10-Q 1 syrg_10q-113012.htm FORM 10-Q FOR THE PERIOD ENDED 11/30/2012 syrg_10q-113012.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)

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

For the quarterly period ended November 30, 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: 54,908,851 shares outstanding as of January 5, 2013.

 
 

 
 
SYNERGY RESOURCES CORPORATION

Index



 
2

 
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
(in thousands, except share data)
 
  ASSETS  
November 30,
 2012
   
August 31,
 2012
 
   
(unaudited)
       
Current assets:
           
Cash and cash equivalents
  $ 12,465     $ 19,284  
Accounts receivable:
               
Oil and gas sales
    5,224       3,606  
Joint interest billing
    3,735       3,268  
Inventory
    178       178  
Other current assets
    219       131  
Total current assets
    21,821       26,467  
                 
Property and equipment
               
Evaluated oil and gas properties, net
    70,173       59,936  
Unevaluated oil and gas properties
    35,779       32,484  
Other property and equipment, net
    262       282  
Property and equipment, net
    106,214       92,702  
                 
Deferred tax asset, net
    -       332  
Other assets
    2,707       1,230  
                 
Total assets
  $ 130,742     $ 120,731  
                 
  LIABILITIES AND SHAREHOLDERS' EQUITY                
                 
Current liabilities:
               
Trade accounts payable
  $ 426     $ 1,499  
Well costs payable
    8,522       5,733  
Revenue payable
    4,981       4,160  
Production taxes payable
    4,582       3,805  
Other accrued expenses
    248       395  
Total current liabilities
    18,759       15,592  
                 
Revolving credit facility
    5,486       3,000  
Deferred tax liability, net
    983       -  
Asset retirement obligations
    1,171       1,027  
Total liabilities
    26,399       19,619  
Commitments and contingencies (See Note 10)
               
                 
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:
         
51,740,310 and 51,409,340 shares issued and outstanding,
         
respectively
    52       51  
Additional paid-in capital
    124,868       123,876  
Accumulated deficit
    (20,577 )     (22,815 )
Total shareholders' equity
    104,343       101,112  
                 
Total liabilities and shareholders' equity
  $ 130,742     $ 120,731  
 
The accompanying notes are an integral part of these financial statements.
 
 
3

 
 
SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
for the three months ended November 30, 2012 and 2011
(unaudited; in thousands, except share and per share data)

   
2012
   
2011
 
             
Oil and gas revenues
  $ 8,314     $ 4,479  
                 
Expenses
               
Lease operating expenses
    523       301  
Production taxes
    814       405  
Depreciation, depletion, and amortization
    2,320       1,214  
General and administrative
    1,111       940  
Total expenses
    4,768       2,860  
                 
Operating income
    3,546       1,619  
                 
Other income
               
Interest Income
    7       8  
                 
Income before income taxes
    3,553       1,627  
                 
Deferred income tax provision
    (1,315 )     -  
Net income
  $ 2,238     $ 1,627  
                 
Net income per common share:
               
Basic
  $ 0.04     $ 0.05  
Diluted
  $ 0.04     $ 0.04  
                 
Weighted average shares outstanding:
               
Basic
    51,661,704       36,098,212  
Diluted
    53,616,182       37,845,212  

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

SYNERGY RESOURCES CORPORATION
 STATEMENTS OF CASH FLOWS
 for the three months ended November 30, 2012 and 2011
(unaudited, in thousands)

   
2012
   
2011
 
Cash flows from operating activities:
           
Net income
  $ 2,238     $ 1,627  
Adjustments to reconcile net income to net
               
cash provided by operating activities:
               
Depreciation, depletion, and amortization
    2,320       1,214  
Provision for deferred taxes
    1,315       -  
Stock-based compensation
    168       97  
Changes in operating assets and liabilities:
               
Accounts receivable
               
Oil and gas sales
    (1,618 )     651  
Joint interest billing
    (467 )     (49 )
Inventory
    -       67  
Accounts payable
               
Trade
    (1,073 )     249  
Revenue
    821       316  
Production taxes
    777       558  
Accrued expenses
    (147 )     (19 )
Other
    (1,565 )     (124 )
Total Adjustments
    531       2,960  
Net cash provided by operating activities
    2,769       4,587  
                 
Cash flows from investing activities:
               
Acquisition of property and equipment
    (12,220 )     (7,071 )
Net cash used in investing activities
    (12,220 )     (7,071 )
                 
Cash flows from financing activities:
               
Proceeds from exercise of warrants
    146       -  
Proceeds from revolving credit facility
    2,486       5,392  
Payment of related party note payable
    -       (5,200 )
Net cash provided by financing activities
    2,632       192  
                 
Net decrease in cash and cash equivalents
    (6,819 )     (2,292 )
                 
Cash and cash equivalents at beginning of period
    19,284       9,491  
                 
Cash and cash equivalents at end of period
  $ 12,465     $ 7,199  
                 
Supplemental Cash Flow Information (See Note 11)
         

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



SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
November 30, 2012
(unaudited)


1.  
Organization and Summary of Significant Accounting Policies
 
Organization:    Synergy Resources Corporation ("the Company”) is engaged in oil and gas acquisition, exploration, development and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado.
 
Basis of Presentation:    The Company has adopted August 31st as the end of its fiscal year.  The Company does not utilize any special purpose entities.
 
At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.
 
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).
 
Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading, and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, 2012.
 
In management’s opinion, the unaudited financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company’s financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.
 
Reclassifications:    Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation.  The reclassifications had no effect on net income, working capital or equity previously reported.
 
Use of Estimates:     The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain.  Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary.  Actual results could differ from these estimates.
 
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

 
 
 
Inventory:    Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market.
 
Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.  Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
 
Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves.  For depletion purposes, the volume of petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.  Investments in unevaluated properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
 
Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is an impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the book value of oil and gas properties.  The capitalized costs of proved and unproved oil and gas properties, net of accumulated depreciation, depletion, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unevaluated properties not being amortized, plus the lower of cost or estimated fair value of unevaluated properties being amortized.  Prices are held constant for the productive life of each well.  Net cash flows are discounted at 10%.  If net capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization.  The calculation of future net cash flows assumes continuation of current economic conditions.  Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount.  No provision for impairment was required for either the three months ended November 30, 2012 or 2011.
 
The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12 month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period, unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials.
 
Oil and Gas Reserves:    Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
 
 
7

 
 
 
The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of the Company’s oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.
 
Capitalized Overhead:    A portion of the Company’s overhead expenses are directly attributable to acquisition and development activities.  Under the full cost method of accounting, these expenses in the amounts showing in the table below were capitalized in the full cost pool:

   
Three months ended November 30,
(in thousands)
 
   
2012
   
2011
 
Capitalized Overhead
  $ 103     $ 82  
 
Well Costs Payable:  The cost of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings (“JIB”).  For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the Authorization for Expenditure (“AFE”).
 
Other Property and Equipment:  Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market.  Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years.
 
Asset Retirement Obligations:    The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk free interest rate.  Estimates are periodically reviewed and adjusted to reflect changes.
 
The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed or an asset is placed in service.  When the ARO is initially recorded, the Company capitalizes the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset.  ARCs related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the net capitalized cost decreases over the useful life of the asset, as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation for valuing the full cost pool
 
Oil and Gas Sales:  The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties.  Revenues from production  on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and lease operating costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser.  Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.


 
8

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

   
Three Months Ended November 30,
 
Major Customers
 
2012
   
2011
 
Company A
  68%     78%  
Company B
  22%     19%  

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

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

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

Major Customers
 
As of November 30, 2012
 
As of August 31, 2012
Company A
 
32%
 
35%
Company B
 
28%
 
30%

Stock-Based Compensation:  The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date, calculated using the Black-Scholes-Merton option pricing model.  The expense is recognized over the vesting period of the respective grants.  See Note 9 for additional information.

Earnings Per Share Amounts:    Basic earnings per share includes no dilution and is computed by dividing net income or loss by the weighted-average number of shares outstanding during the period.  Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company.  The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method.  Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.  The following table sets forth the share calculation of diluted earnings per share:
 
   
Three months ended November 30,
 
   
2012
   
2011
 
Weighted-average shares outstanding-basic
    51,661,704       36,098,212  
Potentially dilutive common shares from:
               
Stock Options
    1,533,812       1,364,493  
Warrants
    420,666       382,507  
Weighted-average shares outstanding - diluted
    53,616,182       37,845,212  


 
9

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

   
As of November 30,
 
   
2012
   
2011
 
Warrants
    14,098,000       14,931,067  
Employee stock options
    2,875,000       4,745,000  
Total
    16,973,000       19,676,067  


Income Taxes:    Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities due to a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions were identified as of any date on or before November 30, 2012.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of November 30, 2012, the Company has not recognized any interest or penalties related to uncertain tax benefits.

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

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

As discussed in Note 6, the Company incurred asset retirement obligations during the periods presented, the value of which was determined using unobservable pricing inputs (or Level 3 inputs).  The Company uses the income valuation technique to estimate the fair value of the obligation using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement.

The Company did not have any hedging activities in any of the periods presented.  Hedging strategies, or absence of hedging, may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events.  Please see Note 12 regarding the hedging agreement signed subsequent to November 30, 2012.



 
10

 

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

2.  
Property and Equipment

Capitalized costs of property and equipment at November 30, 2012, and August 31, 2012, consisted of the following:

   
As of
November 30, 2012
(in thousands)
   
As of
August 31, 2012
(in thousands)
 
Oil and gas properties, full cost method:
           
Unevaluated costs, not subject to amortization:
           
Lease acquisition and other costs
  $ 28,944     $ 27,070  
Wells in progress
    6,835       5,414  
Subtotal, unevaluated costs
    35,779       32,484  
                 
Evaluated costs:
               
Producing and non-producing
    82,166       69,667  
Total capitalized costs
    117,945       102,151  
Less, accumulated depletion
    (11,993 )     (9,731 )
Oil and gas properties, net
    105,952       92,420  
                 
Other property and equipment:
               
Vehicles
    164       164  
Leasehold improvements
    71       71  
Office equipment
    164       157  
Land
    44       44  
Less, accumulated depreciation
    (181 )     (154 )
Other property and equipment, net
    262       282  
                 
Total property and equipment, net
  $ 106,214       92,702  
                 
Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value. The reviews as of November 30, 2012 and 2011, indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment. The full cost ceiling test, explained in Note 1, and, as performed as of November 30, 2012 and 2011, similarly revealed no impairment of oil and gas assets.

 
11

 
 
 
3.  
Interest Expense
 
The components of interest expense recorded for the three months ended November 30, 2012, and 2011 consisted of:
 
   
Three Months Ended November 30,
(in thousands)
 
   
2012
   
2011
 
Revolving bank credit facility at a variable rate
  $ 30     $ --  
Related party note payable at 5.25%
    --       68  
Amortization of debt issuance costs
    20       --  
Less, interest capitalized
    (50 )     (68 )
Interest expense, net
  $ --     $ --  

4.  
Depletion, depreciation and amortization
 
Depletion, depreciation and amortization for the three months ended November 30, 2012 and 2011, consisted of the following:
 
   
Three Months ended
November 30,
(in thousands)
 
   
2012
   
2011
 
Depletion
  $ 2,262     $ 1,176  
Depreciation
    27       20  
Amortization
    31       18  
    $ 2,320     $ 1,214  
Depletion expense per BOE
  $ 15.37     $ 14.76  
 
5.  
Revolving Credit Facility

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

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate.  The interest rate pricing grid includes use of either the Prime Rate or the London Interbank Offered Rate (LIBOR), at the Company’s option.    The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain customary financial ratios.  Certain of the Company’s assets, including substantially all developed properties, have been designated as collateral under the arrangement.  The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves and limited borrowings to $47 million at November 30, 2012.  The borrowing base limitation will be redetermined on a semi-annual basis.     The credit facility expires on November 28, 2016.

Terms of the LOC require the Company to maintain hedge contracts covering future production quantities that are included in the borrowing base.  Subsequent to an initial transition period, the Company will be required to hedge a minimum of 45% of scheduled production for a rolling 24 months.  The Company will not be allowed to hedge more than 80% of scheduled production.  Subsequent to November 30, 2012, the Company commenced its hedging position.
 
 
 
12

 
 
 
As of November 30, 2012, the interest rate on the amounts borrowed was 2.7%, representing LIBOR plus 2.5%.  The interest rate pricing grid includes pricing differentials based upon LOC utilization, and can be calculated using Prime Rate plus a margin of 0% to 1%, or LIBOR plus a margin of 2.5% to 3.25%.

6. 
Asset Retirement Obligations
 
Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon wells, and restore sites to their original uses.  The estimated present value of such obligations are determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.
 
The following table summarizes the change in asset retirement obligations for the three months ended November 30, 2012:
 
(in thousands)
     
Asset retirement obligations, August 31, 2012
  $ 1,027  
   Liabilities incurred
    115  
   Liabilities settled
    --  
   Accretion
    29  
   Revisions in estimated liabilities
    --  
Asset retirement obligations, November 30, 2012
  $ 1,171  

7.  
Related Party Transaction
 
The Company leases office space and an equipment yard from HS Land & Cattle, LLC (“HSLC”) in Platteville, Colorado for $10,000 per month.  The twelve month lease arrangement with HSLC is renewable annually on July 1.   Under the lease arrangement, the Company paid HSLC $30,000 during each of the three months ended November 30, 2012 and 2011.  HSLC is controlled by two of the Company’s executive officers.

8.  
Shareholders’ Equity
 
The Company’s classes of stock are summarized as follows:

   
As November 30,
2012
   
As August 31,
2012
 
Preferred stock, shares authorized
    10,000,000       10,000,000  
Preferred stock, par value
  $ 0.01     $ 0.01  
Preferred stock, shares issued and outstanding
    -       -  
Common stock, shares authorized
    100,000,000       100,000,000  
Common stock, par value
  $ 0.001     $ 0.001  
Common stock, shares issued and outstanding
    51,740,310       51,409,340  

Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors.  Since inception, the Company has not issued any preferred shares.

 
13

 
 
 
Common stock issued for acquisition of mineral interests

During the three months ended November 30, 2012 , the Company issued common shares in exchange for mineral property interests.  The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.
 
   
For the three
months ended
November 30,
2012
 
Number of common shares issued for assets
  222,369  
Average price per common share
  $3.04  
Aggregate value of shares issued (in thousands)
  $677  

The following table summarizes information about the Company’s issued and outstanding common stock warrants as of November 30, 2012:
 
Exercise Price
 
Description
 
Number of Shares
   
Remaining Contractual Life (in years)
   
Exercise Price times Number of Shares
 
$1.60  
Series D
    715,211       2.05     $ 1,144,338  
$2.69  
Investor Relation Warrants
    100,000       3.45       269,000  
$6.00  
Series A
    4,098,000       0.30       24,588,000  
$6.00  
Series C
    9,000,000       2.30       54,000,000  
$10.00  
Series B
    1,000,000       0.30       10,000,000  
          14,913,211       1.61     $ 90,001,338  
 
The following table summarizes activity for common stock warrants for the three month period ended November 30, 2012:
 
   
Number of
Warrants
 
Weighted Average
Exercise Price
             
Outstanding, August 31, 2012
    15,031,067     $ 6.02  
Granted
    --       --  
Exercised
    (117,856 )*     1.72  *
Outstanding, November 30, 2012
    14,913,211     $ 6.04  
* Warrants exercised include 33,980 warrants exercised on a cashless basis, which reduced the net cash proceeds to the Company to $1.24 per warrant.
 

 

 
14

 

9.  
Stock-Based Compensation

In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity based compensation in the form of stock options, restricted stock grants, and warrants.  The Company records an expense related to equity compensation by pro-rating the estimated fair value of each grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”).  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model.

The amount of stock based compensation expense recorded for each of the three months ended November 30, 2012 and 2011 is shown in the table below:


   
Three Months Ended November 30,
(in thousands)
 
   
2012
   
2011
 
Stock options
  $ 125     $ 97  
Restricted stock grants
    12       -  
Investor relations warrants
    31       -  
Total
  $ 168     $ 97  

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

During the respective three months, the Company granted the following employee stock options:

   
Three months ended November 30
 
   
2012
   
2011
 
Number of options to purchase common shares
    230,000       100,000  
Weighted average exercise price
  $ 3.90     $ 2.80  
Term
 
10 years
   
10 years
 
Vesting Period
 
5 years
   
4 years
 
Fair Value (in thousands)
  $ 621     $ 179  

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

   
Three months ended November 30
 
   
2012
   
2011
 
Expected Term
 
6.4 years
   
6.5 years
 
Expected Volatility
    79.9%       69.43%  
Risk free rate
    1.01%       1.12%  
Expected dividend yield
    0.00%       0.00%  
Forfeiture rate
    0.00%       0.00%  


 
15

 
 
 
The following table summarizes activity for stock options for the three months ended November 30, 2012:

   
Number
of Shares
   
Weighted Average Exercise Price
 
Outstanding, August 31, 2012
    4,915,000     $5.09  
Granted
    230,000     $3.90  
Exercised
    -     -  
Outstanding, November 30, 2012
    5,145,000     $5.03  

The following table summarizes information about issued and outstanding stock options as of November 30, 2012:

   
Outstanding Options
   
Vested Options
 
Number of shares
    5,145,000       4,300,500  
Weighted average remaining contractual life
   
2.3 years
     
1.0 years
 
Weighted average exercise price
    $5.03       $5.33  
Aggregate intrinsic value (in thousands)
    $6,409       $6,009  

The estimated unrecognized compensation cost from unvested stock options as of November 30, 2012, which will be recognized ratably over the remaining vesting phase, is as follows:

   
Unvested Options at November 30, 2012
 
Unrecognized compensation expense (in thousands)
  $1,698  
Remaining vesting phase
 
3.7 years
 

10.  
Commitments and Contingencies

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company will own a working interest.  The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs.  As of November 30, 2012, the Company had agreed to participate in one future horizontal well with a working interest of approximately 3% and expects that its share of future costs will be approximately $146,000.  In addition, the Company has been notified by other operators of their intent to drill three horizontal wells in which Synergy will own an interest.  As of December 31, 2012, the Company had not yet committed to participate in the future wells and had not determined its potential working interest or cost obligation.
 

 
 
16

 
 
11.  
Supplemental Schedule of Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the financial statements for the three months ended November 30, 2012 and 2011:

   
Three Months Ended
November 30,
(in thousands)
 
   
2012
   
2011
 
Supplemental cash flow information:
           
    Interest paid
  $ 30     $ 142  
    Income taxes paid
    --       --  
                 
Non-cash investing and financing activities:
               
Well costs payable
  $ 8,522     $ 5,733  
Assets acquired in exchange for common stock
    677       --  
Asset retirement costs and obligations
    115       52  

12.  
Subsequent Events

On December 5, 2012, the Company completed its acquisition of oil and gas assets from Orr Energy, LLC.  The assets include interests in 36 producing oil and gas wells and approximately 3,933 gross (3,196 net) mineral acres.

Results of operations for the Orr Energy assets will be included with the Company’s revenues and expenses commencing on December 5, 2012, and are expected to be accretive immediately.  All of the producing properties are located in the Wattenberg Field and will be integrated with the Company’s existing properties.  Approximately 1,000 undeveloped acres are located in the Denver-Julesburg Basin in an area which is north east of the Wattenberg field and will be evaluated by the Company using seismic data acquired with the assets.

Consideration for the assets included cash of $30 million and 3,128,422 restricted shares of Synergy's common stock for a total purchase price of $42 million, and is subject to adjustment for customary post-closing reconciliations.  The purchase price allocation has not yet been completed and the Company is currently evaluating the acquired assets and estimates of fair value of the assets.

Effective January 1, 2013, the Company entered into a commodity swap for approximately 58,000 barrels of future oil production. The swap covers 3,000 barrels of oil per month during 2013 and 1,840 barrels of oil per month during 2014. Under the terms of the swap, the Company will receive payment from the counterparty of approximately $91.70 per barrel for 2013 and $90.80 per barrel for 2014.  The Company will pay the monthly average price per barrel for West Texas Intermediate (WTI) based on the New York Mercantile Exchange daily settlement price.  Any difference between the swap price and the monthly WTI average settlement price per barrel will be recorded as realized and unrealized commodity gains or losses in the Statement of Operations.

 
17

 

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

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding the financial condition as of November 30, 2012, and the results of operations for the three months ended November 30, 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, 2012.

Overview

Synergy Resources Corporation (“we,” “our,” “us” or “the Company”) is a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin (“D-J Basin”) of Colorado. All of our producing wells are in the Wattenberg Field, which has a history as one of the most prolific production areas in the country.  We are expanding our undeveloped acreage holdings in eastern Colorado and western Nebraska, and may commence development activities in these areas.

Since commencing active operations in September 2008, we have undergone significant growth. As disclosed in the following table, as of December 31, 2012, we have drilled, acquired, or participated in 273 gross oil and gas wells and have successfully completed 250 wells that went into production.

   
Operated
         
Participated
       
Year
 
Drilled
   
Completed
   
Drilled
   
Completed
   
Acquired
 
2009
    -       -       2       2       -  
2010
    36       22       -       -       -  
2011
    20       28       11       11       72  
2012
    51       47       13       5       4  
2013
 1   27       15       1       8       36  
Total
    134       112       27       26       112  

As of November 30, 2012, our estimated proved reserves exceeded 5 million Bbls of oil and 33 Bcf of gas.  We currently hold approximately 235,000 gross acres and 199,000 net acres under lease.

Strategy
 
Our strategy for continued growth includes additional drilling activities, acquisition of existing wells, and recompletion of wells to more rapidly access and/or extend reserves through improved hydraulic stimulation techniques. We attempt to maximize our return on assets by drilling and operating wells in which we have a majority net revenue interest. We attempt to limit our risk by drilling in proven areas. To date, we have not drilled any dry holes.

All wells drilled prior to 2012 were relatively low-risk vertical or directional wells. During 2012 we participated with other operators in six horizontal wells.  Five of the wells had reached productive status by December 31, 2012.  Initial results from the wells have been promising and we plan to expand our horizontal well operations during 2013.  Our capital expenditure budget anticipates participation in ten horizontal wells as a non-operating interest owner.  Furthermore, we plan to drill and operate four horizontal wells for our own account.  Horizontal drilling operations are expected to commence in the spring.

 
18

 
 
Historically, our cash flow from operations was not sufficient to fund our growth plans and we relied on proceeds from the sale of debt and equity securities. Our cash flow from operations is increasing, and we plan to finance an increasing percentage of our growth with internally generated funds. Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain.

Significant Developments

As an operator, we continued our active vertical well drilling program from September 1, 2012 through December 31, 2012.  During that time, we drilled 27 wells and brought 15 wells into productive status.  As of December 31, 2012, we were the operator of 22 wells that were in various stages of completion, all of which are expected to reach productive status during our second fiscal quarter.  We have substantially completed our plans for drilling vertical wells during the 2013 fiscal year, and plan to focus our efforts on horizontal wells during the remaining eight months of the fiscal year.  Our activity on wells in which we participate as a non-operating interest owner included eight wells that reached productive status and one well that was drilled.  One non-operated well was in the completion phase at December 31, 2012.

On December 5, 2012, we completed an acquisition of assets from Orr Energy LLC.  The assets included 36 producing oil and gas wells along with a number of undeveloped leases.  We assumed operational responsibility on 35 of the producing wells.  Purchase consideration included cash of $30 million and 3,128,422 shares of our restricted common stock.  Our preliminary evaluation of the assets indicates that the fair value of the acquisition will approximate $42 million and that revenues and expenses from the assets will be consolidated with our operations commencing on December 5, 2012.

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

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios.  The borrowing arrangement is collateralized by certain of our assets, including producing properties.  Maximum borrowings are subject to reduction based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports.  As of November 30, 2012, the borrowing base calculation limited maximum borrowings to $47 million.  In December, we utilized a portion of the financing available through this arrangement to fund the acquisition of Orr assets.  We expect to use the remaining proceeds to fund our drilling and development expenditures and to provide working capital.

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

We commenced our commodity hedging program beginning January 1, 2013 by hedging approximately 58,000 barrels of oil over the next 24 months of production using a commodity swap with an average price of $91.25.  Our overall hedging strategy includes increasing our hedging position to 175,000 barrels of oil covering 24 months future production by using swaps or costless collar contracts.


 
19

 

RESULTS OF OPERATIONS

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

For the three months ended November 30, 2012, compared to the three months ended November 30, 2011

For the three months ended November 30, 2012, we reported net income of $2.2 million compared to $1.6 million during the three months ended November 30, 2011.  Earnings per diluted share were $0.04 for both the three months ended November 30, 2012 and the three months ended November 30, 2011. The comparison between the two years was primarily influenced by increasing revenues and expenses associated with the increased number of producing wells as well as the effect of deferred income taxes.  As of November 30, 2012 we had 214 gross producing wells (163 wells net), compared to 141 gross producing wells (103 wells net) as of November 30, 2011.

Oil and Gas Production and Revenues – For the three months ended November 30, 2012, we recorded total oil and gas revenues of $8.3 million compared to $4.4 million for the three months ended November 30, 2011, an increase of $3.8 million or 86%.  Our growth in revenue was the result of an increase in our production volume of 89% quarter-over-quarter.  For the quarter, our gas / oil ratio (“GOR”) was 47/53.  During the comparable prior period, our GOR was 52/48.

Key production information is summarized in the following table:

   
Three Months Ended
November 30,
       
   
2012
   
2011
   
Change
 
Production:
                 
  Oil (Bbls)
    80,301       38,277     110%  
  Gas (Mcf)
    423,646       248,486     70%  
  BOE (Bbls)
    150,909       79,691     89%  
                       
Revenues
(in thousands):
                     
  Oil
  $ 6,507     $ 3,178     105%  
  Gas
    1,807       1,301     39%  
    Total
  $ 8,314     $ 4,479     86%  
                       
Average sales price:
                     
  Oil (Bbls)
  $ 81.03     $ 83.03     (2.4%)  
  Gas (Mcf)
  $ 4.27     $ 5.23     (18.3%)  
  BOE (Bbls)
  $ 55.09     $ 56.20     (2.0%)  

 “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.



 
20

 
 
Net oil and gas production for the three months ended November 30, 2012 was 150,909 BOE, or 1,658 BOE per day. For the three months ended November 30, 2011, production averaged 876 BOE per day, a year over year increase of 89%.  As a further comparison, average BOE production was 1,270 per day during the quarter ended August 31, 2012. The significant increase in production from the comparable period in the prior year reflects the additional wells that began production over the past twelve months.

Lease Operating Expenses (“LOE”) and Production Taxes – Direct operating costs of producing oil and natural gas and taxes on production and properties are reported as lease operating expenses as follows:

   
Three Months ended
November 30,
(in thousands)
 
   
2012
   
2011
 
Production costs
  $ 523     $ 213  
Work-Over
    -       46  
Other
    -       42  
    Lifting cost
    523       301  
Severance and ad valorem taxes
    814       405  
    Total LOE
  $ 1,337     $ 706  
                 
 
               
Per BOE:
               
Production costs
  $ 3.47     $ 2.67  
Work-Over
    -       0.58  
Other
    -       0.53  
    Lifting cost
    3.47       3.78  
Severance and ad valorem taxes
    5.40       5.08  
    Total LOE
  $ 8.87     $ 8.86  

Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.  Taxes make up the largest component of production costs and tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes averaged 10% for the three months ended November 30, 2012 and 9% for the three months ended November 30, 2011.
 
On a BOE basis, production costs increased approximately 30% for the quarter ended November 30, 2012 compared to the quarter ended November 30, 2011.  The increase is primarily due to costs incurred to mitigate high line pressure within the Wattenberg field. The Company incurred production costs to rent and install compressors on six pads and installed upgraded valves and other equipment upgrades on some of the Company’s older wells.



Depreciation, Depletion, and Amortization (“DDA”) – DDA expense is summarized in the following table:
 
   
Three Months ended
November 30,
(in thousands)
 
   
2012
   
2011
 
Depletion
  $ 2,262     $ 1,177  
Depreciation
    27       20  
Amortization
    31       17  
        Total DDA
  $ 2,320     $ 1,214  
                 
Depletion per BOE
  $ 15.37     $ 14.76  

The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves.  The capitalized costs of evaluated oil and gas properties are depleted using the units-of-production method based on estimated reserves.  Production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate.  For the three months ended November 30, 2012, production volumes of 150,909 BOE and estimated net proved reserves of 10,509,231 BOE were the basis of the depletion rate calculation.  For the three months ended November 30, 2011, production volumes of 79,691 BOE and estimated net proved reserves of 4,446,565 BOE were the basis of the depletion rate calculation.  Depletion expense per BOE increased approximately 4.1%.

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

   
Three Months ended
November 30,
(in thousands)
 
   
2012
   
2011
 
Cash based compensation
  $ 510     $ 408  
Share based compensation
    168       97  
Professional fees
    382       331  
Insurance
    43       31  
Other general and administrative
    111       155  
Capitalized general and administrative
    (103 )     (82 )
    Totals
  $ 1,111     $ 940  

Cash based compensation includes payments to employees.  The increase of $102,000 from 2011 to 2012 reflects the expansion of our business, including the addition of two employees since the prior period.  Share based compensation includes compensation paid to employees, directors and service providers in the form of either stock options, warrants, or restricted stock grants.  The amount of expense recorded for stock options and warrants is calculated by using the Black-Scholes-Merton option pricing model.  The amount of expense recorded for common stocks grants is calculated based upon the closing market value of the shares.

Our professional fees have increased as we grow our business.  In addition to legal, accounting and auditing fees, this category includes technical consulting services such as petroleum engineering studies.  A portion of the increase can be attributed to increasing costs of compliance with additional regulatory requirements such as those included in the Sarbanes-Oxley and Dodd-Frank laws.

 
22

 
 
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.

Income taxes – We reported income tax expense of $1.3 million for the three months ended November 30, 2012, representing an effective tax rate of 37%.  During the comparable prior year period, there was no reported tax expense, as the tax effects of our net deferred tax assets were fully offset by a valuation allowance.

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

LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the three months ended November 30, 2012, and 2011 are summarized below:

   
Three Months Ended
November 30,
(in thousands)
 
   
2012
   
2011
 
             
Cash provided by operations
  $ 2,769     $ 4,587  
Acquisition of oil and gas properties and equipment
    (12,220 )     (7,071 )
Cash provided by financing activities
    2,632       192  
  Net decrease in cash and cash equivalents
  $ (6,819 )   $ (2,292 )

Net cash provided by operating activities was $2.7 million and $4.5 million for the three months ended November 30, 2012 and 2011, respectively.  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 $6.0 million and $2.9 million for the three months ended November 30, 2012 and 2011, respectively.  The improvement of $3.1 million under that measure is closely correlated to, and primarily explained by, increased revenues of $3.8 million less increases in direct costs of $631,000 and general and administrative expenses of $171,000.

 
23

 
 
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 $15.8 million and $8.4 million for the three months ended November 30, 2012 and 2011, respectively, compared to cash payments of $12.2 million and $7.1 million, respectively.  A reconciliation of the differences is summarized in the following table:

   
Three Months Ended
November 30,
(in thousands)
 
   
2012
   
2011
 
             
Cash payments
  $ 12,220     $ 7,071  
Accrued costs, beginning of period
    (5,733 )     (4,967 )
Accrued costs, end of period
    8,522       6,267  
Properties acquired in exchange for common stock
    677       --  
Asset retirement obligation
    115       51  
  Capital expenditures
  $ 15,801     $ 8,422  

During the quarter ended November 30, 2012, we engaged in drilling or completion activities on 35 wells which we operate.  Fifteen of the wells reached productive status during the quarter.  Completion activities were underway on 20 wells, most of which are expected to reach productive status during our second fiscal quarter.  In addition, ten wells in which we participated as a non-operating owner reached productive status and one non-operated well was in the drilling phase.   Most of our capital expenditures for the three months ended November 30, 2012, represent drilling and completion costs of the wells in progress.

Our net borrowings during the quarter were $2,486,000, substantially all of which were used to partially fund the acquisition of operating assets from Orr Energy.

We believe that the cash flow from operations plus additional borrowings available under our revolving line of credit facility will be sufficient to meet our liquidity needs during the remainder of this fiscal year.

Our primary need for cash for the remainder of the fiscal year ending August 31, 2013, will be to fund our drilling and acquisition programs.  Under the updated plans for our 2013 capital budget, we estimate capital expenditures of approximately $82 million, consisting of drilling and completion costs for wells which we operate, our pro-rata share of the costs on wells drilled by other operators, and the costs of acquiring properties.  We increased the budget from $55 million in connection with the acquisition of assets from Orr Energy, which entailed a cash payment of $30 million.  As an operator, we plan to spend approximately $15 million to drill 25 vertical wells and approximately $17 million to drill 4 horizontal wells.  An additional $13.5 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 $1.5 million on 10 wells that indicate good potential for additional hydraulic stimulation. We allocated $5 million for the acquisition of undeveloped acreage.  Our capital expenditure plans described herein represent cash payments, and exclude assets acquired in exchange for common stock.  The acquisition of assets from Orr Energy included partial payment in shares of common stock with a value of $12 million.  Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.

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

 
 
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Non-GAAP Financial Measures
 
We use "adjusted 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 operating, 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 net cash provided by operating activities, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during the period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices. See the Statements of Cash Flows in this report.
  
Adjusted EBITDA. We define adjusted EBITDA as net income (loss) adjusted to exclude the impact of interest expense, interest income, income taxes, and depreciation, depletion and amortization for the period, stock based compensation, plus/minus the change in fair value of derivative assets or liabilities. We believe adjusted EBITDA is relevant because it is a measure of cash available to fund our capital expenditures and service our debt and is a widely used industry metric which may provide comparability of our results with our peers. 

The following table presents a reconciliation of each of our non-GAAP financial measures to its nearest GAAP measure.
 
   
Three Months Ended
November 30,
(in thousands)
 
 
 
2012
   
2011
 
Adjusted cash flow from operations:
 
 
   
 
 
Net cash provided by operating activities
  $ 2,769     $ 4,587  
Changes in assets and liabilities
    3,272       (1,649 )
        Adjusted cash flow from operations
  $ 6,041     $ 2,938  
                 
Adjusted EBITDA:
               
Net Income
  $ 2,238     $ 1,627  
Interest income
    (7 )     (8 )
Provision for income tax
    1,315       --  
Depreciation, depletion and amortization
    2,320       1,214  
Stock based compensation
    168       97  
          Adjusted EBITDA
  $ 6,034     $ 2,930  


 
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TREND AND OUTLOOK

Throughout calendar year 2012, the Wattenberg Field experienced elevated high line pressure for the gathering of our natural gas and liquids.  We consider line pressures greater than 200 PSI to be elevated. During the first quarter of 2013, high line pressure has persisted, although not as extreme as the third and fourth quarters of 2012.  As previously disclosed, DCP Midstream Partners is currently implementing a multi-year facility expansion capable of significantly increasing the long-term gathering and processing capacity in the Wattenberg Field.  A significant improvement in the system will occur in the summer of 2013 when a new processing plant in LaSalle, CO comes on line. The LaSalle, CO plant will have an estimated capacity of 110 million cubic feet per day.

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

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

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

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

CRITICAL ACCOUNTING POLICIES

There have been no changes in our critical accounting policies since August 31, 2012, and a detailed discussion of the nature of our accounting practices can be found in the section titled “Critical Accounting Policies”  in Part II, Item 7 of our Annual Report on Form 10-K for the year ended August 31, 2012.



 
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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

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

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

 
The success of our exploration and development efforts;
 
The price of oil and gas;
 
The worldwide economic situation;
 
Any change in interest rates or inflation;
 
The willingness and ability of third parties to honor their contractual commitments;
 
Our ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital;
 
Our capital costs, as they may be affected by delays or cost overruns;
 
Our costs of production;
 
Environmental and other regulations, as the same presently exist or may later be amended;
 
Our ability to identify, finance and integrate any future acquisitions;
 
The volatility of our stock price; and
 
Changes to tax policy.
 
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
 
Commodity Risk - Our primary market risk exposure results from the price we receive for our oil and natural gas production. Realized commodity pricing for our production is primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas.  Pricing for oil and natural gas production has been volatile and unpredictable in recent years, and we expect this volatility to continue in the foreseeable future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable commodity index price.

Interest Rate Risk - At November 30, 2012, we had debt outstanding under our bank credit facility totaling $5.4 million.  Interest on our bank credit facility accrues at the greater of 3.25% or the prime rate, which was also 3.25% at November 30, 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.

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

 
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Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q.  Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.  Based on that evaluation, our management concluded that, as of November 30, 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 November 30, 2012, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.


PART II

Item 6.   Exhibits

a.  Exhibits




 
101.INS
XBRL Instance Document
 
 
101.SCH
XBRL Schema Document
 
 
101.CAL
XBRL Calculation Linkbase Document
 
 
101.DEF
XBRL Definition Linkbase Document
 
 
101.LAB
XBRL Labels Linkbase Document
 
 
101.PRE
XBRL Presentation Linkbase Document


 
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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
SYNERGY RESOURCES CORPORATION
 
       
Date:  January 9, 2013
By:
/s/ Ed Holloway  
    Ed Holloway, President and Principal Executive Officer  
       
       
 
       
Date:  January 9, 2013
By:
/s/ Frank L. Jennings  
    Frank L. Jennings, Principal Financial and Accounting Officer  
       
       
 

 
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