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,
2010





o        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)


(913)
754-7754


(Registrant’s
telephone number, including area code)





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





Name of
each exchange on which registered:




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        xNo





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


 ̈Yes        xNo





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 check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).  ̈
Yes  xNo





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: $2,756,678.65
based


on a share value of
$0.95.





Indicate
the number of shares outstanding of each of the registrant’s classes of common
stock, as of the latest practicable date: 5,133,873 shares of common
stock, $0.001 par value, outstanding on July 14, 2010.





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
              
              3Items 1 and 2.
              Business
      and Properties
              
              3Item 1A.
              Risk
      Factors
              
              26Item 1B.
              Unresolved
      Staff Comments
              
              46Item 3.
              Legal
      Proceedings
              
              46PART
      II
              
              
              46Item 5.
              Market
      for Registrant’s Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities
              
              46Item 6.
              Selected
      Financial Data
              
              50Item 7.
              Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
              
              51Item 7A.
              Quantitative
      and Qualitative Disclosures about Market Risk
              
              63Item 8.
              Financial
      Statements and Supplementary Data
              
              63Item 9.
              Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
              
              63Item 9A(T).
              Controls
      and Procedures
              
              63Item 9B.
              Other
      Information
              
              64Part
      III
              
              
              65Item 10.
              Directors,
      Executive Officers and Corporate Governance
              
              65Item 11.
              Executive
      Compensation
              
              71Item 12.
              Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
              
              75Item 13.
              Certain
      Relationships and Related Transactions, and Director
      Independence
              
              77Item 14.
              Principal
      Accountant Fees and Services
              
              78Part
      IV
              
              
              80Item 15.
              Exhibits,
      Financial Statement Schedules
              
              80







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;


·
            effect
      of our hedging strategies on our results of
  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;


·
            continued
      weather conditions that impact our abilities to efficiently manage our
      drilling and development
activities;


·
            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;


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


·
            the
      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;


1


·
            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


·
            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 21 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.


2





PART
I




Items
1 and 2. Business and Properties.





Company History





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. 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.





Our Business





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 2010, 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 at March 31, 2010 was approximately 1.8
million barrels of oil equivalent, or BOE. Of the 1.8 million BOE of
total proved reserves, approximately 31% are proved developed and approximately
69% are proved undeveloped. The proved developed reserves consist of 78% proved
developed producing reserves and 22% proved developed non-producing
reserves.





The total
proved PV10 (present value) of our reserves (“PV10”) as of March 31, 2010 was
approximately $21.3 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 53, for a reconciliation to
the comparable GAAP financial measure.


3





In response to declining
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.We are continually evaluating oil and natural gas opportunities in
Eastern Kansas and anticipate that this economic strategy would 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.  However, 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.





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, 2009 and 2008, 39.5 million barrels and 39.7
million barrels of oil were produced in Kansas. Of the total barrels produced in
Kansas in the calendar year ended December 2009, 20 companies accounted for
approximately 35% of the total production, with the remaining 65% produced by
over 3,600 active producers.





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, once sufficiently capitalized, 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.


4





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





OurProperties





The table
below summarizes our acreage by project name as of March 31, 2010.





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,
      2010.





BlackOaks Project





On April
9, 2007, we entered into a “Joint Exploration Agreement” with a shareholder,
MorMeg, LLC, (MorMeg), controlled by Mark Haas, our chief operating officer and
a director,   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.





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, 2010, 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,
2010.


5





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. Pursuant to amendments to the
Joint Exploration Agreement, we have until August 1, 2010 to contribute one
million dollars in additional capital toward the Black Oaks Project development.
In addition, we are generally required to provide additional one million dollar
capital contributions every sixty days, or upon full deployment of the prior
capital contribution, until the Black Oaks Project is completed.  If we
elect not or cannot, contribute further capital to the Black Oaks Project as
discussed above prior to the project’s full development while it is economically
viable to do so, 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
Texas Capital Bank 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, 2010, we had proved oil reserves on Phase I of this project
of:





GrossSTB(1)
                  
                  
                  NetSTB(2)
                  
                  
                  PV10(3)
                    (beforetax)Proved,
      Developed Producing
                  
                  
                  439,190
                  
                  
                  
                  169,760
                  
                  
                  $
                  4,272,400Proved,
      Developed Non-Producing
                  
                  
                  52,330
                  
                  
                  
                  24,860
                  
                  
                  $
                  820,260Proved,
      Undeveloped
                  
                  
                  1,648,740
                  
                  
                  
                  536,780
                  
                  
                  $
                  3,672,640Total
      Proved
                  
                  
                  2,140,260
                  
                  
                  
                  731,400
                  
                  
                  $
                  8,765,300


(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 21 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 53, 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.





Through
March 31, 2010, we have invested approximately $800,000 for the development of
this project and as of March 31, 2010, 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, 2010, we had proved oil reserves on this project of:





Gross STB(1)
                  
                  
                  Net STB(2)
                  
                  
                  PV10(3)
                    (before tax)Proved,
      Developed Producing
                  
                  
                  57,400
                  
                  
                  
                  12,680
                  
                  
                  $
                  303.190Proved,
      Developed Non-Producing
                  
                  
                  31,180
                  
                  
                  
                  6,680
                  
                  
                  $
                  172,740Proved,
      Undeveloped
                  
                  
                  73,330
                  
                  
                  
                  42,480
                  
                  
                  $
                  135,990Total
      Proved
                  
                  
                  161,910
                  
                  
                  
                  61,840
                  
                  
                  $
                  611,920


(1)
              STB = one stock-tank
      barrel.


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


6


(3)
              See
      “Glossary” on page 21 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 53, 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 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 anticipate the conversion of our working interest to occur in fiscal
2011.





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, 2010, 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, 2010, 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.





As of
March 31, 2010, we had proved oil reserves on this project of:


Gross STB(1)
                
                
                Net STB(2)
                
                
                PV10(3)
                  (before tax)Proved,
      Developed Producing
                
                
                75,980
                
                
                
                64,020
                
                
                $
                1,475,250Proved,
      Developed Non-Producing
                
                
                56,850
                
                
                
                46,890
                
                
                $
                1,002,890Proved,
      Undeveloped
                
                
                200,150
                
                
                
                165,180
                
                
                $
                407,420Total
      Proved
                
                
                332,980
                
                
                
                276,090
                
                
                $
                2,885,560


(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 21 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 53, 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.


7





Through
March 31, 2010, 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, 2010, the Tri-County Project consisted of 166 producing wells and 59
water injection wells with production averaging approximately 49
BOPD.





As of
March 31, 2010, we had proved oil reserves on this project of:





Gross STB(1)
                  
                  
                  Net STB(2)
                  
                  
                  PV10(3)
                    (before tax)Proved,
      Developed Producing
                  
                  
                  249,550
                  
                  
                  
                  196,870
                  
                  
                  $
                  2,668,410Proved,
      Developed Non-Producing
                  
                  
                  60,660
                  
                  
                  
                  47,680
                  
                  
                  $
                  1,174,130Proved,
      Undeveloped
                  
                  
                  609,450
                  
                  
                  
                  488,620
                  
                  
                  $
                  5,084,340Total
      Proved
                  
                  
                  919,660
                  
                  
                  
                  733,170
                  
                  
                  $
                  8,926,880


(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 21 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 53, 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.





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. Over time Euramerica contributed $1,624,000
in capital toward the project, but failed to fund the full purchase and
development funds needed for the project. Therefore, Euramerica 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 reverted back to
us.  In addition, all operating agreements between us and Euramerica
relating to the Gas City Project were deemed null and void.





As of
March 31, 2010, 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
                    
                    
                    50
                    
                    
                    
                    40
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    $
                    220Proved,
      Developed Non-Producing
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    $
                    -Proved,
      Undeveloped
                    
                    
                    10,900
                    
                    
                    
                    8,990
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    $
                    71,640Total
      Proved
                    
                    
                    11,950
                    
                    
                    
                    9,030
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    $
                    71,860


(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,
      2010.


(4)
              Net MCF is based upon our net
      revenue interest.  There were no natural gas reserves at March
      31, 2010.


8


(5)
              See
      “Glossary” on page 21 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 53, 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 contributed up to $700,000 in initial development
capital. In May of 2010 we sold our 10% carried working interest to Pharyn for
$50,000.





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 a 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:





·
            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.


9





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. 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.





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.





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.





Significant
Developments in Fiscal 2010





The
following is a brief description of our most significant corporate developments
that occurred in fiscal 2010:





·
            In
      April and May of 2009, we repurchased a total of $450,000 of the
      subordinated debentures and in December 2009, we redeemed $150,000 of the
      subordinated debentures and received 75,000 shares of our stock for
      cancellation for $193,500 in cash. The principal balance remaining as of
      March 31, 2010 is approximately $2.47 million. These debentures mature on
      September 30, 2010.





·
            On
      August 3, 2009, upon advice and recommendation by the GCNC of EnerJex, we
      exchanged all of the 438,500 outstanding options to purchase shares of our
      common stock for shares of twelve-month restricted common stock to be
      issued pursuant to the terms of the EnerJex Resources, Inc. Stock
      Incentive Plan.  All of the stock options outstanding on August
      3, 2009 were exchanged for 109,700 shares of restricted common stock
      valued at $109,700 based upon the fair market value of the stock on the
      date of exchange.


10


·
            Also
      on August 3, 2009, we awarded 211,050 shares of twelve-month restricted
      common stock, valued at $211,500 to be issued pursuant to the terms of the
      EnerJex Resources, Inc. Stock Incentive Plan for the
      following:  151,750 shares to employees as incentive
      compensation (with such shares being issued on August 4, 2010 assuming
      each employee remains employed by us through such in June of 2010); and
      59,300 shares to our named executives and independent directors as
      compensation related to options rescinded in the prior fiscal
      year.





·
            In
      addition, on August 3, 2009, we issued 150,000 shares of restricted common
      stock (valued at $150,000) to vendors in satisfaction of certain
      outstanding balances payable to them and 32,000 shares of restricted
      common stock (valued at $32,000) to the four non-employee directors in
      lieu of cash compensation for board retainers for the period from July 1,
      2009 through September 30, 2009.





·
            Effective
      August 18, 2009, the Credit Facility with Texas Capital Bank was amended
      to implement a minimum interest rate of five percent (5.0%); establish
      minimum volumes to be hedged by September 15, 2009 of not less than
      seventy-five percent (75%) of the proved developed producing reserves
      attributable to our interest in the borrowing base oil and gas properties
      projected to be produced; and reduce the borrowing base to $6,986,500.
      Additionally, the borrowing base was reduced by $100,000 on the first day
      of each month by a Monthly Borrowing Base Reduction (MBBR) beginning
      September 1, 2009 and continuing through the January 1, 2010
      redetermination.





·
            On
      August 25, 2009 we entered into a fixed price swap transaction under the
      terms of the BP ISDAfor a total of
      20,250 gross barrels at a price of $77.05 per barrel before transportation
      costs for the period beginning October 1, 2009 and ending on March 31,
      2011.  This transaction allowed us to comply with the minimum
      hedge volumes required by Texas Capital Bank and increased the weighted
      average price for hedged volumes to between $64.958 and $61.963 from
      October 1, 2009 through March 2011.





·
            On
      August 25, 2009, we entered into an agreement with Coffeyville Resources
      Refining and Marketing, LLC (“Coffeyville”) to sell all our crude oil
      production beginning October 1, 2009 through March 31, 2011 to
      Coffeyville. All physical production will be sold to Coffeyville at
      current market prices defined as the average of the daily settlement price
      for light sweet crude oil reported by NYMEX for any given delivery month.
      All prices received are before location basis differential and oil quality
      adjustments.





·
            On
      December 3, 2009, we entered into a Stock Equity Distribution Agreement
      (“SEDA”) with Paladin Capital Management, S.A. (“Paladin”).  The
      SEDA provides that we may issue and sell to Paladin up to 1,300,000 shares
      (subject to adjustment as provided therein) of our common
      stock.  We issued 90,000 shares to Paladin as a commitment fee
      under the terms of the SEDA.  The price we receive shall be set
      at (i) 95% of the Market Price to the extent the Common Stock is trading
      at or above $2.00 per share during the Pricing Period, (ii) 92% of the
      Market Price to the extent the Common Stock is trading at or above $1.00
      per share during the Pricing Period, (iii) 90% of the Market Price to the
      extent the Common Stock is trading below $1.00 per share during the
      Pricing Period, or (iv) 85% of the Market Price for the initial two
      advances.  In December of 2009 we filed a registration statement
      on Form S-1 to register the 1,390,000 shares included in the SEDA. This
      registration statement is not yet
effective.


11





·
            On
      January 4, 2010, we issued to MorMeg, LLC 45,000 shares of restricted
      common stock for payment of consulting fees accrued from July 2009 through
      March 31, 2010 and 65,000 shares of restricted common stock as payment for
      granting an extension on the date required to provide additional
      development funding on the Black Oaks
project.





·
            On
      January 5, 2010, in an effort for us to preserve cash in light of
      deteriorated global economic conditions and the significant declines in
      commodity prices of oil and natural gas, Steve Cochennet, our
      CEO/President, agreed to convert his salary for the months of January and
      February 2010 into 73,261 shares of the Company’s restricted common
      stock.





·
            Effective
      January 13, 2010, the Credit Facility with Texas Capital Bank was amended
      to modify the senior funded debt to EBITDA ratio on a quarterly basis
      beginning with the quarter ending December 31, 2009 and to modify the
      annualization of the interest coverage ratio, also beginning with the
      quarter ending December 31, 2009.  The senior funded debt to
      EBITDA ratio allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March
      31, 2010; 5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010;
      and 4.25:1.00 for all quarters ending after September 30,
      2010.  We were not in compliance with the working capital ratio
      covenant at December 31, 2009; however, we were able to obtain a waiver of
      default from TCB.





·
            In
      the first quarter of 2010, we further amended the Debentures to extend the
      scheduled due dates for the January and February 2010 redemption payments
      to March 10, 2010 and to remove the conversion feature of the
      Debentures.  Further, the Maturity Date was extended to December
      31, 2010.





Relationship with Haas
Petroleumand
MorMeg





In April
of 2007, we entered into a consulting agreement with Mark Haas, President of
Haas Petroleum and managing member of MorMeg, which was terminated in April of
2010 when Mr. Haas was appointed to serve as our chief operating officer and a
director.  Mr. Haas provides executive level services 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.


12





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.





Drilling Activity





The
following table sets forth the results of our drilling activities during the
2008, 2009 and 2010 fiscal years.





Drilling ActivityGross Wells
                
                
                Net Wells(1)Fiscal Year
                
                Total
                
                
                Producing
                
                
                Dry
                
                
                Total
                
                
                Producing
                
                
                Dry2008
      Exploratory
                
                
                10
                
                
                
                10
                
                
                
                -0-
                
                
                
                10
                
                
                
                10
                
                
                
                -0-2009
      Exploratory(2)
                
                
                12
                
                
                
                12
                
                
                
                -0-
                
                
                
                12
                
                
                
                12
                
                
                
                -0-2010
      Exploratory
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-
                
                
                
                -0-2008
      Development
                
                
                59
                
                
                
                57
                
                
                
                2
                
                
                
                58
                
                
                
                56
                
                
                
                22009
      Development
                
                
                96
                
                
                
                95
                
                
                
                1
                
                
                
                96
                
                
                
                95
                
                
                
                12010
      Development
                
                
                2
                
                
                
                2
                
                
                
                -0-
                
                
                
                2
                
                
                
                2
                
                
                
                1


(1)
              Net
      wells are based on our net working interest as of March 31,
      2010.


(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, 2010 and 2009 and 2008, the average sales prices, average
production costs and direct lifting costs per unit of production.





Fiscal Year Ended
                  March 31, 2010
                
                
                Fiscal Year Ended
                  March 31, 2009
                
                
                Fiscal Year Ended
                  March 31, 2008Net
      ProductionOil
      (Bbl)
                
                
                64,948
                
                
                
                74,289
                
                
                
                43,697Natural
      gas (Mcf)
                
                
                -0-
                
                
                
                12,275
                
                
                
                17,762Average
      Sales PricesOil
      (per Bbl)
                
                $
                62.64
                
                
                $
                85.67
                
                
                $
                79.71Natural
      gas (per Mcf)
                
                $
                -0-
                
                
                $
                5.57
                
                
                $
                6.20Average
      Production Cost (1)Per
      Bbl of oil
                
                $
                40.38
                
                
                $
                45.01
                
                
                $
                56.65Per
      Mcf of natural gas
                
                $
                -0-
                
                
                $
                15.11
                
                
                $
                13.12Average
      Lifting Costs (2)Per
      Bbl of oil
                
                $
                28.22
                
                
                $
                33.01
                
                
                $
                37.08Per
      Mcf of natural gas
                
                $
                -0-
                
                
                $
                15.11
                
                
                $
                9.86







13





(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.




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, 2008 through
March 31, 2010. 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, 2010
                    
                    
                    For the
                      Fiscal Year
                      Ended
                      March 31, 2009
                    
                    
                    For the
                      Fiscal Year
                      Ended
                      March 31, 2008Production
      revenues
                    
                    $
                    4,856,027
                    
                    
                    $
                    6,436,805
                    
                    
                    $
                    3,602,798Production
      costs
                    
                    
                    (1,833,108
                    )
                    
                    
                    (2,637,333
                    )
                    
                    
                    (1,795,188
                    )Depreciation,
      depletion and amortization
                    
                    
                    (789,455
                    )
                    
                    
                    (872,230
                    )
                    
                    
                    (913,224
                    )Results
      of operations for producing activities
                    
                    $
                    2,233,464
                    
                    
                    $
                    2,972,242
                    
                    
                    $
                    894,386





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, 2010.





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,
      2010.




Reserves





Our
estimated total proved PV10 (present value) before tax of reserves as of March
31, 2010 was $21.26 million, versus $10.63 million as of March 31, 2009. Our
total proved reserves increased almost 40% at March 31, 2010 and over 2009
from 1.8 million and 1.3 million barrels of oil equivalent (BOE),
respectively. In addition, the PV10 increased dramatically due to the
estimated average price of oil at March 31, 2010 of $62.64 versus $42.65 at
March 31, 2009.  Of the 1.8 million BOE at March 31, 2010
approximately 31% are proved developed and approximately 69% are proved
undeveloped. The proved developed reserves consist of proved developed producing
(78%) and proved developed non-producing (22%). See “Glossary” on page 21
for our definition of PV10.


14





Based on
an estimated oil price of $62.64 as of March 31, 2010, and applying an annual
discount rate of 10% of the future net cash flow, the estimated PV10 of the 1.8
million BOE, before tax, is calculated as set forth in the following
table:





Summary
of Oil and Natural Gas Reserves


as
of March 31, 2010





ProvedReserves
                    Category
                  
                  Gross
                    STB(1)
                  
                  
                  Net
                    STB(2)
                  
                  
                  Gross
                    MCF(3)
                  
                  
                  Net
                    MCF(4)
                  
                  
                  PV10(5)
                    (beforetax)Proved,
      Developed Producing
                  
                  
                  822,180
                  
                  
                  
                  443,380
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  $
                  8,719,460Proved,
      Developed Non-Producing
                  
                  
                  201,020
                  
                  
                  
                  126,100
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  3,170,010Proved,
      Undeveloped
                  
                  
                  2,542,560
                  
                  
                  
                  1,242,040
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  9,372,030Total
      Proved
                  
                  
                  3,565,760
                  
                  
                  
                  1,811,520
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  $
                  21,261,500


(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,
      2010.


(4)
              Net MCF is based upon our net
      revenue interest.  There we no natural gas reserves at March 31,
      2010.


(5)
              See
      “Glossary” on page 21 for our definition of PV10 and “Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations-Reserves” page 53, 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, 2010.





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.


15


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 Coffeyville to sell all of our current oil
production through March of 2011. 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 Recovery and 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.


16





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.





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.


17




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.





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 and changing 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.


18





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





·
            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 renewal by 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 environmental laws 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 significant impact 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
authorize the 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.


19





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.





Personnel





As of
March 31, 2010, we had 14 full-time employees; however, subsequent to year-end
we have reduced staff to 5 employees.  As production and drilling
activities increase or decrease, we may have to continue to adjust our
technical, operational and administrative personnel as appropriate. We are using
and will continue to use 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 and general expenses, and capital
costs.





Facilities





We currently lease our
executive offices at27 Corporate Woods, Suite 350, 10975 Grandview
Drive, Overland Park, Kansas  66210, which expires in September 30,
2013.  Future minimum payments $72,000 to $75,600 for years
ended March 31, 2011-2013 and $38,750 for the year ended March 31,
2014.


20





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 rocks occur 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 brought into
      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 production owned 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 placing the 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 that proceeds 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.


21





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 the underground 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 over the 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 of gross 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 technique used 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.


22





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
      contained in 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 the applicable 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” on
      page 57 for a reconciliation to the comparable GAAP financial
      measure.


23





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 the oil 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 natural gas 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
              
              A
      well 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 into the 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 to a
waterflood.


24





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 percentage of 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.


25




Item
1A. Risk Factors.





In the
course of conducting our business operations, we are exposed to a variety of
risks that are inherent to the oil and gas industry. The following discusses
some of the key inherent risk factors that could affect our business and
operations, as well as other risk factors which are particularly relevant to us
in the current period of significant economic and market disruption. Other
factors besides those discussed below or elsewhere in this report also could
adversely affect our business and operations, and these risk factors should not
be considered a complete list of potential risks that may affect
us.





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 of the banking system and
the financial markets generally.  In recent months, 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, which may materially adversely 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 sustained losses, 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:





·
            the
      future prices of natural gas and
oil;


·
            our
      ability to raise adequate working
capital;


·
            success
      of our development and exploration
efforts;


·
            effects
      of our hedging strategies;


·
            demand
      for 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 requirements or advancements;


·
            government
      regulation and taxation;


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


26


·
            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.





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 anticipated reserve 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, operating difficulties, constrained capital sources
or other 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 or otherwise 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.


27





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, 2010 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.





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 changes in 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 and worldwide 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.


28





Approximately 69%
of our total proved reserves as of March 31, 2010 consist 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, 2010 was $21.26 million, versus $10.63 million as of March 31,
2009.   The substantial increase in PV10 is primarily due to the
estimated average price of oil at March 31, 2010 of $62.64 versus $42.65 at
March 31, 2009.  We developed total proved reserves to 1.8 million
barrels of oil equivalent, or BOE, as of March 31, March 31, 2010. Of the
1.8 million BOE of total proved reserves, approximately 31% are proved
developed and approximately 69% are proved undeveloped. The proved developed
reserves consist of 78% proved developed producing reserves and 22% proved
developed non-producing reserves.   See “Glossary” on page 21 for
our definition of PV10.





As of
March 31, 2010, approximately 69% of our total proved reserves were undeveloped
and approximately 7% were developed non-producing. Assuming we can obtain
adequate capital resources, we plan to develop and produce all of our proved
reserves, but ultimately some of these reserves may not be developed or
produced. 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 at all.





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 reserves at
March 31, 2010 was prepared by Miller and Lents, Ltd., an independent petroleum
consultant.  There are numerous uncertainties inherent in estimating
quantities of proved reserves and cash flows from such reserves, including
factors beyond our control and the control of these 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 available data, 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 and value 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 estimates of 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 by Miller 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.


29





The
present value of future net cash flows from our proved reserves is not
necessarily the same as the current 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;


·
            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 our properties 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.





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 for our oil and natural gas production typically
trade 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 terms of our agreement with BP through March of
2011, the differential on physical sales after that date is still under
negotiation.  We cannot accurately predict oil and natural gas
differentials. In recent years for example, production increases from competing
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 decreases in the
differential between the benchmark price for oil and natural gas and the
wellhead price we receive.  These fluctuations could 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.


30





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:





·
            unexpected
      operational 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:





·
            injury
      or 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;


·
            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 levels that 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.


31





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 geological conditions, 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 development
wells. Substantially all of our wells drilled through March 31, 2010 have
been development wells. A variety 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 and lack of access to
economically acceptable capital 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, among other 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 requires significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Our estimates 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.


32





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 efficiently developing 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 acceptable
      purchase 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 are either in the
early stage of implementation or are scheduled for implementation subject 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 any development 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;


·
            longer
      response times;


·
            higher
      costs associated with obtaining
capital;


·
            unusual
      or unexpected geological
formations;


·
            fluctuations
      in natural gas and oil prices;


·
            regulatory
      changes;


33


·
            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
we make 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 additional debt 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;


·
            an
      inability 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 perform an 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 the properties 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 when an
inspection is undertaken.


34





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 commencement or 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 new customers for our
production.





We have
contracted with Coffeyville for the sale of all of our oil through March 2011 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 are
not 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. We have 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.


35





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 to our 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, 2013 for between
30 and 130 barrels of oil per day that could result in both realized and
unrealized hedging losses. As of March 31, 2010 we had incurred realized and
unrealized losses of approximately 3.911 million. 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.





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 or lack 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 will arise and
their duration. Any significant curtailment in gathering system or pipeline
capacity could significantly reduce our ability to market our oil and natural
gas production and could materially harm our business.


36





Cost
and availability of 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 personnel could
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 has agreed to provide up to two drilling rigs to
the Black Oaks Project when needed, subject to availability of capital, we do
not have any contracts for drilling rigs and drilling rigs may not be readily
available when we need them. Drilling and other costs may 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.





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 in
revenues 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 dilutive effect on our lease ownership and could significantly reduce
our operating revenues.


37





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 drilling
      operations;


·
            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.





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.


38


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.


39


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, 2010. 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, 2009.





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.


40


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, 2010, $2.47 million in debentures and approximately $6.7 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, 2010, we had total indebtedness of $10.1 million, including
$6.691 million of borrowings under the Credit Facility and $2.47 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, 2010. 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;


·
            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;


41


·
            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 were not in compliance with three
covenants at March 31, 2010. 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.





Risks Associated with our
Common Stock





We
have derivative securities currently outstanding and we may issue derivative
securities in the future. Exercise of the derivatives will cause dilution to
existing and new shareholders.





The
exercise of our outstanding warrants, and the conversion of a convertible note,
will cause additional shares of common stock to be issued, resulting in dilution
to our existing and future common stockholders





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.


42


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;


·
            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.


43


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.





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





As of
March 31, 2010, we had warrants to purchase approximately 75,000 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:


44


·
            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.





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.


45


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.




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





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 on Yahoo! Finance for fiscal years 2009 and 2010. The
quotations reflect inter-dealer prices without retail mark-up, markdown, or
commissions and may not represent actual transactions.





Low
                  
                  
                  HighFiscal
      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
                  
                  
                  
                  1.88Fiscal
      2010Quarter
      ended June 30, 2009
                  
                  
                  0.15
                  
                  
                  
                  1.34Quarter
      ended September 30, 2009
                  
                  
                  0.15
                  
                  
                  
                  1.85Quarter
      ended December 31, 2009
                  
                  
                  0.41
                  
                  
                  
                  1.00Quarter
      ended March 31, 2010
                  
                  
                  0.29
                  
                  
                  
                  1.09





The last
reported sale price of our common stock on the OTC:BB was $0.69 per share
on  July 9, 2010.


46


(b)
Holders of Common Stock





As of
July 9, 2010, there were 1,146 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.


(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 and all such shares were
previously granted to Mr. Cochennet. On August 3, 2009, we exchanged these
outstanding options for 50,000 shares of our restricted common stock. Therefore,
all 200,000 shares reserved for issuance under this plan are again available for
issuance.





Stock
Incentive 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 2002-2003 Stock Option Plan was not to exceed 400,000 shares.
In September 2007 our stockholders approved a proposal to amend and restate the
2002-2003 Stock Option Plan to increase the number of shares issuable to
1,000,000.  On October 14, 2008 our stockholders approved a proposal
to amend and restate the 2002-2003 Stock Option Plan to (i) rename it the
EnerJex Resources, Inc. Stock Incentive Plan (the “Stock Incentive Plan”), (ii)
increase the maximum number of shares of our common stock that may be issued
under the Stock Incentive Plan from 1,000,000 to 1,250,000, and (iii) add
restricted stock as an eligible award that can be granted under the Stock
Incentive Plan.





We had
previously granted 238,500 options under this plan. On August 3, 2009, we
exchanged all 238,500 outstanding options for 59,700 shares of our restricted
common stock. In addition, we granted 151,750 shares of restricted common stock
under the Stock Incentive Plan to employees for fiscal 2009 bonuses and 59,300
shares to our officers and directors for the prior rescission of stock options
in fiscal 2008.


47


General
Terms of 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 awards under the 2000/2001 Stock Option Plan and the Stock
Incentive Plan. A committee of the board of directors will administer the plans
and will determine those persons to whom awards will be granted, the number of
and type of awards to be granted, the provisions applicable to each grant and
the time periods during which the awards may be exercised. No awards may be
granted more than ten years after the date of the adoption of the
plans.





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
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 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.




Restricted
stock will have full dividend, voting and other ownership rights, unless
otherwise indicated in the applicable award agreement pursuant to which it is
granted.  If any dividends or distributions are paid in shares of
common stock during the restricted period, the applicable award agreement may
provide that such shares will be subject to the same restrictions as the
restricted stock with respect to which they were paid.




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





On August
3, 2009, we issued 100,000 shares of restricted common stock to C.K. Cooper
& Company, LLC, valued at $100,000, in full satisfaction of C.K. Cooper’s
outstanding balance payable as of the date of issuance. The Company believes
that the issuance of the shares was exempt from the registration and prospectus
delivery requirements of the Securities Act of 1933 by virtue of
Section 4(2) thereof.





On August
3, 2009, we issued Accuity Financial Inc. 50,000 shares of restricted common
stock, valued at $50,000, for payment against Accuity’s outstanding balance
payable. The Company believes that the issuance of the shares was exempt from
the registration and prospectus delivery requirements of the Securities Act of
1933 by virtue of Section 4(2) thereof.


48


On August
3, 2009, in an effort for us to preserve cash in light of deteriorated global
economic conditions and the significant declines in commodity prices of oil and
natural gas, each of the Company’s non-employee directors agreed to convert
their board/committee retainers for the period from July 1, 2009 through
September 30, 2009 into 32,000 shares of the Company’s restricted common stock.
The Company believes that the issuance of the shares was exempt from the
registration and prospectus delivery requirements of the Securities Act of 1933
by virtue of Section 4(2) thereof.





On August
3, 2009, we issued a total of 109,700 shares of our common stock in exchange for
438,500 currently outstanding options to purchase shares of our common
stock.  The shares issued were issued pursuant to the EnerJex
Resources Stock Incentive Plan and registered on the Form S-8 filed on October
20, 2008.





On August
3, 2009, we awarded a total of 151,750 shares of our common stock for 2009
incentive bonuses to our employees. Such shares were issued to the employees in
June of 2010. The shares were awarded pursuant to the EnerJex Resources Stock
Incentive Plan and registered on the Form S-8 filed on October 20,
2008.





On August
3, 2009, we issued a total of 59,300 shares of our common stock to our named
executive officers and directors for options that were previously rescinded for
no consideration. The shares issued were issued pursuant to the EnerJex
Resources Stock Incentive Plan and registered on the Form S-8 filed on October
20, 2008.





On August
20, 2009, we issued the Debenture holders 2,330 shares of our common stock in
lieu of interest payments for the quarter ended March 31, 2009 and 2,394 shares
of our common stock in lieu of interest payments for the quarter ended June 30,
2009. We believe that the issuance of the shares was exempt from the
registration and prospectus delivery requirements of the Securities Act of 1933
by virtue of Section 4(2) thereof.





On
October 8, 2009, we issued the Debenture holders 1,424 shares of our common
stock in lieu of interest payments for the quarter ended September 30, 2009. We
believe that the issuance of the shares was exempt from the registration and
prospectus delivery requirements of the Securities Act of 1933 by virtue of
Section 4(2) thereof.





On
December 3, 2009, we authorized the issuance of 90,000 shares of our common
stock to Paladin as a commitment fee under the SEDA. We believe that the
issuance of the shares was exempt from the registration and prospectus delivery
requirements of the Securities Act of 1933 by virtue of Section 4(2)
thereof.





On
December 22, 2009, in an effort for the Company to preserve cash in light of
deteriorated global economic conditions and the significant declines in
commodity prices of oil and natural gas, each of the Company’s non-employee
directors agreed to convert their board/committee retainers for the period from
October 1, 2009 through December 31, 2009 into 20,000 shares of the Company’s
restricted common stock.  The Company believes that the issuance of
the shares was exempt from the registration and prospectus delivery requirements
of the Securities Act of 1933 by virtue of Section 4(2)
thereof.


49


On
January 4, 2010, the Company issued to MorMeg, LLC 45,000 shares of restricted
common stock for payment of consulting fees accrued from July 2009 through March
31, 2010 and 65,000 shares of restricted common stock as payment for granting an
extension on the date required to provide additional development funding on the
Black Oaks project. The Company believes that the issuance of the shares was
exempt from the registration and prospectus delivery requirements of the
Securities Act of 1933 by virtue of Section 4(2) thereof.





On January 5, 2010, in an effort for
the Company to preserve cash in light of deteriorated global economic conditions
and the significant declines in commodity prices of oil and natural gas, Steve
Cochennet, our CEO/President, agreed to convert his salary for the months of
January and February 2010 into 73,261 shares of the Company’s restricted common
stock. The Company believes that the issuance of the shares was exempt from the
registration and prospectus delivery requirements of the Securities Act of 1933
by virtue of Section 4(2) thereof.





On
January 5, 2010, we issued to Tom Nelson of Ten Associates, LLC 5,000 share of
restricted common stock for payment of professional services to be rendered
beginning in January 2010. The Company believes that the issuance of the shares
was exempt from the registration and prospectus delivery requirements of the
Securities Act of 1933 by virtue of Section 4(2) thereof.





On January 12, 2010, we issued the
Debenture holders an additional 45 shares of our common stock in lieu of
interest payments for the quarter ended September 30, 2009 and 4,223 shares of
our common stock in lieu of interest payments for the quarter ended December 31,
2009. We believe that the issuance of the shares was exempt from the
registration and prospectus delivery requirements of the Securities Act of 1933
by virtue of Section 4(2) thereof.





Issuer
Purchases of Equity Securities





In December 2009, we redeemed $150,000
of our subordinated debentures for $150,000 in cash. In accordance with the
terms of the amended Debentures, 75,000 shares were tendered to us and cancelled
for the $150,000 redemption.





Other than set forth above we did not
repurchase any of our equity securities during the fiscal years ended March 31,
2010 or 2009.




Item
6. Selected Financial Data.





Not applicable.


50


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
includedelsewhere 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
may differ 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.





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.





Results
of Operations for the Fiscal Years Ended March 31, 2010 and 2009
compared.





Income:


Fiscal
      Year Ended
                      March
      31,2010
                    
                    
                    2009
                    
                    
                    Increase
      / (Decrease)Amount
                    
                    
                    Amount
                    
                    
                    $Oil
      and natural gas revenues
                    
                    $
                    4,856,027
                    
                    
                    $
                    6,436,805
                    
                    
                    $
                    (1,580,778
                    )





Revenues





Oil and
natural gas revenues for the fiscal year ended March 31, 2010 were
$4,856,027 compared to revenues of $6,436,805 in the fiscal year ended
March 31, 2009. The decrease in revenues is primarily the result of the
lower price per barrel of oil.  The average price per barrel we
received for oil sold during the twelve months ended March 31, 2010 was $69.62
compared to $85.67 for the twelve months ended March 31, 2009. Natural gas sales
accounted for less than 1% of the total revenues. There were no natural gas
sales during the fiscal year ended March 31, 2010 and ended March 31, 2009
respectively.





Expenses:


Fiscal
      Year Ended
                        March
      31,2010
                      
                      
                      2009
                      
                      
                      Increase
      /
                        (Decrease)Amount
                      
                      
                      Amount
                      
                      
                      $Expenses:Direct
      operating costs
                      
                      $
                      1,833,108
                      
                      
                      $
                      2,637,333
                      
                      
                      $
                      (804,225
                      )Depreciation,
      depletion and amortization
                      
                      
                      789,455
                      
                      
                      
                      872,230
                      
                      
                      
                      (82,775
                      )Total
      production expenses
                      
                      
                      2,622,563
                      
                      
                      
                      3,509,563
                      
                      
                      
                      (887,000
                      )Professional
      fees
                      
                      
                      561,625
                      
                      
                      
                      1,320,332
                      
                      
                      
                      (758,707
                      )Salaries
                      
                      
                      835,576
                      
                      
                      
                      849,340
                      
                      
                      
                      (13,764
                      )Depreciation
      on other fixed assets
                      
                      
                      47,081
                      
                      
                      
                      39,063
                      
                      
                      
                      8,018Administrative
      expenses
                      
                      
                      1,016,484
                      
                      
                      
                      1,392,645
                      
                      
                      
                      (376,161
                      )Impairment
      of oil & gas properties
                      
                      
                      -
                      
                      
                      
                      4,777,723
                      
                      
                      
                      (4,777,723
                      )Total
      expenses
                      
                      
                      5,083,329
                      
                      
                      
                      11,888,666
                      
                      
                      
                      (6,805,337
                      )


51
  Direct
Operating Costs




Direct
operating costs for the fiscal year ended March 31, 2010 were
$1,833,108 compared to $2,637,333 for the fiscal year ended March 31, 2009.
The decrease 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, 2010. 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, 2010 was
$789,455, compared to $872,230 for the fiscal year ended March 31, 2009. The
decrease was primarily a result of lower production. The rate of depletion was
$12.16 per barrel for the fiscal year ended March 31, 2010 as compared to $12.02
per barrel for the fiscal year ended March 31, 2009.





Professional
Fees




Professional
fees for the fiscal year ended March 31, 2010 were $561,625 compared to
$1,320,332 for the fiscal year ended March 31, 2009. 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, 2010 were $835,576 compared to $849,340
for the fiscal year ended March 31, 2009. The number of full-time employees
was flat compared to the respective years.





Depreciation
on Other Fixed Assets





Depreciation on other fixed assets
fiscal year ended March 31, 2010 was $47,081 compared to $39,063 for the fiscal
year ended March 31, 2009.  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, 2010 were $1,016,484 compared
to $1,392,645 in the fiscal year ended March 31, 2009. The administrative
expenses decreased resulting from less activity in development and exploration
and cost cutting measures.


52


Impairment
of Oil & Gas Properties




No
impairment was recorded for the fiscal year ended March 31, 2010.  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,
2010 increased to $21.26 million from $10.63 million as of March 31, 2009.
Total proved reserves at March 31, 2010 and 2009 increased approximately
40% to 1.8 million and from 1.3 million barrels of oil equivalent
(BOE), over the year ended March 31, 2009. Further, the PV10
increased dramatically due to the estimated average price of oil at
March 31, 2010 of $62.64 versus $42.65 at March 31, 2009.  Of the 1.8
million BOE at March 31, 2010 approximately 31% are proved developed and
approximately 69% are proved undeveloped. The proved developed reserves consist
of proved developed producing (78%) and proved developed non-producing
(22%).





The
following table presents summary information regarding our estimated net proved
reserves as of March 31, 2010. 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 13 to our audited financial
statements as of and for the fiscal year ended March 31, 2010.





Summary
of Proved Oil and Natural Gas Reserves


as
of March 31, 2010





Proved
      Reserves Category
                
                Gross
                
                
                Net
                
                
                PV10
      (before tax)(1)Proved,
      Developed ProducingOil
      (stock-tank barrels)
                
                
                822,180
                
                
                
                443,380
                
                
                $
                8,719,460Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -Proved,
      Developed Non-ProducingOil
      (stock-tank barrels)
                
                
                201,020
                
                
                
                126,100
                
                
                $
                3,170,010Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -Proved,
      UndevelopedOil
      (stock-tank barrels)
                
                
                2,542,560
                
                
                
                1,242,040
                
                
                $
                9,372,030Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -Total
      Proved ReservesOil
      (stock-tank barrels)
                
                
                3,565,760
                
                
                
                1,,811,520
                
                
                $
                21,261,500Natural
      Gas (mcf)(2)
                
                
                -
                
                
                
                -
                
                
                
                -




53


(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,
                    2010PV10
      (before tax)
                  
                  $
                  21,261,500Future
      income taxes, net of 10% discount
                  
                  
                  (3,712,060
                  )Standardized
      measure of discounted future net cash flows
                  
                  $
                  17,549,440





(2)
              There
      were no natural gas reserves at March 31,
2010.





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. We have classified $660,000
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. Further, in the future we may access funds through the sale of
shares under the SEDA with Paladin.





The
following table summarizes total current assets, total current liabilities and
working capital at March 31, 2010 as compared to March 31, 2009.





March
      31,
                    
                    
                    March
      31,
                    
                    
                    Increase
      / (Decrease)2010
                    
                    
                    2009
                    
                    
                    $Current
      Assets
                    
                    $
                    665,683
                    
                    
                    $
                    898,941
                    
                    
                    
                    233,258Current
      Liabilities
                    
                    $
                    14,977,607
                    
                    
                    $
                    2,827,015
                    
                    
                    
                    12,150,592Working
      Capital (deficit)
                    
                    $
                    (14,311,925
                    )
                    
                    $
                    (1,928,074
                    )
                    
                    
                    12,383,851




54


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 (“TCB”).  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.  A
borrowing base redetermination was completed by Texas Capital Bank effective
January 1, 2010.  The borrowing base was determined to be $6,746,000
and called for $55,000 Monthly Borrowing Base Reductions (“MBBR”) beginning
February 1, 2010.





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 have borrowed
all of our available borrowing base as of March 31, 2010.





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, but
in no event shall be less than five percent (5.0%). 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 extension, but in no event shall be less than five percent
(5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR
options, except that beginning March 30, 2009 and continuing through the date of
this report, TCB has suspended all LIBOR based funding with maturities less than
90 days due to the extreme volatility in the interest rate market and the
unprecedented spread between the 90 day LIBOR and the shorter term LIBOR
options. 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, 2010.





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.


55


The
Credit Facility was amended August 18, 2009 to implement a minimum interest rate
of five (5.0%) and establish minimum volumes to be hedged of not less than
seventy-five percent (75%) of the proved developed producing reserves
attributable to our interest in the borrowing base oil and gas properties
projected to be produced. The Credit Facility was further amended January
13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis
beginning with the quarter ended December 31, 2009 and to modify the
annualization of the interest coverage ratio, also beginning with the quarter
ended December 31, 2009.  The senior funded debt to EBITDA ratio
allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010;
5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00
for all quarters ending after September 30, 2010. We were not in compliance the
three technical covenants of the Credit Facility at March 31, 2010, however, we
were current with principal and interest and we have requested a waiver of this
technical default from TCB.  There can be no assurance that TCB will
grant us a waiver. As a result, we have classified the entire outstanding
balance due under the Credit Facility as a current liability.





Additionally,
TCB and the holders of the debentures entered into a Subordination Agreement
whereby the debentures issued on June 21, 2007 are subordinated to the Credit
Facility.





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. Effective July 7, 2008, we
redeemed an aggregate principal amount of $6.3 million of the Debentures. We
also amended the remaining $2.7 million of aggregate principal Debentures 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 and eliminate the covenant to maintain
certain production thresholds.





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.  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 year ended March
31, 2010 was $596,108. There was is no remaining amount of interest to
accrete.





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 year
ended March 31, 2010 was $45,929.


56


The Debentures originally had a
three-year term, maturing on March 31, 2010, and an interest rate equal to 10%
per annum.  We further amended the Debentures in June 2009 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 our common
stock.  Subsequent to the quarter ended December 31, 2009, we further
amended the Debentures to extend the scheduled due dates for the January and
February 2010 redemption payments to March 10, 2010.  In addition, in
April of 2010, we further amended the Debentures to remove the conversion
feature and extend the Maturity Date to December 31, 2010.





Interest
is payable quarterly in arrears on the first day of each succeeding quarter. The
interest rate remains 14% per annum for cash interest payments.  The
payment-in-kind interest rate is equal to 12.5% per annum.  If
interest payments are made through payment-in-kind interest, we must issue
common stock equal to an additional 2.5% of the quarterly interest payment
due.  As of March 31, 2010, we have recorded additional principal on
the Debentures of $368,045 and common stock of $9,792.





We again
amended the Debentures on November 16, 2009 to provide for the tender and
cancellation of shares by the Buyers upon retirement of a portion of the
Debentures in accordance with an agreed upon schedule.  We redeemed
$150,000 of the Debentures for $150,000 in cash in accordance with this
amendment during the quarter ended December 31, 2009.  As a result,
75,000 shares have been tendered and will be cancelled.





We 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.  During the year ended
March 31, 2010 we also repurchased $450,000 of the Debentures at a gain of
$406,500.





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 2010, 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.


57




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.





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, 2010, we had 14 full-time employees; however, subsequent to year-end
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 and general 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.




58


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.





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.




59


As of
March 31, 2010, 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.





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





Accounting Standards Codification— On July 1, 2009, the Financial Accounting Standards Board
(“FASB”) instituted a
new referencing system, which codifies, but does not amend, previously existing
nongovernmental GAAP.  The FASBAccounting Standards CodificationTM(“ASC”) is now
the single authoritative source for GAAP.  Although the implementation
of ASC had no impact on our financial statements, certain references to
authoritative GAAP literature within our footnotes have been changed to cite the
appropriate content within the ASC.





FASB
Accounting Standards Update (“ASU”) 2010-03 was issued on
January 6, 2010, and aligns the current oil and natural gas reserve
estimation and disclosure requirements of ASC 932 with those in the SEC Final Rule Modernization of Oil
and Gas
Reporting issued December 31, 2008. The rules only apply
prospectively as a change in estimate. The most significant amendments to the
reserve and disclosure requirements include the following:




·
            Commodity
      Prices—Economic producibility of reserves and discounted cash flows will
      be based on an unweighted arithmetic average of the first day of the month
      commodity price during the 12-month period ending on the balance sheet
      date unless contractual arrangements designate the price to be
      used.




60





·
            Disclosure
      of Unproved Reserves—Probable and possible reserves may be disclosed
      separately on a voluntary basis.





·
            Proved
      Undeveloped Reserve Guidelines—Reserves may be classified as proved
      undeveloped if there is a high degree of confidence that the quantities
      will be recovered.





·
            Reserve
      Estimation Using New Technologies—Reserves may be estimated through the
      use of reliable technology in addition to flow tests and production
      history.





·
            Reserve
      Personnel and Estimation Process—Additional disclosure is required
      regarding the qualifications of the chief technical person who oversees
      our reserves estimation process. We will also be required to provide a
      general discussion of our internal controls used to assure the objectivity
      of the reserves estimate.





·
            Disclosure
      by Geographic Area—Reserves in foreign countries or continents must be
      presented separately if they represent more than 15% of our total oil and
      natural gas proved reserves.





·
            Non-Traditional
      Resources—The definition of oil and natural gas producing activities will
      expand and focus on the marketable product rather than the method of
      extraction.




ASU
2010-03 is effective for entities with annual reporting periods ending on or
after December 31, 2009. We adopted both the FASB and the SEC
rules.





Adoption of ASU 2009-05 — In
August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting
Standards Update (“ASU”) No. 2009-05, Fair Value Measurement and
Disclosures: Measuring Liabilities at Fair Value.  ASU 2009-05
provides clarification on measuring liabilities at fair value when a quoted
price in an active market is not available.  We adopted ASU No.
2009-05 (FASB ASC 820-10).  The adoption of this statement did not
have an impact on our financial position or results of operations.





Interim Disclosures about Fair Value
of Financial Instrument — We adopted FSP SFAS 107-1 and APB 28-1 “Interim
Disclosures about Fair Value of Financial Instruments”, which is now
incorporated into ASC Topic No. 825 (“ASC 825”).  This
statement increases the frequency of fair value disclosures to a quarterly
instead of annual basis.  The guidance relates to fair value
disclosures for any financial instruments that are not currently reflected on
the balance sheet at fair value.  The adoption of this statement did
not have a material impact on our financial position or results of
operations.





Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly — We adopted
the FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity
for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly” which is now incorporated into ASC Topic No.
820 (“ASC
820”).  ASC 820 provides guidelines for a broad
interpretation of when to apply market-based fair value measures.  It
reaffirms management’s need to use judgment to determine when a market that was
once active has become inactive and in determining fair values in markets that
are no longer active.




61


Disclosure about Derivative
Instruments and Hedging Activities — We adopted FASB Statement No. 161,
“Disclosure about Derivative Instruments and Hedging Activities, an amendment of
FASB Statement No. 133” which is now incorporated into ASC Topic No. 815 (“ASC 815”).  ASC 815
amends and expands the disclosure requirements for derivative instruments and
hedging activities with the intent to provide users of financial statements with
an enhanced understanding of: (i) how and why an entity uses derivative
instruments; (ii) how derivative instruments and related hedged items are
accounted for; and (iii) how derivative instruments and related hedged
items affect an entity’s financial position, results of operations and cash
flows. The adoption of this statement did not have an impact on our
financial position or results of operations.





Business Combinations —We
adopted SFAS No. 141 (Revised 2007) “Business Combinations” which is now
incorporated into ASC Topic No. 805 (“ASC 805”).  The
revision broadens the definition of a business combination to include all
transactions or other events in which control of one or more businesses is
obtained.  Further, this statement establishes principles and
requirements for how an acquirer recognizes assets acquired, liabilities assumed
and any non-controlling interests acquired.  The adoption of this
statement has not had an impact on our financial position or results of
operations, because we have not yet had any business combinations in the year
ended March 31, 2010.





Effective Date of FASB Statement No.
157 - We also adopted FSP SFAS 157-2, “Effective Date of FASB Statement
No. 157”, which is also now incorporated into ASC Topic No. 820. The
effective date was deferred for all nonfinancial assets and nonfinancial
liabilities, except for items that are recognized or disclosed at fair value in
the financial statements on a recurring basis (at least annually) to fiscal
years beginning after November 15, 2008, and interim periods within
those fiscal years.   The adoption of this statement did not have
a material impact on our financial position or results of
operations.





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.


62




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




Not applicable.




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 currently 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 and Principal Financial Officer, C. Stephen Cochennet,
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 concluded that our disclosure controls and procedures
are effective in timely altering him to material information relating to us
(including our consolidated subsidiaries) required to be included in our
periodic SEC filings.


63


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.





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, 2010.





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.




Technical Default under
Credit Facility





On July
3, 2008, we 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 are subject to a borrowing base limitation based on
our current proved oil and gas reserves and are subject to semi-annual
redeterminations.





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 and to maintain a minimum ratio of EBITDA to
senior funded debt. We obtained a waiver of default from Texas Capital Bank on
two technical covenants at March 31, 2009 and one at June 30,
2009.  We were not in compliance with the technical covenants of the
Credit Facility at March 31, 2010, however, we are current with principal and
interest and we have requested a waiver of this technical default from
TCB.  There can be no assurance that TCB will grant us a waiver. As a
result, we have classified the entire outstanding balance due under the Credit
Facility as a current liability.


64


We have
received Monthly Commitment Reduction notices from Texas Capital under the
Credit Facility through monthly installments.  We paid $637,000 to
reduce the borrowing base during the year ended March 31, 2010. Following
receipt of the notices, we commenced discussions with Texas Capital regarding a
possible forbearance agreement or waiver, pursuant to which the bank would
waive, postpone or delay the requirement to repay some or all of the anticipated
Monthly Commitment Reductions, in order to afford us additional time to raise
equity capital, increase production or consummate alternative financing
transactions. The discussions are currently ongoing, although there is no
assurance that we will be able to negotiate successfully a forbearance agreement
or obtain any other waiver of compliance from the bank.





Although
we anticipate the ability to make monthly payments of $55,000 following the most
recent borrowing base review, which will be applied towards the borrowing base
reduction; if we are unable to successfully negotiate a forbearance agreement,
obtain a waiver of compliance or cure a borrowing base deficiency, an event of
default under the Credit Facility will occur. An event of default under the
Credit Facility permits Texas Capital to accelerate repayment of all amounts due
and to terminate the commitments thereunder. We currently have approximately
$6.69 million drawn under the Credit Facility. Any event of default which
results in such acceleration under the Credit Facility would also result in an
event of default under our Debentures, described above. We do not have
sufficient cash resources to repay these amounts if Texas Capital accelerates
its obligations under the Credit Facility. If we are unable to successfully
negotiate a forbearance agreement or waiver with Texas Capital, or if Texas
Capital accelerates its obligations under the Credit Facility, we may be forced
to voluntarily seek bankruptcy protection.





The terms
of the Credit Facility (including a full description of the rights and remedies
of Texas Capital upon an event of default), and copies of the Texas Capital
agreements related to the Credit Facility can be found in our prior filings with
the SEC, including the Current Reports on Forms 8-K filed with the SEC on July
10, 2008 and November 19, 2008, which are incorporated herein by reference and
in the First Amendment to the Credit Agreement included in exhibit 10.12 and in
the Second Amendment to the Credit Agreement included in exhibit
10.16.





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, Principal Financial Officer and
      Director
              
              NoneMark
      Haas
              
              53
              
              Chief
      Operating Officer and Director
              
              RestructuringThomas
      Kmak
              
              49
              
              Chairman
              
              GCNC,
      Restructuring and AuditLoren
      Moll
              
              53
              
              Director
              
              GCNC,
      Restructuring (Chairman) and AuditDarrel
      G. Palmer
              
              51
              
              Director
              
              GCNCDierdre
      P. Jones(2)
              
              44
              
              Former
      Chief Financial Officer
              
              NoneRobert
      G. Wonish(3)
              
              55
              
              Former
      Director
              
              Formerly
      GCNC (Chairman) and
                AuditDaran
      G. Dammeyer(3)
              
              48
              
              Former
      Director
              
              Formerly
      Audit (Chairman) and
                GCNCDr.
      James W. Rector(3)
              
              48
              
              Former
      Director
              
              None




65





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


“Restructuring”
means the Restructuring Committee of the Board of Directors.


(2)
            Effective
      June 10, 2010, Ms. Jones resigned as our chief financial officer to pursue
      other opportunities.


(3)
            Effective
      April 1, 2010, Messrs. Wonish, Dammeyer and Dr. Rector resigned as members
      of our board of directors.





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.





Mark Haas. Mr. Haas has been
the President of Haas Petroleum, LLC, an oil and natural gas operator, since its
inception in 1974. He is also the President of Skyy Drilling, LLC, a full
service drilling company formed in 2002, and the Managing Director of MorMeg,
LLC, an E&P company. From 1970 until 1974, Mr. Haas worked at Haas Oil
Company where he learned the fundamentals of Kansas oil production and geology
from his father, Mr. John Haas, who was inducted into the Kansas Oil Producers
Hall of Fame for his vast contributions to the state’s oil industry and is
patriarch of four generations in the oil industry. Haas Oil Company was founded
in 1955 by Mark Haas’ father, who continues to be active in the oil industry,
consults with Mark on a regular basis.





Since its
formation in 1974, Haas Petroleum has grown from being a small producer to
becoming one of the top oil producers in the state of Kansas and is licensed to
operate in both Kansas and Oklahoma and has recently begun operations in
Texas.  Mr. Haas owns four full service drilling rigs and employs a
total of 40 full-time employees among his service and producing operations. Mr.
Haas serves as the operator of our Greenwood and Woodson counties Joint
Development program and has consulted with EnerJex on our other operations since
2007.




66


Thomas Kmak. Since October of
2007, Mr. Kmak has been the CEO of Fiduciary Benchmarks Insights, LLC which
provides benchmarking of fees and services for defined contribution plans
through advisors/consultants, recordkeepers and other plan service providers.
Prior to founding Fiduciary Benchmarks, Tom was CEO of JPMorgan Retirement Plan
Services. Tom started that business in 1990 and when he left 18 years later it
employed 1,100 people serving 200 large plan sponsors with over 1.5 million
participants and over $115 billion in assets. Tom graduated Phi Beta Kappa with
Bachelor of Arts degrees in economics and computational mathematics from DePauw
University in Greencastle, Indiana.





Loren Moll. Since November
1996, Mr. Moll has been a partner of Caldwell & Moll, L.C., a law firm in
Overland Park, Kansas.  Mr. Moll has 24 years of experience in the
practice of law. His practice has focused on the representation of small
businesses and entrepreneurs concerning a wide array of both everyday and
complex legal issues.   In addition to practicing law, since 2003
Mr. Moll has served as a director of Petrol Oil and Gas, Inc., a publicly traded
energy development company, where he has also served as President and
CEO.  Prior to starting his own law firm, Mr. Moll was an associate
attorney at Bryan Cave LLP and partner of Lewis, Rice and Fingersh,
L.C.  Mr. Moll graduated from the University of Kansas with a Bachelor
of Arts degree and a Juris Doctorate.





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.





Involvement in Certain Legal
Proceedings





None of
our executive officers or directors has been the subject of any Order, Judgment,
or Decree of any Court of competent jurisdiction, or any regulatory agency
permanently or temporarily enjoining, barring suspending or otherwise limiting
him from acting as an investment advisor, underwriter, broker or dealer in the
securities industry, or as an affiliated person, director or employee of an
investment company, bank, savings and loan association, or insurance company or
from engaging in or continuing any conduct or practice in connection with any
such activity or in connection with the purchase or sale of any
securities.





None of
our executive officers or directors has been convicted in any criminal
proceeding (excluding traffic violations) or is the subject of a criminal
proceeding, which is currently pending.


67




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.





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., Palmer and Kmak and Moll
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. Kmak is the chairman and Mr. Moll 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. Kmak 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
2010, when its members consisted of Messrs. Dammeyer and Wonish.





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.




68


Governance,
Compensation and Nominating Committee





The governance, compensation and
nominating committee is comprised of Messrs. Kmak, Moll and
Palmer.  Mr. Kmak 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 2010, when its members
consisted of Messrs. Wonish, Dammeyer and Palmer.





Restructuring
Committee





The restructuring committee is
comprised of Messrs. Moll and Kmak.  Mr. Moll serves as the chairman
of the restructuring committee.  The restructuring committeeshall work with
management and outside professionals to address the potential for restructuring
of EnerJex in any and all areas and respects, including management structure,
delegation of authority and any and all strategies and courses of action for
EnerJex and its future as a going concern.





Code
of Ethics





We have
adopted a Code 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 ended March 31,
2007 which 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.




69


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 78.378 et 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.





We are
subject to the provisions of Sections 78.411 et 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 interested stockholder. 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 associated with 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 be
used to inhibit a change in control.


70




Item
11. Executive Compensation.




The
following table sets forth summary compensation information for the fiscal years
ended March 31, 2010 and 2009 for our chief executive officer and chief
financial officer. We did not have any other executive officers as of the end of
fiscal 2010 whose total compensation exceeded $100,000. We refer to these
persons as our named executive officers elsewhere in this report.





Summary Compensation
Table





Name and Principal Position
                        
                        Fiscal
                          Year
                        
                        Salary
                          ($)
                        
                        
                        Bonus ($)
                        
                        
                        Option
                          Awards
                          ($)
                        
                        
                        All Other
                          Compen-
                          sation
                          ($)
                        
                        
                        Total
                          ($)C.
      Stephen Cochennet
                        
                        2010
                        
                        $
                        150,000
                        
                        
                        $
                        -
                        
                        
                        
                        -
                        
                        
                        $
                        33,333.34
                        (2)
                        
                        $
                        183,333.34President,
      Chief Executive Officer
                        
                        2009
                        
                        $
                        186,525
                        
                        
                        $
                        50,000
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        $
                        236,525Dierdre
      P. Jones(1)
                        
                        2010
                        
                        $
                        140,000
                        
                        
                        $
                        20,000
                        (3)
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        $
                        160,000Former
      Chief Financial Officer
                        
                        2009
                        
                        $
                        128,808
                        
                        
                        $
                        10,000
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        $
                        138,808








(1)
            Ms.
      Jones resigned as our chief financial officer in June of
    2010.


(2)
            Amount
      represents the estimated total fair market value of shares of common stock
      issued to Mr. Cochennet in lieu of salary under SFAS
      123(R).


(3)
            Amount
      represents the estimated total fair market value of shares of common stock
      issued to Ms. Jones as a bonus under SFAS
  123(R).





Outstanding Equity Awards at2009Fiscal Year-End





The
following table lists the outstanding equity incentive awards held by our named
executive officers as of March 31, 2010.





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
                                  
                                  2010
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -Dierdre
      P. Jones
                                  
                                  2010
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -




71


Option
Exercises for fiscal 2010





There
were no options exercised by our named executive officers in fiscal 2010.
However, on August
3, 2009, we issued a total of 109,700 shares of our common stock in exchange for
438,500 then outstanding options to purchase shares of our common stock.See “Securities Authorized for Issuance under Equity Compensation Plans”
for a description of our outstanding equity compensation plans.





Employment
Agreements




C. Stephen Cochennet – Chief
Executive Officer




On August
1, 2008, we entered into an employment agreement with C. Stephen Cochennet, our
president and chief executive officer. Mr. Cochennet’s employment agreement was
approved by the governance, compensation and nominating committee of our board
of directors.




In
general, Mr. Cochennet’s employment agreement contains provisions concerning
terms of employment, voluntary and involuntary termination, indemnification,
severance payments, and other termination benefits, in addition to a non-compete
clause and certain other perquisites, such as long-term disability insurance,
director and officer insurance, and an automobile allowance. The original term
of Mr. Cochennet’s employment agreement runs from August 1, 2008 until July 31,
2011. The term of the employment agreement is automatically extended for
additional one year terms unless otherwise terminated in accordance with its
terms.




Mr.
Cochennet’s employment agreement provides for an initial annual base salary of
$200,000, which may be adjusted by the governance, compensation and nominating
committee or our board of directors.




In
addition, Mr. Cochennet is eligible to receive an annual bonus of up to 100% of
his applicable base salary in cash or shares of restricted stock (if approved by
stockholders) subject to our obtaining certain business objectives established
by our board of directors. In addition Mr. Cochennet is eligible to receive
long-term incentives of up to 135,000 options to purchase shares of our common
stock based upon our achievement of specified performance targets. Additional
information regarding these options is set forth in the following
table.




Fiscal
                  Year
                
                Potential
                  Grant Date
                
                Maximum #
                  of Options
                
                Strike Price of Options
                
                Option
                  Expiration Date*2009
                
                7/1/2009
                
                30,000
                
                Fair
      market value on grant date
                
                6/30/20102010
                
                7/1/2010
                
                45,000
                
                Fair
      market value on grant date
                
                6/30/20102011
                
                7/1/2011
                
                60,000
                
                Fair
      market value on grant date
                
                6/30/2010





*
            The
      options shall be immediately vested and exercisable from the grant date
      through the option expiration date.




The
number of stock options granted each fiscal year shall be based upon a schedule
set forth in Mr. Cochennet’s employment agreement and will be prorated if
actual performance does not equal or exceed 100% of the targeted performance
conditions. Mr. Cochennet must be employed by us on the grant date to receive
the stock options.




72


The
maximum number of options available to be earned by Mr. Cochennet each year is
subject to a “catch-up”
provision, such that if an element in any year is missed, it may be “caught-up”
in a subsequent year, so long as the cumulative goal is met. For example, if the
2009 share price element of $11.00 is not met by March 31, 2009, Mr. Cochennet
would still be able to earn the available options for this element if our share
price is at least $16.85 on March 31, 2010, or $22.55 on March 31, 2011. Any
caught-up options would be granted at the then current stock price. The
cumulative goal for Mr. Cochennet’s long-term incentive compensation is
comprised of three factors; a 35% year over year net reserve growth (40% of the
goal), a 35% year over year net production increase (30% of the goal), and the
previously stated share price increases (30% of the goal).




As
consideration for his efforts during fiscal 2008 we also agreed to pay Mr.
Cochennet a $50,000 cash bonus and grant him 75,000 options to purchase shares
of our common stock at $6.25 per share; 30,000 vested immediately upon grant and
the remaining 45,000 were to vest over a three year period. These options were
rescinded in November 2008 at the request of the board’s compensation committee
and with the approval of Mr. Cochennet in an effort to reduce compensation
expense which, through non-cash, would have had a substantial negative impact on
our financial statements and results of operations for the quarter ended
September 30, 2008.  Shares subject to these options were returned to
the plan and are available for future issuance. On August 3, 2009, we issued Mr.
Cochennet 18,800 shares of twelve month restricted stock in consideration for
the prior rescission of the options discussed above.




In the
event of a termination of employment with us by Mr. Cochennet for “good reason”, which includes
by reason of a “change of
control”, or by us without “cause” (each as defined in
the employment agreement), Mr. Cochennet would receive: (i) a lump sum
payment equal to all earned but unpaid base salary through the date of
termination of employment; (ii) a lump sum payment equal to the annual incentive
amount (assuming achievement at 100% of target) that Mr. Cochennet would have
earned if he had remained employed through June 30th following the last day of
the current fiscal year; (iii) a lump sum payment equal to an amount equal to
the lesser of (a) 12-months base salary or (b) the base salary Mr.
Cochennet would have received had he remained in employment through the end of
the then-existing term of the agreement; and (iv) immediate vesting of all
equity awards (including but not limited to stock options and restricted
shares).




In the
event of a termination of Mr. Cochennet’s employment with us by reason of
incapacity, disability or death, Mr. Cochennet, or his estate, would receive:
(i) a lump sum payment equal to all earned but unpaid base salary through the
date of termination of employment or death; (ii) a lump sum payment equal to the
annual incentive amount (assuming achievement at 100% of target) that Mr.
Cochennet would have earned if he had remained employed through June 30th
following the last day of the current fiscal year; and (iii) a lump sum payment
equal to an amount equal to six-months base salary.




In the
event of a termination of Mr. Cochennet’s employment by us for “cause” (as defined in the
employment agreement), Mr. Cochennet would receive all earned but unpaid base
salary through the date of termination of employment. However, if a dispute
arises between us and Mr. Cochennet that is not resolved within 60 days and
neither party initiates arbitration proceedings pursuant to the terms of the
employment agreement, we will have the option to pay Mr. Cochennet a lump sum
payment equal to six-months base salary in lieu of any and all other amounts or
payments to which Mr. Cochennet may be entitled relating to his
employment.




73


Effective
April 1, 2010, C. Stephen Cochennet, the Registrant’s chief executive officer
and president, agreed to waive all salary payable to him (approximately $50,000)
for the months of April, May and June of 2010. All other terms and provisions of
Mr. Cochennet’s employment agreement dated August 1, 2008 remain
unchanged.




Dierdre P. Jones – Chief
Financial Officer




On July
23, 2008, Dierdre P. Jones, our former director of finance and accounting, was
appointed our chief financial officer. On August 1, 2008, we entered into an
employment agreement with Ms. Jones. The employment agreement was approved by
the governance, compensation and nominating committee of our board of directors.
Ms. Jones resigned as our chief financial officer on June 10, 2010 to pursue
other business opportunities.




74




Potential Payments Upon Termination
or Change in Control




We
entered into employment agreements with our chief executive officer and our
chief financial officer, which could result in payments to such officers
because of their resignation, incapacity or disability, or other termination of
employment with us or our subsidiaries, or a change in control, or a change in
their responsibilities following a change in control.





In Aril
of 2010, we experienced a change in control, as defined in our executive
employment agreements, when three of the members of our board of directors
(Messrs. Dammeyer, Wonish and Dr. Rector) resigned and were replaced by three
new members (Messrs. Kmak, Haas and Moll).  As of the date of this
report, we have not received any claims or paid any payments as a result of this
change in control.





Director Compensation




The
following table sets forth summary compensation information for the fiscal year
ended March 31, 2010 for 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(1)
                
                $
                27,375
                
                
                $
                15,000
                (2)
                
                $
                -0-
                
                
                $
                12,375
                (3)
                
                $
                70,000Darrel
      G. Palmer
                
                $
                45,000
                
                
                $
                15,000
                (2)
                
                $
                -0-
                
                
                $
                70,000
                (3)
                
                $
                46,500Robert
      G. Wonish(1)
                
                $
                20,625
                
                
                $
                10,000
                (2)
                
                $
                -0-
                
                
                $
                17,250
                (3)
                
                $
                49,000Dr.
      James W. Rector(1)
                
                $
                1,500
                
                
                $
                10,000
                (2)
                
                $
                -0-
                
                
                $
                11,500
                (3)
                
                $
                22,500




(1)
              Effective
      April 1, 2010, Messrs. Wonish, Dammeyer and Dr. Rector resigned as members
      of our board of directors.
 
 (2)
              Amount
      represents the estimated fair market value of shares of common stock
      issued for board retainer fee for fiscal year ended March 31, 2010 under
      SFAS 123(R).
 
 (3)
              Represents
      the amount of accrued but unpaid director and committee member fees for
      fiscal year ended March 31,
2010.




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 9, 2010 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 5,133,873 shares of common stock
outstanding.




75


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 9, 2010 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)
                                    
                                    
                                    542,061
                                    
                                    
                                    
                                    10.6
                                    %Mark
      Haas, Chief Operating Officer and Director
                                    
                                    
                                    189,000
                                    (4)
                                    
                                    
                                    3.7
                                    %Thomas Kmak,
      Director(3)
                                    
                                    
                                    228,677
                                    (5)
                                    
                                    
                                    4.5
                                    %Darrel G. Palmer,
      Director(3)
                                    
                                    
                                    32,000
                                    
                                    
                                    
                                    *Loren Moll,
      Director(3)
                                    
                                    
                                    -0-
                                    
                                    
                                    
                                    *Directors
      and Officers as a Group
                                    
                                    
                                    991,738
                                    
                                    
                                    
                                    19.3
                                    %West Coast
      Opportunity Fund LLC(6)
                                    
                                    
                                    954,098
                                    
                                    
                                    
                                    18.6
                                    %West
      Coast Asset Management, Inc.
                                      Paul
      Orfalea, Lance Helfert & R. Atticus Lowe
                                      2151
      Alessandro Drive, #100
                                      Ventura,
      CA 93001Enable
      Growth Partners L.P.(7)
                                    
                                    
                                    286,270
                                    
                                    
                                    
                                    5.6
                                    %Enable
      Capital Management, LLC
                                      Mitchell
      S. Levine
                                      One
      Ferry Building, Suite 225
                                      San
      Francisco, CA 94111





*
            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
      129,000 shares held by MorMeg, LLC, which is controlled by Mr.
      Haas.


(5)
            98,270
      shares held in Mr. Kmak’s IRA.


(6)
            Based
      on a Schedule 13D filed with the SEC on February 13, 2010, 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.


76


(7)
            Based
      on a Schedule 13G/A filed with the SEC on February 11, 2010, 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. (265,667 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, 2010 regarding
outstanding options granted under our stock option plans and options reserved
for future grant under the plans.


Plan Category
                    
                    Number
                      ofsharestobeissued
                      uponexerciseof
                      outstandingoptions,
                      warrantsandrights
                      (a)
                    
                    
                    Weighted-average
                      exercisepriceof
                      outstandingoptions,
                      warrantsandrights
                      (b)
                    
                    
                    Numberofshares
                      remainingavailablefor
                      futureissuanceunder
                      equitycompensation
                      plans(excludingshares
                      reflectedincolumn(a)
                      (c)Equity
      compensation plans approved by stockholders
                    
                    
                    0
                    
                    
                    
                    —
                    
                    
                    
                    —Equity compensation plans not approved by
      stockholders
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —Total
                    
                    
                    0
                    
                    
                    
                    —
                    
                    
                    
                    —


As of
March 31, 2010, we have granted 254,270 shares of restricted stock under
our  Stock Incentive Plan.




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 one percent of the
      average of our total assets at year end for the last two completed fiscal
      years ($72,446); 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.




During
the year ended March 31, 2010. Mark Haas, our chief operating officer and a
director, was paid $10,000 in cash for consulting fees. In addition, Mr. Haas is
also the managing member of MorMeg, LLC, the operator of our Black Oaks Project.
On January 4, 2010, we issued to MorMeg, LLC 45,000 shares of restricted common
stock for payment of consulting fees accrued from July 2009 through March 31,
2010 and 65,000 shares of restricted common stock as payment for granting an
extension on the date required to provide additional development funding on the
Black Oaks project.
 
 Director
Independence





Our board
of directors has affirmatively determined that Messrs. Kmak and Moll 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.




77


Item
14. Principal Accountant Fees and Services.
 
 Weaver & Martin, LLC served as our
principal independent public accountants for fiscal  2010 and 2009
years. Aggregate fees billed to us for the fiscal years ended March 31, 2010 and
2009 by Weaver & Martin, LLC were as follows:
 
 FortheFiscalYears
                                Ended
                                March31,2010
                              
                              2009Audit
      Fees(1)
                              
                              $
                              63,000
                              
                              
                              $
                              56,000Audit-Related
      Fees(2)
                              
                              
                              -0-
                              
                              
                              
                              -0-Tax
      Fees(3)
                              
                              
                              10,000
                              
                              
                              
                              10,000All
      Other Fees(4)
                              
                              
                              
                              
                              
                              
                              19,718Total
      fees of our principal accountant
                              
                              $
                              73,000
                              
                              
                              $
                              85,718
 
 (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 Exchange Commission. This category also includes
      fees for auditsprovided 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.
 (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 diligence related 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 requirements
      and 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 2010, all fees paid to Weaver & Martin were unanimously
pre-approved in accordance with this policy.
  78
 
 Less than
50 percent of hours expended on the principal accountants engagement to audit
the registrants financial statements for the most recent fiscal year were
attributed to work performed by persons other than the principal accountants
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 Boards determination that he is fully qualified to oversee EnerJexs
internal audit function, assess and select independent auditors, and oversee
EnerJexs 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 EnerJexs 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.
  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, 2010 (“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.
  79
  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:
  Thomas
Kmak (Chairman)
 Loren
Moll
 
 PART
IV
  Item
15. Exhibits, Financial Statement Schedules.
 
 The
following information required under this item is filed as part of this
report:
 
 10.1.
Financial Statements
 
 PageManagement
      Responsibility for Financial Information
                  
                  63Management’s
      Report on Internal Control Over Financial Reporting
                  
                  64Index
      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
 
 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)
  80
 
 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. dated July 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. dated July 3, 2008 (incorporated by
      reference to Exhibit 10.34 to the Form 10-K filed on July 10,
      2008)10.3
                      
                      Amended
      and Restated Mortgage, Security Agreement, Financing Statement and
      Assignment of Production and Revenues with Texas Capital Bank, N.A. dated
      July 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. dated July 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 dated July 3, 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)10.12(b)
      †
                      
                      Dierdre
      P. Jones Rescission of Option Grant Agreement dated November 17, 2008
      (incorporated by reference to Exhibit 10.38(b) to the Form 10-Q filed on
      February 23, 2009)10.12
                      
                      Daran
      G. Dammeyer Rescission 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. Palmer Rescission 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. Rector Rescission 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. Wonish Rescission 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.  (incorporated by reference to Exhibit 10.15 to the Form
      10-K filed July 14,
2009)
  81
 
 10.16
              
              Waiver
      from Texas Capital Bank, N.A. dated  July 14, 2009 (incorporated
      by reference to Exhibit 10.16 to Form 10-K filed July 14,
      2009)10.17
              
              First
      Amendment to Credit Agreement dated August 18, 2009 (incorporated by
      reference to the Exhibit 10.12 to the Form 10-Q filed August 18,
      2009)10.18
              
              Debenture
      Holder Amendment Letter dated November 16, 2009 (incorporated by reference
      to the Exhibit 10.13 to the Form 10-Q filed November 20,
    2009)10.19
              
              Standby
      Equity Distribution Agreement with Paladin Capital Management, S.A. dated
      December 3, 2009 (incorporated by reference to Exhibit 10.52 to the Form
      S-1 filed on December 9, 2009)10.20
              
              Amendment
      5 to Joint Exploration Agreement effective as of December 31, 2009 between
      MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to
      Exhibit 10.15 to the Form 10-Q filed on February 16,
  2010)10.21
              
              Second
      Amendment to Credit Agreement dated January 13, 2010 (incorporated by
      reference to Exhibit 10.16 to the Form 10-Q filed on February 16,
      2010)10.22
              
              Debenture
      Holder Amendment Letter dated January 27, 2010 (incorporated by reference
      to Exhibit 10.17 to the Form 10-Q filed on February 16,
    2010)10.23
              
              Waiver
      from Texas Capital Bank, N.A. dated  February 10, 2009
      (incorporated by reference to Exhibit 10.18 to the Form 10-Q filed on
      February 16, 2010)10.24
              
              Amendment
      6 to Joint Exploration Agreement effective as of March 31, 2010 between
      MorMeg LLC and EnerJex Resources, Inc.10.25
              
              Debenture
      Holder Amendment Letter dated April 1, 201021.1
              
              List
      of Subsidiaries23.1
              
              Miller
      & Lents, Ltd. Consent Of Independent Petroleum Engineers and
      Geologists Letter dated July 13 and effective March 31,
    201023.2
              
              Consent
      of Weaver & Martin, LLC31.1
              
              Certification
      of Chief Executive and Principal Financial Officer pursuant to Section 302
      of the Sarbanes-Oxley Act of 200232.1
              
              Certification
      of Chief Executive and Principal Financial Officer pursuant to Section 906
      of the Sarbanes-Oxley Act of 2002
 
 †
Indicates management contract or compensatory plan or
arrangement.
  82
  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, 2010
  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, 2010C.
      Stephen Cochennet
              
              (Principal
      Executive Officer),
                Secretary
      Director/s/ Mark Haas
              
              Chief
      Operating Officer, Director
              
              July
      14, 2010Mark
      Haas/s/ Tom Kmak
              
              Director,
      Chairman
              
              July
      14, 2010Tom
      Kmak/s/ Loren Moll
              
              Director
              
              July
      14, 2010Loren
      Moll/s/ Darrel G. Palmer
              
              Director
              
              July
      14, 2010Darrel
      G. Palmer
  83
  Index
to Financial Statements
  PageIndex
      to Financial Statements
                F-1Report
      of Independent Registered Public Accounting Firm
                F-2Consolidated
      Balance Sheets at March 31, 2010 and 2009
                F-3Consolidated
      Statements of Operations for the Fiscal Years Ended March 31, 2010 and
      2009
                F-4Consolidated
      Statement of Stockholders’ Equity(Deficit) for the Fiscal Years Ended
      March 31, 2010 and 2009
                F-5Consolidated
      Statement of Cash Flows for the Fiscal Years Ended March 31, 2010 and
      2009
                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, 2010 and 2009 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, 2010. 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, 2010 and 2009 and the consolidated results of its
operations and cash flows for each of the years in the two–year period ended
March 31, 2010 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
 
 Weaver
& Martin, LLC
 Kansas
City, Missouri
 July 14,
2010
  F-2
 
 EnerJex
Resources, Inc. and Subsidiaries
 Consolidated
Balance Sheets
 
 March
      31,2010
                    
                    
                    2009AssetsCurrent
      assets:Cash
                    
                    $
                    169,163
                    
                    
                    $
                    127,585Accounts
      receivable
                    
                    
                    330,102
                    
                    
                    
                    462,044Prepaid
      debt issue costs
                    
                    
                    -
                    
                    
                    
                    45,929Deposits
      and prepaid expenses
                    
                    
                    166,418
                    
                    
                    
                    263,383Total
      current assets
                    
                    
                    665,683
                    
                    
                    
                    898,941Fixed
      assets
                    
                    
                    371,885
                    
                    
                    
                    365,019Less:
      Accumulated depreciation
                    
                    
                    120,545
                    
                    
                    
                    63,988Total
      fixed assets
                    
                    
                    251,340
                    
                    
                    
                    301,031Other
      assets:Oil
      and gas properties using full-cost accounting:Properties
      not subject to amortization
                    
                    
                    -
                    
                    
                    
                    31,183Properties
      subject to amortization
                    
                    
                    5,891,994
                    
                    
                    
                    6,449,023Total
      other assets
                    
                    
                    5,891,994
                    
                    
                    
                    6,480,206Total
      assets
                    
                    $
                    6,809,017
                    
                    
                    $
                    7,680,178Liabilities
      and Stockholders’ Equity (Deficit)Current
      liabilities:Accounts
      payable
                    
                    $
                    877,511
                    
                    
                    $
                    1,016,168Accrued
      liabilities
                    
                    
                    417,142
                    
                    
                    
                    87,811Derivative
      liability
                    
                    
                    1,184,178
                    
                    
                    
                    -Convertible
      note payable
                    
                    
                    25,000
                    
                    
                    
                    -Long-term
      debt, current
                    
                    
                    9,182,679
                    
                    
                    
                    1,723,036Total
      current liabilities
                    
                    
                    11,686,510
                    
                    
                    
                    2,827,015Asset
      retirement obligation
                    
                    
                    883,589
                    
                    
                    
                    803,624Derivative
      liability
                    
                    
                    2,364,068Convertible
      note payable
                    
                    
                    -
                    
                    
                    
                    25,000Long-term
      debt, net of discount at March 31, 2009 of $596,108
                    
                    
                    43,440
                    
                    
                    
                    7,818,163Total
      liabilities
                    
                    
                    14,977,607
                    
                    
                    
                    11,473,802Contingencies
      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 –5,053,189 at March 31, 2010 and 4,443,512 at March 31, 2009
      and 4,836 of owned but not issued stock at March 31, 2010
                    
                    
                    5,058
                    
                    
                    
                    4,444Paid
      in capital
                    
                    
                    9,505,417
                    
                    
                    
                    8,932,906Retained
      (deficit)
                    
                    
                    (17,679,065
                    )
                    
                    
                    (12,730,974
                    )Total
      stockholders’ equity (deficit)
                    
                    
                    (8,168,590
                    )
                    
                    
                    (3,793,624
                    )Total
      liabilities and stockholders’ equity (deficit)
                    
                    $
                    6,809,017
                    
                    
                    $
                    7,680,178
 
 See
Notes to Consolidated Financial Statements.
  F-3
 
 EnerJex
Resources, Inc. and Subsidiaries
 Consolidated
Statements of Operations
 
 For the Fiscal Years EndedMarch 31,2010
                        
                        
                        2009Oil
      and natural gas revenues
                        
                        $
                        4,856,027
                        
                        
                        $
                        6,436,805Expenses:Direct
      operating costs
                        
                        
                        1,833,108
                        
                        
                        
                        2,637,333Depreciation,
      depletion and amortization
                        
                        
                        836,536
                        
                        
                        
                        911,293Impairment
      of oil and gas properties
                        
                        
                        -
                        
                        
                        
                        4,777,723Professional
      fees
                        
                        
                        561,625
                        
                        
                        
                        1,320,332Salaries
                        
                        
                        835,576
                        
                        
                        
                        849,340Administrative
      expense
                        
                        
                        1,016,484
                        
                        
                        
                        1,392,645Total
      expenses
                        
                        
                        5,083,329
                        
                        
                        
                        11,888,666Loss
      from operations
                        
                        
                        (227,302
                        )
                        
                        
                        (5,451,861
                        )Other
      income (expense):Interest
      expense
                        
                        
                        (751,470
                        )
                        
                        
                        (882,426
                        )Loan
      interest accretion
                        
                        
                        (596,108
                        )
                        
                        
                        (2,814,095
                        )Gain
      on liquidation of hedging instrument
                        
                        
                        -
                        
                        
                        
                        3,879,050Gain
      on repurchase of debentures
                        
                        
                        436,500
                        
                        
                        
                        -Loss
      on derivatives
                        
                        
                        (3,911,063
                        )
                        
                        
                        -Other
      Gain/(Loss)
                        
                        
                        101,352
                        
                        
                        
                        (37,736
                        )Total
      other income (expense)
                        
                        
                        (4,720,789
                        )
                        
                        
                        144,793Net
      income - (loss)
                        
                        $
                        (4,948,091
                        )
                        
                        $
                        (5,307,068
                        )Weighted
      average shares outstanding  - basic
                        
                        
                        4,743,774
                        
                        
                        
                        4,443,249Net
      income  (loss) per share - basic
                        
                        $
                        (1.04
                        )
                        
                        $
                        (1.19
                        )
 
 See
Notes to Consolidated Financial Statements.
  F-4
 
 EnerJex
Resources, Inc. and Subsidiaries
 Consolidated
Statements of Stockholders’ Equity (Deficit)
 
 Common StockShares
                  
                  
                  Par Value
                  
                  
                  Paid in
                    Capital
                  
                  
                  Retained Deficit
                  
                  
                  Total Stockholders’ Equity
                    (Deficit)Balance,  April
      1, 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
                  )Stock
      issued for services and interest
                  
                  
                  365,416
                  
                  
                  
                  370
                  
                  
                  
                  328,422
                  
                  
                  
                  -
                  
                  
                  
                  328,792Stock
      issued for employees and directors
                  
                  
                  314,261
                  
                  
                  
                  314
                  
                  
                  
                  274,019
                  
                  
                  
                  -
                  
                  
                  
                  274,333Stock
      redeemed and cancelled
                  
                  
                  (70,000
                  )
                  
                  
                  (70
                  )
                  
                  
                  (29,930
                  )
                  
                  
                  -
                  
                  
                  
                  (30,000
                  )Net
      loss for the year
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (4,948,091
                  )
                  
                  
                  (4,948,091
                  )Balance,
      March 31, 2010
                  
                  
                  5,053,189
                  
                  
                  $
                  5,058
                  
                  
                  $
                  9,505,417
                  
                  
                  $
                  (17,679,065
                  )
                  
                  $
                  (8,168,590
                  )
 
 See
Notes to Consolidated Financial Statements.
  F-5
 
 EnerJex
Resources, Inc.
 Consolidated
Statements of Cash Flows
 For the Fiscal Years EndedMarch 31,2010
                        
                        
                        2009Cash
      flows from operating activitiesNet
      (loss)
                        
                        $
                        (4,948,091
                        )
                        
                        $
                        (5,307,068
                        )Depreciation
      and depletion
                        
                        
                        869,251
                        
                        
                        
                        950,357Debt
      issue cost amortization
                        
                        
                        45,929
                        
                        
                        
                        157,191Stock
      and options issued for services and interest
                        
                        
                        328,792
                        
                        
                        
                        79,452Accretion
      of interest on long-term debt discount
                        
                        
                        596,108
                        
                        
                        
                        2,814,095Accretion
      of asset retirement obligation
                        
                        
                        75,687
                        
                        
                        
                        60,864Loss
      on derivatives
                        
                        
                        3,548,245
                        
                        
                        
                        -Gain
      on purchase of debentures
                        
                        
                        (436,500
                        )
                        
                        
                        -Stock
      issued to employees and directors
                        
                        
                        274,333
                        
                        
                        
                        -Loss
      on sale of fixed assets
                        
                        
                        25,999
                        
                        
                        
                        -Principal
      issued on debentures for interest
                        
                        
                        368,045
                        
                        
                        
                        -Impairment
      of oil & gas properties
                        
                        
                        -
                        
                        
                        
                        4,777,723Adjustments
      to reconcile net (loss) to cash provided by operating
      activities:Accounts
      receivable
                        
                        
                        131,942
                        
                        
                        
                        (234,989
                        )Deposits
      and prepaid expenses
                        
                        
                        96,965
                        
                        
                        
                        24,224Accounts
      payable
                        
                        
                        (138,659
                        )
                        
                        
                        599,334Accrued
      liabilities
                        
                        
                        329,330
                        
                        
                        
                        17,350Deferred
      payment from Euramerica for development
                        
                        
                        -
                        
                        
                        
                        (251,951
                        )Cash
      provided by operating activities
                        
                        
                        1,167,376
                        
                        
                        
                        3,686,582Cash
      flows from investing activitiesPurchase
      of fixed assets
                        
                        
                        (72,603
                        )
                        
                        
                        (204,200
                        )Additions
      to oil & gas properties
                        
                        
                        (228,962
                        )
                        
                        
                        (3,123,003
                        )Sale
      of oil & gas properties
                        
                        
                        32,000
                        
                        
                        
                        300,000Proceeds
      from sale of vehicle
                        
                        
                        16,500Cash
      used in investing activities
                        
                        
                        (253,065
                        )
                        
                        
                        (3,027,203
                        )Cash
      flows from financing activitiesProceeds
      from (repayment of) note payable, net
                        
                        
                        (193,500
                        )
                        
                        
                        (965,000
                        )Borrowings
      on long-term debt
                        
                        
                        38,480
                        
                        
                        
                        11,274,843Payments
      on long-term debt
                        
                        
                        (717,713
                        )
                        
                        
                        (11,792,641
                        )Cash
      used in financing activities
                        
                        
                        (872,733
                        )
                        
                        
                        (1,482,798
                        )Increase
      (decrease) in cash and  cash equivalents
                        
                        
                        41,578
                        
                        
                        
                        (823,419
                        )Cash
      and cash equivalents, beginning
                        
                        
                        127,585
                        
                        
                        
                        951,004Cash
      and cash equivalents, end
                        
                        $
                        169,163
                        
                        
                        $
                        127,585Supplemental
      disclosures:Interest
      paid
                        
                        $
                        325,625
                        
                        
                        $
                        768,053Income
      taxes paid
                        
                        $
                        -
                        
                        
                        $
                        -Non-cash
      transactions:Share-based
      payments issued for services
                        
                        $
                        603,125
                        
                        
                        $
                        -Principal
      issued on debentures for interest
                        
                        $
                        368,045
                        
                        
                        $
                        -
 See
Notes to Consolidated Financial Statements.
  F-6
 
 EnerJex
Resources, Inc.
 Notes
to Consolidated Financial Statements
 
 Note
1 – Summary of Accounting Policies
 
 Basis
of Presentation
 
 Our
consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in the United States. Our operations
are considered to fall within a single industry segment, which is the
acquisition, development, exploitation and production of natural gas and crude
oil properties in the United States.  All significant intercompany
balances and transactions have been eliminated upon
consolidation.  Certain reclassifications have been made to the prior
year financial statements to conform to the current year
presentation.
 
 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.
 
 Use of
Estimatesin the
Preparation of Financial Statements
 
 The
preparation of consolidated financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting period.  Significant estimates included in the
consolidated financial statements are: (1) oil revenues and reserves; (2)
depreciation, depletion and amortization; (3) valuation allowances associated
with income taxes (4) accrued assets and liabilities; (5) stock-based
compensation; (6) asset retirement obligations and (7) valuation of derivative
instruments.  Although management believes these estimates are
reasonable, changes in facts
 and
circumstances or discovery of new information may result in revised
estimates.  Actual results 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.
  F-7
 
 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.
 
 Income
Taxes
 
 Income
taxes are accounted for under the asset and liability method. Deferred tax
assets and liabilities are recognized when items of income and expense are
recognized in the financial statements in different periods than when recognized
in the applicable tax return. Deferred tax assets arise when expenses are
recognized in the financial statements before the tax returns or when income
items are recognized in the tax return prior to the financial statements.
Deferred tax assets also arise when operating losses or tax credits are
available to offset tax payments due in future years. Deferred tax liabilities
arise when income items are recognized in the financial statements before the tax returns or
when expenses are recognized in the tax return prior to the financial
statements. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates is recognized in
income in the period that includes the date when the change in the tax rate was
enacted.
 
 We
routinely assess the realizability of our deferred tax assets.  If we
conclude that it is more likely than not that some portion or all of the
deferred tax assets will not be realized under accounting standards, the tax
asset is reduced by a valuation allowance.  In addition we routinely assess
uncertain tax positions, and accrue for tax positions that are not
more-likely-than-not to be sustained upon examination by taxing
authorities.
 
 Fair
Value Measurements
 
 Accounting
guidance establishes a single authoritative definition of fair value based upon
the assumptions market participants would use when pricing an asset or liability
and creates a fair value hierarchy that prioritizes the information used to
develop those assumptions.  Additional disclosures are required,
including disclosures of fair value measurements by level within the fair value
hierarchy.  We incorporate a credit risk assumption into the
measurement of certain assets and liabilities
 
 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.
  F-8
 
 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.
 
 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.
 
 Oil
and Gas Properties
 
 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.
  F-9
 
 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.
 
 The
estimates of proved natural gas, crude oil and natural gas liquids reserves
utilized in the preparation of the financial statements are estimated in
accordance with guidelines established by the Securities and Exchange Commission
(“SEC”) and the
Financial Accounting Standards Board (“FASB”), which require that
reserve estimates be prepared under existing economic and operating conditions
using a 12-month average price with no provision for price and cost escalations
in future years except by contractual arrangements.
 
 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, 2010 and 2009 we sold all of our oil production to one
purchaser’.
  F-10
 
 Recent
Issued Accounting Standards
 
 Accounting Standards Codification— On July 1, 2009, the Financial Accounting Standards Board
(“FASB”) instituted a
new referencing system, which codifies, but does not amend, previously existing
nongovernmental GAAP.  The FASBAccounting Standards CodificationTM(“ASC”) is now
the single authoritative source for GAAP.  Although the implementation
of ASC had no impact on our financial statements, certain references to
authoritative GAAP literature within our footnotes have been changed to cite the
appropriate content within the ASC.
 
 FASB
Accounting Standards Update (“ASU”) 2010-03 was issued on
January 6, 2010, and aligns the current oil and natural gas reserve
estimation and disclosure requirements of ASC 932 with those in the SEC Final Rule Modernization of Oil
and Gas
Reporting issued December 31, 2008. The rules only apply
prospectively as a change in estimate. The most significant amendments to the
reserve and disclosure requirements include the following:
  ·
              Commodity
      Prices—Economic producibility of reserves and discounted cash flows will
      be based on an unweighted arithmetic average of the first day of the month
      commodity price during the 12-month period ending on the balance sheet
      date unless contractual arrangements designate the price to be
      used.
 
 ·
              Disclosure
      of Unproved Reserves—Probable and possible reserves may be disclosed
      separately on a voluntary basis.
 
 ·
              Proved
      Undeveloped Reserve Guidelines—Reserves may be classified as proved
      undeveloped if there is a high degree of confidence that the quantities
      will be recovered.
 
 ·
              Reserve
      Estimation Using New Technologies—Reserves may be estimated through the
      use of reliable technology in addition to flow tests and production
      history.
 
 ·
              Reserve
      Personnel and Estimation Process—Additional disclosure is required
      regarding the qualifications of the chief technical person who oversees
      our reserves estimation process. We will also be required to provide a
      general discussion of our internal controls used to assure the objectivity
      of the reserves estimate.
 
 ·
              Disclosure
      by Geographic Area—Reserves in foreign countries or continents must be
      presented separately if they represent more than 15% of our total oil and
      natural gas proved reserves.
 
 ·
              Non-Traditional
      Resources—The definition of oil and natural gas producing activities will
      expand and focus on the marketable product rather than the method of
      extraction.
  ASU
2010-03 is effective for entities with annual reporting periods ending on or
after December 31, 2009. We adopted both the FASB and the SEC
rules.
  F-11
 
 Adoption of ASU 2009-05 — In
August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting
Standards Update (“ASU”) No. 2009-05, Fair Value Measurement and
Disclosures: Measuring Liabilities at Fair Value.  ASU 2009-05
provides clarification on measuring liabilities at fair value when a quoted
price in an active market is not available.  We adopted ASU No.
2009-05 (FASB ASC 820-10).  The adoption of this statement did not
have an impact on our financial position or results of operations.
 
 Interim Disclosures about Fair Value
of Financial Instrument — We adopted FSP SFAS 107-1 and APB 28-1 “Interim
Disclosures about Fair Value of Financial Instruments”, which is now
incorporated into ASC Topic No. 825 (“ASC 825”).  This
statement increases the frequency of fair value disclosures to a quarterly
instead of annual basis.  The guidance relates to fair value
disclosures for any financial instruments that are not currently reflected on
the balance sheet at fair value.  The adoption of this statement did
not have a material impact on our financial position or results of
operations.
 
 Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly — We adopted
the FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity
for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly” which is now incorporated into ASC Topic No.
820 (“ASC
820”).  ASC 820 provides guidelines for a broad
interpretation of when to apply market-based fair value measures.  It
reaffirms management’s need to use judgment to determine when a market that was
once active has become inactive and in determining fair values in markets that
are no longer active.
 
 Disclosure about Derivative
Instruments and Hedging Activities — We adopted FASB Statement No. 161,
“Disclosure about Derivative Instruments and Hedging Activities, an amendment of
FASB Statement No. 133” which is now incorporated into ASC Topic No. 815 (“ASC 815”).  ASC 815
amends and expands the disclosure requirements for derivative instruments and
hedging activities with the intent to provide users of financial statements with
an enhanced understanding of: (i) how and why an entity uses derivative
instruments; (ii) how derivative instruments and related hedged items are
accounted for; and (iii) how derivative instruments and related hedged
items affect an entity’s financial position, results of operations and cash
flows. The adoption of this statement did not have an impact on our
financial position or results of operations.
 
 Business Combinations —We
adopted SFAS No. 141 (Revised 2007) “Business Combinations” which is now
incorporated into ASC Topic No. 805 (“ASC 805”).  The
revision broadens the definition of a business combination to include all
transactions or other events in which control of one or more businesses is
obtained.  Further, this statement establishes principles and
requirements for how an acquirer recognizes assets acquired, liabilities assumed
and any non-controlling interests acquired.  The adoption of this
statement has not had an impact on our financial position or results of
operations, because we have not yet had any business combinations in the year
ended March 31, 2010.
 
 Effective Date of FASB Statement No.
157 - We also adopted FSP SFAS 157-2, “Effective Date of FASB Statement
No. 157”, which is also now incorporated into ASC Topic No. 820. The
effective date was deferred for all nonfinancial assets and nonfinancial
liabilities, except for items that are recognized or disclosed at fair value in
the financial statements on a recurring basis (at least annually) to fiscal
years beginning after November 15, 2008, and interim periods within
those fiscal years.   The adoption of this statement did not have
a material impact on our financial position or results of
operations.
  F-12
 
 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
transaction in fiscal 2010:
 
 We issued
355,000 shares of our stock for services during the year ended March 31,
2010.  The value of the stock was $1 per share which approximated the
market value at the time the obligations were settled.
 
 We issued
10,416 shares of stock and have unissued but owed 4,836 shares of stock for
payment in kind interest on our debentures.  The
value assigned to the transaction varied from $.46 to $1.28 and was based on the
approximate market value at the time the obligations were settled.
 
 We issued
109,700 shares of stock in order to cancel the 438.500 outstanding
options.  The value assigned to the transaction was $1 per share
and was based on the approximate market value at the time the exchange was
made.
 
 We issued
204,561 to employees and directors for services.  The value of the
stock ranged from $.45 to $1.00 per share and was based on the approximate
market value at the time the obligations were settled.
 
 We
purchased debentures from the
holders and in connection with the purchase we received 75,000 of our
shares.  We cancelled 70,000 shares by March 31, 2010 and will cancel
an additional 5,000 shares.  The value assigned to this acquisition
was based on the market value of the shares and debentures at the time of
purchase.  We recorded a $30,000 reduction in equity for this
transaction.
 
 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.
  F-13
 
 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.
 
 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, 2010, there
were no outstanding options.
 
 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, 2010 there were no outstanding
options.
 
 Option
transactions in fiscal 2009:
 
 We
cancelled 20,000 options in accordance with the provisions regarding
terminations in Stock Option Plan.
 
 At March 31, 2009, we included as
expense $67,452 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, 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
                    
                    
                    $
                    3.00Granted
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Cancelled
                    
                    
                    (438,500
                    )
      )
                    
                    
                    (6.30
                    )
                    
                    
                    -
                    
                    
                    
                    -Exercised
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Outstanding
      March 31, 2010
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    75,000
                    
                    
                    $
                    3.00
 F-14





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, 2008
                    
                    $
                    459,689Liabilities
      incurred during the period
                    
                    
                    283,071Liabilities
      settled during the period
                    
                    
                    -Accretion
                    
                    
                    60,864Asset
      retirement obligations, March 31, 2009
                    
                    
                    803,624Liabilities
      incurred during the period
                    
                    
                    4,281Liabilities
      settled during the period
                    
                    
                    -Accretion
                    
                    
                    75,684Asset
      retirement obligations, March 31, 2010
                    
                    $
                    883,589





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 (“TCB”).  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.  A
borrowing base redetermination was completed by Texas Capital Bank effective
January 1, 2010.  The borrowing base was determined to be $6,746,000
and called for $55,000 Monthly Borrowing Base Reductions (“MBBR”) beginning
February 1, 2010.





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 have borrowed
all of our available borrowing base as of March 31, 2010.




F-15


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, but
in no event shall be less than five percent (5.0%). 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 extension, but in no event shall be less than five percent
(5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR
options, except that beginning March 30, 2009 and continuing through the date of
this report, TCB has suspended all LIBOR based funding with maturities less than
90 days due to the extreme volatility in the interest rate market and the
unprecedented spread between the 90 day LIBOR and the shorter term LIBOR
options. 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, 2010.
 
 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.
 
 The
Credit Facility was amended August 18, 2009 to implement a minimum interest rate
of five (5.0%) and establish minimum volumes to be hedged of not less than
seventy-five percent (75%) of the proved developed producing reserves
attributable to our interest in the borrowing base oil and gas properties
projected to be produced. The Credit Facility was further amended January
13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis
beginning with the quarter ended December 31, 2009 and to modify the
annualization of the interest coverage ratio, also beginning with the quarter
ended December 31, 2009.The senior funded debt to EBITDA ratio allowed is
6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010; 5.25:1.00 at June
30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00 for all quarters
ending after September 30, 2010.  We were not in compliance with the
three covenants at March31, 2010; however, we
are current in principal and interest payments..
 
 Additionally,
TCB and the holders of the debentures entered into a Subordination Agreement
whereby the debentures issued on June 21, 2007 are 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. Effective July 7, 2008, we
redeemed an aggregate principal amount of $6.3 million of the Debentures. We
also amended the remaining $2.7 million of aggregate principal Debentures 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 and eliminate the covenant to maintain
certain production thresholds.
 
 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.  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 years ended March
31, 2010 and 2009 was $596,108 and $2,814,095. 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.  At March 31, 2010 all
of the interest has been accreted.
 
 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 years
ended March 31, 2010 and 2009 were $45,929 and $268,453. Of this amount, $195,559
was expensed upon the redemption of $6.3 million of the
Debentures.
 
 The
Debentures originally had a three-year term, maturing on March 31, 2010, and an
interest rate equal to 10% per annum.  We further amended the
Debentures in June 2009 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 our common stock.  The conversion price on or before May 31,
2010 is equal to $3.00 per share.  From June 1, 2010 through the maturity
date, assuming the Debentures have not been redeemed, the conversion price per
share 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.
  F-17
 
 Interest
is payable quarterly in arrears on the first day of each succeeding quarter. The
interest rate remains 10% per annum for cash interest payments.  The
payment-in-kind interest rate is equal to 12.5% per annum.  If
interest payments are made through payment-in-kind interest, we must issue
common stock equal to an additional 2.5% of the quarterly interest payment
due.  As of March 31, 2010, we have recorded additional principal on
the Debentures of $368,045 and common stock issued and unissued of
$9,792.
 
 We
amended the Debentures on November 16, 2009 to provide for the tender and
cancellation of shares by the Buyers upon retirement of a portion of the
Debentures in accordance with an agreed upon schedule.  We redeemed
$150,000 of the Debentures for $150,000 in cash in accordance with this
amendment during the quarter ended December 31, 2009.  As a result,
75,000 shares have been or will be tendered and cancelled.  We
recorded a gain on the purchase of debentures of $30,000 based on the relative
fair value of the debentures and stock tendered.
 
 We 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.  During the year ended
March 31, 2010, we repurchased $450,000 of the Debentures for $43,500 resulting
in a gain of $406,500.
 
 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
four years and the weighted average interest is 7.2% per
annum.  Vehicles collateralize these notes.
  Long-term
debt consists of the following at March 31, 2010:
  Credit
      Facility
                    
                    $
                    6,691,000Debentures
                    
                    
                    2,468,045Vehicle
      notes payable
                    
                    
                    67,074Total
      long-term debt
                    
                    
                    9,226,119Less
      current portion
                    
                    
                    (9,182,679
                    )Long-term
      debt
                    
                    $
                    43,440
 
 Principal
amounts are due on long-term and convertible debt as follows: Year ended March
31, 2011 -$9,182,679 , March 31, 2012 -$24,063 , March 31, 2013 -$16,217, March
31, 2014 -$3,160.
  F-18
  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.  Pursuant to amendments to the
Joint Exploration Agreement, we had until March 31, 2010 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 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.
 
 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.
  F-19
  Capitalized costs of oil
and natural gas
producing properties
  Our aggregate capitalized costs related
to oil and natural gas producing activities are as follows:
 
 March31,
                      2010
                    
                    
                    March31,
                      2009Proven
                    
                    $
                    9,131,405
                    
                    
                    $
                    8,866,979Unevaluated
      and unproved
                    
                    
                    -
                    
                    
                    
                    31,183Accumulated
      depreciation and depletion
                    
                    
                    (2,607,411
                    )
                    
                    
                    (1,817,956
                    )Sale
      of properties
                    
                    
                    (632,000
                    )
                    
                    
                    (600,000
                    )Net
      capitalized costs
                    
                    $
                    5,891,994
                    
                    
                    $
                    6,480,206
 
 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,
                      2010
                    
                    
                    March31,
                      2009Acquisition
      of proved and unproved properties
                    
                    $
                    -
                    
                    
                    $
                    123,040Development
      costs
                    
                    
                    228,962
                    
                    
                    
                    2,999,963Exploration
      costs
                    
                    
                    -
                    
                    
                    
                    -Total
                    
                    $
                    228,962
                    
                    
                    $
                    3,123,003
 
 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.
 
 We have
previously entered into consulting agreements and acquired some leases and
utilize entities affiliated with a Director.  The Director was paid
$55,000 for consulting and received stock for the extension of certain
agreements totaling $65,000.
  F-20
 
 Note
8 – Commitments and Contingencies
  We have a
lease agreement that expires in September 30, 2013.  Rent expense for
the years ended March 31, 2010 and 2009 were approximately $71,000 and future
minimum payments are approximately $72,000 to $75,600 for years ended March 31,
2011-2013 and $38,750 for the year ended March 31, 2014.
  We, as a
lessee and operator of oil and gas properties, are subject to various federal,
state and local laws and regulations relating to discharge of materials into,
and protection of, the environment. These laws and regulations may, among other
things, impose liability on the lessee under an oil and gas lease for the cost
of pollution clean-up resulting from operations and subject to the lessee to
liability for pollution damages. In some instances, the Company may be directed
to suspend or cease operations in the affected
area.As of
March 31, 2010, we have no reserve for environmental remediation and are
not aware of any environmental claims.
  Note
9 – Income Taxes
 
 There was
no current or deferred income tax expense (benefit) for the years ended March
31, 2010 and 2009 because there was a net loss and a valuation allowance that
offsets the deferred tax amounts.  At March 31, 2010 we have a net
operating loss carryforward of approximately $9,597,000 expiring in
2021-2024.
 
 Significant
components of the deferred tax assets and liabilities are as
follows:
 
 March31,
                      2010
                    
                    
                    March31,
                      2009Non-current
      deferred tax asset:Impaired
      oil & gas costs and long-lived assets
                    
                    $
                    1,825,000
                    
                    
                    $
                    1,864,700Derivative
      instruments
                    
                    
                    1,206,400
                    
                    
                    
                    —Net
      operating loss carry-forward
                    
                    
                    3,263,000
                    
                    
                    
                    2,754,600Valuation
      allowance
                    
                    
                    (6,294,400
                    )
                    
                    
                    (4,619,300
                    )Total
      deferred tax net
                    
                    $
                    -
                    
                    
                    $
                    -
 
 A reconciliation of the provision for
income taxes to the statutory federal rate for continuing operations is as
follows:
 
 March31,
                      2010
                    
                    
                    March31,
                      2009Statutory
      tax rate
                    
                    
                    34.0
                    %
                    
                    
                    34.0
                    %Equity
      based compensation
                    
                    
                    -
                    %
                    
                    
                    (1.0
                    )%Derivative
      instruments
                    
                    
                    (24.4
                    )%
                    
                    
                    -
                    %Oil
      & gas costs and long-lived assets
                    
                    
                    (.8
                    )%
                    
                    
                    (29.0
                    )%Change
      in valuation allowance
                    
                    
                    (10.4
                    )%
                    
                    
                    (4.0
                    )%Effective
      tax rate
                    
                    
                    -
                    %
                    
                    
                    -
                    %
  F-21
 
 ASC 740,Income
Taxes(“ASC
740”) prescribes a recognition threshold and a measurement attribute for the
financial statement recognition and measurement of income tax positions taken or
expected to be taken in an income tax return.  For those benefits to
be recognized, an income tax position must be more-likely-than-not to be
sustained upon examination by taxing authorities.Our policy
is to recognize interest and penalties related to uncertain tax positions as
income tax benefit (expense) in our Consolidated Statements of
Operations.  For the years ended March 31, 2010 and 2009,
respectively, we recorded no interest expense and penalties related to
unrecognized tax benefits associated with uncertain tax positions recognized in
our provision for income taxes.
 
 Note
10 – Fair Value Measurements
 
 We hold
certain financial assets which are required to be measured at fair value on a
recurring basis in accordance with the Statement of Financial Accounting
Standard No. 157, “Fair Value
Measurements” (“ASC Topic 820-10”)..   ASC Topic 820-10
establishes a fair value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value. The hierarchy gives the highest priority
to unadjusted quoted prices in active markets for identical assets or
liabilities (Level 1 measurements) and the lowest priority to unobservable
inputs (Level 3 measurements).  ASC Topic 820-10 defines fair value as
the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants on the
measurement date. A fair value measurement assumes that the transaction to sell
the asset or transfer the liability occurs in the principal market for the asset
or liability. The three levels of the fair value hierarchy under ASC Topic
820-10 are described below:
 
 Level
1. Valuations based on quoted prices in active markets for identical assets
or liabilities that an entity has the ability to access.  The
Company’s Level 1 assets include cash, receivable, payables, notes payable and
convertible debt.
 
 Level
2. Valuations based on quoted prices for similar assets or liabilities,
quoted prices for identical assets or liabilities in markets that are not
active, or other inputs that are observable or can be corroborated by observable
data for substantially the full term of the assets or liabilities.  We
consider the derivative liability to be Level
2.  We  determine the fair value of  derivative
liability utilizing various inputs, including NYMEX price quotations and
contract terms.
 
 Level 3.
Valuations based on inputs that are supported by little or no market activity
and that are significant to the fair value of the assets or liabilities. We
have no level 3 assets or liabilities.
 
 Our
derivative instruments consist of variable to fixed price commodity
swaps.
 
 FairValueMeasurementTotalAmount
                          
                          
                          Level1
                          
                          
                          Level2
                          
                          
                          Level3Crude
      oil contracts
                          
                          $
                          3,548,245
                          
                          
                          $
                          -
                          
                          
                          $
                          3,548,245
                          
                          
                          $
                          -
  F-22
 
 Note
11 – Derivative Instruments
 
 We have
entered into certain derivative or physical arrangements with respect to
portions of our crude oil production to reduce our sensitivity to volatile
commodity prices and/or to meet hedging requirements under our CreditFacility.  We
believe that these derivative arrangements, although not free of risk, allow us
to achieve a more predictable cash flow and to reduce exposure to commodity
price fluctuations.  However, derivative arrangements limit the
benefit of increases in the prices of crude oil.  Moreover, our
derivative arrangements apply only to a portion of our production.
 
 We have an Intercreditor
Agreement in place between us; our counterparty, BP Corporation North America,
Inc. (“BP”); and our agent, Texas Capital Bank, N.A. (“TCB”), which allows TCB
to also act as agent for BP for the purpose of holding and enforcing any liens
or security interests resulting from our derivative
arrangements.  Therefore, we generally are not required to post
additional collateral, including cash.
 
 The
following derivative contracts were in place at December 31, 2010:
 
 Term
                            
                            Monthly Volumes
                            
                            Price per Bbl
                            
                            
                            Fair ValueCrude
      oil swap
                            
                            4/10-12/13
                            
                            2,266
      Bbl
                            
                            $
                            57.30
                            
                            
                            $
                            (3,428,307
                            )Crude
      oil swap
                            
                            4/10-3/11
                            
                            963 Bbls
                            
                            $
                            77.05
                            
                            
                            $
                            (119,938
                            )$
                            (3,548,245
                            )
 
 Monthly
volume is the weighted average throughout the period.
 
 The total
fair value is shown as a derivative instrument in both the current and
non-current liabilities on the balance sheet.  We recorded a loss of
$3,911,063 in the year ended March 31, 2010.
 
 Note
12 – Income (Loss) Per Common Share
 
 The
numerator for basic earning and diluted per share is income (loss) available to
common stockholders.
 
 Potential
dilutive securities (stock options, warrants and convertible debt) in 2010 and
2009 have not been considered since we reported a net loss and, accordingly,
their effects would be antidilutive.  There were no dilutive shares
2010 and 2009.
 
 Note
13 – Subsequent Events
 
 On August
3, 2009, we awarded a total of 151,750 shares of our common stock for 2009
incentive bonuses to our employees. Such shares were issued to the employees in
June of 2010. The shares were awarded pursuant to the EnerJex Resources Stock
Incentive Plan and registered on the Form S-8 filed on October 20,
2008.
  F-23
 
 Note
14 – 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
 
 March31,2010
                      
                      
                      March31,2009Production
      revenues
                      
                      $
                      4,856,027
                      
                      
                      $
                      6,436,805Production
      costs
                      
                      
                      (1,833,108
                      )
                      
                      
                      (2,637,333
                      )Depletion
      and depreciation
                      
                      
                      (789,455
                      )
                      
                      
                      (892,871
                      )Results
      of operations for producing activities
                      
                      $
                      2,233,464
                      
                      
                      $
                      2,906,601
 
 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 by Miller and
Lents, LTD 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, 2010
                    
                    
                    March 31, 2009Gas-mcf
                    
                    
                    Oil-stb
                    
                    
                    Gas-mcf
                    
                    
                    Oil-stbProved
      reserves:Beginning
                    
                    
                    -
                    
                    
                    
                    1,336,630
                    
                    
                    
                    401,197
                    
                    
                    
                    1,372,014Revisions
      of previous estimates
                    
                    
                    
                    
                    
                    
                    539,848
                    
                    
                    
                    (394,732
                    )
                    
                    
                    (14,375
                    )Purchase
      of minerals in place
                    
                    
                    -
                    
                    
                    
                    
                    
                    
                    
                    -
                    
                    
                    
                    53,280Extensions
      and discoveries
                    
                    
                    -
                    
                    
                    
                    
                    
                    
                    
                    -Production
                    
                    
                    
                    
                    
                    
                    (64,948
                    )
                    
                    
                    (6,465
                    )
                    
                    
                    (74,289
                    )Total
                    
                    
                    -
                    
                    
                    
                    1,811,530
                    
                    
                    
                    -
                    
                    
                    
                    1,336,630
 
 Proved
developed reserves for March 31, 2010 and 2009 were all oil reserves and totaled
569.5 and 525.0 MBbls, respectively.  Proved undeveloped reserves at
March 31, 2010 and 2009 were 1,242.0 and 811.7 MBbls,
respectively.
  F-24
 
 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.
 
 March31,
                      2010
                    
                    
                    March31,
                      2009Future
      production revenue
                    
                    $
                    113,473,940
                    
                    
                    $
                    57,007,970Future
      production costs
                    
                    
                    (43,520,350
                    )
                    
                    
                    (24,732,440
                    )Future
      development costs
                    
                    
                    (16,127,500
                    )
                    
                    
                    (9,584,500
                    )Future
      cash flows before income taxes
                    
                    
                    53,826,090
                    
                    
                    
                    22,691,030Future
      income taxes
                    
                    
                    10,003,500
                    
                    
                    
                    -Future
      net cash flows
                    
                    
                    43,822,590
                    
                    
                    
                    22,691,03010%
      annual discount for estimating of future cash flows
                    
                    
                    (26,273,150
                    )
                    
                    
                    (12,061,690
                    )Standardized
      measure of discounted net cash flows
                    
                    $
                    17,549,440
                    
                    
                    $
                    10,629,340
 
 Changes
in Standardized Measure of Discounted Future Net Cash Flows
 
 March31,
                      2010
                    
                    
                    March31,
                      2009Balance
      beginning of year
                    
                    $
                    10,629,340
                    
                    
                    $
                    28,200,503Sales,
      net of production costs
                    
                    
                    (3,039,640
                    )
                    
                    
                    (5,697,410
                    )Net
      change in pricing and production costs
                    
                    
                    10,082,110
                    
                    
                    
                    (31,927,063
                    )Net
      change in future estimateddevelopment
      costs
                    
                    
                    (3,716,010
                    )
                    
                    
                    9,220,510Purchase
      of minerals in place
                    
                    
                    -
                    
                    
                    
                    136,190Extensions
      and discoveries
                    
                    
                    -
                    
                    
                    
                    518,297Revisions
                    
                    
                    6,987,170
                    
                    
                    
                    (1,089,039
                    )Accretion
      of discount
                    
                    
                    310,890
                    
                    
                    
                    (143,477
                    )Change
      in income tax
                    
                    
                    (3,704,420
                    )
                    
                    
                    11,410,829Balance
      end of year
                    
                    $
                    17,549,440
                    
                    
                    $
                    10,629,340
  F-25