UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549





FORM
10-K





x           ANNUAL
REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934





For the
fiscal year ended March 31,
2009


or





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





Commission
file number 000-30234





ENERJEX
RESOURCES, INC.


(Exact
name of registrant as specified in its charter)





Nevada
                  
                  88-0422242(State
      or other jurisdiction of incorporation or organization)
                  (I.R.S.
      Employer Identification
No.)





27
      Corporate Woods, Suite 35010975
      Grandview DriveOverland
      Park, Kansas
                  66210(Address
      of principal executive offices)
                  (Zip
      Code)





7300
      W. 110th,
      7th
      FloorOverland
      Park, Kansas
                  66210(Former
      Address of principal executive offices)
                  (Zip
      Code)





Registrant’s
telephone number, including area code (913)
754-7754





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




Securities
registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $0.001 par
value





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.


 ̈
Yes                      x
No





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


 ̈
Yes                      x
No





Indicate
by checkmark whether the registrant (1) has filed all reports required 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. xYes    ̈
No





Indicate by checkmark if disclosure of
delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this
chapter) is not contained herein, and will not be contained, to the best of
registrant’s, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form
10-K.x





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





Large
      accelerated filer  ̈
              
              Accelerated
      filer  ̈Non-accelerated
      filer  ̈
      (Do not check if a smaller reporting company)
              
              Smaller
      reporting company x





Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).


Yes   ̈      No
x





State the
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of the
last business day of the registrant’s most recently completed second fiscal
quarter: $15,197,050





Indicate
the number of shares outstanding of each of the registrant’s classes of common
stock, as of the latest practicable date: 4,443,512 shares of common
stock, $0.001 par value, outstanding on July 14, 2009.





DOCUMENTS
INCORPORATED BY REFERENCE





List
hereunder the following documents if incorporated by reference and the Part of
the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: (1) Any annual report to security holders; (2) Any proxy or
information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or
(c) under the Securities Act of 1933. The listed documents should be clearly
described for identification purposes (e.g., annual report to security holders
for fiscal year ended December 24, 1980).





NONE.







ENERJEX
RESOURCES, INC.


FORM
10-K


TABLE
OF CONTENTS





PagePART
      I
                                                              
                                                              
                                                              2Items
      1 and 2.
                                                              
                                                              Business
      and Properties
                                                              2Item
      1A.
                                                              
                                                              Risk
      Factors
                                                              28Item
      1B.
                                                              
                                                              Unresolved
      Staff Comments
                                                              48Item
      3.
                                                              
                                                              Legal
      Proceedings
                                                              48Item
      4.
                                                              
                                                              Submission
      of Matters to a Vote of Security Holders
                                                              48PART
      II
                                                              
                                                              
                                                              49Item
      5.
                                                              
                                                              Market
      for Registrant’s Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities
                                                              49Item
      6.
                                                              
                                                              Selected
      Financial Data
                                                              51Item
      7.
                                                              
                                                              Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
                                                              51Item
      7A.
                                                              
                                                              Quantitative
      and Qualitative Disclosures about Market Risk
                                                              65Item
      8.
                                                              
                                                              Financial
      Statements and Supplementary Data
                                                              66Item
      9.
                                                              
                                                              Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
                                                              66Item
      9A(T).
                                                              
                                                              Controls
      and Procedures
                                                              66Item
      9B.
                                                              
                                                              Other
      Information
                                                              67Part
      III
                                                              
                                                              
                                                              67Item
      10.
                                                              
                                                              Directors,
      Executive Officers and Corporate Governance
                                                              67Item
      11.
                                                              
                                                              Executive
      Compensation
                                                              72Item
      12.
                                                              
                                                              Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
                                                              74Item
      13.
                                                              
                                                              Certain
      Relationships and Related Transactions, and Director
      Independence
                                                              76Item
      14.
                                                              
                                                              Principal
      Accountant Fees and Services
                                                              76Part
      IV
                                                              
                                                              
                                                              78Item
      15.
                                                              
                                                              Exhibits,
      Financial Statement Schedules
                                                              78





FORWARD-LOOKING
STATEMENTS





This
report contains forward-looking statements. These forward-looking statements are
subject to a number of risks and uncertainties, many of which are beyond our
control. All statements, other than statements of historical fact, contained in
this report, including statements regarding future events, our future financial
performance, business strategy and plans and objectives of management for future
operations, are forward-looking statements. We have attempted to identify
forward-looking statements by terminology including “anticipates,” “believes,”
“can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,”
“potential,” “predicts” or “should” or the negative of these terms or other
comparable terminology. Although we do not make forward-looking statements
unless we believe we have a reasonable basis for doing so, we cannot guarantee
their accuracy. These statements are only predictions and involve known and
unknown risks, uncertainties and other factors, including the risks outlined
under “Risk Factors” or elsewhere in this report, which may cause our or our
industry’s actual results, levels of activity, performance or achievements to be
materially different from any future results, levels of activity, performance or
achievements expressed or implied by these forward-looking statements. Moreover,
we operate in a very competitive and rapidly changing environment. New risks
emerge from time to time and it is not possible for us to predict all risk
factors, nor can we address the impact of all factors on our business or the
extent to which any factor, or combination of factors, may cause our actual
results to differ materially from those contained in any forward-looking
statements. The factors impacting these risks and uncertainties include, but are
not limited to:





·
            inability
      to attract and obtain additional development
  capital;


·
            inability
      to achieve sufficient future sales levels or other operating
      results;


·
            inability
      to efficiently manage our
operations;


·
            potential
      default under our secured obligations or material debt
      agreements;


·
            estimated
      quantities and quality of oil and natural gas
  reserves;


·
            declining
      local, national and worldwide economic
  conditions;


·
            fluctuations
      in the price of oil and natural
gas;


·
            the
      inability of management to effectively implement our strategies and
      business plans;


·
            approval
      of certain parts of our operations by state
  regulators;


·
            inability
      to hire or retain sufficient qualified operating field
      personnel;


·
            increases
      in interest rates or our cost of
borrowing;


·
            deterioration
      in general or regional (especially Eastern Kansas) economic
      conditions;


·
            occurrence
      of natural disasters, unforeseen weather conditions, or other events or
      circumstances that could impact our operations or could impact the
      operations of companies or contractors we depend upon in our
      operations;


·
            inability
      to acquire mineral leases at a favorable economic value that will allow us
      to expand our development efforts;


·
            adverse
      state or federal legislation or regulation that increases the costs of
      compliance, or adverse findings by a regulator with respect to existing
      operations; and


1





·
            changes
      in U.S. GAAP or in the legal, regulatory and legislative environments in
      the markets in which we operate.





You
should not place undue reliance on any forward-looking statement, each of which
applies only as of the date of this report. Except as required by law, we
undertake no obligation to update or revise publicly any of the forward-looking
statements after the date of this report to conform our statements to actual
results or changed expectations.  For a detailed description of these
and other factors that could cause actual results to differ materially from
those expressed in any forward-looking statement, please see “Risk Factors” in
this document under ITEM 1A.





All references in this report to “we,”
“us,” “our,” “company” and “EnerJex” refer to EnerJex Resources, Inc. and our
wholly-owned operating subsidiaries, EnerJex Kansas, Inc. and DD Energy, Inc.,
unless the context requires otherwise. We report our financial information on
the basis of a March 31 fiscal year end.  We have provided definitions
for the oil and natural gas industry terms used in this report in the “Glossary”
beginning on page 23 of this report.





AVAILABLE
INFORMATION





We file
annual, quarterly and other reports and other information with the
SEC.  You can read these SEC filings and reports over the Internet at
the SEC’s website at www.sec.gov or on our website at www.enerjexresources.com.  You
can also obtain copies of the documents at prescribed rates by writing to the
Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on
official business days between the hours of 10:00 am and 3:00
pm.  Please call the SEC at (800) SEC-0330 for further information on
the operations of the public reference facilities. We will provide a copy of our
annual report to security holders, including audited financial statements, at no
charge upon receipt to of a written request to us at EnerJex Resources, Inc., 27
Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park,
Kansas  66210.





INDUSTRY
AND MARKET DATA





The
market data and certain other statistical information used throughout this
report are based on independent industry publications, government publications,
reports by market research firms or other published independent sources. In
addition, some data are based on our good faith estimates.





PART
I




Items
1 and 2. Business and Properties.





Our Business





EnerJex,
formerly known as Millennium Plastics Corporation, is an oil and natural gas
acquisition, exploration and development company. Midwest Energy, Inc. was
incorporated in the State of Nevada on December 30, 2005. In August of 2006,
Millennium Plastics Corporation, following a reverse merger by and among us,
Millennium Acquisition Sub (our wholly-owned subsidiary) and Midwest Energy,
changed the focus of its business plan from the development of
biodegradable plastic materials and entered into the oil and natural gas
industry. In conjunction with the change, the company was renamed EnerJex
Resources, Inc.


2





Our
principal strategy is to focus on the acquisition of oil and natural gas mineral
leases that have existing production and cash flow. Once acquired, subject to
availability of capital, we strive to implement an accelerated development
program utilizing capital resources, a regional operating focus, an experienced
management and technical team, and enhanced recovery technologies to attempt to
increase production and increase returns for our stockholders. Our oil and
natural gas acquisition and development activities are currently focused in
Eastern Kansas.





From the
beginning of fiscal 2008 through the end of fiscal 2009, we deployed
approximately $12 million in capital resources to acquire and develop five
operating projects and drill 179 new wells (111 producing wells and 65
water injection wells and 3 dry holes). As a result, our estimated total
net proved oil reserves increased from zero at March 31, 2007 to 1.3
million barrels of oil equivalent, or BOE, as of March 31, 2009. Of the
1.3 million BOE of total proved reserves, approximately 39% are proved
developed and approximately 61% are proved undeveloped. The proved developed
reserves consist of 82% proved developed producing reserves and 18% proved
developed non-producing reserves.





The total
proved PV10 (present value) of our reserves (“PV10”) as of March 31, 2009 was
$10.63 million. PV10 means the estimated future gross revenue to be
generated from the production of proved reserves, net of estimated production
and future development and abandonment costs, using prices and costs in effect
at the determination date, before income taxes, and without giving effect to
non-property related expenses, discounted to a present value using an annual
discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a
non-GAAP financial measure and generally differs from the standardized measure
of discounted future net cash flows, the most directly comparable GAAP financial
measure, because it does not include the effects of income taxes on future net
revenues. See “Management’s Discussion and Analysis of Financial Condition and
Results of Operations-Reserves” page 57, for a reconciliation to the comparable
GAAP financial measure.





In response to economic conditions and
capital market constraints, we have recently begun to explore and evaluate
various strategic initiatives that would allow us to continue our plans to grow
production and reserves in the mid-continent region of the United States.
Initiatives include creating joint ventures to further develop current leases,
restructuring current debt, as well as evaluating other options ranging from
capital formation to some type of business combination.  Though there
can be no assurance that any particular outcome will result from this process,
we believe there are significant opportunities to increase our growth rates
given current market conditions.  We believe this process may create
options that will allow us to better position EnerJex to take advantage of these
opportunities.





The Opportunity in
Kansas





According
to the Kansas Geological Survey, the State of Kansas has historically been one
of the top 10 domestic oil producing regions in the United States. For the
years ended December 31, 2008 and 2007, 39.6 million barrels and 36.6
million barrels of oil were produced in Kansas. Of the total barrels
produced in Kansas in the calendar year ended December 2007, 15 companies
accounted for approximately 29% of the total production, with the remaining 71%
produced by over 1,750 active producers.


3





In
addition to significant historical oil and natural gas production levels in the
region, we believe that a confluence of the following factors in Eastern Kansas
and the surrounding region make it an attractive area for oil and natural gas
development activities:





·
            Traditional Roll-Up
      Strategy.  We are seeking to employ a traditional roll-up
      strategy utilizing a combination of capital resources, operational and
      management expertise, technology, and our strategic partnership with Haas
      Petroleum, which has experience operating in the region for nearly 70
      years.





·
            Numerous Acquisition
      Opportunities.  There are many small producers and owners
      of mineral rights in the region, which afford us numerous opportunities to
      pursue negotiated lease transactions instead of having to competitively
      bid on fundamentally sound assets.





·
            Fragmented Ownership
      Structure.  There are numerous opportunities to acquire
      producing properties at attractive prices, because of the currently
      inefficient and fragmented ownership
structure.





Our Properties





The table
below summarizes our acreage by project name as of March 31, 2009.





Project Name
                  
                  Developed Acreage
                  
                  
                  Undeveloped Acreage
                  
                  
                  Total AcreageGross
                  
                  
                  Net(1)
                  
                  
                  Gross
                  
                  
                  Net(1)
                  
                  
                  Gross
                  
                  
                  Net(1)Black
      Oaks Project
                  
                  
                  550
                  
                  
                  
                  522
                  
                  
                  
                  1,850
                  
                  
                  
                  1,758
                  
                  
                  
                  2,400
                  
                  
                  
                  2,280Thoren
      Project
                  
                  
                  135
                  
                  
                  
                  135
                  
                  
                  
                  591
                  
                  
                  
                  591
                  
                  
                  
                  726
                  
                  
                  
                  726DD
      Energy Project
                  
                  
                  400
                  
                  
                  
                  400
                  
                  
                  
                  1,370
                  
                  
                  
                  1,370
                  
                  
                  
                  1,770
                  
                  
                  
                  1,770Tri-County
      Project
                  
                  
                  610
                  
                  
                  
                  606
                  
                  
                  
                  652
                  
                  
                  
                  651
                  
                  
                  
                  1,262
                  
                  
                  
                  1,257Gas
      City Project
                  
                  
                  600
                  
                  
                  
                  600
                  
                  
                  
                  4,713
                  
                  
                  
                  4,713
                  
                  
                  
                  5,313
                  
                  
                  
                  5,313Total
                  
                  
                  2,295
                  
                  
                  
                  2,263
                  
                  
                  
                  9,176
                  
                  
                  
                  9,083
                  
                  
                  
                  11,471
                  
                  
                  
                  11,346





(1)
            Net
      acreage is based on our net working interest as of March 31,
      2009.





BlackOaks Project





On April
9, 2007, we entered into a “Joint Exploration Agreement” with a shareholder,
MorMeg, LLC, (MorMeg) whereby we agreed to advance $4.0 million to a joint
operating account for further development of MorMeg’s Black Oaks leaseholds in
exchange for a 95% working interest in the Black Oaks Project. The Black Oaks Project
encompasses approximately 2,400 gross acres in Woodson and Greenwood Counties, Kansas, which
at the time of acquisition had approximately 35 oil wells producing an average
of approximately 32 barrels of oil per day, or BOPD.


4


The Black Oaks Project is a primary and
enhanced secondary recovery project between us and MorMeg. Phase I of the Black
Oaks Project development plan commenced shortly after closing with the drilling
of 44 in-fill wells. During fiscal 2008, we began injecting water into the first
five water injection wells at an average rate of approximately 50 barrels of
water per day per well. This pilot program was expanded so that by June 2008, we
were injecting approximately 200 barrels of water per day (bbls water/day) per
well in the initial 5 injection wells. Adjacent oil wells showed increased
production from an average of approximately 5 BOPD to 25 BOPD. As of March
31, 2009, we are maintaining the 200 bbls water/day average on the injection
wells in the pilot program area. We have seen no additional response on this
area as of yet. We are also injecting an average of 100 bbls
water/day per well in 4 injection wells adjacent to the pilot program area and
are closely monitoring data and activities for any resulting increase in
production.  Based upon the results of our testing, we expect to
continue the development plan, subject to availability of capital. Phase II of
the plan contemplates drilling over 25 additional water injection wells and
drilling over 20 additional producer wells. Project-wide production was an
average of approximately 96 BOPD as of March 31, 2009.





We will maintain
our 95% working interest until “payout”, at which time the MorMeg 5% carried
working interest will be converted to a 30% working interest and our working
interest becomes 70%. Payout is generally the point in time when the total
cumulative revenue from the project equals all of the project’s development
expenditures and costs associated with funding. Through an additional extension,
we have until December 31, 2009 to contribute additional capital toward the
Black Oaks Project development. If we elect not to contribute further capital to
the Black Oaks Project prior to the project’s full development while it is
economically viable to do so, or if there is more than a thirty day delay in
project activities due to lack of capital, MorMeg has the option to cease
further joint development and we will receive an undivided interest in the Black
Oaks Project. The extension will have no force and effect, however, upon a
material default by EnerJex under the Credit Facility. The undivided interest
will be the proportionate amount equal to the amount that our investment bears
to our investment plus $2.0 million, with MorMeg receiving an undivided interest
in what remains.





As of
March 31, 2009, we had proved oil reserves on Phase I of this project
of:





Gross STB(1)
                    
                    
                    Net STB(2)
                    
                    
                    PV10(3)
                      (before tax)Proved,
      Developed Producing
                    
                    
                    420,080
                    
                    
                    
                    197,640
                    
                    
                    $
                    3,781,690Proved,
      Developed Non-Producing
                    
                    
                    50,440
                    
                    
                    
                    30,450
                    
                    
                    $
                    650,430Proved,
      Undeveloped
                    
                    
                    875,300
                    
                    
                    
                    352,370
                    
                    
                    $
                    944,100Total
      Proved
                    
                    
                    1,345,820
                    
                    
                    
                    580,460
                    
                    
                    $
                    5,376,220


(1)   
STB = one stock-tank
barrel.


(2)   
Net STB is based upon our net
revenue interest, including any applicable reversionary
interest.


(3)
            See
      “Glossary” on page 23 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 57, for a reconciliation to the comparable GAAP
      financial measure.





Thoren
Project





On April
27, 2007, we acquired a 100% working interest in the Thoren Project for $400,000
from MorMeg. This project, at the time of acquisition, contained 240 acres in
Douglas County, Kansas, with 12 oil wells producing an average of approximately
10 BOPD, 4 water injection wells, and one water supply well. We have leased an
additional 486 acres increasing the total acreage of this project to 726
acres.


5





Through
March 31, 2009, we have invested approximately $800,000 for the development of
this project and as of March 31, 2009, we had 32 oil wells producing an average
of approximately 38 BOPD; along with 16 water injection wells and one water
supply well.





As of
March 31, 2009, we had proved oil reserves on this project of:





Gross STB(1)
                                
                                Net STB(2)
                                
                                PV10(3)
                                  (before tax)Proved,
      Developed Producing
                                
                                48,030
                                
                                24,600
                                
                                $
                                539,510Proved,
      Developed Non-Producing
                                
                                24,920
                                
                                7,690
                                
                                $
                                146,490Proved,
      Undeveloped
                                
                                43,020
                                
                                37,640
                                
                                $
                                85,970Total
      Proved
                                
                                115,970
                                
                                69,930
                                
                                $
                                771,970


(1)
            STB = one stock-tank
      barrel.


(2)
            Net STB is based upon our net
      revenue interest, including any applicable reversionary
      interest.


(3)
            See
      “Glossary” on page 23 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 57, for a reconciliation to the comparable GAAP
      financial measure.





We will
maintain our 100% working interest until “payout” and our working interest will
become 75%, at which time the MorMeg working interest will be converted to a 25%
working interest. Payout for this project occurs at that point in time when the
total cumulative revenue from production equals the total amount of the purchase
price, all costs and expenses incurred by us in the development and operation,
and loan and interest costs incurred in the finance and funding of the
purchase.





We have
identified an additional 7 drillable producer locations and 8 drillable injector
locations on this project.





DD Energy
Project





Effective
September 1, 2007, we acquired a 100% working interest in the DD Energy Project
for $2.7 million, which consisted of approximately 1,500 acres in Johnson,
Anderson and Linn Counties, Kansas. At the time of acquisition, this project was
producing an average of approximately 45 BOPD.





In
addition, we have acquired additional leases bringing the total acreage for this
project to approximately 1,700 acres. As of March 31, 2009, we had 110 oil
wells, 41 water injection wells and 2 water supply wells on this project with
production averaging approximately 61 BOPD. Through March 31, 2009, we have
invested an additional $2.4 million in this project and have drilled 41 water
injection wells and 34 producing wells.  We have seen some indication
of an initial response from 5 of the injectors and are closely monitoring data
and activities for any resulting increase in production.


6





As of March 31, 2009, we had proved oil
reserves on this project of:


Gross STB(1)
                    
                    
                    Net STB(2)
                    
                    
                    PV10(3)
                      (before tax)Proved,
      Developed Producing
                    
                    
                    75,510
                    
                    
                    
                    64,700
                    
                    
                    $
                    972,220Proved,
      Developed Non-Producing
                    
                    
                    23,070
                    
                    
                    
                    19,470
                    
                    
                    $
                    183,090Proved,
      Undeveloped
                    
                    
                    39,390
                    
                    
                    
                    31,840
                    
                    
                    $
                    85,030Total
      Proved
                    
                    
                    137,970
                    
                    
                    
                    116,010
                    
                    
                    $
                    1,240,340


(1)
            STB = one stock-tank
      barrel.


(2)
            Net STB is based upon our net
      revenue interest, including any applicable reversionary
      interest.


(3)
            See
      “Glossary” on page 23 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 57, for a reconciliation to the comparable
      GAAP financial measure.





We
have identified an additional 88 drillable producer locations and 86 drillable
injector locations on this project.





Tri-County
Project





On
September 14, 2007, we acquired nearly a 100% working interest in the Tri-County
Project for $800,000, which consisted of approximately 1,100 acres in Miami,
Johnson and Franklin Counties, Kansas. At the time of acquisition, this project
was producing an average of approximately 25 BOPD.





Through
March 31, 2009, we have invested approximately $700,000 towards the development
of this project. Funds have been used to drill four producer wells, make
infrastructure upgrades, and perform work-overs on approximately 20 wells in
this project. We have also acquired additional leases, bringing the total
project to approximately 1,300 acres.





As of
March 31, 2009, the Tri-County Project consisted of 166 producing wells and 59
water injection wells with production averaging approximately 49
BOPD.





As of
March 31, 2009, we had proved oil reserves on this project of:





Gross STB(1)
                  
                  
                  Net STB(2)
                  
                  
                  PV10(3)
                    (before tax)Proved,
      Developed Producing
                  
                  
                  177,560
                  
                  
                  
                  141,330
                  
                  
                  $
                  1,369,700Proved,
      Developed Non-Producing
                  
                  
                  48,190
                  
                  
                  
                  37,940
                  
                  
                  $
                  479,270Proved,
      Undeveloped
                  
                  
                  474,210
                  
                  
                  
                  380,030
                  
                  
                  $
                  1,361,430Total
      Proved
                  
                  
                  699,960
                  
                  
                  
                  559,300
                  
                  
                  $
                  3,210,400


(1)
            STB = one stock-tank
      barrel.


(2)
            Net STB is based upon our net
      revenue interest, including any applicable reversionary
      interest.


(3)
            See
      “Glossary” on page 23 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 57, for a reconciliation to the comparable
      GAAP financial measure.





We have
identified an additional 83 drillable producer locations and 90 drillable
injector locations on this project.


7


Gas City
Project





In August
of 2007, we entered into a development agreement with Euramerica Energy, Inc.,
or Euramerica, to further the development and expansion of the Gas City
Project, which included 6,600 acres, whereby Euramerica contributed $524,000 in
capital toward the project. Euramerica was granted an option to purchase this
project for $1.2 million with a requirement to invest an additional $2.0 million
for project development by August 31, 2008. We were the operator of the project
at a cost plus 17.5% basis. We received $600,000 of the $1.2 million purchase
price and $500,000 of the $2.0 million development funds.





On
September 15, 2008, we amended the well development agreement to extend the date
on which Euramerica was required to make its third and fourth quarterly
installment payments of the purchase price to October 15, 2008.  The
amendment also extended until November 15, 2008 the requirement to fund the
remaining $1.5 million in development capital.





On
October 15, 2008, we again amended the agreement with Euramerica for the
purchase of the Gas City Project to include the following material changes to
the Euramerica agreement, as amended, extended and supplemented:





·
            Euramerica
      was granted an extension until January 15, 2009 (with no further
      grace periods) to pay the remaining $600,000 of the purchase price for its
      option to purchase an approximately 6,600 acre portion of the Gas City
      Project and $1.5 million in previously due development funds for the Gas
      City Project;


·
            If
      Euramerica fails to fully fund both the purchase price and these
      development funds by January 15, 2009, Euramerica will lose all rights to
      the Gas City Project and assets and there will be no payout from
      the revenue of the wells on this
project;


·
            The
      oil zones and production from such oil zones in two oil
      wells then became 100% owned by
EnerJex;


·
            We
      may deduct from the development funds all amounts owed to us prior to
      applying the funds to any actual
development;


·
            Euramerica
      specifically recognized that we can shut in or stop the development of the
      project if the project is not producing in paying quantities or if the
      project is operating at a loss. The decision to shut in the project and
      cease all operations was made on October 15,
  2008; and


·
            If
      Euramerica funds the remaining portion of the purchase price for its
      option and the development funds in the Gas City Project on or before
      January 15, 2009, “Payout” as used in the Assignment and other documents
      is now based on “drilling and completion costs on a well-by-well
      basis.”





Subsequently,
Euramerica failed to fully fund by January 15, 2009 both the balance of the
purchase price and the remaining development capital owed under the Amended and
Restated Well Development Agreement and Option for “Gas City Property” between
us and Euramerica.  Therefore, Euramerica has forfeited all of its
interest in the property, including all interests in any wells, improvements or
assets, and all of Euramerica's interest in the property reverts back to
us.  In addition, all operating agreements between us and Euramerica
relating to the Gas City Project are null and void.


8





We
drilled 22 wells on behalf of Euramerica under the development agreement. We are
currently exploring options to sell or further develop the Gas City Project
through joint venture partnerships or other opportunities.  The gas
project remains shut in and certain leases approximating 1,300 acres were not
renewed upon expiration.  As of March 31, 2009 we were producing an
average of approximately 10 BOPD from the two oil wells now 100% owned by
us.





As of
March 31, 2009, we had proved oil and natural gas reserves on this project
of:





Gross
                  STB(1)
                
                
                Net
                  STB(2)
                
                
                Gross
                  MCF(3)
                
                
                Net
                  MCF(4)
                
                
                PV10(5)
                  (before tax)Proved,
      Developed Producing
                
                
                1,400
                
                
                
                1,150
                
                
                
                -
                
                
                
                -
                
                
                $
                28,430Proved,
      Developed Non-Producing
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                $
                -Proved,
      Undeveloped
                
                
                11,850
                
                
                
                9,780
                
                
                
                -
                
                
                
                -
                
                
                $
                1,970Total
      Proved
                
                
                13,250
                
                
                
                10,930
                
                
                
                -
                
                
                
                -
                
                
                $
                30,400


(1)
            STB
      = one stock-tank barrel.


(2)
            Net STB is based upon our net
      revenue interest, including any applicable reversionary
      interest.


(3)
            MCF = thousand cubic feet of
      natural gas.  There were no natural gas reserves at March 31,
      2009.


(4)
            Net MCF is based upon our net
      revenue interest.  There were no natural gas reserves at March
      31, 2009.


(5)
            See
      “Glossary” on page 23 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 57, for reconciliation to the comparable GAAP
      financial measure.





Brownrigg
Project





We entered into an agreement with
Pharyn Resources (Pharyn) on June 1, 2009 to begin a 20 well development program
on EnerJex’s Brownrigg lease in Linn County, Kansas. We contributed the 320 acre
property in exchange for a 10% carried working interest and a cost-plus
management fee. Pharyn will contribute up to $700,000 in initial development
capital. We intend to develop the project and remain the operator of the
property. We will be working with Pharyn in this, our first joint venture
project and feel we have an agreement that pairs our drilling and operating
background with Pharyn’s investment objectives, which is intended to build
long-term sustainable earnings growth for both companies. As of the date of this
report, we have drilled 5 wells and are in various stages of
completion.





Our Business
Strategy





Our
principal strategy has been to focus on the acquisition of oil and natural gas
mineral leases that have existing production and cash flow. Once acquired,
subject to availability of capital, we strive to implement an accelerated
development program utilizing capital resources, a regional operating focus, an
experienced management and technical team, and enhanced recovery technologies to
attempt to increase production and increase returns for our stockholders. Our
oil and natural gas acquisition and development activities are currently focused
in Eastern Kansas.Depending on availability
of capital, and other restraints, ourgoal is to increase
stockholder value by finding and developing oil
andnatural
gas reservesat costs that provide an attractive rate of return on our investments. The
principal elements of our business strategy are:


9





·
            Develop Our Existing
      Properties.  We intend to create reserve and production
      growth from over 400 additional drilling locations we have identified on
      our properties.   We have identified an additional 193
      drillable producer locations and 213 drillable injector
      locations.  The structure and the continuous oil accumulation in
      Eastern Kansas, and the expected long-life production and reserves of our
      properties, are
      anticipated to enhance our opportunities for long-term
      profitability.





·
            Maximize Operational
      Control.  We seek to operate our properties and maintain
      a substantial working interest. We believe the ability to control our
      drilling inventory will provide us with the opportunity to more
      efficiently allocate capital, manage resources, control operating and
      development costs, and utilize our experience and knowledge of oilfield
      technologies.





·
            Pursue Selective Acquisitions
      and Joint Ventures.  Due to our local presence in Eastern
      Kansas and strategic partnership with Haas Petroleum, we believe we are
      well-positioned to pursue selected acquisitions, subject to availability
      of capital, from the fragmented and capital-constrained owners of mineral
      rights throughout Eastern Kansas.





·
            Reduce Unit Costs Through
      Economies of Scale and Efficient
      Operations.  As we increase our oil production and
      develop our existing properties, we expect that our unit cost structure
      will benefit from economies of scale. In particular, we anticipate
      reducing unit costs by greater utilization of our existing infrastructure
      over a larger number of wells.





We are
continually evaluating oil and natural gas opportunities in Eastern Kansas and
are also in various stages of discussions with potential joint venture (“JV”)
partners who would contribute capital to develop leases we currently own or
would acquire for the JV. Subsequent to year-end (in June 2009), we entered
into one such opportunity on the Brownrigg lease in Linn County, Kansas, as
discussed above.  This economic strategy is anticipated to allow us to
utilize our own financial assets toward the growth of our leased acreage
holdings, pursue the acquisition of strategic oil and natural gas producing
properties or companies and generally expand our existing operations while
further diversifying risk. Subject to availability of capital, we plan to
continue to bring potential acquisition and JV opportunities to various
financial partners for evaluation and funding options.  It is our
vision to grow the business in a disciplined and well-planned
manner.





We began
generating revenues from the sale of oil during the fiscal year ended March 31,
2008. Subject to availability of capital, we expect our production to continue
to increase, both through development of wells, through our acquisition
strategy, and other strategic initiatives. Our future financial results will
continue to depend on: (i) our ability to source and screen potential projects;
(ii) our ability to discover commercial quantities of natural gas and oil; (iii)
the market price for oil and natural gas; and (iv) our ability to fully
implement our exploration, work-over and development program, which is in part
dependent on the availability of capital resources. There can be no assurance
that we will be successful in any of these respects, that the prices of oil and
natural gas prevailing at the time of production will be at a level allowing for
profitable production, or that we will be able to obtain additional funding at
terms favorable to us to increase our currently limited capital
resources.    For a detailed description of these and other
factors that could materially impact actual results, please see “Risk Factors”
in this document under ITEM 1A.


10





The board
of directors has implemented a crude oil and natural gas hedging strategy that
will allow management to hedge up to 80% of our net production to mitigate a
majority of our exposure to changing oil prices in the intermediate
term.





Our Competitive
Strengths





We have a
number of strengths that we believe will help us successfully execute our
strategy:





·
            Acquisition and Development
      Strategy.  We have what we believe to be a relatively
      low-risk acquisition and development strategy compared to some of our
      competitors. We generally buy properties that have proven current
      production, with a projected pay-back within a relatively short period of
      time, and with potential growth and upside in terms of development,
      enhancement and efficiency. We also plan to minimize the risk of natural
      gas and oil price volatility by developing a sales portfolio of pricing
      for our production as it expands and as market conditions
      permit.





·
            Significant Production Growth
      Opportunities.  We have acquired an attractive acreage
      position with favorable lease terms in a region with historical
      hydrocarbon production. Based on drilling success we have had within our
      acreage position and subject to availability of capital, we expect to
      increase our reserves, production and cash
flow.





·
            Experienced Management Team
      and Strategic Partner with Strong Technical
      Capability.  Our CEO has over 20 years of experience in
      the energy industry, primarily related to gas/electric utilities, but
      including experience related to energy trading and production, and members
      of our board of directors have considerable industry experience and
      technical expertise in engineering, horizontal drilling, geoscience and
      field operations. In addition, our strategic partner, Haas Petroleum, has
      over 70 years of experience in Eastern Kansas, including completion and
      secondary recovery techniques and technologies. Our board of directors and
      Mark Haas of Haas Petroleum work closely with management during the
      initial phases of any major project to ensure its feasibility and to
      consider the appropriate recovery techniques to be
    utilized.





·
            Incentivized Management
      Ownership.  The equity ownership of our directors and
      executive officers is strongly aligned with that of our stockholders. As
      of July 14, 2009, our directors and executive officers owned approximately
      9.1% of our outstanding common stock, with options that upon exercise
      would increase their ownership of our outstanding common stock to
      15.6%.


11





Company History





Midwest
Energy, Inc. was incorporated in the State of Nevada on December 30, 2005. Prior
to the reverse merger with Midwest Energy in August of 2006, we operated under
the name Millennium Plastics Corporation and focused on the development of
biodegradable plastic materials. This business plan was ultimately abandoned
following its unsuccessful implementation. Following the merger, we assumed the
business plan of Midwest Energy and entered into the oil and natural gas
industry. Concurrent with the effectiveness of the merger, we changed our name
to “EnerJex Resources, Inc.” The result of the merger was that the former
stockholders of Midwest Energy controlled approximately 98% of our outstanding
shares of common stock. In addition, Midwest Energy was deemed to be the
acquiring company for financial reporting purposes and the merger was accounted
for as a reverse merger. In November 2007 Midwest Energy changed its name to
EnerJex Kansas. All of our current operations are conducted through EnerJex
Kansas and DD Energy, our wholly-owned subsidiaries.





Significant
Developments in Fiscal 2009





The
following is a brief description of our most significant corporate developments
that occurred in fiscal 2009:





·
            On March 6, 2008 we
      entered into an agreement with Shell Trading (US) Company, or
      Shell, whereby we agreed to an 18-month fixed-price swap with Shell for
      130 BOPD at a fixed price per barrel of $96.90, before transportation
      costs from April 1, 2008 through September 30, 2009. This represented
      approximately 60% of our total oil production on a net revenue basis at
      that time and locked in approximately $6.8 million in gross revenue before
      transportation costs over the 18 month period. In addition, we agreed to
      sell all of our remaining oil production at current spot market pricing
      beginning April 1, 2008 through September 30, 2009 to
      Shell.  For the fiscal year ended March 31, 2009, the positive
      impact on our net revenue from the fixed-price swap was approximately
      $506,000.





·
            On
      July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a
      three-year $50 million Senior Secured Credit Facility (the “Credit
      Facility”) with Texas Capital Bank, N.A.  Borrowings under the
      Credit Facility will be subject to a borrowing base limitation based on
      our current proved oil and gas reserves and will be subject to semi-annual
      redeterminations and other interim adjustments.  The initial
      borrowing base was set at $10.75 million and was reduced to $7.428 million
      following the liquidation of the BP hedging instrument in November
      2008.  The borrowing base was reviewed by Texas Capital Bank in
      February 2009 and it was determined that it shall be reduced by $200,000
      per month beginning April 2009 with the expectation  that this
      monthly reduction would continue through December 2009. We had borrowings
      $7.328 million outstanding at March 31, 2009.  Subsequent to
      year-end, we have made an additional $200,000 of payments to reduce the
      borrowing base.  The Credit Facility is secured by a lien on
      substantially all assets of the Company and its subsidiaries. The Credit
      Facility has a term of three years, and matures on July 3,
      2011.  The Credit Facility also provides for the issuance of
      letters-of-credit up to a $750,000 sub-limit under the borrowing base and
      up to an additional $2.25 million limit not subject to the borrowing base
      to support our hedging program.


12





·
            On
      July 7, 2008, we amended the $2.7 million of aggregate principal amount of
      our 10% debentures that remain outstanding to, among other things, permit
      the indebtedness under our Credit Facility, subordinate the security
      interests of the debentures to the Credit Facility, provide for the
      redemption of the remaining debentures with the net proceeds from any next
      debt or equity offering, eliminate the covenant to maintain certain
      production thresholds and waive all known defaults.  Subsequent
      to year-end, we again amended the debentures to extend the maturity date
      to September 30, 2010, to allow us to pay interest in either cash or
      payment-in-kind interest (an increase in the amount of principal due) or
      payment of interest through the issuance of shares of common stock, and
      add a provision for the conversion of the debentures into shares of our
      common stock. Through May 31, 2010
      the conversion price per share equals $3.00.  FromJune 1, 2010
      through the Maturity Date,
      assuming the debenture has not
      been redeemed,the conversionprice
      per share equalsthat price which
      shall be computed as 100.0% of the arithmetic average of the Weighted
      Average Price of the Common Stock on each of the thirty (30) consecutive
      Trading Days immediately preceding the Conversion Date, and considering
      adjustments, if any, as specified in the
  amendment.





·
            As
      of July 3, 2008, we entered into an ISDA master agreement and a costless
      collar with BP Corporation North America Inc., or BP, for 130 barrels of
      oil per day with a price floor of $132.50 per barrel and a price ceiling
      of $155.70 per barrel for NYMEX West Texas Intermediate for the
      period of October 1, 2009 until March 31, 2011.  We liquidated
      this costless collar in November 2008 and received proceeds of
      approximately $3.9 million from BP.  We reduced the debt
      outstanding under our Credit Facility by approximately $3.3 million and
      used the remainder for general operating
  purposes.





·
            On
      August 1, 2008, we executed three-year employment agreements with C.
      Stephen Cochennet, our chief executive officer, and Dierdre P. Jones, our
      chief financial officer.  Mr. Cochennet and Ms. Jones have
      agreed to amend their employment agreements to reflect options rescinded
      in November 2008.





·
            Euramerica
      failed to fully fund by January 15, 2009 both the balance of the purchase
      price and the remaining development capital owed under the Amended and
      Restated Well Development Agreement and Option for “Gas City Property”
      between us and Euramerica.  Therefore, Euramerica has forfeited
      all of its interest in the property, including all interests in any wells,
      improvements or assets, and all of Euramerica's interest in the property
      reverts back to us.  In addition, all operating agreements
      between us and Euramerica relating to the Gas City Project are null and
      void.





·
            In
      February 2009, we entered into a fixed price swap transaction under the
      terms of the BP ISDA for a total of 120,000 gross barrels at a price of
      $57.30 per barrel before transportation costs for the period beginning
      October 1, 2009 and ending on December 31,
2013.


13





·
            We
      recorded a non-cash impairment of $4,777,723 to the carrying value of our
      proved oil and gas properties during the fiscal year ended March 31, 2009.
      The impairment is primarily attributable to lower prices for both oil and
      natural gas.  The charge results from the application of the
      “ceiling test” under the full cost method of accounting at December 31,
      2008. Under full cost accounting requirements, the carrying value may not
      exceed an amount equal to the sum of the present value of estimated future
      net revenues (adjusted for cash flow hedges) less estimated future
      expenditures to be incurred in developing and producing the proved
      reserves, less any related income tax effects. In calculating future net
      revenues, current prices and costs used are those as of the end of the
      appropriate quarterly period. Such prices are utilized except where
      different prices are fixed and determinable from applicable contracts for
      the remaining term of those contracts, including the effects of
      derivatives qualifying as cash flow hedges. A ceiling test charge occurs
      when the carrying value of the oil and gas properties exceeds the full
      cost ceiling.





·
            We
      accrued but did not pay interest due at March 31, 2009 to our subordinated
      debenture holders on the $2.7 million outstanding as of that
      date.  Subsequent to year-end, we agreed to pay the accrued
      interest on a payment-in-kind
basis.





Relationship withHaas Petroleum





In April
of 2007, we entered into a consulting agreement with Mark Haas, President of
Haas Petroleum and managing member of MorMeg. This agreement provides that Mr.
Haas will consult with us at an executive level regarding field development,
acquisition evaluation, identification of additional acquisition opportunities
and overall business strategy. Haas Petroleum has been in the oil exploration
and production business for over 70 years and Mark Haas has been in the business
for over 30 years.





We
believe that this relationship provides us with a competitive advantage when
evaluating and sourcing acquisition opportunities. As a long-term producer and
oil field service provider, Haas Petroleum has existing relationships with
numerous oil and natural gas producers in Eastern Kansas and is generally aware
of existing opportunities to enhance many of these properties through the
deployment of capital, and application of enhanced drilling and production
technologies. We believe that we will be able to leverage the experience and
relationships of Mr. Haas to compliment our business strategy. To date, Mr. Haas
has helped us identify and evaluate all of our property acquisitions, and has
been instrumental in the creation and implementation of our development
plans of these properties.





One
of our fundamental goals with respect to the consulting arrangement is to align
the interests of Mr. Haas with those of ours as much as possible. As a result,
the consulting agreement provides that we will pay him five thousand dollars per
month. In addition, we have granted Mr. Haas options to purchase 60,000 shares
of our common stock at an exercise price of $6.25 per share, expiring on May 3,
2011. Finally, we have utilized our common stock, in part, for the purchase of
assets owned by MorMeg, which we believe will further align our business
interests with those of Mr. Haas.


14





Drilling Activity





The
following table sets forth the results of our drilling activities during the
2007, 2008 and 2009 fiscal years.





Drilling ActivityGross Wells
                
                
                Net Wells(1)Fiscal Year
                
                Total
                
                
                Producing
                
                
                Dry
                
                
                Total
                
                
                Producing
                
                
                Dry2007
      Exploratory
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-2008
      Exploratory
                
                
                10
                
                
                
                10
                
                
                
                -0-
                
                
                
                10
                
                
                
                10
                
                
                
                -0-2009
      Exploratory(2)
                
                
                12
                
                
                
                12
                
                
                
                -0-
                
                
                
                12
                
                
                
                12
                
                
                
                -0-2007
      Development
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-2008
      Development
                
                
                59
                
                
                
                57
                
                
                
                2
                
                
                
                58
                
                
                
                56
                
                
                
                22009
      Development
                
                
                96
                
                
                
                95
                
                
                
                1
                
                
                
                96
                
                
                
                95
                
                
                
                1


(1)
            Net
      wells are based on our net working interest as of March 31,
      2009.


(2)
            We
      incurred some exploration costs related to exploratory wells drilled on
      behalf of Euramerica.





Net Production, Average Sales Price
and Average Production and Lifting Costs





The table
below sets forth our net oil and natural gas production (net of all royalties,
overriding royalties and production due to others) for the fiscal years ended
March 31, 2009 and 2008 and 2007, the average sales prices, average
production costs and direct lifting costs per unit of production.





Fiscal Year Ended
                  March 31, 2009
                
                
                Fiscal Year Ended
                  March 31, 2008
                
                
                Fiscal Year Ended
                  March 31,2007Net ProductionOil
      (Bbl)
                
                
                74,289
                
                
                
                43,697
                
                
                
                -0-Natural
      gas (Mcf)
                
                
                12,275
                
                
                
                17,762
                
                
                
                19,254Average
      Sales PricesOil
      (per Bbl)
                
                $
                85.67
                
                
                $
                79.71
                
                
                $
                -0-Natural
      gas (per Mcf)
                
                $
                5.57
                
                
                $
                6.20
                
                
                $
                4.72Average
      Production Cost (1)Per
      Bbl of oil
                
                $
                45.01
                
                
                $
                56.65
                
                
                $
                -0-Per
      Mcf of natural gas
                
                $
                15.11
                
                
                $
                13.12
                
                
                $
                9.55Average
      Lifting Costs (2)Per
      Bbl of oil
                
                $
                33.01
                
                
                $
                37.08
                
                
                $
                -0-Per
      Mcf of natural gas
                
                $
                15.11
                
                
                $
                9.86
                
                
                $
                8.95





(1)
            Production
      costs include all operating expenses, depreciation, depletion and
      amortization, lease operating expenses and all associated taxes.
      Impairment of oil and natural gas properties is not included in production
      costs.


(2)
            Direct
      lifting costs do not include impairment expense or depreciation, depletion
      and amortization.


15





Results of Oil and Natural Gas
Producing Activities





The
following table shows the results of operations from our oil and natural gas
producing activities from fiscal years ended March 31, 2007 through March
31, 2009. Results of operations from these activities have been determined using
historical revenues, production costs, depreciation, depletion and amortization
of the capitalized costs subject to amortization. General and administrative
expenses and interest expense have been excluded from this
determination.




For the
                      Fiscal Year
                      Ended
                      March 31, 2009
                    
                    
                    For the
                      Fiscal Year
                      Ended
                      March 31, 2008
                    
                    
                    For the
                      Fiscal Year
                      Ended
                      March 31, 2007Production
      revenues
                    
                    $
                    6,436,805
                    
                    
                    $
                    3,602,798
                    
                    
                    $
                    90,800Production
      costs
                    
                    
                    (2,637,333
                    )
                    
                    
                    (1,795,188
                    )
                    
                    
                    (172,417
                    )Depreciation,
      depletion and amortization
                    
                    
                    (872,230
                    )
                    
                    
                    (913,224
                    )
                    
                    
                    (11,477
                    )Results
      of operations for producing activities
                    
                    $
                    2,972,242
                    
                    
                    $
                    894,386
                    
                    
                    $
                    (93,094
                    )





Producing Wells





The
following table sets forth the number of productive oil and natural gas wells in
which we owned an interest as of March 31, 2009.





ProducingProject
                          
                          Gross Oil
                          
                          
                          Net Oil(1)
                          
                          
                          Gross
                            Natural
                            Gas
                          
                          
                          Net
                            Natural
                            Gas(1)Black
      Oaks Project
                          
                          
                          62
                          
                          
                          
                          59
                          
                          
                          
                          -0-
                          
                          
                          
                          -0-Thoren
      Project
                          
                          
                          33
                          
                          
                          
                          33
                          
                          
                          
                          -0-
                          
                          
                          
                          -0-DD
      Energy Project
                          
                          
                          114
                          
                          
                          
                          114
                          
                          
                          
                          -0-
                          
                          
                          
                          -0-Tri-County
      Project
                          
                          
                          170
                          
                          
                          
                          170
                          
                          
                          
                          -0-
                          
                          
                          
                          -0-Gas
      City Project
                          
                          
                          -0-
                          
                          
                          
                          -0-
                          
                          
                          
                          22
                          
                          
                          
                          22Total
                          
                          
                          379
                          
                          
                          
                          376
                          
                          
                          
                          22
                          
                          
                          
                          22


(1)
            Net
      wells are based on our net working interest as of March 31,
      2009.





Reserves





Our
estimated total proved PV10 (present value) before tax of reserves as of March
31, 2009 was $10.63 million, versus $39.6 million as of March 31,
2008.   Though total proved reserves were comparable at March 31,
2009 and 2008; 1.3 million and 1.4 million barrels of oil equivalent (BOE),
respectively, the PV10 declined dramatically due to the estimated average
price of oil at March 31, 2009 of $42.65 versus $94.53 at March 31,
2008.  Of the 1.3 million BOE at March 31, 2009 approximately 39% are
proved developed and approximately 61% are proved undeveloped. The proved
developed reserves consist of proved developed producing (82%) and proved
developed non-producing (18%). See “Glossary” on page 23 for our definition
of PV10.





Based on
an estimated oil price of $42.65 as of March 31, 2009, and applying an annual
discount rate of 10% of the future net cash flow, the estimated PV10 of the 1.3
million BOE, before tax, is calculated as set forth in the following
table:


16





Summary
of Oil and Natural Gas Reserves


as
of March 31, 2009





Proved Reserves
                    Category
                  
                  Gross
                    STB(1)
                  
                  
                  Net
                    STB(2)
                  
                  
                  Gross
                    MCF(3)
                  
                  
                  Net
                    MCF(4)
                  
                  
                  PV10(5)
                    (before tax)Proved,
      Developed Producing
                  
                  
                  722,590
                  
                  
                  
                  429,420
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  $
                  6,691,550Proved,
      Developed Non-Producing
                  
                  
                  146,620
                  
                  
                  
                  95,560
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1,459,280Proved,
      Undeveloped
                  
                  
                  1,440,760
                  
                  
                  
                  811,650
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,478,510Total
      Proved
                  
                  
                  2,309,970
                  
                  
                  
                  1,336,630
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  $
                  10,629,340


(1)
            STB
      = one stock-tank barrel.


(2)
            Net STB is based upon our net
      revenue interest, including any applicable reversionary
      interest.


(3)
            MCF = thousand cubic feet of
      natural gas.  There we no natural gas reserves at March 31,
      2009.


(4)
            Net MCF is based upon our net
      revenue interest.  There we no natural gas reserves at March 31,
      2009.


(5)
            See
      “Glossary” on page 23 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 57, for a reconciliation to the comparable
      GAAP financial measure.





Oil and Natural Gas Reserves Reported
to Other Agencies





We did
not file any estimates of total proved net oil or natural gas reserves with, or
include such information in reports to, any federal authority or agency, other
than the SEC, during the fiscal year ended March 31, 2009.





Title to
Properties





Our
properties are subject to customary royalty interests, liens under indebtedness,
liens incident to operating agreements and liens for current taxes and other
burdens, including mineral encumbrances and restrictions. Further, our debt is
secured by first and second liens substantially on all of our assets. These
burdens have not materially interfered with the use of our properties in the
operation of our business to date, though there can be no assurance that such
burdens will not materially impact our operations in the future.





We
believe that we have satisfactory title to or rights in all of our producing
properties. As is customary in the natural gas and oil industry, minimal
investigation of title is made at the time of acquisition of undeveloped
properties. In most cases, we investigate title and obtain title opinions from
counsel or have title reviewed by professional landmen only when we acquire
producing properties or before we begin drilling operations. However, any
acquisition of producing properties without obtaining title opinions are subject
to a greater risk of title defects.


17


Sale of Natural Gas and
Oil





We do not
intend to refine our natural gas or oil production. We expect to sell all or
most of our production to a small number of purchasers in a manner consistent
with industry practices at prevailing rates by means of long-term and short-term
sales contracts, some of which may have fixed price components. We have a
long-term purchase contract with Shell to sell all of our current oil production
beginning April 1, 2008 through September of 2009.  We also have an
ISDA master agreement and a fixed price swap with BP beginning October 1,
2009 through December 31, 2013. Under current conditions, we should be able
to find other purchasers, if needed. All of our produced oil is held in tank
batteries and then each respective purchaser transports the oil by truck to the
refinery. In addition, our board of directors has implemented a crude oil and
natural gas hedging strategy that will allow management to hedge up to 80% of
our net production in an effort to mitigate a majority of our exposure to
changing oil prices in the intermediate term.





Secondary Recoveryand Other Production Enhancement
Strategies





When an
oil field is first produced, the oil typically is recovered as a result of
natural pressure within the producing formation, often assisted by pumps of
various types. The only natural force present to move the crude oil to the
wellbore is the pressure differential between the higher pressure in the
formation and the lower pressure in the wellbore. At the same time, there are
many factors that act to impede the flow of crude oil, depending on the
nature of the formation and fluid properties, such as pressure,
permeability, viscosity and water saturation. This stage of production is
referred to as “primary production,” which in Eastern Kansas normally only
recovers up to 15% of the crude oil originally in place in a producing
formation.





Many, but
not all, oil fields are amenable to assistance from a waterflood, a form of
“secondary recovery,” which is used to maintain or increase reservoir pressure
and to help sweep oil to the wellbore. In a waterflood, certain wells are used
to inject water into the reservoir while other wells are used to recover the oil
in place.  We utilize waterflooding as a secondary recovery technique for
the majority of our oil field projects.





As the
waterflood matures, the fluid produced contains increasing amounts of water and
decreasing amounts of oil. Surface equipment is used to separate the oil from
the water, with the oil going to holding tanks for sale and the water being
recycled to the injection facilities. In the Black Oaks Project, we realized an
initial increase of approximately 20 barrels per day in oil production as a
result of the waterflood pilot program.





In
addition, we may utilize 3-D seismic analysis, horizontal drilling, and other
technologies and production techniques to improve drilling results and
ultimately enhance our production and returns. We also believe use of such
technologies and production techniques in exploring for, developing and
exploiting oil and natural gas properties will help us reduce drilling risks,
lower finding costs and provide for more efficient production of oil and natural
gas from our properties.





Markets and
Marketing





The
natural gas and oil industry has experienced dramatic price volatility in recent
years, and especially in recent months. As a commodity, global natural gas and
oil prices respond to macro-economic factors affecting supply and demand. In
particular, world oil prices have risen and fallen in response to political
unrest and supply uncertainty in the United States, Iraq, Venezuela, Nigeria,
Russia and Iran, and changing demand for energy in rapidly growing economies,
notably India and China. North American prospects have become more attractive as
efforts to stimulate the US economy and reduce dependence on foreign oil
increase. Escalating conflicts in the Middle East and the ability of OPEC to
control supply and pricing are some of the factors impacting the availability of
global supply. The costs of steel and other products used to construct drilling
rigs and pipeline infrastructure, as well as drilling and well-servicing
rig rates, are impacted by the commodity price volatility.


18





Our
market is affected by many factors beyond our control, such as the availability
of other domestic production, commodity prices, the proximity and capacity of
natural gas and oil pipelines, and general fluctuations of global and domestic
supply and demand. We have entered into two sales contracts (with Shell and BP)
at this time, and we do not anticipate difficulty in finding additional sales
opportunities, as and when needed.





Natural
gas and oil sales prices are negotiated based on factors such as the spot price
for natural gas or posted price for oil, price regulations, regional price
variations, hydrocarbon quality, distances from wells to pipelines, well
pressure, and estimated reserves. Many of these factors are outside our control.
Natural gas and oil prices have historically experienced high volatility,
related in part to ever-changing perceptions within the industry of future
supply and demand.





Competition





The
natural gas and oil industry is intensely competitive and we must compete
against larger companies that may have greater financial and technical resources
than we do and substantially more experience in our industry. These competitive
advantages may better enable our competitors to sustain the impact of higher
exploration and production costs, natural gas and oil price volatility,
productivity variances between properties, overall industry cycles and other
factors related to our industry. Their advantage may also negatively impact our
ability to acquire prospective properties, develop reserves, attract and retain
quality personnel and raise capital.





Research
and Development Activities





We have not spent any material amount
of time in the last two fiscal years on research and development
activities.





Governmental
Regulations





Regulation of Oil and Natural Gas
Production.  Our oil and natural gas exploration, production
and related operations, when developed, are subject to extensive rules and
regulations promulgated by federal, state, tribal and local authorities and
agencies. For example, some states in which we may operate, including Kansas,
require permits for drilling operations, drilling bonds and
reports concerning operations and impose other requirements relating to the
exploration and production of oil and natural gas. Such states may 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 wells, and the regulation of
spacing, plugging and abandonment of such wells. Failure to comply with any such
rules and regulations can result in substantial penalties. Moreover, such
states may place burdens from previous operations on current lease owners, and
the burdens could be significant. The regulatory burden on the oil and natural
gas industry will most likely increase our cost of doing business and may affect
our profitability. Although we believe we are currently in substantial
compliance with all applicable laws and regulations, because such rules and
regulations are frequently amended or reinterpreted, we are unable to predict
the future cost or impact of complying with such laws. Significant expenditures
may be required to comply with governmental laws and regulations and may have a
material adverse effect on our financial condition and results of
operations.


19




Federal Regulation
of Natural Gas.The Federal Energy
Regulatory Commission (“FERC”) regulates interstate natural gas
transportation rates and service conditions, which may affect the marketing of
natural gas produced by us, as well as the revenues that may be received by us for sales of such
production. Since the mid-1980’s, FERC has issued a series of orders,
culminating in Order Nos. 636, 636-A and 636-B (“Order 636”), that have
significantly altered the marketing and transportation of natural gas. Order 636
mandated a fundamental restructuring of interstate pipeline sales and
transportation service, including the unbundling by interstate pipelines of the
sale, transportation, storage and other components of the city-gate sales
services such pipelines previously performed. One of FERC’s purposes in issuing
the order was to increase competition within all phases of the natural gas
industry. The United States Court of Appeals for the District of Columbia
Circuit largely upheld Order 636 and the Supreme Court has declined to hear the
appeal from that decision. Generally, Order 636 has eliminated or substantially
reduced the interstate pipelines’ traditional role as wholesalers of natural gas
in favor of providing only storage and transportation service, and has
substantially increased competition and volatility in natural gas
markets.





The price we may receive from the sale
of oil and natural gas liquids will be affected by the cost of transporting
products to markets. Effective January 1, 1995, FERC implemented regulations establishing an
indexing system for transportation rates for oil pipelines, which, generally,
would index such rates to inflation, subject to certain conditions and
limitations. We are not able to predict with certainty the effect, if
any,of these regulations on our intended
operations. However, the regulations may increase transportation costs or reduce
well head prices for oil and natural gas liquids.





Environmental
Matters





Our operations and properties are
subject to extensive andchanging federal, state and local laws
and regulations relating to environmental protection, including the generation,
storage, handling, emission, transportation and discharge of materials into the
environment, and relating to safety and health. The recent trend in environmental legislation and
regulation generally is toward stricter standards, and this trend will likely
continue.





These laws and regulations
may:





·
            require the acquisition of a
      permit or other authorization before construction or drilling commences
      and for certain other
activities;





·
            limit or prohibit construction,
      drilling and other activities on certain lands lying within wilderness and
      other protected
      areas; and


20





·
            impose substantial liabilities for
      pollution resulting from its operations, or due to previous operations
      conducted on any leased
lands.





The permits required for our operations
may be subject to revocation, modification and renewalby issuing authorities. Governmental
authorities have the power to enforce their regulations, and violations are
subject to fines or injunctions, or both. In the opinion of management, we are
in substantial compliance with current applicable environmentallaws and regulations, and 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
significantimpact on us, as well as the oil and
natural gas industry in general.





The Comprehensive Environmental,
Response, Compensation, and Liability Act, as amended (“CERCLA”), and comparable state statutes impose
strict, joint and several liability on owners and operators of 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 land owners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous
substances released into the environment. The Federal Resource Conservation and
Recovery Act, as amended (“RCRA”), and comparable state statutes govern
the disposal of “solid
waste”and “hazardous waste”and authorizethe imposition of substantial fines and
penalties for noncompliance. Although CERCLA currently excludes petroleum from
its definition of “hazardous substance,”state laws affecting our operations may
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.





The Federal Water Pollution Control Act
of 1972, as amended (“Clean
Water Act”), and analogous
state laws impose restrictions and controls on the discharge of pollutants into
federal and state waters. These laws also regulate the discharge of storm water in process areas.
Pursuant to these laws and regulations, we are required to obtain and maintain
approvals or permits for the discharge of wastewater and storm water and develop
and implement spill prevention, control and countermeasure plans, also referred to as
“SPCC plans,”in connection with on-site
storage of greater than threshold quantities of oil. The EPA issued revised SPCC
rules in July 2002 whereby SPCC plans are subject to more rigorous review and
certification procedures. We believe that our operations are in substantial
compliance with applicable Clean Water Act and analogous state requirements,
including those relating to wastewater and storm water discharges and SPCC
plans.





The Endangered Species Act, as amended
(“ESA”), seeks to ensure that activities do
not jeopardize endangered or threatened animal, fish and plant species, nor
destroy or modify the critical habitat of such species. Under ESA, exploration
and production operations, as well as actions by federal agencies, may not significantly impair or
jeopardize the species or its habitat. ESA provides for criminal penalties for
willful violations of the Act. Other statutes that provide protection to animal
and plant species and that may apply to our operations include, but are not necessarily limited to,
the Fish and Wildlife Coordination Act, the Fishery Conservation and Management
Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.
Although we believe that our operations will be in substantial compliance with such statutes,
any change in these statutes or any reclassification of a species as endangered
could subject us to significant expenses to modify our operations or could force
us to discontinue certain operations altogether.


21




Personnel





As of March 31, 2009, we had14full-time employees, an increase from 9 full time employees
at our fiscal year ended March 31, 2008.  We hired a number of former
independent fieldcontractors to help secure
a more stable work base during the months where extremely high oil prices could
have limited our access toproducts and services needed to develop
and operate our properties.Since November 2008, we have
reduced personnel levels by 5 full time employees and one independent contractor
in response to declining
economic conditions and in an effort to reduce our operating and generalexpenses,and cash outlay.As productionand drillingactivities increaseor decrease, wemay have to adjust ourtechnical, operational and
administrative personnel asappropriate. We are using and will continue to useindependent consultants and contractors
to perform various professional services, particularly in the area of land
services, reservoir engineering, geology drilling, water hauling, pipeline
construction,well design,
well-site monitoring and surveillance, permitting and environmental assessment.
We believe that this use of third-party service providers may enhance our
ability to containoperating andgeneral expenses, and capital costs.





Facilities





We
currently lease our executive offices at 27 Corporate Woods, Suite
350, 10975 Grandview Drive, Overland Park, Kansas  66210, whichexpires in September 30, 2013.  Future minimum payments are
$71,180 for the year ending March 31, 2010.


22


GLOSSARY





Term
                                    
                                    DefinitionBarrel
(bbl)
                                    
                                    The standard unit of measurement
      of liquids in the petroleum industry, it contains 42 U.S. standard
      gallons. Abbreviated to “bbl”.Basin
                                    
                                    A depression in the crust of the
      Earth, caused by plate tectonic activity and subsidence,in which sediments accumulate.
      Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can
      be bounded by faults. Rift basins are commonly symmetrical; basins along
      continental margins tend to be asymmetrical. If rich hydrocarbon source
      rocksoccur in combination with
      appropriate depth and duration of burial, then a petroleum system can
      develop within the basin.BOPD
                                    
                                    Abbreviation for barrels of oil
      per day, a common unit of measurement for volume of crude oil. The volume
      of a barrel is equivalent to 42 U.S. standard
      gallons.Carried Working
      Interest
                                    
                                    The owner of this type of working
      interest in the drilling of a well incurs no capital contribution
      requirement for drilling or completion costs associated with a well and,
      if specified in the particular contract, may not incur
      capital contribution requirements beyond the completion of the
      well.Completion /
      Completing
                                    
                                    A well made ready to produce oil
      or natural gas.Development
                                    
                                    The phase in which a proven oil or
      natural gas field is broughtinto production by drilling
      development wells.Development
      Drilling
                                    
                                    Wells drilled during the
      Development phase.Division
    order
                                    
                                    A directive signed by the royalty
      owners verifying to the purchaser or operator of a well the decimal
      interest of productionowned by the royalty owner. The
      Division Order generally includes the decimal interest, a legal
      description of the property, the operator’s name, and several legal
      agreements associated with the process. Completion of this step generally
      precedes placingthe royalty owner on pay status to
      begin receiving revenue payments.Drilling
                                    
                                    Act of boring a hole through which
      oil and/or natural gas may be produced.Dry Wells
                                    
                                    A well found to be incapable of
      producing hydrocarbons in sufficient quantities such thatproceeds from the sale of such
      production exceed production expenses and taxes.Exploration
                                    
                                    The phase of operations which
      covers the search for oil or natural gas generally in unproven or
      semi-proven
territory.




23





Exploratory
      Drilling
                                        
                                        Drilling of a relatively high percentage of
      properties which are unproven.Farm out
                                        
                                        An arrangement whereby the owner
      of a lease assigns all or some portion of the lease or licenses to another
      company for undertaking exploration or development
      activity.Field
                                        
                                        An area consisting of a single reservoir or
      multiple reservoirs all grouped on, or related to, the same individual
      geological structural feature or stratigraphic condition. The field name
      refers to the surface area, although it may refer to both the surface and
      theunderground productive
      formations.Fixed price
      swap
                                        
                                        A derivative instrument that
      exchanges or “swaps”the “floating”or daily price of a specified
      volume of natural gas, oil or NGL, over a specified period, for a fixed
      price for the specified volume overthe same period (typically three
      months or longer).Gathering line /
      system
                                        
                                        Pipelines and other facilities
      that transport oil or natural gas from wells and bring it by separate and
      individual lines to a central delivery point for delivery into a
      transmission line or
      mainline.Gross acre
                                        
                                        The number of acres in which the
      Company owns any working interest.Gross Producing
      Well
                                        
                                        A well in which a working interest
      is owned and is producing oil or natural gas or other liquids or
      hydrocarbons. The number ofgross producing wells is the total
      number of wells producing oil or natural gas or other liquids or
      hydrocarbons in which a working interest is
  owned.Gross well
                                        
                                        A well in which a working interest
      is owned. The number of gross wells is the total number of wells in which a working
      interest is owned.Held-By-Production
      (HBP)
                                        
                                        Refers to an oil and natural gas
      property under lease, in which the lease continues to be in force, because
      of production from the property.Horizontal
      drilling
                                        
                                        A drilling techniqueused in certain formations where
      a well is drilled vertically to a certain depth and then turned and
      drilled horizontally. Horizontal drilling allows the wellbore to follow
      the desired formation.In-fill
    wells
                                        
                                        In-fill wells refers to wells
      drilled between
      established producing wells; a drilling program to reduce the spacing
      between wells in order to increase production and recovery of in-place
      hydrocarbons.Oil and Natural Gas
      Lease
                                        
                                        A legal instrument executed by a
      mineral owner granting the right to another to explore, drill, and
      produce subsurface oil and natural gas. An oil and natural gas lease
      embodies the legal rights, privileges and duties pertaining to the lessor
      and lessee.Lifting
    Costs
                                        
                                        The expenses of producing oil from
      a well. Lifting costs
      are the operating costs of the wells including the gathering and
      separating equipment. Lifting costs do not include the costs of drilling
      and completing the wells or transporting the
  oil.




24





Mcf
                                      
                                      Thousand cubic
      feet.Mmcf
                                      
                                      Million cubic
      feet.Net acres
                                      
                                      Determined by multiplying gross
      acres by the working interest that the Company owns in such
      acres.Net Producing
      Wells
                                      
                                      The number of producing wells
      multiplied by the working interest in such
wells.Net Revenue
      Interest
                                      
                                      A share of production
      revenues after all
      royalties, overriding royalties and other nonoperating interests have been
      taken out of production for a well(s).Operator
                                      
                                      A person, acting for itself, or as
      an agent for others, designated to conduct the operations on its or the
      joint interest
      owners’behalf.Overriding
      Royalty
                                      
                                      Ownership in a percentage of
      production or production revenues, free of the cost of production, created
      by the lessee, company and/or working interest owner and paid by the
      lessee, company and/or working interest owner out of revenue from the
      well.Pooled Unit
                                      
                                      A term frequently used
      interchangeably with “Unitization”but more properly used to
      denominate the bringing together of small tracts sufficient for the
      granting of a well permit under applicable spacing
      rules.Proved Developed
      Reserves
                                      
                                      Proved reserves that can be
      expected to be recovered from existing wells with existing equipment and
      operating methods. This definition of proved developed reserves has been
      abbreviated from the applicable definitions containedin Rule 4-10(a)(2-4) of
      Regulation
      S-X.Proved Developed
      Non-Producing
                                      
                                      Proved developed reserves expected
      to be recovered from zones behind casings in existing
      wells.Proved Undeveloped
      Reserves
                                      
                                      Proved undeveloped reserves are
      the portion of proved reserves which can be expected to
      be recovered from new wells on undrilled proved acreage, or from existing
      wells where a relatively major expenditure is required for completion.
      This definition of proved undeveloped reserves has been abbreviated from
      theapplicable definitions contained in
      Rule 4-10(a)(2-4) of Regulation
    S-X.PV10
                                      
                                      PV10 means the estimated future
      gross revenue to be generated from the production of proved reserves, net
      of estimated production and future development and abandonment costs,
      using prices and
      costs in effect at the determination date, before income taxes, and
      without giving effect to non-property related expenses, discounted to a
      present value using an annual discount rate of 10% in accordance with the
      guidelines of the SEC. PV10 is a non-GAAP financial measure.
      See “Management’s Discussion and Analysis of
      Financial Condition and Results of Operations-Reserves”onpage57for a reconciliation to the
      comparable GAAP financial
measure.




25





Re-completion
                                    
                                    Completion of an existing
      well for production
      from one formation or reservoir to another formation or reservoir that
      exists behind casing of the same well.Reservoir
                                    
                                    The underground rock formation
      where oil and natural gas has accumulated. It consists of a porous rock to
      hold theoil or
      natural gas, and a cap rock that prevents its
    escape.Reservoir
      Pressure
                                    
                                    The pressure at the face of the
      producing formation when the well is shut-in. It equals the shut-in
      pressure at the wellhead plus the weight of the column of oil and naturalgas in the
      well.Roll-Up
      Strategy
                                    
                                    A “roll-up strategy” is a
      common business term used to describe a business plan whereby a company
      accumulates multiple small operators in a particular business sector with
      a goal to generate synergies, stimulate growth and optimize the value of
      the individual pieces.Secondary
      Recovery
                                    
                                    The stage of hydrocarbon
      production during which an external fluid such as water or natural gas is
      injected into the reservoir through injection wells located in rock that
      has fluid communication with production wells.
      The purpose of secondary recovery is to maintain reservoir pressure and to
      displace hydrocarbons toward the wellbore.
                                      
                                      The most common secondary recovery
      techniques are natural gas injection and waterflooding. Normally,
      natural gas is
      injected into the natural gas cap and water is injected into the
      production zone to sweep oil from the reservoir. A pressure-maintenance
      program can begin during the primary recovery stage, but it is a form of
      enhanced recovery.Shut-in
well
                                    
                                    Awell which is capable of
      producing but is not presently producing. Reasons for a well being shut-in
      may be lack of equipment, market or other.Stock Tank Barrel or
      STB
                                    
                                    A stock tank barrel of oil is the
      equivalent of 42 U.S. Gallons at 60 degrees Fahrenheit.Undeveloped
      acreage
                                    
                                    Lease acreage on which wells have
      not been drilled or completed to a point that would permit the production
      of commercial quantities of oil and natural gas regardless of whether such
      acreage contains proved reserves.Unitize, Unitization
                                    
                                    When owners of oil and/or natural
      gas reservoir pool their individual interests in return for an interest in
      the overall unit.Waterflood
                                    
                                    The injection of water into an oil
      reservoir to “push”additional oil out of the
      reservoir rock and intothe wellbores of producing wells.
      Typically a secondary recovery process.Water Injection
      Wells
                                    
                                    A well in which fluids are
      injected rather than produced, the primary objective typically being to
      maintain or increase reservoir pressure, often pursuant toa
    waterflood.




26





Water Supply
      Wells
                    
                    A well in which fluids are being
      produced for use in a Water Injection Well.Wellbore
                    
                    A borehole; the hole drilled by
      the bit. A wellbore may have casing in it or it may be open (uncased); or
      part of it may be cased,and part of it may be open. Also
      called a borehole or hole.Working
      Interest
                    
                    An interest in an oil and natural
      gas lease entitling the owner to receive a specified percentage of the
      proceeds of the sale of oil and natural gas production or a percentageof the production,
      but requiring the owner of the working interest to bear the cost to
      explore for, develop and produce such oil and natural
      gas.


27




Item
1A. Risk Factors.





Declining economic conditions could
negatively impact our business





Our operations are affected by local, national and
worldwide economic conditions.  Markets in the United States and
elsewhere have been experiencing extreme volatility and disruption for more than
12 months, due in part to the financial stresses affecting the liquidity
ofthe banking system and the financial
markets generally.  In recentmonths, this volatility and disruption has
reached unprecedented levels.  The consequences of a potential or
prolonged recession may include a lower level of economic activity and
uncertainty regarding
energy prices and the capital and commodity markets. While the ultimate outcome
and impact of the current economic conditions cannot be predicted, a lower level
of economic activity might result in a decline in energy consumption, whichmaymateriallyadversely affect the price of oil, our
revenues, liquidity and future growth.  Instability in the financial
markets, as a result of recession or otherwise, also may affect the cost of
capital and our ability to raise capital.





We have sustainedlosses, which raises doubt as to our
ability to successfully develop profitable business
operations.





Our prospects must be considered in
light of the risks, expenses and difficulties frequently encountered in
establishing and maintaining a business in the oil and natural gas industries. There
is nothing conclusive at this time on which to base an assumption that our
business operations will prove to be successful or that we will be able to
operate profitably. Our future operating results will depend on many factors,
including:





·
            thefuture prices of natural gas and
      oil;


·
            ourability to raise adequate working
      capital;


·
            success of our development and
      exploration efforts;


·
            demandfor natural gas and
      oil;


·
            the level of our
      competition;


·
            our ability to attract and maintain key management,
      employees and operators;


·
            transportation
      and processing fees on our
facilities;


·
            fuel conservation
      measures;


·
            alternate fuel
      requirementsor
      advancements;


·
            government regulation and
      taxation;


·
            technical advances in
      fuel economy and
      energy generation devices;
and


·
            our ability to efficiently
      explore, develop and produce sufficient quantities of marketable natural
      gas or oil in a highly competitive and speculative environment while
      maintaining quality and controlling costs.





To achieve profitable operations, we
must, alone or with others, successfully execute on the factors stated above,
along with continually developing ways to enhance our production efforts.
Despite our best efforts, we may not be successful in our development efforts or obtain required
regulatory approvals. There is a possibility that some of our wells may never
produce natural gas or oil in sustainable or economic
quantities.


28





We will need additional capital in the
future to finance our planned growth, which we may not be able to raise or
may only be available on terms unfavorable to us or our stockholders, which may
result in our inability to fund our working capital requirements and harm our
operational results.





We have and expect to continue to
have substantial capital
expenditure and working capital needs. We will need to rely on cash flow from
operations and borrowings under our Credit Facility or raise additional cash to
fund our operations, pay outstanding long-term debt, fund our anticipatedreserve replacement needs and implement
our growth strategy, or respond to competitive pressures and/or perceived
opportunities, such as investment, acquisition, exploration, work-over and
development activities.





If low natural gas and oil prices,
operatingdifficulties, constrained capital
sourcesorother factors, many of which are beyond
our control, cause our revenues or cash flows from operations to decrease, we
may be limited in our ability to spend the capital necessary to complete our
development, production
exploitation and exploration programs. If our resources or cash flows do not
satisfy our operational needs, we will require additional financing, in addition
to anticipated cash generated from our operations, to fund our planned growth.
Additional financing might not be available on
terms favorable to us, or at all. If adequate funds were not available or were
not available on acceptable terms, our ability to fund our operations, take
advantage of opportunities, develop or enhance our business orotherwise respond to competitive
pressures would be significantly limited.In such a capital restricted situation,
we may curtail our acquisition, drilling, development, and exploration
activities or be forced to sell some of our assets on an untimely or
unfavorable
basis.  Our
current plans to address lower crude and natural gas prices are primarily to
reduce both capital and operating expenditures to a level equal to or below cash
flow from operations.  However, our plans may not be successful in
improving our results of
operations and liquidity.





If we raise additional funds through the
issuance of equity or convertible debt securities, the percentage ownership of
our stockholders would be reduced, and these newly issued securities might have
rights, preferences or
privileges senior to those of existing stockholders.





Our
auditor’s report reflects the fact that without realization of additional
capital, it would be unlikely for us to continue as a going
concern.





As a
result of our deficiency in working capital at March 31, 2009 and other factors,
our auditors have included a paragraph in their audit report regarding
substantial doubt about our ability to continue as a going concern. Our plans in
this regard are to increase production, seek strategic alternatives and to seek
additional capital through future equity private placements or debt
facilities.





Natural gas and oil prices are volatile.
This volatility may occur in the future, causing negative change in cash flows
which may result in our inability to cover our operating or capital
expenditures.


29


Our future revenues, profitability,
future growth and the carrying value of our properties is anticipated to depend
substantially on the prices we may realize for our natural gas and oil
production. Our realized
prices may also affect the amount of cash flow available for operating or
capital expenditures and our ability to borrow and raise additional
capital.





Natural gas and oil prices are subject
to wide fluctuations in response to relatively minor changesin or perceptions regarding supply and
demand. Historically, the markets for natural gas and oil have been volatile,
and they are likely to continue to be volatile in the future. Among the factors
that can cause this volatility are:





·
            local, national andworldwide economic
      conditions;


·
            worldwide or regional demand for
      energy, which is affected by economic
  conditions;


·
            the domestic and foreign supply of
      natural gas and oil;


·
            weather
      conditions;


·
            natural
      disasters;


·
            acts of
      terrorism;


·
            domestic and foreign governmental regulations and
      taxation;


·
            political and economic conditions
      in oil and natural gas producing countries,including those in the
      Middle East and South America;


·
            impact
      of the U.S. dollar exchange rates on oil and natural gas
      prices;


·
            the availability of refining
      capacity;


·
            actions of the Organization of
      Petroleum Exporting Countries, or OPEC, and other state controlled oil
      companies relating to oil price and production controls;
      and


·
            the price and availability of
      other fuels.





It is impossible to predict natural gas and oil
price movements with certainty. Lower natural gas and oil prices may not only
decrease our future revenues on a per unit basis but also may reduce the amount
of natural gas and oil that we can produce economically.A substantial or extended decline in
natural gas and oil prices may materially and adversely affect our future
business enough to force us to cease our business operations. In addition, our
reserves, financial condition, results of operations, liquidity and ability to finance and execute planned
capital expenditures will also suffer in such a price decline. Further, natural
gas and oil prices do not necessarily move together.





Approximately68% of our total proved reserves as of
March 31, 2009consist of undeveloped and developed non-producing
reserves, and those reserves may not ultimately be developed or
produced.





Our
estimated total proved PV 10 (present value) before tax of reserves as of March
31, 2009 was $10.63 million, versus $39.6 million as of March 31,
2008.   The decline in PV10 is primarily due to the estimated
average price of oil at March 31, 2009 of $42.65 versus $94.53 at March 31,
2008.  We developed total proved reserves to 1.3 million barrels of oil equivalent, or
BOE, as of March 31, 2009.
Of the1.3million BOE of total proved reserves,
approximately39% are proved developed and approximately61% are proved undeveloped. The proved
developed reserves consist of82% proved developed producing reserves
and18% proved developed
non-producingreserves.  See “Glossary”onpage 23for our definition of
PV10.


30


As ofMarch 31,2009, approximately61% of our total proved reserves were
undeveloped and approximately7% were developed non-producing. We plan
to develop and produce all of our proved reserves, but ultimately some of these
reserves may not be developed orproduced. Furthermore, not all of our
undeveloped or developed non-producing reserves may be ultimately produced in
the time periods we have planned, at the costs we have budgeted, or
atall.





Because we face uncertainties in
estimating proven recoverable reserves, you should not place undue reliance on
such reserve information.





Our reserve estimate and the future net
cash flows attributable to those reservesat March 31, 2009 was prepared by Miller and Lents, Ltd., an independent petroleum
consultant.  Prior to this fiscal year,
our reserves were evaluated and estimates wereprepared by McCune Engineering,anindependent petroleum and geological
engineer. There are numerous uncertaintiesinherent in estimating quantities of
proved reserves and cash flows from such reserves, including factors beyond our
control and the control ofthese independent consultants and engineers. Reserve engineering is a subjective
process of estimating underground accumulations of natural gas and oil
that can be economically extracted, which cannot be measured in an exact manner.
The accuracy of an estimate of quantities of reserves, or of cash flows
attributable to these reserves, is a function of the availabledata, assumptions regarding future
natural gas and oil prices, expenditures for future development and exploitation
activities, and engineering and geological interpretation and judgment. Reserves
and future cash flows may also be subject to material downward or upward revisions based upon
production history, development and exploitation activities and natural gas and
oil prices. Actual future production, revenue, taxes, development expenditures,
operating expenses, quantities of recoverable reserves andvalue of cash flows from those reserves
may vary significantly from the assumptions and estimates in our reserve
reports. Any significant variance from these assumptions to actual figures could
greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and
oil attributable to any particular group of properties, the classification of
reserves based on risk of recovery, and estimates of the future net cash flows.
In addition, reserve engineers may make different estimatesof reserves and cash flows based on the
same available data. The estimated quantities of proved reserves and the
discounted present value of future net cash flows attributable to those reserves
included in this report were prepared byMiller and Lents, Ltd.in accordance with rules of the
Securities and Exchange Commission, or SEC, and are not intended to represent
the fair market value of such reserves.





The present value of future net cash
flows from our proved reserves is not necessarily the same as thecurrent market value of our estimated
reserves. We base the estimated discounted future net cash flows from our proved
reserves on prices and costs. However, actual future net cash flows from our
natural gas and oil properties also will be affected by factors such as:





·
            geological
      conditions;


·
            assumptions governing
      future oil and natural gas prices;


·
            amount
      and timing of actual production;


·
            availability
      of funds;


·
            future
      operating and development
costs;


31





·
            actual
      prices we receive for natural gas and
oil;


·
            supply
      and demand for our natural gas and
oil;


·
            changes
      in government regulations and taxation;
and


·
            capital
      costs of drilling new wells.





The timing of both our production and
our incurrence of expenses in connection with the development and production of
ourproperties will affect
the timing of actual future net cash flows from proved reserves, and thus their
actual present value. In addition, the 10% discount factor we use when
calculating discounted future net cash flows may not be the most appropriate
discount factor based on interest rates in
effect from time to time and risks associated with our business or the natural
gas and oil industry in general.





Currently, The SEC permits natural gas
and oil companies, in their public filings, to disclose only proved reserves
that a company has demonstrated by actual production or conclusive formation
tests to be economically and legally producible under existing economic and
operating conditions. These current SEC guidelines strictly prohibit us from
including “probable reserves” and “possible reserves” in such filings.Effective January 1, 2010,however,theSEC is adopting revisions to its oil and
gas reporting disclosures which are intended to provide investors with a more
meaningful and comprehensive understanding of oil and gas reserves, which should
help investors evaluate the relative value of oil and gas companies. Oil and gas
companies will be permitted, but not required, to disclose probable reserves
(i.e., reserves less likely to be recovered than proved reserves, but as likely
as not to be recovered) and possible reserves (i.e., reserves less certain to be
recovered than probable reserves).We also caution you that the SEC has, in
the past, viewed such probable and possible reserve estimates as inherently
unreliable and these estimates may be seen as misleading to investors unless the
reader is an expert in the natural gas and oil industry. Unless you have such
expertise, you should not place undue reliance on these estimates.Potential investors should also be aware
that such “probable” and “possible” reserve estimates will not be contained in
any filing with the SEC, any “resale” or other registration statement filed by
us that offers or sells shares on behalf of purchasers of our common stock and
may have an impact on the valuation of the resale of the shares until permitted
by SEC rules. Except as required by applicable law, we undertake no duty to
update this information.





The differential between the New York
Mercantile Exchange, or NYMEX, or other benchmark price of oil and natural gas and
the wellhead price we receive could have a material adverse effect on our
results of operations, financial condition and cash flows.





The prices that we receive
forour oil and natural gas productiontypicallytrade at a discount to the relevant benchmark
prices, such as NYMEX, that are used for calculating hedge positions. The
difference between the benchmark price and the price we receive is called a
differential.While we have
fixed this differential under the termsof our agreement with Shell through
September 31, 2009,the
differential on physical sales after that dateis still under negotiation.Wecannot accurately predict oil and
natural gas differentials. In recent years forexample, production increases fromcompeting Canadian and
Rocky Mountain producers, in conjunction with limited refining and pipeline
capacity from the Rocky Mountain area, have gradually widened this differential.Recent economic conditions,
including volatility in the price of oil and natural gas,have resulted in both increases and
decreasesin the
differential between the benchmark price for oil and natural gas and the
wellhead price we receive.  These
fluctuationscould have a
material adverse effect on our results of operations, financial condition and cash flows by
decreasing the proceeds we receive for our oil and natural gas production in
comparison to what we would receive if not for the
differential.


32





The natural gas and oil business
involves numerous uncertainties and operating risks that can prevent us from realizing
profits and can cause substantial losses.





Our development, exploitation and
exploration activities may be unsuccessful for many reasons, including weather,
cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling
of a natural gas and oil well does not ensure a profit on investment. A variety
of factors, both geological and market-related, can cause a well to become
uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our
efforts to replace reserves.





The natural gas and oil business
involves a variety of operating risks, including:





·
            unexpectedoperational events and/or
      conditions;


·
            unusual or unexpected geological
      formations;


·
            reductions in natural gas and oil
      prices;


·
            limitations in the market for oil
      and natural gas;


·
            adverse weather
      conditions;


·
            facility
      or equipment malfunctions;


·
            title
    problems;


·
            natural gas and oil quality
      issues;


·
            pipe, casing, cement or pipeline
      failures;


·
            natural
      disasters;


·
            fires, explosions, blowouts,
      surface cratering, pollution and other risks or
      accidents;


·
            environmental hazards, such as
      natural gas leaks,
      oil spills, pipeline ruptures and discharges of toxic
      gases;


·
            compliance with environmental and
      other governmental requirements;
and


·
            uncontrollable flows of oil,
      natural gas or well fluids.





If we experience any of these problems,
it could affect well bores,
gathering systems and processing facilities, which could adversely affect our
ability to conduct operations. We could also incur substantial losses as a
result of:





·
            injuryor loss of
      life;


·
            severe damage to and destruction
      of property, natural
      resources and equipment;


·
            pollution and other environmental
      damage;


·
            clean-up
      responsibilities;


·
            regulatory investigation and
      penalties;


33





·
            suspension of our operations;
      and


·
            repairs to resume
      operations.





Because we use third-party
drilling contractors to
drill our wells, we may not realize the full benefit of worker compensation laws
in dealing with their employees. Our insurance does not protect us against all
operational risks. We do not carry business interruption insurance at levelsthat would provide enough funds for us to
continue operating without access to other funds. For some risks, we may not
obtain insurance if we believe the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks generally are not
fully insurable. If a significant accident or other event occurs and is not
fully covered by insurance, it could impact our operations enough to force us to
cease our operations.





Drilling wells is speculative, often
involving significant costs
that may be more than our estimates, and may not result in any addition to our
production or reserves. Any material inaccuracies in drilling costs, estimates
or underlying assumptions will materially affect our
business.





Developing and exploring for natural gas and oil
involves a high degree of operational and financial risk, which precludes
definitive statements as to the time required and costs involved in reaching
certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and
can increase significantly when drilling costs rise due to a tightening in the
supply of various types of oilfield equipment and related services. Drilling may
be unsuccessful for many reasons, including geologicalconditions, weather, cost overruns,
equipment shortages and mechanical difficulties. Moreover, the successful
drilling of a natural gas or oil well does not ensure a profit on investment.
Exploratory wells bear a much greater risk of loss than developmentwells.Substantially all of our wells drilled
throughMarch 31, 2009have been development
wells. Avariety of
factors, both geological and market-related, can cause a well to become
uneconomical or only marginally economic. Our initial drilling and
development sites, and any
potential additional sites that may be developed, require significant additional
exploration and development, regulatory approval and commitments of resources
prior to commercial development. If our actual drilling and development
costs are significantly more than our
estimated costs, we may not be able to continue our business operations as
proposed and would be forced to modify our plan of
operation.





Development of our reserves, when
established, may not occur
as scheduled and the actual
results may not be as anticipated. Drilling activity andlack ofaccess toeconomically acceptablecapital may result in downward
adjustments in reserves or higher than anticipated costs. Our estimates will be
based on various assumptions, including assumptions over which we have control
and assumptions required by the SEC relating to natural gas and oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. We have control over our operations that affect, amongother things, acquisitions and
dispositions of properties, availability of funds, use of applicable
technologies, hydrocarbon recovery efficiency, drainage volume and production
decline rates that are part of these estimates and assumptions and any
variance in our operations that affects these
items within our control may have a material effect on reserves.  The
process of estimating our natural gas and oil reserves is extremely complex, and
requiressignificant decisions and assumptions
in the evaluationof
available geological, geophysical, engineering and economic data for each
reservoir. Ourestimates
may not be reliable enough to allow us to be successful in our intended business
operations. Our actual production, revenues, taxes, development
expenditures and operating
expenses will likely vary from those anticipated. These variances may be
material.


34





Unless we replace our oil and natural
gas reserves, our reserves and production will decline, which would adversely
affect our cash flows and income.





Unless we conduct successful development,
exploitation and exploration activities or acquire properties containing proved
reserves, our proved reserves will decline as those reserves are produced.
Producing oil and natural gas reservoirs generally are characterized by declining production rates
that vary depending upon reservoir characteristics and other factors. Our future
oil and natural gas reserves and production, and, therefore our cash flow and
income, are highly dependent on our success in efficientlydeveloping and exploiting our current
reserves and economically finding or acquiring additional recoverable reserves.
We may be unable to make such acquisitions because we are:





·
            unable to identify attractive
      acquisition candidates or negotiate acceptablepurchase contracts with
      them;


·
            unable
      to obtain financing for these acquisitions on economically acceptable
      terms;or


·
            outbid by
      competitors.





If we are unable to develop, exploit,
find or acquire additional reserves to replace our current and future
production, our cash flow
and income will decline as production declines, until our existing properties
would be incapable of sustaining commercial production.





A significant portion of our potential
future reserves and our business plan depend upon secondary recovery techniques to establish
production. There are significant risks associated with such
techniques.





We anticipate that a significant portion
of our future reserves and our business plan will be associated with secondary
recovery projects that areeither in theearlystage of implementation or are scheduled
for implementationsubject
to availability of capital.
We anticipate that secondary recovery will affect our reserves and our business
plan, and the exact project initiation dates and, by the very nature of waterflood operations, the
exact completion dates of such projects are uncertain. In addition, the reserves
and our business plan associated with these secondary recovery projects, as with
any reserves, are estimates only, as the success of anydevelopment project, including these
waterflood projects, cannot be ascertained in advance. If we are not successful
in developing a significant portion of our reserves associated with secondary
recovery methods, then the project may be uneconomic or generate less cash flow and reserves than we
had estimated prior to investing the capital. Risks associated with secondary
recovery techniques include, but are not limited to, the
following:





·
            higher than projected operating
      costs;


·
            lower-than-expected
      production;


35





·
            longerresponse
      times;


·
            higher costs associated with
      obtaining capital;


·
            unusual or unexpected geological
      formations;


·
            fluctuations in natural gas and
      oil prices;


·
            regulatory
  changes;


·
            shortages of equipment;
      and


·
            lack of technical
      expertise.





If any of these risks occur, it could
adversely affect our financial condition or results of
operations.





Any acquisitions we complete are subject
to considerable risk.





Even when wemake acquisitions that we believe are
good for our business, any acquisition involves potential risks, including,
among other things:





·
            the validity of our assumptions
      about reserves, future production, revenues and costs, including
      synergies;


·
            an inability to integrate successfully the
      businesses we acquire;


·
            a decrease in our liquidity by
      using our available cash or borrowing capacity to finance
      acquisitions;


·
            a significant increase in our
      interest expense or financial leverage if we incur additionaldebt to finance
      acquisitions;


·
            the assumption of unknown
      liabilities, losses or costs for which we are not indemnified or for which
      our indemnity is inadequate;


·
            the diversion of
      management’s attention from other business
      concerns;


·
            aninability to hire, train or retain qualified
      personnel to manage the acquired properties or
    assets;


·
            the incurrence of other
      significant charges, such as impairment of goodwill or other intangible
      assets, asset devaluation or restructuring
  charges;


·
            unforeseen difficulties encountered in operating in new
      geographic or geological areas;
and


·
            customer or key employee losses at
      the acquired businesses.





Our decision to acquire a property will
depend in part on the evaluation of data obtained from production reports and
engineering studies,
geophysical and geological analyses and seismic and other information, the
results of which are often incomplete or inconclusive.





Our reviews of acquired properties can
be inherently incomplete because it is not always feasible to
performan in-depth review
of the individual properties involved in each acquisition. Even a detailed
review of records and properties may not necessarily reveal existing or
potential problems, nor will it permit a buyer to become sufficiently familiar
with theproperties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well, and environmental problems, such as ground water contamination, plugging
or orphaned well liability are not necessarily observable even whenan inspection is
undertaken.


36


We must obtain governmental permits and
approvals for drilling operations, which can result in delays in our operations,
be a costly and time consuming process, and result in restrictions on our
operations.





Regulatory authorities exercise considerable discretion in
the timing and scope of permit issuances in the region in which we operate.
Compliance with the requirements imposed by these authorities can be costly and
time consuming and may result in delays in the commencementor continuation of our exploration or
production operations and/or fines. Regulatory or legal actions in the future
may materially interfere with our operations or otherwise have a material
adverse effect on us. In addition, we are often required to prepare and present to federal, state or
local authorities data pertaining to the effect or impact that a proposed
project may have on the environment, threatened and endangered species, and
cultural and archaeological artifacts. Accordingly, the permits we
need may not be issued, or if issued, may
not be issued in a timely fashion, or may involve requirements that restrict our
ability to conduct our operations or to do so profitably.





Due to our lack of geographic
diversification, adverse developments in our operating areas would materially affect
our business.





We currently only lease and operate oil
and natural gas properties located in Eastern Kansas. As a result of this
concentration, we may be disproportionately exposed to the impact of delays or
interruptions of production
from these properties caused by significant governmental regulation,
transportation capacity constraints, curtailment of production, natural
disasters, adverse weather conditions or other events which impact this
area.





We depend on a small number of customers for all, or a
substantial amount of our sales. If these customers reduce the volumes of oil
and natural gas they purchase from us, our revenue and cash available for
distribution will decline to the extent we are not able to find newcustomers for our
production.





We have contracted with Shell for the
sale of all of our oil through September 2009 and will likely contract for the
sale of our natural gas with one, or a small number, of buyersif and when we resume operations on the
GasCity
Project. It is not likely
that there will be a large pool of available purchasers. If a key purchaser were
to reduce the volume of oil or natural gas it purchases from us, our revenue and
cash available for operations will decline to the extent we arenot able to find new customers to
purchase our production at equivalent prices.





We are not the operator of some of our
properties and we have limited control over the activities on those
properties.





We are not the operator on our Black
Oaks Project. Wehave only
limited ability to influence or control the operation or future development of
the Black Oaks Project or the amount of capital expenditures that we can fund
with respect to it. In the case of the Black Oaks Project, our dependence on the
operator, Haas Petroleum, limits our ability to
influence or control the operation or future development of the project. Such
limitations could materially adversely affect the realization of our targeted
returns on capital related to exploration, drilling or production activities and lead to unexpected
future costs.


37





We may suffer losses or incur liability
for events for which we or the operator of a property have chosen not to obtain
insurance.





Our operations are subject to hazards
and risks inherent in producing and transporting natural gas and oil,
such as fires, natural disasters, explosions, pipeline ruptures, spills, and
acts of terrorism, all of which can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage toour and others’properties. As protection against
operating hazards, we maintain insurance coverage against some, but not all,
potential losses. In addition, pollution and environmental risks generally are
not fully insurable. As a result of market conditions, existing insurance policies may
not be renewed and other desirable insurance may not be available on
commercially reasonable terms, if at all. The occurrence of an event that is not
covered, or not fully covered, by insurance could have a material adverse effect on our business, financial
condition and results of operations.





Our hedging activities could result in
financial losses or could reduce our available funds or income and therefore
adversely affect our financial position.





To achieve more predictable cash flow and to reduce our
exposure to adverse fluctuations in the prices of oil and natural gas, we have
entered into derivative arrangements from April 1, 2008 until December 31, 2013forbetween 30 and130 barrels of oil per day that could
result in both realized and
unrealized hedging losses. As ofMarch 31, 2009we had not incurred any such
losses.The extent of our
commodity price exposure is related largely to the effectiveness and scope of
our derivative activities. For example, the derivative instruments we may utilize may be
based on posted market prices, which may differ significantly from the actual
crude oil, natural gas and NGL prices we realize in our
operations.





Our
actual future production may be significantly higher or lower than we estimate
at the time we enter into derivative transactions for such period. If the actual
amount is higher than we estimate, we will have greater commodity price exposure
than we intended. If the actual amount is lower than the nominal amount that is
subject to our derivative financial instruments, we might be forced to satisfy
all or a portion of our derivative transactions without the benefit of the cash
flow from our sale or purchase of the underlying physical commodity, resulting
in a substantial diminution of our liquidity. As a result of these factors, our
derivative activities may not be as effective as we intend in reducing the
volatility of our cash flows, and in certain circumstances may actually increase
the volatility of our cash flows. In addition, while we believe our existing
derivative activities are with creditworthy counterparties (Shell and BP),
continued deterioration in the credit markets may cause a counterparty not to
perform its obligation under the applicable derivative instrument or impact
their willingness to enter into future transactions with us.





38




Our business depends in part on
gathering and transportation facilities owned by others. Any limitation in the
availability of those facilities could interfere with our ability to
market our oil and natural
gas production and could harm our business.




The marketability of our oil and natural
gas production will depend in a very large part on the availability, proximity
and capacity of pipelines, oil and natural gas gathering systems and processing facilities. The amount of
oil and natural gas that can be produced and sold is subject to curtailment in
certain circumstances, such as pipeline interruptions due to scheduled and
unscheduled maintenance, excessive pressure, physical damage orlack of available capacity on such
systems. The curtailments arising from these and similar circumstances may last
from a few days to several months. In many cases, we will be provided only with
limited, if any, notice as to when these circumstances willarise and their duration. Any
significant curtailment in gathering system or pipeline capacity could
significantly reduce our ability to market our oil and naturalgas production andcould materiallyharm our business.





Costand availabilityof drilling rigs, equipment, supplies, personnel and
other services could adversely affect our ability to execute on a timely basis
our development, exploitation and exploration plans.





Shortages or an increase in cost of
drilling rigs, equipment, supplies or personnelcould delay or interrupt our operations,
which could impact our financial condition and results of operations. Drilling
activity in the geographic areas in which we conduct drilling activities may
increase, which would lead to increases in associated costs, including those related to drilling
rigs, equipment, supplies and personnel and the services and products of other
vendors to the industry. Increased drilling activity in these areas may also
decrease the availability of rigs. Although Haas Petroleum hasagreed to provideup totwo drilling rigs to the Black Oaks
Projectwhen needed,subject to availability of
capital, wedo not have any contracts for drilling
rigs and drilling rigs may not be readily available when we need them. Drilling
and other costsmay
increase further and necessary equipment and services may not be available to us
at economical prices.





Our exposure to possible leasehold
defects and potential title failure could materially adversely impact our
ability to conduct drilling operations.





We obtain the right and access to
properties for drilling by obtaining oil and natural gas leases either directly
from the hydrocarbon owner, or through a third party that owns the lease. The
leases may be taken or assigned to us without title insurance.There is a risk of title failure with
respect to such leases, and such title failures could materially adversely
impact our business by causing us to be unable to access properties to conduct
drilling operations.





Our reserves are subject to the risk of
depletion because many of
our leases are in mature fields that have produced large quantities of oil and
natural gas to date.





Our operations are located in
established fields in Eastern Kansas. As a result, many of our leases are in, or
directly offset, areas that
have produced large quantities of oil and natural gas to date.  As
such, our reserves may be partially or completely depleted by offsetting wells
or previously drilled wells, which could significantly harm our
business.


39





Our lease ownership may be diluted due to financing strategies we
may employ in the future due to our lack of capital.





To accelerate our development efforts we
plan to take on working interest partners who will contribute to the costs of
drilling and completion and then share inrevenues derived from production. In
addition, we may in the future, due to a lack of capital or other strategic
reasons, establish joint venture partnerships or farm out all or part of our
development efforts. These economic strategies may have a dilutiveeffect on our lease ownership and could
significantly reduce our operating revenues.





We are subject to complex laws and
regulations, including environmental regulations, which can adversely affect the
cost, manner or feasibility of doing business.





Development, production and sale of natural
gas and oil in the United States are subject to extensive laws and regulations,
including environmental laws and regulations. We may be required to make large
expenditures to comply with environmental and other governmental regulations. Matters subject to
regulation include, but are not limited to:





·
            location
      and density of wells;


·
            the handling of drilling fluids
      and obtaining discharge permits for drillingoperations;


·
            accounting for and payment of
      royalties on production from state, federal and
      Indian lands;


·
            bonds for ownership, development
      and production of natural gas and oil
  properties;


·
            transportation of natural gas and
      oil by pipelines;


·
            operation of wells and reports
      concerning operations; and


·
            taxation.





Under these laws and regulations, we
could be liable for personal injuries, property damage, oil spills, discharge of
hazardous materials, remediation and clean-up costs and other environmental
damages. Failure to comply with these laws and regulations also may result in the suspension or
termination of our operations and subject us to administrative, civil and
criminal penalties. Moreover, these laws and regulations could change in ways
that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions,
terminations or regulatory changes could materially adversely affect our
financial condition and results of operations enough to possibly force us to
cease our business operations.


40





Our
operations may expose us to significant costs and liabilities with respect to
environmental, operational safety and other matters.





We may
incur significant costs and liabilities as a result of environmental and safety
requirements applicable to our oil and natural gas exploration and production
activities. We may also be exposed to the risk of costs associated with Kansas
Corporation Commission requirements to plug orphaned and abandoned wells on our
oil and natural gas leases from wells previously drilled by third parties. In
addition, we may indemnify sellers or lessors of oil and natural gas properties
for environmental liabilities they or their predecessors may have created. These
costs and liabilities could arise under a wide range of federal, state and local
environmental and safety laws and regulations, including regulations and
enforcement policies, which have tended to become increasingly strict over time.
Failure to comply with these laws and regulations may result in the assessment
of administrative, civil and criminal penalties, imposition of cleanup and site
restoration costs, liens and to a lesser extent, issuance of injunctions to
limit or cease operations. In addition, claims for damages to persons or
property may result from environmental and other impacts of our
operations.





Strict,
joint and several liability may be imposed under certain environmental laws,
which could cause us to become liable for the conduct of others or for
consequences of our own actions that were in compliance with all applicable laws
at the time those actions were taken. New laws, regulations or enforcement
policies could be more stringent and impose unforeseen liabilities or
significantly increase compliance costs. If we are not able to recover the
resulting costs through insurance or increased revenues, our ability to operate
effectively could be adversely affected.





Our
facilities and activities could be subject to regulation by the Federal Energy
Regulatory Commission or the Department of Transportation, which could take
actions that could result in a material adverse effect on our financial
condition.





Although
it is anticipated that our natural gas gathering systems will be exempt from
FERC and DOT regulation, any revisions to this understanding may affect our
rights, liabilities, and access to midstream or interstate natural gas
transportation, which could have a material adverse effect on our operations and
financial condition. In addition, the cost of compliance with any revisions to
FERC or DOT rules, regulations or requirements could be substantial and could
adversely affect our ability to operate in an economic manner. Additional FERC
and DOT rules and legislation pertaining to matters that could affect our
operations are considered and adopted from time to time. We cannot predict what
effect, if any, such regulatory changes and legislation might have on our
operations, but we could be required to incur additional capital expenditures
and increased costs.





Although
our natural gas sales activities are not currently projected to be subject to
rate regulation by FERC, if FERC finds that in connection with making sales in
the future, we (i) failed to comply with any applicable FERC administered
statutes, rules, regulations or orders, (ii) engaged in certain fraudulent acts,
or (iii) engaged in market manipulation, we could be subject to substantial
penalties and fines of up to $1.0 million per day per violation.





We
operate in a highly competitive environment and our competitors may have greater
resources than us.





The
natural gas and oil industry is intensely competitive and we compete with other
companies, many of which are larger and have greater financial, technological,
human and other resources. Many of these companies not only explore for and
produce crude oil and natural gas but also carry on refining operations and
market petroleum and other products on a regional, national or worldwide basis.
Such companies may be able to pay more for productive natural gas and oil
properties and exploratory prospects or define, evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
human resources permit. In addition, such companies may have a greater ability
to continue exploration activities during periods of low oil and natural gas
market prices. Our ability to acquire additional properties and to discover
reserves in the future will be dependent upon our ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive
environment. If we are unable to compete, our operating results and financial
position may be adversely affected.


41





We
may incur substantial write-downs of the carrying value of our natural gas and
oil properties, which would adversely impact our earnings.





We review
the carrying value of our natural gas and oil properties under the full-cost
accounting rules of the SEC on a quarterly basis. This quarterly review is
referred to as a ceiling test. Under the ceiling test, capitalized costs, less
accumulated amortization and related deferred income taxes, may not exceed an
amount equal to the sum of the present value of estimated future net revenues
(adjusted for cash flow hedges) less estimated future expenditures to be
incurred in developing and producing the proved reserves, less any related
income tax effects. In calculating future net revenues, current prices and costs
used are those as of the end of the appropriate quarterly period. Such prices
are utilized except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts, including the
effects of derivatives qualifying as cash flow hedges. Two primary factors
impacting this test are reserve levels and current prices, and their associated
impact on the present value of estimated future net revenues. Revisions to
estimates of natural gas and oil reserves and/or an increase or decrease in
prices can have a material impact on the present value of estimated future net
revenues. Any excess of the net book value, less deferred income taxes, is
generally written off as an expense. Under SEC regulations, the excess above the
ceiling is not expensed (or is reduced) if, subsequent to the end of the period,
but prior to the release of the financial statements, natural gas and oil prices
increase sufficiently such that an excess above the ceiling would have been
eliminated (or reduced) if the increased prices were used in the
calculations.





As
previously announced, in December 2008, the Securities and Exchange Commission
(“SEC”) issued new regulations for oil and gas reserve reporting which go into
effect effective for fiscal years ending on or after December 31,
2009.  One of the key elements of the new regulations relate to the
commodity prices which are used to calculate reserves and their present
value.  The new regulations provide for disclosure of oil and gas
reserves evaluated using annual average prices based on the prices in effect on
the first day of each month rather than the current regulations which utilize
commodity prices on the last day of the year.





There was
no impairment for the fiscal year ended March 31, 2008.  We recorded
an impairment of $4,777,723 during the fiscal year ended March 31, 2009
primarily attributable to lower prices for both oil and natural gas at December
31, 2008.


42


Our
success depends on our key management and professional personnel, including C.
Stephen Cochennet, the loss of whom would harm our ability to execute our
business plan.





Our
success depends heavily upon the continued contributions of C. Stephen
Cochennet, whose knowledge, leadership and technical expertise would be
difficult to replace, and on our ability to retain and attract experienced
engineers, geoscientists and other technical and professional staff. We have
entered into an employment agreement with Mr. Cochennet, and we maintain $1.0
million in key person insurance on Mr. Cochennet. However, if we were to lose
his services, our ability to execute our business plan would be harmed and we
may be forced to significantly alter our operations until such time as we could
hire a suitable replacement for Mr. Cochennet.





Risks Associated with our
Debt Financing





Significant
and prolonged declines in commodity prices may negatively impact our borrowing
base and our ability to borrow overall.





Our
borrowing base, which is based on our oil and gas reserves and is subject to
review and adjustment on a semi-annual basis and other interim adjustments, has
been and may be further reduced when it is reviewed.  A reduction in
our base results in a “loan excess” which is required to be eliminated through
payment of a portion of the loan and/or cash collateralization of Letters of
Credit obligations; or adding properties to the borrowing base sufficient to
offset the “loan excess”.  A reduction in our borrowing base or the
ability to borrow under our Credit Facility, combined with a reduction in cash
flow from operations resulting from a decline in oil prices, may require us to
further reduce our capital expenditures and our operating
activities.





Until
we repay the full amount of our outstanding debentures and Credit Facility, we
may continue to have substantial indebtedness, which is secured by substantially
all of our assets.





On March
31, 2009, $2.7 million in debentures and approximately $7.3 million of bank
loans were outstanding. Under a default situation with respect to the debentures
or other secured debt, the lenders may enforce their rights as a secured party
and we may lose all or a portion of our assets or be forced to materially reduce
our business activities.





Our
substantial indebtedness could make it more difficult for us to fulfill our
obligations under our Credit Facility and our debentures and, therefore,
adversely affect our business.





On
July 3, 2008, we entered into a three-year, Senior Secured Credit
Facility providing for aggregate borrowings of up to $50 million.  As
of March 31, 2009, we had total indebtedness of $10.1 million, including $7.328
million of borrowings under the Credit Facility and $2.7 million of remaining
debentures, as well as other notes payable totaling approximately $109,000. We
had no outstanding letters of credit under the new facility on March 31,
2009.  Our substantial indebtedness, and the related interest expense,
could have important consequences to us, including:





·
            limiting
      our ability to borrow additional amounts for working capital, capital
      expenditures, debt service requirements, execution of our business
      strategy, or other general corporate
purposes;


·
            being
      forced to use cash flow to reduce our outstanding balance as a result of
      an unfavorable borrowing base
redetermination;


43





·
            limiting
      our ability to use operating cash flow in other areas of our business
      because we must dedicate a substantial portion of these funds to service
      our indebtedness;


·
            increasing
      our vulnerability to general adverse economic and industry
      conditions;


·
            placing
      us at a competitive disadvantage as compared to our competitors that have
      less leverage;


·
            limiting
      our ability to capitalize on business opportunities and to react to
      competitive pressures and changes in government
  regulation;


·
            limiting
      our ability to, or increasing the cost of, refinancing our
      indebtedness; and


·
            limiting
      our ability to enter into marketing, hedging, optimization and trading
      transactions by reducing the number of counterparties with whom we can
      enter into such transactions as well as the volume of those
      transactions.





The
covenants in our Credit Facility and debentures impose significant operating and
financial restrictions on us.





The
Credit Facility and our debentures impose significant operating and financial
restrictions on us. These restrictions limit our ability and the ability of our
subsidiaries, among other things, to:





·
            incur
      additional indebtedness and provide additional
  guarantees;


·
            pay
      dividends and make other restricted
payments;


·
            create
      or permit certain liens;


·
            use
      the proceeds from the sales of our oil and natural gas
      properties;


·
            use
      the proceeds from the unwinding of certain financial
    hedges;


·
            engage
      in certain transactions with affiliates;
and


·
            consolidate,
      merge, sell or transfer all or substantially all of our assets or the
      assets of our subsidiaries.





The
Credit Facility and our debentures also contain various affirmative covenants
with which we are required to comply.  We obtained a waiver of default from
Texas Capital Bank on two technical covenants at March 31, 2009.  We
are taking steps in an effort to comply with these same covenants in future
quarters, including but not limited to, a reduction in principal of
approximately $3.3 million with proceeds from liquidating a costless collar we
entered into on July 3, 2008 and the reduction of our operating and general
expenses.  We may be unable to comply with some or all of these
covenants in the future as well. If we do not comply with these covenants and
are unable to obtain waivers from our lenders, we would be unable to make
additional borrowings under these facilities, our indebtedness under these
agreements would be in default and could be accelerated by our
lenders.  In addition, it could cause a cross-default under our other
indebtedness, including our debentures. If our indebtedness is accelerated, we
may not be able to repay our indebtedness or borrow sufficient funds to
refinance it. In addition, if we incur additional indebtedness in the future, we
may be subject to additional covenants, which may be more restrictive than those
to which we are currently subject.


44


Risks Associated with our
Common Stock





We
have the ability to issue additional shares of our common stock and shares of
preferred stock without asking for stockholder approval, which could cause your
investment to be diluted.





Our
Articles of Incorporation authorizes the Board of Directors to issue up to
100,000,000 shares of common stock and 10,000,000 shares of preferred
stock.  The power of the Board of Directors to issue shares of common
stock, preferred stock or warrants or options to purchase shares of common stock
or preferred stock is generally not subject to shareholder
approval.  Accordingly, any additional issuance of our common stock,
or preferred stock that may be convertible into common stock, or debt
instruments that may be convertible into common or preferred stock, may have the
effect of diluting one’s investment.





Our
common stock is traded on an illiquid market, making it difficult for investors
to sell their shares.





Our
common stock trades on the Over-the-Counter Bulletin Board under the symbol
“ENRJ,” but trading has been minimal. Therefore, the market for our common stock
is limited. The trading price of our common stock could be subject to wide
fluctuations. Investors may not be able to purchase additional shares or sell
their shares within the time frame or at a price they desire.





The
price of our common stock may be volatile and you may not be able to resell your
shares at a favorable price.





Regardless
of whether an active trading market for our common stock develops, the market
price of our common stock may be volatile and you may not be able to resell your
shares at or above the price you paid for such shares. The following factors
could affect our stock price:





·
            our
      operating and financial performance and
  prospects;


·
            quarterly
      variations in the rate of growth of our financial indicators, such as net
      income or loss per share, net income or loss and
  revenues;


·
            changes
      in revenue or earnings estimates or publication of research reports by
      analysts about us or the exploration and production
    industry;


·
            potentially
      limited liquidity;


·
            actual
      or anticipated variations in our reserve estimates and quarterly operating
      results;


·
            changes
      in natural gas and oil prices;


·
            sales
      of our common stock by significant stockholders and future issuances of
      our common stock;


·
            increases
      in our cost of capital;


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


·
            commencement
      of or involvement in litigation;


·
            changes
      in market valuations of similar
companies;


45





·
            additions
      or departures of key management
personnel;


·
            general
      market conditions, including fluctuations in and the occurrence of events
      or trends affecting the price of natural gas and oil;
  and


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





Our
articles of incorporation, bylaws and Nevada Law contain provisions that could
discourage an acquisition or change of control of us.





Our
articles of incorporation authorize our board of directors to issue preferred
stock and common stock without stockholder approval. If our board of directors
elects to issue preferred stock, it could be more difficult for a third party to
acquire control of us. In addition, provisions of the articles of incorporation
and bylaws could also make it more difficult for a third party to acquire
control of us. In addition, Nevada’s “Combination with Interested Stockholders’
Statute” and its “Control Share Acquisition Statute” may have the effect in the
future of delaying or making it more difficult to effect a change in control of
us.





These
statutory anti-takeover measures may have certain negative consequences,
including an effect on the ability of our stockholders or other individuals to
(i) change the composition of the incumbent board of directors; (ii) benefit
from certain transactions which are opposed by the incumbent board of directors;
and (iii) make a tender offer or attempt to gain control of us, even if such
attempt were beneficial to us and our stockholders. Since such measures may also
discourage the accumulations of large blocks of our common stock by purchasers
whose objective is to seek control of us or have such common stock repurchased
by us or other persons at a premium, these measures could also depress the
market price of our common stock. Accordingly, our stockholders may be deprived
of certain opportunities to realize the “control premium” associated with
take-over attempts.





We
have no plans to pay dividends on our common stock. You may not receive funds
without selling your stock.





We do not
anticipate paying any cash dividends on our common stock in the foreseeable
future. We currently intend to retain future earnings, if any, to finance the
expansion of our business. Our future dividend policy is within the discretion
of our board of directors and will depend upon various factors, including our
business, financial condition, results of operations, capital requirements,
investment opportunities and restrictions imposed by our debentures and Credit
Facility.





We
may issue shares of preferred stock with greater rights than our common
stock.





Although
we have no current plans, arrangements, understandings or agreements to issue
any preferred stock, our articles of incorporation authorizes our board of
directors to issue one or more series of preferred stock and set the terms of
the preferred stock without seeking any further approval from our stockholders.
Any preferred stock that is issued may rank ahead of our common stock, with
respect to dividends, liquidation rights and voting rights, among other
things.


46





We
have derivative securities currently outstanding. Exercise of these derivatives
will cause dilution to existing and new stockholders.





As of
March 31, 2009, we had options and warrants to purchase approximately 438,500
shares of common stock outstanding in addition to 2,500 shares issuable upon
conversion of a convertible note. The exercise of our outstanding options and
warrants, and the conversion of the note, will cause additional shares of common
stock to be issued, resulting in dilution to our existing common
stockholders.





Because
our common stock is deemed a low-priced “Penny” stock, an investment in our
common stock should be considered high risk and subject to marketability
restrictions.





Our
common stock is currently deemed to be a penny stock, as defined in Rule 3a51-1
under the Securities Exchange Act, which may make it more difficult for
investors to liquidate their investment even if and when a market develops for
the common stock. Until the trading price of the common stock consistently
trades above $5.00 per share, if ever, trading in the common stock may be
subject to the penny stock rules of the Securities Exchange Act specified in
rules 15g-1 through 15g-10. Those rules require broker-dealers, before effecting
transactions in any penny stock, to:





·
            Deliver
      to the customer, and obtain a written receipt for, a disclosure
      document;


·
            Disclose
      certain price information about the
stock;


·
            Disclose
      the amount of compensation received by the broker-dealer or any associated
      person of the broker-dealer;


·
            Send
      monthly statements to customers with market and price information about
      the penny stock; and


·
            In
      some circumstances, approve the purchaser’s account under certain
      standards and deliver written statements to the customer with information
      specified in the rules.





Consequently,
the penny stock rules may restrict the ability or willingness of broker-dealers
to sell the common stock and may affect the ability of holders to sell their
common stock in the secondary market and the price at which such holders can
sell any such securities. These additional procedures could also limit our ability to raise
additional capital in the future.





If
we fail to remain current on our reporting requirements, we could be removed
from the OTC Bulletin Board, which would limit the ability of broker-dealers to
sell our securities and the ability of stockholders to sell their securities in
the secondary market.





Companies
trading on the OTC Bulletin Board, such as us, must be reporting issuers under
Section 12 of the Securities Exchange Act of 1934, as amended, and must be
current in their reports under Section 13, in order to maintain price quotation
privileges on the OTC Bulletin Board.  More specifically, FINRA has enacted
Rule 6530, which determines eligibility of issuers quoted on the OTC Bulletin
Board by requiring an issuer to be current in its filings with the
Commission.  Pursuant to Rule 6530(e), if we file our reports late with the
Commission three times in a two-year period or our securities are removed from
the OTC Bulletin Board for failure to timely file twice in a two-year period
then we will be ineligible for quotation on the OTC Bulletin
Board.  As a result, the market liquidity for our securities could be
severely adversely affected by limiting the ability of broker-dealers to sell
our securities and the ability of stockholders to sell their securities in the
secondary market.


47





FINRA
sales practice requirements may limit a stockholder's ability to buy and sell
our stock.





In
addition to the “penny stock” rules described above, FINRA has adopted rules
that require that in recommending an investment to a customer, a broker-dealer
must have reasonable grounds for believing that the investment is suitable for
that customer. Prior to recommending speculative low priced securities to their
non-institutional customers, broker-dealers must make reasonable efforts to
obtain information about the customer's financial status, tax status, investment
objectives and other information. Under interpretations of these rules, the
FINRA believes that there is a high probability that speculative low priced
securities will not be suitable for at least some customers. The FINRA
requirements make it more difficult for broker-dealers to recommend that their
customers buy our common stock, which may limit your ability to buy and sell our
stock and have an adverse effect on the market for our shares.





Additional Risks and
Uncertainties





We are an
oil and natural gas acquisition, exploration and development company. If any of
the risks that we face actually occur, irrespective of whether those risks are
described in this section or elsewhere in this report, our business, financial
condition and operating results could be materially adversely
affected.




Item
1B. Unresolved Staff Comments.





Not applicable.




Item
3. Legal Proceedings.





We may become involved in various
routine legal proceedings incidental to our business. However, to our knowledge
as of the date of this report, there are no material pending legal proceedings
to which we are a party or to which any of our property is subject.




Item
4. Submission of Matters to a Vote of Security Holders.





We did not submit any matters to a vote
of our security holders during the fourth quarter ended March 31,
2009.


48





PART
II




Item
5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.





(a)
Market Information





PRICE RANGE OF COMMON
STOCK





Prior to
completion of the reverse merger with Midwest Energy in August of 2006, our
common stock was sporadically traded in the inter-dealer markets of the OTC:BB,
“pink sheets” and “gray sheets” under the symbol “MPCO.” Our common stock
currently trades on the OTC:BB under the symbol “ENRJ.” Our common stock has
traded infrequently on the OTC:BB, which limits our ability to locate accurate
high and low bid prices for each quarter within the last two fiscal years.
Therefore, the following table lists the quotations for the high and low bid
prices as reported by a Quarterly Trade and Quote Summary Report of the OTC
Bulletin Board and Yahoo! Finance for fiscal years 2008 and 2009. The quotations
reflect inter-dealer prices without retail mark-up, markdown, or commissions and
may not represent actual transactions.





Low
                  
                  
                  HighFiscal
      2008Quarter
      ended June 30, 2007
                  
                  
                  1.00
                  
                  
                  
                  1.25Quarter
      ended September 30, 2007
                  
                  
                  0.75
                  
                  
                  
                  1.35Quarter
      ended December 31, 2007
                  
                  
                  0.70
                  
                  
                  
                  1.20Quarter
      ended March 31, 2008
                  
                  
                  0.81
                  
                  
                  
                  1.20Fiscal
      2009Quarter
      ended June 30, 2008
                  
                  
                  0.95
                  
                  
                  
                  1.20Quarter
      ended September 30, 2008
                  
                  
                  4.20
                  
                  
                  
                  5.00Quarter
      ended December 31, 2008
                  
                  
                  0.45
                  
                  
                  
                  3.16Quarter
      ended March 31, 2009
                  
                  
                  0.25
                  
                  
                  
                  1.88





The last
reported sale price of our common stock on the OTC:BB was $0.79 per share on
July 8, 2009.





(b)
Holders of Common Stock





As of
July 14, 2009, there were 1,121 holders of record of our common
stock.





(c)
Dividends





We have
never paid or declared any cash dividends on our common stock. We currently
intend to retain any future earnings to finance the growth and development of
our business and we do not expect to pay any cash dividends on our common stock
in the foreseeable future. In addition, we are contractually prohibited by the
terms of our outstanding debt from paying cash dividends on our common stock.
Payment of future dividends, if any, will be at the discretion of our board of
directors and will depend on our financial condition, results of operations,
capital requirements, restrictions contained in current or future financing
instruments, including the consent of debt holders, if applicable at such time,
and other factors our board of directors deems relevant.


49





(d)
Securities Authorized for Issuance under Equity Compensation Plans





2000/2001
Stock Option Plan





The Board of Directors approved the
2000/2001 Stock Option Plan and our stockholders ratified the plan on September
25, 2000.  The total number of options that can be granted under the
plan is 200,000 shares.





Stock
Option Plan





The Board
of Directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1,
2002 (the “2002-2003 Stock Option Plan”).  Originally, the total
number of options that could be granted under the plan was not to exceed 400,000
shares.  On May 4, 2007, the Governance, Compensation, and Nominating
Committee amended and restated the stock option plan to rename the plan and to
increase the number of shares issuable to 1,000,000.  Our stockholders
approved this plan in September of 2007. In no event may the option price with
respect to any stock option granted under the 2002-2003 Stock Option Plan be
less than the fair market value of such common stock.  However the
price of an incentive stock option will not be less than 110% of the fair market
value per share on the date of the grant in the case of an individual then
owning more than 10% of the total combined voting power of all classes of stock
of the corporation.





Each
option granted under the 2002-2003 Stock Option Plan will be assigned a time
period for exercising not to exceed ten years after the date of the
grant.  Certain other restrictions will apply in connection with this
plan when some awards may be exercised.





In the
event of a change of control (as defined in the plan), the date on which all
options outstanding under the plan may first be exercised will be
accelerated.  Generally, all options terminate 90 days after a change
of control.





General
Terms of Stock Option Plans





Officers (including officers who are
members of the board of directors), directors, and other employees and
consultants and our subsidiaries (if established) will be eligible to receive
options under the stock option plans.  The Governance, Compensation
and Nominating Committee, or GCNC, of the Board of Directors will administer the
stock option plans and will determine those persons to whom options will be
granted, the number of options to be granted, the provisions applicable to each
grant and the time periods during which the options may be
exercised.  No options may be granted more than ten years after the
date of the adoption of the stock option plans.


50


Non-qualified
stock options will be granted by the committee with an option price equal to the
fair market value of the shares of common stock to which the non-qualified stock
option relates on the date of grant.  The committee may, in its
discretion, determine to price the non-qualified option at a different
price.  In no event may the option price with respect to an incentive
stock option granted under the stock option plans be less than the fair market
value of such common stock to which the incentive stock option relates on the
date the incentive stock option is granted. However the price of an incentive
stock option will not be less than 110% of the fair market value per share on
the date of the grant in the case of an individual then owning more than 10% of
the total combined voting power of all classes of stock of the
corporation.





Each option granted under the stock
option plans will be exercisable for a term of not more than ten years after the
date of grant.  Certain other restrictions will apply in connection
with the plans when some awards may be exercised.  In the event of a
change of control (as defined in the stock option plans), the date on which all
options outstanding under the stock option plans may first be exercised will be
accelerated.  Generally, all options terminate 90 days after a change
of control.





These plans are intended to encourage
directors, officers, employees and consultants to acquire ownership of common
stock.  The opportunity so provided is intended to foster in
participants a strong incentive to put forth maximum effort for our continued
success and growth, to aid in retaining individuals who put forth such effort,
and to assist in attracting the best available individuals in the
future.





Recent
Sales of Unregistered Securities





None.





Issuer
Purchases of Equity Securities





We did not repurchase any of our equity
securities during the fiscal years ended March 31, 2009 or 2008.




Item
6. Selected Financial Data.





Not applicable.





Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations.





The following discussion of our
financial condition and results of operations should be read in conjunction with
our financial statements and the related notes to our financial statements
included elsewhere in
this report. In addition to historical financial information, the following
discussion and analysis contains forward-looking statements that involve risks,
uncertainties and assumptions. Our actual results and timing of selected events
maydiffer materially from those
anticipated in these forward-looking statements as a result of many factors,
including those discussed under ITEM 1A. Risk Factors and elsewhere in this
report.


51





Overview





Our
principal strategy is to focus on the acquisition of oil and natural gas mineral
leases that have existing production and cash flow. Once acquired, we strive to
implement an accelerated development program utilizing capital resources, a
regional operating focus, an experienced management and technical team, and
enhanced recovery technologies to attempt to increase production and increase
returns for our stockholders. Our oil and natural gas acquisition and
development activities are currently focused in Eastern Kansas.





Since the
beginning of fiscal 2008 and throughout fiscal 2009, we deployed approximately
$12 million in capital resources to acquire and develop five operating projects
and drill 179 new wells (111 producing wells, 65 water injection wells, and 3
dry holes). Our estimated total proved PV 10 (present value) of reserves as of
March 31, 2009 was $10.63 million, versus $39.6 million as of March 31,
2008.  We developed total proved reserves to 1.3 million barrels of
oil equivalent, or BOE, as of March 31, 2009. Of the 1.3 million BOE of
total proved reserves, approximately 39% are proved developed and approximately
61% are proved undeveloped. The proved developed reserves consist of 82% proved
developed producing reserves and 18% proved developed non-producing
reserves.   See “Glossary” on page 23 for our definition of
PV10.





The total
proved PV10 (present value) of our reserves as of March 31, 2009 was $10.63
million. PV10 is a non-GAAP financial measure and generally differs from the
standardized measure of discounted future net cash flows, the most directly
comparable GAAP financial measure, because it does not include the effects of
income taxes on future net revenues. See “Glossary” on page 24 for our
definition of PV10 and “Management’s Discussion and Analysis of Financial
Condition and Results of Operations-Reserves” page 57, for
a reconciliation to the comparable GAAP financial measure.





We are
continually evaluating oil and natural gas opportunities in Eastern Kansas and
are also in various stages of discussions with potential joint venture (“JV”)
partners who would contribute capital to develop leases we currently own or
would acquire for the JV. We recently entered into one such opportunity on the
Brownrigg lease in Linn County, Kansas.  This economic strategy will
allow us to utilize our own financial assets toward the growth of our leased
acreage holdings, pursue the acquisition of strategic oil and natural gas
producing properties or companies and generally expand our existing operations
while further diversifying risk. Subject to availability of capital, we plan to
continue to bring potential acquisition and JV opportunities to various
financial partners for evaluation and funding options.  It is our
vision to grow the business in a disciplined and well-planned
manner.





We began
generating revenues from the sale of oil during the fiscal year ended March 31,
2008. Subject to availability of capital, we expect our production to continue
to increase, both through development of wells, through our acquisition
strategy, and other strategic initiatives. Our future financial results will
continue to depend on: (i) our ability to source and screen potential projects;
(ii) our ability to discover commercial quantities of natural gas and oil; (iii)
the market price for oil and natural gas; and (iv) our ability to fully
implement our exploration, work-over and development program, which is in part
dependent on the availability of capital resources. There can be no assurance
that we will be successful in any of these respects, that the prices of oil and
natural gas prevailing at the time of production will be at a level allowing for
profitable production, or that we will be able to obtain additional funding at
terms favorable to us to increase our currently limited capital
resources.


52





The board
of directors has implemented a crude oil and natural gas hedging strategy that
will allow management to hedge up to 80% of our net production to mitigate a
majority of our exposure to changing oil prices in the intermediate
term.





Recent
Developments





We entered into an agreement with Shell
Trading (US) Company, or Shell, whereby we agreed to an 18-month fixed-price
swap with Shell for 130 BOPD at a fixed price per barrel of $96.90, before
transportation costs from April 1, 2008 through September 30, 2009. This
represented approximately 60% of our total oil production on a net revenue basis
at that time and locked in approximately $6.8 million in gross revenue before
transportation costs over the 18 month period. In addition, we agreed to sell
all of our remaining oil production at current spot market pricing beginning
April 1, 2008 through September 30, 2009 to Shell.  For the fiscal
year ended March 31, 2009, the positive impact on our net revenue from the
fixed-price swap was approximately $506,000.





On July 3, 2008, EnerJex, EnerJex
Kansas, and DD Energy entered into a three-year $50 million Senior Secured
Credit Facility (the “Credit Facility”) with Texas Capital Bank,
N.A.  Borrowings under the Credit Facility will be subject to a
borrowing base limitation based on our current proved oil and gas reserves and
will be subject to semi-annual redeterminations and interim
adjustments.  The initial borrowing base was set at $10.75 million and
was reduced to $7.428 million following the liquidation of the BP hedging
instrument in November 2008.  The Borrowing Base was reviewed by Texas
Capital Bank in February 2009 and it was determined that it should be reduced by
$200,000 per month beginning April 2009 and likely continuing through December
2009, primarily as a result of commodity oil prices. The Credit Facility is
secured by a lien on substantially all assets of the Company and its
subsidiaries. The Credit Facility has a term of three years, and all unpaid
principal and interest will be due and payable in full on July 3,
2011.  The Credit Facility also provides for the issuance of
letters-of-credit up to a $750,000 sub-limit under the borrowing base and up to
an additional $2.25 million limit not subject to the borrowing base to support
our hedging program.  We had borrowings $7.328 million outstanding at
March 31, 2009.  Subsequent to year-end, we have made Borrowing Base
Reduction payments of $200,000.





On July 7, 2008, we amended the $2.7
million of aggregate principal amount of our 10% debentures that remain
outstanding to, among other things, permit the indebtedness under our Credit
Facility, subordinate the security interests of the debentures to the Credit
Facility, provide for the redemption of the remaining debentures with the net
proceeds from any next debt or equity offering, eliminate the covenant to
maintain certain production thresholds and waive all known
defaults.  Subsequent to year-end, we again amended the debentures to
extend the maturity date to September 30, 2010, and allow us to pay interest in
either cash or payment-in-kind interest (an increase in the amount of principal
due) or pay interest through the issuance of shares of common stock, and add a
provision for the conversion of the debentures into shares of our common stock.


53





As of July 3, 2008, we entered into an
ISDA master agreement and a costless collar with BP Corporation North America
Inc., or BP, for 130 barrels of oil per day with a price floor of $132.50 per
barrel and a price ceiling of $155.70 per barrel for NYMEX West Texas
Intermediate for the period of October 1, 2009 until March 31,
2011.  We liquidated this costless collar in November 2008 and
received proceeds of approximately $3.9 million from BP.  We reduced
the debt outstanding under our Credit Facility by approximately $3.3 million and
used the remainder for general operating purposes.





On August 1, 2008, we executed
three-year employment agreements with C. Stephen Cochennet, our chief executive
officer, and Dierdre P. Jones, our chief financial officer.  Mr.
Cochennet and Ms. Jones have agreed to amend their employment agreements to
reflect options rescinded in November 2008.





In February 2009, we entered into a
fixed price swap transaction under the terms of the BP ISDA for a total of
120,000 gross barrels at a price of $57.30 per barrel before transportation
costs for the period beginning October 1, 2009 and ending on December 31,
2013.





Euramerica failed to fully fund by
January 15, 2009 both the balance of the purchase price and the remaining
development capital owed under the Amended and Restated Well Development
Agreement and Option for “Gas City Property” between us and
Euramerica.  Therefore, Euramerica has forfeited all of its interest
in the property, including all interests in any wells, improvements or assets,
and all of Euramerica's interest in the property reverts back to
us.  In addition, all operating agreements between us and Euramerica
relating to the Gas City Project are null and void.





We recorded a non-cash impairment of
$4,777,723 to the carrying value of our proved oil and gas properties during the
fiscal year ended March 31, 2009. The impairment is primarily attributable to
lower prices for both oil and natural gas at December 31, 2008. The charge
results from the application of the “ceiling test” under the full cost method of
accounting. Under full cost accounting requirements, the carrying value may not
exceed an amount equal to the sum of the present value of estimated future net
revenues (adjusted for cash flow hedges) less estimated future expenditures to
be incurred in developing and producing the proved reserves, less any related
income tax effects. In calculating future net revenues, current prices and costs
used are those as of the end of the appropriate quarterly period. Such prices
are utilized except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts, including the
effects of derivatives qualifying as cash flow hedges. A ceiling test charge
occurs when the carrying value of the oil and gas properties exceeds the full
cost ceiling.





On March 3, 2009, we
withdrew our Form S-1 Registration Statement after deciding to terminate the
registered public offering.   Asglobal economic
conditions deteriorated and the commodity prices of oil and natural gas
experienced significant declines, the availability of equity capital became
severely constrained.  While we intend to return to the equity market
when conditions improve and are conducive to raising capital, there can be no
assurance that we will be successful in doing so.


54





On March
23, 2009 we received a Monthly Commitment Notice from Texas Capital Bank
requiring a $200,000 Borrowing Base Reduction payment on or before April 1,
2009.  This reduction was in response to decreased oil commodity
prices. Notices in April, May and June of 2009 called for $200,000 monthly
payments as well.  We have made three separate $100,000 payments
towards that Borrowing Base Reduction request.  As of the date of this
report, we have not received a default notification from Texas Capital Bank,
even though we have paid them less than the amount requested as part of their
redetermination.  We have been working closely with Texas Capital
Bank, as oil commodity prices rebound, and our Independent Reserve Engineers to
revalue our reserves in light of commodity prices and improved production levels
since Texas Capital’s redetermination.





In April and May of 2009, we redeemed
$450,000 of the subordinated debentures.  The balance remaining as of
the date of this report is $2.25 million and these debentures mature on
September 30, 2010.





Results
of Operations for the Fiscal Years Ended March 31, 2009 and 2008
compared.





We began
acquiring oil properties with existing production in April of 2007, the first
month of our fiscal year ended March 31, 2008.  These acquisitions
included the Black Oaks and Thoren Projects.  We acquired both the DD
Energy and the Tri-County Projects in November of 2007, or about mid-year of
that same fiscal year.  We owned these projects throughout the entire
fiscal year ended March 31, 2009.  Comparisons between the fiscal
years, then, will reflect a full year of revenues and expenses for all projects
for the fiscal year ended March 31, 2009 and a partial year of revenues and
expenses for the two of the four projects for the fiscal year ended March 31,
2008.





Income:


Fiscal
      Year Ended
                    March
      31,2009
                  
                  
                  2008
                  
                  
                  Increase
      / (Decrease)Amount
                  
                  
                  Amount
                  
                  
                  $Oil
      and natural gas revenues
                  
                  $
                  6,436,805
                  
                  
                  $
                  3,602,798
                  
                  
                  $
                  2,834,007





Revenues





Oil and
natural gas revenues for the fiscal year ended March 31, 2009 were
$6,436,805 compared to revenues of $3,602,798 in the fiscal year ended
March 31, 2008. The increase in revenues is primarily the result of the greater
oil production levels as well as a higher average price per barrel of
oil.  The average price per barrel we received for oil sold during the
twelve months ended March 31, 2009 was $85.67 compared to $79.71 for the twelve
months ended March 31, 2008. Natural gas sales accounted for less than 1% of the
total revenues. The average price per Mcf for natural gas sales during the
fiscal year ended March 31, 2009 was $5.57, compared to $6.20 during the fiscal
year ended March 31, 2008.


55





Expenses:


Fiscal
      Year Ended
                        March
      31,2009
                      
                      
                      2008
                      
                      
                      Increase
      / (Decrease)Amount
                      
                      
                      Amount
                      
                      
                      $Expenses:Direct
      operating costs
                      
                      $
                      2,637,333
                      
                      
                      $
                      1,795,188
                      
                      
                      $
                      842,145Depreciation,
      depletion andamortization
                      
                      
                      872,230
                      
                      
                      
                      913,224
                      
                      
                      
                      (40,994
                      )Total
      production expenses
                      
                      
                      3,509,563
                      
                      
                      
                      2,708,412
                      
                      
                      
                      801,151Professional
      fees
                      
                      
                      1,320,332
                      
                      
                      
                      1,226,998
                      
                      
                      
                      93,334Salaries
                      
                      
                      849,340
                      
                      
                      
                      1,703,099
                      
                      
                      
                      (853,759
                      )Depreciation
      on other fixed assets
                      
                      
                      39,063
                      
                      
                      
                      22,106
                      
                      
                      
                      16,957Administrative
      expenses
                      
                      
                      1,392,645
                      
                      
                      
                      887,872
                      
                      
                      
                      504,773Impairment
      of oil & gas properties
                      
                      
                      4,777,723
                      
                      
                      
                      -
                      
                      
                      
                      4,777,723Total
      expenses
                      
                      
                      11,888,666
                      
                      
                      
                      6,548,487
                      
                      
                      
                      5,340,179





Direct
Operating Costs




Direct
operating costs for the fiscal year ended March 31, 2009 were $2,637,517
compared to $1,795,188 for the fiscal year ended March 31, 2008. The increase
over the prior period results from the operating costs on a greater number of
wells on our existing and acquired oil leases during the fiscal year ended
March 31, 2009. Direct operating costs include pumping, gauging, pulling,
repairs, certain contract labor costs, and other non-capitalized
expenses.




Depreciation, Depletion and
Amortization




Depreciation,
depletion and amortization for the fiscal year ended March 31, 2009 was
$872,230, compared to $913,224 for the fiscal year ended March 31, 2008. The
decrease was primarily a result of the lower cost per barrel of depletion of oil
reserves.  The rate of depletion was $12.02 per barrel for the fiscal
year ended March 31, 2009 as compared to $19.57 per barrel for the fiscal year
ended March 31, 2008.





Professional
Fees




Professional
fees for the fiscal year ended March 31, 2009 were $1,320,332 compared to
$1,226,998 for the fiscal year ended March 31, 2008. Payments for services
rendered in connection with acquisition and financing activities, our audit,
legal, and consulting fees are recorded as professional fees and remained
relatively constant over the two fiscal years.





Salaries





Salaries
for the fiscal year ended March 31, 2009 were $849,340 compared to $1,703,099
for the fiscal year ended March 31, 2008. There were expenses totaling
$1,204,102 during the prior fiscal year related to non-cash equity based
payments made by issuing stock options to our management.  No such
issuances were made in the current fiscal year.  In addition, the
number of full-time employees increased from 9 at March 31, 2008 to 19 at
one point during the fiscal year ended March 31, 2009, then settled at
14 on March 31, 2009.  As a result, cash based salary
expense increased by approximately $500,000 during the current fiscal
year.


56





Depreciation
on Other Fixed Assets





Depreciation on other fixed assets
fiscal year ended March 31, 2009 was $39,063 compared to $22,106 for the
fiscal year ended March 31, 2008.  The increase was primarily due to
depreciation on fixed assets acquired during the period.





Administrative Expenses




Administrative
expenses for the fiscal year ended March 31, 2009 were $1,392,645compared to
$887,872 in the fiscal year ended March 31, 2008. The administrative expenses
increased in relation to the addition of employees, office space, and corporate
activity related to growth in operations.





Impairment
of Oil & Gas Properties




The
impairment of oil and natural gas properties in the year ended March 31, 2009 of
$4,777,723 represented an impairment through applying the full-cost ceiling test
method.  This ceiling test was applied to all of the cost of our oil
and natural gas properties accounted for under the full-cost method that were
subject to amortization at March 31, 2009.  We took this impairment
based on the ceiling test results during the quarter ended December 31, 2008,
and was primarily due to depressed commodity prices at the time.





Reserves





Our
estimated total proved PV 10 (present value) of reserves as of March 31,
2009 decreased to $10.63 million from $39.6 million as of March 31, 2008.
Though total proved reserves were comparable at March 31, 2009 and 2008; 1.3
million and 1.4 million barrels of oil equivalent (BOE), respectively, the PV10
declined dramatically due to the estimated average price of oil at March
31, 2009 of $42.65 versus $94.53 at March 31, 2008.  Of the 1.3
million BOE at March 31, 2009 approximately 39% are proved developed and
approximately 61% are proved undeveloped. The proved developed reserves consist
of proved developed producing (82%) and proved developed non-producing
(18%).





The
following table presents summary information regarding our estimated net proved
reserves as of March 31, 2009. All calculations of estimated net proved reserves
have been made in accordance with the rules and regulations of the SEC, and,
except as otherwise indicated, give no effect to federal or state income taxes.
The estimates of net proved reserves are based on the reserve reports prepared
by Miller and Lents, Ltd., our independent petroleum consultants. For additional
information regarding our reserves, please see Note 11 to our audited financial
statements as of and for the fiscal year ended March 31, 2009.


57





Summary
of Proved Oil and Natural Gas Reserves


as
of March 31, 2009





Proved
      Reserves Category
                
                Gross
                
                
                Net
                
                
                PV10
      (before tax)(1)Proved,
      Developed ProducingOil
      (stock-tank barrels)
                
                
                722,590
                
                
                
                429,420
                
                
                $
                6,691,550Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -Proved,
      Developed Non-ProducingOil
      (stock-tank barrels)
                
                
                146,620
                
                
                
                95,560
                
                
                $
                1,459,280Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -Proved,
      UndevelopedOil
      (stock-tank barrels)
                
                
                1,440,760
                
                
                
                811,650
                
                
                $
                2,478,510Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -Total
      Proved ReservesOil
      (stock-tank barrels)
                
                
                2,309,970
                
                
                
                1,136,630
                
                
                $
                10,629,340Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -





(1)
            The
      following table shows our reconciliation of our PV10 to our standardized
      measure of discounted future net cash flows (the most direct comparable
      measure calculated and presented in accordance with GAAP). PV10 is our
      estimate of the present value of future net revenues from estimated proved
      natural gas reserves after deducting estimated production and ad valorem
      taxes, future capital costs and operating expenses, but before deducting
      any estimates of future income taxes. The estimated future net revenues
      are discounted at an annual rate of 10% to determine their “present
      value.” We believe PV10 to be an important measure for evaluating the
      relative significance of our oil and natural gas properties and that the
      presentation of the non-GAAP financial measure of PV10 provides useful
      information to investors because it is widely used by professional
      analysts and sophisticated investors in evaluating oil and gas companies.
      Because there are many unique factors that can impact an individual
      company when estimating the amount of future income taxes to be paid, we
      believe the use of a pre-tax measure is valuable for evaluating our
      company. We believe that most other companies in the oil and gas industry
      calculate PV10 on the same basis. PV10 should not be considered as an
      alternative to the standardized measure of discounted future net cash
      flows as computed under GAAP.


As
      of
                    March
      31,
                    2009PV10
      (before tax)
                  
                  $
                  10,629,340Future
      income taxes, net of 10% discount
                  
                  
                  -Standardized
      measure of discounted future net cash flows
                  
                  $
                  10,629,340





(2)
            There
      were no natural gas reserves at March 31,
2009.





Liquidity
and Capital Resources





Liquidity
is a measure of a company’s ability to meet potential cash requirements. We have
historically met our capital requirements through debt financing, revenues from
operations and the issuance of equity securities. As a result of the $200,000
monthly reduction of our borrowing base beginning April 2009, with
the expectation that this monthly reduction would continue through December
2009, we have classified $1.7 million of the borrowings outstanding under our
Credit Facility as a current liability.As we may be unable to
provide the necessary liquidity we need by the revenues generated from our net
interests in our oil and natural gas production at current commodity prices, we
are exploring strategic initiative and JV partnerships, as well as sales of
reserves in our existing properties to finance our operations and to service our
debt obligations.


58





The
following table summarizes total current assets, total current liabilities and
working capital at March 31, 2009 as compared to March 31, 2008.


March
      31,
                        2009
                      
                      
                      March
      31,
                        2008
                      
                      
                      Increase
      / (Decrease)$Current
      Assets
                      
                      $
                      898,941
                      
                      
                      $
                      1,511,595
                      
                      
                      
                      (612,654
                      )Current
      Liabilities
                      
                      $
                      2,827,015
                      
                      
                      $
                      2,117,176
                      
                      
                      
                      709,839Working
      Capital (deficit)
                      
                      $
                      (1,928,074
                      )
                      
                      $
                      (605,581
                      )
                      
                      
                      (1,322,493
                      )





Senior
Secured Credit Facility





On July 3, 2008, EnerJex, EnerJex
Kansas, and DD Energy entered into a three-year $50 million Senior Secured
Credit Facility (the “Credit Facility”) with Texas Capital Bank,
N.A.  Borrowings under the Credit Facility will be subject to a
borrowing base limitation based on our current proved oil and gas reserves and
will be subject to semi-annual redeterminations and interim
adjustments.  The initial borrowing base was set at $10.75 million and
was reduced to $7.428 million following the liquidation of the BP hedging
instrument in November 2008.  The borrowing base was reviewed by Texas
Capital Bank in February 2009 and was reduced by $200,000 per month beginning
April 2009 with the expectation that this monthly reduction would continue
through December 2009. We had borrowings $7.328 million outstanding at March 31,
2009.  Subsequent to year-end, we have made $200,000 of Borrowing Base
Reduction payments. The Credit Facility is secured by a lien on
substantially all assets of the Company and its subsidiaries. The Credit
Facility has a term of three years, and matures on July 3, 2011.  The
Credit Facility also provides for the issuance of letters-of-credit up to a
$750,000 sub-limit under the borrowing base and up to an additional $2.25
million limit not subject to the borrowing base to support our hedging
program.





Proceeds
from the initial extension of credit under the Credit Facility were used: (1) to
redeem our 10% Senior Secured Debentures in an aggregate principal amount of
$6.3 million plus accrued interest (the “April Debentures”), (2) for Texas
Capital Bank’s acquisition of the Company’s approximately $ 2 million
indebtedness to Cornerstone Bank, (3) for complete repayment of promissory notes
issued to the sellers in connection with the Company’s purchase of the DD Energy
project in an aggregate principal amount of $965,000 plus accrued interest, and
(4) transaction costs, fees and expenses related to the new
facility.  Future borrowings may be used for the acquisition,
development and exploration of oil and gas properties, capital expenditures and
general corporate purposes.


59


Advances
under the Credit Facility will be in the form of either base rate loans or
Eurodollar loans. The interest rate on the base rate loans fluctuates based upon
the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus
a margin of 0.50%, plus a margin of between 0.0% and 0.5% depending on the
percent of the borrowing base utilized at the time of the credit extension. The
interest rate on the Eurodollar loans fluctuates based upon the British Bankers’
Association Interest Settlement Rate appearing on the display designated as page
3750 on Moneyline Telerate, Inc., plus a margin of 2.25% to 2.75% depending on
the percent of the borrowing base utilized at the time of the credit
extensionon. Eurodollar loans of one, two, three and six months may be selected
by the Company. A commitment fee of 0.375% on the unused portion of the
borrowing base will accrue, and be payable quarterly in arrears.





The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires the Company, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, to maintain
a minimum current assets to current liabilities ratio, and minimum ratios of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and to senior funded debt.





Additionally,
Texas Capital Bank, N.A. and the holders of the Senior Secured Debentures
entered into a Subordination Agreement whereby the Senior Secured Debentures
issued on June 21, 2007 will be subordinated to the Credit
Facility.





Debenture
Financing.





On April
11, 2007, we completed a $9.0 million private placement of senior secured
debentures. In accordance with the terms of the debentures, we received $6.3
million (before expenses and placement fees) at the first closing and an
additional $2.7 million (before closing fees and expenses) at the second closing
on June 21, 2007. In connection with the sale of the debentures, we issued the
lenders 9,000,000 shares of common stock. On July 7, 2008, we redeemed $6.3
million aggregate principal amount of our debentures.





The
debentures originally matured on March 31, 2010, absent earlier redemption by
us, and carry an interest rate of 10%. Interest on the debentures began accruing
on April 11, 2007 and is payable quarterly in arrears on the first day of each
succeeding quarter during the term of the debentures, beginning on or about May
11, 2007 and ending on the maturity date of September 30, 2010 - the maturity
date was amended subsequent to March 31, 2009 year-end. We may, under certain
conditions specified in the debentures, pay interest payments in shares of our
registered common stock. Additionally, on the maturity date, we are required to
pay the amount equal to the principal, as well as all accrued but unpaid
interest.


60


In connection with the Credit Facility,
we entered into an agreement amending the Securities Purchase Agreement,
Registration Rights Agreement, the Pledge and Security Agreement and the Senior
Secured Debentures issued on June 21, 2007 (the “Debenture Agreements”), with
the holders (the “Buyers”) of the Senior Secured Debentures issued on June 21,
2007 (the “June Debentures”). Pursuant to this agreement, we, among other
things, (i) redeem the April Debentures, (ii) agreed to use the net proceeds
from the Company’s next debt or equity offering to redeem the June Debentures,
(iii) agreed to update the Buyers’ registration statements to sell our common
stock owned by the Buyers, (iv) amended certain terms of the Debenture
Agreements in recognition of the indebtedness under the Credit Facility, (v)
amended the Securities Purchase Agreement and Registration Rights Agreement to
remove the covenant to issue and register additional shares of common stock in
the event that our oil production does not meet certain thresholds over time
among other things, and (vi) the Buyers agreed to waive all known events of
default.  Subsequent to March 31,
2009 year-end, we again amended the debentures to extend the maturity date to
September 30, 2010, and allow us to pay interest in either cash or
payment-in-kind interest (an increase in the amount of principal due) or
payment-in-kind shares (issuance of shares of common stock), and add a provision
for the conversion of the debentures into shares of EnerJex’s common
stock.





Going
Concern





Our
accompanying consolidated financial statements have been prepared assuming that
we will continue as a going concern. Our ability to continue as a going concern
is dependent upon attaining profitable operations based on increased production
and prices of oil and natural gas. We intend to use borrowings, equity and asset
sales, and other strategic initiatives to mitigate the effects of our cash
position, however, no assurance can be given that debt or equity financing, if
and when required, will be available. The financial statements do not include
any adjustments relating to the recoverability and classification of recorded
assets and classification of liabilities that might be necessary should we be
unable to continue in existence.





Satisfaction of our cash obligations
for the next 12 months.





A
critical component of our operating plan is the ability to obtain additional
capital through additional equity and/or debt financing and working interest
participants. During fiscal 2009, we were in the midst of a public equity
offering when global economic conditions deteriorated and the commodity prices
of oil and natural gas experienced significant declines. Our cash revenues from
operations have been significantly impacted as has our ability to meet our
monthly operating expenses and service our debt obligations. In the event we
cannot obtain additional capital through other means to allow us to pursue our
strategic plan, this would materially impact our ability to continue our desired
growth. There is no assurance we would be able to obtain such financing on
commercially reasonable terms, if at all.





We
intend to implement and execute our business and marketing strategy, respond to
competitive developments, and attract, retain and motivate qualified personnel.
There can be no assurance that we will be successful in addressing such risks,
and the failure to do so can have a material adverse effect on our business
prospects, financial condition and results of operations.





Summary of product research and
development that we will perform for the term of our plan.





We do not
anticipate performing any significant product research and development under our
plan of operation until such time as we can raise adequate working capital to
sustain our operations.


61




Expected purchase or sale of any
significant equipment.





We
anticipate that we will purchase the necessary production and field service
equipment required to produce oil and natural gas during our normal course of
operations over the next twelve months.





Significant changes in the number of
employees.





As of March 31, 2009, we had 14
full-time employees, an increase from 9 full time employees at our fiscal year
ended March 31, 2008.  We hired a number of former independent field
contractors to help secure
a more stable work base during the months where extremely high oil prices could
have limited our access to products and services needed to develop and operate
our properties.  Since November 2008, we have reduced personnel levels
by 5 full time employees and one independent contractor in
response to declining economic conditions and in an effort to reduce our
operating and general expenses and cash outlay. As drilling production
activities increase or decrease, we may have to adjust our technical,
operational and administrative personnel as
appropriate. We are using and will continue to use the services of independent
consultants and contractors to perform various professional services,
particularly in the area of land services, reservoir engineering,geology drilling, water hauling,
pipeline construction, well design, well-site monitoring and surveillance,
permitting and environmental assessment. We believe that this use of third-party
service providers may enhance our ability to contain operating andgeneral expenses, and capital
costs.





Off-Balance Sheet
Arrangements





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





Critical
Accounting Policies and Estimates





Our
critical accounting estimates include our oil and gas properties, asset
retirement obligations and the value of share-based payments.





Oil and Gas
Properties:





The
accounting for our business is subject to special accounting rules that are
unique to the gas and oil industry. There are two allowable methods of
accounting for oil and gas business activities: the successful efforts method
and the full-cost method. We follow the full-cost method of accounting under
which all costs associated with property acquisition, exploration and
development activities are capitalized. We also capitalize internal costs that
can be directly identified with our acquisition, exploration and development
activities and do not include any costs related to production, general corporate
overhead or similar activities.


62


Under the
full-cost method, capitalized costs are amortized on a composite
unit-of-production method based on proved gas and oil reserves. Depreciation,
depletion and amortization expense is also based on the amount of estimated
reserves. If we maintain the same level of production year over year, the
depreciation, depletion and amortization expense may be significantly different
if our estimate of remaining reserves changes significantly. Proceeds from the
sale of properties are accounted for as reductions of capitalized costs unless
such sales involve a significant change in the relationship between costs and
the value of proved reserves or the underlying value of unproved properties, in
which case a gain or loss is recognized. The costs of unproved properties are
excluded from amortization until the properties are evaluated. We review all of
our unevaluated properties quarterly to determine whether or not and to what
extent proved reserves have been assigned to the properties, and otherwise if
impairment has occurred. Unevaluated properties are assessed individually when
individual costs are significant.





We review
the carrying value of our gas and oil properties under the full-cost accounting
rules of the SEC on a quarterly basis. This quarterly review is referred to as a
ceiling test. Under the ceiling test, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal
to the sum of the present value of estimated future net revenues (adjusted for
cash flow hedges) less estimated future expenditures to be incurred in
developing and producing the proved reserves, less any related income tax
effects. In calculating future net revenues, current prices and costs used are
those as of the end of the appropriate quarterly period. Such prices are
utilized except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts, including the
effects of derivatives qualifying as cash flow hedges. Two primary factors
impacting this test are reserve levels and current prices, and their associated
impact on the present value of estimated future net revenues. Revisions to
estimates of gas and oil reserves and/or an increase or decrease in prices can
have a material impact on the present value of estimated future net revenues.
Any excess of the net book value, less deferred income taxes, is generally
written off as an expense. Under SEC regulations, the excess above the ceiling
is not expensed (or is reduced) if, subsequent to the end of the period, but
prior to the release of the financial statements, gas and oil prices increase
sufficiently such that an excess above the ceiling would have been eliminated
(or reduced) if the increased prices were used in the calculations.





The
process of estimating gas and oil reserves is very complex, requiring
significant decisions in the evaluation of available geological, geophysical,
engineering and economic data. The data for a given property may also change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and a continual reassessment
of the viability of production under changing economic conditions. As a result,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various properties increase the
likelihood of significant changes in these estimates.





As of
March 31, 2009, approximately 100% of our proved reserves were evaluated by an
independent petroleum consultant. All reserve estimates are prepared based upon
a review of production histories and other geologic, economic, ownership and
engineering data.


63


Asset
Retirement Obligations:





The asset
retirement obligation relates to the plug and abandonment costs when our wells
are no longer useful. We determine the value of the liability by obtaining
quotes for this service and estimate the increase we will face in the future. We
then discount the future value based on an intrinsic interest rate that is
appropriate for us. If costs rise more than what we have expected there could be
additional charges in the future however we monitor the costs of the abandoned
wells and we will adjust this liability if necessary.





Share-Based
Payments:





The value
we assign to the options and warrants that we issue is based on the fair market
value as calculated by the Black-Scholes pricing model. To perform a calculation
of the value of our options and warrants, we determine an estimate of the
volatility of our stock.  We need to estimate volatility because there
has not been enough trading of our stock to determine an appropriate measure of
volatility. We believe our estimate of volatility is reasonable, and we review
the assumptions used to determine this whenever we issue a new equity
instruments.  If we have a material error in our estimate of the
volatility of our stock, our expenses could be understated or
overstated.





Recent
Issued Accounting Standards




In May
2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 163,
“Accounting for Financial
Guarantee Insurance Contracts – An interpretation of FASB Statement No.
60”. SFAS No. 163 requires that an insurance enterprise recognize a claim
liability prior to an event of default when there is evidence that credit
deterioration has occurred in an insured financial obligation. It also clarifies
how Statement 60 applies to financial guarantee insurance contracts, including
the recognition and measurement to be used to account for premium revenue and
claim liabilities, and requires expanded disclosures about financial guarantee
insurance contracts. It is effective for financial statements issued for fiscal
years beginning after December 15, 2008, except for some disclosures about the
insurance enterprise’s risk-management activities. SFAS No. 163 requires that
disclosures about the risk-management activities of the insurance enterprise be
effective for the first period beginning after issuance. Except for those
disclosures, earlier application is not permitted. The adoption of this
statement is not expected to have a material effect on the Company’s financial
statements.




In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles”. SFAS No. 162 identifies the sources of accounting
principles and the framework for selecting the principles to be used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting principles in the
United States. It is effective 60 days following the SEC’s approval of the
Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting Principles”. The adoption
of this statement is not expected to have a material effect on the Company’s
financial statements.


64




In March
2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161,
“Disclosures about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133”. SFAS No. 161 is intended to improve financial standards for
derivative instruments and hedging activities by requiring enhanced disclosures
to enable investors to better understand their effects on an entity's financial
position, financial performance, and cash flows. Entities are required to
provide enhanced disclosures about: (a) how and why an entity uses derivative
instruments; (b) how derivative instruments and related hedged items are
accounted for under Statement 133 and its related interpretations; and (c) how
derivative instruments and related hedged items affect an entity’s financial
position, financial performance, and cash flows. It is effective for financial
statements issued for fiscal years beginning after November 15, 2008, with early
adoption encouraged. The Company is currently evaluating the impact of SFAS No.
161 on its financial statements, and the adoption of this statement is not
expected to have a material effect on the Company’s financial
statements.




In
December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No.
141 (revised 2007), “Business Combinations”. This statement replaces SFAS No.
141 and defines the acquirer in a business combination as the entity that
obtains control of one or more businesses in a business combination and
establishes the acquisition date as the date that the acquirer achieves control.
SFAS 141 (revised 2007) requires an acquirer to recognize the assets acquired,
the liabilities assumed, and any non-controlling interest in the acquired at the
acquisition date, measured at their fair values as of that date. SFAS 141
(revised 2007) also requires the acquirer to recognize contingent consideration
at the acquisition date, measured at its fair value at that date. This statement
is effective for fiscal years, and interim periods within those fiscal years,
beginning on or after December 15, 2008. Earlier adoption is prohibited. The
adoption of this statement is not expected to have a material effect on the
Company's financial statements.




In
December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in
Consolidated Financial Statements Liabilities –an Amendment of ARB No. 51”. This
statement amends ARB 51 to establish accounting and reporting standards for the
Non-controlling interest in a subsidiary and for the deconsolidation of a
subsidiary. This statement is effective for fiscal years, and interim periods
within those fiscal years, beginning on or after December 15, 2008. Earlier
adoption is prohibited. The adoption of this statement is not expected to have a
material effect on the Company's financial statements.





Effects
of Inflation and Pricing





The oil
and natural gas industry is very cyclical and the demand for goods and services
of oil field companies, suppliers and others associated with the industry puts
extreme pressure on the economic stability and pricing structure within the
industry. Material changes in prices impact revenue stream, estimates of future
reserves, borrowing base calculations of bank loans and value of properties in
purchase and sale transactions. Material changes in prices can impact the value
of oil and natural gas companies and their ability to raise capital, borrow
money and retain personnel. We anticipate business costs and the demand for
services related to production and exploration will fluctuate while the
commodity prices for oil and natural gas, both remain volatile.




Item
7A. Quantitative and Qualitative Disclosures about Market Risk.





Not applicable.


65




Item
8. Financial Statements and Supplementary Data.





Management
Responsibility for Financial Information





We are
responsible for the preparation, integrity and fair presentation of our
financial statements and the other information that appears in this annual
report on Form 10-K. The financial statements have been prepared in accordance
with accounting principles generally accepted in the United States and include
estimates based on our best judgment.





We
maintain a comprehensive system of internal controls and procedures designed to
provide reasonable assurance, at an appropriate cost-benefit relationship, that
our financial information is accurate and reliable, our assets are safeguarded
and our transactions are executed in accordance with established
procedures.





Weaver
& Martin, LLC, an independent registered public accounting firm, is retained
to audit our consolidated financial statements. Its accompanying report is based
on audits conducted in accordance with the standards of the Public Company
Accounting Oversight Board (United States).





The Audit
Committee, which is comprised of two independent directors, meets with our
management and the independent registered public accounting firm to ensure that
each is properly fulfilling its responsibilities. The Committee oversees our
systems of internal control, accounting practices, financial reporting and
audits to ensure their quality, integrity and objectivity are sufficient to
protect stockholders’ investments.





Our
consolidated financial statements and notes thereto, and other information
required by this Item 8 are included in this report beginning on page


F-1.




Item
9. Changes in and Disagreements With Accountants On Accounting and Financial
Disclosure.





None.




Item
9A(T). Controls and Procedures.





Our Chief
Executive Officer, C. Stephen Cochennet, and our Chief Financial Officer,
Dierdre P. Jones, evaluated the effectiveness of our disclosure controls and
procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of
1934, as amended) as of the end of the period covered by this
Report.  Based on the evaluation, Mr. Cochennet and Ms. Jones
concluded that our disclosure controls and procedures are effective in timely
alerting them to material information relating to us (including our consolidated
subsidiaries) required to be included in our periodic SEC filings.





There
were no changes in our internal control over financial reporting that occurred
during our most recent fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.


66


Management’s
Report on Internal Control over Financial Reporting





Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as is defined in the Securities Exchange Act
of 1934. These internal controls are designed to provide reasonable assurance
that the reported financial information is presented fairly, that disclosures
are adequate and that the judgments inherent in the preparation of financial
statements are reasonable. There are inherent limitations in the effectiveness
of any system of internal control, including the possibility of human error and
overriding of controls. Consequently, an effective internal control system can
only provide reasonable, not absolute, assurance, with respect to reporting
financial information.





Management
conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the framework and criteria established in Internal
Control — Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation, management
concluded that our internal control over financial reporting was effective as of
March 31, 2009.





This
annual report does not include an attestation report of our registered public
accounting firm regarding internal control over financial reporting.
Management’s report was not subject to attestation by our registered public
accounting firm pursuant to temporary rules of the Securities and Exchange
Commission that permit us to provide only management’s report in this annual
report.




Item
9B. Other Information.





None.





PART III




Item
10. Directors, Executive Officers and Corporate Governance.





The following table sets forth certain
information regarding our current
directors and executive officers. Our executive officers serve one-year
terms.





Name
                
                Age
                
                Position
                
                Board Committee(s)(1)C. Stephen
      Cochennet
                
                52
                
                President, Chief Executive
      Officer, and Chairman
                
                NoneDierdre P.
      Jones
                
                44
                
                Chief Financial
      Officer
                
                NoneRobert G.
      Wonish
                
                55
                
                Director
                
                GCNC (Chairman)
      and
                  AuditDaran G.
      Dammeyer
                
                48
                
                Director
                
                Audit (Chairman)
      and
                  GCNCDarrel G.
      Palmer
                
                51
                
                Director
                
                GCNCDr. James W.
      Rector
                
                48
                
                Director
                
                None





(1)
            “GCNC”
      means the Governance, Compensation and Nominating Committee of the Board
      of Directors. “Audit” means the Audit Committee of the Board of
      Directors.


67


C. Stephen Cochennet, has
been our President, Chief Executive Officer and Chairman since August 15,
2006.    From July 2002 to present, Mr. Cochennet has been
President of CSC Group, LLC. Mr. Cochennet formed the CSC Group, LLC through
which he supports a number of clients that include Fortune 500 corporations,
international companies, natural gas/electric utilities, outsource service
providers, as well as various start up organizations. The services provided
include strategic planning, capital formation, corporate development, executive
networking and transaction structuring. Mr. Cochennet currently spends less than
10 hours per month on activities associated with CSC Group, LLC. From 1985 to
2002, he held several executive positions with UtiliCorp United Inc. (Aquila) in
Kansas City. His responsibilities included finance, administration, operations,
human resources, corporate development, natural gas/energy marketing, and
managing several new start up operations. Prior to his experience at UtiliCorp
United Inc., Mr. Cochennet served 6 years with the Federal Reserve System. Mr.
Cochennet graduated from the University of Nebraska with a B.A. in Finance and
Economics.





Dierdre P. Jones was promoted
to Chief Financial Officer on July 23, 2008. Ms. Jones was our Director of
Finance and Accounting from August 2007 through July 2008.  From May 2007
through August 2007, Ms. Jones provided independent consulting services for the
company, primarily in the testing and implementation of financial accounting and
reporting software.  From May 2002 through May 2007, Ms. Jones was sole
proprietor of These Faux
Walls, a specialty design company. She holds the professional
designations of Certified Public Accountant and Certified Internal
Auditor.  Prior to joining EnerJex, Ms. Jones held management positions
with UtiliCorp United Inc. (Aquila), and served three years in public accounting
with Arthur Andersen & Co. Ms. Jones graduated with distinction from the
University of Kansas with a B.S. in Accounting and Business
Administration.




Robert G. Wonish has served
as a member of our board of directors since May 2007. Effective April 7, 2009,
Mr. Wonish was appointed President & Chief Operating Officer of Petrodome
Energy, LLC, a privately held firm. From December 2004 to June 30, 2007, Mr.
Wonish was Vice President of Petroleum Engineers Inc., a subsidiary of The CYMRI
Corporation, now CYMRI, L.L.C., which is a wholly-owned subsidiary of Stratum
Holdings, Inc. On July 1, 2007, Mr. Wonish was appointed President and Chief
Operating Officer of Petroleum Engineers Inc. Mr. Wonish was also President of
CYMRI, L.L.C. After the sale of Petroleum Engineers Inc. in March of 2008, Mr.
Wonish resigned all positions in Petroleum Engineers Inc. and CYMRI, L.L.C. as
well as resigning as a member of the Stratum Holdings, Inc. board of directors.
Mr. Wonish held the position of President & Chief Operating Officer of
Striker Oil & Gas, Inc. prior to his engagement with Petrodome Energy,
LLC..  He previously achieved positions of increasing responsibility
with PANACO, Inc., a public oil and natural gas company, ultimately serving as
that company’s President and Chief Operating Officer. He began his engineering
career at Amoco in 1975 and joined Panaco’s engineering staff in
1992.  Mr. Wonish serves as EnerJex’s chairman of the Governance,
Compensation and Nominating committee and is a member of the company’s audit
committee. Mr. Wonish received his Mechanical Engineering degree from the
University of Missouri-Rolla.


68




Daran G. Dammeyer, has served
as a member of our board of directors since May 2007. Since July 1999, Mr.
Dammeyer has served as President of D-Two Solutions through which he supports
clients by primarily providing merger and acquisition support, strategic
planning, budgeting and forecasting process development and
implementation.  From March 1999 through July 1999, Mr. Dammeyer was a
Director of International Financial Management for UtiliCorp United Inc.
(Aquila), a multinational energy solutions provider in Kansas City,
Missouri.  From November 1995 through March 1999, Mr. Dammeyer served
as the Chief Financial Controller of United Energy Limited in Melbourne,
Australia.  Mr. Dammeyer also served in numerous management positions
at Michigan Energy Resources Company, including Director of Internal
Audit.  Mr. Dammeyer earned his Bachelor of Business Administration
degree, with dual majors in Accounting and Corporate Financial Management from
The University of Toledo, Ohio.




Darrel G. Palmer, has served
as a member of our board of directors since May of 2007. Since January 1997, Mr.
Palmer has been President of Energy Management Resources, an energy process
management firm serving industrial and large commercial companies throughout the
U. S. and Canada.  Mr. Palmer has 25 years of expertise in the natural
gas arena.  His experiences encompass a wide area of the natural gas
industry and include working for natural gas marketing companies, local
distribution companies, and FERC regulated pipelines.  Prior to
becoming an independent energy consultant in 1997, Mr. Palmer’s last position
was Vice President/National Account Sales at UtiliCorp United Inc. (Aquila) of
Kansas City, Missouri.  Over the years Mr. Palmer has worked in many civic
organizations including United Way and has been a President of the local Kiwanis
Club.  Junior Achievement of Minnesota awarded him the Bronze
Leadership Award for his accomplishments which included being an advisor,
program manager, holding various Board positions, and ultimately being Board
President.





Dr. James W. Rector, has
served as a member of our board of directors since March 19, 2008.Dr. Rector is
the author of numerous technical papers along with a number of patents on
seismic technology. He was a co-founder of two seismic technology startups that
were later sold to NYSE-listed companies, and he regularly consults for many of
the major oil companies including Chevron and BP. In 1998, he founded Berkeley
GeoImaging LLC, which has completed five equity private placements for oil and
natural gas exploration and development projects. Dr. Rector is a tenured
professor of Geophysics at the University of California at Berkeley and a
faculty staff scientist at the Lawrence Berkeley National Laboratory. He has
been the Editor-in-Chief of the Journal of Applied Geophysicsand has also served on the Society of Exploration Geophysicists Executive
Committee. He received his Masters and Ph.D. degrees in Geophysics from Stanford
University.




Section
16(a) Beneficial Ownership Reporting Compliance





Section 16(a) of the Securities Exchange
Act of 1934, as amended (the “Exchange Act”), requires our executive officers and
directors, and persons who beneficially own more than ten percent of our common
stock, to file initial reports of ownership and reports of changes in ownership
with the SEC. Executive officers, directors and greater than ten percent
beneficial owners are required by SEC regulations to furnish us with copies of
all Section 16(a) forms they file. Based upon a review of the copies of such forms furnished to us and
written representations from our executive officers and directors, we believe
that as of the date of this report they were all current in their 16(a)
reports.


69


Board
of Directors





Our board of directors currently
consists of five members. Our directors serve one-year terms. Our board of
directors has affirmatively determined that Messrs. Wonish, Dammeyer, Palmer and
Dr. Rector are independent directors, as defined by Section 803 of the American
Stock Exchange Company Guide.





Committees
of the Board of Directors





Our board of directors has two standing
committees: an audit committee and a governance, compensation and nominating
committee. Each of those committees has the composition and responsibilities set
forth below.





Audit
Committee





On May 4,
2007, we established and appointed initial members to the audit committee of our
board of directors. Mr. Dammeyer is the chairman and Mr. Wonish serves as the
other member of the committee.  Currently, none of the members of the
audit committee are, or have been, our officers or employees, and each member
qualifies as an independent director as defined by Section 803 of the American
Stock Exchange Company Guide and Section 10A(m) of the Securities Exchange Act
of 1934, and Rule 10A-3 thereunder.  The Board of Directors has
determined that Mr. Dammeyer is an “audit committee financial expert” as
that term is used in Item 401(h) of Regulation S-K promulgated under the
Securities Exchange Act. The audit committee held five meetings during fiscal
2009.





The audit
committee has the sole authority to appoint and, when deemed appropriate,
replace our independent registered public accounting firm, and has established a
policy of pre-approving all audit and permissible non-audit services provided by
our independent registered public accounting firm. The audit committee has,
among other things, the responsibility to evaluate the qualifications and
independence of our independent registered public accounting firm; to review and
approve the scope and results of the annual audit; to review and discuss with
management and the independent registered public accounting firm the content of
our financial statements prior to the filing of our quarterly reports and annual
reports; to review the content and clarity of our proposed communications with
investors regarding our operating results and other financial matters; to review
significant changes in our accounting policies; to establish procedures for
receiving, retaining, and investigating reports of illegal acts involving us or
complaints or concerns regarding questionable accounting or auditing matters,
and supervise the investigation of any such reports, complaints or concerns; to
establish procedures for the confidential, anonymous submission by our employees
of concerns or complaints regarding questionable accounting or auditing matters;
and to provide sufficient opportunity for the independent auditors to meet with
the committee without management present.


70


Governance, Compensation and Nominating
Committee





The governance, compensation and
nominating committee is comprised of Messrs. Wonish, Dammeyer and
Palmer.  Mr. Wonish serves as the chairman of the governance,
compensation and nominating committee.  The governance, compensation
and nominating committeeis responsible for,
among other things;identifying, reviewing,
and evaluating individuals qualified to become members of the Board, setting the
compensation of the Chief Executive Officer and performing other compensation
oversight, reviewing and recommending the nomination of Board members, and
administering our equity compensation plans. The governance, compensation and
nominating committee held five meetings during fiscal 2009.





Code
of Ethics





We have adopted aCode of
Business Conduct and Ethics that applies to all of our directors, officers and
employees, as well as to directors, officers and employees of each subsidiary of
the Company. Our Code of Ethics
was filed as Exhibit 99.6 to the Annual Report on Form 10-KSB for the year endedMarch31, 2007which was filed on June 13, 2007.A copy of our Code of Business Conduct and Ethics will be provided to any
person, without charge, upon request. It is available on our
website:  enerjexresources.com, or you may contact C. Stephen
Cochennet at 913-754-7754 to request a copy of the Code or send your request to
EnerJex Resources, Inc., Attn: C. Stephen Cochennet, 27 Corporate Woods, Suite
350, 10975 Grandview Drive, Overland Park, Kansas 66210. If any substantive
amendments are made to the Code of Business Conduct and Ethics or if we grant
any waiver, including any implicit waiver, from a provision of the Code to any
of our officers and directors, we will disclose the nature of such amendment or
waiver in a report on Form 8-K.





Limitation of
Liability of
Directors





Pursuant
to the Nevada General Corporation Law, our Articles of Incorporation exclude
personal liability for our Directors for monetary damages based upon any
violation of their fiduciary duties as Directors, except as to liability for any
breach of the duty of loyalty, acts or omissions not in good faith or which
involve intentional misconduct or a knowing violation of law, or any transaction
from which a Director receives an improper personal benefit. This exclusion of
liability does not limit any right which a Director may have to be indemnified
and does not affect any Director’s liability under federal or applicable state
securities laws. We have agreed to indemnify our directors against expenses,
judgments, and amounts paid in settlement in connection with any claim against a
Director if he acted in good faith and in a manner he believed to be in our best
interests.





Nevada Anti-Takeover
Law and Charter and By-law Provisions





Depending on the number of residents in
the state of Nevada who own
our shares, we could be subject to the provisions of Sections 78.378et
seq. of the Nevada Revised
Statutes which, unless otherwise provided in a company’s articles of incorporation or by-laws,
restricts the ability of an acquiring person to obtain a controlling interest of 20% or more
of our voting shares. Our articles of incorporation and by-laws do not contain
any provision which would currently keep the change of control restrictions of
Section 78.378 from applying to us.


71


We are subject to the provisions of Sections 78.411et
seq. of the Nevada Revised
Statutes. In general, this statute prohibits a publicly held Nevada corporation
from engaging in a “combination”with an “interested stockholder”for a period of three years after the
date of the transaction in
which the person became an interested stockholder, unless the combination or the
transaction by which the person became an interested stockholder is approved by
the corporation’s board of directors before the person
becomes an interestedstockholder. After the expiration of the
three-year period, the corporation may engage in a combination with an
interested stockholder under certain circumstances, including if the combination
is approved by the board of directors and/or stockholders in a prescribed
manner, or if specified requirements are met regarding consideration. The term
“combination” includes mergers, asset sales and other transactions resulting in
a financial benefit to the interested stockholder. Subject to certain
exceptions, an “interested stockholder” is a person who, together with
affiliates and associates, owns, or within three years did own, 10% or more of
the corporation’s voting stock. A Nevada corporation may “opt out” from the
application of Section 78.411 et seq. through a provision
in its articles of incorporation or by-laws. We have not “opted out” from the
application of this section.





Apart from Nevada law, however, our
articles of incorporation and by-laws do not contain any provisions which are
sometimes associatedwith
inhibiting a change of control from occurring (i.e., we do not provide for a
staggered board, or for “super-majority”votes on major corporate issues).
However, we do have 10,000,000 shares of authorized “blank check”preferred stock, which could
beused to inhibit a change in
control.




Item
11. Executive Compensation.





The following table sets forth summary
compensation information for the fiscal years endedMarch 31, 2009and 2008for our chief executive officer and
chief financial officer. We didnot have any other executive officers
as of the end of fiscal 2009whose total compensation exceeded
$100,000.We refer tothesepersons as our named executive
officerselsewhere in this
report.





Summary Compensation
Table




Name and Principal Position
                          
                          Fiscal
                            Year
                          
                          Salary
                            ($)
                          
                          
                          Bonus
                            ($)
                          
                          
                          Option
                            Awards
                            ($)
                          
                          
                          All Other
                            Compen-
                            sation
                            ($)
                          
                          
                          Total
                            ($)C.
      Stephen Cochennet
                          
                          2009
                          
                          $
                          186,525
                          
                          
                          $
                          50,000
                          
                          
                          $
                          -
                          (2)
                          
                          $
                          -
                          
                          
                          $
                          236,525President,
      Chief Executive Officer
                          
                          2008
                          
                          $
                          156,000
                          
                          
                          
                          -
                          
                          
                          
                          859,622
                          (1)
                          
                          
                          -
                          
                          
                          $
                          1,015,622Dierdre
      P. Jones
                          
                          2009
                          
                          $
                          128,808
                          
                          
                          $
                          10,000
                          
                          
                          
                          -
                          (2)
                          
                          
                          -
                          
                          
                          $
                          138,808Chief
      Financial Officer
                          
                          2008
                          
                          
                          -
                          (3)
                          
                          
                          -
                          (3)
                          
                          
                          -
                          (3)
                          
                          
                          -
                          (3)
                          
                          
                          -
                          (3)





(1)
            Amount represents the estimated
      total fair value of stock options granted to Mr. Cochennet under SFAS
      123(R).


(2)
            InAugust, 2008,we granted
      C. Stephen Cochennet, our chief executive officer, an option to purchase
      75,000 shares of our common stock at $6.25 per share and we granted
      Dierdre P. Jones, our chief financial officer, and option to purchase
      40,000 shares of our common stock at $6.25 per shareunder SFAS 123(R) as discussed in
      Note 3 to our financial statements for the year ended March 31, 2009
      included elsewhere in this report. These options were rescinded in
      November 2008 at the request of the board’s compensation committee and the
      approval of each option holder.


72


(3)
            Ms.
      Jones was promoted to chief financial officer during fiscal 2009 and was
      not a named executive officer in fiscal
2008.





Outstanding Equity
Awards at 2008 Fiscal Year-End





The following tablelists the outstanding equity incentive
awards held by our named executive officers as ofMarch 31, 2009.





Option AwardsFiscal
                                            Year
                                          
                                          Number of
                                            Securities
                                            Underlying
                                            Unexercised
                                            Options
                                            Exercisable
                                            (#)
                                          
                                          
                                          Number of
                                            Securities
                                            Underlying
                                            Unexercised
                                            Options
                                            Unexercisable
                                            (#)
                                          
                                          
                                          Number of
                                            Securities
                                            Underlying
                                            Unexercised
                                            Unearned
                                            Options
                                            (#)
                                          
                                          
                                          Option
                                            Exercise
                                            Price
                                            ($)
                                          
                                          Option
                                            Expiration
                                            DateC.
      Stephen Cochennet
                                          
                                          2009
                                          
                                          
                                          200,000
                                          
                                          
                                          
                                          -
                                          
                                          
                                          
                                          -
                                          
                                          
                                          $
                                          6.25
                                          
                                          05/03/2011Dierdre
      P. Jones
                                          
                                          2009
                                          
                                          
                                          20,000
                                          
                                          
                                          
                                          -
                                          
                                          
                                          
                                          -
                                          
                                          
                                          $
                                          6.30
                                          
                                          07/31/2011





Option Exercises for fiscal2009





There were no options exercised by our
named executive officers in fiscal2009. See “Securities Authorized for Issuance under
Equity Compensation Plans”onpage 49for a description of our outstanding
equity compensation
plans.





Potential Payments
Upon Termination or Change in Control





We entered intoemployment agreementswithbothof our named executive officers whichcould result in payments to such officers
because of their resignation,incapacity or disability, or other termination of employment
with us or our subsidiaries, orachange in control, or a change in the person’s responsibilities following a change in
control.





Director
Compensation




The following table sets forth summary
compensation informationfor the fiscal year endedMarch 31, 2009for each of our non-employee
directors.





Name
                
                Fees
                  Earned
                  or Paid in
                  Cash
                  $
                
                
                Stock
                  Awards
                  $
                
                
                Option
                  Awards(2)
                  $
                
                
                All Other
                  Compensation
                  $
                
                
                Total
                  $Daran
      G. Dammeyer
                
                $
                58,000
                
                
                $
                12,000
                (1)
                
                $
                -0-
                
                
                $
                -0-
                
                
                $
                70,000Darrel
      G. Palmer
                
                $
                26,500
                
                
                $
                -0-
                
                
                $
                -0-
                
                
                $
                20,000
                (3)
                
                $
                46,500Robert
      G. Wonish
                
                $
                49,000
                
                
                $
                -0-
                
                
                $
                -0-
                
                
                $
                -0-
                
                
                $
                49,000Dr.
      James W. Rector
                
                $
                22,500
                
                
                $
                -0-
                
                
                $
                -0-
                
                
                $
                -0-
                
                
                $
                22,500




73


(1)
            Amount represents the estimated
      total fair marketvalue of 2,182 shares of common stock issued to Mr. Dammeyer for services
      as audit committee chairman under SFAS 123(R), as discussed in Note 3 to
      our audited financial statements for the year ended March 31, 2009
      included elsewhere in this
report.


(2)
            InJuly, 2008, 28,000 stock options
      were granted to each of Messrs. Dammeyer, Palmer and Wonish and 38,000
      stock options were granted to Dr. Rector under SFAS 123(R), as discussed
      in Note 3 to our financial statements for the year ended March 31, 2009
      included elsewhere in this report. These
      total 122,000 options granted to Messrs. Dammeyer, Palmer and Wonish and
      to Dr. Rector were rescinded in November
  2008.


(3)
            Mr.
      Palmer was paid $20,000 for assisting in the establishment and development
      of the audit committee and for his involvement and assistance to the chief
      executive officer in finalizing the hedging instrument with
      BP.





Item
12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters.





The
following table presents information,to the best of EnerJex’s knowledge,about the ownership
of EnerJex’s common stock on July 14, 2009 relating to those persons known to
beneficially own more than 5% of EnerJex’s capital stock and by EnerJex’s
directors and executive officers. The percentage of beneficial ownership for the
following table is based on 4,443,512 shares of common stock
outstanding.





Beneficial
ownership is determined in accordance with the rules of the Securities and
Exchange Commission and does not necessarily indicate beneficial ownership for
any other purpose. Under these rules, beneficial ownership includes those shares
of common stock over which the stockholder has sole or shared voting or
investment power. It also includes shares of common stock that the stockholder
has a right to acquire within 60 days after July 14, 2009 pursuant to options,
warrants, conversion privileges or other right. The percentage ownership of the
outstanding common stock, however, is based on the assumption, expressly
required by the rules of the Securities and Exchange Commission, that only the
person or entity whose ownership is being reported has converted options or
warrants into shares of EnerJex’s common stock.




Name and Address of Beneficial Owner, Officer
      or
                      Director(1)
                    
                    Number
                      of Shares
                    
                    
                    Percent of
                      Outstanding
                      Shares of
                      Common Stock(2)C.
      Stephen Cochennet, President & Chief Executive Officer(3)
                    
                    
                    600,000
                    (4)
                    
                    
                    12.5
                    %Dierdre
      P. Jones, Chief Financial Officer
                    
                    
                    20,000
                    
                    
                    
                    *Robert
      (Bob) G. Wonish, Director(3)
                    
                    
                    40,000
                    (5)
                    
                    
                    *Darrel
      G. Palmer, Director(3)
                    
                    
                    40,000
                    (5)
                    
                    
                    *Daran
      G. Dammeyer, Director(3)
                    
                    
                    44,102
                    (5)
                    
                    
                    *Dr.
      James W. Rector, Director(3)
                    
                    
                    -0-
                    
                    
                    
                    *Directors
      and Officers as a Group
                    
                    
                    
                    
                    
                    
                    15.6
                    %West
      Coast Opportunity Fund LLC(6)
                      West
      Coast Asset Management, Inc.
                      Paul
      Orfalea, Lance Helfert & R. Atticus Lowe
                      2151
      Alessandro Drive, #100
                      Ventura,
      CA 93001
                    
                    
                    1,000,000
                    
                    
                    
                    22.5
                    %Enable
      Growth Partners L.P.(7)
                      Enable
      Capital Management, LLC
                      Mitchell
      S. Levine
                      One
      Ferry Building, Suite 225
                      San
      Francisco, CA 94111
                    
                    
                    353,800
                    
                    
                    
                    8.7
                    %





74







*
            Represents beneficial ownership of
      less than 1%


(1)
              As
      used in this table, “beneficial ownership” means the sole or shared power
      to vote, or to direct the voting of, a security, or the sole or shared
      investment power with respect to a security (i.e., thepower to dispose
      of, or to direct the disposition of, a
  security).


(2)
            Figures
      are rounded to the nearest tenth of a
percent.


(3)
            The
      address of each person is care of EnerJex Resources: Corporate Woods 27,
      Suite 350, 10975 Grandview Drive, Overland Park,
      Kansas  66210.


(4)
            Includes
      200,000 options, exercisable at $6.25 per share through May 3,
      2011.


(5)
            Includes
      40,000 options, exercisable at $6.25 per share through May 3,
      2011.


(6)
            Based
      on a Schedule 13D filed with the SEC on February 13, 2009, the investment
      manager of West Coast Opportunity Fund, LLC (“WCOF”) is West Coast Asset
      Management (“WCAM”).  WCAM has the authority to take any and all
      actions on behalf of WCOF, including voting any shares held by
      WCOF.  Paul Orfalea, Lance Helfert and R. Atticus Lowe
      constitute the Investment Committee of WCOF.  Messrs. Orfalea,
      Helfert and Lowe disclaim beneficial ownership of the
    shares.


(7)
            Based
      on a Schedule 13G/A filed with the SEC on February 11, 2009, Enable
      Capital Management, LLC, as general and investment manager of Enable
      Growth Partners L.P. and other clients, may be deemed to have the power to
      direct the voting or disposition of shares of common stock held by Enable
      Growth Partners L.P. (353,800 shares of common stock) and other clients
      (285,040 shares of common stock).  Therefore, Energy Capital
      Management, LLC, as Enable Growth Partners L.P.’s and those other
      accounts’ general partner and investment manager, and Mitchell S. Levine,
      as managing member and majority owner of Enable Capital Management, LLC,
      may be deemed to beneficially own the shares of common stock owned by
      Enable Growth Partners L.P. and such other
  accounts.





Equity
Compensation Plan Information





The
following table sets forth information as of March 31, 2009 regarding
outstanding options granted under our stock option plans and options reserved
for future grant under the plans.




Plan
    Category
                      
                      Number
                        of shares to be issued
                        upon exercise of
                        outstanding options,
                        warrants and rights
                        (a)
                      
                      
                      Weighted-average
                        exercise price of
                        outstanding options,
                        warrants and rights
                        (b)
                      
                      
                      Number of shares
                        remaining available for
                        future issuance under
                        equity compensation
                        plans (excludingshares
                        reflected in column (a)
                        (c)Equity compensation plansapproved by
      stockholders
                      
                      
                      438,500
                      
                      
                      $
                      6.30
                      
                      
                      
                      761,500Equity compensation plans notapproved by
      stockholders
                      
                      
                      —
                      
                      
                      
                      —
                      
                      
                      
                      —Total
                      
                      
                      438,500
                      
                      
                      $
                      6.30
                      
                      
                      
                      761,500




75


On May 4,
2007, we granted a non-qualified option to C. Stephen Cochennet for all 200,000
options available under our 2000 Stock Option and Incentive Plan.





As of
March 31, 2009, we have granted 254,330 non-qualified options under our
2002-2003 Stock Option Plan at prices ranging from $6.25 to $6.30 per
share.




Item
13. Certain Relationships and Related Transactions, and Director
Independence.




We describe below transactions and
series of similar transactions that have occurred during this fiscal year to
which we were a party or will be a party in which:





•
            The amounts involved exceeds the
      lesser of$120,000 or
      onepercent of the
      average of our total assets at year end for the last two completedfiscal
      years ($93,280);
  and





•
            A director, executive officer,
      holder of more than 5% of our common stock or any member of their
      immediate family had or will have a direct or indirect material
      interest.





Our board
of directors has affirmatively determined that Messrs. Wonish, Dammeyer, Palmer
and Dr. Rector are independent directors, as defined by Section 803 of the
American Stock Exchange Company Guide. Mr. Palmer is not eligible to serve on
our Audit Committee pursuant to Section 10A(m)(3) of the Securities Exchange Act
of 1934, as amended.




Item
14. Principal Accountant Fees and Services.





Weaver & Martin, LLC served as our
principal independent public accountants for fiscal 2009 and 2008 years.
Aggregate fees billed to us for the fiscal years ended March 31, 2009 and 2008
by Weaver & Martin, LLC were as follows:





For
      the Fiscal Years
                      Ended
                      March
      31,2009
                    
                    2008Audit
      Fees(1)
                    
                    $
                    56,000
                    
                    
                    $
                    105,000Audit-Related
      Fees(2)
                    
                    
                    -0-
                    
                    
                    
                    -0-Tax
      Fees(3)
                    
                    
                    10,000
                    
                    
                    
                    13,000All
      Other Fees(4)
                    
                    
                    19,718
                    
                    
                    
                    -0-Total
      fees
      paid or accrued to our principal accountant
                    
                    $
                    85,718
                    
                    
                    $
                    118,000





(1)
            Audit Fees include fees billed and
      expected to be billed for services performed to comply with Generally
      Accepted Auditing Standards (GAAS), including the recurring audit of the
      Company’s consolidated financial
      statements for such period included in this Annual Report on
      Form 10-K and for the reviews of the consolidated quarterly financial
      statements included in the Quarterly Reports on Form 10-QSB filed
      with the Securities and ExchangeCommission. This category also
      includes fees for audits provided in connection with statutory filings or
      procedures related to audit of income tax provisions and related reserves,
      consents and assistance with and review of documents filed with the
      SEC.


76


(2)
            Audit-Related Fees include fees
      for services associated with assurance and reasonably related to the
      performance of the audit or review of the Company’s financial statements. This
      category includes fees related to assistance in financial due diligencerelated to mergers
      and acquisitions, consultations regarding Generally Accepted Accounting
      Principles, reviews and evaluations of the impact of new regulatory
      pronouncements, general assistance with implementation of Sarbanes-Oxley
      Act of 2002 requirementsand audit services not required
      by statute or regulation.


(3)
            Tax fees consist of fees related
      to the preparation and review of the Company’s federal and state income tax
      returns.


(4)
            Other fees include fees related to
      the preparation and review of the Form S-1 Registration
      Statement.





Audit Committee Policies and
Procedures





Our Audit
Committee pre-approves all services to be provided to us by our independent
auditor. This process involves obtaining (i) a written description of the
proposed services, (ii) the confirmation of our Principal Accounting
Officer that the services are compatible with maintaining specific principles
relating to independence, and (iii) confirmation from our securities
counsel that the services are not among those that our independent auditors have
been prohibited from performing under SEC rules, as outlined in the Audit
Committee charter. The members of the Audit Committee then make a determination
to approve or disapprove the engagement of Weaver & Martin for the proposed
services. In fiscal 2009, all fees paid to Weaver & Martin were unanimously
pre-approved in accordance with this policy.





Less than
50 percent of hours expended on the principal accountant's engagement to audit
the registrant's financial statements for the most recent fiscal year were
attributed to work performed by persons other than the principal accountant's
full-time, permanent employees.





AUDIT
COMMITTEE AND INDEPENDENT PUBLIC ACCOUNTANTS




Qualification
Of Audit Committee Members




Our
Audit Committee consists of two independent directors, each of whom has been
selected for membership on the Audit Committee by the Board of Directors based
on the Board's determination that he is fully qualified to oversee EnerJex's
internal audit function, assess and select independent auditors, and oversee
EnerJex's financial reporting processes and overall risk management. The Audit
Committee has the authority to seek advice and assistance from outside legal,
accounting or other advisors and exercises such authority as it deems necessary.
The full text of the charter of the Audit Committee can be found in the investor
section of our website at www.enerjexresources.com.




Through
a range of education, experiences in business and executive leadership and
service on the boards of directors, and through experience on EnerJex's Board of
Directors and Audit Committee, each member of the Committee has an understanding
of generally accepted accounting principles and has experience in evaluating the
financial performance of public companies. Moreover, the Audit Committee members
have gained valuable special knowledge of the financial condition and
performance of EnerJex. The Board has determined that Daran G. Dammeyer is a
"financial expert" as that term is used in Item 401(h) of Regulation S-K
promulgated under the Securities Exchange Act.


77




Report
Of The Audit Committee Of The Board




The
Company’s management is responsible for preparing our financial statements and
ensuring they are complete and accurate and prepared in accordance with
generally accepted accounting principles. Weaver & Martin, LLC, our
independent registered public accounting firm, is responsible for performing an
independent audit of our consolidated financial statements and expressing an
opinion on the conformity of those financial statements with generally accepted
accounting principles.




The Audit
Committee has reviewed and discussed with our management the audited financial
statements of the Company included in our Annual Report on Form 10-K for
the fiscal year ended March 31, 2009 (“10-K”).




The Audit
Committee has also reviewed and discussed with Weaver & Martin, LLC the
audited financial statements in the 10-K. In addition, the Audit Committee
discussed with Weaver & Martin, LLC those matters required to be discussed
by the Statement on Auditing Standards No. 61, as amended. Additionally,
Weaver & Martin, LLC provided to the Audit Committee the written disclosures
and the letter required by applicable requirements of the Public Company
Accounting Oversight Board regarding the independent accountant’s communications
with the Audit Committee concerning independence. The Audit Committee also
discussed with Weaver & Martin, LLC its independence from the
Company.




Based
upon the review and discussions described above, the Audit Committee recommended
to the Board of Directors that the audited financial statements be included in
the Company’s 10-K for filing with the United States Securities and Exchange
Commission.




Submitted
by the following members of the Audit Committee:




Daran G.
Dammeyer (Chairman)




Robert G.
Wonish




PART IV




Item
15. Exhibits, Financial Statement Schedules.





The
following information required under this item is filed as part of this
report:





(a) 1.
Financial Statements





PageManagement
      Responsibility for Financial Information
                  65Management’s
      Report on Internal Control Over Financial Reporting
                  66Index
      to Financial Statements
                  F-1Report
      of Independent Registered Public Accounting Firm
                  F-2Consolidated
      Balance Sheets
                  F-3Consolidated
      Statements of Operations
                  F-4Consolidated
      Statements of Stockholders Equity
                  F-5Consolidated
      Statements of Cash Flows
                  F-6




78


2.
Financial Statement Schedules





None.





3. Exhibit Index





Exhibit No.
              
              Description2.1
              
              Agreement
      and Plan of Merger between Millennium Plastics Corporation and Midwest
      Energy, Inc. effective August 15, 2006 (incorporated by reference to
      Exhibit 2.3 to the Form 8-K filed on August 16, 2006)3.1
              
              Amended
      and Restated Articles of Incorporation, as currently in effect
      (incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August
      14, 2008)3.2
              
              Amended
      and Restated Bylaws, as currently in effect (incorporated by reference
      to Exhibit 3.3 to the Form SB-2 filed on February 23,
  2001)4.1
              
              Article
      VI of Amended and Restated Articles of Incorporation of Millennium
      Plastics Corporation (incorporated by reference to Exhibit 1.3 to the Form
      8-K filed on December 6, 1999)4.2
              
              Article
      II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of
      Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1
      to the Form SB-2 filed on February 23, 2001)4.3
              
              Specimen
      common stock certificate (incorporated by reference to Exhibit 4.3 to the
      Form S-1/A filed on May 27, 2008)10.1
              
              Credit Agreement with Texas Capital Bank, N.A.
      datedJuly
      3, 2008(incorporated by reference
      to Exhibit 10.33 to the Form 10-K filed on July 10,
  2008)10.2
              
              Promissory Note to Texas Capital
      Bank, N.A. datedJuly
      3, 2008(incorporated by reference
      to Exhibit 10.34 to the Form 10-K filed on July 10,
  2008)10.3
              
              Amended and RestatedMortgage, Security Agreement,
      Financing Statement and Assignment of Production and Revenues with Texas
      Capital Bank, N.A. datedJuly 3, 2008(incorporated by reference
      to Exhibit 10.35 to the Form 10-K filed on July 10,
  2008)10.4
              
              Security Agreement with Texas
      Capital Bank, N.A. datedJuly 3, 2008(incorporated by reference
      to Exhibit 10.36 to the Form 10-K filed on July 10,
  2008)10.5
              
              Letter Agreement with Debenture
      Holders datedJuly3, 2008(incorporated by reference
      to Exhibit 10.37 to the Form 10-K filed on July 10,
  2008)10.6†
              
              C.
      Stephen Cochennet Employment Agreement dated August 1, 2008 (incorporated
      by reference to Exhibit 10.1 to the Form 8-K filed on August 1,
      2008)10.7†
              
              Dierdre P. Jones Employment Agreement
      dated August 1, 2008 (incorporated by reference to Exhibit 10.2 to
      the Form 8-K filed on August 1, 2008)10.8†
              
              Amended and Restated EnerJex
      Resources, Inc. Stock Incentive Plan (incorporated by reference to
      Exhibit 10.1 to the Form 8-K filed on October 16, 2008)10.9
              
              Form of Officer and Director
      Indemnification Agreement (incorporated by reference to Exhibit
      10.2 to the Form 8-K filed on October 16, 2008)10.10
              
              Euramerica Letter Agreement
      Amendment dated September 15,2008 (incorporated by
      reference to Exhibit 10.10 to the Form 8-K filed on September 18,
      2008)10.11
              
              Euramerica Letter Agreement
      Amendment dated October 15, 2008 (incorporated by reference to
      Exhibit 10.11 to the Form 8-K filed on October 21,
2008)10.12(a)†
              
              C. Stephen Cochennet Rescission of
      Option Grant Agreement dated  November 17, 2008(incorporated by reference to
      Exhibit 10.38(a) to the Form 10-Q filed on February 23,
      2009)


79





10.12(b)†
              
              Dierdre P. Jones Rescission of
      Option Grant Agreement datedNovember 17, 2008(incorporated by reference to
      Exhibit 10.38(b) to the Form 10-Q filed on February 23,
      2009)10.12(c)
              
              Daran G. DammeyerRescission of Option Grant
      Agreement dated November 17, 2008(incorporated by reference to
      Exhibit 10.38(c) to the Form 10-Q filed on February 23,
      2009)10.12(d)
              
              Darrel G. PalmerRescission of Option Grant
      Agreement dated November  17, 2008(incorporated by reference to
      Exhibit 10.38(d) to the Form 10-Q filed on February 23,
      2009)10.12(e)
              
              Dr. James W. RectorRescission of Option Grant Agreement
      dated November 17, 2008(incorporated by reference to
      Exhibit 10.38(e) to the Form 10-Q filed on February 23,
      2009)10.12(f)
              
              Robert G. WonishRescission of Option Grant
      Agreement dated November 17, 2008(incorporated by reference to Exhibit 10.38(f) to the
      Form 10-Q filed on February 23, 2009)10.13
              
              Letter
      Agreement with Debenture Holders dated June 11, 2009 (incorporated by
      reference to  Exhibit 10.1 to the Form 8-K filed on June 16,
      2009)10.14
              
              Joint
      Operating Agreement with Pharyn Resources to explore and develop the
      Brownrigg Lease Press Release dated June 1, 2009 (incorporated by
      reference to Exhibit 99.1 to the Form 8-K filed on June 5,
      2009)10.15
              
              Amendment 4 to Joint Exploration
      Agreement effective as of  November 6, 2008 between MorMeg, LLC and
      EnerJex Resources, Inc.10.16
              
              Waiver
      from Texas Capital Bank, N.A. dated  July 14,
    200921.1
              
              List
      of Subsidiaries23.1
              
              Miller
      & Lents, Ltd. Consent Of Independent Petroleum Engineers and
      Geologists Letter dated June 24, 2009 and effective March 31,
      200923.2
              
              Consent
      of Weaver & Martin, LLC31.1
              
              Certification of Chief Executive
      Officer pursuant to Section 302 of the Sarbanes-Oxley Act of
      200231.2
              
              Certification of ChiefFinancialOfficer pursuant to
      Section 302of the
      Sarbanes-Oxley Act of 200232.1
              
              Certification of Chief Executive
      Officer pursuant to Section 906 of the Sarbanes-Oxley Act of
      200232.2
              
              Certification of ChiefFinancialOfficer pursuant to
      Section 906 of the Sarbanes-Oxley Act of
  2002




†
Indicates management contract or compensatory plan or
arrangement.


80


SIGNATURES




Pursuant to the requirements of Section
13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.




ENERJEX
      RESOURCES, INC.By:
                    /s/
      C. Stephen CochennetC.
      Stephen Cochennet, Chief Executive OfficerDate:
      July 14,
2009




Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.




ENERJEX
      RESOURCES, INC.By:
                    /s/
      Dierdre P JonesDierdre
      P Jones, Chief Financial OfficerDate:
      July 14,
2009




Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities and on the dates indicated.




Name
              
              Title
              
              Date/s/
      C. Stephen Cochennet
              
              President,
      Chief Executive Officer,
              
              July
      14, 2009C.
      Stephen Cochennet
              
              (Principal
      Executive Officer),Secretary,
      Chairman/s/
      Dierdre P Jones
              
              Chief
      Financial Officer
              
              July
      14, 2009Dierdre
      P. Jones/s/
      Robert G. Wonish
              
              Director
              
              July
      14, 2009Robert
      G. Wonish/s/
      Daran G. Dammeyer
              
              Director
              
              July
      14, 2009Daran
      G. Dammeyer/s/
      Darrel G. Palmer
              
              Director
              
              July
      14, 2009Darrel
      G. Palmer/s/
      Dr. James W. Rector
              
              Director
              
              July
      14, 2009Dr.
      James W. Rector




81




Index
to Financial Statements




PageIndex
      to Financial Statements
                F-1Report
      of Independent Registered Public Accounting Firm
                F-2Consolidated
      Balance Sheets at March 31, 2009 and 2008
                F-3Consolidated
      Statements of Operations for the Fiscal Years Ended March 31, 2009 and
      2008
                F-4Consolidated
      Statement of Stockholders’ Equity(Deficit) for the Fiscal Years Ended
      March 31, 2009 and 2008
                F-5Consolidated
      Statement of Cash Flows for the Fiscal Years Ended March 31, 2009 and
      2008
                F-6Notes
      to Consolidated Financial Statements
                F-7


F-1


Report
of Independent Registered Public Accounting Firm





Stockholders
and Directors


EnerJex
Resources, Inc.


Overland
Park, Kansas





We have
audited the accompanying consolidated balance sheet of EnerJex Resources, Inc.
as of March 31, 2009 and 2008 and the related consolidated statements of
operations, stockholders’ equity (deficit), and cash flows for each of the years
in the two-year period ended March 31, 2009. These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements 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 audit to obtain reasonable assurance about whether the financial
statements are free of material misstatements. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting.  Our audit included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company’s internal control over financial
reporting.  Accordingly, we express no such opinion.  An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.





In our
opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of EnerJex Resources,
Inc. as of March 31, 2009 and 2008 and the consolidated results of its
operations and cash flows for each of the years in the two–year period ended
March 31, 2009 in conformity with accounting principles generally accepted in
the United States of America.





The
accompanying financial statements have been prepared assuming that the Company
will continue as a going concern. As discussed in Note 2 to the financial
statements, the Company has suffered recurring losses and had negative cash
flows that raise substantial doubt about the Company's ability to continue as a
going concern. Management's plans in regard to these matters are described in
the Note 2. The financial statements do not include any adjustments that might
result from the outcome of this uncertainty.





/S/





Weaver
& Martin, LLC


Kansas
City, Missouri


July 9,
2009


F-2


EnerJex
Resources, Inc. and Subsidiaries


Consolidated
Balance Sheets





March
      31,2009
                  
                  
                  2008AssetsCurrent
      assets:Cash
                  
                  $
                  127,585
                  
                  
                  $
                  951,004Accounts
      receivable
                  
                  
                  462,044
                  
                  
                  
                  227,055Prepaid
      debt issue costs
                  
                  
                  45,929
                  
                  
                  
                  157,191Deposits
      and prepaid expenses
                  
                  
                  263,383
                  
                  
                  
                  176,345Total
      current assets
                  
                  
                  898,941
                  
                  
                  
                  1,511,595Fixed
      assets
                  
                  
                  365,019
                  
                  
                  
                  185,299Less:
      Accumulated depreciation
                  
                  
                  63,988
                  
                  
                  
                  30,982Total
      fixed assets
                  
                  
                  301,031
                  
                  
                  
                  154,317Other
      assets:Prepaid
      debt issue costs
                  
                  
                  -
                  
                  
                  
                  157,191Oil
      and gas properties using full-cost accounting:Properties
      not subject to amortization
                  
                  
                  31,183
                  
                  
                  
                  62,216Properties
      subject to amortization
                  
                  
                  6,449,023
                  
                  
                  
                  8,982,510Total
      other assets
                  
                  
                  6,480,206
                  
                  
                  
                  9,201,917Total
      assets
                  
                  $
                  7,680,178
                  
                  
                  $
                  10,867,829Liabilities
      and Stockholders’ Equity (Deficit)Current
      liabilities:Accounts
      payable
                  
                  $
                  1,016,168
                  
                  
                  $
                  416,834Accrued
      liabilities
                  
                  
                  87,811
                  
                  
                  
                  70,461Notes
      payable
                  
                  
                  -
                  
                  
                  
                  965,000Deferred
      payments from Euramerica development
                  
                  
                  -
                  
                  
                  
                  251,951Long-term
      debt, current
                  
                  
                  1,723,036
                  
                  
                  
                  412,930Total
      current liabilities
                  
                  
                  2,827,015
                  
                  
                  
                  2,117,176Asset
      retirement obligation
                  
                  
                  803,624
                  
                  
                  
                  459,689Convertible
      note payable
                  
                  
                  25,000
                  
                  
                  
                  25,000Long-term
      debt, net of discount of $596,108
                  
                  
                  7,818,163
                  
                  
                  
                  6,831,972Total
      liabilities
                  
                  
                  11,473,802
                  
                  
                  
                  9,433,837Contingencies
      and commitmentsStockholders’
      Equity (Deficit):Preferred
      stock, $0.001 par value, 10,000,000 shares authorized, no shares issued
      and outstanding
                  
                  
                  -
                  
                  
                  
                  -Common
      stock, $0.001 par value, 100,000,000 shares authorized; shares issued and
      outstanding –4,443,512 at March 31, 2009 and 4,440,651 at March 31,
      2008
                  
                  
                  4,444
                  
                  
                  
                  4,441Paid
      in capital
                  
                  
                  8,932,906
                  
                  
                  
                  8,853,457Retained
      (deficit)
                  
                  
                  (12,730,974
                  )
                  
                  
                  (7,423,906
                  )Total
      stockholders’ equity (deficit)
                  
                  
                  (3,793,624
                  )
                  
                  
                  1,433,992Total
      liabilities and stockholders’ equity (deficit)
                  
                  $
                  7,680,178
                  
                  
                  $
                  10,867,829





See
Notes to Consolidated Financial Statements.


F-3


EnerJex
Resources, Inc. and Subsidiaries


Consolidated
Statements of Operations





For the Fiscal Years EndedMarch 31,2009
                    
                    
                    2008Oil
      and natural gas revenues
                    
                    $
                    6,436,805
                    
                    
                    $
                    3,602,798Expenses:Direct
      operating costs
                    
                    
                    2,637,333
                    
                    
                    
                    1,795,188Depreciation,
      depletion and amortization
                    
                    
                    911,293
                    
                    
                    
                    935,330Impairment
      of oil and gas properties
                    
                    
                    4,777,723
                    
                    
                    
                    -Professional
      fees
                    
                    
                    1,320,332
                    
                    
                    
                    1,226,998Salaries
                    
                    
                    849,340
                    
                    
                    
                    1,703,099Administrative
      expense
                    
                    
                    1,392,645
                    
                    
                    
                    887,872Total
      expenses
                    
                    
                    11,888,666
                    
                    
                    
                    6,548,487Loss
      from operations
                    
                    
                    (5,451,861
                    )
                    
                    
                    (2,945,689
                    )Other
      income (expense):Interest
      expense
                    
                    
                    (882,426
                    )
                    
                    
                    (792,448
                    )Loan
      interest accretion
                    
                    
                    (2,814,095
                    )
                    
                    
                    (1,089,798
                    )Gain
      on liquidation of hedging instrument
                    
                    
                    3,879,050
                    
                    
                    
                    -Other
      Gain/(Loss)
                    
                    
                    (37,736
                    )
                    
                    
                    -Total
      other income (expense)
                    
                    
                    144,793
                    
                    
                    
                    (1,882,246
                    )Net
      income - (loss)
                    
                    $
                    (5,307,068
                    )
                    
                    $
                    (4,827,935
                    )Weighted
      average shares outstanding  - basic
                    
                    
                    4,443,249
                    
                    
                    
                    4,284,144Net
      income  (loss) per share - basic
                    
                    $
                    (1.19
                    )
                    
                    $
                    (1.13
                    )





See
Notes to Consolidated Financial Statements.


F-4


EnerJex
Resources, Inc. and Subsidiaries


Consolidated
Statements of Stockholders’ Equity (Deficit)





Common StockShares
                  
                  
                  Par Value
                  
                  
                  Owed but not
                    issued
                  
                  
                  Paid in
                    Capital
                  
                  
                  Retained Deficit
                  
                  
                  Total
                    Stockholders’
                    Equity (Deficit)Balance,
      April 1, 2007
                  
                  
                  2,635,731
                  
                  
                  $
                  2,636
                  
                  
                  $
                  3
                  
                  
                  $
                  2,548,742
                  
                  
                  $
                  (
      2,595,971
                  )
                  
                  $
                  (44,590
                  )Stock
      sold
                  
                  
                  1,800,000
                  
                  
                  
                  1,800
                  
                  
                  
                  -
                  
                  
                  
                  4,311,956
                  
                  
                  
                  -
                  
                  
                  
                  4,313,756Stock
      issued for services
                  
                  
                  1,920
                  
                  
                  
                  2
                  
                  
                  
                  -
                  
                  
                  
                  14,998
                  
                  
                  
                  -
                  
                  
                  
                  15,000Previously
      authorized but unissued stock
                  
                  
                  3,000
                  
                  
                  
                  3
                  
                  
                  
                  (3
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Stock
      options issued for services
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1,977,761
                  
                  
                  
                  -
                  
                  
                  
                  1,977,761Net
      (loss) for the year
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (4,827,935
                  )
                  
                  
                  (4,827,935
                  )Balance,
      March 31, 2008
                  
                  
                  4,440,651
                  
                  
                  
                  4,441
                  
                  
                  
                  -
                  
                  
                  
                  8,853,457
                  
                  
                  
                  (7,423,906
                  )
                  
                  
                  1,433,992Stock
      options issued for services
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  67,452
                  
                  
                  
                  -
                  
                  
                  
                  67,452Stock
      issued for services
                  
                  
                  2,182
                  
                  
                  
                  2
                  
                  
                  
                  -
                  
                  
                  
                  11,998
                  
                  
                  
                  -
                  
                  
                  
                  12,000Stock
      issued in reverse stock split
                  
                  
                  679
                  
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  (1
                  )
                  
                  
                  -
                  
                  
                  
                  -Net
      loss for the year
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  $
                  (5,307,068
                  )
                  
                  
                  (5,307,068
                  )Balance,
      March 31, 2009
                  
                  
                  4,443,512
                  
                  
                  $
                  4,444
                  
                  
                  $
                  -
                  
                  
                  $
                  8,932,906
                  
                  
                  $
                  ( 12,730,974
                  )
                  
                  $
                  (3,793,624
                  )





See
Notes to Consolidated Financial Statements.


F-5


EnerJex
Resources, Inc.


Consolidated
Statements of Cash Flows





For the Fiscal Years EndedMarch 31,2009
                      
                      
                      2008Cash
      flows from operating activitiesNet
      (loss)
                      
                      $
                      (5,307,068
                      )
                      
                      $
                      (4,827,935
                      )Depreciation
      and depletion
                      
                      
                      950,357
                      
                      
                      
                      935,330Debt
      issue cost amortization
                      
                      
                      157,191
                      
                      
                      
                      152,453Stock
      and options issued for services
                      
                      
                      79,452
                      
                      
                      
                      1,992,761Accretion
      of interest on long-term debt discount
                      
                      
                      2,814,095
                      
                      
                      
                      1,089,798Accretion
      of asset retirement obligation
                      
                      
                      60,864
                      
                      
                      
                      30,331Impairment
      of oil & gas properties
                      
                      
                      4,777,723
                      
                      
                      
                      -Adjustments
      to reconcile net (loss) to cash used in operating
    activities:Accounts
      receivable
                      
                      
                      (234,989
                      )
                      
                      
                      (222,917
                      )Notes
      and interest receivable
                      
                      
                      -
                      
                      
                      
                      10,300Deposits
      and prepaid expenses
                      
                      
                      24,224
                      
                      
                      
                      (169,672
                      )Accounts
      payable
                      
                      
                      599,334
                      
                      
                      
                      374,535Accrued
      liabilities
                      
                      
                      17,350
                      
                      
                      
                      (25,429
                      )Deferred
      payment from Euramerica for development
                      
                      
                      (251,951
                      )
                      
                      
                      251,951Cash
      used in operating activities
                      
                      
                      3,686,582
                      
                      
                      
                      (408,494
                      )Cash
      flows from investing activitiesPurchase
      of fixed assets
                      
                      
                      (204,200
                      )
                      
                      
                      (149,799
                      )Additions
      to oil & gas properties
                      
                      
                      (3,123,003
                      )
                      
                      
                      (9,530,321
                      )Sale
      of oil & gas properties
                      
                      
                      300,000
                      
                      
                      
                      300,000Note
      and interest receivable from officer
                      
                      
                      -
                      
                      
                      
                      23,100Proceeds
      from sale of vehicle
                      
                      
                      
                      
                      
                      
                      -Cash
      used in investing activities
                      
                      
                      (3,027,203
                      )
                      
                      
                      (9,357,020
                      )Cash
      flows from financing activitiesProceeds
      from (repayment of) note payable, net
                      
                      
                      (965,000
                      )
                      
                      
                      615,000Proceeds
      from sales of common stock
                      
                      
                      -
                      
                      
                      
                      4,313,756Debt
      issue costs
                      
                      
                      
                      
                      
                      
                      (466,835
                      )Borrowings
      on long-term debt
                      
                      
                      11,274,843
                      
                      
                      
                      6,344,816Payments
      on long-term debt
                      
                      
                      (11,792,641
                      )
                      
                      
                      (189,712
                      )Cash
      provided from financing activities
                      
                      
                      (1,482,798
                      )
                      
                      
                      10,617,025Increase
      (decrease) in cash and  cash equivalents
                      
                      
                      (823,419
                      )
                      
                      
                      851,511Cash
      and cash equivalents, beginning
                      
                      
                      951,004
                      
                      
                      
                      99,493Cash
      and cash equivalents, end
                      
                      $
                      127,585
                      
                      
                      $
                      951,004Supplemental
      disclosures:Interest
      paid
                      
                      $
                      768,053
                      
                      
                      $
                      733,972Income
      taxes paid
                      
                      $
                      -
                      
                      
                      $
                      -Non-cash
      transactions:Share-based
      payments issued for services
                      
                      $
                      -
                      
                      
                      $
                      280,591





See
Notes to Consolidated Financial Statements.


F-6


EnerJex
Resources, Inc.


Notes
to Consolidated Financial Statements





Note
1 – Summary of Accounting Policies





Nature
of Business





We are an
independent energy company engaged in the business of producing and selling
crude oil and natural gas. This crude oil and natural gas is obtained primarily
by the acquisition and subsequent exploration and development of mineral
leases.  Development and exploration may include drilling new
exploratory or development wells on these leases. These operations are conducted
primarily in Eastern Kansas.





Principles
of Consolidation





Our
consolidated financial statements include the accounts of our wholly-owned
subsidiaries, EnerJex Kansas, Inc., DD Energy, Inc.





Use
of Estimates





The
preparation of these financial statements requires the use of estimates by
management in determining our assets, liabilities, revenues, expenses and
related disclosures.  Actual amounts could differ from those
estimates.





Trade
Accounts Receivable





Trade
accounts receivable are recorded at the invoiced amount and do not bear any
interest.  We regularly review receivables to insure that the amounts
will be collected and establish or adjust an allowance for uncollectible amounts
as necessary using the specific identification method.  Account
balances are charged off against the allowance after all means of collection
have been exhausted and the potential for recovery is considered remote. There
were no reserves for uncollectible amounts in the periods
presented.





Share-Based
Payments





The value
we assign to the options and warrants that we issue is based on the fair market
value as calculated by the Black-Scholes pricing model. To perform a calculation
of the value of our options and warrants, we determine an estimate of the
volatility of our stock.  We need to estimate volatility because there
has not been enough trading of our stock to determine an appropriate measure of
volatility. We believe our estimate of volatility is reasonable, and we review
the assumptions used to determine this whenever we issue a new equity
instruments.  If we have a material error in our estimate of the
volatility of our stock, our expenses could be understated or
overstated.


F-7





Income
Taxes





We
account for income taxes under the Statement of Financial Accounting Standards
“SFAS” Statement 109, “Accounting for Income Taxes”.  The asset and
liability approach requires the recognition of deferred tax liabilities and
assets for the expected future tax consequences of temporary differences between
the carrying amounts and the tax basis of assets and liabilities.  The
provision for income taxes differs from the amount currently payable because of
temporary differences in the recognition of certain income and expense items for
financial reporting and tax reporting purposes.





We
adopted the Financial Accounting Standards Board “FASB” Interpretation No. 48,
“Accounting for Uncertainty in Income Taxes – an interpretation of FASB
Statement No. 109” (“FIN 48”) as of April 1, 2007. FIN 48 clarifies the
accounting for uncertainty in income taxes recognized in companies’ financial
statements in accordance with FASB Statement No. 109, “Accounting for Income
Taxes”. As a result, we apply a more-likely-than-not recognition threshold for
all tax uncertainties. FIN 48 only allows the recognition of those tax benefits
that have a greater than fifty percent likelihood of being sustained upon
examination by the taxing authorities. As a result of implementing FIN 48, we
have reviewed our tax positions and determined there were no outstanding or
retroactive tax positions with less than a 50% likelihood of being sustained
upon examination by the taxing authorities, therefore the implementation of this
standard has not had a material effect on the Company.





We
classify tax-related penalties and net interest on income taxes as income tax
expense. As of March 31, 2009 and 2008, no income tax expense had been
incurred.





Fair
Value of Financial Instruments





Our
financial instruments consist of accounts receivable and notes payable. Interest
rates currently available to us for debt with similar terms and remaining
maturities are used to estimate fair value of such financial instruments.
Accordingly the carrying amounts are a reasonable estimate of fair
value.





Earnings
Per Share





SFAS No.
128, “Earnings Per Share”, requires dual presentation of basic and diluted
earnings per share on the face of the income statement for all entities with
complex capital structures and requires a reconciliation of the numerator and
denominator of the diluted income or loss per share computation.





For the
year ended March 31, 2009 and 2008, there were 513,500 and 533,500,
respectively, of potentially issuable shares of common stock pursuant to
outstanding stock options and warrants.  These have been excluded from
the denominator of the diluted earnings per share computation, as their effect
would be anti-dilutive.


F-8


Cash
and Cash Equivalents





We
consider all highly liquid investment instruments purchased with original
maturities of three months or less to be cash equivalents for purposes of the
consolidated statements of cash flows and other statements. We maintain cash on
deposit, which, at times, exceed federally insured limits. We have not
experienced any losses on such accounts and believe we are not exposed to any
significant credit risk on cash and equivalents.





Revenue
Recognition and Imbalances





Oil and
gas revenues are recognized net of royalties when production is sold to a
purchaser at a fixed or determinable price, when delivery has occurred and title
has transferred, and if collection of the revenue is probable. Cash received
relating to future revenues is deferred and recognized when all revenue
recognition criteria are met.





We use
the sales method of accounting for gas production imbalances. The volumes of gas
sold may differ from the volumes to which we are entitled based on our interests
in the properties. These differences create imbalances that are recognized as a
liability only when the properties’ estimated remaining reserves net to us will
not be sufficient to enable the under-produced owner to recoup its entitled
share through production. No receivables are recorded for those wells where we
have taken less than our share of production. Gas imbalances are reflected as
adjustments to estimates of proved gas reserves and future cash flows
in the supplemental oil and gas disclosures.  There was no
imbalance at March 31, 2009 and 2008.





Goodwill





Goodwill
represents the excess of the purchase price of an entity over the estimated fair
value of the assets acquired and liabilities assumed. We assess the carrying
amount of goodwill by testing the goodwill for impairment annually and when
impairment indicators arise. The impairment test requires allocating goodwill
and all other assets and liabilities to assigned reporting units. The fair value
of each unit is determined and compared to the book value of the reporting unit.
If the fair value of the reporting unit is less than the book value, including
goodwill, then the goodwill is written down to the implied fair value of the
goodwill through a charge to expense.





Property
and Equipment





Property
and equipment are recorded at cost. Depreciation is on a straight-line method
using the estimated lives of the assets. (3-15 years).  Expenditures
for maintenance and repairs are charged to expense.





Debt
issue costs





Debt
issuance costs incurred are capitalized and subsequently amortized over the term
of the related debt on the straight-line method of amortization over the
estimated life of the debt.


F-9





Oil
and Gas Properties





The
accounting for our business is subject to special accounting rules that are
unique to the gas and oil industry. There are two allowable methods of
accounting for oil and gas business activities: the successful efforts method
and the full-cost method. We follow the full-cost method of accounting under
which all costs associated with property acquisition, exploration and
development activities are capitalized. We also capitalize internal costs that
can be directly identified with our acquisition, exploration and development
activities and do not include any costs related to production, general corporate
overhead or similar activities.





Under the
full-cost method, capitalized costs are amortized on a composite
unit-of-production method based on proved gas and oil reserves. Depreciation,
depletion and amortization expense is also based on the amount of estimated
reserves. If we maintain the same level of production year over year, the
depreciation, depletion and amortization expense may be significantly different
if our estimate of remaining reserves changes significantly. Proceeds from the
sale of properties are accounted for as reductions of capitalized costs unless
such sales involve a significant change in the relationship between costs and
the value of proved reserves or the underlying value of unproved properties, in
which case a gain or loss is recognized. The costs of unproved properties are
excluded from amortization until the properties are evaluated. We review all of
our unevaluated properties quarterly to determine whether or not and to what
extent proved reserves have been assigned to the properties, and otherwise if
impairment has occurred. Unevaluated properties are assessed individually when
individual costs are significant.





The
process of estimating gas and oil reserves is very complex, requiring
significant decisions in the evaluation of available geological, geophysical,
engineering and economic data. The data for a given property may also change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and a continual reassessment
of the viability of production under changing economic conditions. As a result,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various properties increase the
likelihood of significant changes in these estimates.





We review
the carrying value of our gas and oil properties under the full-cost accounting
rules of the SEC on a quarterly basis. This quarterly review is referred to as a
ceiling test. Under the ceiling test, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal
to the sum of the present value of estimated future net revenues (adjusted for
cash flow hedges) less estimated future expenditures to be incurred in
developing and producing the proved reserves, less any related income tax
effects. In calculating future net revenues, current SEC regulations require us
to utilize prices at the end of the appropriate quarterly period. Such prices
are utilized except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts, including the
effects of derivatives qualifying as cash flow hedges. Two primary factors
impacting this test are reserve levels and current prices, and their associated
impact on the present value of estimated future net revenues. Revisions to
estimates of gas and oil reserves and/or an increase or decrease in prices can
have a material impact on the present value of estimated future net revenues.
Any excess of the net book value, less deferred income taxes, is generally
written off as an expense. Under SEC regulations, the excess above the ceiling
is not expensed (or is reduced) if, subsequent to the end of the period, but
prior to the release of the financial statements, gas and oil prices increase
sufficiently such that an excess above the ceiling would have been eliminated
(or reduced) if the increased prices were used in the
calculations.


F-10





As
previously announced, in December 2008, the Securities and Exchange Commission
(“SEC”) issued new regulations for oil and gas reserve reporting which go into
effect effective for fiscal years ending on or after December 31,
2009.  One of the key elements of the new regulations relate to the
commodity prices which are used to calculate reserves and their present
value.  The new regulations provide for disclosure of oil and gas
reserves evaluated using annual average prices based on the prices in effect on
the first day of each month rather than the current regulations which utilize
commodity prices on the last day of the year.





All
reserve estimates are prepared based upon a review of production histories and
other geologic, economic, ownership and engineering data.





Long-Lived
Assets





Impairment
of long-lived assets is recorded when indicators of impairment are present and
the undiscounted cash flows estimated to be generated by those assets are less
than the assets’ carrying value.  The carrying value of the assets is
then reduced to their estimated fair value that is usually measured based on an
estimate of future discounted cash flows.





Asset
Retirement Obligations





The asset
retirement obligation relates to the plug and abandonment costs when our wells
are no longer useful. We determine the value of the liability by obtaining
quotes for this service and estimate the increase we will face in the future. We
then discount the future value based on an intrinsic interest rate that is
appropriate for us. If costs rise more than what we have expected there could be
additional charges in the future, however, we monitor the costs of the abandoned
wells and we will adjust this liability if necessary.





Major
Purchasers





For the
years ended March 31, 2009 and 2008 we sold all of our natural gas production to
one purchaser. We sold all of our oil production to one purchaser during fiscal
2009 and to a single, but different purchaser in fiscal 2008.





Recent
Issued Accounting Standards




In May
2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 163,
“Accounting for Financial
Guarantee Insurance Contracts – An interpretation of FASB Statement No.
60”. SFAS No. 163 requires that an insurance enterprise recognize a claim
liability prior to an event of default when there is evidence that credit
deterioration has occurred in an insured financial obligation. It also clarifies
how Statement 60 applies to financial guarantee insurance contracts, including
the recognition and measurement to be used to account for premium revenue and
claim liabilities, and requires expanded disclosures about financial guarantee
insurance contracts. It is effective for financial statements issued for fiscal
years beginning after December 15, 2008, except for some disclosures about the
insurance enterprise’s risk-management activities. SFAS No. 163 requires that
disclosures about the risk-management activities of the insurance enterprise be
effective for the first period beginning after issuance. Except for those
disclosures, earlier application is not permitted. The adoption of this
statement is not expected to have a material effect on the Company’s financial
statements.


F-11




In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles”. SFAS No. 162 identifies the sources of accounting
principles and the framework for selecting the principles to be used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting principles in the
United States. It is effective 60 days following the SEC’s approval of the
Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting Principles”. The adoption
of this statement is not expected to have a material effect on the Company’s
financial statements.




In March
2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161,
“Disclosures about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133”. SFAS No. 161 is intended to improve financial standards for
derivative instruments and hedging activities by requiring enhanced disclosures
to enable investors to better understand their effects on an entity's financial
position, financial performance, and cash flows. Entities are required to
provide enhanced disclosures about: (a) how and why an entity uses derivative
instruments; (b) how derivative instruments and related hedged items are
accounted for under Statement 133 and its related interpretations; and (c) how
derivative instruments and related hedged items affect an entity’s financial
position, financial performance, and cash flows. It is effective for financial
statements issued for fiscal years beginning after November 15, 2008, with early
adoption encouraged. The Company is currently evaluating the impact of SFAS No.
161 on its financial statements, and the adoption of this statement is not
expected to have a material effect on the Company’s financial
statements.




In
December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No.
141 (revised 2007), “Business Combinations”. This statement replaces SFAS No.
141 and defines the acquirer in a business combination as the entity that
obtains control of one or more businesses in a business combination and
establishes the acquisition date as the date that the acquirer achieves control.
SFAS 141 (revised 2007) requires an acquirer to recognize the assets acquired,
the liabilities assumed, and any non-controlling interest in the acquired at the
acquisition date, measured at their fair values as of that date. SFAS 141
(revised 2007) also requires the acquirer to recognize contingent consideration
at the acquisition date, measured at its fair value at that date. This statement
is effective for fiscal years, and interim periods within those fiscal years,
beginning on or after December 15, 2008. Earlier adoption is prohibited. The
adoption of this statement is not expected to have a material effect on the
Company's financial statements.




In
December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in
Consolidated Financial Statements Liabilities –an Amendment of ARB No. 51”. This
statement amends ARB 51 to establish accounting and reporting standards for the
Non-controlling interest in a subsidiary and for the deconsolidation of a
subsidiary. This statement is effective for fiscal years, and interim periods
within those fiscal years, beginning on or after December 15, 2008. Earlier
adoption is prohibited. The adoption of this statement is not expected to have a
material effect on the Company's financial statements.


F-12





Reclassifications





Certain
reclassifications have been made to prior periods to conform to current
presentation.





Note
2 – Going Concern




The
accompanying consolidated financial statements have been prepared assuming that
we will continue as a going concern. Our ability to continue as a going concern
is dependent upon attaining profitable operations based on the development of
products that can be sold. We intend to use borrowings, equity and asset sales,
and other strategic initiatives to mitigate the affects of our cash position,
however, no assurance can be given that debt or equity financing, if and when
required, will be available. The financial statements do not include any
adjustments relating to the recoverability and classification of recorded assets
and classification of liabilities that might be necessary should we be unable to
continue in existence.





Note
3 – Stock Transactions





Stock
transactions in fiscal 2009:





We issued
2,182 shares of common stock to a Director and chairman of our Audit Committee
for services over the next year. For the year ended March 31, 2009, we recorded
director compensation in the amount $13,000.





Option
and Warrant transactions:





Officers (including officers who are
members of the board of directors), directors, employees and consultants are
eligible to receive options under our stock option plans.  We
administer the stock option plans and we determine those persons to whom options
will be granted, the number of options to be granted, the provisions applicable
to each grant and the time periods during which the options may be
exercised.  No options may be granted more than ten years after the
date of the adoption of the stock option plans.





Each option granted under the stock
option plans will be exercisable for a term of not more than ten years after the
date of grant.  Certain other restrictions will apply in connection
with the plans when some awards may be exercised.  In the event of a
change of control (as defined in the stock option plans), the vesting date on
which all options outstanding under the stock option plans may first be
exercised will be accelerated.  Generally, all options terminate 90
days after a change of control.


F-13


2000-2001
Stock Option Plan





The Board
of Directors approved a stock option plan and our stockholders ratified the plan
on September 25, 2000.  The total number of options that can be
granted under the plan is 200,000 shares.  At March 31, 2009, we had
granted 200,000 non-qualified options under this plan.





Stock
Option Plan





On May 4,
2007, we amended and restated the EnerJex Resources, Inc. Stock Option Plan to
rename the plan and to increase the number of shares issuable under the plan to
1,000,000.  Our stockholders approved this plan in September of
2007.  At March 31, 2009 we had granted 238,500 non-qualified options
under this plan.





Option
transactions in fiscal 2008:





The
unvested option issued in the year ended March 31, 2007, was unexercised and
cancelled in accordance with a separation agreement.  We recognized
the remaining expense ($61,187) relating to the options in the year ended March
31, 2008.





We
granted 458,500 options in the year ended March 31, 2008.  30,000 of
the options were for services earned over a one-year period.  We
measured the compensation cost of the options based on the vesting and the
market value as determined by the Black-Scholes pricing model.





For the
year ended March 31, 2008, we included as expense $1,977,761 relating to the
value of vested options.





The fair
value of each option award was estimated on the date of grant using the
assumptions noted in the following table.  Volatility is based on the
historical volatility of stock trading, expected term was the estimated exercise
period, risk free rate was the rate of a U.S. Treasury instrument of the time
period in which the options would be outstanding, and dividend rate was
estimated to be zero as we cannot assume that there will be any future
dividends.





Weighted
      average expected volatility
                  
                  
                  101
                  %Weighted
      average expected term  (in years)
                  
                  
                  3.95Weighted
      average expected dividends
                  
                  
                  0
                  %Weighted
      average risk free rate
                  
                  
                  4.42
                  %





The
weighted average grant date fair value of the options granted in the year ended
March 31, 2009 was $4.35.





In the
year ended March 31, 2008, we granted warrants to purchase 75,000 shares of our
common stock as partial payment for services rendered in connection with our
financing activities. The warrants have an exercise price of $3.00 and expire on
April 11, 2010. The fair value of the warrants based on the Black-Scholes
pricing model totaled $280,591 (approximately $3.75 per warrant). The following
assumptions were used in the valuation: stock price-$1.00; exercise price-$0.60;
life- 3 years; volatility- 106%; yield-4.66%. We have included the value of the
warrants with the loan and equity transaction costs (See Note
5).


F-14





Option
transactions in fiscal 2009:





We
cancelled 20,000 options in accordance with the provisions regarding
terminations in the Stock Option Plan.





At March 31, 2009, we included as
expense $66,456 relating to the options that were for services earned over a
one-year period.





A summary
of stock options and warrants is as follows:


Options
                
                
                Weighted
                  Ave. Exercise
                  Price
                
                
                Warrants
                
                
                Weighted
                  Ave. Exercise
                  PriceOutstanding
      April 1, 2007
                
                
                60,000
                
                
                $
                6.25
                
                
                
                -Granted
                
                
                458,500
                
                
                
                6.30
                
                
                
                75,000
                
                
                $
                3.00Cancelled
                
                
                (60,000
                )
                
                
                (6.25
                )
                
                
                -
                
                
                
                -Exercised
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Outstanding
      March 31, 2008
                
                
                458,500
                
                
                $
                6.30
                
                
                
                75,000
                
                
                $
                3.00Granted
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Cancelled
                
                
                (20,000
                )
                
                
                (6.25
                )
                
                
                -
                
                
                
                -Exercised
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Outstanding
      March 31, 2009
                
                
                438,500
                
                
                $
                6.30
                
                
                
                75,000
                
                
                $
                3.00





Note
4 – Asset Retirement Obligation





Our asset
retirement obligations relate to the abandonment of oil and natural gas wells.
The amounts recognized are based on numerous estimates and assumptions,
including future retirement costs, inflation rates and credit adjusted risk-free
interest rates. The following shows the changes in asset retirement
obligations:





Asset
      retirement obligation at April 1, 2007
                  
                  $
                  23,908Liabilities
      incurred during the period
                  
                  
                  405,450Liabilities
      settled during the period
                  
                  
                  -Accretion
                  
                  
                  30,331Asset
      retirement obligations, March 31, 2008
                  
                  
                  459,689Liabilities
      incurred during the period
                  
                  
                  283,071Liabilities
      settled during the period
                  
                  
                  -Accretion
                  
                  
                  60,864Asset
      retirement obligations, March 31, 2009
                  
                  $
                  803,624


F-15


Note
5 - Long-Term Debt





Senior
Secured Credit Facility





On July
3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year $50
million Senior Secured Credit Facility (the “Credit Facility”) with Texas
Capital Bank, N.A.  Borrowings under the Credit Facility will be
subject to a borrowing base limitation based on our current proved oil and gas
reserves and will be subject to semi-annual redeterminations and interim
adjustments.  The initial borrowing base was set at $10.75 million and
was reduced to $7.428 million following the liquidation of the BP hedging
instrument.  The Credit Facility is secured by a lien on substantially
all assets of the Company and its subsidiaries. The Credit Facility has a term
of three years, and all principal amounts, together with all accrued and unpaid
interest, will be due and payable in full on July 3, 2011.  The Credit
Facility also provides for the issuance of letters-of-credit up to a $750,000
sub-limit under the borrowing base and up to an additional $2.25 million limit
not subject to the borrowing base to support our hedging program.  We
had borrowings $7.328 million outstanding at March 31, 2009.





Advances
under the Credit Facility will be in the form of either base rate loans or
Eurodollar loans. The interest rate on the base rate loans fluctuates based upon
the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus
0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the
percent of the borrowing base utilized at the time of the credit extension. The
interest rate on the Eurodollar loans fluctuates based upon the applicable Libor
rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing
base utilized at the time of the credit extensionon. We may select Eurodollar
loans of one, two, three and six months. A commitment fee of 0.375% on the
unused portion of the borrowing base will accrue, and be payable quarterly in
arrears.  There was no commitment fee due at March 31,
2009.





The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires that we, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, maintain a
minimum current assets to current liabilities ratio and a minimum ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and at the end of each fiscal quarter beginning with the
quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior
funded debt.





Additionally,
Texas Capital Bank, N.A. and the holders of the debentures entered into a
Subordination Agreement whereby the debentures issued on June 21, 2007 will be
subordinated to the Credit Facility.


F-16


Debentures




On April
11, 2007, we entered into a Securities Purchase Agreement, Registration Rights
Agreements, Senior Secured Debentures, a Pledge and Security Agreement, a
Secured Guaranty, and other related agreements (the “Financing Agreements”) with
the “Buyers” of a new series of senior secured debentures (the “Debentures”).
Under the terms of the Financing Agreements, we agreed to sell Debentures for a
total purchase price of $9.0 million. In connection with the purchase, we agreed
to issue to the Buyers a total of 1,800,000 shares. The first closing occurred
on April 12, 2007 with a total of $6.3 million in Debentures being sold and the
remaining $2.7 million closing on June 21, 2007.





The
Debentures originally had a three-year term, maturing on March 31, 2010, and
bear interest at a rate equal to 10% per annum. Interest is payable quarterly in
arrears on the first day of each succeeding quarter. We may pay interest in
either cash or registered shares of our common stock. The Debentures have no
prepayment penalty so long as we maintain an effective registration statement
with the Securities Exchange Commission and provided we give six (6) business
days prior notice of redemption to the Buyers.





The
proceeds from the Debentures were allocated to the long-term debt and the stock
issued based on the fair market value of each item that we calculated to be $9.0
million for each item.  Since each of the instruments had a value
equal to 50% of the total, we allocated $4.5 million to stock and $4.5 million
to the note.  The loan discount costs of $4.5 million will accrete as
interest based on the interest method over the period of issue to maturity or
redemption.  The amount of interest accreted for the fiscal year ended
March 31, 2009 was $2,814,095 and $1,089,798 for the fiscal year ended March 31,
2008.  Of the $2,814,095 interest accreted during the period ended
March 31, 2009, $2,112,267 relates to the redemption of $6.3 million of the
Debentures. The remaining amount of interest to accrete in future periods is
$596,108 as of March 31, 2009.





We incurred debt issue costs totaling
$466,835.  The debt issue costs are initially recorded as assets and
are amortized to expense on a straight-line basis over the life of the
loan.  The amount expensed in the twelve month period ended March 31,
2009 was $268,453.  Of this amount, $195,559 was expensed upon the
redemption of $6.3 million of the Debentures. The remaining debt issue costs
totaling $45,929 will be expensed in the fiscal year ended March 31,
2010.





Effective July 7, 2008, we redeemed an
aggregate principal amount of $6.3 million of the Debentures and amended the
$2.7 million of aggregate principal amount of the remaining Debentures to, among
other things, permit the indebtedness under our new Credit Facility, subordinate
the security interests of the debentures to the new Credit Facility, provide for
the redemption of the remaining Debentures with the net proceeds from our next
debt or equity offering and eliminate the covenant to maintain certain
production thresholds.




Pursuant
to the terms of the Registration Rights Agreement, as amended, between us and
one of the Buyers, we were obligated to register 1,000,000 of the shares issued
under the Financing Agreements. These shares were registered effective December
24, 2008.


F-17





Convertible
and Other Long-Term Debt





On August
3, 2006, we sold a $25,000 convertible note that has an interest rate of 6% and
matures August 2, 2010.  The note is convertible at any time at the
option of the note holder into shares of our common stock at a conversion rate
of $10.00 per share.





We
financed the purchase of vehicles through a bank.  The notes are for
seven years and the weighted average interest is 6.99% per
annum.  Vehicles collateralize these notes.




Long-term
debt consists of the following at March 31, 2009:




Credit
      Facility
                  
                  $
                  7,328,000Debentures
                  
                  
                  2,700,000Unaccreted
      discount
                  
                  
                  (596,108
                  )Debentures,
      net of unaccreted discount
                  
                  
                  2,103,892Vehicle
      notes payable
                  
                  
                  109,307Total
      long-term debt
                  
                  
                  9,541,199Less
      current portion
                  
                  
                  (1,723,036
                  )Long-term
      debt
                  
                  $
                  7,818,163





Principal
amounts are due on long-term and convertible debt as follows: Year ended March
31, 2010 -$1,723,036, March 31, 2011 -$8,377,636, March 31, 2012 -$25,243, March
31, 2013 -$16,044, March 31, 2014 -$13,171 and thereafter-$7,177.




Note
6 – Oil & Gas Properties





On April 9, 2007, we
entered into a “Joint Exploration
Agreement”with a shareholder, MorMeg, LLC,
whereby we agreed to advance $4.0 million to a joint operating account for
further development of MorMeg’s Black Oaks leaseholds in
exchange for a 95% working interest in the Black Oaks
Project.  We will maintain our 95% working interest until
“payout”, at which time the MorMeg 5% carried working interest will be converted
to a 30% working interest and our working interest becomes 70%. Payout is
generally the point in time when the total cumulative revenue from the project
equals all of the project’s development expenditures and costs associated with
funding. Through an additional extension, we have until December 31, 2009 to
contribute additional capital toward the Black Oaks Project development. If we
elect not to contribute further capital to the Black Oaks Project prior to the
project’s full development while it is economically viable to do so, or if there
is more than a thirty day delay in project activities due to lack of capital,
MorMeg has the option to cease further joint development and we will receive an
undivided interest in the Black Oaks Project. The extension will have no
force and effect, however, upon a material default by EnerJex under the Credit
Facility. The undivided interest will be the proportionate amount equal to the
amount that our investment bears to our investment plus $2.0 million, with
MorMeg receiving an undivided interest in what remains.


F-18





In August
of 2007, we entered into a development agreement with Euramerica Energy, Inc.,
or Euramerica, to further the development and expansion of the Gas City Project,
which included 6,600 acres, whereby Euramerica contributed $524,000 in capital
toward the project. Euramerica was granted an option to purchase this project
for $1.2 million with a requirement to invest an additional $2.0 million for
project development by August 31, 2008. We were the operator of the project at a
cost plus 17.5% basis. We received $600,000 of the $1.2 million purchase price
and $500,000 of the $2.0 million development funds.  We have recorded a
reduction of $600,000 to our oil & gas properties using full-cost accounting
subject to amortization as of the year ended March 31, 2009.  In
January 2009,Euramerica failed to fully fund both the balance of the
purchase price and the remaining development capital owed under the agreements
between us and Euramerica.  Therefore, Euramerica has forfeited all of
its interest in the property, including all interests in any wells, improvements
or assets, and all of Euramerica's interest in the property reverts back to
us.  In addition, all operating agreements between us and Euramerica
relating to the Gas City Project are null and void.  We drilled 22 wells on
behalf of Euramerica under the development agreement. We are currently exploring
options to sell or further develop the Gas City Project through joint venture
partnerships or other opportunities.  The gas project remains shut
in.





We
recorded a non-cash impairment of $4,777,723 to the carrying value of our proved
oil and gas properties during the fiscal year ended March 31, 2009. The
impairment is primarily attributable to lower prices for both oil and natural
gas at December 31, 2008. The charge results from the application of the
“ceiling test” under the full cost method of accounting. Under full cost
accounting requirements, the carrying value may not exceed an amount equal to
the sum of the present value of estimated future net revenues (adjusted for cash
flow hedges) less estimated future expenditures to be incurred in developing and
producing the proved reserves, less any related income tax effects. In
calculating future net revenues, current prices and costs used are those as of
the end of the appropriate quarterly period. Such prices are utilized except
where different prices are fixed and determinable from applicable contracts for
the remaining term of those contracts, including the effects of derivatives
qualifying as cash flow hedges. A ceiling test charge occurs when the carrying
value of the oil and gas properties exceeds the full cost ceiling.




Note
7 – Related party transactions




In August 2008, we paid $20,000 to a
non-employee director and former member of the audit committee for assisting in
the establishment and development of the audit committee and for his involvement
and assistance to the chief executive officer in finalizing the hedging
instrument with BP.





Note
8 – Commitments and Contingencies




We have a
lease agreement that expires in September 30, 2013.  Future minimum
payments are $71,180 for the year ending March 31, 2010.


F-19





Note
9 – Income Taxes





Deferred
income taxes are determined based on the tax effect of items subject to
different treatment between book and tax bases. At March 31, 2009, there is
approximately $8,100,000 of net operating loss carry-forwards expiring in
2021-2023.  The net deferred tax is as follows:





March31,
                    2009
                  
                  
                  March31,
                    2008Non-current
      deferred tax asset:Impaired
      oil & gas costs and long-lived assets
                  
                  $
                  1,864,700
                  
                  
                  $
                  312,800Net
      operating loss carry-forward
                  
                  
                  2,754,600
                  
                  
                  
                  2,429,900Valuation
      allowance
                  
                  
                  (4,619,300
                  )
                  
                  
                  (2,742,700
                  )Total
      deferred tax net
                  
                  $
                  -
                  
                  
                  $
                  -





A reconciliation of the provision for
income taxes to the statutory federal rate for continuing operations is as
follows:





March31,
                    2009
                  
                  
                  March31,
                    2008Statutory
      tax rate
                  
                  
                  34
                  %
                  
                  
                  34
                  %Equity
      based compensation
                  
                  
                  (1
                  )%
                  
                  
                  (15
                  )%Oil
      & gas costs and long-lived assets
                  
                  
                  (29
                  )%
                  
                  
                  1
                  %Change
      in valuation allowance
                  
                  
                  (4
                  )%
                  
                  
                  (20
                  )%Effective
      tax rate
                  
                  
                  0
                  %
                  
                  
                  0
                  %





Note
10 – Subsequent Events





In April
and May of 2009, we retired $450,000 of the $2.7 million Debentures that were
outstanding at March 31, 2009, leaving a remaining balance of $2.25 million as
of the date of this report.





Subsequent
to year-end, we amended the Debentures to extend the maturity date to September
30, 2010, to allow us to pay interest in either cash or payment-in-kind interest
(an increase in the amount of principal due) or payment-in-kind shares (issuance
of shares of common stock), and add a provision for the conversion of the
debentures into shares of EnerJex’s common stock.  See Note
5.





We have
made Borrowing Base Reduction payments of $200,000 on our Credit
Facility.





Note
11 – Supplemental Oil and Natural Gas Reserve Information
(Unaudited)





Results
of operations from oil and natural gas producing activities





The following table shows the results
of operations from the Company’s oil and gas producing
activities.  Results of operations from these activities are
determined using historical revenues, production costs and depreciation,
depletion and amortization of the capitalized costs subject to
amortization.  General and administrative expenses, professional,
investor relations and interest expense is excluded from this
determination.


F-20





March31,
                    2009
                  
                  
                  March31,
                    2008Production
      revenues
                  
                  $
                  6,436,805
                  
                  
                  $
                  3,602,798Production
      costs
                  
                  
                  (2,637,333
                  )
                  
                  
                  (1,795,188
                  )Depletion
      and depreciation
                  
                  
                  (892,871
                  )
                  
                  
                  (913,224
                  )Results
      of operations for producing activities
                  
                  $
                  2,906,601
                  
                  
                  $
                  894,386




Capitalized costs of oil
and natural gas
producing properties





The Company’s aggregate capitalized
costs related to oil and natural gas producing activities are as
follows:





March31,
                    2009
                  
                  
                  March31,
                    2008Proved
                  
                  $
                  8,566,979
                  
                  
                  $
                  10,207,596Unevaluated
      and unproved
                  
                  
                  31,183
                  
                  
                  
                  62,216Accumulated
      depreciation and depletion
                  
                  
                  (1,817,956
                  )
                  
                  
                  (925,086
                  )Sale
      of properties
                  
                  
                  (300,000
                  )
                  
                  
                  (300,000
                  )Net
      capitalized costs
                  
                  $
                  6,480,206
                  
                  
                  $
                  9,044,726





Unproved and unevaluated properties are
not included in the full-cost pool and are therefore not subject to depletion or
depreciation. These assets consist primarily of leases that have not been
evaluated. We will continue to evaluate our unproved and unevaluated properties;
however, the timing of such evaluation has not been
determined.





Capitalized
costs incurred for oil and natural gas producing activities





Costs incurred in oil and natural gas
property acquisition, exploration and development activities that have been
capitalized are summarized below:





March31,
                    2009
                  
                  
                  March31,
                    2008Acquisition
      of proved and unproved properties
                  
                  $
                  123,040
                  
                  
                  $
                  4,352,040Development
      costs
                  
                  
                  2,999,963
                  
                  
                  
                  5,178,281Exploration
      costs
                  
                  
                  -
                  
                  
                  
                  -Total
                  
                  $
                  3,123,003
                  
                  
                  $
                  9,530,321


F-21


Gas
and oil Reserve Quantities





Our
ownership interests in estimated quantities of proved oil and gas reserves and
changes in net proved reserves all of which are located in the United States are
summarized below.  Proved reserves are estimated quantities of natural
gas and oil that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those that are
expected to be recovered through existing wells with existing equipment and
operating methods. Reserves are stated in thousand cubic feet (mcf) of natural
gas and barrels (stb) of oil. Geological and engineering estimates of proved
natural gas and oil reserves at one point in time are highly interpretive,
inherently imprecise and subject to ongoing revisions that may be substantial in
amount. Although every reasonable effort is made to ensure that the reserve
estimates are accurate, by their nature reserve estimates are generally less
precise than other estimates presented in connection with financial statement
disclosures.





March 31, 2009
                  
                  
                  March 31, 2008Gas-mcf
                  
                  
                  Oil-stb
                  
                  
                  Gas-mcf
                  
                  
                  Oil-stbProved
      reserves:Revisions
      of previous estimates
                  
                  
                  (394,732
                  )
                  
                  
                  (14,575
                  )
                  
                  
                  -
                  
                  
                  
                  -Purchase
      of minerals in place
                  
                  
                  -
                  
                  
                  
                  53,280
                  
                  
                  
                  418,959
                  
                  
                  
                  347,228Extensions
      and discoveries
                  
                  
                  -
                  
                  
                  
                  
                  
                  
                  
                  -
                  
                  
                  
                  1,068,683Production
                  
                  
                  (6,465
                  )
                  
                  
                  (74,289
                  )
                  
                  
                  (17,762
                  )
                  
                  
                  (43,697
                  )Total
                  
                  
                  -
                  
                  
                  
                  1,336,630
                  
                  
                  
                  401,197
                  
                  
                  
                  1,372,214





Proved
developed reserves at the end of the period:





Gas- mcf
                  
                  Oil – stbMarch 31, 2009
                  
                  March 31, 2009-
                  
                  
                  524,980




Gas- mcf
                    
                    Oil stbMarch 31, 2008
                    
                    March 31, 2008401,197
                    
                    
                    861,240





Standardized
measure of discounted future net cash flows





The
standardized measure of discounted future net cash flows from our proved
reserves for the periods presented in the financial statements is summarized
below. The standardized measure of future cash flows as of March 31, 2009 and
2008 is calculated using a price per Mcf of gas of $0 and $7.479, respectively
and a price for oil of $42.65 and $94.53, respectively. The resulting estimated
future cash inflows are reduced by estimated future costs to develop and produce
the estimated proved reserves.  These costs are based on year-end cost
levels.  Future income taxes are based on year-end statutory
rates.  The future net cash flows are reduced to present value by
applying a 10% discount rate.  The standardized measure of discounted
future cash flows is not intended to represent the replacement cost or fair
market value of the Company’s oil and gas properties.




F-22




March31,
                    2009
                  
                  
                  March31,
                    2008Future
      production revenue
                  
                  $
                  57,007,970
                  
                  
                  $
                  132,457,459Future
      production costs
                  
                  
                  (24,732,440
                  )
                  
                  
                  (39,629,625
                  )Future
      development costs
                  
                  
                  (9,584,500
                  )
                  
                  
                  (18,827,013
                  )Future
      cash flows before income taxes
                  
                  
                  22,691,030
                  
                  
                  
                  74,000,821Future
      income taxes
                  
                  
                  -
                  
                  
                  
                  (19,241,954
                  )Future
      net cash flows
                  
                  
                  22,691,030
                  
                  
                  
                  54,758,86710%
      annual discount for estimating of futurecash
      flows
                  
                  
                  (12,061,690
                  )
                  
                  
                  (26,558,364
                  )Standardized
      measure of discounted netcash
      flows
                  
                  $
                  10,629,340
                  
                  
                  $
                  28,200,503





Changes
in Standardized Measure of Discounted Future Net Cash Flows





March31,
                    2009
                  
                  
                  March31,
                    2008Balance
      beginning of year
                  
                  $
                  28,200,503
                  
                  
                  $
                  -Sales,
      net of production costs
                  
                  
                  (5,697,410
                  )
                  
                  
                  (1,777,278
                  )Net
      change in pricing and production costs
                  
                  
                  (31,927,063
                  )
                  
                  
                  -Net
      change in future estimateddevelopment
      costs
                  
                  
                  9,220,510
                  
                  
                  
                  -Purchase
      of minerals in place
                  
                  
                  136,190
                  
                  
                  
                  8,124,394Extensions
      and discoveries
                  
                  
                  518,297
                  
                  
                  
                  21,853,387Revisions
                  
                  
                  (1,089,039
                  )
                  
                  
                  -Accretion
      of discount
                  
                  
                  (143,477
                  )
                  
                  
                  -Change
      in income tax
                  
                  
                  11,410,829
                  
                  
                  
                  -Balance
      end of year
                  
                  $
                  10,629,340
                  
                  
                  $
                  28,200,503


F-23