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SYRG > SEC Filings for SYRG > Form 10-K on 14-Nov-2012All Recent SEC Filings

Show all filings for SYNERGY RESOURCES CORP

Form 10-K for SYNERGY RESOURCES CORP


14-Nov-2012

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to explain certain items regarding the financial condition as of August 31, 2012, and the results of operations for the years ended August 31, 2012, 2011 and 2010. It should be read in conjunction with the "Selected Financial Data" and the accompanying audited financial statements and related notes thereto contained in this annual report on Form 10-K.

This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the "Cautionary Note Regarding Forward-Looking Statements" at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in the subsection entitled "Risk Factors" above, which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

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. During 2011, we expanded 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 August 31, 2012, we have drilled, acquired, or participated in 209 gross oil and gas wells and have successfully completed 191 wells that were in production. There were 18 wells in progress at August 31, 2012.

                          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
          Total         107             97            26               18             76


As of August 31, 2012, we:

were the operator of 146 wells that were producing oil and gas and the operator of 10 wells that were in the completion process and we were participating as a non-operating working interest owner in 45 producing wells and 8 wells that were in progress;

held approximately 222,085 gross acres and 187,751 net acres under lease; and

had estimated proved reserves of 5.1 million barrels ("Bbls") of oil and 33.4 billion cubic feet ("Bcf") of gas.

Estimated BOE proved reserves increased 140% during the fiscal year 2012, primarily as a result of the success achieved under the 2012 drilling program.

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. However, the increased pace of horizontal drilling activity in the D-J Basin by numerous operators has provided us with the opportunity to witness best practices in the industry first hand. Consequently, we agreed to participate in our first horizontal well, which began drilling operations in January 2012 and commenced production in March 2012. The introduction of horizontal drilling to the D-J Basin has accelerated the retrieval of natural gas reserves in the Niobrara Shale and Codell formations. We subsequently agreed to participate in additional horizontal wells. By the end of August, we were a participant in three horizontal wells that were in production, two wells that were in the completion phase and one well that was in the drilling phase. We expect to participate in additional horizontal wells and we are preparing to drill and operate horizontal wells for our own account during our 2013 fiscal year.

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.

Results of Operations

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

For the year ended August 31, 2012, compared to the year ended August 31, 2011

For the year ended August 31, 2012, we reported net income of $12,123,942, or $0.26 per share, $0.25 per diluted share, compared to a net loss of $(11,600,158), or $(0.45) per basic and diluted share for the period ended August 31, 2011.


Our rapid improvement in profitability was driven by our successful drilling program. The significant variances between the two years are (i) increased revenues and expenses associated with more producing wells, (ii) the cessation of certain interest and other non-cash expenses, and (iii) the effect of income taxes. As further explained below, our net loss for 2011 resulted from non-cash charges related to the convertible promissory notes and the derivative conversion liability. The following discussion also expands upon items of inflow and outflow that affect operating income.

Oil and Gas Production and Revenues - For the year ended August 31, 2012, we recorded total revenues of $24,969,213 compared to $10,001,668 for the year ended August 31, 2011, an increase of $14,967,545 or 150%. We experienced an overall 151% annual increase in production from the prior year having realized a full year of production from wells at the beginning of the year, and the addition of wells, including new wells drilled as well as those acquired. Although there was significant commodity price fluctuation during the year, overall pricing on a BOE basis was not significantly different from 2011 to 2012. For the fiscal year ended August 31, 2012, our gas / oil ratio ("GOR") on a BOE basis was 44/56 compared to 45/55 for the fiscal year ended August 31, 2011.

                                             Year Ended August 31,
                                              2012            2011
               Production:
                Oil (Bbls1)                    235,691          89,917
                Gas (Mcf2)                   1,109,057         450,831

               Total production in BOE3        420,534         165,056

               Revenues:
                Oil                       $ 20,643,863     $ 7,469,709
                Gas                          4,325,350       2,307,463
                  Total                   $ 24,969,213     $ 9,777,172

               Average sales price:
                Oil (Bbls1)               $      87.59     $     83.07
                Gas (Mcf2)                $       3.90     $      5.12
                BOE3                      $      59.38     $     59.24

1 "Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.

2 "Mcf" refers to one thousand cubic feet of natural gas.

3 "BOE" refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

As of August 31, 2012, we had 191 producing wells. Net oil and gas production averaged 1,149 BOE per day in 2012, as compared with 452 BOE per day for 2011, a year over year increase of 154% in BOEPD production. The significant increase in production from the prior year reflects 52 additional wells that went into productive status since August 31, 2011 and a full year of production from the 111 wells that were added over the course of fiscal year 2011. Production for the fourth fiscal quarter of 2012 averaged 1,270 BOE per day.


Revenues are sensitive to changes in commodity prices. From 2011 to 2012, our realized annual average sales price per barrel of oil rose 5%; however, we experienced a decline of 24% in our realized annual average sales price per Mcf of natural gas. There was a 45% and 130% swing in the price of crude and natural gas from the respective low to high prices during the twelve month period ended August 31, 2012. Barrel and Mcf prices at year end were up 2% and down 9%, respectively, from twelve month average. We did not utilize any commodity price hedges during either year, but expect to do so in the future.

While our balanced production mix of oil and gas and the high liquid content of our gas help to mitigate the negative effect of volatility in commodity prices, downward price pressure could have a negative effect on revenues reported in future periods.

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:

                                                  Year ended August 31,
                                                  2012            2011
            Production costs                   $ 1,146,294     $   350,853
            Work-over                               66,431          86,797
            Other                                        -          46,463
              Lifting cost                       1,212,725         484,113
              Severance and ad valorem taxes     2,435,740         955,705
                Total LOE                      $ 3,648,465     $ 1,439,818

            Per BOE:
            Production costs                   $      2.73     $      2.13
            Work-over                                 0.16            0.53
            Other                                        -            0.28
              Lifting cost                            2.89            2.94
              Severance and ad valorem taxes          5.79            5.79
                Total LOE per BOE              $      8.68     $      8.73

Lease operating and work-over costs tend to fluctuate with the number of producing wells, and, to a lesser extent, on variations in oil field service costs and changes in the production mix of crude oil and natural gas. From 2011 to 2012, we experienced an increase in production cost per BOE in connection with additional costs to bolster output from some of our older wells. Taxes, the largest component of lease operating expenses, generally move with the value of oil and gas sold. As a percent of revenues, taxes averaged 10% in both 2012 and 2011.

Depletion, Depreciation and Amortization ("DDA") - We recognized DDA expense of $6,009,510 and $2,838,307 for the fiscal years ended August 31, 2012 and 2011, respectively, of which $5,837,788 and $2,743,441 was the depletion of oil and gas properties for 2012 compared to 2011. Depletion expense more than doubled, primarily as a result of growth in production and producing properties from 2011 to 2012.


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 fiscal year 2012, our depletable reserve base was 5,321,502 barrels of oil and 34,555,031 Mcf of natural gas. Fiscal year 2012 production represented 4% and 3% of those reserve bases, respectively.

Depletion expense per BOE declined 16% from 2011 to 2012. For the fiscal year ended August 31, 2012, depletion of oil and gas properties was $13.88 per BOE compared to $16.62 for the fiscal year ended August 31, 2011. During 2012, we have been able to increase reserves and production faster than the increase in capitalized costs, which caused the decline in the expense per BOE.

General and Administrative ("G&A") - The following table summarizes the components of general and administration expenses:

                                                     Year Ended August 31,
                                                     2012            2011
         Cash based compensation                  $ 1,901,296     $ 1,260,688
         Share based compensation                     473,040         627,486
         Professional fees                            953,162         716,210
         Insurance                                    136,167          78,127
         Other general and administrative             438,425         427,025
         Capitalized general and administrative      (345,343 )      (206,233 )
            Total G&A                             $ 3,556,747     $ 2,903,303

Although G&A costs increased during 2012, they increased at a lower rate than the overall growth of our business, as we strive to maintain an efficient overhead structure. For the fiscal year ended August 31, 2012, G&A was $8.46 per BOE compared to $17.59 for the fiscal year ended August 31, 2011.

Cash based compensation and benefits include payments to employees and directors. Share based compensation is associated with compensation in the form of either stock options or common stock grants for employees, directors, and service providers. The amount of expense recorded for stock options is calculated using the Black-Scholes-Merton option pricing model, while the amount of expense recorded for common stock grants is calculated based upon the closing market value of the shares on the date of grant.

Professional fees have increased as we have grown our business. The two primary factors driving this increase are the additional accounting and auditing fees incurred in connection with operating as a public company, and the additional professional services required to meet the compliance requirements of the Sarbanes-Oxley Act, as we have progressed from a smaller reporting company to an accelerated filer under SEC definitions. The listing on the NYSE: MKT contributed to costs in excess of those reported in the comparable prior year period when our stock was listed on the OTC Bulletin Board.


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.

Operating Income (Loss) - For the year ended August 31, 2012, we generated operating income of $11,754,491, compared to $2,820,240 for the year ended August 31, 2011. This tri-fold increase in operating income resulted primarily from the increasing contribution of wells brought into production during the last two years, which includes wells drilled under the 2012 and 2011 drilling programs, the acquisition of producing properties from PEM and other parties, and increased production from older wells that were recompleted using newer hydraulic fracturing techniques. Increased revenues more than offset increased costs incurred by us to accomplish these objectives.

Other Income (Expense) - Other income for the fiscal year ended August 31, 2012 was $37,451, consisting solely of interest income. Interest cost of $208,344 was incurred during 2012, all of which was capitalized as part of the cost of oil and gas properties. For the fiscal year ended August 31, 2011, we reported several significant items of expense in addition to interest income of $55,776. These other expenses reported in 2011 primarily related to our convertible promissory notes, including net interest expense of $589,539, accretion of debt discount of $2,664,138, amortization of debt issuance costs of $1,587,799, and a change in the fair value of the derivative conversion liability of $10,229,229. During 2011, interest expense was also recorded on the related party note and the bank line of credit in the amounts of $74,047 and $41,559, respectively. Of these expenses, we capitalized interest and amortization of $710,137.

The convertible promissory notes contained a conversion feature which was considered an embedded derivative and recorded as a liability at its initial estimated fair value. This derivative conversion liability was then marked-to-market over time, with the resulting change in fair value recorded as a non-cash item in the statement of operations. All expenses related to the convertible promissory notes ceased mid-year 2011, as all noteholders converted their holdings into equity.

Income Taxes - We reported income tax expense of $4,579,000 offset by a tax benefit of $4,911,000 for the fiscal year ended August 31, 2012, resulting in a net income tax benefit of $332,000 and a corresponding net deferred tax asset in the same amount. For all reporting periods prior to 2012, no income tax expense or benefit was reported, as all tax assets or liabilities were effectively offset by a valuation allowance.

The income tax benefit is a one-time event representing the expected value of the future deduction of the net operating loss carry-forward generated during our start-up years.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome. During the current fiscal year, 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 we released our entire valuation allowance of $4,911,000. Prior to 2012, management concluded that it was more likely than not that our net deferred tax asset would not be realized in the foreseeable future and, accordingly, a full valuation allowance was provided against the net deferred tax asset.


During 2012 management concluded that positive indicators outweighed negative indicators and that it was appropriate to release the valuation allowance. Although we reported net losses every year since inception through August 31, 2011, we attributed all of the net losses for the 2011 and 2010 fiscal years to a single discrete item. The discrete item was the fair value accounting treatment of the components of the convertible promissory notes issued in 2010, which created non-cash expenses for accretion of debt discount, amortization of issuance costs, and change in fair value of derivative liability. As all of the convertible notes were converted, those expenses will not recur, and it is appropriate to exclude them from a consideration of future profitability. Secondly, we had begun to report net income and had significantly increased oil and gas reserve values. Lastly, we completed a debt financing arrangement and an equity financing arrangement that allow us to continue with our operating plan. Accordingly, we believed that it was appropriate to release the valuation allowance related to the deferred tax asset created by the net operating loss carryover.

Future reporting periods are expected to report income tax expense at an estimated effective tax rate of approximately 37%.

For the year ended August 31, 2011, compared to the year ended August 31, 2010

For the year ended August 31, 2011, we reported a net loss of $(11,600,158), or $(0.45) per share, compared to a net loss of $(10,794,172), or $(0.88) per share for the period ended August 31, 2010. As explained below, the net loss for each year is significantly affected by non-cash charges related to the convertible promissory notes and the derivative conversion liability. The following discussion also expands upon items of inflow and outflow that affect operating income. In most cases, the nature of the change from 2010 to 2011 involves the significant growth in number of producing properties and activities to acquire additional undeveloped acreage and proved properties.

Oil and Gas Production and Revenues - For the year ended August 31, 2011, we recorded total oil and gas revenues of $9,777,172 compared to $2,158,444 for the year ended August 31, 2010, as summarized in the following table:

                                             Year Ended August 31,
                                             2011            2010
                Production:
                 Oil (Bbls1)                   89,917          21,080
                 Gas (Mcf2)                   450,831         141,154

                Total production in BOE       165,056          44,606

                Revenues:
                 Oil                      $ 7,469,709     $ 1,441,562
                 Gas                        2,307,463         716,882
                   Total                  $ 9,777,172     $ 2,158,444

                Average sales price:
                 Oil (Bbls1)              $     83.07     $     68.38
                 Gas (Mcf2)               $      5.12     $      5.08

1 "Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.

2 "Mcf" refers to one thousand cubic feet of natural gas.

3 "BOE" refers to barrel of oil equivalent, which 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 year ended August 31, 2011, was 165,056 BOE, or 452 BOE per day, as compared with 44,606 BOE, or 122 BOE per day, for the year ended August 31, 2010. The significant increase in production from the prior year resulted from realizing a full year of production from wells at the beginning of the year, and the addition of wells, including new wells drilled and those acquired in the PEM acquisition. Production for the fourth fiscal quarter of 2011 averaged 577 BOE per day.

Lease Operating Expenses - As summarized in the following table, our lease expenses include the direct operating costs of producing oil and natural gas, taxes on production and properties, and well work-over costs:

                                                 Year ended August 31,
                                                   2011           2010
            Production costs                   $    350,853     $  86,554
            Work-over                                86,797             -
            Other                                    46,463             -
              Lifting cost                          484,113       386,554
              Severance and ad valorem taxes        955,705       236,966
                Total LOE                      $  1,439,818     $ 323,520

            Per BOE:
            Production costs                   $       2.13     $    1.94
            Work-over                                  0.53             -
            Other                                      0.28             -
              Lifting cost                             2.94          1.94
              Severance and ad valorem taxes           5.79          5.31
                Total LOE per BOE              $       8.73     $    7.25

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 tend to increase or decrease primarily based on the value of oil and gas sold, and, as a percent of revenues, averaged 10% in 2011 and 11% in 2010.


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

                                                       Year ended August 31,
                                                         2011           2010
      Depletion - oil and gas assets                 $  2,743,441     $ 692,274
      Depreciation and amortization - other assets         57,138         7,592
      Accretion of asset retirement obligations            37,728         1,534
          Total DDA                                  $  2,838,307     $ 701,400

      Depletion expense per BOE                      $      16.62     $   15.52

The determination of depletion, depreciation and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves and actual production volumes. As of August 31, 2011, we had 4,446,565 BOE of estimated net proved reserves compared to 1,423,524 BOE of estimated net proved reserves as of August 31, 2010. Depletion expense per BOE increased approximately 7% as a result of cost increases across all of our operating sectors, including costs incurred for lease acquisition, drillings, and well completion.

Impairment of Oil and Gas Properties - We use the full cost accounting method, which requires recognition of impairment when the total capitalized costs of oil and gas properties exceed the "ceiling" amount, as defined in the full cost accounting literature. During the years ended August 31, 2011 and 2010, no impairment was recorded because our capitalized costs subject to the ceiling test were less than the estimated future net revenues from proved reserves discounted at 10% plus the lower of cost or market value of unevaluated properties. The ceiling test is performed each quarter and there is the possibility for impairments to be recognized in future periods. Once impairment is recognized, it cannot be reversed.

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

                                                     Year Ended August 31,
                                                     2011            2010
         Cash based compensation                  $ 1,260,688     $   536,627
         Share based compensation                     627,486         581,233
. . .
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