FORM 10-K

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                   (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, 2011
                                       OR

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


                       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                 (I.R.S.Employer
 incorporation or organization)                 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 AMEX
-----------------------------------    ----------------------------------
-----------------------------------    ----------------------------------

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

----------------------------------------------------------------------------
                                (Title of class)

----------------------------------------------------------------------------
                                (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. [ ]

Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. [ ]

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 [ ]

Indicate by check mark weather 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 [ ]

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]

<PAGE>

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  [ ]                  Accelerated filer  [X]

Non-accelerated filer  [ ]                    Smaller reporting company  [ ]
(Do not check if a smaller reporting company)

Indicate by check mark whether the  registrant is a shell company (as defined in
Rule 12b-2 of the Act): [ ] Yes [X] No

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, 2011, was approximately $90,388,000.

As of November 1, 2011, the Registrant had 36,098,212 issued and outstanding
shares of common stock.

Documents Incorporated by Reference:   None

<PAGE>


                                     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:

     o    The success of our exploration and development efforts;
     o    The price of oil and gas;
     o    The worldwide economic situation;
     o    Any change in interest rates or inflation;
     o    The   willingness   and  ability  of  third  parties  to  honor  their
          contractual commitments;
     o    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;
     o    Our capital costs, as they may be affected by delays or cost overruns;
     o    Our costs of production;
     o    Environmental  and other  regulations,  as the same presently exist or
          may later be amended;
     o    Our   ability  to   identify,   finance  and   integrate   any  future
          acquisitions; and
     o    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  Wattenberg  field in the D-J
Basin in northeast Colorado.  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,  2011,  we had 183,584  gross and 162,461 net acres
under lease,  substantially  all of which are located in the D-J Basin.  Of this
acreage, 7,110 gross acres are held by production. Between September 1, 2008 and
October 31, 2011, we drilled and completed 56 development  wells that we own and
operate.  Additionally,  during  this  timeframe  we  acquired  interests  in 72
producing wells.

     At August 31,  2011,  our  estimated  net proved oil and gas  reserves,  as
prepared by our independent reserve engineering firm, Ryder Scott Company, L.P.,

                                       1

<PAGE>

were  2,069.7  MBbls  of oil and  condensate  and 14.3 Bcf of  natural  gas.  We
operated  95 wells and had an  ownership  interest  in 141 gross  wells (103 net
wells).

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:

     o    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.

     o    Develop and exploit existing oil and natural gas properties. Since our
          inception  our  principal  growth  strategy  has been to  develop  and
          exploit our acquired and discovered properties to add proved reserves.
          As of October 31, 2011, we have  identified  over 400  development and
          extension  drilling  locations  and  over  20   recompletion/work-over
          projects on our existing properties and wells.

     o    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.

     o    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.

     o    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.

  Competitive Strengths


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

     o    Management experience. Our key management team possesses an average of
          thirty  years of  experience  in the oil and gas  industry,  primarily

                                       2

<PAGE>

          within the D-J Basin. Members of our management
          team have drilled,  participated in drilling, and/or operated over 350
          wells in the D-J Basin.

     o    Balanced oil and natural gas reserves  and  production.  At August 31,
          2011,  approximately 47% of our estimated proved reserves were oil and
          condensate  and 53% were  natural  gas and  liquids.  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.

     o    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.

     o    Insider  ownership.  At October 31, 2011 our  directors  and executive
          officers  beneficially  owned  approximately  33% of  our  outstanding
          shares of common  stock,  providing  a strong  alignment  of  interest
          between   management,   the  board  of   directors   and  our  outside
          shareholders.


Recent Developments

     We expanded our business  during the fiscal year ended August 31, 2011.  We
increased  our  producing  wells,  our reserves,  and our  undeveloped  acreage.
Significant developments are described below.

     Acquisition  of  Oil  and  Gas  Properties  from  Petroleum  Exploration  &
Management  LLC - In May 2011,  we  acquired  interests  in 88 gross oil and gas
wells (40 net) in the  Wattenberg  Field,  and  interests  in oil and gas leases
covering  approximately  6,968 gross  acres.  These oil and gas  interests  were
acquired from Petroleum Exploration and Management, LLC ("PEM"), a company owned
by Ed Holloway and William E. Scaff, Jr., two of our officers, for consideration
of a cash payment of $10 million, a promissory note payable of $5.2 million, and
1,381,818 shares of restricted common stock. The transaction was approved by the
disinterested directors and by a vote of the shareholders, with Mr. Holloway and
Mr. Scaff not voting. Some of the 88 gross wells acquired were wells operated by
us and in which PEM held a minority interest.

     On October 1, 2010, we completed the  acquisition of oil and gas properties
in the  Wattenberg  Field  from  Petroleum  Management,  LLC  (also  owned by Ed
Holloway and William E. Scaff) and PEM for  approximately  $1.0  million.  These
properties  include 8 oil and gas wells (100% working interest / 80% net revenue
interest), 15 drill sites (net 6.25 wells) and miscellaneous equipment.

     We expanded  our growth  strategy to include an area of interest in eastern
Colorado   (including  Yuma  and  Washington   counties)  and  western  Nebraska
(including Hayes, Dundy, and Chase counties).  We designate the area of interest
as the Shallow Niobrara Acreage. Our acquisitions totaled 166,434 gross (147,849
net)  undeveloped  acres. The majority of these oil and gas lease interests were
acquired in exchange for 1,849,838  shares of our common stock.  George  Seward,
one of our directors,  has extensive  experience in the area. We look forward to
evaluating this area as it could provide excellent growth  opportunities and may
yield a significant return on investment.

                                       3

<PAGE>

     On May 26,  2011,  we entered  into a farm-in  agreement  with an unrelated
third party pertaining to a 640-acre lease in the Wattenberg Filed.  Pursuant to
the terms of the agreement,  we were required to commence drilling five wells on
the lease by August 15, 2011.  Drilling  operations  began on August 1, 2011 and
were  completed  for these  five  wells on August 31,  2011.  Subsequent  to the
completion of these five wells, we have the option of drilling  additional wells
on the lease in accordance with the following schedule:

     o    five wells by February 15, 2012
     o    five wells by August 15, 2012
     o    five wells by February 15, 2013.

     If we do not adhere to the foregoing  drilling  schedule our right to drill
any additional wells on the lease will terminate. For each well drilled, we will
receive an assignment of the lease covering the 40 acres  surrounding  the well.
However, if we drill and complete all 20 wells allowed by the farm-in agreement,
we will receive an assignment  of the entire lease.  We will have a 100% working
interest  (80% net revenue  interest)  in any acreage  assigned to us and in any
wells we drill on the leased acreage. We estimate the aggregate cost of drilling
and completing our option wells on this lease will be approximately $10 million.

     On January 11,  2011,  we closed on the sale of 9 million  shares of common
stock to private investors.  The shares were sold at a price of $2.00 per share.
Net proceeds from the sale of the shares were approximately  $16.7 million after
deductions for the sales commissions and expenses.

     On June 8, 2011,  we entered  into a revolving  line of credit with Bank of
Choice,  which allows us to borrow up to $7 million.  Amounts borrowed under the
line of credit  are  secured  by certain of our assets as well as 64 oil and gas
wells in which we have a working interest.  Principal amounts  outstanding under
the line of credit bear interest,  payable  monthly,  at the prime rate plus 2%,
subject to a minimum interest rate of 5.5%.

     All of the persons holding our 8% convertible  promissory  notes elected to
convert  their notes into  shares of common  stock at a rate of $1.60 per common
share, thereby converting an $18 million convertible note liability into equity.
In addition,  there was a derivative  conversion  liability  associated with the
notes  that was  converted  into  equity at the same time,  which  significantly
strengthened our balance sheet and eliminated  future impact on our statement of
operations from changes in fair value of the financial instruments.

     We received cash proceeds from two separate  sales of  undeveloped  oil and
gas leases covering an aggregate of 5,902 gross acres (3,738 net acres) for $8.4
million. These acres were outside our core area of interest.

     Our development  efforts during the year focused on completing and bringing
on-line  14 wells  drilled  as part of our 2010  drilling  program  and new well
development on existing prospects.  In December 2010, we acquired four producing
wells  in an area  that is  adjacent  to our  Pratt  prospect.  We  subsequently
commenced  drilling  on our Pratt  prospect,  and we  successfully  drilled  and
completed 14 development wells. Our development activities on our Pratt prospect
resulted  in  the  conversion  of  90,996  Bbls  and  1,006,188  Mcf  of  proved

                                       4

<PAGE>

undeveloped  reserves reported at August 31, 2010 into proved producing reserves
of 271,813 Bbls and 1,317,117 Mcf as of August 31, 2011.

     In August 2011,  we commenced a 21-well  drilling  program on various other
lease  prospects.  We anticipate  the drilling of these wells to be completed by
December 2011, with completion following shortly thereafter.

Well and Production Data

     Since  September  2008,  and through  October 31, 2011, we have drilled and
completed  56 gross  oil and gas  wells  which we own and  operate.  We have not
drilled any dry holes.  We have  acquired  interests in 72 gross wells.  We have
participated  with other  operators in the drilling and  completion  of 13 gross
wells. These wells were all located in the Wattenberg Field of the D-J Basin.

     During the periods presented, we drilled or participated in the drilling of
the following wells. We did not drill any exploratory wells during these years.

                             Years Ended August 31,
               -----------------------------------------------------------------
                       2011                   2010                  2009
               ---------------------  ---------------------  -------------------
                 Gross       Net       Gross        Net       Gross       Net
               ----------  ---------  ---------  ----------  ---------  --------
Development
Wells:
  Productive:
    Oil               31       22.4         36        23.8          2       0.75
    Gas               --         --         --          --         --         --
Nonproductive         --         --         --          --         --         --

     As of  October  31,  2011,  we were  drilling 1 gross (1 net) well and were
completing  15  gross  (15  net)  wells.  These  wells  are all  located  in the
Wattenberg Field of the D-J Basin.

     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,
                               --------------------------------------
                                   2011         2010         2009
                               -------------  ---------   -----------
Production:
Oil (Bbls)                           89,917     21,080         1,730
Gas (Mcf)                           450,831    141,154         4,386

Average sales price:
Oil ($/Bbl)                          $83.07     $68.38        $45.59
Gas ($/Mcf)                          $ 5.12     $ 5.08        $ 3.48

Average  production  cost  per       $ 2.13     $ 1.94        $ 0.85
BOE

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

                                       5

<PAGE>

"Mcf" refers to one thousand cubic feet. A BOE (i.e.  barrel of oil  equivalent)
combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl
of oil.

     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 advalorem
and severance taxes, are not included in 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.

Oil and Gas Properties and Proven Reserves

     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:

     o    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

     o    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,   carried,  net  profits,  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, 2011, by state,  our producing
wells, developed acreage, and undeveloped acreage,  excluding service (injection
and disposal) wells:

                Productive Wells       Developed Acreage     Undeveloped Acreage
               -------------------    --------------------   -------------------
  State         Gross       Net        Gross       Net        Gross       Net
-----------    ---------  --------    ---------  ---------   ---------  --------

Colorado            151     112.6        6,148      6,122      58,947     39,497

Nebraska              -         -     -          -            118,329    116,682

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<PAGE>


Wyoming               -         -     -          -                160        160
               ---------  --------    ---------  ---------   ---------  --------
  Total             151     112.6        6,148      6,122     177,436    156,339
               =========  ========    =========  =========   =========  ========

(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, 2011, the status of our gross
acreage:

  State         Held by        Not Held by
               Production      Production
-----------  ---------------  --------------

Colorado              7,110          57,985

Nebraska                  -         118,329
Wyoming                   -             160
             ---------------  --------------
  Total               7,110         176,474
             ===============  ==============

     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.

     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    Expiration
           Acres      of Lease
    ---------------  -----------


             995        2012

           6,922        2013

          10,602        2014

         157,955     After 2014

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

     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,  2011.  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 report of Ryder Scott is filed as Exhibit
99 to this report. Ryder Scott was selected by two of our officers,  Ed Holloway
and William E. Scaff, Jr.

                                       7

<PAGE>

     Thomas E.  Venglar  was the  technical  person  primarily  responsible  for
overseeing the preparation of the reserve report.  Mr. Venglar earned a Bachelor
of Science  degree in Petroleum  Engineering  from Texas A&M University and is a
registered Professional Engineer in Colorado. Mr. Venglar has more than 30 years
of practical experience in the estimation and evaluation of petroleum reserves.

     Ed  Holloway,  our  President,  oversaw  the  preparation  of  the  reserve
estimates by Ryder Scott.  Mr.  Holloway has over thirty years of  experience in
oil and gas exploration and development.  We do not have a reserve committee and
we do not have any specific  internal  controls  regarding  the estimates of our
reserves.

     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 millions 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, 2011 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 2011.

     Below are estimates of our net proved  reserves at August 31, 2011,  all of
which are located in Colorado:

                      Oil         Gas
                    (Bbls)       (Mcf)        BOE
                   ----------  -----------  ---------
Proved:
  Producing          613,180    4,497,733   1,362,802
  Nonproducing       170,641    1,080,334    350,697
  Undeveloped      1,285,884    8,683,091   2,733,066
                   ----------  -----------  ---------
    Total          2,069,705   14,261,158   4,446,565
                   ==========  ===========  =========

     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

                                       8

<PAGE>

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,
2011 and 2010. 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, 2011 and 2010, our  standardized  oil and gas measurements
were as follows:


<TABLE>
<S>                           <C>               <C>           <C>             <C>
                                           Proved - August 31, 2011
                        ----------------------------------------------------------------
                                  Developed                                   
                        -------------------------------                       Total
                           Producing      Nonproducing     Undeveloped       Proved
                        --------------  ---------------  ---------------  --------------
 Future gross revenue    $71,027,480     $ 18,819,100     $145,392,300    $ 235,238,880
 Deductions              (14,298,253)      (5,647,380)     (61,736,015)     (81,681,648)
 Future net cash flow     56,729,227       13,171,720       83,656,285      153,557,232
 Discounted future net
 cash flow (pre-tax)     $ 33,946,592    $    6,995,878   $ 30,815,373    $  71,757,843
 Standardized measure
 of discounted future
 net cash flows (after
 tax)                                                                     $  57,550,414
</TABLE>



<TABLE>
<S>                           <C>               <C>           <C>             <C>
                                             Proved - August 31, 2010
                          ----------------------------------------------------------------
                                    Developed                                   
                          ------------------------------                        Total
                            Producing     Nonproducing      Undeveloped        Proved
                          --------------  --------------   ---------------  --------------
  Future gross revenue    $ 12,323,383     $ 24,126,662     $ 28,220,857    $  64,670,902
  Deductions                (2,955,552)      (8,942,579)     (20,319,150)    (32,217,281)

  Future net cash flow       9,367,831       15,184,083        7,901,707       32,453,621
  Discounted future net   
  cash flow (pre-tax)     $  6,120,468     $  8,704,767     $  1,732,491    $  16,557,726
  Standardized measure
  of discounted future
  net cash flows (after
  tax)                                                                      $  13,022,397
</TABLE>


     For   standardized  oil  and  gas  measurement   purposes,   our  drilling,
acquisition,  and participation activities during the year ended August 31, 2011
generated  increases in projected  future gross revenue from proved  reserves of
$170,567,978  and future net cash flow of  $121,103,611  from  August 31,  2010.
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 $55,200,117.  Our  standardized  measure of discounted  future net cash flows
increased by $44,528,017  from August 31, 2010 to August 31, 2011.  Increases in
our standardized oil and gas measures were the result of our expenditures during
the  year  ended  August  31,  2011  of  approximately  $36.5  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 conducts  successful  exploration and
development  activities,  or both, our proved  reserves will decline as reserves
are produced.  Accordingly,  volumes  generated  from our future  activities are

                                       9

<PAGE>

highly  dependent  upon the level of success in acquiring or finding  additional
reserves and the costs incurred in doing so.

     As of August 31, 2011 our proved developed  reserves consisted of 2,069,705
Bbls of oil and  14,261,158  Mcf of gas. Our proved  developed  and  undeveloped
reserves  increased  substantially  during  the  year  ended  August  31,  2011,
primarily  as the result of our  drilling  and  completing  21 gross  (14.8) net
wells, the acquisition of oil and gas properties from Petroleum  Exploration and
Management, LLC.

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 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

                                       10

<PAGE>

increases  our cost of doing  business  and affects its  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.

     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 our 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 interpretations  thereof 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

                                       11

<PAGE>

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 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.

     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 2011 for
emissions occurring in 2010.

     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. The U.S.  Senate has begun work on
its own  legislation  for  restricting  domestic  greenhouse  gas  emissions and

                                       12

<PAGE>

President  Obama has indicated his support of legislation  to reduce  greenhouse
gas emissions through an emission allowance system.

     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  ("frack"  or  "fracking")  to  allow  for  or  increase  hydrocarbon
production.  Fracking  involves  the  process  of forcing a mixture of fluid and
proppant  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
fracked and we expect to frack all future wells that we drill.

     We  outsource  all  fracking  related  services to service  providers  with
significant  fracking  experience,   and  whom  we  deem  to  be  competent  and
responsible. Our fracking service providers supply all personnel,  equipment and
materials needed to perform each frack, including the mixtures that are injected
into our wells. These mixtures primarily consist of water and sand, with nominal
amounts of other ingredients that include chemical  compounds  commonly found in
consumer  products.  This  mixture is injected  into our wells at  pressures  of
5,500-6,000  psi at injection  rates that that range  between  25-55  barrels of
mixture  per  minute.   On  average,   a  typical   fracking  job  will  utilize
approximately 4,500 barrels of water and 125,000 pounds of sand.

     The  fracking  service  companies we hire  indemnify  us against  incidents
occurring in connection with their fracking  activities.  Our service  providers
are  responsible  for obtaining  any  regulatory  permits  necessary for them to
perform their services in the respective  geographic  location.  The Company has
not had any  incidents,  citations  or lawsuits  relating  to any  environmental
issues resulting from fracking and is not presently aware of any such matters.

Competition and Marketing

     We will be faced with  strong  competition  from many other  companies  and
individuals  engaged  in the oil and gas  business,  many 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.

     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 will depend upon  independent
drilling  contractors  to furnish rigs,  equipment and tools to drill its wells.
Higher  prices for oil and gas may result in  competition  among  operators  for

                                       13

<PAGE>

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 lease  requires  monthly  payments of
$10,000 and expires on July 1, 2012.

     As of October 31, 2011, we had 11 full time employees.

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


I
TEM 1A.  RISK FACTORS

     Not applicable

                                       14

<PAGE>


ITEM 1B.    UNRESOLVED STAFF COMMENTS

     Not applicable


ITEM 2.   PROPERTIES

     See Item 1 of this report.


ITEM 3.   LEGAL PROCEEDINGS

     None.


ITEM 4.   (REMOVED AND RESERVED)



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

     On February  27, 2008,  our common stock began  trading on the OTC Bulletin
Board under the symbol "BRSH." There was no  established  trading market for our
common stock prior to that date.

     On  September  22, 2008, a 10-for-1  reverse  stock split,  approved by our
shareholders  on September 8, 2008,  became  effective on the OTC Bulletin Board
and our trading symbol was changed to  "SYRG.OB.".  On July 27, 2011, our common
stock began trading on the NYSE Amex under the symbol "SYRG".

     Shown  below is the range of high and low  closing  prices  for our  common
stock for the periods  indicated as reported by the OTC Bulletin  Board prior to
July 27,  2011 and by the NYSE  Amex on and  after  July 27,  2011.  The  market
quotations reflect  inter-dealer  prices,  without retail mark-up,  mark-down or
commissions and may not necessarily represent actual transactions.

      Quarter Ended                                         High     Low
      -------------                                         ----     ---

       November 30, 2008                                   $4.75     $3.10
       February 28, 2009                                   $3.45     $1.25
       May 31, 2009                                        $1.80     $1.45
       August 31, 2009                                     $1.80     $1.10

      Quarter Ended                                         High     Low
      -------------                                         ----     ---

       November 30, 2009                                   $1.47     $1.00
       February 28, 2010                                   $3.86     $1.35
       May 31, 2010                                        $3.85     $2.40
       August 31, 2010                                     $3.00     $2.25

                                       15

<PAGE>

      Quarter Ended                                         High     Low
      -------------                                         ----     ---

       November 30, 2010                                   $2.40     $1.95
       February 28, 2011                                   $4.74     $2.25
       May 31, 2011                                        $4.90     $3.20
       August 31, 2011                                     $3.69     $2.55

     As of October 31, 2011,  the closing  price of our common stock on the NYSE
Amex was $2.96.

     As of October 31,  2011,  we had  36,098,212  outstanding  shares of common
stock and 293  shareholders  of record.  The number of beneficial  owners of our
common stock is approximately 925.

     Holders of our common  stock are  entitled to receive  dividends  as may be
declared by our board of  directors.  Our board of directors  is not  restricted
from paying any dividends  but is not  obligated to declare a dividend.  No cash
dividends have ever been declared and it is not anticipated  that cash dividends
will ever be paid.

     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.

     On December 1, 2008, we purchased 1,000,000 shares of our common stock from
the Synergy Energy Trust, one of our initial shareholders, for $1,000, which was
the same amount which we received  when the shares were sold to the Trust.  With
the exception of that  transaction,  we have not purchased any of our securities
and no person  affiliated  with us has purchased any of our  securities  for our
benefit.

Additional Shares Which May be Issued

     The following table lists additional shares of our common stock,  which may
be issued as of October 31, 2011 upon the  exercise  of  outstanding  options or
warrants or the issuance of shares for oil and gas leases.

                                                            Number of     Note
                                                              Shares   Reference
                                                            ---------  ---------

   Shares issuable upon the exercise of Series C 
      warrants                                           9,000,000        A

   Shares issuable upon the exercise of Series D
      placement agents' warrants                           769,601        A

                                       16

<PAGE>


   Shares issuable upon exercise of Series A warrants
      that were granted to those persons owning shares
      of our common stock prior to the acquisition of
      Predecessor Synergy                                1,038,000        B

   Shares issuable upon exercise of Series A warrants
      sold in prior private offering.                    2,060,000        C

   Shares issuable upon exercise of Series A and Series 
      B warrants                                         2,000,000        D

   Shares issuable upon exercise of sales agent warrants   126,932        D

   Shares issuable upon exercise of options held by our
      officers and employees                             4,645,000        E

   Shares issuable upon the closing of proposed transactions
      to acquire mineral interests                         287,244         F

A.  Between  December  2009 and  March  2010,  we sold  180  Units at a price of
$100,000 per Unit to private investors. Each Unit consisted of one $100,000 note
and 50,000 Series C warrants. The notes were converted into shares of our common
stock at a  conversion  price of $1.60 per share,  at the option of the  holder.
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 the interim reporting period ended May 31, 2011, all notes had been converted
into 11,250,000 shares of our common stock.


     We paid Bathgate  Capital  Partners (now named GVC Capital),  the placement
agent for the Unit offering,  a commission of 8% of the amount Bathgate  Capital
raised in 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. The placement  agent's warrants expire on December 31, 2014. As
of the  reporting  period ended August 31,  2011,  warrants to purchase  355,399
shares had been exercised by their holders.


B. Each  shareholder  of record on the close of  business on  September  9, 2008
received  one Series A warrant  for each share which they owned on that date (as
adjusted  for a  reverse  split of our  common  stock  which  was  effective  on
September 22, 2008).  Each Series A 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, 2012.


C. Prior to our  acquisition of Predecessor  Synergy,  Predecessor  Synergy sold
2,060,000  Units to a group of private  investors  at a price of $1.00 per Unit.
Each Unit consisted of one share of Predecessor  Synergy's  common stock and one
Series A warrant.  In connection  with the  acquisition of Predecessor  Synergy,
these Series A warrants  were  exchanged for 2,060,000 of our Series A warrants.
The Series A warrants are identical to the Series A warrants described in Note B
above.

                                       17

<PAGE>

D. Between  December 1, 2008 and June 30,  2009,  we sold  1,000,000  units at a
price of $3.00 per unit.  Each unit consisted of two shares of our common stock,
one  Series A warrant  and one  Series B  warrant.  The  Series A  warrants  are
identical  to the Series A warrants  described  in Note B above.  Each  Series B
warrant entitles the holder to purchase one share of our common stock at a price
of $10.00 per share at any time prior to December 31, 2012.

     In  connection  with this unit  offering,  we paid the sales  agent for the
offering a commission of 10% of the amount the sales agent sold in the offering.
We also issued  warrants to the sales agent.  The warrants allow the sales agent
to purchase  31,733 units  (which units were  identical to the units sold in the
offering) at a price of $3.60 per unit.  The sales agent warrants will expire on
the earlier of December 31, 2012 or twenty days following  written  notification
from us that our  common  stock  had a closing  bid price at or above  $7.00 per
share for any ten of twenty consecutive trading days.

E. See  Note 11 to the  Financial  Statements  included  with  this  report  for
information  regarding  shares  issuable  upon  exercise of options  held by our
officers and employees.

F. We may  issue up to  287,244  shares  of  common  stock in  exchange  for the
acquisition of oil and gas leases.

     We may  sell  additional  shares  of our  common  stock,  preferred  stock,
warrants,  convertible notes or other securities to raise additional capital. We
do not have any commitments or  arrangements  from any person to purchase any of
our  securities  and there can be no  assurance  that we will be  successful  in
selling any additional securities.


ITEM 6.     SELECTED FINANCIAL DATA

     Not applicable.


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,
2011,  and the results of  operations  for the years ended August 31, 2011,  and
2010. It should be read in conjunction with the audited financial statements and
notes thereto contained in this report.

Overview

     We are an independent oil and gas company working to acquire,  develop, and
produce crude oil and natural gas in and around the Denver-Julesburg Basin ("D-J
Basin").  All of our producing  wells are in the Wattenberg  Field,  which has a
well-developed  infrastructure and takeaway  capacity.  During 2011, we expanded
our undeveloped  acreage holdings in eastern Colorado and western Nebraska,  and
may commence development activities in that area.

                                       18

<PAGE>

     Since  commencing  active  operations in September  2008, we have undergone
significant growth. Specifically,  we have drilled or acquired 141 producing oil
and gas wells, as follows:

     o    Participated in two wells during fiscal 2009;

     o    Drilled and completed 22 wells during fiscal 2010:

     o    Acquired  interests in 72 wells,  completed 28 wells, and participated
          in eight wells during fiscal 2011:

     As of October 31, 2011, we were drilling or completing 16 wells.

     Our activities  have increased our estimated  proved  reserves to 2,069,705
Bbls of oil and 14,261,158 Mcf of gas as of August 31, 2011,  including reserves
associated with the acquisition of producing properties. In addition, during the
year ended August 31, 2011, we drilled and completed 14  developmental  wells on
our Pratt prospect,  thereby  converting 90,906 Bbls and 1,006,188 Mcf of proved
undeveloped  reserves as of August 31, 2010, into proved  producing  reserves of
271,813 Bbls and 1,317,117 Mcf as of August 31, 2011.

     As of August 31,  2011,  in the area  known as the  Wattenberg  Field,  our
acreage position was 11,277 gross (9,172 net). In addition,  we had an inventory
of 166,031 gross  undeveloped  acres (147,447 net acres) in eastern Colorado and
western Nebraska (the "Shallow  Niobrara  Acreage"),  substantially all of which
was  acquired  during  2011 at an  average  cost of $54 per net  acre.  Industry
interest and activity in this area has recently  increased  and we are currently
evaluating our development plans for the Shallow Niobrara Acreage.

     During fiscal 2009, we issued 8% convertible  promissory  notes with a face
value of $18,000,000,  which could be converted into shares of common stock at a
rate of $1.60 per share. All of the noteholders  elected to convert,  and, as of
March 31, 2011, the entire principal  balance had been converted into 11,250,000
shares of common stock.  In addition,  during fiscal 2011, we completed the sale
of 9,000,000 shares of common stock at an offering price of $2.00 per share.

     In June 2011 we obtained a one year  commitment for a $7,000,000  revolving
line of credit from Bank of Choice, with interest payable at the prime rate plus
2%..

     Our strategy for continued growth includes additional drilling  activities,
acquisition  of existing  wells,  and  recompletion  of wells that  provide good
prospects for improved hydraulic stimulation techniques.  We attempt to maximize
our return on assets  invested by drilling and  operating  development  wells in
which we have a significant net revenue  interest.  We attempt to limit our risk
by drilling in proven areas. To date, we have not drilled any dry holes.  All of
our current wells are relatively  low-risk vertical or directional wells, and we
do not  currently  have any  horizontal  wells.  However,  the  success  rate of
horizontal wells drilled by other operators has recently  improved and we expect
to drill or participate  in horizontal  wells in the future.  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.

                                       19

<PAGE>

Significant Developments

     Acquisition  from Petroleum  Exploration and  Management,  LLC - On May 24,
2011 we significantly expanded our position in the Wattenberg Field by acquiring
all of the  operating  oil and gas assets  owned by  Petroleum  Exploration  and
Management,  LLC (`PEM"),  a company owned equally by Ed Holloway and William E.
Scaff,  Jr., two of our officers and directors.  The oil and gas assets included
interests in 88 gross (40 net) oil and gas wells in the  Wattenberg  Field,  and
interests in oil and gas leases covering  approximately  6,968 gross acres.  The
transaction  was approved by the  disinterested  directors  and by a vote of our
shareholders  owning a majority of the shares in attendance at a special meeting
of our  shareholders  held on May 23, 2011,  with Mr. Holloway and Mr. Scaff not
voting.

     In  consideration  for the oil and gas properies we paid PEM $10,000,000 in
cash and  issued  PEM  1,381,818  shares of our  restricted  common  stock and a
promissory  note in the principal  amount of $5,200,000.  The note pays interest
annually  at 5.25%,  is due on  January  2,  2012,  and is secured by the assets
acquired from PEM. We did not assume any of PEM's liabilities.

     Expansion of oil and gas lease interests in the Shallow  Niobrara Acreage -
During  2011,  we expanded our growth  strategy to include the Shallow  Niobrara
Acreage.  Our Shallow Niobrara Acreage is primarily  located in eastern Colorado
(Yuma and Washington  counties),  and western Nebraska (Chase,  Dundy, and Hayes
counties).  We believe the area provides excellent growth  opportunities and has
the potential to yield a significant  return on investment.  George Seward,  our
director,  has  extensive  experience  in  the  area.  We  acquired  significant
interests in the area and at August 31, 2011, our holdings totaled 166,434 gross
(147,849 net)  undeveloped  acres with an average cost of $54 per net acre. Many
of the leases  were  acquired in exchange  for shares of our common  stock.  Our
primary  leases  within this area have an initial term of 10 years to provide us
with enough time to complete a thorough evaluation.

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

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

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

                                       20

<PAGE>

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

Total production in BOE            165,056         44,606

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

Average sales price:
  Oil (Bbls)                       $ 83.07        $ 68.38
  Gas (Mcf)                         $ 5.12         $ 5.08

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

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

     Service  Revenue - The  Company  provides  certain  services  to other well
owners, including supervision of drilling operations and management of producing
properties.  There  activities have not been, and are not expected to become,  a
significant component of the Company's business.

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

                                        Year ended August 31,
                                  ------------------------------
                                       2011             2010
                                  ----------------  ------------

Severance   and  ad   valorem
taxes                               $  955,705      $ 236,966
Production costs                       350,853         86,554
Work-over
Other                                   86,797              -
                                        46,463              -
                                  ----------------  ------------
    Total   lease   operating
expenses                          $  1,439,818      $ 323,520
                                  ================  ============

Per BOE:
  Severance  and  ad  valorem                           
taxes                             $       5.79      $    5.31

                                       21

<PAGE>

  Production costs                        2.13           1.94
  Work-over                               0.53              -
  Other                                   0.28              -
                                  ----------------  ------------
     Total per BOE                $       8.73      $    7.25
                                  ================  ============

     Lease operating and work-over costs tend to increase or decrease  primarily
in relation to the number of wells in production,  and, to a lesser  extent,  on
fluctuation  in oil field  service  costs and changes in the  production  mix of
crude oil and natural gas. Taxes tend to increase or decrease primarily based on
the value of oil and gas sold,  and, as a percent of  revenues,  averaged 10% in
2011 and 11% in 2010.

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

                                             Year ended August 31,
                                      ------------------------------------
                                            2011                2010
                                      ------------------  ----------------
DDA - oil and gas assets              $       2,743,441   $       692,274

DDA - other assets                               57,138             7,592
Accretion of asset retirement
obligations                                      37,728             1,534
                                      ------------------  ----------------
        Total DDA                     $       2,838,307   $       701,400
                                      ==================  ================
Depletion expense per BOE             $           16.62   $         15.52

     The  determination of depreciation,  depletion and amortization  expense is
highly dependent on the estimates of the proved oil and natural gas reserves and
actual  production  volumes.  As of August 31,  2011,  we had  4,446,565  BOE of
estimated net proved reserves with a Standardized  Measure of $57,550,414 (based
on SEC average prices of $5.07 Mcf and $84.90 Bbl). For comparative purposes, at
the end of the prior year we had 1,423,524 BOE of estimated net proved  reserves
with a Standardized Measure of $13,022,397 (based on SEC average prices of $4.76
Mcf and $69.20 Bbl).  Depletion  expense per BOE increased  approximately 7%. We
are currently  experiencing cost increases across all of our operating  sectors,
including costs incurred for lease acquisition, drillings, and well completion.

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

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

                                       22

<PAGE>

                                             Year Ended August 31,
                                     ---------------------------------------
                                           2011                  2010
                                     ------------------  -------------------
Cash based compensation               $    1,260,688       $    536,627
Share based compensation                     627,486            581,233
Professional fees                            716,210            419,588
Insurance                                     78,127             62,528
Other general and administrative             427,025            410,548
Capitalized general and
 administrative                             (206,233)           (95,475)
                                     ------------------  -------------------
    Totals                            $    2,903,303       $  1,915,049
                                     ==================  ===================

     Cash based  compensation  includes  payments to employees.  The increase of
$724,061 from 2010 to 2011 reflects the expansion of our business, including the
addition  of 5  employees  during the year.  Stock-based  compensation  includes
compensation paid to employees,  directors, and service providers in the form of
stock  options or shares of common  stock.  The amount of expense  recorded  for
stock  options is calculated by using the  Black-Scholes-Merton  option  pricing
model.  The amount of expense  recorded for shares of common stock is calculated
based upon the closing market value of the shares.

     The increase in  professional  fees includes  certain  accounting  fees and
investment  banking  fees  related to the  acquisition  of assets  from PEM.  In
addition,  our progression from smaller  reporting  company to accelerated filer
required  additional  professional  services  related to our compliance with the
rules and regulations of Sarbanes -Oxley.

     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 2010 to 2011 reflects our increasing activities to acquire leases and
develop the properties.

     Operating  Income (Loss) - For the year ended August 31, 2011, we generated
operating  income of $2,820,240,  as compared with an operating loss of $781,525
for the year  ended  August 31,  2010.  This  increase  of  $3,601,765  resulted
primarily  from the  increasing  contribution  of wells brought into  production
during the last two years,  which includes wells drilled under the 2011 and 2010
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)  - During  the year  ended  August  31,  2011,  we
recognized  $14,420,398  in other  expense  compared to  $10,012,647  during the
comparable  period in 2010. The amounts  included in other income  (expense) are
primarily  related to components of the 8% convertible  promissory notes. The 8%
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. By March 31, 2011, all of the notes had been converted,
thereby eliminating the derivative conversion liability.  The Company recognized
a non-cash expense of $10,229,229 and $7,678,457  during the years ending August

                                       23

<PAGE>

31,  2011 and 2010,  respectively,  related  to the  change in fair value of the
derivative conversion liability.

     Interest  expense,  net,  contains  several  components  related  to the 8%
convertible  promissory  notes.  In addition to the 8% coupon rate,  we recorded
amortization of debt issue costs of $1,587,799 and accretion of debt discount of
$2,664,137  during the year ended August 31, 2011.  During the year ended August
31, 2010,  amortization  of debt issue costs was $453,656 and  accretion of debt
discount was  $1,333,590.  In connection with the conversion of the remaining 8%
convertible  promissory notes outstanding  during 2011, the Company  accelerated
its recognition of all remaining amounts for unamortized debt issuance costs and
debt discount and the acceleration is included in the amounts presented above.

     Income Taxes - Income taxes do not currently  have an impact on our results
of operations as we have reported a net loss every year since  inception and for
tax purposes have a net operating  loss carry forward  ("NOL") of  approximately
$11.3 million.  The NOL is available to offset future taxable income, if any. At
such time, if ever, that we are able to demonstrate  that it is more likely than
not that we will be able to realize  the  benefits  of our tax  assets,  we will
begin to recognize the impact of taxes in our financial statements.

Liquidity and Capital Resources

     Our  sources  and (uses) of funds for the years  ended  August 31, 2011 and
2010, are shown below:

                                                Year Ended August 31,
                                           ------------------------------
                                                2011            2010
                                           --------------  --------------

Cash provided by (used in) operations        $ 7,916,308   $ (2,443,059)
Acquisition of oil and gas properties
 and equipment                               (30,247,327)     (9,152,175)
Proceeds from sales of oil and gas
 properties                                     8,382,167               -
Proceeds from sale of convertible notes,
 net of debt issuance costs                             -      16,651,023
(Repayment) / proceeds from bank loan                  -       (1,161,811)
Proceeds from sale of common stock, net
 of offering costs                             16,690,721               -
                                           --------------  --------------
Net increase in cash                          $ 2,741,869  $    3,893,978
                                           ==============  ==============

     Net cash  provided by (used in) operating  activities  was  $7,916,308  and
($2,443,059)  for the years ended  August 31, 2011 and 2010,  respectively.  The
significant improvement reflects the operating contribution from 2010 wells that
were producing for the entire year, plus the contribution  from wells that began
production  during 2011. In addition to our analysis  using amounts  included in
the cash flow statement,  we evaluate operations using a non-GAAP measure called
"adjusted  cash flow from  operations",  which  adjusts for cash flow items that
merely  reflect the timing of certain cash receipts and  expenditures.  Adjusted
cash flow from  operations  was  $6,346,800  for the year ended August 31, 2011,
compared to usage of $45,836 for the prior year.  The  improvement of $6,392,636
under that  measure is  closely  correlated  to,  and  primarily  explained  by,
increased revenues of $7,843,224 less increased direct costs of $2,104,552.

                                       24

<PAGE>

     The cash flow  statement  reports  actual  cash  expenditures  for  capital
expenditures,  which differs from total capital  expenditures  on a full accrual
basis.  Specifically,  cash paid for  acquisition  of property and  equipment as
reflected in the statement of cash flows excludes non-cash capital  expenditures
and  includes  an  adjustment  (plus or minus) to reflect the timing of when the
capital expenditure obligations are incurred and when the actual cash payment is
made. On a full accrual basis,  capital  expenditures  totaled  $47,237,827  and
$12,888,373 for the years ended August 31, 2011 and 2010, respectively, compared
to cash payments of $30,247,327 and $9,152,175,  respectively.  A reconciliation
of the differences is summarized in the following table:

                                              Year Ended August 31,
                                        ---------------------------------
                                              2011              2010
                                        ----------------  ---------------

Cash payments                            $ 30,247,327      $   9,152,175
Accrued costs, beginning of period         (3,466,439)                 - 
Accrued costs, end of period                4,967,368          3,466,439
Properties acquired in exchange for
 common stock                               9,938,487             16,645
Properties acquired in exchange for
 note payable                               5,200,000                  - 
Asset retirement obligation                   351,083            253,114 
                                        ----------------  ---------------
Capital expenditures                     $ 47,237,826      $  12,888,373
                                        ================  ===============

     Capital expenditures included the cost of proved properties of $21,250,000,
leasehold  acquisition  costs of $8,546,000,  drilling and  completion  costs on
completed  wells  of  $10,534,000,  costs  incurred  on  wells  in  progress  of
$4,814,000,   and  all  other  expenditures,   including  capitalized  interest,
capitalized overhead, and asset retirement obligations, of $2,094,000.

     Financing for our capital  expenditures was provided by several sources. In
addition to cash flow from  operations,  on January 11, 2011,  we completed  the
sale of 9 million shares of our common stock in a private  offering.  The shares
were sold at a price of $2.00  per  share.  Proceeds  to us from the sale of the
shares were $16,690,721 after deductions for sales commissions and expenses.

     In two separate  transactions,  we sold oil and gas leases  covering  5,902
gross acres  (3,738 net acres) for net cash  proceeds of  $8,382,167,  after the
deduction of selling costs of $248,700.

     We acquired  certain mineral  interests in exchange for 1,849,838 shares of
restricted common stock with a market value of $5,240,307.

     The structure of the  agreement to acquire  assets from PEM included a cash
payment of $10,000,000, a promissory note with a principal amount of $5,200,000,
and 1,381,818 shares of common stock with a value of $4,698,181.

     In June 2011 we obtained a commitment  for a $7,000,000  revolving  line of
credit from Bank of Choice.

                                       25

<PAGE>

     Our primary  need for cash  during the fiscal  year ending  August 31, 2012
will be to fund our acquisition and drilling  program.  Subsequent to August 31,
2011, we filed a registration statement on Form S-3 that provides for the future
sale of securities  up to $75 million.  As market  conditions  are not currently
conducive  to an  offering,  we have not  undertaken  an  offering at this time.
However,  we  continue to monitor  market  conditions  and may  proceed  with an
offering if conditions are favorable.  If we do not obtain additional financing,
we  estimate  that  capital  expenditures  for the year will  approximate  $31.7
million,  primarily  for the  drilling  of 28 wells  in which we own a  majority
interest,  participation  with other  operators in 14 wells,  recompletion of 20
wells that indicate good potential for  additional  hydraulic  stimulation,  and
acquisition of undeveloped  acreage and proved  properties.  We have  identified
additional  opportunities  that could expand our capital  expenditures  to $70.1
million under certain circumstances,  which would require additional funding. If
we  increase  our capital  budget to $70.1  million,  it could  expand our lease
acquisition program by $1.7 million, increase by 32 the number of wells drilled,
and include an  acquisition  of several  producing  properties  aggregating  $17
million. Our capital expenditure  estimate is subject to significant  adjustment
for  drilling  success,  acquisition  opportunities,  operating  cash flow,  and
available capital resources.

     We plan to generate profits by drilling or acquiring  productive oil or gas
wells.  However,  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.

Non-GAAP Financial Measures
 
     We use "adjusted cash flow from operations" and "adjusted EBITDA," non-GAAP
financial   measures,   for  internal  managerial   purposes,   when  evaluating
period-to-period  comparisons.  These  measures  are not  measures 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  measures  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 these measures as well as a  reconciliation  of each to the nearest U.S. GAAP
measure.

Reconciliation of Non-GAAP Financial Measures

     Adjusted  cash flow from  operations.  We  define  adjusted  cash flow from
operations as the cash flow earned or incurred from operating activities without
regard to the collection or payment of associated  receivables and payables.  We
believe it is important to consider  adjusted cash flow from  operations as well
as cash flow from operations,  as we believe it often provides more transparency
into what  drives  the  changes in our  operating  trends,  such as  production,
prices,  operating costs,  and related  operational  factors,  without regard to
whether the earned or incurred item was collected or paid during the period.  We
also use this measure  because the  collection of our  receivables or payment of

                                       26

<PAGE>

our obligations has not been a significant issue for our business,  but merely a
timing issue from one period to the next, with fluctuations  generally caused by
significant  changes in commodity  prices.  See the  Statements of Cash Flows in
this report.
  
     Adjusted  EBITDA.  We define  adjusted  EBITDA as net  income  (loss)  plus
interest  expense,  net of interest  income,  income  taxes,  and  depreciation,
depletion and amortization for the period plus/minus the change in fair value of
our derivative  conversion  liability.  We believe  adjusted  EBITDA is relevant
because it is a measure of cash available to fund our capital  expenditures  and
service our debt and is a widely used industry metric which allows comparability
of our results with our peers.

     The  following  table  presents a  reconciliation  of each of our  non-GAAP
financial measures to its nearest GAAP measure.
 
                                                    Year Ended August 31,
                                               ---------------------------------
                                                    2011              2010
                                               ---------------  ----------------
Adjusted cash flow from operations:
  Adjusted cash flow from operations            $ 6,346,800      $    (45,836)
  Changes in assets and liabilities               1,569,508        (2,397,223)
                                               ---------------  ----------------
   Net cash provided by (used in) operating
     activities                                 $ 7,916,308      $ (2,443,059)
                                               ===============  ================

Adjusted EBITDA:
   Adjusted EBITDA                              $ 5,658,547     $     (80,125)
   Interest expense and related items, net       (4,191,169)       (2,334,190)
   Change in fair value of derivative
     conversion liability                       (10,229,229)       (7,678,457)

   Depreciation, depletion and amortization      (2,838,307)         (701,400)
                                               ---------------  ----------------
   Net loss                                    $(11,600,158)    $ (10,794,172)
                                               ===============  ================

Contractual Obligations

     The following table summarizes our contractual obligations as of August 31,
2011:

                            Less than     One to       Three to        
                             One Year   Three Years   Five Years       Total
                           -----------  -----------   ------------  ------------
Note payable, related
 party               (1)   5,200,000            -             -       5,200,000
Employment Agreements
                             780,000      770,000             -       1,550,000
Operating Leases
                             110,000            -             -         110,000
Rig Contract         (2)
                           2,647,774            -             -       2,647,774
                           -----------  -----------   ------------  ------------
  Total
                           8,737,774      770,000       -             9,507,774
                           ===========  ===========   ============  ============

     (1)  See "Acquisition of Oil and Gas Properties from Petroleum  Exploration
          & Management LLC" in Item 1 of this report for information  concerning
          this note.

                                       27

<PAGE>

     (2)  In August  2011 we entered in a contract  with  Ensign  United  States
          Drilling,  Inc. which provided that Ensign would drill and complete 21
          wells in the Wattenberg Field on our behalf. As of October 31, 2011 we
          had reached  total depth on 15 wells  pursuant  to the  agreement.  We
          expect  that the  remaining  6 wells  we  committed  to drill  will be
          drilled, and if warranted, completed by December 31, 2011 at a cost of
          approximately $189,000 per well, or $1,134,000 in total.


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.

Outlook

     The factors that will most  significantly  affect our results of operations
include  (i)  activities  on  properties  that  we  do  not  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  more  easily 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.

     A decline in oil and gas prices (i) will reduce our cash flow which in turn
will reduce the funds  available  for  exploring  for and  replacing oil and gas
reserves,  (ii) will  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,  (v) may
result  in  marginally   productive  oil  and  gas  wells  being   abandoned  as
non-commercial,  and (vi) may increase the  difficulty  of obtaining  financing.
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.

                                       28

<PAGE>

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.
The preparation of these financial  statements requires us to make estimates and
assumptions that affect the reported amounts of assets,  liabilities,  including
oil and gas reserves, and disclosure of contingent assets and liabilities at the
date of the  financial  statements  and the  reported  amounts of  revenues  and
expenses during the reporting period.  Management  routinely makes judgments and
estimates about the effects of matters that are inherently uncertain. Management
bases its estimates and judgments on historical  experience and on various other
factors that are believed to be reasonable under the circumstances,  the results
of which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources.  Estimates and
assumptions are revised  periodically and the effects of revisions are reflected
in the  financial  statements  in the period it is  determined  to be necessary.
Actual results could differ from these estimates.

     We provide expanded discussion of our more significant accounting policies,
estimates and judgments below. 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 discussion
of additional accounting policies and estimates made by management.

     Oil and Gas Properties: We use the full cost method of accounting for costs
related to its 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  amortized  using  the
unit-of-production   method  based  upon  estimates  of  proved  reserves.   For
amortization  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.

     Under the full cost method of accounting,  a ceiling test is performed each
quarter.  The full cost ceiling test is an  impairment  test  prescribed  by SEC
regulations.  The ceiling  test  determines a limit on the book value of oil and
gas  properties.  The  capitalized  costs of  proved  and  unproved  oil and gas
properties,  net of accumulated depreciation,  depletion, and amortization,  and
the related  deferred income taxes, may not exceed the estimated future net cash
flows from proved oil and gas  reserves,  less future cash  outflows  associated
with  asset  retirement  obligations  that have been  accrued,  plus the cost of
unevaluated properties not being amortized,  plus the lower of cost or estimated
fair value of unevaluated  properties being amortized,  less income tax effects.
Prices are held constant for the  productive  life of each well.  Net cash flows

                                       29

<PAGE>

are discounted at 10%. If net capitalized costs exceed this limit, the excess is
charged  to  expense  and  reflected  as  additional  accumulated  depreciation,
depletion and  amortization.  The  calculation  of future net cash flows assumes
continuation  of  current  economic  conditions.   Once  impairment  expense  is
recognized, it cannot be reversed in future periods, even if changing conditions
raise the ceiling amount.

     Oil and Gas Reserves:  The  determination  of  depreciation,  depletion and
amortization  expense, as well as the ceiling test related to the recorded value
of our oil and natural gas properties, will be highly dependent on the estimates
of the proved oil and natural gas reserves. Oil and natural gas reserves include
proved reserves that represent estimated quantities of crude oil and natural gas
which geological and engineering  data demonstrate 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 natural gas reserves and their values, including many factors beyond our
control. Accordingly,  reserve estimates are often different from the quantities
of oil and natural gas ultimately recovered and the corresponding  lifting costs
associated with the recovery of these reserves.

     Asset  Retirement  Obligations:  Our activities are subject to various laws
and  regulations,  including  legal  and  contractual  obligations  to  reclaim,
remediate,  or otherwise restore properties at the time the asset is permanently
removed from  service.  The fair value of a liability  for the asset  retirement
obligation  ("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. 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. The capitalized ARCs are included in the full cost
pool and subject to depletion,  depreciation and amortization.  In addition, the
ARCs  are  included  in the  ceiling  test  calculation.  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.

     Derivative  Conversion  Liability:   We  account  for  embedded  conversion
features in our convertible promissory notes in accordance with the guidance for
derivative  instruments,  which require a periodic valuation of their fair value
and a corresponding recognition of liabilities associated with such derivatives.
The recognition of derivative conversion  liabilities related to the issuance of
convertible  debt is applied  first to the  proceeds of such  issuance as a debt
discount at the date of the issuance. Any subsequent increase or decrease in the
fair value of the derivative conversion liabilities is recognized as a charge or
credit to other income (expense) in the statements of operations.  In connection
with the conversion of convertible promissory notes into shares of the Company's
common  stock,  during the years ended  August 31, 2011 and 2010 the  derivative
conversion liability balances were reclassified to additional paid-in-capital.

     Revenue Recognition:  Revenue is recognized for the sale of oil and natural
gas when production is sold to a purchaser and title has  transferred.  Revenues
from production on properties in we share an economic interest with other owners
are recognized on the basis of our interest.  Provided that reasonable estimates
can be made,  revenue  and  receivables  are  accrued to  recognize  delivery of

                                       30

<PAGE>

product to the  purchaser.  Payment is typically  received  sixty to ninety days
after production.  Differences  between estimates and actual volumes and prices,
if any, are adjusted upon final settlement.

     Stock Based  Compensation:  We record stock-based  compensation  expense in
accordance with the fair value  recognition  provisions of US GAAP.  Stock based
compensation  is measured at the grant date based upon the estimated  fair value
of the award and the expense is recognized  over the required  employee  service
period,  which generally  equals the vesting period of the grant. The fair value
of stock  options is  estimated  using the  Black-Scholes-Merton  option-pricing
model.  The fair value of restricted stock grants is estimated on the grant date
based upon the fair value of the common stock.

     Recent Accounting Pronouncements: We evaluate the pronouncements of various
authoritative  accounting  organizations,  primarily  the  Financial  Accounting
Standards Board ("FASB"),  the Securities and Exchange Commission  ("SEC"),  and
the  Emerging  Issues  Task  Force  ("EITF"),  to  determine  the  impact of new
pronouncements on US GAAP and the impact on the Company.

     We have recently adopted the following new accounting standards:
     
     Effective  March 1, 2011,  the Company  adopted ASU No.  2010-29 - Business
Combinations (Topic 805):  Disclosure of Supplementary Pro Forma Information for
Business Combinations--A  consensus of the FASB Emerging Issues Task Force. This
update provides  clarification  requiring  public  companies that have completed
material  acquisitions  to disclose  the revenue  and  earnings of the  combined
business as if the  acquisition  took place at the  beginning of the  comparable
prior  annual  reporting  period,  and also expands the  supplemental  pro forma
disclosures  to include a  description  of the  nature  and amount of  material,
nonrecurring  pro  forma  adjustments  directly  attributable  to  the  business
combination included in the reported pro forma revenue and earnings.  See Note 9
for the Company's disclosures of business combinations.

     There were various other updates recently issued, most of which represented
technical  corrections  to the  accounting  literature  or  were  applicable  to
specific  industries,  and are not  expected  to have a  material  impact on our
financial position, results of operations or cash flows.


I
TEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

     Not applicable.


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     See the financial  statements  and  accompanying  notes  included with this
report.

                                       31

<PAGE>


ITEM  9.  CHANGES  IN AND  DISAGREEMENTS  WITH  ACCOUNTANTS  ON  ACCOUNTING  AND
          FINANCIAL DISCLOSURE

     None


ITEM 9A.  CONTROLS AND PROCEDURES  

Disclosure Controls and Procedures

     An  evaluation  was  carried  out  under  the   supervision  and  with  the
participation of our management,  including our Principal  Executive Officer and
Principal 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 Principal
Executive Officer and Principal Financial Officer, or persons performing similar
functions,  as  appropriate,   to  allow  timely  decisions  regarding  required
disclosure.  Based on that  evaluation,  our  management  concluded  that, as of
August 31, 2011, our disclosure controls and procedures were effective.

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 our  Principal  Executive
Officer  and  Principal  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 Principal  Executive  Officer and Frank L. Jennings,  our
Principal Financial Officer, evaluated the effectiveness of our internal control
over financial reporting as of August 31, 2011 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, 2011.

                                       32

<PAGE>

Changes in Internal Control Over Financial Reporting 
 
     There was no change in our internal  control over financial  reporting that
occurred during the period covered by this report that has materially  affected,
or is  reasonably  likely  to  materially  affect,  our  internal  control  over
financial reporting.

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.


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               59    President, Principal Executive Officer and 
                                    Director
William E. Scaff, Jr.         54    Vice President, Secretary, Treasurer and 
                                    Director
Frank L. Jennings             60    Principal Financial and Accounting Officer
Rick A. Wilber                64    Director
Raymond E. McElhaney          55    Director
Bill M. Conrad                55    Director
R.W. Noffsinger, III          37    Director
George Seward                 61    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 &
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

                                       33

<PAGE>

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 Principal  Financial
and  Accounting  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.

Raymond E.  McElhaney - Mr.  McElhaney has been one of our  directors  since May
2005, and prior to the acquisition of Predecessor  Synergy was our President and
Chief  Executive  Officer.  Mr.  McElhaney  began his  career in the oil and gas
industry in 1983 as founder and President of Spartan  Petroleum and Exploration,
Inc.  Mr.  McElhaney  also served as a chairman  and  secretary of Wyoming Oil &
Minerals,  Inc., a publicly traded  corporation,  from February 2002 until 2005.
From 2000 to 2003,  he served as vice  president  and  secretary of New Frontier
Energy,  Inc., a publicly traded  corporation.  McElhaney is a co-founder of MCM
Capital  Management  Inc., a privately held financial  management and consulting
company  formed in 1990 and has served as its  president of that  company  since
inception.

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 & gas
industry over the past 20 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 since that time.

                                       34

<PAGE>

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  cubit  feet of proved  gas  reserves  and was
producing  55  million  cubic  foot 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 Amex
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.


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, 2011.

<TABLE>
<S>                  <C>       <C>         <C>        <C>       <C>          <C>          <C>

    Name and                                        Stock     Option      All Other       
   Principal       Fiscal    Salary       Bonus     Awards     Awards     Compensation
    Position        Year       (1)         (2)       (3)        (4)           (5)         Total
-----------------  -------  ----------   --------  ---------  ---------   ------------  ------------
Ed Holloway,        2011     $300,000    100,000          -          -          9,800    $  409,800
Principal           2010     $175,000          -          -          -              -    $  175,000
Executive           2009     $150,000          -          -  5,092,672              -    $5,242,672
Officer             

                                       35

<PAGE>

William E.          2011     $300,000    100,000          -          -          9,800    $  409,800
Scaff, Jr.,         2010     $175,000          -          -          -              -    $  175,000
Vice President,     2009     $150,000          -          -  5,092,672              -    $5,242,672
Secretary and       
Treasurer            
                    
Frank L             2011     $ 87,391          -    220,000    404,352              -    $  711,743
Jennings,           2010     $106,225          -          -          -              -    $  106,255
Principal           2009     $ 63,715          -          -          -              -    $   63,715
Financial and               
Accounting          
Officer
</TABLE>

 
     (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 11,  2008,  we signed  employment  agreements  with Ed Holloway and
William E. Scaff Jr. Each employment  agreement provided that the employee would
be paid a  monthly  salary  of  $12,500  and  required  the  employee  to devote
approximately 80% of his time to our business. The employment agreements expired
on June 1, 2010.

     On June 1,  2010,  we entered  into a new  employment  agreements  with Mr.
Holloway and Mr. Scaff. The new employment  agreements,  which expire on May 31,
2013,  provide that we 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 our  business.  In  addition,  for every 50 wells  that  begin
producing  oil  and/or  gas after  June 1,  2010,  whether  as the result of our
successful  drilling  efforts or  acquisitions,  we will  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 our common
stock for the 20 trading days prior to the date the 50th well begins producing.

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

     o    50,000 shares of our restricted common stock; and

     o    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.

                                       36

<PAGE>

     The employment agreement expires on March 7, 2014 and requires Mr. Jennings
to devote all of his time to our business.

     If Mr.  Jennings  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 Mr.  Jennings 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 Mr. Jennings will vest immediately.

     In the event there is a change in the  control,  the  employment  agreement
allows Mr.  Jennings 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 Mr.  Jennings  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.

     We had a  consulting  agreement  with Ray  McElhaney  and Bill Conrad which
provided that Mr.  McElhaney and Mr. Conrad would render,  on a part-time basis,
consulting  services pertaining to corporate  acquisitions and development.  For
these services,  Mr. McElhaney and Mr. Conrad were paid a monthly consulting fee
of $5,000. The consulting agreement expired on September 15, 2009.

                                       37

<PAGE>

     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 a 2011  non-qualified  stock option plan,  a 2011  incentive  stock
option  plan,  and a 2011 stock bonus plan. A summary  description  of each plan
follows.


     2011 Non-Qualified  Stock Option Plan. Our Non-Qualified  Stock Option 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 be granted  options  pursuant to the
Plan,  provided  however  that  bona  fide  services  must 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.

     2011  Incentive   Stock  Option  Plan.  Our  Incentive  Stock  Option  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 be granted  options  pursuant to the
Plan,  provided  however  that  bona  fide  services  must 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.

     2011 Stock  Bonus Plan.  Our Stock  Bonus Plan  allows for the  issuance of
shares of common stock to our employees,  directors,  officers,  consultants and
advisors.  However,  bona fide services must be rendered by the  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 plans adopted  during 2011 replaced a  non-qualified  stock option plan
and a stock bonus plan  originally  adopted during 2005 (the "2005  Plans").  No
additional options or shares will be issued under the 2005 Plans.

     Summary.  The  following is a summary of options  granted or shares  issued
pursuant to the Plans as of October 31, 2011.  Each option  represents the right
to purchase one share of our common stock.

                              Total
                              Shares     Reserved for    Shares     Remaining
                             Reserved    Outstanding    Issued as Options/Shares
Name of Plan                Under Plans    Options     Stock Bonus  Under Plans 
------------                -----------  ------------  ----------- -------------

2011 Non-Qualified Stock
 Option Plan                  2,000,000     150,000        0       1,850,000
2011 Incentive Stock 
 Option Plan                  2,000,000           0        0       2,000,000
2011 Stock Bonus Plan         2,000,000           0        0       2,000,000

                                       38

<PAGE>

Options

     In  connection  with the  acquisition  of  Predecessor  Synergy,  we issued
options to the persons shown below in exchange for options  previously issued by
Predecessor  Synergy.  The terms of the options we issued are  identical  to the
terms of the Predecessor Synergy options.  The options were not granted pursuant
to our 2005  Plans.  As of October 31,  2011,  none of these  options  have been
exercised.

                            Grant    Shares Issuable Upon   Exercise  Expiration
Name                        Date     Exercise of Options     Price        Date  
----                       -------   --------------------   --------  ----------

Ed Holloway (1)            9-10-08       1,000,000          $ 1.00     6-11-13
William E. Scaff, Jr. (2)  9-10-08       1,000,000          $ 1.00     6-11-13
Ed Holloway (1)            9-10-08       1,000,000          $10.00     6-11-13
William E. Scaff, Jr. (2)  9-10-08       1,000,000          $10.00     6-11-13

     (1)  Options are held of record by a limited liability  company  controlled
          by Mr. Holloway.

     (2)  Options are held of record by a limited liability  company  controlled
          by Mr. Scaff.

     The following table shows information concerning our outstanding options as
of October 31, 2011.

                        Shares underlying unexercised
                             Option which are: 
                        ---------------------------    Exercise      Expiration
Name                    Exercisable   Unexercisable      Price          Date   
----                    -----------   -------------    --------      -----------

Ed Holloway             1,000,000              --       $ 1.00        6-11-13
William E. Scaff, Jr.   1,000,000              --       $ 1.00        6-11-13
Ed Holloway             1,000,000              --       $10.00        6-11-13
William E. Scaff, Jr.   1,000,000              --       $10.00        6-11-13
Employees               10,000(1)         610,000 (1)       (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 $4.40 per share. The options expire at various dates between
          December 2018 and August, 2021.

     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, 2011. Prior to 2011, neither our Non-Qualified  Stock
Option Plan nor the issuance of any of our other  options have been  approved by
our shareholders.

                                       39

<PAGE>


<TABLE>
<S>                                    <C>           <C>                 <C>    

                                       1              2                  3
                                                                 Number of Securities
                                     Number                      Remaining Available
                                 of Securities                   For Future Issuance
                                  be Issued    Weighted-Average     Under Equity
                                Upon Exercise   Exercise Price   Compensation Plans,
                                of Outstanding  of Outstanding   Excluding Securities
   Plan category                   Options          Options      Reflected in Column 1
--------------------------------------------------------------------------------------

Non-Qualified Stock Option Plan      620,000        $3.40             1,380,000 (1)
Other Options                      4,000,000        $5.50                     -

</TABLE>


     (1)  As of May 23, 2011,  this Plan was terminated  and no further  options
          will be issued pursuant to its terms.

Compensation of Directors During Year Ended August 31, 2011

                        Fees Earned or   Stock        Option
                        Paid in Cash   Awards (1)    Awards (2)      Total
                        -------------- ----------    ----------      -----

Rick Wilber               $20,000           --            --        $20,000
Raymond McElhaney         $32,500           --            --         32,500
Bill Conrad                28,000           --            --         28,000
R.W. Noffsinger            24,000           --            --         24,000
George Seward              20,000           --            --         20,000
                         --------          ---                     --------
                         $124,500           --                     $124,500
                         ========          ===                     ========

     (1)  The fair value of stock  issued for  services  computed in  accordance
          with ASC 718.

     (2)  The fair value of options granted  computed in accordance with ASC 718
          on the date of grant.



ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND 
          RELATED STOCKHOLDER MATTERS

     The following table shows, as of October 31, 2011, information with respect
to those  persons  owning  beneficially  5% or more of our common  stock and the
number and percentage of  outstanding  shares owned by each of our directors and
officers  and by  all  officers  and  directors  as a  group.  Unless  otherwise
indicated,  each owner has sole voting and investment  powers over his shares of
common stock.
                                               Number           Percent
Name                                         of Shares (1)      of Class(2) 
----                                         -------------      -----------

Ed Holloway                                 4,760,909 (3)      13.19%
William E. Scaff, Jr.                       4,760,909 (4)      13.19%

                                       40

<PAGE>

Frank L. Jennings                              74,000               *
Rick A. Wilber                                536,700           1.49%
Raymond E. McElhaney                          245,725               *
Bill M. Conrad                                247,225               *
R.W. Noffsinger, III                          288,425               *
George Seward                                 909,080           2.52%
Wayne L. Laufer                             2,893,750           8.02%

All officers and directors as a group 
 (8 persons)                               11,822,973          32.75%

*   Less than 1%

     (1)  Share ownership includes shares issuable upon the exercise of options,
          all of which are  currently  exercisable,  held by the persons  listed
          below.

                           Share
                         Issuable
                           Upon        Option
                        Exercise of    Exercise   Expiration
Name                      Options       Price       Date
---------------------  --------------  ---------  ----------

Ed Holloway            1,000,000         $ 1.00   6/11/2013
Ed Holloway            1,000,000         $10.00   6/11/2013
William E. Scaff, Jr.  1,000,000         $ 1.00   6/11/2013
William E. Scaff, Jr.  1,000,000         $10.00   6/11/2013

     (2)  Computed based upon 36,098,212  shares of common stock  outstanding as
          of October 31, 2011.

     (3)  Shares are held of record by  various  trusts  and  limited  liability
          companies controlled by Mr. Holloway.

     (4)  Shares are held of record by  various  trusts  and  limited  liability
          companies controlled by Mr. Scaff.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Our two  officers,  Ed  Holloway  and William  Scaff,  Jr.,  are  currently
involved in oil and gas exploration and development. Mr. Holloway and Mr. Scaff,
or their affiliates (collectively the "Holloway/Scaff  Parties"), may present us
with  opportunities  to acquire  leases or to participate in drilling oil or gas
wells.  The  Holloway/Scaff  Parties  control three  entities with which we have
entered into agreements.  These entities are Petroleum  Management,  LLC ("PM"),
Petroleum  Exploration and Management,  LLC ("PEM"), and HS Land and Cattle, LLC
("HSLC").

     Any transaction between us and the Holloway/Scaff  Parties must be approved
by a majority of our disinterested  directors.  In the event the  Holloway/Scaff
Parties are presented  with or become aware of any potential  transaction  which
they  believe  would be of interest to us, they are  required to provide us with
the right to  participate in the  transaction.  The  Holloway/Scaff  Parties are
required to disclose any interest they have in the potential transaction as well

                                       41

<PAGE>

as any  interest  they  have  in any  property  which  could  benefit  from  our
participation in the transaction, such as by our drilling an exploratory well on
a lease which is in proximity to leases in which the Holloway/Scaff Parties have
an interest.  Without our consent, the Holloway/Scaff Parties may participate up
to 25% in a potential  transaction  on terms which are no  different  than those
offered to us.

     We  acquired  all of the  working  oil and  gas  assets  owned  by PEM in a
transaction  that closed on May 24, 2011. In total, we acquired  interests in 88
gross (40 net) oil and gas wells in the Wattenberg  Field,  and interests in oil
and gas leases covering  approximately 6,968 gross acres in the Wattenberg Field
and the Eastern D-J Basin (eastern Colorado and western Nebraska). These oil and
gas interests  were acquired from  Petroleum  Exploration  and  Management,  LLC
("PEM"),  a company  owned by Ed Holloway and William E. Scaff,  Jr., two of our
officers,  for approximately $19.0 million.  The transaction was approved by the
disinterested directors and by a vote of the shareholders, with Mr. Holloway and
Mr. Scaff not voting.

     In October 2010, and following the approval of our  directors,  we acquired
oil and gas properties from PM and PEM, for approximately $1.0 million.  The oil
and gas properties we acquired are located in the Wattenberg Field and consisted
of:

     o    six producing oil and gas wells
     o    two shut in oil wells
     o    fifteen drill sites, net 6.25 wells
     o    miscellaneous equipment

     We have a 100%  working  interest  (80% net  revenue  interest)  in the six
producing wells and the two shut in wells.

     In 2009,  PM and PEM  acquired the same oil and gas  properties  sold to us
from an unrelated third party for $920,000.  The difference in the price we paid
for the properties  and the price PM and PEM paid for the properties  represents
interest on the amount paid by PM and PEM for the properties,  closing costs and
equipment improvements.

     We had a letter agreement with PM and PEM which provided us with the option
to acquire  working  interests  in oil and gas leases  owned by these  firms and
covering  lands on the D-J basin.  The oil and gas leases  covered  640 acres in
Weld County,  Colorado and, subject to certain conditions,  would be transferred
to us for payment of $1,000 per net mineral acre.  The working  interests in the
leases we could  acquire  varied,  but the net  revenue  interest in the leases,
could not be less than 75%. Under this letter  agreement,  through February 2010
we  acquired  leases  covering  640 gross  (360 net)  acres  from PM and PEM for
$360,000.

     Pursuant to the terms of an Administrative Services Agreement, through June
30, 2010 PM provided us with office space and equipment  storage in Platteville,
Colorado,  as well as secretarial,  word processing,  telephone,  fax, email and
related  services for a fee of $20,000 per month.  Following the  termination of
the Administrative Services Agreement, and since July 1, 2010 we have leased the
office space and equipment  storage yard in  Platteville  from HSLC at a rate of
$10,000 per month.

                                       42

<PAGE>

     During the year ended August 31, 2011,  we acquired oil and gas leases from
George Seward, a member of our board of directors.  In total, we purchased lease
interests  covering  22,066 gross  (19,717 net)  undeveloped  acres,  located in
eastern  Colorado and western  Nebraska,  in exchange for 353,817  shares of our
common stock.  Based on the market price of our common stock on the  transaction
dates, these acquisitions were valued at $788,676.

     Prior to our acquisition of Predecessor  Synergy,  Predecessor Synergy made
the following sales of its securities:

  Name                      Shares      Series A Warrants Consideration
  ----                      ------      ----------------- -------------

  Ed Holloway (1)          2,070,000               --      $  2,070
  William E. Scaff, Jr.(1) 2,070,000               --         2,070
  Benjamin Barton (1)        600,000               --           600
  John Staiano (1)           600,000               --           600
  Synergy Energy trust     1,900,000 (2)           --         1,900
  Third Parties              660,000               --           660
  Private Investors        1,000,000        1,000,000       $1.00 Per Unit (3)
  Private Investors        1,060,000        1,060,000       $1.50 Per Unit (3)
                           ---------        ---------
  Total                    9,960,000        2,060,000
                           =========        =========

     (1)  Shares are held of record by entities controlled by this person.
     (2)  In December  2008, we  repurchased  1,000,000  shares from the Synergy
          Energy Trust.
     (3)  Shares and warrants were sold as units,  with each unit  consisting of
          one share of our common stock and one Series A warrant.

     In connection  with our acquisition of Predecessor  Synergy,  the 9,960,000
shares of  Predecessor  Synergy,  plus the  2,060,000  Series A  warrants,  were
exchanged for 9,960,000 shares of our common stock, plus 2,060,000 of our Series
A warrants.

     In contemplation of the acquisition of Predecessor  Synergy,  our directors
declared a dividend of Series A warrants. The dividend provided that each person
owning our shares at the close of business on September 9, 2008 will receive one
Series A warrant for each  post-split  share which they owned on that date.  Mr.
McElhaney  and Mr.  Conrad,  due to  their  ownership  of our  common  stock  on
September 9, 2008, received 271,000 and 247,000 Series A warrants, respectively.

     Each  Series A warrant  entitles  the holder to  purchase  one share of our
common stock at a price of $6.00 per share.  The Series A warrants expire on the
earlier of December 31, 2012 or twenty days following written  notification from
us that our common  stock had a closing  bid price at or above $7.00 for any ten
of twenty consecutive trading days.


ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

     For each of the two years ended  August 31, 2011 and 2010,  Ehrhardt  Keefe
Steiner  Hottman P.C.  ("EKS&H")  served as our  independent  registered  public
accounting firm.

                                       43

<PAGE>

                                  Year Ended              Year Ended
                               August 31, 2011          August 31, 2010
                               ---------------          ---------------

      Audit Fees                $  119,514                 $ 72,213
      Audit-Related Fees        $   35,993                 $  7,500
      Tax Fees                  $   43,157                 $  3,800
      All Other Fees                    --                       --

     Audit fees represent amounts billed for professional  services rendered for
the audit of our annual  financial  statements  and the reviews of the financial
statements  included in our Form 10-Q and Form 10-K reports.  Audit-related fees
include amounts billed for the review of our registration statement on Form S-1.
Prior to  contracting  with EKS&H to render  audit or non-audit  services,  each
engagement was approved by our audit committee.


ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibits                                               Page Number
--------                                               -----------

3.1.1  Articles of Incorporation                          (1)

3.1.2  Amendment to Articles of Incorporation             (2)

3.1.3  Bylaws                                             (1)

10.1   Employment Agreement with Ed Holloway              (2)

10.2   Employment Agreement with William E.
       Scaff, Jr.                                         (2)

10.3   Administrative Services Agreement                  (3)

10.4   Agreement regarding Conflicting Interest
       Transactions                                       (3)

10.5   Consulting Services Agreement with
       Raymond McElhaney and Bill Conrad                  (4)

10.6.1 Form of Convertible Note                           (4)

10.6.2 Form of Subscription Agreement                     (4)

10.6.3 Form of Series C Warrant                           (4)

10.7   Purchase and Sale Agreement with Petroleum
       Exploration and Management, LLC (wells,
       equipment and well bore leasehold assignments)     (4)

10.8   Purchase and Sale Agreement with Petroleum
       Management, LLC (operations and
       leasehold)                                         (4)

                                       44

<PAGE>

10.9   Purchase and Sale Agreement with Chesapeake Energy (4)

10.10  Lease with HS Land & Cattle, LLC                   (4)

10.11  Employment Agreement with Frank L. Jennings        (5)

10.12  Purchase and Sale Agreement with Petroleum
       Exploration and Management, LLC                    (6)

14.    Code of Ethics                                     (7)

23     Consent of Accountants

31     Rule 13a-14(a) Certifications

32     Section 1350 Certifications

99     Report of Ryder Scott Company, L.P.

(1)  Incorporated by reference to the same exhibit filed with our registration
     statement on Form SB-2, File #333-146561.

(2)  Incorporated by reference to the same exhibit filed with the Company's
     transition report on Form 8-K for the period ended August 31, 2008.

(3)  Incorporated by reference to the same exhibit filed with our transition
     report on Form 10-K for the year ended August 31, 2008.


(4)  Incorporated by reference to the same exhibit filed with the Company's
     report on Form 10-K/A filed on June 3, 2011.


(5)  Incorporated by reference to the same exhibit filed with the Company's
     report on Form 8-K filed on June 24, 2011.


(6)  Incorporated by reference to Exhibit 10.12 filed with the Company's report
     on Form 8-K filed on August 5, 2011.


(7)  Incorporated by reference to Exhibit 14 filed with the Company's report on
     Form 8-K filed on July 22, 2011.

                                       45

<PAGE>

                          SYNERGY RESOURCES CORPORATION

                          INDEX TO FINANCIAL STATEMENTS




  Index to Financial Statements                                          F-1 
  
  Report of Independent Registered Public Accounting Firm                F-2 

  Balance Sheets as of August 31, 2011 and 2010                          F-3

  Statements of Operations for the years ended August 31, 2011 and 2010  F-4 

  Statements of Changes in Shareholders' Equity (Deficit)
   for the years ended August 31, 2011 and 2010                          F-5 

  Statements of Cash Flows for the years ended August 31, 2011 and 2010  F-6

  Notes to Financial Statements                                          F-7

                                      F-1

<PAGE>


             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Synergy Resources Corporation

We have audited the accompanying balance sheets of Synergy Resources Corporation
("the  Company") as of August 31, 2011 and 2010,  and the related  statements of
operations,  changes in shareholders'  equity,  and cash flows for each of years
then ended. We have also audited the Company's  internal  control over financial
reporting  as of August 31,  2011,  based on  criteria  established  in Internal
Control  -  Integrated   Framework   issued  by  the   Committee  of  Sponsoring
Organizations of the Treadway  Commission  (COSO).  The Company's  management is
responsible for these financial  statements,  for maintaining effective internal
control over financial reporting, and for its assessment of the effectiveness of
internal control over financial  reporting.  Our responsibility is to express an
opinion on these financial  statements and an opinion on the Company's  internal
control over financial reporting based on our audits.

We conducted our audits in accordance  with the standards of the Public  Company
Accounting Oversight Board (United States). Those standards require that we plan
and  perform  the  audits to  obtain  reasonable  assurance  about  whether  the
financial  statements are free of material  misstatement  and whether  effective
internal  control  over  financial  reporting  was  maintained  in all  material
respects.  Our audits of the financial statements included examining,  on a test
basis,  evidence  supporting  the  amounts  and  disclosures  in  the  financial
statements,  assessing the accounting  principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
Our audit of internal  control over financial  reporting  included  obtaining an
understanding of internal control over financial  reporting,  assessing the risk
that a material  weakness  exists,  and  testing and  evaluating  the design and
operating  effectiveness  of internal  control based on the assessed  risk.  Our
audits also included performing such other procedures as we considered necessary
in the circumstances.  We believe that our audits provide a reasonable basis for
our opinions.

A company's  internal control over financial  reporting is a process designed to
provide reasonable  assurance  regarding the reliability of financial  reporting
and the preparation of financial  statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial  reporting  includes those policies and procedures that (1) pertain to
the  maintenance  of records that, in reasonable  detail,  accurately and fairly
reflect the  transactions  and  dispositions  of the assets of the company;  (2)
provide  reasonable  assurance  that  transactions  are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting  principles,  and that receipts and  expenditures  of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of  unauthorized  acquisition,  use, or  disposition  of the company's
assets that could have a material effect on the financial statements.

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.

In our opinion,  the financial  statements  referred to above present fairly, in
all material respects,  the financial position of Synergy Resources  Corporation
as of August 31, 2011 and 2010,  and the results of its  operations and its cash
flows for each of the years then ended in conformity with accounting  principles
generally accepted in the United States of America. Also in our opinion, Synergy
Resources Corporation,  in all material respects,  maintained effective internal
control  over  financial  reporting  as of December  August 31,  2011,  based on
criteria  established in Internal  Control - Integrated  Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ Ehrhardt Keefe Steiner & Hottman PC

Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado
November 11, 2011


                                      F-2

<PAGE>

                          SYNERGY RESOURCES CORPORATION
                                 BALANCE SHEETS
                         As of August 31, 2011 and 2010

                                                        2011           2010
                                                    ------------    ----------
                                     ASSETS
Current assets:    
  Cash and cash equivalents                         $  9,490,506   $  6,748,637
  Accounts receivable:
    Oil and gas sales                                  2,185,051        377,675
    Joint interest billing                             2,406,473      1,930,810
    Related party receivable                                   -        867,835
  Inventory                                              459,592        387,864
  Other current assets                                    89,336         12,310
                                                    ------------    -----------
     Total current assets                             14,630,958     10,325,131
                                                    ------------    -----------
Property and equipment: 
  Oil and gas properties, full cost method, net       48,614,857     12,692,194
  Other property and equipment, net                      283,207        150,789
                                                    ------------    -----------
   Property and equipment, net                        48,898,064     12,842,983
                                                    ------------    -----------
Debt issuance costs, net of amortization                       -      1,587,799
Other assets                                             168,863         86,000
                                                    ------------    -----------
     Total assets                                   $ 63,697,885    $24,841,913
                                                    ============    ===========

                      LIABILITIES AND SHAREHOLDERS' EQUITY 
Current liabilities:
  Accounts payable: 
    Trade                                           $  6,620,561    $ 3,015,562
    Related party payable                                      -        554,669
  Accrued expenses                                     2,125,852        517,921
  Notes payable, related party                         5,200,000              -

                                                    ------------    -----------
     Total current liabilities                        13,946,413      4,088,152

Asset retirement obligations                             643,459        254,648
Convertible promissory notes, net of debt
   discount                                                    -     12,190,945
Derivative conversion liability                                -      9,325,117
                                                    ------------    -----------
     Total liabilities                                14,589,872     25,858,862
                                                    ------------    -----------
Commitments and contingencies (See Note 12)   

Shareholders' equity (deficit):  
  Preferred stock - $0.01 par value, 10,000,000
    shares authorized: no shares issued and
     outstanding                                               -              -
  Common stock - $0.001 par value, 100,000,000
    shares authorized: 36,098,212 and 13,510,981
     shares issued and outstanding as of August 31,
     2011 and 2010, respectively                          36,098         13,511
  Additional paid-in capital                          84,011,496     22,308,963
  Accumulated deficit                                (34,939,581)   (23,339,423)
                                                    ------------    -----------
     Total shareholders' equity (deficit)             49,108,013     (1,016,949)
                                                    ------------    -----------
     Total liabilities and shareholders' equity     $ 63,697,885    $24,841,913
                                                    ============    ===========

   The accompanying notes are an integral part of these financial statements.

                                      F-3

<PAGE>

                          SYNERGY RESOURCES CORPORATION
                            STATEMENTS OF OPERATIONS
                  For the years ended August 31, 2011 and 2010

                                                    2011            2010
                                                --------------  --------------
Revenues: 
  Oil and gas revenues                          $  9,777,172     $  2,158,444
  Service revenues                                   224,496                -
                                                ------------     ------------
     Total revenues                               10,001,668        2,158,444
                                                ------------     ------------
Expenses: 
  Lease operating expenses                         1,439,818          323,520
  Depreciation, depletion, and amortization        2,838,307          701,400
  General and administrative                       2,903,303        1,915,049
                                                ------------     ------------
    Total expenses                                 7,181,428        2,939,969
                                                ------------     ------------
Operating income (loss)                            2,820,240         (781,525)
                                                ------------     ------------
Other income (expense):
  Change in fair value of derivative
     conversion liability                        (10,229,229)      (7,678,457)
  Interest expense, net                           (4,246,945)      (2,338,849)
  Interest income                                     55,776            4,659
                                                ------------     ------------
    Total other (expense)                        (14,420,398)     (10,012,647)
                                                ------------     ------------
Loss before income taxes                         (11,600,158)     (10,794,172)
Provision for income taxes                                 -                -
                                                ------------     ------------
     Net loss                                   $(11,600,158)    $(10,794,172)
                                                ============     ============
Net loss per common share:
    Basic and diluted                           $      (0.45)    $      (0.88)
                                                ============     ============
Weighted average shares outstanding:
    Basic and diluted                             26,009,283       12,213,999
                                                ============     ============

   The accompanying notes are an integral part of these financial statements.

                                      F-4

<PAGE>

                          SYNERGY RESOURCES CORPORATION
             STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT)
                  for the years ended August 31, 2011 and 2010

<TABLE>
<S>                                         <C>          <C>         <C>              <C>              <C>
                                                                                                      Total
                                          Number of               Additional                      Shareholders'
                                           Common       Common     Paid-In         Accumulated       Equity
                                           Shares        Stock     Capital          (Deficit)       (Deficit)
                                          ----------    --------  ----------       -----------    ------------

Balance, August 31, 2009                  11,998,000      11,998   15,521,697      (12,545,251)      2,988,444
Shares issued pursuant to conversion
  of debt and accrued interest at
  $1.60 per share, net of $165,212
  unamortized debt discount                1,309,027      1,309     1,927,917                -       1,929,226
Reclassification of derivative
conversion liability to equity
  pursuant to early conversion of debt             -          -     1,809,149                -       1,809,149

Shares issued for services                   197,988        198       544,377                -         544,575
Shares issued in exchange for mineral
  leases                                       5,966          6        16,639                -          16,645
Series C warrants issued in connection
  with sale of convertible debt at $100,000
  per Unit pursuant to November 27, 2009
  offering memorandum                              -          -     1,760,048                -       1,760,048
Series D warrants issued in connection with
  sale of convertible debt at $100,000
  per Unit pursuant to November 27, 2009
  offering memorandum                              -          -       692,478                -         692,478

Share based compensation                           -          -        36,658                -          36,658

Net (loss)                                         -          -             -      (10,794,172)    (10,794,172)
                                         -----------    -------    ----------       -----------     -----------
Balance, August 31, 2010                  13,510,981     13,511    22,308,963      (23,339,423)     (1,016,949)
 
Shares issued pursuant to conversion
  of debt and accrued interest at
  $1.60 per share, net of $1,052,917
  unamortized debt discount                9,979,376      9,979    14.904.100                 -     14,914,079
Reclassification of derivative
  conversion liability to equity
  pursuant to early conversion of debt             -          -    19,554,346                 -     19,554,346
Shares issued for services                   150,000        150       429,850                 -        430,000
Shares issued in exchange for mineral
  leases                                   1,849,838      1,850     5,238,457                 -      5,240,307
Shares issued in exchange for oil and
  gas assets, related party                1,381,818      1,382     4,696,799                 -      4,698,181
Shares issued for cash at $2.00 per
  share pursuant to November 30, 2010
  offering memorandum, net of offering
  costs                                    9,000,000      9,000    16,681,721                 -     16,690,721
Shares issued pursuant to conversion
  of Series D warrants on a cashless basis   226,199        226          (226)                -              -
Share based compensation                           -          -       197,486                 -        197,486
Net (loss)                                         -          -             -       (11,600,158)   (11,600,158)
                                         -----------   --------    ----------       ------------  ------------
Balance, August 31, 2011                  36,098,212   $ 36,098   $84,011,496      $(34,939,581)  $ 49,108,013
                                         ===========   ========   ===========       ============  ============
</TABLE>



   The accompanying notes are an integral part of these financial statements.

                                      F-5

<PAGE>


                          SYNERGY RESOURCES CORPORATION
                             STATEMENTS OF CASH FLOWS
                   for the years ended August 31, 2011 and 2010

                                                         2011          2010
                                                    ------------    ----------
 Cash flows from operating activities:
  Net loss                                          $(11,600,158)  $(10,794,172)
                                                    ------------  -------------
  Adjustments to reconcile net loss to
   net cash used in operating activities:
    Depreciation, depletion, and amortization          2,838,307        701,400
    Amortization of debt issuance cost                 1,587,799        453,656
    Accretion of debt discount                         2,664,138      1,333,590
    Stock-based compensation                             627,486        581,233
    Change in fair value of derivative liability      10,229,229      7,678,457
  Changes in operating assets and liabilities:
    Accounts receivable                               (1,415,204)    (3,091,677)
    Inventory                                            (71,728)       744,821
    Accounts payable                                   1,549,400       (518,942)
    Accrued expenses                                   1,666,928        460,780
      Other                                             (159,889)         7,795
                                                    ------------  -------------
  Total adjustments                                   19,516,466      8,351,113
                                                    ------------  -------------
  Net cash provided by (used in) 
    operating activities                               7,916,308     (2,443,059)
                                                    ------------  -------------
  Cash flows from investing activities:
    Acquisition of property and equipment            (30,247,327)    (9,152,175)
    Net proceeds from sales of oil and
       gas properties                                  8,382,167              -
                                                    ------------  -------------
     Net cash (used in) investing activities         (21,865,160)    (9,152,175)
                                                    ------------  -------------
 Cash flows from financing activities:
    Cash proceeds from sale of stock                  18,000,000              -
    Offering costs                                    (1,309,279)             -
    Cash proceeds from convertible promissory notes            -     18,000,000
    Debt issuance costs                                        -     (1,348,977)
    Principal repayments                                       -     (1,161,811)
                                                    ------------  -------------
     Net cash provided by financing activities        16,690,721     15,489,212
                                                    ------------  -------------
 Net increase in cash and equivalents                  2,741,869      3,893,978
 Cash and equivalents at beginning of period           6,748,637      2,854,659
                                                    ------------  -------------
 Cash and equivalents at end of period              $  9,490,506  $   6,748,637
                                                    ============  =============

Supplemental Cash Flow Information (See Note 14)


  The accompanying notes are an integral part of these financial statements.

                                      F-6

<PAGE>

                          SYNERGY RESOURCES CORPORATION
                          NOTES TO FINANCIAL STATEMENTS
                            August 31, 2011 and 2010


1. Organization and Summary of Significant Accounting Policies

     Organization:  Synergy Resources Corporation (the "Company") represents the
result  of  a  merger  transaction  on  September  10,  2008,  between  Brishlin
Resources,   Inc.  ("Predecessor  Brishlin"),  a  public  company,  and  Synergy
Resources Corporation ("Predecessor Synergy"), a private company. The Company is
engaged in oil and gas  acquisitions,  exploration,  development  and production
activities,  primarily  in the area  known as the  Denver-Julesburg  Basin.  The
Company has adopted August 31st as the end of its fiscal year.

     Basis of  Presentation:  The Company  prepares its financial  statements in
accordance with accounting principles generally accepted in the United States of
America ("US  GAAP").  In June 2009 the  Financial  Accounting  Standards  Board
("FASB") established the Accounting Standards Codification ("ASC") as the single
source of authoritative US GAAP to be applied by nongovernmental entities. Rules
and  interpretive  releases of the  Securities and Exchange  Commission  ("SEC")
under authority of federal  securities laws are also sources of authoritative US
GAAP for SEC  registrants.  New accounting  standards are  communicated  by FASB
through Accounting Standards Updates ("ASU's").

     Reclassifications:  Certain amounts previously  presented for prior periods
have  been   reclassified   to  conform  to  the   current   presentation.   The
reclassifications had no effect on net loss,  accumulated deficit, net assets or
total shareholders' equity.

     Use of Estimates:  The  preparation  of financial  statements in conformity
with US GAAP requires  management to make estimates and assumptions  that effect
the reported amount of assets and  liabilities,  including oil and gas reserves,
and disclosure of contingent assets and liabilities at the date of the financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period.  Management  routinely makes judgments and estimates about the
effects of matters that are inherently uncertain. Management bases its estimates
and  judgments on  historical  experience  and on various other factors that are
believed to be reasonable under the circumstances, the results of which form the
basis for making  judgments  about the carrying values of assets and liabilities
that are not readily apparent from other sources.  Estimates and assumptions are
revised periodically and the effects of revisions are reflected in the financial
statements in the period it is determined to be necessary.  Actual results could
differ from these estimates.

     Cash and Cash Equivalents: The Company considers cash in banks, deposits in
transit,  and highly liquid debt instruments  purchased with original maturities
of three months or less to be cash and cash equivalents.

     Inventory:   Inventories  consist  primarily  of  tubular  goods  and  well
equipment to be used in future drilling  operations or repair operations and are
carried at the lower of cost or market.

                                      F-7

<PAGE>

     Oil and Gas Properties: The Company uses the full cost method of accounting
for  costs  related  to its 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  amortized  using  the
unit-of-production   method  based  upon  estimates  of  proved  reserves.   For
amortization  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.

     Under the full cost method of accounting,  a ceiling test is performed each
quarter.  The full cost ceiling test is an  impairment  test  prescribed  by SEC
regulations.  The ceiling  test  determines a limit on the book value of oil and
gas  properties.  The  capitalized  costs of  proved  and  unproved  oil and gas
properties,  net of accumulated depreciation,  depletion, and amortization,  and
the related  deferred income taxes, may not exceed the estimated future net cash
flows from proved oil and gas  reserves,  less future cash  outflows  associated
with  asset  retirement  obligations  that have been  accrued,  plus the cost of
unevaluated properties not being amortized,  plus the lower of cost or estimated
fair value of unevaluated  properties being amortized,  less income tax effects.
Prices are held constant for the  productive  life of each well.  Net cash flows
are discounted at 10%. If net capitalized costs exceed this limit, the excess is
charged  to  expense  and  reflected  as  additional  accumulated  depreciation,
depletion and  amortization.  The  calculation  of future net cash flows assumes
continuation  of  current  economic  conditions.   Once  impairment  expense  is
recognized, it cannot be reversed in future periods, even if changing conditions
raise the ceiling amount.

     For the years  ended  August 31,  2011 and 2010,  the oil and  natural  gas
prices  used to  calculate  the full cost  ceiling  limitation  are the 12 month
average prices, calculated as the unweighted arithmetic average of the first day
of the month price for each month within the 12 month period prior to the end of
the reporting  period,  unless prices are defined by  contractual  arrangements.
Prices are adjusted for basis or location differentials.

     Capitalized  Overhead:  A portion of the  Company's  overhead  expenses are
directly attributable to acquisition and development activities.  Under the full
cost method of accounting, these expenses are capitalized in the full cost pool.
The Company capitalized overhead expenses of approximately  $206,233 and $95,475
for the years ended August 31, 2011 and 2010, respectively.

                                      F-8

<PAGE>

     Oil and Gas Reserves:  The  determination  of  depreciation,  depletion and
amortization  expense, as well as the ceiling test related to the recorded value
of the  Company's  oil and natural gas  properties,  is highly  dependent on the
estimates  of the proved oil and  natural  gas  reserves.  Oil and  natural  gas
reserves  include proved reserves that represent  estimated  quantities of crude
oil and natural gas which  geological  and  engineering  data  demonstrate  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 natural gas  reserves  and their
values,  including  many  factors  beyond the  Company's  control.  Accordingly,
reserve estimates are often different from the quantities of oil and natural gas
ultimately  recovered and the  corresponding  lifting costs  associated with the
recovery of these reserves.

     Capitalized Interest: The Company capitalizes interest on expenditures made
in connection with  acquisition of mineral  interests and  development  projects
that are not subject to current amortization. Interest is capitalized during the
period that  activities  are in progress to bring the projects to their intended
use.

     Debt Issuance  Costs:  Debt issuance  costs of $2,041,455  were incurred in
connection  with executing  convertible  promissory  notes between  December 29,
2009,  and March 12,  2010  (See Note 7). As a result of the  conversion  of all
outstanding  convertible  promissory  notes into shares of the Company's  common
stock,  all debt issuance costs have been  recognized as a component of interest
expense through August 31, 2011.

     Fair Value  Measurements:  Effective September 1, 2008, the company adopted
FASB Accounting  Standards  Codification  ("ASC") "Fair Value  Measurements  and
Disclosures",  which establishes a framework for assets and liabilities measured
at fair value on a recurring  basis  included in the Company's  balance  sheets.
Effective  September 1, 2009, similar accounting guidance was adopted for assets
and  liabilities  measured at fair value on a nonrecurring  basis. As defined in
the guidance, fair value is the price that would be received to sell an asset or
be paid to  transfer  a  liability  in an  orderly  transaction  between  market
participants at the measurement date (exit price).

     The Company uses market data or assumptions that market  participants would
use in pricing the asset or liability,  including  assumptions about risk. These
inputs  can either be  readily  observable,  market  corroborated  or  generally
unobservable.  Fair value balances are classified based on the  observability of
the various inputs.

     Asset  Retirement  Obligations:  The  Company's  activities  are subject to
various laws and  regulations,  including legal and  contractual  obligations to
reclaim,  remediate,  or otherwise  restore  properties at the time the asset is
permanently  removed from  service.  The fair value of a liability for the asset
retirement  obligation  ("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,
the Company  capitalizes the cost (asset retirement cost or "ARC") by increasing
the carrying value of the related asset. 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.  The capitalized  ARCs are included

                                      F-9

<PAGE>

in the full cost pool and subject to depletion,  depreciation and  amortization.
In addition, the ARCs are included in the ceiling test calculation.  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 the  Company's  credit
adjusted  risk free  interest  rate.  Estimates  are  periodically  reviewed and
adjusted to reflect changes.

     Derivative  Conversion  Liability:  The Company  accounts  for its embedded
conversion  features in its convertible  promissory notes in accordance with the
guidance for derivative instruments, which require a periodic valuation of their
fair value and a corresponding  recognition of liabilities  associated with such
derivatives. The recognition of derivative conversion liabilities related to the
issuance of  convertible  debt is applied first to the proceeds of such issuance
as a debt  discount  at the date of the  issuance.  Any  subsequent  increase or
decrease  in  the  fair  value  of  the  derivative  conversion  liabilities  is
recognized as a charge or credit to other income  (expense) in the statements of
operations.  In connection with the conversion of convertible  promissory  notes
into shares of the  Company's  common  stock,  during the years ended August 31,
2011 and 2010  derivative  conversion  liabilities of $19,554,346 and $1,809,149
were reclassified to additional paid-in-capital, respectively.

     Revenue Recognition:  Revenue is recognized for the sale of oil and natural
gas when production is sold to a purchaser and title has  transferred.  Revenues
from  production on properties in which the Company shares an economic  interest
with  other  owners  are  recognized  on the  basis of the  Company's  interest.
Provided that  reasonable  estimates can be made,  revenue and  receivables  are
accrued to recognize delivery of product to the purchaser.  Payment is typically
received sixty to ninety days after  production.  Differences  between estimates
and actual volumes and prices, if any, are adjusted upon final settlement.

     Major  Customer and  Operating  Region:  The Company  operates  exclusively
within the United States of America. Except for cash and equivalent instruments,
all of the Company's  assets are employed in and all of its revenues are derived
from the oil and gas industry.

     The Company's oil and gas production is purchased by a few  customers.  The
table below presents the percentage of oil and gas revenue that was purchased by
major customers.

                                            Year Ended August
                                                   31,
                                           ---------------------
                   Major Customers           2011        2010
                   ---------------         ----------  ---------

                   Company A                  75%        57%
                   Company B                  21%        30%
                   Company C                     *       13%

                  *  less than 10%

     As there are other  purchasers  that are capable of and willing to purchase
the  Company's  oil and gas  production  and since the Company has the option to
change  purchasers  on its  properties  if  conditions  so warrant,  the Company
believes that its oil and gas  production can be sold in the market in the event
that  it  is  not  sold  to  the  Company's  existing  customers,  but  in  some

                                      F-10

<PAGE>

circumstances  a change in customers  may entail  significant  transition  costs
and/or shutting in or curtailing  production for weeks or even months during the
transition to a new customer.

     Stock Based  Compensation:  The Company  records  stock-based  compensation
expense in  accordance  with the fair value  recognition  provisions of US GAAP.
Stock based  compensation is measured at the grant date based upon the estimated
fair value of the award and the expense is recognized over the required employee
service period, which generally equals the vesting period of the grant. The fair
value  of  stock   options   is   estimated   using   the   Black-Scholes-Merton
option-pricing  model. The fair value of restricted stock grants is estimated on
the grant date based upon the fair value of the common stock.

     Earnings Per Share  Amounts:  Basic earnings per share includes no dilution
and is computed by dividing net income (or loss) by the weighted-average  number
of  shares  outstanding  during  the  period.  Diluted  earnings  per  share  is
equivalent  to basic  earnings  per  share as all  dilutive  securities  have an
antidilutive  effect on earnings per share.  The following  dilutive  securities
could dilute the future earnings per share:

                                2011            2010
                            -------------   -------------

Convertible promissory notes           -       9,942,500
Accrued interest                       -         135,068
Warrants(1)                   14,931,067      15,286,466
Employee stock options         4,645,000       4,220,000
                            -------------   -------------
      Total                   19,576,067      29,584,034
                            =============   =============

       (1)  Also as of August 31, 2011 and 2010, the Company had a contingent
obligation to issue 63,466 potentially dilutive securities, all of which were
excluded from the calculation because the contingency conditions had not been
met.

     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. The Company provides for deferred taxes for
the  estimated  future tax effects  attributable  to temporary  differences  and
carry-forwards  when  realization  is  more  likely  than  not.  If the  Company
concludes  that it is more  likely  than not that some  portion,  or all, of the
deferred tax asset will not be  realized,  the balance of deferred tax assets is
reduced by a valuation allowance.

     The Company  adheres to the provisions of the ASC regarding  uncertainty in
income taxes.  No significant  uncertain tax positions were identified as of any
date on or before August 31. 2011.  Given the  substantial  net  operating  loss
carry-forwards  at both  the  federal  and  state  levels,  neither  significant
interest expense nor penalties charged for any examining agents' tax adjustments

                                      F-11

<PAGE>

of income tax returns  prior to and including the year ended August 31, 2011 are
anticipated  since such  adjustments  would very  likely  simply  reduce the net
operating loss carry-forwards.

     Recent Accounting Pronouncements:  The Company evaluates the pronouncements
of various authoritative accounting organizations to determine the impact of new
pronouncements on US GAAP and the impact on the Company.

     The Company has recently adopted the following new accounting standards:

     Business  Combinations - Effective  March 1, 2011, the Company  adopted ASU
No. 2010-29 - Business Combinations (Topic 805): Disclosure of Supplementary Pro
Forma Information for Business Combinations.  This update provides clarification
requiring public companies that have completed material acquisitions to disclose
the revenue and earnings of the  combined  business as if the  acquisition  took
place at the beginning of the comparable prior annual reporting period, and also
expands the supplemental  pro forma  disclosures to include a description of the
nature and  amount of  material,  nonrecurring  pro forma  adjustments  directly
attributable  to the  business  combination  included in the  reported pro forma
revenue  and  earnings.  Adoption  of this  ASU had no  material  effect  on the
Company's financial position,  results of operations,  or cash flows. See Note 9
for the Company's disclosures of business combinations.

     The following  accounting  standards  updates were recently issued and have
not yet been adopted by the Company.  These standards are currently under review
to  determine  their  impact on the  Company's  financial  position,  results of
operations, or cash flows.

     Presentation  of  Comprehensive  Income - In June 2011, the FASB issued ASU
2011-05 - Presentation of Comprehensive  Income ("ASU 2011-05"),  which requires
entities to present reclassification adjustments included in other comprehensive
income on the face of the financial  statements  and allows  entities to present
the  total  of  comprehensive  income,  the  components  of net  income  and the
components of other comprehensive income either in a single continuous statement
of comprehensive income or in two separate but consecutive  statements.  It also
eliminates   the  option  for  entities  to  present  the  components  of  other
comprehensive  income  as part of the  statement  of  changes  in  stockholders'
equity.  For public  companies,  ASU 2011-05 is effective  for fiscal years (and
interim  periods within those years)  beginning  after  December 15, 2011,  with
earlier  adoption  permitted.  Adoption  of this ASU is not  expected  to have a
material effect on the Company's financial position,  results of operations,  or
cash flows.

     There were various other updates recently issued, most of which represented
technical  corrections  to the  accounting  literature  or  were  applicable  to
specific  industries,  and are not  expected  to have a  material  impact on the
Company's financial position, results of operations or cash flows.

                                      F-12

<PAGE>

2.      Accounts Receivable

     Accounts receivable consist primarily of trade receivables from oil and gas
sales and amounts due from other working  interest owners which have been billed
for  their  proportionate  share  of  wells  which  the  Company  operates.  For
receivables from joint interest owners,  the Company  typically has the right to
withhold  future revenue  disbursements  to recover  outstanding  joint interest
billings.  As of August 31,  2011 and 2010,  major  customers  (i.e.  those with
balances greater than 10% of total receivables) were as follows:

                                                 As of August 31,
                                           ---------------------------
 Major Customer or Joint Interest Owner       2011           2010
 --------------------------------------    -----------   -------------
  Company A                                    31%            27%
  Company B                                    31%              *
  Company C                                    13%              *
  *  less than 10%

                                      F-13

<PAGE>

3.     Property and Equipment

     Capitalized  costs of property  and  equipment  at August 31, 2011 and 2010
consisted of the following:

                                                      As of August 31,
                                                -----------------------------
                                                    2011            2010
                                                --------------  -------------
Oil and gas properties, full cost method:
   Unevaluated costs, not subject to
    amortization:
      Lease acquisition costs                     $ 9,942,908     $  848,696
      Wells in progress                             4,813,749             --
                                                --------------  -------------
                                                   14,756,657        848,696
                                                                            
   Evaluated costs:
      Producing and non-producing                  37,750,737     12,992,594
                                                --------------  -------------
         Total capitalized costs                   52,507,394     13,841,290
      Less, accumulated depletion                 (3,892,537)    (1,149,096)
                                                --------------  -------------
            Oil and gas properties, net            48,614,857     12,692,194
                                                --------------  -------------
Other property and equipment:
    Vehicles
                                                      163,904         89,527
    Leasehold improvements                             35,490         32,329
    Office equipment
                                                      105,089         36,821
    Land                                               43,750             --
    Less, accumulated depreciation                    (65,026)        (7,888)
                                                --------------  -------------
            Other property and equipment, net         283,207        150,789
                                                --------------  -------------
Total property and equipment, net                $ 48,898,064   $ 12,842,983
                                                ==============  =============

     The  capitalized  costs of evaluated  oil and gas  properties  are depleted
using  the  unit-of-production  method  based  on  estimated  reserves  and  the
calculation  is  performed  quarterly.  Production  volumes  for the quarter are
compared  to  beginning  of quarter  estimated  total  reserves  to  calculate a
depletion  rate. For the years ended August 31, 2011 and 2010,  depletion of oil
and  gas  properties  was  $2,743,441  and  $692,274,   respectively,  which  is
equivalent to $16.62 and $15.52 per barrel of oil equivalent, respectively.

     Periodically,  the  Company  reviews  its  unevaluated  properties  and its
inventory to determine  if the carrying  value of either asset  exceeds its fair
value.  The review for the years ended August 31, 2011 and 2010,  indicated that
asset carrying values were less than fair values and no impairment was required.

     On a quarterly  basis the Company  performs the full cost ceiling test. The
quarterly  ceiling  tests  performed  during the years ended August 31, 2011 and
2010 did not reveal any impairments.

                                      F-14

<PAGE>

     During the year ended August 31, 2011,  the Company sold oil and gas leases
covering  5,902  gross  acres  (3,738  net  acres)  for  net  cash  proceeds  of
$8,382,167,  after the  deduction of selling  costs of  $248,700.  No gains were
recognized  on the sales and all of the proceeds  were credited to the full cost
pool.  The  sale  reduced  the  amortization  base  of the  full  cost  pool  by
approximately 7%, which was determined to be less than the "significant  change"
threshold required to recognize a gain on the sale.

     For the  years  ended  August  31,  2011 and  2010,  depreciation  of other
property and equipment was $57,138 and $7,592, respectively.

4.     Interest Expense

     The components of interest  expense recorded for the years ended August 31,
2011 and 2010, consisted of:

                                            2011             2010
                                         ------------   ----------------
      Convertible promissory notes        $  589,539        $790,976
      at 8%
      Related party note payable at           74,047               -
      5.25%
      Bank credit facility, variable          41,559          30,388
      rate                        
      Accretion of debt discount           2,664,138       1,333,590
      (see Note 7)
      Amortization of debt issuance        1,587,799         453,656
      costs
      Less, interest capitalized            (710,137)       (269,761)
                                         -------------    --------------
      Interest expense, net               $4,246,945       $2,338,849
                                         =============    ==============

5.     Bank Credit Facility

     In June 2011, the Company  entered into a revolving line of credit facility
with Bank of  Choice  ("2011  LOC"),  which  provides  for  borrowings  up to $7
million.  The 2011 LOC expires on June 3, 2012.  Amounts borrowed under the 2011
LOC are  subject to a security  interest  in the  Company's  oil and gas assets.
Principal amounts outstanding under the 2011 LOC bear interest, payable monthly,
at the Wall Street  Journal  Prime Rate plus 2%,  subject to a minimum  interest
rate of 5.5%.  As of August  31,  2011,  the  Company  had  available  borrowing
capacity of $6,975,000 under the 2011 LOC.

     In previous  years,  the Company  maintained  a similar  revolving  line of
credit  facility that provided for borrowings up to  $1,161,811.  In April 2010,
all borrowings under the facility were paid in full.

6.     Asset Retirement Obligations

     During the years ended August 31, 2011 and 2010, the Company brought 66 net
wells into productive  status and will have asset removal  obligations  once the
wells are permanently removed from service.  The primary obligations involve the
removal and disposal of surface  equipment,  plugging and  abandoning the wells,
and site  restoration.  For the  purpose  of  determining  the fair value of ARO

                                      F-15

<PAGE>

incurred  during the years ended August 31, 2011 and 2010,  the Company used the
following assumptions:

                                               2011             2010
                                            -----------      -----------
      Inflation rate                            4.0%             5.0%
      Estimated asset life (years)               24               24
      Credit    adjusted   risk   free        11.64%           10.53%
      interest rate

     In connection with the acquisition of certain oil and gas properties on May
24, 2011 (see Note 9) the Company assumed the future  responsibility to plug and
abandon  the  producing   wells  and  recorded  the  associated  ARO  for  these
properties, which had a present value of $179,410 at the date of acquisition.

     The following table summarizes the changes in asset retirement  obligations
associated  with our oil and gas  properties for the years ended August 31, 2011
and 2010:

                                                    2011           2010
                                                -------------  -------------

Beginning asset retirement obligation             $  254,648     $       --
Liabilities incurred                                 351,083        253,114
Liabilities settled                                       --             --
Accretion expense                                     37,728          1,534
Revisions in previous estimates                           --             --
                                                -------------  -------------
Ending asset retirement obligation                $  643,459     $  254,648
                                                =============  =============

7.     Convertible Promissory Notes and Derivative Conversion Liability

     During the fiscal year ended August 31, 2011,  the Company  received  gross
proceeds of  $18,000,000  from the sale of 180 Units at $100,000 per Unit.  Each
Unit  consisted of one  convertible  promissory  note  ("Note") in the principal
amount of $100,000 and 50,000  Series C warrants  (collectively  referenced as a
"Unit").  The Notes bore interest at 8% per year, payable  quarterly,  and had a
stated  maturity date of December 31, 2012.  Each Series C warrant  entitles the
holder to purchase  one share of common  stock at a price of $6.00 per share and
expires on December 31, 2014. Through August 31, 2011, all of the Notes had been
converted into shares of the Company's common stock.

     The Notes were considered  hybrid debt instruments  containing a detachable
warrant and a conversion  feature  under which the proceeds of the offering were
allocated to the detachable  warrants and the conversion  feature based on their
fair values.  The Series C warrants were determined to be a component of equity,
and the fair value of the warrants was recorded as additional  paid-in  capital.
Since the warrants  were  recorded as a component  of equity,  the fair value of
$1,760,048 was estimated at issuance and not re-measured in subsequent  periods.
The Notes  contained a conversion  feature,  at an initial  conversion  price of
$1.60 that was subject to adjustment under certain circumstances,  which allowed
the Note holders to convert the  principal  balance into a maximum of 11,250,000
common  shares,  plus  conversion  of accrued  and unpaid  interest  into common

                                      F-16

<PAGE>

shares,  also at $1.60 per share. The conversion feature was determined to be an
embedded  derivative  requiring the  conversion  option to be separated from the
host contract and measured at its fair value.  At issuance,  the estimated  fair
value of the  conversion  feature was  $3,455,809 and was recorded as derivative
conversion liability. The conversion option was re-measured and recorded at fair
value each subsequent reporting period, with changes in the fair value reflected
in other income  (expense) in the statements of operations.  Allocation of value
to the components created a debt discount of $5,215,857, which was accreted over
the life of the Notes,  subject to early Note  conversions,  using the effective
interest method. The effective interest rate on the Notes was 19%.

     In  connection  with the  sale of the  Units,  the  Company  paid  fees and
expenses of $1,348,977 and issued  1,125,000  Series D warrants to the placement
agent.  The Series D warrants have an exercise  price of $1.60 and an expiration
date of December  31,  2014.  The  warrants  were  valued at $692,478  using the
Black-Scholes-Merton  option pricing model. The Company  recorded  $2,041,455 of
debt issuance  costs,  which was being  amortized  over the expected term of the
Notes, with accelerated amortization recognition on early Note conversions.  For
the years ended  August 31, 2011 and 2010,  the  Company  recorded  amortization
expense for debt issuance costs of $1,587,799 and $453,656, respectively.

     At the time the Notes  were  converted,  the  estimated  fair  value of the
derivative  conversion  liability  attributable  to the converted  notes totaled
$19,554,346,  which was  reclassified  from derivative  conversion  liability to
additional   paid-in   capital.   Similarly,   the  unamortized   debt  discount
attributable to the converted  notes totaled  $3,120,293.  The unamortized  debt
discount  of  $2,067,376  applicable  to the  conversion  option was  charged to
accretion  of debt  discount and the  unamortized  debt  discount of  $1,052,917
applicable  to the warrants was  reclassified  from debt  discount to additional
paid-in  capital.  The Company recorded  accretion  expense for debt discount of
$2,664,138  and  $1,333,590  for the  years  ended  August  31,  2011 and  2010,
respectively.

8.     Fair Value Measurements

     Assets and  liabilities are measured at fair value on a recurring basis for
disclosure  or  reporting,  as  required  by ASC "Fair  Value  Measurements  and
Disclosures".

     A fair value hierarchy was established  that prioritizes the inputs used to
measure  fair value.  The  hierarchy  gives the highest  priority to  unadjusted
quoted prices in active  markets for identical  assets or  liabilities  (Level 1
measurements)   and  the  lowest  priority  to  unobservable   inputs  (Level  3
measurements).

     Level 1 - Quoted  prices are  available  in active  markets  for  identical
assets or  liabilities  as of the reporting  date.  Active  markets are those in
which transactions for the asset or liability occur in sufficient  frequency and
volume to provide  pricing  information on an ongoing  basis.  Level 1 primarily
consists of financial  instruments such as exchange-traded  derivatives,  listed
securities and U.S. government treasury securities.

                                      F-17

<PAGE>

     Level 2 - Pricing  inputs are other than  quoted  prices in active  markets
included in Level 1, which are either  directly or  indirectly  observable as of
the reporting date. Level 2 includes those financial instruments that are valued
using models or other valuation methodologies,  where substantially all of these
assumptions  are observable in the  marketplace  throughout the full term of the
instrument,  can be derived from  observable data or are supported by observable
levels at which transactions are executed in the marketplace.

     Level 3 - Pricing inputs include significant inputs that are generally less
observable  than  objective  sources.  These inputs may be used with  internally
developed methodologies that result in management's best estimate of fair value.
Level 3 includes  those  financial  instruments  that are valued using models or
other valuation methodologies,  where substantial assumptions are not observable
in the marketplace throughout the full term of the instrument, cannot be derived
from  observable  data  or are not  supported  by  observable  levels  at  which
transactions  are executed in the  marketplace.  At each balance sheet date, the
Company performs an analysis of all applicable instruments and includes in Level
3 all of those whose fair value is based on significant unobservable inputs.

     A substantial portion of the Company's financial  instruments  consisted of
cash  and  equivalents,  accounts  receivable,  accounts  payable,  and  accrued
liabilities. Due to the short original maturities and high liquidity of cash and
equivalents,  accounts  receivable,  accounts payable,  and accrued liabilities,
carrying amounts approximated fair values.

     As  permitted  under  fair  value  accounting  guidance,   the  outstanding
principal  balance of the Company's Notes were not restated to fair value in the
Company's  financial  statements for each  reporting  period that the Notes were
outstanding.  Due to the short  term to  maturity  and the  Company's  option to
prepay the debt at any time after  January 1, 2011,  it was  estimated  that the
fair value of the Notes approximated face value. The Notes contained an embedded
conversion  option  which  was  required  to  be  separated  and  reported  as a
derivative  conversion liability at fair value. As a result of the conversion of
all Notes into shares of the Company's common stock,  the derivative  conversion
liability at the time of  conversion  was  reclassified  to  additional  paid-in
capital.

     The Company utilized the Monte Carlo Simulation  ("MCS") model to value the
derivative conversion liability.  Inputs to this valuation technique include the
Company's  quoted stock price and published  interest rates and credit  spreads.
All of the  significant  inputs  utilized were  observable,  either  directly or
indirectly;   therefore,  the  Company's  derivative  conversion  liability  was
included within the Level 2 fair value hierarchy.

     The following  table  presents,  for each hierarchy  level,  our assets and
liabilities,  including both current and non-current portions,  measured at fair
value on a recurring basis as of August 31, 2011 and 2010.

                                      F-18

<PAGE>

As of August 31, 2011       Total        Level 1      Level 2       Level 3
-----------------------  ------------  ------------ -------------  -----------
Derivative Conversion   
Liability                $         -    $        -   $         -    $        - 

As of August 31, 2010       Total        Level 1      Level 2       Level 3
-----------------------  ------------  ------------ -------------  -----------
Derivative Conversion  
Liability                $ 9,325,117    $        -   $ 9,325,117    $       -

     The Company also measures all nonfinancial  assets and liabilities that are
not recognized or disclosed on a recurring  basis. As discussed in Note 6, asset
retirement  obligations  and costs  totaling  $351,083  and  $253,114  have been
accounted  for as  long-term  liabilities  and  included  in  the  oil  and  gas
properties, full cost pool at August 31, 2011 and 2010, respectively.  The Level
3 inputs used to measure the  estimated  fair value of the  obligations  include
assumptions  and  judgments  about the ultimate  settlement  amounts,  inflation
factors,  credit adjusted discount rates,  timing of settlement,  and changes in
regulations.  Changes in  estimates  are  reflected in the  obligations  as they
occur.

9.     Related Party Transactions and Commitments
 
     Two of the Company's  executive  officers  control three entities that have
entered into  agreements to provide various goods,  services,  and facilities to
the Company.  The  entities  are  Petroleum  Management,  LLC ("PM"),  Petroleum
Exploration and Management, LLC ("PEM"), and HS Land & Cattle, LLC ("HSLC").

     Acquisition  of Oil and Gas Assets from PEM: In two separate  transactions,
the Company purchased oil and gas assets from PEM.

     On May 24, 2011, the Company acquired  operating (working interest) oil and
gas  assets  owned by PEM,  including  interest  in 88 gross  oil and gas  wells
(approximately  40 net wells) and mineral leases  covering  approximately  6,968
gross acres.  All of the producing  properties  acquired from PEM are located in
the  Wattenberg  Field of the D-J  Basin.  Some of the  undeveloped  leases  are
located in Yuma County, Colorado.

     The purchase price consisted of a cash payment of $10,000,000, the issuance
of 1,381,818  restricted  shares of common stock,  and a promissory  note in the
principal  amount  of  $5,200,000.  The  transaction  is  subject  to  customary
post-closing  adjustments for events  occurring  between January 1, 2011 and May
24, 2011. The promissory  note bears interest at an annual rate of 5.25%, is due
on January 2, 2012, and is secured by the  properties  purchased by the Company.
No liabilities of PEM were assumed in the transaction. Prior to consummating the
transaction,  the Company's acquisition  committee,  consisting of disinterested
directors,  reviewed and approved the transaction, and the Company shareholders,
not including Mr. Holloway and Mr. Scaff, approved the transaction.

     For accounting purposes,  the value of the transaction was determined to be
$19,358,392,   which  includes  the  impact  of  post-closing  adjustments.  The

                                      F-19

<PAGE>

accounting value, which is subject to further post-closing adjustments,  if any,
includes an updated  valuation of 1,381,818 shares of common stock to $4,698,181
based upon the closing price of the Company's  common stock on May 24, 2011, and
reflects net cash receipts of $539,799 for  transactions  that occurred  between
January 1 and May 24, 2011.  The entire  purchase price was allocated to oil and
gas  properties.  No gain or loss was recorded on the  transaction.  The Company
incurred additional general and administrative  costs of approximately  $150,000
related to the  transaction,  all of which were  charged to  operating  expenses
during the year ended August 31, 2011.

     The  results  of  operations  from the assets  acquired  from PEM have been
included in the financial statements since the date of acquisition.  Revenue and
operating  income generated from the assets acquired from May 24, 2011 to August
31, 2011 were $615,635 and $455,242, respectively.

     The  following  unaudited  pro forma  financial  information  presents  the
combined  results of the Company and the properties  acquired from PEM as though
the acquisition  had been  consummated as of September 1, 2009, the beginning of
the Company's fiscal year, for the two periods indicated below:

                                             2011             2010
                                         -------------     ------------

      Operating revenues               $  12,592,535      $   3,981,590
      Net loss                         $ (10,476,234)     $ (11,360,440)
      Basic  and  Diluted  loss per    $       (0.39)     $       (0.84)
      share

     The pro forma  information does not necessarily  reflect the actual results
of  operations  had the  acquisition  been  consummated  at the beginning of the
period indicated nor is it necessarily  indicative of future operating  results.
The pro  forma  information  does  not  give  effect  to any  potential  revenue
enhancements or operating efficiencies that could result from the acquisition.

     On October 1, 2010, the Company  acquired certain mineral assets located in
the Wattenberg  field,  part of the D-J Basin, from PM and PEM for $1,017,435 in
cash.  The oil and gas  properties  consist of a 100% working  interest (80% net
revenue  interest)  in 8 oil  and gas  wells,  as well  as 15  drill  sites  and
miscellaneous equipment.

     Other Related Party  Transactions:  The Company  leases office space and an
equipment  yard from HSLC in  Platteville,  Colorado for $10,000 per month.  The
twelve month lease  arrangement with HSLC commenced July 1, 2010 and was renewed
on July 1, 2011, for another year.  Under these leases,  the Company paid HSLC a
total of $120,000  and  $20,000  for the years  ended  August 31, 2011 and 2010,
respectively.

     From June 2008 through June 2010,  the Company  received  certain  services
under an Administrative Services Agreement with PM. The Company paid $10,000 per
month for leasing  office  space and an equipment  yard located in  Platteville,
Colorado,  and paid  $10,000  per month for office  support  services  including
secretarial service, word processing,  communication services,  office equipment
and supplies. The Company paid $200,000 under this

                                      F-20

<PAGE>

agreement  during the year ended August 31, 2010.  Effective  June 30, 2010, the
Company terminated the agreement.

     In addition to the  transactions  described  above,  the Company  undertook
various  activities  with PM and PEM that are  related  to the  development  and
operation of oil and gas properties. The Company occasionally purchases services
and certain oil and gas equipment,  such as tubular goods and surface equipment,
from PM. The Company  reimburses  PM for the  original  cost of the services and
equipment.  Prior to the asset  acquisition  transaction  that closed on May 24,
2011,  PEM was a joint working  interest  owner of certain wells operated by the
Company.  PEM was charged for its pro-rata share of costs and expenses  incurred
on its behalf by the Company,  and  similarly  PEM was credited for its pro-rata
share of revenues  collected on its behalf.  The following table  summarizes the
transactions with PM and PEM during the years ended August 31, 2011 and 2010:

                                      Years Ended August 31,
                                   -----------------------------
                                        2011           2010
                                   --------------  -------------
Purchase of equipment from PM       $    2,290      $ 1,070,495
Payments to PM for equipment          (540,988)        (531,797)
                                   --------------  -------------
Balance due to PM for equipment     $        -      $   538,698
                                   ==============  =============

Joint interest costs billed to PEM  $  396,469      $ 1,629,895
Amounts collected from PEM          (1,264,060)        (762,060)
                                   --------------  -------------
Joint  interest  billing  due from  $        -      $   867,835
PEM  
                                   ==============  =============

Revenues  collected  on  behalf of
PEM                                 $  794,726      $   167,499
Payments to PEM                       (810,697)        (151,528)
                                   --------------  -------------
Balance due to PEM for revenues     $        -      $    15,971
                                   ==============  =============

     During the year ended  August 31,  2011,  the Company  acquired oil and gas
leases from George  Seward,  a member of the Company's  board of  directors.  In
total,  lease interests  covering 22,066 gross (19,717 net)  undeveloped  acres,
located in eastern Colorado and western Nebraska,  were acquired in exchange for
353,817 shares of the Company's  common stock.  Based on the market price of the
Company's common stock on the transaction  dates, these acquisitions were valued
at $788,676.

10. Shareholders' Equity

     Preferred Stock: The Company has authorized  10,000,000 shares of preferred
stock with a par value of $0.01 per share.  These shares may be issued in series
with such rights and preferences as may be determined by the Board of Directors.
Since inception, the Company has not issued any preferred shares.

     Common Stock: The Company has authorized 100,000,000 shares of common stock
with a par value of $0.001 per share.

                                      F-21

<PAGE>

      Issued and Outstanding: The Company's total issued and outstanding common
shares were 36,098,212 and 13,510,981 at August 31, 2011 and 2010, respectively.
Issuance of shares of the Common stock during the two years ended August 31,
2011 is as follows:

     i.   Common stock  issued for  conversions  of Notes:  During the two years
          ended August 31, 2011, holders of convertible  promissory Notes with a
          face value of $18,000,000  converted the Notes into 11,250,000  shares
          of  common  stock at the  contractual  conversion  price of $1.60  per
          share.

     ii.  Sale of common stock: In January 2011, the Company  completed the sale
          of 9,000,000 shares of common stock to private  investors.  The shares
          were sold at a price of $2.00 per share.  Net  proceeds to the Company
          from the sale of the shares were $16,690,721  after deductions for the
          placement agents' commissions and expenses of the offering.

     iii. Common stock issued for mineral leases:  The Company issued  1,849,838
          and 5,966  common  shares in exchange  for mineral  leases  during the
          years ended  August 31,  2011 and 2010,  respectively.  The  aggregate
          value for these  transactions  was  $5,240,307  and $16,645 during the
          years  ended  August  31,  2011  and  2010,  respectively,  which  was
          determined using the market price of the Company's common stock.

     iv.  Common stock issued in connection with PEM  acquisition:  In May 2011,
          the Company  acquired certain assets from PEM (see Note 9). As part of
          the  consideration,  the Company issued 1,381,818 shares of restricted
          common  stock valued at  $4,698,181,  based on the market price of the
          Company's common stock.

     v.   Common  stock  issued for  warrants  exercised:  During the year ended
          August 31, 2011,  the Company  issued  common  shares  pursuant to the
          exercise  of Series D  warrants.  As the Series D  warrants  contain a
          cashless  exercise   provision,   warrant  holders  exercised  355,399
          warrants  in  exchange  for 226,199  shares of common  stock,  and the
          Company received no cash proceeds in the transaction.

     vi.  Common  stock  issued for  services:  During the year ended August 31,
          2011,  the Company  issued a total of 150,000  shares of common stock,
          with a fair market value of $430,000,  to individuals as  compensation
          for services provided to the Company. During the year ended August 31,
          2010, the Company  issued 197,988 shares of common stock,  with a fair
          market value of $544,575 as partial compensation to its directors.

     During the year ended  August 31,  2010,  the Company  issued  Series C and
Series D warrants in  connections  with the sale of 180  convertible  promissory
note units at $100,000 per unit. (See Note 7) Each Series C warrant entitles the
holder to purchase  one share of common  stock at a price of $6.00 per share and
warrants were issued to purchase an aggregate of 9,000,000  common  shares.  The
Series C warrants  expire on December 31, 2014.  Each Series D warrant  entitles
the holder to purchase  one share of common  stock at a price of $1.60 per share

                                      F-22

<PAGE>

and warrants  were issued to purchase an aggregate of 1,125,000  common  shares.
The  Series D  warrants  contain a  cashless  exercise  provision  and expire on
December 31, 2014.

     In connection with various  transactions  during the years ended August 31,
2009 and 2008, the Company issued Series A warrants to purchase 4,098,000 shares
of common  stock and issued  Series B warrants to purchase  1,000,000  shares of
common stock and issued sales agent warrants to purchase 63,466 shares of common
stock.  The Series A warrants entitle the holder to purchase one share of common
stock at a price of $6.00 per share,  and they expire on December 31,  2012,  or
earlier under certain  conditions.  The Series B warrants  entitle the holder to
purchase  one share of common  stock at a price of $10.00  per  share,  and they
expire on December 31, 2012,  or earlier  under  certain  conditions.  The sales
agent  warrants  entitle the holder to purchase  one share of common  stock at a
price of $1.80 per share, and they expire on December 31, 2012.

     The following table summarizes  activity for common stock warrants for each
of the two years ended August 31, 2011:

                               Number of    Weighted average
                               warrants      exercise price
                               ---------    ----------------

Outstanding, August 31, 2009    5,161,466           $6.72
Granted                        10,125,000           $5.51
Exercised                              --
                              -------------
Outstanding, August 31, 2010   15,286,466           $5.92
Granted                                --
Exercised                         355,399           $1.60
                              -------------
Outstanding, August 31, 2011   14,931,067           $6.02
                              =============

     The following table summarizes  information  about the Company's issued and
outstanding common stock warrants as of August 31, 2011:

                                                                      Exercise
                                                     Remaining       Price times
  Exercise                            Number of     Contractual       Number of
    Price    Description                Shares    Life (in years)      Shares
    -----    -----------                ------    ---------------      ------

   $1.60     Series D                     769,601       3.3          $ 1,231,362
   $1.80     Sales Agent Warrants          63,466       1.3              114,239
   $6.00     Series A                   4,098,000       1.3           24,588,000
   $6.00     Series C                   9,000,000       3.3           54,000,000
   $10.00    Series B                   1,000,000       1.3           10,000,000
                                      ------------                --------------
                                       14,931,067       2.6         $ 89,933,601
                                      ============                ==============

11.     Stock Based Compensation

     During the year ended August 31, 2011, the Company's  shareholders approved
the 2011  Incentive  Stock Option Plan and the 2011  Non-Qualified  Stock Option

                                      F-23

<PAGE>

Plan to replace a previous  plan.  The  shareholders  authorized the issuance of
options to purchase up to 2,000,000 shares of common stock under each plan.

     The Company accounts for stock option  activities as provided by ASC "Stock
Compensation,"  which requires the Company to expense as compensation  the value
of grants and  options as  determined  in  accordance  with the fair value based
method prescribed in the guidance.  The Company estimates the fair value of each
stock option at the grant date by using the Black-Scholes-Merton  option-pricing
model.

     The Company  recorded  stock-based  compensation  expense of  $627,486  and
$581,233  for the  years  ended  August  31,  2011 and 2010,  respectively.  The
components  of the expense  for the year ended  August 31,  2011  include  stock
grants  of  $430,000  to  an  employee  and  a  consultant,   and   option-based
compensation  of  $197,486.  The  components  of the  expense for the year ended
August 31, 2010 include stock grants of $544,575 to directors  and  option-based
compensation of $36,658.

     The  weighted-average  grant  date fair  value per share for stock  options
granted  during the years  ended  August 31, 2011 and 2010 were $2.33 and $1.30,
respectively.  The  following  table  summarizes  the  assumptions  used  in the
Black-Scholes-Merton  option  pricing  model to  calculate  the grant  date fair
values for stock  options  granted  during the years  ended  August 31, 2011 and
2010:

                                       2011            2010
                                  ---------------  -------------
      Volatility                  53.18 - 69.43%      53.18%
      Expected option term
      (years)                       6.0 - 6.5         5.875
      Risk-free interest rate      1.48 - 2.63%       2.08%
      Expected dividend yield           0%              0%

     The expected  volatility is estimated  using the  calculated  volatility of
public companies with characteristics similar to the Company (industry,  company
size,  and life  cycle)  at the  grant  date,  as the  trading  history  for the
Company's  common stock is less than the expected term of stock options granted.
The  expected  term of  options  granted is  estimated  in  accordance  with the
simplified  method  prescribed in SEC Staff Accounting  Bulletin ("SAB") No. 107
and SAB No. 110. The  risk-free  interest  rate is  determined at the time stock
options  are  granted  using  rates  for  U.S  Treasury  notes  with  maturities
corresponding to the expected term of stock options.

     The estimated unrecognized compensation cost from unvested stock options as
of August 31, 2011, was  approximately  $1,068,100,  substantially  all of which
will be recognized during the next four years.


                                      F-24

<PAGE>
The following table  summarizes  activity for stock options for years ended
August 31, 2011 and 2010:

                                     2011                        2010
                            ----------------------   -------------------------
                                          Weighted                   Weighted
                             Number        Average                    Average
                              of          Exercise    Number of       Exercise
                            Options        Price      Options          Price
                            -------       --------    ---------      ----------
Outstanding at beginning   
of year                    4,220,000      $   5.36    4,100,000       $   5.50
  Granted                    425,000      $   3.79      120,000       $   2.50
  Exercised                        -      $      -            -       $      -
  Cancelled                        -      $      -            -       $      -
                           ---------      --------    ---------       --------
Outstanding at end of
year                       4,645,000      $   5.21    4,220,000       $   5.36
                           =========      ========    =========       ========

Exercisable at August 31,  4,089,000      $   5.44    4,010,000       $   5.49
                           =========      ========    =========       ========

      The following table summarizes information about outstanding stock options
as of August 31, 2011:

                                              Outstanding      Vested
                                               Options        Options
                                              ----------      --------
      Number of shares
                                               4,645,000     4,089,000
      Weighted average remaining
      contractual life                         2.8 years     1.9 years
      Weighted average exercise price         $     5.21    $    $5.44
      Aggregate intrinsic value               $4,339,700    $4,262,790

      The following table summarizes changes in the unvested options for the
years ended August 31, 2011 and 2010:

                                                             Weighted
                                                             Average
                                               Number of    Grant Date
                                                Options     Fair Value
                                              ------------  -----------
      Non-vested September 1, 2010              210,000      $    1.53
        Granted                                 425,000      $    2.33
        Vested                                  (79,000)     $    1.38
        Cancelled                                     -      $       -
                                                -------      ---------
      Non-vested, August 31, 2011               556,000      $    2.16
                                                =======      =========

12.     Commitments and Contingencies

      In connection with a 2008 private offering, the Company issued placement
agent warrants which entitle the holder to purchase units consisting of common
stock and warrants (Series A and B) at a price of $3.60 per unit. The Series A
and Series B warrants issuable upon exercise of the placement agent warrants are
not considered outstanding for accounting purposes until such time, if ever,
that the placement agent warrants are exercised. In the event that the placement
agent warrants are exercised, the Company will be obligated to issue 31,733
Series A warrants and 31,733 Series B warrants.

                                      F-25

<PAGE>

13.     Income Taxes

      The components of the provision for income tax expense (benefit) consist
of the following:

                                                  Years Ended August 31,
                                            ----------------------------------
                                                  2011              2010
                                            -----------------   --------------
      Current income taxes                   $        --          $        -- 
      Deferred income taxes                   (4,620,000)          (3,994,000)
      Valuation allowance                      4,620,000            3,994,000 
                                             -----------          -----------
              Total tax benefit              $        --          $        --
                                             ===========          ===========

      A reconciliation of expected federal income taxes on income from
continuing operations at statutory rates with the expense (benefit) for income
taxes is follows:

                                                    Years Ended August 31,
                                               ---------------------------------
                                                   2011              2010
                                               --------------   ----------------
     Federal income taxes                       $(3,944,000)      $(3,670,000)
     State income taxes                            (354,000)         (324,000)
     Other                                         (322,000)               --
     Change in valuation allowance                4,620,000         3,994,000
                                                -----------       -----------
                                                $        --       $        --
                                                ===========       ===========

      The Company reported a change in valuation allowance of $4,620,000 for the
year ended August 31, 2011, which differs from the amount obtained from
calculating the difference between the balance sheet amounts from $7,147,000 at
August 31, 2010 to $4,911,000 at August 31, 2011. The reconciling item is the
tax effect of $6,856,000 representing 37% of amounts reclassified directly from
liabilities to equity as a result of the early conversion of the convertible
promissory notes and the related derivative conversion liability into shares of
the Company's common stock.

                                      F-26

<PAGE>

      The tax effects of temporary differences that give rise to significant
components of the deferred tax assets and deferred tax liabilities at August 31,
2011 and 2010, are presented below:

                                                As of August 31,
                                          -----------------------------
                                              2011            2010
                                          -------------   -------------
  Deferred tax assets:
    Net operating loss carry-forward        $4,176,000      $3,838,000
      
    Stock-based compensation                 3,913,000       3,834,000
    Convertible promissory notes                    --       1,876,000
    Other                                       69,000          10,000
    Less: valuation allowance               (4,911,000)     (7,147,000)
                                          ------------     -----------
              Subtotal                       3,247,000       2,411,000
                                          ------------     -----------
  Deferred tax liabilities:
    Basis of oil and gas properties         (3,247,000)     (2,411,000)
                                          ------------     -----------
              Subtotal
                                           (3,247,000)     (2,411,000)
                                          ------------     -----------
                      Total               $         --     $        --
                                          ============     ===========


     At August 31, 2011, the Company has a net operating loss  carry-forward for
federal  and state tax  purposes  of  approximately  $11,300,000  that  could be
utilized to offset  taxable  income of future  years.  Substantially  all of the
carry-forward will expire between 2029 and 2031.

      The realization of the deferred tax assets related to the net operating
loss carry-forwards is dependent upon the Company's ability to generate future
taxable income. Given the Company's history of book and tax operating losses
since inception, and the expectation of future tax deductions associated with
planned drilling activities, it cannot be assumed that the generation of future
taxable income is more likely than not. The ability of the Company to utilize
net operating loss carry-forwards may be further limited by other provisions of
the Code. Accordingly, the Company has established a full valuation allowance
against the deferred tax assets.

                                      F-27

<PAGE>

14.     Supplemental Schedule of Information to the Statements of Cash Flows

      The following table supplements the cash flow information presented in the
financial statements for the years ended August 31, 2011 and 2010:

                                                      Years Ended August 31,
                                                    ---------------------------
                                                       2011           2010
                                                   -----------     ----------
Supplemental cash flow information:
    Interest paid                                    $ 788,211      $617,017
    Income taxes paid                                       --            --

Non-cash investing and financing activities:
    Conversion of promissory  notes into common   
        stock                                     $ 15,908,000   $ 2,092,000
    Mineral leases acquired for common stock         5,240,307        16,645
    Assets  acquired for note payable,  related 
        party                                        5,200,000            --
    Accrued capital expenditures                     4,967,369     3,446,439
    Assets  acquired for common stock,  related  
        party                                        4,698,181            --
    Asset retirement costs and obligations             351,083       253,114
    Placement  agent  commission in the form of  
        warrants                                            --       692,478

15.     Supplemental Oil and Gas Information (unaudited)

      Costs Incurred: Costs incurred in oil and gas property acquisition,
exploration and development activities for the years ended August 31, 2011 and
2010, were:

                                 Years Ended August 31,
                               -----------------------------
                                   2011           2010
                               -------------- --------------
Acquisition of Property:
    Unproved                    $ 9,198,417    $ 1,625,696
    Proved                       21,251,032             --
Exploration costs                        --             --
Development costs                15,347,982     10,360,516
                                -----------    -----------
  Total Costs Incurred          $45,797,431    $11,986,212
                                ===========    ===========

      Capitalized Costs Excluded from Amortization: The following table
summarizes costs related to unevaluated properties that have been excluded from
amounts subject to depletion, depreciation, and amortization at August 31, 2011.
There were no individually significant properties or significant development
projects included in the Company's unevaluated property balance. The Company
regularly evaluates these costs to determine whether impairment has occurred.
The majority of these costs are expected to be evaluated and included in the
amortization base within three years.


                                      F-28

<PAGE>

                                     Period Incurred   
                              ------------------------------        Total at
                               2011        2010       2009      August 31, 2011
                              -----       ------     ------     ---------------
Unproved leasehold  
  acquisition costs         $9,003,134    $705,391   $234,383     $9,942,908
Unevaluated development
  costs                              -           -          -              -
                            ----------    --------   --------     ----------
     Total                  $9,003,134    $705,391   $234,383     $9,942,908
                            ==========    ========   ========     ==========

      Oil and Natural Gas Reserve Information: Proved reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions (prices and costs held constant as of the date the estimate is made).
Proved developed reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Proved
undeveloped reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.

      Proved oil and natural gas reserve information at August 31, 2011 and
2010, and the related discounted future net cash flows before income taxes are
based on estimates prepared by Ryder Scott Company LP. Reserve information for
the properties was prepared in accordance with guidelines established by the
SEC.

      The reserve estimates prepared as of August 31, 2011 and 2010 were
prepared in accordance with "Modernization of Oil and Gas Reporting" published
by the SEC. The recent guidance included updated definitions of proved developed
and proved undeveloped oil and gas reserves, oil and gas producing activities
and other terms. Proved oil and gas reserves as of August 31, 2011 and 2010 were
calculated based on the prices for oil and gas during the 12 month period before
the reporting date, determined as the unweighted arithmetic average of the first
day of the month price for each month within such period, rather than the
year-end spot prices, which had been used in prior years. This average price is
also used in calculating the aggregate amount and changes in future cash inflows
related to the standardized measure of discounted future cash flows. Undrilled
locations can be classified as having proved undeveloped reserves only if a
development plan has been adopted indicating that they are scheduled to be
drilled within five years. The recent guidance broadened the types of
technologies that may be used to establish reserve estimates.

      The following table sets forth information regarding the Company's net
ownership interests in estimated quantities of proved developed and undeveloped
oil and gas reserve quantities and changes therein for the years ended August
31, 2011 and 2010:

                                                 Oil (Bbl)       Gas (Mcf)
                                              --------------   --------------

Balance, August 31, 2009                            6,430           25,680
  Revision of previous estimates                    4,318           24,844
  Purchase of reserves in place                        --               --
  Extensions,   discoveries,  and  other
     additions                                    687,017        4,571,680
  Sale of reserves in place                            --               --
  Production                                      (21,080)        (141,154)
                                                ---------       -----------

                                      F-29

<PAGE>

Balance, August 31, 2010                          676,685        4,481,051
  Revision of previous estimates                  323,704          611,517
  Purchase of reserves in place                   967,302        8,466,714
  Extensions, discoveries, and other
     additions                                    191,931        1,152,708
  Sale of reserves in place                            --               --
  Production                                      (89,917)        (450,831)
                                                ---------       ----------
Balance, August 31, 2011                        2,069,705       14,261,158
                                                =========       ==========


Proved developed and undeveloped reserves:

  Developed at August 31, 2010                    395,453        2,349,027
  Undeveloped at August 31, 2010                  281,232        2,132,024
                                                ---------       ----------
                                                  676,685        4,481,051
                                                =========       ==========
  Developed at August 31, 2011                    783,821        5,578,067
  Undeveloped at August 31, 2011                1,285,884        8,683,091
                                                ---------       ----------
                                                2,069,705       14,261,158
                                                =========       ==========

     Standardized  Measure of  Discounted  Future Net Cash Flows:  The following
analysis is a standardized  measure of future net cash flows and changes therein
related  to  estimated  proved  reserves.  Future  oil and gas  sales  have been
computed by applying average prices of oil and gas during the years ended August
31, 2011 and 2010.  Future  production  and  development  costs were computed by
estimating  the  expenditures  to be incurred in  developing  and  producing the
proved oil and gas reserves at the end of the year, based on year-end costs. The
calculation assumes the continuation of existing economic conditions,  including
the use of constant prices and costs. Future income tax expenses were calculated
by applying year-end statutory tax rates, with consideration of future tax rates
already  legislated,  to future pretax cash flows relating to proved oil and gas
reserves,  less the tax basis of  properties  involved  and tax credits and loss
carry-forwards  relating  to oil and gas  producing  activities.  All cash  flow
amounts are  discounted  at 10% annually to derive the  standardized  measure of
discounted future cash flows.  Actual future cash inflows may vary considerably,
and the  standardized  measure does not necessarily  represent the fair value of
the Company's  oil and gas  reserves.  Actual future net cash flows from oil and
gas  properties  will also be  affected  by  factors  such as actual  prices the
Company  receives for oil and gas,  the amount and timing of actual  production,
supply of and demand for oil and gas, and changes in governmental regulations or
taxation.

                                      F-30

<PAGE>

      The following table sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in the ASC:

                                                     Year Ended August 31,
                                                -------------------------------
                                                     2011            2010
                                                --------------    -----------
Future cash inflows                             $235,238,880     $ 64,670,902
Future production costs                          (41,277,367)     (16,380,316)
Future development costs                         (40,404,280)     (15,836,965)
Future income tax expense                        (30,737,928)      (6,926,890)
                                                ------------     ------------
Future net cash flows                            122,819,305       25,526,731
10% annual discount for estimated timing of
  cash flows                                     (65,268,891)     (12,504,334)
                                                ------------     ------------
Standardized measure of discounted future       
   net cash flows                               $ 57,550,414     $ 13,022,397
                                                ============     ============

     There have been  significant  fluctuations  in the posted prices of oil and
natural gas during the last two years.  Prices actually received from purchasers
of the  Company's  oil and gas are  adjusted  from  posted  prices for  location
differentials,   quality  differentials,  and  BTU  content.  Estimates  of  the
Company's  reserves are based on realized  prices.  The following table presents
the prices  used to prepare the  estimates,  based upon  average  prices for the
years ended August 31, 2011 and 2010:

                                              Natural Gas        Oil
                                                 (Mcf)          (Bbl)
                                              -----------       -----
               August 31, 2010 (Average)         $4.76         $69.20
               August 31, 2011 (Average)         $5.07         $84.90


                                      F-31

<PAGE>

      Changes in the Standardized Measure of Discounted Future Net Cash Flows:
The principle sources of change in the standardized measure of discounted future
net cash flows are:

                                                       Year Ended August 31,
                                                  -----------------------------
                                                       2011             2010
                                                  --------------   ------------
   Standardized measure, beginning of year        $  13,022,397   $    232,957
   Sale and transfers, net of production costs       (8,337,354)    (1,834,924)
   Net changes in prices and production costs        15,483,714       131,153
   Extensions, discoveries, and improved
     recovery                                        13,692,899     17,785,154
   Changes in estimated future development
     costs                                          (20,471,127)            --
   Development costs incurred during the period      16,251,935             --
   Revision of quantity estimates                    15,424,097        212,851
   Accretion of discount                              3,245,362         30,535
   Net change in income taxes                       (12,011,643)    (3,535,329)
   Purchase of reserves in place                     21,250,134             --
   Sale of reserves in place                                 --             --
                                                   ------------    -----------
   Standardized measure, end of year               $ 57,550,414    $13,022,397
                                                   ============    ===========

16.     Subsequent Events

      On September 30, 2011, the Company filed a registration statement under
Form S-3 that provides for the potential sale of securities for proceeds up to
$75,000,000. The registration statement was declared effective on October 7,
2011. At such time as the Company determines that it is appropriate to offer
securities under the terms of the registration statement, a supplement will be
filed containing additional details about the offering, including the nature of
the securities, the number of securities, and the offering price.


                                      F-32

<PAGE>


 
                                  SIGNATURES

     In accordance  with Section 13 or 15(a) of the Exchange Act, the Registrant
has caused this Report to be signed on its behalf by the undersigned,  thereunto
duly authorized on the 11th day of November, 2011.


                                     SYNERGY RESOURCES CORPORATION

                                     By:/s/ Ed Holloway
                                        ------------------------------------
                                         Ed Holloway, President


     Pursuant to the  requirements of the Securities  Exchange Act of l934, this
Report  has  been  signed  below  by the  following  persons  on  behalf  of the
Registrant and in the capacities and on the dates indicated.

Signature                        Title                            Date
---------                        -----                            ----

/s/ Ed Holloway             President, Principal Executive   November 11, 2011
----------------------      Officer and Director
Ed Holloway                      

/s/ Frank L. Jennings       Principal Financial and          November   11, 2011
----------------------      Accounting Officer
Frank L. Jennings                

/s/ William E. Scaff, Jr.    Director                        November 11, 2011
------------------------
William E. Scaff, Jr.


/s/ Rick Wilber                Director                      November 11, 2011
----------------------
Rick Wilber

/s/ Raymond E. McElhaney       Director                      November 11, 2011
------------------------
Raymond E. McElhaney

/s/ Bill M. Conrad             Director                      November 11, 2011
----------------------
Bill M. Conrad

/s/ R.W. Noffsinger, III       Director                      November 11, 2011
------------------------
R. W. Noffsinger, III

/s/ George Seward              Director                      November 11, 2011
----------------------
George Seward



<PAGE>



                          SYNERGY RESOURCES CORPORATION

                                    FORM 10-K

                                    EXHIBITS


<PAGE>







                                   EXHIBIT 23



<PAGE>

            CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the registration statements (No.
333-177123)  on Form S-3 of Synergy  Resources  Corporation  of our report dated
November 11, 2011,  with respect to the financial  statements as of and for each
of the years ended August 31, 2011 and 2010,  which report appears in the August
31, 2011 annual report on Form 10-K of Synergy  Resources  Corporation.  

/s/ Ehrhardt Keefe Steiner & Hottman PC

November 11, 2011
Denver, Colorado


<PAGE>





                                   EXHIBIT 31


<PAGE>


                                 CERTIFICATIONS

I, Ed Holloway, certify that:

1. I have reviewed this annual report on Form 10-K of Synergy Resources
Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15 and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:

      a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information
 relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;

      b) designed such internal control over financial reporting, or cause such
internal control over financial reporting to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;

      c) evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and

      d) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting;
and

5. The registrant's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of the internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):

      a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and

      b) any fraud, whether or not material, that involves management or other
employees who have significant role in the registrant's internal control over
financial reporting.


November 11, 2011                    /s/ Ed Holloway                     
                                     ------------------------------------
                                     Ed Holloway,
                                     Principal Executive Officer



<PAGE>


                                 CERTIFICATIONS

I, Frank L. Jennings, certify that:

1. I have reviewed this annual report on Form 10-K of Synergy Resources
Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15 and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:

      a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;

      b) designed such internal control over financial reporting, or cause such
internal control over financial reporting to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;

      c) evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and

      d) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting;
and

5. The registrant's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of the internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):

      a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and

      b) any fraud, whether or not material, that involves management or other
employees who have significant role in the registrant's internal control over
financial reporting.


November 11, 2011                    /s/ Frank L. Jennings               
                                     ------------------------------------
                                     Frank L. Jennings,
                                     Principal Financial Officer



<PAGE>



                                   EXHIBIT 32



<PAGE>


     In connection with the Annual Report of Synergy Resources  Corporation (the
"Company")  on Form 10-K for the period ending August 31, 2011 as filed with the
Securities and Exchange  Commission (the "Report"),  Ed Holloway,  the Company's
Principal  Executive and Frank L. Jennings,  the Company's  Principal  Financial
Officer,  certify,  pursuant to 18 U.S.C.  Section 1350, as adopted  pursuant to
Section  906 of the  Sarbanes-Oxley  Act of  2002,  that to the  best  of  their
knowledge:

     (1)  The Report fully  complies with the  requirements  of Section 13(a) or
          15(d) of the Securities Exchange Act of 1934; and

     (2)  The  information  contained  in the  Report  fairly  presents,  in all
          material respects, the financial condition and results of the Company.


November 11, 2011                   By: /s/ Ed Holloway                      
                                        -------------------------------------
                                        Ed Holloway, Principal Executive Officer



November 11, 2011                   By: /s/ Frank L. Jennings            
                                        ---------------------------------
                                        Frank L. Jennings, Principal Financial 
                                        Officer







<PAGE>





                                   EXHIBIT 99



<PAGE>



RYDER SCOTT COMPANY
PETROLEUM CONSULTANTS
621 Seventeenth Street, Suite 1550, Denver, COLORADO 80293
Telephone (303) 623-9147

                                October 13, 2011



Synergy Resources Corporation
20203 Highway 60
Platteville, Colorado 80651

Gentlemen:

     At your request,  Ryder Scott Company,  L.P.  (Ryder Scott) has prepared an
estimate of the proved reserves,  future production,  and income attributable to
certain  leasehold  and  royalty  interests  of  Synergy  Resources  Corporation
(Synergy) as of August 31, 2011. The subject properties are located in the state
of placeStateColorado.  The reserves and income data were estimated based on the
definitions  and  disclosure  guidelines  of the United  States  Securities  and
Exchange  Commission  (SEC) contained in Title 17, Code of Federal  Regulations,
Modernization of Oil and Gas Reporting,  Final Rule released January 14, 2009 in
the Federal  Register  (SEC  regulations).  Our third party study,  completed on
October 13, 2011 and  presented  herein,  was prepared for public  disclosure by
Synergy  in  filings  made  with  the  SEC in  accordance  with  the  disclosure
requirements set forth in the SEC regulations. The properties evaluated by Ryder
Scott represent 100 percent of the total net proved
 liquid hydrocarbon  reserves
and 100 percent of the total net proved gas reserves of Synergy.

     The  estimated  reserves  and future net income  amounts  presented in this
report,  as  of  August  31,  2011,  are  related  to  hydrocarbon  prices.  The
hydrocarbon  prices  used in the  preparation  of this  report  are based on the
average prices during the 12-month period prior to the ending date of the period
covered in this report,  determined  as  unweighted  arithmetic  averages of the
prices  in effect  on the  first-day-of-the-month  for each  month  within  such
period, unless prices were defined by contractual  arrangements,  as required by
the SEC regulations. Actual future prices may vary significantly from the prices
required by SEC regulations;  therefore,  volumes of reserves actually recovered
and the amounts of income actually  received may differ  significantly  from the
estimated  quantities  presented in this  report.  The results of this study are
summarized below.


                                        1

<PAGE>

                                 SEC PARAMETERS
                     Estimated Net Reserves and Income Data
                   Certain Leasehold and Royalty Interests of
                          Synergy Resources Corporation
                               As of August 31, 2011
                 -----------------------------------------------

                                                  Proved
                          -----------------------------------------------------
                                  Developed 
                          -------------------------                     Total
                           Producing   Non-Producing   Undeveloped     Proved
                          ----------   -------------   ------------   ---------
Net Remaining Reserves
  Oil/Condensate - Barrels  613,180        170,641      1,285,884     2,069,705
  Gas - MCF               4,497,734      1,080,333      8,683,091    14,261,158

Income Data, $
  Future Gross Revenue  $71,027,480    $18,819,100   $145,392,300  $235,238,880
  Deductions             14,298,252      5,647,381     61,736,015    81,681,648
                        -----------    -----------   ------------  ------------
  Future Net Income 
    (FNI)               $56,729,228    $13,171,719    $83,656,285  $153,557,232

  Discounted FNI @ 10%  $33,946,592    $ 6,995,878    $30,815,373  $ 71,757,843

      Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are reported on an "as sold" basis expressed in thousands of cubic feet
(MCF) at the official temperature and pressure base of Colorado, which are
60(degree)F and 14.73 psia, respectively.

      The estimates of reserves, future production and income attributable to
properties in this report were prepared using the economic software package
PHDWin Petroleum Economic evaluation Software, a copyrighted program of TRC
Consultants, L.C. Ryder Scott has found this program to be generally acceptable,
but notes that certain summaries and calculations may vary due to rounding and
may not exactly match the sum of the properties being summarized. Furthermore,
one line economic summaries may vary slightly from the more detailed cash flow
projections of the same properties, also due to rounding. The rounding
differences are not material.

      The future gross revenue is after the deduction of production taxes. The
deductions incorporate the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs and development costs. The future net income
is before the deduction of state and federal income taxes and general
administrative overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or undistributed
income. Liquid hydrocarbon reserves account for approximately 71 percent and gas
reserves account for the remaining 29 percent of total future gross revenue from
proved reserves.

                                        2

<PAGE>

      The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded annually. Future net income was
discounted at four other discount rates which were also compounded annually.
These results are shown in summary form as follows.


                                      Discounted Future Net Income
                                         As of August 31, 2011
                                     -------------------------------
                Discount Rate                     Total
                   Percent                      Proved $
               ----------------               --------------

                       5                       $100,095,569
                       8                       $ 81,237,159
                      12                       $ 64,028,274
                      15                       $ 54,841,974


      The results shown above are presented for your information and should not
be construed as our estimate of fair market value.

Reserves Included in This Report

      The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulations Part 210.4-10 (a). An
abridged version of the SEC reserves definitions from 210.4-10(a) entitled
"Petroleum Reserves Definitions" is included as an attachment to this report.
The various reserve status categories are defined under the attachment entitled
"Petroleum Reserves Definitions" in this report. The Proved Developed
Non-Producing Reserves included herein consist of the Shut-In and Behind Pipe
categories.

      No attempt was made to quantify or otherwise account for any accumulated
gas production imbalances that may exist. The gas volumes included herein do not
attribute gas consumed in operations as reserves.

      Reserves are "estimated remaining quantities of oil and gas and related
substances anticipated to be economically producible, as of a given date, by
application of development projects to known accumulations." All reserve
estimates involve an assessment of the uncertainty relating the likelihood that
the actual remaining quantities recovered will be greater or less than the
estimated quantities determined as of the date the estimate is made. The
uncertainty depends chiefly on the amount of reliable geologic and engineering
data available at the time of the estimate and the interpretation of these data.
The relative degree of uncertainty may be conveyed by placing reserves into one
of two principal classifications, either proved or unproved. Unproved reserves
are less certain to be recovered than proved reserves, and may be further
sub-classified as probable and possible reserves to denote progressively
increasing uncertainty in their recoverability. At Synergy's request, this
report addresses only the proved reserves attributable to the properties
evaluated herein.

      Proved oil and gas reserves are those quantities of oil and gas which, by
analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible from a given date forward. The proved
reserves included herein were estimated using deterministic methods. If
deterministic methods are used, the SEC has defined reasonable certainty for
proved reserves as a "high degree of confidence that the quantities will be
recovered."

                                        3

<PAGE>

     Proved  reserve  estimates  will  generally be revised  only as  additional
geologic or engineering data become available or as economic  conditions change.
For  proved  reserves,  the  SEC  states  that  "as  changes  due  to  increased
availability  of  geoscience   (geological,   geophysical,   and   geochemical),
engineering, and economic data are made to the estimated ultimate recovery (EUR)
with time,  reasonably  certain  EUR is much more  likely to  increase or remain
constant  than to  decrease."  Moreover,  estimates  of proved  reserves  may be
revised as a result of future operations,  effects of regulation by governmental
agencies or  geopolitical  or economic  risks.  Therefore,  the proved  reserves
included in this report are estimates  only and should not be construed as being
exact quantities, and if recovered, the revenues therefrom, and the actual costs
related thereto, could be more or less than the estimated amounts.

      Synergy's operations may be subject to various levels of governmental
controls and regulations. These controls and regulations may include, but may
not be limited to, matters relating to land tenure and leasing, the legal rights
to produce hydrocarbons, drilling and production practices, environmental
protection, marketing and pricing policies, royalties, various taxes and levies
including income tax and are subject to change from time to time. Such changes
in governmental regulations and policies may cause volumes of proved reserves
actually recovered and amounts of proved income actually received to differ
significantly from the estimated quantities.

      The estimates of proved reserves presented herein were based upon a
detailed study of the properties in which Synergy owns an interest; however, we
have not made any field examination of the properties. No consideration was
given in this report to potential environmental liabilities that may exist nor
were any costs included for potential liabilities to restore and clean up
damages, if any, caused by past operating practices.

Estimates of Reserves

      The estimation of reserves involves two distinct determinations. The first
determination results in the estimation of the quantities of recoverable oil and
gas and the second determination results in the estimation of the uncertainty
associated with those estimated quantities in accordance with the definitions
set forth by the Securities and Exchange Commission's Regulations Part
210.4-10(a). The process of estimating the quantities of recoverable oil and gas
reserves relies on the use of certain generally accepted analytical procedures.
These analytical procedures fall into three broad categories or methods: (1)
performance-based methods; (2) volumetric-based methods; and (3) analogy. These
methods may be used singularly or in combination by the reserve evaluator in the
process of estimating the quantities of reserves. Reserve evaluators must select
the method or combination of methods which in their professional judgment is
most appropriate given the nature and amount of reliable geoscience and
engineering data available at the time of the estimate, the established or
anticipated performance characteristics of the reservoir being evaluated and the
stage of development or producing maturity of the property.

     In many cases,  the analysis of the available  geoscience  and  engineering
data and the  subsequent  interpretation  of this data may  indicate  a range of
possible  outcomes in an estimate,  irrespective  of the method  selected by the
evaluator. When a range in the quantity of reserves is identified, the evaluator
must determine the uncertainty associated with the incremental quantities of the
reserves.  If the  reserve  quantities  are  estimated  using the  deterministic
incremental approach,  the uncertainty for each discrete incremental quantity of
the  reserves is addressed by the reserve  category  assigned by the  evaluator.


                                        4

<PAGE>

Therefore,  it is the categorization of reserve  quantities as proved,  probable
and/or  possible  that  addresses  the  inherent  uncertainty  in the  estimated
quantities reported.  For proved reserves,  uncertainty is defined by the SEC as
reasonable  certainty wherein the "quantities  actually  recovered are much more
likely than not to be  achieved."  The SEC states that  "probable  reserves  are
those  additional  reserves  that are less certain to be  recovered  than proved
reserves but which,  together with proved  reserves,  are as likely as not to be
recovered." The SEC states that "possible reserves are those additional reserves
that are less  certain to be  recovered  than  probable  reserves  and the total
quantities  ultimately  recovered  from  a  project  have a low  probability  of
exceeding  proved plus  probable  plus  possible  reserves."  All  quantities of
reserves within the same reserve category must meet the SEC definitions as noted
above.

      Estimates of reserves quantities and their associated reserve categories
may be revised in the future as additional geoscience or engineering data become
available. Furthermore, estimates of reserves quantities and their associated
reserve categories may also be revised due to other factors such as changes in
economic conditions, results of future operations, effects of regulation by
governmental agencies or geopolitical or economic risks as previously noted
herein.

      The proved reserves for the properties included herein were estimated by
performance methods or by analogy. Proved producing and proved shut in reserves
attributable to wells and/or reservoirs were estimated by the performance or
analogy method. These performance methods include decline curve analysis which
utilized extrapolations of historical production and pressure data available
through August, 2011 in about ninety-eight percent of those cases where such
data were considered to be definitive. In the remaining two percent of cases,
this data, while available, was not sufficient for extrapolation. In these
cases, the analogy method was used. The data utilized in this analysis were
supplied to Ryder Scott by Synergy or obtained from public data sources and were
considered sufficient for the purpose thereof.

      One hundred percent of the proved behind pipe and undeveloped reserves
included herein were estimated by the analogy method. The analogy method
utilized pertinent well data supplied to Ryder Scott by Synergy or which we have
obtained from public data sources that were available through August, 2011.

     To  estimate  economically  recoverable  proved  oil and gas  reserves  and
related  future  net cash  flows,  we  consider  many  factors  and  assumptions
including,  but not limited to, the use of  reservoir  parameters  derived  from
geological,  geophysical and engineering data that cannot be measured  directly,
economic  criteria  based on current  costs and SEC  pricing  requirements,  and
forecasts   of   future   production   rates.    Under   the   SEC   regulations
210.4-10(a)(22)(v)   and  (26),  proved  reserves  must  be  anticipated  to  be
economically  producible  from a given date forward  based on existing  economic
conditions including the prices and costs at which economic producibility from a
reservoir is to be determined.  While it may reasonably be anticipated  that the
future prices  received for the sale of production  and the operating  costs and
other costs  relating to such  production  may  increase or decrease  from those
under existing economic conditions,  such changes were, in accordance with rules
adopted by the SEC, omitted from consideration in making this evaluation.

     Synergy has  informed us that they have  furnished  us all of the  material
accounts,  records,  geological and engineering data, and reports and other data
required  for this  investigation.  In preparing  our forecast of future  proved
production  and  income,  we have  relied upon data  furnished  by Synergy  with
respect to property  interests  owned,  production  and well tests from examined


                                       5

<PAGE>

wells, normal direct costs of operating the wells or leases, other costs such as
transportation   and/or  processing  fees,  ad  valorem  and  production  taxes,
recompletion and development costs,  product prices based on the SEC regulations
and adjustments or  differentials  to product prices.  Ryder Scott reviewed such
factual  data  for  its  reasonableness;  however,  we  have  not  conducted  an
independent  verification  of the data  furnished  by Synergy.  We consider  the
factual data used in this report  appropriate  and sufficient for the purpose of
preparing the estimates of reserves and future net revenues herein.

      In summary, we consider the assumptions, data, methods and analytical
procedures used in this report appropriate for the purpose hereof, and we have
used all such methods and procedures that we consider necessary and appropriate
to prepare the estimates of reserves herein. The proved reserves included herein
were determined in conformance with the United States Securities and Exchange
Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including
all references to Regulation S-X and Regulation S-K, referred to herein
collectively as the "SEC Regulations." In our opinion, the proved reserves
presented in this report comply with the definitions, guidelines and disclosure
requirements as required by the SEC regulations.

Future Production Rates

      For wells currently on production, our forecasts of future production
rates are based on historical performance data. If no production decline trend
has been established, future production rates were held constant, or adjusted
for the effects of curtailment where appropriate, until a decline in ability to
produce was anticipated. An estimated rate of decline was then applied to
depletion of the reserves. If a decline trend has been established, this trend
was used as the basis for estimating future production rates.

      Offset analogies and other related information were used to estimate the
anticipated initial production rates for those wells or locations that are not
currently producing. For reserves not yet on production, sales were estimated to
commence at an anticipated date furnished by Synergy. Wells or locations that
are not currently producing may start producing earlier or later than
anticipated in our estimates due to unforeseen factors causing a change in the
timing to initiate production. Such factors may include delays due to weather,
the availability of rigs, the sequence of drilling, completing and/or
recompleting wells and/or constraints set by regulatory bodies.

      The future production rates from wells currently on production or wells or
locations that are not currently producing may be more or less than estimated
because of changes including, but not limited to, reservoir performance,
operating conditions related to surface facilities, compression and artificial
lift, pipeline capacity and/or operating conditions, producing market demand
and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

      The hydrocarbon prices used herein are based on SEC price parameters using
the average prices during the 12-month period prior to the ending date of the
period covered in this report, determined as the unweighted arithmetic averages
of the prices in effect on the first-day-of-the-month for each month within such
period, unless prices were defined by contractual arrangements. For hydrocarbon
products sold under contract, the contract prices, including fixed and
determinable escalations, exclusive of inflation adjustments, were used until
expiration of the contract. Upon contract expiration, the prices were adjusted
to the 12-month unweighted arithmetic average as previously described.


                                       6

<PAGE>

     Ryder  Scott  determined  the 1st day of the  month  unweighted  arithmetic
average  prices in effect on August 31,  2011.  These  initial  SEC  hydrocarbon
prices  were  determined  using  the  12-month  average   first-day-of-the-month
benchmark  prices  appropriate to the geographic area where the hydrocarbons are
sold. These benchmark  prices are prior to the adjustments for  differentials as
described  herein.  The table below  summarizes  the "price  reference"  and the
"average benchmark prices" used for the geographic area included in the report.

      The product prices that were actually used to determine the future gross
revenue for each property reflect adjustments to the benchmark prices for
gravity, quality, local conditions, and/or distance from market, referred to
herein as "differentials." The differentials used in the preparation of this
report were estimated by Ryder Scott based on information furnished by Synergy.

      In addition, the table below summarizes the net volume weighted benchmark
prices adjusted for differentials and referred to herein as the "average
realized prices." The average realized prices shown in the table below were
determined from the total future gross revenue before production taxes and the
total net reserves for the geographic area and presented in accordance with SEC
disclosure requirements for each of the geographic areas included in the report.

 ------------------------------------------------------------------------------
                                                       Average         Average
                                       Price          Benchmark        Realized
 Geographic Area      Product        Reference          Prices          Prices
 ------------------------------------------------------------------------------
 North America
 ------------------------------------------------------------------------------
 Colorado         Oil/Condensate     WTI Cushing       $93.25/BBL    $84.90/BBL
 ------------------------------------------------------------------------------
                        Gas          Henry Hub         $4.15/MMBTU   $ 5.07/MCF
-------------------------------------------------------------------------------

      The effects of derivative instruments designated as price hedges of oil
and gas quantities are not reflected in our individual property evaluations.

Costs

      Operating costs for the leases and wells in this report are based on the
operating expense reports of Synergy and include only those costs directly
applicable to the leases or wells. The operating costs include a portion of
general and administrative costs allocated directly to the leases and wells. The
operating costs for non-operated properties include the COPAS overhead costs
that are allocated directly to the leases and wells under terms of operating
agreements. The operating costs furnished by Synergy were reviewed by us for
their reasonableness using information supplied by Synergy for this purpose. No
deduction was made for loan repayments, interest expenses, or exploration and
development prepayments that were not charged directly to the leases or wells.

      Development costs were furnished to us by Synergy and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. The development costs furnished by Synergy were reviewed by us for
their reasonableness using information supplied by Synergy for this purpose.
Synergy's estimates of zero abandonment costs after salvage value for all
properties were used in this report. Ryder Scott has not performed a detailed
study of the abandonment costs or the salvage value and makes no warranty for
Synergy's estimate.

     The proved  non-producing and undeveloped reserves in this report have been
incorporated herein in accordance with Synergy's plans to develop these reserves
as of August 31, 2011.  The  implementation  of Synergy's  development  plans as
presented  to us and  incorporated  herein is  subject to the  approval  process
adopted by Synergy's management. As the result of our inquires during the course


                                       7

<PAGE>

of  preparing  this  report,  Synergy  has  informed  us  that  the  development
activities  included  herein have been  subjected  to and  received the internal
approvals required by Synergy's  management at the appropriate  local,  regional
and/or corporate level. In addition to the internal approvals as noted,  certain
development  activities may still be subject to specific  partner AFE processes,
Joint Operating Agreement (JOA) requirements or other  administrative  approvals
external to  Synergy.  Additionally,  Synergy has  informed us that they are not
aware of any legal,  regulatory,  political  or  economic  obstacles  that would
significantly alter their plans.

      Current costs used by Synergy were held constant throughout the life of
the properties.

Standards of placeCityIndependence and Professional Qualification

      Ryder Scott is an independent petroleum engineering consulting firm that
has been providing petroleum consulting services throughout the world for over
seventy years. Ryder Scott is employee- owned and maintains offices in Houston,
Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty
engineers and geoscientists on our permanent staff. By virtue of the size of our
firm and the large number of clients for which we provide services, no single
client or job represents a material portion of our annual revenue. We do not
serve as officers or directors of any privately owned or publicly traded oil and
gas company and are separate and independent from the operating and investment
decision-making process of our clients. This allows us to bring the highest
level of independence and objectivity to each engagement for our services.

      Ryder Scott actively participates in industry related professional
societies and organizes an annual public forum focused on the subject of
reserves evaluations and SEC regulations. Many of our staff have authored or
co-authored technical papers on the subject of reserves related topics. We
encourage our staff to maintain and enhance their professional skills by
actively participating in ongoing continuing education.

      Prior to becoming an officer of the Company, Ryder Scott requires that
staff engineers and geoscientists have received professional accreditation in
the form of a registered or certified professional engineer's license or a
registered or certified professional geoscientist's license, or the equivalent
thereof, from an appropriate governmental authority or a recognized
self-regulating professional organization.

      We are independent petroleum engineers with respect to Synergy. Neither we
nor any of our employees have any interest in the subject properties and neither
the employment to do this work nor the compensation is contingent on our
estimates of reserves for the properties which were reviewed.

      The results of this study, presented herein, are based on technical
analysis conducted by teams of geoscientists and engineers from Ryder Scott. The
professional qualifications of the undersigned, the technical person primarily
responsible for preparing the reserves information discussed in this report, are
included as an attachment to this letter.


                                       8

<PAGE>

Terms of Usage

      The results of our third party study, presented in report form herein,
were prepared in accordance with the disclosure requirements set forth in the
SEC regulations and intended for public disclosure as an exhibit in filings made
with the SEC by Synergy.

      Synergy makes periodic filings on Form 10-K with the SEC under the 1934
Exchange Act. Furthermore, Synergy has certain registration statements filed
with the SEC under the 1933 Securities Act into which any subsequently filed
Form 10-K is incorporated by reference. We have consented to the incorporation
by reference in the registration statements on Form S-3 of Synergy of the
references to our name as well as to the references to our third party report
for Synergy, which appears in the August 31, 2011 annual report on Form 10-K of
Synergy. Our written consent for such use is included as a separate exhibit to
the filings made with the SEC by Synergy.

      We have provided Synergy with a digital version of the original signed
copy of this report letter. In the event there are any differences between the
digital version included in filings made by Synergy and the original signed
report letter, the original signed report letter shall control and supersede the
digital version.

      The data and work papers used in the preparation of this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.

                                          Very truly yours,

                                          RYDER SCOTT COMPANY, L.P.
                                          TBPE Firm Registration No. F-1580


                                           /s/ Thomas E. Venglar
                                           Thomas E. Venglar, P.E.
                                           Colorado License No. 28846
                                           Senior Petroleum Engineer

            [SEAL]

Approved:



/s/ James L. Baird
James L. Baird, P.E.
Managing Senior Vice President


                                       9

<PAGE>





             Professional Qualifications of Primary Technical Person

The  conclusions  presented in this report are the result of technical  analysis
conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.
Thomas E. Venglar was the primary  technical  person  responsible for overseeing
the estimate of the future net reserves and income.

Mr. Venglar,  an employee of Ryder Scott Company L.P. (Ryder Scott) beginning in
2006,  is  a  Senior  Petroleum   Engineer   responsible  for  coordinating  and
supervising  staff and consulting  engineers of the company in ongoing reservoir
evaluation  studies.  Before joining Ryder Scott,  Venglar served in a number of
engineering  positions with Grynberg  Petroleum  Company and Anadarko  Petroleum
Corporation.  For more information  regarding Mr.  Venglar's  geographic and job
specific  experience,  please  refer  to the  Ryder  Scott  Company  website  at
www.ryderscott.com/Experience/Employees.

Venglar  earned a  Bachelor  of Science  degree in  Petroleum  Engineering  from
PlaceNameTexas  PlaceNameA&M  PlaceTypeUniversity  in 1979  and is a  registered
Professional Engineer in the state of placeStateColorado. He is also a member of
the Society of Petroleum Engineers.

Based on his  educational  background,  professional  training  and more than 30
years of practical  experience  in the  estimation  and  evaluation of petroleum
reserves,  Venglar has attained the  professional  qualifications  as a Reserves
Estimator  and  Reserves  Auditor as set forth in Article III of the  "Standards
Pertaining to the Estimating  and Auditing of Oil and Gas Reserves  Information"
promulgated by the Society of Petroleum Engineers as of February 19, 2007.