Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding the financial condition as of November 30, 2012, and the results of operations for the three months ended November 30, 2012, and 2011. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in the Form 10-K for the fiscal year ended August 31, 2012.

Overview

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

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

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

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

Strategy

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

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

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

Significant Developments

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

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

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

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

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

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

RESULTS OF OPERATIONS

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

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

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

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

Key production information is summarized in the following table:

                                        Three Months Ended
                                           November 30,
                                        2012          2011        Change
               Production:
                Oil (Bbls)               80,301        38,277      110%
                Gas (Mcf)               423,646       248,486       70%
                BOE (Bbls)              150,909        79,691       89%

               Revenues
               (in thousands):
                Oil                   $   6,507     $   3,178      105%
                Gas                       1,807         1,301       39%
                 Total                $   8,314     $   4,479       86%

               Average sales price:
                Oil (Bbls)            $   81.03     $   83.03     (2.4%)
                Gas (Mcf)             $    4.27     $    5.23     (18.3%)
                BOE (Bbls)            $   55.09     $   56.20     (2.0%)

"Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons. "Mcf" refers to one thousand cubic feet. A BOE (i.e. barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

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

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

                                                  Three Months ended
                                                     November 30,
                                                    (in thousands)
                                                   2012           2011
               Production costs                 $      523       $  213
               Work-Over                                 -           46
               Other                                     -           42
                 Lifting cost                          523          301
               Severance and ad valorem taxes          814          405
                 Total LOE                      $    1,337       $  706


               Per BOE:
               Production costs                 $     3.47       $ 2.67
               Work-Over                                 -         0.58
               Other                                     -         0.53
                 Lifting cost                         3.47         3.78
               Severance and ad valorem taxes         5.40         5.08
                 Total LOE                      $     8.87       $ 8.86

Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas. Taxes make up the largest component of production costs and tend to increase or decrease primarily based on the value of oil and gas sold. As a percent of revenues, taxes averaged 10% for the three months ended November 30, 2012 and 9% for the three months ended November 30, 2011.

On a BOE basis, production costs increased approximately 30% for the quarter ended November 30, 2012 compared to the quarter ended November 30, 2011. The increase is primarily due to costs incurred to mitigate high line pressure within the Wattenberg field. The Company incurred production costs to rent and install compressors on six pads and installed upgraded valves and other equipment upgrades on some of the Company's older wells.

Depreciation, Depletion, and Amortization ("DDA") - DDA expense is summarized in the following table:

                                           Three Months ended
                                              November 30,
                                             (in thousands)
                                            2012          2011
                     Depletion           $    2,262      $ 1,177
                     Depreciation                27           20
                     Amortization                31           17
                         Total DDA       $    2,320      $ 1,214

                     Depletion per BOE   $    15.37      $ 14.76

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

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

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

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

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

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties. Those costs are reclassified from general and administrative expenses and capitalized into the full cost pool. The increase in capitalized costs from 2011 to 2012 reflects our increasing activities to acquire leases and develop the properties.

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

                                                            Three Months Ended
                                                               November 30,
                                                              (in thousands)
                                                             2012          2011

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

Net cash provided by operating activities was $2.7 million and $4.5 million for the three months ended November 30, 2012 and 2011, respectively. In addition to our analysis using amounts included in the cash flow statement, we evaluate operations using a non-GAAP measure called "adjusted cash flow from operations," which adjusts for cash flow items that merely reflect the timing of certain cash receipts and expenditures. Adjusted cash flow from operations was $6.0 million and $2.9 million for the three months ended November 30, 2012 and 2011, respectively. The improvement of $3.1 million under that measure is closely correlated to, and primarily explained by, increased revenues of $3.8 million less increases in direct costs of $631,000 and general and administrative expenses of $171,000.

The cash flow statement reports actual cash expenditures for capital expenditures, which differs from total capital expenditures on a full accrual basis. Specifically, cash paid for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On a full accrual basis, capital expenditures totaled $15.8 million and $8.4 million for the three months ended November 30, 2012 and 2011, respectively, compared to cash payments of $12.2 million and $7.1 million, respectively. A reconciliation of the differences is summarized in the following table:

                                                           Three Months Ended
                                                              November 30,
                                                             (in thousands)
                                                            2012          2011

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

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

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

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

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

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

Non-GAAP Financial Measures

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

Reconciliation of Non-GAAP Financial Measures

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

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

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