SRC Energy Inc. - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - SRC Energy Inc.	Financial_Report.xls
EX-32 - EXHIBIT 32 - SRC Energy Inc.	ex32.htm
EX-31.1 - EXHIBIT 31.1 - SRC Energy Inc.	ex31x1.htm
EX-31.2 - EXHIBIT 31.2 - SRC Energy Inc.	ex31x2.htm

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 November 30, 2011

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: 51,147,858 shares outstanding as of January 5, 2012.

SYNERGY RESOURCES CORPORATION

Index

		Page
Part I – FINANCIAL INFORMATION

Item 1.	Financial Statements

	Balance Sheets as of November 30, 2011 (unaudited) and August 31, 2011	3

	Statements of Operations for the three months ended November 30, 2011 and 2010 (unaudited)	4

	Statements of Cash Flows for the three months ended November 30, 2011 and 2010 (unaudited)	5

	Notes to Financial Statements (unaudited)	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27

Item 4.	Controls and Procedures	28

Part II - OTHER INFORMATION

Item 6.	Exhibits	28

SIGNATURES		28

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

	November 30, 2011			August 31, 2011
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	7,198,914		$	9,490,506
Accounts receivable:
Oil and gas sales		1,533,887			2,185,051
Joint interest billing		2,455,973			2,406,473
Inventory		391,762			459,592
Other current assets		153,622			89,336
Total current assets		11,734,158			14,630,958

Property and equipment:
Oil and gas properties, full cost method, net		55,855,163			48,614,857
Other property and equipment, net		268,741			283,207
Property and equipment, net		56,123,904			48,898,064

Other assets		228,963			168,863

Total assets	$	68,087,025		$	63,697,885

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Accounts payable:
Trade	$	8,489,423		$	6,620,561
Accrued expenses		2,660,198			2,125,852
Note payable, related party		-			5,200,000
Total current liabilities		11,149,621			13,946,413

Revolving credit facility		5,392,110			-
Asset retirement obligations		712,682			643,459
Total liabilities		17,254,413			14,589,872

Commitments and contingencies (See Note 12)

Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding		-			-
Common stock - $0.001 par value, 100,000,000 shares authorized:
36,098,212 shares issued and outstanding as of
November 30, 2011 and August 31, 2011		36,098			36,098
Additional paid-in capital		84,108,762			84,011,496
Accumulated deficit		(33,312,248	)		(34,939,581	)
Total shareholders' equity		50,832,612			49,108,013

Total liabilities and shareholders' equity	$	68,087,025		$	63,697,885

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

SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

for the three months ended November 30, 2011 and 2010

(unaudited)

		2011		2010

Oil and gas revenues	$	4,478,864	$	1,443,595

Expenses:
Lease operating expenses		706,320		202,675
Depreciation, depletion, and amortization		1,213,842		584,981
General and administrative		939,550		645,101
Total expenses		2,859,712		1,432,757

Operating income (loss)		1,619,152		10,838

Other income (expense)
Change in fair value of derivative conversion liability		-		(389,263	)
Interest expense, net		-		(782,040	)
Interest income		8,181		461
Total other income (expense)		8,181		(1,170,842	)

Income (loss) before taxes		1,627,333		(1,160,004	)

Provision for income taxes		-		-
Net income (loss)	$	1,627,333	$	(1,160,004	)

Net income (loss) per common share:
Basic	$	0.05	$	(0.08	)
Diluted	$	0.04	$	(0.08	)

Weighted average shares outstanding:
Basic		36,098,212		13,715,651
Diluted		37,845,212		13,715,651

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

SYNERGY RESOURCES CORPORATION

STATEMENTS OF CASH FLOWS

for the three months ended November 30, 2011 and 2010

(unaudited)

	2011			2010

Cash flows from operating activities:
Net income (loss)	$	1,627,333		$	(1,160,004	)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion, and amortization		1,213,842			584,981
Amortization of debt issuance cost		-			170,122
Accretion of debt discount		-			420,923
Stock-based compensation		97,266			235,486
Change in fair value of derivative liability		-			389,263
Changes in operating assets and liabilities:
Accounts receivable		601,664			603,170
Inventory		67,830			23,380
Accounts payable		569,581			1,362,081
Accrued expenses		534,346			191,418
Other		(124,386	)		(117,814	)
Total adjustments		2,960,143			3,863,010
Net cash provided by operating activities		4,587,476			2,703,006

Cash flows from investing activities:
Acquisition of property and equipment		(7,071,178	)		(4,723,613	)

Cash flows from financing activities:
Proceeds from credit facility		5,392,110			-
Payment of related party note payable		(5,200,000	)		-
Net cash provided by financing activities		192,110			-

Net decrease in cash and equivalents		(2,291,592	)		(2,020,607	)

Cash and equivalents at beginning of period		9,490,506			6,748,637

Cash and equivalents at end of period	$	7,198,914		$	4,728,030

Supplemental Cash Flow Information (See Note 13)

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

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

1.	Organization and Summary of Significant Accounting Policies

Organization: Synergy Resources Corporation (the “Company”) is engaged in oil and gas acquisitions, exploration, development and production activities, primarily in the area known as the Denver-Julesburg Basin. The Company has adopted August 31st as the end of its fiscal year.

Basis of Presentation: The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). In June 2009 the Financial Accounting Standards Board (“FASB”) established the Accounting Standards Codification (“ASC”) as the single source of authoritative US GAAP to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants. New accounting standards are communicated by FASB through Accounting Standards Updates (“ASU’s”).

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, 2011.

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 loss, working capital or equity previously reported..

Use of Estimates: The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from these estimates.

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

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

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 months ended November 30, 2011 or 2010.

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.

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, which totaled $82,386 and $64,720 for the three months ended November 30, 2011 and 2010, respectively, were capitalized in the full cost pool.

Oil and Gas Reserves: The determination of depreciation, depletion and amortization expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and natural gas properties, will be highly dependent on the estimates of the proved oil and natural gas reserves. Oil and natural gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate 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 natural gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are often different from the quantities of oil and natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

Capitalized Interest: The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. During the three months ended November 30, 2011 and 2010, the Company capitalized interest totaling $68,063 and $119,739, respectively.

Debt Issuance Costs: The Company incurred debt issuance costs in connection with issuing convertible promissory notes during the year ended August 31, 2010. As a result of the early conversion of all outstanding convertible promissory notes into shares of the Company’s common stock during prior periods, all debt issuance costs were recognized as a component of interest expense during the periods in which the conversions occurred.

Fair Value Measurements: Fair value is the price that would be received upon the sale of an asset or be paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can either be readily observable, market corroborated or generally unobservable. Fair value balances are classified based on the observability of the various inputs (see Note 8).

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. The fair value of a liability for the asset retirement obligation (“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. 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. The capitalized ARCs are included in the full cost pool and subject to depletion, depreciation and amortization. In addition, the ARCs are included in the ceiling test calculation. Calculation of an ARO requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk free interest rate. Estimates are periodically reviewed and adjusted to reflect changes.

Derivative Conversion Liability: In connection with certain previously outstanding convertible promissory notes, the Company accounted for the embedded conversion features in accordance with the guidance for derivative instruments, which requires a periodic assessment of fair value and a corresponding recognition of liabilities at fair value associated with such derivatives. As a result of the early conversion of all outstanding convertible promissory notes into shares of the Company’s common stock prior to March 31, 2011, the remaining derivative liability was reclassified to additional paid-in-capital during the year ended August 31, 2011.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

Revenue Recognition: Revenue is recognized for the sale of oil and natural gas when production is sold to a purchaser and title has transferred. 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 interest. Provided that reasonable estimates can be made, revenue and receivables are accrued, and differences between the estimates and actual volumes and prices, if any, are adjusted upon settlement, which typically occurs sixty to ninety days after production.

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 Company’s oil and gas production is purchased by a few customers. The table below presents the percentages of oil and gas revenue that was purchased by major customers.

	Three Months Ended November 30,
Major Customers	2011	2010
Company A	68%	78%
Company B	22%	19%

As there are other purchasers that are capable of and willing to purchase the Company’s oil and gas production and since the Company has the option to change purchasers on its properties 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, but 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.

Share Based Compensation: Share based compensation is measured at the grant date based upon the estimated fair value of the award and the expense is recognized over the required employee service period, which generally equals the vesting period of the grant. The fair value of stock options is estimated using the Black-Scholes-Merton option-pricing model. The fair value of restricted stock grants is estimated on the grant date based upon the fair value of the common stock.

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. For the three months ended November 30, 2010 all potentially dilutive securities have an anti-dilutive effect on earnings per share. For the three months ended November 30, 2011, a reconciliation of weighted-average shares outstanding is as follows:

Weighted-average shares outstanding - basic			36,098,212
Potentially dilutive common shares from:
Stock options			1,364,493
Warrants			382,507
			1,747,000

Weighted-average shares outstanding - diluted			37,845,212

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

The following potentially dilutive securities could dilute future earnings per share:

	November 30,
	2011		2010
Convertible promissory notes		-		9,630,000
Accrued interest convertible into common stock		-		128,752
Warrants(1)		14,931,067		15,286,466
Employee stock options		4,745,000		4,270,000
Total		19,676,067		29,315,218

(1) Also as of November 30, 2011 and 2010, the Company had a contingent obligation to issue 63,466 potentially dilutive securities, all of which were excluded from the calculation because the contingency conditions had not been met.

Income Taxes: Deferred income taxes are recorded for timing differences between items of income or expense reported in the financial statements and those reported for income tax purposes using the asset/liability method of accounting for income taxes. Deferred income taxes and tax benefits are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, and for tax loss and credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The Company provides for deferred taxes for the estimated future tax effects attributable to temporary differences and carry-forwards when realization is more likely than not. If the Company concludes that it is more likely than not that some portion, or all, of the net deferred tax asset will not be realized, the balance of net deferred tax assets is reduced by a valuation allowance. At November 30, 2011, management concluded that it was more likely than not that the Company’s net deferred tax asset will not be realized in the foreseeable future and accordingly, a full valuation allowance was provided against the net deferred tax asset.

The Company follows the provisions of the ASC regarding uncertainty in income taxes. No significant uncertain tax positions were identified as of any date on or before November 30, 2011. Given the substantial net operating loss carry-forwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated as any such adjustments would very likely simply adjust the net operating loss carry-forwards.

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.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

In June 2011, the FASB issued ASU 2011-05 – Presentation of Comprehensive Income (“ASU 2011-05”), which requires entities to present reclassification adjustments included in other comprehensive income on the face of the financial statements and allows entities to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. It also eliminates the option for entities to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. For public companies, ASU 2011-05 is effective for fiscal years (and interim periods within those years) beginning after December 15, 2011, with earlier adoption permitted. Effective September 1, 2011, the Company adopted the provisions of ASU 2011-05. The adoption of ASU 2011-05 did not have a material impact on the Company’s financial position, results of operations, or cash flows.

There were various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.

2.	Accounts Receivable

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. For receivables from joint interest owners, the Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings. As of November 30, 2011 and August 31, 2011, major customers (i.e. those with balances greater than 10% of total receivables) are shown in the following table:

Accounts Receivable	As of November 30,		As of August 31,
from Major Customers:	2011		2011
Company A		34%		31%
Company B		19%		31%
Company C		17%		13%
Company D		12%		*

* less than 10%

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

3.	Property and Equipment

Capitalized costs of property and equipment at November 30, 2011, and August 31, 2011, consisted of the following:

	As of November 30, 2011			As of August 31, 2011
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	11,363,263		$	9,942,908
Wells in progress		5,885,668			4,813,749
Subtotal, unevaluated costs		17,248,931			14,756,657

Evaluated costs:
Producing and non-producing		43,675,280			37,750,737
Total capitalized costs		60,924,211			52,507,394
Less, accumulated depletion		(5,069,048	)		(3,892,537	)
Oil and gas properties, net		55,855,163			48,614,857

Other property and equipment:
Vehicles		163,904			163,904
Leasehold improvements		36,904			35,490
Office equipment		108,901			105,089
Land		43,750			43,750
Less, accumulated depreciation		(84,718	)		(65,026	)
Other property and equipment, net		268,741			283,207

Total property and equipment, net	$	56,123,904		$	48,898,064

The capitalized costs of evaluated oil and gas properties are depleted using the unit-of-production method based on estimated reserves and the calculation is performed quarterly. Production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate. For the three months ended November 30, 2011 and 2010, depletion of oil and gas properties was $1,176,511 and $568,038, respectively, or $14.76 and $19.05 per barrel of oil equivalent, respectively.

Periodically, the Company reviews its unevaluated properties and its inventory to determine if the carrying value of either asset exceeds its estimated fair value. The reviews for the three months ended November 30, 2011, and 2010 indicated that asset carrying values were less than estimated fair values and no reclassification to the full cost pool was required.

On a quarterly basis, the Company performs the full cost ceiling test. The ceiling tests performed for the three months ended November 30, 2011, and 2010 did not reveal any impairments.

For the three months ended November 30, 2011 and 2010, depreciation of other property and equipment was $19,692 and $10,239, respectively.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

4.	Interest Expense

The components of interest expense recorded for the three months ended November 30, 2011, and 2010 consisted of:

	Three Months Ended November 30,
	2011			2010
Convertible promissory notes at 8%	$	--		$	310,734
Related party note payable at 5.25%		68,063			--
Accretion of debt discount		--			420,923
Amortization of debt issuance costs		--			170,122
Less, interest capitalized		(68,063	)		(119,739	)
Interest expense, net	$	--		$	782,040

5.	Bank Credit Facility

In November 2011, the Company entered into a revolving line of credit facility with Bank of Choice (LOC), which provides for borrowings up to $15 million. The LOC replaced the previous credit facility the Company had with Bank of Choice, which had provided for borrowings up to $7 million. Under the new LOC, interest is payable monthly and accrues at the greater of the bank’s prime rate, which was 3.25% at November 30, 2011, or 3.25% annually. The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves. Certain of the Company’s assets, including substantially all developed properties, have been designated as collateral under the arrangement. The LOC matures on November 30, 2014. As of November 30, 2011, the amount of additional borrowings available under the LOC was $9.6 million.

6.	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 are 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 three months ended November 30, 2011:


Asset retirement obligations, August 31, 2011	$	643,459
Liabilities incurred		51,584
Liabilities settled		--
Accretion		17,639
Revisions in estimated liabilities		--
Asset retirement obligations, November 30, 2011	$	712,682

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

7.	Convertible Promissory Notes and Derivative Conversion Liability

During the fiscal year ended August 31, 2010, the Company received gross proceeds of $18,000,000 from the sale of 180 Units at $100,000 per Unit. Each Unit consisted of one convertible promissory note (“Note”) in the principal amount of $100,000 and 50,000 Series C warrants (collectively referenced as a “Unit”). The Notes were convertible into shares of common stock at a rate of $1.60 per share. At various dates and in various amounts, noteholders converted their Notes such that, by March 31, 2011, all of the Notes had been converted into 11,250,000 shares of the Company’s common stock.

The Notes were considered hybrid debt instruments containing a detachable warrant and a conversion feature under which the proceeds of the offering were allocated to the detachable warrants and the conversion feature based on their fair values. The conversion feature was determined to be an embedded derivative requiring the conversion option to be separated from the host contract and measured at its fair value. The conversion option was re-measured and recorded at fair value each subsequent reporting period, with changes in the fair value reflected in other income (expense) in the statements of operations.

In connection with the sale of the Units, the Company recorded $2,041,455 of debt issuance costs, which were amortized over the expected term of the Notes, with accelerated amortization recognition on early Note conversions. For the three months ended November 30, 2010, the Company recorded amortization expense for debt issuance costs of $170,122.

The Company recorded accretion expense for debt discount of $420,923 for the three months ended November 30, 2010.

Prior to the conversion of the Notes, the fair value of the derivative conversion liability was adjusted each quarter to reflect the change in value. The change in fair value of derivative conversion liability was $389,263 during the three months ended November 30, 2010, including a change of $311,898 related to the early conversion of Notes during the period.

8.	Fair Value Measurements

Financial assets and liabilities are measured at fair value on a recurring basis for disclosure or reporting, as required by ASC “Fair Value Measurements and Disclosures”.

A fair value hierarchy was established that 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).

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and US government treasury securities.

Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies, where substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

Level 3 - Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 includes those financial instruments that are valued using models or other valuation methodologies, where substantial assumptions are not observable in the marketplace throughout the full term of the instrument, cannot be derived from observable data or are not supported by observable levels at which transactions are executed in the marketplace. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

For the most part, the Company’s financial instruments consisted of cash and equivalents, accounts receivable, accounts payable, accrued liabilities, and obligations under the revolving line of credit facility. Due to the short original maturities and high liquidity of cash and equivalents, accounts receivable, accounts payable, and accrued liabilities, carrying amounts approximated fair values. Carrying amounts for the revolving line of credit facility are considered to approximate fair value because of the variable nature of the interest rate.

The Company also measures all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis. As discussed in Note 6, asset retirement obligations and costs totaling $712,682 and $643,359 have been accounted for as long-term liabilities and included in each property’s asset value at November 30, 2011 and August 31, 2011, respectively. The Level 3 inputs used to measure the estimated fair value of the obligations include assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations.

9.	Related Party Transactions and Commitments

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

Acquisition of Oil and Gas Assets from PEM: During the year ended August 31, 2011, the Company acquired oil and gas assets from PEM in two separate transactions.

In May 2011, the Company acquired operating (working interest) oil and gas wells, and other oil and gas assets, from PEM. The purchase price consisted of a cash payment of $10,000,000, the issuance of 1,381,818 restricted shares of common stock, and a promissory note in the principal amount of $5,200,000. In November 2011 the Company utilized proceeds from the LOC (Note 5) to repay the entire principal balance and accrued interest of $142,110.

In October 2010, the Company acquired certain mineral assets located in the Wattenberg Field of the D-J Basin, from PM and PEM for $1,017,435 in cash. The assets acquired included operating (working interest) oil and gas wells, certain drill sites, and miscellaneous equipment.

Other Related Party Transactions: The Company leases office space and an equipment yard from HSLC in Platteville, Colorado for $10,000 per month. The twelve month lease arrangement with HSLC commenced July 1, 2010 and was renewed on July 1, 2011, for another year. Under these leases, the Company paid HSLC $30,000 during each of the three months ended November 30, 2011 and 2010.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

The Company has agreed to compensate George Seward, a member of the Company’s board of directors, for his efforts to acquire certain mineral leases. Amounts payable to Mr. Seward are calculated at the rate of $7 per qualifying net mineral acre and, as of November 30, 2011, the Company had accrued fees of $543,611 payable to Mr. Seward. Fees will be paid in the form of restricted shares of the Company’s common stock. Subsequent to November 30, 2011, the Company issued 188,137 shares of restricted common stock to Mr. Seward as partial compensation under this agreement.

10.	Shareholders’ Equity

Preferred Stock: The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.01 per share. These shares may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares.

Common Stock: The Company has authorized 100,000,000 shares of common stock with a par value of $0.001 per share.

Issued and Outstanding: The total issued and outstanding common stock at November 30, 2011 and August 31, 2011 was 36,098,212 common shares.

As of November 30, 2011, there were various warrants outstanding to purchase 14,931,067 shares of common stock. The following table summarizes information about the Company’s issued and outstanding common stock warrants as of November 30, 2011:

Exercise Price		Description	Number of Shares		Remaining Contractual Life (in years)	Exercise Price times Number of Shares
	$1.60	Series D		769,601	3.1	$	1,231,362
	$1.80	Sales Agent Warrants		63,466	1.1		114,239
	$6.00	Series A		4,098,000	1.1		24,588,000
	$6.00	Series C		9,000,000	3.1		54,000,000
	$10.00	Series B		1,000,000	1.1		10,000,000
				14,931,067	2.4	$	89,933,601

The following table summarizes activity for common stock warrants for the three month period ended November 30, 2011:

	Number of Warrants		Weighted Average Exercise Price

Outstanding, August 31, 2011		14,931,067	$	6.02
Granted		--		--
Exercised		--		--
Outstanding, November 30, 2011		14,931,067	$	6.02

See Note 11 for information concerning the Company’s outstanding stock options.

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

11.	Stock-Based Compensation

The Company did not issue any stock grants during the three months ended November 30, 2011, and issued stock grants of 100,000 restricted shares valued at $210,000 to a consultant during the three months ended November 30, 2010.

Effective September 22, 2011, the Company granted employee stock options to purchase 100,000 shares of common stock at an exercise price of $2.80 and a term of ten years. The options vest over four years. These options were determined to have a fair value of $178,526 using the assumptions outlined in the table below.

For the grant of various stock options that are currently in the vesting phase, the Company recorded stock-based compensation expense of $97,266 and $25,486 for the three months ended November 30, 2011 and 2010, respectively. The estimated unrecognized compensation cost from unvested stock options as of November 30, 2011, was approximately $1,149,317, which will be recognized ratably over the next four years.

The assumptions used in valuing stock options for the three months ended November 30, 2011 were as follows:

Expected term (in years)	6.5
Expected volatility	69.43	%
Risk free rate	1.12	%
Expected dividend yield	0.00	%
Forfeiture rate	0.00	%

The following table summarizes activity for stock options for the period from August 31, 2011 to November 30, 2011:

	Number of Shares		Weighted Average Exercise Price

Outstanding, August 31, 2011		4,645,000	$	5.21
Granted		100,000	$	2.80
Exercised		--		--
Outstanding, November 30, 2011		4,745,000	$	5.16

The following table summarizes information about issued and outstanding stock options as of November 30, 2011:

	Outstanding Options		Vested Options
Number of shares		4,745,000		4,099,000
Weighted average remaining contractual life		2.7 years		1.7 years
Weighted average exercise price	$	5.16	$	5.43
Aggregate intrinsic value	$	5,312,500	$	5,088,500

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

November 30, 2011

(unaudited)

12.	Other Commitments and Contingencies

In connection with a 2008 private offering, the Company issued placement agent warrants which entitle the holder to purchase units consisting of common stock and warrants (Series A and B) at a price of $3.60 per unit. The Series A and Series B warrants issuable upon exercise of the placement agent warrants are not considered outstanding for accounting purposes until such time, if ever, that the placement agent warrants are exercised. In the event that the placement agent warrants are exercised, the Company will be obligated to issue 31,733 Series A warrants and 31,733 Series B warrants.

13.	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 months ended November 30, 2011 and 2010:

	Three Months Ended November 30,
	2011		2010
Supplemental cash flow information:
Interest paid	$	142,110	$	320,840
Income taxes paid		--		--

Non-cash investing and financing activities:
Conversion of promissory notes into common stock	$	--	$	500,000
Net change in accrued capital expenditures		1,299,281		(3,059,620	)
Asset retirement costs and obligations		51,584		51,108

14.	Subsequent Events

In December 2011, the Company sold 14,636,363 shares of common stock pursuant to a registration statement filed on Form S-3 with the Securities and Exchange Commission. The shares were issued at a price of $2.75 per share, and the Company received net cash proceeds of approximately $37,459,000 after deductions for the placement agents’ commissions and expenses of the offering.

Subsequent to November 30, 2011, the Company issued 413,283 shares of restricted common stock to 18 persons in exchange for interests in mineral leases and services rendered.

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 November 30, 2011, and the results of operations for the three months ended November 30, 2011, and 2010. 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 Form 10-K for the fiscal year ended August 31, 2011.

Our Prospectus Supplement filed on December 16, 2011 (designated as 424B5 on the SEC’s EDGAR system) should also be read as the Prospectus Supplement includes risk factors which pertain to our business and the market for our common stock.

Overview

We are an independent oil and gas company working to acquire, develop, and produce crude oil and natural gas in and around the Denver-Julesburg Basin (“D-J Basin”). All of our producing wells are in the Wattenberg Field, which has a well-developed infrastructure and takeaway capacity. During 2011, we expanded our undeveloped acreage holdings in eastern Colorado and western Nebraska, and may commence development activities in that area.

Since commencing active operations in September 2008, we have undergone significant growth. Specifically, we have drilled or acquired 141 producing oil and gas wells, as follows:

·	Participated in two wells during fiscal 2009;

·	Drilled and completed 22 wells during fiscal 2010:

·	Acquired interests in 72 wells, increased our ownership interest in 28 wells, completed 28 wells, and participated in 11 wells during fiscal 2011:

·	Completed six wells and participated in three wells that reached productive status during the three months ended November 30, 2011.

As of November 30, 2011, we were the operator of twelve wells that were in the drilling or completion process. Furthermore, we were participating as a non-operator in one additional well that was in the process of being completed.

As of November 30, 2011, we had estimated proved reserves of 2,032,773 Bbls of oil and 14,040,112 Mcf of gas.

We currently hold an acreage position of 191,132 gross acres and 169,579 net acres under lease.

Our strategy for continued growth includes additional drilling activities, acquisition of existing wells, and recompletion of wells that provide good prospects for improved hydraulic stimulation techniques. We attempt to maximize our return on assets invested by drilling and operating development wells in which we have a significant net revenue interest. We attempt to limit our risk by drilling in proven areas. To date, we have not drilled any dry holes. All of our current wells are relatively low-risk vertical or directional wells, and we do not currently have any horizontal wells. However, the success rate of horizontal wells drilled by other operators has recently improved and we expect to drill or participate in horizontal wells in the future. Historically, our cash flow from operations was not sufficient to fund our growth plans and we relied on proceeds from the sale of debt and equity securities. Our cash flow from operations is increasing, and we plan to finance an increasing percentage of our growth with internally generated funds. Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain.

Significant Developments

During the 22 weeks from August 1, 2011 through December 31, 2011 we drilled 22 wells, of which six had reached productive status by December 31, 2011. Completion activities are underway on sixteen wells, most of which are expected to reach productive status during our second fiscal quarter. In January, we continued drilling operations with a rig under contract to us from Ensign United States Drilling, Inc. We expect to drill and complete approximately 46 wells during our 2012 fiscal year.

In November 2011, we entered into a new revolving line of credit facility with Bank of Choice. The new revolving line of credit increases our borrowing capacity up to $15 million from our previous facility that provided for borrowings up to $7 million. Our new line of credit accrues interest at the greater of the Prime Rate, as defined, or 3.25% annually, with interest payable monthly, and matures on November 30, 2014.

We used proceeds from the revolving line of credit facility to repay the outstanding principal balance of $5,200,000 plus accrued interest of $142,110 under our related party note payable.

During December 2011 we completed the sale of 14.6 million shares of our common stock at $2.75 per share for net proceeds totaling approximately $37.5 million after deduction of sales commissions and expenses. The public offering of additional shares of our common stock was underwritten by Northland Capital Markets, C. K. Cooper & Company, and GVC Capital LLC.

RESULTS OF OPERATIONS

For the three months ended November 30, 2011, compared to the three months ended November 30, 2010

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 November 30, 2011, we reported net income of $1,627,333 compared with a net loss of ($1,160,004) during the three months ended November 30, 2010. Earnings per basic and diluted share were $0.05 and $0.04, respectively, for the three months ended November 30, 2011, compared to a loss of ($0.08) per basic and diluted share for the three months ended November 30, 2010. The comparison between the two years was primarily influenced by increasing revenues and expenses associated with the increased number of producing wells. As of November 30, 2011 we had 141 producing wells, a quarter-over-quarter increase of 94 wells, which consists of 64 wells added through acquisitions and 30 wells completed since November 30, 2010. These changes resulted in our operating income increasing from $10,838 in 2010 to $1,619,152 in 2011, an increase of $1,608,314.

Oil and Gas Production and Revenues – For the three months ended November 30, 2011, we recorded total oil and gas revenues of $4,478,864 compared to $1,443,595 for the three months ended November 30, 2010, an increase of $3,035,269 or 210%. Our growth in revenue was the result of an increase in our production volume of 167% quarter-over-quarter, and an increase in our average selling price per BOE of 16% quarter-over-quarter. For the quarter, our gas / oil ratio (“GOR”) was 52/48. During the comparable prior period, our GOR was 47/53.

Key production information is summarized in the following table:

	Three Months Ended November 30,
	2011		2010		Change
Production:
Oil (Bbls)		38,277		15,939	140.1%
Gas (Mcf)		248,486		83,306	198.3%
BOE (Bbls)		79,691		29,823	167.2%

Revenues:
Oil	$	3,178,069	$	1,153,779	175.4%
Gas		1,300,795		289,816	348.8%
Total	$	4,478,864	$	1,443,595	210.3%

Average sales price:
Oil (Bbls)	$	83.03	$	72.39	14.7%
Gas (Mcf)	$	5.23	$	3.48	50.5%
BOE (Bbls)	$	56.20	$	48.40	16.1%

“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 November 30, 2011 was 79,691 BOE, or 876 BOE per day. The significant increase in production from the comparable period in the prior year reflects the additional wells that were acquired or began production over the past twelve months.

We do not currently engage in any commodity hedging activities, although we may do so in the future.

Lease Operating Expenses – As summarized in the following table, our lease expenses include the direct operating costs of producing oil and natural gas and taxes on production and properties:

	Three Months ended November 30,
	2011		2010
Severance and ad valorem taxes	$	405,011	$	140,799
Work-over		46,137		-
Production costs		212,797		54,600
Other		42,375		7,276
Total production expenses	$	706,320	$	202,675

Per BOE:
Severance and ad valorem taxes	$	5.08	$	4.72
Work-over		0.58		-
Production costs		2.67		1.83
Other		0.53		0.24
Total per BOE	$	8.86	$	6.80

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 component of production costs and tend to increase or decrease primarily based on the value of oil and gas sold. As a percent of revenues, taxes averaged 9% for the three months ended November 30, 2011 and 10% for the three months ended November 30, 2010.

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

	Three Months ended November 30,
	2011		2010
Depletion	$	1,176,511	$	568,038
Depreciation and amortization		19,692		10,239
Accretion of asset retirement obligations		17,639		6,704
Total DDA	$	1,213,842	$	584,981

Depletion per BOE	$	14.76	$	19.05

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 November 30, 2011, production volumes of 79,691 BOE and estimated net proved reserves of 4,446,565 BOE were the basis of the depletion rate calculation. For the three months ended November 30, 2010, production volumes 29,823 BOE and estimated net proved reserves of 1,357,000 BOE were the basis of the depletion rate calculation. Depletion expense per BOE decreased approximately 23%, primarily because of the significant increase in the reserve base over the past year. Another factor that contributed to the decrease in per unit costs was the accounting treatment of proceeds received from the sale of undeveloped interests during the year ended August 31, 2011, which were recorded as a reduction of costs in the full cost pool and reduced DDA by approximately $1.80 per BOE.

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

	Three Months ended November 30,
	2011			2010
Cash based compensation	$	408,188		$	246,311
Share based compensation		97,266			235,486
Professional fees		330,707			162,107
Other general and administrative		185,775			65,917
Capitalized general and administrative		(82,386	)		(64,720	)
Totals	$	939,550		$	645,101

Cash based compensation includes payments to employees. The increase of $161,877 from 2010 to 2011 reflects the expansion of our business, including the addition of four employees during the year. Share based compensation includes compensation paid to employees, directors and service providers in the form of either stock options or common stock grants. The amount of expense recorded for stock options is calculated by using the Black-Scholes-Merton option pricing model. The Company recognized stock option expense of $97,266 and $25,486 for the three months ended November 30, 2011 and 2010, respectively. The amount of expense recorded for common stock grants is calculated based upon the closing market value of the shares. The Company recognized expenses for common stock grants of $0 and $210,000 for the three months ended November 30, 2011 and 2010, respectively.

Our professional fees have increased as we grow our business. The two primary factors driving this increase are the additional accounting and auditing fees incurred in connection with operating as a public company, and the additional professional services required to meet the compliance requirements of Sarbanes-Oxley as we have progressed from a smaller reporting company to an accelerated filer.

The increase in other general administrative expenses primarily relates to additional fees and expenses of approximately $84,000 incurred in connection with listing our common stock on the NYSE Amex in July 2011. Our common stock previously traded “over the counter” on the OTC Bulletin Board, for which we were not charged fees.

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 2010 to 2011 reflects our increasing activities to acquire leases and develop the properties.

Other Income (Expense) – Our other income for the three months ended November 30, 2011 was $8,181, as compared with other expenses, net, of $1,170,842 for the three months ended November 30, 2010. The change is primarily the result of expenses associated with convertible promissory notes that were outstanding during the three months ended November 30, 2010. Our previously outstanding convertible promissory notes were all converted into shares of our common stock during the year ended August 31, 2011. Expenses during the three months ended November 30, 2010 associated with these convertible promissory notes totaled $1,171,303, which included interest expense, net of $190,995, accretion of debt discount of $420,923, amortization of debt issuance costs of $170,122, and a non-cash expense of $389,263 representing the change in the fair value of the derivative conversion liability.

Income Taxes – Income taxes do not currently have an impact on our results of operations as we have reported a net loss every year since inception and for tax purposes have a net operating loss carry forward (“NOL”) of approximately $11.3 million. The NOL is available to offset future taxable income, if any. At such time, if ever, that we are able to demonstrate that it is more likely than not that we will be able to realize the benefits of our tax assets, we will begin to recognize the impact of taxes in our financial statements.

LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the three months ended November 30, 2011, and 2010 are shown below:

	Three Months Ended November 30,
	2011			2010

Cash provided by operations	$	4,587,476		$	2,703,006
Acquisition of oil and gas properties, and equipment		(7,071,178	)		(4,723,613	)
Net borrowings		192,110			--
Net decrease in cash	$	(2,291,592	)	$	(2,020,607	)

Net cash provided by operating activities was $4,587,476 and $2,703,006 for the three months ended November 30, 2011 and 2010, respectively. The change reflects significant growth in operating contribution from the additional wells that were producing during 2011 as compared to 2010. In addition to our analysis using amounts included in the cash flow statement, we evaluate operations using a non-GAAP measure called “adjusted cash flow from operations,” which adjusts for cash flow items that merely reflect the timing of certain cash receipts and expenditures. Adjusted cash flow from operations was $2,938,441 and $640,771 for the three months ended November 30, 2011 and 2010, respectively. The improvement of $2,297,670 under that measure is closely correlated to, and primarily explained by, increased revenues of $3,053,796 less increases in direct costs of $503,645 and general and administrative expenses of $294,449.

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 $8,422,043 and $1,715,098 for the three months ended November 30, 2011 and 2010, respectively, compared to cash payments of $7,071,178 and $4,723,613, respectively. A reconciliation of the differences is summarized in the following table:

	Three Months Ended November 30,
	2011			2010

Cash payments	$	7,071,178		$	4,723,613
Accrued costs, beginning of period		(4,967,369	)		(3,446,439	)
Accrued costs, end of period		6,266,650			386,816
Asset retirement obligation		51,584			51,108
Capital expenditures	$	8,422,043		$	1,715,098

During the quarter ended November 30, 2011, we engaged in drilling or completion activities on 18 wells which we operate. Six of the wells reached productive status during the quarter. Completion activities were underway on 12 wells, most of which are expected to reach productive status during our second fiscal quarter.

Most of our capital expenditures for the three months ended November 30, 2011, represent the cost of the 18 wells in progress. In addition, we incurred costs of approximately $1.4 million on the acquisition of mineral leases, and approximately $500,000 as our share of the costs on four wells in which we participate as a non-operator.

In November 2011, we modified our borrowing arrangement with Bank of Choice to increase the maximum allowable borrowings and to reduce the interest rate. The new revolving line of credit increases our borrowing capacity up to $15 million from our previous facility that provided for borrowings up to $7 million. Our new line of credit accrues interest at the greater of the bank’s prime rate, which was 3.25% at November 30, 2011, or 3.25% annually, with interest payable monthly, and matures on November 30, 2014. 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. As of November 30, 2011, the borrowing base calculation was not restrictive. We utilized the new arrangement to retire amounts outstanding under our related party note payable.

Our net borrowings during the quarter were $192,110, which consisted of borrowings of $5,392,110 under our new line of credit, offset by the repayment of the entire outstanding principal balance under our related party note payable for $5,200,000.

Subsequent to end of the quarter, we received net proceeds of $37.5 million from the sale of 14.6 million shares of common stock. We believe that the proceeds from this sale, plus cash flow from operations, plus additional borrowings available under our revolving line of credit will be sufficient to meet our liquidity needs during the 2012 fiscal year.

Our primary need for cash during the fiscal year ending August 31, 2012, will be to fund our drilling and acquisition programs. We currently estimate capital expenditures of approximately $41 million for our drilling program. As an operator we plan to spend approximately $30 million to drill 46 wells in which we own a significant interest. An additional $8 million has been estimated as our portion of the cost of vertical and horizontal wells in which we will participate as a non-operator. We also plan recompletion costs approximating $3 million on 20 wells that indicate good potential for additional hydraulic stimulation. Under our proposed acquisition program, acquisition of undeveloped acreage and proved properties is expected to require funds of up to $21 million. Our capital expenditure estimate is subject to significant 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.

Contractual Commitments

In addition to the commitments disclosed in our Annual Report on Form 10-K, we elected to participate in a horizontal well to be drilled by another operator. Our estimated costs under the Authorization for Expenditure are $1.2 million.

Non-GAAP Financial Measures

We use "adjusted cash flow from operations" and "adjusted EBITDA," non-GAAP financial measures, for internal managerial purposes, when evaluating period-to-period comparisons. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, net income, nor as a liquidity measure or indicator of cash flows or an indicator of operating performance reported in accordance with U.S. GAAP. The non-GAAP financial measures that we use may not be comparable to measures with similar titles reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-GAAP Financial Measures below for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure.

Reconciliation of Non-GAAP Financial Measures

Adjusted cash flow from operations. We define adjusted cash flow from operations as the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables and payables. We believe it is important to consider adjusted cash flow from operations as well as cash flow from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during the period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices. See the Statements of Cash Flows in this report.

Adjusted EBITDA. We define adjusted EBITDA as net income (loss) plus interest expense, net of interest income, income taxes, and depreciation, depletion and amortization for the period plus/minus the change in fair value of our derivative conversion liability. We believe adjusted EBITDA is relevant because it is a measure of cash available to fund our capital expenditures and service our debt and is a widely used industry metric which allows comparability of our results with our peers.

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

	Three Months Ended November 30,
	2011			2010
Adjusted cash flow from operations:
Adjusted cash flow from operations	$	2,938,441		$	640,771
Changes in assets and liabilities		1,649,035			2,062,235
Net cash provided by operating activities	$	4,587,476		$	2,703,006

Adjusted EBITDA:
Adjusted EBITDA	$	2,832,994		$	595,819
Interest expense and related items, net		8,181			(781,579	)
Change in fair value of derivative conversion liability		--			(389,263	)
Depreciation, depletion and amortization		(1,213,842	)		(584,981	)
Net income (loss)	$	1,627,333		$	(1,160,004	)

TREND AND OUTLOOK

The 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, (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may increase the difficulty of obtaining financing. 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, 2011, 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, 2011.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

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

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

•

The success of our exploration and development efforts;

•

The price of oil and gas;

•

The worldwide economic situation;

•

Any change in interest rates or inflation;

•

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

•

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

•

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

•

Our costs of production;

•

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

•

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

•

The volatility of our stock price.

Item 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 November 30, 2011, we had debt outstanding under our bank credit facility totaling $5,392,110. Interest on our bank credit facility accrues at the greater of 3.25% or the prime rate, which was also 3.25% at November 30, 2011. While we are currently incurring interest at the floor of 3.25%, we are exposed to interest rate risk on the bank credit facility if the prime rate exceeds the floor. If interest rates increase, our interest expense would increase and our available cash flow would decrease.

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 November 30, 2011, 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 November 30, 2011, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II

Item 6. Exhibits

a. Exhibits

31.1

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

31.2

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

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

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: January 9, 2012	By:	/s/ Ed Holloway
		Ed Holloway, President and Principal Executive Officer



Date: January 9, 2012	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Principal Financial and Accounting Officer

SRC Energy Inc. - FORM 10-Q - January 9, 2012

Attached files

SRC Energy Inc. Reports