XASE:SYRG Synergy Resources Corp Quarterly Report 10-Q Filing - 2/29/2012

Effective Date 2/29/2012

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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 29, 2012

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 March 30, 2012.
 
 
 
 

 
 
SYNERGY RESOURCES CORPORATION

Index

 
Page
Part I – FINANCIAL INFORMATION
   
     
Item 1.
Financial Statements
 
     
 
Balance Sheets as of February 29, 2012 (unaudited)
  and August 31, 2011
3
       
 
Statements of Operations for the three months and six months ended
  February 29, 2012 and February 28, 2011 (unaudited)
4
       
 
Statements of Cash Flows for the six months ended
  February 29, 2012, and February 28, 2011 (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
32
     
Item 4.
Controls and Procedures
32
       
Part II - OTHER INFORMATION
   
       
Item 6.
Exhibits
33
       
SIGNATURES
34

 
2
 
 

 
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
 
   
As of
   
As of
 
   
February 29,
   
August 31,
 
    2012    
2011
 
   
(unaudited)
       
ASSETS
           
Current assets:
           
Cash and cash equivalents
  $ 38,852,524     $ 9,490,506  
Accounts receivable:
               
Oil and gas sales
    3,237,796       2,185,051  
Joint interest billing
    2,651,139       2,406,473  
Inventory
    490,546       459,592  
Other current assets
    102,091       89,336  
Total current assets
    45,334,096       14,630,958  
                 
Property and equipment:
               
Oil and gas properties, full cost method, net
    67,457,604       48,614,857  
Other property and equipment, net
    285,747       283,207  
Property and equipment, net
    67,743,351       48,898,064  
                 
Deferred tax asset, net
    3,241,000       -  
Other assets
    219,912       168,863  
                 
Total assets
  $ 116,538,359     $ 63,697,885  
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
               
Current liabilities:
               
Accounts payable:
               
Trade
  $ 11,441,896     $ 6,620,561  
Accrued expenses
    3,212,546       2,125,852  
Notes payable, related party
    -       5,200,000  
Total current liabilities
    14,654,442       13,946,413  
                 
Revolving credit facility
    5,392,110       -  
Asset retirement obligations
    815,873       643,459  
Total liabilities
    20,862,425       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:
               
51,147,858 and 36,098,212 shares issued and outstanding
               
as of February 29, 2012, and August 31, 2011, respectively
    51,148       36,098  
Additional paid-in capital
    122,818,486       84,011,496  
Accumulated deficit
    (27,193,700 )     (34,939,581 )
Total shareholders' equity
    95,675,934       49,108,013  
                 
Total liabilities and shareholders' equity
  $ 116,538,359     $ 63,697,885  
 
 
The accompanying notes are an integral part of these financial statements.
 
3
 
 

 
 
SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
 (unaudited)

 
Three Months Ended
   
Six Months Ended
 
   
February 29,
   
February 28,
   
February 29,
   
February 28,
 
   
2012
   
2011
   
2012
   
2011
 
                         
Revenues:
                       
Oil and gas revenues
  $ 6,218,975     $ 2,033,687     $ 10,697,839     $ 3,477,282  
Total revenues
    6,218,975       2,033,687       10,697,839       3,477,282  
                                 
Expenses:
                               
Lease operating expenses
    854,414       260,480       1,560,734       463,155  
Depreciation, depletion,
     and amortization
    1,552,237       647,205       2,766,079       1,232,186  
General and administrative
    937,029       439,589       1,876,838       1,084,690  
Total expenses
    3,343,680       1,347,274       6,203,651       2,780,031  
                                 
Operating income
    2,875,295       686,413       4,494,188       697,251  
                                 
Other income (expense):
                               
Change in fair value of 
    derivative conversion liability
    -       (9,926,158 )     -       (10,315,421 )
Interest expense, net
    -       (2,514,045 )     -       (3,296,084 )
Interest income
    2,510       15,430       10,693       15,891  
Total other income (expense)
    2,510       (12,424,773 )     10,693       (13,595,614 )
                                 
Income (loss) before income taxes
    2,877,805       (11,738,360 )     4,504,881       (12,898,363 )
                                 
Provision for income tax benefit
    3,241,000       -       3,241,000       -  
Net income (loss)
  $ 6,118,805     $ (11,738,360 )   $ 7,745,881     $ (12,898,363 )
                                 
Net income (loss) per common share:
                               
Basic
  $ 0.13     $ (0.55 )   $ 0.19     $ (0.73 )
Diluted
  $ 0.12     $ (0.55 )   $ 0.18     $ (0.73 )
                                 
Weighted average shares outstanding:
                         
Basic
    47,445,178       21,487,951       41,771,695       17,580,331  
Diluted
    49,229,042       21,487,951       43,536,398       17,580,331  

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 29, 2012 and February 28, 2011
(unaudited)
 
   
2012
   
2011
 
             
 Cash flows from operating activities:
           
 Net income (loss)
  $ 7,745,881     $ (12,898,363 )
 Adjustments to reconcile net income (loss) to net cash
               
   provided by operating activities:
               
 Depreciation, depletion, and amortization
    2,766,079       1,232,186  
 Amortization of debt issuance cost
    -       1,165,271  
 Accretion of debt discount
    -       1,902,002  
 Provision for deferred taxes
    (3,241,000 )     -  
 Stock-based compensation
    215,109       260,971  
 Change in fair value of derivative liability
    -       10,315,421  
 Changes in operating assets and liabilities:
               
 Accounts receivable
    (1,297,411 )     (785,734 )
 Inventory
    (30,954 )     (118,981 )
 Accounts payable
    1,959,527       2,322,788  
 Accrued expenses
    1,577,697       341,476  
 Other
    (63,804 )     (68,091 )
 Total adjustments
    1,885,243       16,567,309  
Net cash provided by operating activities
    9,631,124       3,668,946  
                 
Cash flows from investing activities:
               
Acquisition of property and equipment
    (17,882,999 )     (5,946,766 )
Net cash used in investing activities
    (17,882,999 )     (5,946,766 )
                 
Cash flows from financing activities:
               
Cash proceeds from sale of stock
    40,249,998       18,000,000  
Offering costs
    (2,828,215 )     (1,309,279 )
Proceeds from revolving credit facility
    5,392,110       -  
Principal repayment of related party notes payable
    (5,200,000 )     -  
Net cash provided by financing activities
    37,613,893       16,690,721  
                 
Net increase in cash and equivalents
    29,362,018       14,412,901  
                 
Cash and equivalents at beginning of period
    9,490,506       6,748,637  
                 
Cash and equivalents at end of period
  $ 38,852,524     $ 21,161,538  
                 
Supplemental Cash Flow Information (See Note 13)
               

The accompanying notes are an integral part of these financial statements.
 
5
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(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.
 

6
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(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, capitalized costs are subject to an impairment test known as a ceiling test.  For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, cannot exceed an amount (the cost center ceiling) equal to the sum of (a) the present value of estimated future net cash flows from proved oil and gas reserves, computed by applying current prices, as defined, to estimated future production, less estimated future expenditures to be incurred in developing and producing the proved reserves using a discount factor of 10 percent and assuming continuation of existing economic conditions; plus (b) the cost of properties not being amortized; plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; less (d) income tax effects related to differences between the future net revenues and value and the tax bases of the related assets.  If amounts recorded as capitalized costs, less accumulated amortization and related deferred income taxes, exceed the cost center ceiling, the excess is considered an impairment that is immediately charged to expense.  Once an impairment expense is recorded, it cannot be reinstated in future periods, even if subsequent events increase the cost center ceiling.

For purposes of the ceiling test calculation, current prices are defined 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.  Prices are adjusted for basis or location differentials.  Unless sales contracts specify otherwise, prices are held constant for the productive life of each well.  Similarly, current costs are assumed to remain constant over the entire calculation period.

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 $85,885 and $168,271 for the three months and six months ended February 29, 2012, respectively, were capitalized in the full cost pool.  The comparable capitalized overhead for the previous fiscal year was $43,228 and $107,948 for the three and six months ended February 28, 2011, respectively.
 

7
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 
 
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, is 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.

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.

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 its 2008 convertible promissory notes, the Company accounted for the embedded conversion features in accordance with the guidance for derivative instruments, which required 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.
 
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.

 8
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 
 
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
   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
   
February 29,
2012
   
February 28,
2011
 
                         
Company A
    81%       78%       71%       78%  
Company B
    13%       19%       15%       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 February 28, 2011 all potentially dilutive securities have an anti-dilutive effect on earnings per share.  For the three months ended February 29, 2012, a reconciliation of weighted-average shares outstanding is as follows:

   
Three Months Ended
   
Six Months Ended
 
   
2012
   
2011
   
2012
   
2011
 
                         
Weighted-average shares outstanding - basic
    47,445,178       21,487,951       41,771,695       17,580,331  
Potentially dilutive common shares from:
                               
Stock options
    1,390,248       -       1,376,758       -  
Warrants
    393,616       -       387,945       -  
      1,783,864       -       1,764,703       -  
Weighted-average shares outstanding - diluted
    49,229,042       21,487,951       43,536,398       17,580,331  

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.
 
9
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 

 
The realization of the deferred tax assets related to the net operating loss carry-forwards is dependent upon the Company’s ability to generate future taxable income.  The ability of the Company to utilize net operating loss carry-forwards may be further limited by other provisions of the Code.  For reporting periods prior to February 29, 2012, 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.  Effective February 29, 2012, management concluded that positive indicators outweighed negative indicators, and that it was appropriate to release the valuation allowance.

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 February 29, 2012.  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.

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.  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 February 29, 2012 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
February 29,
 
As of
August 31,
from Major Customers:
 
2012
 
2011
Company A
 
32%
 
31%
Company B
 
27%
 
31%
Company C
 
13%
 
13%
 
10
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 

 
3.     Property and Equipment

Capitalized costs of property and equipment at February 29, 2012, and August 31, 2011, consisted of the following:

   
As of
February 29,
2012
   
As of
August 31,
2011
 
Oil and gas properties, full cost method:
           
   Unevaluated costs, not subject to amortization:
           
      Lease acquisition and other costs
  $ 12,839,595     $ 9,942,908  
      Wells in progress
    7,076,261       4,813,749  
         Subtotal, unevaluated costs
    19,915,856       14,756,657  
                 
   Evaluated costs:
               
      Producing and non-producing
    54,123,867       37,750,737  
         Total capitalized costs
    74,039,723       52,507,394  
      Less, accumulated depletion
    (6,582,119 )     (3,892,537 )
           Oil and gas properties, net
    67,457,604       48,614,857  
                 
Other property and equipment:
               
    Vehicles
    163,904        163,904  
    Leasehold improvements
    65,806        35,490  
    Office equipment
    116,913        105,089  
    Land
    43,750       43,750  
      Less, accumulated depreciation
    (104,626 )      (65,026 )
            Other property and equipment, net
    285,747       283,207  
                 
Total property and equipment, net
  $ 67,743,351     $ 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 and six months ended February 29, 2012, depletion of oil and gas properties was $1,513,071 and $2,689,582, respectively, or $15.24 and $14.84 per barrel of oil equivalent, respectively. The comparable depletion expense for the previous fiscal year was $627,517 ($18.07 per BOE) and $1,195,555 ($18.52 per BOE) for the three months and six months ended February 28, 2011, 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 and six months ended February 29, 2012, and February 28, 2011 indicated that asset carrying values were less than estimated fair values and no reclassification to the full cost pool was required.
 

11
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 
 
On a quarterly basis, the Company performs the full cost ceiling test.  The ceiling tests performed for the three months and six months ended February 29, 2012, and February 28, 2011 did not reveal any impairments.

For the three months and six months ended February 29, 2012, depreciation of other property and equipment was $19,908 and $39,600, respectively.  For the three months and six months ended February 28, 2011, depreciation of other property and equipment was $11,499 and $21,738, respectively.

4.     Interest Expense

The components of interest expense recorded for the three months and six months ended February 29, 2012, and February 28, 2011 consisted of:

   
Three Months Ended
   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
   
February 29,
2012
   
February 28,
2011
 
Revolving bank credit facility at 3.25%
  $ 44,782     $ --     $ 44,782     $ --  
Convertible promissory notes at 8%
    --       258,721       --       569,455  
Related party note payable at 5.25%
    --       --       68,063       --  
Accretion of debt discount
    --       1,481,079       --       1,902,002  
Amortization of debt issuance costs
    --       995,150       --       1,165,271  
Less, interest capitalized
    (44,782 )     (220,905 )     (112,845 )     (340,644 )
Interest expense, net
  $ --     $ 2,514,045     $ --     $ 3,296,084  

5.     Revolving Bank Credit Facility

In November 2011, the Company entered into a revolving line of credit facility (“LOC”) with Bank of Choice, 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 bank’s prime rate, subject to a minimum rate of 3.25%.  At February 29, 2012, the bank’s prime rate was 3.25%.  The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves. In addition, the Company must maintain certain customary financial ratios during the term of the agreement.  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 February 29, 2012, the amount of additional borrowings available under the LOC was $9.6 million and the Company was in compliance with all covenants.
 

12
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 
 
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 six months ended February 29, 2012:
       
Asset retirement obligations, August 31, 2011
  $ 643,459  
  Liabilities incurred
    135,517  
  Liabilities settled
    --  
  Accretion
    36,897  
  Revisions in estimated liabilities
    --  
Asset retirement obligations, February 29, 2012
  $ 815,873  

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.

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”.
 

13
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 
 
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.

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 have been accounted for as long-term liabilities.  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, facilities, and oil and gas properties 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.
 

14
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 
 
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 storage 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 and $60,000 during the three months and six months ended February 29, 2012, respectively.  The comparable payments for the prior fiscal year were $30,000 and $60,000 for the three months and six months ended February 28, 2011, respectively.

During 2010, the Company initiated a program to acquire mineral interests in several Colorado and Nebraska counties that are considered the eastern portion of the D-J Basin.  George Seward, a member of the Company’s board of directors, agreed to lead that program.  The Company agreed to compensate the persons, including Mr. Seward, to assist the Company with the acquisitions at a specific rate per qualifying net mineral acre.  The compensation is paid in the form of restricted shares of the Company’s common stock.  The Company has recorded aggregate compensation of $565,217 payable to Mr. Seward, of which $74,214 was accrued and unpaid at February 29, 2011. During the six months ended February 29, 2012, issued 188,137 shares of restricted common stock to Mr. Seward as partial payment under this program.

10.     Shareholders’ Equity

Preferred Stock:  The Company is authorized to issue 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 is authorized to issue 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 February 29, 2012 and August 31, 2011 was 51,147,858 and 36,098,212 common shares, respectively.  The following shares of common stock were issued during the six months ended February 29, 2012:

Sale of common stock:  On December 30, 2011, the Company completed the sale of 14,636,363 shares of common stock in a public offering of common stock at a public offering price of $2.75 per share.  The underwriters were Northland Capital Markets, C.K. Cooper & Company, and GVC Capital, LLC.  Net proceeds to the Company were $37.4 million after deductions for the underwriting discounts, commissions and expenses of the offering.

Common stock issued for acquisition of mineral interests:  The Company issued 220,146 common shares in exchange for mineral leases and joint venture interests.  The aggregate value of these transactions was $694,145 which was determined using the market price of the Company’s common stock.
 
15
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 

 
Common stock issued for services:  The Company issued a total of 193,137 shares of common stock, with a fair market value of $508,003, to individuals as compensation for services provided to the Company.

As of February 29, 2012, 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 February 29, 2012:
 
                             
Exercise
Price
 
Description
   
Number of Shares
     
Remaining Contractual Life (in years)
     
Exercise Price times Number of Shares
 
$1.60  
Series D
    769,601       2.8     $ 1,231,362  
$1.80  
Sales Agent Warrants
    63,466       0.8       114,239  
$6.00  
Series A
    4,098,000       0.8       24,588,000  
$6.00  
Series C
    9,000,000       2.8       54,000,000  
$10.00  
Series B
    1,000,000       0.8       10,000,000  
          14,931,067       2.1     $ 89,933,601  
                             
The following table summarizes activity for common stock warrants for the six month period ended February 29, 2012:
 
   
Number of
Warrants
   
Weighted Average
Exercise Price
 
             
Outstanding, August 31, 2011
    14,931,067     $ 6.02  
Granted
    --       --  
Exercised
    --       --  
Outstanding, February 29, 2012
    14,931,067     $ 6.02  

In addition to the common stock warrants that are outstanding, the Company has issued options to purchase shares of common stock.  Information about the options is contained in Note 11.

11.     Stock-Based Compensation

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 this Note.

The Company records an expense related to stock options by pro-rating the estimated fair value of the option grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”).  For the grant of various stock options that are currently in the vesting phase, the Company recorded stock-based compensation expense of $100,842 and $198,109 for the three months and six months ended February 29, 2012, respectively.  The comparable stock-based compensation expense for the three months and six months ended February 28, 2011 was $25,486 and $50,971, respectively.
 
16
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 

 
The estimated unrecognized compensation cost from unvested stock options as of February 29, 2012, was approximately $1,048,475, which will be recognized ratably over the remaining vesting phase, which is approximately four years.

The assumptions used in valuing stock options for the six months ended February 29, 2012 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 February 29, 2012:

   
Number of Shares
   
Weighted Average
Exercise Price
 
             
Outstanding, August 31, 2011
    4,645,000     $ 5.21  
Granted
    100,000     $ 2.80  
Exercised
    --       --  
Outstanding, February 29, 2012
    4,745,000     $ 5.16  

The following table summarizes information about issued and outstanding stock options as of February 29, 2012:

   
Outstanding Options
   
Vested
Options
 
Number of shares
    4,745,000       4,119,000  
Weighted average remaining contractual life
 
2.0 years
   
1.5 years
 
Weighted average exercise price
  $ 5.16     $ 5.42  
Aggregate intrinsic value
  $ 5,161,300     $ 4,971,360  

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.
 

17
 
 

 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 29, 2012
(unaudited)
 
 
 
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 six months ended February 29, 2012 and February 28, 2011:

   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
 
Supplemental cash flow information:
           
    Interest paid
  $ 186,891     $ 703,331  
    Income taxes paid
    --       --  
                 
Non-cash investing and financing activities:
               
    Accrued capital expenditures
  $ 7,829,177     $ 2,515,024  
    Assets acquired in exchange for common stock
  $ 694,145       --  
    Asset retirement costs and obligations
  $ 135,517     $ 76,663  
    Reclass derivative liability to equity
    --     $ 9,394,278  
    Conversion of promissory notes into common stock
    --     $ 9,811,675  

14.     Income Taxes

The Company released its entire valuation allowance of $4,911,000 and recorded a net deferred tax asset of $3,241,000 for the six months ended February 29, 2012.  The effective tax rate for the period differs from the statutory federal income tax rate because of the inclusion of state income taxes and the change in the valuation allowance.

As of August 31, 2011, the Company had a net deferred tax asset of $4,911,000.  For reporting periods prior to February 29, 2012, 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.  Effective February 29, 2012, management concluded that positive indicators outweighed negative indicators, and that it was appropriate to release the valuation allowance, primarily for the three following reasons.  First, all of the net losses for the two prior fiscal years can be attributed to a single discrete item.  The discrete item was the fair value accounting treatment of the components of the 8% convertible promissory notes issued in 2010, which created non-cash expenses for accretion of debt discount, amortization of issuance costs, and change in fair value of derivative liability.  As all of the convertible notes were converted prior to March 31, 2011, those expenses will not recur, and it is appropriate to exclude them from a consideration of future profitability.  Second, the Company has reported three consecutive quarters of net income and six consecutive quarters of operating income.  Third, the Company completed a debt financing arrangement and an equity financing arrangement that allow it to continue with its operating plan.  Accordingly, the Company believes that it is appropriate to release the valuation allowance related to the deferred tax asset created by the net operating loss carryover.
 
 
 
18
 
 

 

 
 
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 29, 2012, and the results of operations for the three months and six months ended February 29, 2012, and 2011.  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 adequate pipeline and trucking 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 157 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:
·  
Acquired interests in four wells and completed 18 wells during the six months ended February 29, 2012.

As of February 29, 2012, we were the operator of thirteen wells that were in the drilling or completion process and we were participating as a non-operating working interest owner in two wells that were in progress.

As of February 29, 2012, we had estimated proved reserves of 2,351,526 Bbls of oil and 15,810,703 Mcf of gas.

During March 2012, we closed on the acquisition of 8,875 net acres in the D-J Basin, which brought our acreage position to 204,937 gross acres and 176,601 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 the wells drilled prior to 2012 are relatively low-risk vertical or directional wells.  In January 2012, we participated with another operator in a horizontal well, and in March 2012, we participated in a second horizontal well.  We expect to drill or participate in additional 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.
 

19
 
 

 
Recent Developments

During August 2011, we commenced drilling operations with a rig under contract to us from Ensign United States Drilling, Inc.  During the 31 weeks from August 1, 2011, through February 29, 2012, the rig drilled 31 wells, of which 18 had reached productive status by February 29, 2012.  Completion activities are underway on 13 wells, most of which are expected to reach productive status during our third fiscal quarter.  In March 2012, the rig commenced drilling at a site near AIMS Community College in Greeley, Colorado where we expect to drill 9 wells.  We anticipate that we will drill and complete 52 wells during our 2012 fiscal year.

In January 2012, we participated with another operator in a horizontal well in Weld County, the Wake E24-77HN.  The well reached total depth in February and, as of February 29, 2012, completion activities were underway.  We own a 25% working interest in the well and expect our share of the drilling and completion costs to be approximately $1.2 million.  In March 2012, we participated with another operator in the Leffler 24-1-H well.  We own a 28.75% working interest in the well, which is proposed to have a 5,068 foot horizontal lateral targeted in the Niobrara formation.  Drilling of the well commenced on March 24, 2012.

In March 2012, we closed on the acquisition of mineral leases covering approximately 17,000 gross acres (8,875 net) in Weld, Morgan and Larimer Counties.  Cost of the acreage was $2.7 million payable in the form of $2,200,000 in cash and 155,770 shares of common stock.  Initial exploration activities on the prospect will focus on the potential for horizontal drilling in the Niobrara and Greenhorn formations.

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 $37.4 million after deduction of discounts, 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.

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 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 3.25% annually or the bank’s prime rate, and matures on November 30, 2014.

We used a partial drawdown from the revolving line of credit facility to repay all outstanding amounts under our related party note payable.

We released the entire valuation allowance of $4,911,000 and recorded a net deferred tax asset of $3,241,000 for the six months ended February 29, 2012.  The effective tax rate for the period differs from the statutory federal income tax rate because of the inclusion of state income taxes and the change in the valuation allowance.

For reporting periods prior to February 29, 2012, 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.  Effective February 29, 2012, management concluded that positive indicators outweighed negative indicators, and that it was appropriate to release the valuation allowance against the net deferred tax asset, primarily for the three following reasons.  First, all of the net losses for the two prior fiscal years can be attributed to a single discrete item.  The discrete item was the fair value accounting treatment of the components of the 8% convertible promissory notes issued in 2010, which created non-cash expenses for accretion of debt discount, amortization of issuance costs, and change in fair value of derivative liability.  As all of the convertible notes were converted prior to March 31, 2011, those expenses will not recur, and it is appropriate to exclude them from a consideration of future profitability.  Second, the Company has reported three consecutive quarters of net income and six consecutive quarters of operating income.  Third, the Company completed a debt financing arrangement and an equity financing arrangement that allow it to continue with its operating plan.  Accordingly, the Company believes that it is appropriate to release the valuation allowance related to the deferred tax asset created by the net operating loss carryover.

20
 
 

 
RESULTS OF OPERATIONS

For the three months ended February 29, 2012, compared to the three months ended February 28, 2011

For the three months ended February 29, 2012, we reported net income of $6,118,805 compared with a net loss of ($11,738,360) during the three months ended February 28, 2011.  Earnings per basic and diluted share were $0.13 and $0.12 for the three months ended February 29, 2012, compared to a loss of ($0.55) per basic and diluted share for the three months ended February 28, 2011.  The comparison between the two years was primarily influenced by a) increasing revenues and expenses associated with the increased number of producing wells, and b) by the cessation of interest and other expenses related to the convertible promissory notes that were converted into equity subsequent to February 28, 2011, and c) provision for income tax benefit.

As of February 29, 2012 we had 157 producing wells, a comparative increase of 101 wells, which consists of 64 wells added through acquisitions and 37 wells completed since February 28, 2011.

Oil and Gas Production and Revenues – For the three months ended February 29, 2012, we recorded total oil and gas revenues of $6,218,975 compared to $2,033,687 for the three months ended February 28, 2011, an increase of $4,185,288 or 206%.  Our growth in revenue was the result of an increase in our production volume of 186% over the comparative period, and an increase in our average selling price per BOE of 7%.  For both of the comparative quarters, our gas / oil ratio (“GOR”) was 44/56.

Our revenues are sensitive to changes in commodity prices.  Subsequent to February 29, 2012, the posted price for natural gas sold in the United States continued to decline.  As of April 5, 2012, the price for natural gas was quoted at $2.11 per mcf.  While our balanced production mix of oil and gas and the high liquid content of our gas help to mitigate the negative effect of downward gas prices, the downward pressure from declining natural gas commodity prices could have a negative effect on revenues reported for future quarters.

Key production information is summarized in the following table:

   
Three Months Ended
       
   
February 29,
2012
   
February 28,
2011
   
Change
 
Production:
                 
  Oil (Bbls)
    55,823       19,511     186.11%  
  Gas (Mcf)
    260,627       91,333     185.36%  
  BOE (Bbls)
    99,261       34,733     185.78%  
                       
Revenues:
                     
  Oil
  $ 5,153,870     $ 1,631,905     215.82%  
  Gas
    1,065,105       401,782     165.10%  
    Total
  $ 6,218,975     $ 2,033,687     205.80%  
                       
Average sales price:
                     
  Oil (Bbls)
  $ 92.33     $ 83.64     10.38%  
  Gas (Mcf)
  $ 4.09     $ 4.40     (7.10)%  
  BOE (Bbls)
  $ 62.65     $ 58.55     7.00%  
 

21
 
 

 
“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 29, 2012 was 99,261 BOE, or 1,091 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
 
   
February 29,
2012
   
February 28,
2011
 
Severance and ad valorem taxes
  $ 563,972     $ 205,009  
Work-over
    -       -  
Production costs
    270,216       47,024  
Other
    20,226       8,447  
    Total production expenses
  $ 854,414     $ 260,480  
                 
Per BOE:
               
  Severance and ad valorem taxes
  $ 5.68     $ 5.90  
  Work-over
    -       -  
  Production costs
    2.72       1.35  
  Other
    0.21       0.24  
     Total per BOE
  $ 8.61     $ 7.50  

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.  During the comparative periods presented above, we experienced an increase in production cost per BOE because of additional service and maintenance work on some of our older wells that we have undertaken to increase BOE production.  Taxes make up the largest component of lease operating expenses 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 February 29, 2012 and 10% for the three months ended February 29, 2011.

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

   
Three Months Ended
 
   
February 29,
2012
   
February 28,
2011
 
DDA – oil and gas properties
  $ 1,513,071     $ 627,517  
DDA – other assets
    19,908       11,499  
Accretion of asset retirement obligations
    19,258       8,189  
        Total DDA
  $ 1,552,237     $ 647,205  
                 
DDA – oil and gas properties per BOE
  $ 15.24     $ 18.07  
 

22
 
 

 
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 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.  For the three months ended February 28, 2011, production volumes of 34,733 BOE and estimated net proved reserves of 1,395,295 BOE were the basis of the depletion rate calculation.  Depletion expense per BOE decreased approximately 16%, primarily because of 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. Another factor that contributed to the decrease in per unit costs was the significant increase in the reserve base over the past year.

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

   
Three Months Ended ,
 
   
February 29,
2012
   
February 28,
2011
 
Cash based compensation
  $ 557,457     $ 228,265  
Share based compensation
    100,842       25,486  
Professional fees
    186,993       125,567  
Insurance
    38,616       18,505  
Other general and administrative
    139,006       104,841  
Capitalized general and administrative
    (85,885 )     (43,228 )
    Totals
  $ 937,029     $ 459,436  
                 
Cash based compensation includes payments to employees.  The increase of $329,192 from 2011 to 2012 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.  We recognized stock option expense of $100,842 and $25,486 for the three months ended February 29, 2012 and February 28, 2011, 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.
 

23
 
 

 
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 2011 to 2012 reflects our increasing activities to acquire leases and develop the properties.

Other Income (Expense) – Our other income for the three months ended February 29, 2012 was $2,510, consisting solely of interest income.  For the three months ended February 28, 2011, we reported several significant items of expense in addition to interest income of $15,430.  All of the other expenses in 2011 were related to our convertible promissory notes, including net interest expense of $258,721, accretion of debt discount of $1,481,079, amortization of debt issuance costs of $995,150, and a change in the fair value of the derivative conversion liability of $9,926,158.  Subsequent to February 28, 2011, noteholders converted their holdings into equity, and expenses related to the promissory notes ceased

Income Taxes –We released the entire valuation allowance of $4,911,000 and recorded a net deferred tax asset of $3,241,000 for the three months ended February 29, 2012.  The effective tax rate for the period differs from the statutory federal income tax rate because of the inclusion of state income taxes and the change in the valuation allowance.

For the six months ended February 29, 2012, compared to the six months ended February 28, 2011

For the six months ended February 29, 2012, we reported net income of $7,745,881 compared with a net loss of ($12,898,363) during the six months ended February 28, 2011.  Earnings per basic and diluted share were $0.19 and $0.18, respectively, for the six months ended February 29, 2012, compared to a loss of ($0.73) per basic and diluted share for the six months ended February 28, 2011.  The comparison between the two years was primarily influenced by a) increasing revenues and expenses associated with the increased number of producing wells, and b) by the cessation of interest and other expenses related to the convertible promissory notes that were converted into equity subsequent to February 28, 2011, and c) provision for income tax benefit.

Oil and Gas Production and Revenues – For the six months ended February 29, 2012, we recorded total oil and gas revenues of $10,697,839 compared to $3,477,282 for the six months ended February 28, 2011, an increase of $7,220,557 or 208%.  Our growth in revenue was the result of an increase in our production volume of 181% over the comparative period, and an increase in our average selling price per BOE of 10%.  For the six months ended February 29, 2012, our gas / oil ratio (“GOR”) was 46/54.  During the comparable prior period, our GOR was 45/55.

Our revenues are sensitive to changes in commodity prices.  Subsequent to February 29, 2012, the posted price for natural gas sold in the United States continued to decline.  As of April 5, 2012, the price for natural gas was quoted at $2.11 per mcf.  While our balanced production mix of oil and gas and the high liquid content of our gas help to mitigate the negative effect of downward gas prices, the downward pressure from declining natural gas commodity prices could have a negative effect on revenues reported for future quarters.

Key production information is summarized in the following table:

   
Six Months Ended
       
   
February 29,
2012
   
February 28,
2011
   
Change
 
Production:
                 
  Oil (Bbls)
    97,227       35,450       174.27%  
  Gas (Mcf)
    504,208       174,639       188.71%  
  BOE (Bbls)
    181,262       64,557       180.78%  
                         
Revenues:
                       
  Oil
  $ 8,331,939     $ 2,785,683       199.10%  
  Gas
    2,365,900       691,599       242.09%  
    Total
  $ 10,697,839     $ 3,477,282       207.65%  
                         
Average sales price:
                       
  Oil (Bbls)
  $ 85.70     $ 78.58       9.05%  
  Gas (Mcf)
  $ 4.69     $ 3.96       18.49%  
  BOE (Bbls)
  $ 59.02     $ 53.86       9.57%  
 

24
 
 

 
“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 six months ended February 29, 2012 was 181,262 BOE, or 996 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:

   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
 
Severance and ad valorem taxes
  $ 968,983     $ 345,807  
Work-over
    40,862       -  
Production costs
    483,012       101,625  
Other
    67,877       15,723  
    Total production expenses
  $ 1,560,734     $ 463,155  
                 
Per BOE:
               
  Severance and ad valorem taxes
  $ 5.35     $ 5.36  
  Work-over
    0.23       -  
  Production costs
    2.66       1.57  
  Other
    0.37       0.24  
     Total per BOE
  $ 8.61     $ 7.17  

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.  During the comparative periods presented above, we experienced an increase in production cost per BOE because of additional service and maintenance work on some of our older wells that we have undertaken to increase BOE production.  Taxes make up the largest component of lease operating expenses 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 six months ended February 29, 2012 and 10% for the six months ended February 29, 2011.

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

   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
 
DDA – oil and gas properties
  $ 2,689,582     $ 1,195,555  
DDA – other assets
    39,600       21,738  
Accretion of asset retirement obligations
    36,897       14,893  
        Total DDA
  $ 2,766,079     $ 1,232,186  
                 
DDA – oil and gas properties per BOE
  $ 14.84     $ 18.52  
 

25
 
 

 
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 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.  For the six months ended February 28, 2011, production volumes of 64,557 BOE and estimated net proved reserves of 1,425,119 BOE were the basis of the depletion rate calculation.  Depletion expense per BOE decreased approximately 20%, 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:

   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
 
Cash based compensation
  $ 879,338     $ 455,890  
Share based compensation
    215,109       260,971  
Professional fees
    517,700       287,674  
Insurance
    70,229       32,826  
Other general and administrative
    362,733       155,276  
Capitalized general and administrative
    (168,271 )     (107,947 )
    Totals
  $ 1,876,838     $ 1,084,690  
                 
Cash based compensation includes payments to employees.  The increase of $440,448 from 2011 to 2012 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.  We recognized stock option expense of $198,109 and $50,971 for the six months ended February 29, 2012 and February 28, 2011, respectively.  The amount of expense recorded for common stock grants is calculated based upon the closing market value of the shares.  We recognized expenses for common stock grants of $17,000 and $210,000 for the six months ended February 29, 2012 and February 28, 2011, 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 $109,000 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 2011 to 2012 reflects our increasing activities to acquire leases and develop the properties.
 

26
 
 

 
Other Income (Expense) – Our other income for the six months ended February 29, 2012 was $10,693, consisting solely of interest income.  For the six months ended February 28, 2011, we reported several significant items of expense in addition to interest income of $15,891.  All of the other expenses in 2011 were related to our convertible promissory notes, including net interest expense of $569,455, accretion of debt discount of $1,902,002, amortization of debt issuance costs of $1,165,271, and a change in the fair value of the derivative conversion liability of $10,315,421.  Subsequent to February 28, 2011, noteholders converted their holdings into equity, and expenses related to the promissory notes ceased.

Income Taxes – We released the entire valuation allowance of $4,911,000 and recorded a net deferred tax asset of $3,241,000 for the six months ended February 29, 2012.  The effective tax rate for the period differs from the statutory federal income tax rate because of the inclusion of state income taxes and the change in the valuation allowance.

LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the six months ended February 29, 2012, and February 28, 2011, are shown below:

   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
 
             
Cash provided by operations
  $ 9,631,124     $ 3,668,946  
Acquisition of oil and gas properties, and equipment
    (17,882,999 )     (5,946,766 )
Net proceeds from sale of stock
    37,421,783       16,690,721  
Net borrowings
    192,110       --  
  Net increase in cash
  $ 29,362,018     $ 14,412,901  

Net cash provided by operating activities was $9,631,124 and $3,668,946 for the six months ended February 29, 2012 and February 28, 2011, respectively.  The change reflects significant growth in operating contribution from the additional wells that were producing during 2012 as compared to 2011.  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 $7,977,072 and $1,977,488 for the six months ended February 29, 2012 and February 28, 2011, 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 $21,574,469 and $5,092,014 for the six months ended February 29, 2012 and February 28, 2011, respectively, compared to cash payments of $17,882,999 and $5,946,766, respectively.  A reconciliation of the differences is summarized in the following table:

 
   
Six Months Ended
 
   
February 29,
2012
   
February 28,
2011
 
             
Cash payments
  $ 17,882,999     $ 5,946,766  
Non-cash payments
    694,145       --  
Accrued costs, beginning of period
    (4,967,369 )     (3,446,439 )
Accrued costs, end of period
    7,829,177       2,515,024  
Asset retirement obligations
    135,517       76,663  
  Capital expenditures
  $ 21,574,469     $ 5,092,014  
                 
 
 
27
 
 

 
During the six months ended February 29, 2012, we engaged in drilling or completion activities on 31 wells which we operate.  Eighteen of the wells reached productive status during the period.  Completion activities were underway on 13 wells, most of which are expected to reach productive status during our third fiscal quarter.

Most of our capital expenditures for the six months ended February 29, 2012, represent drilling and completion cost on wells in progress.  In addition, we incurred costs of approximately $2.9 million on the acquisition of mineral leases.

On December 30, 2011, we completed the sale of 14.6 million shares of common stock in a public offering of common stock priced at $2.75 per share.  Net proceeds to us were $37.4 million, after deductions for the underwriting discounts, commissions and expenses of the offering.

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.  Outstanding borrowings accrue interest at the greater of 3.25% annually or the bank’s prime rate, which was also 3.25% at February 29, 2012.  The maturity date for the arrangement is 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 February 29, 2012, the borrowing base calculation was not restrictive.  We utilized the new arrangement to retire amounts outstanding under our related party note payable.

We believe that the proceeds from our equity offering, 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 $45 million for our drilling program.  As an operator we plan to spend approximately $34 million to drill 52 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 $17 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 and Quarterly Reports on Form 10-Q, we elected to participate in a second horizontal well with another operator which commenced drilling in March 2012.  Our estimated costs to drill, and if warranted, complete this well are $1.2 million.
 

28
 
 

 
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.
  
Adjusted EBITDA. We define adjusted EBITDA as net income (loss) plus net interest expense, 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 metric used by some industry analysts to provide a comparison 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.
 
   
Six Months Ended
 
 
 
February 29,
2012
   
February 28,
2011
 
Adjusted cash flow from operations:
 
 
   
 
 
Adjusted cash flow from operations
  $ 7,977,072     $ 1,977,488  
Changes in assets and liabilities
    1,654,052       1,691,458  
Net cash provided by operating activities
  $ 9,631,124     $ 3,668,946  
                 
Adjusted EBITDA:
               
Adjusted EBITDA
  $ 7,260,267     $ 1,929,437  
Interest expense and related items, net
    10,693       (3,280,193 )
Change in fair value of derivative conversion liability
    --       (10,315,421 )
Provision for income tax benefit
    3,241,000       --  
Depreciation, depletion and amortization
    (2,766,079 )     (1,232,186 )
Net income (loss)
  $ 7,745,881     $ (12,898,363 )
 

29
 
 

 
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

Except for our Income Tax accounting policy, 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.  We updated our Income Tax accounting policy to reflect our conclusion that it was more likely than not that we would be able to utilize the future tax benefits of our net operating loss carryover.  The updated Income Tax accounting policy is:

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.
 

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The realization of the deferred tax assets related to the net operating loss carry-forwards is dependent upon the Company’s ability to generate future taxable income.  The ability of the Company to utilize net operating loss carry-forwards may be further limited by other provisions of the Internal Revenue Code.  For reporting periods prior to February 29, 2012, 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.  Effective February 29, 2012, management concluded that positive indicators outweighed negative indicators, and that it was appropriate to release the valuation allowance.

Management considers many factors in its evaluation of deferred tax assets, including the following sources of taxable income that may be available under the tax law to realize a portion or all of a tax benefit for deductible timing differences and carry forwards:

--
Future reversals of existing taxable temporary differences,
--
Taxable income in prior carry back years, if permitted,
--
Tax planning strategies,
--
Future taxable income exclusive of reversing temporary differences and carry forwards.

After evaluating positive and negative evidence available as of the reporting date, including recent earnings history, the Company concluded that it was more likely than not that it will utilize its net operating loss carry forwards.

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 February 29, 2012.  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.

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.
 

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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 29, 2012, 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 February 29, 2012.  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 February 29, 2012, 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 29, 2012, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.



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PART II

Item 6.     Exhibits

a.  Exhibits

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

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

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

 
101
Interactive Data Files



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

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