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SYRG > SEC Filings for SYRG > Form 10-Q on 9-Jan-2014All Recent SEC Filings

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Form 10-Q for SYNERGY RESOURCES CORP


9-Jan-2014

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 our financial condition as of November 30, 2013, and our results of operations for the three months ended November 30, 2013 and 2012. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in the Company's Form 10-K for the fiscal year ended August 31, 2013.

Overview

We are a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin ("D-J Basin") of Colorado. Substantially all of our producing wells are either in or adjacent to the Wattenberg Field, which has a history as one of the most prolific production areas in the country. In addition to the approximately 24,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold significant undeveloped acreage positions in (i) an area directly to the north and east of the Wattenberg Field that is considered the northern extension area, (ii) in an area around Yuma County that produces dry gas, and (iii) in western Nebraska. While we do not expect to devote significant resources to the exploration and development of our holdings outside of the Wattenberg Field in the near future, we expect to drill two test wells in the northern extension area.

Since commencing active operations in September 2008, we have undergone significant growth. Our growth was primarily driven by (i) our activities as an operator where we drill and complete productive oil and gas wells; (ii) our participation as a part owner in wells drilled by other operating companies; and
(iii) our acquisition of producing oil wells from other individuals or companies. As disclosed in the following table, as of November 30, 2013, we have completed, acquired, or participated in 361 gross (265 net) successful oil and gas wells. We have not drilled or participated in any dry holes.

                                                PRODUCTIVE WELLS
                          OPERATED WELLS     NON-OPERATED WELLS
                            Completed           Participated       Acquired      Total
Years ended:               Gross    Net        Gross       Net     Gross Net   Gross Net

August 31, 2009              -       -           2          1        -    -      2    1
August 31, 2010             36       28          -          -        -    -     36   28
August 31, 2011             20       19          11         3       72   51     103  73
August 31, 2012             51       48          13         4        4    4     68   56
August 31, 2013             27       26          21         6       36   34     84   66
Nov 30, 2013 (3 months)      5       5           2          -       61   36     68   41

        Total               139     126          49        14       173  125    361  265

In addition to the 361 wells that had reached productive status as of November 30, 2013, we were the operator of eight horizontal wells in progress, including six wells on the Leffler prospect that commenced production after November, and we were participating as a non-operator in seven gross (one net) wells that were in various stages of the drilling or completion process. Wells in progress represent wells during the period of time between spud date and date of first production. Generally, horizontal wells on a six well pad are expected to require 120 to 150 days to drill, complete and connect to the gathering system. All of the wells in progress at November 30, 2013, are expected to commence production during the next six months.


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Strategy

As of November 30, 2013, we:

were the operator of 283 wells that were producing oil and gas and we were participating as a non-operating working interest owner in 78 producing wells;

held approximately 392,000 gross acres and 286,000 net acres under lease;

had estimated proved reserves of 7.3 million barrels ("Bbls") of oil and 41.7 billion cubic feet ("Bcf") of gas;

Our basic strategy for continued growth includes additional drilling activities and acquisition of existing wells in well-defined areas that provide significant cash flow and rapid return on investment. We attempt to maximize our return on assets by drilling in low risk areas and by operating wells in which we have a majority net revenue interest. Our drilling efforts are focused on the Wattenberg Field as it yields consistent results. Until 2012, all of our wells were low risk vertical wells. During 2012, we began to participate with other operators in horizontal wells. The success of those wells, as well as the success of numerous other horizontal wells drilled in this area, convinced us to shift our strategy from vertical wells to horizontal wells. During 2013, we spent the first half of the year drilling vertical wells and spent the second half of the year drilling horizontal wells. Our plans for 2014 contemplate drilling or participating in 39 horizontal wells. Our horizontal wells will primarily target the Niobrara and Codell formations.

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

Significant Developments

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

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

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


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

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

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

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

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

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

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


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RESULTS OF OPERATIONS

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

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

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

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

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

Key production information is summarized in the following table:

                                           Three Months Ended
                                      November 30       November 30
                                         2013              2012           Change
          Production:
          Oil (Bbls)                       168,278            80,301        110 %
          Gas (McF)                        741,755           423,646         75 %
          BOE (Bbls)                       291,904           150,909         93 %

          Revenues (in thousands):
          Oil                        $      15,660     $       6,507        141 %
          Gas                                3,606             1,807        100 %
          Total                      $      19,266     $       8,314        132 %

          Average sales price:
          Oil                        $       93.06     $       81.03         15 %
          Gas                        $        4.86     $        4.27         14 %
          BOE (Bbls)                 $       66.00     $       55.09         20 %

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


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

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

                                                  Three Months Ended
                                            November 30        November 30
                                               2013               2012
          Production Costs                 $       1,203      $         523
          Work-Over                                   70                  -
          Lifting cost                             1,273                523
          Severance and ad valorem taxes           2,016                814
          Total LOE                        $       3,289      $       1,337

          Per BOE:
          Production costs                 $        4.12      $        3.47
          Work-Over                                 0.24                  -
          Lifting cost                              4.36               3.47
          Severance and ad valorem taxes            6.91               5.40
          Total LOE                        $       11.27      $        8.87

Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas. Taxes make up the largest single component of direct costs and tend to increase or decrease primarily based on the value of oil and gas sold. As a percent of revenues, taxes averaged 10% for the three months ended November 30, 2013 and 9% for the three months ended November 30, 2012.

On a BOE basis, production costs increased approximately 19% for the quarter ended November 30, 2013 compared to the quarter ended November 30, 2012. The increase is primarily due to costs incurred to mitigate production difficulties within the Wattenberg Field. We incurred additional costs to provide wellhead compression at some well locations. In addition, we began a work-over program to improve pressures and flows from older wells.


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

                                                  Three Months Ended
                                            November 30        November 30
                                               2013               2012
           Depletion                       $       5,490      $       2,262
           Depreciation and amortization             101                 58
           Total DDA                       $       5,591      $       2,320

           DDA expense per BOE             $       19.15      $       15.37

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

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

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

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

                G&A Expense per BOE   $       10.85      $        7.36


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

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

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

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

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

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

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

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

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

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


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LIQUIDITY AND CAPITAL RESOURCES

Our sources and (uses) of funds for the three months ended November 30, 2013,
and 2012 are summarized below (in thousands):

                                                            Three Months Ended
                                                       November 30       November 30
                                                          2013              2012
Cash provided by operations                           $      14,913     $       2,769
Acquisition of oil and gas properties and equipment         (57,127 )         (12,220 )
Proceeds from short-term investments                         19,987                 -
Equity financing activities                                  23,737               146
Net borrowings                                                    -             2,486
Net increase in cash and cash equivalents             $       1,510     $      (6,819 )

Net cash provided by operating activities was $14.9 million and $2.7 million for the three months ended November 30, 2013 and 2012, respectively. In addition to amounts reclassified from short term investments based upon the proceeds received with the investments matured, we received $23.7 million from the exercise of Series C warrants at $6.00 per share.

The cash flow statement reports actual cash expenditures for capital expenditures using a strict cash flow basis, which differs from the "all-inclusive" basis used to calculate other amounts reported in our financial statements. Specifically, cash payments for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On the "all-inclusive" basis, capital expenditures totaled $69.0 million and $15.8 million for the three months ended November 30, 2013 and 2012, respectively, compared to cash payments of $57.1 million and $12.2 million, respectively. A reconciliation of the differences is summarized in the following table (in thousands):

                                                      Three Months Ended
                                                 November 30       November 30
                                                    2013              2012
. . .
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