AgEagle Aerial Systems Inc. - Quarter Report: 2010 September (Form 10-Q)
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
þ QUARTERLY
REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the
quarterly period ended September 30,
2010
¨ TRANSITION
REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
Commission
file number 000-30234
ENERJEX RESOURCES,
INC.
|
(Exact
name of registrant as specified in its charter)
Nevada
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88-0422242
|
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(State or other jurisdiction of incorporation or
organization)
|
(I.R.S. Employer Identification No.)
|
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27 Corporate Woods, Suite 350
|
||
10975 Grandview Drive
|
||
Overland Park, Kansas
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66210
|
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(Address of principal executive offices)
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(Zip Code)
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(913) 754-7754
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(Registrant’s
telephone number, including area
code)
|
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes þ No
¨
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes ¨ No
þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
|
Accelerated filer ¨
|
Non-accelerated filer ¨ (Do not check if a smaller reporting company)
|
Smaller reporting company þ
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Yes ¨ No
þ
The
number of shares of Common Stock, $0.001 par value, outstanding on November 02,
2010 was 5,134,628 shares.
ENERJEX
RESOURCES, INC.
FORM
10-Q
TABLE
OF CONTENTS
Page
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PART
I FINANCIAL STATEMENTS
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|||
Item
1.
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Financial
Statements
|
1
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Condensed
Consolidated Balance Sheets
|
1
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||
Condensed
Consolidated Statements of Operations
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2
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Condensed
Consolidated Statements of Cash Flows
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3
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Notes
to Condensed Consolidated Financial Statements
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4
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Forward-Looking
Statements
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9
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||
Item
2.
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Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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10
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Item
3.
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Quantitative
and Qualitative Disclosures about Market Risk
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19
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Item
4T.
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Controls
and Procedures
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20
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PART
II OTHER INFORMATION
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Item
1.
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Legal
Proceedings
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20
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Item
1A.
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Risk
Factors
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20
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Item
2.
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Unregistered
Sales of Equity Securities and Use of Proceeds
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23
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Item
3.
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Defaults
Upon Senior Securities
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23
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Item
4.
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Submission
of Matters to a Vote of Security Holders
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24
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Item
5.
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Other
Information
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24
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Item
6.
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Exhibits
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26
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SIGNATURES |
28
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PART
1 – FINANCIAL INFORMATION
Item
1. Financial Statements
EnerJex
Resources, Inc. and Subsidiaries
Condensed
Consolidated Balance Sheets
September 30,
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March 31,
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|||||||
2010
|
2010
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|||||||
(Unaudited)
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(Audited)
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|||||||
Assets
|
||||||||
Current
assets:
|
||||||||
Cash
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$ | 123,638 | $ | 169,163 | ||||
Accounts
receivable
|
332,143 | 330,102 | ||||||
Deferred
and prepaid expenses
|
139,103 | 166,418 | ||||||
Total
current assets
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594,885 | 665,683 | ||||||
Fixed
assets
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294,094 | 371,885 | ||||||
Less:
Accumulated depreciation
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129,985 | 120,545 | ||||||
Total
fixed assets
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164,109 | 251,340 | ||||||
Other
assets:
|
||||||||
Oil
and gas properties using full-cost accounting:
|
||||||||
Properties
subject to amortization
|
5,650,425 | 6,093,033 | ||||||
Total
other assets
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5,650,425 | 6,093,033 | ||||||
Total
assets
|
$ | 6,409,419 | $ | 7,010,056 | ||||
Liabilities
and Stockholders’ Equity (Deficit)
|
||||||||
Current
liabilities:
|
||||||||
Accounts
payable
|
$ | 837,325 | $ | 877,511 | ||||
Accrued
liabilities
|
140,455 | 417,142 | ||||||
Derivative
liability
|
340,747 | 1,184,178 | ||||||
Long-term
debt, current
|
9,385,395 | 9,182,679 | ||||||
Convertible
note payable
|
25,000 | 25,000 | ||||||
Total
current liabilities
|
10,728,922 | 11,686,510 | ||||||
Asset
retirement obligation
|
863,625 | 883,589 | ||||||
Long-term
debt
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22,764 | 43,440 | ||||||
Derivative
liability
|
2,434,003 | 2,364,068 | ||||||
Total
liabilities
|
14,049,314 | 14,977,607 | ||||||
Commitments
and contingencies
|
||||||||
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 – 5,134,898 at September 30, 2010 and
5,053,189 at March 31, 2010
|
5,157 | 5,058 | ||||||
Paid-in
capital
|
9,587,464 | 9,505,417 | ||||||
Retained
(deficit)
|
(17,232,458 | ) | (17,748,026 | ) | ||||
Total
stockholders’ equity (deficit)
|
(7,639,896 | ) | (7,967,551 | ) | ||||
Total
liabilities and stockholders’ equity
|
$ | 6,409,419 | $ | 7,010,056 |
See
Notes to Condensed Consolidated Financial Statements.
1
EnerJex
Resources, Inc. and Subsidiaries
Condensed
Consolidated Statements of Operations
(Unaudited)
For
the Three Months Ended
|
For
the Six Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Oil
and natural gas revenues
|
$ | 897,219 | $ | 1,394,117 | $ | 1,944,913 | $ | 2,789,179 | ||||||||
Expenses:
|
||||||||||||||||
Direct
operating costs
|
524,442 | 430,316 | 922,508 | 864,835 | ||||||||||||
Depreciation,
depletion and amortization
|
173,269 | 289,604 | 341,375 | 445,895 | ||||||||||||
Professional
fees
|
106,276 | 310,455 | 169,865 | 419,139 | ||||||||||||
Salaries
|
57,746 | 399,254 | 100,154 | 552,989 | ||||||||||||
Administrative
expense
|
103,267 | 264,714 | 268,675 | 455,316 | ||||||||||||
Total
expenses
|
965,000 | 1,694,343 | 1,802,579 | 2,738,174 | ||||||||||||
Income
(loss) from operations
|
(67,781 | ) | (300,226 | ) | 125,119 | 51,005 | ||||||||||
Other
income (expense):
|
||||||||||||||||
Interest
expense
|
(216,314 | ) | (174,727 | ) | (422,209 | ) | (353,565 | ) | ||||||||
Loan
interest accretion
|
- | (144,101 | ) | - | (279,490 | ) | ||||||||||
Management
fee revenue
|
- | 75,291 | - | 75,291 | ||||||||||||
Gain
on repurchase of debentures
|
- | - | - | 406,500 | ||||||||||||
Unrealized
gain (loss) on derivative instruments
|
(702,148 | ) | - | 533,801 | - | |||||||||||
Other
income (loss)
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32,138 | - | (8,797 | ) | - | |||||||||||
Total
other income (expense)
|
(886,324 | ) | (243,537 | ) | 120,389 | (151,264 | ) | |||||||||
Net
income (loss)
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$ | (954,105 | ) | $ | (543,763 | ) | $ | 245,508 | $ | (100,259 | ) | |||||
Weighted
average shares outstanding Common shares outstanding basic and
diluted
|
5,134,062 | 4,670,767 | 5,100,901 | 4,557,760 | ||||||||||||
Net
income (loss) per share – basic and diluted
|
$ | (0.19 | ) | $ | (0.12 | ) | $ | 0.05 | $ | (0.02 | ) |
See
Notes to Condensed Consolidated Financial Statements.
2
EnerJex
Resources, Inc. and Subsidiaries
Condensed
Consolidated Statements of Cash Flows
(Unaudited)
For the Six Months Ended
|
||||||||
September 30,
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||||||||
2010
|
2009
|
|||||||
Cash
flows (used in) / provided from operating activities
|
||||||||
Net
income (loss)
|
$ | 245,508 | $ | (100,259 | ) | |||
Depreciation
and depletion
|
356,453 | 460,974 | ||||||
Accretion
of interest on long-term debt discount
|
- | 279,490 | ||||||
Principal
increase on debentures
|
206,214 | 214,707 | ||||||
Shares
issued for interest on debentures
|
5,125 | 5,368 | ||||||
Shares
issued for compensation and services
|
- | 494,750 | ||||||
Accretion
of asset retirement obligation
|
38,882 | 37,396 | ||||||
Gain
on derivatives
|
(773,496 | ) | - | |||||
Loss
on sale of fixed assets
|
26,362 | - | ||||||
Principal
issued on debentures for interest
|
206,214 | - | ||||||
Adjustments
to reconcile net income (loss) to cash
used
in operating activities:
|
||||||||
Accounts
receivable
|
(2,041 | ) | (28,555 | ) | ||||
Prepaid
expenses
|
27,315 | 63,533 | ||||||
Accounts
payable
|
(40,186 | ) | (338,252 | ) | ||||
Accrued
liabilities
|
(199,665 | ) | (87,732 | ) | ||||
Deferred
payment - development
|
- | 148,125 | ||||||
Net
cash (used in) / provided from operating activities
|
(109,529 | ) | (1,149,545 | ) | ||||
Cash
flows (used in) / provided from investing activities
|
||||||||
Purchase
of fixed assets
|
- | (63,180 | ) | |||||
Additions
to oil & gas properties
|
- | (117,504 | ) | |||||
Proceeds
from sale of oil & natural gas properties
|
60,000 | - | ||||||
Proceeds
from sale of fixed assets
|
28,178 | - | ||||||
Net
cash (used in) / provided from investing activities
|
88,178 | (180,684 | ) | |||||
Cash
flows (used in) / provided from financing activities
|
||||||||
Payments
on long-term debt
|
(24,174 | ) | (1,045,380 | ) | ||||
Borrowings
on long-term debt
|
- | 38,480 | ||||||
Notes
payable, net
|
- | - | ||||||
Net
cash (used in) / provided from financing activities
|
(24,174 | ) | (1,006,900 | ) | ||||
Net
increase (decrease) in cash
|
(45,525 | ) | (38,039 | ) | ||||
Cash
- beginning
|
169,163 | 127,585 | ||||||
Cash
- ending
|
$ | 123,638 | $ | 89,546 | ||||
Supplemental
disclosures:
|
||||||||
Interest
paid
|
$ | 171,986 | $ | 151,334 | ||||
Income
taxes paid
|
$ | - | $ | - | ||||
Non-cash
transactions:
|
||||||||
Share-based
payments issued for services and interest
|
$ | 82,145 | $ | 500,118 | ||||
Principal
issued on debentures for interest
|
206,214 | - |
See
Notes to Condensed Consolidated Financial Statements.
3
EnerJex
Resources, Inc. and Subsidiaries
Notes
to Condensed Consolidated Financial Statements
Note
1 – Basis of Presentation
The
unaudited condensed 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,
2010.
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, 2010
|
- | - | 75,000 | $ | 3.00 | |||||||||||
Cancelled
|
(438,500 | ) | $ | (6.30 | ) | (75,000 | ) | (3.00 | ) | |||||||
Exercised
|
- | - | - | - | ||||||||||||
Outstanding
September 30, 2010
|
- | $ | - | - | $ | - |
Note
4 – Fair Value Measurements
We hold
certain financial assets which are required to be measured at fair value on a
recurring basis in accordance with the Statement of Financial Accounting
Standard No. 157, “Fair Value
Measurements” (“ASC Topic 820-10”). ASC Topic 820-10 establishes a fair
value hierarchy that prioritizes the inputs to valuation techniques used to
measure fair value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or liabilities (Level 1
measurements) and the lowest priority to unobservable inputs (Level 3
measurements). ASC Topic 820-10 defines fair value as the price that
would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants on the measurement date. A fair value
measurement assumes that the transaction to sell the asset or transfer the
liability occurs in the principal market for the asset or liability. The three
levels of the fair value hierarchy under ASC Topic 820-10 are described
below:
4
Level
1. Valuations based on quoted prices in active markets for identical assets
or liabilities that an entity has the ability to access. The
Company’s Level 1 assets include cash, receivable, payables, notes payable and
convertible debt.
Level
2. Valuations based on quoted prices for similar assets or liabilities,
quoted prices for identical assets or liabilities in markets that are not
active, or other inputs that are observable or can be corroborated by observable
data for substantially the full term of the assets or liabilities. We
consider the derivative liability to be Level 2. We determine the
fair value of derivative liability utilizing various inputs,
including NYMEX price quotations and contract terms.
Level 3.
Valuations based on inputs that are supported by little or no market activity
and that are significant to the fair value of the assets or
liabilities. We have no level 3 assets or liabilities.
Our
derivative instruments consist of variable to fixed price commodity
swaps.
Fair Value Measurement
|
||||||||||||||||
Total Amount
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Crude
oil swaps
|
$ | 2,777,750 | $ | - | $ | 2,777,750 | $ | - |
5
Note
5 - 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, April 1, 2010
|
$ | 883,589 | ||
Liabilities
incurred during the period
|
- | |||
Liabilities
settled during the period
|
(58,846 | ) | ||
Accretion
|
38,882 | |||
Asset
retirement obligations, September 30, 2010
|
$ | 863,625 |
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.
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 September 30, 2010:
Term
|
Monthly Contract
Volumes
|
Price per Bbl
|
Fair Value
|
|||||||||
Crude
oil swap
|
Oct.2010
– Dec. 2013
|
2,154 Bbls
|
$ | 61.16 | $ | (2,069,800 | ) | |||||
Crude
oil swap
|
Jan
2013-Dec 2014
|
1,150 Bbls
|
$ | 62.50 | (707,950 | ) | ||||||
$ | (2,777,750 | ) |
The total
fair value is shown as a derivative instrument in both the current and
non-current liabilities on the balance sheet.
Note
7 - Long-Term Debt and Convertible Debt
Senior
Secured Credit Facility
On July
3, 2008, 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.
6
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 September 30, 2010.
Advances
under the Credit Facility will be in the form of either base rate loans or
Eurodollar loans. The interest rate on the base rate loans fluctuates based upon
the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus
0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the
percent of the borrowing base utilized at the time of the credit extension, but
in no event shall be less than five percent (5.0%). The interest rate on the
Eurodollar loans fluctuates based upon the applicable LIBOR rate, plus a margin
of 2.25% to 2.75% depending on the percent of the borrowing base utilized at the
time of the credit extension, but in no event shall be less than five percent
(5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR
options, except that beginning March 30, 2009 and continuing through the date of
this report, TCB has suspended all LIBOR based funding with maturities less than
90 days due to the extreme volatility in the interest rate market and the
unprecedented spread between the 90 day LIBOR and the shorter term LIBOR
options. A commitment fee of 0.375% on the unused portion of the borrowing base
will accrue, and be payable quarterly in arrears. There was no
commitment fee due at September 30, 2010.
The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires that we, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, maintain a
minimum current assets to current liabilities ratio and a minimum ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and at the end of each fiscal quarter beginning with the
quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior
funded debt.
The
Credit Facility was amended August 18, 2009 to implement a minimum interest rate
of five (5.0%) and establish minimum volumes to be hedged of not less than
seventy-five percent (75%) of the proved developed producing reserves
attributable to our interest in the borrowing base oil and gas properties
projected to be produced. The Credit Facility was further amended January
13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis
beginning with the quarter ended December 31, 2009 and to modify the
annualization of the interest coverage ratio, also beginning with the quarter
ended December 31, 2009. 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 covenants at September 30, 2010 and we had not
made required principal reduction payments as of September 30,
2010.
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.
7
Debentures
On April
11, 2007, we entered into a Securities Purchase Agreement, Registration Rights
Agreements, Senior Secured Debentures, a Pledge and Security Agreement, a
Secured Guaranty, and other related agreements (the “Financing Agreements”) with
the “Buyers” of a new series of senior secured debentures (the “Debentures”).
Under the terms of the Financing Agreements, we agreed to sell Debentures for a
total purchase price of $9.0 million. In connection with the purchase, we agreed
to issue to the Buyers a total of 1,800,000 shares. The first closing occurred
on April 12, 2007 with a total of $6.3 million in Debentures being sold and the
remaining $2.7 million closing on June 21, 2007. Effective July 7, 2008, we
redeemed an aggregate principal amount of $6.3 million of the Debentures. We
also amended the remaining $2.7 million of aggregate principal Debentures to,
among other things, permit the indebtedness under our Credit Facility,
subordinate the security interests of the debentures to the Credit Facility,
provide for the redemption of the remaining Debentures with the net proceeds
from any next debt or equity offering and eliminate the covenant to maintain
certain production thresholds.
The Debentures originally had a
three-year term, maturing on March 31, 2010, and an interest rate equal to 10%
per annum. We further amended the Debentures in June 2009 to extend
the maturity date to September 30, 2010, to allow us to pay interest in either
cash or payment-in-kind interest (an increase in the amount of principal due) or
payment-in-kind shares (issuance of shares of common stock), and add a provision
for the conversion of the debentures into shares of our common stock. Subsequent
to the quarter ended December 31, 2009, we further amended the Debentures to
extend the scheduled due dates for the January and February 2010 redemption
payments to March 10, 2010. In addition, in April of 2010, we further
amended the Debentures to remove the conversion feature and extend the Maturity
Date to December 31, 2010.
Interest
is payable quarterly in arrears on the first day of each succeeding quarter. The
interest rate remains 14% per annum for cash interest payments. The
payment-in-kind interest rate is equal to 14% 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. For the three months and six month period ended September 30,
2010 we have recorded additional principal on the Debentures of $107,727 and
$206,214 respectively and common stock of $2,693 and $5,155
respectively.
Convertible
and Other Long-Term Debt
Long-term
debt consists of the following at September 30, 2010:
Credit
Facility
|
$ | 6,691,000 | ||
Debentures
|
2,674,260 | |||
Vehicle
notes payable
|
42,899 | |||
Total
debt
|
9,408,159 | |||
Less
current portion, long-term debt
|
9,385,395 | |||
Long-term
debt
|
$ | 22,764 |
We have a
$25,000 convertible note that has an interest rate of 6%. 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.
8
FORWARD-LOOKING
STATEMENTS
This
report contains forward-looking statements. These forward-looking statements are
subject to a number of risks and uncertainties, many of which are beyond our
control. All statements, other than statements of historical fact, contained in
this report, including statements regarding future events, our future financial
performance, business strategy and plans and objectives of management for future
operations, are forward-looking statements. We have attempted to identify
forward-looking statements by terminology including “anticipates,” “believes,”
“can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,”
“potential,” “predicts,” or “should” or the negative of these terms or other
comparable terminology. Although we do not make forward-looking statements
unless we believe we have a reasonable basis for doing so, we cannot guarantee
their accuracy. These statements are only predictions and involve known and
unknown risks, uncertainties and other factors, including the risks outlined
under “Risk Factors” or elsewhere in this report, which may cause our or our
industry’s actual results, levels of activity, performance or achievements to be
materially different from any future results, levels of activity, performance or
achievements expressed or implied by these forward-looking statements. Moreover,
we operate in a very competitive and rapidly changing environment. New risks
emerge from time to time and it is not possible for us to predict all risk
factors, nor can we address the impact of all factors on our business or the
extent to which any factor, or combination of factors, may cause our actual
results to differ materially from those contained in any forward-looking
statements. The factors impacting these risks and uncertainties include, but are
not limited to:
|
·
|
inability
to attract and obtain additional development
capital;
|
|
·
|
inability
to achieve sufficient future sales levels or other operating
results;
|
|
·
|
inability
to efficiently manage our
operations;
|
|
·
|
potential
default under our secured obligations or material debt
agreements;
|
|
·
|
estimated
quantities and quality of oil and natural gas
reserves;
|
|
·
|
declining
local, national and worldwide economic
conditions;
|
|
·
|
fluctuations
in the price of oil and natural
gas;
|
|
·
|
the
inability of management to effectively implement our strategies and
business plans;
|
|
·
|
approval
of certain parts of our operations by state
regulators;
|
|
·
|
inability
to hire or retain sufficient qualified operating field
personnel;
|
|
·
|
increases
in interest rates or our cost of
borrowing;
|
|
·
|
deterioration
in general or regional (especially Eastern Kansas) economic
conditions;
|
|
·
|
the
occurrence of natural disasters, unforeseen weather conditions, or other
events or circumstances that could impact our operations or could impact
the operations of companies or contractors we depend upon in our
operations;
|
|
·
|
inability
to acquire mineral leases at a favorable economic value that will allow us
to expand our development efforts;
|
|
·
|
adverse
state or federal legislation or regulation that increases the costs of
compliance, or adverse findings by a regulator with respect to existing
operations; and
|
|
·
|
changes
in U.S. GAAP or in the legal, regulatory and legislative environments in
the markets in which we operate.
|
You
should not place undue reliance on any forward-looking statement, each of which
applies only as of the date of this report. Except as required by law, we
undertake no obligation to update or revise publicly any of the forward-looking
statements after the date of this report to conform our statements to actual
results or changed expectations. For a detailed description of these and other
factors that could cause actual results to differ materially from those
expressed in any forward-looking statement, please see “Risk Factors” in this
document and in our Annual Report on Form 10-K for the year ended March 31,
2010.
9
All references in this report to “we,”
“us,” “our,” “company” and “EnerJex” refer to EnerJex Resources, Inc. and our
wholly-owned operating subsidiaries, EnerJex Kansas, Inc. and DD Energy, Inc.,
unless the context requires otherwise. We report our financial information on
the basis of a March 31 fiscal year end.
AVAILABLE
INFORMATION
We file
annual, quarterly and other reports and other information with the
SEC. You can read these SEC filings and reports over the Internet at
the SEC’s website at www.sec.gov or on our website at www.enerjexresources.com. You
can also obtain copies of the documents at prescribed rates by writing to the
Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on
official business days between the hours of 10:00 am and 3:00
pm. Please call the SEC at (800) SEC-0330 for further information on
the operations of the public reference facilities. We will provide a copy of our
annual report to security holders, including audited financial statements, at no
charge upon receipt to of a written request to us at EnerJex Resources, Inc., 27
Corporate Woods, Suite 350, 10975 Grandview Drive, Overland Park,
Kansas 66210.
INDUSTRY
AND MARKET DATA
The
market data and certain other statistical information used throughout this
report are based on independent industry publications, government publications,
reports by market research firms or other published independent sources. In
addition, some data are based on our good faith estimates.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
The
following discussion of our financial condition and results of operations should
be read in conjunction with our financial statements and the related notes to
our financial statements included elsewhere in this report. In addition to
historical financial information, the following discussion and analysis contains
forward-looking statements that involve risks, uncertainties and assumptions.
Our actual results and timing of selected events may differ materially from
those anticipated in these forward-looking statements as a result of many
factors, including those discussed under ITEM 1A. Risk Factors and elsewhere in
this report.
Overview
Our
principal strategy is to focus on the acquisition of oil and natural gas mineral
leases that have existing production and cash flow. Once acquired, 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, 2010 was $29.9
million, versus $10.63 million as of March 31, 2009. We developed
estimated total proved reserves to 2.5 million barrels of oil equivalent, or
BOE, as of March 31, 2010. Our total proved reserves increased almost
38% at March 31, 2010 over 2009, from 2.5 million and 1.3 million barrels of oil
equivalent (BOE), respectively. In addition, the PV10 increased dramatically due
to the estimated average price of oil at March 31, 2010 of $62.64 versus
$42.65 at March 31, 2009. Of the 2.5 million BOE at March 31, 2010
approximately 30% are proved developed and approximately 70% are proved
undeveloped. The proved developed reserves consist of proved developed producing
(79%) and proved developed non-producing (21%).
10
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.
Recent
Developments
On October 30, 2010, we entered into a
binding letter of intent (the “LOI”) with J&J
Operating, LLC (“J&J”); West Coast
Opportunity Fund, LLC (“WCOF”); Montecito
Venture Partners, LLC, a controlled affiliate of WCOF (“MVP”); and Black
Sable Energy, LLC, a controlled affiliate of MVP (“BSE”)(collectively
J&J, WCOF, MVP and BSE are referred to as the “Acquisition Parties”) under
which the parties will negotiate the terms on which we may acquire certain
assets owned by the Acquisition Parties.
In
accordance with the LOI, and subject to the completion of legal due diligence by
us and the Acquisition Parties, the parties agree that the terms and conditions
of the acquisitions shall be as set forth in certain formal definitive
agreements (“Definitive Agreements”), anticipated to be negotiated and entered
into by and between the parties on or prior to November 30,
2010. There are numerous conditions that need to be satisfied
in order for the contemplated transactions to proceed, including but not limited
to agreements with third parties over which we and the other parties to such
transactions have no control. It is unclear whether those
conditions will be satisfied, and consequently it is unclear if those
contemplated transactions will ever close.
We are
subject to customary “no-shop” restrictions on its ability to solicit
alternative acquisition proposals from third parties and to provide information
to and engage in discussions with third parties regarding alternative
acquisition proposals. However, the no-shop provision is subject to a customary
“fiduciary-out” provision which allows us under certain circumstances, and
subject to certain conditions, to provide information to and participate in
discussions with third parties with respect to certain unsolicited alternative
acquisition proposals that the board of directors has determined would, if
consummated, result in a transaction more favorable to our stockholders than the
transaction contemplated by the LOI and is reasonably likely to be completed on
the terms proposed on a timely basis.
11
The LOI
contains certain rights for us and the Acquisition Parties. Upon breach or
termination of the LOI under specified circumstances, we may be required to pay
WCOF a break-up fee. If we are required to pay a break-up fee as a result of our
breach of the terms of the LOI, the Definitive Agreements or entering into an
alternative acquisition agreement, the amount of the break-up fee is
$750,000.
The
foregoing description of the LOI and the transactions contemplated thereby does
not purport to be complete and is subject to, and qualified in its entirety by,
the full text of the LOI attached as Exhibit 10.1 to the Form 8-K filed with the
SEC on November 4, 2010, which is incorporated herein by reference
hereto.
Results of Operations for the Three
Months and Six Months Ended September 30, 2010 and 2009
compared.
Income:
Three Months Ended
|
Increase /
|
Six Months Ended
|
Increase /
|
|||||||||||||||||||||
September 30,
|
(Decrease)
|
September 30,
|
(Decrease)
|
|||||||||||||||||||||
2010
|
2009
|
$
|
2010
|
2009
|
$
|
|||||||||||||||||||
Oil
and natural gas revenues
|
$ | 897,219 | $ | 1,394,117 | $ | (496,898 | ) | $ | 1,944,913 | $ | 2,789,179 | $ | (844,266 | ) |
Revenues
Oil and
natural gas revenues for the three months ended September 30, 2010 were $897,219
compared to revenues of $1,394,117 in the three months ended September 30, 2009.
This compares to oil and natural gas revenues for the six months ended September
30, 2010 of $1,944,913 and revenues of $2,789,179 in the six months ended
September 30, 2009. The decrease in the three and six month revenues is due to
lower sales volumes and prices.
Expenses:
Three Months Ended
|
Increase /
|
Six Months Ended
|
Increase /
|
|||||||||||||||||||||
September 30,
|
(Decrease)
|
September 30,
|
(Decrease)
|
|||||||||||||||||||||
2010
|
2009
|
$
|
2010
|
2009
|
$
|
|||||||||||||||||||
Production
expenses:
|
||||||||||||||||||||||||
Direct
operating costs
|
$ | 524,442 | $ | 430,316 | $ | 94,124 | $ | 922,508 | $ | 864,835 | $ | 57,673 | ||||||||||||
Depreciation,
depletion
and
amortization
|
173,269 | 289,604 | (116,335 | ) | 341,375 | 445,895 | (104,520 | ) | ||||||||||||||||
Total
production expenses
|
697,711 | 719,920 | (22,209 | ) | 1,263,883 | 1,310,730 | (46,847 | ) | ||||||||||||||||
General
expenses:
|
||||||||||||||||||||||||
Professional
fees
|
106,276 | 310,455 | (204,179 | ) | 169,865 | 419,139 | (249,274 | ) | ||||||||||||||||
Salaries
|
57,746 | 399,254 | (341,508 | ) | 100,154 | 552,989 | (452,835 | ) | ||||||||||||||||
Administrative
expense
|
103,267 | 264,714 | (161,447 | ) | 268,675 | 455,316 | (186,641 | ) | ||||||||||||||||
Total
general expenses
|
267,289 | 974,423 | (707,134 | ) | 538,694 | 1,427,444 | (888,750 | ) | ||||||||||||||||
Total
production and general expenses
|
965,000 | 1,694,343 | (729,343 | ) | 1,802,577 | 2,738,174 | (935,597 | ) | ||||||||||||||||
Income
(loss) from operations
|
(67,781 | ) | (300,226 | ) | (232,445 | ) | 125,119 | 51,005 | 74,114 | |||||||||||||||
Other
income (expense)
|
||||||||||||||||||||||||
Interest
expense
|
(216,314 | ) | (174,727 | ) | 41,587 | (422,209 | ) | (353,565 | ) | 68,644 | ||||||||||||||
Loan
interest accretion
|
- | (144,101 | ) | 144,101 | - | (279,490 | ) | 279,490 | ||||||||||||||||
Gain
on repurchase of debentures
|
- | - | - | - | 406,500 | (406,500 | ) | |||||||||||||||||
Management
fee revenue
|
- | 75,291 | (75,291 | ) | - | 75,291 | (75,291 | ) | ||||||||||||||||
Gain
on derivatives
|
(702,148 | ) | - | 702,148 | 533,801 | - | (533,801 | ) | ||||||||||||||||
Other
income (loss)
|
32,138 | - | (32,138 | ) | (8,797 | ) | - | 8,797 | ||||||||||||||||
Total
other income (expense)
|
(886,324 | ) | (243,537 | ) | (547,551 | ) | 120,389 | (151,264 | ) | (30,875 | ) | |||||||||||||
Net
income (loss)
|
$ | (954,105 | ) | $ | (543,763 | ) | $ | - | $ | 245,568 | (100,259 | ) | $ | - |
12
Direct
Operating Costs
Direct
operating costs include pumping, gauging, pulling, repairs, certain contract
labor costs, and other non-capitalized expenses. Direct operating
costs for the three months ended September 30, 2010 were $524,442 compared to
$430,316 for the three months ended September 30, 2009 and $922,508 compared to
$864,835 for each of the six months ended September 30, 2010 and 2009,
respectively. Direct costs increased primarily as a result of repairing and
replacing equipment that reached the end of its useable life.
Depreciation,
Depletion and Amortization
Depreciation,
depletion and amortization for the three and six months ended September 30, 2010
was $173,269 and $341,375, respectively, compared to $289,604 and $445,895 for
the three and six months ended September 30, 2009. Decreases in depreciation,
depletion and amortization were primarily the result of our efforts to reduce
our fixed assets and adjustments to our reserves.
Professional
Fees
Professional
fees for the three months ended September 30, 2010 were $106,276 compared to
$310,455 for the three months ended September 30, 2009. This compares to
professional fees of $169,865 for the six months ended September 30, 2010 and
$419,139 for the same period in 2009. We have continued to reduce our
professional fees through the utilization of more cost effective service
providers and as the result of reduced activities at the corporate
level.
Salaries
Salaries
for the three months ended September 30, 2010 were $57,746 compared to $399,254
for the three months ended September 30, 2009. Additionally, salaries
for the six month periods ended September 30, 2010 and 2009 were $100,154 and
$552,989, respectively. Salaries have continued to decrease as we reduce
the number of full-time employees in response to declining economic conditions
and rely on the services of independent contractors in an effort to reduce our
operating and general expenses and cash outlay.
Administrative
Expense
Administrative
expense for the three and six months ended September 30, 2010 were $103,267 and
$268,675, compared to $264,714 in the three months ended September 30, 2009 and
$455,316 in the six months ended September 30, 2009. The administrative expenses
decreased resulting from less activity in development and exploration and cost
cutting measures. We intend to continue to focus on cost cutting measures during
fiscal 2011 while pursuing other strategic initiatives for the
company.
13
Interest
Expense
Interest
expense for the three and six months ended September 30, 2010 was $216,314 and
$422,209, whereas interest expense for the three and six months ended September
30, 2009 was $174,727 and $353,565.
Loan
Interest Accretion
There
were no loan interest accretion expenses for the three and six months ended
September 30, 2010, as compared to $144,101 and $279,490 for the three and six
months ended September 30, 2009.
Gain
on Repurchase of Debentures
We repurchased $450,000 of the
Debentures during the six months ended September 30, 2009, resulting in a gain
of $406,500.
Management
Fee Revenue
Management fee revenue for the three
and six months ended September 30, 2009 was $75,291 and represents revenues
earned as operator on the Brownrigg joint venture project, in accordance with
the terms of the joint operating agreement.
Gain
on Derivatives
There was a gain on the derivative
contracts in 2010 due to the prices changes in the benefit of the
Company.
Net
Income (Loss)
Net loss
for the three and six months ended September 30, 2010 was $954,105 and $245,508
as compared to net loss of $543,763 and $100,259 in the three and six months
ended September 30, 2009. Non-cash expenses such as depreciation and
depletion as well as loan costs and accretions are significant factors
contributing to the net loss in the prior periods.
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
$300,000 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.
14
The
following table summarizes total current assets, total current liabilities and
working capital at September 30, 2010 as compared to March 31,
2010.
September 30,
2010
|
March 31,
2010
|
Increase /
(Decrease)
$
|
||||||||||
Current
Assets
|
$ | 594,885 | $ | 665,683 | (70,798 | ) | ||||||
Current
Liabilities
|
$ | 10,728,922 | $ | 11,686,510 | (957,588 | ) | ||||||
Working
Capital (deficit)
|
$ | (10,134,037 | ) | $ | (11,020,827 | ) | (886,790 | ) |
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. We have not made any of the MBBRs for June, July or August of
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 September 30, 2010.
Advances
under the Credit Facility will be in the form of either base rate loans or
Eurodollar loans. The interest rate on the base rate loans fluctuates based upon
the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus
0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the
percent of the borrowing base utilized at the time of the credit extension, but
in no event shall be less than five percent (5.0%). The interest rate on the
Eurodollar loans fluctuates based upon the applicable LIBOR rate, plus a margin
of 2.25% to 2.75% depending on the percent of the borrowing base utilized at the
time of the credit extension, but in no event shall be less than five percent
(5.0%). Eurodollar loans may be based upon one, two, three and six month LIBOR
options, except that beginning March 30, 2009 and continuing through the date of
this report, TCB has suspended all LIBOR based funding with maturities less than
90 days due to the extreme volatility in the interest rate market and the
unprecedented spread between the 90 day LIBOR and the shorter term LIBOR
options. A commitment fee of 0.375% on the unused portion of the borrowing base
will accrue, and be payable quarterly in arrears. There was no
commitment fee due at September 30, 2010.
The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires that we, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, maintain a
minimum current assets to current liabilities ratio and a minimum ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and at the end of each fiscal quarter beginning with the
quarter ended September 30, 2008 to maintain a minimum ratio of EBITDA to senior
funded debt.
15
The
Credit Facility was amended August 18, 2009 to implement a minimum interest rate
of five (5.0%) and establish minimum volumes to be hedged of not less than
seventy-five percent (75%) of the proved developed producing reserves
attributable to our interest in the borrowing base oil and gas properties
projected to be produced. The Credit Facility was further amended January
13, 2010 to modify the senior funded debt to EBITDA ratio on a quarterly basis
beginning with the quarter ended December 31, 2009 and to modify the
annualization of the interest coverage ratio, also beginning with the quarter
ended December 31, 2009. The senior funded debt to EBITDA ratio
allowed is 6.25:1.00 at December 31, 2009; 5.75:1.00 at March 31, 2010;
5.25:1.00 at June 30, 2010; and 4.75:1.00 at September 30, 2010; and 4.25:1.00
for all quarters ending after September 30, 2010. We were not in compliance with
the three technical covenants of the Credit Facility at September 30, 2010 As a
result, we have classified the entire outstanding balance due under the Credit
Facility as a current liability.
Additionally,
TCB and the holders of the debentures entered into a Subordination Agreement
whereby the debentures issued on June 21, 2007 are subordinated to the Credit
Facility.
Debenture
Financing
On April
11, 2007, we entered into a Securities Purchase Agreement, Registration Rights
Agreements, Senior Secured Debentures, a Pledge and Security Agreement, a
Secured Guaranty, and other related agreements (the “Financing Agreements”) with
the “Buyers” of a new series of senior secured debentures (the “Debentures”).
Under the terms of the Financing Agreements, we agreed to sell Debentures for a
total purchase price of $9.0 million. In connection with the purchase, we agreed
to issue to the Buyers a total of 1,800,000 shares. The first closing occurred
on April 12, 2007 with a total of $6.3 million in Debentures being sold and the
remaining $2.7 million closing on June 21, 2007. Effective July 7, 2008, we
redeemed an aggregate principal amount of $6.3 million of the Debentures. We
also amended the remaining $2.7 million of aggregate principal Debentures to,
among other things, permit the indebtedness under our Credit Facility,
subordinate the security interests of the debentures to the Credit Facility,
provide for the redemption of the remaining Debentures with the net proceeds
from any next debt or equity offering and eliminate the covenant to maintain
certain production thresholds.
The
proceeds from the Debentures were allocated to the long-term debt and the stock
issued based on the fair market value of each item that we calculated to be $9.0
million. Since each of the instruments had a value equal to 50% of
the total, we allocated $4.5 million to stock and $4.5 million to the
note. The loan discount costs of $4.5 million will accrete as
interest based on the interest method over the period of issue to maturity or
redemption. The amount of interest accreted for the year ended March
31, 2010 was $596,108. There was is no remaining amount of interest to
accrete.
The Debentures originally had a
three-year term, maturing on March 31, 2010, and an interest rate equal to 10%
per annum. We further amended the Debentures in June 2009 to extend
the maturity date to September 30, 2010, to allow us to pay interest in either
cash or payment-in-kind interest (an increase in the amount of principal due) or
payment-in-kind shares (issuance of shares of common stock), and add a provision
for the conversion of the debentures into shares of our common
stock. Subsequent to the quarter ended December 31, 2009, we further
amended the Debentures to extend the scheduled due dates for the January and
February 2010 redemption payments to March 10, 2010. In addition, in
April of 2010, we further amended the Debentures to remove the conversion
feature and extend the Maturity Date to December 31, 2010.
Interest
is payable quarterly in arrears on the first day of each succeeding quarter. The
interest rate remains 14% per annum for cash interest payments. The
payment-in-kind interest rate is equal to 12.5% per annum. If
interest payments are made through payment-in-kind interest, we must issue
common stock equal to an additional 2.5% of the quarterly interest payment
due.
16
We again
amended the Debentures on November 16, 2009 to provide for the tender and
cancellation of shares by the Buyers upon retirement of a portion of the
Debentures in accordance with an agreed upon schedule. We redeemed
$150,000 of the Debentures for $150,000 in cash in accordance with this
amendment during the quarter ended December 31, 2009. As a result,
75,000 shares have been tendered cancelled.
We have
no prepayment penalty so long as we maintain an effective registration statement
with the Securities Exchange Commission and provided we give six (6) business
days prior notice of redemption to the Buyers. During the year ended
March 31, 2010 we also repurchased $450,000 of the Debentures at a gain of
$406,500.
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 and
through the sale of certain assets. 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
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
September 30, 2010, we had 4 full time employees, 10 less than the number of
full time employees at our fiscal year ended March 31, 2010. In November
2008, we began reducing personnel levels 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.
17
Off-Balance
Sheet Arrangements
We do not
have any off-balance sheet arrangements that have or are reasonably likely to
have a current or future effect on our financial condition, changes in financial
condition, revenues or expenses, results of operations, liquidity, capital
expenditures or capital resources that is material to investors.
Critical
Accounting Policies and Estimates
Our
critical accounting estimates include 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.
18
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.
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.
Effects
of Inflation and Pricing
The oil
and natural gas industry is very cyclical and the demand for goods and services
of oil field companies, suppliers and others associated with the industry puts
extreme pressure on the economic stability and pricing structure within the
industry. Material changes in prices impact revenue stream, estimates of future
reserves, borrowing base calculations of bank loans and value of properties in
purchase and sale transactions. Material changes in prices can impact the value
of oil and natural gas companies and their ability to raise capital, borrow
money and retain personnel. We anticipate business costs and the demand for
services related to production and exploration will fluctuate while the
commodity prices for oil and natural gas, both remain volatile.
Item
3. Quantitative and Qualitative Disclosures About Market
Risk.
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. 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 apportion 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.
19
Item 4T.
Controls and Procedures.
Our Chief
Executive Officer and Principal Financial Officer, C. Stephen Cochennet,
evaluated the effectiveness of our disclosure controls and procedures (as
defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended)
as of the end of the period covered by this Report. Based on the
evaluation, Mr. Cochennet concluded that our disclosure controls and procedures
are effective in timely altering him to material information relating to us
(including our consolidated subsidiaries) required to be included in our
periodic SEC filings.
There
were no changes in our internal control over financial reporting that occurred
during our most recent fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
PART
II—OTHER INFORMATION
Item
1. Legal Proceedings.
We may
become involved in various routine legal proceedings incidental to our business.
However, to our knowledge as of the date of this report, there are no material
pending legal proceedings to which we are a party or to which any of our
property is subject.
Item
1A. Risk Factors.
Information
regarding risk factors appears in Part I, “Item 2. Management’s Discussion
and Analysis of Financial Condition and Results of Operations” under the
captions “Overview”, “Recent Developments” and “Cautionary Note Regarding
Forward-Looking Statements” contained in this Quarterly Report on Form 10-Q and
in “Item 1A. RISK FACTORS” of our Annual Report on Form 10-K for the year
ended March 31, 2010. Other than as set forth below, there have been no material
changes from the risk factors previously disclosed in our Annual Report on
Form 10-K for the year ended March 31, 2010.
Risks Associated with Our
Business
Our
auditor’s report reflects the fact that without realization of additional
capital, it would be unlikely for us to continue as a going
concern.
As a
result of our deficiency in working capital at March 31, 2010 and other factors,
our auditors have included a paragraph in their audit report regarding
substantial doubt about our ability to continue as a going concern. We have also
included a footnote to our financial statements disclosing this same 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.
20
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
September 30, 2010 $2.6 million in debentures and approximately $6.691 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.
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
September 30, 2010, we had total indebtedness of $9.3 million, including $6.691
million of borrowings under the Credit Facility and $2.6 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 September 30,
2010. Our substantial indebtedness, and the related interest expense,
could have important consequences to us, including:
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·
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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;
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·
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being
forced to use cash flow to reduce our outstanding balance as a result of
an unfavorable borrowing base
redetermination;
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·
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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;
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·
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increasing
our vulnerability to general adverse economic and industry
conditions;
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·
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placing
us at a competitive disadvantage as compared to our competitors that have
less leverage;
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·
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limiting
our ability to capitalize on business opportunities and to react to
competitive pressures and changes in government
regulation;
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·
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limiting
our ability to, or increasing the cost of, refinancing our
indebtedness; and
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·
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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.
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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:
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·
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incur
additional indebtedness and provide additional
guarantees;
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·
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pay
dividends and make other restricted
payments;
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·
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create
or permit certain liens;
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·
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use
the proceeds from the sales of our oil and natural gas
properties;
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·
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use
the proceeds from the unwinding of certain financial
hedges;
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·
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engage
in certain transactions with affiliates;
and
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·
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consolidate,
merge, sell or transfer all or substantially all of our assets or the
assets of our subsidiaries.
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21
The
Credit Facility and our debentures also contain various affirmative covenants
with which we are required to comply. We were not in compliance with
three covenants at September 30, 2010. We may be unable to comply with some or
all of these covenants in the future as well. If we do not comply with these
covenants and are unable to obtain waivers from our lenders, we would be unable
to make additional borrowings under these facilities, our indebtedness under
these agreements would be in default and could be accelerated by our
lenders. In addition, it could cause a cross-default under our other
indebtedness, including our debentures. If our indebtedness is accelerated, we
may not be able to repay our indebtedness or borrow sufficient funds to
refinance it. In addition, if we incur additional indebtedness in the future, we
may be subject to additional covenants, which may be more restrictive than those
to which we are currently subject.
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 through December 31, 2014 that could result in both
realized and unrealized hedging losses. As of September 30, 2010 we had
unrealized losses of approximately 2.777 million. The extent of our commodity
price exposure is related largely to the effectiveness and scope of our
derivative activities. For example, the derivative instruments we may utilize
may be based on posted market prices, which may differ significantly from the
actual crude oil, natural gas and NGL prices we realize in our
operations.
Our
actual future production may be significantly higher or lower than we estimate
at the time we enter into derivative transactions for such period. If the actual
amount is higher than we estimate, we will have greater commodity price exposure
than we intended. If the actual amount is lower than the nominal amount that is
subject to our derivative financial instruments, we might be forced to satisfy
all or a portion of our derivative transactions without the benefit of the cash
flow from our sale or purchase of the underlying physical commodity, resulting
in a substantial diminution of our liquidity. As a result of these factors, our
derivative activities may not be as effective as we intend in reducing the
volatility of our cash flows, and in certain circumstances may actually increase
the volatility of our cash flows. In addition, while we believe our existing
derivative activities are with creditworthy counterparties (Shell and BP),
continued deterioration in the credit markets may cause a counterparty not to
perform its obligation under the applicable derivative instrument or impact
their willingness to enter into future transactions with us.
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.
22
Risks Associated with our
Common Stock
We
have derivative securities currently outstanding and we may issue derivative
securities in the future. Exercise of the derivatives will cause dilution to
existing and new shareholders.
The
exercise of our outstanding warrants, and the conversion of a convertible note,
will cause additional shares of common stock to be issued, resulting in dilution
to our existing and future common stockholders.
If
we fail to remain current on our reporting requirements, we could be removed
from the OTC Bulletin Board, which may 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. We were late in filing our annual report on Form 10-K for the
year ended March 31, 2010, as a result we can only be late two more times in the
remaining two-year period without risking being removed from the OTC Bulletin
Board.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds.
We intend
to issue the Debenture holders 20,342 shares of our common stock in lieu of
interest payments for the quarter ended September 30, 2010. 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. As of the date of this report these shares have not been
issued.
Item
3. Defaults Upon Senior Securities.
Technical Defaults under
Credit Facility
On July
3, 2008, we entered into a three-year $50 million Senior Secured Credit Facility
(the “Credit Facility”) with Texas Capital Bank, N.A. Borrowings
under the Credit Facility are subject to a borrowing base limitation based on
our current proved oil and gas reserves and are subject to semi-annual
redeterminations.
The
Credit Facility also requires that we, at the end of each fiscal quarter
beginning with the quarter ending September 30, 2008, maintain a minimum current
assets to current liabilities ratio and a minimum ratio of EBITDA (earnings
before interest, taxes, depreciation and amortization) to interest expense and
at the end of each fiscal quarter and to maintain a minimum ratio of EBITDA to
senior funded debt. We obtained a waiver of default from Texas Capital Bank on
two technical covenants at March 31, 2009 and one at June 30,
2009. We were not in compliance with the technical covenants of the
Credit Facility at June 30, 2010. As a result, we have classified the entire
outstanding balance due under the Credit Facility as a current
liability.
23
We have
received Monthly Commitment Reduction notices from Texas Capital under the
Credit Facility through monthly installments. We paid $637,000 to
reduce the borrowing base during the year ended March 31, 2010. Following
receipt of the notices, we commenced discussions with Texas Capital regarding a
possible forbearance agreement or waiver, pursuant to which the bank would
waive, postpone or delay the requirement to repay some or all of the anticipated
Monthly Commitment Reductions, in order to afford us additional time to raise
equity capital, increase production or consummate alternative financing
transactions. The discussions are currently ongoing, although there is no
assurance that we will be able to negotiate successfully a forbearance agreement
or obtain any other waiver of compliance from the bank.
In
addition, we have not made required monthly borrowing base reduction payments of
$55,000 for the months of June, July and August of 2010; if we are unable to
successfully negotiate a forbearance agreement, obtain a waiver of compliance or
cure a borrowing base deficiency, an event of default under the Credit Facility
will occur. An event of default under the Credit Facility permits Texas Capital
to accelerate repayment of all amounts due and to terminate the commitments
thereunder. We currently have approximately $6.69 million drawn under the Credit
Facility. Any event of default which results in such acceleration under the
Credit Facility would also result in an event of default under our Debentures,
described above. We do not have sufficient cash resources to repay these amounts
if Texas Capital accelerates its obligations under the Credit Facility. If we
are unable to successfully negotiate a forbearance agreement or waiver with
Texas Capital, or if Texas Capital accelerates its obligations under the Credit
Facility, we may be forced to voluntarily seek bankruptcy
protection.
The terms
of the Credit Facility (including a full description of the rights and remedies
of Texas Capital upon an event of default), and copies of the Texas Capital
agreements related to the Credit Facility can be found in our prior filings with
the SEC, including the Current Reports on Forms 8-K filed with the SEC on July
10, 2008 and November 19, 2008, which are incorporated herein by reference, in
our Form 10-K filed with the SEC on July 14, 2009 and Forms 10-Q filed on August
18, 2009 and February 16, 2010.
Item
4. (Removed and Reserved).
Item
5. Other Information.
On October 30, 2010, we entered into a
binding letter of intent (the “LOI”) with J&J
Operating, LLC (“J&J”); West Coast
Opportunity Fund, LLC (“WCOF”); Montecito
Venture Partners, LLC, a controlled affiliate of WCOF (“MVP”); and Black
Sable Energy, LLC, a controlled affiliate of MVP (“BSE”)(collectively
J&J, WCOF, MVP and BSE are referred to as the “Acquisition Parties”) under
which the parties will negotiate the terms on which we may acquire certain
assets owned by the Acquisition Parties.
In
accordance with the LOI, and subject to the completion of legal due diligence by
us and the Acquisition Parties, the parties agree that the terms and conditions
of the acquisitions shall be as set forth in certain formal definitive
agreements (“Definitive Agreements”), anticipated to be negotiated and entered
into by and between the parties on or prior to November 30,
2010. There are numerous conditions that need to be satisfied
in order for the contemplated transactions to proceed, including but not limited
to agreements with third parties over which we and the other parties to such
transactions have no control. It is unclear whether those
conditions will be satisfied, and consequently it is unclear if those
contemplated transactions will ever close.
We are
subject to customary “no-shop” restrictions on its ability to solicit
alternative acquisition proposals from third parties and to provide information
to and engage in discussions with third parties regarding alternative
acquisition proposals. However, the no-shop provision is subject to a customary
“fiduciary-out” provision which allows us under certain circumstances, and
subject to certain conditions, to provide information to and participate in
discussions with third parties with respect to certain unsolicited alternative
acquisition proposals that the board of directors has determined would, if
consummated, result in a transaction more favorable to our stockholders than the
transaction contemplated by the LOI and is reasonably likely to be completed on
the terms proposed on a timely basis.
24
The LOI
contains certain rights for us and the Acquisition Parties. Upon breach or
termination of the LOI under specified circumstances, we may be required to pay
WCOF a break-up fee. If we are required to pay a break-up fee as a result of our
breach of the terms of the LOI, the Definitive Agreements or entering into an
alternative acquisition agreement, the amount of the break-up fee is
$750,000.
The
foregoing description of the LOI and the transactions contemplated thereby does
not purport to be complete and is subject to, and qualified in its entirety by,
the full text of the LOI attached as Exhibit 10.1 to the Form 8-K filed with the
SEC on November 4, 2010, which is incorporated herein by reference
hereto.
25
Item 6.
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Exhibits.
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Exhibit No.
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Description
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2.1
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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)
|
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3.1
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Amended
and Restated Articles of Incorporation, as currently in effect
(incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August
14, 2008)
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3.2
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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)
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4.1
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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)
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4.2
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Article
II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of
Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1
to the Form SB-2 filed on February 23, 2001)
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4.3
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Specimen
common stock certificate (incorporated by reference to Exhibit 4.3 to the
Form S-1/A filed on May 27, 2008)
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10.1
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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)
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10.2
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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)
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10.3
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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)
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10.4
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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)
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10.5
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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)
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10.6†
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C.
Stephen Cochennet Employment Agreement dated August 1, 2008 (incorporated
by reference to Exhibit 10.1 to the Form 8-K filed on August 1,
2008)
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10.7†
|
Dierdre
P. Jones Employment Agreement dated August 1, 2008 (incorporated by
reference to Exhibit 10.2 to the Form 8-K filed on August 1,
2008)
|
|
10.8†
|
Amended
and Restated EnerJex Resources, Inc. Stock Incentive Plan (incorporated by
reference to Exhibit 10.1 to the Form 8-K filed on October 16,
2008)
|
|
10.9
|
Form
of Officer and Director Indemnification Agreement (incorporated by
reference to Exhibit 10.2 to the Form 8-K filed on October 16,
2008)
|
|
10.10
|
Euramerica
Letter Agreement Amendment dated September 15, 2008 (incorporated by
reference to Exhibit 10.10 to the Form 8-K filed on September 18,
2008)
|
|
10.11
|
Euramerica
Letter Agreement Amendment dated October 15, 2008 (incorporated by
reference to Exhibit 10.11 to the Form 8-K filed on October 21,
2008)
|
|
10.12(a)
†
|
C.
Stephen Cochennet Rescission of Option Grant Agreement
dated November 17, 2008 (incorporated by reference to Exhibit
10.38(a) to the Form 10-Q filed on February 23, 2009)
|
|
10.12(b)
†
|
Dierdre
P. Jones Rescission of Option Grant Agreement dated November 17, 2008
(incorporated by reference to Exhibit 10.38(b) to the Form 10-Q filed on
February 23, 2009)
|
|
10.12
|
Daran
G. Dammeyer Rescission of Option Grant Agreement dated November 17, 2008
(incorporated by reference to Exhibit 10.38(c) to the Form 10-Q filed on
February 23, 2009)
|
|
10.12(d)
|
Darrel
G. Palmer Rescission of Option Grant Agreement dated
November 17, 2008 (incorporated by reference to Exhibit
10.38(d) to the Form 10-Q filed on February 23, 2009)
|
|
10.12(e)
|
Dr.
James W. Rector Rescission of Option Grant Agreement dated November 17,
2008 (incorporated by reference to Exhibit 10.38(e) to the Form 10-Q filed
on February 23, 2009)
|
26
10.12(f)
|
Robert
G. Wonish Rescission of Option Grant Agreement dated November 17, 2008
(incorporated by reference to Exhibit 10.38(f) to the Form 10-Q filed on
February 23, 2009)
|
|
10.13
|
Letter
Agreement with Debenture Holders dated June 11, 2009 (incorporated by
reference to Exhibit 10.1 to the Form 8-K filed on June 16,
2009)
|
|
10.14
|
Joint
Operating Agreement with Pharyn Resources to explore and develop the
Brownrigg Lease Press Release dated June 1, 2009 (incorporated by
reference to Exhibit 99.1 to the Form 8-K filed on June 5,
2009)
|
|
10.15
|
Amendment
4 to Joint Exploration Agreement effective as of November 6,
2008 between MorMeg, LLC and EnerJex Resources,
Inc. (incorporated by reference to Exhibit 10.15 to the Form
10-K filed July 14, 2009)
|
|
10.16
|
Waiver
from Texas Capital Bank, N.A. dated July 14, 2009 (incorporated
by reference to Exhibit 10.16 to Form 10-K filed July 14,
2009)
|
|
10.17
|
First
Amendment to Credit Agreement dated August 18, 2009 (incorporated by
reference to the Exhibit 10.12 to the Form 10-Q filed August 18,
2009)
|
|
10.18
|
Debenture
Holder Amendment Letter dated November 16, 2009 (incorporated by reference
to the Exhibit 10.13 to the Form 10-Q filed November 20,
2009)
|
|
10.19
|
Standby
Equity Distribution Agreement with Paladin Capital Management, S.A. dated
December 3, 2009 (incorporated by reference to Exhibit 10.52 to the Form
S-1 filed on December 9, 2009)
|
|
10.20
|
Amendment
5 to Joint Exploration Agreement effective as of December 31, 2009 between
MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to
Exhibit 10.15 to the Form 10-Q filed on February 16,
2010)
|
|
10.21
|
Second
Amendment to Credit Agreement dated January 13, 2010 (incorporated by
reference to Exhibit 10.16 to the Form 10-Q filed on February 16,
2010)
|
|
10.22
|
Debenture
Holder Amendment Letter dated January 27, 2010 (incorporated by reference
to Exhibit 10.17 to the Form 10-Q filed on February 16,
2010)
|
|
10.23
|
Waiver
from Texas Capital Bank, N.A. dated February 10, 2009
(incorporated by reference to Exhibit 10.18 to the Form 10-Q filed on
February 16, 2010)
|
|
10.24
|
Amendment
6 to Joint Exploration Agreement effective as of March 31, 2010 between
MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to
Exhibit 10.15 to the Form 10-K filed on July 15, 2010)
|
|
10.25
|
Debenture
Holder Amendment Letter dated April 1, 2010 (incorporated by reference to
Exhibit 10.2 to the Form 10-K filed on July 15, 2010)
|
|
10.26
|
Binding
Letter of Intent dated October 30, 2010 (incorporated by reference to
Exhibit 10.1 to the Form 8-K filed on November 4, 2010)
|
|
31.1
|
Certification
of Chief Executive and Principal Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
|
|
32.1
|
Certification
of Chief Executive and Principal Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of
2002
|
27
SIGNATURES
In
accordance with the requirements of the Exchange Act, the registrant caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
ENERJEX
RESOURCES, INC.
|
||
(Registrant)
|
||
By:
|
/s/ C. Stephen Cochennet
|
|
C.
Stephen Cochennet, Chief Executive Officer
|
||
(Principal
Financial Officer)
|
||
Date:
November 18, 2010
|
28