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SYRG > SEC Filings for SYRG > Form 10-Q on 9-Apr-2013All Recent SEC Filings

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Form 10-Q for SYNERGY RESOURCES CORP


9-Apr-2013

Quarterly Report


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

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding the financial condition as of February 28, 2013, and the results of operations for the three months and six months ended February 28, 2013 and February 29, 2012. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in the Company's Form 10-K for the fiscal year ended August 31, 2012.

Overview

Synergy Resources Corporation ("we," "our," "us" or "the Company") is a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin ("D-J Basin") of Colorado. 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. We hold developed and undeveloped acreage in the Wattenberg Field, and hold significant undeveloped acreage positions east of the Wattenberg Field. Our holdings outside of the Wattenberg Field include Colorado, Wyoming, and Nebraska. Although we have not yet commenced exploration and development activities in the other areas, we may do so in the future.

Since commencing active operations in September 2008, we have undergone significant growth. As disclosed in the following table, as of February 28, 2013, we have drilled, acquired, or participated in 284 gross oil and gas wells and have successfully completed 278 wells that went into production. There were six wells at various stages of the drilling and completion process. We have not drilled any non-productive wells.

                          Operated                     Participated
          Year     Drilled       Completed       Drilled        Completed      Acquired
          2009            -               -             2                2             -
          2010           36              22             -                -             -
          2011           20              28            11               11            72
          2012           51              47            13                5             4
          2013           27              37            12               14            36
          Total         134             134            38               32           112

As of February 28, 2013 our estimated proved reserves exceeded 7 million Bbls of oil and 44 Bcf of gas. We currently hold approximately 259,000 gross acres and 218,000 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.

All wells drilled prior to 2012 were relatively low-risk vertical wells (including wells that are considered directional wells). Over the last twelve months we participated with other operators in six horizontal wells that reached productive status. We have agreed to participate in seven horizontal wells that have either commenced drilling operations or expect drilling activity during 2013, and are evaluating prospects for 27 wells that have been proposed.


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Historically, we were a company that drilled vertical wells. Newer technology allows exploitation of hydrocarbon deposits using horizontal wells. The new technology is evolving rapidly and shows great promise. We plan to transition our primary emphasis from vertical drilling to horizontal drilling during the remainder of the fiscal year. Our capital expenditure budget for 2013 anticipated participation in ten horizontal wells operated by others. That budget may be increased. Furthermore, we plan to drill and operate four horizontal wells for our own account during the current fiscal year.

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

Significant Developments

As an operator, we continued our active vertical well drilling program from September 1, 2012 through February 28, 2013. During that time, we drilled 27 new wells and brought all of them into productive status. In addition, the ten wells that were in progress at August 31, 2012 reached productive status. 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 six months of the fiscal year. With regard to activity on wells in which we participate as a non-operating interest owner, nine wells were drilled (including two horizontal wells) and fourteen wells reached productive status (including three horizontal wells) during the six month period. Six non-operated wells were in various stages of drilling or completion at February 28, 2013, and two additional horizontal wells were spud in March.

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

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. Revenues and expenses from the Orr properties were consolidated with our operations commencing on December 5, 2012, and contributed approximately $745,000 to operating income during the quarter.

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.


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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 February 28, 2013, 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. As of February 28, 2013, we had hedged approximately 188,000 barrels of oil over the remainder of calendar 2013 and all of calendar 2014. We used both commodity swaps and collars. Our hedge positions generated a loss of $154,000 during the quarter, consisting of realized losses of $20,000 and net unrealized losses of $134,000. Our commodity hedge positions are revalued at fair value for each reporting period, and can have a significant impact on reported results of operations.

RESULTS OF OPERATIONS

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

For the three months ended February 28, 2013, compared to the three months ended February 29, 2012

For the three months ended February 28, 2013, we reported net income of $2.7 million compared to $6.1 million during the three months ended February 29, 2012. Earnings per diluted share were $0.05 for the three months ended February 28, 2013 compared to $0.12 for the three months ended February 29, 2012. The comparison between the two years was primarily influenced by increasing revenues and expenses associated with the increased number of producing wells plus the effect of deferred income taxes. As of February 28, 2013 we had 278 gross producing wells (220 wells net), compared to 157 gross producing wells (116 wells net) as of February 29, 2012. For deferred income taxes, the 2013 quarter included tax expense of $1.6 million while the 2012 quarter included a tax benefit of $3.2 million, for a net difference of $4.8 million. An explanation of income taxes is provided later in this section.

Oil and Gas Production and Revenues - For the three months ended February 28, 2013 we recorded total oil and gas revenues of $10.9 million compared to $6.2 million for the three months ended February 29, 2012, an increase of $4.7 million or 76%. Our growth in revenue was the result of an increase in our production volume of 87% during the intervening period. For the quarter, our gas/oil ratio ("GOR") was 46/54. During the comparable prior period, our GOR was 44/56.

Our revenues are sensitive to changes in commodity prices. As shown in the following table, average realized prices have declined by 8.8% for oil and increased 16.6% for natural gas. To mitigate the impact of short term price fluctuations, we engage in commodity swap and collar transactions. The following table presents actual realized prices, before the effect of hedge transactions.


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Key production information is summarized in the following table:

                                          Three Months Ended
                                    February 28,       February 29,
                                        2013               2012           Change
        Production:
        Oil (Bbls)                        100,694             55,823       80.4%
        Gas (McF)                         512,069            260,627       96.5%
        BOE (Bbls)                        186,039             99,261       87.4%

        Revenues (in thousands):
        Oil                        $        8,478     $        5,154       64.5%
        Gas                                 2,443              1,065       129.4%
        Total                      $       10,921     $        6,219       75.6%

        Average sales price:
        Oil                        $        84.20     $        92.33       (8.8%)
        Gas                        $         4.77     $         4.09       16.6%
        BOE (Bbls)                 $        58.70     $        62.65       (6.3%)

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

Net oil and gas production for the three months ended February 28, 2013 was 186,039 BOE, or 2,067 BOE per day. For the three months ended February 29, 2012, production averaged 1,091 BOE per day, a year over year increase of 87%. As a further comparison, average BOE production was 1,658 per day during the quarter ended November 30, 2012, a quarter over quarter increase of 25%. The significant increases in production from the comparable prior periods reflect the additional wells that began production over the past twelve months and production from the wells acquired in the Orr transaction. The Orr wells provided approximately 320 BOE per day during the quarter. Although production increased significantly, it was somewhat reduced by technical production issues during the period. Sixteen of our new wells entered productive status on February 20, 2013, and only contributed to production for 8 days. Our wells have generally been affected by high line pressures in the gathering system and we have been unable to produce at full capacity. Finally, certain wells were shut-in during the period because of "freeze-ups" in the gas pipeline. Freeze-ups are more common as the ground begins to freeze in the winter. It is caused by water in the line which forms an ice plug that stops the flow of gas. During the quarter, freeze-ups shut in our wells for an aggregate of approximately 1,340 production days.


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

                                                  Three Months Ended
                                                    (in thousands)
                                           February 28,         February 29,
                                               2013                 2012
         Production Costs                 $          637       $          271
         Work-Over                                   144                    -
         Other                                         -                   20
         Lifting cost                                781                  291
         Severance and ad valorem taxes            1,094                  564
         Total LOE                        $        1,875       $          855

         Per BOE:
         Production costs                 $         3.42       $         2.72
         Work-Over                        $         0.77                    -
         Other                                         -                 0.21
         Lifting cost                               4.20                 2.93
         Severance and ad valorem taxes             5.88                 5.68
         Total LOE                        $        10.08       $         8.61

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 February 28, 2013 and 9% for the three months ended February 29, 2012.

On a BOE basis, production costs increased approximately 26% for the quarter ended February 28, 2013 compared to the quarter ended February 29, 2012. The increase is primarily due to costs incurred to mitigate high line pressure within the Wattenberg Field. The Company incurred production costs to provide compression at some well locations and is currently installing additional compression capability. In addition, the Company began a work-over program to improve pressures and flows from the Orr wells.

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

                                                 Three Months Ended
                                                   (in thousands)
                                           February 28,       February 29,
                                               2013               2012
          Depletion                       $        3,117      $       1,513
          Depreciation and amortization               59                 39
          Total DDA                       $        3,176      $       1,552

          DDE expense per BOE             $        17.07      $       15.64


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The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves. The capitalized costs of evaluated oil and gas properties are depleted using the units-of-production method based on estimated reserves. Production volumes for the quarter are compared to beginning of quarter estimated total reserves to calculate a depletion rate. For the three months ended February 28, 2013, production volumes of 186,039 BOE and estimated net proved reserves of 14,630,301 BOE were the basis of the depletion rate calculation. For the three months ended February 29, 2012, production volumes of 99,261 BOE and estimated net proved reserves of 5,085,905 BOE were the basis of the depletion rate calculation. Depletion expense per BOE increased approximately 9.9% primarily as a result of additional DDA associated with the Orr assets.

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

                                                      Three Months Ended
                                                        (in thousands)
                                               February 28,         February 29,
                                                   2013                 2012
     Cash based compensation                  $          700       $          557
     Stock based compensation                            215                  101
     Professional fees                                   194                  187
     Insurance                                            45                   39
     Other general and administrative                    357                  139
     Capitalized general and administrative             (123 )                (86 )
     Totals                                   $        1,388       $          937

     G&A Expense per BOE                      $         7.46       $         9.44

Cash based compensation includes payments to employees. Stock based compensation includes compensation paid to employees, directors and service providers in the form of either stock options, warrants, or restricted stock grants. The amount of expense recorded for stock options and warrants is calculated by using the Black-Scholes-Merton option pricing model. The amount of expense recorded for common stocks grants is calculated based upon the closing market value of the shares. The increase in compensation expense from 2012 to 2013 reflects the expansion of our business, including the addition of new employees. As of February 28, 2013, we employed 14 persons on a full-time basis, compared to 11 persons as of February 29, 2012. Since February 28, 2013, two additional employees have been hired.

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

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

Income taxes - We reported income tax expense of $1.6 million for the three months ended February 28, 2013, representing an effective tax rate of 37%. During the comparable prior year period, we reported a tax benefit of $3.2 million. In 2012, we recognized a tax asset of $4.9 million, representing the one-time benefit of the expected value of the net operating loss carryforward accumulated during our start-up years.


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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.

For the six months ended February 28, 2013, compared to the six months ended February 29, 2012

For the six months ended February 28, 2013, we reported net income of $4.9 million compared to net income of $7.7 million for the six months ended February 29, 2012. Earnings per basic and diluted share were $0.09 for the six months ended February 28, 2013, compared to $0.19 per basic and $0.18 per diluted share for the six months ended February 29, 2012. The comparison between the two years was primarily influenced by increasing revenues and expenses associated with the increased number of producing wells, as well as the effect of deferred income taxes. As of February 28, 2013 we had 278 gross producing wells (220 wells net), compared to 157 gross producing wells (116 wells net) as of February 29, 2012. The 2013 period included tax expense of $2.9 million while the 2012 period included a tax benefit of $3.2 million, for a net difference of $6.1 million. A full explanation of income taxes is provided later in this section.

Oil and Gas Production and Revenues - For the six months ended February 28, 2013 we recorded total oil and gas revenues of $19.2 million compared to $10.7 million for the six months ended February 29, 2012, an increase of $8.5 million or 79%. Our growth in revenue was the result of an increase in our production volume of 86% over the comparative period, and a decrease in our average selling price per BOE of 3%. For the six months ended February 28, 2013, our gas/oil ratio ("GOR") was 46/54. During the comparable prior period, our GOR was 46/54.

Our revenues are sensitive to changes in commodity prices. As shown in the following table, there has been a decrease of 3% in average realized prices between the two periods. To mitigate the impact of short term price fluctuations, we engage in commodity swap and collar transactions. The following table presents actual realized prices, before the effect of hedge transactions.

Key production information is summarized in the following table:

                                           Six Months Ended
                                    February 28,       February 29,
                                        2013               2012          Change
         Production:
         Oil (Bbls)                       180,995             97,227       86.2%
         Gas (McF)                        935,715            504,208       85.6%
         BOE (Bbls)                       336,948            181,262       85.9%

         Revenues (in thousands)
         Oil                       $       14,985     $        8,332       79.8%
         Gas                                4,250              2,366       79.6%
         Total                     $       19,235     $       10,698

         Average sales price:
         Oil                                82.79     $        85.70        -3%
         Gas                                 4.54     $         4.69        -3%
         BOE (Bbls)                         57.09     $        59.02        -3%

"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.


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

                                                   Six Months Ended
                                                    (in thousands)
                                            February 28,      February 29,
                                                2013              2012
           Production Costs                 $       1,160     $         483
           Work-Over                                  144                41
           Other                                        -                68
           Lifting cost                             1,304               592
           Severance and ad valorem taxes           1,908               969
           Total LOE                        $       3,212     $       1,561

           Per BOE:
           Production costs                 $        3.44     $        2.66
           Work-Over                                 0.43              0.23
           Other                                        -              0.37
           Lifting cost                              3.87              3.26
           Severance and ad valorem taxes            5.66              5.35
           Total LOE                        $        9.53     $        8.61

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 six months ended February 28, 2013 and 9% for the six months ended February 29, 2012.

. . .

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