$	0.12	$	0.09		$	0.18
Weighted average shares outstanding:
Basic		54,900,326			47,445,178		53,272,213			41,771,695
Diluted		56,481,752			49,229,042		54,713,361			43,536,398

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

4

SYNERGY RESOURCES CORPORATION

 STATEMENTS OF CASH FLOWS

 for the six months ended February 28, 2013 and February 29 2012

(unaudited, in thousands)

	2013			2012
Cash flows from operating activities:
Net income	$	4,970		$	7,746
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization		5,496			2,766
Provision for deferred taxes		2,919			(3,241	)
Stock-based compensation		383			215
Valuation (increase) decrease in commodity derivatives		134			-
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales		(2,291	)		(1,052	)
Joint interest billing		(490	)		(245	)
Inventory		(74	)		(31	)
Accounts payable
Trade		595			55
Revenue		2,514			627
Production taxes		2,898			1,277
Accrued expenses		(40	)		1,578
Other		661			(64	)
Total Adjustments		12,705			1,885
Net cash provided by operating activities		17,675			9,631
Cash flows from investing activities:
Acquisition of property and equipment		(57,579	)		(17,883	)
Net cash used in investing activities		(57,579	)		(17,883	)
Cash flows from financing activities:
Proceeds from sale of stock		-			40,250
Offering costs		-			(2,828	)
Proceeds from exercise of warrants		407			-
Proceeds from revolving credit facility		38,486			5,392
Payment of related party note payable		-			(5,200	)
Net cash provided by financing activities		38,893			37,614
Net increase (decrease) in cash and cash equivalents		(1,011	)		29,362
Cash and cash equivalents at beginning of period		19,284			9,491
Cash and cash equivalents at end of period	$	18,273		$	38,853

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, 2013

(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.

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

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

Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the 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.

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 three months or less to be cash and cash equivalents.

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, 2013 or February 29, 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 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:

	Three Months Ended				Six Months Ended
	(in thousands)				(in thousands)
	February 28,		February 29,		February 28,		February 29,
	2013		2012		2013		2012
Capitalized Overhead	$	123	$	86	$	226	$	168

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 that was purchased by major customers.

	Three Months Ended				Six Months Ended
	February 28,		February 29,		February 28,		February 29,
Major Customers	2013		2012		2013		2012
Company A		58%		81%		61%		78%
Company B		14%		13%		14%		19%
Company C		13%		-		-		-

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, 2013	As of August 31, 2012
Company A	29%	35%
Company B	22%	30%

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.

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 29,		February 28,		February 29,
	2013		2012		2013		2012
Weighted-average shares outstanding-basic		54,900,326		47,445,178		53,272,213		41,771,695
Potentially dilutive common shares from:
Stock Options		1,292,599		1,390,248		1,180,219		1,376,758
Warrants		288,827		393,616		260,929		387,945
		1,581,426		1,783,864		1,441,148		1,764,703
Weighted-average shares outstanding - diluted		56,481,752		49,229,042		54,713,361		43,536,398

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 29,		February 28,		February 29,
	2013		2012		2013		2012
Warrants		8,970,000		14,098,000		8,970,000		14,098,000
Employee stock options		2,355,000		2,425,000		2,450,000		2,425,000
Total		11,325,000		16,523,000		11,420,000		16,523,000

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, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.

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, accounts payable, accrued liabilities, and obligations under the revolving line of credit facility, all of which are considered to be representative of their fair value due to the short-term and highly liquid nature of these instruments.

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 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. 

11

2.   Property and Equipment

Capitalized costs of property and equipment at February 28, 2013, and August 31, 2012, consisted of the following:

	As of			As of
	February 28,  2013			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	$	30,007		$	27,070
Wells in progress		2,327			5,414
Subtotal, unevaluated costs		32,334			32,484
Evaluated costs:
Producing and non-producing		141,931			69,667
Total capitalized costs		174,265			102,151
Less, accumulated depletion		(15,110	)		(9,731	)
Oil and gas properties, net		159,155			92,420
Other property and equipment:
Vehicles		200			164
Leasehold improvements		71			71
Office equipment		198			157
Land		44			44
Less, accumulated depreciation		(209	)		(154	)
Other property and equipment, net		304			282
Total property and equipment, net	$	159,459		$	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 six months ended February 28, 2013 and February 29, 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 six months ended February 28, 2013 and February 29, 2012, similarly revealed no impairment of oil and gas assets.

12

3.   Acquisition

On October 23, 2012, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Orr Energy, LLC (“Orr”), for its interests in 36 producing oil and gas wells and approximately 3,933 gross (3,196 net) mineral acres (the “Orr Assets”). On December 5, 2012, the Company closed the transaction for a combination of cash and stock.  Orr received 3,128,422 shares of the Company’s common stock valued at $13.5 million and cash consideration of approximately $29.0 million. Transaction costs related to the acquisition were approximately $109,000, all of which were recorded in the statement of operations within the general and administrative expenses line item for the three and six months ended February 28, 2013.   No material costs were incurred for the issuance of the shares of common stock.

The acquisition is 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 fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 5, 2012. (3,128,422 shares at $4.32 per share)

13

Pro Forma Financial Information

As stated above, on December 5, 2012, the Company completed an acquisition of oil and gas properties from Orr Energy.  Below are the combined results of operations for the three and six months ended February 28, 2013 and February 29, 2012 as if the acquisition had occurred on September 1, 2011.

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				Six Months Ended
	(in thousands)				(in thousands)
	February 28,		February 29,		February 28,		February 29,
	2013		2012		2013		2012
Oil and Gas Revenues	$	10,921	$	8,453	$	20,772	$	14,852
Net income	$	4,336	$	7,346	$	5,509	$	9,248
Earnings per common share
Basic	$	0.05	$	0.14	$	0.10	$	0.21
Diluted	$	0.05	$	0.13	$	0.10	$	0.20

4.  Interest Expense

The components of interest expense recorded for the three months and six months ended February 28, 2012 and February 29, 2012, consisted of the following:

	Three Months Ended						Six Months Ended
	(in thousands)						(in thousands)
	February 28,			February 29,			February 28,			February 29,
	2013			2012			2013			2012
Revolving bank credit facility at a variable rate	$	345		$	45		$	375		$	45
Related party note payable at 5.25%		-			-			-			68
Amortization of debt issuance costs		50			-			70			-
Less, interest capitalized		(395	)		(45	)		(445	)		(113	)
Interest expense, net	$	-		$	-		$	-		$	-

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5.   Depletion, depreciation and amortization

Depletion, depreciation and amortization for the three months and six months ended February 28, 2012 and February 29, 2012, consisted of the following:

	Three Months ended				Six Months ended
	(in thousands)				(in thousands)
	February 28,		February 29,		February 28,		February 29,
	2013		2012		2013		2012
Depletion	$	3,117	$	1,513	$	5,379	$	2,690
Depreciation and amortization		59		39		117		76
	$	3,176	$	1,552	$	5,496	$	2,766

6.   Revolving Credit Facility

On November 28, 2012, the Company entered into an amendment to its revolving line of 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 Synergy, subject to a borrowing base limitation.  Community Banks of Colorado acts as the administrative agent for the banks with respect to the LOC.

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate.  The interest rate pricing grid includes use of either the Prime Rate or the London Interbank Offered Rate (LIBOR), at the Company’s option.    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 and limited borrowings to $47 million at February 28, 2012.  The borrowing base limitation will be redetermined on a semi-annual basis.     The credit facility expires on November 28, 2016.

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.  The Company commenced its hedging position during the quarter ended February 28, 2013 (Note 8).

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 LIBOR plus a margin of 2.75% to 3.25%.  The average interest rate incurred during the quarter ended February 28, 2013 was 3.3%.  As of February 28, 2013, the interest rate on the outstanding balance was 3.2%, representing LIBOR plus 3.0%.

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7.   Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon wells, and restore sites to their original uses.  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.

The following table summarizes the change in asset retirement obligations for the six months ended February 28, 2013:

(in thousands)
Asset retirement obligations, August 31, 2012	$	1,027
Liabilities incurred		282
Liabilities assumed		240
Liabilities settled		-
Accretion		61
Asset retirement obligations, February 28, 2013	$	1,610

8.   Commodity Derivative Instruments

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

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

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

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The Company’s commodity derivative contracts as of February 28, 2013 are summarized below:

Contract Type	Basis (1)	Quantity (Bbl/month)		Strike Price ($/Bbl)		Term
Collar	NYMEX		3,014		$87.00 - $102.50	Mar 1, 2013 - Dec 31, 2013
Collar	NYMEX		1,840		$85.00 - $98.50	Jan 1, 2014 - Dec 31, 2014

Contract Type	Basis (1)	Quantity (Bbl/month)		Swap Price ($/Bbl)		Term
Swap	NYMEX		3,014		$91.70	Mar 1, 2013 - Dec 31, 2013
Swap	NYMEX		6,000		$96.35	Mar 1, 2013 - Dec 31, 2013	(2)
2013 Total/Average			9,014		$94.03
Swap	NYMEX		1,840		$90.80	Jan 1, 2014 - Dec 31, 2014
Swap	NYMEX		2,000		$90.11	Jan 1, 2014 - Dec 31, 2014
2014 Total/Average			3,840		$90.46
(1) NYMEX refers to WTI quoted prices on the New York Mercantile Exchange (2) In connection with entering into these swaps with premium hedged prices, the counterparty has the right, but not the obligation to extend the swap to January 1, 2014 through December 31, 2014 at the current strike price and quantity.  This option expires on December 31, 2013.

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

		As of		As of
Derivatives	Balance Sheet Location	February 28, 2013 (in thousands)		August 31, 2012 (in thousands)
Asset
Commodity derivatives	Current assets	$	124	$	-
Commodity derivatives	Noncurrent assets
Liability
Commodity derivatives	Current liabilities	$	-	$	-
Commodity derivatives	Noncurrent liabilities	$	257	$	-

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

	Three Months ended					Six Months ended
	(in thousands)					(in thousands)
	February 28,			February 29,		February 28,			February 29,
	2013			2012		2013			2012
Unrealized gain (loss) on commodity derivatives	$	(134	)	$	-	$	(134	)	$	-
Realized gain (loss) on commodity derivatives		(20	)		-		(20	)		-
Total gain (loss)	$	(154	)	$	-	$	(154	)	$	-

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9.   Fair Value Measurements

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

·   Level 1: Quoted prices are available in active markets for identical assets or liabilities;

·   Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

·   Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis during the reporting periods after initial recognition.

The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 7—Asset Retirement Obligations, and for the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3—Acquisitions.

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

The 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.

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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, 2013 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at February 28, 2013
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative asset	$	-	$	124	$	-	$	124
Financial Liabilities:
Commodity derivative liability	$	-	$	257	$	-	$	257

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, 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.

10.  Related Party Transaction

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 $60,000 during the three and six months ended February 28, 2013 and February 29, 2012.  HSLC is controlled by two of the Company’s executive officers.

11.   Shareholders’ Equity

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

	As February 28,		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		55,226,616		51,409,340

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.

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Common stock issued for acquisition of mineral interests

During the six months ended February 28, 2013 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, 2013
Number of common shares issued for mineral leases		247,488
Number of common shares issued for Orr Energy acquisition		3,128,422
Total common shares issued		3,375,910
Average price per common share	$	4.23
Aggregate value of shares issued (in thousands)	$	14,284

The following table summarizes information about the Company’s issued and outstanding common stock warrants as of February 28, 2013:

Exercise Price	Description	Number of Shares		Remaining Contractual Life (in years)		Exercise Price times Number of Shares
$1.60	Series D		325,998		1.8	$	521,597
$2.69	Investor Relations Warrants		100,000		2.9		269,000
$6.00	Series C		8,970,000		1.8		53,820,000
			9,395,998		1.8	$	54,610,597

The following table summarizes activity for common stock warrants for the six month period ended February 28, 2013:

	Number of Warrants			Weighted Average Exercise Price
Outstanding, August 31, 2012		15,031,067		$	6.02
Granted		-			-
Exercised		(537,069	) *	$	1.87
Expired		(5,098,000	)	$	6.78
Outstanding, February 28, 2013		9,395,998		$	5.81
* Warrants exercised include 434,603 warrants exercised on a cashless basis in exchange for 329,150 shares of common stock, which reduced the net cash proceeds to the Company to $0.76 per warrant.

12.   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.

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The amount of stock based compensation expense recorded for each of the three and six months ended February 28, 2013 and February 29, 2012 is shown in the table below:

	Three Months ended				Six Months ended
	(in thousands)				(in thousands)
	February 28,		February 29,		February 28,		February 29,
	2013		2012		2013		2012
Stock options	$	154	$	101	$	279	$	198
Restricted stock grants		46		17		58		17
Investor relations warrants		15		-		46		-
	$	215	$	118	$	383	$	215

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

During the reporting periods presented below, the Company granted the following employee stock options:

	Three Months ended				Six Months ended
	February 28,		February 29,		February 28,		February 29,
	2013		2012		2013		2012
Number of options to purchase common shares		125,000				355,000		100,000
Weighted average exercise price	$	5.65			$	4.52	$	2.80
Term		10.0				10.0		10
Vesting Period		5		-		5		4
Fair Value (in thousands)	$	490		-	$	1,111	$	179

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

	Six Months Ended
	February 28, 2013		February 29, 2012
Expected Term	6.4 years		6.5 years
Expected Volatility		78.7%		69.43%
Risk free rate		1.06%		1.12%
Expected dividend yield		0.00%		0.00%
Forfeiture rate		0.00%		0.00%

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The following table summarizes activity for stock options for the six months ended February 28, 2013:

	Number of Shares		Weighted Average Exercise Price
Outstanding, August 31, 2012		4,915,000		$5.09
Granted		355,000		$4.52
Exercised		-		-
Outstanding, February 28, 2013		5,270,000		$5.05

The following table summarizes information about issued and outstanding stock options as of February 28, 2013:

	Outstanding Options		Vested Options
Number of shares		5,270,000		4,325,500
Weighted average remaining contractual life		2.3 years		0.8 years
Weighted average exercise price		$5.05		$5.32
Aggregate intrinsic value (in thousands)		$15,069		$12,416

The estimated unrecognized compensation cost from unvested stock options as of February 28, 2013, which will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at February 28, 2013
Unrecognized compensation expense (in thousands)	$ 2,032
Remaining vesting phase	3.8 years

13.   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, 2013, the Company was participating in two horizontal wells and four vertical wells that were in various stages of drilling or completion.  Costs accrued for these wells in progress totaled $2.3 million.  Also as of February 28, 2013, the Company had agreed to participate in five future horizontal wells and six future vertical wells with working interests ranging from 2% to 65% and expects that its share of future costs will be approximately $7.5 million.

In addition, the Company has been notified by other operators of their non-binding intent to drill 27 horizontal wells and 4 vertical wells in which the Company may own an interest.  As of March 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.

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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 three and six months ended February 28, 2013 and February 29, 2012:

	Six Months ended (in thousands)
	February 28,		February 29,
	2013		2012
Supplemental cash flow information:
Interest paid	$	294	$	187
Income taxes paid		-		-
Non-cash investing and financing activities:
Well costs payable	$	5,539	$	7,829
Assets acquired in exchange for common stock		14,284		694
Asset retirement costs and obligations		522		135

15.   Subsequent Events

On March 13, 2013, the Company completed its acquisition of oil and gas properties located in Denver-Julesberg Basin, Colorado (the "Agreement") from Vecta Oil and Gas, Ltd., ("Vecta").  At the closing of the Agreement, Synergy paid Vecta a leasehold reimbursement fee consisting of (i) a cash payment of $2,928,502 and (ii) the issuance to Vecta of 100,000 shares of  the Company’s restricted common stock having a value, for purposes of the Agreement, of approximately $660,000.

In total, the Agreement covers approximately 101,675 gross (45,661 net) acres in which Synergy will hold a 35% interest and approximately 3,718 gross (2,983 net) acres in which Synergy will hold a 65% interest.

The Company and Vecta will work together to (a) acquire new proprietary seismic data across a portion of the oil and gas leases which are the subject of the Agreement; (b) drill a horizontal well on one of the leases to evaluate either the Greenhorn Shale or Niobrara Shale; and (c) conduct other exploration projects in the area covered by the leases as may be mutually agreed upon. The Agreement contemplates the drilling of an initial well to test the Greenhorn formation on or before October 31, 2013.

The Agreement names the Company as the operator for all wells to be drilled, pursuant to the terms and conditions of a joint operating agreement.  The Agreement establishes an area of mutual interest covering certain lands in Morgan and Weld Counties, Colorado, and contains certain other provisions customary to exploration agreements.

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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 the financial condition as of February 28, 2013, and the results of operations for the three months and six months ended February 28, 2013 and February 29, 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.

Overview

Synergy Resources Corporation (“we,” “our,” “us” or “the Company”) is a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin (“D-J Basin”) of Colorado. All of our producing wells are either in or adjacent to the Wattenberg Field, which has a history as one of the most prolific production areas in the country.  We hold developed and undeveloped acreage in the Wattenberg Field, and hold significant undeveloped acreage positions east of the Wattenberg Field.  Our holdings outside of the Wattenberg Field include Colorado, Wyoming, and Nebraska.  Although we have not yet commenced exploration and development activities in the other areas, we may do so in the future.

Since commencing active operations in September 2008, we have undergone significant growth. As disclosed in the following table, as of February 28, 2013, we have drilled, acquired, or participated in 284 gross oil and gas wells and have successfully completed 278 wells that went into production.  There were six wells at various stages of the drilling and completion process.  We have not drilled any non-productive wells.

	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		27		37		12		14		36
Total		134		134		38		32		112

As of February 28, 2013 our estimated proved reserves exceeded 7 million Bbls of oil and 44 Bcf of gas.  We currently hold approximately 259,000 gross acres and 218,000 net acres under lease.

Strategy

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

All wells drilled prior to 2012 were relatively low-risk vertical wells (including wells that are considered directional wells). Over the last twelve months we participated with other operators in six horizontal wells that reached productive status.  We have agreed to participate in seven horizontal wells that have either commenced drilling operations or expect drilling activity during 2013, and are evaluating prospects for 27 wells that have been proposed.  

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Historically, we were a company that drilled vertical wells.  Newer technology allows exploitation of hydrocarbon deposits using horizontal wells.  The new technology is evolving rapidly and shows great promise.  We plan to transition our primary emphasis from vertical drilling to horizontal drilling during the remainder of the fiscal year.  Our capital expenditure budget for 2013 anticipated participation in ten horizontal wells operated by others.  That budget may be increased.  Furthermore, we plan to drill and operate four horizontal wells for our own account during the current fiscal year.  

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.

Significant Developments

As an operator, we continued our active vertical well drilling program from September 1, 2012 through February 28, 2013.  During that time, we drilled 27 new wells and brought all of them into productive status.  In addition, the ten wells that were in progress at August 31, 2012 reached productive status.  We have substantially completed our plans for drilling vertical wells during the 2013 fiscal year, and plan to focus our efforts on horizontal wells during the remaining six months of the fiscal year.  With regard to activity on wells in which we participate as a non-operating interest owner, nine wells were drilled (including two horizontal wells) and fourteen wells reached productive status (including three horizontal wells) during the six month period.  Six non-operated wells were in various stages of drilling or completion at February 28, 2013, and two additional horizontal wells were spud in March.

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 increasing drilling activity by other oil and gas companies.  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 over more than 19,000 acres in the Northern DJ Basin is approximately $400 per acre with an average of three years left on our leases and options to extend the leases another two or three years at less than $100 acre.  The agreement also provides Synergy with retaining operating control while gaining the insight and collaboration with Vecta who has considerable technical acumen in geology and geophysics.  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 $30 million and 3,128,422 shares of our restricted common stock.  Our preliminary evaluation of the assets indicates that the fair value of the acquisition will approximate $42 million.  Revenues and expenses from the Orr properties were consolidated with our operations commencing on December 5, 2012, and contributed approximately $745,000 to operating income during the quarter.

In November 2012, we modified our borrowing arrangement with Community Banks of Colorado, successor in interest to Bank of Choice, to increase the maximum allowable borrowings.  The new revolving line of credit increases the maximum lending commitment to $150 million, subject to a borrowing base calculation.

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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.  As of February 28, 2013, the borrowing base calculation limited maximum borrowings to $47 million.  In December, we utilized a portion of the financing available through this arrangement to fund the acquisition of Orr assets.  We expect to use the remaining proceeds to fund our drilling and development expenditures 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 February 28, 2013, we had hedged approximately 188,000 barrels of oil over the remainder of calendar 2013 and all of calendar 2014.  We used both commodity swaps and collars.  Our hedge positions generated a loss of $154,000 during the quarter, consisting of realized losses of $20,000 and net unrealized losses of $134,000.  Our commodity hedge positions are revalued at fair value for each reporting period, and can have a significant impact on reported results of operations.

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, 2013, compared to the three months ended February 29, 2012

For the three months ended February 28, 2013, we reported net income of $2.7 million compared to $6.1 million during the three months ended February 29, 2012.  Earnings per diluted share were $0.05 for the three months ended February 28, 2013 compared to $0.12 for the three months ended February 29, 2012. The comparison between the two years was primarily influenced by increasing revenues and expenses associated with the increased number of producing wells plus the effect of deferred income taxes.  As of February 28, 2013 we had 278 gross producing wells (220 wells net), compared to 157 gross producing wells (116 wells net) as of February 29, 2012.  For deferred income taxes, the 2013 quarter included tax expense of $1.6 million while the 2012 quarter included a tax benefit of $3.2 million, for a net difference of $4.8 million.  An explanation of income taxes is provided later in this section.

Oil and Gas Production and Revenues – For the three months ended February 28, 2013 we recorded total oil and gas revenues of $10.9 million compared to $6.2 million for the three months ended February 29, 2012, an increase of $4.7 million or 76%.  Our growth in revenue was the result of an increase in our production volume of 87% during the intervening period.  For the quarter, our gas/oil ratio (“GOR”) was 46/54.  During the comparable prior period, our GOR was 44/56.

Our revenues are sensitive to changes in commodity prices.  As shown in the following table, average realized prices have declined by 8.8% for oil and increased 16.6% 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, before the effect of hedge transactions.

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Key production information is summarized in the following table:

	Three Months Ended
	February 28,		February 29,
	2013		2012		Change
Production:
Oil (Bbls)		100,694		55,823		80.4%
Gas (McF)		512,069		260,627		96.5%
BOE (Bbls)		186,039		99,261		87.4%
Revenues (in thousands):
Oil	$	8,478	$	5,154		64.5%
Gas		2,443		1,065		129.4%
Total	$	10,921	$	6,219		75.6%
Average sales price:
Oil	$	84.20	$	92.33		(8.8%)
Gas	$	4.77	$	4.09		16.6%
BOE (Bbls)	$	58.70	$	62.65		(6.3%)

 “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, 2013 was 186,039 BOE, or 2,067 BOE per day. For the three months ended February 29, 2012, production averaged 1,091 BOE per day, a year over year increase of 87%.  As a further comparison, average BOE production was 1,658 per day during the quarter ended November 30, 2012, a quarter over quarter increase of 25%.  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 320 BOE per day during the quarter.  Although production increased significantly, it was somewhat reduced by technical production issues during the period.  Sixteen of our new wells entered productive status on February 20, 2013, and only contributed to production for 8 days.  Our wells have generally been affected by high line pressures in the gathering system and we have been unable to produce at full capacity.  Finally, certain wells were shut-in during the period because of “freeze-ups” in the gas pipeline.  Freeze-ups are more common as the ground begins to freeze in the winter.   It is caused by water in the line which forms an ice plug that stops the flow of gas.  During the quarter, freeze-ups shut in our wells for an aggregate of approximately 1,340 production days.

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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:

	Three Months Ended
	(in thousands)
	February 28,		February 29,
	2013		2012
Production Costs	$	637	$	271
Work-Over		144		-
Other		-		20
Lifting cost		781		291
Severance and ad valorem taxes		1,094		564
Total LOE	$	1,875	$	855
Per BOE:
Production costs	$	3.42	$	2.72
Work-Over	$	0.77		-
Other		-		0.21
Lifting cost		4.20		2.93
Severance and ad valorem taxes		5.88		5.68
Total LOE	$	10.08	$	8.61

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 three months ended February 28, 2013 and 9% for the three months ended February 29, 2012.

On a BOE basis, production costs increased approximately 26% for the quarter ended February 28, 2013 compared to the quarter ended February 29, 2012.  The increase is primarily due to costs incurred to mitigate high line pressure within the Wattenberg Field. The Company incurred production costs to provide compression at some well locations and is currently installing additional compression capability.  In addition, the Company began a work-over program to improve pressures and flows from the Orr wells.

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

	Three Months Ended
	(in thousands)
	February 28,		February 29,
	2013		2012
Depletion	$	3,117	$	1,513
Depreciation and amortization		59		39
Total DDA	$	3,176	$	1,552
DDE expense per BOE	$	17.07	$	15.64

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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 February 28, 2013, production volumes of 186,039 BOE and estimated net proved reserves of 14,630,301 BOE were the basis of the depletion rate calculation.  For the three months ended February 29, 2012, production volumes of 99,261 BOE and estimated net proved reserves of 5,085,905 BOE were the basis of the depletion rate calculation.  Depletion expense per BOE increased approximately 9.9% primarily as a result of additional DDA associated with the Orr assets.

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

	Three Months Ended
	(in thousands)
	February 28,			February 29,
	2013			2012
Cash based compensation	$	700		$	557
Stock based compensation		215			101
Professional fees		194			187
Insurance		45			39
Other general and administrative		357			139
Capitalized general and administrative		(123	)		(86	)
Totals	$	1,388		$	937
G&A Expense per BOE	$	7.46		$	9.44

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 February 28, 2013, we employed 14 persons on a full-time basis, compared to 11 persons as of February 29, 2012.  Since February 28, 2013, two additional employees have been hired.

Our professional fees have increased as we grow our business.  In addition to legal, accounting and auditing fees, this category includes technical consulting services such as petroleum engineering studies.

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 $1.6 million for the three months ended February 28, 2013, representing an effective tax rate of 37%.  During the comparable prior year period, we reported a tax benefit of $3.2 million.  In 2012, we recognized a tax asset of $4.9 million, representing the one-time benefit of the expected value of the net operating loss carryforward accumulated during our start-up years.

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For tax purposes, we have a net operating loss (“NOL”) carryover in excess of $34.0 million, which is available to offset future taxable income.  Accordingly, we do not expect to pay income taxes during the current fiscal year, and all of our income tax expense is reported as a deferred item.

For the six months ended February 28, 2013, compared to the six months ended February 29, 2012

For the six months ended February 28, 2013, we reported net income of $4.9 million compared to net income of $7.7 million for the six months ended February 29, 2012.  Earnings per basic and diluted share were $0.09 for the six months ended February 28, 2013, compared to $0.19 per basic and $0.18 per diluted share for the six months ended February 29, 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 February 28, 2013 we had 278 gross producing wells (220 wells net), compared to 157 gross producing wells (116 wells net) as of February 29, 2012.  The 2013 period included tax expense of $2.9 million while the 2012 period included a tax benefit of $3.2 million, for a net difference of $6.1 million.  A full explanation of income taxes is provided later in this section.

Oil and Gas Production and Revenues – For the six months ended February 28, 2013 we recorded total oil and gas revenues of $19.2 million compared to $10.7 million for the six months ended February 29, 2012, an increase of $8.5 million or 79%.  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 3%.  For the six months ended February 28, 2013, our gas/oil ratio (“GOR”) was 46/54.  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, there has been a decrease of 3% in average realized prices between the two periods.  To mitigate the impact of short term price fluctuations, we engage in commodity swap and collar transactions.  The following table presents actual realized prices, before the effect of hedge transactions.

Key production information is summarized in the following table:

	Six Months Ended
	February 28,		February 29,
	2013		2012		Change
Production:
Oil (Bbls)		180,995		97,227		86.2%
Gas (McF)		935,715		504,208		85.6%
BOE (Bbls)		336,948		181,262		85.9%
Revenues (in thousands)
Oil	$	14,985	$	8,332		79.8%
Gas		4,250		2,366		79.6%
Total	$	19,235	$	10,698
Average sales price:
Oil		82.79	$	85.70		-3%
Gas		4.54	$	4.69		-3%
BOE (Bbls)		57.09	$	59.02		-3%

“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.

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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:

	Six Months Ended
	(in thousands)
	February 28,		February 29,
	2013		2012
Production Costs	$	1,160	$	483
Work-Over		144		41
Other		-		68
Lifting cost		1,304		592
Severance and ad valorem taxes		1,908		969
Total LOE	$	3,212	$	1,561
Per BOE:
Production costs	$	3.44	$	2.66
Work-Over		0.43		0.23
Other		-		0.37
Lifting cost		3.87		3.26
Severance and ad valorem taxes		5.66		5.35
Total LOE	$	9.53	$	8.61

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, 2013 and 9% for the six months ended February 29, 2012.

On a BOE basis, production costs increased approximately 26% for the period ended February 28, 2013 compared to the period ended February 29, 2012.  The increase is primarily due to costs incurred to mitigate high line pressure within the Wattenberg field. The Company incurred production costs to rent and install compressors on six pads and installed upgraded valves and other equipment upgrades on some of the Company’s older wells.  In addition, the Company began a work-over program to improve pressures and flows from older wells.

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

	Six Months Ended
	(in thousands)
	February 28,		February 29,
	2013		2012
Depletion	$	5,379	$	2,690
Depreciation and amortization		117		76
Total DDA	$	5,496	$	2,766
DDA expense per BOE	$	16.31	$	15.26

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 six months ended February 28, 2013, production volumes of 336,948 BOE and estimated net proved reserves of 14,630,301 BOE were the basis of the depletion rate calculation.  For the six months ended February 29, 2012, production volumes of 181,262 BOE and estimated net proved reserves of 4,446,565 BOE were the basis of the depletion rate calculation.  Depletion expense per BOE increased approximately 7.5% primarily as a result of additional DDA associated with the Orr assets.  .

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

	Six Months Ended
	(in thousands)
	February 28,			February 29,
	2013			2012
Cash based compensation	$	1,209		$	879
Stock based compensation		384			215
Professional fees		576			518
Insurance		88			70
Other general and administrative		468			363
Capitalized general and administrative		(226	)		(168	)
Totals	$	2,499		$	1,877

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 February 28, 2013, we employed 14 persons on a full-time basis, compared to 11 persons as of February 29, 2012.  Since February 28, 2013, two additional employees have been hired.

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Our professional fees have increased as we grow our business.  In addition to legal, accounting and auditing fees, this category includes technical consulting services such as petroleum engineering studies.

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 $2.9 million for the six months ended February 28, 2013, representing an effective tax rate of 37%.  During the comparable prior year period, we reported a tax benefit of $3.2 million.  In 2012, we recognized a tax asset of $4.9 million, representing the one-time benefit of the expected value of the net operating loss carry-forward accumulated during our start-up years.

For tax purposes, we have a net operating loss (“NOL”) carryover in excess of $34.0 million, which is available to offset future taxable income.  Accordingly, we do not expect to pay income taxes during the current fiscal year, and all of our income tax expense is reported as a deferred item.

LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the six months ended February 28, 2013, and February 29, 2012 are summarized below:

	Six Months Ended
	(in thousands)
	February 28,			February 29,
	2013			2012
Cash provided by operations	$	17,673		$	9,631
Acquisition of oil and gas properties and equipment		(57,579	)		(17,883	)
Cash provided by equity financing activities		407			37,422
Net borrowings		38,486			192
Net increase in cash and cash equivalents	$	(1,013	)	$	29,362

Net cash provided by operating activities was $17.7 million and $9.6 million for the six months ended February 28, 2013 and February 29, 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 EBITDA was $13.9 million and $7.5 million for the six months ended February 28, 2013 and February 29, 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 $71.7 million and $21.6 million for the six months ended February 28, 2013 and February 29, 2012, respectively, compared to cash payments of $57.6 million and $17.9 million, respectively.  A reconciliation of the differences is summarized in the following table:

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	Six Months Ended
	(in thousands)
	February 28,			February 29,
	2013			2012
Cash payments	$	57,579		$	17,883
Accrued costs, beginning of period		(5,733	)		(4,967	)
Accrued costs, end of period		5,539			7,829
Properties acquired in exchange for common stock		14,284			694
Asset retirement obligations		522			135
Capital expenditures	$	72,191		$	21,574

During the six ended February 28, 2013, we engaged in drilling or completion activities on 37 wells which we operate.  All of the wells reached productive status during the period.  In addition, ten wells in which we participated as a non-operating owner reached productive status and one non-operated well was in the drilling phase.  Approximately $22.5 million of our capital expenditures for the six months ended February 28, 2013, represent drilling and completion costs of the wells in progress.

Our net borrowings during the quarter were $38,486,000, substantially all of which were used to partially fund the acquisition of operating assets from Orr Energy.

We believe that the 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 remainder of this fiscal year.

Our primary need for cash for the remainder of the fiscal year ending August 31, 2013, will be to fund our drilling and acquisition programs.  Under the updated plans for our 2013 capital budget, we estimate capital expenditures of approximately $82 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.  We increased the budget from $55 million in connection with the acquisition of assets from Orr Energy, which entailed a cash payment of $30 million.  As an operator, we spent approximately $16.5 million to drill 27 vertical wells.  We expect to spend approximately $17 million to drill 4 horizontal wells during the last half of the year.  During the six month period, we recorded costs of $4.2 million as our portion of the cost of vertical and horizontal wells in which we are participating as a non-operator.  Our non-operating budget for the year is $13.5 million, and is currently under review.  We also plan recompletion costs approximating $1.5 million on wells that indicate good potential for additional hydraulic stimulation. We allocated $5 million for the acquisition of undeveloped acreage.  Our capital expenditure plans described herein represent cash payments, and exclude assets acquired in exchange for common stock.  The acquisition of assets from Orr Energy included partial payment in shares of common stock with a value of $12 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.

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

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

	Six Months Ended
	(in thousands)
	February 28,			February 29,
	2013			2012
Adjusted EBITDA:
Net income	$	4,970		$	7,746
Depreciation, depletion and amortization		5,496			2,766
Provision for income tax		2,919			(3,241	)
Stock based compensation		383			215
Commodity derivative change		134			-
Interest income		(15	)		(11	)
Adjusted EBITDA	$	13,887		$	7,475

TREND AND OUTLOOK

Throughout calendar year 2012, the Wattenberg Field experienced elevated high line pressure for the gathering of our natural gas and liquids.  During the first calendar quarter of 2013, high line pressure persisted.  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 production equipment, the production 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.

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We are taking steps to mitigate high line pressures.  Where possible, we have installed compressors to aid the production equipment in its injection of gas into the system.  In addition, companies that operate the gas gathering pipelines are making huge investments to increase system capacity.  As previously disclosed, DCP Midstream Partners 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.  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 more easily 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 for and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, and (v) may result in marginally productive oil and gas wells being abandoned as non-commercial.  However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

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

CRITICAL ACCOUNTING POLICIES

There have been no changes in our critical accounting policies since August 31, 2012, 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, 2012.

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.

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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, 2013, we had debt outstanding under our bank credit facility totaling $41.5 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 February 28, 2013, the interest rate was 3.2%, based upon LIBOR plus a margin of 3%.  We are currently incurring interest at a rate of 3.2%, 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.

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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, 2013, 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, 2013, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II

Item 6.                 Exhibits

a.  Exhibits

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

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.

32 Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 for Ed Holloway 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 Labels 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 9, 2013	By:	/s/ Ed Holloway
		Ed Holloway, President and Principal Executive Officer

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

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