10-Q 1 syrg_10q-053113.htm FORM 10-Q FOR THE PERIOD ENDED 5/31/2013 syrg_10q-053113.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 May 31, 2013

o
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _______

Commission File Number: 001-35245

SYNERGY RESOURCES CORPORATION
(Exact Name of Registrant as Specified in its Charter)

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

20203 Highway 60, Platteville, Colorado  80651
(Address of Principal Executive Offices)  (Zip Code)

Registrant's telephone number including area code:  (970) 737-1073

N/A
Former name, former address, and former fiscal year, if changed since last report

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.                         
Yes x    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   
                                                                                                                                                      Yes x    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
  Larger accelerated filer  o   Accelerated filer  x
  Non-accelerated filer  o Smaller reporting company   o

Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
           Yes o    No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 68,952,530 shares outstanding as of July 1, 2013.

 
 

 
 
SYNERGY RESOURCES CORPORATION

Index



 
2

 
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
(in thousands, except share data)
 
   
May 31,
2013
   
August 31,
 2012
 
ASSETS  
(unaudited)
       
Current assets:
           
Cash and cash equivalents
  $ 19,211     $ 19,284  
Accounts receivable:
               
Oil and gas sales
    6,262       3,606  
Joint interest billing
    3,901       3,268  
Inventory
    252       178  
Commodity derivative, current
    320       -  
Other current assets
    57       131  
Total current assets
    30,003       26,467  
                 
Property and equipment
               
Evaluated oil and gas properties, net
    129,839       59,936  
Unevaluated oil and gas properties
    42,695       32,484  
Other property and equipment, net
    276       282  
Property and equipment, net
    172,810       92,702  
                 
Deferred tax asset, net
    -       332  
Commodity derivative
    48       -  
Other assets
    680       1,230  
                 
Total assets
  $ 203,541     $ 120,731  
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
               
                 
Current liabilities:
               
Trade accounts payable
  $ 5,456     $ 1,499  
Well costs payable
    6,625       5,733  
Revenue payable
    6,400       4,160  
Production taxes payable
    5,571       3,805  
Other accrued expenses
    267       395  
Total current liabilities
    24,319       15,592  
                 
Revolving credit facility
    44,486       3,000  
Deferred tax liability, net
    4,288       -  
Asset retirement obligations
    2,694       1,027  
Total liabilities
    75,787       19,619  
Commitments and contingencies (See Note 13)
               
                 
Shareholders' equity:
               
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
               
 no shares issued and outstanding
    -       -  
Common stock - $0.001 par value, 100,000,000 shares authorized:
               
55,700,330 and 51,409,340 shares issued and outstanding, respectively
    56       51  
Additional paid-in capital
    141,929       123,876  
Accumulated deficit
    (14,231 )     (22,815 )
Total shareholders' equity
    127,754       101,112  
                 
Total liabilities and shareholders' equity
  $ 203,541     $ 120,731  
 
The accompanying notes are an integral part of these financial statements.


 
3

 
  
SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
 (unaudited; in thousands, except share and per share data)
 
   
Three Months Ended
   
Nine Months Ended
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Oil and gas revenues
  $ 12,314     $ 7,522     $ 31,549     $ 18,220  
                                 
Expenses
                               
Lease operating expenses
    1,048       456       2,352       1,048  
Production taxes
    1,067       703       2,975       1,672  
Depreciation, depletion,
                               
   and amortization
    3,820       1,834       9,316       4,600  
General and administrative
    1,514       682       4,013       2,559  
Total expenses
    7,449       3,675       18,656       9,879  
                                 
Operating income
    4,865       3,847       12,893       8,341  
                                 
Other income (expense)
                               
Commodity derivative gain
    540       -       386       -  
Interest expense, net
    (94 )     -       (94 )     -  
Interest income
    5       16       20       27  
Total other income
    451       16       312       27  
                                 
Income before income taxes
    5,316       3,863       13,205       8,368  
                                 
Deferred income tax (provision) benefit
    (1,701 )     (1,432 )     (4,620 )     1,809  
Net income
  $ 3,615     $ 2,431     $ 8,585     $ 10,177  
                                 
Net income per common share:
                               
Basic
  $ 0.07     $ 0.05     $ 0.16     $ 0.23  
Diluted
  $ 0.06     $ 0.05     $ 0.15     $ 0.22  
                                 
Weighted average shares outstanding:
                               
Basic
    55,238,098       51,292,810       53,283,695       44,968,566  
Diluted
    58,918,586       53,174,793       55,623,990       46,775,994  


The accompanying notes are an integral part of these financial statements.
 
 
 
4

 
SYNERGY RESOURCES CORPORATION
 STATEMENTS OF CASH FLOWS
 (unaudited, in thousands)
 
   
Nine Months Ended
 
   
May 31, 2013
   
May 31, 2012
 
Cash flows from operating activities:
           
Net income
  $ 8,585     $ 10,177  
Adjustments to reconcile net income to net
               
cash provided by operating activities:
               
Depreciation, depletion, and amortization
    9,316       4,600  
Provision (benefit) for deferred taxes
    4,620       (1,809 )
Stock-based compensation
    994       323  
Valuation (increase) decrease in commodity derivatives
    (368 )     -  
Changes in operating assets and liabilities:
               
Accounts receivable
               
Oil and gas sales
    (2,656 )     (1,220 )
Joint interest billing
    (633 )     (306 )
Inventory
    (74 )     267  
Accounts payable
               
Trade
    3,957       (1,047 )
Revenue
    2,240       3,944  
Production taxes
    1,766       2,016  
Accrued expenses
    (128 )     150  
Other
    624       (17 )
Total adjustments
    19,658       6,901  
Net cash provided by operating activities
    28,243       17,078  
                 
Cash flows from investing activities:
               
Acquisition of property and equipment
    (70,269 )     (34,026 )
Net cash used in investing activities
    (70,269 )     (34,026 )
                 
Cash flows from financing activities:
               
Proceeds from sale of stock
    -       40,250  
Offering costs
    -       (2,828 )
Proceeds from exercise of warrants
    467          
Proceeds from revolving credit facility
    41,486       3,000  
Payment of related party note payable
    -       (5,200 )
Net cash provided by financing activities
    41,953       35,222  
                 
Net increase (decrease) in cash and cash equivalents
    (73 )     18,274  
                 
Cash and cash equivalents at beginning of period
    19,284       9,491  
                 
Cash and cash equivalents at end of period
  $ 19,211     $ 27,765  
                 
Supplemental Cash Flow Information (See Note 14)

The accompanying notes are an integral part of these financial statements.
 
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
May 31, 2013
(unaudited)


1.  
Organization and Summary of Significant Accounting Policies

Organization:    Synergy Resources Corporation ("the Company”) is engaged in oil and gas acquisition, exploration, development and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado.

Basis of Presentation:    The Company has adopted August 31st as the end of its fiscal year.  The Company does not utilize any special purpose entities.

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

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

Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading, and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, 2012.

In management’s opinion, the unaudited financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company’s financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

Reclassifications:    Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation.  The reclassifications had no effect on net income, working capital or equity previously reported.

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

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

Inventory:    Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market.

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.  Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves.  For depletion purposes, the volume of petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.  Investments in unevaluated properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is an impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the book value of oil and gas properties.  The capitalized costs of proved and unproved oil and gas properties, net of accumulated depreciation, depletion, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unevaluated properties not being amortized, plus the lower of cost or estimated fair value of unevaluated properties being amortized.  Prices are held constant for the productive life of each well.  Net cash flows are discounted at 10%.  If net capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization.  The calculation of future net cash flows assumes continuation of current economic conditions.  Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount.  No provision for impairment was required for either the three or nine months ended May 31, 2013 or May 31, 2012.

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

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

 
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 Interest:  The Company capitalizes interest on expenditures made in connection with acquisition of mineral interests and development projects that are not subject to current amortization.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 4 for additional information.

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
   
Nine Months Ended
 
   
(in thousands)
   
(in thousands)
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
   
2013
   
2012
   
2013
   
2012
 
Capitalized Overhead
  $ 189     $ 86     $ 415     $ 254  
 
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  resulting from purchases by major customers.

   
Three Months Ended
   
Nine Months Ended
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
Major Customers
 
2013
   
2012
   
2013
   
2012
 
Company A
    49 %     73 %     56 %     72 %
Company B
    16 %     12 %     16 %     13 %
 
The Company sells production to a small number of customers, as is customary in the industry.  Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions so warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

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

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

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

Stock-Based Compensation:  The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date, calculated using the Black-Scholes-Merton option pricing model.  The expense is recognized over the vesting period of the respective grants.  See Note 12 for additional information.

 
9

 

 
Earnings Per Share Amounts:    Basic earnings per share includes no dilution and is computed by dividing net income or loss by the weighted-average number of shares outstanding during the period.  Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company.  The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method.  Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.  The following table sets forth the share calculation of diluted earnings per share:
 
   
Three Months Ended
   
Nine Months Ended
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Weighted-average shares outstanding-basic
    55,238,098       51,292,810       53,283,695       44,968,566  
Potentially dilutive common shares from:
                               
Stock Options
    2,338,711       1,458,261       2,084,956       1,406,516  
Warrants
    1,341,777       423,722       255,339       400,912  
      3,680,488       1,881,983       2,340,295       1,807,428  
Weighted-average shares outstanding - diluted
    58,918,586       53,174,793       55,623,990       46,775,994  
 
The following potentially dilutive securities, which could dilute future earnings per share, were excluded from the calculation because they were anti-dilutive:
 
   
Three Months Ended
   
Nine Months Ended
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Warrants
    -       14,098,000       8,970,000       14,098,000  
Employee stock options
    2,150,000       2,400,000       2,635,000       2,425,000  
         Total
    2,150,000       16,498,000       11,605,000       16,523,000  
 
Income Taxes:    Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities due to a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions exist.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of May 31, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.

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

 
10

 

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

As discussed in Note 7, the Company incurred asset retirement obligations during the periods presented, the value of which was determined using unobservable pricing inputs (or Level 3 inputs).  The Company uses the income valuation technique to estimate the fair value of the obligation using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement.
 
Recent Accounting Pronouncements:  The Company evaluates the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on the Company.  There were various updates recently issued by the Financial Accounting Standards Board, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's consolidated financial position, results of operations or cash flows. 


 
11

 

 
 
2.  
Property and Equipment
 
Capitalized costs of property and equipment at May 31, 2013, and August 31, 2012, consisted of the following:
 
         
 
 
   
As of
May 31,
2013
   
As of
August 31,
2012
 
   
(in thousands)
   
(in thousands)
 
Oil and gas properties, full cost method:
           
   Unevaluated costs, not subject to amortization:
           
      Lease acquisition and other costs
  $ 36,070     $ 27,070  
      Wells in progress
    6,625       5,414  
         Subtotal, unevaluated costs
    42,695       32,484  
                 
   Evaluated costs:
               
      Producing and non-producing
    148,693       69,667  
         Total capitalized costs
    191,388       102,151  
      Less, accumulated depletion
    (18,854 )     (9,731 )
           Oil and gas properties, net
    172,534       92,420  
                 
Other property and equipment:
               
    Vehicles
    200       164  
    Leasehold improvements
    71       71  
    Office equipment
    203       157  
    Land
    44       44  
      Less, accumulated depreciation
    (242 )     (154 )
            Other property and equipment, net
    276       282  
                 
Total property and equipment, net
  $ 172,810     $ 92,702  
 
Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value. The reviews for the three months and nine months ended May 31, 2013 and 2012 indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment. The full cost ceiling test, explained in Note 1, and, as performed for the three months and nine months ended May 31, 2013 and 2012, similarly revealed no impairment of oil and gas assets.
 
 

 
12

 
 
3.  
Acquisition
 
On October 23, 2012, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Orr Energy, LLC (“Orr”), for its interests in 36 producing oil and gas wells and approximately 3,933 gross (3,196 net) mineral acres (the “Orr Assets”). On December 5, 2012, the Company closed the transaction for a combination of cash and stock.  Orr received 3,128,422 shares of the Company’s common stock valued at $13.5 million and cash consideration of approximately $29.0 million. Transaction costs related to the acquisition were approximately $109,000, all of which were recorded in the statement of operations within the general and administrative expenses line item for the nine months ended May 31, 2013.   No material costs were incurred for the issuance of the shares of common stock.
 
The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of December 5, 2012.  The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):

Preliminary Purchase Price
 
December 5,
2012
 
Consideration Given
     
Cash
  $ 29,012  
Synergy Resources Corp. Common Stock *
    13,515  
         
Total consideration given
  $ 42,527  
         
Preliminary Allocation of Purchase Price
       
Proved oil and gas properties
  $ 43,143  
Unproved oil and gas properties
    466  
Total fair value of oil and gas properties acquired
    43,609  
         
Working capital
  $ (842 )
Asset retirement obligation
    (240 )
         
Fair value of net assets acquired
  $ 42,527  
         
Working capital acquired was estimated as follows:
       
Accounts receivable
    521  
Accrued liabilities and expenses
    (1,363 )
         
Total working capital
  $ (842 )
 
The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 5, 2012. (3,128,422 shares at $4.32 per share)

 
13

 
 
 
Pro Forma Financial Information
 
As stated above, on December 5, 2012, the Company completed an acquisition of oil and gas properties from Orr Energy.  Below are the combined results of operations for the three and nine months ended May 31, 2013 and 2012 as if the acquisition had occurred on September 1, 2011.
 
The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock, additional depreciation expense, costs directly attributable to the acquisition and costs incurred as a result of the Orr Energy acquisition. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

   
Three Months Ended
   
Nine Months Ended
 
   
(in thousands)
   
(in thousands)
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Oil and Gas Revenues
  $ 12,314     $ 9,182     $ 33,086     $ 24,034  
                                 
Net income
  $ 3,615     $ 3,298     $ 9,124     $ 12,226  
                                 
Earnings per common share
                               
Basic
  $ 0.07     $ 0.06     $ 0.17     $ 0.25  
Diluted
  $ 0.06     $ 0.06     $ 0.16     $ 0.24  
 
4.  
Interest Expense
 
The components of interest expense recorded for the three months and nine months ended May 31, 2013 and 2012, consisted of the following:
 
   
Three Months Ended
   
Nine Months Ended
 
   
(in thousands)
   
(in thousands)
 
   
May 31
   
May 31
   
May 31
   
May 31
 
   
2013
   
2012
   
2013
   
2012
 
                         
Revolving bank credit facility at a variable rate
  $ 381     $ 38     $ 756     $ 83  
Related party note payable at 5.25%
    -       -       -       68  
Amortization of debt issuance costs
    40       -       110       -  
Less, interest capitalized
    (327 )     (38 )     (772 )     (151 )
Interest expense, net
  $ 94     $ -     $ 94     $ -  
 
 
14

 
 
 
5.  
Depletion, depreciation and amortization
 
Depletion, depreciation and amortization for the three months and nine months ended May 31, 2013 and 2012, consisted of the following:
 
   
Three Months ended
   
Nine Months ended
 
   
(in thousands)
   
(in thousands)
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
   
2013
   
2012
   
2013
   
2012
 
Depletion
  $ 3,744     $ 1,789     $ 9,123     $ 4,479  
Depreciation and amortization
    76       45       193       121  
    $ 3,820     $ 1,834     $ 9,316     $ 4,600  
 
6.  
Revolving Credit Facility

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

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

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

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

 
 
15

 

 
7.  
Asset Retirement Obligations
 
Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost.  The revisions recognized during 2013 were primarily from increases in the undiscounted abandonment cost estimates.
 
The following table summarizes the change in asset retirement obligations for the nine months ended May 31, 2013:
 
(in thousands)
     
Asset retirement obligations, August 31, 2012
  $ 1,027  
  Liabilities incurred
    360  
  Liabilities assumed
    240  
  Liabilities settled
    -  
  Change in estimate
    962  
  Accretion
    105  
Asset retirement obligations, May 31, 2013
  $ 2,694  

8. 
Commodity Derivative Instruments
 
The Company has entered into commodity derivative instruments, as described below.  The Company has utilized swaps or “no premium” collars to reduce the effect of price changes on a portion of its future oil production.  A swap requires a payment to the counterparty if the settlement price exceeds the strike price and the same counterparty is required to make a payment if the settlement price is less than the strike price.  A collar requires a payment to the counterparty if the settlement price is above the ceiling price and requires the counterparty to make a payment if the settlement price is below the floor price.  The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk.  While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements.  The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions.  The Company does not enter into derivative contracts for speculative purposes.
 
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  The Company’s derivative contracts are currently with one counterparty.  The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination.  The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.
 
The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities.  Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments.  Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the commodity derivative line on the statements of operations.  The Company’s valuation estimate takes into consideration the counterparty’s credit worthiness, the Company’s credit worthiness, and the time value of money.  The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view.  Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

 
16

 

 
The Company’s commodity derivative contracts as of May 31, 2013 are summarized below:
 
Contract Type
Basis (1)
 
Quantity
(Bbl/month)
 
Strike Price
($/Bbl)
 
Term
     
Collar
NYMEX
    3,014       $87.00 - $102.50  
Jun 1, 2013 - Dec 31, 2013
     
Collar
NYMEX
    1,840     $85.00 - $98.50  
Jan 1, 2014 - Dec 31, 2014
     
Collar
NYMEX
    7,000     $80.00 - $92.50  
Jan 1, 2015 - Jun 30, 2015
     
                         
Contract Type
Basis (1)
 
Quantity
(Bbl/month)
 
Swap Price
($/Bbl)
Term
     
Swap
NYMEX
    3,014     $91.70  
Jun 1, 2013 - Dec 31, 2013
     
Swap
NYMEX
    6,000     $96.35  
Jun 1, 2013 - Dec 31, 2013
  (2)  
Swap
NYMEX
    8,000    
$94.45
 
Jun 1, 2013 - Dec 31, 2013
     
2013 Total/Average
    17,014     $94.17          
Swap
NYMEX
    1,840     $90.80  
Jan 1, 2014 - Dec 31, 2014
     
Swap
NYMEX
    2,000     $90.11  
Jan 1, 2014 - Dec 31, 2014
     
Swap
NYMEX
    5,000     $90.50  
Jan 1, 2014 - Dec 31, 2014
     
2014 Total/Average
    8,840      $90.47          
                         
(1) NYMEX refers to WTI quoted prices on the New York Mercantile Exchange
     
(2) In connection with entering into these swaps with premium hedged prices, the counterparty has the right, but not the obligation to extend the swap to January 1, 2014 through December 31, 2014 at the current strike price and quantity. This option expires on December 31, 2013.
 
 
The following table details the fair value of the derivatives recorded in the applicable balance sheet, by category:
 
       
As of
   
As of
 
Derivatives
 
Balance Sheet
Location
 
May 31, 2013
(in thousands)
 
August 31, 2012
(in thousands)
 
Asset
               
Commodity derivatives
 
Current assets
  $ 320     $ -  
Commodity derivatives
 
Noncurrent assets
  $ 48     $ -  
 
 
17

 
 
 
The amount of gain (loss) recognized in the statements of operations related to derivative financial instruments was as follows:
 
   
Three Months ended
   
Nine Months ended
 
   
(in thousands)
   
(in thousands)
 
   
May 31,
   
May 31,
   
May 31,
   
May 31,
 
   
2013
   
2012
   
2013
   
2012
 
Unrealized gain on commodity derivatives
  $ 502     $ -     $ 368     $ -  
Realized gain on commodity derivatives
    38       -       18       -  
Total gain
  $ 540     $ -     $ 386     $ -  
 
9. 
Fair Value Measurements
 
ASC Topic 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

·  
Level 1: Quoted prices are available in active markets for identical assets or liabilities;
·  
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
·  
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.
 
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis during the reporting periods after initial recognition.
 
The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 7—Asset Retirement Obligations, and for the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3—Acquisitions.
 
The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.
 
The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.
 
 
18

 
 
 
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of May 31, 2013 by level within the fair value hierarchy (in thousands):
 
   
Fair Value Measurements at May 31, 2013
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Financial Assets:
                       
Commodity derivative asset
  $ -     $ 368     $ -     $ 368  
 
Commodity Derivative Instruments
 
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At May 31, 2013, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as level 2.

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

11.  
Shareholders’ Equity

The Company’s classes of stock are summarized as follows:
 
   
As May 31,
   
As August 31,
 
   
2013
   
2012
 
Preferred stock, shares authorized
    10,000,000       10,000,000  
Preferred stock, par value
  $ 0.01     $ 0.01  
Preferred stock, shares issued and outstanding
    -       -  
Common stock, shares authorized
    100,000,000       100,000,000  
Common stock, par value
  $ 0.001     $ 0.001  
Common stock, shares issued and outstanding
    55,700,330       51,409,340  
 
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.

 
19

 
 
 
Common stock issued for acquisition of mineral interests
 
During the nine months ended May 31, 2013 the Company issued common shares in exchange for mineral property interests.  The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.
 
   
For the nine
months ended
May 31, 2013
 
Number of common shares issued for mineral property leases
    674,026  
Number of common shares issued for Orr Energy acquisition
    3,128,422  
Total common shares issued
    3,802,448  
         
Average price per common share
  $ 4.36  
Aggregate value of shares issued (in thousands)
  $ 16,594  
 
The following table summarizes information about the Company’s issued and outstanding common stock warrants as of May 31, 2013:
 
Exercise Price
 
Description
 
Number of Shares
   
Remaining
Contractual Life
(in years)
   
Exercise Price times Number of Shares
 
  $1.60  
Series D
    324,882       1.6       519,811  
  $2.69  
Investor Relations Warrants
    50,000       2.7       134,500  
  $6.00  
Series C
    8,960,000       1.6       53,760,000  
            9,334,882       1.6     $ 54,414,311  
 
The following table summarizes activity for common stock warrants for the nine month period ended May 31, 2013:

   
Number of
Warrants
   
Weighted Average
Exercise Price
 
Outstanding, August 31, 2012
    15,031,067     $ 6.02  
Granted
    -       -  
Exercised
    (548,185 ) *   $ 1.94  
Expired
    (5,148,000 )   $ 6.78  
Outstanding, May 31, 2013
    9,334,882     $ 5.81  
                 
* Warrants exercised include 435,719 warrants exercised on a cashless basis in exchange for 329,992 shares of common stock, which reduced the net cash proceeds to the Company to $0.85 per warrant.
 



 

 
12.  
Stock-Based Compensation
 
In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity based compensation in the form of stock options, restricted stock grants, and warrants.  The Company records an expense related to equity compensation by pro-rating the estimated fair value of each grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”).  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model.

The amount of stock based compensation expense recorded for each of the three and nine months ended May 31, 2013 and 2012 is shown in the table below:

   
Three Months ended
   
Nine Months ended
 
   
(in thousands)
   
(in thousands)
 
   
May 31
   
May 31
   
May 31
   
May 31
 
   
2013
   
2012
   
2013
   
2012
 
Stock options
  $ 392     $ 108     $ 671     $ 323  
Restricted stock grants
    219       -       277       -  
Investor relations warrants
    -       -       46       -  
    $ 611     $ 108     $ 994     $ 323  
 
For the periods presented, all stock based compensation expense was classified as a component within General and Administrative expenses on the Statements of Operations.

During the reporting periods presented below, the Company granted the following employee stock options:
 
   
Three Months ended
   
Nine Months ended
 
   
May 31
   
May 31
   
May 31
   
May 31
 
   
2013
   
2012
   
2013
   
2012
 
Number of options to purchase common shares
    535,000       50,000       890,000       150,000  
Weighted average exercise price
  $ 6.68       3.25     $ 5.82     $ 2.95  
Term (in years)
    10.0       10       10.0       10  
Vesting Period (in years)
    5       5       5       4-5  
Fair Value (in thousands)
  $ 2,371       102     $ 3,482     $ 280  
 
The assumptions used in valuing stock options granted during each of the nine months presented were as follows:

   
Nine Months Ended
 
   
May 31, 2013
   
May 31, 2012
 
Expected Term
 
6.4 years
   
6.5 years
 
Expected Volatility
    78.7%       69.43%  
Risk free rate
    1.06%       1.12-1.35%  
Expected dividend yield
    0.00%       0.00%  
Forfeiture rate
    0.00%       0.00%  


 
21

 
The following table summarizes activity for stock options for the nine months ended May 31, 2013:

   
Number
of Shares
   
Weighted Average Exercise Price
 
Outstanding, August 31, 2012
    4,915,000       $5.09  
Granted
    890,000       $5.82  
Exercised
    -       -  
Outstanding, May 31, 2013
    5,805,000       $5.20  
 
The following table summarizes information about issued and outstanding stock options as of May 31, 2013:

   
Outstanding Options
   
Vested Options
 
Number of shares
  5,805,000     4,399,500  
Weighted average remaining contractual life
 
2.7 years
   
0.7 years
 
Weighted average exercise price
  $ 5.20     $ 5.32  
Aggregate intrinsic value (in thousands)
  $ 15,580     $ 12,929  
 
The estimated unrecognized compensation cost from unvested stock options as of May 31, 2013, which will be recognized ratably over the remaining vesting phase, is as follows:

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

13.  
Commitments and Contingencies
 
From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company will own a working interest.  The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs.  As of May 31, 2013, the Company was participating in six horizontal wells and two vertical wells that were in various stages of drilling or completion.  Costs accrued for these eight wells in progress totaled $2.4 million.  Also as of May 31, 2013, the Company had agreed to participate in 14 future horizontal wells and five future vertical wells and expects that its share of future costs will be approximately $6.2 million.
 
In addition, the Company has been notified by other operators of their non-binding intent to drill 41 horizontal wells and 2 vertical wells in which the Company may own an interest.  As of May 31, 2013, the Company had not yet committed to participate in these potential wells.  Since drilling plans frequently change, the Company does not begin to track its working interest or cost obligation of potential wells until it has committed to participate in the well.
 
Effective April 25, 2013, the Company entered into a turn-key drilling contract with Ensign United States Drilling, Inc. (Ensign) to drill a minimum four horizontal wells. Drilling commenced on May 16, 2013 and is expected to be completed by fiscal year-end.  Total payments due to Ensign will depend upon a number of variables, including the location of wells drilled, the target formation, and other technical details.  The Company estimates that this contract will cover the drilling of five horizontal wells with total drilling costs of approximately $5.5 million.

 
22

 
 
 
14.  
Supplemental Schedule of Information to the Statements of Cash Flows
 
The following table supplements the cash flow information presented in the financial statements for the nine months ended May 31, 2013 2012:
 
   
Nine Months ended
 
   
(in thousands)
 
   
May,
   
May,
 
   
2013
   
2012
 
Supplemental cash flow information:
           
    Interest paid
  $ 756     $ 225  
    Income taxes paid
    -       -  
                 
Non-cash investing and financing activities:
               
Well costs payable
  $ 6,625     $ 5,878  
Assets acquired in exchange for common stock
    16,594       1,494  
Asset retirement costs and obligations
    1,562       214  
 
 
15.  
Subsequent Events
 
On June 19, 2013, the Company closed on the sale of 13,225,000 shares of common stock pursuant to an underwriting agreement with Johnson Rice & Company LLC, acting severally on behalf of itself and the other underwriters.  The public offering price was $6.25 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $78.3 million.  Proceeds from the offering are expected to partially fund the Company’s capital expenditures for fiscal year 2014.




 
23

 
 
 
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 May 31, 2013, and the results of operations for the three months and nine months ended May 31, 2013 and 2012. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in the Company’s Form 10-K for the fiscal year ended August 31, 2012.

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

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

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

As of May 31, 2013 our estimated proved reserves exceeded 6.6 million Bbls of oil and 42 Bcf of gas.  We currently hold approximately 360,000 gross acres and 230,000 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.


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

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

Our capital expenditure budget for 2013 anticipated participation in ten horizontal wells operated by others and included plans to drill and operate four horizontal wells for our own account.  During the nine months ended May 31, 2013, we had participated in ten wells (including both wells that had reached productive status and wells that were still in process), and we had agreed to participate in 14 additional wells, most of which will commence drilling operations after the conclusion of our fiscal year.  We expect to drill five wells on the Renfroe prospect by August 31, 2013.
 
During our start-up years, our cash flow from operations was not sufficient to fund our growth plans and we relied on proceeds from the sale of debt and equity securities. Our cash flow from operations is increasing, and we plan to finance an increasing percentage of our growth with internally generated funds. Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain.

Significant Developments

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

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

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

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

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.  Based upon the semi-annual redetermination derived from the February 28, 2013 reserve report, the borrowing base limitation was increased from $47 million to $75 million.

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

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

We commenced our commodity hedging program beginning January 1, 2013.  As of May 31, 2013, we have hedged approximately 310,000 barrels of oil through June 30, 2015.  We use both commodity swaps and collars.  Our hedge positions generated a gain of $540,000 during the quarter, consisting of realized gains of $38,000 and net unrealized gains of $502,000.  Our commodity hedge positions are revalued at fair value for each reporting period, and can have a significant impact on reported results of operations.
 
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 May 31, 2013, compared to the three months ended May 31, 2012

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

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

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

Key production information is summarized in the following table:
 
   
Three Months Ended
       
   
May 31,
   
May 31,
       
   
2013
   
2012
   
Change
 
Production:
                 
Oil (Bbls)
    115,225       69,230       66.4 %
Gas (McF)
    553,909       333,200       66.2 %
BOE (Bbls)
    207,543       124,763       66.3 %
                         
Revenues (in thousands):
                       
Oil
  $ 9,677     $ 6,314       53.3 %
Gas
    2,637       1,208       118.3 %
Total
  $ 12,314     $ 7,522       63.7 %
                         
Average sales price:
                       
Oil
  $ 83.98     $ 91.21       (7.9 %)
Gas
  $ 4.76     $ 3.62       31.5 %
BOE (Bbls)
  $ 59.33     $ 60.29       (1.6 %)

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

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

 
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Lease Operating Expenses (“LOE”) and Production Taxes – Direct operating costs of producing oil and natural gas and taxes on production and properties are reported as lease operating expenses as follows:
 
   
Three Months Ended
 
   
(in thousands)
 
   
May 31,
   
May 31,
 
   
2013
   
2012
 
Production Costs
  $ 993     $ 352  
Work-Over
    55       -  
Other
    -       104  
Lifting cost
    1,048       456  
Severance and ad valorem taxes
    1,067       703  
Total LOE
  $ 2,115     $ 1,159  
                 
Per BOE:
               
Production costs
  $ 4.78     $ 2.82  
Work-Over
    0.27       -  
Other
    -       0.83  
Lifting cost
    5.05       3.65  
Severance and ad valorem taxes
    5.14       5.64  
Total LOE
  $ 10.19     $ 9.29  
 
Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.  Taxes make up the largest single component of direct costs and tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes averaged 9% for the three months ended May 31, 2013 and 9% for the three months ended May 31, 2012.
 
On a BOE basis, production costs increased approximately 70% for the quarter ended May 31, 2013 compared to the quarter ended May 31, 2012.  The increase is primarily due to costs incurred to mitigate production difficulties within the Wattenberg Field. We incurred additional costs to provide wellhead compression at some well locations.   In addition, we began a work-over program to improve pressures and flows from older wells.

 
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Depreciation, Depletion, and Amortization (“DDA”) – DDA expense is summarized in the following table:
 
   
Three Months Ended
 
   
(in thousands)
 
   
May 31,
   
May 31,
 
   
2013
   
2012
 
Depletion
  $ 3,744     $ 1,789  
Depreciation and amortization
    76       45  
      Total DDA   $ 3,820     $ 1,834  
                 
DDA expense per BOE
  $ 18.41     $ 14.70  
 
The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves.  The capitalized costs of evaluated oil and gas properties are depleted using the units-of-production method based on estimated reserves.  Production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate.  For the three months ended May 31, 2013, production volumes of 207,543 BOE and estimated net proved reserves of 13,630,953 BOE were the basis of the depletion rate calculation.  For the three months ended May 31, 2012, production volumes of 124,763 BOE and estimated net proved reserves of 7,756,563 BOE were the basis of the depletion rate calculation.  Depletion expense per BOE increased approximately 25% primarily as a result of additional DDA associated with newly acquired assets.

General and Administrative – The following table summarizes the components of general and administration expenses:
 
   
Three Months Ended
 
   
(in thousands)
 
   
May 31,
   
May 31,
 
   
2013
   
2012
 
Cash based compensation
  $ 646     $ 390  
Stock based compensation
    611       108  
Professional fees
    318       173  
Insurance
    54       33  
Other general and administrative
    74       64  
Capitalized general and administrative
    (189 )     (86 )
Totals
  $ 1,514     $ 682  
                 
G&A Expense per BOE
  $ 7.29     $ 6.87  
 
Cash based compensation includes payments to employees.  Stock based compensation includes compensation paid to employees, directors and service providers in the form of either stock options, warrants, or restricted stock grants.  The amount of expense recorded for stock options and warrants is calculated by using the Black-Scholes-Merton option pricing model.  The amount of expense recorded for common stocks grants is calculated based upon the closing market value of the shares.  The increase in compensation expense from 2012 to 2013 reflects the expansion of our business, including the addition of new employees.  As of May 31, 2013, we employed 16 persons on a full-time basis, compared to 11 persons as of May 31, 2012.

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

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

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

For tax purposes, we have a net operating loss (“NOL”) carryover in excess of $29.5 million, which is available to offset future taxable income.  Accordingly, we do not expect to pay income taxes during the current fiscal year, and all of our income tax expense is reported as a deferred item.

For the nine months ended May 31, 2013, compared to the nine months ended May 31, 2012

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

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

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

 
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Key production information is summarized in the following table:
 
   
Nine Months Ended
       
   
May 31,
   
May 31,
       
   
2013
   
2012
   
Change
 
Production:
                 
Oil (Bbls)
    296,220       160,995       84.0 %
Gas (McF)
    1,489,624       794,691       87.4 %
BOE (Bbls)
    544,490       293,444       85.6 %
                         
Revenues (in thousands)
                       
Oil
  $ 24,662     $ 14,646       68.4 %
Gas
    6,887       3,574       92.7 %
Total
  $ 31,549     $ 18,220       73.2 %
                         
Average sales price:
                       
Oil
    83.25     $ 90.97       (8.5 %)
Gas
    4.62     $ 4.50       2.7 %
BOE (Bbls)
    57.94     $ 62.09       (6.7 %)
 
“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.

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:
 
   
Nine Months Ended
 
   
(in thousands)
 
   
May 31,
   
May 31,
 
   
2013
   
2012
 
Production Costs
  $ 2,153     $ 892  
Work-Over
    199       41  
Other
    -       115  
Lifting cost
    2,352       1,048  
Severance and ad valorem taxes
    2,975       1,672  
Total LOE
  $ 5,327     $ 2,720  
                 
Per BOE:
               
Production costs
  $ 3.95     $ 3.04  
Work-Over
    0.37       0.14  
Other
    -       0.39  
Lifting cost
    4.32       3.57  
Severance and ad valorem taxes
    5.46       5.70  
Total LOE
  $ 9.78     $ 9.27  
 

 
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Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.  Taxes make up the largest single component of direct costs and tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes averaged 9% for the nine months ended May 31, 2013 and 9% for the nine months ended May 31, 2012.
 
On a BOE basis, production costs increased approximately 30% for the nine months ended May 31, 2013 compared to the nine months ended May 31, 2012.  The increase is primarily due to costs incurred to mitigate production difficulties within the Wattenberg field. We incurred additional costs to provide wellhead compressors at some locations.   In addition, we began a work-over program to improve pressures and flows from older wells.

Depreciation, Depletion, and Amortization (“DDA”) – DDA expense is summarized in the following table:
 
   
Nine Months Ended
 
   
(in thousands)
 
   
May 31,
   
May 31,
 
   
2013
   
2012
 
Depletion
  $ 9,123     $ 4,479  
Depreciation and amortization
    193       121  
Total DDA
  $ 9,316     $ 4,600  
                 
DDA expense per BOE
  $ 17.11     $ 15.68  
 
The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves.  The capitalized costs of evaluated oil and gas properties are depleted using the units-of-production method based on estimated reserves.  Production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate.  For the nine months ended May 31, 2013, production volumes of 544,491 BOE and estimated net proved reserves of 12,973,700 BOE were the basis of the depletion rate calculation.  For the nine months ended May 31, 2012, production volumes of 293,444 BOE and estimated net proved reserves of 5,705,333 BOE were the basis of the depletion rate calculation.  Depletion expense per BOE increased approximately 9% primarily as a result of additional DDA associated with newly acquired assets.

 
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General and Administrative – The following table summarizes the components of general and administration expenses:
 
   
Nine Months Ended
 
   
(in thousands)
 
   
May 31,
   
May 31,
 
   
2013
   
2012
 
Cash based compensation
  $ 1,856     $ 1,370  
Stock based compensation
    994       323  
Professional fees
    894       691  
Insurance
    142       103  
Other general and administrative
    542       326  
Capitalized general and administrative
    (415 )     (254 )
Totals
  $ 4,013     $ 2,559  
                 
G&A Expense per BOE
  $ 7.37     $ 8.72  
 
Cash based compensation includes payments to employees.  Stock based compensation includes compensation paid to employees, directors and service providers in the form of either stock options, warrants, or restricted stock grants.  The amount of expense recorded for stock options and warrants is calculated by using the Black-Scholes-Merton option pricing model.  The amount of expense recorded for common stocks grants is calculated based upon the closing market value of the shares.  The increase in compensation expense from 2012 to 2013 reflects the expansion of our business, including the addition of new employees.  As of May 31, 2013, we employed 16 persons on a full-time basis, compared to 11 persons as of May 31, 2012.

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

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

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

For tax purposes, we have a net operating loss (“NOL”) carryover in excess of $29.5 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.

 
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LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the nine months ended May 31, 2013, and 2012 are summarized below:
 
   
Nine Months Ended
 
   
(in thousands)
 
   
May 31,
   
May 31,
 
   
2013
   
2012
 
Cash provided by operations
  $ 28,243     $ 17,078  
Acquisition of oil and gas properties and equipment
    (70,269 )     (34,026 )
Cash provided by equity financing activities
    467       37,422  
Net borrowings
    41,486       (2,200 )
  Net increase in cash and cash equivalents