Attached files
file | filename |
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EX-5.1 - AgEagle Aerial Systems Inc. | v176355_ex5-1.htm |
EX-21.1 - AgEagle Aerial Systems Inc. | v176355_ex21-1.htm |
EX-23.1 - AgEagle Aerial Systems Inc. | v176355_ex23-1.htm |
EX-23.3 - AgEagle Aerial Systems Inc. | v176355_ex23-3.htm |
Registration
No. 333-163611
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-1/A
(Amendment No.
1)
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
ENERJEX
RESOURCES, INC.
(Exact name of
registrant as specified in its charter)
Nevada
|
1311
|
88-0422242
|
||
(State
or other jurisdiction of
incorporation
or organization)
|
(Primary
Standard Industrial
Classification
Code Number)
|
(I.R.S.
Employer
Identification
No.)
|
27
Corporate Woods, Suite 350
10975
Grandview Drive
Overland
Park, Kansas 66210
(913) 754-7754
(Address,
including zip code, and telephone number,
including
area code, of registrant’s principal executive offices)
C.
Stephen Cochennet
President
and Chief Executive Officer
EnerJex
Resources, Inc.
27
Corporate Woods, Suite 350
10975
Grandview Drive
Overland
Park, Kansas 66210
(913) 754-7754
(Name,
address, including zip code, and telephone number,
including
area code, of agent for service)
Copies
to:
DeMint
Law, PLLC
Anthony
N. DeMint, Esq.
3753
Howard Hughes Parkway
Suite
200, #314
Las
Vegas, NV 89169
(702)
586-6436
Approximate date of commencement of
proposed sale to the public: As soon as practicable after this
Registration Statement becomes effective.
If any of
the securities being registered on this Form are to be offered on a delayed or
continuous basis pursuant to Rule 415 under the Securities Act of 1933,
check the following box. x
If this
Form is filed to register additional securities for an offering pursuant to
Rule 462(b) under the Securities Act, please check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. o
If this
Form is a post-effective amendment filed pursuant to Rule 462(c) under the
Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same
offering. o
If this
Form is a post-effective amendment filed pursuant to Rule 462(d) under the
Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same
offering. o
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. (Check one):
Large
accelerated filer o
|
Accelerated
filer o
|
Non-accelerated
filer o
(Do
not check if a smaller reporting company)
|
Smaller
reporting company x
|
CALCULATION OF REGISTRATION
FEE
Title of Securities to be Registered
|
Amount to be
Registered
|
Proposed Maximum
Offering Price Per
Share(1)
|
Proposed Maximum
Aggregate
Offering Price (1)
|
Amount of
Registration
Fee (2)
|
||||||||||||
Common
Stock ($0.001 par value) to be offered for resale by the selling
stockholder
|
1,390,000 | $ | 0.60 | $ | 834,000 | $ | 46.54 |
(1)
|
Estimated
solely for the purpose of calculating the registration fee in accordance
with Rule 457(c) under the Securities Act of 1933, as amended. The
maximum offering price per share is based on the average of the bid and
asked price of the Registrant’s common stock on the over-the-counter
bulletin board on December 3, 2009.
|
(2)
|
Previously
paid.
|
The Registrant hereby amends this
Registration Statement on such date or dates as may be necessary to delay its
effective date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall thereafter become
effective in accordance with Section 8(a) of the Securities Act of 1933 or
until the Registration Statement shall become effective on such date as the
Commission, acting pursuant to said Section 8(a), may
determine.
The
information in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an
offer to sell these securities and it is not soliciting an offer to buy these
securities in any state where the offer or sale is not
permitted.
SUBJECT
TO COMPLETION, DATED March 4, 2010
PROSPECTUS
1,390,000
Shares of Common Stock
(par
value $0.001 per share)
This
prospectus relates to the resale of 1,390,000 shares of the common stock, par
value $0.001 per share, of EnerJex Resources, Inc. by the selling stockholder
identified on page 74 of this prospectus, Paladin Capital Management, S.A.
(“Paladin” or the
“Selling Stockholder”).
We may from time to time issue shares of our common stock to Paladin at between
85% and 95% of the market price at the time of such issuance determined in
accordance with the terms of our Standby Equity Distribution Agreement, dated as
of December 3, 2009, or SEDA, with Paladin. Paladin may from time to time sell
shares in transactions on any stock exchange, market or facility on which our
shares are traded, in privately negotiated transactions or otherwise at market
prices prevailing at the time of sale, at prices related to such market prices
or at negotiated prices. We have no basis for estimating either the number
of shares of our common stock that will ultimately be issued to or sold by the
Selling Stockholder or the prices at which such shares will be sold. We
will bear all expenses of registration incurred in connection with this
offering, including filing fees, printing fees, and expenses of our legal
counsel and other experts, but all selling and other expenses incurred by the
Selling Stockholder will be borne by the Selling Stockholder. For
additional information on the methods of sale that may be used by Paladin, see
the section entitled “Plan of
Distribution” on page 75. We will not receive any of the proceeds from
the sale of these shares. However, we will receive proceeds from Paladin from
the initial sale to such stockholder of these shares.
Our
common stock is included for quotation on the over-the-counter bulletin board
(“OTC:BB”) under the
symbol “ENRJ.OB.” The closing price of our common stock on March 3, 2009 was $
1.03.
This
investment involves a high degree of risk. We urge you to carefully read the
“Risk Factors” section
beginning on page 9 of this prospectus.
We may
amend or supplement this prospectus from time to time by filing amendments or
supplements as required. You should read this prospectus and any prospectus
supplement carefully before you decide to invest. You should not assume that the
information in this prospectus is accurate as of any date other than the date on
the front of this document.
With
the exception of Paladin, which has informed us it is an “underwriter” within the
meaning of the Securities Act of 1933, as amended or the Securities Act, to the
best of our knowledge, no other underwriter or person has been engaged to
facilitate the sale of shares of our stock in this offering. The Securities and
Exchange Commission may take the view that, under certain circumstances, any
broker-dealers or agents that participate with Paladin in the distribution of
the shares may be deemed to be “underwriters” within the
meaning of the Securities Act. Commissions, discounts or concessions
received by any such broker-dealer or agent may be deemed to be underwriting
commissions under the Securities Act.
Neither
the Securities and Exchange Commission nor any state securities commission has
approved or disapproved of these securities or determined if this prospectus is
truthful or complete. Any representation to the contrary is a criminal
offense.
The date
of this prospectus is ______________, 2010
TABLE
OF CONTENTS
SUMMARY
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1
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THE
OFFERING
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6
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SUMMARY
FINANCIAL DATA
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7
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RISK
FACTORS
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9
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SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS
|
25
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USE
OF PROCEEDS
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25
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DIVIDEND
POLICY
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26
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CAPITALIZATION
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26
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PRICE
RANGE OF COMMON STOCK
|
27
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MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
28
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BUSINESS
AND PROPERTIES
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45
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MANAGEMENT
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61
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NON-EMPLOYEE
DIRECTOR COMPENSATION
|
63
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EXECUTIVE
COMPENSATION
|
64
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CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
|
69
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PRINCIPAL
STOCKHOLDERS
|
69
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DESCRIPTION
OF CAPITAL STOCK
|
71
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SELLING
STOCKHOLDER
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74
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PLAN
OF DISTRIBUTION
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75
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LEGAL
MATTERS
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76
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EXPERTS
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76
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INDEPENDENT
PETROLEUM ENGINEERS
|
77
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WHERE
YOU CAN FIND MORE INFORMATION
|
77
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GLOSSARY
|
78
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INDEX
TO FINANCIAL STATEMENTS
|
81
|
You
should rely only on the information contained in this prospectus. The
selling stockholders have not, authorized any person to provide you with
different information. This prospectus is not an offer to sell, nor is it
an offer to buy, these securities in any jurisdiction where the offer or sale is
not permitted. The information in this prospectus is complete and accurate
only as of the date of this prospectus regardless of the time of delivery of
this prospectus or any sale of our common stock. Our business, financial
condition, prospects and other information may have changed since this
date.
No
action is being taken in any jurisdiction outside the United States to permit a
public offering of the common stock or possession or distribution of this
prospectus in that jurisdiction. Persons who come into possession of this
prospectus in jurisdictions outside the United States are required to inform
themselves about, and to observe any restrictions as to, this offering and the
distribution of this prospectus applicable to those jurisdictions.
Industry
and Market Data
The
market data and certain other statistical information used throughout this
prospectus 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.
Non-GAAP
Financial Measures
The body
of accounting principles generally accepted in the United States is commonly
referred to as “GAAP.” A non-GAAP
financial measure is generally defined by the Securities and Exchange
Commission, or SEC, as one that purports to measure historical or future
financial performance, financial position or cash flows, but excludes or
includes amounts that would not be so adjusted in the most comparable GAAP
measures. Any non-GAAP measures are described herein.
SUMMARY
The
items in the following summary are described in more detail later in this
prospectus. Because this section is a summary, it does not contain all the
information that may be important to you or that you should consider before
investing in our common stock. For a more complete understanding, you should
carefully read the more detailed information set out in this prospectus,
especially the risks of investing in our common stock that we discuss under the
“Risk Factors” section, as well as the financial statements and the related
notes to those statements included elsewhere in this prospectus.
All
references in this prospectus 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 prospectus in the “Glossary” beginning on page 78 of this
prospectus.
Our
Business
EnerJex,
formerly known as Millennium Plastics Corporation, is an oil and natural gas
acquisition, exploration and development company. In August 2006, Millennium
Plastics Corporation, following a reverse merger by and among us, Millennium
Acquisition Sub (our wholly-owned subsidiary) and Midwest Energy, Inc., a Nevada
corporation, or Midwest Energy, changed the focus of its business plan from the
development of biodegradable plastic materials and entered into the oil and
natural gas industry. In conjunction with the change, the company was renamed
EnerJex Resources, Inc.
Our
principal strategy is to focus on the acquisition of oil and natural gas mineral
leases that have existing production and cash flow. Once acquired, we strive to
implement an accelerated development program utilizing capital resources, a
regional operating focus, an experienced management and technical team, and
enhanced recovery technologies to attempt to increase production and increase
returns for our stockholders. Our oil and natural gas acquisition and
development activities are currently focused in Eastern Kansas.
Since the
beginning of fiscal 2008, we have deployed approximately $12 million in capital
resources to acquire and develop five operating projects and drill 179 new wells
(111 producing wells and 65 water injection wells and 3 dry holes). As a result,
our estimated total net proved oil reserves increased from zero at March 31,
2007 to 1.3 million barrels of oil equivalent, or BOE, as of March 31, 2009. Of
the 1.3 million BOE of total proved reserves, approximately 39% are proved
developed and approximately 61% are proved undeveloped. The proved developed
reserves consist of 82% proved developed producing reserves and 18% proved
developed non-producing reserves.
The total
proved PV10 (present value) of our reserves (“PV10”) as of March 31, 2009
was $10.63 million, based on an estimated oil price of $42.65 per barrel. 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 “Glossary” on page 78 for our
definition of PV10 and see “Management’s Discussion and Analysis
of Financial Condition and Results of Operations - Reserves” on page 33
for a reconciliation to the comparable GAAP financial measure.
The
following table sets forth a summary of our estimated proved reserves
attributable to our properties as of March 31, 2009:
Proved Reserves
Category
|
Gross
STB(1)
|
Net
STB(2)
|
Gross
MCF(3)
|
Net
MCF(4)
|
PV10(5)
(before tax)
|
|||||||||||||||
Proved,
Developed Producing
|
722,590 | 429,420 | - | - | $ | 6,691,550 | ||||||||||||||
Proved,
Developed Non-Producing
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146,620 | 95,560 | - | - | 1,459,280 | |||||||||||||||
Proved,
Undeveloped
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1,440,760 | 811,650 | - | - | 2,478,510 | |||||||||||||||
Total
Proved
|
2,309,970 | 1,336,630 | - | - | $ | 10,629,340 |
1
|
(1)
|
STB
= one stock-tank barrel.
|
|
(2)
|
Net
STB is based upon our net revenue interest, including any applicable
reversionary interest.
|
|
(3)
|
MCF
= thousand cubic feet of natural gas. There were no natural gas
reserves at March 31, 2009.
|
|
(4)
|
Net
MCF is based upon our net revenue interest. There were no natural
gas reserves at March 31, 2009.
|
|
(5)
|
See
“Glossary” on
page 78 for our definition of PV10 and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Reserves”
page 33, for a reconciliation to the comparable GAAP financial
measure.
|
The
Opportunity in Kansas
According
to the Kansas Geological Survey, the State of Kansas has historically been one
of the top 10 domestic oil producing regions in the United States. For the years
ended December 31, 2008 and 2007, 39.6 million barrels and 36.6 million barrels
of oil were produced in Kansas. Of the total barrels produced in Kansas in the
calendar year ended December 2007, 15 companies accounted for approximately 29%
of the total production, with the remaining 71% produced by over 1,750 active
producers.
In
addition to significant historical oil and natural gas production levels in the
region, we believe that a confluence of the following factors in Eastern Kansas
and the surrounding region make it an attractive area for oil and natural gas
development activities:
|
·
|
Traditional Roll-Up
Strategy. We are seeking to employ a traditional roll-up strategy
utilizing a combination of capital resources, operational and management
expertise, technology, and our strategic partnership with Haas Petroleum,
which has experience operating in the region for nearly 70
years.
|
|
·
|
Numerous Acquisition
Opportunities. There are many small producers and owners of mineral
rights in the region, which afford us numerous opportunities to pursue
negotiated lease transactions instead of having to competitively bid on
fundamentally sound assets.
|
|
·
|
Fragmented Ownership
Structure. There are numerous opportunities to acquire producing
properties at attractive prices, because of the currently inefficient and
fragmented ownership structure.
|
Our
Properties
|
·
|
Black Oaks Project. The
Black Oaks Project is currently a 2,400 acre project in Woodson and
Greenwood Counties of Kansas where we are aggressively implementing a
primary and secondary recovery waterflood program to increase oil
production. We originally acquired an option to purchase and participate
in the Black Oaks Project from MorMeg, LLC, or MorMeg, which is controlled
by Mark Haas, a principal of Haas Petroleum, for $500,000 of cash and
stock. In addition, we established a joint operating account with MorMeg
and funded it with $4.0 million for the initial development of the
project. We have a 95% working interest in the project and MorMeg has a 5%
carried working interest in the project, which will convert to a 30%
working interest upon payout. Our gross production at Black Oaks for the
month of January 2010 was approximately 89
BOEPD.
|
|
·
|
DD Energy
Project. In September 2007, we acquired a 100% working
interest in seven oil and natural gas leases stretching across
approximately 1,700 acres in Johnson, Anderson and Linn Counties of Kansas
for $2.7 million. Our gross production at DD Energy for the month of
January 2010 was approximately 48
BOEPD.
|
|
·
|
Tri-County
Project. We hold a nearly 100% working interest in, and are
the operator of, approximately 1,300 acres of oil and natural gas leases
in Miami, Johnson and Franklin Counties of Kansas that make up the
Tri-County Project. We completed this purchase in September 2007 for
$800,000 in cash. Our gross production for the month of January 2010 at
Tri-County was approximately 35
BOEPD.
|
2
|
·
|
Thoren Project.
We acquired the Thoren Project from MorMeg in April 2007 for $400,000. The
lease currently encompasses approximately 747 acres in Douglas County,
Kansas. We hold a 100% working interest in the Thoren Project. Our gross
production for the month of January 2010 at Thoren was approximately 26
BOEPD.
|
|
·
|
Gas City Project.
The Gas City Project, currently located on approximately 5,313 acres in
Allen County, Kansas, was acquired for $750,000 in February of 2006 and
was our first property acquisition. In August 2007, we entered into a
Development Agreement with Euramerica Energy, Inc., or Euramerica, whereby
Euramerica initially invested $524,000 in capital toward 6,600 acres of
the project. Euramerica was granted an option to purchase this 6,600 acre
portion of the project for $1.2 million with a requirement to invest an
additional $2.0 million for project development. Euramerica paid us
$600,000 of the $1.2 million purchase price and $500,000 of the $2.0
million development funds. On October 15, 2008, the decision was made to
shut in the project and cease all operations until Euramerica provided the
funds that were due by January 15, 2009. Euramerica failed to fully fund
by January 15, 2009 both the balance of the purchase price and the
remaining development capital owed under the agreements between us and
Euramerica. 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. We drilled 22 wells on behalf of Euramerica under the
development agreement. We are currently exploring options to sell or
further develop the Gas City Project through joint venture partnerships or
other opportunities. The gas project remains shut in and certain
leases approximating 1,300 acres were not renewed upon expiration.
The gross production for the month of January 2010 at Gas City was
approximately 6 BOEPD from the oil wells now 100% owned by
us.
|
Our
Business Strategy
Our goal
is to increase stockholder value by finding and developing oil and natural gas
reserves at 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.
|
Our
Competitive Strengths
We have a
number of strengths that we believe will help us successfully execute our
strategy:
|
·
|
Acquisition and Development
Strategy. We have what we believe to be a relatively low-risk
acquisition and development strategy compared to some of our competitors.
We generally buy properties that have proven current production, with a
projected pay-back within a relatively short period of time, and with
potential growth and upside in terms of development, enhancement and
efficiency. We also plan to minimize the risk of natural gas and oil price
volatility by developing a sales portfolio of pricing for our production
as it expands and as market conditions
permit.
|
3
|
·
|
Significant Production Growth
Opportunities. We have acquired an attractive acreage
position with favorable lease terms in a region with historical
hydrocarbon production. Based on drilling success we have had within our
acreage position and subject to availability of capital, we expect to
increase our reserves, production and cash
flow.
|
|
·
|
Experienced Management Team
and Strategic Partner with Strong Technical Capability. Our
CEO has over 20 years of experience in the energy industry, primarily
related to gas/electric utilities, but including experience related to
energy trading and production, and members of our board of directors have
considerable industry experience and technical expertise in engineering,
horizontal drilling, geoscience and field operations. In addition, our
strategic partner, Haas Petroleum, has over 70 years of experience in
Eastern Kansas, including completion and secondary recovery techniques and
technologies. Our board of directors and Mark Haas of Haas Petroleum work
closely with management during the initial phases of any major project to
ensure its feasibility and to consider the appropriate recovery techniques
to be utilized.
|
|
·
|
Incentivized Management
Ownership. The equity ownership of our directors and
executive officers is strongly aligned with that of our stockholders. As
of February 22, 2010, our directors and executive officers owned
approximately 14% of our outstanding common
stock.
|
Company
History
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.
Initially,
all of our oil and natural gas operations were conducted through Midwest Energy.
In November 2007, Midwest Energy changed its name to EnerJex Kansas, Inc., or
EnerJex Kansas. In August 2007, we incorporated DD Energy, Inc., or DD Energy,
as a wholly-owned operating subsidiary. All of our current operations are
conducted through EnerJex Kansas and DD Energy, our wholly-owned
subsidiaries.
Risks
Associated with Our Business
Our
business is subject to numerous risks, as discussed more fully in the section
entitled “Risk Factors”
beginning on page 9 of this prospectus. Some of these risks
include:
|
·
|
Volatility
in natural gas and oil prices, which could negatively impact our revenues
and our ability to cover our operating or capital
expenditures.
|
|
·
|
The
concentration of our properties in Eastern Kansas, which
disproportionately exposes us to adverse events occurring in this
geographic area.
|
|
·
|
Our
ability to achieve and maintain profitable business operations. Although
we recently achieved positive income from operations for the first time in
our history, we have a history of losses since our inception and we may
never be able to maintain
profitability.
|
|
·
|
Our
ability to obtain 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.
|
|
·
|
Our
ability to effectively compete with large companies that may have greater
resources than us.
|
4
|
·
|
Our
ability to accurately estimate proven recoverable
reserves.
|
|
·
|
Our
ability to successfully complete future acquisitions and to integrate
acquired businesses.
|
|
·
|
Our
ability to comply with complex laws and regulations, including
environmental regulations, which can adversely affect the cost, manner or
feasibility of doing business.
|
December
2009 Standby Equity Distribution Agreement
On
December 3, 2009, we and Paladin entered into a Standby Equity Distribution
Agreement, or SEDA, pursuant to which, for a two-year period, we have the right
to sell up to 1,300,000 shares of our common stock to Paladin at any time. These
shares are being registered with this registration statement, even though
Paladin does not own them yet. On December 3, 2009, we authorized the issuance
of 90,000 shares of our common stock to Paladin as a commitment fee. As of
December 9, 2009, we had not sold any shares of common stock to Paladin under
the SEDA.
For each
share of common stock purchased under the SEDA, Paladin will pay a percentage of
the lowest daily volume weighted average closing price during the five
consecutive trading days after we provide notice to Paladin based on the
following:
|
·
|
85%
of the market price for the initial two
advances,
|
|
·
|
90%
of the market price to the extent the Common Stock is trading below $1.00
per share during the pricing
period,
|
|
·
|
92%
of the market price to the extent the Common Stock is trading at or above
$1.00 per share during the pricing period,
or
|
|
·
|
95%
of the market price to the extent the Common Stock is trading at or above
$2.00 per share during the pricing
period.
|
Each such
advance may be for an amount that is the greater of $40,000 or 20% the average
daily trading volume of our common stock for the five consecutive trading days
prior to the notice date. However, our initial two advances under the SEDA may
be for up to $55,000. In addition, in no event shall the number of shares of
common stock issuable to Paladin pursuant to an advance cause the aggregate
number of shares of common stock beneficially owned by Paladin and its
affiliates to exceed 4.99%.
Our right
to deliver an advance notice and the obligations of Paladin thereunder with
respect to an advance is subject to our satisfaction of a number of conditions,
including that our common stock is trading, and we believe will continue for the
foreseeable future to trade, on a principal market, that we have not received
any notice threatening the continued listing of our common stock on the
principal market and that a registration statement is effective.
In
addition, without the written consent of Paladin, we may not, directly or
indirectly, offer to sell, sell, contract to sell, grant any option to sell or
otherwise dispose of any shares of common stock (other than the shares offered
pursuant to the provisions of the agreement) or securities convertible into or
exchangeable for common stock, warrants or any rights to purchase or acquire,
common stock during the period beginning on the 5th trading day immediately
prior to an advance notice date and ending on the 5th trading day immediately
following the settlement date.
We may
terminate the SEDA upon fifteen trading days of prior notice to Paladin, as long
as there are no advances outstanding and we have paid to Paladin all amounts
then due. A copy of the SEDA is attached hereto as an exhibit.
Corporate
Information
EnerJex
Resources, Inc. is a Nevada corporation. Our principal executive office is
located at 27 Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park,
Kansas 66210, and our phone number is (913) 754-7754. We also maintain a website
at www.enerjexresources.com. The information on our website is not incorporated
by reference into this prospectus.
5
THE
OFFERING
We have
agreed to register 1,390,000 shares of our common stock already issued to or
subject to issuance to the Selling Stockholder named in this prospectus for
resale pursuant to this prospectus. The named selling stockholder may
offer shares of our common stock through public or private
transactions.
Common
stock offered by the Selling Stockholder
|
1,390,000 shares
|
|
Use
of proceeds
|
We
will not receive any of the proceeds from the sale of shares of our common
stock in this offering. We will receive proceeds from any sale of
shares of common stock to Paladin pursuant to the SEDA and proceeds
received under the SEDA will be utilized for working capital and general
corporate purposes.See “Use of Proceeds” on
page 25 of this prospectus.
|
|
Current
OTC:BB symbol
|
ENRJ.OB
|
|
Dividend
policy
|
We
do not expect to pay dividends in the foreseeable
future.
|
|
Risk
factors
|
|
Investing
in our common stock involves certain risks. See the risk factors described
under the heading “Risk
Factors” beginning on page 9 of this prospectus and the other
information included in this prospectus for a discussion of factors you
should carefully consider before deciding to invest in shares of our
common stock.
|
6
SUMMARY
FINANCIAL DATA
The
following tables set forth a summary of the historical financial data of EnerJex
Resources, Inc. for, and as of the end of, each of the periods indicated. The
statements of operations, statements of cash flows and other financial data for
the period from (i) inception (December 30, 2005) to March 31, 2006, (ii) the
fiscal years ended March 31, 2007, 2008 and 2009, and (iii) our balance sheets
as of March 31, 2007, March 31, 2008 and March 31, 2009 are derived from our
audited financial statements included elsewhere in this prospectus. Our balance
sheet as of December 31, 2009 and the statements of operations, statements of
cash flows and other financial data for the nine months ended December 31, 2009
and 2008 are derived from our unaudited financial statements included elsewhere
in this prospectus. We have prepared the unaudited financial statements on the
same basis as our audited financial statements and, in our opinion, have
included all adjustments, which include only normal recurring adjustments,
necessary to present fairly our financial position and results of our operations
for each of the periods mentioned.
The
inception date for the financial statements presented in this prospectus is that
of EnerJex Kansas. As a result of a reverse merger between Millennium Plastics
Corporation (now EnerJex Resources, Inc.) and EnerJex Kansas (formerly Midwest
Energy), EnerJex Kansas was deemed to be the acquiring company for financial
reporting purposes and the transaction has been accounted for as a reverse
merger.
Our
historical results are not necessarily indicative of the results to be expected
for any future periods and the results for the nine months ended December 31,
2009 should not be considered indicative of results expected for the full fiscal
year. You should read the following financial information together with the
information under “Management’s Discussion and Analysis
of Results of Operations and Financial Condition” and our financial
statements and related notes included elsewhere in this prospectus.
Nine Months Ended
December 31,
|
Year Ended
March 31,
|
Year Ended
March 31,
|
Year Ended
March 31,
|
From
Inception
(December
30, 2005)
through
March 31,
|
||||||||||||||||||||
2009
|
2008
|
2009
|
2008
|
2007
|
2006
|
|||||||||||||||||||
(Unaudited)
|
(Unaudited)
|
(Audited)
|
(Audited)
|
(Audited)
|
(Audited)
|
|||||||||||||||||||
Statement
of Operations:
|
||||||||||||||||||||||||
Revenue
|
||||||||||||||||||||||||
Oil
and natural gas activities
|
$ | 3,703,724 | $ | 4,652,289 | $ | 6,436,805 | $ | 3,602,798 | $ | 90,800 | $ | 2,142 | ||||||||||||
Expenses
|
||||||||||||||||||||||||
Direct
operating costs
|
1,313,518 | 2,093,994 | 2,637,333 | 1,795,188 | 172,417 | 14,599 | ||||||||||||||||||
Repairs
on oil and natural gas equipment
|
— | — | — | — | 165,603 | 40,436 | ||||||||||||||||||
Depreciation,
depletion and amortization
|
577,288 | 995,069 | 911,293 | 935,330 | 23,978 | 825 | ||||||||||||||||||
Professional
fees
|
479,710 | 400,816 | 1,320,332 | 1,226,998 | 302,071 | 50,490 | ||||||||||||||||||
Salaries
|
706,011 | 694,973 | 849,340 | 1,703,099 | 288,016 | — | ||||||||||||||||||
Administrative
expense
|
789,827 | 1,065,308 | 1,392,645 | 887,872 | 182,773 | 21,700 | ||||||||||||||||||
Impairment
of oil and natural gas Properties
|
— | 4,777,723 | 4,777,723 | — | 273,959 | 468,081 | ||||||||||||||||||
Impairment
of goodwill
|
— | — | — | — | 677,000 | — | ||||||||||||||||||
Total
expenses
|
3,866,354 | 10,027,883 | 11,888,666 | 6,548,487 | 2,085,817 | 596,131 | ||||||||||||||||||
Income
(loss) from operations
|
(162,630 | ) | (5,375,594 | ) | (5,451,861 | ) | (2,945,689 | ) | (1,995,017 | ) | (593,989 | ) | ||||||||||||
Other
income (expense):
|
||||||||||||||||||||||||
Interest
expense
|
(542,939 | ) | (743,372 | ) | (882,426 | ) | (792,448 | ) | (8,434 | ) | (38 | ) | ||||||||||||
Loan
interest accretion
|
(432,864 | ) | (2,686,892 | ) | (2,814,095 | ) | (1,089,798 | ) | — | — | ||||||||||||||
Management
fee revenue
|
99,234 | — | — | — | — | — | ||||||||||||||||||
Gain
on repurchase of debentures
|
406,500 | — | — | — | — | — | ||||||||||||||||||
Loss
on disposal of vehicles
|
(20,695 | ) | (4,421 | ) | — | — | — | — | ||||||||||||||||
Unrealized
gain (loss) on derivative instruments
|
(2,485,706 | ) | — | — | — | — | — | |||||||||||||||||
Gain
on liquidation of hedging instrument
|
— | 3,879,050 | 3,879,050 | — | — | — | ||||||||||||||||||
Other
gain (loss)
|
— | — | (37,736 | ) | — | 348 | 1,159 | |||||||||||||||||
Total
other income (expense)
|
(2,976,470 | ) | 444,365 | 144,793 | (1,882,246 | ) | (8,086 | ) | 1,121 | |||||||||||||||
Net
income (loss)
|
$ | (3,139,100 | ) | $ | (4,931,229 | ) | $ | (5,307,068 | ) | $ | (4,827,935 | ) | $ | (2,003,103 | ) | $ | (592,868 | ) | ||||||
Weighted
average number of common shares outstanding – basic and fully
diluted
|
4,647,879 | 4,442,467 | 4,443,249 | 4,284,144 | 2,448,318 | 1,712,609 | ||||||||||||||||||
Net
income (loss) per share – basic
|
$ | (0.68 | ) | $ | (1.11 | ) | $ | (1.19 | ) | $ | (1.13 | ) | $ | (0.82 | ) | $ | (0.35 | ) |
7
Nine Months Ended
December 31,
|
Year Ended
March 31,
|
Year Ended
March 31,
|
Year Ended
March 31,
|
From
Inception
(December
30, 2005)
through
March 31,
|
||||||||||||||||||||
2009
|
2008
|
2009
|
2008
|
2007
|
2006
|
|||||||||||||||||||
(Unaudited)
|
(Unaudited)
|
(Audited)
|
(Audited)
|
(Audited)
|
(Audited)
|
|||||||||||||||||||
Statement
of Cash Flows:
|
||||||||||||||||||||||||
Cash
provided by (used in) operating activities
|
$ | 1,675,890 | $ | 3,130,719 | $ | 3,686,582 | $ | (408,494 | ) | $ | (1,435,559 | ) | $ | (60,786 | ) | |||||||||
Cash
(used in) investing activities
|
(173,793 | ) | (2,517,241 | ) | (3,027,203 | ) | (9,357,020 | ) | (151,180 | ) | (767,550 | ) | ||||||||||||
Cash
provided by (used in) financing activities
|
(1,217,312 | ) | (1,376,136 | ) | (1,482,798 | ) | 10,617,025 | 1,095,800 | 1,418,768 | |||||||||||||||
Increase
(decrease) in cash and cash equivalents
|
284,785 | (762,658 | ) | (823,419 | ) | 851,511 | (490,939 | ) | 590,432 | |||||||||||||||
Cash
and cash equivalents, beginning
|
127,585 | 951,004 | 951,004 | 99,493 | 590,432 | — | ||||||||||||||||||
Cash
and cash equivalents, end
|
$ | 412,370 | $ | 188,346 | $ | 127,585 | $ | 951,004 | $ | 99,493 | $ | 590,432 | ||||||||||||
Supplemental
disclosures:
|
||||||||||||||||||||||||
Interest
paid
|
$ | 209,681 | $ | 688,062 | $ | 768,053 | $ | 733,972 | $ | 5,407 | $ | 38 | ||||||||||||
Income
tax paid
|
$ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Non-cash
transactions:
|
||||||||||||||||||||||||
Share-
based payments issued for compensation and services
|
$ | 603,750 | 79,455 | — | 280,591 | 558,000 | 33,000 | |||||||||||||||||
Share-based
payments issued for oil
and gas properties
|
$ | — | $ | — | $ | — | $ | — | $ | 200,000 | $ | — | ||||||||||||
Principal
increase on debentures
|
$ | 294,250 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Shares
issued for interest on debentures
|
$ | 7,355 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Asset
retirement obligation
|
$ | 4,281 | $ | 246,871 | $ | — | $ | — | $ | — | $ | — |
At
December 31,
|
At
March 31,
|
At
March 31,
|
At
March 31,
|
At
March 31,
|
||||||||||||||||
2009
|
2009
|
2008
|
2007
|
2006
|
||||||||||||||||
(Unaudited)
|
(Audited)
|
(Audited)
|
(Audited)
|
(Audited)
|
||||||||||||||||
Total
Assets
|
$ | 7,336,967 | $ | 7,680,178 | $ | 10,867,829 | $ | 492,507 | $ | 922,486 | ||||||||||
Total
Liabilities
|
13,658,584 | 11,473,802 | 9,433,837 | 537,097 | 71,586 | |||||||||||||||
Stockholders’
Equity (deficit)
|
$ | (6,321,617 | ) | $ | (3,793,624 | ) | $ | 1,433,992 | $ | (44,590 | ) | $ | 850,900 |
8
RISK
FACTORS
Investing
in our common stock involves a high degree of risk. You should carefully
consider the following risk factors, as well as the other information in this
prospectus, before deciding whether to invest in shares of our common stock. If
any of the following risks actually occur, our business, financial condition,
operating results and prospects would suffer. In that case, the trading price of
our common stock would likely decline and you might lose all or part of your
investment in our common stock. The risks described below are not the only ones
we face. Additional risks that we currently do not know about or that we
currently believe to be immaterial may also impair our operations and business
results.
Risks
Associated with Our Business
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;
|
|
·
|
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
|
|
·
|
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.
9
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.
Our
auditor’s report reflects the fact that without realization of additional
capital, it would be unlikely for us to continue as a going
concern.
As a
result of our deficiency in working capital at March 31, 2009 and other factors,
our auditors have included a paragraph in their audit report regarding
substantial doubt about our ability to continue as a going concern. Our plans in
this regard are to increase production, seek strategic alternatives and to seek
additional capital through future equity private placements or debt
facilities.
Natural
gas and oil prices are volatile. This volatility may occur in the future,
causing negative change in cash flows which may result in our inability to cover
our operating or capital expenditures.
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;
|
10
|
·
|
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.
Approximately
68% of our total proved reserves as of March 31, 2009 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, 2009 was $10.63 million, versus $39.6 million as of March 31, 2008.
The decline in PV10 is primarily due to the estimated average price of oil
at March 31, 2009 of $42.65 versus $94.53 at March 31, 2008. We held total
proved reserves of 1.3 million barrels of oil equivalent, or BOE, as of March
31, 2009. Of the 1.3 million BOE of total proved reserves, approximately
39% are proved developed and approximately 61% are proved undeveloped. The
proved developed reserves consist of 82% proved developed producing reserves and
18% proved developed non-producing reserves. See “Glossary” on page 78 for our
definition of PV10.
As of
March 31, 2009, approximately 61% of our total proved reserves were undeveloped
and approximately 7% were developed non-producing. We plan to develop and
produce all of our proved reserves, but ultimately some of these reserves may
not be developed 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, 2009 was prepared by Miller and Lents, Ltd., an independent petroleum
consultant. Prior to this fiscal year, our reserves were evaluated and
estimates were prepared by McCune Engineering, an independent petroleum and
geological engineer. 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.
11
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.
Currently,
the SEC permits natural gas and oil companies, in their public filings, to
disclose only proved reserves that a company has demonstrated by actual
production or conclusive formation tests to be economically and legally
producible under existing economic and operating conditions. These current SEC
guidelines strictly prohibit us from including “probable reserves” and “possible reserves” in such
filings. Effective January 1, 2010, however, the SEC is adopting revisions to
its oil and gas reporting disclosures which are intended to provide investors
with a more meaningful and comprehensive understanding of oil and gas reserves,
which should help investors evaluate the relative value of oil and gas
companies. Oil and gas companies will be permitted, but not required, to
disclose probable reserves (i.e., reserves less likely to be recovered than
proved reserves, but as likely as not to be recovered) and possible reserves
(i.e., reserves less certain to be recovered than probable reserves).We also
caution you that the SEC has, in the past, viewed such probable and possible
reserve estimates as inherently unreliable and these estimates may be seen as
misleading to investors unless the reader is an expert in the natural gas and
oil industry. Unless you have such expertise, you should not place undue
reliance on these estimates. Potential investors should also be aware that such
“probable” and “possible” reserve estimates
will not be contained in any filing with the SEC, any “resale” or other registration
statement filed by us that offers or sells shares on behalf of purchasers of our
common stock and may have an impact on the valuation of the resale of the shares
until permitted by SEC rules. Except as required by applicable law, we undertake
no duty to update this information.
The
differential between the New York Mercantile Exchange, or NYMEX, or other
benchmark price of oil and natural gas and the wellhead price we receive could
have a material adverse effect on our results of operations, financial condition
and cash flows.
The
prices that we receive 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 Coffeyville Resources Refining and
Marketing, LLC (“Coffeyville”) through March 31, 2011 and may continue on a
month to month basis after that date, we cannot accurately predict future
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.
12
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:
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unexpected
operational events and/or
conditions;
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unusual
or unexpected geological
formations;
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reductions
in natural gas and oil prices;
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limitations
in the market for oil and natural
gas;
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adverse
weather conditions;
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facility
or equipment malfunctions;
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title
problems;
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natural
gas and oil quality issues;
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pipe,
casing, cement or pipeline
failures;
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natural
disasters;
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fires,
explosions, blowouts, surface cratering, pollution and other risks or
accidents;
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environmental
hazards, such as natural gas leaks, oil spills, pipeline ruptures and
discharges of toxic gases;
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compliance
with environmental and other governmental requirements;
and
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uncontrollable
flows of oil, natural gas or well
fluids.
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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:
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injury
or loss of life;
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severe
damage to and destruction of property, natural resources and
equipment;
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pollution
and other environmental damage;
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clean-up
responsibilities;
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regulatory
investigation and penalties;
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suspension
of our operations; and
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repairs
to resume operations.
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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.
13
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 December 31, 2009 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.
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:
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unable
to identify attractive acquisition candidates or negotiate acceptable
purchase contracts with them;
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unable
to obtain financing for these acquisitions on economically acceptable
terms; or
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outbid
by competitors.
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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.
14
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. 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:
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higher
than projected operating costs;
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lower-than-expected
production;
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longer
response times;
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higher
costs associated with obtaining
capital;
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unusual
or unexpected geological
formations;
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fluctuations
in natural gas and oil prices;
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regulatory
changes;
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shortages
of equipment; and
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lack
of technical expertise.
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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:
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the
validity of our assumptions about reserves, future production, revenues
and costs, including synergies;
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an
inability to integrate successfully the businesses we
acquire;
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a
decrease in our liquidity by using our available cash or borrowing
capacity to finance acquisitions;
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a
significant increase in our interest expense or financial leverage if we
incur additional debt to finance
acquisitions;
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the
assumption of unknown liabilities, losses or costs for which we are not
indemnified or for which our indemnity is
inadequate;
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the
diversion of management’s attention from other business
concerns;
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an
inability to hire, train or retain qualified personnel to manage the
acquired properties or assets;
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the
incurrence of other significant charges, such as impairment of goodwill or
other intangible assets, asset devaluation or restructuring
charges;
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unforeseen
difficulties encountered in operating in new geographic or geological
areas; and
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customer
or key employee losses at the acquired
businesses.
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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.
15
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
and will likely contract for the sale of our natural gas with one, or a small
number, of buyers if and when we resume operations on the Gas City Project. It
is not likely that there will be a large pool of available purchasers. If a key
purchaser were to reduce the volume of oil or natural gas it purchases from us,
our revenue and cash available for operations will decline to the extent we 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.
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.
16
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
approximately 30 and 165 barrels of oil per day that could result in both
realized and unrealized hedging losses. As of December 31, 2009 we have realized
losses of $165,116 and have unrealized losses of $2,485,706. 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 (Coffeyville 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 harm our business.
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.
17
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 may 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.
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:
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location
and density of wells;
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the
handling of drilling fluids and obtaining discharge permits for drilling
operations;
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accounting
for and payment of royalties on production from state, federal and Indian
lands;
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bonds
for ownership, development and production of natural gas and oil
properties;
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transportation
of natural gas and oil by
pipelines;
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operation
of wells and reports concerning operations;
and
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taxation.
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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.
18
Our
operations may expose us to significant costs and liabilities with respect to
environmental, operational safety and other matters.
We may
incur significant costs and liabilities as a result of environmental and safety
requirements applicable to our oil and natural gas exploration and production
activities. We may also be exposed to the risk of costs associated with Kansas
Corporation Commission requirements to plug orphaned and abandoned wells on our
oil and natural gas leases from wells previously drilled by third parties. In
addition, we may indemnify sellers or lessors of oil and natural gas properties
for environmental liabilities they or their predecessors may have created. These
costs and liabilities could arise under a wide range of federal, state and local
environmental and safety laws and regulations, including regulations and
enforcement policies, which have tended to become increasingly strict over time.
Failure to comply with these laws and regulations may result in the assessment
of administrative, civil and criminal penalties, imposition of cleanup and site
restoration costs, liens and to a lesser extent, issuance of injunctions to
limit or cease operations. In addition, claims for damages to persons or
property may result from environmental and other impacts of our
operations.
Strict,
joint and several liability may be imposed under certain environmental laws,
which could cause us to become liable for the conduct of others or for
consequences of our own actions that were in compliance with all applicable laws
at the time those actions were taken. New laws, regulations or enforcement
policies could be more stringent and impose unforeseen liabilities or
significantly increase compliance costs. If we are not able to recover the
resulting costs through insurance or increased revenues, our ability to operate
effectively could be adversely affected.
Our
facilities and activities could be subject to regulation by the Federal Energy
Regulatory Commission or the Department of Transportation, which could take
actions that could result in a material adverse effect on our financial
condition.
Although
it is anticipated that our natural gas gathering systems will be exempt from
FERC and DOT regulation, any revisions to this understanding may affect our
rights, liabilities, and access to midstream or interstate natural gas
transportation, which could have a material adverse effect on our operations and
financial condition. In addition, the cost of compliance with any revisions to
FERC or DOT rules, regulations or requirements could be substantial and could
adversely affect our ability to operate in an economic manner. Additional FERC
and DOT rules and legislation pertaining to matters that could affect our
operations are considered and adopted from time to time. We cannot predict what
effect, if any, such regulatory changes and legislation might have on our
operations, but we could be required to incur additional capital expenditures
and increased costs.
Although
our natural gas sales activities are not currently projected to be subject to
rate regulation by FERC, if FERC finds that in connection with making sales in
the future, we (i) failed to comply with any applicable FERC administered
statutes, rules, regulations or orders, (ii) engaged in certain fraudulent acts,
or (iii) engaged in market manipulation, we could be subject to substantial
penalties and fines of up to $1.0 million per day per violation.
We
operate in a highly competitive environment and our competitors may have greater
resources than us.
The
natural gas and oil industry is intensely competitive and we compete with other
companies, many of which are larger and have greater financial, technological,
human and other resources. Many of these companies not only explore for and
produce crude oil and natural gas but also carry on refining operations and
market petroleum and other products on a regional, national or worldwide basis.
Such companies may be able to pay more for productive natural gas and oil
properties and exploratory prospects or define, evaluate, bid for and purchase a
greater number of properties and prospects than our financial or human resources
permit. In addition, such companies may have a greater ability to continue
exploration activities during periods of low oil and natural gas market prices.
Our ability to acquire additional properties and to discover reserves in the
future will be dependent upon our ability to evaluate and select suitable
properties and to consummate transactions in a highly competitive environment.
If we are unable to compete, our operating results and financial position may be
adversely affected.
19
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 SEC issued new regulations for oil
and gas reserve reporting which go into effect effective for fiscal years ending
on or after December 31, 2009. One of the key elements of the
new regulations relate to the commodity prices which are used to calculate
reserves and their present value. The new regulations provide for
disclosure of oil and gas reserves evaluated using annual average prices based
on the prices in effect on the first day of each month rather than the current
regulations which utilize commodity prices on the last day of the
year.
There was
no impairment for the fiscal year ended March 31, 2008. We recorded
an impairment of $4,777,723 during the fiscal year ended March 31, 2009
primarily attributable to lower prices for both oil and natural gas at December
31, 2008.
Our
success depends on our key management and professional personnel, including C.
Stephen Cochennet, the loss of whom would harm our ability to execute our
business plan.
Our
success depends heavily upon the continued contributions of C. Stephen
Cochennet, whose knowledge, leadership and technical expertise would be
difficult to replace, and on our ability to retain and attract experienced
engineers, geoscientists and other technical and professional staff. We have
entered into an employment agreement with Mr. Cochennet, and we maintain $1.0
million in key person insurance on Mr. Cochennet. However, if we were to lose
his services, our ability to execute our business plan would be harmed and we
may be forced to significantly alter our operations until such time as we could
hire a suitable replacement for Mr. Cochennet.
Risks
Associated with our Debt Financing
Significant
and prolonged declines in commodity prices may negatively impact our borrowing
base and our ability to borrow overall.
It is
possible that 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, may be reduced when it is reviewed. A reduction in our
base could result in a “loan
excess” which would be 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 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 reduce our capital expenditures and
our operating activities.
Until
we repay the full amount of our outstanding debentures and Credit Facility, we
may continue to have substantial indebtedness, which is secured by substantially
all of our assets.
On
December 31, 2009, $2.39 million in debentures and approximately $6.75 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. An event of default under the Credit
Facility permits Texas Capital to accelerate repayment of all amounts due and to
terminate the commitments thereunder. Any event of default which results in such
acceleration under the Credit Facility would also result in an event of default
under our Debentures. 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.
20
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
December 31, 2009, we had total indebtedness of $9.2 million, including $6.75
million of borrowings under the Credit Facility and $2.39 million of remaining
debentures, as well as other notes payable totaling approximately $75,000. We
had no outstanding letters of credit under the facility on December 31,
2009. Our substantial indebtedness, and the related interest expense,
could have important consequences to us, including:
|
·
|
limiting
our ability to borrow additional amounts for working capital, capital
expenditures, debt service requirements, execution of our business
strategy, or other general corporate
purposes;
|
|
·
|
being
forced to use cash flow to reduce our outstanding balance as a result of
an unfavorable borrowing base
redetermination;
|
|
·
|
limiting
our ability to use operating cash flow in other areas of our business
because we must dedicate a substantial portion of these funds to service
our indebtedness;
|
|
·
|
increasing
our vulnerability to general adverse economic and industry
conditions;
|
|
·
|
placing
us at a competitive disadvantage as compared to our competitors that have
less leverage;
|
|
·
|
limiting
our ability to capitalize on business opportunities and to react to
competitive pressures and changes in government
regulation;
|
|
·
|
limiting
our ability to, or increasing the cost of, refinancing our
indebtedness; and
|
|
·
|
limiting
our ability to enter into marketing, hedging, optimization and trading
transactions by reducing the number of counterparties with whom we can
enter into such transactions as well as the volume of those
transactions.
|
The
covenants in our Credit Facility and debentures impose significant operating and
financial restrictions on us.
The
Credit Facility and our debentures impose significant operating and financial
restrictions on us. These restrictions limit our ability and the ability of our
subsidiaries, among other things, to:
|
·
|
incur
additional indebtedness and provide additional
guarantees;
|
|
·
|
pay
dividends and make other restricted
payments;
|
|
·
|
create
or permit certain liens;
|
|
·
|
use
the proceeds from the sales of our oil and natural gas
properties;
|
|
·
|
use
the proceeds from the unwinding of certain financial
hedges;
|
|
·
|
engage
in certain transactions with affiliates;
and
|
|
·
|
consolidate,
merge, sell or transfer all or substantially all of our assets or the
assets of our subsidiaries.
|
The
Credit Facility and our debentures also contain various affirmative covenants
with which we are required to comply. We obtained a waiver of default
from Texas Capital Bank on two technical covenants at March 31, 2009 and one at
June 30, 2009. We were not in compliance with working capital ratio
covenant at December 31, 2009; however, we were able to obtain a waiver of
default from TCB. A copy of this waiver is incorporated by reference
in this document and is filed as Exibit 10.18 to the Form 10-Q filed on February
16, 2010. We are taking steps in an effort to comply with these same
covenants in future quarters, including but not limited to, a reduction in
principal of approximately $4 million since November 2008, and the reduction of
our operating and general expenses. We may be unable to comply with
some or all of these covenants in the future as well. If we do not comply with
these covenants and are unable to obtain waivers from our lenders, we would be
unable to make additional borrowings under these facilities, our indebtedness
under these agreements would be in default and could be accelerated by our
lenders. In addition, it could cause a cross-default under our other
indebtedness, including our debentures. If our indebtedness is accelerated, we
may not be able to repay our indebtedness or borrow sufficient funds to
refinance it. In addition, if we incur additional indebtedness in the future, we
may be subject to additional covenants, which may be more restrictive than those
to which we are currently subject.
21
Risks
Associated with our Common Stock and the Offering
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.
There
are substantial risks associated with the Standby Equity Distribution Agreement
with Paladin, which could contribute to the decline of our stock price and have
a dilutive impact on our existing stockholders.
The sale
of shares of our common stock pursuant to the SEDA will have a dilutive impact
on our stockholders. Paladin may re-sell all of the shares we issue to them
under the SEDA and such sales could cause the market price of our common stock
to decline significantly with advances under the SEDA. To the extent of any such
decline, any subsequent advances would require us to issue a greater number of
shares of common stock to Paladin in exchange for each dollar of the advance.
Under these circumstances, our existing stockholders would experience greater
dilution. If we were to fully draw down the commitment amount under the SEDA, we
would have to issue approximately 26.1% of our currently outstanding
shares. Although Paladin is precluded from short sales, the sale of
our common stock under the SEDA could encourage short sales by third parties,
which could contribute to the further decline of our stock price.
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.OB,” but trading
has been minimal. Therefore, the market for our common stock is limited. The
trading price of our common stock could be subject to wide fluctuations.
Investors may not be able to purchase additional shares or sell their shares
within the time frame or at a price they desire.
The
price of our common stock may be volatile and you may not be able to resell your
shares at a favorable price.
Regardless
of whether an active trading market for our common stock develops, the market
price of our common stock may be volatile and you may not be able to resell your
shares at or above the price you paid for such shares. The following factors
could affect our stock price:
|
·
|
our
operating and financial performance and
prospects;
|
|
·
|
quarterly
variations in the rate of growth of our financial indicators, such as net
income per share, net income 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
|
22
|
·
|
domestic
and international economic, legal and regulatory factors unrelated to our
performance.
|
Future
sales of our common stock may result in a decrease in the market price of our
common stock, even if our business is doing well.
The
market price of our common stock could drop due to sales of a large number of
shares of our common stock in the market or the perception that such sales could
occur. This could make it more difficult to raise funds through future offerings
of common stock.
As of
February 22, 2010, we have outstanding 4,979,928 shares of our common stock.
This does not include the 1,390,000 shares being sold by the Selling Stockholder
in this offering, which may be resold from time to time in the public market
following an advance notice by us. The 77,500 shares of our common
stock that are subject to outstanding warrants and convertible securities as of
August 31, 2009 will be eligible for sale in the public market to the extent
permitted by the provisions of applicable securities laws. If these additional
shares are sold, or it is perceived they will be sold, the trading price of our
common stock could decline. These sales also might make it more difficult for us
to sell equity or equity-related securities in the future at a time and price
that we deem reasonable or appropriate.
Our
articles of incorporation, bylaws and Nevada Law contain provisions that could
discourage an acquisition or change of control of us.
Our
articles of incorporation authorize our board of directors to issue preferred
stock and common stock without stockholder approval. If our board of directors
elects to issue preferred stock, it could be more difficult for a third party to
acquire control of us. In addition, provisions of the articles of incorporation
and bylaws could also make it more difficult for a third party to acquire
control of us. In addition, Nevada’s “Combination with Interested
Stockholders’ Statute” and its “Control Share Acquisition
Statute” may have the effect in the future of delaying or making it more
difficult to effect a change in control of us.
These
statutory anti-takeover measures may have certain negative consequences,
including an effect on the ability of our stockholders or other individuals to
(i) change the composition of the incumbent board of directors; (ii) benefit
from certain transactions which are opposed by the incumbent board of directors;
and (iii) make a tender offer or attempt to gain control of us, even if such
attempt were beneficial to us and our stockholders. Since such measures may also
discourage the accumulations of large blocks of our common stock by purchasers
whose objective is to seek control of us or have such common stock repurchased
by us or other persons at a premium, these measures could also depress the
market price of our common stock. Accordingly, our stockholders may be deprived
of certain opportunities to realize the “control premium” associated
with take-over attempts.
We
have no plans to pay dividends on our common stock. You may not receive funds
without selling your stock.
We do not
anticipate paying any cash dividends on our common stock in the foreseeable
future. We currently intend to retain future earnings, if any, to finance the
expansion of our business. Our future dividend policy is within the discretion
of our board of directors and will depend upon various factors, including our
business, financial condition, results of operations, capital requirements,
investment opportunities and restrictions imposed by our debentures and Credit
Facility.
We
may issue shares of preferred stock with greater rights than our common
stock.
Although
we have no current plans, arrangements, understandings or agreements to issue
any preferred stock, our articles of incorporation authorizes our board of
directors to issue one or more series of preferred stock and set the terms of
the preferred stock without seeking any further approval from our stockholders.
Any preferred stock that is issued may rank ahead of our common stock, with
respect to dividends, liquidation rights and voting rights, among other
things.
23
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.
Because
our common stock may be 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 may be deemed to be a penny stock, as defined in Rule 3a51-1 under
the Securities Exchange Act, which may make it more difficult for investors to
liquidate their investment even if and when a market develops for the common
stock. Until the trading price of the common stock consistently trades above
$5.00 per share, if ever, trading in the common stock may be subject to the
penny stock rules of the Securities Exchange Act specified in rules 15g-1
through 15g-10. Those rules require broker-dealers, before effecting
transactions in any penny stock, to:
|
·
|
Deliver
to the customer, and obtain a written receipt for, a disclosure
document;
|
|
·
|
Disclose
certain price information about the
stock;
|
|
·
|
Disclose
the amount of compensation received by the broker-dealer or any associated
person of the broker-dealer;
|
|
·
|
Send
monthly statements to customers with market and price information about
the penny stock; and
|
|
·
|
In
some circumstances, approve the purchaser’s account under certain
standards and deliver written statements to the customer with information
specified in the rules.
|
Consequently,
the penny stock rules may restrict the ability or willingness of broker-dealers
to sell the common stock and may affect the ability of holders to sell their
common stock in the secondary market and the price at which such holders can
sell any such securities. These additional procedures could also limit our
ability to raise additional capital in the future.
If
we fail to remain current on our reporting requirements, we could be removed
from the OTC Bulletin Board, which would limit the ability of broker-dealers to
sell our securities and the ability of stockholders to sell their securities in
the secondary market.
Companies
trading on the OTC Bulletin Board, such as us, must be reporting issuers under
Section 12 of the Securities Exchange Act of 1934, as amended, and must be
current in their reports under Section 13, in order to maintain price quotation
privileges on the OTC Bulletin Board. More specifically, FINRA has enacted
Rule 6530, which determines eligibility of issuers quoted on the OTC Bulletin
Board by requiring an issuer to be current in its filings with the
Commission. Pursuant to Rule 6530(e), if we file our reports late with the
Commission three times in a two-year period or our securities are removed from
the OTC Bulletin Board for failure to timely file twice in a two-year period
then we will be ineligible for quotation on the OTC Bulletin
Board. As a result, the market liquidity for our securities could be
severely adversely affected by limiting the ability of broker-dealers to sell
our securities and the ability of stockholders to sell their securities in the
secondary market.
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.
24
SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This
prospectus 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 prospectus, 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
prospectus, which may cause our or our industry’s actual results, levels of
activity, performance or achievements to be materially different from any future
results, levels of activity, performance or achievements expressed or implied by
these forward-looking statements. Moreover, we operate in a very competitive and
rapidly changing environment. New risks emerge from time to time and it is not
possible for us to predict all risk factors, nor can we address the impact of
all factors on our business or the extent to which any factor, or combination of
factors, may cause our actual results to differ materially from those contained
in any forward-looking statements. The factors impacting these risks and
uncertainties include, but are not limited to:
|
·
|
inability
to attract and obtain additional development
capital;
|
|
·
|
inability
to achieve sufficient future sales levels or other operating
results;
|
|
·
|
inability
to efficiently manage our
operations;
|
|
·
|
potential
default under our secured obligations or material debt
agreements;
|
|
·
|
estimated
quantities and quality of oil and natural gas
reserves;
|
|
·
|
declining
local, national and worldwide economic
conditions;
|
|
·
|
fluctuations
in the price of oil and natural
gas;
|
|
·
|
the
inability of management to effectively implement our strategies and
business plans;
|
|
·
|
approval
of certain parts of our operations by state
regulators;
|
|
·
|
inability
to hire or retain sufficient qualified operating field
personnel;
|
|
·
|
increases
in interest rates or our cost of
borrowing;
|
|
·
|
deterioration
in general or regional (especially Eastern Kansas) economic
conditions;
|
|
·
|
occurrence
of natural disasters, unforeseen weather conditions, or other events or
circumstances that could impact our operations or could impact the
operations of companies or contractors we depend upon in our
operations;
|
|
·
|
inability
to acquire mineral leases at a favorable economic value that will allow us
to expand our development efforts;
|
|
·
|
adverse
state or federal legislation or regulation that increases the costs of
compliance, or adverse findings by a regulator with respect to existing
operations; and
|
|
·
|
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 prospectus. Before you invest in our common
stock, you should be aware that the occurrence of the events described in the
section entitled “Risk
Factors” and elsewhere in this prospectus could negatively affect our
business, operating results, financial condition and stock price. 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 prospectus to conform our
statements to actual results or changed expectations.
USE
OF PROCEEDS
Paladin
is selling all of the shares of our common stock covered by this prospectus for
its own account. Accordingly, we will not receive any proceeds from the sale of
shares by Paladin. All net proceeds from the sale of the common stock covered by
this prospectus will go to Paladin. We will bear all expenses of registration
incurred in connection with this offering, including filing fees, printing fees,
and expenses of our legal counsel and other experts, but all selling and other
expenses incurred by the Selling Stockholder will be borne by the Selling
Stockholder. However, we will receive proceeds from any sale of shares of common
stock to Paladin pursuant to the SEDA.
25
For each
share of common stock purchased under the SEDA, Paladin will pay a percentage of
the lowest daily volume weighted average closing price during the five
consecutive trading days after we provide notice to Paladin based on the
following:
|
·
|
85%
of the market price for the initial two
advances,
|
|
·
|
90%
of the market price to the extent the Common Stock is trading below $1.00
per share during the pricing
period,
|
|
·
|
92%
of the market price to the extent the Common Stock is trading at or above
$1.00 per share during the pricing period,
or
|
|
·
|
95%
of the market price to the extent the Common Stock is trading at or above
$2.00 per share during the pricing
period.
|
Each such
advance may be for an amount that is the greater of $40,000 or 20% the average
daily trading volume of our common stock for the five consecutive trading days
prior to the notice date. However, our initial two advances under the SEDA may
be for up to $55,000.
We
anticipate, and have represented to Paladin in the SEDA, that the proceeds
received under the SEDA will be utilized for working capital and general
corporate purposes.
DIVIDEND
POLICY
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.
CAPITALIZATION
You
should read this capitalization table in conjunction with “Management’s Discussion and Analysis
of Financial Condition and Results of Operations” and our financial
statements and related notes included elsewhere in this prospectus.
The
following table sets forth our capitalization as of December 31,
2009.
As of
December 31, 2009 |
||||
Actual
|
||||
(Unaudited)
|
||||
Stockholders’
equity:
|
||||
Common
stock; $0.001 par value, 100,000,000 shares authorized,
4,910,660 issued and outstanding
|
4,911 | |||
Common
stock owed but not issued
|
186 | |||
Additional
paid-in capital
|
9,543,360 | |||
Retained
(deficit)
|
(15,870,074 | ) | ||
Total
stockholders’ equity (deficit)
|
(6,321,617 | ) | ||
Total
capitalization
|
(6,321,617 | ) |
26
The
information in the table above excludes:
|
·
|
2,500
shares issuable upon conversion of an unsecured $25,000 6% convertible
note due August 2, 2010, which is convertible into shares of our common
stock at $10.00 per share; and
|
|
·
|
75,000
shares of our common stock issuable upon the exercise of outstanding
warrants, at an exercise price of $3.00 per share, that were issued to the
placement agent in connection with the private placement of $9.0 million
of debentures in April 2007.
|
PRICE
RANGE OF COMMON STOCK
Prior to
completion of the reverse merger with Midwest Energy in August 2006, our common
stock was sporadically traded in the inter-dealer markets of the OTC:BB, “pink sheets” and “gray sheets” under the symbol
“MPCO.” As of March 23,
2007, our common stock commenced trading on the OTC:BB under the symbol “EJXR.OB.” On July
28, 2008, in conjunction with the implementation of the 1-for-5 reverse stock
split of all of our common stock, our trading symbol on the OTC:BB changed to
ENRJ.OB. Our common stock has traded infrequently on the OTC:BB,
which limits our ability to locate accurate high and low bid prices for each
quarter within the last two fiscal years. Therefore, the following table lists
the quotations for the high and low bid prices as reported by a Quarterly Trade
and Quote Summary Report of the OTC Bulletin Board and Yahoo! Finance for fiscal
years 2008 and 2009, the first, second and third quarters of fiscal year 2010.
The quotations reflect inter-dealer prices without retail mark-up, markdown, or
commissions and may not represent actual transactions.
Low
|
High
|
|||||||
Fiscal
2008
|
||||||||
Quarter
ended June 30, 2007
|
$ | 5.00 | $ | 6.25 | ||||
Quarter
ended September 30, 2007
|
$ | 3.75 | $ | 6.75 | ||||
Quarter
ended December 31, 2007
|
$ | 3.50 | $ | 6.00 | ||||
Quarter
ended March 31, 2008
|
$ | 4.05 | $ | 6.00 | ||||
Fiscal
2009
|
||||||||
Quarter
ended June 30, 2008
|
$ | 4.80 | $ | 5.90 | ||||
Quarter
ended September 30, 2008
|
$ | 4.00 | $ | 5.10 | ||||
Quarter
ended December 31, 2008
|
$ | 0.45 | $ | 3.16 | ||||
Quarter
ended March 31, 2009
|
$ | 0.25 | $ | 1.88 | ||||
Fiscal
2010
|
||||||||
Quarter
ended June 30, 2009
|
$ | 0.15 | $ | 1.34 | ||||
Quarter
ending September 30, 2009
|
$ | 0.15 | $ | 1.85 | ||||
Quarter
ending December 31, 2009
|
$ | 0.41 | $ | 1.00 |
The last
reported sale price of our common stock on the OTC:BB was $1.03 per share on
March 3 , 2010. As of February 22, 2009, there were approximately 1,135 holders
of record of our common stock.
27
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The
following discussion of our financial condition and results of operations should
be read in conjunction with our financial statements and the related notes to
our financial statements included elsewhere in this prospectus. 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 “Risk Factors” and elsewhere in this
prospectus.
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, 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.
Since the
beginning of fiscal 2008, we have deployed approximately $12 million in capital
resources to acquire and develop five operating projects and drill 179 new wells
(111 producing wells, 65 water injection wells, and 3 dry holes). Our estimated
total proved PV 10 (present value) of reserves as of March 31, 2009 was $10.63
million, versus $39.6 million as of March 31, 2008. We held estimated
total proved reserves of 1.3 million barrels of oil equivalent, or BOE, as of
March 31, 2009. Though total estimated proved reserves were
comparable at March 31, 2009 and 2008; 1.3 million and 1.4 million BOE,
respectively, the PV10 declined dramatically due to the estimated average price
of oil at March 31, 2009 of $42.65 versus $94.53 at March 31,
2008. Of the 1.3 million BOE of total estimated proved reserves,
approximately 39% are proved developed and approximately 61% are proved
undeveloped. The proved developed reserves consist of 82% proved developed
producing reserves and 18% proved developed non-producing reserves.
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.
In response to economic conditions and
capital market constraints, we are exploring and evaluating 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 via
additional debt or equity raising, 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.
We
entered into a joint venture in June 2009 on the Brownrigg (“Brownrigg”) lease in Linn
County, Kansas with Pharyn Impact Growth Fund, LP (“Pharyn”). The
initial development funding on this lease was completed as of January 1, 2010.
We have resumed development and completion activities on Brownrigg and
anticipate production to begin in the quarter ending March 31,
2010.
28
The board
of directors has implemented a crude oil and natural gas hedging strategy that
will allow management to hedge up to 80% of our net production to mitigate a
majority of our exposure to changing oil prices in the intermediate
term.
Recent
Developments
We entered into an agreement with Shell
Trading (US) Company, or Shell, whereby we agreed to an 18-month fixed-price
swap with Shell for 130 BOPD at a fixed price per barrel of $96.90, before
transportation costs from April 1, 2008 through September 30, 2009. This
represented approximately 60% of our total oil production on a net revenue basis
at that time and locked in approximately $6.8 million in gross revenue before
transportation costs over the 18 month period. In addition, we agreed to sell
all of our remaining oil production at current spot market pricing beginning
April 1, 2008 through September 30, 2009 to Shell. Through September
30, 2009, the positive impact on our net revenue from the fixed-price swap was
approximately $787,000.
On July 3, 2008, EnerJex, EnerJex
Kansas, and DD Energy entered into a three-year $50 million Senior Secured
Credit Facility (the “Credit
Facility”) with Texas Capital Bank, N.A. Borrowings under the
Credit Facility will be subject to a borrowing base limitation based on our
current proved oil and gas reserves and will be subject to semi-annual
redeterminations and interim adjustments. The initial borrowing base
was set at $10.75 million and was reduced to $7.428 million following the
liquidation of the BP hedging instrument in November 2008. The
Borrowing Base was most recently reviewed by Texas Capital Bank in January 2010
and it was determined that it should be reduced by $55,000 per month beginning
February 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 unpaid principal and interest will be due and payable in
full on July 3, 2011. The Credit Facility also provides for the
issuance of letters-of-credit up to a $750,000 sub-limit under the borrowing
base and up to an additional $2.25 million limit not subject to the borrowing
base to support our hedging program. We had borrowings $7.328 million
outstanding at March 31, 2009 and $6.746 million at December 31,
2009.
As of July 3, 2008, we entered into an
ISDA master agreement and a costless collar with BP Corporation North America
Inc., or BP, for 130 barrels of oil per day with a price floor of $132.50 per
barrel and a price ceiling of $155.70 per barrel for NYMEX West Texas
Intermediate for the period of October 1, 2009 until March 31,
2011. We liquidated this costless collar in November 2008 and
received proceeds of approximately $3.9 million from BP. We reduced
the debt outstanding under our Credit Facility by approximately $3.3 million and
used the remainder for general operating purposes.
On July
7, 2008, we amended the $2.7 million of aggregate principal amount of our 10%
debentures that remain outstanding to, among other things, permit the
indebtedness under our Credit Facility, subordinate the security interests of
the debentures to the Credit Facility, provide for the redemption of the
remaining debentures with the net proceeds from any next debt or equity
offering, eliminate the covenant to maintain certain production thresholds and
waive all known defaults. Subsequent to year-end, we again amended
the debentures to extend the maturity date to September 30, 2010, and allow us
to pay interest in either cash or payment-in-kind interest (an increase in the
amount of principal due) or pay interest through the issuance of shares of
common stock, and add a provision for the conversion of the debentures into
shares of our common stock. Further, in November of 2009, we amended
the debentures to amend the company redemption section of the debentures to
allow for the retirement of shares of our common stock held by the debenture
holders if we meet certain redemption payment schedules and to amend the
debenture holders’ rights to participate in certain future debt or equity
offerings made by us. We repurchased $450,000 of the Debentures during the nine
months ended December 31, 2009 at a gain of $406,500. We also
redeemed an additional $150,000 of the Debentures during the quarter ended
December 31, 2009 for $150,000 in cash. No gain or loss resulted from
this $150,000 redemption. 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.
On August 1, 2008, we executed
three-year employment agreements with C. Stephen Cochennet, our chief executive
officer, and Dierdre P. Jones, our chief financial officer. Mr.
Cochennet and Ms. Jones have agreed to amend their employment agreements to
reflect options rescinded in November 2008.
29
Euramerica
failed to fully fund by January 15, 2009 both the balance of the purchase price
and the remaining development capital owed under the Amended and Restated Well
Development Agreement and Option for “Gas City Property” between us
and Euramerica. Therefore, Euramerica has forfeited all of its
interest in the property, including all interests in any wells, improvements or
assets, and all of Euramerica's interest in the property reverts back to
us. In addition, all operating agreements between us and Euramerica
relating to the Gas City Project are null and void.
In February 2009, we entered into a
fixed price swap transaction under the terms of the BP ISDA for a total of
120,000 gross barrels at a price of $57.30 per barrel before transportation
costs for the period beginning October 1, 2009 and ending on December 31,
2013.
On March 3, 2009, we withdrew our Form
S-1 Registration Statement after deciding to terminate the registered public
offering. As global economic conditions deteriorated and the
commodity prices of oil and natural gas experienced significant declines, the
availability of equity capital became severely constrained. While we
intend to return to the equity market when conditions improve and are conducive
to raising capital, there can be no assurance that we will be successful in
doing so.
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.
In April
and May of 2009, we repurchased a total of $450,000 of the subordinated
debentures. The principal balance remaining as of December 31, 2009
is approximately $2.39 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.
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 date); 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
Janauary 1, 2010 redetermination.
30
On August
25, 2009 we entered into a fixed price swap transaction under the terms of the
BP ISDA for 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.
Also 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 and Paladin entered into a Standby Equity Distribution
Agreement, or SEDA, pursuant to which, for a two-year period, we have the right
to sell up to 1,300,000 shares of our common stock to Paladin at any
time.
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. See Note 8 to our December 31, 2009 Unaudited Condensed
Consolidated Financial Statements in this report.
Results
of Operations for the Fiscal Years Ended March 31, 2009 and 2008
compared.
We began
acquiring oil properties with existing production in April of 2007, the first
month of our fiscal year ended March 31, 2008. These acquisitions
included the Black Oaks and Thoren Projects. We acquired both the DD
Energy and the Tri-County Projects in November of 2007, or about mid-year of
that same fiscal year. We owned these projects throughout the entire
fiscal year ended March 31, 2009. Comparisons between the fiscal
years, then, will reflect a full year of revenues and expenses for all projects
for the fiscal year ended March 31, 2009 and a partial year of revenues and
expenses for the two of the four projects for the fiscal year ended March 31,
2008.
Income:
Fiscal Year Ended
March 31,
|
||||||||||||
2009
|
2008
|
Increase / (Decrease)
|
||||||||||
Amount
|
Amount
|
$
|
||||||||||
Oil
and natural gas revenues
|
$ | 6,436,805 | $ | 3,602,798 | $ | 2,834,007 |
Revenues
Oil and
natural gas revenues for the fiscal year ended March 31, 2009 were $6,436,805
compared to revenues of $3,602,798 in the fiscal year ended March 31, 2008. The
increase in revenues is primarily the result of the greater oil production
levels as well as a higher average price per barrel of oil. The
average price per barrel we received for oil sold during the twelve months ended
March 31, 2009 was $85.67 compared to $79.71 for the twelve months ended March
31, 2008. Natural gas sales accounted for less than 1% of the total revenues.
The average price per Mcf for natural gas sales during the fiscal year ended
March 31, 2009 was $5.57, compared to $6.20 during the fiscal year ended March
31, 2008.
31
Expenses:
Fiscal
Year Ended
March
31,
|
||||||||||||
2009
|
2008
|
Increase
/ (Decrease)
|
||||||||||
Amount
|
Amount
|
$
|
||||||||||
Expenses:
|
||||||||||||
Direct
operating costs
|
$ | 2,637,333 | $ | 1,795,188 | $ | 842,145 | ||||||
Depreciation,
depletion and amortization
|
872,230 | 913,224 | (40,994 | ) | ||||||||
Total
production expenses
|
3,509,563 | 2,708,412 | 801,151 | |||||||||
Professional
fees
|
1,320,332 | 1,226,998 | 93,334 | |||||||||
Salaries
|
849,340 | 1,703,099 | (853,759 | ) | ||||||||
Depreciation
on other fixed assets
|
39,063 | 22,106 | 16,957 | |||||||||
Administrative
expenses
|
1,392,645 | 887,872 | 504,773 | |||||||||
Impairment
of oil & gas properties
|
4,777,723 | - | 4,777,723 | |||||||||
Total
expenses
|
$ | 11,888,666 | $ | 6,548,487 | $ | 5,340,179 |
Direct
Operating Costs
Direct
operating costs for the fiscal year ended March 31, 2009 were $2,637,333
compared to $1,795,188 for the fiscal year ended March 31, 2008. The increase
over the prior period results from the operating costs on a greater number of
wells on our existing and acquired oil leases during the fiscal year ended March
31, 2009. Direct operating costs include pumping, gauging, pulling, repairs,
certain contract labor costs, and other non-capitalized
expenses.
Depreciation, Depletion and
Amortization
Depreciation,
depletion and amortization for the fiscal year ended March 31, 2009 was
$872,230, compared to $913,224 for the fiscal year ended March 31, 2008. The
decrease was primarily a result of the lower cost per barrel of depletion of oil
reserves. The rate of depletion was $12.02 per barrel for the fiscal
year ended March 31, 2009 as compared to $19.57 per barrel for the fiscal year
ended March 31, 2008.
Professional
Fees
Professional
fees for the fiscal year ended March 31, 2009 were $1,320,332 compared to
$1,226,998 for the fiscal year ended March 31, 2008. Payments for services
rendered in connection with acquisition and financing activities, our audit,
legal, and consulting fees are recorded as professional fees and remained
relatively constant over the two fiscal years.
Salaries
Salaries
for the fiscal year ended March 31, 2009 were $849,340 compared to $1,703,099
for the fiscal year ended March 31, 2008. There were expenses totaling
$1,204,102 during the prior fiscal year related to non-cash equity based
payments made by issuing stock options to our management. No such
issuances were made in the current fiscal year. In addition, the
number of full-time employees increased from 9 at March 31, 2008 to 19 at one
point during the fiscal year ended March 31, 2009, then settled at 14 on March
31, 2009. As a result, cash based salary expense increased by
approximately $500,000 during the current fiscal year.
Depreciation
on Other Fixed Assets
Depreciation on other fixed assets
fiscal year ended March 31, 2009 was $39,063 compared to $22,106 for the fiscal
year ended March 31, 2008. The increase was primarily due to
depreciation on fixed assets acquired during the period.
32
Administrative Expenses
Administrative
expenses for the fiscal year ended March 31, 2009 were $1,392,645 compared
to $887,872 in the fiscal year ended March 31, 2008. The administrative expenses
increased in relation to the addition of employees, office space, and corporate
activity related to growth in operations.
Impairment
of Oil & Gas Properties
The
impairment of oil and natural gas properties in the year ended March 31, 2009 of
$4,777,723 represented an impairment through applying the full-cost ceiling test
method. This ceiling test was applied to all of the cost of our oil
and natural gas properties accounted for under the full-cost method that were
subject to amortization at March 31, 2009. We took this impairment
based on the ceiling test results during the quarter ended December 31, 2008,
and was primarily due to depressed commodity prices at the time.
Reserves
Our
estimated total proved PV 10 (present value) of reserves as of March 31, 2009
decreased to $10.63 million from $39.6 million as of March 31, 2008. Though
total proved reserves were comparable at March 31, 2009 and 2008; 1.3 million
and 1.4 million barrels of oil equivalent (BOE), respectively, the PV10 declined
dramatically due to the estimated average price of oil at March 31, 2009 of
$42.65 versus $94.53 at March 31, 2008. Of the 1.3 million BOE at
March 31, 2009 approximately 39% are proved developed and approximately 61% are
proved undeveloped. The proved developed reserves consist of proved developed
producing (82%) and proved developed non-producing (18%).
The
following table presents summary information regarding our estimated net proved
reserves as of March 31, 2009. All calculations of estimated net proved reserves
have been made in accordance with the rules and regulations of the SEC, and,
except as otherwise indicated, give no effect to federal or state income taxes.
The estimates of net proved reserves are based on the reserve reports prepared
by Miller and Lents, Ltd., our independent petroleum consultants. For additional
information regarding our reserves, please see Note 11 to our audited financial
statements as of and for the fiscal year ended March 31, 2009.
Summary
of Proved Oil and Natural Gas Reserves
as
of March 31, 2009
Proved
Reserves Category
|
Gross
|
Net
|
PV10 (before tax)(1)
|
|||||||||
Proved,
Developed Producing
|
||||||||||||
Oil
(stock-tank barrels)
|
722,590 | 429,420 | $ | 6,691,550 | ||||||||
Natural
Gas (mcf)(2)
|
- | - | - | |||||||||
Proved,
Developed Non-Producing
|
||||||||||||
Oil
(stock-tank barrels)
|
146,620 | 95,560 | $ | 1,459,280 | ||||||||
Natural
Gas (mcf)
(2)
|
- | - | - | |||||||||
Proved,
Undeveloped
|
||||||||||||
Oil
(stock-tank barrels)
|
1,440,760 | 811,650 | $ | 2,478,510 | ||||||||
Natural
Gas (mcf)
(2)
|
- | - | - | |||||||||
Total
Proved Reserves
|
||||||||||||
Oil
(stock-tank barrels)
|
2,309,970 | 1,136,630 | $ | 10,629,340 | ||||||||
Natural
Gas (mcf)
(2)
|
- | - | - |
|
(1)
|
The
following table shows our reconciliation of our PV10 to our standardized
measure of discounted future net cash flows (the most direct comparable
measure calculated and presented in accordance with GAAP). PV10 is our
estimate of the present value of future net revenues from estimated proved
natural gas reserves after deducting estimated production and ad valorem
taxes, future capital costs and operating expenses, but before deducting
any estimates of future income taxes. The estimated future net revenues
are discounted at an annual rate of 10% to determine their “present value.” We
believe PV10 to be an important measure for evaluating the relative
significance of our oil and natural gas properties and that the
presentation of the non-GAAP financial measure of PV10 provides useful
information to investors because it is widely used by professional
analysts and sophisticated investors in evaluating oil and gas companies.
Because there are many unique factors that can impact an individual
company when estimating the amount of future income taxes to be paid, we
believe the use of a pre-tax measure is valuable for evaluating our
company. We believe that most other companies in the oil and gas industry
calculate PV10 on the same basis. PV10 should not be considered as an
alternative to the standardized measure of discounted future net cash
flows as computed under GAAP.
|
33
As of
March 31,
2009
|
||||
PV10
(before tax)
|
$ | 10,629,340 | ||
Future
income taxes, net of 10% discount
|
- | |||
Standardized
measure of discounted future net cash flows
|
$ | 10,629,340 |
|
(2)
|
There
were no natural gas reserves at March 31,
2009.
|
Results
of Operations for the Three Months and Nine Months Ended December 31, 2009 and
2008 compared.
Income:
Three
Months Ended
|
Increase
/
|
Nine
Months Ended
|
Increase
/
|
|||||||||||||||||||||
December
31,
|
(Decrease)
|
December
31,
|
(Decrease)
|
|||||||||||||||||||||
2009
|
2008
|
$
|
2009
|
2008
|
$
|
|||||||||||||||||||
Oil
and natural gas revenues
|
$ | 914,545 | $ | 1,184,547 | $ | (270,002 | ) | $ | 3,703,724 | $ | 4,652,289 | $ | (948,565 | ) |
Three
Months Ended
|
Increase
/
|
Nine
Months Ended
|
Increase
/
|
|||||||||||||||||||||
December
31,
|
(Decrease)
|
December
31,
|
(Decrease)
|
|||||||||||||||||||||
2009
|
2008
|
$
|
2009
|
2008
|
$
|
|||||||||||||||||||
Production
expenses:
|
||||||||||||||||||||||||
Direct
operating costs
|
$ | 448,684 | $ | 562,693 | $ | (114,009 | ) | $ | 1,313,518 | $ | 2,093,994 | $ | (780,476 | ) | ||||||||||
Depreciation,
depletion and amortization
|
131,394 | 277,020 | (145,626 | ) | 577,288 | 995,069 | (417,781 | ) | ||||||||||||||||
Impairment
of oil and gas properties
|
- | 4,777,723 | (4,777,723 | ) | - | 4,777,723 | (4,777,723 | ) | ||||||||||||||||
Total
production expenses
|
580,078 | 5,617,436 | (5,037,358 | ) | 1,890,806 | 7,866,786 | (5,975,980 | ) | ||||||||||||||||
General
expenses:
|
||||||||||||||||||||||||
Professional
fees
|
60,571 | 106,032 | (45,461 | ) | 479,710 | 400,816 | 78,894 | |||||||||||||||||
Salaries
|
153,022 | 200,547 | (47,525 | ) | 706,011 | 694,973 | 11,038 | |||||||||||||||||
Administrative
expense
|
334,512 | 238,726 | 95,786 | 789,827 | 1,065,308 | (275,481 | ) | |||||||||||||||||
Total
general expenses
|
548,105 | 545,305 | 2,800 | 1,975,548 | 2,161,097 | (185,549 | ) | |||||||||||||||||
Total
production and general expenses
|
1,128,183 | 6,162,741 | (5,034,558 | ) | 3,866,354 | 10,027,883 | (6,161,529 | ) | ||||||||||||||||
Other
income (expense)
|
||||||||||||||||||||||||
Interest
expense
|
(189,374 | ) | (205,327 | ) | 15,953 | (542,939 | ) | (743,372 | ) | 200,433 | ||||||||||||||
Loan
interest accretion
|
(153,374 | ) | (119,512 | ) | (33,862 | ) | (432,864 | ) | (2,686,892 | ) | 2,254,028 | |||||||||||||
Gain
on liquidation of hedging instrument
|
- | 3,879,050 | (3,879,050 | ) | - | 3,879,050 | (3,879,050 | ) | ||||||||||||||||
Unrealized
gain (loss) on derivative instruments
|
(2,485,706 | ) | - | (2,485,706 | ) | (2,485,706 | ) | - | (2,485,706 | ) | ||||||||||||||
Loan
fee expense
|
||||||||||||||||||||||||
Gain
on repurchase of debentures
|
- | - | 406,500 | - | 406,500 | |||||||||||||||||||
Management
fee revenue
|
23,944 | - | 23,944 | 99,234 | - | 99,234 | ||||||||||||||||||
Loss
on disposal of vehicle
|
(20,695 | ) | - | (20,695 | ) | (20,695 | ) | (4,421 | ) | (16,274 | ) | |||||||||||||
Total
other income (expense)
|
(2,825,205 | ) | 3,554,211 | (6,379,416 | ) | (2,976,470 | ) | 444,365 | 3,420,835 | |||||||||||||||
Net
income (loss)
|
$ | (3,038,843 | ) | $ | (1,423,983 | ) | $ | 1,614,860 | $ | (3,139,100 | ) | (4,931,229 | ) | $ | 1,792,129 |
34
Revenues
Oil and
natural gas revenues for the three months ended December 31, 2009 were $914,454
compared to revenues of $1,184,547 in the three months ended December 31, 2008.
The decrease in the three month revenues is due to the lower price of oil and to
lower sales volumes during the quarter ended December 31, 2009 as compared to
December 31, 2008. Oil and natural gas revenues for the nine months
ended December 31, 2009 were $3,703,724 and $4,652,289 in the nine months ended
December 31, 2008. The decrease in the nine month revenues is due to both lower
average oil prices and sales volumes in the current year as compared to the
prior year. The average price per barrel of oil, net of transportation costs,
sold during the three months ended December 31, 2009 was $69.34 compared to
$71.91 during the three months ended December 31, 2008 and was $76.64 for the
nine months ended December 31, 2009 compared to $89.97 for the nine months ended
December 31, 2008.
Expenses:
Direct
Operating Costs
Direct
operating costs for the three months ended December 31, 2009 were $448,684
compared to $562,693 for the three months ended December 31, 2008 and $1,313,518
compared to $2,093,994 for each of the nine months ended December 31, 2009 and
2008, respectively. The decrease in the current periods over the prior periods
results from personnel and cost reductions implemented to offset declining oil
and natural gas prices. Direct operating costs include pumping, gauging,
pulling, certain contract labor costs, and other non-capitalized
expenses.
Depreciation,
Depletion and Amortization
Depreciation,
depletion and amortization (DD&A) for the three and nine months ended
December 31, 2009 was $131,394 and $577,288, respectively, compared to $277,020
and $995,069 for the three and nine months ended December 31,
2008. The decreases were primarily a result of lower production in
the quarter and year to date periods ended December 31, 2009 versus the
comparable periods ended December 31, 2008. Costs of depletion per barrel of oil
reserves were also lower in 2009 than in 2008. The rate of depletion was $12.10
per barrel for the nine months ended December 31, 2009 as compared to $17.09 per
barrel for the nine months ended December 31, 2008. The per barrel
rate of depletion is equal to the total book value of oil and gas properties
plus future development costs associated with reserves divided by the net number
of barrels of such reserves. The decline in the rate is directly attributed to
the lower book value of the oil and gas properties at December 31, 2009 as
compared to December 31, 2008 following an impairment charge of nearly $4.8
million in December of 2008.
Impairment
of Oil and Gas Properties
We recorded a non-cash impairment of
$4,777,723 million to the carrying value of our proved oil and gas properties as
of December 31, 2008. 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.
35
Professional
Fees
Professional
fees for the three months ended December 31, 2009 were $60,571 compared to
$106,032 for the three months ended December 31, 2008, reflecting little
change. This compares to professional fees of $479,710 for the
nine months ended December 31, 2009 and $400,816 for the same period in 2008.
The decrease in professional fees in the three months ended December 31, 2009
versus December 31, 2008 results from cost reductions implemented to offset
declining oil and natural gas prices. The increase in professional fees in the
nine months ended December 31, 2009 over December 31, 2008 is due to both higher
costs incurred in connection with the fiscal year end reserve evaluations
performed by a new independent reserve engineer, as well as non-cash charges for
restricted stock issued to non-employees for options cancelled in August
2009.
Salaries
Salaries
for the three months ended December 31, 2009 were $153,022 compared to $200,547
for the three months ended December 31, 2008. There were fewer employees at
December 31, 2009 versus December 31, 2008, which is primarily the cause of the
decline. Additionally, salaries for the nine month periods ended
December 31, 2009 and 2008 were $706,011 and $694,973,
respectively. The effect of the decrease in the number of employees
referred to above is offset by non-cash charges for restricted stock issued to
employees for both options cancelled, and accrued, but un-paid employee
incentives in August 2009.
Administrative
Expense
Administrative
expense for the three and nine months ended December 31, 2009 was $334,512 and
$789,827, compared to $238,726 in the three months ended December 31, 2008 and
$1,065,308 in the nine months ended December 31, 2008. The administrative
expense increased in the quarter ended December 31, 2009 over the quarter ended
December 31, 2008 due to (a) printing expenses totaling $60,000 which were paid
in October 2009; (b) approximately $27,000 of bank fees associated with the
Credit Facility; and (c) increases in auto expenses, depreciation on office
equipment, and insurance. The administrative expense in the prior period ended
December 31, 2008 contained significant public and investor relations expenses
as well as travel related costs incurred in connection with the road show for a
public offering that was subsequently cancelled, explaining the decrease in the
nine month period ended December 31, 2009.
Interest
Expense
Interest
expense for the three and nine months ended December 31, 2009 was $189,374 and
$542,939, whereas interest expense for the three and nine months ended December
31, 2008 was $205,327 and $743,372. Interest expense was primarily related to
our debentures and our Credit Facility. See Note 7 to our Condensed
Consolidated Financial Statements in this report.
Loan
Interest Accretion
Loan
Interest Accretion for the three and nine months ended December 31, 2009 was
$153,374 and $432,864, whereas loan interest accretion for the three and nine
months ended December 31, 2008 was $119,512 and $2,686,892. The amount of
interest accreted is based on the interest method over the period of issue to
maturity or redemption. A proportionate share of the loan costs were
expensed upon redemption of $6.3 of the $9.0 million debentures in July of 2008,
accounting for the significantly higher amount in the nine month period ended
December 31, 2008 as compared to December 31, 2009. See note 7 to our
Condensed Consolidated Financial Statements in this report.
36
Gain
on Liquidation of Hedging Instrument
As of July 3, 2008, we entered into an
ISDA master agreement and a costless collar with BP Corporation North America
Inc., or BP, for 130 barrels of oil per day with a price floor of $132.50 per
barrel and a price ceiling of $155.70 per barrel for NYMEX West Texas
Intermediate for the period of October 1, 2009 until March 31,
2011. We liquidated this costless collar in November 2008 and
received proceeds of approximately $3.9 million from BP. We reduced
the debt outstanding under our Credit Facility by approximately $3.3 million and
used the remainder for general operating purposes.
Unrealized
Gain (loss) on Derivative Instruments
Unrealized gain or loss on derivative
instruments is the mark-to-market exposure under our commodity
swaps. This non-cash unrealized loss for the quarter ended December
31, 2009 was $2,485,706. Unrealized gain or loss will fluctuate from
period to period when commodities are hedged, and will be a function of the
instruments in place and the forward curve pricing for the
commodities.
Gain
on Repurchase of Debentures
We repurchased $450,000 of the
Debentures during the nine months ended December 31, 2009 at a gain of
$406,500. We also redeemed an additional $150,000 of the Debentures
during the quarter ended December 31, 2009 for $150,000 in cash. No
gain or loss resulted from this $150,000 redemption.
Management
Fee Revenue
Management
fee revenue for the three and nine months ended December 31, 2009 was $23,944
and $99,234, respectively, and represents revenues earned as operator on the
Brownrigg joint venture project, in accordance with the terms of the joint
operating agreement.
Net
Income (Loss)
Net loss
for the three months ended December 31, 2009 was $3,038,843 and $3,139,100 for
the nine months ended December 31, 2009 as compared to a net loss of $1,423,983
in the three months ended December 31, 2008 and $4,931,229 in the nine months
ended December 31, 2008. The primary component of the net loss is the
non-cash unrealized loss of $2,485,706 recorded in the quarter ended December
31, 2009. Loan interest accretion, also a non-cash expense further
contributes to the net loss recorded in both the three and nine months ended
December 31, 2009 and 2008.
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. Based upon the monthly
commitment notices we have received to date, we have estimated and classified
$330,000 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 various strategic initiatives and
JV partnerships, as well as sales of reserves in our existing properties to
finance our operations and to service our debt obligations.
We manage
our exposure to commodity price fluctuations by executing derivative
transactions to hedge the change in prices of our production, thereby mitigating
our exposure to price declines, but these transactions will also limit our
earnings potential in periods of rising commodity prices. There also is a risk
that we will be required to post collateral to secure our hedging activities and
this could limit our available funds for our business activities.
The
following table summarizes total current assets, total current liabilities and
working capital at December 31, 2009 as compared to March 31,
2009.
37
December 31,
|
March 31,
|
Increase / (Decrease)
|
||||||||||
2009
|
2009
|
$
|
||||||||||
Current
Assets
|
$ | 977,561 | $ | 898,941 | 78,620 | |||||||
Current
Liabilities
|
$ | 2,258,331 | $ | 2,827,015 | 568,684 | |||||||
Working
Capital (deficit)
|
$ | (1,280,770 | ) | $ | (1,928,074 | ) | 647,304 |
Senior
Secured Credit Facility
On July
3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year $50
million Senior Secured Credit Facility (the “Credit Facility”) with Texas
Capital Bank, N.A. Borrowings under the Credit Facility will be
subject to a borrowing base limitation based on our current proved oil and gas
reserves and will be subject to semi-annual redeterminations. 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.
Proceeds
from the initial extension of credit under the Credit Facility were used: (1) to
redeem our 10% debentures in an aggregate principal amount of $6.3 million plus
accrued interest (the “April Debentures”), (2) for Texas Capital Bank’s
acquisition of our approximately $2.0 million indebtedness to Cornerstone Bank,
(3) for complete repayment of promissory notes issued to the sellers in
connection with our purchase of the DD Energy project in an aggregate principal
amount of $965,000 plus accrued interest, (4) to pay transaction costs, fees and
expenses related to the Credit Facility, and (5) to expand our current
development projects. Future borrowings may be used for the
acquisition, development and exploration of oil and gas properties, capital
expenditures and general corporate purposes.
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, the Texas Capital
Bank 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
December 31, 2009.
The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires that we, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, maintain a
minimum current assets to current liabilities ratio and a minimum ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and at the end of each fiscal quarter beginning with the
quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior
funded debt. 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 ending December 31, 2009
and to modify the annualization of the interest coverage ratio, also beginning
with the quarter ending December 31, 2009. See Note 8 to our
Condensed Consolidated Financial Statements in this report. A copy of the
January 13, 2010 amendment is attached hereto as Exhibit 10.16. 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. A copy of this waiver is attached hereto as Exhibit
10.18.
38
Additionally,
Texas Capital Bank, N.A. and the holders of the debentures entered into a
Subordination Agreement whereby the debentures issued on June 21, 2007 will be
subordinated to the Credit Facility.
Debenture
Financing
On April
11, 2007, we completed a $9.0 million private placement of senior secured
debentures. In accordance with the terms of the debentures, we received $6.3
million (before expenses and placement fees) at the first closing and an
additional $2.7 million (before closing fees and expenses) at the second closing
on June 21, 2007. In connection with the sale of the debentures, we issued the
lenders 1,800,000 shares of common stock. On July 7, 2008, we redeemed $6.3
million aggregate principal amount of our debentures. Effective July
7, 2008, we redeemed an aggregate principal amount of $6.3 million of the
Debentures. We also amended the $2.7 million of aggregate principal amount of
the remaining 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 our 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 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 EnerJex’s common stock. 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 and additional
2.5% of the quarterly interest payment due.
We
have 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. In April and May of
2009, we redeemed $450,000 of the Debentures for $43,500 in cash.
Pursuant
to the terms of the Registration Rights Agreement, as amended, between us and
one of the Buyers, we were obligated to register 1,000,000 of the shares issued
under the Financing Agreements. These shares were registered effective December
24, 2008.
In
connection with the Credit Facility, we entered into an agreement amending the
Securities Purchase Agreement, Registration Rights Agreement, the Pledge and
Security Agreement and the Senior Secured Debentures issued on June 21, 2007
(the “Debenture
Agreements”), with the holders (the “Buyers”) of the debentures
issued on June 21, 2007 (the “June Debentures”). Pursuant
to this agreement, we, among other things, (i) redeemed the April Debentures,
(ii) agreed to use the net proceeds from our next debt or equity offering to
redeem the June Debentures, (iii) agreed to update the Buyers’ registration
statement to sell our common stock owned by the Buyers, (iv) amended certain
terms of the Debenture Agreements in recognition of the indebtedness under the
Credit Facility, (v) amended the Securities Purchase Agreement and Registration
Rights Agreement to remove the covenant to issue and register additional shares
of common stock in the event that our oil production does not meet certain
thresholds over time, and (vi) the Buyers agreed to waive all known events of
default. In June 2009, we again amended the debentures to extend the
maturity date to September 30, 2010, and allow us to pay interest in either cash
or payment-in-kind interest (an increase in the amount of principal due) or
payment-in-kind shares (issuance of shares of common stock), and add a provision
for the conversion of the debentures into shares of EnerJex’s common stock.
Further, in November 2009, we amended the debentures to amend the company
redemption section of the debentures to allow for the retirement of shares of
our common stock held by the debenture holders if we meet certain redemption
payment schedules and to amend the debenture holders’ rights to participate in
certain future debt or equity offerings made by us.
39
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 up 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 will be tendered and cancelled.
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.
Standby
Equity Distribution Agreement with Paladin
On
December 3, 2009, we and Paladin entered into a Standby Equity Distribution
Agreement, or SEDA, pursuant to which, for a two-year period, we have the right
to sell up to 1,300,000 shares of our common stock to Paladin at any time.
These shares are being registered with this registration statement, even though
Paladin does not own them yet. On December 3, 009, we authorized the issuance of
90,000 shares of our common stock to Paladin as a commitment fee. As of December
9, 2009, we had not sold any shares of common stock to Paladin under the
SEDA.
For each
share of common stock purchased under the SEDA, Paladin will pay a percentage of
the lowest daily volume weighted average closing price during the five
consecutive trading days after we provide notice to Paladin based on the
following:
|
·
|
85%
of the market price for the initial two
advances,
|
|
·
|
90%
of the market price to the extent the Common Stock is trading below $1.00
per share during the pricing
period,
|
|
·
|
92%
of the market price to the extent the Common Stock is trading at or above
$1.00 per share during the pricing period,
or
|
|
·
|
95%
of the market price to the extent the Common Stock is trading at or above
$2.00 per share during the pricing
period.
|
Each such advance may be for an amount
that is the greater of $40,000 or 20% the average daily trading volume of our
common stock for the five consecutive trading days prior to the notice date.
However, our initial two advances under the SEDA may be for up to $55,000. In
addition, in no event shall the number of shares of common stock issuable to
Paladin pursuant to an advance cause the aggregate number of shares of common
stock beneficially owned by Paladin and its affiliates to exceed
4.99%.
Our right
to deliver an advance notice and the obligations of Paladin thereunder with
respect to an advance is subject to our satisfaction of a number of conditions,
including that our common stock is trading, and we believe will continue for the
foreseeable future to trade, on a principal market, that we have not received
any notice threatening the continued listing of our common stock on the
principal market and that a registration statement is effective.
In addition, without the written
consent of Paladin, we may not, directly or indirectly, offer to sell, sell,
contract to sell, grant any option to sell or otherwise dispose of any shares of
common stock (other than the shares offered pursuant to the provisions of the
agreement) or securities convertible into or exchangeable for common stock,
warrants or any rights to purchase or acquire, common stock during the period
beginning on the 5th trading day immediately prior to an advance notice date and
ending on the 5th trading day immediately following the settlement
date.
We may
terminate the SEDA upon fifteen trading days of prior notice to Paladin, as long
as there are no advances outstanding and we have paid to Paladin all amounts
then due. A copy of the SEDA is attached hereto as an exhibit.
40
Satisfaction
of our cash obligations for the next 12 months
A
critical component of our operating plan is the ability to obtain additional
capital through additional equity and/or debt financing and working interest
participants. During fiscal 2009, we were in the midst of a public equity
offering when global economic conditions deteriorated and the commodity prices
of oil and natural gas experienced significant declines. Our cash revenues from
operations have been significantly impacted as has our ability to meet our
monthly operating expenses and service our debt obligations. We are actively
seeking opportunities to raise funds through a debt or equity
offering. In the event we cannot obtain additional capital through
other means to allow us to pursue our strategic plan, this would materially
impact not only our ability to continue our desired growth and execute our
business strategy, but also to continue as a going concern. There is no
assurance we would be able to obtain such financing on commercially reasonable
terms, if at all. Failure to do so can have a material adverse effect
on our business prospects, financial condition and results of
operations.
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.
Summary
of product research and development
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
At
December 31, 2009, we had 14 full time employees, equal to the number of full
time employees at our fiscal year ended March 31, 2009. Since November 2008, we
have reduced personnel levels by 5 full time employees and 2 independent
contractors in response to declining economic conditions and in an effort to
reduce our operating and general expenses and cash outlay. As
drilling and 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, drilling, water hauling, pipeline
construction, well design, well-site monitoring and surveillance, permitting and
environmental assessment when it is prudent and necessary to do so. 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.
41
Critical
Accounting Policies and Estimates
Our
critical accounting estimates include the value our oil and gas properties,
asset retirement obligations, current portion of long-term debt, and share-based
payments.
Oil
and Gas Properties:
The
accounting for our business is subject to special accounting rules that are
unique to the gas and oil industry. There are two allowable methods of
accounting for oil and gas business activities: the successful efforts method
and the full-cost method. We follow the full-cost method of accounting under
which all costs associated with property acquisition, exploration and
development activities are capitalized. We also capitalize internal costs that
can be directly identified with our acquisition, exploration and development
activities and do not include any costs related to production, general corporate
overhead or similar activities.
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.
On a
regular basis, we evaluate the carrying value of our gas and oil properties
considering the full-cost accounting methodology. 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. This sum which may not be exceeded is referred to as the
“ceiling”. 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
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.
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.
42
Current
Portion of Long-term Debt:
We have classified a portion of the
borrowings outstanding under our Credit Facility as a current liability based
upon monthly commitment reduction notices that we have received in connection
with borrowing base reviews by Texas Capital Bank. Our future
estimates may change as a result of, among other factors, the semi-annual
borrowing base redeterminations required under the Credit Facility.
Derivative
Instruments:
The Company determines the fair value
of its derivative instruments utilizing various inputs, including NYMEX price
quotations and contract terms. The mark-to-market exposure under our
derivative instruments is recorded as an unrealized gain or
loss. This exposure will vary from period to period with fluctuations
in commodity prices, which have been and may continue to be
volatile.
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
Accounting Pronouncements
In June
2009, the FASB adopted Codification Topic Statement No. 105 “The FASB Accounting
Standards Codification and the Hierarchy of Generally Accepted Accounting
Principles”. ASC 105 is the single source of authoritative
nongovernmental U.S. generally accepted accounting principles (“GAAP”),
superseding existing FASB, American Institute of Certified Public Accounts
(“AICPA”), Emerging Issues Task Force (“EITF”), and related accounting
literature. ASC 105 reorganized the thousands of GAAP pronouncements
into roughly 90 accounting topics and displays them using a consistent
structure. Also included is relevant Securities and Exchange
Commission guidance organized using the same topical structure in separate
sections. ASC 105 will be effective for financial statements issued
for reporting periods that end after September 15, 2009. There was no
impact upon adoption.
In May
2009, the FASB adopted Codification Topic 855,” Subsequent Event’s, which
requires entities to disclose the date through which they have evaluated
subsequent events and whether the date corresponds with the release of its
financial statements. The statement established general standards of
accounting for and disclosure of events that occur after the balance sheet date
but before financial statements are issued or are available to be
issued. ASC 855 is effective for interim or annual financial periods
ending after June 15, 2009, and shall be applied prospectively. The
adoption ASC 855 did not have a material impact on the Company’s financial
statements.
In
April 2009, the Financial Accounting Standards Board (FASB) issued FASB
Staff Position (FSP) Financial Accounting Standard (FAS) 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” (Codification Topic 820). Based on the guidance, if an entity
determines that the level of activity for an asset or liability has
significantly decreased and that a transaction is not orderly, further analysis
of transactions or quoted prices is needed, and a significant adjustment to the
transaction or quoted prices may be necessary to estimate fair value in
accordance with Statement of Financial Accounting Standards (SFAS) No. 157
Fair Value Measurements. This FSP is to be applied prospectively and is
effective for interim and annual periods ending after June 15, 2009 with
early adoption permitted for periods ending after March 15,
2009.
43
In
April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and
Presentation of Other-Than-Temporary Impairments (Codification Topic 320). The
guidance applies to investments in debt securities for which
other-than-temporary impairments may be recorded. If an entity’s management
asserts that it does not have the intent to sell a debt security and it is more
likely than not that it will not have to sell the security before recovery of
its cost basis, then an entity may separate other-than-temporary impairments
into two components: 1) the amount related to credit losses (recorded in
earnings), and 2) all other amounts (recorded in other comprehensive income).
This FSP is to be applied prospectively and is effective for interim and annual
periods ending after June 15, 2009 with early adoption permitted for
periods ending after March 15, 2009.
FSP FAS
107-1 and APB 28-1 - In April 2009, the FASB issued FSP FAS 107-1 and
Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of
Financial Instruments (ACS Topic 825). The FSP amends SFAS No. 107
Disclosures about Fair Value of Financial Instruments to require an entity to
provide disclosures about fair value of financial instruments in interim
financial information. This FSP is to be applied prospectively and is effective
for interim and annual periods ending after June 15, 2009 with early
adoption permitted for periods ending after March 15, 2009.
Recent
Accounting Pronouncement Issued But Not in Effect
In June
2009, the FASB adopted SFAS 166,” Accounting for Transfers of Financial Assets
(“ACS Topic 860”) Statement 166 is a revision to FASB Statement No. 140,
Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities, and will require more information about transfers of financial
assets, including securitization transactions, and where entities have
continuing exposure to the risks related to transferred financial assets. It
eliminates the concept of a “qualifying special-purpose entity,” changes the
requirements for derecognizing financial assets, and requires additional
disclosures. SFAS 166 enhances information reported to users of financial
statements by providing greater transparency about transfers of financial assets
and an entity’s continuing involvement in transferred financial
assets. SFAS 166 will be effective at the start of a reporting
entity’s first fiscal year beginning after November 15, 2009. Early application
is not permitted. The Company does not anticipate the adoption of SFAS 166
will have an impact on its consolidated results of operations or consolidated
financial position.
In June
2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R)
(“ACS Topic 810). Statement 167 is a revision to FASB Interpretation No. 46
(Revised December 2003), Consolidation of Variable Interest Entities, and
changes how a reporting entity determines when an entity that is insufficiently
capitalized or is not controlled through voting (or similar rights) should be
consolidated. The determination of whether a reporting entity is required to
consolidate another entity is based on, among other things, the other entity’s
purpose and design and the reporting entity’s ability to direct the activities
of the other entity that most significantly impact the other entity’s economic
performance. SFAS 167 will require a reporting entity to provide additional
disclosures about its involvement with variable interest entities and any
significant changes in risk exposure due to that involvement. A reporting entity
will be required to disclose how its involvement with a variable interest entity
affects the reporting entity’s financial statements. SFAS 167 will be effective
at the start of a reporting entity’s first fiscal year beginning after November
15, 2009. Early application is not permitted. The Company is currently
evaluating the impact, if any, of adoption of SFAS 167 on its financial
statements.
Effects
of Inflation and Pricing
The oil
and natural gas industry is very cyclical and the demand for goods and services
of oil field companies, suppliers and others associated with the industry puts
extreme pressure on the economic stability and pricing structure within the
industry. Material changes in prices impact revenue stream, estimates of future
reserves, borrowing base calculations of bank loans and value of properties in
purchase and sale transactions. Material changes in prices can impact the value
of oil and natural gas companies and their ability to raise capital, borrow
money and retain personnel. We anticipate business costs and the demand for
services related to production and exploration will fluctuate while the
commodity prices for oil and natural gas, both remain volatile.
44
BUSINESS
AND PROPERTIES
Our Business
EnerJex,
formerly known as Millennium Plastics Corporation, is an oil and natural gas
acquisition, exploration and development company. Midwest Energy, Inc. was
incorporated in the State of Nevada on December 30, 2005. In August of 2006,
Millennium Plastics Corporation, following a reverse merger by and among us,
Millennium Acquisition Sub (our wholly-owned subsidiary) and Midwest Energy,
changed the focus of its business plan from the development of biodegradable
plastic materials and entered into the oil and natural gas industry. In
conjunction with the change, the company was renamed EnerJex Resources,
Inc.
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.
Since the
beginning of fiscal 2008, we deployed approximately $12 million in capital
resources to acquire and develop five operating projects and drill 179 new wells
(111 producing wells and 65 water injection wells and 3 dry holes). As a result,
our estimated total net proved oil reserves increased from zero at March 31,
2007 to 1.3 million barrels of oil equivalent, or BOE, as of March 31, 2009. Of
the 1.3 million BOE of total proved reserves, approximately 39% are proved
developed and approximately 61% are proved undeveloped. The proved developed
reserves consist of 82% proved developed producing reserves and 18% proved
developed non-producing reserves.
The total
proved PV10 (present value) of our reserves (“PV10”) as of March 31, 2009
was $10.63 million, based on an estimated oil price of $42.65 per barrel. 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 33, for a
reconciliation to the comparable GAAP financial measure.
In response to economic conditions and
capital market constraints, we have recently begun to explore and evaluate
various strategic initiatives that would allow us to continue our plans to grow
production and reserves in the mid-continent region of the United States.
Initiatives include creating joint ventures to further develop current leases,
restructuring current debt, as well as evaluating other options ranging from
capital formation to some type of business combination. Though there
can be no assurance that any particular outcome will result from this process,
we believe there are significant opportunities to increase our growth rates
given current market conditions. We believe this process may create
options that will allow us to better position EnerJex to take advantage of these
opportunities.
The Opportunity in
Kansas
According
to the Kansas Geological Survey, the State of Kansas has historically been one
of the top 10 domestic oil producing regions in the United States. For the years
ended December 31, 2008 and 2007, 39.6 million barrels and 36.6 million barrels
of oil were produced in Kansas. Of the total barrels produced in Kansas in the
calendar year ended December 2007, 15 companies accounted for approximately 29%
of the total production, with the remaining 71% produced by over 1,750 active
producers.
In
addition to significant historical oil and natural gas production levels in the
region, we believe that a confluence of the following factors in Eastern Kansas
and the surrounding region make it an attractive area for oil and natural gas
development activities:
|
·
|
Traditional Roll-Up
Strategy. We are seeking to employ a traditional roll-up
strategy utilizing a combination of capital resources, operational and
management expertise, technology, and our strategic partnership with Haas
Petroleum, which has experience operating in the region for nearly 70
years.
|
45
|
·
|
Numerous
Acquisition Opportunities. There are many small producers and
owners of mineral rights in the region, which afford us numerous
opportunities to pursue negotiated lease transactions instead of having to
competitively bid on fundamentally sound
assets.
|
|
·
|
Fragmented
Ownership Structure. There are numerous opportunities to
acquire producing properties at attractive prices, because of the
currently inefficient and fragmented ownership
structure.
|
Our Properties
The table
below summarizes our acreage by project name as of March 31, 2009.
Project
Name
|
Developed
Acreage
|
Undeveloped
Acreage
|
Total
Acreage
|
|||||||||||||||||||||
Gross
|
Net(1)
|
Gross
|
Net(1)
|
Gross
|
Net(1)
|
|||||||||||||||||||
Black
Oaks Project
|
550 | 522 | 1,850 | 1,758 | 2,400 | 2,280 | ||||||||||||||||||
Thoren
Project
|
135 | 135 | 591 | 591 | 726 | 726 | ||||||||||||||||||
DD
Energy Project
|
400 | 400 | 1,370 | 1,370 | 1,770 | 1,770 | ||||||||||||||||||
Tri-County
Project
|
610 | 606 | 652 | 651 | 1,262 | 1,257 | ||||||||||||||||||
Gas
City Project
|
600 | 600 | 4,713 | 4,713 | 5,313 | 5,313 | ||||||||||||||||||
Total
|
2,295 | 2,263 | 9,176 | 9,083 | 11,471 | 11,346 |
|
(1)
|
Net
acreage is based on our net working interest as of March 31,
2009.
|
Black Oaks
Project
On April
9, 2007, we entered into a “Joint Exploration Agreement”
with a shareholder, MorMeg, LLC, (MorMeg) whereby we agreed to advance $4.0
million to a joint operating account for further development of MorMeg’s Black
Oaks leaseholds in exchange for a 95% working interest in the Black Oaks
Project. The Black Oaks Project encompasses approximately 2,400 gross
acres in Woodson and Greenwood Counties, Kansas, which at the time of
acquisition had approximately 35 oil wells producing an average of approximately
32 barrels of oil per day, or BOPD.
The Black
Oaks Project is a primary and enhanced secondary recovery project between us and
MorMeg. Phase I of the Black Oaks Project development plan commenced shortly
after closing with the drilling of 44 in-fill wells. During fiscal 2008, we
began injecting water into the first five water injection wells at an average
rate of approximately 50 barrels of water per day per well. This pilot program
was expanded so that by June 2008, we were injecting approximately 200 barrels
of water per day (bbls water/day) per well in the initial 5 injection wells.
Adjacent oil wells showed increased production from an average of approximately
5 BOPD to 25 BOPD. As of March 31, 2009, we are maintaining the 200 bbls
water/day average on the injection wells in the pilot program area. We have seen
no additional response on this area as of yet. We are also injecting an average
of 100 bbls water/day per well in 4 injection wells adjacent to the pilot
program area and are closely monitoring data and activities for any resulting
increase in production. Based upon the results of our testing, we
expect to continue the development plan, subject to availability of capital.
Phase II of the plan contemplates drilling over 25 additional water injection
wells and drilling over 20 additional producer wells. Project-wide production
was an average of approximately 96 BOPD as of March 31, 2009.
We will maintain our 95% working
interest until “payout”, at which time the
MorMeg 5% carried working interest will be converted to a 30% working interest
and our working interest becomes 70%. Payout is generally the point in time when
the total cumulative revenue from the project equals all of the project’s
development expenditures and costs associated with funding. Through an
additional extension, we have until December 31, 2009 to contribute additional
capital toward the Black Oaks Project development. If we elect not to contribute
further capital to the Black Oaks Project prior to the project’s full
development while it is economically viable to do so, or if there is more than a
thirty day delay in project activities due to lack of capital, MorMeg has the
option to cease further joint development and we will receive an undivided
interest in the Black Oaks Project. The extension will have no force and effect,
however, upon a material default by EnerJex under the Credit Facility. The
undivided interest will be the proportionate amount equal to the amount that our
investment bears to our investment plus $2.0 million, with MorMeg receiving an
undivided interest in what remains.
46
As of March 31, 2009, based on an
estimated oil price of $42.65 per barrel, we had proved oil reserves on Phase I
of this project of:
|
Gross STB(1)
|
Net STB(2)
|
PV10(3)
(before tax)
|
|||||||||
Proved,
Developed Producing
|
420,080 | 197,640 | $ | 3,781,690 | ||||||||
Proved,
Developed Non-Producing
|
50,440 | 30,450 | $ | 650,430 | ||||||||
Proved,
Undeveloped
|
875,300 | 352,370 | $ | 944,100 | ||||||||
Total
Proved
|
1,345,820 | 580,460 | $ | 5,376,220 |
(1)
|
STB
= one stock-tank barrel.
|
(2)
|
Net
STB is based upon our net revenue interest, including any applicable
reversionary interest.
|
|
(3)
|
See
“Glossary” on
page 78 for our definition of PV10 and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Reserves”
page 33, 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, 2009, we have invested approximately $800,000 for the development of
this project and as of March 31, 2009, we had 32 oil wells producing an average
of approximately 38 BOPD; along with 16 water injection wells and one water
supply well.
As of
March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had
proved oil reserves on this project of:
Gross STB(1)
|
Net STB(2)
|
PV10(3)
(before tax)
|
||||||||||
Proved,
Developed Producing
|
48,030 | 24,600 | $ | 539,510 | ||||||||
Proved,
Developed Non-Producing
|
24,920 | 7,690 | $ | 146,490 | ||||||||
Proved,
Undeveloped
|
43,020 | 37,640 | $ | 85,970 | ||||||||
Total
Proved
|
115,970 | 69,930 | $ | 771,970 |
|
(1)
|
STB
= one stock-tank barrel.
|
|
(2)
|
Net
STB is based upon our net revenue interest, including any applicable
reversionary interest.
|
|
(3)
|
See
“Glossary” on
page 78 for our definition of PV10 and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Reserves”
page 33, for a reconciliation to the comparable GAAP financial
measure.
|
We will
maintain our 100% working interest until “payout” and our working
interest will become 75%, at which time the MorMeg working interest will be
converted to a 25% working interest. Payout for this project occurs at that
point in time when the total cumulative revenue from production equals the total
amount of the purchase price, all costs and expenses incurred by us in the
development and operation, and loan and interest costs incurred in the finance
and funding of the purchase.
We have
identified an additional 7 drillable producer locations and 8 drillable injector
locations on this project.
DD Energy
Project
Effective
September 1, 2007, we acquired a 100% working interest in the DD Energy Project
for $2.7 million, which consisted of approximately 1,500 acres in Johnson,
Anderson and Linn Counties, Kansas. At the time of acquisition, this project was
producing an average of approximately 45 BOPD.
47
In
addition, we have acquired additional leases bringing the total acreage for this
project to approximately 1,700 acres. As of March 31, 2009, we had 110 oil
wells, 41 water injection wells and 2 water supply wells on this project with
production averaging approximately 61 BOPD. Through March 31, 2009, we have
invested an additional $2.4 million in this project and have drilled 41 water
injection wells and 34 producing wells. We have seen some indication
of an initial response from 5 of the injectors and are closely monitoring data
and activities for any resulting increase in production.
As of
March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had
proved oil reserves on this project of:
Gross STB(1)
|
Net STB(2)
|
PV10(3)
(before tax)
|
||||||||||
Proved,
Developed Producing
|
75,510 | 64,700 | $ | 972,220 | ||||||||
Proved,
Developed Non-Producing
|
23,070 | 19,470 | $ | 183,090 | ||||||||
Proved,
Undeveloped
|
39,390 | 31,840 | $ | 85,030 | ||||||||
Total
Proved
|
137,970 | 116,010 | $ | 1,240,340 |
|
(1)
|
STB
= one stock-tank barrel.
|
|
(2)
|
Net
STB is based upon our net revenue interest, including any applicable
reversionary interest.
|
|
(3)
|
See
“Glossary” on
page 78 for our definition of PV10 and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Reserves”
page 33, for a reconciliation to the comparable GAAP financial
measure.
|
We
have identified an additional 88 drillable producer locations and 86 drillable
injector locations on this project.
Tri-County
Project
On
September 14, 2007, we acquired nearly a 100% working interest in the Tri-County
Project for $800,000, which consisted of approximately 1,100 acres in Miami,
Johnson and Franklin Counties, Kansas. At the time of acquisition, this project
was producing an average of approximately 25 BOPD.
Through
March 31, 2009, we have invested approximately $700,000 towards the development
of this project. Funds have been used to drill four producer wells, make
infrastructure upgrades, and perform work-overs on approximately 20 wells in
this project. We have also acquired additional leases, bringing the total
project to approximately 1,300 acres.
As of
March 31, 2009, the Tri-County Project consisted of 166 producing wells and 59
water injection wells with production averaging approximately 49
BOPD.
As of
March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had
proved oil reserves on this project of:
Gross STB(1)
|
Net STB(2)
|
PV10(3)
(before tax)
|
||||||||||
Proved,
Developed Producing
|
177,560 | 141,330 | $ | 1,369,700 | ||||||||
Proved,
Developed Non-Producing
|
48,190 | 37,940 | $ | 479,270 | ||||||||
Proved,
Undeveloped
|
474,210 | 380,030 | $ | 1,361,430 | ||||||||
Total
Proved
|
699,960 | 559,300 | $ | 3,210,400 |
|
(1)
|
STB
= one stock-tank barrel.
|
|
(2)
|
Net
STB is based upon our net revenue interest, including any applicable
reversionary interest.
|
|
(3)
|
See
“Glossary” on
page 78 for our definition of PV10 and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Reserves”
page 33, 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.
48
Gas City
Project
In August
of 2007, we entered into a development agreement with Euramerica Energy, Inc.,
or Euramerica, to further the development and expansion of the Gas City Project,
which included 6,600 acres, whereby Euramerica contributed $524,000 in capital
toward the project. Euramerica was granted an option to purchase this project
for $1.2 million with a requirement to invest an additional $2.0 million for
project development by August 31, 2008. We were the operator of the project at a
cost plus 17.5% basis. We received $600,000 of the $1.2 million purchase price
and $500,000 of the $2.0 million development funds.
On
September 15, 2008, we amended the well development agreement to extend the date
on which Euramerica was required to make its third and fourth quarterly
installment payments of the purchase price to October 15, 2008. The
amendment also extended until November 15, 2008 the requirement to fund the
remaining $1.5 million in development capital.
On
October 15, 2008, we again amended the agreement with Euramerica for the
purchase of the Gas City Project to include the following material changes to
the Euramerica agreement, as amended, extended and supplemented:
|
·
|
Euramerica
was granted an extension until January 15, 2009 (with no further
grace periods) to pay the remaining $600,000 of the purchase price for its
option to purchase an approximately 6,600 acre portion of the Gas City
Project and $1.5 million in previously due development funds for the Gas
City Project;
|
|
·
|
If
Euramerica fails to fully fund both the purchase price and these
development funds by January 15, 2009, Euramerica will lose all rights to
the Gas City Project and assets and there will be no payout from
the revenue of the wells on this
project;
|
|
·
|
The
oil zones and production from such oil zones in two oil
wells then became 100% owned by
EnerJex;
|
|
·
|
We
may deduct from the development funds all amounts owed to us prior to
applying the funds to any actual
development;
|
|
·
|
Euramerica
specifically recognized that we can shut in or stop the development of the
project if the project is not producing in paying quantities or if the
project is operating at a loss. The decision to shut in the project and
cease all operations was made on October 15,
2008; and
|
|
·
|
If
Euramerica funds the remaining portion of the purchase price for its
option and the development funds in the Gas City Project on or before
January 15, 2009, “Payout” as used in the
Assignment and other documents is now based on “drilling and completion
costs on a well-by-well basis.”
|
Subsequently,
Euramerica failed to fully fund by January 15, 2009 both the balance of the
purchase price and the remaining development capital owed under the Amended and
Restated Well Development Agreement and Option for “Gas City Property” between
us and Euramerica. Therefore, Euramerica has forfeited all of its
interest in the property, including all interests in any wells, improvements or
assets, and all of Euramerica's interest in the property reverts back to
us. In addition, all operating agreements between us and Euramerica
relating to the Gas City Project are null and void.
We
drilled 22 wells on behalf of Euramerica under the development agreement. We are
currently exploring options to sell or further develop the Gas City Project
through joint venture partnerships or other opportunities. The gas
project remains shut in and certain leases approximating 1,300 acres were not
renewed upon expiration. As of March 31, 2009 we were producing an
average of approximately 10 BOPD from the two oil wells now 100% owned by
us.
As of
March 31, 2009, based on an estimated oil price of $42.65 per barrel, we had
proved oil and natural gas reserves on this project of:
49
Gross
STB(1)
|
Net
STB(2)
|
Gross
MCF(3)
|
Net
MCF(4)
|
PV10(5)
(before tax)
|
||||||||||||||||
Proved,
Developed Producing
|
1,400 | 1,150 | - | - | $ | 28,430 | ||||||||||||||
Proved,
Developed Non-Producing
|
- | - | - | - | $ | - | ||||||||||||||
Proved,
Undeveloped
|
11,850 | 9,780 | - | - | $ | 1,970 | ||||||||||||||
Total
Proved
|
13,250 | 10,930 | - | - | $ | 30,400 |
|
(1)
|
STB
= one stock-tank barrel.
|
|
(2)
|
Net
STB is based upon our net revenue interest, including any applicable
reversionary interest.
|
|
(3)
|
MCF
= thousand cubic feet of natural gas. There were no natural gas
reserves at March 31, 2009.
|
|
(4)
|
Net
MCF is based upon our net revenue interest. There were no
natural gas reserves at March 31,
2009.
|
|
(5)
|
See
“Glossary” on
page 78 for our definition of PV10 and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Reserves”
page 33, for reconciliation to the comparable GAAP financial
measure.
|
Brownrigg
Project
We entered into a joint venture in June
2009 on the Brownrigg (“Brownrigg”) lease in Linn County, Kansas with Pharyn
Impact Growth Fund, LP (“Pharyn”). The initial development funding on this lease
was completed as of January 1, 2010. We have resumed development and completion
activities on Brownrigg and anticipate production to begin in the quarter ending
March 31, 2010.
Our Business
Strategy
Our
principal strategy has been to focus on the acquisition of oil and natural gas
mineral leases that have existing production and cash flow. Once acquired,
subject to availability of capital, we strive to implement an accelerated
development program utilizing capital resources, a regional operating focus, an
experienced management and technical team, and enhanced recovery technologies to
attempt to increase production and increase returns for our stockholders. Our
oil and natural gas acquisition and development activities are currently focused
in Eastern Kansas. Depending on availability of capital, and other restraints,
our goal is to increase stockholder value by finding and developing oil and
natural gas reserves at 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.
|
50
We are
continually evaluating oil and natural gas opportunities in Eastern Kansas and
are also in various stages of discussions with potential joint venture (“JV”) partners who would
contribute capital to develop leases we currently own or would acquire for the
JV. Subsequent to year-end (in June 2009), we entered into one such
opportunity on the Brownrigg lease in Linn County, Kansas, as discussed
above. This economic strategy is anticipated to allow us to utilize
our own financial assets toward the growth of our leased acreage holdings,
pursue the acquisition of strategic oil and natural gas producing properties or
companies and generally expand our existing operations while further
diversifying risk. Subject to availability of capital, we plan to continue to
bring potential acquisition and JV opportunities to various financial partners
for evaluation and funding options. It is our vision to grow the
business in a disciplined and well-planned manner.
We began
generating revenues from the sale of oil during the fiscal year ended March 31,
2008. Subject to availability of capital, we expect our production to continue
to increase, both through development of wells, through our acquisition
strategy, and other strategic initiatives. Our future financial results will
continue to depend on: (i) our ability to source and screen potential projects;
(ii) our ability to discover commercial quantities of natural gas and oil; (iii)
the market price for oil and natural gas; and (iv) our ability to fully
implement our exploration, work-over and development program, which is in part
dependent on the availability of capital resources. There can be no assurance
that we will be successful in any of these respects, that the prices of oil and
natural gas prevailing at the time of production will be at a level allowing for
profitable production, or that we will be able to obtain additional funding at
terms favorable to us to increase our currently limited capital
resources. For a detailed description of these and other
factors that could materially impact actual results, please see “Risk Factors” in this
document.
The board
of directors has implemented a crude oil and natural gas hedging strategy that
will allow management to hedge up to 80% of our net production to mitigate a
majority of our exposure to changing oil prices in the intermediate
term.
Our Competitive
Strengths
We have a
number of strengths that we believe will help us successfully execute our
strategy:
|
·
|
Acquisition and Development
Strategy. We have what we believe to be a relatively
low-risk acquisition and development strategy compared to some of our
competitors. We generally buy properties that have proven current
production, with a projected pay-back within a relatively short period of
time, and with potential growth and upside in terms of development,
enhancement and efficiency. We also plan to minimize the risk of natural
gas and oil price volatility by developing a sales portfolio of pricing
for our production as it expands and as market conditions
permit.
|
|
·
|
Significant Production Growth
Opportunities. We have acquired an attractive acreage
position with favorable lease terms in a region with historical
hydrocarbon production. Based on drilling success we have had within our
acreage position and subject to availability of capital, we expect to
increase our reserves, production and cash
flow.
|
|
·
|
Experienced Management Team
and Strategic Partner with Strong Technical
Capability. Our CEO has over 20 years of experience in
the energy industry, primarily related to gas/electric utilities, but
including experience related to energy trading and production, and members
of our board of directors have considerable industry experience and
technical expertise in engineering, horizontal drilling, geoscience and
field operations. In addition, our strategic partner, Haas Petroleum, has
over 70 years of experience in Eastern Kansas, including completion and
secondary recovery techniques and technologies. Our board of directors and
Mark Haas of Haas Petroleum work closely with management during the
initial phases of any major project to ensure its feasibility and to
consider the appropriate recovery techniques to be
utilized.
|
|
·
|
Incentivized Management
Ownership. The equity ownership of our directors and
executive officers is strongly aligned with that of our stockholders. As
of November 16, 2009, our directors and executive officers owned
approximately 12.1% of our outstanding common
stock.
|
51
Company History
Midwest
Energy, Inc. was incorporated in the State of Nevada on December 30, 2005. Prior
to the reverse merger with Midwest Energy in August of 2006, we operated under
the name Millennium Plastics Corporation and focused on the development of
biodegradable plastic materials. This business plan was ultimately abandoned
following its unsuccessful implementation. Following the merger, we assumed the
business plan of Midwest Energy and entered into the oil and natural gas
industry. Concurrent with the effectiveness of the merger, we changed our name
to “EnerJex Resources, Inc.” The result of the merger was that the former
stockholders of Midwest Energy controlled approximately 98% of our outstanding
shares of common stock. In addition, Midwest Energy was deemed to be the
acquiring company for financial reporting purposes and the merger was accounted
for as a reverse merger. In November 2007 Midwest Energy changed its name to
EnerJex Kansas. All of our current operations are conducted through EnerJex
Kansas and DD Energy, our wholly-owned subsidiaries.
Significant
Developments in Fiscal 2009 and 2010
The
following is a brief description of our most significant corporate developments
that occurred in fiscal 2009:
|
·
|
On
March 6, 2008 we entered into an agreement with Shell Trading (US)
Company, or Shell, whereby we agreed to an 18-month fixed-price swap with
Shell for 130 BOPD at a fixed price per barrel of $96.90, before
transportation costs from April 1, 2008 through September 30, 2009. This
represented approximately 60% of our total oil production on a net revenue
basis at that time and locked in approximately $6.8 million in gross
revenue before transportation costs over the 18 month period. In addition,
we agreed to sell all of our remaining oil production at current spot
market pricing beginning April 1, 2008 through September 30, 2009 to
Shell. Through September 30, 2009, the positive impact on our
net revenue from the fixed-price swap was approximately
$787,000.
|
|
·
|
On
July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a
three-year $50 million Senior Secured Credit Facility (the “Credit Facility”) with
Texas Capital Bank, N.A. Borrowings under the Credit Facility
will be subject to a borrowing base limitation based on our current proved
oil and gas reserves and will be subject to semi-annual redeterminations
and other interim adjustments. The initial borrowing base was
set at $10.75 million and was reduced to $7.428 million following the
liquidation of the BP hedging instrument in November 2008. The
borrowing base was reviewed by Texas Capital Bank in February 2009 and it
was determined that it shall be reduced by $200,000 per month beginning
April 2009 with the expectation that this monthly reduction
would continue through December 2009. We had borrowings $7.328 million
outstanding at March 31, 2009. Subsequent to year-end, we have
made an additional $582,000 of payments to reduce the borrowing base to
$6.746 million at December 31, 2009. The Credit Facility is
secured by a lien on substantially all assets of the Company and its
subsidiaries. The Credit Facility has a term of three years, and matures
on July 3, 2011. The Credit Facility also provides for the
issuance of letters-of-credit up to a $750,000 sub-limit under the
borrowing base and up to an additional $2.25 million limit not subject to
the borrowing base to support our hedging
program.
|
|
·
|
As
of July 3, 2008, we entered into an ISDA master agreement and a costless
collar with BP Corporation North America Inc., or BP, for 130 barrels of
oil per day with a price floor of $132.50 per barrel and a price ceiling
of $155.70 per barrel for NYMEX West Texas Intermediate for the
period of October 1, 2009 until March 31, 2011. We liquidated
this costless collar in November 2008 and received proceeds of
approximately $3.9 million from BP. We reduced the debt
outstanding under our Credit Facility by approximately $3.3 million and
used the remainder for general operating
purposes.
|
52
|
·
|
On
July 7, 2008, we amended the $2.7 million of aggregate principal amount of
our 10% debentures that remain outstanding to, among other things, permit
the indebtedness under our Credit Facility, subordinate the security
interests of the debentures to the Credit Facility, provide for the
redemption of the remaining debentures with the net proceeds from any next
debt or equity offering, eliminate the covenant to maintain certain
production thresholds and waive all known defaults. Subsequent
to year-end, we again amended the debentures to extend the maturity date
to September 30, 2010, to allow us to pay interest in either cash or
payment-in-kind interest (an increase in the amount of principal due) or
payment of interest through the issuance of shares of common stock, and
add a provision for the conversion of the debentures into shares of our
common stock. Through May 31, 2010 the conversion price per
share equals $3.00. From June 1, 2010 through the Maturity
Date, assuming the debenture has not been redeemed, the conversion price
per share equals that price which shall be computed as 100.0% of the
arithmetic average of the Weighted Average Price of the Common Stock on
each of the thirty (30) consecutive Trading Days immediately preceding the
Conversion Date, and considering adjustments, if any, as specified in the
amendment. Further, in November of 2009, we amended the
debentures to amend the company redemption section of the debentures to
allow for the retirement of shares of our common stock held by the
debenture holders if we meet certain redemption payment schedules and to
amend the debenture holders’ rights to participate in certain future debt
or equity offerings made by us. We repurchased $450,000 of the Debentures
during the nine months ended December 31, 2009 at a gain of
$406,500. We also redeemed an additional $150,000 of the
Debentures during the quarter ended December 31, 2009 for $150,000 in
cash. No gain or loss resulted from this $150,000
redemption. 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.
|
|
·
|
On
August 1, 2008, we executed three-year employment agreements with C.
Stephen Cochennet, our chief executive officer, and Dierdre P. Jones, our
chief financial officer. Mr. Cochennet and Ms. Jones have
agreed to amend their employment agreements to reflect options rescinded
in November 2008.
|
|
·
|
Euramerica
failed to fully fund by January 15, 2009 both the balance of the purchase
price and the remaining development capital owed under the Amended and
Restated Well Development Agreement and Option for “Gas City Property”
between us and Euramerica. Therefore, Euramerica has forfeited
all of its interest in the property, including all interests in any wells,
improvements or assets, and all of Euramerica's interest in the property
reverts back to us. In addition, all operating agreements
between us and Euramerica relating to the Gas City Project are null and
void.
|
|
·
|
In
February 2009, we entered into a fixed price swap transaction under the
terms of the BP ISDA for a total of 120,000 gross barrels at a price of
$57.30 per barrel before transportation costs for the period beginning
October 1, 2009 and ending on December 31,
2013.
|
|
·
|
We
recorded a non-cash impairment of $4,777,723 to the carrying value of our
proved oil and gas properties during the fiscal year ended March 31, 2009.
The impairment is primarily attributable to lower prices for both oil and
natural gas. The charge results from the application of the
“ceiling test”
under the full cost method of accounting at December 31, 2008. Under full
cost accounting requirements, the carrying value may not exceed an amount
equal to the sum of the present value of estimated future net revenues
(adjusted for cash flow hedges) less estimated future expenditures to be
incurred in developing and producing the proved reserves, less any related
income tax effects. In calculating future net revenues, current prices and
costs used are those as of the end of the appropriate quarterly period.
Such prices are utilized except where different prices are fixed and
determinable from applicable contracts for the remaining term of those
contracts, including the effects of derivatives qualifying as cash flow
hedges. A ceiling test charge occurs when the carrying value of the oil
and gas properties exceeds the full cost
ceiling.
|
|
·
|
In
April and May of 2009, we repurchased a total of $450,000 of the
subordinated debentures. The principal balance remaining as of
December 31, 2009 is approximately $2.46 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.
|
53
|
·
|
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 date); 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
Janauary 1, 2010 redetermination.
|
|
·
|
On
August 25, 2009 we entered into a fixed price swap transaction under the
terms of the BP ISDA for 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 and Paladin entered into a Standby Equity
Distribution Agreement, or SEDA, pursuant to which, for a two-year period,
we have the right to sell up to 1,300,000 shares of our common stock to
Paladin at any time. These shares are being registered with this
registration statement, even though Paladin does not own them
yet.
|
|
·
|
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. See Note 8 to our December
31, 2009 Unaudited Condensed Consolidated Financial Statements in
this report.
|
Relationship with Haas
Petroleum
In April
of 2007, we entered into a consulting agreement with Mark Haas, President of
Haas Petroleum and managing member of MorMeg. This agreement provides that Mr.
Haas will consult with us at an executive level regarding field development,
acquisition evaluation, identification of additional acquisition opportunities
and overall business strategy. Haas Petroleum has been in the oil exploration
and production business for over 70 years and Mark Haas has been in the business
for over 30 years.
We
believe that this relationship provides us with a competitive advantage when
evaluating and sourcing acquisition opportunities. As a long-term producer and
oil field service provider, Haas Petroleum has existing relationships with
numerous oil and natural gas producers in Eastern Kansas and is generally aware
of existing opportunities to enhance many of these properties through the
deployment of capital, and application of enhanced drilling and production
technologies. We believe that we will be able to leverage the experience and
relationships of Mr. Haas to compliment our business strategy. To date, Mr. Haas
has helped us identify and evaluate all of our property acquisitions, and has
been instrumental in the creation and implementation of our development plans of
these properties.
54
One
of our fundamental goals with respect to the consulting arrangement is to align
the interests of Mr. Haas with those of ours as much as possible. As a result,
the consulting agreement provides that we will pay him five thousand dollars per
month. Finally, we have utilized our common stock, in part, for the purchase of
assets owned by MorMeg, which we believe will further align our business
interests with those of Mr. Haas.
Drilling Activity
The
following table sets forth the results of our drilling activities during the
2007, 2008 and 2009 fiscal years.
Drilling Activity
|
||||||||||||||||||||||||
Gross Wells
|
Net Wells(1)
|
|||||||||||||||||||||||
Fiscal Year
|
Total
|
Producing
|
Dry
|
Total
|
Producing
|
Dry
|
||||||||||||||||||
2007
Exploratory
|
-0- | -0- | -0- | -0- | -0- | -0- | ||||||||||||||||||
2008
Exploratory
|
10 | 10 | -0- | 10 | 10 | -0- | ||||||||||||||||||
2009
Exploratory(2)
|
12 | 12 | -0- | 12 | 12 | -0- | ||||||||||||||||||
2007
Development
|
-0- | -0- | -0- | -0- | -0- | -0- | ||||||||||||||||||
2008
Development
|
59 | 57 | 2 | 58 | 56 | 2 | ||||||||||||||||||
2009
Development
|
96 | 95 | 1 | 96 | 95 | 1 |
|
(1)
|
Net
wells are based on our net working interest as of March 31,
2009.
|
|
(2)
|
We
incurred some exploration costs related to exploratory wells drilled on
behalf of Euramerica.
|
Net Production, Average Sales Price
and Average Production and Lifting Costs
The table
below sets forth our net oil and natural gas production (net of all royalties,
overriding royalties and production due to others) for the fiscal years ended
March 31, 2009 and 2008 and 2007, the average sales prices, average production
costs and direct lifting costs per unit of production.
Fiscal Year Ended
March 31, 2009
|
Fiscal Year Ended
March 31, 2008
|
Fiscal Year Ended
March 31,2007
|
||||||||||
Net
Production
|
||||||||||||
Oil
(Bbl)
|
74,289 | 43,697 | -0- | |||||||||
Natural
gas (Mcf)
|
12,275 | 17,762 | 19,254 | |||||||||
Average
Sales Prices
|
||||||||||||
Oil
(per Bbl)
|
$ | 85.67 | $ | 79.71 | $ | -0- | ||||||
Natural
gas (per Mcf)
|
$ | 5.57 | $ | 6.20 | $ | 4.72 | ||||||
Average
Production Cost (1)
|
||||||||||||
Per
Bbl of oil
|
$ | 45.01 | $ | 56.65 | $ | -0- | ||||||
Per
Mcf of natural gas
|
$ | 15.11 | $ | 13.12 | $ | 9.55 | ||||||
Average
Lifting Costs (2)
|
||||||||||||
Per
Bbl of oil
|
$ | 33.01 | $ | 37.08 | $ | -0- | ||||||
Per
Mcf of natural gas
|
$ | 15.11 | $ | 9.86 | $ | 8.95 |
55
|
(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, 2007 through March 31,
2009. Results of operations from these activities have been determined using
historical revenues, production costs, depreciation, depletion and amortization
of the capitalized costs subject to amortization. General and administrative
expenses and interest expense have been excluded from this
determination.
For the
Fiscal Year
Ended
March 31, 2009
|
For the
Fiscal Year
Ended
March 31, 2008
|
For the
Fiscal Year
Ended
March 31, 2007
|
|||||||||||
Production
revenues
|
$ | 6,436,805 | $ | 3,602,798 | $ | 90,800 | |||||||
Production
costs
|
(2,637,333 | ) | (1,795,188 | ) | (172,417 | ) | |||||||
Depreciation,
depletion and amortization
|
(872,230 | ) | (913,224 | ) | (11,477 | ) | |||||||
Results
of operations for producing activities
|
$ | 2,972,242 | $ | 894,386 | $ | (93,094 | ) |
Producing Wells
The
following table sets forth the number of productive oil and natural gas wells in
which we owned an interest as of March 31, 2009.
Producing
|
||||||||||||||||
Project
|
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 | 22 | ||||||||||||
Total
|
379 | 376 | 22 | 22 |
(1)
|
Net
wells are based on our net working interest as of March 31,
2009.
|
Reserves
Our
estimated total proved PV10 (present value) before tax of reserves as of March
31, 2009 was $10.63 million, versus $39.6 million as of March 31, 2008. Though
total proved reserves were comparable at March 31, 2009 and 2008; 1.3 million
and 1.4 million barrels of oil equivalent (BOE), respectively, the PV10 declined
dramatically due to the estimated average price of oil at March 31, 2009 of
$42.65 versus $94.53 at March 31, 2008. Of the 1.3 million BOE at
March 31, 2009 approximately 39% are proved developed and approximately 61% are
proved undeveloped. The proved developed reserves consist of proved developed
producing (82%) and proved developed non-producing (18%). See “Glossary” on page 78 for our
definition of PV10.
Based on
an estimated oil price of $42.65 as of March 31, 2009, and applying an annual
discount rate of 10% of the future net cash flow, the estimated PV10 of the 1.3
million BOE, before tax, is calculated as set forth in the following
table:
56
Summary
of Oil and Natural Gas Reserves
as
of March 31, 2009
Proved Reserves
Category
|
Gross
STB(1)
|
Net
STB(2)
|
Gross
MCF(3)
|
Net
MCF(4)
|
PV10(5)
(before tax)
|
|||||||||||||||
Proved,
Developed Producing
|
722,590 | 429,420 | - | - | $ | 6,691,550 | ||||||||||||||
Proved,
Developed Non-Producing
|
146,620 | 95,560 | - | - | 1,459,280 | |||||||||||||||
Proved,
Undeveloped
|
1,440,760 | 811,650 | - | - | 2,478,510 | |||||||||||||||
Total
Proved
|
2,309,970 | 1,336,630 | - | - | $ | 10,629,340 |
(6)
|
STB
= one stock-tank barrel.
|
(7)
|
Net
STB is based upon our net revenue interest, including any applicable
reversionary interest.
|
(8)
|
MCF
= thousand cubic feet of natural gas. There were no natural gas
reserves at March 31, 2009.
|
(9)
|
Net
MCF is based upon our net revenue interest. There were no
natural gas reserves at March 31,
2009.
|
(10)
|
See
“Glossary” on
page 78 for our definition of PV10 and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Reserves”
page 33, for a reconciliation to the comparable GAAP financial
measure.
|
Oil and Natural Gas Reserves Reported
to Other Agencies
We did
not file any estimates of total proved net oil or natural gas reserves with, or
include such information in reports to, any federal authority or agency, other
than the SEC, during the fiscal year ended March 31, 2009.
Title to
Properties
Our
properties are subject to customary royalty interests, liens under indebtedness,
liens incident to operating agreements and liens for current taxes and other
burdens, including mineral encumbrances and restrictions. Further, our debt is
secured by first and second liens substantially on all of our assets. These
burdens have not materially interfered with the use of our properties in the
operation of our business to date, though there can be no assurance that such
burdens will not materially impact our operations in the future.
We
believe that we have satisfactory title to or rights in all of our producing
properties. As is customary in the natural gas and oil industry, minimal
investigation of title is made at the time of acquisition of undeveloped
properties. In most cases, we investigate title and obtain title opinions from
counsel or have title reviewed by professional landmen only when we acquire
producing properties or before we begin drilling operations. However, any
acquisition of producing properties without obtaining title opinions are subject
to a greater risk of title defects.
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 an ISDA
master agreement and two fixed price swaps 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.
57
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.
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 Coffeyville
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.
58
Research
and Development Activities
We have not spent any material amount
of time in the last two fiscal years on research and development
activities.
Governmental
Regulations
Regulation of Oil and Natural Gas
Production. Our oil and natural gas exploration, production
and related operations, when developed, are subject to extensive rules and
regulations promulgated by federal, state, tribal and local authorities and
agencies. For example, some states in which we may operate, including Kansas,
require permits for drilling operations, drilling bonds and reports concerning
operations and impose other requirements relating to the exploration and
production of oil and natural gas. Such states may also have statutes or
regulations addressing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum rates of production from wells, and the regulation of spacing, plugging
and abandonment of such wells. Failure to comply with any such rules and
regulations can result in substantial penalties. Moreover, such states may place
burdens from previous operations on current lease owners, and the burdens could
be significant. The regulatory burden on the oil and natural gas industry will
most likely increase our cost of doing business and may affect our
profitability. Although we believe we are currently in substantial compliance
with all applicable laws and regulations, because such rules and regulations are
frequently amended or reinterpreted, we are unable to predict the future cost or
impact of complying with such laws. Significant expenditures may be required to
comply with governmental laws and regulations and may have a material adverse
effect on our financial condition and results of operations.
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.
59
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.
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.
60
Personnel
At
December 31, 2009, we had 14 full time employees, equal to the number of full
time employees at our fiscal year ended March 31, 2009. Since November 2008, we
have reduced personnel levels by 5 full time employees and 2 independent
contractors in response to declining economic conditions and in an effort to
reduce our operating and general expenses and cash outlay. As
drilling and 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, drilling, water hauling, pipeline
construction, well design, well-site monitoring and surveillance, permitting and
environmental assessment when it is prudent and necessary to do so. We believe
that this use of third-party service providers may enhance our ability to
contain operating and general expenses, and capital costs.
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 prospectus, there are no
material pending legal proceedings to which we are a party or to which any of
our property is subject.
Facilities
We
currently maintain an office at 27 Corporate Woods, Suite 350, 10975 Grandview
Drive, Overland Park, Kansas 66210. This space is leased pursuant to a five year
lease that expires in August 2013.
MANAGEMENT
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
|
53
|
President,
Chief Executive Officer, and Chairman
|
None
|
|||
Dierdre
P. Jones
|
45
|
Chief
Financial Officer
|
None
|
|||
Robert
G. Wonish
|
56
|
Director
|
GCNC
(Chairman) and Audit
|
|||
Daran
G. Dammeyer
|
48
|
Director
|
Audit
(Chairman) and GCNC
|
|||
Darrel
G. Palmer
|
51
|
Director
|
GCNC
|
|||
Dr.
James W. Rector
|
|
48
|
|
Director
|
|
None
|
|
(1)
|
“GCNC” means the
Governance, Compensation and Nominating Committee of the Board of
Directors. “Audit” means the Audit
Committee of the Board of
Directors.
|
C. Stephen Cochennet, has
been our President, Chief Executive Officer and Chairman since August 15,
2006. Prior to joining EnerJex, Mr. Cochennet was
President of CSC Group, LLC. Mr. Cochennet formed the CSC Group, LLC through
which he supported a number of clients that included Fortune 500 corporations,
international companies, natural gas/electric utilities, outsource service
providers, as well as various start up organizations. The services provided
included strategic planning, capital formation, corporate development, executive
networking and transaction structuring. From 1985 to 2002, he held several
executive positions with UtiliCorp United Inc. (Aquila) in Kansas City. His
responsibilities included finance, administration, operations, human resources,
corporate development, natural gas/energy marketing, and managing several new
start up operations. Prior to his experience at UtiliCorp United Inc., Mr.
Cochennet served 6 years with the Federal Reserve System. Mr. Cochennet
graduated from the University of Nebraska with a B.A. in Finance and
Economics.
Dierdre P. Jones was promoted
to Chief Financial Officer on July 23, 2008. Ms. Jones was our Director of
Finance and Accounting from August 2007 through July 2008. From May 2007
through August 2007, Ms. Jones provided independent consulting services for the
company, primarily in the testing and implementation of financial accounting and
reporting software. From May 2002 through May 2007, Ms. Jones was sole
proprietor of These Faux
Walls, a specialty design company. She holds the professional
designations of Certified Public Accountant and Certified Internal
Auditor. Prior to joining EnerJex, Ms. Jones held management positions
with UtiliCorp United Inc. (Aquila), and served three years in public accounting
with Arthur Andersen & Co. Ms. Jones graduated with distinction from the
University of Kansas with a B.S. in Accounting and Business
Administration.
61
Robert G. Wonish has served
as a member of our board of directors since May 2007. Effective April 7, 2009,
Mr. Wonish was appointed President and Chief Operating Officer of Petrodome
Energy, LLC, a privately held firm. From December 2004 to June 30, 2007, Mr.
Wonish was Vice President of Petroleum Engineers Inc., a subsidiary of The CYMRI
Corporation, now CYMRI, L.L.C., which is a wholly-owned subsidiary of Stratum
Holdings, Inc. On July 1, 2007, Mr. Wonish was appointed President and Chief
Operating Officer of Petroleum Engineers Inc. Mr. Wonish was also President of
CYMRI, L.L.C. After the sale of Petroleum Engineers Inc. in March of 2008, Mr.
Wonish resigned all positions in Petroleum Engineers Inc. and CYMRI, L.L.C. as
well as resigning as a member of the Stratum Holdings, Inc. board of directors.
Mr. Wonish held the position of President & Chief Operating Officer of
Striker Oil & Gas, Inc. prior to his engagement with Petrodome Energy,
LLC.. He previously achieved positions of increasing responsibility
with PANACO, Inc., a public oil and natural gas company, ultimately serving as
that company’s President and Chief Operating Officer. He began his engineering
career at Amoco in 1975 and joined Panaco’s engineering staff in
1992. Mr. Wonish serves as EnerJex’s chairman of the Governance,
Compensation and Nominating committee and is a member of the company’s audit
committee. Mr. Wonish received his Mechanical Engineering degree from the
University of Missouri-Rolla.
Daran G. Dammeyer, has served
as a member of our board of directors since May 2007. Since July 1999, Mr.
Dammeyer has served as President of D-Two Solutions through which he supports
clients by primarily providing merger and acquisition support, strategic
planning, budgeting and forecasting process development and
implementation. From March 1999 through July 1999, Mr. Dammeyer was a
Director of International Financial Management for UtiliCorp United Inc.
(Aquila), a multinational energy solutions provider in Kansas City,
Missouri. From November 1995 through March 1999, Mr. Dammeyer served
as the Chief Financial Controller of United Energy Limited in Melbourne,
Australia. Mr. Dammeyer also served in numerous management positions
at Michigan Energy Resources Company, including Director of Internal
Audit. Mr. Dammeyer earned his Bachelor of Business Administration
degree, with dual majors in Accounting and Corporate Financial Management from
The University of Toledo, Ohio.
Darrel G. Palmer, has served
as a member of our board of directors since May of 2007. Since January 1997, Mr.
Palmer has been President of Energy Management Resources, an energy process
management firm serving industrial and large commercial companies throughout the
U. S. and Canada. Mr. Palmer has 25 years of expertise in the natural
gas arena. His experiences encompass a wide area of the natural gas
industry and include working for natural gas marketing companies, local
distribution companies, and FERC regulated pipelines. Prior to
becoming an independent energy consultant in 1997, Mr. Palmer’s last position
was Vice President/National Account Sales at UtiliCorp United Inc. (Aquila) of
Kansas City, Missouri. Over the years Mr. Palmer has worked in many civic
organizations including United Way and has been a President of the local Kiwanis
Club. Junior Achievement of Minnesota awarded him the Bronze
Leadership Award for his accomplishments which included being an advisor,
program manager, holding various Board positions, and ultimately being Board
President.
Dr. James W. Rector, has
served as a member of our board of directors since March 19, 2008. Dr. Rector is
the author of numerous technical papers along with a number of patents on
seismic technology. He was a co-founder of two seismic technology startups that
were later sold to NYSE-listed companies, and he regularly consults for many of
the major oil companies including Chevron and BP. In 1998, he founded Berkeley
GeoImaging LLC, which has completed five equity private placements for oil and
natural gas exploration and development projects. Dr. Rector is a tenured
professor of Geophysics at the University of California at Berkeley and a
faculty staff scientist at the Lawrence Berkeley National Laboratory. He has
been the Editor-in-Chief of the Journal of Applied Geophysics
and has also served on the Society of Exploration Geophysicists Executive
Committee. He received his Masters and Ph.D. degrees in Geophysics from Stanford
University.
Board
of Directors
Our board of directors currently
consists of five members. Our directors serve one-year terms. Our board of
directors has affirmatively determined that Messrs. Wonish, Dammeyer, Palmer and
Dr. Rector are independent directors, as defined by Section 803 of the American
Stock Exchange Company Guide.
62
Committees
of the Board of Directors
Our board of directors has two standing
committees: an audit committee and a governance, compensation and nominating
committee. Each of those committees has the composition and responsibilities set
forth below.
Audit
Committee
On May 4,
2007, we established and appointed initial members to the audit committee of our
board of directors. Mr. Dammeyer is the chairman and Mr. Wonish serves as the
other member of the committee. Currently, none of the members of the
audit committee are, or have been, our officers or employees, and each member
qualifies as an independent director as defined by Section 803 of the American
Stock Exchange Company Guide and Section 10A(m) of the Securities Exchange Act
of 1934, and Rule 10A-3 thereunder. The Board of Directors has
determined that Mr. Dammeyer is an “audit committee financial
expert” as that term is used in Item 401(h) of Regulation S-K
promulgated under the Securities Exchange Act. The audit committee held five
meetings during fiscal 2009.
The audit
committee has the sole authority to appoint and, when deemed appropriate,
replace our independent registered public accounting firm, and has established a
policy of pre-approving all audit and permissible non-audit services provided by
our independent registered public accounting firm. The audit committee has,
among other things, the responsibility to evaluate the qualifications and
independence of our independent registered public accounting firm; to review and
approve the scope and results of the annual audit; to review and discuss with
management and the independent registered public accounting firm the content of
our financial statements prior to the filing of our quarterly reports and annual
reports; to review the content and clarity of our proposed communications with
investors regarding our operating results and other financial matters; to review
significant changes in our accounting policies; to establish procedures for
receiving, retaining, and investigating reports of illegal acts involving us or
complaints or concerns regarding questionable accounting or auditing matters,
and supervise the investigation of any such reports, complaints or concerns; to
establish procedures for the confidential, anonymous submission by our employees
of concerns or complaints regarding questionable accounting or auditing matters;
and to provide sufficient opportunity for the independent auditors to meet with
the committee without management present.
Governance,
Compensation and Nominating Committee
The
governance, compensation and nominating committee is comprised of Messrs.
Wonish, Dammeyer and Palmer. Mr. Wonish serves as the chairman of the
governance, compensation and nominating committee. The governance,
compensation and nominating committee is responsible for,
among other things; identifying, reviewing,
and evaluating individuals qualified to become members of the Board, setting the
compensation of the Chief Executive Officer and performing other compensation
oversight, reviewing and recommending the nomination of Board members, and
administering our equity compensation plans. The governance, compensation and
nominating committee held five meetings during fiscal 2009.
NON-EMPLOYEE
DIRECTOR COMPENSATION
The
following table sets forth summary compensation information for the fiscal year
ended March 31, 2009 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
|
$ | 58,000 | $ | 12,000 |
(1)
|
$ | -0- | $ | -0- | $ | 70,000 | |||||||||
Darrel
G. Palmer
|
$ | 26,500 | $ | -0- | $ | -0- | $ | 20,000 |
(3)
|
$ | 46,500 | |||||||||
Robert
G. Wonish
|
$ | 49,000 | $ | -0- | $ | -0- | $ | -0- | $ | 49,000 | ||||||||||
Dr.
James W. Rector
|
$ | 22,500 | $ | -0- | $ | -0- | $ | -0- | $ | 22,500 |
63
(1)
|
Amount
represents the estimated total fair market value of 2,182 shares of common
stock issued to Mr. Dammeyer for services as audit committee chairman
under SFAS 123(R), as discussed in Note 3 to our audited financial
statements for the year ended March 31, 2009 included elsewhere in this
prospectus.
|
(2)
|
In
July, 2008, 28,000 stock options were granted to each of Messrs. Dammeyer,
Palmer and Wonish and 38,000 stock options were granted to Dr. Rector
under SFAS 123(R), as discussed in Note 3 to our financial statements for
the year ended March 31, 2009 included elsewhere in this prospectus. These
total 122,000 options granted to Messrs. Dammeyer, Palmer and Wonish and
to Dr. Rector were rescinded in November
2008.
|
(3)
|
Mr.
Palmer was paid $20,000 for assisting in the establishment and development
of the audit committee and for his involvement and assistance to the chief
executive officer in finalizing the hedging instrument with
BP.
|
Board
compensation was set for fiscal 2009 upon the recommendation of an independent
compensation consultant and the governance, compensation and nominating
committee of the board of directors. The annual retainer for non-employee
directors is $20,000 with a meeting fee of $1,500 for those in attendance and
$750 for those who participate by telephone. The chairman of the audit committee
will be paid an annual retainer of $42,000, payable with $2,500 per month in
cash and $12,000 worth of common stock. Members of the audit committee will be
paid an annual cash retainer of $15,000 and $375 per meeting attended. The
chairman of the governance, compensation and nominating committee will be paid
an annual cash retainer of $8,000, payable quarterly, while members of that
committee will be paid an annual cash retainer of $2,000, payable quarterly, and
$375 per meeting attended. In addition, the directors are reimbursed for
expenses incurred in connection with board and committee
membership.
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 our 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 our restricted common stock.
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.
EXECUTIVE
COMPENSATION
The
following table sets forth summary compensation information for the fiscal years
ended March 31, 2009 and 2008 for our chief executive officer and chief
financial officer. We did not have any other executive officers as of the end of
fiscal 2009 whose total compensation exceeded $100,000. We refer to these
persons as our named executive officers elsewhere in this
prospectus.
Summary Compensation
Table
Name and Principal Position
|
Fiscal
Year
|
Salary
($)
|
Bonus
($)
|
Option
Awards
($)
|
All Other
Compen-sation
($)
|
Total
($)
|
||||||||||||||||
C.
Stephen Cochennet
|
2009
|
$ | 186,525 | $ | 50,000 | $ | - |
(2)
|
$ | - | $ | 236,525 | ||||||||||
President,
Chief Executive Officer
|
2008
|
$ | 156,000 | - | 859,622 |
(1)
|
- | $ | 1,015,622 | |||||||||||||
Dierdre
P. Jones
|
2009
|
$ | 128,808 | $ | 10,000 | - |
(2)
|
- | $ | 138,808 | ||||||||||||
Chief
Financial Officer
|
2008
|
- |
(3)
|
- |
(3)
|
- |
(3)
|
- |
(3)
|
- |
(3)
|
64
|
(1)
|
Amount
represents the estimated total fair value of stock options granted to Mr.
Cochennet under SFAS 123(R). These options were exchanged for shares
of restricted common stock in August of
2009.
|
|
(2)
|
In
August, 2008, we granted C. Stephen Cochennet, our chief executive
officer, an option to purchase 75,000 shares of our common stock at $6.25
per share and we granted Dierdre P. Jones, our chief financial officer,
and option to purchase 40,000 shares of our common stock at $6.25 per
share under SFAS 123(R) as discussed in Note 3 to our financial statements
for the year ended March 31, 2009 included elsewhere in this prospectus.
These options were rescinded in November 2008 at the request of the
board’s compensation committee and the approval of each option
holder.
|
|
(3)
|
Ms.
Jones was promoted to chief financial officer during fiscal 2009 and was
not a named executive officer in fiscal
2008.
|
Outstanding Equity Awards at Fiscal
Year-End
The
following table lists the outstanding equity incentive awards held by our named
executive officers as of March 31, 2009.
Option Awards
|
|||||||||||||||||||
Fiscal
Year
|
Number of
Securities
Underlying
Unexercised
Options
Exercisable
(#)
|
Number of
Securities
Underlying
Unexercised
Options
Unexercisable
(#)
|
Number of
Securities
Underlying
Unexercised
Unearned
Options
(#)
|
Option
Exercise
Price
($)
|
Option
Expiration
Date
|
||||||||||||||
C.
Stephen Cochennet
|
2009
|
200,000 |
(1)
|
- | - | $ | 6.25 |
05/03/2011
|
|||||||||||
Dierdre
P. Jones
|
2009
|
20,000 |
(2)
|
- | - | $ | 6.30 |
07/31/2011
|
|
(1)
|
These
options were exchanged for 50,000 shares of restricted common stock in
August of 2009.
|
|
(2)
|
These
options were exchanged for 5,000 shares of restricted common stock in
August of 2009.
|
Potential Payments Upon Termination
or Change in Control
We
entered into employment agreements with both of our named executive officers
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 the person’s
responsibilities following a change in control.
Option
Exercises for fiscal 2009
There
were no options exercised by our named executive officers in fiscal
2009.
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.
65
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.
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.
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.
66
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.
Potential
|
Maximum #
|
Option
|
|||||||||||
Fiscal Year
|
Grant Date
|
of Options
|
Strike Price of Options
|
Expiration Date*
|
|||||||||
2009
|
7/01/2009
|
30,000
|
Fair
market value on grant date
|
6/30/2012
|
|||||||||
2010
|
7/01/2010
|
45,000
|
Fair
market value on grant date
|
6/30/2013
|
|||||||||
2011
|
7/01/2011
|
60,000
|
Fair
market value on grant date
|
6/30/2014
|
|
*
|
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.
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.
67
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.
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.
In
general, Ms. Jones’ employment agreement contains provisions concerning terms of
employment, voluntary and involuntary termination, indemnification, severance
payments, and other termination benefits, in addition to certain other
perquisites. The original term of the employment agreement runs from August 1,
2008 until July 31, 2011.
Ms.
Jones’ employment agreement provides for an initial annual base salary of
$140,000, which may be adjusted by the governance, compensation and nominating
committee or our board of directors.
In
addition, Ms. Jones is eligible to receive an annual bonus up to 30% of her
applicable base salary and is also eligible to participate in other incentive
programs established by us.
We
granted Ms. Jones 40,000 options to purchase shares of our common stock at $6.25
per share for a period of three years, which vested immediately upon
grant. These options were rescinded in November 2008 at the request
of the board’s compensation committee and with the approval of Ms. Jones 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 Ms. Jones 10,000 shares of twelve month
restricted stock in consideration for the prior rescission of the options
discussed above.
68
In the
event of a termination of employment by Jones for “good reason” prior to a
“change of control” or
by us without “cause”
prior to a “change of
control” (each as defined in the employment agreement), Ms. Jones would
receive: (i) a lump sum payment equal to 12 months of her salary; plus (ii) a
lump sum payment equal to the prorated portion of her bonus through the date of
termination; plus (iii) all unvested stock or options held by Jones shall
immediately vest and become exercisable for the full term set forth in such
stock option or equity award agreements; plus (iv) health insurance premiums for
a period of 12 months.
In the
event of the termination of Ms. Jones’ employment by us in connection with a
“change of control” (as
defined in the employment agreement), without cause within 12 months of a “change of control”, or by Ms.
Jones for “good reason”
within 12 months of a “change
of control,” Ms. Jones shall be entitled to: (i) a lump sum payment equal
to 12 months of her salary; plus (ii) a lump sum payment equal to 100% of her
prior year’s bonus; plus (iii) all unvested stock or options held by Jones shall
immediately vest and become exercisable for the full term set forth in such
stock option or equity award agreements; plus (iv) health insurance premiums for
a period of 12 months.
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
We
describe below transactions and series of similar transactions that have
occurred during fiscal 2009 and during the fiscal years ended March 31, 2008,
2007 and 2006 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; 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.
|
On March
14, 2006 and July 21, 2006, we paid consulting fees totaling $121,000 in
connection with financing activities to Goran Blagojevic, a
stockholder.
Our board
of directors has affirmatively determined that Messrs. Wonish, Dammeyer, Palmer
and Dr. Rector are independent directors, as defined by Section 803 of the
American Stock Exchange Company Guide. Mr. Palmer is not eligible to serve on
our Audit Committee pursuant to Section 10A(m)(3) of the Securities Exchange Act
of 1934, as amended.
PRINCIPAL
STOCKHOLDERS
The
following table presents information, to the best of EnerJex’s knowledge, about
the ownership of EnerJex’s common stock on February 22, 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 4,979,928 shares of common stock
outstanding.
Beneficial
ownership is determined in accordance with the rules of the Securities and
Exchange Commission and does not necessarily indicate beneficial ownership for
any other purpose. Under these rules, beneficial ownership includes those shares
of common stock over which the stockholder has sole or shared voting or
investment power. It also includes shares of common stock that the stockholder
has a right to acquire within 60 days after February 22, 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.
69
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 |
(4)
|
10.9 | % | ||||
Dierdre
P. Jones, Chief Financial Officer(3)
|
15,000 |
(5)
|
* | |||||
Robert
(Bob) G. Wonish, Director(3)
|
32,000 | * | ||||||
Darrel
G. Palmer, Director(3)
|
32,000 | * | ||||||
Daran
G. Dammeyer, Director(3)
|
48,102 | * | ||||||
Dr.
James W. Rector, Director(3)
|
24,500 | * | ||||||
Directors
and Officers as a Group
|
693,663 | 13.9 | % | |||||
West
Coast Opportunity Fund LLC(6)
|
1,486,153 | 29.8 | % | |||||
West
Coast Asset Management, Inc.
|
||||||||
Paul
Orfalea, Lance Helfert & R. Atticus Lowe
|
||||||||
2151
Alessandro Drive, #100
|
||||||||
Ventura,
CA 93001
|
||||||||
Enable
Growth Partners L.P.(7)
|
286,270 | 5.7 | % | |||||
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., the power 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)
|
Does
not include 75,000 shares of restricted stock that could be issued on
August 4, 2010 if Mr. Cochennet remains an employee of EnerJex through
August 3, 2010.
|
|
(5)
|
Does
not include 20,000 shares of restricted stock that could be issued on
August 4, 2010 if Ms. Jones remains an employee of EnerJex through August
3, 2010.
|
|
(6)
|
Based
on a Schedule 13D/A filed with the SEC on February 16, 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. Includes 500,000 shares of common stock
underlying the potential conversion of a $1,500,000 debenture currently
held by WCOF.
|
70
|
(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. and other clients. 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.
|
DESCRIPTION
OF CAPITAL STOCK
Common
Stock
Our
articles of incorporation authorize the issuance of 100,000,000 shares of common
stock, $0.001 par value per share, of which 4,979,928 shares were outstanding as
of February 22, 2010. Holders of common stock have no cumulative voting rights.
Holders of shares of common stock are entitled to share ratably in dividends, if
any, as may be declared, from time to time by the board of directors in its
discretion, from funds legally available to be distributed. In the event of a
liquidation, dissolution or winding up of us, the holders of shares of common
stock are entitled to share pro rata all assets remaining after payment in full
of all liabilities. Holders of common stock have no preemptive rights to
purchase our common stock. There are no conversion rights or redemption or
sinking fund provisions with respect to the common stock. All of the outstanding
shares of common stock are validly issued, fully paid and
non-assessable.
Preferred
Stock
Our
articles of incorporation authorizes the issuance of 10,000,000 shares of
preferred stock, $0.001 par value per share, of which no shares were outstanding
as of the date of this prospectus. The preferred stock may be issued from time
to time by the board of directors as shares of one or more classes or series.
Our board of directors, subject to the provisions of our articles of
incorporation and limitations imposed by law, is authorized to:
•
|
adopt
resolutions;
|
•
|
issue
the shares;
|
•
|
fix
the number of shares;
|
•
|
change
the number of shares constituting any series;
and
|
•
|
provide
for or change the following:
|
•
|
the
voting powers;
|
•
|
designations;
|
•
|
preferences;
and
|
•
|
relative,
participating, optional or other special rights, qualifications,
limitations or restrictions, including the
following:
|
•
|
dividend
rights, including whether dividends are
cumulative;
|
•
|
dividend
rates;
|
•
|
terms
of redemption, including sinking fund
provisions;
|
71
•
|
redemption
prices;
|
•
|
conversion
rights; and
|
•
|
liquidation
preferences of the shares constituting any class or series of the
preferred stock.
|
In each
of the listed cases, we will not need any further action or vote by the
stockholders.
One of
the effects of undesignated preferred stock may be to enable the board of
directors to render more difficult or to discourage an attempt to obtain control
of us by means of a tender offer, proxy contest, merger or otherwise, and
thereby to protect the continuity of our management. The issuance of shares of
preferred stock pursuant to the board of director’s authority described above
may adversely affect the rights of holders of common stock. For example,
preferred stock issued by us may rank prior to the common stock as to dividend
rights, liquidation preference or both, may have full or limited voting rights
and may be convertible into shares of common stock. Accordingly, the issuance of
shares of preferred stock may discourage bids for the common stock at a premium
or may otherwise adversely affect the market price of the common
stock.
Debenture
Financing
On April
11, 2007, we entered into financing agreements for $9.0 million of senior
secured debentures. The debentures mature on September 30, 2010 and bear an
interest rate equal to 10% per annum. In accordance with the terms of the
debentures, we received $6.3 million (before expenses and placement fees) at the
first closing on April 13, 2007 and an additional $2.7 million on June 21, 2007.
Net proceeds from the debentures were approximately $8.3 million, after
approximately $700,000 in fees and expenses to our placement agent, C. K. Cooper
& Company, attorney’s fees and post-closing fees and expenses. On July 7,
2008, we redeemed debentures with an aggregate principal amount of $6.3 million
with proceeds from our new senior secured credit facility. 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.
Further, in June 2009 we amended the Debentures 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. Further, in November 2009, we amended the debentures to amend
the company redemption section of the debentures to allow for the retirement of
shares of our common stock held by the debenture holders if we meet certain
redemption payment schedules and to amend the debenture holders’ rights to
participate in certain future debt or equity offerings made by us. In
January 2010, we further amended the Debentures to extend the scheduled due
dates for the January and February 2010 redemption payments to March 10,
2010.
In
connection with the sale of the debentures, we issued the debenture holders
1,800,000 shares of common stock (1,260,000 shares of common stock were issued
on April 13, 2007 and 540,000 shares of common stock were issued on June 21,
2007).
Right to Redeem
Debenture. So long as a registration statement covering all of
the registrable securities is effective, we have the option of prepaying the
principal, in whole but not in part by paying the amount equal to 100% of the
principal, together with accrued and unpaid interest by giving six (6) business
days prior notice of redemption to the lenders. During the quarter ended June
30, 2009, we repurchased $450,000 of the Debentures. In November of 2009 we
amended the debentures to allow for the retirement of shares of our common stock
held by the debenture holders on a 0.5 share for each $1.00 redeemed if we meet
certain redemption payment schedules.
Interest. Interest is payable
quarterly in arrears on the first day of each succeeding quarter. The interest
rate is 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 and
additional 2.5% of the quarterly interest payment due.
72
Registration
Rights. Pursuant to the terms of the Registration Rights
Agreement, as amended, we are obligated to register 1,000,000 shares of common
stock issuable under the debentures.
If we
fail to obtain and maintain the effectiveness of this registration statement
through a date which the lender may sell all of its shares of common stock
without restriction under Rule 144 of the Securities Act or the date on which
the debenture holders shall have sold all of its shares of common required to be
covered by this registration statement, we will be obligated to pay cash to this
debenture holders equal to 1.5% of the aggregate purchase price allocable to
such lender’s registrable securities included in such registration statement for
each 30 day period following such effectiveness failure or maintenance failure.
These payments are capped at 10% of the lender’s original purchase price as
defined in the registration rights agreement.
Conversion Rights. 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.
Preemptive
Rights. So long as any debenture is outstanding, the debenture
holders have the right to participate in any subsequent issuance of equity or
equity equivalent securities up to each holder’s pro rata portion, based on the
holder’s ownership of shares of common stock compared to the then-outstanding
shares of common stock. At least five days before the closing of a subsequent
issuance, we must give each debenture holder written notice of the issuance and
each debenture holder may request specified additional information and may elect
to participate in the issuance.
The
preemptive rights do not apply to specified issuances, including: (1) options
issued pursuant to an employee benefit plan for up to 1,000,000 options on
specified terms; (2) securities issued in a bona fide underwritten public
offering; and (3) issuances for services performed, at a value not less than
$3.00 per share.
Additional Restrictions and
Operational Covenants. In addition to standard covenants and
conditions such as us maintaining our reporting status with the SEC pursuant to
the Exchange Act, the debentures contain certain restrictions regarding our
operations, including limitations on our ability to incur liens or additional
debt, pay dividends, redeem our stock, make specified investments and engage in
merger, consolidation or asset sale transactions, among other
restrictions.
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.
73
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.
Liability
and Indemnification of Officers and Directors
Our
articles of incorporation and by-laws provide that our directors and officers
shall not be personally liable to us or our stockholders for damages for breach
of fiduciary duty as a director or officer, except for liability for (a) acts of
omissions which involve intentional or reckless conduct, fraud or a knowing
violation of law, or (b) the payment of distributions in violation of Section
78.300 of the Nevada Revised Statutes.
In
addition, on October 14, 2008, we entered into identical indemnification
agreements with each member of our board of directors and each of our executive
officers (the “Indemnification
Agreements”). The Indemnification Agreements provide that we will
indemnify each such director or executive officer to the fullest extent
permitted by Nevada law if he or she becomes a party to or is threatened with
any action, suit or proceeding arising out of his or her service as a director
or executive officer. The Indemnification Agreements also provide
that we will advance, if requested by an indemnified person, any and all
expenses incurred in connection with any such proceeding, subject to
reimbursement by the indemnified person should a final judicial determination be
made that indemnification is not available under applicable law. The
Indemnification Agreements further provide that if we maintain directors’ and
officers’ liability coverage, each indemnified person shall be included in such
coverage to the maximum extent of the coverage available for our directors or
executive officers.
Transfer
Agent
The
transfer agent for our common stock is Standard Registrar & Transfer Company
Inc., 12528 South 1840 East, Draper, Utah 84020.
SELLING
STOCKHOLDER
The
Selling Stockholder named in the table below is offering for resale up to
1,390,000 shares of our common stock. We are registering the shares
covered hereby to permit the Selling Stockholder to offer the shares for resale
from time to time. Other than the ownership of our shares of common
stock, the Selling Stockholder has not within the past three years held a
position or office, had any other material relationship with, or otherwise been
affiliated with, us or any of our predecessors or affiliates. Based
on information provided to us, the Selling Stockholder is not affiliated, nor
has it been affiliated, with any broker-dealer in the United
States.
The named
Selling Stockholder may resell the shares of common stock covered by this
prospectus as provided under the section entitled “Plan of Distribution” and in
any applicable prospectus supplement.
The
following table sets forth the number of shares of our common stock beneficially
owned and the percentage of ownership by the Selling Stockholder as of the date
hereof, the number of shares offered hereby, the number of shares of common
stock that will be beneficially owned and the percentage of ownership of the
Selling Stockholder after the completion of this offering, assuming the sale of
all shares offered and no other changes in beneficial ownership. The
Selling Stockholder may sell all, some or none of its shares in this
offering. See “Plan
of Distribution.” The information set forth below is based on
information provided to us by or on behalf of the Selling
Stockholder.
74
Shares Beneficially Owned
Prior To The Offering
|
Shares Beneficially Owned
After The Offering
|
|||||||||||||||||||
Name
|
Number
|
Percent(1)
|
Maximum
Number Of
Shares Being
Offered
|
Number
|
Percent
|
|||||||||||||||
Paladin
Capital Management, S.A. (1)
|
90,000 |
(2)
|
1.8 | % | 1,390,000 | 0 | * |
|
(1)
|
Applicable
percentage ownership is based on 4,979,928 shares of our common stock
outstanding as of February 22,
2010.
|
|
(2)
|
Paladin
is the investor under the SEDA. Ms. Lidia Matos, the portfolio manager of
Paladin, makes the investment decisision on its behalf. Paladin acquired,
or will acquire, all shares being registered in this offering in financing
transactions with us.
|
|
(3)
|
This
number represents the shares currently held by the Selling Stockholder and
does not include any additional shares which may be sold to the Selling
Stockholder pursuant to the terms of the SEDA. On December 3, 2009, we
authorized the issuance of 90,000 shares of common stock to Paladin for
the payment of a commitment fee.
|
PLAN
OF DISTRIBUTION
We are
registering these shares of our common stock to permit the resale of these
shares by the Selling Stockholder from time to time after the date of this
prospectus. We will not receive any of the proceeds from the sale by
the Selling Stockholder of these shares. We will bear all fees and
expenses incident to the registration of these shares.
The
Selling Stockholder may sell all or a portion of these shares from time to time
directly or through one or more underwriters, broker-dealers or
agents. If these shares are sold through underwriters or
broker-dealers, the Selling Stockholder will be responsible for underwriting
discounts and commissions and brokers’ or agents’ commissions or selling
commissions. These shares may be sold in one or more transactions at
fixed prices, at prevailing market prices at the time of the sale, at varying
prices determined at the time of sale, or at negotiated prices. These
sales may be effected in transactions, which may involve crosses or block
transactions,
|
·
|
on
any national securities exchange or quotation service on which the
securities may be listed or quoted at the time of
sale;
|
|
·
|
in
the over-the-counter market;
|
|
·
|
in
transactions otherwise than on these exchanges or systems or in the
over-the-counter market;
|
|
·
|
through
the writing of options, whether such options are listed on an options
exchange or otherwise;
|
|
·
|
ordinary
brokerage transactions and transactions in which the broker-dealer
solicits purchasers;
|
|
·
|
block
trades in which the broker-dealer will attempt to sell the shares as agent
but may position and resell a portion of the block as principal to
facilitate the transaction;
|
|
·
|
purchases
by a broker-dealer as principal and resale by the broker-dealer for its
account;
|
|
·
|
an
exchange distribution in accordance with the rules of the applicable
exchange;
|
|
·
|
privately
negotiated transactions;
|
|
·
|
short
sales entered into after the effective date of the registration statement
of which this prospectus is a part;
|
|
·
|
sales
pursuant to Rule 144;
|
|
·
|
broker-dealers
may agree with the Selling Stockholder to sell a specified number of such
shares at a stipulated price per
share;
|
|
·
|
a
combination of any such methods of sale;
and
|
|
·
|
any
other method permitted pursuant to applicable
law.
|
75
If the
Selling Stockholder effects such transactions by selling shares to or through
underwriters, broker-dealers or agents, such underwriters, broker-dealers or
agents may receive commissions in the form of discounts, concessions or
commissions from the Selling Stockholder or commissions from purchasers of the
shares for whom they may act as agent or to whom they may sell as principal
(which discounts, concessions or commissions as to particular underwriters,
broker-dealers or agents may be in excess of those customary in the types of
transactions involved). No such broker-dealer will receive
compensation in excess of that permitted by FINRA Rule 2440 and
IM-2440. In no event will any broker-dealer receive total
compensation in excess of 8%.
The
Selling Stockholder and any broker-dealer participating in the distribution of
these shares are “underwriters” within the
meaning of the Securities Act, and any commission paid, or any discounts or
concessions allowed to, any such broker-dealer may be deemed to be underwriting
commissions or discounts under the Securities Act. At the time a
particular offering of these shares is made, a prospectus supplement, if
required, will be distributed which will set forth the aggregate amount of
shares being offered and the terms of the offering, including the name or names
of any broker-dealers or agents, any discounts, commissions and other terms
constituting compensation from the Selling Stockholder and any discounts,
commissions or concessions allowed or reallowed or paid to
broker-dealers.
Under the
securities laws of some states, the shares of our common stock may be sold in
such states only through registered or licensed brokers or
dealers. In addition, in some states the shares of our common stock
may not be sold unless such shares have been registered or qualified for sale in
such state or an exemption from registration or qualification is available and
is complied with.
There can
be no assurance that the Selling Stockholder will sell any or all of the shares
of our common stock registered pursuant to the registration statement of which
this prospectus forms a part.
The
Selling Stockholder and any other person participating in such distribution will
be subject to applicable provisions of the Securities Exchange Act of 1934, as
amended, and the rules and regulations thereunder, including, without
limitation, Regulation M of the Exchange Act, which may limit the timing of
purchases and sales of any of the shares of our common stock by the Selling
Stockholder and any other participating person. Regulation M may also
restrict the ability of any person engaged in the distribution of the shares of
our common stock to engage in market-making activities with respect to such
shares. All of the foregoing may affect the marketability of the
shares of our common stock and the ability of any person or entity to engage in
market-making activities with respect to our common stock.
We will
pay all expenses of the registration of these shares, including, without
limitation, Securities and Exchange Commission filing fees and expenses of
compliance with state securities or “blue sky” laws; provided,
however, that the Selling Stockholder will pay all underwriting discounts,
commissions and concessions and brokers’ or agents’ commissions and concessions
or selling commissions and concessions, if any. We have agreed to
indemnify the Selling Stockholder against liabilities, including some
liabilities under the Securities Act, or the Selling Stockholder will be
entitled to contribution. We may be indemnified by the Selling
Stockholder against civil liabilities, including liabilities under the
Securities Act, that may arise from any written information furnished to us by
the Selling Stockholder specifically for use in this prospectusor we may be
entitled to contribution.
LEGAL
MATTERS
The
validity of the issuance of the shares of common stock offered hereby will be
passed upon for us by the DeMint Law, PLLC, Las Vegas, Nevada.
EXPERTS
Weaver
& Martin, LLC, independent registered public accounting firm, has audited
our financial statements at March 31, 2008 and March 31, 2009, as set forth in
their reports. We have included our financial statements in the prospectus and
elsewhere in the registration statement in reliance on Weaver & Martin,
LLC’s report, given on their authority as experts in accounting and
auditing.
76
INDEPENDENT
PETROLEUM ENGINEERS
Certain
information incorporated herein regarding estimated quantities of oil and
natural gas reserves and their present value is based on estimates of the
reserves and present values prepared by or derived from estimates prepared by
Miller and Lents, Ltd., independent petroleum engineers and geologists. The
reserve information is incorporated herein in reliance upon the authority of
said firm as an expert with respect to such report.
WHERE
YOU CAN FIND MORE INFORMATION
We have
filed a registration statement on Form S-1 under the Securities Act with the SEC
with respect to the common stock offered by this prospectus. This prospectus
does not include all of the information contained in the registration statement
or the exhibits and schedules filed therewith. You should refer to the
registration statement and its exhibits for additional information. Whenever we
make reference in this prospectus to any of our contracts, agreements or other
documents, the references are not necessarily complete and you should refer to
the exhibits attached to the registration statement for copies of the actual
contract, agreement or other document.
We file
annual, quarterly and special reports and other information with the SEC. You
can read these SEC filings and reports, including the registration statement,
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 of your written request to us at
EnerJex Resources, Inc., 27 Corporate Woods, Suite 350, 10975 Grandview Drive,
Overland Park, Kansas 66210.
77
GLOSSARY
Term
|
Definition
|
|
Barrel
(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.
|
|
BOE
|
One barrel of oil equivalent,
determined using a ratio of six Mcf of natural gas to one barrel of crude
oil.
|
|
BOEPD
|
BOE per
day.
|
|
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.
|
|
Costless
Collar
|
When viewed against an appropriate
index, the parties agree to a maximum price (call option) and a minimum
price (put option), through a financially-settled collar. If the average
monthly prices are within the collar range there will be no monthly
settlement. However, if average monthly prices fluctuate outside the
collar, the parties settle the difference in
cash.
|
|
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.
|
|
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).
|
78
Term
|
Definition
|
|
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.
|
|
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.
|
79
Term
|
Definition
|
|
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 33 for a reconciliation to the
comparable GAAP financial measure.
|
|
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.
|
|
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.
|
80
INDEX
TO FINANCIAL STATEMENTS
Page
|
||
Index to Financial
Statements
|
|
|
Report of Independent Registered
Public Accounting Firm
|
F-1
|
|
Consolidated Balance Sheets at
March 31, 2009 and 2008
|
F-2
|
|
Consolidated Statements of
Operations for the Fiscal Years Ended March 31, 2009 and
2008
|
F-3
|
|
Consolidated Statement of
Stockholders’ Equity(Deficit) for the Fiscal Years Ended March 31, 2009
and 2008
|
F-4
|
|
Consolidated Statement of Cash
Flows for the Fiscal Years Ended March 31, 2009 and
2008
|
F-5
|
|
Notes to Consolidated Financial
Statements
|
F-6
|
81
Report
of Independent Registered Public Accounting Firm
Stockholders
and Directors
EnerJex
Resources, Inc.
Overland
Park, Kansas
We have
audited the accompanying consolidated balance sheet of EnerJex Resources, Inc.
as of March 31, 2009 and 2008 and the related consolidated statements of
operations, stockholders’ equity (deficit), and cash flows for each of the years
in the two-year period ended March 31, 2009. These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatements. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audit included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company’s internal control over financial
reporting. Accordingly, we express no such opinion. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our
opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of EnerJex Resources,
Inc. as of March 31, 2009 and 2008 and the consolidated results of its
operations and cash flows for each of the years in the two–year period ended
March 31, 2009 in conformity with accounting principles generally accepted in
the United States of America.
The
accompanying financial statements have been prepared assuming that the Company
will continue as a going concern. As discussed in Note 2 to the financial
statements, the Company has suffered recurring losses and had negative cash
flows that raise substantial doubt about the Company's ability to continue as a
going concern. Management's plans in regard to these matters are described in
the Note 2. The financial statements do not include any adjustments that might
result from the outcome of this uncertainty.
/S/
Weaver & Martin, LLC
Weaver
& Martin, LLC
Kansas
City, Missouri
July 9,
2009
F-1
EnerJex
Resources, Inc. and Subsidiaries
Consolidated
Balance Sheets
March
31,
|
||||||||
2009
|
2008
|
|||||||
Assets
|
||||||||
Current
assets:
|
||||||||
Cash
|
$ | 127,585 | $ | 951,004 | ||||
Accounts
receivable
|
462,044 | 227,055 | ||||||
Prepaid
debt issue costs
|
45,929 | 157,191 | ||||||
Deposits
and prepaid expenses
|
263,383 | 176,345 | ||||||
Total
current assets
|
898,941 | 1,511,595 | ||||||
Fixed
assets
|
365,019 | 185,299 | ||||||
Less:
Accumulated depreciation
|
63,988 | 30,982 | ||||||
Total
fixed assets
|
301,031 | 154,317 | ||||||
Other
assets:
|
||||||||
Prepaid
debt issue costs
|
- | 157,191 | ||||||
Oil
and gas properties using full-cost accounting:
|
||||||||
Properties
not subject to amortization
|
31,183 | 62,216 | ||||||
Properties
subject to amortization
|
6,449,023 | 8,982,510 | ||||||
Total
other assets
|
6,480,206 | 9,201,917 | ||||||
Total
assets
|
$ | 7,680,178 | $ | 10,867,829 | ||||
Liabilities
and Stockholders’ Equity (Deficit)
|
||||||||
Current
liabilities:
|
||||||||
Accounts
payable
|
$ | 1,016,168 | $ | 416,834 | ||||
Accrued
liabilities
|
87,811 | 70,461 | ||||||
Notes
payable
|
- | 965,000 | ||||||
Deferred
payments from Euramerica development
|
- | 251,951 | ||||||
Long-term
debt, current
|
1,723,036 | 412,930 | ||||||
Total
current liabilities
|
2,827,015 | 2,117,176 | ||||||
Asset
retirement obligation
|
803,624 | 459,689 | ||||||
Convertible
note payable
|
25,000 | 25,000 | ||||||
Long-term
debt, net of discount of $596,108
|
7,818,163 | 6,831,972 | ||||||
Total
liabilities
|
11,473,802 | 9,433,837 | ||||||
Contingencies
and commitments
|
||||||||
Stockholders’
Equity (Deficit):
|
||||||||
Preferred
stock, $0.001 par value, 10,000,000 shares authorized, no shares issued
and outstanding
|
- | - | ||||||
Common
stock, $0.001 par value, 100,000,000 shares authorized; shares issued and
outstanding –4,443,512 at March 31, 2009 and 4,440,651 at March 31,
2008
|
4,444 | 4,441 | ||||||
Paid
in capital
|
8,932,906 | 8,853,457 | ||||||
Retained
(deficit)
|
(12,730,974 | ) | (7,423,906 | ) | ||||
Total
stockholders’ equity (deficit)
|
(3,793,624 | ) | 1,433,992 | |||||
Total
liabilities and stockholders’ equity (deficit)
|
$ | 7,680,178 | $ | 10,867,829 |
See
Notes to Consolidated Financial Statements.
F-2
EnerJex
Resources, Inc. and Subsidiaries
Consolidated
Statements of Operations
For the Fiscal Years Ended
|
||||||||
March
31,
|
||||||||
2009
|
2008
|
|||||||
Oil
and natural gas revenues
|
$ | 6,436,805 | $ | 3,602,798 | ||||
Expenses:
|
||||||||
Direct
operating costs
|
2,637,333 | 1,795,188 | ||||||
Depreciation,
depletion and amortization
|
911,293 | 935,330 | ||||||
Impairment
of oil and gas properties
|
4,777,723 | - | ||||||
Professional
fees
|
1,320,332 | 1,226,998 | ||||||
Salaries
|
849,340 | 1,703,099 | ||||||
Administrative
expense
|
1,392,645 | 887,872 | ||||||
Total
expenses
|
11,888,666 | 6,548,487 | ||||||
Loss
from operations
|
(5,451,861 | ) | (2,945,689 | ) | ||||
Other
income (expense):
|
||||||||
Interest
expense
|
(882,426 | ) | (792,448 | ) | ||||
Loan
interest accretion
|
(2,814,095 | ) | (1,089,798 | ) | ||||
Gain
on liquidation of hedging instrument
|
3,879,050 | - | ||||||
Other
Gain/(Loss)
|
(37,736 | ) | - | |||||
Total
other income (expense)
|
144,793 | (1,882,246 | ) | |||||
Net
income - (loss)
|
$ | (5,307,068 | ) | $ | (4,827,935 | ) | ||
Weighted
average shares outstanding - basic
|
4,443,249 | 4,284,144 | ||||||
Net
income (loss) per share - basic
|
$ | (1.19 | ) | $ | (1.13 | ) |
See
Notes to Consolidated Financial Statements.
F-3
EnerJex
Resources, Inc. and Subsidiaries
Consolidated
Statements of Stockholders’ Equity (Deficit)
Common Stock
|
||||||||||||||||||||||||
Shares
|
Par Value
|
Owed but not
issued
|
Paid in
Capital
|
Retained Deficit
|
Total
Stockholders’
Equity (Deficit)
|
|||||||||||||||||||
Balance,
April 1, 2007
|
2,635,731 | $ | 2,636 | $ | 3 | $ | 2,548,742 | $ | ( 2,595,971 | ) | $ | (44,590 | ) | |||||||||||
Stock
sold
|
1,800,000 | 1,800 | - | 4,311,956 | - | 4,313,756 | ||||||||||||||||||
Stock
issued for services
|
1,920 | 2 | - | 14,998 | - | 15,000 | ||||||||||||||||||
Previously
authorized but unissued stock
|
3,000 | 3 | (3 | ) | - | - | - | |||||||||||||||||
Stock
options issued for services
|
- | - | - | 1,977,761 | - | 1,977,761 | ||||||||||||||||||
Net
(loss) for the year
|
- | - | - | - | (4,827,935 | ) | (4,827,935 | ) | ||||||||||||||||
Balance,
March 31, 2008
|
4,440,651 | 4,441 | - | 8,853,457 | (7,423,906 | ) | 1,433,992 | |||||||||||||||||
Stock
options issued for services
|
- | - | - | 67,452 | - | 67,452 | ||||||||||||||||||
Stock
issued for services
|
2,182 | 2 | - | 11,998 | - | 12,000 | ||||||||||||||||||
Stock
issued in reverse stock split
|
679 | 1 | - | (1 | ) | - | - | |||||||||||||||||
Net
loss for the year
|
- | - | - | - | $ | (5,307,068 | ) | (5,307,068 | ) | |||||||||||||||
Balance,
March 31, 2009
|
4,443,512 | $ | 4,444 | $ | - | $ | 8,932,906 | $ | ( 12,730,974 | ) | $ | (3,793,624 | ) |
See
Notes to Consolidated Financial Statements.
F-4
EnerJex
Resources, Inc. and Subsidiaries
Consolidated
Statements of Cash Flows
For the Fiscal Years Ended
|
||||||||
March 31,
|
||||||||
2009
|
2008
|
|||||||
Cash
flows from operating activities
|
||||||||
Net
(loss)
|
$ | (5,307,068 | ) | $ | (4,827,935 | ) | ||
Depreciation
and depletion
|
950,357 | 935,330 | ||||||
Debt
issue cost amortization
|
157,191 | 152,453 | ||||||
Stock
and options issued for services
|
79,452 | 1,992,761 | ||||||
Accretion
of interest on long-term debt discount
|
2,814,095 | 1,089,798 | ||||||
Accretion
of asset retirement obligation
|
60,864 | 30,331 | ||||||
Impairment
of oil & gas properties
|
4,777,723 | - | ||||||
Adjustments
to reconcile net (loss) to cash used in operating
activities:
|
||||||||
Accounts
receivable
|
(234,989 | ) | (222,917 | ) | ||||
Notes
and interest receivable
|
- | 10,300 | ||||||
Deposits
and prepaid expenses
|
24,224 | (169,672 | ) | |||||
Accounts
payable
|
599,334 | 374,535 | ||||||
Accrued
liabilities
|
17,350 | (25,429 | ) | |||||
Deferred
payment from Euramerica for development
|
(251,951 | ) | 251,951 | |||||
Cash
used in operating activities
|
3,686,582 | (408,494 | ) | |||||
Cash
flows from investing activities
|
||||||||
Purchase
of fixed assets
|
(204,200 | ) | (149,799 | ) | ||||
Additions
to oil & gas properties
|
(3,123,003 | ) | (9,530,321 | ) | ||||
Sale
of oil & gas properties
|
300,000 | 300,000 | ||||||
Note
and interest receivable from officer
|
- | 23,100 | ||||||
Proceeds
from sale of vehicle
|
- | |||||||
Cash
used in investing activities
|
(3,027,203 | ) | (9,357,020 | ) | ||||
Cash
flows from financing activities
|
||||||||
Proceeds
from (repayment of) note payable, net
|
(965,000 | ) | 615,000 | |||||
Proceeds
from sales of common stock
|
- | 4,313,756 | ||||||
Debt
issue costs
|
(466,835 | ) | ||||||
Borrowings
on long-term debt
|
11,274,843 | 6,344,816 | ||||||
Payments
on long-term debt
|
(11,792,641 | ) | (189,712 | ) | ||||
Cash
provided from financing activities
|
(1,482,798 | ) | 10,617,025 | |||||
Increase
(decrease) in cash and cash equivalents
|
(823,419 | ) | 851,511 | |||||
Cash
and cash equivalents, beginning
|
951,004 | 99,493 | ||||||
Cash
and cash equivalents, end
|
$ | 127,585 | $ | 951,004 | ||||
Supplemental
disclosures:
|
||||||||
Interest
paid
|
$ | 768,053 | $ | 733,972 | ||||
Income
taxes paid
|
$ | - | $ | - | ||||
Non-cash
transactions:
|
||||||||
Share-based
payments issued for services
|
$ | - | $ | 280,591 |
See
Notes to Consolidated Financial Statements.
F-5
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements
Note
1 – Summary of Accounting Policies
Nature
of Business
We are an
independent energy company engaged in the business of producing and selling
crude oil and natural gas. This crude oil and natural gas is obtained primarily
by the acquisition and subsequent exploration and development of mineral
leases. Development and exploration may include drilling new
exploratory or development wells on these leases. These operations are conducted
primarily in Eastern Kansas.
Principles
of Consolidation
Our
consolidated financial statements include the accounts of our wholly-owned
subsidiaries, EnerJex Kansas, Inc., DD Energy, Inc.
Use
of Estimates
The preparation of these financial
statements requires the use of estimates by management in determining our
assets, liabilities, revenues, expenses and related
disclosures. Actual amounts could differ from those
estimates.
Trade Accounts
Receivable
Trade accounts receivable are recorded
at the invoiced amount and do not bear any interest. We regularly
review receivables to insure that the amounts will be collected and establish or
adjust an allowance for uncollectible amounts as necessary using the specific
identification method. Account balances are charged off against the
allowance after all means of collection have been exhausted and the potential
for recovery is considered remote. There were no reserves for uncollectible
amounts in the periods presented.
Share-Based Payments
The value
we assign to the options and warrants that we issue is based on the fair market
value as calculated by the Black-Scholes pricing model. To perform a calculation
of the value of our options and warrants, we determine an estimate of the
volatility of our stock. We need to estimate volatility because there
has not been enough trading of our stock to determine an appropriate measure of
volatility. We believe our estimate of volatility is reasonable, and we review
the assumptions used to determine this whenever we issue a new equity
instruments. If we have a material error in our estimate of the
volatility of our stock, our expenses could be understated or
overstated.
Income Taxes
We
account for income taxes under the Statement of Financial Accounting Standards
“SFAS” Statement 109, “Accounting for Income Taxes”. The asset and
liability approach requires the recognition of deferred tax liabilities and
assets for the expected future tax consequences of temporary differences between
the carrying amounts and the tax basis of assets and liabilities. The
provision for income taxes differs from the amount currently payable because of
temporary differences in the recognition of certain income and expense items for
financial reporting and tax reporting purposes.
We
adopted the Financial Accounting Standards Board “FASB” Interpretation No. 48,
“Accounting for Uncertainty in Income Taxes – an interpretation of FASB
Statement No. 109” (“FIN 48”) as of April 1, 2007. FIN 48 clarifies the
accounting for uncertainty in income taxes recognized in companies’ financial
statements in accordance with FASB Statement No. 109, “Accounting for Income
Taxes”. As a result, we apply a more-likely-than-not recognition threshold for
all tax uncertainties. FIN 48 only allows the recognition of those tax benefits
that have a greater than fifty percent likelihood of being sustained upon
examination by the taxing authorities. As a result of implementing FIN 48, we
have reviewed our tax positions and determined there were no outstanding or
retroactive tax positions with less than a 50% likelihood of being sustained
upon examination by the taxing authorities, therefore the implementation of this
standard has not had a material effect on the Company.
F-6
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
We
classify tax-related penalties and net interest on income taxes as income tax
expense. As of March 31, 2009 and 2008, no income tax expense had been
incurred.
Fair Value of Financial
Instruments
Our
financial instruments consist of accounts receivable and notes payable. Interest
rates currently available to us for debt with similar terms and remaining
maturities are used to estimate fair value of such financial instruments.
Accordingly the carrying amounts are a reasonable estimate of fair
value.
Earnings Per Share
SFAS No.
128, “Earnings Per Share”, requires dual presentation of basic and diluted
earnings per share on the face of the income statement for all entities with
complex capital structures and requires a reconciliation of the numerator and
denominator of the diluted income or loss per share computation.
For the
year ended March 31, 2009 and 2008, there were 513,500 and 533,500,
respectively, of potentially issuable shares of common stock pursuant to
outstanding stock options and warrants. These have been excluded from
the denominator of the diluted earnings per share computation, as their effect
would be anti-dilutive.
Cash
and Cash Equivalents
We
consider all highly liquid investment instruments purchased with original
maturities of three months or less to be cash equivalents for purposes of the
consolidated statements of cash flows and other statements. We maintain cash on
deposit, which, at times, exceed federally insured limits. We have not
experienced any losses on such accounts and believe we are not exposed to any
significant credit risk on cash and equivalents.
Revenue
Recognition and Imbalances
Oil and gas revenues are recognized net
of royalties when production is sold to a purchaser at a fixed or determinable
price, when delivery has occurred and title has transferred, and if collection
of the revenue is probable. Cash received relating to future revenues is
deferred and recognized when all revenue recognition criteria are
met.
We use the sales method of accounting
for gas production imbalances. The volumes of gas sold may differ from the
volumes to which we are entitled based on our interests in the properties. These
differences create imbalances that are recognized as a liability only when the
properties’ estimated remaining reserves net to us will not be sufficient to
enable the under-produced owner to recoup its entitled share through production.
No receivables are recorded for those wells where we have taken less than our
share of production. Gas imbalances are reflected as adjustments to estimates of
proved gas reserves and future cash flows in the supplemental oil and gas
disclosures. There was no imbalance at March 31, 2009 and
2008.
Goodwill
Goodwill represents the excess of the
purchase price of an entity over the estimated fair value of the assets acquired
and liabilities assumed. We assess the carrying amount of goodwill by testing
the goodwill for impairment annually and when impairment indicators arise. The
impairment test requires allocating goodwill and all other assets and
liabilities to assigned reporting units. The fair value of each unit is
determined and compared to the book value of the reporting unit. If the fair
value of the reporting unit is less than the book value, including goodwill,
then the goodwill is written down to the implied fair value of the goodwill
through a charge to expense.
F-7
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
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
The
accounting for our business is subject to special accounting rules that are
unique to the gas and oil industry. There are two allowable methods of
accounting for oil and gas business activities: the successful efforts method
and the full-cost method. We follow the full-cost method of accounting under
which all costs associated with property acquisition, exploration and
development activities are capitalized. We also capitalize internal costs that
can be directly identified with our acquisition, exploration and development
activities and do not include any costs related to production, general corporate
overhead or similar activities.
Under the
full-cost method, capitalized costs are amortized on a composite
unit-of-production method based on proved gas and oil reserves. Depreciation,
depletion and amortization expense is also based on the amount of estimated
reserves. If we maintain the same level of production year over year, the
depreciation, depletion and amortization expense may be significantly different
if our estimate of remaining reserves changes significantly. Proceeds from the
sale of properties are accounted for as reductions of capitalized costs unless
such sales involve a significant change in the relationship between costs and
the value of proved reserves or the underlying value of unproved properties, in
which case a gain or loss is recognized. The costs of unproved properties are
excluded from amortization until the properties are evaluated. We review all of
our unevaluated properties quarterly to determine whether or not and to what
extent proved reserves have been assigned to the properties, and otherwise if
impairment has occurred. Unevaluated properties are assessed individually when
individual costs are significant.
The
process of estimating gas and oil reserves is very complex, requiring
significant decisions in the evaluation of available geological, geophysical,
engineering and economic data. The data for a given property may also change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and a continual reassessment
of the viability of production under changing economic conditions. As a result,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various properties increase the
likelihood of significant changes in these estimates.
We review
the carrying value of our gas and oil properties under the full-cost accounting
rules of the SEC on a quarterly basis. This quarterly review is referred to as a
ceiling test. Under the ceiling test, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal
to the sum of the present value of estimated future net revenues (adjusted for
cash flow hedges) less estimated future expenditures to be incurred in
developing and producing the proved reserves, less any related income tax
effects. In calculating future net revenues, current SEC regulations require us
to utilize prices at the end of the appropriate quarterly period. Such prices
are utilized except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts, including the
effects of derivatives qualifying as cash flow hedges. Two primary factors
impacting this test are reserve levels and current prices, and their associated
impact on the present value of estimated future net revenues. Revisions to
estimates of gas and oil reserves and/or an increase or decrease in prices can
have a material impact on the present value of estimated future net revenues.
Any excess of the net book value, less deferred income taxes, is generally
written off as an expense. Under SEC regulations, the excess above the ceiling
is not expensed (or is reduced) if, subsequent to the end of the period, but
prior to the release of the financial statements, gas and oil prices increase
sufficiently such that an excess above the ceiling would have been eliminated
(or reduced) if the increased prices were used in the calculations.
F-8
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
As
previously announced, in December 2008, the Securities and Exchange Commission
(“SEC”) issued new regulations for oil and gas reserve reporting which go into
effect effective for fiscal years ending on or after December 31,
2009. One of the key elements of the new regulations relate to the
commodity prices which are used to calculate reserves and their present
value. The new regulations provide for disclosure of oil and gas
reserves evaluated using annual average prices based on the prices in effect on
the first day of each month rather than the current regulations which utilize
commodity prices on the last day of the year.
All
reserve estimates are prepared based upon a review of production histories and
other geologic, economic, ownership and engineering data.
Long-Lived Assets
Impairment of long-lived assets is
recorded when indicators of impairment are present and the undiscounted cash
flows estimated to be generated by those assets are less than the assets’
carrying value. The carrying value of the assets is then reduced to
their estimated fair value that is usually measured based on an estimate of
future discounted cash flows.
Asset Retirement
Obligations
The asset
retirement obligation relates to the plug and abandonment costs when our wells
are no longer useful. We determine the value of the liability by obtaining
quotes for this service and estimate the increase we will face in the future. We
then discount the future value based on an intrinsic interest rate that is
appropriate for us. If costs rise more than what we have expected there could be
additional charges in the future, however, we monitor the costs of the abandoned
wells and we will adjust this liability if necessary.
Major Purchasers
For the years ended March 31, 2009 and
2008 we sold all of our natural gas production to one purchaser. We sold all of
our oil production to one purchaser during fiscal 2009 and to a single, but
different purchaser in fiscal 2008.
Recent
Issued Accounting Standards
In May
2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 163,
“Accounting for Financial
Guarantee Insurance Contracts – An interpretation of FASB Statement No.
60”. SFAS No. 163 requires that an insurance enterprise recognize a claim
liability prior to an event of default when there is evidence that credit
deterioration has occurred in an insured financial obligation. It also clarifies
how Statement 60 applies to financial guarantee insurance contracts, including
the recognition and measurement to be used to account for premium revenue and
claim liabilities, and requires expanded disclosures about financial guarantee
insurance contracts. It is effective for financial statements issued for fiscal
years beginning after December 15, 2008, except for some disclosures about the
insurance enterprise’s risk-management activities. SFAS No. 163 requires that
disclosures about the risk-management activities of the insurance enterprise be
effective for the first period beginning after issuance. Except for those
disclosures, earlier application is not permitted. The adoption of this
statement is not expected to have a material effect on the Company’s financial
statements.
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles”. SFAS No. 162 identifies the sources of accounting
principles and the framework for selecting the principles to be used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting principles in the
United States. It is effective 60 days following the SEC’s approval of the
Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting Principles”. The adoption
of this statement is not expected to have a material effect on the Company’s
financial statements.
F-9
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
In March
2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161,
“Disclosures about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133”. SFAS No. 161 is intended to improve financial standards for
derivative instruments and hedging activities by requiring enhanced disclosures
to enable investors to better understand their effects on an entity's financial
position, financial performance, and cash flows. Entities are required to
provide enhanced disclosures about: (a) how and why an entity uses derivative
instruments; (b) how derivative instruments and related hedged items are
accounted for under Statement 133 and its related interpretations; and (c) how
derivative instruments and related hedged items affect an entity’s financial
position, financial performance, and cash flows. It is effective for financial
statements issued for fiscal years beginning after November 15, 2008, with early
adoption encouraged. The Company is currently evaluating the impact of SFAS No.
161 on its financial statements, and the adoption of this statement is not
expected to have a material effect on the Company’s financial
statements.
In
December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No.
141 (revised 2007), “Business Combinations”. This statement replaces SFAS No.
141 and defines the acquirer in a business combination as the entity that
obtains control of one or more businesses in a business combination and
establishes the acquisition date as the date that the acquirer achieves control.
SFAS 141 (revised 2007) requires an acquirer to recognize the assets acquired,
the liabilities assumed, and any non-controlling interest in the acquired at the
acquisition date, measured at their fair values as of that date. SFAS 141
(revised 2007) also requires the acquirer to recognize contingent consideration
at the acquisition date, measured at its fair value at that date. This statement
is effective for fiscal years, and interim periods within those fiscal years,
beginning on or after December 15, 2008. Earlier adoption is prohibited. The
adoption of this statement is not expected to have a material effect on the
Company's financial statements.
In
December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in
Consolidated Financial Statements Liabilities –an Amendment of ARB No. 51”. This
statement amends ARB 51 to establish accounting and reporting standards for the
Non-controlling interest in a subsidiary and for the deconsolidation of a
subsidiary. This statement is effective for fiscal years, and interim periods
within those fiscal years, beginning on or after December 15, 2008. Earlier
adoption is prohibited. The adoption of this statement is not expected to have a
material effect on the Company's financial statements.
Reclassifications
Certain
reclassifications have been made to prior periods to conform to current
presentation.
Note
2 – Going Concern
The
accompanying consolidated financial statements have been prepared assuming that
we will continue as a going concern. Our ability to continue as a going concern
is dependent upon attaining profitable operations based on the development of
products that can be sold. We intend to use borrowings, equity and asset sales,
and other strategic initiatives to mitigate the affects of our cash position,
however, no assurance can be given that debt or equity financing, if and when
required, will be available. The financial statements do not include any
adjustments relating to the recoverability and classification of recorded assets
and classification of liabilities that might be necessary should we be unable to
continue in existence.
Note
3 – Stock Transactions
Stock
transactions in fiscal 2009:
We issued
2,182 shares of common stock to a Director and chairman of our Audit Committee
for services over the next year. For the year ended March 31, 2009, we recorded
director compensation in the amount $13,000.
Option
and Warrant transactions:
Officers (including officers who are
members of the board of directors), directors, employees and consultants are
eligible to receive options under our stock option plans. We
administer the stock option plans and we determine those persons to whom options
will be granted, the number of options to be granted, the provisions applicable
to each grant and the time periods during which the options may be
exercised. No options may be granted more than ten years after the
date of the adoption of the stock option plans.
F-10
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
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, 2009, we had
granted 200,000 non-qualified options under this plan.
Stock Option Plan
On May 4,
2007, we amended and restated the EnerJex Resources, Inc. Stock Option Plan to
rename the plan and to increase the number of shares issuable under the plan to
1,000,000. Our stockholders approved this plan in September of
2007. At March 31, 2009, we had granted 238,500 non-qualified options
under this plan.
Option
transactions in fiscal 2008:
The
unvested option issued in the year ended March 31, 2007, was unexercised and
cancelled in accordance with a separation agreement. We recognized
the remaining expense ($61,187) relating to the options in the year ended March
31, 2008.
We
granted 458,500 options in the year ended March 31, 2008. 30,000 of
the options were for services earned over a one-year period. We
measured the compensation cost of the options based on the vesting and the
market value as determined by the Black-Scholes pricing model.
For the
year ended March 31, 2008, we included as expense $1,977,761 relating to the
value of vested options.
The fair
value of each option award was estimated on the date of grant using the
assumptions noted in the following table. Volatility is based on the
historical volatility of stock trading, expected term was the estimated exercise
period, risk free rate was the rate of a U.S. Treasury instrument of the time
period in which the options would be outstanding, and dividend rate was
estimated to be zero as we cannot assume that there will be any future
dividends.
Weighted
average expected volatility
|
101 | % | ||
Weighted
average expected term (in years)
|
3.95 | |||
Weighted
average expected dividends
|
0 | % | ||
Weighted
average risk free rate
|
4.42 | % |
The
weighted average grant date fair value of the options granted in the year ended
March 31, 2009 was $4.35.
In the
year ended March 31, 2008, we granted warrants to purchase 75,000 shares of our
common stock as partial payment for services rendered in connection with our
financing activities. The warrants
have an exercise price of $3.00 and expire on April 11, 2010. The fair value of
the warrants based on the Black-Scholes pricing model totaled $280,591
(approximately $3.75 per warrant). The following assumptions were used in the
valuation: stock price-$1.00; exercise price-$0.60; life- 3 years; volatility-
106%; yield-4.66%. We have included the value of the warrants with the loan and
equity transaction costs (See Note 5).
F-11
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
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 $66,456 relating to the options that were for services earned over a
one-year period.
A summary
of stock options and warrants is as follows:
Options
|
Weighted Ave.
Exercise Price
|
Warrants
|
Weighted Ave.
Exercise Price
|
|||||||||||||
Outstanding
April 1, 2007
|
60,000 | $ | 6.25 | - | - | |||||||||||
Granted
|
458,500 | 6.30 | 75,000 | $ | 3.00 | |||||||||||
Cancelled
|
(60,000 | ) | (6.25 | ) | - | - | ||||||||||
Exercised
|
- | - | - | - | ||||||||||||
Outstanding
March 31, 2008
|
458,500 | $ | 6.30 | 75,000 | $ | 3.00 | ||||||||||
Granted
|
- | - | - | - | ||||||||||||
Cancelled
|
(20,000 | ) | (6.25 | ) | - | - | ||||||||||
Exercised
|
- | - | - | - | ||||||||||||
Outstanding
March 31, 2009
|
438,500 | $ | 6.30 | 75,000 | $ | 3.00 |
Note
4 – Asset Retirement
Obligation
Our asset
retirement obligations relate to the abandonment of oil and natural gas wells.
The amounts recognized are based on numerous estimates and assumptions,
including future retirement costs, inflation rates and credit adjusted risk-free
interest rates. The following shows the changes in asset retirement
obligations:
Asset retirement obligation at
April 1, 2007
|
$ | 23,908 | ||
Liabilities incurred during the
period
|
405,450 | |||
Liabilities settled during the
period
|
- | |||
Accretion
|
30,331 | |||
Asset retirement obligations,
March 31, 2008
|
459,689 | |||
Liabilities incurred during the
period
|
283,071 | |||
Liabilities settled during the
period
|
- | |||
Accretion
|
60,864 | |||
Asset retirement obligations,
March 31, 2009
|
$ | 803,624 |
Note
5 - Long-Term Debt
Senior
Secured Credit Facility
On July
3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year $50
million Senior Secured Credit Facility (the “Credit Facility”) with Texas
Capital Bank, N.A. Borrowings under the Credit Facility will be
subject to a borrowing base limitation based on our current proved oil and gas
reserves and will be subject to semi-annual redeterminations and interim
adjustments. The initial borrowing base was set at $10.75 million and
was reduced to $7.428 million following the liquidation of the BP hedging
instrument. The Credit Facility is secured by a lien on substantially
all assets of the Company and its subsidiaries. The Credit Facility has a term
of three years, and all principal amounts, together with all accrued and unpaid
interest, will be due and payable in full on July 3, 2011. The Credit
Facility also provides for the issuance of letters-of-credit up to a $750,000
sub-limit under the borrowing base and up to an additional $2.25 million limit
not subject to the borrowing base to support our hedging program. We
had borrowings $7.328 million outstanding at
March 31, 2009.
F-12
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
Advances
under the Credit Facility will be in the form of either base rate loans or
Eurodollar loans. The interest rate on the base rate loans fluctuates based upon
the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus
0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the
percent of the borrowing base utilized at the time of the credit extension. The
interest rate on the Eurodollar loans fluctuates based upon the applicable Libor
rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing
base utilized at the time of the credit extensionon. We may select Eurodollar
loans of one, two, three and six months. A commitment fee of 0.375% on the
unused portion of the borrowing base will accrue, and be payable quarterly in
arrears. There was no commitment fee due at March 31,
2009.
The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires that we, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, maintain a
minimum current assets to current liabilities ratio and a minimum ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and at the end of each fiscal quarter beginning with the
quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior
funded debt.
Additionally,
Texas Capital Bank, N.A. and the holders of the debentures entered into a
Subordination Agreement whereby the debentures issued on June 21, 2007 will be
subordinated to the Credit Facility.
Debentures
On April
11, 2007, we entered into a Securities Purchase Agreement, Registration Rights
Agreements, Senior Secured Debentures, a Pledge and Security Agreement, a
Secured Guaranty, and other related agreements (the “Financing Agreements”) with
the “Buyers” of a new series of senior secured debentures (the “Debentures”).
Under the terms of the Financing Agreements, we agreed to sell Debentures for a
total purchase price of $9.0 million. In connection with the purchase, we agreed
to issue to the Buyers a total of 1,800,000 shares. The first closing occurred
on April 12, 2007 with a total of $6.3 million in Debentures being sold and the
remaining $2.7 million closing on June 21, 2007.
The
Debentures originally had a three-year term, maturing on March 31, 2010, and
bear interest at a rate equal to 10% per annum. Interest is payable quarterly in
arrears on the first day of each succeeding quarter. We may pay interest in
either cash or registered shares of our common stock. The Debentures have no
prepayment penalty so long as we maintain an effective registration statement
with the Securities Exchange Commission and provided we give six (6) business
days prior notice of redemption to the Buyers.
The
proceeds from the Debentures were allocated to the long-term debt and the stock
issued based on the fair market value of each item that we calculated to be $9.0
million for each item. Since each of the instruments had a value
equal to 50% of the total, we allocated $4.5 million to stock and $4.5 million
to the note. The loan discount costs of $4.5 million will accrete as
interest based on the interest method over the period of issue to maturity or
redemption. The amount of interest accreted for the fiscal year ended
March 31, 2009 was $2,814,095 and $1,089,798 for the fiscal year ended March 31,
2008. Of the $2,814,095 interest accreted during the period ended
March 31, 2009, $2,112,267 relates to the redemption of $6.3 million of the
Debentures. The remaining amount of interest to accrete in future periods is
$596,108 as of March 31, 2009.
We incurred debt issue costs totaling
$466,835. The debt issue costs are initially recorded as assets and
are amortized to expense on a straight-line basis over the life of the
loan. The amount expensed in the twelve month period ended March 31,
2009 was $268,453. Of this amount, $195,559 was expensed upon the
redemption of $6.3 million of the Debentures. The remaining debt issue costs
totaling $45,929 will be expensed in the fiscal year ended March 31,
2010.
Effective July 7, 2008, we redeemed an
aggregate principal amount of $6.3 million of the Debentures and amended the
$2.7 million of aggregate principal amount of the remaining Debentures to, among
other things, permit the indebtedness under our new Credit Facility, subordinate
the security interests of the debentures to the new Credit Facility, provide for
the redemption of the remaining Debentures with the net proceeds from our next
debt or equity offering and eliminate the covenant to maintain certain
production thresholds.
F-13
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
Pursuant
to the terms of the Registration Rights Agreement, as amended, between us and
one of the Buyers, we were obligated to register 1,000,000 of the shares issued
under the Financing Agreements. These shares were registered effective December
24, 2008.
Convertible
and Other Long-Term Debt
On August
3, 2006, we sold a $25,000 convertible note that has an interest rate of 6% and
matures August 2, 2010. The note is convertible at any time at the
option of the note holder into shares of our common stock at a conversion rate
of $10.00 per share.
We
financed the purchase of vehicles through a bank. The notes are for
seven years and the weighted average interest is 6.99% per
annum. Vehicles collateralize these notes.
Long-term
debt consists of the following at March 31, 2009:
Credit
Facility
|
$ | 7,328,000 | ||
Debentures
|
2,700,000 | |||
Unaccreted
discount
|
(596,108 | ) | ||
Debentures, net of unaccreted
discount
|
2,103,892 | |||
Vehicle notes
payable
|
109,307 | |||
Total long-term
debt
|
9,541,199 | |||
Less current
portion
|
(1,723,036 | ) | ||
Long-term
debt
|
$ | 7,818,163 |
Principal
amounts are due on long-term and convertible debt as follows: Year ended March
31, 2010 -$1,723,036, March 31, 2011 -$8,377,636, March 31, 2012 -$25,243, March
31, 2013 -$16,044, March 31, 2014 -$13,171 and thereafter-$7,177.
Note
6 – Oil & Gas Properties
On April 9, 2007, we entered into a
“Joint Exploration Agreement” with a shareholder, MorMeg, LLC, whereby we agreed
to advance $4.0 million to a joint operating account for further development of
MorMeg’s Black Oaks leaseholds in exchange for a 95% working interest in the
Black Oaks Project. We will maintain our 95% working interest until
“payout”, at which time the MorMeg 5% carried working interest will be converted
to a 30% working interest and our working interest becomes 70%. Payout is
generally the point in time when the total cumulative revenue from the project
equals all of the project’s development expenditures and costs associated with
funding. Through an additional extension, we have until December 31, 2009 to
contribute additional capital toward the Black Oaks Project development. If we
elect not to contribute further capital to the Black Oaks Project prior to the
project’s full development while it is economically viable to do so, or if there
is more than a thirty day delay in project activities due to lack of capital,
MorMeg has the option to cease further joint development and we will receive an
undivided interest in the Black Oaks Project. The extension will have no force
and effect, however, upon a material default by EnerJex under the Credit
Facility. The undivided interest will be the proportionate amount equal to the
amount that our investment bears to our investment plus $2.0 million, with
MorMeg receiving an undivided interest in what remains.
F-14
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
In August
of 2007, we entered into a development agreement with Euramerica Energy, Inc.,
or Euramerica, to further the development and expansion of the Gas City Project,
which included 6,600 acres, whereby Euramerica contributed $524,000 in capital
toward the project. Euramerica was granted an option to purchase this project
for $1.2 million with a requirement to invest an additional $2.0 million for
project development by August 31, 2008. We were the operator of the project at a
cost plus 17.5% basis. We received $600,000 of the $1.2 million purchase price
and $500,000 of the $2.0 million development funds. We have recorded
a reduction of $600,000 to our oil & gas properties using full-cost
accounting subject to amortization as of the year ended March 31,
2009. In January 2009, Euramerica failed to fully fund both the
balance of the purchase price and the remaining development capital owed under
the agreements between us and Euramerica. Therefore, Euramerica has
forfeited all of its interest in the property, including all interests in any
wells, improvements or assets, and all of Euramerica's interest in the property
reverts back to us. In addition, all operating agreements between us
and Euramerica relating to the Gas City Project are null and void. We
drilled 22 wells on behalf of Euramerica under the development agreement. We are
currently exploring options to sell or further develop the Gas City Project
through joint venture partnerships or other opportunities. The gas
project remains shut in.
We
recorded a non-cash impairment of $4,777,723 to the carrying value of our proved
oil and gas properties during the fiscal year ended March 31, 2009. The
impairment is primarily attributable to lower prices for both oil and natural
gas at December 31, 2008. The charge results from the application of the
“ceiling test” under the full cost method of accounting. Under full cost
accounting requirements, the carrying value may not exceed an amount equal to
the sum of the present value of estimated future net revenues (adjusted for cash
flow hedges) less estimated future expenditures to be incurred in developing and
producing the proved reserves, less any related income tax effects. In
calculating future net revenues, current prices and costs used are those as of
the end of the appropriate quarterly period. Such prices are utilized except
where different prices are fixed and determinable from applicable contracts for
the remaining term of those contracts, including the effects of derivatives
qualifying as cash flow hedges. A ceiling test charge occurs when the carrying
value of the oil and gas properties exceeds the full cost ceiling.
Note
7 – Related party transactions
In August
2008, we paid $20,000 to a non-employee director and former member of the audit
committee for assisting in the establishment and development of the audit
committee and for his involvement and assistance to the chief executive officer
in finalizing the hedging instrument with BP.
Note
8 – Commitments and Contingencies
We have a
lease agreement that expires in September 30, 2013. Future minimum
payments are $71,180 for the year ending March 31, 2010.
Note
9 – Income Taxes
Deferred
income taxes are determined based on the tax effect of items subject to
different treatment between book and tax bases. At March 31, 2009, there is
approximately $8,100,000 of net operating loss carry-forwards expiring in
2021-2023. The net deferred tax is as follows:
March 31, 2009
|
March 31, 2008
|
|||||||
Non-current
deferred tax asset:
|
||||||||
Impaired
oil & gas costs and long-lived assets
|
$ | 1,864,700 | $ | 312,800 | ||||
Net
operating loss carry-forward
|
2,754,600 | 2,429,900 | ||||||
Valuation
allowance
|
(4,619,300 | ) | (2,742,700 | ) | ||||
Total
deferred tax net
|
$ | - | $ | - |
F-15
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
A reconciliation of the provision for
income taxes to the statutory federal rate for continuing operations is as
follows:
March 31, 2009
|
March 31, 2008
|
|||||||
Statutory
tax rate
|
34 | % | 34 | % | ||||
Equity
based compensation
|
(1 | )% | (15 | )% | ||||
Oil
& gas costs and long-lived assets
|
(29 | )% | 1 | % | ||||
Change
in valuation allowance
|
(4 | )% | (20 | )% | ||||
Effective
tax rate
|
0 | % | 0 | % |
Note
10 – Subsequent Events
In April
and May of 2009, we retired $450,000 of the $2.7 million Debentures that were
outstanding at March 31, 2009, leaving a remaining balance of $2.25 million as
of the date of this prospectus.
Subsequent
to year-end, we amended the Debentures to extend the maturity date to September
30, 2010, to allow us to pay interest in either cash or payment-in-kind interest
(an increase in the amount of principal due) or payment-in-kind shares (issuance
of shares of common stock), and add a provision for the conversion of the
debentures into shares of EnerJex’s common stock. See Note
5.
Subsequent
to year-end, we have made Borrowing Base Reduction payments of $200,000 on our
Credit Facility.
Note
11 – Supplemental Oil and Natural Gas Reserve Information
(Unaudited)
Results
of operations from oil and natural gas producing activities
The following table shows the results
of operations from the Company’s oil and gas producing
activities. Results of operations from these activities are
determined using historical revenues, production costs and depreciation,
depletion and amortization of the capitalized costs subject to
amortization. General and administrative expenses, professional,
investor relations and interest expense is excluded from this
determination.
March 31, 2009
|
March 31, 2008
|
|||||||
Production
revenues
|
$ | 6,436,805 | $ | 3,602,798 | ||||
Production
costs
|
(2,637,333 | ) | (1,795,188 | ) | ||||
Depletion
and depreciation
|
(892,871 | ) | (913,224 | ) | ||||
Results
of operations for producing activities
|
$ | 2,906,601 | $ | 894,386 |
Capitalized
costs of oil and natural gas producing properties
The Company’s aggregate capitalized
costs related to oil and natural gas producing activities are as
follows:
March 31, 2009
|
March 31, 2008
|
|||||||
Proved
|
$ | 8,566,979 | $ | 10,207,596 | ||||
Unevaluated
and unproved
|
31,183 | 62,216 | ||||||
Accumulated
depreciation and depletion
|
(1,817,956 | ) | (925,086 | ) | ||||
Sale
of properties
|
(300,000 | ) | (300,000 | ) | ||||
Net
capitalized costs
|
$ | 6,480,206 | $ | 9,044,726 |
Unproved and unevaluated properties are
not included in the full-cost pool and are therefore not subject to depletion or
depreciation. These assets consist primarily of leases that have not been
evaluated. We will continue to evaluate our unproved and unevaluated properties;
however, the timing of such evaluation has not been
determined.
F-16
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
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:
March 31, 2009
|
March 31, 2008
|
|||||||
Acquisition
of proved and unproved properties
|
$ | 123,040 | $ | 4,352,040 | ||||
Development
costs
|
2,999,963 | 5,178,281 | ||||||
Exploration
costs
|
- | - | ||||||
Total
|
$ | 3,123,003 | $ | 9,530,321 |
Gas
and oil Reserve Quantities
Our
ownership interests in estimated quantities of proved oil and gas reserves and
changes in net proved reserves all of which are located in the United States are
summarized below. Proved reserves are estimated quantities of natural
gas and oil that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those that are
expected to be recovered through existing wells with existing equipment and
operating methods. Reserves are stated in thousand cubic feet (mcf) of natural
gas and barrels (stb) of oil. Geological and engineering estimates of proved
natural gas and oil reserves at one point in time are highly interpretive,
inherently imprecise and subject to ongoing revisions that may be substantial in
amount. Although every reasonable effort is made to ensure that the reserve
estimates are accurate, by their nature reserve estimates are generally less
precise than other estimates presented in connection with financial statement
disclosures.
March 31, 2009
|
March 31, 2008
|
|||||||||||||||
Gas-mcf
|
Oil-stb
|
Gas-mcf
|
Oil-stb
|
|||||||||||||
Proved
reserves:
|
||||||||||||||||
Revisions
of previous estimates
|
(394,732 | ) | (14,575 | ) | - | - | ||||||||||
Purchase
of minerals in place
|
- | 53,280 | 418,959 | 347,228 | ||||||||||||
Extensions
and discoveries
|
- | - | 1,068,683 | |||||||||||||
Production
|
(6,465 | ) | (74,289 | ) | (17,762 | ) | (43,697 | ) | ||||||||
Total
|
- | 1,336,630 | 401,197 | 1,372,214 |
Proved
developed reserves at the end of the period:
Gas- mcf
|
Oil – stb
|
|||
March 31, 2009
|
March 31, 2009
|
|||
-
|
524,980 |
Gas- mcf
|
Oil stb
|
|||
March 31, 2008
|
March 31, 2008
|
|||
401,197
|
861,240 |
F-17
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements – (Continued)
Standardized
measure of discounted future net cash flows
The
standardized measure of discounted future net cash flows from our proved
reserves for the periods presented in the financial statements is summarized
below. The standardized measure of future cash flows as of March 31, 2009 and
2008 is calculated using a price per Mcf of gas of $0 and $7.479, respectively
and a price for oil of $42.65 and $94.53, respectively. The resulting estimated
future cash inflows are reduced by estimated future costs to develop and produce
the estimated proved reserves. These costs are based on year-end cost
levels. Future income taxes are based on year-end statutory
rates. The future net cash flows are reduced to present value by
applying a 10% discount rate. The standardized measure of discounted
future cash flows is not intended to represent the replacement cost or fair
market value of the Company’s oil and gas properties.
March 31, 2009
|
March 31, 2008
|
|||||||
Future
production revenue
|
$ | 57,007,970 | $ | 132,457,459 | ||||
Future
production costs
|
(24,732,440 | ) | (39,629,625 | ) | ||||
Future
development costs
|
(9,584,500 | ) | (18,827,013 | ) | ||||
Future
cash flows before income taxes
|
22,691,030 | 74,000,821 | ||||||
Future
income taxes
|
- | (19,241,954 | ) | |||||
Future
net cash flows
|
22,691,030 | 54,758,867 | ||||||
10%
annual discount for estimating of future cash flows
|
(12,061,690 | ) | (26,558,364 | ) | ||||
Standardized
measure of discounted net cash flows
|
$ | 10,629,340 | $ | 28,200,503 |
Changes
in Standardized Measure of Discounted Future Net Cash Flows
March 31, 2009
|
March 31, 2008
|
|||||||
Balance
beginning of year
|
$ | 28,200,503 | $ | - | ||||
Sales,
net of production costs
|
(5,697,410 | ) | (1,777,278 | ) | ||||
Net
change in pricing and production costs
|
(31,927,063 | ) | - | |||||
Net
change in future estimated development costs
|
9,220,510 | - | ||||||
Purchase
of minerals in place
|
136,190 | 8,124,394 | ||||||
Extensions
and discoveries
|
518,297 | 21,853,387 | ||||||
Revisions
|
(1,089,039 | ) | - | |||||
Accretion
of discount
|
(143,477 | ) | - | |||||
Change
in income tax
|
11,410,829 | - | ||||||
Balance
end of year
|
$ | 10,629,340 | $ | 28,200,503 |
F-18
EnerJex
Resources, Inc. and Subsidiaries
Condensed
Consolidated Balance Sheets
December 31,
2009
|
March 31,
2009
|
|||||||
(Unaudited)
|
(Audited)
|
|||||||
Assets
|
|
|||||||
Current
assets:
|
|
|||||||
Cash
|
$ | 412,370 | $ | 127,585 | ||||
Accounts
receivable
|
363,247 | 462,044 | ||||||
Prepaid
debt issue costs
|
11,325 | 45,929 | ||||||
Deferred
and prepaid expenses
|
190,619 | 263,383 | ||||||
Total
current assets
|
977,561 | 898,941 | ||||||
Fixed
assets
|
382,747 | 365,019 | ||||||
Less:
Accumulated depreciation
|
106,795 | 63,988 | ||||||
Total
fixed assets
|
275,952 | 301,031 | ||||||
Other
assets:
|
||||||||
Oil
and gas properties using full cost accounting:
|
||||||||
Properties
not subject to amortization
|
6,351 | 31,183 | ||||||
Properties
subject to amortization
|
6,077,103 | 6,449,023 | ||||||
Total
other assets
|
6,083,454 | 6,480,206 | ||||||
Total
assets
|
$ | 7,336,967 | $ | 7,680,178 | ||||
Liabilities
and Stockholders' Equity (Deficit)
|
||||||||
Current
liabilities:
|
||||||||
Accounts
payable
|
$ | 865,874 | $ | 1,016,168 | ||||
Accrued
liabilities
|
28,892 | 87,811 | ||||||
Deferred
payments - development
|
337,451 | - | ||||||
Long-term
debt, current
|
353,634 | 1,723,036 | ||||||
Convertible
note payable
|
25,000 | - | ||||||
Derivative
liability
|
647,480 | - | ||||||
Total
current liabilities
|
2,258,331 | 2,827,015 | ||||||
Asset
retirement obligation
|
864,659 | 803,624 | ||||||
Convertible
note payable
|
- | 25,000 | ||||||
Long-term
debt, net of discount of $163,244 and $596,108
|
8,697,368 | 7,818,163 | ||||||
Derivative
liability
|
1,838,226 | - | ||||||
Total
liabilities
|
13,658,584 | 11,473,802 | ||||||
Commitments
and contingencies
|
||||||||
Stockholders'
Equity (Deficit):
|
||||||||
Preferred
stock, $0.001 par value, 10,000,000shares authorized, no shares issued and
outstanding
|
- | - | ||||||
Common
stock, $0.001 par value, 100,000,000 shares authorized shares issued and
outstanding – 4,910,660 at December 31, 2009 and 4,443,512 at March 31,
2009
|
4,911 | 4,444 | ||||||
Common
stock owed but not issued
|
186 | - | ||||||
Paid-in
capital
|
9,543,360 | 8,932,906 | ||||||
Retained
(deficit)
|
(15,870,074 | ) | (12,730,974 | ) | ||||
Total
stockholders’ equity (deficit)
|
(6,321,617 | ) | (3,793,624 | ) | ||||
Total
liabilities and stockholders’ equity
|
$ | 7,336,967 | $ | 7,680,178 |
See
Notes to Condensed Consolidated Financial Statements.
F-19
EnerJex
Resources, Inc. and Subsidiaries
Condensed
Consolidated Statements of Operations
(Unaudited)
For the Three Months Ended
|
For the Nine Months Ended
|
|||||||||||||||
December 31,
|
December 31,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenue
|
||||||||||||||||
Oil
and gas activities
|
$ | 914,545 | $ | 1,184,547 | $ | 3,703,724 | $ | 4,652,289 | ||||||||
Expenses:
|
||||||||||||||||
Direct
operating costs
|
448,684 | 562,693 | 1,313,518 | 2,093,994 | ||||||||||||
Depreciation,
depletion and amortization
|
131,394 | 277,020 | 577,288 | 995,069 | ||||||||||||
Impairment
of oil and gas properties
|
- | 4,777,723 | - | 4,777,723 | ||||||||||||
Professional
fees
|
60,571 | 106,032 | 479,710 | 400,816 | ||||||||||||
Salaries
|
153,022 | 200,547 | 706,011 | 694,973 | ||||||||||||
Administrative
expense
|
334,512 | 238,726 | 789,827 | 1,065,308 | ||||||||||||
Total
expenses
|
1,128,183 | 6,162,741 | 3,866,354 | 10,027,883 | ||||||||||||
Income
(loss) from operations
|
(213,638 | ) | (4,978,194 | ) | (162,630 | ) | (5,375,594 | ) | ||||||||
Other
income (expense):
|
||||||||||||||||
Interest
expense
|
(189,374 | ) | (205,327 | ) | (542,939 | ) | (743,372 | ) | ||||||||
Loan
interest accretion
|
(153,374 | ) | (119,512 | ) | (432,864 | ) | (2,686,892 | ) | ||||||||
Gain
on liquidation of hedging instrument
|
- | 3,879,050 | - | 3,879,050 | ||||||||||||
Unrealized
gain (loss) on derivative instruments
|
(2,485,706 | ) | - | (2,485,706 | ) | - | ||||||||||
Gain
on repurchase of debentures
|
- | - | 406,500 | - | ||||||||||||
Management
fee revenue
|
23,944 | - | 99,234 | - | ||||||||||||
Loss
on disposal of vehicles
|
(20,695 | ) | - | (20,695 | ) | (4,421 | ) | |||||||||
Total
other income (expense)
|
(2,825,205 | ) | 3,554,211 | (2,976,470 | ) | 444,365 | ||||||||||
Net
income (loss)
|
$ | (3,038,843 | ) | $ | (1,423,983 | ) | $ | (3,139,100 | ) | $ | (4,931,229 | ) | ||||
Weighted
average shares outstanding
|
||||||||||||||||
Common
shares outstanding basic and diluted
|
4,827,137 | 4,443,483 | 4,647,879 | 4,442,467 | ||||||||||||
Net
income (loss) per share - basic
|
$ | (0.63 | ) | $ | (0.32 | ) | $ | (0.68 | ) | $ | (1.11 | ) |
See
Notes to Condensed Consolidated Financial Statements.
F-20
EnerJex
Resources, Inc. and Subsidiaries
Condensed
Consolidated Statements of Cash Flows
(Unaudited)
For the Nine Months Ended
|
||||||||
December 31,
|
||||||||
2009
|
2008
|
|||||||
Cash
flows (used in) / provided from operating activities
|
||||||||
Net
income (loss)
|
$ | (3,139,100 | ) | $ | (4,931,229 | ) | ||
Impairment
of oil and gas properties
|
- | 4,777,723 | ||||||
Depreciation
and depletion
|
599,908 | 1,034,013 | ||||||
Accretion
of asset retirement obligation
|
56,754 | 46,928 | ||||||
Principal
increase on debentures
|
294,250 | - | ||||||
Shares
issued for interest on debentures
|
7,355 | - | ||||||
Share-based
payments issued for compensation and services
|
603,750 | 79,455 | ||||||
Loan
costs and accretion of interest
|
432,864 | 2,832,758 | ||||||
Unrealized
(gain) loss on derivative instruments
|
2,485,706 | - | ||||||
Adjustments
to reconcile net income (loss) to cash used in operating
activities:
|
||||||||
Accounts
receivable
|
98,797 | (144,860 | ) | |||||
Prepaid
expenses
|
107,368 | (926,058 | ) | |||||
Accounts
payable
|
(150,294 | ) | 623,761 | |||||
Accrued
liabilities
|
(58,919 | ) | (9,821 | ) | ||||
Deferred
payment - development
|
337,451 | (251,951 | ) | |||||
Net
cash (used in) / provided from operating
activities
|
1,675,890 | 3,130,719 | ||||||
Cash
flows (used in) / provided from investing activities
|
||||||||
Purchase
of fixed assets
|
(14,738 | ) | (171,200 | ) | ||||
Loss
on disposal of vehicles
|
(20,695 | ) | - | |||||
Additions
to oil and gas properties
|
(138,360 | ) | (2,346,041 | ) | ||||
Net
cash (used in) / provided from investing
activities
|
(173,793 | ) | (2,517,241 | ) | ||||
Cash
flows (used in) / provided from financing activities
|
||||||||
Notes
payable, net
|
- | (965,000 | ) | |||||
Borrowings
on long-term debt
|
38,480 | 11,274,842 | ||||||
Notes
payable, net
|
(1,255,792 | ) | (11,685,978 | ) | ||||
Net
cash (used in) / provided from financing activities
|
(1,217,312 | ) | (1,376,136 | ) | ||||
Net
increase (decrease) in cash
|
284,785 | (762,658 | ) | |||||
Cash
- beginning
|
127,585 | 951,004 | ||||||
Cash
- ending
|
$ | 412,370 | $ | 188,346 | ||||
Supplemental
disclosures:
|
||||||||
Interest
paid
|
$ | 209,681 | $ | 688,602 | ||||
Income
taxes paid
|
- | - | ||||||
Non-cash
transactions
|
||||||||
Shares
issued for interest on debentures
|
$ | 7,355 | $ | - | ||||
Share-based
payments issued for compensation and services
|
603,750 | 79,455 | ||||||
Asset
retirement obligation
|
4,281 | 776,906 | ||||||
Unrealized
(gain) loss on derivative instruments
|
2,485,706 | - | ||||||
Impairment
of oil and gas properties
|
$ | - | $ | 4,777,723 |
See Notes to Condensed Consolidated
Financial Statements.
F-21
EnerJex
Resources, Inc. and Subsidiaries
Notes
to Condensed Consolidated Financial Statements
Note
1- Basis of Presentation
The
unaudited consolidated financial statements have been prepared in accordance
with United States generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q
and reflect all adjustments which, in the opinion of management, are necessary
for a fair presentation. All such adjustments are of a normal
recurring nature. The results of operations for the interim period
are not necessarily indicative of the results to be expected for a full
year. Certain amounts in the prior year statements have been
reclassified to conform to the current year presentations. The
statements should be read in conjunction with the financial statements and
footnotes thereto included in our Form 10-K for the fiscal year ended March 31,
2009.
Our
consolidated financial statements include the accounts of our wholly-owned
subsidiaries, EnerJex Kansas, Inc. and DD Energy, Inc. All intercompany
transactions and accounts have been eliminated in consolidation.
Note 2 – Going
Concern
The
accompanying condensed 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 resources that can be sold. 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.
Note
3 - Stock Options and Warrants
A
summary of stock options and warrants is as follows:
Options
|
Weighted
Ave. Exercise
Price
|
Warrants
|
Weighted
Ave. Exercise
Price
|
|||||||||||||
Outstanding
March 31, 2009
|
438,500 | $ | 6.30 | 75,000 | $ | 3.00 | ||||||||||
Cancelled
|
(438,500 | ) | $ | (6.30 | ) | - | - | |||||||||
Exercised
|
- | - | - | - | ||||||||||||
Outstanding
December 31, 2009
|
- | - | 75,000 | $ | 3.00 |
On August
3, 2009, upon advice and recommendation by the governing, compensation and
nominating committee (“GCNC”) of the Board of Directors, we exchanged all of the
438,500 outstanding stock options for 109,700 shares of twelve-month restricted
common stock valued at $109,700 based upon the fair market value of the stock on
the date of exchange.
Note
4 – Fair Value Measurements
The
Company holds 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:
F-22
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.
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. The Company’s Level 2 assets and liabilities consist of
accounts receivable, notes and convertible notes payable, and derivative
liability. Due to the short term nature of its accounts receivable, notes and
convertible notes payable, the Company estimates the fair value of these assets
and liabilities at their current basis. The Company determines the fair value of
its 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. The Company has no level 3 assets or
liabilities.
Our
derivative instruments consist of variable to fixed price commodity
swaps.
Fair Value Measurement
|
||||||||||||||||
Total Amount
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Crude
oil swaps
|
$ | (2,485,706 | ) | $ | - | $ | (2,485,706 | ) | $ | - |
Note
5 - Asset Retirement Obligations
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, April 1, 2009
|
$ | 803,624 | ||
Liabilities
incurred during the period
|
4,281 | |||
Liabilities
settled during the period
|
- | |||
Accretion
|
56,754 | |||
Asset
retirement obligations, December 31, 2009
|
$ | 864,659 |
Note
6 – 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 Credit Facility. See Note 7. None
of our derivative instruments are designated as cash flow hedges. 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,
2009:
F-23
Term
|
Contract Volumes
|
Price per Bbl
|
Fair Value
|
||||||||
Crude
oil swap
|
Oct.
2009 – Dec. 2013
|
120,000
Bbls
|
$ | 57.30 | $ | (2,497,608 | ) | ||||
Crude
oil swap
|
Oct.
2009 – Mar. 2011
|
20,250
Bbls
|
$ | 77.05 | $ | 11,902 | |||||
$ | (2,485,706 | ) |
The total
fair value is shown as a derivative instrument in both the current and
non-current liabilities on the balance sheet. We recorded an
unrealized loss of $2,485,706 in the quarter ended December 31,
2009. We realized a loss of $165,116 in the quarter ended December
31, 2009, the effect of which is recorded in operating revenue in the Condensed
Consolidated Statement of Operations.
Note
7 - Long-Term Debt and Convertible 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 December 31, 2009.
Advances
under the Credit Facility will be in the form of either base rate loans or
Eurodollar loans. The interest rate on the base rate loans fluctuates based upon
the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus
0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the
percent of the borrowing base utilized at the time of the credit extension, 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 December 31, 2009.
The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires that we, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, maintain a
minimum current assets to current liabilities ratio and a minimum ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and at the end of each fiscal quarter beginning with the
quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior
funded debt.
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. See Note 9. 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. A
copy of this waiver is attached hereto as Exhibit 10.18.
F-24
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 nine month period
ended December 31, 2009 was $432,864. The remaining amount of interest to
accrete in future periods is $163,244 as of December 31, 2009.
We
incurred debt issue costs totaling $466,835. The debt issue costs are
initially recorded as assets and are amortized to expense on a straight-line
basis over the life of the loan. The amount expensed in the nine
month period ended December 31, 2009 was $34,604. The remaining debt
issue costs totaling $11,325 will be expensed in the fiscal year ended March 31,
2010.
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.
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 December 31, 2009, we have recorded additional principal
on the Debentures of $294,250 and common stock of $7,355.
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 or will be tendered and 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 nine months
ended December 31, 2009, we also repurchased $450,000 of the Debentures at a
gain of $406,500.
F-25
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.
Convertible
and Other Long-Term Debt
We
financed the purchase of vehicles through a bank. The notes are for
six years and the weighted average interest is 7.1% per
annum. Vehicles collateralize these notes.
Long-term
debt consists of the following at December 31, 2009:
Credit
Facility
|
$ | 6,746,000 | ||
Debentures
|
2,394,250 | |||
Unaccreted
discount
|
(163,244 | ) | ||
Debentures,
net of unaccreted discount
|
2,231,006 | |||
Convertible
note payable
|
25,000 | |||
Vehicle
notes payable
|
73,996 | |||
Total
long-term debt
|
9,076,002 | |||
Less
current portion, long-term debt
|
353,634 | |||
Less
current portion, convertible note payable
|
25,000 | |||
Long-term
debt
|
$ | 8,697,368 |
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.
Note
8 - 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 have 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.
Subsequent
to the quarter ended December 31, 2009, we have listed assets for sale
encompassing five leases in Johnson County, Kansas. Proceeds from the
sale of these assets would, primarily, be used to meet scheduled Debenture
redemptions. See Note 7. These five leases approximate
$1.3 million of the value of our borrowing base. We would be required
to pay this approximate $1.3 million to Texas Capital Bank upon the sale of
these assets.
Note
9 - Subsequent Events
Effective
January 13, 2010 the Credit Facility 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. A copy of this waiver is attached hereto as Exhibit
10.18.
F-26
We have
listed assets for sale encompassing five leases in Johnson County,
Kansas. Proceeds from the sale of these assets would, primarily, be
used to meet scheduled Debenture redemptions. See Note
7. These five leases approximate $1.3 million of the value of our
borrowing base. We would be required to pay this approximate $1.3
million to Texas Capital Bank upon the sale of these assets.
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. See Note 7.
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.
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.
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.
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.
Pursuant to FAS 165, which is now
incorporated into ASC Topic No. 855, management has evaluated all
events and transactions that have occurred subsequent to the balance sheet date
and has determined that there are no additional material events which have
occurred as of February 16, 2010, that would be deemed significant or require
recognition or additional disclosure.
F-27
1,390,000 Shares
Common
Stock
PROSPECTUS
_________,
2010
PART
II
INFORMATION
NOT REQUIRED IN PROSPECTUS
Item
13. Other Expenses
of Issuance and Distribution
The
following table sets forth all costs and expenses, other than underwriting
discounts and commissions, to be paid in connection with the sale of the common
stock being registered hereunder, all of which will be paid by us. All of the
amounts shown are estimates except for the Securities and Exchange Commission
registration fee.
SEC
registration fee
|
$ |
46.54
|
||
Legal
fees and expenses
|
20,000
|
|||
Accounting
fees and expenses
|
1,500
|
|||
Miscellaneous
fees and expenses
|
453.46
|
|||
Total
|
$ |
22,000
|
Item
14. Indemnification
of Directors and Officers
None of
our directors will have personal liability to us or any of our stockholders for
monetary damages for breach of fiduciary duty as a director involving any act or
omission of any such director since provisions have been made in our articles of
incorporation limiting such liability. The foregoing provisions will not
eliminate or limit the liability of a director (i) for any breach of the
director’s duty of loyalty to us or our stockholders, (ii) for acts or omissions
not in good faith or, which involve intentional misconduct or a knowing
violation of law, (iii) under applicable Sections of the Nevada Revised
Statutes, (iv) the payment of dividends in violation of Section 78.300 of the
Nevada Revised Statutes or, (v) for any transaction from which the director
derived an improper personal benefit.
Our
bylaws provide for indemnification of the directors, officers, and employees of
EnerJex Resources, Inc. in most cases for any liability suffered by them or
arising out of their activities as directors, officers, and employees of EnerJex
Resources, Inc. if they were not engaged in willful misfeasance or malfeasance
in the performance of his or her duties; provided that in the event of a
settlement the indemnification will apply only when the board of directors
approves such settlement and reimbursement as being for the best interests of
the corporation. The Bylaws, therefore, limit the liability of directors to the
maximum extent permitted by Nevada law (Section 78.751).
Our
officers and directors are accountable to us as fiduciaries, which means they
are required to exercise good faith and fairness in all dealings affecting us.
In the event that a stockholder believes the officers and/or directors have
violated their fiduciary duties to us, the stockholder may, subject to
applicable rules of civil procedure, be able to bring a class action or
derivative suit to enforce the stockholder’s rights, including rights under
certain federal and state securities laws and regulations to recover damages
from and require an accounting by management. Stockholders who have suffered
losses in connection with the purchase or sale of their interest in EnerJex
Resources, Inc. in connection with such sale or purchase, including the
misapplication by any such officer or director of the proceeds from the sale of
these securities, may be able to recover such losses from us.
We have
entered into identical indemnification agreements with each member of our board
of directors and each of our executive officers (the “Indemnification Agreements”).
The Indemnification Agreements provide that we will indemnify each such director
or executive officer to the fullest extent permitted by Nevada law if he or she
becomes a party to or is threatened with any action, suit or proceeding arising
out of his or her service as a director or executive officer. The
Indemnification Agreements also provide that we will advance, if requested by an
indemnified person, any and all expenses incurred in connection with any such
proceeding, subject to reimbursement by the indemnified person should a final
judicial determination be made that indemnification is not available under
applicable law. The Indemnification Agreements further provide that if we
maintain directors’ and officers’ liability coverage, each indemnified person
shall be included in such coverage to the maximum extent of the coverage
available for our directors or executive officers.
II-1
Item
15. Recent Sales of
Unregistered Securities
The
following is a summary of transactions by us from March 31, 2006 through the
date of this registration statement involving sales of our securities that were
not registered under the Securities Act of 1933. Each offer and sale was made in
reliance on Section 4(2) of the Securities Act of 1933, Regulation D promulgated
under Section 4(2) of the Securities Act of 1933, or Rule 701 promulgated under
Section 3(b) of the Securities Act of 1933, as transactions by an issuer not
involving any public offering or transactions pursuant to compensatory benefit
plans and contracts relating to compensation as provided under Rule 701. The
purchasers were “accredited
investors,” officers, directors or employees of the registrant or known
to the registrant and its management through pre-existing business
relationships, friends and employees. All purchasers were provided access to all
material information which they requested, and all information necessary to
verify such information and was afforded access to management of the registrant
in connection with their purchases. All holders of the unregistered securities
acquired such securities for investment and not with a view toward distribution,
acknowledging such intent to the registrant. All certificates or agreements
representing such securities that were issued contained restrictive legends,
prohibiting further transfer of the certificates or agreements representing such
securities, without such securities either being first registered or otherwise
exempt from registration under the Securities Act of 1933, in any further resale
or disposition.
On July
25, 2006, we issued 31,565 shares of our restricted common stock to Paul
Branagan (our former sole officer), pursuant to his conversion of $40,000 of
liabilities owed to him by us. 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).
Effective
August 15, 2006, we instituted a 1 for 253.45 reverse split of our outstanding
shares of common stock pursuant to our merger with EnerJex Kansas completed on
August 15, 2006.
On August
15, 2006, we agreed to issue 2,366,600 shares of our restricted common stock to
the stockholders of EnerJex Kansas pursuant to the merger (shares were issued on
September 7, 2006). We believe that the issuance and sale of the shares was
exempt from the registration and prospectus delivery requirements of the
Securities Act of 1933 by virtue of Section 4(2) and Regulation D, Rule
506.
On August
16, 2006, we granted 60,000 stock options to Todd Bart in consideration of his
services as Chief Financial Officer. 20,000 options were to vest each year on
the date of the anniversary of the agreement. Pursuant to the June 14, 2007
Separation Agreement we entered into with Mr. Bart, we vested his 60,000 options
and he had until September 13, 2007 to exercise the options. The options expired
without exercise. We believe that the grant of the options was exempt from the
registration and prospectus delivery requirements of the Securities Act of 1933
by virtue of Section 4(2).
On
October 24, 2006, we issued 3,000 shares of our restricted common stock to
William Stoeckinger for his assistance in the assessment of well data and
geology. 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).
On
October 26, 2006, we issued 40,000 shares of our restricted common stock to
Stoecklein Law Group for professional legal services provided to us. 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).
On
October 26, 2006, we issued 68,000 shares of our restricted common stock to Paul
Branagan pursuant to his agreement to convert all of the liabilities owed to him
by us into shares of our common stock. 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).
On
October 26, 2006, we issued 34,000 shares of our restricted common stock to 3GC
Ltd. pursuant to its agreement to convert all of the liabilities owed to 3GC
Ltd. by us into shares of our common stock. 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).
II-2
On
December 12, 2006, we agreed to issue 64,000 shares of our restricted common
stock to MorMeg, LLC pursuant to the Amendment No. 1 to the Letter Agreement
dated December 12, 2006 (shares were issued on February 27, 2007). 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).
Pursuant
to the debentures and the Financing Agreements related thereto, on April 11,
2007, the lenders funded $6,300,000, and concurrent with First Closing, we
issued 1,260,000 shares of restricted common stock to six accredited investors
on April 13, 2007. Pursuant to the terms of the Securities Purchase Agreement,
the lenders funded an additional $2,700,000 at the second closing on June 21,
2007 and we issued an additional 540,000 shares of restricted common stock on
June 26, 2007.
Additionally,
in the event EnerJex Kansas does not meet certain production thresholds, we must
issue to the lenders up to an additional 1,800,000 shares of common stock or
warrants to purchase shares of common stock.
Additionally,
we issued a warrant to purchase 75,000 shares of our common stock to C. K.
Cooper as a private placement fee on April 12, 2007 in connection with the
placement of the debentures. The warrant has an exercise price of $3.00 per
share and expires on April 11, 2010.
We
believe that the issuance and sale of the securities (debentures, common stock
and common stock purchase warrants) and the issuance of warrants to C. K. Cooper
were exempt from the registration and prospectus delivery requirements of the
Securities Act of 1933 by virtue of Section 4(2) and Regulation D Rule
506.
On May 4,
2007, the Governance, Compensation and Nominating Committee agreed to compensate
the Audit Committee Chairman, Daran Dammeyer, $2,500 per month in cash and
$1,000 per month in shares of our common stock. Additionally, it was agreed that
Mr. Dammeyer will be issued the first twelve months of the stock compensation,
1,920 shares, immediately (the 1,920 shares were issued to Mr. Dammeyer on June
1, 2007).
In
addition, on May 4, 2007, the Governance, Compensation and Nominating Committee
agreed to grant the following options to the following persons:
Option
|
|||||||||||||
Person Issued to
|
No. of options
|
Exercise Price
|
Term
|
Plan
|
|||||||||
C.
Stephen Cochennet, Chief Executive Officer
|
200,000
|
$
|
6.25
|
4 Years
|
2000
|
||||||||
Daran
G. Dammeyer, Director
|
40,000
|
$
|
6.25
|
4 Years
|
2002/2003
|
||||||||
Robert
G. Wonish, Director
|
40,000
|
$
|
6.25
|
4 Years
|
2002/2003
|
||||||||
Darrel
G. Palmer, Director
|
40,000
|
$
|
6.25
|
4 Years
|
2002/2003
|
||||||||
Mark
Haas, Service provider
|
60,000
|
$
|
6.25
|
4 Years
|
2002/2003
|
||||||||
Brad
Kramer, Employee
|
15,000
|
$
|
6.25
|
4 Years
|
2002/2003
|
||||||||
Maureen
Elton, Employee
|
10,000
|
$
|
6.25
|
4 Years
|
2002/2003
|
||||||||
Total:
|
405,000
|
We
believe that the above disclosed issuance of shares and grant of options were
exempt from the registration and prospectus delivery requirements of the
Securities Act of 1933 by virtue of Section 4(2).
On May
22, 2007, we issued 3,000 shares of our restricted common stock to P & R Oil
Field Services for oil field services. 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).
On August
1, 2007, we granted Dierdre P. Jones, then our director of finance and
accounting, an option to purchase 20,000 shares of our restricted common stock
at $7.50 per share for a period of four years expiring on July 31, 2011. 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).
II-3
On
November 1, 2007, we granted Jay Schendel, Field Operations Supervisor of the
Company, an option to purchase 10,000 shares of our restricted common stock at
$6.25 per share for a period of four years expiring on October 31, 2011. 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).
On
January 16, 2008, we granted 23,500 options to purchase shares of our common
stock to three employees. The options are exercisable until January 15, 2011 at
a per share price of $6.25. Each option was fully vested upon grant. We believe
that the option grants were exempt from the registration and prospectus delivery
requirements of the Securities Act of 1933 by virtue of Section
4(2).
On May
15, 2008, we issued 2,182 shares of our common stock to Daran Dammeyer as
compensation for his services as Audit Committee Chairman for fiscal 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).
On July
2, 2008, we granted 122,000 options to purchase shares of our common stock to
our non-employee directors as compensation for their service as directors in
fiscal 2009. The options are exercisable until July 1, 2011 at a per share price
of $6.25. We believe that the option grants were exempt from the registration
and prospectus delivery requirements of the Securities Act of 1933 by virtue of
Section 4(2). These options were rescinded in November 2008 at the request of
the board’s compensation committee and the approval of the non-employee
directors in an effort to reduce compensation expense which, though 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
1, 2008, we granted C. Stephen Cochennet, our president and chief executive
officer, an option to purchase 75,000 shares of the our common stock at $6.25
per share, 30,000 of which vested immediately and expire on July 31, 2011. The
remaining 45,000 options vest based on the following schedule: 10,000 vest on
July 1, 2009; 15,000 vest on July 1, 2010; and 20,000 vest on July 1, 2011. The
options will be exercisable for a three year term following each respective
vesting date. 30,000 of 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, though 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. We believe that the grant of the options was
exempt from the registration and prospectus delivery requirements of the
Securities Act of 1933 by virtue of Section 4(2) thereof.
On August
1, 2008, we granted Dierdre P. Jones, our chief financial officer, a vested
option to purchase 40,000 shares of our common stock at $6.25 per share for a
period of three years expiring on July 31, 2011. We believe that the grant of
the option was exempt from the registration and prospectus delivery requirements
of the Securities Act of 1933 by virtue of Section 4(2)
thereof. These options were rescinded in November 2008 at the request
of the board’s compensation committee and with the approval of Ms. Jones in an
effort to reduce compensation expense which, though 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, the Company 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, the Company 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.
On August
3, 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 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.
II-4
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 shall be issued to the employees
on August 4, 2010 if each employee remains employed by us through August 3,
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
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.
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.
II-5
Item
16. Exhibits and
Financial Statement Schedules
(a)
Exhibits
Exhibit No.
|
Description
|
|
2.1
|
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 Form 10-Q filed on
August 14, 2008)
|
|
3.2
|
Amended
and Restated Bylaws, as currently in effect (incorporated by reference to
Exhibit 3.3 to the Form SB-2 filed on February 23,
2001)
|
|
4.1
|
Article VI
of Amended and Restated Articles of Incorporation of Millennium Plastics
Corporation (incorporated by reference to Exhibit 1.3 to the
Form 8-K filed on December 6, 1999)
|
|
4.2
|
Article II
and Article VIII, Sections 3 and 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
Amendment No. 1 to Form S-1 filed on May 27,
2008)
|
|
5.1
|
Opinion
of the DeMintLaw, PLLC
|
|
10.1
|
Letter
Agreement with MorMeg, LLC dated September 26, 2006 (incorporated by
reference to Exhibit 10.9 to the Form 8-K filed on
October 13, 2006)
|
|
10.2
|
Amendment
No. 1 to Letter Agreement with MorMeg, LLC dated December 12,
2006 (incorporated by reference to Exhibit 10.10 to the Form 8-K
filed on January 8, 2007)
|
|
10.3
|
Debenture
Securities Purchase Agreement dated April 11, 2007 (incorporated by
reference to Exhibit 10.11 to the Form 8-K filed on
April 16, 2007)
|
|
10.4
|
Debenture
Registration Rights Agreement dated April 11, 2007 (incorporated by
reference to Exhibit 10.12 to the Form 8-K filed on
April 16, 2007)
|
|
10.5
|
Senior
Secured Debenture — ($3,500,000) West Coast Opportunity Fund, LLC
dated April 11, 2007 (incorporated by reference to Exhibit 10.13
to the Form 8-K filed on April 16, 2007)
|
|
10.6
|
Senior
Secured Debenture — ($700,000) DKR Soundshore Oasis Holding
Fund Ltd. dated April 11, 2007 (incorporated by reference to
Exhibit 10.14 to the Form 8-K filed on April 16,
2007)
|
|
10.7
|
Senior
Secured Debenture — ($1,050,000) Enable Growth Partners, LP dated
April 11, 2007 (incorporated by reference to Exhibit 10.15 to
the Form 8-K filed on April 16, 2007)
|
|
10.8
|
Senior
Secured Debenture — ($350,000) Enable Opportunity Partners LP dated
April 11, 2007 (incorporated by reference to Exhibit 10.16 to
the Form 8-K filed on April 16, 2007)
|
|
10.9
|
Senior
Secured Debenture — ($350,000) Glacier Partners LP dated
April 11, 2007 (incorporated by reference to Exhibit 10.17 to
the Form 8-K filed on April 16, 2007)
|
|
10.10
|
Senior
Secured Debenture — ($350,000) Frey Living Trust dated April 11,
2007 (incorporated by reference to Exhibit 10.18 to the Form 8-K
filed on April 16, 2007)
|
|
10.11
|
Debenture
Secured Guaranty dated April 11, 2007 (incorporated by reference to
Exhibit 10.19 to the Form 8-K filed on April 16,
2007)
|
|
10.12
|
Debenture
Pledge and Security Agreement dated April 11, 2007 (incorporated by
reference to Exhibit 10.20 to the Form 8-K filed on
April 16, 2007)
|
|
10.13
|
Joint
Exploration Agreement with MorMeg, LLC dated March 30, 2007
(incorporated by reference to Exhibit 10.21 to the Form 8-K
filed on April 16, 2007)
|
|
10.14
|
Purchase
and Sale Agreement with MorMeg, LLC dated April 18, 2007
(incorporated by reference to Exhibit 10.22 to the Form 8-K
filed on May 2, 2007)
|
|
10.15†
|
2000/2001
Stock Option Plan (incorporated by reference to Exhibit 99.2 to the
Form 10-QSB filed on February 14, 2001)
|
|
10.16†
|
EnerJex
Resources, Inc. Stock Option Plan (incorporated by reference to
Exhibit 10.23 to the Form 8-K filed on May 11,
2007)
|
II-6
10.17
|
Senior
Secured Debenture dated June 21, 2007 — ($1,500,000)West Coast
Opportunity Fund, LLC (incorporated by reference to Exhibit 10.24 to
the Form 8-K filed on June 25, 2007)
|
|
10.18
|
Senior
Secured Debenture — ($300,000) DKR Soundshore Oasis Holding
Fund Ltd. dated June 21, 2007 (incorporated by reference to
Exhibit 10.25 to the Form 8-K filed on June 25,
2007)
|
|
10.19
|
Senior
Secured Debenture — ($450,000) Enable Growth Partners LP dated
June 21, 2007 (incorporated by reference to Exhibit 10.26 to the
Form 8-K filed on June 25, 2007)
|
|
10.20
|
Senior
Secured Debenture — ($150,000) Enable Opportunity Partners LP dated
June 21, 2007 (incorporated by reference to Exhibit 10.27 to the
Form 8-K filed on June 25, 2007)
|
|
10.21
|
Senior
Secured Debenture — ($150,000) Glacier Partners LP dated
June 21, 2007 (incorporated by reference to Exhibit 10.28 to the
Form 8-K filed on June 25, 2007)
|
|
10.22
|
Senior
Secured Debenture — ($150,000) Frey Living Trust dated June 21,
2007 (incorporated by reference to Exhibit 10.29 to the Form 8-K
filed on June 25, 2007)
|
|
10.23
|
Debenture
Mortgage, Security Agreement and Assignment of Production dated
June 21, 2007 (incorporated by reference to Exhibit 10.30 to the
Form 8-K filed on June 25, 2007)
|
|
10.24
|
Separation
Agreement with Todd Bart dated June 14, 2007 (incorporated by
reference to Exhibit 10.31 to the Form 8-K filed on
June 29, 2007)
|
|
10.25
|
Amended
and Restated Well Development Agreement and Option for Gas City Project
dated August 10, 2007 (incorporated by reference to
Exhibit 10.31 to the Form 10-QSB filed on August 17,
2007)
|
|
10.26
|
Purchase
and Sale Contract for Tri-County Project dated September 27, 2007
(incorporated by reference to Exhibit 10.1 to the Form 8-K filed
on October 2, 2007)
|
|
10.27
|
Purchase
and Sale Contract DD Energy Project dated September 14, 2007
(incorporated by reference to Exhibit 10.33 to the Form 10-QSB
filed on November 14, 2007)
|
|
10.28
|
Amendment
No. 1 to Well Development Agreement and Option for Gas City Project
dated December 10, 2007 (incorporated by reference to
Exhibit 10.35 to the Form 8-K filed on December 20,
2007)
|
|
10.29
|
Debenture
Holder Amendment Letter dated December 10, 2007 (incorporated by
reference to Exhibit 10.36 to the Form 8-K filed on
December 20, 2007)
|
|
10.30
|
Amendment
No. 2 to Joint Exploration Agreement with MorMeg, LLC dated
March 20, 2008 (incorporated by reference to Exhibit 10.1 to the
Form 8-K filed on March 24, 2008)
|
|
10.31
|
Debenture
Holder Consent and Waiver Agreement dated April 9, 2008 (incorporated
by reference to Exhibit 10.1 to the Form 8-K filed on April 15,
2008)
|
|
10.32
|
Agreement
with Shell Trading (US) Company dated March 6, 2008 (incorporated by
reference to Exhibit 10.32 to Amendment No. 1 to Form S-1
filed on May 27, 2008)(1)
|
|
10.33
|
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)
|
|
10.33(a)
|
Waiver
from Texas Capital Bank, N.A. dated November 19, 2008 (incorporated by
reference to Exhibit 10.1(b) to the Form 10-Q filed on November 19,
2008)
|
|
10.34
|
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)
|
|
10.35
|
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)
|
|
10.36
|
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)
|
|
10.37
|
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)
|
|
10.38†
|
Employment
Agreement with C. Stephen Cochennet dated August 1, 2008
(incorporated by reference to Exhibit 10.1 to the Form 8-K filed
on August 1, 2008)
|
|
10.39†
|
Employment
Agreement with Dierdre P. Jones dated August 1, 2008 (incorporated by
reference to Exhibit 10.1 to the Form 8-K filed on
August 1, 2008)
|
|
10.40
|
Form
of Officer and Director Indemnification Agreement (incorporated by
reference to Exhibit 10.2 to the Form 8-K filed on October 16,
2008)
|
|
10.41
|
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)
|
II-7
10.42
|
Euramerica
Letter Agreement Amendment dated September 15, 2008 (incorporated by
reference to Exhibit 10.10 to the Form 10-Q filed on November 19,
2008)
|
|
10.43
|
Euramerica
Letter Agreement Amendment dated October 15, 2008 (incorporated by
reference to Exhibit 10.1 to the Form 8-K filed on October 21,
2008)
|
|
10.44
|
Amendment
3 to Joint Exploration Agreement effective as of November 6, 2008 between
MorMeg, LLC and EnerJex Resources, Inc. (incorporated by reference to
Exhibit 10.12 to the form 10-Q filed on November 19,
2008)
|
|
10.45(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)
|
|
10.45(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)
|
|
10.45(c)
|
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)
|
|
10.45(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)
|
|
10.45(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)
|
|
10.45(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)
|
|
10.46
|
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)
|
|
10.47
|
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)
|
|
10.48
|
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)
|
|
10.49
|
Waiver
from Texas Capital Bank, N.A. dated July 14, 2009 (incorporated
by reference to the Exhibit 10.16 to the Form 10-K filed July 14,
2009)
|
|
10.50
|
First
Amendment to Credit Agreement dated August 18, 2009 (incorporated by
reference to the Exhibit 10.17 to the Form 10-Q filed August 19,
2009)
|
|
10.51
|
Debenture
Holder Amendment Letter dated November 16, 2009 (incorporated by reference
to the Exhibit 10.13 to the Form 10-Q filed November 23,
2009)
|
|
10.52
|
Standby
Equity Distribution Agreement with Paladin Capital Management, S.A. dated
December 3, 2009 (incorporated by reference to the Exhibit 10.52 to the
Form S-1 filed December 9, 2009)
|
|
10.53
|
Amendment
5 to Joint Exploration Agreement effective as of December 31, 2009 between
MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to the
Exhibit 10.15 to the Form 10-Q filed February 16, 2010)
|
|
10.54
|
Second
Amendment to Credit Agreement dated January 13, 2010 (incorporated by
reference to the Exhibit 10.16 to the Form 10-Q filed February 16,
2010)
|
|
10.55
|
Debenture
Holder Amendment Letter dated January 27, 2010 (incorporated by reference
to the Exhibit 10.17 to the Form 10-Q filed February 16,
2010)
|
|
10.56
|
Waiver
from Texas Capital Bank, N.A. dated February 10, 2009
(incorporated by reference to the Exhibit 10.18 to the Form 10-Q filed
February 16, 2010)
|
|
21.1
|
List
of Subsidiaries
|
|
23.1
|
Consent
of Weaver & Martin, LLC
|
|
23.2
|
Consent
of the DeMint Law, PLLC (included in Exhibit 5.1)
|
|
23.3
|
Consent
of Miller and Lents, Ltd.
|
†
|
Indicates
management contract or compensatory plan or
arrangement.
|
(1)
|
Portions
of this exhibit are omitted and were filed separately with the Secretary
of the SEC pursuant to EnerJex’s application requesting confidential
treatment under Rule 24b-2 of the Securities Exchange Act of
1934.
|
II-8
(b)
Financial Statement Schedules
All
schedules have been omitted because the information required to be presented in
them is not applicable or is shown in the financial statements or related
notes.
Item
17. Undertakings.
(a) Insofar
as indemnification for liabilities arising under the Securities Act of 1933 (the
“Act”) may be permitted
to directors, officers and controlling persons of the small business issuer
pursuant to the foregoing provisions, or otherwise, the small business issuer
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the small business issuer of
expenses incurred or paid by a director, officer or controlling person of the
small business issuer in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the small business issuer will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the
Securities Act.
(b) The
undersigned registrant hereby undertakes:
|
(i)
|
To
file, during any period in which offers or sales are being made, a
post-effective amendment to this registration
statement:
|
|
(A)
|
To
include any prospectus required by Section 10(a)(3) of the Securities Act
of 1933;
|
|
(B)
|
To
reflect in the prospectus any facts or events which, individually or
together, represent a fundamental change in the information set forth in
the registration statement. Notwithstanding the foregoing, any
increase or decrease in volume of securities offered (if the total dollar
value of securities offered would not exceed that which was registered)
and any deviation from the low or high end of the estimated maximum
offering range may be reflected in the form of prospectus filed with the
Securities and Exchange Commission pursuant to Rule 424(b) if, in the
aggregate, the changes in volume and price represent no more than a 20
percent change in the maximum aggregate offering price set forth in the
“Calculation of
Registration Fee” table in the effective registration
statement;
|
|
(C)
|
To
include any material information with respect to the plan of distribution
not previously disclosed in the registration statement or any material
change to such information in this registration
statement.
|
|
(ii)
|
That
for the purpose of determining any liability under the Securities Act of
1933, each post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial
bona fide offering thereof.
|
|
(iii)
|
To
remove from registration by means of a post-effective amendment any of the
securities being registered which remain unsold at the termination of the
offering.
|
|
(iv)
|
That,
for the purpose of determining liability under the Securities Act of 1933
to any purchaser, if the Registrant is subject to Rule 430C, each
prospectus filed pursuant to Rule 424(b) as part of a registration
statement relating to an offering, other than registration statements
relying on Rule 430B or other than prospectuses filed in reliance on Rule
430A, shall be deemed to be part of and included in the registration
statement as of the date it is first used after effectiveness; provided,
however, that no statement made in a registration statement or prospectus
that is part of the registration statement or made in a document
incorporated or deemed incorporated by reference into the registration
statement or prospectus that is part of the registration statement will,
as to a purchaser with a time of contract or sale prior to such first use,
supersede or modify any statement that was made in the registration
statement or prospectus that was part of the registration statement or
made in any such document immediately prior to such date of first
use.
|
II-9
SIGNATURES
Pursuant
to the requirements of the Securities Act of 1933, as amended, the registrant
has duly caused this Amendment to the Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Overland
Park, State of Kansas, on the 4th day of
March 2010.
ENERJEX
RESOURCES, INC.
|
||
By:
|
/s/ C. Stephen Cochennet
|
|
C.
Stephen Cochennet
|
||
President
and Chief Executive
Officer
|
Pursuant
to the requirements of the Securities Act of 1933, as amended, this Amendment to
the Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
Signature
|
Title
|
Date
|
||
/s/ C. Stephen Cochennet
|
President,
Chief Executive Officer,
|
March
4, 2010
|
||
C.
Stephen Cochennet
|
(Principal
Executive Officer) and
|
|||
Chairman
|
||||
/s/ Dierdre P. Jones
|
Chief
Financial Officer
|
March
4, 2010
|
||
Dierdre
P. Jones
|
(Principal Financial and Accounting
|
|||
Officer)
|
||||
/s/ Robert G. Wonish
|
Director
|
March
4, 2010
|
||
Robert
G. Wonish
|
||||
/s/ Daran G. Dammeyer
|
Director
|
March
4, 2010
|
||
Daran
G. Dammeyer
|
||||
/s/ Darrel G. Palmer
|
Director
|
March
4, 2010
|
||
Darrel
G. Palmer
|
||||
/s/ Dr. James W. Rector
|
Director
|
March
4, 2010
|
||
Dr. James
W. Rector
|
II-10
EXHIBIT
INDEX
Exhibit No.
|
Description
|
|
2.1
|
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 Form 10-Q filed on
August 14, 2008)
|
|
3.2
|
Amended
and Restated Bylaws, as currently in effect (incorporated by reference to
Exhibit 3.3 to the Form SB-2 filed on February 23,
2001)
|
|
4.1
|
Article VI
of Amended and Restated Articles of Incorporation of Millennium Plastics
Corporation (incorporated by reference to Exhibit 1.3 to the
Form 8-K filed on December 6, 1999)
|
|
4.2
|
Article II
and Article VIII, Sections 3 and 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
Amendment No. 1 to Form S-1 filed on May 27,
2008)
|
|
5.1
|
Opinion
of the DeMint Law, PLLC
|
|
10.1
|
Letter
Agreement with MorMeg, LLC dated September 26, 2006 (incorporated by
reference to Exhibit 10.9 to the Form 8-K filed on
October 13, 2006)
|
|
10.2
|
Amendment
No. 1 to Letter Agreement with MorMeg, LLC dated December 12,
2006 (incorporated by reference to Exhibit 10.10 to the Form 8-K
filed on January 8, 2007)
|
|
10.3
|
Debenture
Securities Purchase Agreement dated April 11, 2007 (incorporated by
reference to Exhibit 10.11 to the Form 8-K filed on
April 16, 2007)
|
|
10.4
|
Debenture
Registration Rights Agreement dated April 11, 2007 (incorporated by
reference to Exhibit 10.12 to the Form 8-K filed on
April 16, 2007)
|
|
10.5
|
Senior
Secured Debenture — ($3,500,000) West Coast Opportunity Fund, LLC
dated April 11, 2007 (incorporated by reference to Exhibit 10.13
to the Form 8-K filed on April 16, 2007)
|
|
10.6
|
Senior
Secured Debenture — ($700,000) DKR Soundshore Oasis Holding
Fund Ltd. dated April 11, 2007 (incorporated by reference to
Exhibit 10.14 to the Form 8-K filed on April 16,
2007)
|
|
10.7
|
Senior
Secured Debenture — ($1,050,000) Enable Growth Partners, LP dated
April 11, 2007 (incorporated by reference to Exhibit 10.15 to
the Form 8-K filed on April 16, 2007)
|
|
10.8
|
Senior
Secured Debenture — ($350,000) Enable Opportunity Partners LP dated
April 11, 2007 (incorporated by reference to Exhibit 10.16 to
the Form 8-K filed on April 16, 2007)
|
|
10.9
|
Senior
Secured Debenture — ($350,000) Glacier Partners LP dated
April 11, 2007 (incorporated by reference to Exhibit 10.17 to
the Form 8-K filed on April 16, 2007)
|
|
10.10
|
Senior
Secured Debenture — ($350,000) Frey Living Trust dated April 11,
2007 (incorporated by reference to Exhibit 10.18 to the Form 8-K
filed on April 16, 2007)
|
|
10.11
|
Debenture
Secured Guaranty dated April 11, 2007 (incorporated by reference to
Exhibit 10.19 to the Form 8-K filed on April 16,
2007)
|
|
10.12
|
Debenture
Pledge and Security Agreement dated April 11, 2007 (incorporated by
reference to Exhibit 10.20 to the Form 8-K filed on
April 16, 2007)
|
|
10.13
|
Joint
Exploration Agreement with MorMeg, LLC dated March 30, 2007
(incorporated by reference to Exhibit 10.21 to the Form 8-K
filed on April 16, 2007)
|
|
10.14
|
Purchase
and Sale Agreement with MorMeg, LLC dated April 18, 2007
(incorporated by reference to Exhibit 10.22 to the Form 8-K
filed on May 2, 2007)
|
|
10.15†
|
2000/2001
Stock Option Plan (incorporated by reference to Exhibit 99.2 to the
Form 10-QSB filed on February 14, 2001)
|
|
10.16†
|
EnerJex
Resources, Inc. Stock Option Plan (incorporated by reference to
Exhibit 10.23 to the Form 8-K filed on May 11,
2007)
|
|
10.17
|
Senior
Secured Debenture dated June 21, 2007 — ($1,500,000)West Coast
Opportunity Fund, LLC (incorporated by reference to Exhibit 10.24 to
the Form 8-K filed on June 25, 2007)
|
|
10.18
|
Senior
Secured Debenture — ($300,000) DKR Soundshore Oasis Holding
Fund Ltd. dated June 21, 2007 (incorporated by reference to
Exhibit 10.25 to the Form 8-K filed on June 25,
2007)
|
II-11
10.19
|
Senior
Secured Debenture — ($450,000) Enable Growth Partners LP dated
June 21, 2007 (incorporated by reference to Exhibit 10.26 to the
Form 8-K filed on June 25, 2007)
|
|
10.20
|
Senior
Secured Debenture — ($150,000) Enable Opportunity Partners LP dated
June 21, 2007 (incorporated by reference to Exhibit 10.27 to the
Form 8-K filed on June 25, 2007)
|
|
10.21
|
Senior
Secured Debenture — ($150,000) Glacier Partners LP dated
June 21, 2007 (incorporated by reference to Exhibit 10.28 to the
Form 8-K filed on June 25, 2007)
|
|
10.22
|
Senior
Secured Debenture — ($150,000) Frey Living Trust dated June 21,
2007 (incorporated by reference to Exhibit 10.29 to the Form 8-K
filed on June 25, 2007)
|
|
10.23
|
Debenture
Mortgage, Security Agreement and Assignment of Production dated
June 21, 2007 (incorporated by reference to Exhibit 10.30 to the
Form 8-K filed on June 25, 2007)
|
|
10.24
|
Separation
Agreement with Todd Bart dated June 14, 2007 (incorporated by
reference to Exhibit 10.31 to the Form 8-K filed on
June 29, 2007)
|
|
10.25
|
Amended
and Restated Well Development Agreement and Option for Gas City Project
dated August 10, 2007 (incorporated by reference to
Exhibit 10.31 to the Form 10-QSB filed on August 17,
2007)
|
|
10.26
|
Purchase
and Sale Contract for Tri-County Project dated September 27, 2007
(incorporated by reference to Exhibit 10.1 to the Form 8-K filed
on October 2, 2007)
|
|
10.27
|
Purchase
and Sale Contract DD Energy Project dated September 14, 2007
(incorporated by reference to Exhibit 10.33 to the Form 10-QSB
filed on November 14, 2007)
|
|
10.28
|
Amendment
No. 1 to Well Development Agreement and Option for Gas City Project
dated December 10, 2007 (incorporated by reference to
Exhibit 10.35 to the Form 8-K filed on December 20,
2007)
|
|
10.29
|
Debenture
Holder Amendment Letter dated December 10, 2007 (incorporated by
reference to Exhibit 10.36 to the Form 8-K filed on
December 20, 2007)
|
|
10.30
|
Amendment
No. 2 to Joint Exploration Agreement with MorMeg, LLC dated
March 20, 2008 (incorporated by reference to Exhibit 10.1 to the
Form 8-K filed on March 24, 2008)
|
|
10.31
|
Debenture
Holder Consent and Waiver Agreement dated April 9, 2008 (incorporated
by reference to Exhibit 10.1 to the Form 8-K filed on April 15,
2008)
|
|
10.32
|
Agreement
with Shell Trading (US) Company dated March 6, 2008 (incorporated by
reference to Exhibit 10.32 to Amendment No. 1 to Form S-1
filed on May 27, 2008)(1)
|
|
10.33
|
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)
|
|
10.33(a)
|
Waiver
from Texas Capital Bank, N.A. dated November 19, 2008 (incorporated by
reference to Exhibit 10.1(b) to the Form 10-Q filed on November 19,
2008)
|
|
10.34
|
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)
|
|
10.35
|
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)
|
|
10.36
|
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)
|
|
10.37
|
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)
|
|
10.38†
|
Employment
Agreement with C. Stephen Cochennet dated August 1, 2008
(incorporated by reference to Exhibit 10.1 to the Form 8-K filed
on August 1, 2008)
|
|
10.39†
|
Employment
Agreement with Dierdre P. Jones dated August 1, 2008 (incorporated by
reference to Exhibit 10.1 to the Form 8-K filed on
August 1, 2008)
|
|
10.40
|
Form
of Officer and Director Indemnification Agreement (incorporated by
reference to Exhibit 10.2 to the Form 8-K filed on October 16,
2008)
|
|
10.41
|
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)
|
|
10.42
|
Euramerica
Letter Agreement Amendment dated September 15, 2008 (incorporated by
reference to Exhibit 10.10 to the Form 10-Q filed on November 19,
2008)
|
|
10.43
|
Euramerica
Letter Agreement Amendment dated October 15, 2008 (incorporated by
reference to Exhibit 10.1 to the Form 8-K filed on October 21,
2008)
|
II-12
10.44
|
Amendment
3 to Joint Exploration Agreement effective as of November 6, 2008 between
MorMeg, LLC and EnerJex Resources, Inc. (incorporated by reference to
Exhibit 10.12 to the form 10-Q filed on November 19,
2008)
|
|
10.45(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)
|
|
10.45(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)
|
|
10.45(c)
|
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)
|
|
10.45(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)
|
|
10.45(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)
|
|
10.45(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)
|
|
10.46
|
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)
|
|
10.47
|
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)
|
|
10.48
|
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)
|
|
10.49
|
Waiver
from Texas Capital Bank, N.A. dated July 14, 2009 (incorporated
by reference to the Exhibit 10.16 to the Form 10-K filed July 14,
2009)
|
|
10.50
|
First
Amendment to Credit Agreement dated August 18, 2009 (incorporated by
reference to the Exhibit 10.17 to the Form 10-Q filed August 19,
2009)
|
|
10.51
|
Debenture
Holder Amendment Letter dated November 16, 2009 (incorporated by reference
to the Exhibit 10.13 to the Form 10-Q filed November 23,
2009)
|
|
10.52
|
Standby
Equity Distribution Agreement with Paladin Capital Management, S.A. dated
December 3, 2009 (incorporated by reference to the Exhibit 10.52 to the
Form S-1 filed December 9, 2009)
|
|
10.53
|
Amendment
5 to Joint Exploration Agreement effective as of December 31, 2009 between
MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to the
Exhibit 10.15 to the Form 10-Q filed February 16, 2010)
|
|
10.54
|
Second
Amendment to Credit Agreement dated January 13, 2010 (incorporated by
reference to the Exhibit 10.16 to the Form 10-Q filed February 16,
2010)
|
|
10.55
|
Debenture
Holder Amendment Letter dated January 27, 2010 (incorporated by reference
to the Exhibit 10.17 to the Form 10-Q filed February 16,
2010)
|
|
10.56
|
Waiver
from Texas Capital Bank, N.A. dated February 10, 2009
(incorporated by reference to the Exhibit 10.18 to the Form 10-Q filed
February 16, 2010)
|
|
21.1
|
List
of Subsidiaries
|
|
23.1
|
Consent
of Weaver & Martin, LLC
|
|
23.2
|
Consent
of the Law Office of DeMint Law, PLLC(included in
Exhibit 5.1)
|
|
23.3
|
Consent
of Miller and Lents, Ltd.
|
†
|
Indicates
management contract or compensatory plan or
arrangement.
|
(1)
|
Portions
of this exhibit are omitted and were filed separately with the Secretary
of the SEC pursuant to EnerJex’s application requesting confidential
treatment under Rule 24b-2 of the Securities Exchange Act of
1934.
|
II-13