10-K 1 syrg_10k-083113.htm FORM 10-K FOR THE FISCAL YEAR ENDED 8/31/2013 syrg_10k-083113.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended August 31, 2013

OR

 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

 SYNERGY RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
 
COLORADO
20-2835920
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
20203 Highway 60,  Platteville, CO
80651
 (Address of principal executive offices) 
 (Zip Code)
 
Registrant's telephone number, including area code: (970) 737-1073

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
 
Name of each exchange on which registered
Common Stock
 
NYSE MKT

Securities registered pursuant to Section 12(g) of the Act:
 _______________
(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o  No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No x

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.

Persons who respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number.

 
 
 
 
Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such filing). Yes x  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's  knowledge,  in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 
Large accelerated filer  o
Accelerated filer  x
   
Non-accelerated filer  o   (Do not check if a smaller reporting company)    
Smaller reporting company  o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act):  Yes o  No x

The aggregate market value of the voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on February 28, 2013, was approximately $309 million.  Shares of the registrant’s common stock held by each officer and director and each person known to the registrant to own 10% or more of the outstanding voting power of the registrant have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not a determination for other purposes.

As of October 31, 2013, the Registrant had 74,391,364 issued and outstanding shares of common stock.



 
 
 
 

PART I

Cautionary Statement Concerning Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as “believes”, “expects”, “anticipates”, “intends”, “plans”, “estimates”, “should”, “likely” or similar expressions, indicates a forward-looking statement.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:
 
▪   
The success of our exploration and development efforts;

▪   
The price of oil and gas;
 
▪   
The worldwide economic situation;
 
▪   
Any change in interest rates or inflation;
 
▪   
The willingness and ability of third parties to honor their contractual commitments;
 
▪   
Our ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital;
 
▪   
Our capital costs, as they may be affected by delays or cost overruns;
 
▪   
Our costs of production;
 
▪   
Environmental and other regulations, as the same presently exist or may later be amended;
 
▪   
Our ability to identify, finance and integrate any future acquisitions; and
 
▪   
The volatility of our stock price.
 
ITEM 1.  BUSINESS

Overview
 
 We are an oil and gas operator in Colorado and are focused on the acquisition, development, exploitation, exploration and production of oil and natural gas properties primarily located in the Denver-Julesburg Basin (“D-J Basin”) in northeast Colorado.  We have concentrated on drilling and completing wells located in the Wattenberg Field, an area within the D-J Basin, which has a prolific production history.  We serve as the operator for most of our wells and focus our efforts on those prospects in which we have a significant net revenue interest.  As of October 31, 2013, we had 374,000 gross and 245,000 net acres under lease, substantially all of which are located in the D-J Basin.  Of this acreage, 12,550 gross acres are held by production.
 
 We commenced active operations in the D-J Basin in 2008.  Between September 1, 2008 and August 31, 2013, we completed, participated or otherwise acquired an interest in 293 gross (224 net) producing oil and gas wells.  We are the operator of 218 wells and participate with other operators in 75 wells.  In addition to the wells that had reached productive status at the end of our fiscal year, there are 16 gross (8 net) wells in various stages of drilling or completion as of August 31, 2013.  There have been no dry holes.  

 
1

 
At August 31, 2013, our estimated net proved oil and gas reserves, as prepared by our independent reserve engineering firm, Ryder Scott Company, L.P., were 7.0 MMBbls of oil and condensate and 40.7 Bcf of natural gas.

Business Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves and cash flow through acquisitions, development, exploitation, exploration and divestiture of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures in a combination of lower risk development and exploitation activities and higher potential exploration prospects. Key elements of our business strategy include the following:

·  
Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience.  All of our current wells are located within the D-J Basin and our undeveloped acreage is located either in or adjacent to the D-J Basin.  Focusing our operations in this area leverages our management, technical and operational experience in the basin.
 
·  
Develop and exploit existing oil and natural gas properties.  Since inception our principal growth strategy has been to develop and exploit our acquired and discovered properties to add proved reserves.  In the Wattenberg Field, we target three formations, the Niobrara, the Codell, and the J-Sand.  We selectively target the zones most likely to yield the greatest return on investment, and leave certain zones “behind pipe” for future extraction.  However our future plans will focus on horizontal development of our assets in the Wattenberg Field as we believe horizontal development can increase the potential recovery of hydrocarbons significantly when compared to conventional vertical drilling.  We consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential wells.  There is enough similarity between wells in the Field that the exploitation process is generally repeatable.
 
·  
Complete selective acquisitions.  We seek to acquire undeveloped and producing oil and gas properties, primarily in the D-J Basin and certain adjacent areas.  We will seek acquisitions of undeveloped and producing properties that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation opportunities.
 
·  
Retain control over the operation of a substantial portion of our production. As operator on a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled or existing wells to be recompleted.  This allows us to modify our capital spending as our financial resources allow and market conditions support.

·  
Maintain financial flexibility while focusing on controlling the costs of our operations.  We intend to finance our operations through a mixture of debt and equity capital as market conditions allow.  Our management has historically been a low cost operator in the D-J Basin and we continue to focus on operating efficiencies and cost reductions.

·  
Use the latest technology to maximize returns.  Drilling horizontal wells is expected to significantly increase our future production and the value of our asset base.  Latest industry practices are drilling horizontal wells in the Wattenberg Field in increasing density and technical advancements in completing these wells is leading to enhanced productivity.  We have identified an additional 600 potential horizontal wells in the Niobrara and Codell formations on existing Wattenberg acreage and over 125 potential horizontal well locations in the Greenhorn and Niobrara formations in the Northern D-J Basin acreage.  Of these locations, 71 are in the drilling permit process.
 
 
2

 
Competitive Strengths
 
We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:

·  
Management experience.  Our key management team possesses an average of thirty years of experience in oil and gas exploration and production, primarily within the D-J Basin.  
 
·  
Balanced oil and natural gas reserves and production.  At August 31, 2013, approximately 51% of our estimated proved reserves were oil and condensate and 49% were natural gas and liquids, measured upon a BTU equivalent basis.  We believe this balanced commodity mix will provide diversification of sources of cash flow and will lessen the risk of significant and sudden decreases in revenue from short-term commodity price movements.
 
·  
Ability to recomplete D-J Basin wells numerous times throughout the life of a well.  We have experience with and knowledge of D-J Basin wells that have been recompleted up to three times since initial drilling.  This provides us with numerous high return recompletion investment opportunities on our current and future wells and the ability to manage the production through the life of a well.
 
·  
Low cost operator.  We have successfully demonstrated our ability to drill wells for lower costs than our major competitors and to successfully integrate acquired assets without incurring significant increases in overhead.
 
 

 
 
3

 
Recent Developments

We expanded our business during the fiscal year ended August 31, 2013.  We increased our producing wells, our reserves, and our undeveloped acreage.  Significant developments are described below.

As an operator, we began our transition from vertical drilling to horizontal drilling.

During the first half of the fiscal year, we continued our active vertical well drilling program.  We substantially completed our 2013 plans for drilling vertical wells during the second quarter.  From September 1, 2012, through December 31, 2012, we drilled 27 new vertical wells and brought all of them into productive status during the first half of the fiscal year.

During the year, our efforts shifted to horizontal wells.  In May 2013 drilling operations commenced on the first horizontal well at our Renfroe prospect.  By the end of August, we had substantially completed all five wells planned for the initial phase the Renfroe pad.  All wells commenced production during the first week in September.  The wells were included in the reserve report as of August 31, 2013, where they were classified as proved non-producing wells.  Drilling operations on our second horizontal prospect, the Leffler, commenced during the fiscal fourth quarter and continued into the first fiscal quarter of 2014.  Drilling operations for the six wells initially planned for the Leffler prospect were substantially concluded by the end of October and the wells are scheduled for completion activities during November and December 2013.

Our first horizontal wells are being drilled under a contract with Ensign United States Drilling, Inc.  The contract, as amended, covers the use of one rig to drill a total of 25 wells.  Pricing is on a turn-key basis, with pricing adjustments based upon well location, target formation, and other technical details.  Assuming that the rig continues to drill approximately two horizontal wells per month, we anticipate completion of the current contract during the summer of 2014.

We continued our participation with other operators in vertical and horizontal wells in which we own a partial interest.  During 2012, we participated in 5 gross (1 net) horizontal wells that commenced production.  During 2013, the number of non-operated horizontal wells that commenced production increased to 11 gross (2.4 net).  In addition, as of August 31, 2013, we were participating in 8 gross (1 net) horizontal wells that were in various stages of drilling or completion.  Furthermore, by the end of October, we had received either an AFE (Authorization for Expenditure) or a preliminary drilling notification on 70 horizontal wells that may be drilled in 2014 and future years.  Our participation with other operators in vertical wells also increased during 2013, as 10 gross (3.7 net) wells commenced production.

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 $29 million and 3,128,422 shares of our restricted common stock.  Our evaluation of the net assets indicates that the fair value of the acquisition approximates $42 million.  Revenues and expenses from the Orr properties were consolidated with our operations commencing on December 5, 2012.

As a result of our drilling activities, our acquisition activities, and our participation activities, we increased our proved reserve quantities by 30% during the year.  The August 31, 2013, reserve report indicated that we had estimated proved reserves of 7.0 million barrels of oil and 40.7 billion cubic feet of gas.  The estimated present value of future cash flows before tax (discounted at 10%) was $236 million.

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 seen increasing drilling activity by other oil and gas companies.  Vecta, a firm which has considerable technical acumen in geology and geophysics, will provide their scientific expertise while we provide our expertise as oil and gas operators.  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 for more than 19,000 acres in the Northern DJ Basin is approximately $400 per acre.  The leases have an average remaining term of three years and contain renewal options that will allow us to extend the term of the leases for another two or three years at a cost of less than $100 per acre.    Lastly, the area has potential for multiple pay formations, including the Greenhorn, Niobrara, D Sand and J Sand.

 
4

 
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.  Maximum borrowings are subject to reduction based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports.  Based upon the semi-annual redetermination derived from the February 28, 2013 reserve report, the borrowing base limitation was increased from $47 million to $75 million.  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.

In December, we utilized a portion of the financing available through this arrangement to fund the acquisition of the Orr assets.  We currently have approximately $38 million available for future borrowings if needed.  Additional borrowings, if any, are expected to be used to fund acquisitions, expenditures for well drilling and development, 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.

During June 2013, we completed the sale of 13.2 million shares of our common stock at a price to the public of $6.25 per share for net proceeds totaling approximately $78.3 million after deduction of discounts, commissions and expenses.  The public offering of additional shares of our common stock was underwritten by a syndicate of investment bank led by Johnson Rice LLC.

We commenced our commodity derivative program beginning January 1, 2013.  Using swaps and collars, we contracted for approximately 340,000 barrels of oil through June 30, 2015.  The average price of our swap positions is approximately $96 per barrel for the remainder of calendar year 2013, $92 per barrel for calendar year 2014, and $86 per barrel for the first half of calendar year 2015.  Since we designed our commodity derivative activity to protect our cash flow during periods of oil price declines, the high average prices experienced during 2013 created a realized loss of $0.4 million for the year, and an unrealized decrease in the fair value of our commodity derivatives of $2.6 million.

We announced two pending transactions to acquire mineral interests.  In the aggregate, the agreements cover the acquisition of interests in 59 gross producing wells that we will operate, plus various other assets.  Subject to satisfactory completion of due diligence activities and all other conditions precedent, closings are scheduled for the first quarter of fiscal year 2014.  The transactions contemplate aggregate consideration of $37 million, including approximately $7 million payable in the form of shares of restricted common stock.  All amounts are subject to customary closing and post-closing adjustments.

In early September there was a devastating flood in Colorado.  The impact to our operations and assets will not be significant to our financial statement.  We had 20 well sites that were shut-in as a result of the flood.  We were able to quickly repair the damage and all the wells were brought back on-line during the first quarter.



 
5

 

Well and Production Data
 
During the periods presented below, we drilled or participated in the drilling of a number of wells that reached productive status in each respective fiscal year.  We did not drill any exploratory wells nor did we drill any dry holes during these years.  The following table excludes wells that are in the drilling or completion phase and had not reached the point at which they are capable of producing oil and gas.

   
Years Ended August 31,
 
   
2013
   
2012
   
2011
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Development Wells:
                                   
  Productive:
                                   
    Oil
    48       32       64       52       31       22  
    Gas
                                   
Nonproductive
                                   

 Excluded from the table above are wells that had not reached productive status as of August 31, 2013.  As such, there were 16 gross (7.5 net) wells in progress that were not included in the above well counts. Except for one well, these wells are all located in, or adjacent to, the Wattenberg Field of the D-J Basin.  One well is located in Yuma County.
 
 The following table shows our net production of oil and gas, average sales prices and average production costs for the periods presented:
 
   
Years Ended August 31,
 
   
2013
   
2012
   
2011
 
Production:
                 
Oil (Bbls)
    421,265       235,691       89,917  
Gas (Mcf)
    2,107,603       1,109,057       450,831  
BOE (Bbls)
    772,532       420,534       165,055  
                         
Average sales price:
                       
Oil ($/Bbl1)
  $ 85.95     $ 87.59     $ 83.07  
Gas ($/Mcf2)
  $ 4.75     $ 3.90     $ 5.12  
BOE
  $ 59.83     $ 59.37     $ 59.24  
                         
Average production cost per BOE3
  $ 4.42     $ 2.73     $ 2.13  

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.

Production costs are substantially similar among our wells as all of our wells are in the Wattenberg Field and employ the same methods of recovery.  Production costs generally include pumping fees, maintenance, repairs, labor, utilities and administrative overhead.  Taxes on production, including ad valorem and severance taxes, are excluded from production costs.

We are not obligated to provide a fixed and determined quantity of oil or gas to any third party in the future.  During the last three fiscal years, we have not had, nor do we now have, any long-term supply or similar agreement with any government or governmental authority.

 
6

 
Oil and Gas Properties
 
We evaluate undeveloped oil and gas prospects and participate in drilling activities on those prospects, which, in the opinion of our management, are favorable for the production of oil or gas.  If, through our review, a geographical area indicates geological and economic potential, we will attempt to acquire leases or other interests in the area.  We may then attempt to sell portions of our leasehold interests in a prospect to third parties, thus sharing the risks and rewards of the exploration and development of the prospect with the other owners.  One or more wells may be drilled on a prospect, and if the results indicate the presence of sufficient oil and gas reserves, additional wells may be drilled on the prospect.
 
We may also:

·  
acquire a working interest in one or more prospects from others and participate with the other working interest owners in drilling, and if warranted, completing oil or gas wells on a prospect, or
 
·  
purchase producing oil or gas properties.
 
Our activities are primarily dependent upon available financing.
 
Title to properties we acquire may be subject to royalty, overriding royalty, working and other similar interests and contractual arrangements customary in the oil and gas industry, and subject to liens for current taxes not yet due and to other encumbrances.  As is customary in the industry, in the case of undeveloped properties little investigation of record title will be made at the time of acquisition (other than a preliminary review of local records).  However, drilling title opinions may be obtained before commencement of drilling operations.
 
The following table shows, as of October 31, 2013, by state, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells:

   
Productive Wells
   
Developed Acreage
   
Undeveloped Acreage 1
 
State
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                     
Colorado
    307       230       11,306       9,372       231,140       103,214  
Nebraska
                            141,771       141,451  
Wyoming
                            1,143       472  
Total
    307       230       11,306       9,372       374,054       245,137  
 
            1  Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.

The following table shows, as of October 31, 2013, the status of our gross acreage:

State
 
Held by Production
   
Not Held by Production
 
             
Colorado
    12,550       229,896  
Nebraska
          141,771  
Wyoming
          1,143  
Total
    12,550       372,810  
 
 Acres that are Held by Production remain in force so long as oil or gas is produced from the well on the particular lease.  Leased acres which are not Held By Production require annual rental payments to maintain the lease until the first to occur of the following: the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage.  At the time oil or gas is produced from wells drilled on the leased acreage, the lease is considered to be Held by Production.
 

 
7

 
 The following table shows the years our leases, which are not Held By Production, will expire, unless a productive oil or gas well is drilled on the lease.
 
     Leased Acres
 
Expiration
of Lease
     
34,616
 
2014
73,376
 
2015
42,023
 
2016
222,795
 
After 2016

 The overriding royalty interests that we own are not material to our business.

Proved Reserve Estimates
 
 Ryder Scott Company, L.P. (“Ryder Scott”) prepared the estimates of our proved reserves, future productions and income attributable to our leasehold interests for the year ended August 31, 2013.  Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years.  The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by teams of geoscientists and engineers employed at Ryder Scott.  The office of Ryder Scott that prepared our reserves estimates is registered in the state of Texas (License #F-1580).  Ryder Scott prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for our wells.  Additionally, authorizations for expenditure, geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to Ryder Scott engineers for consideration in estimating our underground accumulations of crude oil and natural gas.
 
The report of Ryder Scott dated October 16, 2013, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99 to this report.
 
 Ed Holloway, our President and Chief Executive Officer, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission.  Mr. Holloway has over thirty years of experience in oil and gas exploration and development.
 
 Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology.  Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.
 
 Estimates of volumes of proved reserves at year end are presented in barrels (Bbls) for oil and for, natural gas, in thousands of cubic feet (Mcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.
 
 The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include decline curve analysis, which utilized extrapolations of historical production and pressure data available through August 31, 2013, in those cases where this data was considered to be definitive.  The data used in this analysis was obtained from public data sources and were considered sufficient for calculating producing reserves.
 
 The proved non-producing and undeveloped reserves were estimated by the analogy method.  The analogy method uses pertinent well data obtained from public data sources that were available through August 2013.
 
 
8

 
 Below are estimates of our net proved reserves at August 31, 2013, all of which are located in Colorado:

   
Oil
   
Gas
 
   
(Bbls)
   
(Mcf)
 
Proved:
           
  Producing
    1,894,222       11,513,428  
  Nonproducing
    2,765,183       14,352,580  
  Undeveloped
    2,387,870       14,823,823  
    Total
    7,047,275       40,689,831  
 
Below are estimates of our present value of estimated future net revenues from such reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities – Oil and Gas.  The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions.  The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the years ended August 31, 2013, 2012 and 2011.  The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels.  No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead.  Present values were computed by discounting future net revenues by 10% per year.

As of August 31, 2013, 2012 and 2011, our standardized oil and gas measurements were as follows (in thousands):
 
   
Proved - August 31, 2013
 
   
Developed
         
Total
 
   
Producing
   
Nonproducing
   
Undeveloped
   
Proved
 
Future gross revenue
  $ 206,065     $ 286,207     $ 256,758     $ 749,030  
Deductions
    (46,410 )     (78,691 )     (129,541 )     (254,642 )
Future net cash flow
    159,655       207,516       127,217       494,388  
Discounted future net cash flow (pre-tax)
  $ 92,888     $ 104,392     $ 38,836     $ 236,116  
Standardized measure of discounted future
                         
     net cash flows (after tax)
                          $ 181,732  
 
   
Proved - August 31, 2012
 
   
Developed
         
Total
 
   
Producing
   
Nonproducing
   
Undeveloped
   
Proved
 
Future gross revenue
  $ 120,802     $ 173,144     $ 243,516     $ 537,462  
Deductions
    (21,099 )     (48,536 )     (116,798 )     (186,433 )
Future net cash flow
    99,703       124,608       126,718       351,029  
Discounted future net cash flow (pre-tax)
  $ 57,797     $ 56,196     $ 34,890     $ 148,883  
Standardized measure of discounted future
                         
     net cash flows (after tax)
                          $ 102,505  
 
   
Proved - August 31, 2011
 
   
Developed
           
Total
 
   
Producing
   
Nonproducing
   
Undeveloped
   
Proved
 
Future gross revenue
  $ 71,027     $ 18,819     $ 145,392     $ 235,238  
Deductions
    (14,298 )     (5,647 )     (61,736 )     (81,681 )
Future net cash flow
    56,729       13,172       83,656       153,557  
Discounted future net cash flow (pre-tax)
  $ 33,947     $ 6,996     $ 30,815     $ 71,758  
Standardized measure of discounted future
                         
     net cash flows (after tax)
                          $ 57,550  
 
 
9

 

For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2013, generated increases in projected future gross revenue from proved reserves of $211.6 million and future net cash flow of $143.3 million from August 31, 2012.  During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $87.2 million.  Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2013, of approximately $104.3 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.

For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2012, generated increases in projected future gross revenue from proved reserves of $302.2 million and future net cash flow of $197.4 million from August 31, 2011.  During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $77.1 million.  Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2012, of approximately $33 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.

In general, the volume of production from our oil and gas properties declines as reserves are depleted.  Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.  Accordingly, volumes generated from our future activities are highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.

Government Regulation
 
Various state and federal agencies regulate the production and sale of oil and natural gas.  All states in which we plan to operate impose restrictions on the drilling, production, transportation and sale of oil and natural gas.

The Colorado Oil and Gas Conservation Commission (“COGCC”) is the primary regulator of exploration and production of oil and gas resources in the area in which we operate.  Via the permitting and inspection process, COGCC regulates oil and gas operators and, among other criteria, enforces specifications regarding the mechanical integrity of wells as well as the prevention and mitigation of adverse environmental impacts.

The Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas.  FERC’s jurisdiction over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce.

FERC has pursued policy initiatives that have affected natural gas marketing.  Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market.  We do not know what effect FERC’s other activities will have on the access to markets, the fostering of competition and the cost of doing business.
 
Our sales of oil and natural gas liquids will not be regulated and will be at market prices.  The price received from the sale of these products will be affected by the cost of transporting the products to market.  Much of that transportation is through interstate common carrier pipelines.
 
   Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production and related operations.  Most states require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil and gas.  Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells.  The statutes and regulations of some states limit the rate at which oil and gas is produced from our properties.  The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability.  Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with those laws.
 
 
10

 
 As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment.  The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue.  These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.
 
 The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities.  Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both.  In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in their interpretation could have a significant impact on us, as well as the oil and natural gas industry in general.
 
     The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites.  It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize imposition of substantial fines and penalties for noncompliance.  Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products.  In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.
 
      Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters.  The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States.  For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility.  Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us.  In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas.  The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations.  We are required to maintain such permits or meet general permit requirements.  The EPA and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions.  These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit.  Most agencies recognize the unique qualities of oil and natural gas exploration and production operations.  A number of agencies have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit pollutants.  We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.
 
      The EPA recently amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act (the “SDWA”) to exclude hydraulic fracturing from the definition of “underground injection.”  However, the U.S. Senate and House of Representatives are currently considering the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”), which will amend the SDWA to repeal this exemption.  If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, which could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements.
 
      The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.  While no federal law is presently in place, some states have enacted laws pertaining to chemical disclosure.  In December 2011, the State of Colorado approved regulation requiring parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process.  The regulation went into effect in April 2012 and requires the reporting of additives used.

 
11

 
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes.  These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.
 
Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources.  In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2012 for emissions occurring in 2011.

Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (the “ACESA”) which would establish an economy-wide cap-and-trade program to reduce United States emissions of greenhouse gases including carbon dioxide and methane that may contribute to the warming of the Earth’s atmosphere and other climatic changes.  If it becomes law, ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050.  Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere.  These allowances would be expected to escalate significantly in cost over time.  The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas.

Climate change has emerged as an important topic in public policy debate regarding our environment.  It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases, which may ultimately pose a risk to society and the environment.  Products produced by the oil and natural gas exploration and production industry are a source of certain greenhouse gases, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

Hydraulic Fracturing

We operate in the Wattenberg Field of the D-J Basin where the rock formations are typically tight and it is a common practice to utilize hydraulic fracturing to allow for or increase hydrocarbon production.  Hydraulic fracturing involves the process of forcing a mixture of fluid and white sand into a formation to create pores and fractures, thus creating a passageway for the release of oil and gas.  All of our producing wells were hydraulic fractured and we expect to employ the technique extensively in future wells that we drill and complete.

We outsource all hydraulic fracturing services to service providers with significant experience, and which we deem to be competent and responsible.  Our service providers supply all personnel, equipment and materials needed to perform each stimulation, including the mixtures that are injected into our wells.  These mixtures primarily consist of water and sand, with nominal amounts of other ingredients used as accelerants and proppants.  The additional ingredients are designed to improve the resulting porosity of the shale and include food based compounds commonly found in consumer products.  This mixture is injected into our wells at pressures of 4,500-6,000 psi at injection rates that that range between 25-55 barrels of mixture per minute.  On average, a single stage stimulation will utilize approximately 4,500 barrels of water and 150,000 pounds of sand.
 
We require our service companies to carry adequate insurance covering incidents that could occur in connection with their activities.  Our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the respective geographic location.  We have not had any incidents, citations or lawsuits relating to any environmental issues resulting from hydraulic fracture stimulation and we are not presently aware of any such matters.

In recent years, environmental opposition to hydraulic fracturing has increased, and various governmental and regulatory authorities are considering the adequacy of current regulations.  In Colorado, the primary regulator is the Colorado Oil and Gas Conservation Commission, which requires parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process.  Some municipalities are considering, or have adopted, more stringent regulations, including the prohibition of hydraulic fracturing within their city limits.  We continue to monitor these developments, as we consider the process to be critical to our success.

Competition and Marketing

We are faced with strong competition from many other companies and individuals engaged in the oil and gas business, many of which are very large, well established energy companies with substantial capabilities and established earnings records.  We may be at a competitive disadvantage in acquiring oil and gas prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs.  It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business.

 
12

 
Exploration for and production of oil and gas are affected by the availability of pipe, casing and other tubular goods and certain other oil field equipment including drilling rigs and tools.  We depend upon independent drilling contractors to furnish rigs, equipment and tools to drill our wells.  Higher prices for oil and gas may result in competition among operators for drilling equipment, tubular goods and drilling crews, which may affect our ability expeditiously to drill, complete, recomplete and work-over wells.

The market for oil and gas is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted.  These factors include the proximity of wells to, and the capacity of, natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation.  In addition, there is always the possibility that new legislation may be enacted, which would impose price controls or additional excise taxes upon crude oil or natural gas, or both.  Oversupplies of natural gas can be expected to recur from time to time and may result in the gas producing wells being shut-in.  Imports of natural gas may adversely affect the market for domestic natural gas.

The market price for crude oil is significantly affected by policies adopted by the member nations of Organization of Petroleum Exporting Countries ("OPEC").  Members of OPEC establish prices and production quotas among themselves for petroleum products from time to time with the intent of controlling the current global supply and consequently price levels.  We are unable to predict the effect, if any, that OPEC or other countries will have on the amount of, or the prices received for, crude oil and natural gas.

Gas prices, which were once effectively determined by government regulations, are now largely influenced by competition.  Competitors in this market include producers, gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as residual fuel oil.  Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry.

Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term contracts priced at spot market prices.

General

Our offices are located at 20203 Highway 60, Platteville, CO  80651.  Our office telephone number is (970) 737-1073 and our fax number is (970) 737-1045.

The Platteville office and equipment yard is rented to us pursuant to a lease with HS Land & Cattle, LLC, a firm controlled by Ed Holloway and William E. Scaff, Jr., two of our officers.  The 2013 lease, which expired on July 1, 2013, required monthly payments of $10,000.  The 2014 lease, which will expire on July 1, 2014, requires monthly payments of $15,000. The 2014 lease increased rentable area to the leased premises, including a field operations office.

As of October 31, 2013, we had 16 full time employees.

Neither we, nor any of our properties, are subject to any pending legal proceedings.

Available Information

We make available on our website, www.syrginfo.com, under “Investor Relations, SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”).

The “Investor Relations, News / Events” pages on our website contain press releases and investor presentations with more recent information than may have been available at the time of the most recent filing with the SEC.

Our Code of Ethics and Board of Directors Committee Charters (Audit and Compensation Committees) are also available on our website under “Investor Relations, Corporate Governance.”

 
13

 
ITEM 1A.  RISK FACTORS

Investors should be aware that any purchase of our securities involves certain risks, including those described below, which could adversely affect the value of our common stock.  We do not make, nor have we authorized any other person to make, any representation about the future market value of our common stock.  In addition to the other information contained in this annual report, the following factors should be considered carefully in evaluating an investment in our securities.

Laws and Regulations

Our operations will be affected from time to time and in varying degrees by political developments and federal and state laws and regulations regarding the development, production and sale of crude oil and natural gas.  These regulations require permits for drilling of wells and also cover the spacing of wells, the prevention of waste, and other matters.  Rates of production of oil and gas have for many years been subject to federal and state conservation laws and regulations.

In addition, the production of oil or gas may be interrupted or terminated by governmental authorities due to ecological and other considerations.  Compliance with these regulations may require a significant capital commitment by and expense to us and may delay or otherwise adversely affect our operations.

From time to time legislation has been proposed relating to various conservation and other measures designed to decrease dependence on foreign oil.  No prediction can be made as to what additional legislation may be proposed or enacted.  Oil and gas producers may face increasingly stringent regulation in the years ahead and a general hostility towards the oil and gas industry on the part of a portion of the public and of some public officials.  Future regulation will probably be determined by a number of economic and political factors beyond our control or the oil and gas industry.

Our activities are subject to existing federal and state laws and regulations governing environmental quality and pollution control.  Compliance with environmental requirements and reclamation laws imposed by federal, state, and local governmental authorities may necessitate significant capital outlays and may materially affect our earnings.  It is impossible to predict the impact of environmental legislation and regulations (including regulations restricting access and surface use) on our operations in the future although compliance may necessitate significant capital outlays, materially affect our earning power or cause material changes in our intended business.  In addition, we may be exposed to potential liability for pollution and other damages.

Dry holes and non-productive wells

Oil and gas exploration is not an exact science, and involves a high degree of risk.  The primary risk lies in the drilling of dry holes or drilling and completing wells, which, though productive, do not produce gas and/or oil in sufficient amounts to return the amounts expended and produce a profit.  Hazards, such as unusual or unexpected formation pressures, downhole fires, blowouts, loss of circulation of drilling fluids and other conditions are involved in drilling and completing oil and gas wells and, if such hazards are encountered, completion of any well may be substantially delayed or prevented.  In addition, adverse weather conditions can hinder or delay operations, as can shortages of equipment and materials or unavailability of drilling, completion, and/or work-over rigs.  Even though a well is completed and is found to be productive, water and/or other substances may be encountered in the well, which may impair or prevent production or marketing of oil or gas from the well.

Exploratory drilling involves substantially greater economic risks than development drilling because the percentage of wells completed as producing wells is usually less than in development drilling.  Exploratory drilling itself can be of varying degrees of risk and can generally be divided into higher risk attempts to discover a reservoir in a completely unproven area or relatively lower risk efforts in areas not too distant from existing reservoirs.  While exploration adjacent to or near existing reservoirs may be more likely to result in the discovery of oil and gas than in completely unproven areas, exploratory efforts are nevertheless high risk activities.

Although the completion of oil and gas wells is, to a certain extent, less risky than drilling for oil and gas, the process of completing an oil or gas well is nevertheless associated with considerable risk.  In addition, even if a well is completed as a producer, the well for a variety of reasons may not produce oil or gas in quantities sufficient to repay our investment in the well.

 
14

 
The acquisition, exploration and development of oil and gas properties, and the production and sale of oil and gas are subject to many factors not under our control.  These factors include, among others, general economic conditions, proximity to pipelines, oil import quotas, supply, demand, and price of other fuels and the regulation of production, refining, transportation, pricing, marketing and taxation by various governmental authorities.

Supply and demand

Buyers of our gas, if any, may refuse to purchase gas from us in the event of oversupply.  If we drill wells that are productive of natural gas, the quantities of gas that we may be able to sell may be too small to pay for the expenses of operating the wells.  In such a case, the wells would be "shut-in" until such time, if ever, that economic conditions permit the sale of gas in quantities which would be profitable.

Insurable risks, defects, and hazards

Interests that we may acquire in oil and gas properties may be subject to royalty and overriding royalty interests, liens incident to operating agreements, liens for current taxes and other burdens and encumbrances, easements and other restrictions, any of which may subject us to future undetermined expenses.  We do not intend to purchase title insurance, title memos, or title certificates for any leasehold interests we will acquire.

It is possible that at some point we will have to undertake title work involving substantial costs.  In addition, it is possible that we may suffer title failures resulting in significant losses.

The drilling of oil and gas wells involves hazards such as blowouts, unusual or unexpected formations, pressures or other conditions, which could result in substantial losses or liabilities to third parties.  Although we intend to acquire adequate insurance, or to be named as an insured under coverage acquired by others (e.g., the driller or operator), we may not be insured against all such losses because insurance may not be available, premium costs may be deemed unduly high, or for other reasons.  Accordingly, uninsured liabilities to third parties could result in the loss of our funds or property.

Opposition to Hydraulic Fracturing

Hydraulic fracturing, the process used for releasing oil and gas from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.  While companies have been using the technique for decades, as drilling expands to more populated areas, environmentalists raise concern about the effects on the population’s health and drinking water.

In April of this year, the Obama administration proposed the first national standards to control air pollution from gas wells stimulated by hydraulic fracturing.  The EPA published claims that the new regulations would ensure pollution is controlled without slowing natural gas production, actually resulting in more product for fuel suppliers to bring to market.  The proposal would restrict the venting of gases during the well completion phase, and require the implementation of a new technology to reduce emissions of pollutants during completion of wells.  Implementation of the pollution-reducing equipment for so-called “green completions” is required by January 2015.

Locally, some counties and municipalities are attempting to impose more stringent regulations than those required by the Colorado Oil and Gas Conservation Commission.  Litigation has been initiated to determine the legality of these attempts.  Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, state and/or local levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements.  Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and gas resources from shale formations which are not commercial without the use of hydraulic fracturing.  This could have an adverse effect on our business.

Related Party Transactions

 Our transactions with related parties may cause conflicts of interests that may adversely affect us.  Ed Holloway and William E. Scaff, Jr., both of whom are officers, directors and principal shareholders, control two entities, Petroleum Exploration & Management, LLC ("PEM") and HS Land & Cattle, LLC (“HSLC”), with whom we do business.  We presently lease the Platteville office space and equipment storage yard from HSLC at a rate of $15,000 per month.  During 2011, we purchased all of the operating oil and gas assets owned by PEM.    Material transactions with related parties are approved by our independent directors.

We believe that the transactions and agreements that we have entered into with these affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third parties.  However, these relationships could create, or appear to create, potential conflicts of interest when our board of directors is faced with decisions that could have different implications for us and these affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public's perception of us, as well as our relationship with other companies and our ability to enter into new relationships in the future, which could have a material adverse effect on our ability to do business.

 
15

 
Funding

Our failure to obtain capital may significantly restrict our proposed operations.  We may need additional capital to fund our capital expenditure plans.  We do not know what the terms of any future capital raising may be but any future sale of our equity securities would dilute the ownership of existing stockholders and could be at prices substantially below the price investors paid for their shares of our common stock. Our failure to obtain the capital required will result in the slower implementation of our business plan.  There can be no assurance that we will be able to obtain the necessary capital.

We will need to consistently generate positive cash flow or obtain additional financing to consistently yield sufficient cash for the growth of our operations and to execute our strategic business plan.

Market for our Common Stock

Although our common stock has been listed on the NYSE MKT since July 27, 2011, the trading in our stock has, at times, been limited and sporadic.  Additionally, the trading price of our common stock may fluctuate widely in response to various factors, some of which are beyond our control.  Factors that could negatively affect our share price include, but are not limited to:

·  
actual or anticipated fluctuations in our quarterly results of operations;

·  
liquidity;

·  
sales of common stock by our shareholders;

·  
changes in oil and natural gas prices;

·  
changes in our cash flow from operations or earnings estimates;

·  
publication of research reports about us or the oil and natural gas exploration and production industry generally;

·  
increases in market interest rates which may increase our cost of capital;

·  
changes in applicable laws or regulations, court rulings and enforcement and legal actions;

·  
changes in market valuations of similar companies;

·  
adverse market reaction to any indebtedness we incur in the future;

·  
additions or departures of key management personnel;

·  
actions by our shareholders;

·  
political opposition to the oil and gas industry

·  
commencement of or involvement in litigation;

·  
news reports relating to trends, concerns, technological or competitive developments, regulatory changes and other related issues in our industry;

·  
speculation in the press or investment community regarding our business;

·  
general market and economic conditions; and

·  
domestic and international economic, legal and regulatory factors unrelated to our performance.

Shares issuable upon the exercise of outstanding warrants and options may substantially increase the number of shares available for sale in the public market and may depress the price of our common stock.  We have outstanding options and warrants which could potentially allow the holders to acquire a substantial number of shares of our common stock.  Until the options and warrants expire, the holders will have an opportunity to profit from any increase in the market price of our common stock without assuming the risks of ownership.  Holders of options and warrants may exercise these securities at a time when we could obtain additional capital on terms more favorable than those provided by the options or warrants.  The exercise of the options and warrants will dilute the voting interest of the current owners of our outstanding shares by adding a substantial number of additional shares of common stock.

 
16

 
Reliance on Key Personnel

We are dependent upon the contributions of our senior management team and other key employees for our success.  If one or more of these executives, or other key employees, were to cease to be employed by us, our progress could be adversely affected.  In particular, we may have to incur costs to replace senior executive officers or other key employees who leave, and our ability to execute our business strategy could be impaired if we are unable to replace such persons in a timely manner.
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. 
PROPERTIES

See Item 1 of this report.

ITEM 3. 
LEGAL PROCEEDINGS

None.

ITEM 4. 
MINE SAFETY DISCLOSURES

Not applicable.


 
17

 
 
PART II

ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the NYSE MKT under the symbol “SYRG”.

Trading of our stock on the NYSE Amex (predecessor to the NYSE MKT) began on July 27, 2011.  Prior to listing on the NYSE Amex, our stock traded on the OTC Bulletin Board.  Shown below is the range of high and low sales prices for our common stock as reported by the NYSE MKT since September 1, 2011. 
 
Quarter Ended
 
High
 
Low
November 30, 2011
 
$3.75
 
$2.20
February 29, 2012
 
$3.72
 
$2.42
May 31, 2012
 
$3.65
 
$2.52
August 31, 2012
 
$3.10
 
$2.40

Quarter Ended
 
High
 
Low
November 30, 2012
 
$4.74
 
$2.70
February 28, 2013
 
$7.00
 
$3.75
May 31, 2013
 
$7.78
 
$6.14
August 31, 2013
 
$9.43
 
$6.23
 
As of October 31, 2013, the closing price of our common stock on the NYSE MKT was $10.36.

As of October 31, 2013, we had 74,391,364 outstanding shares of common stock and 149 shareholders of record.  The number of beneficial owners of our common stock is in excess of 4,600.

Since inception, we have not paid any cash dividends on common stock.  Cash dividends are restricted under the terms of our credit facility and we presently intend to continue the policy of using retained earnings for expansion of our business.
 
Our articles of incorporation authorize our board of directors to issue up to 10,000,000 shares of preferred stock.  The provisions in the articles of incorporation relating to the preferred stock allow our directors to issue preferred stock with multiple votes per share and dividend rights, which would have priority over any dividends paid with respect to the holders of our common stock.  The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in certain transactions such as mergers or tender offers if these transactions are not favored by our management.

 
18

 
Additional Shares Which May be Issued

The following table lists additional shares of our common stock, which may be issued as of October 31, 2013, upon the exercise of outstanding options or warrants or the issuance of shares for oil and gas leases.
 
   
Number of
Shares
 
Note
Reference
Shares issuable upon the exercise of Series C warrants
 
4,782,750
 
A
         
Shares issuable upon the exercise of Series D warrants
    (also described as Placement Agent warrants)
 
63,989
 
A
         
Shares issuable upon exercise of investor relations warrants
 
25,000
 
B
         
Shares issuable upon exercise of options held by our officers and employees
 
1,954,000
 
C
         

A.           We issued 9,000,000 Series C warrants in connection with the sale of 180 Units at a price of $100,000 per Unit to private investors during fiscal year 2010.  Each Unit consisted of one $100,000 note and 50,000 Series C warrants.   Each Series C warrant entitles the holder to purchase one share of our common stock at a price of $6.00 per share at any time prior to December 31, 2014.  As of October 31, 2013, 4,217,250 warrants had been exercised.  We received cash proceeds of $25.3 million from the exercise of the warrants.
 
In connection with the unit offering, we also sold to the placement agent, for a nominal price, warrants to purchase 1,125,000 shares of our common stock at a price of $1.60 per share (these warrants are sometimes described as Series D warrants).  The placement agent’s warrants expire on December 31, 2014.  As of October 31, 2013, warrants to purchase 1,061,011 shares had been exercised by their holders.

B.           During the fiscal year ended August 31, 2012, we entered into an agreement with an investor relations firm and agreed to issue warrants to the firm.  Each warrant entitles the holder to purchase one share of common stock at a price of $2.69 at any time prior to December 31, 2015.  As of October 31, 2013, 25,000 warrants had been exercised.

C.           See Item 11 of this report for information regarding shares issuable upon exercise of options held by our officers and employees.
 

 
 
19

 
Comparison of Cumulative Return

The performance graph below compares the cumulative total return of our common stock over the five-year period ended August 31, 2013 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the companies with a Standard Industrial Code ("SIC") of 1311. The SIC Code 1311 is a weighted composite of 254 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on September 1, 2008 and in the S&P 500 Index and the SIC Code on the same date. The results shown in the graph below are not necessarily indicative of future performance.
 
 
 
20

 
 
ITEM 6.       SELECTED FINANCIAL DATA

The selected financial data presented in this item has been derived from our audited financial statements that are either included in this report or in reports previously filed with the U.S. Securities and Exchange Commission.  The information in this item should be read in conjunction with the financial statements and accompanying notes and other financial data included in this report.

   
For the Years Ended August 31,
 
   
2013
   
2012
   
2011
   
2010
   
2009
 
Results of Operations
(in thousands):
                             
Revenues
  $ 46,223     $ 24,969     $ 10,002     $ 2,158     $ 94  
Net income (loss)
    9,581       12,124       (11,600 )     (10,794 )     (12,352 )
Net income (loss) per common share:
                                       
  Basic
  $ 0.17     $ 0.26     $ (0.45 )   $ (0.88 )   $ (1.14 )
  Diluted
  $ 0.16     $ 0.25     $ (0.45 )   $ (0.88 )   $ (1.14 )
                                         
Certain Balance Sheet Information (in thousands):
                                       
Total Assets
  $ 291,236     $ 120,731     $ 63,698     $ 24,842     $ 4,833  
Working Capital
    50,608       10,875       685       6,237       2,249  
Total Liabilities
    88,016       19,619       14,590       25,859       1,844  
Equity (Deficit)
    203,220       101,112       49,108       (1,017 )     2,988  
                                         
Certain Operating Statistics:
                                       
Production:
                                       
   Oil (Bbls)
    421,265       235,691       89,917       21,080       1,730  
   Gas (Mcf)
    2,107,603       1,109,057       450,831       141,154       4,386  
      Total production in BOE
    772,532       420,534       165,056       44,606       2,461  
   Average sales price per BOE
  $ 59.83     $ 59.38     $ 59.24     $ 48.39     $ 38.25  
   LOE per BOE
  $ 4.42     $ 2.89     $ 2.94     $ 1.94     $ 4.70  
   DDA per BOE
  $ 17.26     $ 14.29     $ 16.62     $ 15.52     $ 39.54  
 
The fluctuation in results of operations and financial position is due in part to acquisitions of producing oil and gas properties coupled with the aggressive drilling program we executed during 2011, 2012 and 2013.

See Note 17 to the Financial Statements included as part of this report for our quarterly financial data.
 
 
21

 
 
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.

 
22

 
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.


 
23

 
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.

 
24

 

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.

 
25

 
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

 
26

 
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.


 
27

 
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.

 
28

 
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 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 17% from 2011 to 2012.  For the fiscal year ended August 31, 2012, depletion of oil and gas properties was $14.29 per BOE compared to $17.19 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.

 
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General and Administrative (“G&A”) – The following table summarizes the components of general and administration expenses:

   
Years Ended August 31,
 
(in thousands)
 
2012
   
2011
 
Cash based compensation
  $ 1,901     $ 1,261  
Share based compensation
    473       627  
Professional fees
    953       716  
Insurance
    136       78  
Other general and administrative
    439       428  
Capitalized general and administrative
    (345 )     (206 )
   Total G&A
  $ 3,557     $ 2,904  
                 
G&A Expense per BOE
  $ 8.46     $ 17.59  

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 $11.7 million, compared to $2.8 million 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 $37,000, consisting solely of interest income.  Interest cost of $208,000 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 $56,000.  These other expenses reported in 2011 primarily related to our convertible promissory notes, including net interest expense of $590,000, accretion of debt discount of $2.6 million, amortization of debt issuance costs of $1.6 million, and a change in the fair value of the derivative conversion liability of $10.2 million.  During 2011, interest expense was also recorded on the related party note and the bank line of credit in the amounts of $74,000 and $41,000, respectively.  Of these expenses, we capitalized interest and amortization of $710,000.

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.

 
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Income Taxes – We reported income tax expense of $4.6 million offset by a tax benefit of $4.9 million 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 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.
 
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 allowed 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.

 
 
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Liquidity and Capital Resources

Our primary source of liquidity since inception has been net cash provided by sales and other issuances of equity and debt securities.  Our secondary sources of capital have been cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities.  Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties.  Our future success in growing proved reserves and production will be highly dependent on capital resources available to us.  We believe that cash on hand plus cash flows from operations plus available borrowings under our revolving credit facility will provide sufficient liquidity.  However, unforeseen events may require us to obtain additional equity or debt financing.  We have on file with the SEC an effective universal shelf registration statement that we may use for future securities offerings.  Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.

During the year, we completed the sale of common stock for net proceeds of $78.2 million.  The underwritten offering, which closed on June 19, 2013, was comprised of 13,225,000 shares of common stock at a price to the public of $6.25 per share.

In November 2012, we modified our borrowing arrangements.  The new revolving line of credit increases the maximum lending commitment to $150 million, subject to the limitations of a borrowing base calculation.  The bank group providing the facility is led by Community Banks of Colorado, a division of NBH Bank, NA.

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.  The maximum lending commitment is subject to reduction based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports.  Based upon the semi-annual redetermination derived from the February 28, 2013 reserve report, the borrowing base was increased from $47 million to $75 million.

In December, we utilized a portion of the financing available through this arrangement to fund the acquisition of assets from Orr Energy.  We currently have approximately $38 million available for future borrowings if needed.  Additional borrowings, if any, are expected to be used to fund acquisitions, expenditures for well drilling and development, and to provide working capital.

Interest on our revolving line of credit 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 engage in the use of commodity derivatives in connection with anticipated crude oil sales to mitigate the impact of commodity price volatility.  During the year ended August 31, 2013, we realized a cash loss from commodity derivatives of $0.4 million.

At August 31, 2013, we had cash and cash equivalents of $19.5 million, short term investments of $60.0 million, and an outstanding balance of $37 million under our revolving credit facility.

Our sources and (uses) of funds for the fiscal years ended August 31, 2013, 2012 and 2011, are summarized below (in thousands):
 
   
Years Ended August 31,
 
   
2013
   
2012
   
2011
 
Cash provided by operations
  $ 32,120     $ 21,252     $ 7,916  
Capital expenditures
    (80,469 )     (46,751 )     (30,247 )
Property conveyances
    -       71       8,382  
Cash used by other investing activities
    (60,000 )     -       -  
Cash provided by equity financing activities
    74,528       37,421       16,691  
Net borrowings
    34,000       (2,200 )     -  
Net increase in cash and equivalents
  $ 179     $ 9,793     $ 2,742  

 
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Net cash provided by operations has improved during each of the last three years.  The significant improvement reflects the operating contribution from new wells that were drilled and producing wells that were acquired.

Capital expenditures reported in the Statement of Cash Flows are calculated on a strict cash 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.  

A reconciliation of the differences between cash payments and the “all-inclusive” amounts is summarized in the following table (in thousands):

     
Years Ended August 31,
 
     
2013
   
2012
   
2011
 
Cash payments for capital expenditures
  $ 80,469     $ 46,751     $ 30,247  
Accrued costs, beginning of period
    (5,733 )     (4,967 )     (3,466 )
Accrued costs, end of period
    25,491       5,733       4,967  
Non-cash acquisitions, common stock
    16,684       1,985       9,939  
Non-cash acquisitions, debt financing
    -       -       5,200  
Other
      1,233       300       351  
 
All inclusive capital expenditures
  $ 118,144     $ 49,802     $ 47,238  

During the fiscal year ended August 31, 2013, we engaged in drilling or completion activities on 48 wells.  In addition, we invested $42.5 million in the acquisition of mineral assets from Orr Energy.  Approximately $35.2 million of our capital expenditures for the fiscal year ended August 31, 2013, represent drilling and completion cost on wells on which production commenced during the year.  As of August 31, 2013, we had recorded costs of $25.9 million on 16 wells in progress.  Our mineral lease acquisition program incurred costs of $12.3 million during the year, $3.2 million of which were acquired in exchange for our common stock.

Our primary need for cash for the fiscal year ending August 31, 2014, will be to fund our drilling and acquisition programs.  Our cash requirements are expected to increase significantly as we implement our horizontal drilling program.  Each horizontal well is estimated to cost $4.5 million, compared to the estimated cost of a vertical well of $0.8 million.  Under the preliminary plans for our 2014 capital budget, we estimate capital expenditures of approximately $157.1 million, consisting of drilling and completion costs for wells which we operate, our pro-rata share of the costs on wells drilled by other operators, and the costs of acquiring properties.  It is our plan to drill 24 net horizontal wells during the year and to participate in 5 net non-operated horizontal wells at a total cost of $112.5 million.  We expect to drill or participate in 6 vertical wells.  Leasing activities are expected to cost $5.0 million, and the acquisition of producing properties is budgeted for $30.0 million.  Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.  The amount, timing and allocation of capital expenditures is generally within our control, as participations are a limited portion of our operations.  Fluctuations in prices for oil and natural gas could cause us to defer or accelerate our spending.

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

For 2014, we believe that the cash flow from operations plus proceeds from the sale of common stock during June 2013 plus additional borrowings available under our revolving line of credit facility will be sufficient to meet our liquidity needs during the fiscal year

 
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Contractual Commitments

The following table summarizes our contractual obligations as of August 31, 2013 (in thousands):
 
   
Less than
 One Year
   
One to
 Three Years
   
Three to Five Years
   
Total
 
Rig Contract1
 
$
19,900
   
$
     
   
$
19,900
 
Revolving credit facility
   
     
37,000
     
     
37,000
 
Operating Leases
   
150
     
     
     
150
 
Employment Agreements
   
1,164
     
1,697
     
     
2,861
 
Total
 
$
21,214
   
$
38,697
     
   
$
59,911
 

1
 
As of August 31, 2013, we had agreed with Ensign United States Drilling, Inc. to use one drilling rig to drill a total of 25 wells.  As of August 31, 2013, six wells had been drilled.  We estimate that we will utilize the rig through June 30, 2014.  Total payments due to Ensign will depend upon a number of variables, including the target formations and other technical details.  We estimate that the total commitment for the 25 wells will approximate $25.6 million and that the portion of the obligation to be recorded during fiscal 2014 will approximate $19.9 million.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonable likely to have a current or future material effect on our financial condition, changes in financial condition, results of operations, liquidity or capital resources.

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

See Reconciliation of Non-GAAP Financial Measures below for a detailed description of this measure as well as a reconciliation to the nearest U.S. GAAP measure.

 
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Reconciliation of Non-GAAP Financial Measures
  
Adjusted EBITDA. We define adjusted EBITDA as net income adjusted to exclude the impact of interest expense, interest income, income tax expense, DDA (depreciation, depletion and amortization), stock based compensation, and the plus or minus change in fair value of derivative assets or liabilities. We believe adjusted EBITDA is relevant because it is a measure of cash flow available to fund our capital expenditures and service our debt and is a widely used industry metric which may provide comparability of our results with our peers.  The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to its nearest GAAP measure.
 
   
Years Ended August 31,
 
   
2013
   
2012
   
2011
 
Adjusted EBITDA:
                 
Net income (loss)
  $ 9,581     $ 12,124     $ (11,600 )
Depreciation, depletion and amortization
    13,336       6,010       2,838  
Change in fair value of derivative conversion liability
    -       -       10,230  
Provision for income tax
    6,870       (332 )     -  
Stock based compensation
    1,362       473       627  
Commodity derivative change
    2,649       -       -  
Interest expense
    97       -       4,247  
Interest income
    (47 )     (38 )     (56 )
Adjusted EBITDA
  $ 33,848     $ 18,237     $ 6,286  


 
35

 
Trend and Outlook
 
In early September, 2013, Northern Colorado experienced flooding that covered a wide area and caused extensive damage.  Significant damage was done to the area’s infrastructure, such as roads, bridges, and water treatment facilities, as well as to numerous structures within the flood zone.    Approximately 20 of our well sites were directly affected by the flood waters.  However, the damage to our facilities was not severe, and there were no hydrocarbon spills at our sites.  Most of the wells were repaired within a few weeks and all of the sites are expected to return to service during our first fiscal quarter. The cost of repairs will not have a significant impact on our financial statements.  However, the extent of the flooding throughout our production area was so vast that it impacted our daily operations, even on well sites that were not directly affected by the flood.  For several days, it was difficult to gather and transport hydrocarbons, and sales from our legacy vertical wells for the month of September decreased by 35% from the month of August.  The new horizontal wells which reached productive status during the first week of September were less affected by the flood, and production from those wells is expected to meet our initial expectations for the quarter.

During fiscal year 2012, the Wattenberg Field experienced elevated line pressure in the natural gas and liquids gathering system.  Issues with high line pressure continued during 2013.  High line pressure restricts our ability to produce crude oil and natural gas.  As line pressures increase, it becomes more difficult to inject gas produced by our wells into the pipeline.  When line pressure is greater than the operating pressure of our wellhead equipment, the wellhead equipment is unable to inject gas into the pipeline, and our production is restricted or shut-in.  Since our wells produce a mixture of crude oil and natural gas, restrictions in gas production also restrict oil production.  Although various factors can cause increased line pressure, a significant factor in our area is the success of horizontal wells that have recently been drilled.  As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle.  Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells.  The pace of horizontal drilling in the Wattenberg is accelerating and it appears that it will be some time before the gathering system will have sufficient capacity to eliminate the high line pressure issues.

We are taking steps to mitigate high line pressures.  Where it was cost beneficial, we installed compressors to aid the wellhead equipment in its injection of gas into the system.  Compression equipment at the wellhead has proven beneficial, especially at pad sites with multiple vertical wells.  Along with our mid-stream service provider, we are evaluating the installation of larger diameter pipe to improve the gas gathering capacity.

In addition, companies that operate the gas gathering pipelines are making significant capital investments to increase system capacity.  As publicly disclosed, DCP Midstream Partners (“DCP”) is currently implementing a multi-year facility expansion capable of significantly increasing the long-term gathering and processing capacity in the Wattenberg Field.  DCP is the principle third party provider that we employ to gather production from our wells.  A significant improvement in the system will occur as a new processing plant in LaSalle, CO comes on line. The LaSalle, CO plant will have an estimated capacity of 110 million cubic feet per day.  The grand opening for the LaSalle plant was held in October, 2013 and the plant is expected to reach full operational status during our first and second fiscal quarters.  DCP has also announced the building of the Lucerne Plant II, northeast of Greeley in Weld County, with a maximum capacity of 230 mmcf/d, which is estimated to begin operations in 2015.  At this time, we do not know how long it will take for the mitigation efforts to remedy the problem.

Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our substantial capital requirements, (iv) completion of acquisitions of additional properties and reserves, (v) competition from larger companies and (vi) prices for oil and gas.  Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.

It is expected that our principal source of cash flow will be from the production and sale of oil and gas reserves which are depleting assets.  Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing from more sources or on better terms, and lessens the difficulty of obtaining financing.  However, price increases heighten the competition for oil and gas prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels.

 
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A decline in oil and gas prices (i) will reduce our cash flow which in turn will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, and (v) may result in marginally productive oil and gas wells being abandoned as non-commercial.  However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

Other than the foregoing, we do not know of any trends, events or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues or expenses

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.

The following paragraphs provide a discussion of our more significant accounting policies, estimates and judgments.  We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements.  See Note 1 of the Notes to the Financial Statements for a detailed discussion of the nature of our accounting practices and additional accounting policies and estimates made by management.

Oil and Gas Sales:  We derive revenue primarily from the sale of produced crude oil and natural gas.  Revenues from production on properties in which we share an economic interest with other owners are recognized on the basis of our interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser.  Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Oil and Gas Reserves:  Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control.  Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of our oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Oil and Gas Properties:  We use the full cost method of accounting for costs related to our oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.  Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves.  For depletion purposes, the volume of petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.  Investments in unevaluated properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Asset Retirement Obligations (“ARO”):  We are subject to legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an ARO requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using our credit adjusted risk free interest rate.  Estimates are periodically reviewed and adjusted to reflect changes.
 
 
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The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed or an asset is placed in service.  When the ARO is initially recorded, we capitalize the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset.  ARCs related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the capitalized cost decreases over the useful life of the asset, recognized as depletion.

Stock-Based Compensation:  We recognize all equity-based compensation as stock-based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date.  The expense is recognized over the vesting period of the grant.

Income Taxes: Deferred income taxes are recorded for timing differences between items of income or expense reported in the financial statements and those reported for income tax purposes using the asset/liability method of accounting for income taxes.  Deferred income taxes and tax benefits are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, and for tax loss and credit carry-forwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  We provide for deferred taxes for the estimated future tax effects attributable to temporary differences and carry-forwards when realization is more likely than not.  If we conclude that it is more likely than not that some portion, or all, of the net deferred tax asset will not be realized, the balance of net deferred tax assets is reduced by a valuation allowance.

We consider many factors in our evaluation of deferred tax assets, including the following sources of taxable income that may be available under the tax law to realize a portion or all of a tax benefit for deductible timing differences and carry-forwards:

·
Future reversals of existing taxable temporary differences,
 
·
Taxable income in prior carry back years, if permitted,
 
·
Tax planning strategies, and
 
·
Future taxable income exclusive of reversing temporary differences and carry- forwards.
 

 
38

 
 
 
Recent Accounting Pronouncements
 
We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on U.S. GAAP and their impact on us.
 
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.  This ASU requires us to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements.  The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented.  We are required to implement this guidance effective for the first quarter of fiscal 2014 and do not expect the adoption of ASU 2011-11 to have a material impact on our financial statements.

Various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on our financial position, results of operations or cash flows.
 
ITEM 7A. 
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
 
Commodity Risk - Our primary market risk exposure results from the price we receive for our oil and natural gas production. Realized commodity pricing for our production is primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas.  Pricing for oil and natural gas production has been volatile and unpredictable in recent years, and we expect this volatility to continue in the foreseeable future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable commodity index price.

Interest Rate Risk - At August 31, 2013, we had debt outstanding under our bank credit facility totaling $37.0 million.  Interest on our bank credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate (LIBOR).  At August 31, 2013, the interest rate was 2.7%, based upon LIBOR plus a margin of 2.5%.  We are currently incurring interest at a rate of 2.7%, and we are exposed to interest rate risk on the bank credit facility if the variable reference rates increase.  If interest rates increase, our interest expense would increase and our available cash flow would decrease.

Counterparty Risk –Effective January 1, 2013, we entered into commodity derivative agreements.  These derivative financial instruments present certain market and counterparty risks. We seek to manage the counterparty risk associated with these contracts by limiting transactions to long standing and established counterparties.  We are exposed to potential losses if a counterparty fails to perform according to the terms of the agreement. We do not require collateral or other security to be furnished by counterparties to our derivative financial instruments. There can be no assurance, however, that our practice effectively mitigates counterparty risk. The failure of any of the counterparties to our commodity derivative arrangements to fulfill their obligations to us could adversely affect our results of operations and cash flows.

ITEM 8. 
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See the financial statements and accompanying notes included with this report.
 
ITEM 9. 
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON  ACCOUNTING  AND FINANCIAL DISCLOSURE
 
None


 
39

 
 
ITEM 9A. 
CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of our management, including our President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-K.  Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-K, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our President and Chief Executive Officer as well as our Chief Financial Officer to allow timely decisions regarding required disclosure.

Based on that evaluation, our management concluded that, as of August 31, 2013, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

During the fourth quarter of fiscal year ended August 31, 2013, we took measures to bolster our internal control processes pertaining to financial reporting.  Such measures included the implementation of additional procedures related to the valuation of commodity derivatives.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting.  As defined by the Securities and Exchange Commission, internal control over financial reporting is a process designed by, or under the supervision of two key personnel, our President and Chief Executive Officer and our Chief Financial Officer and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with U.S. generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Ed Holloway, our President and Chief Executive Officer, and Frank L. Jennings, our Chief Financial Officer, evaluated the effectiveness of our internal control over financial reporting as of August 31, 2013 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO Framework.  Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls.  Based on this evaluation, management concluded that our internal control over financial reporting was effective as of August 31, 2013.

Attestation Report of Registered Public Accounting Firm

The attestation report required under this Item 9A is set forth under the caption "Report of Independent Registered Public Accounting Firm", which is included with the financial statements and supplemental data required by Item 8.

ITEM 9B. 
OTHER INFORMATION

None.
 
 
40

 

PART III

ITEM 10. 
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our officers and directors are listed below.  Our directors are generally elected at our annual shareholders' meeting and hold office until the next annual shareholders' meeting or until their successors are elected and qualified.  Our executive officers are elected by our directors and serve at their discretion.
 
Name
 
Age
 
Position
Edward Holloway
 
61
 
President, Chief Executive Officer and Director
William E. Scaff, Jr.
 
56
 
Vice President, Secretary, Treasurer and Director
Frank L. Jennings
 
62
 
Chief Financial Officer
Rick A. Wilber
 
66
 
Director
Raymond E. McElhaney
 
57
 
Director
Bill M. Conrad
 
57
 
Director
R.W. Noffsinger, III
 
39
 
Director
George Seward
 
63
 
Director

Edward Holloway – Mr. Holloway has been an officer and director since September 2008 and was an officer and director of our predecessor between June 2008 and September 2008.  Mr. Holloway co-founded Cache Exploration Inc., an oil and gas exploration and development company.  In 1987, Mr. Holloway sold the assets of Cache Exploration to LYCO Energy Corporation.  He rebuilt Cache Exploration and sold the entire company to Southwest Production a decade later.  In 1997, Mr. Holloway co-founded, and since that date has co-managed, Petroleum Management, LLC, a company engaged in the exploration, operations, production and distribution of oil and natural gas.  In 2001, Mr. Holloway co-founded, and since that date has co-managed, Petroleum Exploration and Management, LLC, a company engaged in the acquisition of oil and gas leases and the production and sale of oil and natural gas.  Mr. Holloway holds a degree in Business Finance from the University of Northern Colorado and is a past president of the Colorado Oil and Gas Association.

William E. Scaff, Jr. – Mr. Scaff has been an officer and director since September 2008 and was an officer and director of our predecessor between June 2008 and September 2008.  Between 1980 and 1990, Mr. Scaff oversaw financial and credit transactions for Dresser Industries, a Fortune 50 oilfield equipment company.  Immediately after serving as a regional manager with TOTAL Petroleum between 1990 and 1997, Mr. Scaff co-founded, and since that date co-managed, Petroleum Management, LLC, a company engaged in the exploration, operations, production and distribution of oil and natural gas.  In 2001, Mr. Scaff co-founded, and since that date has co-managed, Petroleum Exploration and Management, LLC, a company engaged in the acquisition of oil and gas leases and the production and sale of oil and natural gas.  Mr. Scaff holds a degree in Finance from the University of Colorado.

Frank L. Jennings – Mr. Jennings began his service as our Chief Financial Officer on a part-time basis in June 2007.  In March 2011, he joined us on a full-time basis.  From 2001 until 2011, Mr. Jennings was an independent consultant providing financial accounting services, primarily to smaller public companies.  From 2006 until 2011, he also served as the Chief Financial Officer of Gold Resource Corporation (AMEX:GORO).  From 2000 to 2005, he served as the Chief Financial Officer and a director of Global Casinos, Inc., a publicly traded corporation, and from 1994 to 2001 he served as Chief Financial Officer of American Educational Products, Inc. (NASDAQ:AMEP), before it was purchased by Nasco International.  After his graduation from Austin College with a degree in economics and from Indiana University with an MBA in finance, he joined the Houston office of Coopers & Lybrand.  He also spent four years as the manager of internal audit for The Walt Disney Company.

Rick A. Wilber – Mr. Wilber has been one of our directors since September 2008.  Since 1984, Mr. Wilber has been a private investor in, and a consultant to, numerous development stage companies.  In 1974, Mr. Wilber was co-founder of Champs Sporting Goods, a retail sporting goods chain, and served as its President from 1974-1984.  He has been a Director of Ultimate Software Group Inc. since October 2002 and serves as a member of its audit and compensation committees.  Mr. Wilber was a director of Ultimate Software Group between October 1997 and May 2000.  He served as a director of Royce Laboratories, Inc., a pharmaceutical concern, from 1990 until it was sold to Watson Pharmaceuticals, Inc. in April 1997 and was a member of its compensation committee.

 
41

 
Raymond E. McElhaney – Mr. McElhaney has been one of our directors since May 2005.  Since January 2013, he has been the President of a private financial Company, Longhorn Investments, LLC. Until December 2012, he was the President of MCM Capital Management Inc., a privately held financial management company.  Mr. McElhaney is a seasoned executive with numerous appointments, directorships and consulting roles with both private and public companies in a variety of industries and business sectors.  Mr. McElhaney has a strong background in oil and gas exploration and management and was a former Officer and Director of Wyoming Oil and Minerals and a Director of United States Exploration, Inc., both publically traded companies. Mr. McElhaney was a managing partner in the Waco Pipeline, a natural gas gathering system. Over the course of his career, Mr. McElhaney has advised companies on M&A and equity deals, commercial finance transactions, stock offerings, spinoffs and joint venture arrangements. Mr. McElhaney has been involved as an owner breeder of Thoroughbred race horses since 1981. Mr. McElhaney received his Bachelor of Science Degree in Business Administration from the University of Northern Colorado in 1978.

Bill M. Conrad – Mr. Conrad has been one of our directors since May 2005 and prior to the acquisition of Predecessor Synergy was our Vice President and Secretary.  Mr. Conrad has been involved in several aspects of the oil and gas industry over the past 30 years.  From February 2002 until June 2005, Mr. Conrad served as president and a director of Wyoming Oil & Minerals, Inc., and from 2000 until April 2003, he served as vice president and a director of New Frontier Energy, Inc.  Since June 2006, Mr. Conrad has served as a director of Gold Resource Corporation, a publicly traded corporation engaged in the mining industry.  In 1990, Mr. Conrad co-founded MCM Capital Management Inc. and has served as its vice president until December 2012.

R.W. “Bud” Noffsinger, III – Mr. Noffsinger was appointed as one of our directors in September 2009.  Mr. Noffsinger has been the President/ CEO of RWN3 LLC, a company involved with investment securities, since February 2009.  Previously, Mr. Noffsinger was the President (2005 to 2009) and Chief Credit Officer (2008 to 2009) of First Western Trust Bank in Fort Collins, Colorado.  Prior to his association with First Western, Mr. Noffsinger was a manager with Centennial Bank of the West (now Guaranty Bank and Trust).  Mr. Noffsinger’s focus at Centennial was client development and lending in the areas of commercial real estate, agriculture and natural resources.  Mr. Noffsinger is a graduate of the University of Wyoming and holds a Bachelor of Science degree in Economics with an emphasis on natural resources and environmental economics.

George Seward – Mr. Seward was appointed as one of our directors on July 8, 2010. Mr. Seward cofounded Prima Energy in 1980 and served as its Secretary until 2004, when Prima was sold to Petro-Canada for $534,000,000.  At the time of the sale, Prima had 152 billion cubic feet of proved gas reserves and was producing 55 million cubic feet of gas daily from wells in the D-J Basin in Colorado and the Powder River Basin of Wyoming and Utah.  Since March 2006 Mr. Seward has been the President of Pocito Oil and Gas, a limited production company, with operations in northeast Colorado, southwest Nebraska and Barber County, Kansas.  Mr. Seward has also operated a diversified farming operation, raising wheat, corn, pinto beans, soybeans and alfalfa hay in southwestern Nebraska and northeast Colorado, since 1982.
 
We believe Messrs. Holloway, Scaff, McElhaney, Conrad and Seward are qualified to act as directors due to their experience in the oil and gas industry.  We believe Messrs. Wilber and Noffsinger are qualified to act as directors as result of their experience in financial matters.

Rick Wilber, Raymond McElhaney, Bill Conrad and R.W. Noffsinger, are considered independent as that term is defined Section 803.A of the NYSE MKT Rules.
 
The members of our compensation committee are Rick Wilber, Raymond McElhaney, Bill Conrad, and R.W. Noffsinger.  The members of our Audit Committee are Raymond McElhaney, Bill Conrad and R.W. Noffsinger.  Mr. Noffsinger acts as the financial expert for the Audit Committee of our board of directors.
 
We have adopted a Code of Ethics applicable to all employees.
 
 
42

 

ITEM 11.  EXECUTIVE COMPENSATION

The following table shows the compensation paid or accrued to our executive officers during each of the three years ended August 31, 2013 (in thousands).

Name and Principal
Position
 
Fiscal
Year
 
Salary1
   
Bonus2
   
Stock
Awards3
   
Option
Awards4
   
All Other Compensation5
   
Total
 
Ed Holloway,
 
2013
 
$
330
     
200
     
     
     
10
   
$
540
 
President and Chief
 
2012
 
$
300
     
100
     
     
     
10
   
$
410
 
Executive Officer
 
2011
 
$
300
     
100
     
     
     
10
   
$
410
 
                                                     
William E. Scaff, Jr.,
 
2013
 
$
330
     
200
     
     
     
10
   
$
540
 
Vice President, Secretary
 
2012
 
$
300
     
100
     
     
     
10
   
$
410
 
and Treasurer
 
2011
 
$
300
     
100
     
     
     
10
   
$
410
 
                                                     
Frank L Jennings,
 
2013
 
$
180
     
     
     
     
7
   
$
187
 
Chief Financial Officer
 
2012
 
$
180
     
     
     
     
5
   
$
185
 
   
2011
 
$
88
     
     
220
     
404
     
   
$
712
 
 
1
The dollar value of base salary (cash and non-cash) earned.
2
The dollar value of bonus (cash and non-cash) earned.
3
The fair value of stock issued for services computed in accordance with ASC 718 on the date of grant.
4
The fair value of options granted computed in accordance with ASC 718 on the date of grant.
5
All other compensation received that we could not properly report in any other column of the table.
 
The compensation to be paid to Mr. Holloway, Mr. Scaff and Mr. Jennings will be based upon their employment agreements, which are described below.  All material elements of the compensation paid to these officers is discussed below.
 
On June 1, 2010, the Company entered into employment agreements with Mr. Holloway and Mr. Scaff.  The employment agreements, which expired on May 31, 2013, provide that the Company will pay Mr. Holloway and Mr. Scaff each a monthly salary of $25,000 and require both Mr. Holloway and Mr. Scaff to devote approximately 80% of their time to the Company’s business.  In addition, for every 50 net vertical wells that begin producing oil and/or gas after June 1, 2010, whether as the result of the Company’s successful drilling efforts or acquisitions, the Company would issue to each of Mr. Holloway and Mr. Scaff, a cash payment of $100,000 or shares of common stock in an amount equal to $100,000 divided by the average closing price of the Company’s common stock for the 20 trading days prior to the date the 50th well began producing.

Effective June 1, 2013 the Company entered into new employment agreements with Ed Holloway, Synergy’s President and Chief Executive Officer, and William E. Scaff, Jr., Synergy’s Executive Vice President and Secretary/Treasurer.  The employment agreements, which expire on May 31, 2016, provide that the Company will pay Mr. Holloway and Mr. Scaff each an annual salary of $420,000 and require Mr. Holloway and Mr. Scaff to devote approximately 80% of their time to the Company.  In addition, for every 50 wells that begin producing oil and/or gas after June 1, 2013, whether as the result of the Company’s successful drilling efforts or acquisitions, the Company will pay each of Mr. Holloway and Mr. Scaff $100,000, up to a maximum $300,000 during any 12 month period, provided that:

·  
each horizontal well that meets the criteria above will count toward seven wells (as adjusted to reflect the Company’s net working interest in each horizontal well), and
 
·  
the unpaid balance pertaining to any wells included in the previous “50 well bonus program” that first began producing commercial quantities of oil and/or gas as a result of the successful drilling efforts, or as the result of a completed acquisition by the Company, during the three year period ended May 31, 2013, will be counted toward the 50 net well limit applicable for the period beginning June 1, 2013.

The employment agreements will terminate upon the death of Mr. Holloway or Mr. Scaff, their disability or for cause, as the cause may be.  If the employment agreement is terminated for any of these reasons, the employee or his legal representatives, as the case may be, will be paid the salary provided by the employment agreement through the date of termination.

 
43

 
The employment agreements with Mr. Holloway and Mr. Scaff will also will terminate if a Change of Control has occurred.  In the event of a Change in Control, Mr. Holloway and Mr. Scaff can resign as an employee of Synergy and Synergy will pay Mr. Holloway and Mr. Scaff the greater of twelve months of salary or the amount due under their employment agreements.  Whether or not Mr. Holloway of Mr. Scaff resigns as a result of a Change in Control event, all options or bonus shares of Synergy held by Mr. Holloway and Mr. Scaff will become fully vested.

The new employment agreements with Mr. Holloway and Mr. Scaff were approved by our Compensation Committee and Board of Directors.

On June 23, 2011 our directors approved an employment agreement with Frank L. Jennings, our Chief Financial Officer.  The employment agreement provides that we will pay Mr. Jennings a monthly salary of $15,000 and issue to Mr. Jennings:

·
50,000 shares of our restricted common stock; and
 
·
options to purchase 150,000 shares of our common stock.  The options are exercisable at a price of $4.40 per share, vest over three years in 50,000 share increments beginning March 6, 2012, and expire on March 7, 2021.

The employment agreement expires on March 7, 2014 and requires Mr. Jennings to devote all of his time to our business.
 
Generally, if an officer resigns within 90 days of a relocation (or demand for relocation) of his place of employment to a location more than 35 miles from his then current place of employment, the employment agreement will be terminated and the officer will be paid the salary provided by the employment agreement through the date of termination and the unvested portion of any stock options held by the officer will vest immediately.

In the event there is a change in control, the employment agreements allows an officer to resign from his position and receive a lump-sum payment equal to 12 months’ salary.  In addition, the unvested portion of any stock options held by the officer will vest immediately.  For purposes of the employment agreement, a change in the control means: (1) our merger with another entity if after such merger our shareholders do not own at least 50% of the voting capital stock of the surviving corporation; (2) the sale of substantially all of our assets; (3) the acquisition by any person of more than 50% of our common stock; or (4) a change in a majority of our directors which has not been approved by our incumbent directors.
 
The employment agreements mentioned above will terminate upon the employee’s death, or disability or may be terminated by us for cause.  If the employment agreement is terminated for any of these reasons, the employee, or his legal representatives as the case may be, will be paid the salary provided by the employment agreement through the date of termination.
 
For purposes of the employment agreements, “cause” is defined as:
 
 
(i)
the conviction of the employee of any crime or offense involving, or of fraud or moral turpitude, which significantly harms us;
 
 
(ii)
the refusal of the employee to follow the lawful directions of our board of directors;
 
 
(iii)
the employee’s negligence which shows a reckless or willful disregard for reasonable business practices and significantly harms us;  or
 
 
(iv)
a breach of the employment agreement by the employee.

Executive officer compensation, as provided above, is structured to be competitive both in its design and in the total compensation offered.  The Compensation Committee of the Board of Directors determines the compensation of our officers.  The Committee’s philosophy on officer compensation is to align executive and shareholder interests. The philosophy’s objective is to provide fair compensation based upon the individual’s position, experience and individual performance.

Our current policy is that the various elements of the compensation package are not interrelated in that gains or losses from past equity incentives are not factored into the determination of other compensation.

A goal of the compensation program is to provide executive officers with a reasonable level of security through base salary and benefits. We want to ensure that the compensation programs are appropriately designed to encourage executive officer retention and motivation to create shareholder value. The Compensation Committee believes that our stockholders are best served when we can attract and retain talented executives by providing compensation packages that are competitive but fair.

 
44

 
The key components of our executive compensation program include annual base salaries and long-term incentive compensation consisting of stock options. It is our policy to target compensation (i.e., base salary, stock option grants and other benefits) at approximately the median of comparable companies in the oil and gas exploration and development industry. Accordingly, data on compensation practices followed by other companies in the oil and gas exploration and development industry is considered.

Base salaries generally have been targeted to be competitive when compared to the salary levels of persons holding similar positions in other oil and gas exploration and development companies and other publicly traded companies of comparable size.

Stock option grants help to align the interests of our officers with those of its shareholders. Options grants are made under the Company’s Stock Option Plan.

We believe that grants of stock options:
 
     
Enhance the link between the creation of shareholder value and long-term executive incentive compensation;
 
     
Provide focus, motivation and retention incentive; and
 
     
Provide competitive levels of total compensation.

Our long-term incentive program includes of periodic grants of stock options with an exercise price equal to the fair market value of our common stock on the date of grant. Decisions made regarding the timing and size of option grants take into account our performance and that of the employee, “competitive market” practices, and the size of the option grants made in prior years. The weighting of these factors varies and is subjective.

In addition to cash and equity compensation programs, executive officers participate in the health insurance programs available to our other employees.

All executive officers are eligible to participate in the Company’s 401(k) plan on the same basis as all other employees. We matche participant’s contribution in cash, not to exceed 4% of the participant’s total compensation.
 
Employee Pension, Profit Sharing or other Retirement Plans.  Effective November 1, 2010, we adopted a defined contribution retirement plan, qualifying under Section 401(k) of the Internal Revenue Code and covering substantially all of our employees.  We match participant’s contributions in cash, not to exceed 4% of the participant’s total compensation.  Other than this 401(k) Plan, we do not have a defined benefit pension plan, profit sharing or other retirement plan.
 
Stock Option and Bonus Plans
 
We have three stock award plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan.  Each plan authorizes the issuance of shares of our common stock to persons that exercise options granted pursuant to the Plan.  Our employees, directors, officers, consultants and advisors are eligible to receive such awards, provided that bona fide services be rendered by such consultants or advisors and such services must not be in connection with promoting our stock or the sale of securities in a capital-raising transaction.  The option exercise price is determined by our directors, though generally is based upon the closing market price of our shares on the date of grant.
 
Summary. The following is a summary of options granted or shares issued pursuant to the Plans as of October 31, 2013.  Each option represents the right to purchase one share of our common stock.
 
Name of Plan
 
Total Shares Reserved Under Plans
   
Reserved for Outstanding Options
   
Shares Issued as Stock Bonus
   
Remaining Options/Shares Under Plans
 
2011 Non-Qualified Stock Option Plan
   
5,000,000
     
1,954,000
     
     
2,910,000
 
2011 Incentive Stock Option Plan
   
2,000,000
     
     
     
2,000,000
 
2011 Stock Bonus Plan
   
2,000,000
     
     
185,000
     
1,815,000
 
 

 
45

 
Options

In connection with the acquisition of a corporation in 2008, we issued options to the persons shown below in exchange for options previously issued by that corporation.  The terms of the options we issued are identical to the terms of the previously issued options.  The options were not granted pursuant to our 2005 Plans.  During 2013, the options were modified to extend the expiration date to August 31, 2013.  On August 27, 2013, the options were exercised.

Among other provisions, the options contained a net settlement provision that allowed for exercise of the options on a cashless basis.  Under net settlement terms, the option holder is deemed to exercise options and simultaneously tender the shares back to us in settlement of amounts owed for payment of the exercise price and to satisfy statutory payroll tax withholding requirements.  Thus, under a net settlement transaction, the option holder immediately surrenders a number of shares to which they are otherwise entitled, and the net number of shares issued is less than the options exercised.

The following table shows information concerning the options exercised during the fiscal year ended August 31, 2013 by the person named below:
 
Name
 
Date of
Exercise
 
Shares Acquired
On Exercise
   
Value
Realized
(in thousands)
 
Ed Holloway
 
August 27, 2013
    486,978  1     $ 7,530  
William E. Scaff, Jr.
 
August 27, 2013
    486,978  1     $ 7,530  

1
Represents net shares acquired upon the cashless exercise of 1 million options.  Pursuant to the net settlement provision, the option holder immediately tendered 513,022 shares to satisfy statutory tax withholding and payment of option exercise price.

The following table shows information concerning our outstanding options as of October 31, 2013.
 
     
Shares underlying unexercised 
Option which are:
   
Exercise 
     
Expiration 
 
Name
   
Exercisable
     
Unexercisable
   
Price 
     
Date 
 
Frank L. Jennings
   
100,000
     
50,000
   
$
4.40
     
3/7/21
 
Employees
   
358,000
 1
   
1,446,000
  
 
 1
     
1
  
 
1
Options were issued to several employees pursuant to our Non-Qualified Stock Option Plan.  The exercise price of the options varies between $2.40 and $10.67 per share.  The options expire at various dates between December 2018 and October, 2023.

The following table shows the weighted average exercise price of the outstanding options granted pursuant to our Non-Qualified Stock Option Plan or otherwise as of August 31, 2013.

Plan Category
 
Available Securities to be Issued Upon Exercise of Outstanding Options
   
Weighted-Average Exercise Price of Outstanding Options
 
             
Non-Qualified Stock Option Plan
   
1,820,000
   
$
4.88
 
 
 
46

 
Compensation of Directors During Year Ended August 31, 2013 (in thousands)
 
Name
 
Fees Earned or
 Paid in Cash
   
Stock
 Awards1
   
Option
 Awards2
   
Total
 
                         
Rick Wilber
 
$
     
54
     
   
$
54
 
Raymond McElhaney
   
29
     
33
     
     
62
 
Bill Conrad
   
64
     
     
     
64
 
R.W. Noffsinger
   
64
     
     
     
64
 
George Seward
   
56 
     
 —
     
     
56
 
   
$
213
     
87
     
   
$
300
 
 
1
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