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SYRG > SEC Filings for SYRG > Form 10-K/A on 20-Jun-2014All Recent SEC Filings

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Form 10-K/A for SYNERGY RESOURCES CORP


20-Jun-2014

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, 2013, and the results of operations for the years ended August 31, 2013, 2012 and 2011. 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

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 22,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold significant undeveloped acreage positions in (i) the northern extension area of the D-J Basin, (ii) in an area around Yuma County that produces dry gas, and (iii) in western Nebraska. While we do not expect to devote significant resources to the exploration and development of our holdings outside of the Wattenberg Field in the near future, we recently participated in a well in Yuma County that is producing dry gas and we expect to drill two test wells in the northern extension area.

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 August 31, 2013, we have completed, acquired, or participated in 293 gross (224 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

     Total             134        121            47             14        112       89        293       224

In addition to the 293 wells that had reached productive status as of August 31, 2013, we were the operator of seven horizontal wells in progress, including five wells on the Renfroe prospect that commenced production during the first week of September, and we were participating as a non-operator in nine 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 are expected to require 120 to 150 days to drill, complete and connect to the gathering system. All of the wells in progress at August 31, 2013, are expected to commence production during our first or second fiscal quarter of 2014.


As of August 31, 2013, we:

were the operator of 218 wells that were producing oil and gas and we were participating as a non-operating working interest owner in 75 producing wells;

held approximately 374,000 gross acres and 245,000 net acres under lease;

had estimated proved reserves of 7.0 million barrels ("Bbls") of oil and 40.7 billion cubic feet ("Bcf") of gas;

on a BOE basis, increased our estimated proved reserves by 30% during fiscal 2013; and

on a PV-10 basis, increased our estimated proved reserves by 59% during fiscal 2013

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 25 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.


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, 2013, compared to the year ended August 31, 2012

For the year ended August 31, 2013, we reported net income of $9.6 million, or $0.17 per basic share, $0.16 per diluted share, compared to net income of $12.1 million, or $0.26 per basic share and $0.25 per diluted share for the period ended August 31, 2012. The decline in net income for 2013 reflects significant non-cash charges for an unrealized loss of $2.6 million on our commodity derivatives and a provision for deferred income taxes of $6.9 million.

There was an improvement in operating income, which increased from $11.8 million in 2012 to $19.5 million. Our 66% improvement in operating profitability was driven by our successful drilling program and integration of producing wells added in the Orr Energy acquisition. The significant variances between the two years were primarily caused by increased revenues and expenses associated with a greater number of producing wells. The following discussion expands upon significant items of inflow and outflow that affected results of operations

Oil and Gas Production and Revenues - For the year ended August 31, 2013, we recorded total revenues of $46.2 million compared to $25.0 million for the year ended August 31, 2012, an increase of $21.2 million or 85%. We experienced an overall 84% annual increase in production quantities 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 with the December 2012 Orr Energy acquisition.

                                             Years Ended August 31,
                                              2013            2012
                Production:
                 Oil (Bbls1)                   421,265         235,691
                 Gas (Mcf2)                  2,107,603       1,109,057

                Total production in BOE3       772,532         420,534

                Revenues (in thousands):
                 Oil                       $    36,206     $    20,644
                 Gas                            10,017           4,325
                  Total                    $    46,223     $    24,969

                Average sales price:
                 Oil (Bbls1)               $     85.95     $     87.59
                 Gas (Mcf2)                $      4.75     $      3.90
                 BOE3                      $     59.83     $     59.38

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, 2013, we owned interests in 293 producing wells. Net oil and gas production averaged 2,117 BOE per day in 2013, as compared with 1,149 BOE per day for 2012, a year over year increase of 84% in BOEPD production. The significant increase in production from the prior year reflects 84 additional wells that went into productive status during 2013 and a full year of production from the 68 wells that were added over the course of fiscal year 2012. Production for the fourth fiscal quarter of 2013 averaged 2,479 BOE per day.

Revenues are sensitive to changes in commodity prices. From 2012 to 2013, our realized annual average sales price per barrel of oil decreased 2%; however, we experienced an increase of 22% in our realized annual average sales price per Mcf of natural gas. Overall on a BOE basis, 99% of the increase in oil and gas revenues was attributed to increased volumes and 1% was attributed to the increase of BOE prices received.

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

                                             Years Ended August 31,
               Lease Operating Expenses      2013              2012
               Lifting costs              $     3,198       $     1,146
               Work-over                          219                66
                  Total LOE               $     3,417       $     1,212
               LOE per BOE                $      4.42       $      2.88




                                                Years Ended August 31,
            Production Taxes                    2013              2012
            Severance and ad valorem taxes   $     4,237       $     2,436
            Production taxes per BOE         $      5.48       $      5.79

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 2012 to 2013, 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 9.2% in 2013 and 9.8% 2012.

Depletion, Depreciation and Amortization ("DDA") - The following table summarizes the components of DDA. Depletion expense more than doubled, primarily as a result of growth in production and producing properties from 2012 to 2013.

                                               Years ended August 31,
             (in thousands)                      2013             2012
             Depletion                       $     13,046       $  5,838
             Depreciation and amortization            290            172
             Total DDA                       $     13,336       $  6,010

             DDA expense per BOE             $      17.26       $  14.29

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 2013, our depletable reserve base was 14,829,487 BOE. Fiscal year 2013 production represented 5.2% of the reserve base.

Depletion expense per BOE increased 21% from 2012 to 2013. For the fiscal year ended August 31, 2013, depletion of oil and gas properties was $17.26 per BOE compared to $14.29 for the fiscal year ended August 31, 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:

                                          Years Ended August 31,
                 (in thousands)           2013              2012
                 G&A costs incurred    $     6,325       $     3,902
                 Capitalized costs            (637 )            (345 )
                   Total G&A           $     5,688       $     3,557

                 G&A Expense per BOE   $      7.36       $      8.46

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 16 employees, and use consultants, advisors, and contractors to perform certain tasks when it is cost-effective. We maintain our corporate office in Platteville, CO partially to avoid higher rents in other areas.

Although G&A costs have increased as we grow the business we strive to maintain an efficient overhead structure. For the fiscal year ended August 31, 2013, G&A was $7.36 per BOE compared to $8.46 for the fiscal year ended August 31, 2012.

Our G&A expense for 2013 includes share based compensation of $1,362,000. The comparable amount for 2012 was $473,000. 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 2013. Substantially all of the 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.

Beginning in 2013, we entered into commodity derivative contracts for the future sale of oil. We designed our derivative activity to protect our cash flow during periods of oil price declines. Using swaps and collars, we have hedged 340,000 barrels of future production for the next 22 months. Generally, contracts are based upon a reference price indexed to trading of West Texas Intermediate Crude Oil on the NYMEX. During the year ended August 31, 2013, the average index prices were higher than our average contract prices, and we realized a loss of $0.4 million for the year. As of August 31, 2013, the weighted average future index prices were $101.81 per barrel, approximately $7.64 higher than our contract price, creating an unrealized loss of $2.6 million at the end of the year.

Our commodity derivative contracts are revalued at fair value for each reporting period, and changes in the value of the contracts can have a significant impact on reported results of operations


Income Taxes - We reported income tax expense of $6.9 million for the fiscal year ended August 31, 2013. All of the tax liability will be deferred into future years, and it does not appear that any federal or state payments will be required for 2013. During 2012, we reported a net deferred tax benefit of $332,000, essentially representing a future refund, to record the benefit arising from the net operating loss carry-forward (NOL).

For tax purposes, we have a NOL of $41 million which will begin to expire, if not utilized, in year 2031. For book purposes, the NOL is $31 million, as there is a difference of $10 million related to deductions for stock based compensation.

For 2013, we reported an effective tax rate of 42%. Our estimated effective tax rate for future periods, based upon current tax laws, is 37%. The difference reflects several differences between book income and tax income, including adjustments for statutory depletion and an adjustment to the stock based compensation component included in our inventory of deferred tax assets. During 2013, we reversed the timing difference created for the future deduction of stock based compensation when the underlying options expired. Potential tax deductions for compensation are eliminated whenever options expire without exercise.

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 in 2012 we eliminated our entire valuation allowance of $4.9 million. 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.


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 $12.1 million, or $0.26 per share, $0.25 per diluted share, compared to a net loss of $(11.6) million, 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 $24.9 million compared to $10.0 million for the year ended August 31, 2011, an increase of $14.9 million 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.

                                             Years 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 (in thousands):
                 Oil                       $      20,644     $   7,470
                 Gas                               4,325         2,308
                  Total                    $      24,969     $   9,778

                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:

                                                 Years ended August 31,
           (in thousands)                        2012              2011
           Production costs                   $     1,146       $       351
           Work-over                                   66                87
           Other                                        -                46
             Lifting cost                           1,212               484
             Severance and ad valorem taxes         2,436               956
              Total LOE                       $     3,648       $     1,440

           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") - The following table summarizes the components of DDA. Depletion expense more than doubled, primarily as a result of growth in production and producing properties from 2011 to 2012.

                                               Years ended August 31,
            (in thousands)                     2012              2011
            Depletion                       $     5,838       $     2,743
            Depreciation and amortization           172                95
              Total DDA                     $     6,010       $     2,838

            DDA expense per BOE             $     14.29       $     17.19

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 . . .

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