10-Q 1 syrg_10q-113013.htm FORM 10-Q FOR THE PERIOD ENDED 11/30/2013 syrg_10q-113013.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, 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: 75,993,960 shares outstanding as of January 1, 2014.

 
 

 
 
SYNERGY RESOURCES CORPORATION

Index

 
Page
 
   
 
     
 
     
 
     
 
     
 
     
     
     
     
 
     
Item 2. 38
     
     
 

 
 
2

 
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
(in thousands, except share data)
 
 
ASSETS
 
November 30,
2013
   
August 31,
 2013
 
   
(unaudited)
       
Current assets:
           
Cash and cash equivalents
  $ 20,973     $ 19,463  
Short-term investments
    40,032       60,018  
Accounts receivable:
               
Oil and gas sales
    9,425       7,361  
Joint interest billing
    5,468       4,700  
Inventory
    294       194  
Other current assets
    471       239  
Commodity derivative
    69       -  
Total current assets
    76,732       91,975  
                 
Property and equipment
               
Evaluated oil and gas properties, full cost method, net
    170,142       132,979  
Unevaluated oil and gas properties
    89,307       64,715  
Other property and equipment, net
    2,029       271  
Property and equipment, net
    261,478       197,965  
                 
Other assets
    602       1,296  
                 
Total assets
  $ 338,812     $ 291,236  
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
               
                 
Current liabilities:
               
Trade accounts payable
  $ 346     $ 949  
Well costs payable
    26,813       25,491  
Revenue payable
    8,810       6,081  
Production taxes payable
    8,422       6,277  
Other accrued expenses
    504       254  
Commodity derivative
    -       2,315  
Total current liabilities
    44,895       41,367  
                 
Revolving credit facility
    37,000       37,000  
Commodity derivative
    81       334  
Deferred tax liability, net
    9,925       6,538  
Asset retirement obligations
    3,540       2,777  
Total liabilities
    95,441       88,016  
Commitments and contingencies (See Note 12)
               
                 
Shareholders' equity:
               
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
               
no shares issued and outstanding
    -       -  
Common stock - $0.001 par value, 100,000,000 shares authorized:
         
75,746,743 and 70,587,723 shares issued and outstanding, respectively
    76       71  
Additional paid-in capital
    250,429       216,383  
Accumulated deficit
    (7,134 )     (13,234 )
Total shareholders' equity
    243,371       203,220  
                 
Total liabilities and shareholders' equity
  $ 338,812     $ 291,236  
 
 
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
 
   
November 30,
   
November 30,
 
   
2013
   
2012
 
             
Oil and gas revenues
  $ 19,266     $ 8,314  
                 
Expenses
               
Lease operating expenses
    1,273       523  
Production taxes
    2,016       814  
Depletion, depreciation
               
   and amortization
    5,591       2,320  
General and administrative
    3,168       1,111  
Total expenses
    12,048       4,768  
                 
Operating income
    7,218       3,546  
                 
Other income (expense)
               
Commodity derivative realized loss
    (398 )     -  
Commodity derivative unrealized gain
    2,636       -  
Interest income
    31       7  
Total other income
    2,269       7  
                 
Income before income taxes
    9,487       3,553  
                 
Deferred income tax provision
    3,387       1,315  
Net income
  $ 6,100     $ 2,238  
                 
Net income per common share:
               
Basic
  $ 0.08     $ 0.04  
Diluted
  $ 0.08     $ 0.04  
                 
Weighted average shares outstanding:
               
Basic
    73,674,865       51,661,704  
Diluted
    76,044,605       53,616,182  
 
The accompanying notes are an integral part of these financial statements.
 
 
SYNERGY RESOURCES CORPORATION
 STATEMENTS OF CASH FLOWS
 (unaudited, in thousands)
 
   
Three Months Ended
 
   
November 30,
2013
   
November 30,
2012
 
Cash flows from operating activities:
           
Net income
  $ 6,100     $ 2,238  
Adjustments to reconcile net income to net
               
cash provided by operating activities:
               
Depletion, depreciation and amortization
    5,591       2,320  
Provision for deferred taxes
    3,387       1,315  
Stock-based compensation
    419       168  
Valuation (increase) in commodity derivatives
    (2,636 )     -  
Changes in operating assets and liabilities:
               
Accounts receivable
               
    Oil and gas sales
    (2,064 )     (1,618 )
    Joint interest billing
    (768 )     (467 )
Inventory
    (100 )     -  
Accounts payable
               
    Trade
    (603 )     (1,073 )
    Revenue
    2,729       821  
    Production taxes
    2,145       777  
    Accrued expenses
    250       (147 )
Other
    463       (1,565 )
Total adjustments
    8,813       531  
Net cash provided by operating activities
    14,913       2,769  
                 
Cash flows from investing activities:
               
Acquisition of property and equipment
    (57,127 )     (12,220 )
Short-term investments
    19,987       -  
Net cash used in investing activities
    (37,140 )     (12,220 )
                 
Cash flows from financing activities:
               
Proceeds from exercise of warrants
    23,771       146  
Proceeds from revolving credit facility
    -       2,486  
Shares withheld for payment of employee payroll taxes
    (34 )     -  
Net cash provided by financing activities
    23,737       2,632  
                 
Net increase (decrease) in cash and cash equivalents
    1,510       (6,819 )
                 
Cash and cash equivalents at beginning of period
    19,463       19,284  
                 
Cash and cash equivalents at end of period
  $ 20,973     $ 12,465  
 
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
November 30, 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, 2013.

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

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

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

 
6

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

Short-Term Investments:  As part of its cash management strategies, the Company invests in short-term interest bearing deposits such as certificates of deposits with maturities of less than one year.

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 the three months ended November 30, 2013 or November 30, 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 9 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 (in thousands):
 
   
Three Months Ended
 
   
November 30,
 
November 30,
 
   
2013
   
2012
 
Capitalized Overhead
  $ 317     $ 103  
 
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.
 
 
 
8

 
 
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.
 
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
 
   
November 30
 
November 30
 
Major Customers
 
2013
   
2012
 
Company A
    60%       68%  
Company B
    15%       22%  
 
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, 2013
 
As of
November 30, 2012
Company A
 
29%
 
35%
Company B
 
16%
 
30%
Company C
 
10%
 
-

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 11 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
 
   
November 30,
   
November 30,
 
   
2013
   
2012
 
             
Weighted-average shares outstanding-basic
    73,674,865       51,661,704  
Potentially dilutive common shares from:
               
Stock Options
    551,060       1,533,812  
Warrants
    1,818,680       420,666  
      2,369,740       1,954,478  
Weighted-average shares outstanding - diluted
    76,044,605       53,616,182  
 
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
 
   
November 30,
   
November 30,
 
   
2013
   
2012
 
             
Warrants
    -       14,098,000  
Employee stock options
    810,000       2,875,000  
         Total
    810,000       16,973,000  
 
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 November 30, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Financial Instruments:  The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.  A substantial portion of the Company’s financial instruments consist of cash and cash equivalents, short-term investments, 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 5, 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.
 
Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps or “no premium” collars to reduce the effect of price changes on a portion of our future oil production. 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 the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures.  The Company compares the valuations it calculates to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7—Commodity Derivative Instruments.
 
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 November 30, 2013, and August 31, 2013, consisted of the following (in thousands):
 
   
As of
   
As of
 
   
November 30, 2013
   
August 31, 2013
 
Oil and gas properties, full cost method:
           
Unevaluated costs, not subject to amortization:
       
      Lease acquisition and other costs
  $ 55,389     $ 38,826  
      Wells in progress
    33,918       25,889  
         Subtotal, unevaluated costs
    89,307       64,715  
                 
   Evaluated costs:
               
      Producing and non-producing
    198,409       155,755  
         Total capitalized costs
    287,716       220,470  
      Less, accumulated depletion
    (28,267 )     (22,776 )
           Oil and gas properties, net
    259,449       197,694  
                 
Land
    1,744       44  
Other property and equipment
    586       500  
Less, accumulated depreciation
    (301 )     (273 )
            Other property and equipment, net
    2,029       271  
                 
Total property and equipment, net
  $ 261,478     $ 197,965  
 
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 ended November 30, 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 ended November 30, 2013 and 2012, similarly revealed no impairment of oil and gas assets.


 
12

 
 
3.  
Acquisitions
 
On September 16, 2013, the Company entered into a definitive purchase and sale agreement with Trilogy Resources, LLC (“Trilogy”), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the “Trilogy Assets”). On November 12, 2013, the Company closed the transaction for a combination of cash and stock.  Trilogy received 301,339 shares of the Company’s common stock valued at $2.9 million and cash consideration of approximately $16.0 million.  No material transaction costs were incurred in connection with this acquisition.

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 November 12, 2013.  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
 
November 12,
2013
 
Consideration Given
     
Cash
  $ 16,008  
Synergy Resources Corp. Common Stock *
    2,896  
         
Total consideration given
  $ 18,904  
         
Preliminary Allocation of Purchase Price
       
Proved oil and gas properties
  $ 14,317  
Unproved oil and gas properties
    5,057  
Total fair value of oil and gas properties acquired
    19,374  
         
Working capital
  $ (119 )
Asset retirement obligation
    (351 )
         
Fair value of net assets acquired
  $ 18,904  
         
Working capital acquired was estimated as follows:
       
Accounts receivable
    500  
Accrued liabilities and expenses
    (619 )
         
Total working capital
  $ (119 )
         
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 November 12, 2013. (301,339 shares at $9.61 per share)


 
13

 
 
 
On August 27, 2013, the Company entered into a definitive purchase and sale agreement with Apollo Operating, LLC (“Apollo”), for its interests in 45 producing oil and gas wells, approximately 1,000 net mineral acres, and a Class II disposal well (the “Apollo Assets”). On November 13, 2013, the Company closed the transaction for a combination of cash and stock.  Apollo received 550,518 shares of the Company’s common stock valued at $5.2 million and cash consideration of approximately $11.0 million. No material transaction costs were incurred in connection with this acquisition.

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 November 13, 2013.  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
 
November 13,
2013
 
Consideration Given
     
Cash
  $ 11,007  
Synergy Resources Corp. Common Stock *
    5,224  
         
Total consideration given
  $ 16,231  
         
Preliminary Allocation of Purchase Price
       
Proved oil and gas properties
  $ 9,271  
Disposal Well
  $ 1,340  
Unproved oil and gas properties
    6,725  
Total fair value of oil and gas properties acquired
    17,336  
         
Working capital
  $ (883 )
Asset retirement obligation
    (221 )
         
Fair value of net assets acquired
  $ 16,232  
         
Working capital acquired was estimated as follows:
       
Accounts receivable
    380  
Accrued liabilities and expenses
    (1,263 )
         
Total working capital
  $ (883 )
         
*
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 November 13, 2013. (550,518 shares at $9.49 per share)
 
    Subsequent to the close of the Apollo acquisition, the Company acquired the remaining 75% working interests not owned by Apollo from the other owners in the disposal well.  Aggregate consideration paid to the other owners approximated $3.7 million.  The Company believes the price paid for the remaining interests approximates the fair market value of the disposal well.
 
 
14

 

Pro Forma Financial Information

As stated above, on November 12 and 13, 2013, the Company completed acquisitions of oil and gas properties from Trilogy Resources, LLC and Apollo Operating, LLC.  Below are the combined results of operations for the three months ended November 30, 2013 and 2012 as if the acquisition had occurred on September 1, 2012.

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 acquisitions and costs incurred as a result of the Trilogy and Apollo acquisitions. 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
 
   
(in thousands)
 
   
November 30
   
November 30
 
   
2013
   
2012
 
             
Oil and Gas Revenues
  $ 21,631     $ 10,960  
                 
Net income
  $ 6,928     $ 3,247  
                 
Earnings per common share
               
Basic
  $ 0.09     $ 0.06  
Diluted
  $ 0.09     $ 0.06  
 

4.  
Depletion, depreciation and amortization (“DDA”)

Depletion, depreciation and amortization for the three months ended November 30, 2013 and 2012, consisted of the following (in thousands):
 
   
Three Months ended
 
   
November 30,
   
November 30,
 
   
2013
   
2012
 
Depletion
  $ 5,490     $ 2,262  
Depreciation and amortization
    101       58  
Total DDA Expense
  $ 5,591     $ 2,320  
 
Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter.


 
15

 

5.  
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 well, and restore the drilling site 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.  For the purpose of determining the fair value of ARO incurred during the fiscal years presented, the Company used the following assumptions:
 
   
For the Three Months Ended November 30,
   
2013
 
2012
Inflation rate
 
 3.9 - 4.0%
 
 3.9 - 4.0%
Estimated asset life
 
 24.0 - 40.0 years
 
 24.0 - 27.6 years
Credit adjusted risk free interest rate
 
8.0%
 
11.2%
 

The following table summarizes the change in asset retirement obligations for the three months ended November 30, 2013 (in thousands):

Asset retirement obligations, August 31, 2013
  $ 2,777  
  Liabilities incurred
    120  
  Liabilities assumed
    572  
  Liabilities settled
    -  
  Accretion
    71  
Asset retirement obligations, November 30, 2013
  $ 3,540  
 
6.  
Revolving Credit Facility

On November 28, 2012, February 12, 2013, June 28, 2013, and December 20, 2013, the Company amended its revolving credit facility (“LOC”) with a bank syndicate.  The LOC is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit.  The terms provide for $300 million ($150 million prior to December 20, 2013) 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 bank syndicate with respect to the LOC.  The credit facility expires on November 28, 2016.

 
16

 
 
Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin of 0% to 1%, or London Interbank Offered Rate (LIBOR) plus a margin of 2.50% to 3.25%.  The interest rate margin, as well as other bank fees, varies with utilization of the LOC.  The average annual interest rate for borrowings during the quarter ended November 30, 2013, was 2.7%.  As of November 30, 2013, the interest rate on the outstanding balance was 2.68%, representing LIBOR plus a margin of 2.5%.

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 most recent redetermination in December 2013 increased the borrowing base to $90 million from $75 million.  As of November 30, 2013, based upon a borrowing base of $75 million and an outstanding principal balance of $37 million  the unused borrowing base available for future borrowing totaled approximately $38 million.  The increase in the borrowing base in December increased the amount available for future borrowing to approximately $53 million.

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain customary financial ratios.  On a quarterly basis, the Company must maintain (a) an adjusted current ratio greater than 1.0, (b) a ratio of earnings before interest, taxes, depletion, amortization and exploration expense (EBITDAX) greater than 3.5 times interest and fees, (c) a ratio of total funded debt less than 3.5 times EBITDAX, and (d) a ratio of total funded debt less than 0.5 times total capitalization.  Furthermore, terms of the LOC require the Company to maintain hedge contracts covering future production quantities that are included in the borrowing base.  The most recent amendment to the LOC generally requires an overall hedge position that covers a rolling 24 months of estimated future production with a minimum position of no less than 45% and a maximum position of no more than 80% of hydrocarbon production.  As of November 30, 2013, the most recent compliance date, the Company was in compliance with all loan covenants.

As noted above, the most recent amendment to the LOC was subsequent to November 30, 2013, and the revisions implemented thereby included, among other things, an increase in the maximum commitment to $300 million, an increase in the borrowing base to $90 million, and an increase in the number of banks participating in the syndicate.
 
7.  
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 two counterparties.  The Company has netting arrangements with the counterparties 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.
 
 
17

 
 
 
 
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.

The Company’s commodity derivative contracts as of November 30, 2013 are summarized below:
 
Collars
 
Basis (1)
 
Quantity
(Bbl/month)
   
Strike Price
($/Bbl)
 
December 31, 2013
 
NYMEX
    3,014       $87.00 - $102.50  
Jan 1, 2014 - Dec 31, 2014
 
NYMEX
    1,840       $85.00 - $98.50  
Jan 1, 2015 - Jun 30, 2015
 
NYMEX
    7,000       $80.00 - $92.50  
 
                 
Swaps
 
Basis (1)
 
Average Quantity
(Bbl/month)
 
Average Swap Price
($/Bbl)
 
December 31, 2013
 
NYMEX
    32,014       $96.21  
Jan 1, 2014 - Dec 31, 2014
 
NYMEX
    11,340       $92.13  
 
Subsequent to November 30, 2013, the Company entered into the following commodity derivative contracts:
 
Collars
 
Basis (1)
 
Quantity
(Bbl/month)
   
Strike Price
($/Bbl)
 
Jan 1, 2014 - Feb 28, 2014
 
NYMEX
    5,000       $87.00 - $98.50  
Mar 1, 2014 - Dec 31, 2014
 
NYMEX
    20,000       $87.00 - $96.25  
Jan 1, 2015 - Jun 30, 2015
 
NYMEX
    2,500       $80.00 - $95.75  
Jul 1, 2015 - Dec 31, 2015
 
NYMEX
    9,000       $80.00 - $92.25  
 
(1) NYMEX refers to WTI quoted prices on the New York Mercantile Exchange
 
 
18

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

Underlying Commodity
 
Balance Sheet
Location
 
Gross Amounts of Recognized Assets
   
Gross Amounts of Recognized liabilities
   
Net Amounts of Assets and (Liabilities) Presented in the Balance Sheet
 
Crude oil derivative contract
 
Current
  $ 326     $ (257 )   $ 69  
Crude oil derivative contract
 
Noncurrent
  $ 161     $ (242 )   $ (81 )
 
The amount of gain (loss) recognized in the statements of operations related to derivative financial instruments was as follows:

   
Three Months ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
Unrealized gain on commodity derivatives
  $ 2,636     $ -  
Realized loss on commodity derivatives
    (398 )     -  
Total gain
  $ 2,238     $ -  
 
8.  
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 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 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.
 
 
19

 
 
 
The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 5—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.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of  November 30, 2013 by level within the fair value hierarchy (in thousands):
 
   
Fair Value Measurements at November 30, 2013
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Financial Assets:
                       
Commodity derivative asset
  $ -     $ 69     $ -     $ 69  
                                 
Financial Liabilities:
                               
Commodity derivative asset
  $ -     $ 81     $ -     $ 81  
 
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 November 30, 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.

Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents and accounts receivable, accounts payable are representative of their fair values due to their short-term maturities.  The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan.

 
20

 
 

9.  
Interest Expense

The components of interest expense recorded for the three months ended November 30, 2013 and 2012, consisted of the following (in thousands):
 
   
Three Months Ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
             
Revolving credit facility
  $ 251     $ 30  
Amortization of debt issuance costs
    94       20  
Less, interest capitalized
    (345 )     (50 )
Interest expense, net
  $ -     $ -  


10.  
Shareholders’ Equity

The Company’s classes of stock are summarized as follows:
 
   
As of
November 30,
   
As of
August 31,
 
   
2013
   
2013
 
Preferred stock, shares authorized
    10,000,000       10,000,000  
Preferred stock, par value
  $ 0.01     $ 0.01  
Preferred stock, shares issued and outstanding
 
nil
   
nil
 
Common stock, shares authorized
    100,000,000       100,000,000  
Common stock, par value
  $ 0.001     $ 0.001  
Common stock, shares issued and outstanding
    75,746,743       70,587,723  
 
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.

Common stock issued for acquisition of mineral interests

During the three months ended November 30, 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 three months ended November 30, 2013
 
Number of common shares issued for mineral property leases
    203,891  
Number of common shares issued for acquisitions
    851,857  
Total common shares issued
    1,055,748  
         
Average price per common share
  $ 9.38  
Aggregate value of shares issued (in thousands)
  $ 9,898  
 


 
21

 
 
 
The following table summarizes information about the Company’s issued and outstanding common stock warrants as of November 30, 2013:
 
Exercise Price
 
Description
 
Number of Shares
   
Remaining Contractual Life (in years)
   
Exercise Price times Number of Shares (in thousands)
 
  $6.00  
Series C
    4,538,000       1.1     $ 27,228  
  $1.60  
Series D
    3,989       1.1       6  
            4,541,989             $ 27,234  
 
The following table summarizes activity for common stock warrants for the three month period ended November 30, 2013:
 
   
Number of
Warrants
   
Weighted Average
Exercise Price
 
Outstanding, August 31, 2013
    8,666,802     $ 5.92  
Granted
    -     $ -  
Exercised
    (4,124,813 )   $ 5.82  
Expired
    -     $ -  
Outstanding, November 30, 2013
    4,541,989     $ 6.00  
 
 
11.  
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 the three months ended November 30, 2013 and 2012 is shown in the table below (in thousands):
 
   
Three Months ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
Stock options
  $ 420     $ 125  
Restricted stock grants
    -       12  
Investor relations warrants
    -       31  
    $ 420     $ 168  
 
For the periods presented, all stock based compensation expense was classified as a component within General and Administrative expenses on the Statements of Operations.

 
22

 
 
 
During the three months ended November 30, 2013 and 2012, the Company granted the following employee stock options:
 
   
Three Months ended
 
   
November 30,
   
November 30,
 
   
2013
   
2012
 
Number of options to purchase common shares
    150,000       230,000  
Weighted average exercise price
  $ 9.98     $ 3.90  
Term (in years)
    10.0       10.0  
Vesting Period (in years)
    5       5  
Fair Value (in thousands)
  $ 1,014     $ 621  
 
The assumptions used in valuing stock options granted during each of the three months presented were as follows:

   
Three Months Ended
   
November 30, 2013
 
November 30, 2012
Expected Term
 
6.5 years
 
6.4 years
Expected Volatility
 
74%
 
79.9%
Risk free rate
 
1.91%
 
1.01%
Expected dividend yield
 
0.00%
 
0.00%
Forfeiture rate
 
0.00%
 
0.00%
 
The following table summarizes activity for stock options for the three months ended November 30, 2013:

   
Number
of Shares
 
Weighted Average Exercise Price
Outstanding, August 31, 2013
 
1,820,000
 
$4.88
Granted
 
150,000
 
$9.98
Exercised
 
(16,000)
 
$4.26
Outstanding, November 30, 2013
 
1,954,000
 
$5.27

The following table summarizes information about issued and outstanding stock options as of November 30, 2013:

   
 Outstanding Options
 
 Vested Options
Number of shares
 
 1,954,000
 
 468,000
Weighted average remaining contractual life
 
 8.6 years
 
 7.7 years
Weighted average exercise price
 
 $5.27
 
 $3.83
Aggregate intrinsic value (in thousands)
 
 $8,223
 
 $2,625

 
23

 
 
 
The estimated unrecognized compensation cost from unvested stock options as of November 30, 2013, which will be recognized ratably over the remaining vesting phase, is as follows:

   
Unvested Options at November 30, 2013
Unrecognized compensation expense (in thousands)
 
$ 5,646
Remaining vesting phase
 
3.5 years

12.  
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, 2013 the Company was participating in seven horizontal wells that were in various stages of drilling or completion.  Costs accrued for these seven wells in progress totaled $3.0 million.

Effective December 18, 2013, the Company amended its turn-key drilling contract with Ensign United States Drilling, Inc. (Ensign).  Under the contract, the Company secured the use of one automated drilling rig for one year.  Drilling operations under the contract are expected to commence in early January 2014.  Total payments due to Ensign will depend upon a number of variables, including the depth of wells drilled, the target formation, and other technical details.  The Company estimates that this contract will cover the drilling of 24 horizontal wells with total drilling costs of approximately $23.0 million.

13.  
Related Party Transaction

The Company leases office space and an equipment yard from HS Land & Cattle, LLC (“HSLC”) in Platteville, Colorado.  Effective July 1, 2013, the monthly rent was increased to $15,000 from $10,000 to include additional areas leased by the Company.  The twelve month lease arrangement with HSLC is renewable annually on July 1.   Under the lease arrangement, the Company paid HSLC $45,000 and $30,000 during the three months ended November 30, 2013 and 2012, respectively.  HSLC is controlled by two of the Company’s executive officers.

 
24

 
 
 
Effective January 1, 2012, the Company commenced processing revenue distribution payments to all persons that own a mineral interest in wells that it operates.  Payments to mineral interest owners included payments to entities controlled by three of the Company’s directors, Ed Holloway, William Scaff Jr, and George Seward.  The following table summarizes the royalty payments made to directors or their affiliates for the three months ended November 30, 2013 and 2012 (in thousands):

   
Three Months ended
 
   
November 30
 
November 30
 
   
2013
   
2012
 
Total Royalty Payments
  $ 82     $ 45  


14.  
Supplemental Schedule of Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the financial statements for the three months ended November 30, 2013 and 2012 (in thousands):
 
   
Three Months ended
 
   
November 30,
   
November 30,
 
   
2013
   
2012
 
Supplemental cash flow information:
           
    Interest paid
  $ 251     $ 30  
    Income taxes paid
    -       -  
                 
Non-cash investing and financing activities:
               
Well costs payable
  $ 26,813     $ 8,522  
Assets acquired in exchange for common stock
    9,898       677  
Asset retirement costs and obligations
    692       115  
 
 
15.  
Subsequent Events
 
Subsequent to November 30, 2013, the Company amended its revolving credit facility as described in Note 6.

Subsequent to November 30, 2013, he Company amended its turnkey drilling contract with Ensign United States Drilling Inc. as described in Note 12.

Subsequent to November 30, 2013, the Company issued 212,500 shares of common stock pursuant to the exercise of Series C warrants.  The Company received cash proceeds of $1,275,000.

Subsequent to November 30, 2013, the Company completed the six wells on the Leffler prospect.  The wells are temporarily shut-in pending completion of modifications at the midstream processing plant that will purchase natural gas produced by the wells.  Full production is expected to commence in January.

 
 
25

 
  
 
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 our financial condition as of November 30, 2013, and our results of operations for the three months ended November 30, 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, 2013.

Overview

We are 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 24,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold significant undeveloped acreage positions in (i) an area directly to the north and east of the Wattenberg Field that is considered the northern extension area, (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 expect to drill two test wells in the northern extension area.

Since commencing active operations in September 2008, we have undergone significant growth.  Our growth was primarily driven by (i) our activities as an operator where we drill and complete productive oil and gas wells; (ii) our participation as a part owner in wells drilled by other operating companies; and (iii) our acquisition of producing oil wells from other individuals or companies.  As disclosed in the following table, as of November 30, 2013, we have completed, acquired, or participated in 361 gross (265 net) successful oil and gas wells.  We have not drilled or participated in any dry holes.
 
   
PRODUCTIVE WELLS
   
OPERATED WELLS
 
NON-OPERATED WELLS
         
   
Completed
 
Participated
 
Acquired
 
Total
Years ended:
 
Gross
Net
 
Gross
Net
 
Gross
Net
 
Gross
Net
                         
August 31, 2009
 
 -
-
 
2
1
 
-
-
 
2
1
August 31, 2010
 
36
28
 
-
-
 
-
-
 
36
28
August 31, 2011
 
20
19
 
11
3
 
72
51
 
103
73
August 31, 2012
 
51
48
 
13
4
 
4
4
 
68
56
August 31, 2013
 
27
26
 
21
6
 
36
34
 
84
66
Nov 30, 2013 (3 months)
5
5
 
2
-
 
61
36
 
68
41
                         
Total
 
139
126
 
49
14
 
173
125
 
361
265
 
In addition to the 361 wells that had reached productive status as of November 30, 2013, we were the operator of eight horizontal wells in progress, including six wells on the Leffler prospect that commenced production after November, and we were participating as a non-operator in seven gross (one net) wells that were in various stages of the drilling or completion process.  Wells in progress represent wells during the period of time between spud date and date of first production.  Generally, horizontal wells on a six well pad are expected to require 120 to 150 days to drill, complete and connect to the gathering system.  All of the wells in progress at November 30, 2013, are expected to commence production during the next six months.

 
26

 
 
Strategy

As of November 30, 2013, we:

·  
were the operator of 283 wells that were producing oil and gas and we were participating as a non-operating working interest owner in 78 producing wells;
 
·  
held approximately 392,000 gross acres and 286,000 net acres under lease;
 
·  
had estimated proved reserves of 7.3 million barrels (“Bbls”) of oil and 41.7 billion cubic feet (“Bcf”) of gas;
 
Our basic strategy for continued growth includes additional drilling activities and acquisition of existing wells in well-defined areas that provide significant cash flow and rapid return on investment.  We attempt to maximize our return on assets by drilling in low risk areas and by operating wells in which we have a majority net revenue interest.  Our drilling efforts are focused on the Wattenberg Field as it yields consistent results.  Until 2012, all of our wells were low risk vertical wells.  During 2012, we began to participate with other operators in horizontal wells.  The success of those wells, as well as the success of numerous other horizontal wells drilled in this area, convinced us to shift our strategy from vertical wells to horizontal wells.  During 2013, we spent the first half of the year drilling vertical wells and spent the second half of the year drilling horizontal wells.  Our plans for 2014 contemplate drilling or participating in 39 horizontal wells.  Our horizontal wells will primarily target the Niobrara and Codell formations.

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 commenced production from the Renfroe prospect during September.  For us, the Renfroe prospect marked the transition from vertical drilling to horizontal drilling for wells which we operate.  Previously, we participated in 16 horizontal wells operated by other companies.  Drilling operations began at the Renfroe site during May and all wells began production during September.  The first 90 days of production from these wells averaged 343 barrels of oil equivalent (BOE) per day for each of the wells on the location.  Production volumes included in the financial statements for the quarter ended November 30, 2013 were 78,000 bbls of oil and 202,000 mcf of gas for all five wells combined.  Drilling and completion costs averaged $3.6 million per well.

During the November quarter, we focused our drilling and completion efforts on the Leffler prospect.  The well pad location for Leffler is approximately 1.5 miles from the Renfroe location.  Six wells were drilled and completed on the Leffler pad, and production commenced after November 30, 2013.  After drilling the Leffler, the rig moved to the Phelps prospect, where it is scheduled to drill six wells.

Based upon our initial success with horizontal drilling at the Renfroe and Leffler prospects, we negotiated another drilling contract with Ensign United States Drilling, Inc., to use one automated drilling rig (Rig #131) for one year, commencing in January, 2014.  We expect Rig #131 to drill 24 horizontal wells for us during calendar year 2014.  We will continue to use Rig #17, another Ensign drilling rig, to drill wells during the remainder fiscal year 2014.
 
27

 
 
 
With regard to activity on wells in which we participate as a non-operating interest owner, drilling or completion activities were undertaken on 9 wells during the quarter, and 2 of those wells reached productive status prior to November 30, 2013.  Seven non-operated wells were in various stages of drilling or completion at November 30, 2013, and all of them are expected to commence production during the next six months.

In November we completed two significant acquisitions that included producing properties.  On November 12, 2013, we completed an acquisition of assets from Trilogy Resources, LLC.  The assets included 21 producing oil and gas wells along with leases covering 800 net acres.  We assumed operational responsibility on the 21 producing wells.  Purchase consideration included cash of $16.0 million and 301,339 shares of restricted common stock.

On November 13, 2013, we completed an acquisition of assets from Apollo Operating, LLC.  The assets included interests in 38 wells operated by Apollo and approximately 1,000 net acres.  Operational responsibility for the 38 wells was transferred to us.  Other assets included in the transaction were smaller ownership interests in wells not operated by Apollo, including six wells drilled and operated by us, and a 25% interest in a Class II disposal well.  Purchase consideration included cash of $11.0 million and 550,518 shares of restricted common stock.

Based upon the initial evaluation of the assets acquired, substantially all of the purchase consideration will be allocated to oil and gas properties. Revenues and expenses from the acquired properties were consolidated with our operations commencing on the closing dates in November, and did not have a significant impact on reported results for the quarter.  In future quarters, we expect the acquired properties to contribute approximately 350 BOE per day to our operations.

We continue to improve our borrowing arrangement with a bank syndicate led by Community Banks of Colorado.  In December 2013, the arrangement was modified to increase the maximum lending commitment to $300 million from $150 million, to increase the borrowing base to $90 million, and to increase the number of banks involved in the borrowing arrangement.

The success of horizontal drilling techniques in the D-J Basin has significantly increased quantities of oil and natural gas produced in the region.  Local refineries do not have sufficient capacity to process all of the crude oil available.  The imbalance of supply and demand in the area is expected to result in an increase in oil transported from the D-J Basin to other markets, generally via pipeline or railroad car.  We have entered into contracts for 2014 with various oil purchasers that we believe will provide sufficient take-away capacity for all of our oil production.  The imbalance is having an impact on prices paid by oil purchasers.  Our average realized price for the quarter ended November 30, 2013 was $93.06 per barrel, a discount of $7.78 per barrel to the average NYMEX posted price for WTI.  Pricing indicators for our second fiscal quarter are suggesting that the average discounts will increase to a range of $11.50 to $14.90 per barrel.

We continued our commodity hedging program to mitigate the impact of short term price fluctuations on our cash flow.  As a result of price fluctuations in the price of oil during the quarter, our hedge positions increased in value and we recorded a gain of $2.2 million for the three months.  As of November 30, 2013, we have hedged approximately 480,000 barrels of oil through December 2015.  We use both commodity swaps and collars.  Our commodity hedge positions are revalued at fair value for each reporting period, and can have a significant impact on reported results of operations.

 
28

 
 
 
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, 2013, compared to the three months ended November 30, 2012

For the three months ended November 30, 2013, we reported net income of $6.1 million compared to $2.2 million during the three months ended November 30, 2012.  Earnings per basic share were $0.08 for the three months ended November 30, 2013 compared to $0.04 for the three months ended November 30, 2012.  Earnings per diluted share were $0.08 for the three months ended November 30, 2013 compared to $0.04 for the three months ended November 30, 2012.  The increase in net income, as well as the increase in other operating measurements, is the result of the rapid growth in reserves, producing wells, and daily production totals.  As of November 30, 2013 we had 265 net producing wells, compared to 163 net producing wells as of November 30, 2012.

Oil and Gas Production and Revenues – For the three months ended November 30, 2013 we recorded total oil and gas revenues of $19.3 million compared to $8.3 million for the three months ended November 30, 2012, an increase of $11.0 million or 132%.  Our growth in revenue was the result of an increase in our production volume of 93% during the intervening period.

Our revenues are sensitive to changes in commodity prices.  As shown in the following table, average realized prices have increased by 15% for oil and 14% for natural gas.  The following table presents actual realized prices, without the effect of hedge transactions.  The impact of hedge transactions is presented later in this discussion.

Key production information is summarized in the following table:
 
   
Three Months Ended
       
   
November 30
   
November 30
       
   
2013
   
2012
   
Change
Production:
                 
Oil (Bbls)
    168,278       80,301       110 %
Gas (McF)
    741,755       423,646       75 %
BOE (Bbls)
    291,904       150,909       93 %
                         
Revenues (in thousands):
                       
Oil
  $ 15,660     $ 6,507       141 %
Gas
    3,606       1,807       100 %
Total
  $ 19,266     $ 8,314       132 %
                         
Average sales price:
                       
Oil
  $ 93.06     $ 81.03       15 %
Gas
  $ 4.86     $ 4.27       14 %
BOE (Bbls)
  $ 66.00     $ 55.09       20 %

 “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.

 
29

 
 
 
Net oil and gas production for the three months ended November 30, 2013 was 291,904 BOE, or 3,208 BOE per day. For the three months ended November 30, 2012, production averaged 1,658 BOE per day, a year over year increase of 93%.  As a further comparison, average BOE production was 2,479 per day during the quarter ended August 31, 2013, a quarter over quarter increase of 29%.  The significant increases in production from the comparable prior periods reflect the additional wells that began production over the past three months, including production from the five horizontal wells at the Renfroe prospect.

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 (in thousands):
 
   
Three Months Ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
Production Costs
  $ 1,203     $ 523  
Work-Over
    70       -  
Lifting cost
    1,273       523  
Severance and ad valorem taxes
    2,016       814  
Total LOE
  $ 3,289     $ 1,337  
                 
Per BOE:
               
Production costs
  $ 4.12     $ 3.47  
Work-Over
    0.24       -  
Lifting cost
    4.36       3.47  
Severance and ad valorem taxes
    6.91       5.40  
Total LOE
  $ 11.27     $ 8.87  
 
Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.  Taxes make up the largest single component of direct costs and tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes averaged 10% for the three months ended November 30, 2013 and 9% for the three months ended November 30, 2012.
 
On a BOE basis, production costs increased approximately 19% for the quarter ended November 30, 2013 compared to the quarter ended November 30, 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.

 
30

 
 
 
Depreciation, Depletion, and Amortization (“DDA”) – DDA expense is summarized in the following table (in thousands):
 
   
Three Months Ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
Depletion
  $ 5,490     $ 2,262  
Depreciation and amortization
    101       58  
Total DDA
  $ 5,591     $ 2,320  
                 
DDA expense per BOE
  $ 19.15     $ 15.37  

Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate.  For the three months ended November 30, 2013, production represented 2.1% of the reserve base compared to 1.4% for the three months ended November 30, 2012.  The depletion rate for the quarter was greater than prior quarters primarily because of initial production from the Renfroe prospect.  Consistent with the expected decline curve for wells targeting the Niobrara and Codell formations, we expect the Renfroe wells to exhibit robust production during the first few weeks, decline rapidly over the first six months, and eventually stabilize over an expected life in excess of 30 years.  Production from the five Renfroe wells was robust during the quarter and, since our initial reserve estimates are conservative, it increased our overall depletion rate.

For the three months ended November 30, 2013, depletion of oil and gas properties was $19.15 per BOE compared to $15.37 for the three months ended November 30, 2012.  The increase in the DD&A rate was primarily the result of the allocation of the purchase price to proved properties related to the December 2012 acquisition of Orr Energy.  Acquired proved reserves are valued at fair market value on the date of the acquisition, which contributes to a higher amortization base, as compared to our historical cost of acquiring leaseholds and developing our properties.  To date, the fair value of our acquired reserves has been higher than our historical cost of developing our properties even though the resulting EURs are equivalent.  Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties.  We believe that, although initially acquisitions increase our DD&A rate per BOE over the development of the acquired properties, the resulting rates will decline with the drilling of horizontal wells and the addition of the related reserves.

General and Administrative (“G&A”) –The following table summarizes general and administration expenses incurred and capitalized during the last two years:

   
Three Months Ended
 
   
November 30
   
November 30
 
(in thousands)
 
2013
   
2012
 
G&A costs incurred
  $ 3,485     $ 1,214  
Capitalized costs
    (317 )     (103 )
Totals
  $ 3,168     $ 1,111  
                 
G&A Expense per BOE
  $ 10.85     $ 7.36  

 
31

 
 
 
General and administrative includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others.  In an effort to minimize overhead costs, we employ a total staff of 24 employees, and use consultants, advisors, and contractors to perform certain tasks when it is cost-effective.

Although G&A costs have increased as we grow our business we strive to maintain an efficient overhead structure.  For the quarter ended November 30, 2013, G&A was $10.85 per BOE compared to $7.36 for the quarter ended November 30, 2012.  G&A for the quarter included additional compensation of $1.2 million awarded by the compensation committee.

Our G&A expense for 2013 includes share based compensation of $0.4 million.  The comparable amount for 2012 was $0.2 million.  Share based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes.  It is a non-cash charge, which, for stock options, is calculated using the Black-Scholes-Merton option pricing model to estimate the fair value of options.  Amounts are pro-rated over the vesting terms of the option agreement, generally three to five years.

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.

Other income (expense) – Neither interest expense nor interest income had a significant impact on our results of operations for the periods presented.  Interest costs incurred under our credit facility were classified as costs related to our unevaluated assets or wells in progress and were eligible for capitalization into the full cost pool.

To mitigate the impact of short term price fluctuations, we engage in commodity swap and collar transactions.  We designed our derivative activity to protect our cash flow during periods of oil price declines.  Generally, contracts are based upon a reference price indexed to trading of West Texas Intermediate Crude Oil on the NYMEX.  During the quarter ended November 30, 2013, the average index prices were higher than our average contract prices, and we realized a loss of $0.4 million for the quarter.  As of November 30, 2013, the weighted average future index prices were approximately $93 per barrel, approximately $8 lower than the reference price at the end of August, creating an unrealized gain of $2.6 million for the quarter.

Income taxes – We reported income tax expense of $3.4 million for the three months ended November 30, 2013, calculated at an effective tax rate of 35.7%.  During the comparable prior year period, we reported income tax expense of $1.3 million, calculated at an effective tax rate of 37%.  For both periods, it appears that the tax liability will be deferred into future years, and no material federal or state income tax payments will be required for 2013 or 2014.

During fiscal year 2014, we estimate that the effective tax rate will be reduced from the federal and state statutory rate by the impact of deductions for percentage depletion.

For tax purposes, we have a net operating loss (“NOL”) carryover in excess of $41 million, which is available to offset future taxable income.  The NOL will begin to expire, if not used, in 2031.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  During 2013 and 2012, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carry-forward, and have therefore included it in our inventory of deferred tax assets.

 
32

 
 
 
LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the three months ended November 30, 2013, and 2012 are summarized below (in thousands):
 
   
Three Months Ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
Cash provided by operations
  $ 14,913     $ 2,769  
Acquisition of oil and gas properties and equipment
    (57,127 )     (12,220 )
Proceeds from short-term investments
    19,987       -  
Equity financing activities
    23,737       146  
Net borrowings
    -       2,486  
Net increase in cash and cash equivalents
  $ 1,510     $ (6,819 )
 
Net cash provided by operating activities was $14.9 million and $2.7 million for the three months ended November 30, 2013 and 2012, respectively.  In addition to amounts reclassified from short term investments based upon the proceeds received with the investments matured, we received $23.7 million from the exercise of Series C warrants at $6.00 per share.

The cash flow statement reports actual cash expenditures for capital expenditures using a strict cash flow basis, which differs from the “all-inclusive” basis used to calculate other amounts reported in our financial statements.   Specifically, cash payments 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 the “all-inclusive” basis, capital expenditures totaled $69.0 million and $15.8 million for the three months ended November 30, 2013 and 2012, respectively, compared to cash payments of $57.1 million and $12.2 million, respectively.  A reconciliation of the differences is summarized in the following table (in thousands):
 
   
Three Months Ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
Cash payments for capital expenditures
  $ 57,127     $ 12,220  
Accrued costs, beginning of period
    (25,491 )     (5,733 )
Accrued costs, end of period
    26,813       8,522  
Non-cash acquisitions, common stock
    9,898       677  
Other
    692       115  
All inclusive capital expenditures
  $ 69,039     $ 15,801  
 
During the quarter ended November 30, 2013, we engaged in drilling or completion activities on 13 horizontal wells that we operate, including five wells on the Renfroe prospect that commenced production during September and six wells on the Leffler prospect that commenced production subsequent to November 30, 2013.  We participated in drilling and completion activities on 9 non-operated wells, including 2 wells that commenced production during the quarter.  In addition, we invested $35 million in the acquisition of mineral assets from Trilogy Resources LLC and Apollo Operating LLC, including approximately $8 million paid in the form of common stock.  Our mineral lease acquisition program incurred costs of $3 million during the period.

 
33

 
 
 
Our primary need for cash for the fiscal year ending August 31, 2014, will be to fund our drilling and acquisition programs.  Our cash requirements are expected to increase significantly as we implement our horizontal drilling program.  Each horizontal well is estimated to cost $3.8 million, compared to the estimated cost of a vertical well of $0.7 million.  Under the revised plans for our 2014 capital budget, we estimate capital expenditures of approximately $189 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.  It is our plan to drill 34 net horizontal wells during the year and to participate in 5 net non-operated horizontal wells at a total cost of $150 million.  We expect to drill or participate in 5 vertical wells at a total cost of $4 million.  Leasing activities are expected to cost $5.0 million, and the acquisition of producing properties is budgeted for $30 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.

For 2014, we believe that available capital resources, including cash and short term investment on hand plus 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 fiscal year.

In addition to our analysis using amounts included in the cash flow statement, we evaluate operations using a non-GAAP measure called “adjusted EBITDA,” which adjusts for cash flow items that merely reflect the timing of certain cash receipts and expenditures.  As shown on the following paragraphs, adjusted EBITA was $12.8 million and $6.0 million for the three months ended November 30, 2013 and 2012, respectively.

Non-GAAP Financial Measures
 
We use "adjusted EBITDA" as a non-GAAP financial measure when management evaluates our performance.  This non-GAAP measure of financial performance is not defined under U.S. GAAP and should be considered in addition to, not as a substitute for, indicators of financial performance reported in accordance with U.S. GAAP.  We may use non-GAAP financial measures that are not comparable to measures with similar titles reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.  In our reports, we provide a Reconciliation of Non-GAAP Financial Measures that includes a detailed description of these measures as well as a reconciliation of each to its most similar U.S. GAAP measure.

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

 
34

 
 
 
The following table presents a reconciliation of our non-GAAP financial measure to its nearest GAAP measure (in thousands).
 
   
Three Months Ended
 
   
November 30
   
November 30
 
   
2013
   
2012
 
Adjusted EBITDA:
           
Net income
  $ 6,100     $ 2,238  
Depreciation, depletion and amortization
    5,591       2,320  
Provision for income tax
    3,387       1,315  
Stock based compensation
    419       168  
Commodity derivative change
    (2,636 )     -  
Interest income
    (31 )     (7 )
Adjusted EBITDA
  $ 12,830     $ 6,034  

TREND AND OUTLOOK

In early September, 2013, Northern Colorado experienced flooding that covered a wide area and caused extensive damage.  Significant damage was done to the area’s infrastructure, such as roads, bridges, and water treatment facilities, as well as to numerous structures within the flood zone.  Approximately 20 of our well sites were directly affected by the flood waters.  However, the damage to our facilities was not severe, and there were no hydrocarbon spills at our sites.  Most of the wells were repaired within a few weeks and all of the sites were  returned to service during our first fiscal quarter.  The cost of repairs will not have a significant impact on our financial statements.  However, the extent of the flooding throughout our production area was so vast that it impacted our daily operations, even on well sites that were not directly affected by the flood.  For several days, it was difficult to gather and transport hydrocarbons, and oil sales from our legacy vertical wells for the month of September decreased by 35% from the month of August.  The new horizontal wells which reached productive status during the first week of September were less affected by the flood, and production from those wells contributed to our revenues for the quarter.

During fiscal year 2012, the Wattenberg Field experienced elevated line pressure in the natural gas and liquids gathering system.  Issues with high line pressure continued during 2013.  High line pressure restricts our ability to produce crude oil and natural gas.  As line pressures increase, it becomes more difficult to inject gas produced by our wells into the pipeline.  When line pressure is greater than the operating pressure of our wellhead equipment, the wellhead equipment is unable to inject gas into the pipeline, and our production is restricted or shut-in.  Since our wells produce a mixture of crude oil and natural gas, restrictions in gas production also restrict oil production.  Although various factors can cause increased line pressure, a significant factor in our area is the success of horizontal wells that have recently been drilled.  As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle.  Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells.  The pace of horizontal drilling in the Wattenberg is accelerating and it appears that it will be some time before the gathering system will have sufficient capacity to eliminate the high line pressure issues.

We are taking steps to mitigate high line pressures.  Where it was cost beneficial, we installed compressors to aid the wellhead equipment in its injection of gas into the system.  Compression equipment at the wellhead has proven beneficial, especially at pad sites with multiple vertical wells.  Along with our mid-stream service provider, we are evaluating the installation of larger diameter pipe to improve the gas gathering capacity.

 
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In addition, companies that operate the gas gathering pipelines are making significant capital investments to increase system capacity.  As publicly disclosed, DCP Midstream Partners (“DCP”) is currently implementing a multi-year facility expansion capable of significantly increasing the long-term gathering and processing capacity in the Wattenberg Field.  DCP is the principle third party provider that we employ to gather production from our wells.  A new processing plant in LaSalle, CO came on line during October, 2013.  The LaSalle, CO plant will have an estimated capacity of 110 million cubic feet per day.  The plant is expected to reach full operational status during our first and second fiscal quarters.  DCP has also announced the building of the Lucerne Plant II, northeast of Greeley in Weld County, with a maximum capacity of 230 mmcf/d, which is estimated to begin operations in 2015.  At this time, we do not know how long it will take for the mitigation efforts to remedy the problem.

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

It is expected that our principal source of cash flow will be from the production and sale of oil and gas reserves which are depleting assets.  Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing from more sources 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 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, 2013, 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, 2013.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

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

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

 
The success of our exploration and development efforts;
 
The price of oil and gas;
 
The worldwide economic situation;
 
Any change in interest rates or inflation;
 
The willingness and ability of third parties to honor their contractual commitments;
 
Our ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital;
 
Our capital costs, as they may be affected by delays or cost overruns;
 
Our costs of production;
 
Environmental and other regulations, as the same presently exist or may later be amended;
 
Our ability to identify, finance and integrate any future acquisitions;
 
The volatility of our stock price, and
 
Changes to tax policy

Item 3.  Quantitative and Qualitative Disclosures About Market Risk
 
Commodity Risk - Our primary market risk exposure results from the price we receive for our oil and natural gas production. Realized commodity pricing for our production is primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas.  Pricing for oil and natural gas production has been volatile and unpredictable in recent years, and we expect this volatility to continue in the foreseeable future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable commodity index price.

Interest Rate Risk - At November 30, 2013, we had debt outstanding under our bank credit facility totaling $37.0 million.  Interest on our bank credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate (LIBOR).  At November 30, 2013, the interest rate was 2.68%, based upon LIBOR plus a margin of 2.5%.  We are currently incurring interest at a rate of 2.68%, and we are exposed to interest rate risk on the bank credit facility if the variable reference rates increase.  If interest rates increase, our interest expense would increase and our available cash flow would decrease.

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

 
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Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q.  Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.  Based on that evaluation, our management concluded that, as of November 30, 2013, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended November 30, 2013, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.


PART II
 
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the three months ended November 30, 2013 we issued 203,891 shares of our restricted common stock to four persons in consideration for their assignment to us of oil and gas leases.

The shares of common stock described above were not registered under the Securities Act of 1933 and are restricted securities.  We relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 in connection with the issuance of these shares. The persons who acquired these shares were sophisticated investors and were provided full information regarding our business and operations. There was no general solicitation in connection with the offer or sale of these securities. The persons who acquired these shares acquired them for their own accounts. The certificates representing these shares bear a restricted legend providing that they cannot be sold except pursuant to an effective registration statement or an exemption from registration. No commission was paid to any person in connection with the issuance of these shares.
 
Item 6.  Exhibits

a.  Exhibits

 
10.18
Purchase and Sale Agreement dated September 16, 2013, with Trilogy Resources, LLC

 
10.19
Purchase and Sale Agreement dated August 27, 2013, with Apollo Operating, LLC

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

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

 
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Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 for Ed Holloway and Frank L. Jennings.
 
 
101.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 8, 2014
By:
/s/ Ed Holloway  
    Ed Holloway, President and Principal Executive Officer  
 
 
 
     
Date:  January 8, 2014
By: /s/ Frank L. Jennings  
    Frank L. Jennings, Principal Financial and Accounting Officer  
       
       
       
 
 


 
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