NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
1.
|
ORGANIZATION
AND NATURE OF BUSINESS
|
Effective
May 11, 2006, Cadence Resources Corporation (“Cadence”) and its wholly owned
subsidiaries (collectively, the “Company”) amended its articles of incorporation
to change its name to Aurora Oil & Gas Corporation (“AOG”). The Company is
engaged in the exploration, acquisition, development, production, and sale
of
natural gas and crude oil. The Company generates most of its revenue from the
production and sale of natural gas. The Company is currently focused on
acquiring and developing operating interests in unconventional drilling programs
in the Michigan Antrim shale, the New Albany shale of Indiana and Kentucky
and
the Woodford shale in Oklahoma.
The
Company uses different strategies for natural gas sales depending on the
location of the field and the local markets. In most cases, the Company connects
to nearby high pressure transmission pipelines and utilizes a gas marketing
firm
for the sale of production. Effective June 1, 2007, the Company entered into
a
firm sales contract with Integrys Energy Services, Inc. (formerly WPS) for
5,000
mmbtu per day at MichCon city-gate for the period June 1, 2007, through December
31, 2008. Integrys Energy Services, Inc. is the Company’s primary marketing
partner for the majority of Michigan operated properties. In addition, the
Company has five other base contracts established primarily for future natural
gas sales in Indiana and Michigan. The Company sets the firm delivery volume
obligation under these contracts on either a monthly or a daily basis with
the
amount of the obligation varying from month to month or day to day. As new
wells
come online and production volume increases, new production will be sold under
the base contracts on a spot market pricing structure.
The
Company’s revenue, profitability, and future rate of growth are substantially
dependent on prevailing prices of natural gas and oil. Historically, the energy
markets have been very volatile, and it is likely that oil and natural gas
prices will continue to be subject to wide fluctuations in the future. A
substantial or extended decline in natural gas and oil prices could have a
material adverse effect on the Company’s financial position, results of
operations, cash flows, and access to capital and on the quantities of natural
gas and oil reserves that can be economically produced.
NOTE
2.
|
BASIS
OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
|
Basis
of Presentation
The
financial information included herein is unaudited, except the balance sheet
as
of December 31, 2006, which has been derived from our audited consolidated
financial statements as of December 31, 2006. Such information includes all
adjustments (consisting solely of normal recurring adjustments), which are,
in
the opinion of management, necessary for a fair presentation of financial
position, results of operations, and cash flows for the interim periods. The
results of operations for interim periods are not necessarily indicative of
the
results to be expected for an entire year.
Certain
information, accounting policies, and footnote disclosures normally included
in
financial statements prepared in accordance with accounting principles generally
accepted in the United States of America have been condensed or omitted in
this
Form 10-Q pursuant to certain rules and regulations of the Securities and
Exchange Commission. These condensed consolidated financial statements should
be
read in conjunction with the audited consolidated financial statements and
notes
included in our Annual Report on Form 10-KSB for the year ended
December 31, 2006.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
2.
|
BASIS
OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
|
Reclassifications
Certain
reclassifications have been made to the condensed consolidated financial
statements for the three and nine months ended September 30, 2006, in order
to
conform to the December 31, 2006, and September 30, 2007 presentation. These
reclassifications had no effect on net loss or net cash flows as previously
reported.
Principles
of Consolidation
The
accompanying condensed consolidated financial statements of the Company include
the accounts of the wholly-owned subsidiaries and other subsidiaries in which
the Company holds a controlling financial or management interest of which the
Company determined that it is primary beneficiary. The Company uses the equity
method of accounting for investments in entities in which the Company has an
ownership interest between 20% and 50% and exercises significant influence.
The
Company also consolidates its pro rata share of oil and natural gas joint
ventures. All significant intercompany accounts and transactions have been
eliminated in consolidation.
Use
of Estimates
The
preparation of condensed consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities
and
disclosure of contingent assets and liabilities at the date of the condensed
consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Significant estimates underlying these condensed consolidated
financial statements include the estimated quantities of proved oil and natural
gas reserves used to compute depletion of oil and natural gas properties and
to
evaluate the full cost pool in the ceiling test analysis.
Asset
Retirement Obligation
On
January 1, 2006, the Company adopted Financial Accounting Standards Board
(“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement
Obligations,” which is an interpretation of FASB Statement No. 143 “Accounting
for Asset Retirement Obligations.” Accordingly, an entity is required to
recognize a liability for the fair value of a conditional asset retirement
obligation if the fair value can be reasonably estimated. The Company estimates
a fair value of the obligation on each well in which it owns an interest by
identifying costs associated with the future dismantlement and removal of
production equipment and facilities and the restoration and reclamation of
a
field’s surface to a condition similar to that existing before oil and natural
gas extraction began.
In
general, the amount of an Asset Retirement Obligation (“ARO”) and the costs
capitalized will be equal to the estimated future cost to satisfy the
abandonment obligation using current prices that are escalated by an assumed
inflation factor up to the estimated settlement date which is then discounted
back to the date that the abandonment obligation was incurred using an assumed
cost of funds for the Company. After recording these amounts, the ARO is
accreted to its future estimated value using the same assumed cost of funds
and
the additional capitalized costs are depreciated on a unit-of-production basis
within the related full cost pool.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
2.
|
BASIS
OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
|
Effective
January 1, 2007, the accretion of the ARO on producing wells was adjusted
for a change in the estimated life of the wells based on a reserve study
prepared by an independent reserve engineering firm. The estimated life of
the
wells was increased by 10 years to an estimated life of 50 years per well.
The
accretion expense is included in interest expense and the depreciation expense
is included in depreciation, depletion, and amortization in the consolidated
statements of operations.
The
following table sets forth a reconciliation of the Company’s ARO liability for
the periods indicated:
Three
Months Ended September 30,
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
Beginning
balance
|
|
$
|
989,885
|
|
$
|
1,013,329
|
|
Liabilities
incurred
|
|
|
168,162
|
|
|
106,763
|
|
Liabilities
settled
|
|
|
-
|
|
|
(123,809
|
)
|
Accretion
expense
|
|
|
18,983
|
|
|
16,722
|
|
Revisions
of estimated liabilities
|
|
|
161,970
|
|
|
(22,301
|
)
|
Ending
balance
|
|
$
|
1,339,000
|
|
$
|
990,704
|
|
Nine
Months Ended September 30,
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
Beginning
balance
|
|
$
|
1,331,893
|
|
$
|
812,634
|
|
Liabilities
incurred
|
|
|
292,023
|
|
|
369,789
|
|
Liabilities
settled
|
|
|
(34,293
|
)
|
|
(123,809
|
)
|
Accretion
expense
|
|
|
50,095
|
|
|
53,708
|
|
Revisions
of estimated liabilities
|
|
|
(300,718
|
)
|
|
(121,618
|
)
|
Ending
balance
|
|
$
|
1,339,000
|
|
$
|
990,704
|
|
Natural
Gas Derivative Instruments
The
Company’s results of operations and operating cash flows are impacted by the
fluctuations in the market prices of natural gas. To mitigate a portion of
the
exposure to adverse market changes, the Company will periodically enter into
various derivative instruments with a major financial institution. The purpose
of the derivative instrument is to provide a measure of stability to the
Company’s cash flow in meeting financial obligations while operating in a
volatile natural gas market environment. The derivative instrument reduces
the
Company’s exposure on the hedged production volumes to decreases in commodity
prices and limits the benefit the Company might otherwise receive from any
increases in commodity prices on the hedged production volumes.
The
Company recognizes all derivative instruments as assets or liabilities in the
balance sheet at fair value. The accounting treatment for changes in fair value,
as specified in SFAS No. 133 “Accounting for Derivative Investments and Hedging
Activities,” is dependent upon whether or not a derivative instrument is
designated as a hedge. For derivatives designated as cash flow hedges, changes
in fair value, to the extent the hedge is effective, are recognized in
Accumulated Other Comprehensive Income on the accompanying balance sheet until
the hedged item is recognized in earnings as natural gas revenue. If the hedge
has an ineffective portion, that particular portion of the gain or loss would
be
immediately reported in earnings. The following natural gas contracts were
in
place as of September 30, 2007, and qualified as cash flow hedges:
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
2.
|
BASIS
OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
|
Period
|
|
Type
of
Contract
|
|
Natural
Gas
Volume per Day
|
|
Price
per
mmbtu
|
|
Fair
Value
Asset
(Liability)
|
|
April
2007—December 2008
|
|
|
Swap
|
|
|
5,000
mmbtu
|
|
|
|
|
$
|
2,657,646
|
|
April
2007—December 2008
|
|
|
Collar
|
|
|
2,000
mmbtu
|
|
|
|
|
|
171,880
|
|
January
2008
–
December 2008
|
|
|
Swap
|
|
|
2,000
mmbtu
|
|
|
|
|
|
275,486
|
|
January
2009—December 2009
|
|
|
Swap
|
|
|
7,000
mmbtu
|
|
|
|
|
|
704,500
|
|
January
2010—March 2011
|
|
|
Swap
|
|
|
7,000
mmbtu
|
|
|
|
|
|
914,838
|
|
April
2011
–
September 2011
|
|
|
Swap
|
|
|
7,000
mmbtu
|
|
|
|
|
|
(69,035
|
)
|
Total
Estimated Fair Value
|
|
|
|
|
|
|
|
|
|
|
$
|
4,655,315
|
|
For
the
nine months ended September 30, 2007, the Company has recognized in
Comprehensive Income changes in fair value of $2,334,862 on the contracts that
have been designated as cash flow hedges on forecasted sales of natural gas.
See
“Comprehensive Income (Loss)” found in this note section. For the three months
ended September 30, 2007, and 2006, the Company recognized $1,541,930 and
$1,002,300, respectively, in net gains from hedging activities included in
oil
and natural gas revenues. For the nine months ended September 30, 2007, and
2006, the Company recognized $2,900,180 and $1,794,650, respectively, in net
gains from hedging activities included in oil and natural gas revenues.
Interest
Rate Derivative Instruments
The
Company’s use of debt directly exposes it to interest rate risk. The Company’s
policy is to manage interest rate risk through the use of a combination of
fixed
and floating rate debt. Interest rate swaps may be used to adjust interest
rate
exposure when appropriate. These derivatives are used as hedges and are not
for
speculative purposes. These derivatives involve the exchange of amounts based
on
variable interest rates and amounts based on a fixed interest rate over the
life
of the agreement without an exchange of the notional amount upon which payments
are based. The interest rate differential to be received or paid on the swaps
is
recognized over the lives of the swaps as an adjustment to interest
expense.
In
August
2007, the Company entered into a 3-year interest rate swap agreement in the
notional amount of $50 million with BNP to hedge its exposure to the floating
interest rate on the $50 million second lien term loan. The swap converted
the
debt’s floating three month LIBOR base to 4.86% fixed base. This swap on $50
million will yield an effective interest rate of 11.86% for the period from
August 23, 2007 through August 23, 2010 on the second lien term
loan.
For
the
nine months ended September 30, 2007, the Company has recognized in
Comprehensive Income (Loss) changes in fair value of $(351,050) on the interest
rate swap. See “Comprehensive Income (Loss)” found in this note section. For the
three and nine months ended September 30, 2007, the Company recognized $31,031
in interest savings related to the hedge activity which is recorded as an
adjustment to interest expense.
Financial
Instruments
The
Company’s financial instruments consist primarily of cash, accounts receivable,
loans receivable, accounts payable, accrued expenses, and debt. The carrying
amounts of such financial instruments approximate their respective estimated
fair value due to the short-term maturities and approximate market interest
rates of these instruments.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
2.
|
BASIS
OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
|
Stock-Based
Compensation
On
January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based
Payment” (SFAS No. 123R), to account for stock-based employee compensation.
Among other items, SFAS No. 123R eliminates the use of Accounting Principles
Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and
the intrinsic value method of accounting and requires companies to recognize
the
cost of employee services received in exchange for stock-based awards based
on
the grant date fair value of those awards in their financial statements. The
Company elected to use the modified prospective method for adoption, which
requires compensation expense to be recorded for all unvested stock options
beginning in the first quarter of adoption. For stock-based awards granted
or
modified subsequent to January 1, 2006, compensation expense, based on the
fair
value on the date of grant, will be recognized in the financial statements
over
the vesting period. The Company utilizes the Black-Scholes option pricing model
to measure the fair value of stock options. To the extent compensation cost
relates to employees directly involved in oil and natural gas exploration and
development activities, such amounts are capitalized to oil and natural gas
properties. Amounts not capitalized to oil and natural gas properties are
recognized as general and administrative expenses. See Note 8 “Common Stock
Options” which fully describes the Company’s stock-based compensation
plans.
The
following stock-based compensation was recorded for the periods
indicated:
For
the Three Months Ended September 30,
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$
|
597,742
|
|
$
|
957,028
|
|
Oil
and natural gas properties
|
|
|
36,049
|
|
|
195,401
|
|
Total
|
|
$
|
633,791
|
|
$
|
1,152,429
|
|
For
the Nine Months Ended September 30,
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$
|
1,799,498
|
|
$
|
1,349,177
|
|
Oil
and natural gas properties
|
|
|
169,816
|
|
|
560,694
|
|
Total
|
|
$
|
1,969,314
|
|
$
|
1,909,871
|
|
Comprehensive
Income (Loss)
Comprehensive
income (loss) is comprised of net income and other comprehensive income. Other
comprehensive income includes income resulting from derivative instruments
designated as hedging transactions. The details of comprehensive income (loss)
are as follows for the periods indicated:
Three
Months Ended September 30,
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(3,254,294
|
)
|
$
|
(2,086,234
|
)
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
Change
in fair value of natural gas derivative instruments
|
|
|
3,434,811
|
|
|
5,237,123
|
|
Change
in fair value of interest rate derivative instruments
|
|
|
(351,050
|
)
|
|
-
|
|
Comprehensive
Income (Loss)
|
|
$
|
(170,533
|
)
|
$
|
3,150,889
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
2.
|
BASIS
OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
|
Nine
Months Ended September 30,
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(3,765,136
|
)
|
$
|
(4,036,080
|
)
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
Change
in fair value of natural gas derivative instruments
|
|
|
2,334,862
|
|
|
6,991,488
|
|
Change
in fair value of interest rate derivative instruments
|
|
|
(351,050
|
)
|
|
-
|
|
Comprehensive
Income (Loss)
|
|
$
|
(1,781,324
|
)
|
$
|
2,955,408
|
|
Income
(Loss) Per Share
Basic
net
income (loss) per common share is computed based on the weighted average number
of common shares outstanding during each period. Diluted net income (loss)
per
common share is computed based on the weighted average number of common shares
outstanding plus other dilutive securities, such as restricted stock grants,
stock options, warrants, and redeemable convertible preferred stock. All
dilutive securities were excluded in the computation of diluted loss per share
for all periods indicated because their effect of assumed exercises or
conversions was anti-dilutive and, accordingly, basic and dilutive weighted
average shares are the same.
NOTE
3.
|
RECENT
ACCOUNTING PRONOUNCEMENTS
|
On
February 15, 2007, the FASB issued SFAS No. 159, “Fair Value Option for
Financial Assets and Financial Liabilities”—including an amendment of FASB
Statement No. 115. SFAS No. 159 permits entities to choose to measure many
financial instruments and certain other items at fair value. The FASB believes
the statement will improve financial reporting by providing companies the
opportunity to mitigate volatility in reported earnings by measuring related
assets and liabilities differently without having to apply complex hedge
accounting provisions. Use of the statement will expand the use of fair value
measurements for accounting for financial instruments. The Company does not
believe SFAS No. 159 will have a material impact on its consolidated financial
statements.
NOTE
4.
|
ACQUISITIONS
AND DISPOSITIONS
|
2007
– Rex Energy Exercised Option to Acquire Interest in Oil and Natural Gas
Leases
On
September 7, 2007, Rex Energy Corporation exercised an option to acquire a
30%
working interest in various undeveloped oil and natural gas leases located
in
the New Albany shale for approximately $1.1 million. The interest in oil and
gas
leases covers approximately 70,324 (21,097 net) acres in Lawrence, Jackson,
Washington and Orange Counties, Indiana.
2007
–
GFS and
Federated Oil and Gas Properties
On
August
31, 2007, the Company entered into two Purchase Letter Agreements to buy GFS
Energy, Inc. and Federated Oil & Gas Properties, Inc. non-operated working
interests and overriding royalty interests in various developed oil and natural
gas properties located in the Antrim shale for approximately $3.0 million.
The
properties included 93 (33 net) wells, producing approximately 500 mcfe per
day,
and approximately 4,700 (1,706 net) acres. This transaction had an effective
date of September 1, 2007.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
4.
|
ACQUISITIONS
AND DISPOSITIONS
(continued)
|
2007
– Knox, Indiana
On
July
30, 2007, the Company purchased from Horizontal Systems, Inc. its working
interest in various undeveloped oil and natural gas leases located in Knox
County, Indiana for approximately $1.2 million pursuant to a Sale and Assignment
of Oil and Gas Interests Agreement. The properties included 25% working interest
in one well and approximately 9,642 net acres.
2007
– Mining Claims
On
May
15, 2007, the Company sold certain mining claims and mineral leases to U.S.
Silver-Idaho, Inc. for $400,000 in cash and 50,000 shares of common stock in
U.S. Silver Corporation. This non-core property sale consisted of 14 unpatented
and 27 patented mining claims as well as 5 mineral leases located in Idaho.
A
$418,000 gain was recognized in other income since these non-core properties
were being recognized as an investment.
2007
– Kansas Project
On
February 7, 2007, the Company entered into a Purchase and Sale Letter Agreement
to sell to Harvest Energy, LLC all of the Company’s interest in various
developed and undeveloped oil and natural gas properties located in Lane and
Ness Counties in the State of Kansas for approximately $1.0 million. The
properties included two net wells, 98 mmcfe in proven reserves, and
approximately 23,110 net acres. This transaction closed on March 9,
2007.
2007
– Other Investments
From
time
to time, the Company has acquired and disposed of legacy Cadence stock
investments and non-core working interests. For the nine months ended September
30, 2007, the Company recognized minor stock investments valued at approximately
$250,000 and disposed of non-core working interests of approximately
$310,000.
NOTE
5.
|
OIL
AND NATURAL GAS PROPERTIES HELD FOR
SALE
|
During
the second quarter of 2006, the Company identified $21.4 million of oil and
natural gas properties as held for sale due to their high probability of being
sold within a 12 month period. Through September 30, 2007, the Company completed
$5.1 million in planned oil and natural gas properties sales consisting of
four
oil and natural gas properties located in Kansas, Louisiana, Ohio, and New
Mexico. (See Note 4 “Acquisitions and Dispositions” for 2007 activity.) Under
the full cost method, sales of oil and natural gas properties, whether or not
being amortized currently, are accounted for as adjustments of capitalized
costs
with no gain or loss recognized unless such adjustments would significantly
alter the relationship between capitalized costs and proved reserves. The
Company will routinely focus attention on its oil and natural gas properties
to
ensure that its continued holdings are aligned with the Company’s long-term
strategic plan. Management has removed properties held for sale from the balance
sheet given the investigation of strategic alternatives currently being
explored.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Short-Term
Bank Borrowings
The
Company has a $5.0 million revolving line of credit agreement with Northwestern
Bank for general corporate purposes through October 15, 2007. The Company
elected not to request an extension of this revolving line of credit beyond
the
expiration date of October 15, 2007. The interest rate under the revolving
line
of credit is Wall Street prime (7.75% at September 30, 2007, and 8.25% at
September 30, 2006) with interest payable monthly in arrears. Principal is
payable at the expiration of the revolving line of credit agreement.
Northwestern Bank also provides letters of credit for the Company’s drilling
program (as described in Note 9 “Commitments and Contingencies”). These letters
of credit may be extended or may be replaced upon their expiration dates by
letters of credit under the Company’s senior secured credit facility. Interest
expense on the Northwestern Bank revolving line for the three months ended
September 30, 2007, and 2006, was $28,098 and $70,280, respectively. Interest
expense on the Northwestern Bank revolving line for the nine months ended
September 30, 2007, and 2006, was $34,980 and $248,734,
respectively.
Short-Term
Bank Borrowings – Bach Services & Manufacturing Co., L.L.C. (“Bach”), a
wholly-owned subsidiary
On
October 6, 2006, Bach entered into a $175,100 revolving line of credit agreement
with Northwestern Bank for general company purposes. Effective April 16,
2007, Northwestern Bank increased the borrowing capacity under the revolving
line of credit to $0.5 million. This line of credit is secured by all of Bach’s
personal property owned or hereafter acquired and is non-recourse to the
Company. The interest rate under the revolving line of credit is Wall Street
prime (7.75% at September 30, 2007) with interest payable monthly in arrears.
Principal is payable at the expiration of the revolving line of credit
agreement. Northwestern Bank has extended the expiration date to October 1,
2008. Interest expense for the three and nine months ended September 30, 2007,
was $955 and $2,298, respectively.
Mortgage
and Notes Payable - Bach
As
of
September 30, 2007, Bach’s outstanding loans were as follows with interest
expense for the periods indicated:
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
Description
of Loan
|
|
Date
of
Loan
|
|
Maturity
Date
|
|
Interest
Rate
|
|
Principal
Amount
Outstanding
|
|
Three Months
Ended
September 30,
2007
|
|
Nine Months
Ended
September 30,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mortgage
payable on building
|
|
|
10/06/06
|
|
|
10/15/09
|
|
|
6.00
|
%
|
$
|
372,531
|
|
$
|
3,966
|
|
$
|
15,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vehicles
|
|
|
10/06/06
|
|
|
10/01/10
|
|
|
7.50
|
%
|
|
71,947
|
|
|
1,452
|
|
|
4,657
|
|
Equipment
|
|
|
10/06/06
|
|
|
09/01/07
|
|
|
5.50
|
%
|
|
-
|
|
|
21
|
|
|
253
|
|
Vehicles
|
|
|
12/18/06
|
|
|
12/20/09
|
|
|
7.25
|
%
|
|
54,028
|
|
|
1,023
|
|
|
3,460
|
|
Vehicles
|
|
|
04/23/07
|
|
|
04/25/11
|
|
|
7.00
|
%
|
|
85,801
|
|
|
2,239
|
|
|
2,808
|
|
Vehicles
|
|
|
09/13/07
|
|
|
09/15/10
|
|
|
6.95
|
%
|
|
24,119
|
|
|
74
|
|
|
74
|
|
Total
notes payable
|
|
|
|
|
|
|
|
|
|
|
$
|
235,895
|
|
$
|
4,809
|
|
$
|
11,252
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Mortgage
Payable
On
October 4, 2005, the Company entered into a mortgage loan from Northwestern
Bank
in the amount of $2,925,000 for the purchase of an office condominium and
associated interior improvements. The security for this mortgage is the office
condominium real estate. The payment schedule is monthly interest only for
the
first 3 months starting on November 1, 2005, and, beginning on February 1,
2006,
principal and interest in 32 monthly payments of $21,969 with one principal
and
interest payment of $2,733,994 on October 1, 2008. The interest rate is 6.5%
per
year. The maturity date is October 1, 2008. As of September 30, 2007, the
principal amount outstanding was $2,733,888. Interest expense for the three
months ended September 30, 2007, and 2006, was $60,454 and $46,956,
respectively. Interest expense for the nine months ended September 30, 2007,
and
2006, was $129,790 and $146,690, respectively.
Note
Payable – Directors and Officers Insurance
On
November 13, 2006, the Company entered into a financing agreement with AICCO,
Inc. to finance the insurance premium related to director and officer liability
insurance coverage in the amount of $184,230. A monthly payment of $15,807
was
required beginning November 30, 2006, through August 1, 2007. The interest
rate
was 7.01% per year. Interest expense for the three and nine months ended
September 30, 2007, was $273 and $2,546, respectively.
Second
Lien Term Loan
On
August
20, 2007, the Company entered into a second lien term loan agreement with BNP
Paribas (“BNP”), as the arranger and administrative agent, and several other
lenders forming a syndicate. The initial term loan is $50 million for a 5-year
term (expires 8/20/12) which may increase up to $70 million under certain
conditions over the life of the loan facility. The proceeds of the loan were
used to repay the outstanding balance under the Company’s mezzanine financing
with Trust Company of the West (“TCW”) and for general corporate purposes.
Interest under the loan is payable at rates based on the London Interbank
Offered Rate (“LIBOR”) plus 700 basis points with a step-down of 25 basis points
once the Company’s ratio of total indebtedness to earnings before interest,
taxes, depreciation, depletion, amortization, and other non-cash charges is
lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis.
The Company has the ability to prepay the loan during the first year at a price
equal to 103% of par, during the second year at a price equal to 102% of par,
and thereafter at a price equal to 100% of par.
The
loan
contains, among other things, a number of financial and non-financial covenants
relating to restricted payments (as defined), loans or advances to others,
additional indebtedness, incurrence of liens, geographic limitations on
operations to the United States, and maintenance of certain financial and
operating ratios, including (i) maintenance of a maximum of indebtedness to
earnings before interest, income taxes, depreciation, depletion and amortization
and non-cash expenses, and (ii) maintenance of minimum reserve value to
indebtedness. Any event of default under the senior secured credit facility
that
accelerates the maturity of any indebtedness thereunder is also an event of
default under the second lien term loan.
In
both
the loan and senior secured credit facility, the Company agreed to an
affirmative covenant regarding production exit rates with the first net
production target being 9.5 MMcfe per day as of June 30, 2007, which the Company
achieved. The second target production exit target is 10.5 MMcfe per day as
of
September 30, 2007 (which has been achieved), and the third production exit
target is 12.0 MMcfe per day as December 31, 2007, and as of the last day of
each quarter thereafter. In addition, the Company was required to purchase
financial hedges at prices and aggregate notional volumes satisfactory to BNP,
as administrative agent. This requirement has been satisfied.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For
the
three and nine months ended September 30, 2007, interest and fees incurred
for
the loan was $711,143. The Company has also incurred deferred financing fees
of
approximately $1.3 million with regard to the loan. The deferred financing
fees
are being amortized on a straight-line basis over the remaining terms of the
loan obligation. Amortization expense for the loan is estimated to be $264,000
per year through 2011. Amortization expense was $30,316 for the three and nine
months ended September 30, 2007. In addition, the Company incurs annual agency
fees which are recorded to interest expense.
Mezzanine
Financing
Effective
August 20, 2007, the Company’s subsidiary Aurora Antrim North, L.L.C. (“North”)
terminated its Amended Note Purchase Agreement with TCW which provided $50
million in mezzanine financing. As of the effective date, North had outstanding
borrowing of $40 million. The interest rate was fixed at 11.5% per year,
compounded quarterly, and payable in arrears. TCW had limited the borrowing
base
and the agreement contained a commitment expiration date of August 12, 2007.
Under the termination provisions, the Company was required to pay certain fees
and prepayment charges associated with early termination. The following
represents the expenditures paid to TCW: (i) $40 million payment of principal;
(ii) $0.7 million payment of interest expense from June 27, 2007, through August
20, 2007; (iii) $0.36 million payment of interest make-whole provision from
August 21, 2007, through September 27, 2007; (iv) $1.25 million payment of
prepayment premium; and (v) $0.2 million payment for a make-whole provision
on
principal greater than $30 million.
As
part
of the mezzanine financing with TCW, North provided an affiliate of TCW an
overriding royalty interest of 4% in certain leases to be drilled or developed
in the Counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency, and
Otsego in the State of Michigan. The overriding royalty interest will also
continue on leases, including extensions or renewals, held by the Company and
its affiliates at August 20, 2007, that may be developed through September
29,
2009.
For
the
three months ended September 30, 2007, and 2006, interest and fees incurred
for
the mezzanine credit facility was $638,471 and $1,175,417, respectively. For
the
nine months ended September 30, 2007, and 2006, interest and fees incurred for
the mezzanine credit facility was $2,989,305 and $3,526,528, respectively.
In
addition, the Company completed a write-off $1.6 million of unamortized debt
issuance cost associated with the mezzanine financing.
Senior
Secured Credit Facility
On
January 31, 2006, the Company entered into a $100 million senior secured credit
facility with BNP and other lenders for drilling, development, and acquisitions,
as well as other general corporate purposes. In connection with the second
lien
term loan discussed above, the Company also agreed to the amendment and
restatement of the senior secured credit facility, pursuant to which the
borrowing base under the senior secured credit facility was increased from
the
current authorized borrowing base of $50 million to $70 million effective August
20, 2007. The amount of the borrowing base is based primarily upon the estimated
value of the Company’s oil and natural gas reserves. The borrowing base amount
is redetermined by the lenders semi-annually on or about April 1 and October
1
of each year or at other times required by the lenders or at the Company’s
request. The required semiannual reserve report may result in an increase or
decrease in credit availability. The security for this facility is substantially
all of the Company’s oil and natural gas properties; guarantees from all
material subsidiaries; and a pledge of 100% of the stock or member interest
of
all material subsidiaries.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
This
facility provides for borrowings tied to BNP’s prime rate (or, if higher, the
federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0%
depending on the borrowing base utilization, as selected by the Company. The
borrowing base utilization is the percentage of the borrowing base that is
drawn
under the senior secured credit facility from time to time. As the borrowing
base utilization increases, the LIBOR-based interest rates increase under this
facility. As of September 30, 2007, interest on the borrowings had a weighted
average interest rate of 6.93%. For the three months ended September 30, 2007,
and 2006, interest and fees incurred for the senior secured credit facility
were
$794,298 and $785,738, respectively. For the nine months ended September 30,
2007, and 2006, interest and fees incurred for the senior secured credit
facility were $1,773,533 and $1,892,134, respectively. All outstanding principal
and accrued and unpaid interest under the senior secured facility is due and
payable on January 31, 2010. The maturity date of the outstanding loan may
be
accelerated by the lenders upon occurrence of an event of default under the
senior secured credit facility.
The
senior secured credit facility contains, among other things, a number of
financial and non-financial covenants relating to restricted payments (as
defined), loans or advances to others, additional indebtedness, incurrence
of
liens, geographic limitations on operations to the United States, and
maintenance of certain financial and operating ratios, including (i) maintenance
of a minimum current ratio, and (ii) maintenance of a minimum interest coverage
ratio. Any event of default under the second lien term loan that accelerates
the
maturity of any indebtedness thereunder is also an event of default under the
senior secured credit facility.
The
Company has incurred deferred financing fees of approximately $680,350 with
regard to the senior secured credit facility. The deferred financing fees are
being amortized on a straight-line basis over the remaining terms of the debt
obligation. Amortization expense for the senior secured credit facility is
estimated to be $202,000 per year through 2009. Amortization expense was $47,930
and $215,148 for the three months ended September 30, 2007, and 2006,
respectively. Amortization expense was $114,031 and $598,293 for the nine months
ended September 30, 2007, and 2006, respectively. In addition, the Company
incurs various annual fees associated with unused commitment and agency fees.
These annual fees are recorded to interest expense.
The
Company capitalizes interest on debt related to expenditures made in connection
with exploration and development projects that are not subject to the full
cost
amortization pool. Interest is capitalized only for the period that exploration
activities are in progress. Interest is capitalized using a weighted average
interest rate based on the outstanding borrowing and cost of equity of the
Company. Capitalized interest was $1,225,728 and $30,705 for the three months
ended September 30, 2007, and 2006, respectively. Capitalized interest was
$3,083,417 and $677,682 for the nine months ended September 30, 2007, and 2006,
respectively.
NOTE
7.
|
SHAREHOLDERS’
EQUITY
|
Common
Stock
From
February 2007 through September 2007, 170,000 common stock options were
exercised by various Company employees under the existing stock option plans
at
exercise prices ranging from $0.375 to $1.25 per share. The Company received
$77,500 in conjunction with these exercises.
In
June
2007, 75,000 shares of the Company’s common stock valued at $147,000 were
cancelled in order to reconcile with the Company’s transfer agent.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
7.
|
SHAREHOLDERS’
EQUITY (continued)
|
In
February and March 2007, 93,332 common stock options were exercised by various
Company directors under the existing stock option plans at an exercise price
of
$0.375 per share. The Company received $35,000 in conjunction with these
exercises.
In
January 2007, 78,158 shares of the Company’s common stock were issued in
connection with the exercise of outstanding warrants by a non-affiliated party
in a net issue (cashless) exercise transaction.
Common
Stock Warrants
The
following table sets forth information related to stock warrant activity for
the
period indicated:
Nine
Months Ended
September
30, 2007
|
|
|
Number of
Shares Underlying Warrants
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Contract Life
in
Years
|
|
Outstanding
at the beginning of the period
|
|
|
2,079,500
|
|
$
|
1.71
|
|
|
1.98
|
|
Granted
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Exercised
|
|
|
(78,158
|
)
|
|
(1.25
|
)
|
|
0.24
|
|
Forfeitures
and other adjustments
|
|
|
(49,342
|
)
|
|
(1.25
|
)
|
|
0.24
|
|
Outstanding
at the end of the period
|
|
|
1,952,000
|
|
$
|
1.74
|
|
|
1.34
|
|
As
of
September 30, 2007, the Company maintains four stock option plans that are
fully
described in Note 8 “Common Stock Options” in the Company’s Annual Report on
Form 10-KSB for the year-ended December 31, 2006. These stock option plans
provide for the award of options or restricted shares for compensatory purposes.
The purpose of these plans is to promote the interests of the Company by
aligning the interests of employees (including directors and officers who are
employees), consultants, and non-employee directors of the Company and to
provide incentives for such persons to exert maximum efforts for the success
of
the Company and its subsidiaries.
The
following table sets forth activity for the stock option plans referenced above
for the period indicated:
Nine
Months Ended September 30, 2007
|
|
|
Number of Shares
Underlying Options
|
|
Options
outstanding at beginning of period
|
|
|
3,432,496
|
|
Options
granted
|
|
|
185,000
|
|
Options
exercised
|
|
|
(263,332
|
)
|
Options
forfeited and other adjustments
|
|
|
(261,334
|
)
|
Options
outstanding at end of period
|
|
|
3,092,830
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
8.
|
COMMON
STOCK OPTIONS (continued)
|
The
weighted average assumptions used in the Black-Scholes option-pricing model
used
to determine fair value of the option granted in the nine months ended September
30, 2007, were as follows:
Risk-free
interest rate
|
|
|
4.67
|
%
|
Expected
years until exercise
|
|
|
3.25-6.0
|
|
Expected
stock volatility
|
|
|
71.41
|
%
|
Dividend
yield
|
|
|
0
|
%
|
All
Stock Options
In
addition, the Company has awarded compensatory options and warrants totaling
1,430,280 on an individualized basis that was considered outside the awards
issued under its existing stock option plans. The following table sets forth
activity with respect to all stock options awarded for the period
indicated:
Nine Months Ended September 30, 2007
|
|
|
Number of Shares
Underlying Options
|
|
|
Weighted
Average
Exercise Price
|
|
|
Aggregate
Intrinsic
Value(a)
|
|
Options
outstanding at beginning of period
|
|
|
4,862,776
|
|
$
|
2.23
|
|
|
|
|
Options
granted
|
|
|
185,000
|
|
|
3.35
|
|
|
|
|
Options
exercised
|
|
|
(263,332
|
)
|
|
0.43
|
|
|
|
|
Forfeitures
and other adjustments
|
|
|
(261,334
|
)
|
|
4.68
|
|
|
|
|
Options
outstanding at end of period
|
|
|
4,523,110
|
|
$
|
2.24
|
|
$
|
1,713,547
|
|
Exercisable
at end of period
|
|
|
3,018,775
|
|
$
|
1.52
|
|
$
|
1,713,547
|
|
Weighted
average fair value of options granted during period
|
|
$
|
1.20
|
|
|
|
|
|
|
|
(a)
The
intrinsic value of a stock option is the amount by which the current market
value of the underlying stock exceeds the exercise price of the option. The
intrinsic value of the options exercised during the nine months ended September
30, 2007, was approximately $267,000.
The
following table provides the unrecognized compensation expense related to
unvested stock options as of September 30, 2007. The expense is expected to
be
recognized over the following 3-year period.
Period
to be
Recognized
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Total Unrecognized
Compensation Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
st
Quarter
|
|
$
|
-
|
|
$
|
441,781
|
|
$
|
37,255
|
|
$
|
1,146
|
|
|
2
nd
Quarter
|
|
|
-
|
|
|
371,364
|
|
|
16,532
|
|
|
-
|
|
|
3
rd
Quarter
|
|
|
-
|
|
|
125,070
|
|
|
6,284
|
|
|
-
|
|
|
4
th
Quarter
|
|
|
561,185
|
|
|
103,561
|
|
|
2,956
|
|
|
-
|
|
|
Total
|
|
$
|
561,185
|
|
$
|
1,041,776
|
|
$
|
63,027
|
|
$
|
1,146
|
|
$
1,667,134
|
NOTE
8.
|
COMMON
STOCK OPTIONS (continued)
|
The
weighted average remaining life by exercise price as of September 30, 2007,
is
summarized below:
Range of
Exercise Prices
|
|
Outstanding
Shares
|
|
Weighted
Average Life
|
|
Exercisable
Shares
|
|
Weighted
Average Life
|
|
|
$0.25
- $0.38
|
|
|
536,664
|
|
|
3.0
|
|
|
536,664
|
|
|
3.0
|
|
|
$0.50
- $0.75
|
|
|
1,400,000
|
|
|
1.4
|
|
|
1,400,000
|
|
|
1.4
|
|
|
$1.25
- $1.75
|
|
|
342,000
|
|
|
5.5
|
|
|
342,000
|
|
|
5.5
|
|
|
|
|
|
461,280
|
|
|
6.3
|
|
|
130,280
|
|
|
1.8
|
|
|
|
|
|
1,140,000
|
|
|
3.3
|
|
|
300,000
|
|
|
3.1
|
|
|
|
|
|
543,166
|
|
|
7.4
|
|
|
209,831
|
|
|
6.4
|
|
|
$5.19
- $5.54
|
|
|
100,000
|
|
|
3.5
|
|
|
100,000
|
|
|
3.5
|
|
|
$0.25
- $5.54
|
|
|
4,523,110
|
|
|
3.6
|
|
|
3,018,775
|
|
|
2.7
|
|
NOTE
9.
|
COMMITMENTS
AND CONTINGENCIES
|
Environmental
Risk
Due
to
the nature of the oil and natural gas business, the Company is exposed to
possible environmental risks. The Company manages its exposure to environmental
liabilities for both properties it owns as well as properties to be acquired.
The Company has historically not experienced any significant environmental
liability and is not aware of any potential material environmental issues or
claims at September 30, 2007.
Letters
of Credit
For
each
salt water disposal well drilled in the State of Michigan, the Company is
required to issue a letter of credit to the Michigan Supervisor of Wells. The
Supervisor of Wells may draw on the letter of credit if the Company fails to
comply with the regulatory requirements relating to the locating, drilling,
completing, producing, reworking, plugging, filling of pits, and clean up of
the
well site. The letter of credit or a substitute financial instrument is required
to be in place until the salt water disposal well is plugged and abandoned.
For
drilling natural gas wells, the Company is required to issue a blanket letter
of
credit to the Michigan Supervisor of Wells. This blanket letter of credit allows
the Company to drill an unlimited number of natural gas wells. The existing
letters of credit have been issued by Northwestern Bank of Traverse City,
Michigan, and are secured only by a Reimbursement and Indemnification Commitment
issued by the Company, together with a right of setoff against all of the
Company’s deposit accounts with Northwestern Bank. At September 30, 2007,
letters of credit in the amount of $1.2 million were outstanding to the Michigan
Supervisor of Wells.
Employment
Agreement
Effective
June 19, 2006, the Company hired Ronald E. Huff to serve as Chief Financial
Officer of the Company. The Company has entered into a 2-year Employment
Agreement with Mr. Huff, providing for an annual salary of $200,000 per year
and
an award of a stock bonus in the amount of 500,000 shares of the Company’s
common stock on January 1, 2009, so long as he remains employed by the Company
through June 18, 2008, which requires the Company to record approximately $2.1
million in stock-based compensation expense over the contract period. If his
employment with the Company is terminated prior to this date without just cause
or if the Company undergoes a change in control, he will nonetheless be awarded
the full 500,000 shares. If his employment is terminated prior to June 18,
2008,
due to death or disability, he will receive a prorated stock award. Mr. Huff
forfeited the option to purchase 200,000 shares that he was previously awarded
for his service as a director of the Company. Mr. Huff remains a director of
the
Company.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
NOTE
9.
|
COMMITMENTS
AND CONTINGENCIES
(continued)
|
Equipment
Sale - Leaseback Agreement
Effective
June 21, 2007, the Company entered into an agreement with Fifth Third Bank
to
sell and leaseback three natural gas compressors, which were accounted for
as an
operating lease. The net carrying value of the natural gas compressors sold
was
$1,202,000. Because the net carrying value of the natural gas compressors was
equal to the sales price, there was no gain or loss recognized on the sale.
The
lease agreement has a base lease term of 84 months with a monthly rental fee
of
$13,610 beginning July 1, 2007.
Fry
Well Loss
The
Company participated with Savoy Energy, L.P. (“Savoy”) in a exploratory well
known as the Fry 1-13 located in Mecosta County, Michigan. In late December
2006, the well experienced a blow-out event which incurred approximately $5.6
million associated with controlling the well and other related costs. The
Company had a 13.33% cost interest (10% working interest) in this well to casing
point and paid approximately $762,000 to cover its portion of the loss to Savoy.
The Company’s insurance covered approximately 34% or $266,666 of the well
control costs.
Retention
Bonus
On
September 19, 2007, the Company announced that it had retained Johnson Rice
& Company, L.L.C. to assist the Board of Directors with investigating
strategic alternatives for the Company. These alternatives, among other things,
may include revisions to the Company’s strategic plan, asset divestitures,
operating partnerships, identifying additional capital sources, or a sale,
merger, or other business combination of the Company. The Board of Directors
of
the Company has approved a retention bonus arrangement to encourage certain
key
officers and employees to remain with the Company through the completion of
the
Company’s review of potential strategic alternatives. The Board of Directors
recognizes that certain key officers and employees will have increased
responsibilities and duties during the evaluation of strategic alternatives
and
will contribute significantly to the process. The aggregate retention bonus
consists of four payments over an 8-month period beginning in late October
2007
through late April 2008. The key officers and employees must remain continuously
employed with the Company as well as remain in good standing on the scheduled
payment dates. As of October 24, 2007, certain officers of the Company that
accepted this arrangement are as follows: (i) Ronald Huff (President and Chief
Financial Officer); (ii) John C. Hunter (Vice President); (iii) John V. Miller
(Vice President); and (iv) Lorraine M. King (Former Chief Financial Officer).
As
of September 30, 2007, the Company has recorded $237,500 for estimated retention
bonuses in 2007.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
10.
|
RELATED
PARTY TRANSACTION
|
Effective
May 30, 2007, the board of directors named John C. Hunter as Vice President
of
Exploration and Production. He has worked for AOG since 2005 as Senior Petroleum
Engineer. Prior to that, Mr. Hunter was instrumental in certain projects
associated with the Company’s New Albany shale play. Over a series of agreements
with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has
acquired 1.25% working interest in certain leases. The leases cover
approximately 132,600 acres (1,658 net) in certain counties located in Indiana.
The 1.25% carried working interest shall be effective until development costs
exceed $30 million. Thereafter, participation may continue as a standard 1.25%
working interest owner. The Company is entitled to recovery of 100% of
development costs (plus interest at a rate of 6.75% per annum compounded
annually) from 85% of the net operating revenue generated from oil and gas
production developed directly or indirectly in the area of mutual interest
covered by the agreement. As of September 30, 2007, there is no production
associated with this working interest and development costs were approximately
$12.0 million.
Effective
July 1, 2004, Aurora Energy, Ltd., (“AEL”), entered into a Fee Sharing Agreement
with Mr. Hunter as compensation for bringing Bluegrass Energy Enhancement
Fund,
LLC (“Bluegrass”) and AEL together for the development of the 1500 Antrim and
Red Run Projects in Michigan. At this time, AEL and Bluegrass have discontinued
leasing activities in both projects. In the 1500 Antrim project, there are
23,989.41 acres. Mr. Hunter's carried working interest share of 0.8333% is
approximately 199.95 net acres. The carried working interest relates to the
first 55 wells that are drilled in the area of mutual interest. Thereafter,
Mr.
Hunter would pay his proportionate share of working interest expenses.
Currently, there are no producing wells. The Red Run project contains 12,893.64
acres. Mr. Hunter's carried working interest share of 0.8333% is approximately
107.44 net acres. The carried working interest relates to the first 55 wells
that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would
pay his proportionate share of working interest expenses. Currently, there
are 3
wells permitted for the Red Run project and one well was temporarily abandoned
in June 2007.