As
filed with the Securities and Exchange Commission on October 31,
2007
Registration
No. 333-129695
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Post
Effective Amendment No. 4
to
Form
SB-2
REGISTRATION
STATEMENT
UNDER
THE
SECURITIES ACT OF 1933
AURORA
OIL & GAS CORPORATION
(Name
of Small Business Issuer in its Charter)
Utah
|
1311
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87-0306609
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(State
or other jurisdiction of
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(Primary
Standard Industrial
|
(I.R.S.
Employer
|
incorporation
or organization)
|
Classification
Code Number)
|
Identification
No.)
|
4110
Copper Ridge Drive, Suite 100
Traverse
City, Michigan 49684
(231) 941-0073
(Address
and telephone number of principal executive offices, place of
business)
Name,
address and telephone number of agent for service:
William
W. Deneau, Chief Executive Officer
Aurora
Oil & Gas Corporation
4110
Copper Ridge Drive, Suite 100
Traverse
City, Michigan 49684
(231) 941-0073
With
a copy to:
Iris
K. Linder
|
Fraser
Trebilcock Davis & Dunlap, PC
|
124 West
Allegan, Suite 1000
|
Lansing,
MI 48933
|
Approximate
date of proposed sale to the public:
As
soon as practicable after this Registration Statement becomes
effective.
If
this
Form is filed to register additional securities for an offering pursuant to
Rule 462(b) under the Securities Act, check the following box and list the
Securities Act registration statement number of the earlier effective
registration statement for the same offering:
o
If
this
Form is a post-effective amendment filed pursuant to Rule 462(c) under the
Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same
offering:
o
If
this
Form is a post-effective amendment filed pursuant to Rule 462(d) under the
Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same
offering:
o
If
delivery of the prospectus is expected to be made pursuant to Rule 434,
check the following box:
o
The
Registrant hereby amends this Registration Statement on such date or dates
as
may
be
necessary to delay its effective date until the Registrant shall file a
further
amendment
which specifically states that this Registration Statement shall
thereafter
become
effective in accordance with Section 8(a) of the Securities Act of
1933,
as
amended, or until this Registration Statement shall become effective on such
date
as
the Securities and Exchange Commission, acting pursuant to said
Section 8(a),
may
determine.
SUBJECT
TO COMPLETION, DATED OCTOBER 31, 2007.
8,900,000 Shares
Common
Stock
All
of
the shares to which this prospectus relates are being registered for resale
by
certain selling security holders as described more fully beginning on page
61.
We will not sell any of these shares nor will we receive any proceeds from
the
sale of the shares.
Our
common stock is traded on the American Stock Exchange under the symbol “AOG.” On
October 30, 2007, the last sales price of our common stock as reported on
the American Stock Exchange was $1.42 per share.
Investing
in our common stock involves risks. See “Risk Factors”
beginning
on
page 11.
Neither
the Securities and Exchange Commission nor any state securities
commission
has
approved or disapproved of these securities or passed upon the adequacy
or
accuracy
of this prospectus. Any representation to the contrary is a
criminal
offense.
The
date
of this prospectus is October 31, 2007.
TABLE
OF CONTENTS
PROSPECTUS
SUMMARY
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1
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RISK
FACTORS
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11
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CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
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21
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USE
OF PROCEEDS
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22
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PRICE
RANGE OF COMMON STOCK
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23
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SELECTED
HISTORICAL FINANCIAL DATA
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24
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MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
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26
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BUSINESS
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39
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MANAGEMENT
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49
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EXECUTIVE
COMPENSATION
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57
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PRINCIPAL
AND SELLING SECURITY HOLDERS
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60
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RELATED
PARTY TRANSACTIONS
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65
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DESCRIPTION
OF SECURITIES
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68
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LEGAL
MATTERS
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71
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EXPERTS
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71
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CHANGE
IN INDEPENDENT AUDITORS
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71
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WHERE
YOU CAN FIND MORE INFORMATION
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72
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FINANCIAL
STATEMENTS
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F1-F51
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APPENDIX
A — GLOSSARY OF OIL AND NATURAL GAS TERMS
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A1-A4
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You
should rely only on the information contained in this prospectus or to which
we
have
referred you. We have not authorized anyone to provide you with information
that
is
different. This document may only be used where it is legal to sell
these
securities.
The information in this document may only be accurate on the date of
this
prospectus.
Except
as
otherwise indicated or required by the context, references in this prospectus
to
“we”, “us,” “our” or the “Company” refer to Aurora Oil & Gas
Corporation and its subsidiaries. The term “you” refers to a prospective
investor.
PROSPECTUS
SUMMARY
This
summary contains basic information about us and the offering. Because it is
a
summary,
it does not contain all the information that you should consider
before
investing
in our common stock. You should read and carefully consider this
entire
prospectus
before making an investment decision, especially the information
presented
under
the heading “Risk Factors” and our consolidated financial statements and
the
accompanying
notes included elsewhere in this prospectus, as well as the
other
documents
to which we refer you. We have provided definitions for some of the oil
and
natural
gas industry terms used in this prospectus in the “Glossary of Oil
and
Natural
Gas Terms” in Appendix A. Natural gas equivalents are determined
using
the
ratio of six mcf of natural gas to one bbl of crude oil, condensate or
natural
gas
liquids.
AURORA
OIL & GAS CORPORATION
Overview
We
are a
growing independent energy company focused on the exploration, exploitation,
and
development of unconventional natural gas reserves. Our unconventional natural
gas projects target shale plays where large acreage blocks can be easily
evaluated with a series of low cost test wells. Shale plays tend to be
characterized by high drilling success and relatively low drilling costs when
compared to conventional exploration and development plays. Our project areas
are focused in the Antrim shale of Michigan, the New Albany shale of Southern
Indiana and Western Kentucky, and the Woodford shale in Oklahoma.
We
commenced operations in 1969 to explore and mine natural resources under the
name Royal Resources, Inc. In July 2001, we reorganized our business to pursue
oil and natural gas exploration and development opportunities and changed our
name to Cadence Resources Corporation. We acquired Aurora Energy, Ltd.
("Aurora") on October 31, 2005 through the merger of our wholly-owned subsidiary
with and into Aurora. The acquisition of Aurora was accounted for as a reverse
merger, with Aurora being the acquiring party for accounting purposes. The
Aurora executive management team also assumed management control at the time
the
merger closed, and we moved our corporate offices to Traverse City,
Michigan.
Our
strategy is to maximize shareholder value by leveraging our significant acreage
position and the experience of our management and technical teams in finding
and
developing natural gas reserves to profitably grow our reserves and production.
Over the last several years we have focused primarily on the acquisition of
properties in the Antrim and New Albany shale. We have recently begun to acquire
properties in the Woodford shale. As an early stage developer of properties,
we
anticipate reserve growth will be our initial focus followed by a more
traditional balance between reserve and production growth.
Our
Strategy
The
principal elements of our strategy to maximize shareholder value
are:
Generate
growth through drilling
.
We
expect to generate long-term reserve and production growth predominantly through
our drilling activities. We believe the experience and expertise of our
management and technical teams enables us to identify, evaluate and develop
natural gas projects. We anticipate the substantial majority of our future
capital expenditures will be directed toward the drilling of wells, although
we
expect to continue to acquire additional leasehold interests. Initially, we
anticipate reserve growth will be our primary focus with a more balanced reserve
and production growth profile as we continue to execute our growth strategy.
Focus
on lower risk shale development projects, with selective expenditures outside
our focus areas
.
Most of
our acreage in the Antrim and New Albany shale contains lower risk
unconventional natural gas development plays, including 612,577 net leasehold
acres on which we have identified approximately 2,500 net potential drilling
locations. In the Antrim shale play there have been over 9,000 successful gas
wells drilled and are currently in production. The New Albany shale play is
an
emerging play without the history of the Antrim shale play, but we believe
it
will have similar success characteristics to the Antrim shale play. We believe
that by focusing our drilling budget on development oriented activities in
our
shale areas in the short run, we can maintain high drilling success rates
yielding attractive rates of return. We anticipate committing a small portion
of
our drilling budget to locations outside of our shale project areas to
continually evaluate and test new areas for exploration and development
potential.
Employ
leading edge technologies to grow reserves and production and enhance
returns
.
We
employ several leading edge technologies in the drilling, completion and
development of our natural gas reserves. For example, our employees have
developed and implemented a low pressure natural gas production system to
increase the estimated recoverable reserves and improve production rates of
shale-sourced natural gas. We have installed several low pressure, small modular
style compression facilities in our Antrim shale play. We believe this system
has reduced development costs, increased production rates, extended the
commercial life of existing wells and increased the total amount of reserves
ultimately recoverable from each well bore when compared to the high pressure,
large compression facilities that are typically used in the Antrim shale play.
We believe this innovative system gives us a competitive advantage compared
to
other operators in the area.
Manage
costs by maximizing operational control
.
We seek
to exert control over our exploration, exploitation and development activities.
As the operator of our projects, we have greater control over the amount and
timing of the expenditures associated with those activities. As we manage our
growth, we are focused on reducing lease operating expenses, general and
administrative costs and finding and development costs on a per mcfe basis.
As
of June 30, 2007, we operated 39% of our completed wells.
Pursue
complementary leasehold interest and property
acquisitions
.
We
intend to use our experience and regional expertise to supplement our drilling
strategy with complementary leasehold interest and property
acquisitions.
Our
Strengths
We
believe that our strengths will help us successfully execute our strategy.
These
strengths include:
Inventory
of growth opportunities
.
We have
established an asset base of approximately 612,577 net leasehold acres in our
shale areas, of which approximately 92% were undeveloped as of June 30, 2007.
As
of that date, we had approximately 2,500 net potential drilling locations on
this acreage. At our current planned drilling rate, this would accommodate
approximately fifteen plus years of drilling activity.
Experienced
management and technical teams
.
Our
four senior executive officers average 26 years of experience in the natural
gas
industry. In addition, we employ one staff geologist, one senior oil and gas
petroleum engineer, and three senior land professionals with an average over
22
years of oil and gas experience.
Operational
control
.
As of
June 30, 2007, we operated approximately 39% of the wells in which we have
an
interest, and we expect our 66% average working interest in leases to allow
us
to increase the number of wells we will operate in the future. This will afford
us a significant degree of control over costs and other operational
matters.
Our
Challenges
Investing
in our common stock involves risks. You should read carefully the section of
this prospectus entitled “Risk Factors” beginning on page 11 and “Cautionary
Note Regarding Forward-Looking Statements” on page 21 for an explanation of
these risks before investing in our common stock. In particular, the following
considerations may offset our competitive strengths or have a negative effect
on
our strategy as well as activities on our properties, which could cause a
decrease in the price of our common stock and a loss of all or part of your
investment.
Price
volatility
.
Market
prices for natural gas may fluctuate widely for reasons that are outside of
our
control.
Risks
relating to the development of natural gas reserves
.
Our
natural gas reserves and future production and, therefore, our future cash
flow
and income are highly dependent on our ability to successfully execute our
drilling program, which will require substantially greater amounts of capital
than we currently have available to us.
Risks
relating to natural gas reserve estimates
.
Reserve
estimates are based on many assumptions and our properties may not produce
the
reserves we originally forecast. Our reserves will decline unless we are
successful in finding or acquiring new reserves.
Access
to equipment and personnel
.
Shortages of drilling rigs, equipment, supplies or personnel could delay,
restrict or increase the cost of our exploration, exploitation and development
operations, which in turn could impair our financial condition and results
of
operations.
Operating
Areas
Antrim
Shale
.
Our
Antrim shale properties are located in Michigan and represent our primary area
of development over the near term. Nearly all of our development operations
in
this play/trend are focused on unconventional shale plays. Shale development
typically results in higher drilling success and lower drilling costs when
compared to conventional exploration and development activity.
Antrim
shale underlies the entire Michigan basin. The shale is very thick (140 to
over
200 feet) and has a high percentage of organic content (up to 20%). Due to
the
makeup of the natural fractures in the Antrim shale, production will vary from
well to well.
The
productive, fractured trend for the Antrim shale runs across the northern
portion of the Michigan basin from Lake Huron to Lake Michigan (160 miles).
Gas
wells have been drilled and produced in the Antrim shale from depths of 250
feet
down to 1,500 feet below the surface. A high percentage of the wells drilled
in
the Antrim shale have been put into production and levels of production vary
from well to well. Over 9,000 wells are currently producing in the Antrim shale.
In recent years, 200 to 400 wells have been drilled annually by all operators
in
the Antrim shale.
The
gas
produced from the Antrim shale is primarily a biogenic gas due to the presence
of microbes in the low to medium saline waters. The low-density pay zones in
the
Antrim shale are over 100 feet thick. Methane gas is continuously being
generated by anaerobic bacteria that feed on C02 organic material, and the
heavier oil and gases stored in the shale.
The
Antrim shale gas adsorbs to organic material in a manner similar to gas in
coal
seams. Water in the natural fractures of the shale provides a trapping mechanism
to hold the gas in place. As the water is produced, lowering the fluid and
pressure in the reservoir, gases are released from the organic material and
are
produced to the surface. At depths of less than 1,500 feet, the gas-in-place
is
typically 90% methane or greater, with the balance being C02 and some heavier
gases.
The
oldest Antrim shale gas field was drilled in the 1940s, and it is still in
production today. The production curve for the shale typically contains a peak
rate of gas occurring after the first two years of production when the shale
reservoir has been thoroughly dewatered. Peak rate production usually continues
for some time. After the water is taken from the formation and the gas is able
to fully release from the shale into the well bore, the rate of production
will
typically begin to decline 2% to 7% per year.
We
have
identified the Michigan Antrim shale as an area with natural fractures using
a
variety of diagnostic tests, including a review of production trends, fracture
imaging logs and geological mapping. In management's opinion, based upon
performance information from over 9,000 wells with comparable geologic
characteristics, areas with natural fractures in shale have compelling
production potential.
At
June
30, 2007, we owned working interests in 528 (270 net) Antrim wells. For the
six
months ended June 30, 2007, we drilled or participated in 29 (13 net) wells
with
a 92% success rate. In 2006, we drilled 173 (98 net) Antrim wells and
successfully completed 164 gross wells for a success rate of 95%. On average,
our Antrim wells are drilled to depths ranging from 250 to 1,500 feet targeting
reserves of 0.513 bcfe per well based upon our December 31, 2006, Schlumberger
reserve report.
New
Albany shale
.
Our New
Albany shale properties are located in Southern Indiana and Western Kentucky
and
represent a relatively new area of activity for us. Most of our exploratory
and
developmental operations in the Illinois geological basin are focused on
unconventional shale plays. The New Albany shale play, much of which is located
in Indiana, is an emerging play with similar characteristics to the Antrim
shale
play. It is also very thick (100 to over 200 feet) and covers approximately
6,000,000 gross acres, with proven producing pay zones throughout. The shale
is
capped by the Borden shale, a very thick, dense, gray-green shale.
In
the
New Albany shale, a well commonly produces water along with the gas. In the
early 1900's, it was learned that a simple open-hole completion in the very
top
of the shale would yield commercial gas wells that would last for many years,
even while producing some water. Vertical fractures in the shale feed the gas
flow at the top of the shale. The potential of these wells was seldom realized
in the early to mid-twentieth century, as the production systems for handling
the associated water were limited. However, with current technology, the water
can be dealt with cost effectively and allow for better rates of gas
production.
Significant
research and study has been conducted to evaluate the producibility of the
New
Albany shale. In cooperation with the Gas Research Institute, we combined
resources and data with 11 other industry partners in a shale gas producibility
consortium lasting almost two years (concluded in 1999). The consortium
identified critical differences and similarities of the New Albany shale play
to
other shale plays. The consortium study observed that the New Albany shale
reservoir contained high-angled (vertical or nearly so) natural fractures that
are open to unimpeded flow. The predominant fracture system is oriented
east-west with spacing between joints estimated to average five feet based
on
outcrop studies and production simulations. Based on this information, it was
concluded that increases in performance could be achieved with a horizontally
drilled well compared to a vertically drilled well in the same reservoir.
Reserve
studies were conducted on behalf of the consortium by Schlumberger Holditch
& Associates for both vertical producing wells and horizontal wells. Since
then, we have participated in approximately 30 pilot horizontal well drilling
projects across multiple counties which support the conclusions of the
consortium. With the data from these pilot wells, we have established a
development concept for the New Albany shale, which we began to implement in
2006.
Our
New
Albany shale projects are characterized by declining natural gas and water
production with peak natural gas and water flow rates occurring in the first
60
days. Our New Albany shale wells are drilled to depths ranging from 500 to
3,000
feet and based on our December 31, 2006, Schlumberger reserve report could
yield
an average reserve of 1.2 bcfe per well. At June 30, 2007, we owned working
interests in 50 (11.61 net) New Albany shale wells. For the six months ended
June 30, 2007, we drilled or participated in 16 (4.05 net) wells with a 100%
success rate. In 2006, we drilled 26 (7.49 net) New Albany shale wells and
successfully completed 25 of these wells for a success rate of 96%.
Recent
Developments
Refinancing
.
On
August 20, 2007, we entered into a second lien term loan agreement (the “Term
Loan”) with BNP Paribas (“BNP”), as the arranger and administrative agent, and
several other lenders forming a syndication. The initial term loan is $50
million for a 5-year term 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 pay off the Company’s existing mezzanine financing with Trust Company of
the West (‘”TCW”) and for general corporate purposes.
In
connection with the Term Loan, we also agreed to the amendment and restatement
of its senior secured credit facility with BNP and other lenders, 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.
In
both
the Term Loan and senior secured credit facility, we 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. In addition, we were required to purchase
financial hedges at prices and aggregate notional volumes satisfactory to BNP,
as administrative agent. This requirement has been satisfied.
Upon
execution of the Term Loan, we also entered into a 3-year interest rate swap
transaction with BNP to hedge its exposure to the floating interest rate on
the
Term Loan debt. This hedge transaction on $50 million will yield an effective
interest rate of 11.86% for the period from August 23, 2007 through August
23,
2010.
Effective
August 20, 2007, our 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. TCW had limited the borrowing base and the agreement contained
a
commitment expiration date of August 12, 2007. Under the termination provisions,
we were 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) $0.35 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.
Woodford
Shale Play
.
We have
established an acreage position of over 30,000 net acres in the Woodford Shale
natural gas play of Oklahoma. In early 2006, in conjunction with a private
operator based in Oklahoma, we had identified a Woodford Shale target area.
Together, the companies initiated the requisite administrative and leasing
efforts required to assemble an acreage block of sufficient scale to offer
competitive advantages and support exploration activities. The identified target
area is focused in central Oklahoma, which is experiencing a significant
increase in leasing and drilling activity. It is positioned among geological
provinces with active Woodford Shale development, with average depths over
5,000
feet and organic shale thickness up to 300 feet.
We
have
expended approximately $6.5 million for an 89% working interest in over 35,000
gross acres in the play. The early leasing activities have allowed us to
establish this competitive position in the targeted play area. Leasing
activities are continuing. We have targeted 2008 for a pilot program of 5 test
wells in its project area. Since our current capital expenditure budget has
been
dedicated to further development of the Antrim and New Albany Shales, we have
been in discussions with potential financing and joint venture partners to
facilitate aggressive development of this acreage. No financing for this
development has been procured as of the date of this prospectus.
Strategic
Alternatives
.
On
September 19, 2007, we announced that we have retained Johnson Rice &
Company, L.L.C. to assist the Board of Directors with investigating strategic
alternatives for us. These alternatives, among other things, may include
revisions to our strategic plan, asset divestitures, operating partnerships,
identifying additional capital sources, or a sale, merger, or other business
combination. We intend to disclose developments regarding the exploration of
alternatives only if and when the Board of Directors has approved a specific
course of action. There is no assurance that this process will result in any
changes to our current strategic direction. There is no specific timeframe
to
complete the review and there are no constraints on options to be explored.
Johnson Rice & Company will assist our Board of Directors in reviewing the
strategic alternatives, while management continues to focus on executing
Aurora’s current strategic plan.
Our
Offices
Our
principal executive offices are located at 4110 Copper Ridge Drive,
Suite 100, Traverse City, Michigan 49684, and our telephone number is
231-941-0073. Our website is
www.auroraogc.com
.
Information contained on our website does not constitute a part of this
prospectus.
The
Offering
Common
stock offered by us
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|
8,900,000 shares
|
|
|
|
Use
of proceeds
|
|
We
will not receive any of the proceeds from the sale of the shares
by the
selling security holders. We may receive proceeds in connection with
the
exercise of warrants, the underlying shares of which may be sold
by the
selling security holders under this Prospectus. See “Use of Proceeds.”
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Dividend
policy
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|
We
currently anticipate that we will retain all future earnings, if
any, to
finance the growth and development of our business. We do not intend
to
pay cash dividends in the foreseeable future.
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AMEX
market symbol
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“AOG”
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Risk
factors
|
|
Investing
in our common stock involves certain risks. You should carefully
consider
the risk factors discussed under the heading “Risk Factors” beginning on
page 11 of this prospectus and other information contained in this
prospectus before deciding to invest in our common stock.
|
Except
as
otherwise indicated, all information contained in this prospectus:
|
·
|
excludes
5,257,500 shares of common stock reserved for issuance under our 2006
Stock Incentive Plan;
|
|
·
|
excludes
4,794,444 shares of our common stock issuable upon exercise of
outstanding options at a weighted average exercise price of $2.30 per
share; and
|
|
·
|
excludes
1,952,000 shares of our common stock issuable upon exercise of
outstanding warrants at a weighted average exercise price of
$1.74 per share.
|
Summary
Financial Data
The
following table shows our summary financial data as of and for each of the
periods indicated. The data as of and for the years ended December 31,
2006, and 2005, is derived from our historical audited consolidated financial
statements for the periods indicated. The data as of and for the six months
ended June 30, 2007, and 2006, is derived from our historical unaudited
condensed consolidated financial statements for the interim periods indicated.
The interim unaudited information was prepared on a basis consistent with that
used in preparing our audited consolidated financial statements and includes
all
adjustments, consisting of normal and recurring items, that we consider
necessary for a fair presentation of the financial position, results of
operations and cash flows for the unaudited periods. You should review this
information together with “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” and our consolidated historical financial
statements and related notes included elsewhere in this prospectus.
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Six
Months Ended June 30,
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Year
Ended December 31,(a)
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2007
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2006
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2006
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2005
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Statement
of operations data
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Revenues
|
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|
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Oil
and natural gas sales
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$
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12,532,005
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$
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10,941,220
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$
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21,591,811
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$
|
6,743,444
|
|
Pipeline
transportation and marketing
|
|
|
286,932
|
|
|
242,299
|
|
|
1,179,431
|
|
|
-
|
|
Field
service and sales
|
|
|
249,602
|
|
|
-
|
|
|
125,611
|
|
|
-
|
|
Interest
and other income
|
|
|
474,758
|
|
|
181,631
|
|
|
220,592
|
|
|
666,850
|
|
Total
revenue
|
|
|
13,543,297
|
|
|
11,365,150
|
|
|
23,117,445
|
|
|
7,410,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
566,969
|
|
|
445,825
|
|
|
877,319
|
|
|
506,635
|
|
Production
and lease operating expense
|
|
|
4,126,700
|
|
|
2,853,374
|
|
|
6,278,131
|
|
|
1,587,205
|
|
Pipeline
operating expense
|
|
|
177,802
|
|
|
137,484
|
|
|
643,963
|
|
|
-
|
|
Field
service expense
|
|
|
200,096
|
|
|
-
|
|
|
90,913
|
|
|
-
|
|
General
and administrative expense
|
|
|
4,233,701
|
|
|
3,242,713
|
|
|
7,531,718
|
|
|
3,435,507
|
|
Oil
and natural gas depletion and amortization
|
|
|
1,523,460
|
|
|
2,010,383
|
|
|
2,681,290
|
|
|
767,511
|
|
Other
assets depreciation and amortization
|
|
|
1,142,104
|
|
|
1,013,783
|
|
|
2,083,191
|
|
|
308,647
|
|
Interest
expense
|
|
|
2,050,403
|
|
|
3,564,154
|
|
|
4,573,785
|
|
|
1,307,370
|
|
Taxes
(refunds), other
|
|
|
(53
|
)
|
|
29,361
|
|
|
250,884
|
|
|
29,651
|
|
Total
expenses
|
|
|
14,021,182
|
|
|
13,297,077
|
|
|
25,011,194
|
|
|
7,942,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
before minority interest
|
|
|
(477,885
|
)
|
|
(1,931,927
|
)
|
|
(1,893,749
|
)
|
|
(532,232
|
)
|
Minority
interest in (income) loss of subsidiaries
|
|
|
(32,957
|
)
|
|
(17,919
|
)
|
|
(50,898
|
)
|
|
15,960
|
|
Net
loss
|
|
$
|
(510,842
|
)
|
$
|
(1,949,846
|
)
|
$
|
(1,944,647
|
)
|
$
|
(516,272
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss per common share — basic and diluted
|
|
$
|
(0.01
|
)
|
$
|
(0.03
|
)
|
$
|
(0.02
|
)
|
$
|
(0.01
|
)
|
Weighted
average common shares outstanding — basic and
diluted
|
|
|
101,602,875
|
|
|
70,265,281
|
|
|
82,288,243
|
|
|
40,622,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
provided (used) by operating activities
|
|
$
|
5,411,775
|
|
$
|
3,607,502
|
|
$
|
2,244,535
|
|
$
|
(2,392,118
|
)
|
Cash
used by investing activities
|
|
|
(32,016,909
|
)
|
|
(61,497,361
|
)
|
|
(86,317,737
|
)
|
|
(39,881,947
|
)
|
Cash
provided by financing activities
|
|
|
25,590,236
|
|
|
49,504,174
|
|
|
73,827,960
|
|
|
49,075,121
|
|
|
|
As
of June 30,
|
|
As
of December 31,(a)
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Balance
sheet data
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
720,498
|
|
$
|
1,735,396
|
|
$
|
11,980,638
|
|
Other
current assets
|
|
|
9,006,600
|
|
|
12,728,588
|
|
|
7,274,869
|
|
Oil
and gas properties, net (using full cost accounting)
|
|
|
184,249,398
|
|
|
161,294,155
|
|
|
68,960,754
|
|
Other
property and equipment, net
|
|
|
9,306,214
|
|
|
9,221,228
|
|
|
3,610,138
|
|
Other
assets
|
|
|
25,116,848
|
|
|
27,407,825
|
|
|
24,995,746
|
|
Total
assets
|
|
$
|
228,399,558
|
|
$
|
212,387,192
|
|
$
|
116,822,145
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
11,207,070
|
|
$
|
18,117,955
|
|
$
|
17,341,431
|
|
Long-term
debt, net of current maturities
|
|
|
79,187,004
|
|
|
54,538,138
|
|
|
42,794,862
|
|
Redeemable
convertible preferred stock
|
|
|
-
|
|
|
-
|
|
|
59,925
|
|
Shareholders’
equity
|
|
|
138,005,484
|
|
|
139,731,099
|
|
|
56,625,927
|
|
Total
liabilities and shareholders’ equity
|
|
$
|
228,399,558
|
|
$
|
212,387,192
|
|
$
|
116,822,145
|
|
(a)
|
We
acquired Aurora Energy, Ltd. (“Aurora”) on October 31, 2005 through
the merger of our wholly-owned subsidiary with and into Aurora. The
acquisition of Aurora was accounted for as a reverse merger, with
Aurora
being the acquiring party for accounting purposes. As a result of
the
reverse merger, the historical financial statements presented for
periods
prior to the acquisition date are the financial statements of Aurora.
The
operations of the former Cadence Resources Corporation (now known
as
Aurora Oil & Gas Corporation) businesses have been included in
the financial statements from the date of acquisition. The common
stock
per share information in the consolidated financial statements for
the
year ended December 31, 2005, and related notes have been
retroactively adjusted to give effect to the reverse merger on
October 31, 2005.
|
Summary
Operating and Reserve Data
The
following table summarizes our operating and reserve data as of and for each
of
the periods indicated:
|
|
Six
Months
Ended
June 30,
|
|
Year
Ended December 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Production
|
|
|
|
|
|
|
|
Oil
(bbls)
|
|
|
13,772
|
|
|
22,588
|
|
|
10,628
|
|
Natural
gas (mcf)
|
|
|
1,410,820
|
|
|
2,517,897
|
|
|
687,271
|
|
Natural
gas equivalent (mcfe)
|
|
|
1,493,453
|
|
|
2,653,427
|
|
|
751,039
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$
|
784,991
|
|
$
|
1,399,445
|
|
$
|
558,455
|
|
Natural
gas sales
|
|
|
11,747,014
|
|
|
20,192,366
|
|
|
6,184,989
|
|
Total
|
|
$
|
12,532,005
|
|
$
|
21,591,811
|
|
$
|
6,743,444
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price (including realized gains or losses from
hedging)
|
|
|
|
|
|
|
|
|
|
|
Oil
($ per bbl)
|
|
$
|
57.00
|
|
$
|
61.95
|
|
$
|
52.54
|
|
Natural
gas ($ per mcf)
|
|
|
8.33
|
|
|
8.02
|
|
|
9.00
|
|
Natural
gas equivalent ($ per mcfe)
|
|
|
8.39
|
|
|
8.14
|
|
|
8.98
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
production cost ($ per mcfe)
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
$
|
0.38
|
|
$
|
0.33
|
|
$
|
0.67
|
|
Post-production
expenses
|
|
|
0.54
|
|
|
0.55
|
|
|
0.50
|
|
Leasing
operating expenses
|
|
|
2.23
|
|
|
1.82
|
|
|
1.62
|
|
Total
|
|
$
|
3.15
|
|
$
|
2.70
|
|
$
|
2.79
|
|
|
|
As
of December 31,
|
|
|
|
2006
|
|
2005
|
|
Estimated
proved reserves(a)
|
|
|
|
|
|
Oil
(mbbls)
|
|
|
81
|
|
|
99
|
|
Natural
gas (mmcf)
|
|
|
152,964
|
|
|
63,321
|
|
Natural
gas equivalent (mmcfe)
|
|
|
153,450
|
|
|
63,915
|
|
PV-10(b)
|
|
$
|
158,782,810
|
|
$
|
199,507,440
|
|
Standardized
measure(c)
|
|
$
|
130,461,821
|
|
$
|
152,868,240
|
|
(a)
|
Proved
reserves are those quantities of gas which, by analysis of geological
and
engineering data, can be estimated with reasonable certainty to be
commercially recoverable from known reservoirs and under current
economic
conditions, operating methods, and government
regulations.
|
(b)
|
Represents
the present value, discounted at 10% per annum (PV-10), of estimated
future net revenue before income tax of our estimated proven reserves.
The
estimated future net revenues set forth above were determined by
using
reserve quantities of proved reserves and the periods in which they
are
expected to be developed and produced based on economic conditions
prevailing at December 31, 2006, and 2005, respectively. The
estimated future production is priced at December 30, 2006, without
escalation, using $57.81 per bbl and $5.84 per mmbtu. The
estimated future production is priced at December 31, 2005, without
escalation, using $55.75 to $57.92 per bbl and $9.89 per mmbtu.
PV-10 is a non-GAAP financial measure because it excludes income
tax
effects. Management believes that the presentation of the non-GAAP
financial measure of PV-10 provides useful information to investors
because it is widely used by professional analysts and sophisticated
investors in evaluating oil and natural gas companies. PV-10 is not
a
measure of financial or operating performance under GAAP. PV-10 should
not
be considered as an alternative to the standardized measure as defined
under GAAP. We have included a reconciliation of PV-10 to the most
directly comparable GAAP measure — standardized measure of discounted
future net cash flows — in the following
table:
|
|
|
As
of December 31,
|
|
|
|
2006
|
|
2005
|
|
Standardized
measure of discounted future net cash flows
|
|
$
|
130,461,821
|
|
$
|
152,868,240
|
|
Add:
Present value of future income tax discounted at 10%
|
|
|
28,320,989
|
|
|
46,639,204
|
|
PV-10
|
|
$
|
158,782,810
|
|
$
|
199,507,444
|
|
(c)
|
The
standardized measure represents the present value of estimated future
cash
inflows from proved oil and natural gas reserves, less future development,
abandonment, production and income tax expenses, discounted at
10% per annum to reflect timing of future cash flows and using the
same pricing assumptions as were used to calculate PV-10. Standardized
measure differs from PV-10 because standardized measure includes
the
effect of future income taxes.
|
RISK
FACTORS
An
investment in our common stock involves a high degree of risk. You
should
carefully
consider the following risks and all of the other information contained
in
this
prospectus before deciding to invest in our common stock. The risks
described
below
are not the only ones facing our company. Additional risks not presently
known
to
us
or which we currently consider immaterial also may adversely affect
our
company.
RISKS
RELATED TO OUR BUSINESS
Natural
gas prices are volatile. A substantial decrease in natural gas prices
would
significantly
affect our business and impede our growth.
Our
revenues, profitability and future growth depend upon prevailing natural gas
prices. Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow and raise additional capital. Lower
prices may also reduce the amount of natural gas that we can economically
produce. It is possible that prices will be low at the time periods in which
the
wells are most productive, thereby reducing overall returns. It is possible
that
prices will drop so low that production will become uneconomical. Ongoing
production costs that will continue include equipment maintenance, compression
and pumping costs. If production becomes uneconomical, we may decide to
discontinue production until prices improve.
Prices
for natural gas fluctuate widely. For example, from January 1, 2006, through
June 30, 2007, natural gas prices quoted for the near month NYMEX contract
have
ranged from a low of $6.03 per mmbtu to a high of $8.23 per mmbtu. The prices
for natural gas are subject to a variety of factors beyond our control,
including:
|
·
|
the
level of consumer product demand;
|
|
·
|
domestic
and foreign governmental regulations;
|
|
·
|
the
price and availability of alternative fuels;
|
|
·
|
political
conditions in oil and natural gas producing
regions;
|
|
·
|
the
domestic and foreign supply of oil and natural gas;
|
|
·
|
speculative
trading and other market uncertainty; and
|
|
·
|
worldwide
economic conditions.
|
The
failure to develop reserves could adversely affect our production and cash
flows.
Our
success depends upon our ability to find, develop or acquire natural gas
reserves that are economically recoverable. We will need to conduct successful
exploration or development activities or acquire properties containing proved
reserves, or both. The business of exploring for, developing or acquiring
reserves is capital intensive. We may not be able to make the necessary capital
investment to expand our natural gas reserves from cash flows, and external
sources of capital may be limited or unavailable. Our drilling activities may
not result in significant reserves, and we may not have continuing success
drilling productive wells. Exploratory drilling involves more risk than
development drilling because exploratory drilling is designed to test formations
in which proved reserves have not been discovered. Additionally, while our
revenues may increase if prevailing gas prices increase significantly, our
finding costs for reserves also could increase, and we may not be able to
finance additional exploration or development activities.
We
may have difficulty financing our planned growth.
We
have
incurred and expect to continue to incur substantial capital expenditures and
working capital needs, particularly as a result of our property acquisition
and
development drilling activities. We will require substantial additional
financing to fund our planned growth. Additional financing may not be available
to us on acceptable terms or at all. If additional capital resources are
unavailable, we may be forced to curtail our acquisition, development drilling
and other activities or to sell some of our assets on an untimely or unfavorable
basis. We are in the process of evaluating strategic alternatives as of the
date
of this prospectus.
Most
of our current development activity and producing properties are located
in
Michigan
and Indiana, making us vulnerable to risks associated with operating in
this
region.
Our
current development activity is concentrated in Michigan and Indiana, and our
currently producing properties are located primarily in a six-county area in
Michigan. As a result, we may be disproportionately exposed to the impact of
drilling and other delays or disruptions of production from these regions caused
by weather conditions, governmental regulation, lack of field infrastructure,
or
other events which impact these areas. In addition, a majority of our leaseholds
held for development is located in the more untested New Albany shale
play/trend.
Our
potential drilling locations comprise an estimation of part of our
future
drilling
plans over several years, making them susceptible to uncertainties
that
could
materially alter the occurrence or timing of their
drilling.
As
of
June 30, 2007, we had approximately 3,700 net potential drilling locations
to be included in our future multi-year drilling activities on our existing
acreage. These drilling locations represent a significant part of our growth
strategy. Our ability to drill and develop these locations depends on a number
of uncertainties, including the availability of capital, construction of
infrastructure, seasonal conditions, regulatory approvals, natural gas prices,
costs and drilling results. Because of these uncertainties, we do not know
if
our numerous potential drilling locations will ever be drilled or if we will
be
able to produce natural gas from these or any other potential drilling
locations, which could materially affect our business.
We
may continue to incur losses.
We
reported a net loss for the years ended December 31, 2006, and 2005, and
the six months ended June 30, 2007. We expect to report a net loss in the third
quarter of 2007 and also expect to show a net reduction in working capital
and
shareholder equity in the third quarter of 2007. There is no assurance that
we
will be able to achieve and maintain profitability.
We
do not operate a substantial amount of our
properties.
We
conduct much of our oil and natural gas exploration, development and production
activities in joint ventures with others. In some cases, we act as operator
and
retain significant management control. In other cases, we have reserved only
an
overriding royalty interest and have surrendered all management rights. In
still
other cases, we have reserved the right to participate in management decisions,
but do not have ultimate decision-making authority. As of June 30, 2007, we
operated 39% of our wells. As a result of these varying levels of management
control, for those properties that we do not operate, we have no control
over:
|
·
|
the
number of wells to be drilled;
|
|
·
|
the
location of wells to be drilled;
|
|
·
|
the
timing of drilling and re-completing of wells;
|
|
·
|
the
field company hired to drill and maintain the wells;
|
|
·
|
the
timing and amounts of production;
|
|
·
|
the
approval of other participants in drilling wells;
|
|
·
|
development
and operating costs;
|
|
·
|
capital
calls on working interest owners; and
|
These
and
other aspects of the operation of our properties and the success of our drilling
and development activities will in many cases be dependent on the expertise
and
financial resources of our joint venture partners and third-party
operators.
We
may be unable to make acquisitions of producing properties or prospects
or
successfully
integrate them into our operations.
Acquisitions
of producing properties and undeveloped oil and natural gas leases have been
an
essential part of our long-term growth strategy. As of June 30, 2007, we had
acquired approximately 1,312,331 (718,699 net) acres with 153,450 mmcfe in
net
proved reserves. We may not be able to identify suitable acquisitions in the
future or to finance these acquisitions on favorable terms or at all. In
addition, we compete against other companies for acquisitions, many of whom
have
substantially greater managerial and financial resources than we have. The
successful acquisition of producing properties and undeveloped natural gas
leases requires an assessment of the properties’ potential natural gas reserves,
future natural gas prices, development costs, operating costs, potential
environmental and other liabilities and other factors beyond our control. These
assessments are necessarily inexact and their accuracy inherently uncertain.
Such a review may not reveal all existing or potential problems, nor will it
necessarily permit us to become sufficiently familiar with the properties to
fully assess their merits and deficiencies. Significant acquisitions can change
the nature of our operations and business depending upon the character of the
acquired properties, which may be substantially different in operating and
geological characteristics or geographic location than existing properties.
Our
acquisitions may not be integrated successfully into our operations and may
not
achieve desired profitability objectives. For example, in 2006 we closed on
the
acquisition of all of the assets of Bach Enterprises, Inc. (or "Bach") and
certain of its affiliates. Bach is an oil and natural gas services company
whose
services include building compressors, CO2 removal, pipelining and facility
construction. Although the Bach acquisition will be operated separately from
our
current production operations, we have no prior experience in the management
of
such a service company, and may encounter issues that prevent us from
successfully integrating it as part of our business.
We
may lose key management personnel.
Our
current management team has substantial experience in the oil and natural gas
business. We only have an employment agreement with one member of our management
team. The loss of any of these individuals could adversely affect our business.
If one or more members of our management team dies, becomes disabled or
voluntarily terminates employment with us, there is no assurance that a suitable
or comparable replacement will be found.
Much
of our proved reserves are not yet generating production
revenues.
Of
our
proved natural gas reserves as of December 31, 2006, approximately 54% are
classified as proved developed producing, 15% are classified as proved developed
non-producing, and 31% are classified as proved undeveloped.
You
should be aware that our ability to convert proved reserves into revenues is
subject to certain limitations, including the following:
|
|
Reserves
characterized as proved developed producing reserves may be producing
predominantly water and generate little or no production
revenue;
|
|
|
Production
revenues from estimated proved developed non-producing reserves will
not
be realized until some time in the future, after we have installed
supporting infrastructure or taken other necessary steps. It will
be
necessary to incur additional capital expenditures to install this
required infrastructure;
|
|
|
Production
revenues from estimated proved undeveloped reserves will not be realized
until after such time, if ever, as we make significant capital
expenditures with respect to the development of such reserves, including
expenditures to fund the cost of drilling wells, dewatering the wells,
and
building the supporting
infrastructure; and
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The
reserve data assumes that we will make significant capital expenditures
to
develop our reserves. Although we have prepared estimates of the
costs
associated with developing these reserves in accordance with industry
standards, no assurance can be given that our estimates of capital
expenditures will prove accurate, that our financing sources will
be
sufficient to fully fund our planned development activities, or that
development activities will be either successful or in accordance
with our
schedule. We cannot control the performance of our joint venture
partners
on whom we depend for development of a substantial number of properties
in
which we have an economic interest and which are included in our
reserves.
Further, any significant decrease in oil and natural gas prices or
any
significant increase in the cost of development could result in a
significant reduction in the number of wells drilled. No assurance
can be
given that any wells will yield commercially viable
quantities.
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The
oil and natural gas reserve data included in this document are estimates based
on
assumptions
that may be inaccurate and existing economic and operating
conditions
that
may differ from future economic and operating
conditions.
Reservoir
engineering is a subjective and inexact process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact manner
and is based upon assumptions that may change from year to year and vary
considerably from actual results. Accordingly, reserve estimates may be subject
to downward or upward adjustment. Actual production, revenue and expenditures
with respect to our reserves will likely vary from estimates, and such variances
may be material. Information regarding discounted future net cash flows should
not be considered as the current market value of the estimated oil and natural
gas reserves that will be attributable to our properties. Examples of items
that
may cause our estimates to be inaccurate include, but are not limited to, the
following:
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The
estimated discounted future net cash flows from proved reserves are
based
on prices and costs as of the date of the estimate, while actual
future
prices and costs may be materially higher or
lower;
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Because
we have limited operating cost data to draw upon, the estimated operating
costs used to calculate our reserve values may be
inaccurate;
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Actual
future net cash flows also will be affected by factors such as the
amount
and timing of actual production, supply and demand for oil and natural
gas, increases or decreases in consumption, and changes in governmental
regulations or taxation;
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The
reserve report for our Michigan Antrim properties assumes that production
will be generated from each well for a period of 50 years. Because
production is expected for such an extended period of time, the
probability is enhanced that conditions at the time of production
will
vary materially from the current conditions used to calculate future
net
cash flows; and
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The
10% discount factor, which is required by the Financial Accounting
Standards Board in Statement of Financial Accounting Standards No. 69
to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor
based on
interest rates in effect from time to time and risks that will be
associated with our operations or the oil and natural gas industry
in
general.
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Our
drilling activities may be unsuccessful.
We
cannot
predict prior to drilling and testing a well whether the well will be productive
or whether we will recover all or any portion of our investment in the well.
Our
drilling for natural gas may involve unprofitable efforts, not only from dry
holes but from wells that are productive but do not produce sufficient
quantities to cover drilling and completion costs and are not economically
viable. Our efforts to identify commercially productive reservoirs, such as
studying seismic data, the geology of the area and production history of
adjoining fields, do not conclusively establish that natural gas is present
in
commercial quantities. If our drilling efforts are unsuccessful, our
profitability will be adversely affected. For the 18-month period ending June
30, 2007, approximately 7.7% of the gross wells we drilled were
unsuccessful.
Production
levels cannot be predicted with certainty.
Until
a
well is drilled and has been in production for a number of months, we will
not
know what volume of production we can expect to achieve from the well. Even
after a well has achieved its full production capacity, we cannot be certain
how
long the well will continue to produce or the production decline that will
occur
over the life of the well. Estimates as to production volumes and production
life are based on studies of similar wells (of which there are relatively few
in
the New Albany play) and, therefore, are speculative and not fully reliable.
As
a result, our revenue budgets for producing wells may prove to be
inaccurate.
Drilling
and production delays may occur.
In
order
to generate revenues from the sale of oil and natural gas production from new
wells, we must complete significant development activity. Delay in receiving
governmental permits, adverse weather, a shortage of labor or parts, and/or
dewatering time frames may cause delays, as discussed below. These delays will
result in delays in achieving revenues from these new wells.
Oil
and
natural gas producers often compete for experienced and competent drilling,
completion and facilities installation vendors and production laborers. The
unavailability of experienced and competent vendors and laborers may cause
development and production delays.
From
time
to time, vendors of equipment needed for oil and natural gas drilling and
production become backlogged, forcing delays in development until suitable
equipment can be obtained.
For
each
new well, before drilling can commence, we will have to obtain a drilling
permit
from the state in which the well is located. We will also have to obtain
a
permit for each salt water disposal well. It is possible that for reasons
outside of our control, the issuance of the required permits will be delayed,
thereby delaying the time at which production is achieved. We have previously
experienced a delay in receiving permits from the State of Michigan, Department
of Environmental Quality ("DEQ"), for drilling horizontal wells, while the
DEQ
further reviews this drilling methodology. As a result of these delays, we
have
had to defer the drilling of certain wells in the Antrim shale until the
review
by the DEQ was completed and permits were issued. The DEQ has also forced
producers to discontinue operations in certain areas of the Michigan Antrim
so
that the DEQ can inspect the salt water disposal wells operated in those
areas.
We have no control over this type of regulatory delay.
The
DEQ
has also recently instituted a water sampling and monitoring requirement for
wells north of a line that includes three of our Antrim projects. The drilling
permits for these wells require produced water monitoring and reporting of
gas
and water volume and water quality. If the water produced by a well has levels
of dissolved solid concentration below specified levels, we may be required
to
shut-in the well. If the well cannot be remediated so that fresh water is no
longer produced, we may be required to plug the well.
Adverse
weather may foreclose any drilling or development activity, forcing delays
until
more favorable weather conditions develop. This is more likely to occur during
the winter and spring months, but can occur at other times of the
year.
Different
natural gas reservoirs contain different amounts of water. The actual amount
of
time required for dewatering with respect to each well cannot be predicted
with
accuracy. The period of time when the volume of gas that is produced is limited
by the dewatering process may be extended, thereby delaying revenue
production.
Pipeline
capacity may be inadequate.
Because
of the nature of natural gas development, there may be periods of time when
pipeline capacity is inadequate to meet our gas transportation needs. It is
often the case that as new development comes online, pipelines are close to
or
at capacity before new pipelines are built. During periods when pipeline
capacity is inadequate, we may be forced to reduce production or incur
additional expense as existing production requires additional compression to
enter existing pipelines.
Our
reliance on third parties for gathering and distribution could curtail
future
exploration
and production activities.
The
marketability of our production will depend on the proximity of our reserves
to,
and the capacity of, third party facilities and services, including oil and
natural gas gathering systems, pipelines, trucking or terminal facilities,
and
processing facilities. The unavailability or insufficient capacity of these
facilities and services could force us to shut-in producing wells, delay the
commencement of production, or discontinue development plans for some of our
properties, which would adversely affect our financial condition and
performance. During 2006, production was hampered by curtailments in a
third-party processing facility; we recently completed construction of our
own
processing facility and built an alternative pipeline route in response to
this
curtailment.
There
is a potential for increased costs.
The
oil
and natural gas industry has historically experienced periods of rapidly
increasing drilling and production costs, frequently during times of increased
drilling activities. If significant cost increases occur with respect to our
development activity, we may have to reduce the number of wells we drill, which
may adversely affect our financial performance.
We
may incur compression difficulties and expense.
As
production of natural gas increases, more compression is generally required
to
compress the production into the pipeline. As more compression is required,
production costs increase, primarily because more fuel is required in the
compression process. Furthermore, because compression is a mechanical process,
a
breakdown may occur that will cause us to be unable to deliver natural gas
until
repairs are made.
We
may not have good and marketable title to our
properties.
It
is
customary in the oil and natural gas industry that upon acquiring an interest
in
a non-producing property, only a preliminary title investigation is done at
that
time and that a drilling title opinion is done prior to the initiation of
drilling, neither of which can substitute for a complete title investigation.
We
have followed this custom to date and intend to continue to follow this custom
in the future. Furthermore, title insurance is not available for mineral leases,
and we will not obtain title insurance or other guaranty or warranty of good
title. If the title to our prospects should prove to be defective, we could
lose
the costs that we have incurred in their acquisition or incur substantial costs
for curative title work.
Competition
in our industry is intense, and we are smaller and have a more
limited
operating
history than most of our competitors.
We
compete with major and independent oil and natural gas companies for property
acquisitions and for the equipment and labor required to develop and operate
these properties. Most of our competitors have substantially greater financial
and other resources than we do. In addition, larger competitors may be able
to
absorb the burden of any changes in federal, state and local laws and
regulations more easily than we can, which would adversely affect our
competitive position. These competitors may be able to pay more for exploratory
prospects and productive oil and natural gas properties and may be able to
define, evaluate, bid for and purchase a greater number of properties and
prospects than we can. Our ability to explore for oil and natural gas prospects
and to acquire additional properties in the future will depend on our ability
to
conduct operations, to evaluate and select suitable properties and to complete
transactions in this highly competitive environment.
Oil
and natural gas operations involve various operating
risks.
The
oil
and natural gas business involves operating hazards such as well blowouts,
craterings, explosions, uncontrollable flows of crude oil, natural gas or well
fluids, fires, formations with abnormal pressures, pipeline ruptures or spills,
pollution, releases of toxic gas and other environmental hazards and risks.
Personal injuries, damage to property and equipment, reservoir damage, or loss
of reserves may occur if such a catastrophe occurs, any one of which could
cause
us to experience substantial losses. In addition, we may be liable for
environmental damage caused by previous owners of properties purchased or leased
by us.
Federal
and state regulation of oil and natural gas production and transportation,
tax
and energy policies, changes in supply and demand and general economic
conditions all could adversely affect our ability to produce and market our
natural gas and crude oil. Production from natural gas wells in many geographic
areas of the United States has been curtailed or shut-in for considerable
periods of time due to a lack of market demand, and such curtailments may
continue for a considerable period of time in the future. There may be an excess
supply of natural gas in areas where our operations will be conducted. If so,
it
is possible that there will be no market or a very limited market for our
production.
As
a
result of operating hazards, regulatory risks and other uninsured risks, we
could incur substantial liabilities to third parties or governmental entities,
the payment of which could reduce or eliminate funds available for exploration,
development or acquisitions.
We
may lack insurance that could lower risks to our
investors.
We
have
procured insurance policies for general liability, property/pollution, well
control and director and officer liability in amounts considered by management
to be adequate, as well as a $20 million excess liability umbrella policy.
Nonetheless, the policy limits may be inadequate in the case of a catastrophic
loss, and there are some risks that are not insurable. We have limited business
interruption insurance. An uninsured loss could adversely affect our financial
performance.
Our
credit facilities have operating restrictions and financial covenants that
limit
our
flexibility and may limit our borrowing capacity; needed increases in
borrowing
capacity
may not be available.
As
of
June 30, 2007, our outstanding debt includes a senior credit facility with
a
current approved borrowing base of $50 million, $35 million of which is
currently drawn, a mezzanine financing facility with a current approved
borrowing base of $50 million, of which $40 million is currently
drawn, and a $5 million revolving line of credit, of which $1.4 million is
currently drawn. Our mezzanine credit facility limits the amount of earnings
from production that are available to us with regard to the properties pledged
as collateral on the loan. All of our credit facilities, other than our office
mortgage loan, have operational restrictions and credit ratio compliance
requirements that limit our flexibility. If the ratio requirements are not
satisfied, curative action may be required, such as repaying a part of the
outstanding principal or pledging more assets as collateral, and we will be
unable to draw more funds to use in development.
The
value
of the assets pledged as collateral under our senior credit facility and
mezzanine financing facility will depend on the then current commodity prices
for natural gas. If prices drop significantly, we may have trouble satisfying
the ratio covenants of these credit facilities. As noted above, oil and natural
gas prices are volatile. The value of the stock pledged to support the guaranty
of our revolving line of credit is tied to the price at which our stock is
trading. We will be unable to control this variable.
In
order
to execute our current development plan we will need to increase our credit
availability as we add proved reserves. If we are unable to convert our assets
to proved reserves at our planned pace, or if the value of our proved reserves
drops as described above, we may be unable to increase our available credit
as
needed. Furthermore, any increases to our available credit will be entirely
within the discretion of our lenders and may not be available to us even if
we
are successful in increasing the value of our proved reserves.
If
we are
unable to make use of our credit facilities, it may be difficult to find
replacement sources of financing to use for working capital, capital
expenditures, drilling, technology purchases or other purposes. Even if
replacement financing is available, it may be on less advantageous terms than
the current credit facilities. If we are unable to obtain increases in our
borrowing capacity as needed, we may be unable to execute our development plan
as described in this Prospectus.
We
have hedged and may continue to hedge a portion of our production, which
may
result
in our making cash payments or prevent us from receiving the full benefit
of
increases
in prices for oil and natural gas.
In
order
to reduce our exposure to short-term fluctuations in the price of oil and
natural gas, and in some cases as required by our lenders, we periodically
enter
into hedging arrangements. Our hedging arrangements apply to only a portion
of
our production and provide only partial price protection against declines in
oil
and natural gas prices. Such hedging arrangements may expose us to risk of
financial loss in certain circumstances, including instances where production
is
less than expected, our customers fail to purchase contracted quantities of
oil
or natural gas or a sudden, unexpected event materially impacts oil or natural
gas prices. In addition, our hedging arrangements may limit the benefit to
us of
increases in the price of oil and natural gas.
We
will be subject to the requirements of Section 404 of the Sarbanes-Oxley
Act.
If
we are unable to timely comply with Section 404 or if the costs related
to
compliance
are significant, our profitability, stock price and results of
operations
and
financial condition could be materially adversely
affected.
We
will
be required to comply with the provisions of Section 404 of the
Sarbanes-Oxley Act of 2002 as of December 31, 2007. Section 404
requires that we document and test our internal controls over financial
reporting and issue management’s assessment of our internal controls over
financial reporting. This section also requires that our independent registered
public accounting firm opine on those internal controls and management’s
assessment of those controls. We will be required to evaluate our existing
controls against the criteria established in "Internal Control — Integrated
Framework" issued by the Committee of Sponsoring Organizations of the Treadway
Commission, or COSO. During the course of our ongoing evaluation and integration
of the internal control over financial reporting, we may identify areas
requiring improvement, and we may have to design enhanced processes and controls
to address issues identified through this review.
We
believe that the out-of-pocket costs, the diversion of management’s attention
from running the day-to-day operations and operational changes caused by the
need to comply with the requirements of Section 404 of the Sarbanes-Oxley
Act could be significant. If the time and costs associated with such compliance
significantly exceed our current expectations, our results of operations could
be materially affected.
We
cannot
be certain at this time that we will be able to successfully complete the
procedures, certification and attestation requirements of Section 404 or
that we or our auditors will not identify material weaknesses in internal
control over financial reporting. If we fail to comply with the requirements
of
Section 404 or if we or our auditors identify and report such material
weakness, the accuracy and timeliness of the filing of our annual and quarterly
reports may be materially adversely affected and could cause investors to lose
confidence in our reported financial information, which could have a negative
effect on the trading price of our common stock. In addition, a material
weakness in the effectiveness of our internal controls over financial reporting
could result in an increased chance of fraud and the loss of customers, reduce
our ability to obtain financing and require additional expenditures to comply
with these requirements, each of which could have a material adverse effect
on
our business, results of operations and financial condition.
We
are subject to complex federal, state and local laws and regulations that
could
adversely
affect our business.
Oil
and
natural gas operations are subject to various federal, state and local
government laws and regulations, which may be changed from time to time in
response to economic or political conditions. Matters that are typically
regulated include:
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discharge
permits for drilling operations;
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reports
concerning operations;
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unitization
and pooling of properties;
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environmental
protection; and
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From
time
to time, regulatory agencies have imposed price controls and limitations on
production by restricting the rate of flow of oil and natural gas wells below
actual production capacity to conserve supplies of natural gas and crude oil.
We
also are subject to changing and extensive tax laws, the effects of which we
cannot predict.
The
development, production, handling, storage, transportation and disposal of
natural gas and crude oil, by-products and other substances and materials
produced or used in connection with oil and natural gas operations are subject
to laws and regulations primarily relating to protection of human health and
the
environment. The discharge of natural gas, crude oil or pollutants into the
air,
soil or water may give rise to significant liabilities on our part to the
government and third parties and may result in the assessment of civil or
criminal penalties or require us to incur substantial costs of
remediation.
Legal
and
tax requirements frequently are changed and subject to interpretation, and
we
are unable to predict the ultimate cost of compliance with these requirements
or
their effect on our operations. Existing laws or regulations, as currently
interpreted or reinterpreted in the future, could harm our business, results
of
operations and financial condition.
RISKS
RELATED TO THE OWNERSHIP OF OUR STOCK
We
may experience volatility in our stock price.
For
the
18-month period ending June 30, 2007, our stock traded as high as $3.30 per
share and as low as $1.30 per share. The market price of our common stock may
fluctuate significantly in response to a number of factors, some of which are
beyond our control, including:
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changes
in natural gas prices;
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changes
in the natural gas industry and the overall economic
environment;
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quarterly
variations in operating results;
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changes
in financial estimates by securities analysts;
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changes
in market valuations of other similar companies;
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announcements
by us or our competitors of new discoveries or of significant technical
innovations, contracts, acquisitions, strategic partnerships or joint
ventures;
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additions
or departures of key personnel;
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any
deviations in net sales or in losses from levels expected by securities
analysts; and
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future
sales of our common stock.
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In
addition, the stock market from time to time experiences extreme volatility
that
has often been unrelated to the performance of particular companies. These
market fluctuations may cause our stock price to fall regardless of our
performance.
A
small number of existing shareholders control us and we do not have
cumulative
voting.
In
connection with the closing of the merger of Cadence Resources Corporation
and
Aurora Energy, Ltd. certain of our shareholders, including certain former Aurora
shareholders who became shareholders of us in connection with the merger,
executed and delivered voting agreements pursuant to which they agreed, until
October 31, 2008, to vote their shares of our common stock in favor of
(i) five directors designated by William W. Deneau, who were initially
William W. Deneau, Earl V. Young, Gary J. Myles, Richard Deneau, and Ronald
E.
Huff; and (ii) two directors designated by William W. Deneau from among our
board of directors immediately before the closing of the merger, who were
initially Howard Crosby and Kevin Stulp. In addition, these shareholders agreed
to vote all of their shares of common stock to ensure that the size of our
board
of directors will be set and remain at seven directors. After recent amendments
to the voting agreements, an aggregate of 11,702,580 shares, approximately
11.5% of our outstanding shares, are subject to these voting
agreements.
Also
in
connection with the closing of the merger, certain of our shareholders executed
and delivered irrevocable proxies naming William W. Deneau and Lorraine King
as
proxies to vote their shares through October 31, 2008, in the manner
determined by such proxies. An aggregate of approximately 10.7 million
shares of our common stock held by such shareholders was subject to these
proxies at June 30, 2007. These provisions will limit our other shareholders’
ability to influence the outcome of shareholder votes through October 31,
2008, including votes concerning the election of directors, the adoption or
amendment of provisions in our articles of incorporation or bylaws and the
approval of mergers and other significant corporate transactions.
Our
shareholders do not have the right to cumulative voting in the election of
our
directors. Cumulative voting, in some cases, could allow a minority group to
elect at least one director to our board. Because there is no provision for
cumulative voting, a minority group will not be able to elect any directors.
Accordingly, the holders of a majority of the shares of common stock, present
in
person or by proxy, will be able to elect all of the members of our board of
directors.
Our
articles of incorporation contain provisions that discourage a change of
control.
Our
articles of incorporation contain provisions that could discourage an
acquisition or change of control without our board of directors’ approval. Our
articles of incorporation authorize our board of directors to issue preferred
stock without shareholder approval. If our board of directors elects to issue
preferred stock, it could be more difficult for a third party to acquire control
of us, even if that change of control might be beneficial to our
shareholders.
You
may experience dilution of your ownership interests due to the future issuance
of
shares
of our common stock, which could have an adverse effect on our stock
price.
We
may,
in the future, issue our previously authorized and unissued securities,
resulting in the dilution of the ownership interests of our present
shareholders. Our authorized capital stock consists of 250,000,000 shares
of common stock and 20,000,000 shares of preferred stock with such
designations, preferences and rights as may be determined by our board of
directors. On June 30, 2007, we had 101,589,456 shares of common stock
outstanding.
At
June
30, 2007, we had warrants and options outstanding that were exercisable for
6,746,444 shares of our common stock. We have an additional 5,257,500 shares
available for award as either option or stock grants under our existing
incentive plans. The potential issuance of such additional shares of common
stock may create downward pressure on the trading price of our common stock.
We
may also issue additional shares of our common stock or other securities that
are convertible into or exercisable for common stock in connection with the
hiring of personnel, future acquisitions, private placements of our securities
for capital raising purposes, or for other business purposes. In the future,
we
may engage in public offerings of our stock. Future sales of substantial amounts
of our common stock, or the perception that sales could occur, could have a
material adverse effect on the price of our common stock.
The
market price of our common stock could be adversely affected by sales
of
substantial
amounts of our common stock in the public markets.
We
have
two shelf registration statements that are currently effective, which together
have registered almost 20.6 million shares of common stock for resale. The
sale of a large number of shares of our common stock pursuant to the resale
registration statements, the perception that any such sale might occur, or
the
issuance of a large number of shares of our common stock in connection with
future acquisitions, equity financings or otherwise, could cause the market
price of our common stock to decline significantly. As of June 30, 2007, we
had
approximately 101.6 million shares of common stock issued and outstanding,
including approximately 10.5 million shares of our common stock held or
controlled by our executive officers and directors. Of those 10.5 million
shares, 8.6 million are subject to lock-up agreements through October 31, 2008,
0.5 million are eligible for resale on two S-8 registration statements, and
the
balance are eligible for sale under Rule 144 ("Rule 144") under the Securities
Act of 1933, as amended (the "Securities Act"). We have two currently effective
S-8 registration statements that, combined, include 469,996 shares owned or
controlled by our executive officers and directors that are registered for
resale.
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This
report contains forward-looking statements within the meaning of Section 27A
of
the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E
of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All
statements other than statements of historical facts are forward-looking
statements. You can find many of these statements by looking for words such
as
"believes," "expects," "anticipates," "estimates", "intends", or similar
expressions used in this report.
These
forward-looking statements are subject to numerous assumptions, risks and
uncertainties. Factors which may cause our actual results, performance or
achievements to be materially different from any future results, performance
or
achievements expressed or implied by us in those statements include, among
others, the following:
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the
quality of our properties with regard to, among other things, the
existence of reserves in economic
quantities;
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uncertainties
about the estimates of reserves;
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our
ability to increase our production and oil and natural gas income
through
exploration and development;
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the
number of well locations to be drilled and the time frame within
which
they will be drilled;
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the
timing and extent of changes in commodity prices for natural gas
and crude
oil;
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domestic
demand for oil and natural gas;
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drilling
and operating risks;
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the
availability of equipment, such as drilling rigs and transportation
pipelines;
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changes
in our drilling plans and related budgets;
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the
adequacy of our capital resources and liquidity including, but not
limited
to, access to additional borrowing capacity;
and
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other
factors discussed above under the heading "Risks Related To Our Business".
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Because
such statements are subject to risks and uncertainties, actual results may
differ materially from those expressed or implied by the forward-looking
statements. You are cautioned not to place undue reliance on such statements,
which speak only as of the date of this report.
USE
OF PROCEEDS
We
will
not receive any of the proceeds from the sale of the shares owned by the selling
security holders. We may receive proceeds in connection with the exercise of
warrants, the underlying shares of which may in turn be sold by the selling
security holders. Although the amount and timing of our receipt of any such
proceeds are uncertain, such proceeds, if received, will be used for general
corporate purposes.
PRICE
RANGE OF COMMON STOCK
Our
common stock trades under the symbol AOG on the American Stock Exchange
(“AMEX”). Prior to May 2006, our common stock traded under the symbol CDNR.BB on
the Over-the-Counter Bulletin Board Electronic Quotation System maintained
by the National Association of Securities Dealers. The following chart shows
the
range of high and low bid prices/sales prices for our common stock for each
fiscal quarter in the last two calendar years plus the first two quarters of
2007. The prices during the time in which our stock traded over-the-counter
are
bid prices, without retail mark-up, mark-down or commission, and may not
necessarily represent actual transactions. The prices during the time in which
our stock traded on AMEX are actual sales prices.
Quarter
Ended
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High
Bid/
Sales
Price
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|
Low
Bid/
Sales
Price
|
|
March 31,
2005
|
|
$
|
2.95
|
|
$
|
1.05
|
|
June 30,
2005
|
|
$
|
2.67
|
|
$
|
2.00
|
|
September 30,
2005
|
|
$
|
3.47
|
|
$
|
1.86
|
|
December 31,
2005
|
|
$
|
4.85
|
|
$
|
3.15
|
|
March 31,
2006
|
|
$
|
7.44
|
|
$
|
4.45
|
|
June 30,
2006
|
|
$
|
6.10
|
|
$
|
3.76
|
|
September 30,
2006
|
|
$
|
4.74
|
|
$
|
2.94
|
|
December
31, 2006
|
|
$
|
3.22
|
|
$
|
3.08
|
|
March
31, 2007
|
|
$
|
3.30
|
|
$
|
2.06
|
|
June
30, 2007
|
|
$
|
2.77
|
|
$
|
1.30
|
|
On
September 28, 2007, the last reported sale price of our common stock on
AMEX was $1.44 and there were 101,679,456 shares of our common stock outstanding
and approximately 527 holders of record.
DIVIDEND
POLICY
There
have been no cash dividends declared on our common stock since we were formed.
We do not intend to pay cash dividends on our common stock for the foreseeable
future. Our current credit facilities prohibit our borrowing subsidiaries from
declaring dividends, which means that we will generally not have cash flow
available from which to pay cash dividends.
SELECTED
HISTORICAL FINANCIAL DATA
The
following table sets forth our selected historical financial data as of and
for
each of the periods indicated. The data as of and for the years ended
December 31, 2006, and 2005, is derived from our historical audited
consolidated financial statements for the periods indicated. The data as of
and
for the six months ended June 30, 2007, and 2006, is derived from our
historical unaudited condensed consolidated financial statements for the interim
periods indicated. The interim unaudited information was prepared on a basis
consistent with that used in preparing our audited consolidated financial
statements and includes all adjustments, consisting only of normal and recurring
items, that we consider necessary for a fair presentation of the financial
position, results of operations and cash flows for the unaudited periods.
Operating results for the six months ended June 30, 2007, are not
necessarily indicative of results that may be expected for the entire year
2007
or any future periods. You should review this information together with
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and our consolidated historical financial statements and related
notes included elsewhere in this prospectus.
|
|
Six
Months Ended June 30,
|
|
Year
Ended December 31,(a)
|
|
|
|
2007
|
|
2006
|
|
2006
|
|
2005
|
|
Statement
of operations data
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$
|
12,532,005
|
|
$
|
10,941,220
|
|
$
|
21,591,811
|
|
$
|
6,743,444
|
|
Pipeline
transportation and marketing
|
|
|
286,932
|
|
|
242,299
|
|
|
1,179,431
|
|
|
-
|
|
Field
service and sales
|
|
|
249,602
|
|
|
-
|
|
|
125,611
|
|
|
-
|
|
Interest
and other income
|
|
|
474,758
|
|
|
181,631
|
|
|
220,592
|
|
|
666,850
|
|
Total
revenue
|
|
|
13,543,297
|
|
|
11,365,150
|
|
|
23,117,445
|
|
|
7,410,294
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
566,969
|
|
|
445,825
|
|
|
877,319
|
|
|
506,635
|
|
Production
and lease operating expense
|
|
|
4,126,700
|
|
|
2,853,374
|
|
|
6,278,131
|
|
|
1,587,205
|
|
Pipeline
operating expense
|
|
|
177,802
|
|
|
137,484
|
|
|
643,963
|
|
|
-
|
|
Field
service expense
|
|
|
200,096
|
|
|
-
|
|
|
90,913
|
|
|
-
|
|
General
and administrative expense
|
|
|
4,233,701
|
|
|
3,242,713
|
|
|
7,531,718
|
|
|
3,435,507
|
|
Oil
and natural gas depletion and amortization
|
|
|
1,523,460
|
|
|
2,010,383
|
|
|
2,681,290
|
|
|
767,511
|
|
Other
assets depreciation and amortization
|
|
|
1,142,104
|
|
|
1,013,783
|
|
|
2,083,191
|
|
|
308,647
|
|
Interest
expense
|
|
|
2,050,403
|
|
|
3,564,154
|
|
|
4,573,785
|
|
|
1,307,370
|
|
Taxes
|
|
|
(53
|
)
|
|
29,361
|
|
|
250,884
|
|
|
29,651
|
|
Total
expenses
|
|
|
14,021,182
|
|
|
13,297,077
|
|
|
25,011,194
|
|
|
7,942,526
|
|
Loss
before minority interest
|
|
|
(477,885
|
)
|
|
(1,931,927
|
)
|
|
(1,893,749
|
)
|
|
(532,232
|
)
|
Minority
interest in (income) loss of subsidiaries
|
|
|
(32,957
|
)
|
|
(17,919
|
)
|
|
(50,898
|
)
|
|
15,960
|
|
Net
loss
|
|
$
|
(510,842
|
)
|
$
|
(1,949,846
|
)
|
$
|
(1,944,647
|
)
|
$
|
(516,272
|
)
|
Net
loss per common share — basic and diluted
|
|
$
|
(0.01
|
)
|
$
|
(0.03
|
)
|
$
|
(0.02
|
)
|
$
|
(0.01
|
)
|
Weighted
average common shares outstanding — basic and
diluted
|
|
|
101,602,875
|
|
|
70,265,281
|
|
|
82,288,243
|
|
|
40,622,000
|
|
Cash
flow data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
provided (used) by operating activities
|
|
$
|
5,411,775
|
|
$
|
3,607,502
|
|
$
|
2,244,535
|
|
$
|
(2,392,118
|
)
|
Cash
used by investing activities
|
|
|
(32,016,909
|
)
|
|
(61,497,361
|
)
|
|
(86,317,737
|
)
|
|
(39,881,947
|
)
|
Cash
provided by financing activities
|
|
|
25,590,236
|
|
|
49,504,174
|
|
|
73,827,960
|
|
|
49,075,121
|
|
|
|
As
of June 30,
|
|
As
of December 31,(a)
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Balance
sheet data
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
720,498
|
|
$
|
1,735,396
|
|
$
|
11,980,638
|
|
Other
current assets
|
|
|
9,006,600
|
|
|
12,728,588
|
|
|
7,274,869
|
|
Oil
and gas properties, net (using full cost accounting)
|
|
|
184,249,398
|
|
|
161,294,155
|
|
|
68,960,754
|
|
Other
property and equipment, net
|
|
|
9,306,214
|
|
|
9,221,228
|
|
|
3,610,138
|
|
Other
assets
|
|
|
25,116,848
|
|
|
27,407,825
|
|
|
24,995,746
|
|
Total
assets
|
|
$
|
228,399,558
|
|
$
|
212,387,192
|
|
$
|
116,822,145
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
11,207,070
|
|
$
|
18,117,955
|
|
$
|
17,341,431
|
|
Long-term
debt, net of current maturities
|
|
|
79,187,004
|
|
|
54,538,138
|
|
|
42,794,862
|
|
Redeemable
convertible preferred stock
|
|
|
-
|
|
|
-
|
|
|
59,925
|
|
Shareholders’
equity
|
|
|
138,005,484
|
|
|
139,731,099
|
|
|
56,625,927
|
|
Total
liabilities and shareholders’ equity
|
|
$
|
228,399,558
|
|
$
|
212,387,192
|
|
$
|
116,822,145
|
|
(a)
|
We
acquired Aurora on October 31, 2005 through the merger of our
wholly-owned subsidiary with and into Aurora. The acquisition of
Aurora
was accounted for as a reverse merger, with Aurora being the acquiring
party for accounting purposes. As a result of the reverse merger,
the
historical financial statements presented for periods prior to the
acquisition date are the financial statements of Aurora. The operations
of
the former Cadence Resources Corporation (now known as Aurora
Oil & Gas Corporation) businesses have been included in the
financial statements from the date of acquisition. The common stock
per
share information in the consolidated financial statements for the
year
ended December 31, 2005, and related notes have been retroactively
adjusted to give effect to the reverse merger on October 31,
2005.
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The
following discussion and analysis should be read in conjunction with
the
“Selected
Historical Financial Data” and the consolidated financial statements
and
related
notes included elsewhere in this prospectus. This discussion
contains
forward-looking
statements reflecting our current expectations and estimates
and
assumptions
concerning events and financial trends that may affect our
future
operating
results or financial position. Actual results and the timing of events
may
differ
materially from those contained in these forward-looking statements due to
a
number
of factors, including those discussed in the sections entitled “Risk
Factors”
and
“Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere
in
this
prospectus.
Executive
Summary
We
are a
growing independent energy company focused on the exploration, exploitation,
and
development of unconventional natural gas reserves. Our unconventional natural
gas projects target shale plays where large acreage blocks can be easily
evaluated with a series of low cost test wells. Shale plays tend to be
characterized by high drilling success and relatively low drilling costs when
compared to conventional exploration and development plays. Our project areas
are focused in the Antrim shale of Michigan, the New Albany shale of Southern
Indiana and Western Kentucky, and the Woodford shale in Oklahoma.
We
commenced operations in 1969 to explore and mine natural resources under the
name Royal Resources, Inc. In July 2001, we reorganized our business to pursue
oil and gas exploration and development opportunities and changed our name
to
Cadence Resources Corporation. We acquired Aurora Energy, Ltd. (“Aurora”) on
October 31, 2005, through the merger of our wholly-owned subsidiary with and
into Aurora. The acquisition of Aurora was accounted for as a reverse merger
with Aurora being the acquiring party for accounting purposes. The Aurora
executive management team also assumed management control at the time the merger
closed, and we moved our corporate offices to Traverse City, Michigan. Effective
May 11, 2006, Cadence Resources Corporation amended its articles of
incorporation to change the parent company name to Aurora Oil & Gas
Corporation.
Our
revenue, profitability and future rate of growth are substantially dependent
on
our ability to find, develop, and acquire gas reserves that are economically
recoverable based 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 our financial position, results of operations, cash
flows, access to capital and on the quantities of natural gas and oil that
can
be economically produced.
Highlights
For
the
six months ended June 30, 2007, we continued to shift our focus from acquisition
of properties to an early stage developer of unconventional shale development
projects. As of June 30, 2007, our leasehold acres (both developed and
undeveloped) were 1,312,331 (718,699 net) which represent a 8% increase over
our
December 31, 2006 net acres. Of the 95,552 (28,808 net) leasehold acres
increase, 1,874 net acres were acquired in the Antrim shale play, 14,708 net
acres were acquired in the New Albany shale play, 35,417 net acres were acquired
in the Other plays, and 23,191 net acres were sold in the Other
plays.
With
regard to our strategy to generate growth through drilling, we drilled or
participated in 58 (28 net) wells for the six months ended June 30, 2007, with
a
91% success rate. Our Antrim drilling program was restricted for the first
three
months due to frost laws not allowing movement of drilling rigs. As of June
30,
2007, we had 504 (241 net) producing wells, 63 (35 net) wells awaiting hook-up,
31 (20 net) wells requiring resource assessment and 18 (8 net) wells temporary
abandoned. We also continued our strategy to have greater control over our
projects by operating 240 (223 net) wells, thus, operating 39% of our gross
wells and 74% of our net wells. Of the 223 net wells operated by the Company,
173 net wells are producing in the Antrim; 28 net wells are awaiting hook-up
primarily in the Antrim; 16 net wells requiring resource assessment primarily
in
the New Albany shale and Other; and 6 net wells are temporary abandoned in
the
Antrim.
Oil
and
natural gas production for the six months ended June 30, 2007, was 1,493,454
mcfe, a 15% increase over the 1,295,879 mcfe produced in the six months ended
June 30, 2006. For the six months ended June 30, 2007, production continues
to
be hampered by delays bringing wells into production, and dewatering. The
Company has seen its Michigan operated production significantly stabilize adding
a 10% increase in existing Michigan operated production during the second
quarter of 2007 as well as adding 5% net increase due to new wells being placed
on-line.
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 of June 1, 2007 through December 31, 2008. Integrys
Energy Services, Inc. will be the Company’s primary marketing partner for all of
Michigan operated properties. The Company expects this partnering to provide
extensive market and pipeline knowledge, strong credit worthiness as well as
back office support.
In
order
to reduce exposure to fluctuations in the price of natural gas, the Company
has
recently increased its natural gas hedge position by entering into the following
financial swap contracts: (1) 2,000 mmbtu per day at a fixed price of $8.41
for
the period from January 1, 2008 through December 31, 2008; (2) 7,000 mmbtu
per
day at a fixed price of $8.72 for the period from January 1, 2009 through
December 31, 2009; (3) 7,000 mmbtu per day at a fixed price of $8.68 for the
period from January 1, 2010 through March 31, 2011; and (4) 7,000 mmbtu per
day
at a fixed price of $7.62 for the period from April 1, 2011 through September
30, 2011. These additional derivative instruments provide the Company with
a
weighted average floor price of $8.53 per mmbtu on this first 7,000 mmbtu per
day through September 30, 2011.
Our
2007
capital budget for drilling and related well work and infrastructure has been
revised from an estimated $73.7 million with participation in 291 (182 net)
wells to an estimated $52.9 million with participation in 162 (111 net) wells.
The following table summarizes our revised 2007 drilling and related well work
budget for our key exploration and development areas:
|
|
Actual
January
2007 - June 2007 (a)
|
|
Budget
July
2007 - December 2007 (a)
|
|
Play/Trend
|
|
Gross
Wells Drilled
|
|
Net
Wells Drilled
|
|
Net
Capital Expenditure Budget
|
|
Gross
Wells Projected to be Drilled
|
|
Net
Wells Projected to be Drilled
|
|
Net
Capital Expenditure Budget
|
|
Antrim
|
|
|
29
|
|
|
12.94
|
|
$
|
7,150,000
|
|
|
49
|
|
|
41.29
|
|
$
|
20,253,000
|
|
New
Albany
|
|
|
16
|
|
|
4.05
|
|
|
2,869,000
|
|
|
28
|
|
|
17.23
|
|
|
15,881,000
|
|
Other
|
|
|
12
|
|
|
10.93
|
|
|
2,425,000
|
|
|
28
|
|
|
24.85
|
|
|
4,304,000
|
|
Total
|
|
|
57
|
|
|
27.92
|
|
$
|
12,444,000
|
|
|
105
|
|
|
83.37
|
|
$
|
40,438,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
21
|
|
|
19.20
|
|
$
|
7,706,000
|
|
|
77
|
|
|
72.43
|
|
$
|
35,656,000
|
|
Non-operated
|
|
|
36
|
|
|
8.72
|
|
|
4,738,000
|
|
|
28
|
|
|
10.94
|
|
|
4,782,000
|
|
Total
|
|
|
57
|
|
|
27.92
|
|
$
|
12,444,000
|
|
|
105
|
|
|
83.37
|
|
$
|
40,438,000
|
|
Note:
(a)
Does not include costs for leasehold interest of $2.7 million for 2007 YTD
actuals and $1.7 million for the second half 2007 budget
RESULTS
OF OPERATIONS
Operating
Statistics
The
following table sets forth certain key operating statistics for the six months
ended June 30, 2007, and 2006, and for the years ended December 31, 2006, and
2005:
|
|
Six
Months Ended
June 30,
|
|
Year
Ended
December 31,
|
|
|
|
2007
|
|
2006
|
|
2006
|
|
2005
|
|
Total
net acreage held
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
156,517
|
|
|
125,993
|
|
|
154,643
|
|
|
78,163
|
|
New
Albany
|
|
|
456,060
|
|
|
449,460
|
|
|
441,351
|
|
|
271,891
|
|
Other
|
|
|
106,122
|
|
|
45,837
|
|
|
93,897
|
|
|
14,036
|
|
Total
|
|
|
718,699
|
|
|
621,290
|
|
|
689,891
|
|
|
364,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
wells drilled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
12
|
|
|
27
|
|
|
93
|
|
|
105
|
|
New
Albany
|
|
|
4
|
|
|
2
|
|
|
7
|
|
|
-
|
|
Other
|
|
|
8
|
|
|
4
|
|
|
5
|
|
|
1
|
|
Dry
|
|
|
4
|
|
|
2
|
|
|
7
|
|
|
7
|
|
Total
|
|
|
28
|
|
|
35
|
|
|
112
|
|
|
113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
net wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
- producing
|
|
|
227
|
|
|
154
|
|
|
199
|
|
|
110
|
|
Antrim
- awaiting hookup
|
|
|
33
|
|
|
31
|
|
|
51
|
|
|
52
|
|
NAS
- producing
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
-
|
|
NAS
- awaiting hookup
|
|
|
1
|
|
|
3
|
|
|
7
|
|
|
2
|
|
Other
- producing
|
|
|
13
|
|
|
15
|
|
|
14
|
|
|
13
|
|
Other
- awaiting hookup
|
|
|
1
|
|
|
4
|
|
|
1
|
|
|
6
|
|
Total
|
|
|
276
|
|
|
207
|
|
|
273
|
|
|
183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf)
|
|
|
1,410,820
|
|
|
1,224,551
|
|
|
2,517,897
|
|
|
687,271
|
|
Crude
oil (bbls)
|
|
|
13,772
|
|
|
11,888
|
|
|
22,588
|
|
|
10,628
|
|
Natural
gas equivalent
|
|
|
1,493,453
|
|
|
1,295,879
|
|
|
2,653,427
|
|
|
751,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
daily production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (mcf)
|
|
|
7,795
|
|
|
6,765
|
|
|
6,898
|
|
|
1,883
|
|
Crude
oil (bbls)
|
|
|
76
|
|
|
66
|
|
|
62
|
|
|
29
|
|
Natural
gas equivalent
|
|
|
8,251
|
|
|
7,161
|
|
|
7,270
|
|
|
2,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales prices (including realized gains or losses from
hedging)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas ($ per mcf)
|
|
$
|
8.33
|
|
$
|
8.33
|
|
$
|
8.02
|
|
$
|
9.00
|
|
Crude
oil ($ per bbl)
|
|
$
|
57.00
|
|
$
|
62.34
|
|
$
|
61.95
|
|
$
|
52.54
|
|
Natural
gas equivalent
|
|
$
|
8.39
|
|
$
|
8.44
|
|
$
|
8.14
|
|
$
|
8.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
11,747,014
|
|
$
|
10,200,110
|
|
$
|
20,192,366
|
|
$
|
6,184,989
|
|
Crude
oil
|
|
|
784,991
|
|
|
741,110
|
|
|
1,399,445
|
|
|
558,455
|
|
Total
|
|
$
|
12,532,005
|
|
$
|
10,941,220
|
|
$
|
21,591,811
|
|
$
|
6,743,444
|
|
|
|
Six
Months Ended
June 30,
|
|
Year
Ended
December 31,
|
|
|
|
2007
|
|
2006
|
|
2006
|
|
2005
|
|
Average
expenses ($ per mcfe)
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
$
|
0.38
|
|
$
|
0.34
|
|
$
|
0.33
|
|
$
|
0.67
|
|
Post-production
expenses
|
|
|
0.54
|
|
|
0.49
|
|
|
0.55
|
|
|
0.50
|
|
Leasing
operating expenses
|
|
|
2.23
|
|
|
1.71
|
|
|
1.82
|
|
|
1.62
|
|
General
and administrative expense
|
|
|
2.83
|
|
|
2.50
|
|
|
2.84
|
|
|
4.57
|
|
General
and administrative expense excluding stock-based
compensation
|
|
|
2.03
|
|
|
1.92
|
|
|
2.00
|
|
|
4.57
|
|
Oil
and natural gas depreciation, depletion and amortization expense
|
|
|
1.02
|
|
|
1.55
|
|
|
1.01
|
|
|
1.02
|
|
Other
assets depreciation and amortization
|
|
|
0.76
|
|
|
0.78
|
|
|
0.79
|
|
|
0.41
|
|
Interest
expense
|
|
|
1.37
|
|
|
2.75
|
|
|
1.72
|
|
|
1.74
|
|
Taxes
|
|
|
-
|
|
|
0.02
|
|
|
0.09
|
|
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of employees
|
|
|
88
|
|
|
53
|
|
|
90
|
|
|
36
|
|
RESULTS
OF OPERATIONS
Six
Months Ended June 30, 2007 (“Current Period”), compared with Six Months Ended
June 30, 2006 (“Prior Year Period”)
General
.
For the
Current Period, the Company had a net loss of $0.5 million, or $(0.01) per
diluted common share, on total revenues of $13.5 million. This compares to
a net
loss of $1.9 million, or $(0.03) per diluted common share, on total revenue
of
$11.4 million for the Prior Year Period. The $2.2 million increase in revenue
represents our initial steps as an early stage developer of oil and natural
gas
properties as well as a gain recognized in the sale of mining
claims.
Oil
and Natural Gas Sales
.
During
the Current Period, oil and natural gas sales were $12.5 million compared to
$10.9 million in the Prior Year Period. The Company produced 1,493,453 mcfe
at a
weighted average price of $8.39 compared to 1,295,879 mcfe at a weighted average
price of $8.44. This increase in production was due to new wells placed on-line
and gains in stabilizing production in the second quarter of 2007. We had 241
net wells producing as of June 30, 2007, as compared to 169 net wells producing
as of June 30, 2006. The weighted average price included $1.4 million and $0.8
million of realized gains from the gas derivative contract for Current Period
and Prior Year Period, respectively. Production from the Antrim shale play
represented approximately 92% of our oil and natural gas revenue for the Current
Period.
The
following table summarizes our oil and natural gas revenue by play/trend in
the
periods set forth below:
|
|
Six
Months Ended
June
30, 2007
|
|
Six
Months Ended
June
30, 2006
|
|
Play/Trend
|
|
(mcfe)
|
|
Amount
|
|
(mcfe)
|
|
Amount
|
|
Antrim
|
|
|
1,384,508
|
|
$
|
11,560,199
|
|
|
1,114,142
|
|
$
|
9,245,791
|
|
New
Albany
|
|
|
22,892
|
|
|
173,344
|
|
|
9,130
|
|
|
69,101
|
|
Other
|
|
|
86,053
|
|
|
798,462
|
|
|
172,607
|
|
|
1,626,328
|
|
Total
|
|
|
1,493,453
|
|
$
|
12,532,005
|
|
|
1,295,879
|
|
$
|
10,941,220
|
|
Other
Revenues
.
Other
revenues increased by $0.6 million, or 99% to $1.0 million in the Current Period
from $0.4 million in the Prior Year Period. This increase is attributed to
the
sale of mining claims ($0.4 million) and to the Bach acquisition ($0.2 million)
in October 2006 which provides oil and natural gas field services.
Production
Taxes.
Production
taxes were $0.6 million in the Current Period compared to $0.4 million in the
Prior Year Period. This increase is attributed to new wells being added and
production growth of existing wells. On a unit of production basis, production
taxes were $0.38 per mcfe in the Current Period compared to $0.34 per mcfe
in
the Prior Year Period.
Production
and Lease Operating Expenses
.
Our
production and lease operating expenses include services related to producing
oil and natural gas, such as post-production costs, including marketing and
transportation, and expenses to operate the wells and equipment on producing
leases.
Production
and lease operating expenses were $4.1 million in the Current Period compared
to
$2.9 million in the Prior Year Period. On a per unit of production basis,
production and lease operating expenses were $2.77 per mcfe in the Current
Period compared to $2.20 per mcfe in the Prior Year Period. The increase in
the
Current Period was primarily attributable to higher energy costs, higher
property taxes, higher pumping costs, repair and maintenance associated with
meters, compressors and pumps, and outside labor. On a component basis,
post-production expenses were $0.8 million, or $0.54 per mcfe, in the Current
Period compared to $0.6 million, or $0.49 per mcfe, in the Prior Year Period,
and lease operating expenses were $3.3 million, or $2.23 per mcfe, in the
Current Period compared to $2.2 million, or $1.71 per mcfe, in the Prior Year
Period.
Production
and lease operating expenses for operated properties were $2.57 per mcfe in
the
Current Period while non-operated production and lease operating expenses were
$3.40 per mcfe in the Current Period. Our operated Arrowhead project continues
to negatively impact our operating cost controls and efficiency. Production
and
lease operating expenses for operated properties excluding Arrowhead were $2.27
per mmcfe in the Current Period.
Pipeline
Operating Expenses and Field Services Expenses
.
Pipeline operating expenses were $0.2 million in the Current Period compared
to
$0.1 million in the Prior Year Period. Field services expenses were $0.2 million
in the Current Period compared to no expense in the Prior Year Period which
are
attributable to the Bach acquisition in October 2006.
General
and Administrative Expenses
.
Our
general and administrative expenses include officer and employee compensation,
travel, audit, tax and legal fees, office supplies, utilities, insurance,
consulting fees, and office related expense. General and administrative expenses
in the Current Period increased by $1.0 million, or 31%, from the Prior Year
Period. This increase is the result of executing our growth strategy. This
has
resulted in substantial increases in employees and related cost. Our staffing
requirements increased 39% to 59 employees for the Current Period compared
to 52
employees in the Prior Year Period which excludes 29 employees from the Bach
acquisition.
Payroll
and related costs increased by $1.8 million to $3.1 million in the Current
Period due to higher stock-based compensation ($1.2 million), bonuses ($0.3
million) and staffing additions ($0.3 million). Legal, accounting, and other
consulting services were reduced by $0.8 million to $0.7 million in the Current
Period compared to $1.9 million in the Prior Year Period.
The
Company follows the full cost method of accounting under which all costs
associated with property acquisition, exploration, and development activities
are capitalized. We capitalized certain 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. We capitalized $0.8 million of payroll and benefit costs
for
the Current Period compared to $1.0 million in the Prior Year
Period.
Oil
and Natural Gas Depletion, Depreciation and Amortization
(“DD&A”)
.
DD&A of oil and natural gas properties was $1.5 million and $2.0 million
during the Current Period and the Prior Year Period, respectively. DD&A is a
function of capitalized costs in the full cost pool and related underlying
reserves in the periods presented. This decrease is the result of a change
in
estimate of DD&A from proven developed reserves to total proven reserves and
the underlying reserves increasing by 89 bcfe as of December 31, 2006. The
average DD&A cost per mcfe was $1.02 and $1.55 in the Current Period and the
Prior Year Period, respectively.
Other
Assets Depreciation and Amortization (“D&A”)
.
D&A
of other assets was $1.1 million in the Current Period, compared to $1.0 million
in the Prior Year Period. This increase was primarily the result of additions
in
other assets.
Interest
Expense
.
Interest expense was $2.1 million in the Current Period compared to $3.6 million
in the Prior Year Period. This decrease is the result of a change in estimating
capitalized interest and reduction in borrowing under the senior secured credit
facility. During the fourth quarter 2006, the Company modified its approach
to
estimating capitalized interest by recognizing that debt need not be specific
debt incurred on a specific asset.
Taxes,
Other
.
Tax
expense (refund) was ($53) in the Current Period compared to $29,361 in the
Prior Year Period. This decrease primarily represents a 2003 Indiana property
tax refund of $39,884 received in 2007. The Company has significant net
operating loss carryforwards, thus no federal income tax expense has been
recognized.
Year
Ended December 31, 2006, compared with Year Ended December 31,
2005
General
.
For the
year ended December 31, 2006, the Company had a net loss of $1.9 million, or
$(0.02) per diluted common share, on total revenues of $23.1 million. This
compares to a net loss of $0.5 million, or $(0.01) per diluted common share,
on
total revenue of $7.4 million during the year ended December 31, 2005. The
$15.7
million increase in revenue represents our initial steps as an early stage
developer of oil and natural gas properties.
Oil
and Natural Gas Sales
.
During
2006, oil and natural gas sales were $21.6 million compared to $6.7 million
in
the 2005. The Company produced 2,653,427 mcfe at a weighted average price of
$8.14 compared to 751,039 mcfe at a weighted average price of $8.98. This
increase in production was due to new wells placed on-line, acquisition of
additional working interest in the Hudson properties and the producing assets
from the Cadence reverse merger. We had 213 net wells producing as of December
31, 2006 as compared to 123 net wells producing as of December 31, 2005. The
weighted average price included $2.7 million of realized gains from the gas
derivative contract entered into 2006. Production from the Antrim shale play
represented approximately 88% of our oil and natural gas revenue for the 2006.
The
following table summarizes our oil and natural gas revenue by play/trend in
the
periods set forth below:
|
|
Year
Ended
December
31, 2006
|
|
Year
Ended
December
31, 2005
|
|
Play/Trend
|
|
(mcfe)
|
|
Amount
|
|
(mcfe)
|
|
Amount
|
|
Antrim
|
|
|
2,353,691
|
|
$
|
18,948,300
|
|
|
649,660
|
|
$
|
6,139,670
|
|
New
Albany
|
|
|
28,517
|
|
|
190,079
|
|
|
11,079
|
|
|
94,620
|
|
Other
|
|
|
271,219
|
|
|
2,453,432
|
|
|
90,300
|
|
|
509,154
|
|
Total
|
|
|
2,653,427
|
|
$
|
21,591,811
|
|
|
751,039
|
|
$
|
6,743,444
|
|
Other
Revenues
.
Other
revenues increased by $0.9 million, or 129% to $1.5 million in 2006 from $0.7
million in 2005. This increase is attributed to two acquisitions in 2006. The
first acquisition is the Hudson gas properties with pipeline business component
and the second acquisition is Bach which provides oil and natural gas field
services.
Production
Taxes.
Production
taxes were $0.9 million in 2006 compared to $0.5 million in 2005. This increase
is attributed to new wells being added and production growth of existing wells.
On a unit of production basis, production taxes were $0.33 per mcfe in 2006
compared to $0.67 per mcfe in 2005.
Production
and Lease Operating Expenses
.
Our
production and lease operating expenses include services related to producing
oil and natural gas, such as post production costs, including marketing and
transportation, and expenses to operate the wells and equipment on producing
leases.
Production
and lease operating expenses were $6.3 million in 2006 compared to $1.6 million
in 2005. On a unit of production basis, production and lease operating expenses
were $2.37 per mcfe in 2006 compared to $2.11 per mcfe in 2005. The increase
in
2006 was primarily attributable to higher energy costs, higher pumping costs,
repair and maintenance associated with compressors and pumps, and road and
location maintenance. On a component basis, post-production expenses were $1.5
million, or $0.55 per mcfe in 2006 compared to $0.4 million or $0.50 per mcfe
in
2005 and lease operating expenses were $4.8 million, or $1.82 per mcfe in 2006
compared to $1.2 million, or $1.62 per mcfe in 2005.
Production
and lease operating expenses for operated properties were $2.22 per mcfe in
2006
compared to $1.53 per mcfe in 2005. Non-operated production and lease operating
expenses were $2.77 per mcfe in 2006 compared to $2.36 in 2005.
Pipeline
Operating Expense and Field Services Expenses
.
Pipeline operating expenses were $0.6 million in 2006 compared to no expense
in
2005 which are attributable to the Hudson acquisition. Field services expenses
were $0.1 million in 2006 compared to no expense in 2005 which are attributable
to the Bach acquisition.
General
and Administrative Expenses
.
Our
general and administrative expenses include officer and employee compensation,
travel, audit, tax and legal fees, office supplies, utilities, insurance,
consulting fees and office related expense. General and administrative expenses
in 2006 increased by $4.1 million, or 119%, from 2005. This increase is the
result of executing our growth strategy as well as costs of becoming and
maintaining a public entity. This has resulted in substantial increases in
employees and related costs, legal and accounting services related to SEC
filings as well as increased consulting services. General and administrative
expenses in 2005 primarily reflected Aurora as a private entity.
Payroll
and related costs increased by $2.1 million to $4.6 million in 2006. This
included stock-based compensation of $2.2 million in 2006 which consists of
$0.8
million for directors, $0.8 for senior management and $0.6 for employees. Fiscal
year 2005 did not have any stock-based compensation. We incurred $1.8 million
in
legal, accounting and other consulting services as a result of our growth
strategy including development costs associated with becoming a public entity
and on-going public costs.
The
Company follows the full cost method of accounting under which all costs
associated with property acquisition, exploration and development activities
are
capitalized. We capitalized certain 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. During the year ended December 31, 2006, we capitalized
$1.4
million of payroll and benefit costs to oil and natural gas
properties.
Oil
and Natural Gas Depletion, Depreciation and Amortization
(“DD&A”)
.
DD&A of oil and natural gas properties was $2.7 million and $0.8 million
during 2006 and 2005, respectively. DD&A is a function of capitalized costs
in the full cost pool and related underlying reserves in the periods presented.
This increase is the result of $81.5 million being added to proved properties
in
the full cost pool, production growth, and the underlying reserves increasing
by
89 bcfe. The average DD&A cost per mcfe was $1.01 and $1.02 in 2006 and
2005, respectively
Other
Assets Depreciation and Amortization (“D&A”)
.
D&A
of other assets was $2.1 million in 2006, compared to $0.3 million in 2005.
This
increase was primarily the result of intangible assets amortization of $1.5
million connected with the Cadence merger, pipeline depreciation of $0.3 million
related to the 2006 Hudson pipeline acquisition and $0.3 million depreciation
related to other property and equipment.
Interest
Expense
.
Interest expense was $4.6 million in 2006, compared to $1.3 million in 2005.
This increase is due to higher utilization of debt to continue our growth
strategy of acquiring and developing operating interests in the Antrim shale
and
the New Albany shale.
Taxes,
Other.
Tax
expense was $0.3 million in 2006, compared to $29,651 in 2005. This increase
represents state taxes on Texas and Louisiana properties, as well as real and
personal property taxes in Michigan.
LIQUIDITY
AND CAPITAL RESOURCES
We
expect
to fund our growth using a combination of existing and anticipated debt
capacity, sale of non-core assets, existing cash balances, and internally
generated cash flows from sales of natural gas production. Our revised 2007
capital budget for drilling and related well work and infrastructure is
estimated to be approximately $52.9 million with anticipated participation
in
162 (111 net) wells. We may be required to adjust our capital expenditures
if
the anticipated debt financing is not obtained and we are not able to complete
sales of non-core assets. Future cash flows are subject to a number of
variables, including the level of production, natural gas prices and successful
drilling efforts. There can be no assurance that operations and other capital
resources will provide cash in sufficient amounts to maintain planned or future
levels of capital expenditures.
On
August
20, 2007, we entered into a second lien term loan agreement (“Term Loan”) with
BNP Paribas (“BNP”), as the arranger and administrative agent, and several other
lenders forming a syndication. The initial term loan is $50 million for a 5-year
term 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 payoff the Company’s
existing mezzanine financing with Trust Company of the West (‘”TCW”) and for
general corporate purposes.
Interest
under the Term Loan is payable at rates based on the London Interbank Offered
Rate 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 noncash 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 Term 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 minimum current ratio, (ii)
maintenance of a minimum interest coverage ratio, (iii) maintenance of a maximum
of indebtedness to earnings before interest, income taxes, depreciation,
depletion and amortization and non-cash expenses, and (iv) maintenance of
minimum reserve value to indebtedness.
In
connection with the Term Loan, the Company also agreed to the amendment and
restatement of its senior secured credit facility with BNP and other lenders,
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.
In
both
the Term 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. 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.
Upon
execution of the Term Loan, the Company also entered into a 3-year interest
rate
swap transaction with BNP to hedge its exposure to the floating interest rate
on
the Term Loan debt. This hedge transaction on $50 million will yield an
effective interest rate of 11.86% for the period from August 23, 2007 through
August 23, 2010.
Our
senior secured credit facility is a $100 million senior secured credit facility
with BNP Paribas (“BNP”). The current borrowing base under this facility is $50
million and has not been updated for our 2006 year end reserves. As proved
reserves are added, this borrowing base may increase up to $100 million with
TCW
consent. This facility matures the earlier of January 31, 2010, or 91 days
prior
to the maturity of the mezzanine credit facility. This facility provides for
borrowings tied to prime rate or LIBOR plus 1.25 to 2.0% depending on the
borrowing base utilization that we select. As of June 30, 2007, interest on
borrowings under our senior credit facility had a weighted average interest
rate
of 7.125% and our total borrowings under this facility were $35 million. A
required semi-annual reserve report may result in an increase or decrease in
credit availability.
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, (ii) maintenance of a minimum interest coverage
ratio, (iii) maintenance of a maximum of indebtedness to earnings before
interest, income taxes, depreciation, depletion and amortization and non-cash
expenses, and (iv) maintenance of minimum reserve value to indebtedness. As
of
June 30, 2007, we were in compliance with all of the applicable covenants.
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. 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) $0.35
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.
Our
short-term line of credit is a $5 million revolving line of credit with
Northwestern Bank for general corporate purposes. As of June 30, 2007, our
total
borrowing capacity available under this facility was $3.6 million. The interest
rate is the prime rate with interest payable monthly in arrears. Principal
is
payable at the expiration of the line of credit, October 15, 2007. The Company
has elected not to request an extension of this revolving line of credit beyond
the expiration date and has paid the remaining loan balance as of September
25,
2007.
Our
total
capitalization was as follows:
|
|
As
of
June 30,
2007
|
|
As
of
December 31,
2006
|
|
As
of
December 31,
2005
|
|
Short-term
bank borrowings
|
|
$
|
1,418,615
|
|
$
|
542,788
|
|
$
|
6,210,000
|
|
Obligations
under capital lease
|
|
|
11,545
|
|
|
17,096
|
|
|
11,085
|
|
Related
party notes payable
|
|
|
264,170
|
|
|
280,321
|
|
|
69,833
|
|
Mortgage
payable
|
|
|
3,128,741
|
|
|
3,175,298
|
|
|
2,865,477
|
|
Mezzanine
financing
|
|
|
40,000,000
|
|
|
40,000,000
|
|
|
40,000,000
|
|
Senior
secured credit facility
|
|
|
35,000,000
|
|
|
10,000,000
|
|
|
—
|
|
Total
debt
|
|
|
79,823,071
|
|
|
54,015,503
|
|
|
49,156,395
|
|
Redeemable
convertible preferred stock
|
|
|
|
|
|
|
|
|
59,925
|
|
Shareholders’
equity
|
|
|
138,005,484
|
|
|
139,731,099
|
|
|
56,625,927
|
|
Total
capitalization
|
|
$
|
217,828,555
|
|
$
|
193,746,602
|
|
$
|
105,842,247
|
|
CASH
FLOWS
Operating
activities
Cash
provided by operating activities was $5.4 million in the Current Period,
compared to cash provided by operating activities of $3.6 million in the Prior
Year Period. The $1.8 million increase in cash provided by operating activities
primarily due to higher production volumes offset by higher operating expenses.
The Current Period cash flow provided by operating activities included; (1)
$2.7
million received from joint interest partners for development projects and
drilling advances; (2) $4.3 million in non-cash charges; (3) $0.4 million
decrease in other investment and subsidiaries: (4) $0.2 million received from
notes receivable; (5) $0.9 million decrease in current assets and liabilities;
and (6) a net loss of $0.5 million. See Results of Operations” for discussion of
changes in revenues and expenses.
Cash
provided by operating activities was $2.2 million in 2006, compared to cash
used
of $2.4 million in 2005. This $4.6 million increase in net cash provided by
operating activities was substantially due to a 220% increase in production
revenues. See “Results of Operations” for discussion of changes in revenues and
expenses. Non-cash charges increased due to higher depreciation, depletion
and
amortization as well as recognition of stock-based compensation in 2006. Changes
in current operating assets and liabilities decreased cash flow from operations
by $4.0 million.
Investing
activities
The
following table describes our significant investing transactions that we
completed in the periods set forth below:
|
|
Six
Months Ended June 30,
|
|
Year
Ended
December 31,
|
|
|
|
2007
|
|
2006
|
|
2006
|
|
2005
|
|
Acquisitions
of leaseholds
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
$
|
915,684
|
|
$
|
4,496,399
|
|
$
|
7,138,014
|
|
$
|
5,747,079
|
|
New
Albany
|
|
|
1,250,111
|
|
|
13,485,397
|
|
|
16,143,356
|
|
|
8,488,834
|
|
Other
|
|
|
3,449,129
|
|
|
1,232,308
|
|
|
3,556,327
|
|
|
4,047,089
|
|
Drilling
and development of oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
14,571,159
|
|
|
10,337,497
|
|
|
22,088,181
|
|
|
22,127,354
|
|
New
Albany
|
|
|
3,988,899
|
|
|
307,421
|
|
|
3,050,097
|
|
|
9,422
|
|
Other
|
|
|
908,678
|
|
|
2,784,404
|
|
|
2,561,400
|
|
|
321,416
|
|
Infrastructure
properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
6,321,732
|
|
|
6,334,665
|
|
|
12,035,440
|
|
|
6,523,298
|
|
New
Albany
|
|
|
276,234
|
|
|
-
|
|
|
1,934,415
|
|
|
105,770
|
|
Other
|
|
|
10,288
|
|
|
18,785
|
|
|
378,566
|
|
|
-
|
|
Acquisitions
of oil and natural gas properties
|
|
|
-
|
|
|
23,967,283
|
|
|
24,011,335
|
|
|
-
|
|
Acquisitions/additions
to pipeline, property and equipment
|
|
|
356,288
|
|
|
3,787,922
|
|
|
4,111,780
|
|
|
4,523,706
|
|
Additions
to other property and equipment
|
|
|
2,653,132
|
|
|
1,749,057
|
|
|
855,070
|
|
|
485,741
|
|
Subtotal
of capital expenditures
|
|
|
34,701,334
|
|
|
68,501,138
|
|
|
97,863,981
|
|
|
52,379,709
|
|
Sale
of oil and natural gas properties
|
|
|
(1,024,663
|
)
|
|
(6,990,681
|
)
|
|
(11,489,456
|
)
|
|
(11,504,428
|
)
|
Other,
net
|
|
|
(1,659,762
|
)
|
|
(13,096
|
)
|
|
(56,788
|
)
|
|
(36,314
|
)
|
Net
cash acquired in merger
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(957,020
|
)
|
Subtotal
of capital divestitures
|
|
|
(2,684,425
|
)
|
|
(7,003,777
|
)
|
|
(11,546,244
|
)
|
|
(12,497,762
|
)
|
Total
|
|
$
|
32,016,909
|
|
$
|
61,497,361
|
|
$
|
86,317,737
|
|
$
|
39,881,947
|
|
Financing
activities
Cash
flows provided by financing activities were $25.6 million in the Current Period
compared to $49.5 million in the Prior Year Period. Cash flows provided in
the
Current Period included: (1) $26.0 million of senior secured credit borrowing;
and (2) $5.3 million of short-term bank borrowings. Cash flows used in the
Current Period included: (1) pay-down of $4.5 within short-term bank borrowings;
(2) pay-down of $1.0 million in senior credit borrowings; (3) pay-down of $0.2
million in mortgage obligations; and (3) payment of $0.2 million in financing
fees.
Cash
flows provided by financing activities in the Prior Year Period included: (1)
$40.0 million of senior secured credit borrowing; (2) $18.1 million of net
proceeds received from exercise of common stock options and warrants; and (3)
$0.8 million in short-term borrowings. Cash flows used by financing in the
Prior
Year Period included: (1) net pay-down of $7.0 million within short-term bank
borrowings; (2) payments of $2.4 million in financing fees; and (3) pay-down
of
$0.1 million within mortgage obligations and other.
Cash
flows provided by financing activities were $73.8 million in 2006 compared
to
$49.1 million in 2005. Cash flows provided in 2006 included: 1) $60.0 million
of
senior secured credit borrowing, of which, $27.6 million was paid directly
for
the Hudson acquisition; 2) $54.5 million of proceeds from public equity
offering; and 3) $17.6 million of net proceeds received from exercise of common
stock options and warrants and rescission of certain officer exercised stock
options. Cash flows used in 2006 included: 1) net pay-down of $5.8 in short-term
bank borrowings; 2) $50.0 million pay-down of the senior secured credit
facility; 3) pay-down of $0.1 million in mortgage obligations; and 4) payment
of
$2.5 million in financing fees.
Cash
flows provided by financing activities in 2005 included: 1) $14.7 million of
proceeds received from sales of common stock; 2) $30.0 million of mezzanine
borrowing; 3) $2.9 million of mortgage obligation to purchase office space;
and
4) $5.8 million of net short-term bank borrowings. Cash flows used by financing
in 2005 included: 1) pay-off of $2.9 million of certain related-party notes;
2)
distributions of $0.8 million to minority interest members for their
proportionate share of the El Paso sale proceeds; and 3) pay-down of $0.5
million in financing fees.
RECENT
ACCOUNTING PRONOUNCEMENTS
The
following is a summary of recent accounting pronouncements issued in 2007.
We do
not expect any of such recently issued accounting pronouncements to have a
material effect on our consolidated financial position or results of
operations.
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.
CRITICAL
ACCOUNTING POLICIES
Our
consolidated financial statements are prepared in accordance with accounting
principles generally accepted in the United States of America. The reported
financial results and disclosures were determined using the significant
accounting policies, practices and estimates described in the notes to the
consolidated financial statements. We believe that the reported financial
results are reliable and the ultimate actual results will not differ materially
from those reported. Uncertainties associated with the methods, assumptions
and
estimates underlying our critical accounting measurements are discussed
below.
Use
of Estimates
The
preparation of consolidated financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Significant estimates underlying these 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.
Oil
and Gas Properties
The
Company utilizes the full cost method of accounting for oil and natural gas
properties. Under this method, subject to a limitation based on estimated value,
all costs associated with property acquisition, exploration, and development
activities of oil and natural gas, including costs of unsuccessful exploration
and overhead charges directly related to acquisition, exploration, and
development activities, are capitalized. The Company is currently participating
in oil and natural gas exploration and development projects in the Antrim shale
of Michigan and the New Albany shale of southern Indiana and western Kentucky.
Thus, all capitalized costs of oil and natural gas properties considered proven,
are amortized on the unit-of-production method using estimates of proven
reserves. No gain or loss is recognized upon the sale or abandonment of
undeveloped or producing oil and natural gas properties unless the sale
represents a significant portion of oil and natural gas properties and the
gain
or loss significantly alters the relationship between capitalized costs and
proven reserves.
Capitalized
costs of oil and natural gas properties may not exceed an amount equal to the
present value, discounted at 10%, of estimated future net revenues from proven
reserves plus the lower of cost or fair value of unproven properties. Should
capitalized costs exceed this ceiling, an impairment is recognized. The present
value of estimated future net cash flows is computed by applying year-end prices
of oil and natural gas to estimated future production of proved oil and natural
gas reserves as of year end less estimated future expenditures to be incurred
in
developing and producing the proved reserves and assuming continuation of
existing economic conditions.
Oil
and Gas Reserves
Our
estimates of oil and natural gas reserves, by necessity, are projections based
on geological and engineering data, and there are uncertainties inherent in
the
interpretation of such data, as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering
is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is
a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and
natural gas reserves and future net cash flows necessarily depend upon a number
of variable factors and assumptions, such as historical production from the
area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs, and workover and remedial costs, all of which may, in fact,
vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to
any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected from there
may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect
the
carrying value of our oil and natural gas properties and/or the rate of
depletion of the oil and natural gas properties. Actual production, revenues,
and expenditures with respect to our reserves will likely vary from estimates,
and such variances may be material.
Many
factors will affect actual net cash flows, including the following: the amount
and timing of actual production; supply and demand for natural gas; curtailments
or increases in consumption by natural gas purchasers; and changes in
governmental regulations or taxation.
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.
For
the
year ended December 31, 2006, the Company recorded stock-based compensation
of
$2,663,814 under the 2006 Stock Incentive Plan and 1997 Stock Option Plan,
as
well as a certain employment agreement. Of that amount, $2,206,801 has been
included in general and administrative expense on the consolidated statement
of
operations and $457,013 has been capitalized in oil and natural gas properties.
The impact on future net income is estimated to be $3,411,000 recognized over
the applicable requisite service period of approximately 3 years.
Income
Taxes
The
Company has adopted the provisions of Statement of Financial Accounting
Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under the
asset and liability method of SFAS No. 109, deferred tax assets and liabilities
are recognized for future tax consequences attributable to the differences
between the consolidated financial statement carrying amounts of existing assets
and liabilities and their respective tax bases and operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured using enacted
income tax rates to apply to taxable income in the years in which those
differences are expected to be recovered or settled. Under SFAS No. 109, the
effect on deferred tax assets and liabilities of a change in income tax rates
is
recognized in the results of operations in the period that includes the
enactment date. At December 31, 2006, the Company had approximately $34.3
million of net operating loss carryforwards which expire between 2010 and
2026.
SIGNIFICANT
ACCOUNTING PRINCIPLES RELATING TO THE MERGER
As
a
result of the reverse merger, we were required to conform certain of Cadence’s
accounting principles to the accounting principles used by Aurora prior to
the
merger. This was required because Aurora was considered to be the accounting
acquirer. Our financial statements for the year ended December 31, 2005
were prepared using these accounting principles. A summary of these accounting
principles is as follows:
|
·
|
Aurora
is treated as the acquirer in the merger for accounting purposes,
and
accordingly, reverse acquisition accounting is applied to the business
combination.
|
|
·
|
We
measured the cost of the business acquired in the merger by reference
to
the fair value of the target’s securities (i.e., shares of Cadence common
stock, including outstanding options and warrants to purchase such
shares)
at the date of the merger agreement, January 31, 2005. The fair value
was determined to be approximately
$41,500,000.
|
|
·
|
We
uniformly apply the full cost method to all of our oil and natural
gas
operations. Accordingly, the consolidated financial statements include
a
net upward adjustment to the Cadence assets in the amount of $774,912
to
capitalized costs previously expensed by Cadence under the successful
efforts method. This increased capitalized costs was used to recalculate
depreciation on the new asset base.
|
|
·
|
In
accounting for stock-based compensation for the year ended
December 31, 2005, we continued to use the intrinsic value method
under APB Opinion 25. For the year ending December 31, 2006, we will
use FAS No. 123(R). Aurora stock options outstanding as of the
date of the merger are not accounted for under APB Opinion 25 or
FAS 123 because these options were fully vested at the time of the
merger. Their fair value was included in the cost of the business
acquired, as discussed above.
|
OFF
BALANCE SHEET ARRANGEMENTS
We
have
no special purpose entities, financing partnerships, guarantees, or off-balance
sheet arrangements other than the outstanding letter of credits totaling $1.1
million discussed in Note 9 “Commitments and Contingencies” of our unaudited
condensed consolidated financial statements for the six months ended June 30,
2007, and 2006.
BUSINESS
GENERAL
We
are a
growing independent energy company focused on the exploration, exploitation,
and
development of unconventional natural gas reserves. Our unconventional natural
gas projects target shale plays where large acreage blocks can be easily
evaluated with a series of low cost test wells. Shale plays tend to be
characterized by high drilling success and relatively low drilling costs when
compared to conventional exploration and development plays. Our project areas
are focused in the Antrim shale of Michigan and New Albany shale of Southern
Indiana and Western Kentucky.
We
commenced operations in 1969 to explore and mine natural resources under the
name Royal Resources, Inc. In July 2001, we reorganized our business to pursue
oil and natural gas exploration and development opportunities and changed our
name to Cadence Resources Corporation. We acquired Aurora Energy, Ltd.
("Aurora") on October 31, 2005 through the merger of our wholly-owned subsidiary
with and into Aurora. The acquisition of Aurora was accounted for as a reverse
merger, with Aurora being the acquiring party for accounting purposes. The
Aurora executive management team also assumed management control at the time
the
merger closed, and we moved our corporate offices to Traverse City,
Michigan.
Our
strategy is to maximize shareholder value by leveraging our significant acreage
position and the experience of our management and technical teams in finding
and
developing natural gas reserves to profitably grow our reserves and production.
Over the last several years we have focused primarily on the acquisition of
properties in the Antrim and New Albany shale. As an early stage developer
of
properties, we anticipate reserve growth will be our initial focus followed
by a
more traditional balance between reserve and production growth.
OPERATING
AREAS
Antrim
shale
Our
Antrim shale properties are located in Michigan and represent our primary area
of development over the next 12 months. Nearly all of our development operations
in this play/trend are focused on unconventional shale plays. Shale development
typically results in higher drilling success and lower drilling costs when
compared to conventional exploration and development activity.
Antrim
shale underlies the entire Michigan basin. The shale is very thick (140 to
over
200 feet) and has a high percentage of organic content (up to 20%). Due to
the
makeup of the natural fractures in the Antrim shale, production will vary from
well to well.
The
productive, fractured trend for the Antrim shale runs across the northern
portion of the Michigan basin from Lake Huron to Lake Michigan (160 miles).
Gas
wells have been drilled and produced in the Antrim shale from depths of 250
feet
down to 1,500 feet below the surface. A high percentage of the wells drilled
in
the Antrim shale have been put into production and levels of production vary
from well to well. Over 9,000 wells are currently producing in the Antrim shale.
In recent years, 200 to 400 wells have been drilled annually by all operators
in
the Antrim shale.
The
gas
produced from the Antrim shale is primarily a biogenic gas due to the presence
of microbes in the low to medium saline waters. The low-density pay zones in
the
Antrim shale are over 100 feet thick. Methane gas is continuously being
generated by anaerobic bacteria that feed on C02 organic material, and the
heavier oil and gases stored in the shale.
The
Antrim shale gas adsorbs to organic material in a manner similar to gas in
coal
seams. Water in the natural fractures of the shale provides a trapping mechanism
to hold the gas in place. As the water is produced, lowering the fluid and
pressure in the reservoir, gases are released from the organic material and
are
produced to the surface. At depths of less than 1,500 feet, the gas-in-place
is
typically 90% methane or greater, with the balance being C02 and some heavier
gases.
The
oldest Antrim shale gas field was drilled in the 1940s, and it is still in
production today. The production curve for the shale typically contains a peak
rate of gas occurring after the first two years of production when the shale
reservoir has been thoroughly dewatered. Peak rate production usually continues
for some time. After the water is taken from the formation and the gas is able
to fully release from the shale into the well bore, the rate of production
will
typically begin to decline 2% to 7% per year.
We
have
identified the Michigan Antrim shale as an area with natural fractures using
a
variety of diagnostic tests, including a review of production trends, fracture
imaging logs and geological mapping. In management's opinion, based upon
performance information from over 9,000 wells with comparable geologic
characteristics, areas with natural fractures in shale have compelling
production potential.
At
June
30, 2007, we owned working interests in 528 (270 net) Antrim wells. For the
six
months ended June 30, 2007, we drilled or participated in 29 (13 net) wells
with
a 92% success rate. In 2006, we drilled 173 (98 net) Antrim wells and
successfully completed 164 gross wells for a success rate of 95%. On average,
our Antrim wells are drilled to depths ranging from 250 to 1,500 feet targeting
reserves of 0.513 bcfe per well based upon to our December 31, 2006,
Schlumberger reserve report.
New
Albany shale
Our
New
Albany shale properties are located in Southern Indiana and Western Kentucky
and
represent a relatively new area of activity for us. Most of our exploratory
and
developmental operations in the Illinois geological basin are focused on
unconventional shale plays. The New Albany shale play, much of which is located
in Indiana, is an emerging play with similar characteristics to the Antrim
shale
play. It is also very thick (100 to over 200 feet) and covers approximately
6,000,000 gross acres, with proven producing pay zones throughout. The shale
is
capped by the Borden shale, a very thick, dense, gray-green shale.
In
the
New Albany shale, a well commonly produces water along with the gas. In the
early 1900's, it was learned that a simple open-hole completion in the very
top
of the shale would yield commercial gas wells that would last for many years,
even while producing some water. Vertical fractures in the shale feed the gas
flow at the top of the shale. The potential of these wells was seldom realized
in the early to mid-twentieth century, as the production systems for handling
the associated water were limited. However, with current technology, the water
can be dealt with cost effectively and allow for better rates of gas
production.
Significant
research and study has been conducted to evaluate the producibility of the
New
Albany shale. In cooperation with the Gas Research Institute, we combined
resources and data with 11 other industry partners in a shale gas producibility
consortium lasting almost two years (concluded in 1999). The consortium
identified critical differences and similarities of the New Albany shale play
to
other shale plays. The consortium study observed that the New Albany shale
reservoir contained high-angled (vertical or nearly so) natural fractures that
are open to unimpeded flow. The predominant fracture system is oriented
east-west with spacing between joints estimated to average five feet based
on
outcrop studies and production simulations. Based on this information, it was
concluded that increases in performance could be achieved with a horizontally
drilled well compared to a vertically drilled well in the same reservoir.
Reserve
studies were conducted on behalf of the consortium by Schlumberger Holditch
& Associates for both vertical producing wells and horizontal wells. Since
then, we have participated in approximately 30 pilot horizontal well drilling
projects across multiple counties which support the conclusions of the
consortium. With the data from these pilot wells, we have established a
development concept for the New Albany shale, which we began to implement in
2006.
Our
New
Albany shale projects are characterized by declining natural gas and water
production with peak natural gas and water flow rates occurring in the first
60
days. Our New Albany shale wells are drilled to depths ranging from 500 to
3,000
feet and based on our December 31, 2006, Schlumberger reserve report could
yield
an average reserve of 1.2 bcfe per well. At June 30, 2007, we owned working
interests in 50 (11.61 net) New Albany shale wells. For the six months ended
June 30, 2007, we drilled or participated in 16 (4.05 net) wells with a 100%
success rate. In 2006, we drilled 26 (7.49 net) New Albany shale wells and
successfully completed 25 of these wells for a success rate of 96%.
Drilling
techniques and natural gas processing
We
are
experienced at drilling both vertical and horizontal wells. In the Antrim,
our
first choice would typically be vertical drilling, although in some situations,
we may determine that horizontal drilling is preferred. Our drilling technique
in the New Albany shale continues to evolve as we seek to improve cost
containment and producibility. Horizontal drilling has become our development
method of first choice in the New Albany shale, primarily because of the high
angled natural fractures. We seek to maximize intersections of the east-west
natural fractures through horizontal drilling, as we believe that this will
optimize production results. Directional drilling with enhanced shale technology
fracturing helps test New Albany exploration areas for development
potential.
For
shale
gas wells, we generally use a production system that is designed to achieve
low
pressure on the wells, pipelines, facilities and reservoir. This is done by
keeping natural fractures open to the well bore and by using low-pressure gas
processing near well sites. Using this low-pressure production approach, we
seek
to increase the recoverability of shale gas production through lower down-hole
reservoir pressure enhancing dewatering and gas recovery.
In
the
Michigan Antrim, we use a simple proven completion procedure with industry
proven hydraulic fracturing technology. This procedure involves drilling through
several pay zones, setting and cementing casing, and drilling extended rat-hole,
which is used for gas-water separation. The wells are then hydraulically
fractured with a specifically designed fracture procedures incorporating
multiple stages with enhanced diversion methods to increase effective vertical
coverage. Imaging logs are used to identify which zones are best fractured
and
will yield commercial gas production. For horizontal New Albany shale wells,
no
stimulation has been required to date to make economic gas wells. In exploratory
areas of the New Albany and Antrim, shale log analysis is incorporated to
enhance fracturing and completion design.
In
order
to contain costs, we try to keep facilities for gas processing decentralized.
Salt water disposal wells are drilled close to the compression facilities,
near
to each field's wells. Skid mounted separators that can be easily upgraded
or
downsized are used at the site of the salt water disposal wells. The localized
disposal of water reduces power demand. Different reservoirs contain different
amounts of water. We cannot accurately predict the actual amount of time
required for dewatering with respect to each well. The period of time during
which the gas production rate is limited by the dewatering process could be
as
much as two years, thereby delaying peak revenue production.
We
use
skid mounted compressors in a series to maximize compression efficiencies from
the well to the transportation line. We also seek to maintain low pressure
in
the gathering systems. Gas is usually drawn at low wellhead pressure using
a
five and one-half inch or seven inch production casing and up to 12-inch
polypipe.
One
strategy we use to minimize costs is to minimize the use of land surface. This
is accomplished by using small well sites in open areas near roads, and by
not
building central processing facilities, but instead using localized facilities
as described above. We continue to explore innovations in technology and
methodologies that will reduce production costs and increase efficiencies.
We
may use other drilling, completion and operating procedures than those described
above if, in our opinion, alternative procedures will generate higher returns.
Our
wells
are drilled by outside drilling companies. We believe that there is currently
enough capacity available in the areas in which we are working that we will
not
have a problem finding one or more drilling companies available to meet our
time
schedule for drilling wells. However, over time, circumstances could change
as
development activity in the industry accelerates.
Oil
and natural gas reserves
The
following table presents information as of December 31, 2006 with respect to
our
estimated proved reserves. Estimates of our future net revenues from proved
reserves are discounted to present value using an annual discount rate of 10%
(PV-10), using oil and natural gas prices in effect as of the dates of such
estimates, held constant throughout the life of the properties. The information
presented is based on a reserve report prepared by Data & Consulting
Services Division of Schlumberger Technology Corporation ("Schlumberger").
According to this report, approximately 46% of our proved reserves are
classified as either proved developed non-producing or proved
undeveloped.
|
|
As
of December 31, 2006
|
|
Oil
and Natural Gas Reserves(a)
|
|
Oil
|
|
Gas
|
|
Total
|
|
PV-10(d)
|
|
Standardized
Measure(e)
|
|
|
|
(mbbls)
|
|
(mmcf)
|
|
(mmcfe)
|
|
(In
thousands)
|
|
(In
thousands)
|
|
Proved
developed producing
|
|
|
54
|
|
|
82,580
|
|
|
82,904
|
|
$
|
97,553
|
|
$
|
76,952
|
|
Proved
developed non-producing
|
|
|
-
|
|
|
22,693
|
|
|
22,693
|
|
|
28,428
|
|
|
19,238
|
|
Proved
undeveloped
|
|
|
27
|
|
|
47,691
|
|
|
47,853
|
|
|
32,802
|
|
|
34,272
|
|
Total
proved (b) (c)
|
|
|
81
|
|
|
152,964
|
|
|
153,450
|
|
$
|
158,783
|
|
$
|
130,462
|
|
Oil
and Natural Gas Reserves by Play/Trend(a)
|
|
Total
|
|
Percent
of Proved Reserves
|
|
PV-10
|
|
|
|
(mmcfe)
|
|
|
|
(In
thousands)
|
|
Antrim
|
|
|
150,107
|
|
|
98
|
%
|
$
|
152,427
|
|
New
Albany
|
|
|
2,298
|
|
|
1
|
%
|
|
2,977
|
|
Other
|
|
|
1,045
|
|
|
1
|
%
|
|
3,379
|
|
Total
|
|
|
153,450
|
|
|
100
|
%
|
$
|
158,783
|
|
Change
in reserve quantity information for the year ended December 31,
2006(a)
|
|
Oil
|
|
Gas
|
|
Total
|
|
|
|
(mbbls)
|
|
(mmcf)
|
|
(mmcfe)
|
|
Proved
reserves as of December 31, 2005
|
|
|
99
|
|
|
63,322
|
|
|
63,916
|
|
Revisions
of previous estimates
|
|
|
(40
|
)
|
|
4,880
|
|
|
4,640
|
|
Purchases
of minerals in place
|
|
|
-
|
|
|
22,843
|
|
|
22,843
|
|
Extensions
and discoveries
|
|
|
45
|
|
|
65,095
|
|
|
65,365
|
|
Production
|
|
|
(23
|
)
|
|
(2,511
|
)
|
|
(2,649
|
)
|
Sales
of minerals in place
|
|
|
-
|
|
|
(665
|
)
|
|
(665
|
)
|
Proved
reserves as of December 31, 2006
|
|
|
81
|
|
|
152,964
|
|
|
153,450
|
|
(a)
|
The
information presented for reserves is based on reserve reports prepared
by
Schlumberger. Consistent with Schlumberger's standard engineering
practices, these reports and such reserves excluded the impact of
financial hedges.
|
(b)
|
Proved
reserves are those quantities of gas which, by analysis of geological
and
engineering data, can be estimated with reasonable certainty to be
commercially recoverable from known reservoirs and under current
economic
conditions, operating methods, and government regulations.
|
(c)
|
Developed
reserves are expected to be recovered from existing wells. Undeveloped
reserves are expected to be recovered: (i) from new wells on undrilled
acreage; (ii) from deepening existing wells to a different reservoir;
or
(iii) where relatively large expenditure is required to recomplete
an
existing well or install production or transportation facilities
for
primary or improved recovery
projects.
|
(d)
|
Represents
the present value, discounted at 10% per annum (PV-10), of estimated
future net revenue before income tax of our estimated proven reserves.
The
estimated future net revenues were determined by using reserve quantities
of proved reserves and the periods in which they are expected to
be
developed and produced based on economic conditions prevailing at
December
31, 2006. The estimated future production is priced at December 31,
2006,
without escalation, using $57.81 per bbl and $5.84 per mmbtu, in
each case
adjusted by lease for transportation fees and regional price
differentials. PV-10 is a non-GAAP financial measure because it excludes
income tax effects. Management believes that the presentation of
the
non-GAAP financial measure of PV-10 provides useful information because
it
is widely used by professional analysts and sophisticated investors
in
evaluating oil and natural gas companies. PV-10 is not a measure
of
financial or operating performance under GAAP. PV-10 should not be
considered as an alternative to the standardized measure as defined
under
GAAP. We have included a reconciliation of PV-10 to the most directly
comparable GAAP measure - standardized measure of discounted future
net
cash flow - in the following table:
|
|
|
As
of December 31,
|
|
|
|
2006
|
|
2005
|
|
Standardized
measure of discounted future net cash flows
|
|
$
|
130,461,821
|
|
$
|
152,868,240
|
|
Add:
Present value of future income tax discounted at 10%
|
|
|
28,320,989
|
|
|
46,639,204
|
|
PV-10
|
|
$
|
158,782,810
|
|
$
|
199,507,444
|
|
(e)
|
The
standardized measure represents the present value of estimated future
cash
inflows from proved oil and natural gas reserves, less future development,
abandonment, production and income tax expenses, discounted at 10%
per
annum to reflect timing of future cash flows and using the same pricing
assumptions as were used to calculate PV-10. Standardized measure
differs
from PV-10 because standardized measure includes the effect of future
income taxes. As noted in footnote (a) above, this excludes the impact
of
our hedges.
|
Management
uses future net revenue, which is calculated without deducting estimated future
income tax expense, and the present value thereof as one measure of the value
of
our current proved reserves and to compare relative values among peer companies
without regard to income taxes. We also understand that securities analysts
use
this measure in similar ways.
Acreage
The
following table sets forth as of June 30, 2007, the gross and net acres of
both
developed and undeveloped oil and gas leases which we hold. "Gross" acres are
the total number of acres in which we own a working interest. "Net" acres refer
to gross acres multiplied by our fractional working interest. Acreage numbers
do
not include our options to acquire additional leaseholds which have not been
exercised.
|
|
Developed(a)
|
|
Undeveloped(b)
|
|
Total
|
|
Play/Trend
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Antrim
|
|
|
82,278
|
|
|
43,824
|
|
|
211,572
|
|
|
112,693
|
|
|
293,850
|
|
|
156,517
|
|
New
Albany
|
|
|
10,560
|
|
|
3,133
|
|
|
876,581
|
|
|
452,927
|
|
|
887,141
|
|
|
456,060
|
|
Other
|
|
|
1,313
|
|
|
1,062
|
|
|
130,027
|
|
|
105,060
|
|
|
131,340
|
|
|
106,122
|
|
Total
|
|
|
94,151
|
|
|
48,019
|
|
|
1,218,180
|
|
|
670,680
|
|
|
1,312,331
|
|
|
718,699
|
|
(a)
|
Developed
refers to the number of acres which are allocated or assignable to
producing wells or wells capable of production. Developed acreage
includes
acreage having wells shut-in awaiting the addition of
infrastructure.
|
(b)
|
Undeveloped
refers to lease acreage on which wells have not been developed or
completed to a point that would permit the production of commercial
quantities of oil or natural gas regardless of whether such acreage
contains proved reserves.
|
Production
and price information
The
following table summarize sales volumes, sales prices, and production cost
information for the periods indicated:
|
|
Six
Months
Ended
June 30,
|
|
Year
Ended December 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
Oil
(bbls)
|
|
|
13,772
|
|
|
22,588
|
|
|
10,628
|
|
Natural
gas (mcf)
|
|
|
1,410,820
|
|
|
2,517,897
|
|
|
687,271
|
|
Natural
gas equivalent (mcfe)
|
|
|
1,493,453
|
|
|
2,653,427
|
|
|
751,039
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$
|
784,991
|
|
$
|
1,399,445
|
|
$
|
558,455
|
|
Natural
gas sales
|
|
|
11,747,014
|
|
|
20,192,366
|
|
|
6,184,989
|
|
Total
|
|
$
|
12,532,005
|
|
$
|
21,591,811
|
|
$
|
6,743,444
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price (including realized gains or losses from
hedging)
|
|
|
|
|
|
|
|
|
|
|
Oil
($ per bbl)
|
|
$
|
57.00
|
|
$
|
61.95
|
|
$
|
52.54
|
|
Natural
gas ($ per mcf)
|
|
|
8.33
|
|
|
8.02
|
|
|
9.00
|
|
Natural
gas equivalent ($ per mcfe)
|
|
|
8.39
|
|
|
8.14
|
|
|
8.98
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
production expenses ($ per mcfe)
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
$
|
0.38
|
|
$
|
0.33
|
|
$
|
0.67
|
|
Post-production
expenses
|
|
|
0.54
|
|
|
0.55
|
|
|
0.50
|
|
Leasing
operating expenses
|
|
|
2.23
|
|
|
1.82
|
|
|
1.62
|
|
Total
|
|
$
|
3.15
|
|
$
|
2.70
|
|
$
|
2.79
|
|
Productive
wells
The
following table sets forth as of June 30, 2007, information relating to the
productive wells in which we owned a working interest. Productive wells consist
of producing wells and wells capable of production, including natural gas wells
awaiting pipeline connections to commence deliveries and oil wells awaiting
connection to production facilities. Gross wells are the total number of
productive wells in which we have an interest, and net wells are the sum of
our
fractional working interests owned in gross wells.
|
|
Natural
Gas
|
|
Oil
|
|
Play/Trend
|
|
Gross
Wells
|
|
Net
Wells
|
|
Gross
Wells
|
|
Net
Wells
|
|
Antrim
|
|
|
528
|
|
|
270.34
|
|
|
-
|
|
|
-
|
|
New
Albany
|
|
|
50
|
|
|
11.61
|
|
|
-
|
|
|
-
|
|
Other
|
|
|
9
|
|
|
7.24
|
|
|
29
|
|
|
13.97
|
|
Total
|
|
|
587
|
|
|
289.19
|
|
|
29
|
|
|
13.97
|
|
Drilling
activities
The
following table sets forth information with respect to wells drilled and
completed during the periods indicated. The information should not be considered
indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled,
quantities of reserves found or economic value. Productive wells are those
that
produce commercial quantities of hydrocarbons, whether or not they produce
a
reasonable rate of return.
|
|
Gross
Wells
|
|
Net
Wells
|
|
Type
of Well
|
|
Productive
(b)
|
|
Dry
(c)
|
|
Total
|
|
Productive
(b)
|
|
Dry
(c)
|
|
Total
|
|
Six
Months Ended 06/30/07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
New
Albany
|
|
|
7
|
|
|
-
|
|
|
7
|
|
|
3.60
|
|
|
-
|
|
|
3.60
|
|
Other
|
|
|
7
|
|
|
4
|
|
|
11
|
|
|
6.48
|
|
|
3.10
|
|
|
9.58
|
|
Total
|
|
|
14
|
|
|
4
|
|
|
18
|
|
|
10.08
|
|
|
3.10
|
|
|
13.18
|
|
Development
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
28
|
|
|
1
|
|
|
29
|
|
|
11.94
|
|
|
1.00
|
|
|
12.94
|
|
New
Albany
|
|
|
9
|
|
|
-
|
|
|
9
|
|
|
0.45
|
|
|
-
|
|
|
0.45
|
|
Other
|
|
|
2
|
|
|
-
|
|
|
2
|
|
|
1.45
|
|
|
-
|
|
|
1.45
|
|
Total
|
|
|
39
|
|
|
1
|
|
|
40
|
|
|
13.84
|
|
|
1.00
|
|
|
14.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended 12/31/06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
2
|
|
|
-
|
|
|
2
|
|
|
2.00
|
|
|
-
|
|
|
2.00
|
|
New
Albany
|
|
|
13
|
|
|
1
|
|
|
14
|
|
|
6.39
|
|
|
0.50
|
|
|
6.89
|
|
Other
|
|
|
1
|
|
|
3
|
|
|
4
|
|
|
0.38
|
|
|
1.25
|
|
|
1.63
|
|
Total
|
|
|
16
|
|
|
4
|
|
|
20
|
|
|
8.77
|
|
|
1.75
|
|
|
10.52
|
|
Development
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
162
|
|
|
9
|
|
|
171
|
|
|
91.53
|
|
|
4.93
|
|
|
96.46
|
|
New
Albany
|
|
|
12
|
|
|
-
|
|
|
12
|
|
|
0.60
|
|
|
-
|
|
|
0.60
|
|
Other
|
|
|
6
|
|
|
-
|
|
|
6
|
|
|
3.95
|
|
|
-
|
|
|
3.95
|
|
Total
|
|
|
180
|
|
|
9
|
|
|
189
|
|
|
96.08
|
|
|
4.93
|
|
|
101.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended 12/31/05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
0.20
|
|
|
0.20
|
|
|
0.40
|
|
New
Albany
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Other
|
|
|
3
|
|
|
-
|
|
|
3
|
|
|
1.17
|
|
|
-
|
|
|
1.17
|
|
Total
|
|
|
4
|
|
|
1
|
|
|
5
|
|
|
1.37
|
|
|
0.20
|
|
|
1.57
|
|
Development
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
136
|
|
|
5
|
|
|
141
|
|
|
101.37
|
|
|
3.40
|
|
|
104.77
|
|
New
Albany
|
|
|
3
|
|
|
-
|
|
|
3
|
|
|
0.15
|
|
|
-
|
|
|
0.15
|
|
Other
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
|
|
|
139
|
|
|
5
|
|
|
144
|
|
|
101.52
|
|
|
3.40
|
|
|
104.92
|
|
(a)
|
An
exploratory well is a well drilled either in search of a new, as
yet
undiscovered, oil or natural gas reservoir or to greatly extend the
known
limits of a previously discovered reservoir. A development well is
a well
drilled within the presently proved productive area of an oil or
natural
gas reservoir, as indicated by reasonable interpretation of available
data, with the objective of being completed in that reservoir.
|
(b)
|
A
productive well is an exploratory or development well found to be
capable
of producing either oil or natural gas in sufficient quantities to
justify
completion as an oil or natural gas well.
|
(c)
|
A
dry well is an exploratory or development well that is not a producing
well or a well that has either been plugged or has been converted
to
another use.
|
Sale
of production
We
use
different strategies for gas sales depending on the location of the field and
the local markets. In some locations, we may use proprietary C0
2
reduction units to process our own gas and sell it to nearby local markets.
In
other cases, we connect to nearby high pressure transmission pipelines. We
are
not currently aware of any restraints with respect to pipeline availability
other than curtailments in existing pipelines that may occur from time to time
due to technical difficulties. However, because of the nature of natural gas
development, there may be periods of time when pipeline capacity is inadequate
to meet our transportation needs. It is often the case that as new development
comes on-line, pipelines are near or at capacity before new pipelines are built.
We
entered into a firm delivery gas contract to be effective for the period June
1,
2007, through December 31, 2008, for the delivery of 5,000 mmbtu per day. The
contract covers much of our existing Antrim production operated by us.
We
also
have five other base contracts for the sale of natural gas. We set our firm
delivery volume obligation under these contracts on a monthly basis, with the
amount of our obligation varying from month to month. As we bring new wells
on-line and our production volume increases, we will sell the new production
in
the spot markets or under the monthly base contracts. We expect that we will
usually sell in this fashion, partly through firm gas delivery contracts and
partly in the spot markets.
Prices
for oil and natural gas fluctuate fairly widely based on supply and demand.
Supply and demand are influenced by weather, foreign policy and industry
practices. Nonetheless, in light of historical fluctuations in prices, there
can
be no assurance at what price we will be able to sell our oil and natural gas.
It is possible that prices will be low at the time periods in which the wells
are most productive, thereby reducing overall returns.
Hedging
In
order
to reduce exposure to fluctuations in the price of natural gas, we will
periodically enter into financial arrangements with a major financial
institution. We have entered into a swap transaction in order to hedge a portion
of our production. The purpose of the swap is to provide a measure of stability
to our cash flow in meeting financial obligations while operating in a volatile
gas market environment. The swap reduces our exposure on the hedged volumes
to
decreases in commodity prices and limits the benefit we might otherwise receive
from any increases in commodity prices on the hedged volumes.
Other
properties
On
October 4, 2005, we purchased office space in the Copper Ridge Professional
Center Five, located in Traverse City, Michigan. Our unit contains approximately
14,645 square feet on the second floor of a three story building, plus common
areas and 15 covered parking spaces. We moved our corporate offices into this
space on December 5, 2005.
We
also
own non-oil and natural gas mineral rights in a number of properties, although
we do not presently consider them to be material to our business.
Employees
As
of
September 30, 2007, we had 79 full-time employees and 2 part-time employees.
We
are not a party to any collective bargaining agreements. We believe that our
relations with our employees are good.
Competition
and markets
We
face
competition from other oil and natural gas companies in all aspects of our
business, including acquisition of producing properties and oil and natural
gas
leases, marketing of oil and natural gas, and obtaining goods, services and
labor. Many of our competitors have substantially larger financial and other
resources than we have. Factors that affect our ability to acquire producing
properties include available funds, available information about prospective
properties and our limited number of employees. Gathering systems are the only
practical method for the intermediate transportation of natural gas. Therefore,
competition for natural gas delivery is presented by other pipelines and gas
gathering systems. Competition is also presented by alternative fuel sources,
including heating oil and other fossil fuels. Renewable energy sources may
become more competitive in the future.
The
availability of a ready market for and the price of any hydrocarbons produced
will depend on many factors beyond our control including, but not limited to,
the amount of domestic production and imports of foreign oil and liquefied
natural gas, the marketing of competitive fuels, the proximity and capacity
of
natural gas pipelines, the availability of transportation and other market
facilities, the demand for hydrocarbons, the effect of federal and state
regulation of allowable rates of production, taxation, the conduct of drilling
operations and federal regulation of natural gas. In addition, the restructuring
of the natural gas pipeline industry virtually eliminated the gas purchasing
activity of traditional interstate gas transmission pipeline buyers. Producers
of natural gas have therefore been required to develop new markets among gas
marketing companies, end users of natural gas and local distribution companies.
All of these factors, together with economic factors in the marketing arena,
generally may affect the supply of and/or demand for oil and natural gas and
thus the prices available for sales of oil and natural gas.
Regulatory
considerations
Proposals
and proceedings that might affect the oil and gas industry are periodically
presented to Congress, the Federal Energy Regulatory Commission ("FERC"), the
Minerals Management Service ("MMS"), state legislatures and commissions and
the
courts. We cannot predict when or whether any such proposals may become
effective. The natural gas industry is heavily regulated. There is no assurance
that the regulatory approach currently pursued by various agencies will continue
indefinitely. Notwithstanding the foregoing, we currently do not anticipate
that
compliance with existing federal, state and local laws, rules and regulations,
will have a material or significantly adverse effect upon our capital
expenditures, earnings or competitive position. No material portion of our
business is subject to renegotiation of profits or termination of contracts
or
subcontracts at the election of the federal government.
Our
operations are subject to various types of regulation at the federal, state
and
local levels. This regulation includes requiring permits for drilling wells,
maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells,
the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used or generated
in
connection with operations. Our operations are also subject to various
conservation laws and regulations. These include the regulation of the size
of
drilling and spacing units or proration units and the density of wells which
may
be drilled and the unitization or pooling of oil and natural gas properties.
In
addition, state conservation laws sometimes establish maximum rates of
production from oil and natural gas wells, generally prohibit the venting or
flaring of natural gas and impose certain requirements regarding the ratability
of production. The effect of these regulations may limit the amount of oil
and
natural gas we can produce from our wells in a given state and may limit the
number of wells or the locations at which we can drill.
Currently,
there are no federal, state or local laws that regulate the price for our sales
of natural gas, natural gas liquids, crude oil or condensate. However, the
rates
charged and terms and conditions for the movement of gas in interstate commerce
through certain intrastate pipelines and production area hubs are subject to
regulation under the Natural Gas Policy Act of 1978, as amended. Pipeline and
hub construction activities are, to a limited extent, also subject to
regulations under the Natural Gas Act of 1938, as amended. While these controls
do not apply directly to us, their effect on natural gas markets can be
significant in terms of competition and cost of transportation services, which
in turn can have a substantial impact on our profitability and costs of doing
business. Additional proposals and proceedings that might affect the natural
gas
and crude oil extraction industry are considered from time to time by Congress,
FERC, state regulatory bodies and the courts. We cannot predict when or if any
such proposals might become effective and their effect, if any, on our
operations. We do not believe that we will be affected by any action taken
in
any materially different respect from other crude oil and natural gas producers,
gatherers and marketers with whom we compete.
State
regulation of gathering facilities generally includes various safety,
environmental and in some circumstances, nondiscriminatory take requirements.
This regulation has not generally been applied against producers and gatherers
of natural gas to the same extent as processors, although natural gas gathering
may receive greater regulatory scrutiny in the future.
Our
oil
and natural gas production and saltwater disposal operations and our processing,
handling and disposal of hazardous materials, such as hydrocarbons and naturally
occurring radioactive materials ("NORM") are subject to stringent environmental
regulation. Compliance with environmental regulations is generally required
as a
condition to obtaining drilling permits. State inspectors frequently inspect
regulated facilities and review records required to be maintained for document
compliance. We could incur significant costs, including cleanup costs resulting
from a release of hazardous material, third-party claims for property damage
and
personal injuries, fines and sanctions, as a result of any violations or
liabilities under environmental or other laws. Changes in or more stringent
enforcement of environmental laws could also result in additional operating
costs and capital expenditures.
Various
federal, state and local laws regulating the discharge of materials into the
environment, or otherwise relating to the protection of the environment,
directly impact oil and natural gas exploration, development and production
operations, and consequently may impact our operations and costs. These
regulations include, among others, (i) regulations by the Environmental
Protection Agency ("EPA"), and various state agencies regarding approved methods
of disposal for certain hazardous and non-hazardous wastes; (ii) the
Comprehensive Environmental Response, Compensation and Liability Act, and
analogous state laws, which regulate the removal or remediation of previously
disposed wastes (including wastes disposed of or released by prior owners or
operators), property contamination (including groundwater contamination), and
remedial plugging operations to prevent future contamination; (iii) the Clean
Air Act and comparable state and local requirements, which may require certain
pollution controls with respect to air emissions from our operations; (iv)
the
Oil Pollution Act of 1990 which contains numerous requirements relating to
the
prevention of and response to oil spills into waters of the United States;
(v)
the Resource Conservation and Recovery Act, which is the principal federal
statute governing the treatment, storage and disposal of hazardous wastes;
and
(vi) state regulations and statutes governing the handling, treatment, storage
and disposal of NORM.
A
permit
from the EPA and the Michigan Department of Environmental Quality or a state
regulatory agency (Indiana) must be obtained before we may drill a salt water
disposal well. The amount of time required to obtain such a permit varies from
state to state, but can take as much as six or more months in Michigan. Since
many gas wells can only be produced if a salt water disposal well is available,
the salt water disposal well permit requirement may delay the commencement
of
production.
In
the
course of our routine oil and natural gas operations, surface spills and leaks,
including casing leaks of oil or other materials may occur, and we may incur
costs for waste handling and environmental compliance. It is also possible
that
our oil and natural gas operations may require us to manage NORM. NORM is
present in varying concentrations in sub-surface formations, including
hydrocarbon reservoirs, and may become concentrated in scale, film and sludge
in
equipment that comes in contact with crude oil and natural gas production and
processing streams. Some states, including Michigan and Texas, have enacted
regulations governing the handling, treatment, storage and disposal of NORM.
Moreover, we are able to control directly the operations of only those wells
for
which we act as the operator. Despite our lack of control over wells owned
by us
but operated by others, the failure of the operator to comply with the
applicable environmental regulations may, in certain circumstances, be
attributed to us under applicable state, federal or local laws or
regulations.
We
believe that we are in substantial compliance with all currently applicable
environmental laws and regulations. To date, compliance with such laws and
regulations has not required the expenditure of any material amount of money,
and we do not currently anticipate that future compliance with environmental
laws will have a materially adverse effect on our consolidated financial
position or results of operations. Since these laws and regulations are
periodically amended, however, we are unable to predict the ultimate cost of
compliance. To our knowledge, there are currently no material adverse
environmental conditions that exist on any of our properties and there are
no
current or threatened actions or claims by any local, state or federal agency,
or by any private landowner against us pertaining to such a condition. Further,
we are not aware of any currently existing condition or circumstance that may
give rise to such actions or claims in the future.
MANAGEMENT
The
following table sets forth the name, age, and position of each of our executive
officers and directors.
Name
|
|
Age
|
|
Position(s)
with the Company
|
William
W. Deneau
|
|
63
|
|
Director,
Chairman and Chief Executive Officer
|
Ronald
E. Huff
|
|
52
|
|
Director,
President and Chief Financial Officer
|
John
V. Miller, Jr.
|
|
49
|
|
Vice
President, Business and Corporate Development
|
John
C. Hunter
|
|
56
|
|
Vice
President, Exploration and Production
|
Thomas
W. Tucker
|
|
65
|
|
Vice
President, Exploration (retired effective 06/30/07)
|
Richard
M. Deneau
|
|
61
|
|
Director
|
Gary
J. Myles
|
|
62
|
|
Director
|
Wayne
G. Schaeffer
|
|
61
|
|
Director
|
Kevin
D. Stulp
|
|
51
|
|
Director
|
Earl
V. Young
|
|
66
|
|
Director
|
Under
the
Company’s by-laws, the authorized number of directors is set at no fewer than
three and no more than ten directors. The Board of Directors currently has
seven
members. Each member of the Board of Directors serves for a term of one year
that expires at the following annual shareholders’ meeting. Each officer serves
at the pleasure of the Board of Directors and until a successor has been
qualified and appointed, except that the Company has entered into an employment
agreement with Ronald E. Huff to serve as the Chief Financial Officer of the
Company through June 18, 2008.
To
the
best of our knowledge, none of our Directors has been convicted in a criminal
proceeding, excluding traffic violations or similar misdemeanors, or has been
a
party to any judicial or administrative proceeding during the past five years,
except for matters that were dismissed without sanction or settlement, that
resulted in a judgment, decree, or final order enjoining the person from future
violations of, or prohibiting activities subject to, federal or state securities
laws, or a finding of any violation of federal or state securities
laws.
Set
forth
below is certain biographical information regarding each of our directors and
executive officers:
William
W. Deneau
has
served on our Board of Directors and as Chief Executive Officer and Chairman
of
the Board of Directors since November 1, 2005. Mr. Deneau also served as
President until May 30, 2007. Mr. Deneau became an employee of Aurora at the
time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora in
exchange for Aurora’s stock on April 22, 1997. Since April 1997, Mr. Deneau has
been responsible for managing Aurora’s affairs. He became a Director of Aurora
on June 25, 1997, and the President of Aurora on July 17, 1997, positions
he continues to hold. William W. Deneau is the brother of Richard M. Deneau,
another one of our Directors.
Ronald
E. Huff
has
served as our Chief Financial Officer since June 19, 2006 and as a Director
since November 21, 2005. Mr. Huff assumed additional responsibilities as
President effective May 30, 2007. From December 5, 2005, through June 18, 2006,
Mr. Huff served as Chairperson of our Audit Committee. He resigned from the
Audit Committee on June 18, 2006. From 2004 until he became our Chief Financial
Officer, Mr. Huff served as the Chief Financial Officer and Vice President
of
Finance for Visual Edge Technology, Inc., a California holding company engaged
in acquiring imaging companies. From 1999 to 2004, Mr. Huff was a Principal
and
Founder of TriMillennium Ventures, LLC, a private equity investment company.
From 1986 to 1999, Mr. Huff was an executive at Belden & Blake Corporation
serving as Chief Financial Officer and President of this large Appalachian
and
Michigan Basin exploration and production company.
John
V. Miller
has
served as a Vice President since November 1, 2005, holding positions variously
titled as Vice President of Exploration and Production, Vice President of
Science and Strategic Planning, and Vice President of Business and Corporate
Development. Mr. Miller became an employee of Aurora at the time he sold his
interest in Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora’s
stock on April 22, 1997. From April 1997 to the present, he has been the
Vice President responsible for overseeing exploration and development activities
for Aurora. From June 1997 through October 2005 he served as a Director of
Aurora.
John
C. Hunter
has
served as Vice President of Exploration and Production, since May 30, 2007.
Mr.
Hunter is a petroleum engineer with over thirty years of oil and gas experience.
He has worked for the Company since 2005 as Senior Petroleum Engineer. From
2004
to 2005, Mr. Hunter was Executive Vice President of Wellstream Energy Services
providing petroleum engineering consulting services. From 2000 to 2004, Mr.
Hunter was President of Terra Drilling Services, LLC and TerraFluids, LLC which
provides short radius horizontal drilling services as well as drilling and
completion fluids in the United States. From 1995 to 2004, Mr. Hunter was
Director of Exploitation of Torch Energy Advisors, Inc. located in Houston,
Texas where he managed a staff of 15 employees dedicated to the development
of
oil and natural gas properties.
Thomas
W. Tucker
served
as a Vice President from November 1, 2005, through his effective retirement date
of June 30, 2007, holding positions variously titled as Vice President of Land
Development, Vice President of Operations, and Vice President of Exploration.
Mr. Tucker became an employee of Aurora at the time he sold his interest in
Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora’s stock on
April 22, 1997. From April 1997 to June 30, 2007, he has been the Vice President
responsible for overseeing land development activities for Aurora. From June
1997 to October 2005 he served as a Director of Aurora. We have made
arrangements with Mr. Tucker to be available in a consulting capacity through
December 31, 2007, to assist us on various matters.
Richard
M. Deneau
has
served on our Board of Directors since November 21, 2005. Mr. Deneau served
as a
Director and President of Anchor Glass Container Corporation (“Anchor”) from
1997 until his retirement in 2004. He was also the Chief Operating Officer
of
Anchor from 1997 to 2002, and the Chief Executive Officer of Anchor from 2002
until his retirement. Anchor, which was publicly traded and listed on NASDAQ,
is
the third largest glass container manufacturer in the United States, with annual
revenues of about $750 million. When Richard M. Deneau joined Anchor, it
was a financially troubled company. He designed and implemented strategies
to
turn its financial performance around. One of the strategies involved a Chapter
11 bankruptcy filing in April, 2002. The purpose of this filing was to provide
assurance to a new investor that all prior claims had been extinguished. Richard
M. Deneau is the brother of William W. Deneau, another one of our Directors,
our
Chairman, and our Chief Executive Officer.
Gary
J. Myles
has
served on our Board of Directors since November 21, 2005. From June 1997 to
the
present, Mr. Myles has also served as a Director of Aurora. He is currently
retired from his primary employment. Prior to his retirement, Mr. Myles served
as Vice President and Consumer Loan Manager for Fifth Third Bank of Northern
Michigan (previously Old Kent Mortgage Company), a wholly owned subsidiary
of
Fifth Third Bank (previously Old Kent Financial Corporation). As the Affiliate
Consumer Loan Manager, Mr. Myles was based in Traverse City, Michigan, and
had
full bottom line responsibility for the mortgage and indirect consumer loan
departments generating net revenue of $3.5 million annually. Mr. Myles had
been
with Fifth Third Bank and its predecessor, Old Kent Mortgage Company, since
July
1988. Mr. Myles is the chairperson of our Audit Committee and Nominating and
Corporate Governance Committee.
Wayne
G. Schaeffer
joined
our Board of Directors on January 19, 2007. Mr. Schaeffer was employed by
Citizens Banking Corporation from 1983 until his retirement in June 2005.
Positions held with Citizens Banking Corporation include Executive Vice
President, Head of Consumer Banking (June 2002 - June 2005) and Executive Vice
President of Citizens Banking Corporation and President, Citizens Bank-Southeast
Michigan (June 1996 - June 2002).
Kevin
D. Stulp
has
served on our Board of Directors since March 1997. Since August 1995, Mr. Stulp
has worked as a consultant with Forte Group, on the board of the Bible League,
and is active with various other non-profit organizations and is currently
a
director of U.S. Silver Corporation, a publicly-traded silver mining company
with operations in Wallace, Idaho. From December 1983 to July 1995, Mr. Stulp
held various positions with Compaq Computer Corporation, including industrial
engineer, new products planner, manufacturing manager, director of
manufacturing, and director of worldwide manufacturing
reengineering.
Earl
V. Young
has
served on our Board of Directors since November 21, 2005. From March 2001 to
the
present, Mr. Young has also served as a Director of Aurora. He is currently
President of Earl Young & Associates of Dallas, Texas, which he founded in
1999. Mr. Young is also a Director and chair of the Audit Committee for Diamond
Fields International, a Canadian company that is listed on the Toronto Stock
Exchange and is a producer of offshore diamonds in Nambia with exploration
activity in Sierra Leone and Liberia. Mr. Young is a Director of Madagascar
Resources, an Australian public company that is engaged in mineral exploration
in Madagascar. Mr. Young is the chairperson of our Compensation
Committee.
More
detailed biographical information about our directors and executive officers
may
be found on our website at
www.auroraogc.com
.
To
our
knowledge, no director, officer or affiliate of the Company, and no owner of
record or beneficial owner of more than five percent (5%) of our securities,
or
any associate of any such director, officer or security holder is a party
adverse to us or has a material interest adverse to us in reference to pending
litigation.
BOARD
COMMITTEES
A
majority of our seven member Board of Directors qualify as independent
directors. The following directors are independent directors as defined in
Section 121A of the American Stock Exchange Corporate Governance Rules, a
non-employee director as defined in Rule 16b-3 under the Securities Exchange
Act
of 1934, and an outside director as defined under Section 162(m) of the Internal
Revenue Code: Gary J. Myles, Wayne G. Schaeffer, Kevin D. Stulp, and Earl V.
Young.
We
require that all members of our standing Board committees be independent
directors. Effective May 18, 2007, our Board committees are as
follows:
Audit
Committee: Wayne G. Schaeffer (chairman), Gary J. Myles and, Earl V.
Young.
Compensation
Committee: Gary J. Myles (chairman), Wayne G. Schaeffer, and Kevin D.
Stulp.
Nominating
Committee: Kevin D. Stulp (chairman), Gary J. Myles and Earl V.
Young.
Corporate
Governance Committee: Earl V. Young (chairman), Wayne G. Schaeffer and Kevin
D.
Stulp.
During
2006, our Board of Directors met five times. All of the Directors attended
at
least 75% of the meetings of the Board of Directors and each committee on which
they served.
Our
Shareholder Communications with Directors Policy states that the Directors
are
expected to attend our annual meeting of shareholders each year in person
whether or not they are standing for re-election. Each of the then-serving
Directors attended the annual meeting held in 2006. We do not have information
about Director participation in previous annual meetings.
Audit
Committee
We
have a
separately designated standing Audit Committee established in accordance with
Section 3(a)(58)(A) of the Securities Exchange Act of 1934, as amended
(“Exchange Act”). Members of the Audit Committee currently include Wayne G.
Schaeffer, Chairman, Gary J. Myles, and Earl V. Young. During 2006, Kevin D.
Stulp also served as a member of the Audit Committee. Each of them is an
independent outside director. Two of them, Gary J. Myles and Wayne G. Schaeffer,
are financial experts. We have included in the biographical information above
a
brief summary of their relevant experience.
On
February 10, 2006, our Board of Directors adopted an Audit Committee Charter,
a
copy of which is posted on our website at
www.auroraogc.com
.
Among
the
responsibilities of our Audit Committee are: (i) to appoint our independent
auditors and monitor the independence of our independent auditors; (ii) to
review our policies and procedures on maintaining accounting records and the
adequacy of internal controls; (iii) to review management’s implementation of
recommendations made by the independent auditors and internal auditors; (iv)
to
consider and pre-approve the range of audit and non-audit services performed
by
independent auditors and fees for such services; and (v) to review our audited
financial statements, Management’s Discussion and Analysis of Financial
Conditions and Results of Operations, and disclosures regarding internal
controls before they are filed with the SEC.
COMPENSATION
DISCUSSION AND ANALYSIS
Compensation
Committee
Our
Compensation Committee is comprised of three independent directors, Gary J.
Myles, Chairman, Wayne G. Schaeffer, and Kevin D. Stulp. Each of these directors
is an independent director as defined in Section 121A of the American Stock
Exchange Corporate Governance Rules, a non-employee director as defined in
Rule
16b-3 under the Securities Exchange Act of 1934, and an outside director as
defined under Section 162(m) of the Internal Revenue Code.
Our
Compensation Committee Charter delegates certain responsibilities to the
Compensation Committee, including the following:
|
·
|
Establish
compensation policies that effectively attract, retain and motivate
executive officers to successfully lead and manage the
company;
|
|
·
|
Review
and approve corporate goals and objectives relevant to compensation
of
senior management, evaluate the performance of senior management
in light
of these goals and objectives, and set the compensation level for
senior
management based on this
evaluation;
|
|
·
|
Review,
evaluate and approve all compensation of directors and executive
officers,
including salary adjustments, bonuses, stock awards, stock option
grants,
warrants, perquisites and other
benefits;
|
|
·
|
Review
at least annually the Chief Executive Officer’s performance in connection
with setting compensation;
|
|
·
|
Review
and make recommendations to the Board of Directors with respect to
the
adoption, amendment and termination of the company’s compensation plans
(such as 401(k) savings, profit sharing, and other retirement plans
and
employee stock plans), oversee their administration and discharge
any
duties allocated to the Committee under any such
plan;
|
|
·
|
Review,
evaluate and make recommendations to the Board of Directors with
respect
to the approval of the employment agreements of executive officers;
and
|
|
·
|
Review
director compensation levels and practices and recommend to the full
Board
of Directors, from time to time, changes in such compensation levels
and
practices.
|
As
a
matter of practice and procedure, our Compensation Committee makes
recommendations to the full Board of Directors for the compensation package
for
each of our executive officers. The final compensation package for our executive
officers is required to be approved by a majority of our independent directors.
We receive input from our Chief Executive Officer (“CEO”) about his
recommendations for the structure of our executive officer compensation.
However, we do not allow any executive officer whose compensation is being
set
to be present at either the Compensation Committee meeting or the Board of
Directors meeting during the time that his compensation is being deliberated
about or voted upon.
It
is our
practice to seek to establish executive compensation at the first Board of
Directors meeting of every year. If there are unresolved issues related to
executive compensation at the first Board of Directors meeting of the year,
executive compensation may be established at later Board of Directors meetings,
and any compensation adjustments from the prior year may be applied
retroactively to the beginning of the year. To the extent that there are options
awarded for a year to existing executive officers, we will tie the exercise
price to the closing price at which our stock is traded on the first day of
the
Board of Directors meeting at which the option awards are approved. To the
extent that we hire new executive officers and award them stock options as
a
signing bonus, the exercise price of the options will be the closing price
at
which our stock is traded on the first day of the following calendar
quarter.
General
Objectives of Compensation Program
Our
Compensation Committee Charter states that the Committee’s objective is to
develop a compensation system that is competitive with our peers and encourages
both short-term and long-term performance in a manner beneficial to us and
our
operations. Our compensation philosophy will vary among the executive officers,
depending upon variables such as previous history with the company, number
of
shares of company stock owned, the impact of peer group comparison, and whether
recruitment is a factor under the circumstances. We do not believe that a single
approach or even a single objective is appropriate with respect to all executive
officers. If an executive officer is also a director, it is our practice to
compensate him only as an executive officer. He will not participate in the
compensation awarded to the non-employee directors.
Compensation
of our Chief Executive Officer, President and Vice
Presidents
Objectives
Our
CEO
and our two Vice Presidents joined us upon closing of the merger between Cadence
Resources Corporation and Aurora on October 31, 2005. Prior to the merger
closing, they were the management team for Aurora. As a result of this
management change upon closing the merger, our approach to executive officer
compensation is in transition from that typical of a privately held growth
stage
company to that more typical of a publicly traded company.
For
the
year 2006, our objective in establishing the compensation for our CEO and Vice
Presidents was to provide a fair compensation that would reward the extra effort
we anticipated to be required during the year as a result of the October 31,
2005 merger. We knew that there would be a substantial learning curve through
which they would have to guide the company as they took the company to the
next
level. We also had a need at that time to preserve cash. We were aware that
our
executive compensation was not as high as our peer group for publicly traded
companies, but we felt that we needed to take some time to review our
compensation structure before implementing significant changes.
As
we
entered 2007, we have continued to work on developing our compensation
philosophy. We have been working with consultants to help us develop our
philosophy for executive officer and director compensation. Accordingly, our
primary objective for the year 2007 is to maintain a fair compensation level
while we continue to work on developing a more comprehensive compensation
philosophy.
Our
Compensation Committee has also asked our CEO to work with a compensation
consultant to develop a comprehensive compensation plan for all employees other
than the executive officers. We expect that once our comprehensive compensation
plan is developed, our compensation philosophy for executive officers will
tie
into the larger overall plan.
Elements
of Executive Compensation
Base
Salary
.
Unless
a pre-existing employment contract requires otherwise, it is our practice to
re-evaluate base salary for our executive officers each year. To assist us,
we
have retained the services of a compensation consulting firm that has provided
us with data regarding compensation for peer executive officers within our
industry. In general, our philosophy is to pay a base salary that is fair in
the
sense of being competitive enough in the market place to attract and retain
our
executive officers, given the circumstances of each individual involved, but
no
more. Our philosophy is not to match our peers, but to determine what is fair
compensation under the circumstances. For the year 2006, we paid our CEO a
base
salary of $140,000 per year, and our two Vice Presidents each a base salary
of
$125,000 per year.
We
will
generally not increase or decrease our base salary compensation levels
materially unless there is a material change in our financial and market
performance. We will generally look at modest annual increases as a means of
making up for inflationary cost of living increases and to provide some modest
merit-based increase for work done during the prior year.
Annual
Performance Bonus
.
Our
approach to the use of annual performance bonuses will vary from year to year.
We do not have a formal incentive bonus plan tied to predetermined performance
benchmarks in place for our executive officers for the year 2007. However,
we
have recently awarded stay bonuses and retention bonuses to some of our
executive officers as more fully described below.
Stock
Options
.
We use
stock options from time to time to serve as a long-term incentive to keep our
employees' performance aligned with our overall corporate goals. Because of
the
tax preferred treatment of incentive stock options, we evaluate the tax benefits
of incentive stock options when evaluating compensation for our executive
officers. In the past, we have not taken into account the effect of stock
options on our financial statements when we determine whether or not to award
stock options to our executive officers. This may change in the
future.
In
2006,
we awarded our CEO an option to purchase 200,000 shares of our common stock
vesting over three years with 60,000 shares vesting on December 31, 2006, 70,000
shares vesting on December 31, 2007, and 70,000 shares vesting on
December 31, 2008. This award was intended to provide additional
compensation in acknowledgement of our CEO’s work in closing the merger in 2005,
and to serve as a longer term incentive to lead us in such a fashion as to
improve our stock value over time. We have not awarded our CEO any new stock
options during 2007.
In
2006,
we awarded each of our two Vice Presidents an option to purchase 40,000 shares
of our common stock. These awards were vested on the date of grant. These awards
were intended to provide additional compensation in acknowledgement of their
work in closing the merger in 2005, and to serve as a longer term incentive
to
lead us in such a fashion as to improve our stock value over time. We have
not
awarded our two Vice Presidents any stock options in 2007.
Stock
Awards
.
In
addition to the issuance of stock options, we also have used, and from time
to
time expect to continue to use, stock awards as an element of executive
compensation. This determination will be made on a case-by-case basis. For
the
year 2007, we have not made any separate stock awards to our CEO or our two
Vice
Presidents.
Other
Types of Compensation
.
Except
as provided below, we do not have in place at this time any other types of
long-term incentive compensation or special executive benefits not provided
to
all of our employees on the same terms. Our philosophy at this time is to
maintain a fairly simple executive compensation structure.
Compensation
of our Chief Financial Officer
We
hired
our Chief Financial Officer in June 2006 under a two-year contract. Our primary
motivation when we negotiated this contract was immediate recruitment. Under
this contract, our Chief Financial Officer receives a base salary of $200,000
per year held constant during the term of the contract. This contract does
not
provide for an annual or other cash performance bonus or stock option
award.
This
contract provides that so long as our Chief Financial Officer continues to
serve
as an employee through June 18, 2008, on January 1, 2009, we will grant him
500,000 shares of our common stock. He may also receive this stock award if
his
employment terminates before June 18, 2008 upon the happening of certain events,
such as termination without just cause, death, disability and a change of
control. These triggers were negotiated prior to his acceptance of our offer
of
employment, and were selected based upon what was necessary to get him to accept
our offer. Because our Chief Financial Officer does not currently have a sizable
equity position in the Company similar to our other executive officers, we
wanted to align his interests in a significant way with all other shareholders
in the Company.
Equity
Ownership Guidelines and Requirements
We
do not
require non-director executive management to own our equity. As described below,
Directors are required to own a nominal amount of our stock within a specified
period of time. This requirement applies to executive officers who are also
Directors.
Our
Insider Trading Policy prohibits all insiders, including executive officers
and
directors, from trading in any interest or position relating to our future
stock
prices, such as puts, calls and short sales. We have encouraged our executive
officers who desire to trade in our stock to establish 10b5-1 Plans in order
to
minimize the risk of trading on non-public information.
Recent
Contractual Arrangements
On
September 19, 2007, we announced that we had retained an investment banker
to
assist the Board of Directors in evaluating strategic alternatives. These
alternatives, among other things, may include revisions to our strategic plan,
asset divestitures, operating partnerships, identifying additional capital
sources, or a sale, merger, or other business combination. We recognize that
the
possibility of a change in control may exist and it is in our best interest
to
assure that we maintain dedicated key employees to provide significant services
through the evaluation process. The following arrangements have been approved
for certain key officers and employees.
Stay
Bonus
.
On
September 18, 2007, our Board of Directors approved a stay bonus arrangement
to
encourage employees to remain employed by us through any possible change in
control. For purposes of this arrangement, “change in control” means any
transaction or occurrence (including a sale of stock or a merger) where our
shareholders before the transaction or occurrence own less than 50% of our
voting shares after the transaction or occurrence or there is a sale or
disposition of a majority of our assets.
The
stay
bonus arrangement provides that if a change in control occurs on or before
September 1, 2008, and employees remain continuously employed with us through
such change of control, employees are then eligible for a stay bonus in the
amount of 50% of their then current annual base salary. We will pay this stay
bonus less applicable withholdings and taxes upon the occurrence of a change
in
control. Certain of our officers are covered by this arrangement and their
potential stay bonuses are estimated on their current salaries as follows:
(i)
Ronald E. Huff (President and Chief Financial Officer) $100,000; (ii) John
V.
Miller (Vice President) $67,500; (iii) John C. Hunter (Vice President) $66,000;
and (iv) Lorraine M. King (Former Chief Financial Officer) $62,500.
Change
of Control Agreements
.
On
October 19, 2007, the Board of Directors approved a change in control
arrangement to encourage certain key officers and employees to remain employed
by us through any potential change in control. The change in control agreement
provides for the employment of the certain key officers and employees during
a
specified period following a change of control and provides certain benefits
in
the event that the key officer or employee’s employment is terminated during
such period other than for cause or by the key officer or employee for good
reason.
For
purposes of this arrangement, “change in control” is defined in the change in
control agreement to cover various transactions or occurrences resulting in
a
change in our stock or asset ownership.
The
change of control agreement provides that during the two-year period, the key
officer or employee will (i) have a position and duties commensurate to those
of
the officer prior to the change of control, (ii) perform his or her services
at
a location within a 35-mile radius from the previous work site before the change
in control, and (iii) receive an annual base salary at least equal to the
employee’s annual base salary prior to a change in control unless a reduction
occurs on a proportional basis simultaneously with a Company-wide reduction
in
senior management salaries.
In
the
event of a covered termination during the two-year period following a change
of
control, the arrangement provides for (i) the payment of an amount equal to
either one or two times the employee’s annual salary as specified in each
employee’s individual agreement, (ii) the provision for medical and dental
benefits for up to 24 months following the date of termination, and (iii)
benefits continuation substantially similar to those to which the employee
was
entitled prior to the date of termination.
Certain
of our officers are covered by this arrangement and their specified lump sum
payments in the event of a termination are as follows: (i) John C. Hunter (Vice
President) two times his annual base salary, and (ii) Lorraine M. King (Former
Chief Financial Officer) one times her annual base salary.
Retention
Bonus
.
Our
Board of Directors has approved a retention bonus arrangement to encourage
certain key officers and employees to remain employed with us through the
completion of our 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 us as well as remain in good standing on the scheduled payment
dates. As of October 24, 2007, certain of our officers accepted this arrangement
and their potential retention bonuses are estimated as follows: (i) Ronald
E.
Huff (President and Chief Financial Officer), $100,000; (ii) John C. Hunter
(Vice President), $80,000; (iii) John V. Miller, Jr. (Vice President), $40,000;
and (iv) Lorraine M. King (former Chief Financial Officer), $25,000.
EXECUTIVE
COMPENSATION
On
November 1, 2005, our prior management team was replaced by the Aurora
management team. As part of the merger, we changed from a September 30 to a
December 31 fiscal year-end. Our financial results for 2005 include 12 months
of
Aurora operations and two months (November and December 2005) of operations
of
Cadence Resources Corporation. We are disclosing executive compensation in
the
same fashion below. The information below shows compensation paid by Aurora
to
the executives listed below for the 12 months ended December 31, 2005 and
2004, and compensation paid by Cadence Resources Corporation (now Aurora Oil
& Gas Corporation) for the 12 months ended December 31, 2006 and the months
of November and December 2005.
The
following four tables set forth information regarding our Chief Executive
Officer, Chief Financial Officer, and our remaining two executive officers
of
the Company.
SUMMARY
COMPENSATION TABLE
|
Name
and Principal Position
|
|
Year
|
|
Salary
($)
|
|
Bonus
($)
|
|
Stock
Awards ($)
|
|
Option
Awards ($)
|
|
All
Other Compen-sation ($)
|
|
Total
($)
|
|
William
W. Deneau
|
|
|
2006
|
|
|
140,000
|
|
|
28,000
|
|
|
-
|
|
|
196,974
|
(a)
|
|
2,450
|
(b)
|
|
367,424
|
|
President,
Chief
|
|
|
2005
|
|
|
140,000
|
(c)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
140,000
|
|
Executive
Officer
|
|
|
2004
|
|
|
90,000
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
90,000
|
|
Ronald
E. Huff
|
|
|
2006
|
|
|
105,400
|
(d)
|
|
-
|
|
|
566,521
|
(e)
|
|
-
|
|
|
2,000
|
(b)
|
|
673,921
|
|
Chief
Financial
|
|
|
2005
|
|
|
2,500
|
(d)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2,500
|
|
Officer
|
|
|
2004
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
John
V. Miller, Jr.
|
|
|
2006
|
|
|
125,000
|
|
|
26,250
|
|
|
-
|
|
|
64,332
|
(a)
|
|
1,875
|
(b)
|
|
217,457
|
|
Vice
President
|
|
|
2005
|
|
|
125,000
|
(c)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
125,000
|
|
|
|
|
2004
|
|
|
90,000
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
90,000
|
|
Thomas
W. Tucker
|
|
|
2006
|
|
|
125,000
|
|
|
26,250
|
|
|
-
|
|
|
64,332
|
(a)
|
|
-
|
|
|
215,582
|
|
Vice
President
|
|
|
2005
|
|
|
125,000
|
(c)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
125,000
|
|
|
|
|
2004
|
|
|
90,000
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
90,000
|
|
Lorraine
M. King
|
|
|
2006
|
|
|
125,000
|
(f)
|
|
-
|
|
|
-
|
|
|
108,610
|
(a)
|
|
-
|
|
|
233,610
|
|
Chief
Financial
|
|
|
2005
|
|
|
125,000
|
|
|
-
|
|
|
116,400
|
(g)
|
|
4,465
|
|
|
-
|
|
|
245,865
|
|
Officer
(resigned
|
|
|
2004
|
|
|
65,000
|
|
|
25,000
|
|
|
-
|
|
|
3,301
|
|
|
-
|
|
|
93,301
|
|
as
CFO effective
6/19/2006)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The
assumptions used to calculate value in accordance with FAS 123R may
be
found in Note 10 “Common Stock Options” of our financial statements
provided in our 12/31/06 Form 10-KSB which was filed on March 15,
2007.
|
(b)
|
These
reflect our company match to a 401(K) defined contribution
plan.
|
(c)
|
Some
of the executive officers received additional cash compensation during
2005, but this was payment of deferred salaries for the years 2000
and
2001 that had been recorded, but not paid. This includes an additional
cash payment of $47,244 for Mr. Deneau, $26,667 for Mr. Miller and
$50,000
for Mr. Tucker.
|
(d)
|
Mr.
Huff became our chief financial officer on June 19, 2006. We paid
him a
salary in the amount of $90,900 (annual salary of $200,000 per year)
for
services rendered from the period June 19, 2006 through December
31, 2006.
Mr. Huff served as a director throughout the entire year of 2006.
We paid
him $14,500 for director services through June 18, 2006, including
compensation for his services as chairman of our audit committee.
We do
not pay our executive officers separate compensation for serving
as a
director. Accordingly, Mr. Huff did not receive separate compensation
for
his service as a director from June 19, 2006 through the end of 2006.
The
salary paid to Mr. Huff in 2005 was related exclusively to his services
as
a director.
|
(e)
|
In
connection with hiring Mr. Huff to serve as our Chief Financial Officer,
on June 19, 2006, we agreed to award Mr. Huff a stock bonus in the
amount
of 500,000 shares of common stock on January 1, 2009, so long as
he
remains employed by us through June 18, 2008. The total value of this
award is $2,110,000 based on the $4.22 per share price at which our
stock
was trading on June 19, 2006. Because of the two-year vesting
requirement, we are prorating the compensation expense associated
with
this award over the vesting period.
|
(f)
|
Effective
June 19, 2006, Ms. King resigned as Chief Financial Officer. We continue
to employ her as Treasurer.
|
(g)
|
This
reflects an award of 30,000 shares on December 8, 2005. The closing
price
at which our stock traded on that date was $3.88 per
share.
|
The
following table sets forth the grants of plan-based awards to our executive
officers during the year 2006.
GRANTS
OF PLAN-BASED AWARDS
|
Name
|
|
Grant
Date
|
|
Date
of Board Action
|
|
Stock
Awards No. of Shares of Stock
|
|
Option
Awards No. of Shares of Stock Underlying Options
|
|
Exercise
Price of Option Award
|
|
Closing
Market Price on Grant Date
|
|
Grant
Date Fair Value of Stock and Option Awards
|
|
William
W. Deneau
(a)
|
|
|
05/19/06
|
|
|
12/08/05
|
|
|
-
|
|
|
200,000
|
|
$
|
3.62
|
|
$
|
4.70
|
|
$
|
399,800
|
|
Ronald
E. Huff
(b)
|
|
|
06/19/06
|
|
|
06/19/06
|
|
|
500,000
|
|
|
-
|
|
|
-
|
|
$
|
4.22
|
|
$
|
2,110,000
|
|
John
V. Miller, Jr.
(c)
|
|
|
03/16/06
|
|
|
03/16/06
|
|
|
-
|
|
|
40,000
|
|
$
|
5.50
|
|
$
|
5.50
|
|
$
|
64,332
|
|
Thomas
W. Tucker
(c)
|
|
|
03/16/06
|
|
|
03/16/06
|
|
|
-
|
|
|
40,000
|
|
$
|
5.50
|
|
$
|
5.50
|
|
$
|
64,332
|
|
Lorraine
M. King
(c)
(former
|
|
|
03/16/06
|
|
|
03/16/06
|
|
|
-
|
|
|
60,000
|
|
$
|
5.50
|
|
$
|
5.50
|
|
$
|
108,610
|
|
CFO)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The
grant date is the date that we had an equity incentive plan in place
with
sufficient capacity to issue these options and an effective S-8
registration statement for these options. The exercise price is the
fair
market value on November 21, 2005, the date our new Board of
Directors was impaneled after the October 31, 2005, merger, calculated
using the average closing stock price over the preceding 30 trading
days.
The option award granted to Mr. Deneau vests as follows: 60,000 shares
on
December 31, 2006; 70,000 shares on December 31, 2007; and 70,000
shares on December 31, 2008.
|
(b)
|
On
June 19, 2006, we entered into an employment agreement with Ronald E.
Huff relating to his service as our Chief Financial Officer. This
agreement provides for a term of two years and an annualized salary
of
$200,000 per year. We have also agreed to award Mr. Huff a stock
bonus in the amount of 500,000 shares of common stock on
January 1, 2009, so long as Mr. Huff remains employed by us
through June 18, 2008, which will require us to record $2,110,000 in
stock-based compensation expense over the contract period. If
Mr. Huff’s employment is terminated prior to this date without just
cause or if we undergo a change in control, Mr. Huff will nonetheless
be awarded the full 500,000 shares. If Mr. Huff’s employment is
terminated prior to June 18, 2008 due to death or disability, he will
receive a prorated stock award. As part of his employment arrangement,
Mr. Huff forfeited the option to purchase 200,000 shares that he
was previously awarded by the Company in return for his service as
a
director. Mr. Huff will not be eligible to participate in any annual
bonus plan or other additional long-term incentive award during the
term
of the Employment Agreement.
|
(c)
|
All
of the option awards depicted on the foregoing table, other than
options
awarded to Mr. Deneau, were fully vested upon issuance.
|
The
following table sets forth information on exercised options and unvested
stock
awards held by our executive officers as of December 31, 2006.
OUTSTANDING
EQUITY AWARDS AT FISCAL
YEAR-END
|
Name
|
|
No.
of Shares
Underlying
Unexercised
Options
- No.
Exercisable
|
|
No.
of Shares
Underlying
Unexercised
Options
- No.
Unexercisable
|
|
Option
Exercise
Price
|
|
Option
Expiration
Date
|
|
No.
of Shares
That
Have
Not
Vested
|
|
Market
Value
of
Shares That
Have
Not
Vested
|
|
William
W. Deneau
|
|
|
60,000
|
|
|
140,000
|
|
$
|
3.62
|
|
|
11/11/10
|
|
|
-
|
|
|
-
|
|
Ronald
E. Huff
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
500,000
|
|
$
|
1,605,000
|
|
John
V. Miller, Jr.
|
|
|
40,000
|
|
|
-
|
|
$
|
5.50
|
|
|
03/16/11
|
|
|
-
|
|
|
-
|
|
Thomas
W. Tucker
|
|
|
40,000
|
|
|
-
|
|
$
|
5.50
|
|
|
03/16/11
|
|
|
-
|
|
|
-
|
|
Lorraine
M. King
(former
CFO)
|
|
|
20,000
60,000
|
|
|
-
-
|
|
$
$
|
1.75
5.50
|
|
|
10/18/15
03/16/11
|
|
|
-
-
|
|
|
-
-
|
|
The
following table sets forth the options exercised by our executive officers
during 2006, and stock awards held by our executive officers that vested
during
2006.
OPTION
EXERCISES AND STOCK VESTED
|
Name
|
|
No.
of
Shares
Acquired
on
Exercise
|
|
Value
Realized
on
Exercise
|
|
No.
of Shares
Acquired
on
Vesting
|
|
Value
Realized
on
Vesting
|
|
William
W. Deneau
(a)
|
|
|
0
|
|
|
-
|
|
|
0
|
|
|
-
|
|
Ronald
E. Huff
|
|
|
0
|
|
|
-
|
|
|
0
|
|
|
-
|
|
John
V. Miller, Jr.
(a)
|
|
|
0
|
|
|
-
|
|
|
0
|
|
|
-
|
|
Thomas
W. Tucker
(a)
|
|
|
0
|
|
|
-
|
|
|
0
|
|
|
-
|
|
Lorraine
M. King
|
|
|
140,000
|
|
$
|
515,900
|
|
|
0
|
|
|
-
|
|
(former
CFO)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
In
December 2006, Mr. Deneau, Mr. Miller and Mr. Tucker rescinded
option
exercises for 600,000 shares each. The option exercise price of
$249,000
was returned to each of these officers and, in exchange, each officer
surrendered 600,000 shares of common stock. These options expired
in
2006.
|
COMPENSATION
OF DIRECTORS
The
table
below sets forth the compensation we paid to our non-employee directors during
2006.
Name
|
|
Fees
Earned or
Paid
in Cash
|
|
Value
of
Option
Awards
|
|
Total
|
|
Howard
Crosby
|
|
$
|
3,000
|
|
|
0
(a
|
)
|
$
|
3,000
|
|
Richard
M. Deneau
|
|
$
|
17,500
|
|
$
|
196,974
(b
|
)
|
$
|
214,474
|
|
Gary
J. Myles
|
|
$
|
17,500
|
|
$
|
196,974
(c
|
)
|
$
|
214,474
|
|
Kevin
D. Stulp
|
|
$
|
17,500
|
|
$
|
196,974
(d
|
)
|
$
|
214,474
|
|
Earl
V. Young
|
|
$
|
25,000
|
|
$
|
196,974
(e
|
)
|
$
|
221,974
|
|
|
(a)
|
Howard
Crosby resigned as our director on June 6, 2006. Although he was
granted
an option to purchase 200,000 shares of our common stock on May
19, 2006,
the option was unvested in its entirety on the date of his resignation,
and therefore was forfeited
immediately.
|
|
(b)
|
At
December 31, 2006, Richard M. Deneau owned options to purchase
an
aggregate of 200,000 shares of our common stock, 60,000 of which
are
vested and 140,000 of which are unvested.
|
|
(c)
|
At
December 31, 2006, Gary J. Myles owned options to purchase an aggregate
of
359,998 shares of our common stock, 219,998 of which are vested,
and
140,000 of which are unvested.
|
|
(d)
|
At
December 31, 2006, Kevin D. Stulp owned options to purchase an
aggregate
of 250,000 shares of our common stock, 110,000 of which are vested,
and
140,000 of which are unvested.
|
|
(e)
|
At
December 31, 2006, Earl V. Young owned options to purchase an aggregate
of
333,332 shares of our common stock, 193,332 of which are vested,
and
140,000 of which are unvested.
|
For
2006,
our standard compensation arrangement for service as a director was as
follows:
|
|
Option
to purchase 200,000 shares of our common stock; vesting 60,000
shares on
December 31, 2006, 70,000 shares on December 31, 2007, and 70,000
shares
on December 31, 2008.
|
|
|
Cash
fee of $1,000 per Board of Directors meeting attended in person,
with
additional payments of $1,000 per day for each travel day from
the
Director’s place of residence to the location of the Board of Directors
meeting, up to a total of two additional days in addition to the
date of
the meeting.
|
|
|
Cash
fee of $500 for participation in each telephonic Board of Directors
meeting.
|
|
|
Cash
fee of $1,000 for each committee meeting attended in
person.
|
|
|
Cash
fee of $500 for participating in each telephonic committee
meeting.
|
|
|
Annual
retainer of $10,000 for the Audit Committee
chairperson.
|
Our
Board
of Directors has adopted a policy requiring each director to own at least
20,000
shares of our common stock. For new directors, this requirement must be
satisfied within one year of joining our Board of Directors. This requirement
applies to all directors, including those who are employees and those who
are
not employees.
PRINCIPAL
AND SELLING SECURITY HOLDERS
The
following table sets forth, as of September 30, 2007, certain information
regarding the ownership of voting securities of the Company by each shareholder
known by the management of the Company to be (i) the beneficial owner of
more than 5% of our outstanding common stock, (ii) our directors,
(iii) our current executive officers and (iv) all executive officers
and directors as a group. Except as otherwise reflected in the notes below,
the
Company believes that the beneficial owners of the common stock listed below,
based on information furnished by such owners, have sole investment and voting
power with respect to such shares.
Unless
otherwise specified, the address of each of the persons set forth below is
in
care of Aurora Oil & Gas Corporation, 4110 Copper Ridge Drive,
Suite 100, Traverse City, Michigan, 49684.
Name
and Address of Beneficial Owners(a)
|
|
Amount
and Nature of
Beneficial
Ownership(b)
|
|
Percent
of
Outstanding
Shares
|
|
FMR
Corp.(c)
|
|
|
14,919,444
|
|
|
15
|
%
|
82
Devonshare Street
|
|
|
|
|
|
|
|
Boston,
Massachusetts 02109
|
|
|
|
|
|
|
|
Nathan
A. Low Roth IRA and affiliates
|
|
|
8,586,409(d
|
)
|
|
8
|
%
|
641
Lexington Avenue
|
|
|
|
|
|
|
|
New
York, New York 10022
|
|
|
|
|
|
|
|
Crestview
Capital Master, LLC
|
|
|
5,819,500(e
|
)
|
|
6
|
%
|
95
Revere Drive, Suite A
|
|
|
|
|
|
|
|
Northbrook,
Illinois 60062
|
|
|
|
|
|
|
|
CCM
Master Qualified Fund
|
|
|
4,994,453(f
|
)
|
|
5
|
%
|
One
North Wacker Drive, Suite 4725
|
|
|
|
|
|
|
|
Chicago,
Illlinois 60606
|
|
|
|
|
|
|
|
William
W. Deneau
|
|
|
3,714,814(g
|
)
|
|
4
|
%
|
Thomas
W. Tucker (retired 6/30/07)
|
|
|
3,167,016(h
|
)
|
|
3
|
%
|
John
V. Miller, Jr.
|
|
|
2,717,430(i
|
)
|
|
3
|
%
|
Kevin
D. Stulp
|
|
|
587,500(j
|
)
|
|
*
|
|
Earl
V. Young
|
|
|
476,204(k
|
)
|
|
*
|
|
Gary
J. Myles
|
|
|
368,798(l
|
)
|
|
*
|
|
Richard
M. Deneau
|
|
|
80,000(m
|
)
|
|
*
|
|
Ronald
E. Huff
|
|
|
20,000(n
|
)
|
|
*
|
|
Wayne
G. Schaeffer
|
|
|
20,000(o
|
)
|
|
*
|
|
John
C. Hunter
|
|
|
79,400(p
|
)
|
|
*
|
|
All
executive officers and directors as a group (10 persons)
|
|
|
11,231,162(q
|
)
|
|
12
|
%
|
(a)
|
Addresses
are only given for holders of more than 5% of outstanding common
stock who
are not executive officers or
directors.
|
(b)
|
A
person is deemed to be the beneficial owner of a security if such
person
has or shares the power to vote or direct the voting of such security
or
the power to dispose or direct the disposition of such security.
A person
is also deemed to be a beneficial owner of any securities if that
person
has the right to acquire beneficial ownership within 60 days of
the date
of this chart.
|
(c)
|
Based
on Schedule 13G/A filed with the Securities and Exchange Commission
(“SEC”) on February 14, 2007, FMR Corp., through its wholly-owned
subsidiary Fidelity Management & Research Company (“Fidelity”), an
investment advisor registered under Section 203 of the Investment
Advisors
Act of 1940, is the beneficial owner of 14,590,844 shares of common
stock.
Edward C. Johnson III and members of his family form a controlling
group
with respect to FMR Corp. Accordingly, FMR Corp. and Edward C.
Johnson III
have the sole power to dispose of 14,590,844 shares of common stock.
They
do not, however, have voting power, which instead resides with
the Board
of Trustees of the investment companies that are managed by Fidelity.
Fidelity Management Trust Company, a wholly-owned subsidiary of
FMR Corp.
and a bank, is the beneficial owner of 15,200 shares of common
stock, and
FMR Corp and Edward C. Johnson III have the sole dispositive power
and
sole power to vote or direct the voting of the 15,200 shares of
common
stock beneficially owned by Fidelity Management Trust Company.
Pyramis
Global Advisors Trust Company (“Pyramis”), an indirect wholly-owned
subsidiary of FMR Corp. and a bank, is the beneficial owner of
313,400
shares of common stock. FMR Corp and Edward C. Johnson III have
the sole
dispositive power over the 313,400 shares of common stock beneficially
owned by Pyramis, and the sole power to vote or to direct the voting
of
275,900 shares of common stock beneficially owned by
Pyramis.
|
(d)
|
Based
on information included in an amendment to Schedule 13D/A filed
with the
SEC on February 27, 2006, Nathan A. Low has the sole power to vote
or
direct the vote of, and the sole power to direct the disposition
of, the
shares held by the Nathan A. Low Roth IRAs and the shares held
by him
individually. Although Nathan A. Low has no direct voting or dispositive
power over the 828,643 shares of common stock held by the Nathan
A. Low
Family Trust or the 100,000 shares of common stock held in individual
trusts for the Neufeld children, he may be deemed to beneficially
own
those shares because his wife, Lisa Low, is the trustee of the
Nathan A.
Low Family Trust and custodian for the Neufeld children. Therefore,
Nathan
A. Low reports shared voting and dispositive power over 928,643
shares of
common stock.
|
(e)
|
Based
on information included in an amendment to Schedule 13G/A filed
with the
SEC on June 26, 2006, Crestview Capital Master LLC is the beneficial
owner
of 5,819,500 shares of common stock. Messrs. Stewart Flink, Robert
Hoyt
and Daniel Warsh, share the sole dispositive power and the sole
power to
vote or direct the voting of the 5,819,500 shares beneficially
owned by
Crestview Capital Master, LLC.
|
(f)
|
Based
on Schedule 13G filed with SEC for the period ended June 30, 2007,
4,994,453 shares of common stock were deemed to be beneficially
owned by
CCM Master Qualified Fund, Ltd., Coghill Capital Management, L.L.C.,
and
Clint D. Coghill. Mr. Coghill is the managing member of Coghill
Capital
Management, L.L.C., an entity which serves as the investment manager
of
CCM Master Qualified Fund, Ltd. CCM Master Qualified Fund, Ltd.,
Coghill
Capital Management, L.L.C., and Clint D. Coghill share voting power
and
dispositive power to vote or direct the voting of the 4,994,453
shares
beneficially owned by them.
|
(g)
|
Includes
options currently exercisable for 60,000 shares of common stock;
3,272,000
shares of common stock held by the Patricia A. Deneau Trust; 360,146
shares of common stock held by the Denthorn Trust; 20,000 shares
of common
stock held by White Pine Land Services, Inc.; and 2,668 shares
of common
stock held by Circle D, Ltd. (shared investment interest). Does
not
include an option to purchase 140,000 shares of common stock vesting
as
follows: 70,000 shares on January 1, 2008; and 70,000 shares on
January 1,
2009.
|
(h)
|
Includes
1,567,774 shares of common stock held by the Sandra L. Tucker Trust;
1,454,377 shares of common stock held by the Thomas W. Tucker Trust;
2,668
shares of common stock held by Circle D, Ltd. (shared investment
interest); and options currently exercisable for 40,000 shares
of common
stock.
|
(i)
|
Includes
1,000,000 shares of common stock held by Miller Resources, Inc.;
1,648,976
shares of common stock owned by Circle M, LLC; 10,000 shares of
common
stock held by spouse; 2,668 shares of common stock held by Circle
D, Ltd.
(shared investment interest); 5,000 shares of common stock held
by John
Miller Jr. Trust; and options currently exercisable for 40,000
shares of
common stock.
|
(j)
|
Includes
options currently exercisable for 110,000 shares of common stock;
2,750
shares of common stock owned by the Kevin Dale Stulp IRA; and 1,750
shares
of common stock owned by the Kevin and Marie Stulp Charitable Remainder
Unitrust of which Mr. Stulp is a co-trustee. Does not include an
option to
purchase 140,000 shares of common stock vesting as follows: 70,000
shares
on January 1, 2008; and 70,000 shares on January 1,
2009.
|
(k)
|
Includes
options currently exercisable for 193,332 shares of common stock.
Does not
include an option to purchase 140,000 shares of common stock vesting
as
follows: 70,000 shares on January 1, 2008; and 70,000 shares on
January 1,
2009.
|
(l)
|
Includes
144,466 shares of common stock held by the Gary J. Myles & Rosemary
Myles Inter Vivos Trust; and options currently exercisable for
193,332
shares of common stock. Does not include an option to purchase
140,000
shares of common stock vesting as follows: 70,000 shares on January
1,
2008; and 70,000 shares on January 1,
2009.
|
(m)
|
Includes
options currently exercisable for 60,000 shares of common stock.
Does not
include an option to purchase 140,000 shares of common stock vesting
as
follows: 70,000 shares on January 1, 2008; and 70,000 shares on
January 1,
2009.
|
(n)
|
Does
not include 500,000 shares of common stock to be awarded on January
1,
2009, subject to vesting
requirements.
|
(o)
|
Does
not include an option to purchase 140,000 shares of common stock
vesting
as follows: 70,000 shares on February 23, 2008; and 70,000 shares
on
February 23, 2009.
|
(p)
|
Includes
2,400 shares of common stock held by son and options currently
exercisable
for 65,000 shares of common stock. Does not include an option to
purchase
40,000 shares of common stock vesting as follows: 30,000 shares
on March
1, 2008; 5,000 shares on May 19, 2008; and 5,000 shares on May
19,
2009.
|
(q)
|
Includes
options currently exercisable for a total of 761,664 shares of
common
stock.
|
Selling
security holders
We
issued
to the selling security holders the common stock and the warrants to purchase
common stock that are covered by this prospectus pursuant to a private placement
in January 2005. This prospectus relates to the resale from time to time
of up
to a total of 8,900,000 shares of our common stock acquired by the certain
selling security holders identified in this prospectus either directly in
the
January private placement or pursuant to the exercise of warrants purchased
in
the January private placement. We filed a registration statement, of which
this
prospectus constitutes a part, in order to permit the selling security holders
to resell to the public the shares of our common stock in connection with
the
January 2005 private placement.
The
following table sets forth the names of the selling security holders, the
number
of shares of common stock beneficially owned by the selling security holders,
the number of shares of common stock being offered by the selling security
holders, the number of shares of common stock each selling security holder
will
beneficially own if the security holder sells all of the shares being registered
and the selling security holder’s percentage ownership of our common stock if
all the shares in the offering are sold. The shares being offered hereby
are
being registered to permit public secondary trading, and the selling security
holders may offer all or part of the shares for resale from time to time.
However, the selling security holders are under no obligation to sell all
or any
portion of such shares nor are the selling security holders obligated to
sell
any shares immediately under this prospectus. To prevent dilution to the
selling
security holders, the following numbers may change because of adjustments
to
reflect stock splits, stock dividends, or similar events involving our common
stock.
None
of
the selling security holders have, nor within the past three years have had,
any
position, office, or other material relationship with us or any of our
predecessors or affiliates, other than as a greater than 5% shareholder,
except
that Nathan A. Low, through his controlled entity, Sunrise Securities
Corporation, performed institutional investor relations services for us and
acted as a finder of investors in various private placements in which we
have
previously engaged.
Selling
Security Holders
|
|
Shares
of Common Stock Beneficially Owned Prior to Offering*
|
|
Shares
of Common Stock to be Sold*
|
|
Beneficial
Ownership After Offering if all Shares are Sold*
|
|
Percent
of Class Owned After Offering if all Shares are Sold**
|
|
Crestview
Capital Master, LLC(1)
|
|
|
5,819,500
|
|
|
3,680,000
|
|
|
2,139,500
|
|
|
2.1
|
%
|
Nathan
Low Family Trust, DTD 4/12/96(2)
|
|
|
928,643
|
|
|
720,000
|
|
|
208,643
|
|
|
0.2
|
%
|
Bear
Stearns, as Custodian for Nathan A. Low Roth IRA(2)
|
|
|
7,657,766
|
|
|
400,000
|
|
|
7,257,766
|
|
|
7.1
|
%
|
Ruth
Low
|
|
|
538,259
|
|
|
480,000
|
|
|
58,259
|
|
|
***
|
|
Coghill
Capital(3)
|
|
|
3,829,620
|
|
|
640,000
|
|
|
3,189,620
|
|
|
3.1
|
%
|
Cordillera
Fund L.P.(4)
|
|
|
800,000
|
|
|
800,000
|
|
|
0
|
|
|
-
|
|
Enable
Growth Partners LP(5)
|
|
|
480,000
|
|
|
480,000
|
|
|
0
|
|
|
-
|
|
Michael
Weiss
|
|
|
180,000
|
|
|
100,000
|
|
|
80,000
|
|
|
***
|
|
Don
Sanders
|
|
|
320,000
|
|
|
320,000
|
|
|
0
|
|
|
-
|
|
Sanders
Opportunity Fund (Inst) LP(6)
|
|
|
493,646
|
|
|
493,646
|
|
|
0
|
|
|
-
|
|
Sanders
Opportunity Fund LP(6)
|
|
|
154,354
|
|
|
154,354
|
|
|
0
|
|
|
-
|
|
Sanders
1998 Children’s Trust(6)
|
|
|
240,000
|
|
|
240,000
|
|
|
0
|
|
|
-
|
|
Don
Weir and Julie E. Weir
|
|
|
160,000
|
|
|
160,000
|
|
|
0
|
|
|
-
|
|
Ben
T. Morris
|
|
|
40,000
|
|
|
40,000
|
|
|
0
|
|
|
-
|
|
Fredrick
Saalwachter(7)
|
|
|
40,000
|
|
|
40,000
|
|
|
0
|
|
|
-
|
|
George
L. Ball
|
|
|
40,000
|
|
|
40,000
|
|
|
0
|
|
|
-
|
|
John
Malanga and Jodi Malanga(8)
|
|
|
32,000
|
|
|
32,000
|
|
|
0
|
|
|
-
|
|
Bruce
McMaken(9)
|
|
|
40,000
|
|
|
40,000
|
|
|
0
|
|
|
-
|
|
Mike
Chadwick
|
|
|
40,000
|
|
|
40,000
|
|
|
0
|
|
|
-
|
|
Totals
|
|
|
21,833,788
|
|
|
8,900,000
|
|
|
12,933,788
|
|
|
12.5
|
%
|
*
|
This
information is provided as of November 1, 2005, except to the extent
that
we were able to update it based on a Schedule 13D or Schedule 13G
filing
made by the selling security holder after that date. We have, however,
revised our footnotes below to reflect exercises of warrants that
have
occurred since November 1, 2005. Since this registration statement
became
effective, many of the shares included in the registration statement
have
been sold. Except in cases where a Schedule 13D or Schedule 13G
have been
filed, we are not able to track exactly how many shares have been
sold to
date under the registration statement, or how many shares may have
subsequently been acquired by the selling security holders. We
are
therefore presenting the information in the first three columns
as of the
time this registration statement became effective, except in the
cases
where a Schedule 13D or Schedule 13G filing reflect different
information.
|
**
|
The
percent of class information is based upon a total of 101,679,458
shares
of common stock outstanding. However, as reflected in the previous
footnote, the beneficial ownership used to calculate the percent
of class
is based upon the ownership at the time this registration statement
became
effective, except in those situations in which a Schedule 13D or
Schedule
13G have since been filed, in which case the calculation is based
on those
filings.
|
(1)
|
Based
on a Schedule 13G filed with the SEC on June 23, 2006, Crestview
Capital
Partners, LLC controls Crestview Capital Master, LLC, and the power
to
vote or dispose of our shares beneficially owned by Crestview Capital
Master, LLC is shared by Stewart Flink, Robert Hoyt and Daniel
Warsh, each
of whom disclaims beneficial ownership of our shares.
|
(2)
|
See
footnote (d) above under the heading "Principal Shareholders").
|
(3)
|
Based
on Schedule 13G filed with the SEC on February 14, 2006, Clint
D. Coghill
is the managing member of Coghill Capital, and shares the power
to vote
and dispose of these shares with CCM Master Qualified Fund, Ltd.
and
Coghill Capital Management, L.L.C.
|
(4)
|
We
have been informed that James Andrew is the controlling person
at
Cordillera Fund, L.P.
|
(5)
|
We
have been informed that Brendan O'Neil is the controlling person
of Enable
Growth Partners LP. Shares of common stock beneficially owned and
to be
sold includes warrants to purchase 240,000 shares of our common
stock.
|
(6)
|
We
have been informed that Don A. Sanders is the controlling person
of
Sanders Opportunity Fund (Inst.) LP, Sanders Opportunity Fund LP,
and
Sanders 1998 Children's Trust.
|
(7)
|
Shares
of common stock beneficially owned and to be sold includes warrants
to
purchase 20,000 shares of our common stock.
|
(8)
|
Shares
of common stock beneficially owned and to be sold included warrants
to
purchase 16,000 shares of our common stock.
|
(9)
|
Shares
of common stock beneficially owned and to be sold includes warrants
to
purchase 20,000 shares of our common
stock.
|
RELATED
PARTY TRANSACTIONS
In
connection with the December 2005 through February 2006 exercise of certain
warrants that had previously been issued by the Company and Aurora in January
31, 2005 transactions, we paid a commission to Sunrise Securities Corporation,
an affiliate of Nathan A. Low, who is a greater than 5% holder of our common
stock, in the amount of $1,534,697. This entire amount was used by Mr. Low
to
exercise certain outstanding warrants to purchase 1,469,860 shares of our
common
stock.
William
W. Deneau, John V. Miller, Jr. and Thomas W. Tucker, each of whom is one
of our
executive officers, are involved as equity owners in numerous corporations
and
limited liability companies that are active in the oil and natural gas business
and in some cases, participate in the same wells and fields that we participate
in. They also own miscellaneous overriding royalty interests in wells in
which
we have an interest. During 2006, our Nominating and Corporate Governance
Committee asked that these executive officers divest themselves of all such
interests for which we serve as operator. That divesture was accomplished
by the
end of 2006.
In
order
to replace the collateral pledged to Northwestern Bank for our revolving
line of
credit, on December 21, 2005, The Denthorn Trust, which is controlled by
William
W. Deneau, executed a Commercial Guaranty of our obligation on the Northwestern
Bank revolving line of credit, and a Commercial Pledge Agreement pursuant
to
which The Denthorn Trust has pledged to Northwestern Bank 306,450 shares
of our
common stock to secure payment of our indebtedness. Also on December 21,
2005,
the Patricia A. Deneau Trust, DTD 10/12/95, which is controlled by William
W.
Deneau, executed a Commercial Guaranty and a Commercial Pledge Agreement,
pursuant to which it pledged 2,944,800 shares of our common stock to
Northwestern Bank to secure payment of our indebtedness.
Mr.
Hunter has been 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 June 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.
Thomas
W.
Tucker retired effective June 30, 2007. The Company has signed a consulting
arrangement with Mr. Tucker to be available through December 31, 2007, to
assist
the Company on various matters.
It
is
probable that on occasion, we will find it necessary or appropriate to deal
with
other entities in which Messrs. Deneau and Miller have an interest. From
time to time, we may also enter into transactions in which our directors
have an
interest. Our Corporate Governance Committee Charter requires this Committee
to
review and approve all related party transactions between the Company and
its
executive officers and directors.
PLAN
OF DISTRIBUTION
The
selling security holders may, from time to time, sell any or all of their
shares
of common stock on any stock exchange, market, or trading facility on which
the
shares are traded or in private transactions. These sales may be at fixed
or
negotiated prices. The selling security holders may use any one or more of
the
following methods when selling shares:
|
·
|
ordinary
brokerage transactions and transactions in which the broker-dealer
solicits purchasers;
|
|
·
|
block
trades in which the broker-dealer will attempt to sell the shares
as agent
but may position and resell a portion of the block as principal
to
facilitate the transaction;
|
|
·
|
purchases
by a broker-dealer as principal and resale by the broker-dealer
for its
account;
|
|
·
|
an
exchange distribution in accordance with the rules of the applicable
exchange
|
|
·
|
privately
negotiated transactions;
|
|
·
|
broker-dealers
may agree with the selling security holders to sell a specified
number of
such shares at a stipulated price per
share;
|
|
·
|
a
combination of any such methods of sale;
and
|
|
·
|
any
other method permitted pursuant to applicable
law.
|
The
selling security holders may also sell shares under Rule 144 under the
Securities Act, if available, rather than under this prospectus.
The
selling security holders may also engage in short sales against the box,
puts
and calls, and other transactions in our securities or derivatives of our
securities and may sell or deliver shares in connection with these trades.
However, selling security holders may not engage in short sales before this
registration statement becomes effective.
Broker-dealers
engaged by the selling security holders may arrange for other brokers-dealers
to
participate in sales. Broker-dealers may receive commissions or discounts
from
the selling security holders (or, if any broker-dealer acts as agent for
the
purchaser of shares, from the purchaser) in amounts to be negotiated. The
selling security holders do not expect these commissions and discounts to
exceed
what is customary in the types of transactions involved. Any profits on the
resale of shares of common stock by a broker-dealer acting as principal might
be
deemed to be underwriting discounts or commissions under the Securities Act.
Discounts, concessions, commissions, and similar selling expenses, if any,
attributable to the sale of shares will be borne by a selling security holder.
The selling security holders may agree to indemnify any agent, dealer, or
broker-dealer that participates in transactions involving sales of the shares,
if liabilities are imposed on that person under the Securities Act.
The
selling security holders may from time to time pledge or grant a security
interest in some or all of the shares of common stock owned by them and,
if they
default in the performance of their secured obligations, the pledges or secured
parties may offer and sell the shares of common stock from time to time under
this prospectus after we have filed an amendment to this prospectus under
Rule
424(b)(3) or other applicable provision of the Securities Act of 1933 amending
the list of selling security holders to include the pledge, transferee, or
other
successors in interest as selling security holders under this
prospectus.
The
selling security holders also may transfer the shares of common stock in
other
circumstances, in which case the transferees, pledges, or other successors
in
interest will be the selling beneficial owners for purposes of this prospectus
and may sell the shares of common stock from time to time under this prospectus
after we have filed an amendment to this prospectus under Rule 424(b)(3)
or
other applicable provision of the Securities Act of 1933 amendment the list
of
selling security holders to include the pledge, transferee, or other successors
in interest as selling security holders under this prospectus.
The
selling security holders and any broker-dealers or agents that are involved
in
selling the shares of common stock may be deemed to be “underwriters” within the
meaning of the Securities Act in connection with such sales. In such event,
any
commissions received by such broker-dealers or agents and any profit on the
resale of the shares of common stock purchased by them may be deemed to be
underwriting commissions or discounts under the Securities Act. The selling
security holders have advised us that they have acquired their securities
in the
ordinary course of business and that they have not entered into any agreements,
understandings, or arrangements with any underwriters or broker-dealers
regarding the sale of their shares of common stock, nor is there an underwriter
or coordinating broker acting in connection with a proposed sale of shares
of
common stock by any selling security holder. If the selling security holders
use
this prospectus for any sale of the shares of common stock, they will be
subject
to the prospectus delivery requirements of the Securities Act.
We
are
required to pay all fees and expenses incident to the registration of the
shares
of common stock. We have agreed to indemnify the selling security holders
against certain losses, claims, damages, and liabilities, including liabilities
under the Securities Act.
The
anti-manipulation rules of Regulation M under the Securities Exchange Act
of
1934 may apply to sales of our common stock and activities of the selling
security holders.
DESCRIPTION
OF SECURITIES
Our
authorized capital stock consists of 250,000,000 shares of common stock,
par value $0.01 per share and 20,000,000 shares of preferred stock,
par value $0.01 per share. As of September 30, 2007, we had
101,679,456 shares of common stock issued and outstanding.
Common
Stock
The
holders of our common stock are entitled to one vote for each share held
of
record on all matters submitted to a vote of shareholders. Accordingly, holders
of a majority of the shares of our common stock entitled to vote in any election
of directors may elect all of the directors standing for election. Holders
of
common stock are entitled to receive ratably such dividends as may be declared
by the board out of funds legally available therefor. In the event of our
liquidation, dissolution or winding up, holders of common stock are entitled
to
share ratably in the assets remaining after payment of liabilities. Holders
of
our common stock have no preemptive, conversion or redemption rights. All
of the
outstanding shares of common stock are fully paid and
non-assessable.
Holders
As
of
September 30, 2007, there were 527 holders of record for our common stock,
although we believe that there are additional beneficial owners of our common
stock who own their shares in “street name.”
Preferred
Stock
Our
board
of directors may, without shareholder approval, establish and issue shares
of
one or more classes or series of preferred stock having the designations,
number
of shares, dividend rates, liquidation preferences, redemption provisions,
sinking fund provisions, conversion rights, voting rights and other rights,
preferences and limitations that our board may determine. Our board may
authorize the issuance of preferred stock with voting, conversion and economic
rights senior to the common stock so that the issuance of preferred stock
could
adversely affect the market value of the common stock. The creation of one
or
more series of preferred stock may adversely affect the voting power or other
rights of the holders of common stock. The issuance of preferred stock, while
providing flexibility in connection with possible acquisitions and other
corporate purposes, could, among other things and under some circumstances,
have
the effect of delaying, deferring or preventing a change in control without
any
action by shareholders. Our board of directors has authorized the issuance
of
2,500,000 shares of Class A Preferred Shares. As of June 30,
2007, there were no remaining shares of our Class A Preferred Shares
outstanding.
No
other
classes or series of preferred stock are currently authorized or
outstanding.
Stock
Certificates
Our
bylaws permit each shareholder to elect whether to hold our stock as an
uncertificated security or in the form of a paper stock certificate.
Shareholders holding uncertificated securities will receive a written
information statement summarizing their holdings. We participate in the Direct
Registration System through our transfer agent.
Warrants
The
warrants being registered in connection with the January Private Placement
are
exercisable at $1.75 per share and expire on January 31, 2009. The warrants
may
be exercised in whole or in part, subject to the limitations provided in
the
warrants. Any warrant holders who do not exercise their warrants prior to
the
conclusion of the exercise period will forfeit the right to purchase the
shares
of common stock underlying the warrants and any outstanding warrants will
become
void and be of no further force or effect. If at any time while any of the
warrants are outstanding we issue common stock or securities convertible
into
common stock to any person at a price per share of common stock less than
the
exercise price of the warrants, the exercise price of the warrants will be
reduced pursuant to a formula as provided in the warrant. In addition, in
the
event of a merger, consolidation, or sale of all or substantially all of
our
assets, the holder of the warrant has the right to receive a warrant
substantially similar to the warrant or, at the option of the holder of the
warrant, an amount in cash equal to the value of the warrant. If a dividend
is
declared on our common stock, the exercise price of the warrant will be reduced
in accordance with the terms of the warrant and the number of shares of common
stock the warrant is exercisable for will be proportionately increased. If
we
were to offer any securities to its holders of common stock as a class, the
holder of the warrant would be entitled to purchase such number of securities
as
if the warrant holder were a holder of common stock.
Holders
of the warrants have no voting rights of a shareholder, no liquidation
preference, and no dividends will be declared on the warrants.
Transfer
Agent and Registrar
Our
transfer agent and registrar is Mellon Investor Services.
Securities
Authorized For Issuance Under Equity Compensation Plans
In
October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it
was
authorized to issue compensatory options to purchase up to 1,000,000 shares
of common stock. Prior to the merger closing, Aurora had issued options to
purchase a total of 580,000 shares of Aurora’s common stock under this
plan, which upon closing the merger, converted into the right to acquire
up to
1,160,000 shares of our common stock. Because of the merger, no further
awards can be made under this plan.
In
2001,
Aurora’s board of directors and shareholders approved the adoption of an Equity
Compensation Plan for Non-Employee Directors. This plan provided that each
non-employee director is entitled to receive options to purchase
100,000 shares of Aurora’s common stock, issuable in increments of options
to purchase 33,333 shares each year over a period of three years, so long
as the director continues in office. Prior to the merger closing, Aurora
had
issued options to purchase a total of 309,997 shares of Aurora common stock
under this plan, which upon closing the merger converted to the right to
acquire
619,994 shares of our common stock. Because of the merger, no further
awards can be made under this plan.
In
2004,
our board of directors adopted a 2004 Equity Incentive Plan. Our shareholders
approved this plan, also in 2004. This plan provides for the grant of options
or
restricted shares for compensatory purposes for up to 1,000,000 shares of
common stock. The number of shares issued or subject to options issued under
this plan totaled 910,500. Although we do not intend to make any further
awards
under this plan, this plan currently continues to exist.
In
March
2006, our board of directors adopted, and in May 2006 our shareholders approved,
the 2006 Stock Incentive Plan. This Plan provides for the award of options
or
restricted shares for compensatory purposes for up to 8,000,000 shares. As
of June 30, 2007, we had awarded restricted stock and options to purchase
restricted stock in a total amount of 2,742,500 shares, leaving
5,257,500 shares available for future awards.
We
have
awarded compensatory options and warrants on an individualized basis in addition
to awards under our 2004 Equity Incentive Plan. Aurora has also issued
compensatory options and warrants on an individualized basis in addition
to its
1997 Stock Option Plan and Equity Compensation Plan for Non-Employee
Directors.
The
following chart sets forth certain information as of June 30, 2007, regarding
the shares of our common stock (i) issuable upon exercise of options or
warrants granted as compensation for services; and (ii) available for grant
under existing plans.
Plan
Category
|
|
No.
of Securities
to
be
Issued
Upon Exercise of
Outstanding
Options,
Warrants
and Rights
|
|
Weighted
Average
Exercise
Price of
Outstanding
Options,
Warrants
and Rights
|
|
No.
of Securities Remaining
Available
for Future Issuance
Under
Equity Compensation
Plans
(Excluding Securities in
the
First Column of this Table)
|
|
Equity
compensation plans approved by security holders
|
|
|
3,364,164
|
|
$
|
2.99
|
|
|
5,257,500
|
|
Equity
compensation plans and awards not approved by security
holders
|
|
|
86,280(a
|
)
|
|
1.69
|
|
|
-
|
|
Total
|
|
|
3,450,444
|
|
$
|
2.96
|
|
|
5,257,500
|
|
(a)
|
These
options and warrants were issued pursuant to the following
plans:
|
Warrants
to purchase 56,000 shares (these are Aurora conversion shares originally
issued to purchase 28,000 shares of Aurora common stock) were issued to Nathan
A. Low and his designees in compensation for investment banking services
rendered.
Options
to purchase 30,280 shares were issued in two separate individualized
compensation arrangements with executive officers and/or directors not pursuant
to a formal plan.
Shares Eligible
For Future Sale
Our
shares of common stock that are eligible for future sale may have an adverse
effect on the price of our stock. At June 30, 2007, we had
101,412,966 shares of common stock outstanding. Of this amount,
11,702,580 shares (approximately 11.5% of our outstanding shares prior to
the close of this offering) are subject to lock-up and may not be sold through
October 31, 2008.
We
have
two shelf registration statements that are currently effective, which together
have registered almost 20.6 million shares of common stock for resale. This
includes approximately 296,000 shares issuable upon exercise of certain
outstanding warrants and options, with the balance being shares that are
already
issued. We are maintaining the effectiveness of these registration statements
because of registration rights agreements provided in the financings received
by
us and Aurora on January 31, 2005.
On
June
30, 2007, we had options and warrants to purchase 6,746,444 shares of
common stock outstanding, and we had still available 5,257,500 shares for
issuance under our 2006 Stock Incentive Plan.
Upon
completion of this offering, we will have outstanding an aggregate of
101,679,456 shares of common stock, assuming no exercise of outstanding
options and warrants. All of the shares sold in this offering will be freely
tradable without restriction or further registration under the Securities
Act
except for shares, if any, which may be acquired by our “affiliates” as that
term is defined in Rule 144 under the Securities Act. Persons who may be
deemed to be affiliates generally include individuals or entities that control,
are controlled by, or are under common control with, us and may include our
directors and officers as well as our significant shareholders.
In
general, under Rule 144 as currently in effect, a person who has
beneficially owned shares of our common stock for at least one year is entitled
to sell within any three-month period a number of shares that does not exceed
the greater of:
|
·
|
1%
of the number of shares of our common stock then outstanding, which
will
equal approximately 1,016,795 shares immediately after this
offering; and
|
|
·
|
the
average weekly trading volume of our common stock on AMEX during
the four
calendar weeks preceding the filing of a notice on Form 144 with
respect to such sale.
|
Sales
under Rule 144 are also subject to manner of sale provisions and notice
requirements and to the availability of current public information about
us.
Under Rule 144(k), a person who has not been one of our affiliates at any
time during the 90 days preceding a sale, and who has beneficially owned
the shares proposed to be sold for at least two years, is entitled to sell
those
shares without complying with the manner of sale, public information, volume
limitation or notice provisions of Rule 144.
Anti-Takeover
Provisions
Utah
law,
our articles of incorporation and our bylaws permit our board of directors
to
issue undesignated preferred stock. This ability may enable our board of
directors to render more difficult or discourage an attempted change of control
of us by means of a merger, tender offer, proxy contest, or otherwise. For
example, if in the due exercise of its fiduciary obligations, the board of
directors were to determine that a takeover proposal is not in our best
interest, the board of directors could cause shares of preferred stock to
be
issued without shareholder approval in one or more private offerings or other
transactions that might dilute the voting or other rights of the proposed
acquirer, or insurgent shareholder or shareholder group. These provisions
are
expected to discourage coercive takeover practices and inadequate takeover
bids.
These provisions are also designed to encourage persons seeking to acquire
control of us to first negotiate with our board of directors. We believe
that
the benefits of increased protection of our potential ability to negotiate
with
the proponent of an unfriendly or unsolicited proposal to acquire or restructure
us outweigh the disadvantages of discouraging such proposals because
negotiations of such proposals could result in an improvement of their
terms.
LEGAL
MATTERS
The
validity of the shares of common stock offered in this prospectus will be
passed
upon for us by Fraser Trebilcock Davis & Dunlap, P.C., Lansing,
Michigan.
EXPERTS
Our
consolidated financial statements for the years ended December 31, 2006 and
December 31, 2005 have been audited by Rachlin Cohen & Holtz LLP,
an independent registered public accounting firm, as indicated in their
accompanying report. These financial statements and accompanying report are
included in this prospectus in reliance on the authority of Rachlin
Cohen & Holtz LLP as an expert in auditing and accounting.
The
reference to (and inclusion of) the reports of Data & Consulting
Services, Division of Schlumberger Technology Corporation, referred to in
this
prospectus as Schlumberger Holditch, with respect to estimates of proved
reserves of oil and natural gas located in Michigan and Indiana, and the
reference to (and inclusion of) reports of acquired proved reserves estimated
by
Netherland, Sewell & Associates, Inc. and Ralph E. Davis Associates,
Inc., is made in reliance upon the authority of these firms as experts with
respect to such matters.
CHANGE
IN INDEPENDENT AUDITORS
On
March
23, 2007, after the completion of the audit of our financial statements for
the
years ended December 31, 2006 and 2005, the Company dismissed Rachlin Cohen
& Holtz LLP as its independent auditors. The report of Rachlin Cohen &
Holtz LLP on the Company’s financial statements for the years ended December 31,
2006 and 2005, contained no adverse opinion or disclaimer of opinion and
was not
qualified or modified as to uncertainty, audit scope, or accounting principles.
In connection with its audit for the years ended December 31, 2006 and 2005,
there have been no disagreements with Rachlin Cohen & Holtz LLP on any
matter of accounting principles or practices, financial statement disclosure,
or
auditing scope or procedure, which disagreements, if not resolved to the
satisfaction of Rachlin Cohen & Holtz LLP, would have caused them to make
reference thereto in their report on the financial statements for such years
except as described in the following paragraph:
As
described under Item 3 of the Company’s Form 10-QSB/A for the quarter ended
March 31, 2006 (as filed on October 31, 2006), Rachlin Cohen & Holtz LLP
advised the Company and the Company disclosed that it had a material weakness
resulting from a deficiency in internal controls relating to the lack of
accounting recognition given to the stock option grants authorized and approved
by the Board of Directors in March 2006, which resulted in (a) the
financial statements being modified to account for all of the stock option
grants in accordance with the applicable provisions of Statement of Financial
Accounting Standards No. 123(R) and (b) remedial actions being taken
by the Company. In addition, as described under Item 3 of the Company’s Form
10-QSB/A for the quarter ended June 30, 2006 (as filed on October 31, 2006),
the
Company validated the remedial actions taken to correct the material weakness
in
connection with the reporting of stock option compensation.
The
decision to change firms was approved by our Audit Committee of the Board
of
Directors.
The
Company engaged Weaver and Tidwell L.L.P. as its new independent auditors
effective March 23, 2007, and we have relied upon Weaver and Tidwell L.L.P.
as
an expert in auditing and accounting from that date.
WHERE
YOU CAN FIND MORE INFORMATION
We
have
filed with the SEC a registration statement on Form SB-2 under the
Securities Act covering the securities offered by this prospectus. This
prospectus, which constitutes a part of that registration statement, does
not
contain all of the information that you can find in that registration statement
and its exhibits. Certain items are omitted from this prospectus in accordance
with the rules and regulations of the SEC. For further information about
us and
the common stock offered by this prospectus, reference is made to the
registration statement and the exhibits filed with the registration statement.
Statements contained in this prospectus and any prospectus supplement as
to the
contents of any contract or other document referred to are not necessarily
complete and in each instance such statement is qualified by reference to
each
such contract or document filed as part of the registration statement. We
are
subject to the information and reporting requirements of the Exchange Act
, and
are therefore required to file annual, quarterly and current reports, proxy
statements and other information with the SEC. You may read any materials
we
file with the SEC free of charge at the SEC’s Public Reference Room at 100 F
Street, N.E., Washington, D.C. 20549. Copies of all or any part of these
documents may be obtained from such office upon the payment of the fees
prescribed by the SEC. The public may obtain information on the operation
of the
public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains
an
Internet site that contains reports, proxy and information statements and
other
information regarding registrants that file electronically with the SEC.
The
address of the site is
www.sec.gov
.
The
registration statement, including all exhibits thereto and amendments thereof,
has been filed electronically with the SEC.
You
should rely only on the information provided in this prospectus, any prospectus
supplement or as part of the registration statement filed on Form SB-2 of
which this prospectus is a part, as such registration statement is amended
and
in effect with the SEC. We have not authorized anyone else to provide you
with
different information. We are not making an offer to sell these securities
in
any state where the offer is not permitted. You should not assume that the
information in this prospectus, any prospectus supplement or any document
incorporated by reference is accurate as of any date other than the date
of
those documents.
FINANCIAL
STATEMENTS
INDEX
TO FINANCIAL STATEMENTS
|
|
Page
|
|
Aurora
Oil & Gas Corporation Consolidated Financial
Statements
|
|
|
|
for
the years ended December 31, 2006 and 2005
|
|
|
|
Report
of Independent Registered Public Accounting Firm
|
|
|
F-ii
|
|
Consolidated
Financial Statements
|
|
|
|
|
Balance
Sheets
|
|
|
F1-F2
|
|
Statements
of Operations
|
|
|
F-3
|
|
Statements
of Shareholders’ Equity
|
|
|
F-4
|
|
Statements
of Cash Flows
|
|
|
F5-F6
|
|
Notes
to Financial Statements
|
|
|
F7-F28
|
|
Supplemental
Oil and Gas Information (unaudited)
|
|
|
F29-F32
|
|
Aurora
Oil & Gas Corporation Unaudited Condensed Consolidated Financial
Statements
|
|
|
|
|
for
the Six Months Ended June 30, 2007 and 2006
|
|
|
F33
|
|
Unaudited
Condensed Consolidated Financial Statements
|
|
|
|
|
Balance
Sheet
|
|
|
F34-F35
|
|
Statements
of Operations
|
|
|
F-36
|
|
Statement
of Shareholders’ Equity
|
|
|
F-37
|
|
Statements
of Cash Flows
|
|
|
F38-F39
|
|
Notes
to Financial Statements
|
|
|
F40-F51
|
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board
of
Directors and Shareholders
Aurora
Oil & Gas Corporation and Subsidiaries
Traverse
City, Michigan
We
have
audited the accompanying consolidated balance sheets of Aurora Oil & Gas
Corporation and Subsidiaries as of December 31, 2006 and 2005, and the related
consolidated statements of operations, shareholders’ equity, and cash flows for
each of the years then ended. These consolidated financial statements are
the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required
to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audit included consideration of internal control
over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company’s internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures
in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In
our
opinion, the consolidated financial statements referred to above present
fairly,
in all material respects, the financial position of Aurora Oil & Gas
Corporation and Subsidiaries as of December 31, 2006, and 2005, and the
results of their operations and their cash flows for each of the years then
ended in conformity with accounting principles generally accepted in the
United
States.
As
discussed in Note 3 to the consolidated financial statements, the Company
changed the manner in which it accounts for share-based payments in
2006.
RACHLIN
COHEN & HOLTZ LLP
Miami,
Florida
March
13,
2007
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
1,735,396
|
|
$
|
11,980,638
|
|
Accounts
receivable
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
|
4,082,231
|
|
|
2,409,675
|
|
Joint
interest owners
|
|
|
3,079,715
|
|
|
4,380,606
|
|
Notes
receivable
|
|
|
|
|
|
|
|
Related
party
|
|
|
-
|
|
|
35,720
|
|
Other
|
|
|
341,698
|
|
|
208,626
|
|
Drilling
advances
|
|
|
1,408,860
|
|
|
-
|
|
Prepaid
expenses and other current assets
|
|
|
264,024
|
|
|
240,242
|
|
Short-term
derivative instruments
|
|
|
3,552,060
|
|
|
-
|
|
Total
current assets
|
|
|
14,463,984
|
|
|
19,255,507
|
|
|
|
|
|
|
|
|
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
|
|
|
|
Oil
and natural gas properties, using full cost accounting:
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
121,178,499
|
|
|
39,643,003
|
|
Unproved
properties
|
|
|
41,847,526
|
|
|
37,279,889
|
|
Properties
held for sale
|
|
|
8,896,568
|
|
|
-
|
|
Less:
accumulated depletion and amortization
|
|
|
(10,628,438
|
)
|
|
(7,962,138
|
)
|
Total
oil and natural gas properties, net
|
|
|
161,294,155
|
|
|
68,960,754
|
|
Pipelines
|
|
|
4,881,240
|
|
|
-
|
|
Other
property and equipment
|
|
|
5,093,777
|
|
|
3,723,918
|
|
Less:
accumulated depreciation
|
|
|
(753,789
|
)
|
|
(113,780
|
)
|
Total
property and equipment, net
|
|
|
170,515,383
|
|
|
72,570,892
|
|
|
|
|
|
|
|
|
|
OTHER
ASSETS:
|
|
|
|
|
|
|
|
Long-term
derivative instruments
|
|
|
1,668,573
|
|
|
-
|
|
Deposits
on purchase of oil and natural gas properties
|
|
|
-
|
|
|
3,206,102
|
|
Goodwill
|
|
|
19,373,264
|
|
|
15,973,346
|
|
Intangibles
(net of accumulated amortization of
|
|
|
|
|
|
|
|
$2,946,250
and $1,407,083, respectively)
|
|
|
2,008,750
|
|
|
3,197,917
|
|
Other
investments
|
|
|
985,706
|
|
|
1,855,977
|
|
Debt
issuance costs (net of accumulated amortization
|
|
|
|
|
|
|
|
of
$892,535 and $79,096, respectively)
|
|
|
2,363,898
|
|
|
723,993
|
|
Other
|
|
|
1,007,634
|
|
|
38,411
|
|
Total
other assets
|
|
|
27,407,825
|
|
|
24,995,746
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
212,387,192
|
|
$
|
116,822,145
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
December
31,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
Accounts
payable and accrued liabilities
|
|
$
|
5,701,464
|
|
$
|
5,489,657
|
|
Accrued
exploration, development, and leasehold costs
|
|
|
11,587,850
|
|
|
1,980,922
|
|
Short-term
bank borrowings
|
|
|
542,788
|
|
|
6,210,000
|
|
Current
portion of obligations under capital leases
|
|
|
8,868
|
|
|
8,823
|
|
Current
portion of note payable - related party
|
|
|
-
|
|
|
69,833
|
|
Current
portion of note payable - other
|
|
|
161,774
|
|
|
-
|
|
Current
portion of mortgage payable
|
|
|
95,828
|
|
|
72,877
|
|
Drilling
advances
|
|
|
19,383
|
|
|
-
|
|
Deposit
on sale of oil and natural gas properties
|
|
|
-
|
|
|
3,509,319
|
|
Total
current liabilities
|
|
|
18,117,955
|
|
|
17,341,431
|
|
|
|
|
|
|
|
|
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
|
|
|
Obligations
under capital leases, net of current portion
|
|
|
8,228
|
|
|
2,262
|
|
Asset
retirement obligation
|
|
|
1,331,893
|
|
|
-
|
|
Notes
payable
|
|
|
118,547
|
|
|
-
|
|
Mortgage
payable
|
|
|
3,079,470
|
|
|
2,792,600
|
|
Senior
secured credit facility
|
|
|
10,000,000
|
|
|
-
|
|
Mezzanine
financing
|
|
|
40,000,000
|
|
|
40,000,000
|
|
Total
long-term liabilities
|
|
|
54,538,138
|
|
|
42,794,862
|
|
Total
liabilities
|
|
|
72,656,093
|
|
|
60,136,293
|
|
|
|
|
|
|
|
|
|
COMMITMENTS,
CONTINGENCIES and SUBSEQUENT EVENT (Notes 11 and
16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REDEEMABLE
CONVERTIBLE PREFERRED STOCK:
|
|
|
|
|
|
|
|
Authorized
20,000,000 shares; outstanding none
|
|
|
|
|
|
|
|
and
34,984 shares, respectively
|
|
|
-
|
|
|
59,925
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS'
EQUITY:
|
|
|
|
|
|
|
|
Common
stock, $.01 par value; authorized 250,000,000
|
|
|
|
|
|
|
|
shares;
issued and outstanding 101,412,966 shares
|
|
|
|
|
|
|
|
and
61,536,261, respectively
|
|
|
1,014,130
|
|
|
615,363
|
|
Additional
paid-in capital
|
|
|
138,105,626
|
|
|
58,670,698
|
|
Accumulated
other comprehensive income
|
|
|
5,220,633
|
|
|
-
|
|
Accumulated
deficit
|
|
|
(4,609,290
|
)
|
|
(2,660,134
|
)
|
Total
shareholders' equity
|
|
|
139,731,099
|
|
|
56,625,927
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
$
|
212,387,192
|
|
$
|
116,822,145
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
Year
Ended December 31,
|
|
|
|
2006
|
|
2005
|
|
REVENUES:
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$
|
21,591,811
|
|
$
|
6,743,444
|
|
Pipeline
transportation and marketing
|
|
|
1,179,431
|
|
|
-
|
|
Field
service and sales
|
|
|
125,611
|
|
|
-
|
|
Interest
and other
|
|
|
220,592
|
|
|
666,850
|
|
Total
revenues
|
|
|
23,117,445
|
|
|
7,410,294
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
877,319
|
|
|
506,635
|
|
Production
and lease operating expense
|
|
|
6,278,131
|
|
|
1,587,205
|
|
Pipeline
operating expense
|
|
|
643,963
|
|
|
-
|
|
Field
services expense
|
|
|
90,913
|
|
|
-
|
|
General
and administrative expense
|
|
|
7,531,718
|
|
|
3,435,507
|
|
Oil
and natural gas depletion and amortization
|
|
|
2,681,290
|
|
|
767,511
|
|
Other
assets depreciation and amortization
|
|
|
2,083,191
|
|
|
308,647
|
|
Interest
expense
|
|
|
4,573,785
|
|
|
1,307,370
|
|
Taxes,
other
|
|
|
250,884
|
|
|
29,651
|
|
Total
expenses
|
|
|
25,011,194
|
|
|
7,942,526
|
|
|
|
|
|
|
|
|
|
LOSS
BEFORE MINORITY INTEREST
|
|
|
(1,893,749
|
)
|
|
(532,232
|
)
|
|
|
|
|
|
|
|
|
MINORITY
INTEREST IN (INCOME)
|
|
|
|
|
|
|
|
LOSS
OF SUBSIDIARIES
|
|
|
(50,898
|
)
|
|
15,960
|
|
|
|
|
|
|
|
|
|
NET
LOSS
|
|
$
|
(1,944,647
|
)
|
$
|
(516,272
|
)
|
|
|
|
|
|
|
|
|
NET
LOSS PER COMMON SHARE-BASIC AND DILUTED
|
|
$
|
(0.02
|
)
|
$
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE COMMON SHARES
|
|
|
|
|
|
|
|
OUTSTANDING
- BASIC AND DILUTED
|
|
|
82,288,243
|
|
|
40,622,000
|
|
Supplemental
Information
Net
loss
for the years ended December 31, 2006, and 2005, included stock-based
compensation expense of $2,206,801 and none, respectively, under Statement
of
Financial Accounting Standards No. 123 (revised 2004). See Note 3 “Common Stock
Options” for additional information.
The
accompanying notes are an integral part of these consolidated financial
statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
|
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS' EQUITY
|
|
|
Year
Ended December 31,
|
|
|
|
2006
|
|
2005
|
|
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
COMMON
STOCK:
|
|
|
|
|
|
|
|
|
|
Balance,
beginning
|
|
|
61,536,261
|
|
$
|
615,363
|
|
|
13,775,933
|
|
$
|
13,776
|
|
Cashless
exercise of stock options and warrants
|
|
|
3,280,105
|
|
|
32,801
|
|
|
245,068
|
|
|
2,451
|
|
Conversion
of redeemable convertible preferred stock to common stock
|
|
|
34,984
|
|
|
349
|
|
|
298,050
|
|
|
298
|
|
Issuance
of stock in private placement, net of commissions and fees
|
|
|
-
|
|
|
-
|
|
|
4,972,200
|
|
|
4,972
|
|
Exercise
of stock options prior to merger
|
|
|
-
|
|
|
-
|
|
|
10,000
|
|
|
10
|
|
Issuance
of stock in connection with the merger between Cadence and
Aurora
|
|
|
-
|
|
|
-
|
|
|
39,592,510
|
|
|
567,431
|
|
Exercise
of stock options and warrants
|
|
|
15,823,457
|
|
|
158,235
|
|
|
2,642,500
|
|
|
26,425
|
|
Issuance
of stock in connection with public equity offering
|
|
|
19,600,000
|
|
|
196,000
|
|
|
-
|
|
|
-
|
|
Issuance
of stock in connection with an acquisition
|
|
|
1,378,299
|
|
|
13,783
|
|
|
-
|
|
|
-
|
|
Issuance
of stock to officers and directors in lieu of compensation
|
|
|
90,000
|
|
|
900
|
|
|
|
|
|
|
|
Issuance
of stock to related parties in lieu of commission relating to
exercise of
warrants
|
|
|
1,469,860
|
|
|
14,699
|
|
|
-
|
|
|
-
|
|
Rescission
of stock option exercises by certain officers
|
|
|
(1,800,000
|
)
|
|
(18,000
|
)
|
|
-
|
|
|
-
|
|
Balance,
end
|
|
|
101,412,966
|
|
$
|
1,014,130
|
|
|
61,536,261
|
|
$
|
615,363
|
|
ADDITIONAL
PAID-IN CAPITAL:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
beginning
|
|
|
|
|
|
58,670,698
|
|
|
|
|
|
8,183,025
|
|
Cashless
exercise of stock options and warrants
|
|
|
|
|
|
(32,801
|
)
|
|
|
|
|
(2,451
|
)
|
Conversion
of redeemable convertible preferred stock to common stock
|
|
|
|
|
|
59,576
|
|
|
|
|
|
148,727
|
|
Issuance
of stock in private placement, net of commissions and fees
|
|
|
|
|
|
-
|
|
|
|
|
|
11,020,028
|
|
Exercise
of stock options prior to merger
|
|
|
|
|
|
-
|
|
|
|
|
|
7,490
|
|
Issuance
of stock in connection with merger between Cadence and
Aurora
|
|
|
|
|
|
-
|
|
|
|
|
|
35,706,179
|
|
Stock-based
compensation
|
|
|
|
|
|
2,663,814
|
|
|
|
|
|
-
|
|
Exercise
of stock options and warrants
|
|
|
|
|
|
18,143,714
|
|
|
|
|
|
3,607,700
|
|
Issuance
of stock in connection with public equity offering
|
|
|
|
|
|
54,309,807
|
|
|
|
|
|
-
|
|
Issuance
of stock in connection with an acquisition
|
|
|
|
|
|
4,686,217
|
|
|
|
|
|
-
|
|
Issuance
of stock to officers and directors in lieu of compensation
|
|
|
|
|
|
348,300
|
|
|
|
|
|
-
|
|
Issuance
of stock to related party in lieu of commission relating to exercise
of
warrants
|
|
|
|
|
|
(14,699
|
)
|
|
|
|
|
-
|
|
Rescission
of stock option exercises by certain officers
|
|
|
|
|
|
(729,000
|
)
|
|
|
|
|
-
|
|
Balance,
end
|
|
|
|
|
$
|
138,105,626
|
|
|
|
|
$
|
58,670,698
|
|
ACCUMULATED
OTHER COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
beginning
|
|
|
|
|
|
-
|
|
|
|
|
|
-
|
|
Unrealized
gains on derivative instruments
|
|
|
|
|
|
7,903,933
|
|
|
|
|
|
-
|
|
Recognition
of gain on derivative instruments
|
|
|
|
|
|
(2,683,300
|
)
|
|
|
|
|
-
|
|
Balance,
end
|
|
|
|
|
$
|
5,220,633
|
|
|
|
|
|
-
|
|
ACCUMULATED
DEFICIT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
beginning
|
|
|
|
|
|
(2,660,134
|
)
|
|
|
|
|
(2,099,522
|
)
|
Dividends
accrued on redeemable convertible preferred stock
|
|
|
|
|
|
(4,509
|
)
|
|
|
|
|
(44,340
|
)
|
Net
loss
|
|
|
|
|
|
(1,944,647
|
)
|
|
|
|
|
(516,272
|
)
|
Balance,
end
|
|
|
|
|
|
(4,609,290
|
)
|
|
|
|
|
(2,660,134
|
)
|
TOTAL
SHAREHOLDERS' EQUITY
|
|
|
|
|
$
|
139,731,099
|
|
|
|
|
$
|
56,625,927
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
Year
Ended December 31,
|
|
|
|
2006
|
|
2005
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
loss
|
|
$
|
(1,944,647
|
)
|
$
|
(516,272
|
)
|
Adjustments
to reconcile net loss to net cash provided by (used in) operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
4,764,481
|
|
|
1,076,158
|
|
Amortization
of debt issuance costs
|
|
|
813,715
|
|
|
79,096
|
|
Accretion
of asset retirement obligation
|
|
|
74,097
|
|
|
-
|
|
Stock-based
compensation
|
|
|
2,206,801
|
|
|
-
|
|
Equity
loss of other investments and other
|
|
|
329,902
|
|
|
116,372
|
|
Changes
in operating assets and liabilities, net of effects of merger and
acquisitions:
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
532,765
|
|
|
(3,827,537
|
)
|
Drilling
advance, net
|
|
|
(1,389,477
|
)
|
|
(387,175
|
)
|
Prepaid
expenses
|
|
|
(66,173
|
)
|
|
41,634
|
|
Other
assets
|
|
|
(1,052,297
|
)
|
|
-
|
|
Accounts
payable and accrued liabilities
|
|
|
(2,024,632
|
)
|
|
1,025,606
|
|
Net
cash provided by (used in) operating activities
|
|
|
2,244,535
|
|
|
(2,392,118
|
)
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Exploration
and development of oil and natural gas properties
|
|
|
(42,048,099
|
)
|
|
(29,087,260
|
)
|
Leasehold
expenditures, net
|
|
|
(26,837,697
|
)
|
|
(18,283,002
|
)
|
Acquisition
of oil and natural gas properties
|
|
|
(24,011,335
|
)
|
|
-
|
|
Sale
of oil and natural gas properties
|
|
|
11,489,456
|
|
|
11,504,428
|
|
Acquisitions/additions
for pipeline, property and equipment
|
|
|
(4,111,780
|
)
|
|
(4,523,706
|
)
|
Additions
in other investments
|
|
|
(855,070
|
)
|
|
(485,741
|
)
|
Other,
net
|
|
|
56,788
|
|
|
36,314
|
|
Net
cash acquired in merger
|
|
|
-
|
|
|
957,020
|
|
Net
cash used in investing activities
|
|
|
(86,317,737
|
)
|
|
(39,881,947
|
)
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Net
short-term bank borrowings (payments)
|
|
|
(5,775,628
|
)
|
|
5,860,000
|
|
Advances
on senior secured credit facility
|
|
|
60,000,000
|
|
|
-
|
|
Payments
on senior secured credit facility
|
|
|
(50,000,000
|
)
|
|
-
|
|
Advances
on mezzanine financing
|
|
|
-
|
|
|
30,000,000
|
|
Advances
(payments) on mortgage obligations
|
|
|
(73,205
|
)
|
|
2,865,477
|
|
Payments
of financing fees on credit facilities
|
|
|
(2,452,786
|
)
|
|
(508,542
|
)
|
Distributions
to minority interest members
|
|
|
-
|
|
|
(805,000
|
)
|
Net
proceeds from sales of common stock
|
|
|
54,505,807
|
|
|
14,666,625
|
|
Net
proceeds from exercise of options and warrants
|
|
|
17,554,949
|
|
|
-
|
|
Dividends
paid on preferred stock
|
|
|
(20,250
|
)
|
|
(44,340
|
)
|
Other,
net
|
|
|
89,073
|
|
|
(2,959,099
|
)
|
Net
cash provided by financing activities
|
|
|
73,827,960
|
|
|
49,075,121
|
|
Net
(decrease) increase in cash and cash equivalents
|
|
|
(10,245,242
|
)
|
|
6,801,056
|
|
Cash
and cash equivalents, beginning of the period
|
|
|
11,980,638
|
|
|
5,179,582
|
|
Cash
and cash equivalents, end of the period
|
|
$
|
1,735,396
|
|
$
|
11,980,638
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
Year
Ended December 31,
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
NONCASH
FINANCING AND INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Oil
and natural gas properties asset retirement obligation
|
|
$
|
1,257,796
|
|
$
|
-
|
|
Accrued
exploration and development costs on oil and natural gas
properties
|
|
|
11,161,730
|
|
|
1,464,032
|
|
Accrued
leasehold costs
|
|
|
426,120
|
|
|
516,890
|
|
Properties
acquired in connection with Cadence merger in exchange for
equity
|
|
|
|
|
|
|
|
—Oil
and natural gas properties, net
|
|
|
-
|
|
|
14,647,614
|
|
—Intangibles
and goodwill
|
|
|
-
|
|
|
20,578,346
|
|
—Other
investments
|
|
|
-
|
|
|
1,701,238
|
|
Field
service acquisition through common stock issuance including $600,000
of
unproven leasehold
|
|
|
4,686,217
|
|
|
-
|
|
Pipeline
acquisition, transfer of investment to pipeline assets
|
|
|
1,100,973
|
|
|
-
|
|
Oil
and natural gas properties capitalized stock-based
compensation
|
|
|
457,013
|
|
|
-
|
|
SUPPLEMENTAL
INFORMATION OF INTEREST PAID:
|
|
|
|
|
|
|
|
Cash
paid for interest
|
|
$
|
7,286,611
|
|
$
|
2,215,745
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
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
an oil and natural gas corporation 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 and the New
Albany
shale of Indiana and Kentucky.
On
October 31, 2005, the Company (formerly Cadence) acquired Aurora Energy,
Ltd.
(“Aurora”) through the merger of a wholly-owned subsidiary with and into Aurora.
As a result of the merger, Aurora became a wholly-owned subsidiary. The merger
has been accounted for as a reverse acquisition using the purchase method
of
accounting. See Note 2 “Merger with Aurora Energy, Ltd.” for complete discussion
of the merger.
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. To cover a portion of the
existing production, the Company entered into a firm delivery gas contract
to be
effective for the period April 1, 2006, through March 31, 2007, for the
delivery of 5,000 mmbtu per day. The Company will be paid $0.01 per mmbtu
less
than the published index for this gas. The Company also has five other base
contracts for the sale of natural gas. 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
in the
spot markets or under the base contracts.
As
an
independent oil and natural gas producer, 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.
|
MERGER
WITH AURORA ENERGY, LTD.
|
On
October 31, 2005, the Company (formerly Cadence) acquired Aurora through
the
merger of a wholly-owned subsidiary with and into Aurora. As a result of
the
merger, Aurora became a wholly-owned subsidiary. The merger has been accounted
for as a reverse acquisition using the purchase method of accounting. Although
the merger was structured such that Aurora became a wholly-owned subsidiary
of
the Company, Aurora has been treated as the acquiring company for accounting
purposes under Statement of Financial Accounting Standards (“SFAS”) No. 141,
“Business Combinations,” due to the following factors: (1) Aurora’s
stockholders received the larger share of the voting rights in the merger;
(2) Aurora received the majority of the members of the board of directors;
and (3) Aurora’s senior management, prior to the merger, dominated the
senior management of the combined company.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
The
definitive merger agreement was executed on January 31, 2005, whereby Cadence
agreed to acquire 100% of the outstanding stock and options of Aurora.
Consideration in this transaction consisted of the issuance of two shares
of
common stock of Cadence for every one share of outstanding stock of Aurora
and
the issuance of two options for the purchase of stock in Cadence for each
option
outstanding of Aurora. The purchase price was $41,546,351 determined as
follows:
Fair
value of Cadence’s common stock outstanding at January 31,
2005
(a)
|
|
$
|
33,951,817
|
|
Fair
value of Cadence’s stock options outstanding at January 31,
2005
|
|
|
536,210
|
|
Fair
value of Cadence’s warrants outstanding at January 31,
2005
|
|
|
7,058,324
|
|
Total
purchase price
|
|
$
|
41,546,351
|
|
(a)
The
$33,951,817 was computed as 20,702,327 shares of Cadence common stock multiplied
by $1.64, the market price of Cadence common stock as of January 31, 2005,
the
date of the definitive merger agreement.
In
recording the acquisition of Cadence, the following table summarizes the
estimated fair value of the assets acquired and the liabilities assumed at
the
date of acquisition. The Company obtained third-party valuations of certain
tangible and intangible assets acquired from Cadence.
Net
working capital, adjusted for Cadence operating activity from date
of
definitive merger agreement to October 31, 2005
|
|
$
|
4,679,078
|
|
Oil
and natural gas properties and property and equipment, net
|
|
|
14,647,614
|
|
Investments
|
|
|
1,503,832
|
|
Other
mineral properties
|
|
|
197,406
|
|
Noncompete
agreements
|
|
|
3,265,000
|
|
Proprietary
business relationships
|
|
|
1,340,000
|
|
Goodwill
|
|
|
15,973,346
|
|
Redeemable
convertible preferred stock
|
|
|
(59,925
|
)
|
|
|
$
|
41,546,351
|
|
The
following unaudited condensed pro forma results of operations reflect the
pro
forma combination of Aurora and Cadence as if the combination had occurred
at
the beginning of fiscal year 2005 compared with the historical results of
operations of Aurora for the same period.
|
|
2005
|
|
|
|
Historical
|
|
Pro
Forma
|
|
Oil
and natural gas revenues
|
|
$
|
6,743,444
|
|
$
|
8,821,869
|
|
Production
expenses
|
|
|
(2,093,840
|
)
|
|
(2,846,316
|
)
|
Net
operating revenues
|
|
|
4,649,604
|
|
|
5,975,553
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(516,272
|
)
|
$
|
(4,293,053
|
)
|
|
|
|
|
|
|
|
|
Net
loss per common share - basic and diluted
|
|
$
|
(0.01
|
)
|
$
|
(0.07
|
)
|
|
|
|
|
|
|
|
|
Weighted
average number of common shares outstanding - basic and
diluted
|
|
|
40,622,000
|
|
|
58,108,000
|
|
NOTE
3.
|
BASIS
OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
|
Principles
of Consolidation
The
accompanying consolidated financial statements of the Company include the
accounts of the wholly-owned subsidiaries. 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.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
As
a
result of the reverse acquisition discussed in Note 2 “Merger with Aurora
Energy, Ltd.,” the historical financial statements presented for periods prior
to the acquisition date are the financial statements of Aurora. The operations
of the former Cadence businesses have been included in the financial statements
from the date of acquisition. The common stock per share information in the
consolidated financial statements for the year ended December 31, 2005, and
related notes have been retroactively adjusted to give effect to the reverse
merger on October 31, 2005.
Use
of Estimates
The
preparation of consolidated financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Significant estimates underlying these 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.
Reclassifications
Certain
amounts in the prior year financial statements have been reclassified to
conform
to current year presentations.
Cash
and Cash Equivalents
The
Company considers all highly liquid investments with an initial maturity
of 3
months or less to be cash equivalents. The Company’s bank accounts periodically
exceed federally insured limits. As of December 31, 2006, cash in excess
of FDIC
limits amounted to approximately $3,123,000. The Company maintains its deposits
with high quality financial institutions and, accordingly, believes its credit
risk exposure associated with cash is remote.
Accounts
Receivable and Credit Policy
Accounts
receivable generally consist of amounts due from the sale of oil and natural
gas
products and from working interest partners for their proportionate share
of
expenses related to certain oil and natural gas projects. The Company regularly
assesses the collectibility of accounts receivable and accrues an allowance
when
it is believed that a receivable may not be collected. The allowance for
doubtful accounts was $79,030 and $0 at December 31, 2006, and 2005,
respectively.
The
Company extends credit, primarily in the form of uncollateralized oil and
natural gas sales and joint interest owner's receivables, to various companies
in the oil and natural gas industry which results in a concentration of credit
risk. The concentration of credit risk may be affected by changes in economic
or
other conditions within the industry and may accordingly impact the Company’s
overall credit risk. However, the risk of these unsecured receivables is
mitigated by the size, reputation, and nature of the companies to which the
Company extends credit. Oil and natural gas sales to the primary customer
were
approximately 62% and 56% of total oil and natural gas sales for the years
ended
December 31, 2006, and 2005, respectively.
Oil
and Natural Gas Properties
The
Company utilizes the full cost method of accounting for oil and natural gas
properties. Under this method, subject to a limitation based on estimated
value,
all costs associated with property acquisition, exploration, and development
activities of oil and natural gas, including costs of unsuccessful exploration
and overhead charges directly related to acquisition, exploration, and
development activities, are capitalized. The Company is currently participating
in oil and natural gas exploration and development projects in the Antrim
shale
of Michigan and the New Albany shale of southern Indiana and western Kentucky.
Thus, all capitalized costs of oil and natural gas properties considered
proven,
are amortized on the unit-of-production method using estimates of proven
reserves. No gain or loss is recognized upon the sale or abandonment of
undeveloped or producing oil and natural gas properties unless the sale
represents a significant portion of oil and natural gas properties and the
gain
or loss significantly alters the relationship between capitalized costs and
proven reserves.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Capitalized
costs of oil and natural gas properties may not exceed an amount equal to
the
present value, discounted at 10%, of estimated future net revenues from proven
reserves plus the lower of cost or fair value of unproven properties. Should
capitalized costs exceed this ceiling, an impairment is recognized. The present
value of estimated future net cash flows is computed by applying year-end
prices
of oil and natural gas to estimated future production of proved oil and natural
gas reserves as of year end less estimated future expenditures to be incurred
in
developing and producing the proved reserves and assuming continuation of
existing economic conditions.
Asset
Retirement Obligation
On
January 1, 2006, the Company adopted Financial Accounting Standards Board
(“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement
Obligations,” and 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 estimated the fair value of the
obligation 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. Prior to January 1, 2006, such amount
was
not considered material.
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. The accretion expense is included in interest
expense and the depreciation expense is included in depreciation, depletion,
and
amortization in the consolidated statement of operations.
The
change in the ARO for the year ended December 31, 2006, is as
follows:
|
|
2006
|
|
|
|
|
|
Beginning
balance
|
|
$
|
812,634
|
|
Liabilities
incurred
|
|
|
719,229
|
|
Liabilities
settled
|
|
|
(123,809
|
)
|
Accretion
expense
|
|
|
74,097
|
|
Revisions
of estimated liabilities
|
|
|
(150,258
|
)
|
Ending
balance
|
|
$
|
1,331,893
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Pipeline,
Other Property and Equipment
Pipeline,
other property, and equipment are recorded at original cost and depreciated
using the straight-line method over the estimated useful lives. Major
improvements, replacements, and renewals are capitalized while ordinary
maintenance and repairs are expensed as incurred. Long-lived assets, other
than
oil and natural gas properties, are evaluated annually for impairment to
determine if current circumstances and market conditions indicate the carrying
amount may not be recoverable. The Company has not recognized any impairment
losses for the years ended December 31, 2006, and 2005. A summary of the
pipeline, other property, and equipment for years ended December 31, 2006,
and
2005, are as follows:
|
|
2006
|
|
2005
|
|
Useful
Life in Years
|
|
|
|
|
|
|
|
|
|
Land
|
|
$
|
78,000
|
|
$
|
-
|
|
|
N/A
|
|
Buildings
|
|
|
3,552,392
|
|
|
3,165,382
|
|
|
40
|
|
Furniture
and fixtures
|
|
|
328,173
|
|
|
265,115
|
|
|
5-10
|
|
Office
equipment
|
|
|
65,781
|
|
|
39,579
|
|
|
5
|
|
Computer
equipment
|
|
|
234,782
|
|
|
148,601
|
|
|
5
|
|
Software
|
|
|
188,434
|
|
|
85,070
|
|
|
3-5
|
|
Vehicles
and other equipment
|
|
|
646,215
|
|
|
20,171
|
|
|
5
|
|
Total
other property and equipment
|
|
|
5,093,777
|
|
|
3,723,918
|
|
|
|
|
Less
accumulated depreciation
|
|
|
(341,198
|
)
|
|
(113,780
|
)
|
|
|
|
Other
property and equipment, net
|
|
$
|
4,752,579
|
|
$
|
3,610,138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines
|
|
$
|
4,881,240
|
|
$
|
-
|
|
|
15
|
|
Less
accumulated depreciation
|
|
|
(412,591
|
)
|
|
-
|
|
|
|
|
Pipelines,
net
|
|
$
|
4,468,649
|
|
$
|
-
|
|
|
|
|
Other
Investments
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. Under the equity method of accounting, the Company’s
proportionate share of the investees’ net income or loss is included in the
results of operations as other income. A summary of the other investments
for
the years ended December 31, 2006, and 2005, are as follows:
|
|
2006
|
|
2005
|
|
Investments
in unconsolidated subsidiaries:
|
|
|
|
|
|
Hudson
Pipeline & Processing Co., LLC
|
|
$
|
-
|
|
$
|
1,224,995
|
|
GeoPetra
Partners, LLC
|
|
|
721,596
|
|
|
344,502
|
|
Mineral
properties
|
|
|
197,406
|
|
|
197,406
|
|
Other
|
|
|
66,704
|
|
|
89,074
|
|
|
|
$
|
985,706
|
|
$
|
1,855,977
|
|
Goodwill
Goodwill
represents the excess of the purchase price over the fair value of net assets
acquired. The Company follows SFAS No. 142, “Goodwill and Other Intangible
Assets,” which requires that goodwill and intangible assets with indefinite
useful lives not to be amortized but written down, as needed, based on an
impairment test that must occur at least annually or sooner if an event occurs
or circumstances change that would more likely than not result in an impairment
loss. The amount of goodwill impairment, if any, is measured on projected
discounted future operating cash flows using a 10% discount rate. Future
impairment of goodwill could result if the Company’s estimated future operating
cash flows are not achieved. No impairment loss was recorded for the years
ended
December 31, 2006, and 2005, respectively.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Intangible
Assets
Acquired
intangible assets, which consist of noncompete agreements, pending patents,
and
proprietary business relationships, are recorded at fair value or cost and
amortized on a straight-line basis using estimated useful lives of 3 to 6
years.
A summary of amortization expense over the next 5 years is as
follows:
2007
|
|
$
|
1,551,667
|
|
2008
|
|
|
194,584
|
|
2009
|
|
|
66,666
|
|
2010
|
|
|
66,666
|
|
2011
|
|
|
66,667
|
|
Thereafter
|
|
|
62,500
|
|
|
|
$
|
2,008,750
|
|
Revenue
Recognition
Oil
and
natural gas revenue is recognized as income as production is extracted and
sold.
Revenues from service contracts are recognized ratably over the term of the
contract.
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.
For
the
year ended December 31, 2006, the Company recorded stock-based compensation
of
$2,663,814 under the 2006 Stock Incentive Plan, 2004 Equity Incentive Plan,
and
1997 Stock Option Plan (as described in Note 10 “Common Stock Options”), as well
as a certain employment agreement (as described in Note 11 “Contingencies and
Commitments”). Of that amount, $2,206,801 has been included in general and
administrative expense on the consolidated statement of operations and $457,013
has been capitalized in oil and natural gas properties. The impact on future
net
income is estimated to be approximately $3,411,000 recognized over the
applicable requisite service period of approximately 3 years.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Prior
to
2006, the Company applied APB No. 25 and related interpretations in accounting
for its plans. Under APB 25, if the exercise price of the stock options was
greater than the market value of the shares at the date of grant, no
compensation cost was recognized in the consolidated financial statements.
The
following table illustrates the effect on net loss and loss per share as
if the
Company had applied the fair value recognition provisions of SFAS 123 during
the
year ended December 31, 2005:
|
|
2005
|
|
|
|
|
|
Net
loss
|
|
$
|
(516,272
|
)
|
Deduct
total stock-based compensation expense determined under fair value
based
method for all awards, net of related tax effects
|
|
|
(298,745
|
)
|
Pro
forma net loss
|
|
$
|
(815,017
|
)
|
|
|
|
|
|
Loss
per share—basic and diluted
|
|
|
|
|
As
reported
|
|
$
|
(0.01
|
)
|
Pro
forma
|
|
$
|
(0.02
|
)
|
Income
Taxes
The
Company has adopted the provisions of Statement of Financial Accounting
Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under the
asset and liability method of SFAS No. 109, deferred tax assets and liabilities
are recognized for the estimated future tax consequences attributable to
the
differences between the consolidated financial statement carrying amounts
of
existing assets and liabilities and their respective tax bases and operating
loss and tax credit carryforwards. Deferred tax assets and liabilities are
measured using enacted income tax rates to apply to taxable income in the
years
in which those temporary differences are expected to be recovered or settled.
Under SFAS No. 109, the effect on deferred tax assets and liabilities of
a
change in income tax rates is recognized in the results of operations in
the
period that includes the enactment date. A valuation allowance is provided
when
it is more likely than not that some portion or all of the deferred tax assets
will not be realized.
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:
|
|
Years
Ended December 31,
|
|
|
|
2006
|
|
2005
|
|
Net
Loss
|
|
$
|
(1,944,647
|
)
|
$
|
(516,272
|
)
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
Unrealized
gains on derivative instruments
|
|
|
7,903,933
|
|
|
-
|
|
Recognition
of gains on derivative instruments
|
|
|
(2,683,300
|
)
|
|
-
|
|
|
|
|
5,220,633
|
|
|
-
|
|
Comprehensive
Income (Loss)
|
|
$
|
3,275,986
|
|
$
|
(516,272
|
)
|
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 stock options, warrants,
and
redeemable convertible preferred stock. During the years ended December 31,
2006, and 2005, stock options, warrants, and redeemable convertible preferred
stock were excluded in the computation of diluted loss per share because
their
effect of assumed exercises or conversions was anti-dilutive.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
NOTE
4.
|
RECENT
ACCOUNTING PRONOUNCEMENTS
|
In
February 2006, the FASB issued SFAS 155, “Accounting for Certain Hybrid
Financial Instruments,” which eliminates the exemption from applying SFAS 133,
“Accounting for Derivative Instruments and Hedging Activities,” to interests in
securitized financial assets so that similar instruments are accounted for
similarly, regardless of the form of the instruments. SFAS 155 also allows
the
election of fair value measurement at acquisition, at issuance, or when a
previously-recognized financial instrument is subject to a remeasurement
event.
Adoption is effective for all financial instruments acquired or issued after
the
beginning of the first fiscal year that begins after September 15, 2006.
The
adoption did not have an impact on the Company’s consolidated financial
statements.
In
February 2006, the FASB issued Financial Staff Position (“FSP”) FAS 123(R)-4
"Classification of Options and Similar Instruments Issued as Employee
Compensation that Allow for Cash Settlement upon the Occurrence of a Contingent
Event." This FSP amends SFAS No. 123(R) addressing cash settlement features
that
can be exercised only upon the occurrence of a contingent event that is outside
the employee's control. These instruments are not required to be classified as a
liability until it becomes probable that the event will occur. The adoption
did
not have an impact on the Company’s consolidated financial
statements.
In
July
2006, the FASB issued Interpretation No. 48. This Interpretation clarifies
the
accounting for uncertainty in income taxes recognized in an enterprise's
financial statements in accordance with SFAS Statement No. 109, “Accounting for
Income Taxes.” This Interpretation prescribes a recognition threshold and
measurement attribute for the financial statement recognition and measurement
of
a tax position taken or expected to be taken in a tax return. This
Interpretation also provides guidance on derecognition, classification, interest
and penalties, accounting in interim periods, disclosure, and transition.
This
Interpretation is effective for fiscal years beginning after December 15,
2006.
Management believes the adoption of this standard will not have a material
impact on the Company’s consolidated financial statements.
In
September 2006, the FASB issued SFAS 157, “Fair Value Measurements,” which
provides guidance for using fair value to measure assets and liabilities.
The
standard applies whenever other standards require (or permit) assets or
liabilities to be measured at fair value but does not expand the use of fair
value in any new circumstances. The standard clarifies that, for items that
are
not actively traded, such as certain kinds of derivatives, fair value should
reflect the price in a transaction with a market participant, including an
adjustment for risk, not just the Company’s mark-to-model value. FASB 157 also
requires expanded disclosure of the effect on earnings for items measured
using
unobservable data. The provisions of FASB 157 are effective for financial
statements issued for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years. Management believes the adoption
of
this standard will not have a material impact on the Company’s consolidated
financial statements.
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.
In
September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB 108”).
Due to diversity in practice among registrants, SAB 108 expresses the SEC
staff’s views regarding the process by which misstatements in financial
statements are evaluated to determine whether financial statement restatement
is
necessary. SAB 108 is effective for fiscal years ending after November 15,
2006.
SAB 108 did not have a material impact on the Company’s consolidated financial
statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
NOTE
5.
|
RISK
MANAGEMENT ACTIVITIES
|
Derivative
Instruments
In
order
to reduce exposure to fluctuations in the price of natural gas, the Company
will
periodically enter into financial instruments with a major financial
institution. The Company has entered into swap instruments in order to hedge
a
portion of its production. The purpose of the swaps 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 reduces
the Company’s exposure on the hedged volumes to decreases in commodity prices
and limits the benefit the Company might otherwise receive from any increases
in
commodity prices on the hedged 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 swap contracts
were
in place at December 31, 2006:
Period
|
|
Natural
Gas Volume per Day
|
|
Fixed
Price per mmbtu
|
|
Fair
Value Asset
|
|
April
2006—March 2007
|
|
|
5,000
mmbtu
|
|
$
|
8.59
|
|
$
|
1,055,835
|
|
April
2007—December 2008
|
|
|
5,000
mmbtu
|
|
$
|
9.00
|
|
|
4,164,798
|
|
|
|
|
|
|
|
|
|
$
|
5,220,633
|
|
For
the
year ended December 31, 2006, the Company has recognized in Accumulated Other
Comprehensive Income net unrealized gains of $7,903,933 on the swap contracts
that have been designated as cash flow hedges on forecasted sales of natural
gas. In addition, for the year ended December 31, 2006, the Company recognized
$2,683,300 net gains from hedging activities included in oil and natural
gas
revenues. In 2005, the Company had no derivative instruments to manage price
risk related to its natural gas production.
On
January 29, 2007, the Company entered into a costless collar contract for
2,000
mmbtu per day with a ceiling price of $9.00 per mmbtu and a floor price of
$7.55
per mmbtu for the period from April 1, 2007 through December 31,
2008.
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.
NOTE
6.
|
ACQUISITIONS
AND DISPOSITIONS
|
2006
- Hudson Pipeline and Processing Co., L.L.C.
On
January 31, 2006, Aurora Antrim North, L.L.C. (“North”), a wholly-owned
subsidiary of Aurora, completed the acquisition of oil and natural gas leases,
working interests, and interests in related pipelines and production facilities
that are located in the Hudson Township area of the Michigan Antrim shale
play.
The interests acquired are collectively referred to as the Hudson Properties.
In
addition, interests in the related pipelines and production facilities were
acquired by purchasing additional membership interests in Hudson Pipeline
and
Processing Co., L.L.C. (“HPPC”). North previously owned a working interest in
the properties and a membership interest in HPPC. This acquisition increased
North’s working interest in the Hudson Properties from an average of 49% to 96%
and increased the membership interest in HPPC from 48.75% to 90.94%.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
The
total
purchase price for the Hudson Properties and HPPC was approximately $27,600,000.
North also acquired an additional 2.5% membership interest in HPPC effective
January 1, 2006, which increased the membership interest to 93.60%.
With
these increases in membership interest in HPPC, effective January 1, 2006,
HPPC
was converted from the equity method to being consolidated as a subsidiary
in
the Company’s accompanying consolidated financial statements.
2006
- Wabash Project
On
February 2, 2006, Aurora closed on two Purchase and Sale Agreements with
respect
to certain New Albany Shale acreage located in Indiana, commonly called the
Wabash project. Aurora acquired 64,000 acres of oil and natural gas leases
from
Wabash Energy Partners, L.P. for a purchase price of $11,840,000. The Company
was required to deposit into escrow for the seller $3,200,000.
Aurora
then sold half its interest in a combined 95,000-acre lease position in the
Wabash project to New Albany-Indiana, L.L.C. (“New Albany”), an affiliate of Rex
Energy Operating Corporation, for a sale price of $10,500,000. Pursuant to
the
terms of this sales agreement, $3,500,000 was placed in escrow by New Albany
on
behalf of the Company as a deposit until the closing in February 2006.
2006
- DeSoto Parish, Louisiana
On
July
20, 2006, the Company entered into a Purchase and Sale Agreement with respect
to
the DeSoto Parish, Louisiana, properties to sell certain assets to BEUSA
Energy,
Inc. for a purchase price of $4,750,000. BEUSA Energy, Inc. is the current
operator and joint interest owner in these properties. The properties included:
(1) fourteen gross wells with working interest ranging from 22.5% to 45%;
(2)
4,480 (1,657 net) acres; and (3) various pipelines and facilities. The effective
date of the sale was July 1, 2006.
2006
- Crossroads Project, Henry, Ohio
Effective
August 15, 2006, the Company agreed to assign all of its working interests
in
the Crossroads Project located in Henry County, Ohio, to an unrelated party.
The
7.06% working interest included 15,519 (1,096 net) leasehold acres, 13 (0.92
net) wells, and pipeline assets. Aurora agreed to pay $251,225 for disposition
costs but will receive future pipeline revenue over the life of the project.
2006
- Bach
On
October 6, 2006, the Company closed on the purchase of all assets of Bach
Enterprises, Inc., certain assets owned by Bach Energy, LLC, and a limited
liability company known as Kingsley Development LLC (together “Bach”). Bach is
primarily an oil and natural gas service company. The Company has been working
exclusively with Bach as a service business in Michigan for several years.
Services they have provided include building compressors, CO2 removal,
pipelining, and facility construction. The purchase price included common
stock
and cash. The common stock issued is subject to a 1-year lock-up period.
In
addition, the Company entered into 5-year employment agreements with two
principals of Bach who agreed not to compete during their employment and
for a
period of 1 year following termination of their employment.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
2005
- New Albany
On
January 3, 2005, El Paso Corporation exercised an option to purchase 95%
of the
working interest in certain New Albany shale acreage in Indiana. As a result
of
this transaction, Aurora received gross proceeds in the amount of $7,373,737.
After deducting a distribution to subsidiary members of $805,000 and an
additional $1,000,000 set aside for the subsidiary’s share of anticipated future
drilling expense, approximately $5,500,000 of net proceeds was retained by
Aurora. In addition, the Company retained a 5% carried working interest in
the
first 50 wells drilled by El Paso Corporation.
2005/2006
- GeoPetra Partners, LLC Investment
In
June
2005, the Company acquired a 33% interest in GeoPetra Partners, LLC (“GeoPetra”)
for $14,000. GeoPetra is a limited liability company engaged primarily in
the
following activities: (i) identification and evaluation for acquisition of
oil
and natural gas properties and interest and entities which hold such properties
and interests; (ii) areas to be explored and developed for the production
of oil
and natural gas; and (iii) providing consultation, advice, and recommendations
to the members of GeoPetra in connection with other oil and natural gas
properties and interests, operations, and activities. GeoPetra was formed
April
1, 2005. In July 2006, the Company finalized a sale of 18% of its 33% interest
in GeoPetra to JetEX, LLC. This transaction reduced the gross investment
made to
GeoPetra by $199,000. Thus, as of December 31, 2006, the Company had contributed
$1,192,987 to GeoPetra with net operating losses of $471,391 resulting in
an
investment balance of $721,596.
2005-
New Albany Corner #1 Project
In
July
2005, the Company sold a 50% working interest in 28,610 leasehold acres located
in the New Albany shale to Samson Resources Company for $344,100. This included
an 80% net revenue interest in the existing leasehold acres.
Short-Term
Bank Borrowings
On
October 12, 2005, the Company entered into a $7.5 million revolving line
of
credit agreement with Northwestern Bank for general corporate purposes. On
January 31, 2006, the credit availability on this line of credit was reduced
to
$5.0 million to meet the requirements of the senior secured credit facility
(as
described below). To secure this line of credit, two trusts controlled by
an
executive officer pledged certain shares of the Company’s common stock under his
control. The interest rate under the revolving line of credit is Wall Street
prime (8.25% and 7.25% at December 31, 2006 and 2005, respectively) 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 15, 2007. Northwestern Bank also provides letters
of
credit for the drilling program (as described in Note 11 “Commitments and
Contingencies”). Interest expense on the Northwestern Bank revolving line for
the years ended December 31, 2006, and 2005, were $283,163 and $37,326,
respectively. As of March 2, 2007, the Company had no outstanding borrowings
under this credit facility.
Note
Payable - Related Parties
Through
May 1, 2006, the Company was indebted under a note payable to a minority
member
of Indiana Royalty Trustory, L.L.C., an affiliated company, in the amount
of
$69,833. The interest rate was 10.5% per year. The note payable matured on
May
1, 2006, and was paid in full.
Short-Term
Bank Borrowings - Bach
On
October 6, 2006, the Company entered into a $175,100 revolving line of credit
agreement with Northwestern Bank for general corporate purposes covering
the
Bach activities. This line of credit is secured by all of Bach’s personal
property owned or hereafter acquired. The interest rate under the revolving
line
of credit is Wall Street prime (8.25% at December 31, 2006) with interest
payable monthly in arrears. Principal is payable at the expiration of the
revolving line of credit agreement. The expiration date is October 1, 2007.
Interest expense for the year ended December 31, 2006, was $2,166.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Mortgage
and Notes Payable - Bach
The
following information details the loans assumed and entered into in connection
with the Bach acquisition:
Description
of Loan
|
|
Date
of Loan
|
|
Maturity
Date
|
|
Interest
Rate
|
|
Principal
Amount
|
|
2006
Interest Expense
|
|
Mortgage
payable on building
|
|
|
10/06/06
|
|
|
10/15/09
|
|
|
6.00
|
%
|
$
|
383,026
|
|
$
|
5,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vehicles
|
|
|
10/06/06
|
|
|
10/01/10
|
|
|
7.50
|
%
|
|
95,087
|
|
|
|
|
Equipment
|
|
|
10/06/06
|
|
|
09/01/07
|
|
|
5.50
|
%
|
|
16,700
|
|
|
|
|
Vehicles
|
|
|
12/18/06
|
|
|
12/20/09
|
|
|
7.25
|
%
|
|
70,118
|
|
|
|
|
Total
notes payable
|
|
|
|
|
|
|
|
|
|
|
$
|
181,905
|
|
$
|
1,816
|
|
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. During September 2006, Northwestern Bank released
the
personal guaranties of three of the Company’s officers. 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.
Interest expense for the year ended December 31, 2006, and 2005, was
$192,814 and $15,732, respectively.
Mezzanine
Financing
On
December 8, 2005, the Company entered into an Amended Note Purchase Agreement
to
increase its 5-year mezzanine credit facility with Trust Company of the West
(“TCW”) from $30 million to $50 million for the Michigan Antrim drilling
program. The borrower is North. Upon closing of the BNP Paribas (“BNP”) senior
secured credit facility discussed below, TCW now holds a second lien position
in
the Michigan Antrim natural gas properties. The interest rate is fixed at
11.5%
per year, compounded quarterly, and payable in arrears. Beginning September
28,
2006, and quarterly thereafter, the required principal payment is 75% (100%
if
coverage deficiency or default occurs) of adjusted net cash flow determined
by
deducting specific expenses, including capital expenditures from “gross cash
revenue.” The Company estimates that no principal payments on the mezzanine
financing will be required until maturity because of the level of anticipated
capital expenditures. The maturity date is September 30, 2009. The borrowing
base is impacted by, among other factors, the fair value of the Company’s
natural gas reserves that are pledged to TCW. Changes in the fair value of
the
natural gas reserves are caused by changes in prices for natural gas, operating
expenses, and the results of drilling activity. A significant decline in
the
fair value of these reserves could reduce the borrowing base, and the Company
may not be able to meet certain facility covenants.
The
mezzanine credit facility contains, among other things, certain covenants
relating to restricted payments (as defined), loans or advances to others,
additional indebtedness, and incurrence of liens and provides for the
maintenance of certain financial and operating ratios, including current
ratio
and specified coverage ratios (collateral coverage and proved developed
producing reserves coverage ratios).
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
As
additional consideration to induce TCW to enter into the mezzanine facility,
the
Company provided an affiliate of TCW an overriding royalty interest in certain
of properties drilled or developed in the Counties of Alcona, Alpena,
Charlevoix, Cheboygan, Montmorency, and Otsego in the State of Michigan. The
overriding royalty interest is 4%, subject to certain adjustments.
For
the
years ended December 31, 2006, and 2005, interest incurred for the mezzanine
credit facility was $4,714,861, and $2,171,389, respectively. As of March 2,
2007, the Company had total borrowings of $40 million under this credit
facility.
Senior
Secured Credit Facility
On
January 31, 2006, the Company entered into a senior secured credit facility
with
BNP for drilling, development, and acquisitions, as well as other general
corporate purposes. The borrower is North. The initial borrowing base was $40
million without hedges. Effective July 14, 2006, the borrowing base was
increased to $50 million. As proved reserves are added, this borrowing base
may
increase to $100 million with TCW consent. A required semiannual reserve report
may result in an increase or decrease in credit availability. The security
for
this facility is a first lien position in certain Michigan Antrim assets; a
guarantee from Aurora; and a guarantee from the Company secured by a pledge
of
its stock in Aurora. This facility matures the earlier of January 31, 2010,
or
91 days prior to the maturity of the mezzanine credit facility, unless the
Company elects to terminate the commitment earlier pursuant to the terms of
the
senior secured credit facility.
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. For the year ended December 31, 2006, interest incurred was
$2,323,732. As of March 2, 2007, the Company had total borrowings of $25 million
under this credit facility.
On
July
14, 2006, the senior secured credit facility was amended to defer the trailing
12-month interest coverage ratio covenant until the fourth quarter of 2006
and
to provide for a reduced ratio for that quarter. The trailing 12-month interest
coverage ratio amendment was intended to correct a previous error in the
covenant, which failed to account for the fact that the acquisition of the
Hudson Properties (as described in Note 6 “Acquisitions and Dispositions”) in
the first quarter of 2006 would not have a full trailing 12 months of cash
flow
included in the financial statements until the first quarter of 2007. This
amendment supersedes the waiver BNP issued regarding the interest coverage
covenant for the first quarter of 2006.
On
September 22, 2006, the Company agreed that BNP could establish a syndication
thereby allowing various financial institutions to participate under the senior
secured credit facility. In addition, effective December 21, 2006, the senior
secured credit facility was amended to eliminate the interest coverage ratio
covenant for the fiscal quarter ending December 31, 2006, and to modify the
2007
fiscal quarters’ interest coverage ratio covenants.
The
senior secured credit facility contains, among other things, a number of
financial and nonfinancial covenants relating to restricted payments (as
defined), loans or advances to others, additional indebtedness, incurrence
of
liens, a prohibition on the Company’s ability to prepay the mezzanine credit
facility, geographic limitations on operations to the United States, and
maintenance of certain financial and operating ratios, including current ratio
and specified coverage ratios (collateral coverage and proved developed
producing reserves coverage ratios).
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Maturities
of Debt
Aggregate
maturities of long-term debt at December 31, 2006, are as follows:
2007
|
|
$
|
817,485
|
|
2008
|
|
|
2,769,517
|
|
2009
|
|
|
50,406,497
|
|
2010
|
|
|
22,004
|
|
Total
|
|
$
|
54,015,503
|
|
The
Company has incurred deferred financing fees of approximately $406,000 from
BNP
and approximately $2,850,000 from TCW. These financing fees are being amortized
on a straight-line basis over the remaining terms of each debt obligation.
Amortization expense is estimated to be $0.8 million per year through
2009.
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 $3,896,645 and $1,146,084 for the years ended
December 31, 2006 and 2005, respectively.
NOTE
8.
|
SHAREHOLDERS’
EQUITY
|
Redeemable
Convertible Preferred Stock
On
April 23, 2001, the Company’s board of directors authorized
20,000,000 shares of preferred stock with a par value of $0.01 per
share and rights and preferences to be determined. During 2003, the Company
issued 34,984 shares of its Class A preferred stock to investors at
prices ranging from $1.50 to $2.00 per share for aggregate proceeds of
$59,925. The shares were convertible to common stock at a price of $1.50 to
$2.00 per share under certain terms and conditions. The shares carried a
preferred dividend of 15% per annum. In 2006, the shareholders converted
all of the 34,984 shares of redeemable convertible preferred stock into
common stock.
Common
Stock
2005
The
Company sold 4,972,200 shares of common stock to unrelated third parties at
$2.50 per share in the first quarter of 2005. Total net proceeds from the
sale of these shares, after commissions and fees, amounted to $11,025,000.
In
connection with the sale of these shares, together with the sale of certain
common stock by Cadence at that same time, an affiliate of one of the Company’s
major shareholders was paid a commission of approximately $976,000 and was
issued a warrant to purchase 1,821,000 shares of common stock for services
rendered as the placement agent in the transaction. Included in accounts payable
at December 31, 2005, is a balance of $50,000 due to this affiliate.
The
Company issued 10,000 shares of common stock to a director upon the
exercise of options at a price of $0.75 per share.
As
a
result of the reverse merger, Aurora’s shareholders’ equity reflects the
following transactions:
The
total
outstanding Aurora shares, at the effective date of the merger, of 19,056,183
were in the 2 for 1 exchange.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Cadence
returned 600,000 shares to treasury stock for 300,000 shares it held
in Aurora at the time of merger which became 600,000 shares in the 2 for 1
exchange. This is reflected as a reduction to Aurora’s equity.
The
total
outstanding Cadence shares, at the effective date of the merger, of 21,136,327
were added to Aurora’s equity.
The
Company issued 2,642,500 shares of common stock upon the exercise of
certain options and warrants at prices ranging from $1.25 to $1.75 per
share.
During
the last quarter of 2005, certain option and warrant holders exercised their
options and warrants under the cashless exercise provision within their options
and warrants. This resulted in the issuance of 245,068 shares of the
Company’s stock. In December 2005, an additional 2,160,000 shares were issued
for cash proceeds of $2,916,000.
2006
From
late
December 2005 through early February 2006, the Company reduced the exercise
price of certain outstanding options and warrants in order to encourage the
early exercise of these securities. Each holder who took advantage of the
reduced exercise price was required to execute a 6-month lock-up agreement
with
respect to the shares issued in the exercise. As a result of the options and
warrants exercised pursuant to this reduced exercise price arrangement and
pursuant to other exercises of outstanding options, an additional 20,573,422
shares were issued during the year ended December 31, 2006, representing
15,823,457 shares issued for cash proceeds of $18,301,949, and 4,749,965 shares
issued pursuant to cashless exercises of the applicable and other warrants
or
options. In December 2006, three officers of the Company rescinded option
exercises for 600,000 shares each. The option exercise price of $249,000 was
returned to each of these officers and in exchange each officer surrendered
600,000 shares of common stock.
In
February 2006, a special meeting of the shareholders was held where they voted
to increase the number of authorized shares of common stock from 100,000,000
to
250,000,000.
In
2006,
a total of 34,984 shares of redeemable convertible preferred stock were
converted into 34,984 shares of common stock.
In
June
2006, an officer of the Company was issued 30,000 shares for services provided
in 2005. Compensation expense related to this activity was recorded in 2005.
Additionally, two directors of the Company were issued 30,000 shares each for
their services provided to Aurora as Board members prior to the merger with
Cadence. Compensation expense related to this activity was recorded in
2005.
In
October 2006, upon the acquisition of the assets of Bach Enterprises, Inc.
and
its affiliates, 1,378,299 of unregistered common shares were issued. Of the
shares issued, 500,000 shares have been placed in an escrow for one year as
security for any indemnity obligation resulting from a breach of any
representation or warranty in the purchase agreement.
The
Company closed on the public offering of 16 million shares on November 7, 2006,
and received net proceeds of approximately $44.4 million, which were utilized
to
repay amounts outstanding under the senior secured credit facility. The 30-day
over-allotment option granted to the underwriters for the purchase of 3.6
million additional shares was exercised and closed on November 13, 2006, and
the
Company received net proceeds of approximately $10.2 million.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
Common
Stock Warrants
The
following table provides information related to stock warrant activity for
the
years ended December 31:
|
|
2006
|
|
2005
|
|
|
|
Number
of Shares Underlying Warrants
|
|
Number
of Shares Underlying Warrants
|
|
Outstanding
at the beginning of the period
|
|
|
19,697,500
|
|
|
-
|
|
Granted
|
|
|
-
|
|
|
2,402,000
|
|
Assumed
upon merger:
|
|
|
|
|
|
|
|
2
for 1 exchange of Aurora warrants
|
|
|
-
|
|
|
2,402,000
|
|
Cadence
warrants
|
|
|
-
|
|
|
17,498,500
|
|
Exercised
under early exercise program
|
|
|
(13,182,625
|
)
|
|
-
|
|
Exercised
|
|
|
(3,589,871
|
)
|
|
(2,596,677
|
)
|
Forfeitures
and other adjustments
|
|
|
(845,504
|
)
|
|
(8,323
|
)
|
Outstanding
at the end of the period
|
|
|
2,079,500
|
|
|
19,697,500
|
|
As
of
December 31, 2006, these common stock warrants had an average remaining
contractual life of 1.88 years and weighted average exercise price per share
of
$1.71.
Income
tax expense (benefit) for the years ended December 31 consists of the
following:
|
|
2006
|
|
2005
|
|
Current
taxes
|
|
$
|
-
|
|
$
|
-
|
|
Deferred
taxes
|
|
|
1,862,000
|
|
|
175,500
|
|
Less:
change in valuation allowance
|
|
|
(1,862,000
|
)
|
|
(175,500
|
)
|
|
|
|
|
|
|
|
|
Net
income tax expense (benefit)
|
|
$
|
-
|
|
$
|
-
|
|
The
effective income tax rate for the years ended December 31 differs from the
U.S.
federal statutory income tax rate due to the following:
|
|
2006
|
|
2005
|
|
Federal
statutory income tax rate
|
|
$
|
(661,000
|
)
|
$
|
(175,500
|
)
|
Adjustment
of estimated income tax provision of prior years
(a)
|
|
|
2,523,000
|
|
|
-
|
|
Change
in valuation allowance
|
|
|
(1,862,000
|
)
|
|
175,500
|
|
|
|
|
|
|
|
|
|
Net
income tax expense (benefit)
|
|
$
|
-
|
|
$
|
-
|
|
(a)
Adjustment
of estimated income tax provision of prior year is due primarily to intangible
costs that were expensed in prior year calculation but capitalized and amortized
in tax return.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
The
components of the deferred tax assets and liabilities as of December 31 are
as
follows:
|
|
2006
|
|
2005
|
|
Deferred
tax assets:
|
|
|
|
|
|
Net
operating loss carryover
|
|
$
|
11,661,000
|
|
$
|
12,324,600
|
|
Stock
options
|
|
|
928,000
|
|
|
-
|
|
Section
1231 carryover
|
|
|
-
|
|
|
146,900
|
|
Capital
loss carryover
|
|
|
33,000
|
|
|
66,000
|
|
Less
valuation allowance
|
|
|
(530,000
|
)
|
|
(2,391,700
|
)
|
Deferred
tax assets, net
|
|
|
12,092,000
|
|
|
10,145,800
|
|
|
|
|
|
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
Excess
assigned acquisition value
|
|
|
(4,339,000
|
)
|
|
(4,339,000
|
)
|
Intangible
drilling costs and other
|
|
|
(7,753,000
|
)
|
|
(5,806,800
|
)
|
Deferred
tax liabilities, net
|
|
|
(12,092,000
|
)
|
|
(10,145,800
|
)
|
|
|
|
|
|
|
|
|
Net
deferred tax assets (liabilities)
|
|
$
|
-
|
|
$
|
-
|
|
The
Company has net operating loss carryforwards available to offset future federal
taxable income of approximately $34,297,000, which expire from 2010 through
2026. Included in this amount is a premerger net operating loss carryforward
incurred by Cadence of approximately $16,900,000. The valuation allowance
decreased by approximately $1,862,000 and $175,500 as of December 31, 2006,
and
2005, respectively. Due to the net operating loss carryforwards, no income
tax
expense was recorded in 2006 and 2005.
NOTE
10.
|
COMMON
STOCK OPTIONS
|
Stock
Option Plans
In
October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it
was
authorized to issue compensatory options to purchase up to 1,000,000 shares
of
common stock. The 1997 Stock Option Plan provides that the total number of
shares of common stock of Aurora which may be granted as options shall not
exceed 10% of the outstanding shares of the Company as of December 31 of each
year for the following year. Aurora issued options to purchase a total of
580,000 shares of Aurora's common stock under this plan which, upon closing
the
merger, converted into the right to acquire up to 1,160,000 shares of common
stock. The maximum term of options granted is 10 years. Because of the merger,
no further awards will be made under this plan.
In
2001,
Aurora's board of directors and shareholders approved the adoption of an Equity
Compensation Plan for Non-Employee Directors. This plan provided that each
nonemployee director is entitled to receive options to purchase 100,000 shares
of Aurora's common stock, issuable in increments of options to purchase 33,333
shares each year over a period of 3 years, so long as the director continues
in
office. Prior to the merger closing, Aurora had issued options to purchase
a
total of 309,997 shares of Aurora common stock under this plan which, upon
closing the merger, converted to the right to acquire 619,994 shares of our
common stock. Because of the merger, no further awards will be made under this
plan.
In
2004,
Cadence’s board of directors adopted, and the shareholders approved, a 2004
Equity Incentive Plan. This plan provides for the grant of options or restricted
shares for compensatory purposes for up to 1,000,000 shares of common stock.
The
number of shares issued or subject to options issued under this plan total
910,500. The maximum term of options granted is 10 years. The Company does
not
currently intend to make any further awards under this plan, the plan continues
to exist, and the Company may decide to use it in the future.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
In
March
2006, the Company’s board of directors adopted, and, in May 2006, shareholders
approved, the 2006 Stock Incentive Plan. This Plan provides for the award of
options or restricted shares for compensatory purposes for up to 8,000,000
shares. The purpose of the Plan is to promote the interests of the Company
by
aligning the interests of employees (including directors and officers who are
employees) of the Company, consultants, and nonemployee directors of the Company
and to provide incentives for such persons to exert maximum efforts for the
success of the Company and its affiliates. The maximum term for options granted
is 10 years.
Activity
related to the stock option plans referenced above was as follows for the years
ended December 31, 2006, and 2005:
|
|
2006
|
|
2005
|
|
Options
outstanding at beginning of period
|
|
|
1,804,994
|
|
|
943,994
|
|
Options
granted
|
|
|
2,727,500
|
|
|
146,000
|
|
Assumed
upon merger:
|
|
|
|
|
|
|
|
2
for 1 exchange of Aurora options
|
|
|
-
|
|
|
490,000
|
|
Cadence
options
|
|
|
-
|
|
|
400,000
|
|
Options
exercised
|
|
|
(592,732
|
)
|
|
(195,000
|
)
|
Options
forfeited and other adjustments
|
|
|
(507,266
|
)
|
|
20,000
|
|
Options
outstanding at end of period
|
|
|
3,432,496
|
|
|
1,804,994
|
|
The
weighted average assumptions used in the Black-Scholes option-pricing model
used
to determine fair value were as follows:
|
|
2006
|
|
2005
|
|
Risk-free
interest rate
|
|
|
4.1
|
%
|
|
4
|
%
|
Expected
years until exercise
|
|
|
2.5-6.0
|
|
|
10
|
|
Expected
stock volatility
|
|
|
41
|
%
|
|
41
|
%
|
Dividend
yield
|
|
|
0
|
%
|
|
0
|
%
|
All
Stock Options
In
addition, Cadence awarded compensatory options and warrants totaling 30,280
on
an individualized basis that was considered outside the awards issued under
its
2004 Equity Incentive Plan. Aurora also issued compensatory options and warrants
totaling 1,400,000 on an individualized basis that was considered outside the
awards issued under its 1997 Stock Option Plan and Equity Compensation Plan
for
Non-Employee Directors. Activity with respect to all stock options is presented
below for the years ended December 31, 2006, and 2005:
|
|
2006
|
|
2005
|
|
|
|
Shares
|
|
Weighted
Average Exercise Price
|
|
Shares
|
|
Weighted
Average Exercise Price
|
|
Options
outstanding at the beginning of period
|
|
|
6,448,468
|
|
$
|
0.72
|
|
|
2,700,664
|
|
$
|
0.99
|
|
Options
granted
|
|
|
2,727,500
|
|
|
3.89
|
|
|
156,000
|
|
|
3.32
|
|
Assumed
upon merger:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
for 1 exchange of Aurora options
|
|
|
-
|
|
|
-
|
|
|
2,856,664
|
|
|
-
|
|
Cadence
options
|
|
|
-
|
|
|
-
|
|
|
1,124,349
|
|
|
1.79
|
|
Options
exercised
|
|
|
(3,800,926
|
)
|
|
0.67
|
|
|
(357,500
|
)
|
|
1.20
|
|
Forfeitures
and other adjustments
|
|
|
(512,266
|
)
|
|
3.65
|
|
|
(31,709
|
)
|
|
0.43
|
|
Options
outstanding at end of period
|
|
|
4,862,776
|
|
$
|
2.23
|
|
|
6,448,468
|
|
$
|
0.72
|
|
Exercisable
at end of period
|
|
|
2,775,609
|
|
$
|
1.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average fair value of options granted during the period
|
|
$
|
3.85
|
|
|
|
|
|
|
|
|
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
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 outstanding at December 31, 2006, was
approximately $6,577,000 and the intrinsic value of the options exercisable
at
December 31, 2006, was approximately $6,440,000. The intrinsic value of the
options exercised during the year ended December 31, 2006, was
approximately $4,647,000.
The
weighted average remaining life by exercise price as of December 31, 2006,
is
summarized below:
Range
of
Exercise
Prices
|
|
Outstanding
Shares
|
|
Weighted
Average Life
|
|
Exercisable
Shares
|
|
Weighted
Average Life
|
|
$0.25
- $0.38
|
|
|
749,996
|
|
|
3.7
|
|
|
749,996
|
|
|
3.7
|
|
$0.50
- $0.75
|
|
|
1,440,000
|
|
|
2.1
|
|
|
1,440,000
|
|
|
2.1
|
|
$1.25
- $1.75
|
|
|
352,000
|
|
|
7.7
|
|
|
352,000
|
|
|
7.7
|
|
$2.23
- $3.55
|
|
|
453,280
|
|
|
7.0
|
|
|
80,280
|
|
|
2.6
|
|
$3.62
|
|
|
1,000,000
|
|
|
3.9
|
|
|
-
|
|
|
-
|
|
$4.45
- $4.70
|
|
|
667,500
|
|
|
8.9
|
|
|
13,333
|
|
|
5.1
|
|
$5.19
- $5.54
|
|
|
200,000
|
|
|
4.9
|
|
|
140,000
|
|
|
4.2
|
|
$0.25
- $5.54
|
|
|
4,862,776
|
|
|
4.6
|
|
|
2,775,609
|
|
|
3.4
|
|
NOTE
11.
|
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 December 31, 2006.
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 December 31, 2006, letters
of credit in the amount of $1,116,100 were outstanding to the Michigan
Supervisor of Wells.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
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.
Expiration
of Pending Acquisition
On
May 9,
2006, North signed a letter of intent with a third party to acquire oil and
natural gas leases, working interests, and interests in related pipelines and
production facilities that are located in the Michigan Antrim shale. This
encompasses two projects that were still in development, but already are
generating some production. On June 30, 2006, the letter of intent was amended
to extend the due diligence effort through September 30, 2006, with
anticipated closing of the transaction on or before November 15, 2006. Based
upon further evaluation, the Company allowed the letter of intent to expire
and
does not intend to pursue the acquisition.
NOTE
12.
|
RELATED
PARTY TRANSACTIONS
|
William Deneau,
Thomas Tucker, and John Miller, who are officers , are all involved as equity
owners in numerous corporations and limited liability companies that are active
in the oil and natural gas business. They also own miscellaneous overriding
royalty interests in wells in which the Company has an interest but are operated
by unrelated third parties. During 2006, these officers divested themselves
of
all interests for which the Company served as operator.
On
September 7, 2004, the Patricia A. Deneau Trust, DTD 10/12/95, borrowed
$100,000 from an Aurora subsidiary to purchase shares of Aurora common stock
from an Aurora shareholder. This trust is controlled by William W. Deneau.
The
loan was evidenced by an unsecured demand promissory note bearing interest
at
the rate of 4.5% per year. The promissory note has been repaid in full as
of May 2006. The shares purchased by the trust were subsequently sold by the
trust to a company employee.
Kevin
D.
Stulp, a director, owns a 33 1/3% working interest in ten wells drilled and
operated by TN Oil Company (six of which are dry). The Company owns
650,000 shares of TN Oil Company at a cost of $65,000, which represents
approximately a 14% equity interest in TN Oil Company.
In
order
to replace the collateral pledged to Northwestern Bank for the revolving line
of
credit, on December 21, 2005, The Denthorn Trust, which is controlled by William
W. Deneau, executed a Commercial Guaranty of the Company’s obligation on the
Northwestern Bank revolving line of credit, and a Commercial Pledge Agreement
pursuant to which The Denthorn Trust has pledged to Northwestern Bank 306,450
shares of our common stock to secure payment of the Company’s indebtedness. Also
on December 21, 2005, the Patricia A. Deneau Trust, DTD 10/12/95, which is
controlled by William W. Deneau, executed a Commercial Guaranty and a Commercial
Pledge Agreement, pursuant to which it pledged 2,944,800 shares of our common
stock to Northwestern Bank to secure payment of the Company’s indebtedness. (See
Note 7 “Debt.”)
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
At
the
time of the merger, Aurora had a lease for office and storage space from
South 31, L.L.C. William W. Deneau and Thomas W. Tucker each owned
one-third of South 31, L.L.C. Rent was paid through December 31, 2005,
on a lease extending through March 31, 2007. After the Company moved the
corporate offices in early December 2005, the Company no longer had a need
for
the space in the South 31, L.L.C. property. The Company entered into a
Settlement Agreement and Mutual Release with South 31, L.L.C. pursuant to
which a payment was made to South 31, L.L.C. in the amount of $65,250 on
January 27, 2006, and South 31, L.L.C. released the Company from any
further obligation on the lease. The Company currently maintains a
month-to-month storage lease with South 31, L.L.C. for $600 per
quarter.
NOTE
13.
|
RETIREMENT
BENEFITS
|
401(k)
Plan
Effective
May 1, 2006, the Company established a qualified retirement plan referred to
as
the Aurora 401(k) Plan (the “Plan”). The Plan is available to all employees who
have completed at least 1,000 hours of service over their first 12 consecutive
months of employment and are at least 21 years of age. Effective July 1, 2006,
the Company waived the age and service requirements for any employee employed
by
the Company on or before July 1, 2006. The Company may provide: (1)
discretionary matching of employee contributions; (2) discretionary
profit-sharing contributions; and (3) qualified nonelective contributions to
the
Plan. Company-provided contributions are subject to certain vesting schedules.
For the year ended December 31, 2006, the Company contributed $42,350 as a
discretionary matching contribution.
2007
Incentive Bonus Plan
The
Company has adopted an incentive bonus plan for the year 2007. The incentive
bonus plan is available to all full-time employees, excluding officers and
employees of subsidiaries. The bonus will be up to 10% of eligible employees’
compensation during the year 2007 if certain objectives are met.
NOTE
14.
|
OIL
AND NATURAL GAS PROPERTIES HELD FOR
SALE
|
Management
is currently in the process of evaluating the Company’s property portfolio to
ensure that the oil and natural gas properties portfolio properly matches the
Company’s long-term strategic plan. During the second quarter of 2006, the
Company identified certain leasehold properties as held for sale due to their
high probability of being sold within the next 12 months. Total oil and natural
gas properties held for sale before depletion amounted to $8,896,568 at December
31, 2006, of which $7,202,622 is proved and $1,693,946 is unproved. (See Note
6
“Acquisitions and Dispositions.”) These properties are carried at the lower of
historical cost or fair value. 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 has evaluated the proved reserves of
these properties (1,046 mmcfe as of December 31, 2006) and determined that
there
is no significant effect on the proved reserves regarding the assets held for
sale. In 2005, no properties were classified as held for sale.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
NOTE
15.
|
FOURTH
QUARTER
ADJUSTMENTS
|
During
the fourth quarter of 2006, the Company modified its approach to estimating
capitalized interest. The Company’s original accounting approach was to estimate
capitalized interest by identifying specific assets to specific debt. Thus,
if
debt was not drawn down in a month, no interest was capitalized. However,
applicable accounting principles and related guidance provide that the debt
need
not be specific debt incurred on the asset. Therefore, a company may capitalize
interest cost even though the entire development or construction cost of the
asset was paid in cash, so long as the company has incurred some form of cost
of
capital. This change in estimate resulted in additional $3.2 million of
capitalized interest for the entire fiscal year which was recorded in the fourth
quarter; of this amount, $1.9 million related to prior quarters.
During
the fourth quarter of 2006, the Company modified its approach to estimating
oil
and natural gas depreciation, depletion and amortization (“DD&A”). The
Company’s original accounting approach was to amortize all capitalized costs of
oil and natural gas properties considered proven developed, on the
unit-of-production method using estimates of proven developed reserves. However,
applicable accounting principles and related guidance provides that capitalized
costs of oil and natural gas properties can be amortized on a unit-of-production
method based on all proved oil and natural gas reserves. As of December 31,
2006, all of the Company’s proven reserves were evaluated by an independent
petroleum engineering group which resulted in a 89 bcfe increase in proved
reserves associated with the full cost pool. This change in estimate from proven
developed reserves to proven reserves as well as an updated reserve report
resulted in a reduction of $ 2.7 million in oil and natural gas depreciation,
depletion and amortization.
NOTE
16.
|
SUBSEQUENT
EVENT
|
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. As of
December 31, 2006, the properties included two net wells and approximately
23,110 net acres. This transaction closed on March 9, 2007.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL
GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited)
Supplemental
Reserve Information
.
The
following information presents estimates of our proved oil and natural gas
reserves. The Company retained the service of an independent petroleum
consultant (Data & Consulting Services, Division of Schlumberger Technology
Corporation) to estimate its proved natural gas reserves at December 31, 2006,
and 2005. Included in the tables that follow are proved oil and natural gas
reserves located in Michigan that were acquired as a separate property
acquisition early in 2006 and proved oil and natural gas reserves acquired
in
conjunction with the reverse merger with Cadence Resources Corporation effective
October 31, 2005. These acquired proved reserves were estimated by Netherland,
Sewell & Associates, Inc. and Ralph E. Davis Associates, Inc., respectively.
Crude oil and natural gas reserves at December 31, 2006, and 2005, were
estimated under the Securities and Exchange Commission (“SEC”) reporting
standards.
Estimates
of Proved Reserves
|
|
Oil
(mbbl)
|
|
Natural
Gas
(mmcf)
|
|
Proved
reserves as of December 31, 2004
|
|
-
|
|
34,949
|
|
Revisions
of previous estimates
|
|
|
6
|
|
|
5,382
|
|
Purchases
of minerals in place
|
|
|
103
|
|
|
1,572
|
|
Extensions
and discoveries
|
|
|
-
|
|
|
22,107
|
|
Production
|
|
|
(10
|
)
|
|
(688
|
)
|
Proved
reserves as of December 31, 2005
|
|
|
99
|
|
|
63,322
|
|
Revisions
of previous estimates
|
|
|
(40
|
)
|
|
4,880
|
|
Purchases
of minerals in place
|
|
|
-
|
|
|
22,843
|
|
Extensions
and discoveries
|
|
|
45
|
|
|
65,095
|
|
Production
(a)
|
|
|
(23
|
)
|
|
(2,511
|
)
|
Sales
of minerals in place
|
|
|
-
|
|
|
(665
|
)
|
Proved
reserves as of December 31, 2006
|
|
|
81
|
|
|
152,964
|
|
|
|
|
|
|
|
|
|
Proved
developed reserves:
|
|
|
|
|
|
|
|
December
31, 2005
|
|
|
70
|
|
|
45,205
|
|
December
31, 2006
|
|
|
54
|
|
|
82,580
|
|
(a)
Production
for 2006 does not reflect 142 mcfe of production the Company received in
association with certain non-operated wells excluded in the year end reserve
report.
The
following table summarizes the weighted average year-end prices (net of basis
adjustments) used to estimate reserves in accordance with SEC
guidelines.
|
|
2006
|
|
2005
|
|
Natural
gas (per mmbtu)
|
|
$
|
5.84
|
|
$
|
9.89
|
|
Oil
(per barrel)
|
|
$
|
57.81
|
|
$
|
56.41
|
|
Standardized
Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Natural
Gas Reserves
The
following information has been developed utilizing procedures prescribed by
SFAS
No. 69 and based on crude oil and natural gas reserve and production volumes
estimated by the Company’s independent reserve engineers. It may be useful for
certain comparison purposes but should not be solely relied upon in evaluating
the Company or its performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows nor should the Standardized Measure of Discounted Future
Net
Cash Flows be viewed as representative of the current value of the
Company.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL
GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited)
The
future cash flows presented below are computed by applying year-end prices
to
year-end quantities of proved crude oil and natural gas reserves. Future
production and development costs are computed by estimating the expenditures
to
be incurred in developing and producing the Company’s proved reserves based on
year-end costs and assuming continuation of existing economic conditions. It
is
expected that material revisions to some estimates of crude oil and natural
gas
reserves may occur in the future, development and production of the reserves
may
occur in periods other than those assumed, and actual prices realized and costs
incurred may vary significantly from those used.
Management
does not rely upon the following information in making investment and operating
decisions. Such decision are based upon a wide range of factors, including
estimates of probable as well as proved reserves, and varying price and cost
assumptions are considered more representative of a range of possible economic
conditions that may be anticipated.
The
following table sets forth the Standardized Measure of Discounted Future Net
Cash Flows from projected production of the Company’s crude oil and natural gas
reserves for the years ended December 31, 2006, and 2005.
|
|
2006
|
|
2005
|
|
Future
gross revenues (1)
|
|
$
|
884,186,810
|
|
$
|
632,058,720
|
|
Future
production costs (2)
|
|
|
(378,345,360
|
)
|
|
(182,710,406
|
)
|
Future
development costs (2)
|
|
|
(37,324,420
|
)
|
|
(15,073,590
|
)
|
Future
net cash flows before income taxes
|
|
$
|
468,517,030
|
|
$
|
434,274,724
|
|
Future
income tax expense (3)
|
|
|
(83,566,133
|
)
|
|
(101,521,160
|
)
|
Future
net cash flows after income taxes
|
|
$
|
384,950,897
|
|
$
|
332,753,564
|
|
Discount
at 10% per annum
|
|
|
(254,489,076
|
)
|
|
(179,885,324
|
)
|
Standardized
measure of discounted future net cash flows relating to proved oil
and
natural gas reserves
|
|
$
|
130,461,821
|
|
$
|
152,868,240
|
|
(1)
|
Crude
oil and natural gas revenues are based on year-end prices with adjustments
for changes reflected in existing contracts. There is no consideration
for
future discoveries or risks associated with future production of
proved
reserves.
|
(2)
|
Based
on economic conditions at year-end. Does not include administrative,
general, or financing costs.
|
(3)
|
Future
income taxes are computed by applying the statutory tax rate to future
net
cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and natural gas producing
activities, and tax carryforwards.
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL
GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited)
Changes
in Standardized Measure of Discounted Future Cash Flows
The
following table sets forth the changes in Standardized Measure of Discounted
Future Net Cash Flows for the years ended December 31, 2006, and
2005.
|
|
2006
|
|
2005
|
|
Beginning
balance
|
|
$
|
152,868,240
|
|
$
|
32,159,710
|
|
|
|
|
|
|
|
|
|
Revisions
to reserves proved in prior years:
|
|
|
|
|
|
|
|
Net
change in prices and production costs
|
|
|
(113,774,170
|
)
|
|
85,425,515
|
|
Net
changes in future development costs
|
|
|
(802,360
|
)
|
|
6,299,524
|
|
Net
changes due to revisions in quantity estimates
|
|
|
3,484,229
|
|
|
33,335,739
|
|
Net
change in accretion of discount
|
|
|
19,950,751
|
|
|
(66,761,600
|
)
|
Other
|
|
|
(15,976,530
|
)
|
|
38,137,602
|
|
Total
revisions to reserves provided in prior years
|
|
|
(107,118,080
|
)
|
|
96,436,780
|
|
|
|
|
|
|
|
|
|
New
discoveries and extensions, net of future development and production
costs
|
|
|
62,343,872
|
|
|
76,487,826
|
|
Purchases
of minerals in place
|
|
|
23,605,950
|
|
|
11,834,500
|
|
Sales
of oil and natural gas produced, net of production costs
|
|
|
(4,756,826
|
)
|
|
(4,696,416
|
)
|
Previously
estimated development costs incurred
|
|
|
(14,436,361
|
)
|
|
-
|
|
Net
change in income taxes
|
|
|
17,955,026
|
|
|
(59,354,160
|
)
|
|
|
|
|
|
|
|
|
Net
change in standardized measure of discounted cash flows
|
|
|
(22,406,419
|
)
|
|
120,708,530
|
|
|
|
|
|
|
|
|
|
Ending
balance
|
|
$
|
130,461,821
|
|
$
|
152,868,240
|
|
Capitalized
Costs Related to Oil and Natural Gas Producing Activities
The
following table sets forth the capitalized costs relating to the Company’s
natural gas and crude oil producing activities at December 31, 2006, and
2005.
|
|
2006
|
|
2005
|
|
Proved
properties
|
|
$
|
128,381,121
|
|
$
|
39,643,003
|
|
Unproved
properties
|
|
|
43,541,472
|
|
|
37,279,889
|
|
Total
oil and natural gas properties
|
|
|
171,922,593
|
|
|
76,922,892
|
|
Less
accumulated depreciation, depletion, and amortization
|
|
|
(10,628,438
|
)
|
|
(7,962,138
|
)
|
Oil
and natural gas properties—net
|
|
$
|
161,294,155
|
|
$
|
68,960,754
|
|
Costs
Incurred in Oil and Natural Gas Producing Activities
The
acquisition, exploration, and development costs disclosed in the following
table
are in accordance with definitions in SFAS No. 19, “Financial Accounting and
Reporting by Oil and Gas Producing Companies.” Acquisition costs include costs
incurred to purchase, lease, or otherwise acquire property. Exploration costs
include exploration expenses, additions to exploration wells in progress, and
depreciation of support equipment used in exploration activities. Development
costs include additions to production facilities and equipment, additions to
development wells in progress and related facilities, and depreciation of
support equipment and related facilities used in development
activities.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL
GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited)
The
following table sets forth capitalized costs incurred related to the Company’s
oil and natural gas activities for the years ended December 31, 2006, and
2005.
|
|
2006
|
|
2005
|
|
Property
acquisition costs
|
|
|
|
|
|
Proved
|
|
$
|
24,011,335
|
|
$
|
22,763,734
|
|
Unproved
|
|
|
27,554,145
|
|
|
19,607,099
|
|
Exploration
|
|
|
8,347,848
|
|
|
781,586
|
|
Development
|
|
|
46,575,829
|
|
|
29,707,367
|
|
Total
costs incurred
(a)
|
|
|
106,489,157
|
|
|
72,859,786
|
|
Sales
of oil and natural gas properties
|
|
|
(11,489,456
|
)
|
|
(11,504,428
|
)
|
Total
|
|
$
|
94,999,701
|
|
$
|
61,355,358
|
|
(a)
Total
costs incurred include (i) capitalized general and administrative costs
directly associated with the acquisition, exploration, and development efforts
of approximately $1.3 million and $0 million for years ended December 31, 2006,
and 2005, respectively, and (ii) interest expense on unproven properties of
$3.9 million and $1.1 million for years ended December 31, 2006, and 2005,
respectively. Certain non-cash transactions are included as follows:
(1) 2006 asset retirement obligation and capitalized stock compensation of
$1.3 million and $0.45 million, respectively, (2) net transfer of $0.31 million
from 2005 deposits to 2006 oil and natural gas properties, and (3) the 2005
fair market value of properties received from Cadence in the merger valued
at
$22.4 million.
Results
of Operations
The
following table sets forth the results of operations related to natural gas
activities for the Company for the years ended December 31, 2006, and
2005.
|
|
2006
|
|
2005
|
|
Oil
and natural gas sales
|
|
$
|
21,591,811
|
|
$
|
6,743,444
|
|
Production
and lease operating costs
|
|
|
(7,155,450
|
)
|
|
(2,093,840
|
)
|
Depreciation
and depletion
|
|
|
(2,681,290
|
)
|
|
(767,511
|
)
|
Results
of producing activities
|
|
$
|
11,755,071
|
|
$
|
3,882,093
|
|
These
results of operations do not include a provision for income taxes due to the
net
operating loss carryforward available to offset taxable income during both
2006
and 2005.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
FOR
THE
SIX MONTHS ENDED JUNE 30, 2007, and 2006
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEET
|
|
|
June
30, 2007
|
|
|
|
(Unaudited)
|
|
ASSETS
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
Cash
and cash equivalents
|
|
$
|
720,498
|
|
Accounts
receivable
|
|
|
|
|
Oil
and natural gas sales
|
|
|
4,982,887
|
|
Joint
interest owners
|
|
|
1,004,172
|
|
Notes
receivable
|
|
|
-
|
|
Prepaid
expenses and other current assets
|
|
|
817,825
|
|
Short-term
derivative instruments
|
|
|
2,201,716
|
|
Total
current assets
|
|
|
9,727,098
|
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
|
Oil
and natural gas properties, using full cost accounting:
|
|
|
|
|
Proved
properties
|
|
|
142,200,610
|
|
Unproved
properties
|
|
|
54,200,686
|
|
Properties
held for sale
|
|
|
-
|
|
Less:
accumulated depletion and amortization
|
|
|
(12,151,898
|
)
|
Total
oil and natural gas properties, net
|
|
|
184,249,398
|
|
Pipelines
|
|
|
5,019,906
|
|
Other
property and equipment
|
|
|
5,400,816
|
|
Less:
accumulated depreciation
|
|
|
(1,114,508
|
)
|
Total
property and equipment, net
|
|
|
193,555,612
|
|
OTHER
ASSETS:
|
|
|
|
|
Long-term
derivative instruments
|
|
|
560,718
|
|
Goodwill
|
|
|
19,373,264
|
|
Intangibles
(net of accumulated amortization of $3,722,085 and $2,946,250,
respectively)
|
|
|
1,232,915
|
|
Other
investments
|
|
|
901,268
|
|
Debt
issuance costs (net of accumulated amortization of $1,329,051 and
$892,535, respectively)
|
|
|
2,054,648
|
|
Other
|
|
|
994,035
|
|
Total
other assets
|
|
|
25,116,848
|
|
TOTAL
ASSETS
|
|
$
|
228,399,558
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEET
(continued)
|
|
|
June
30, 2007
|
|
|
|
(Unaudited)
|
|
LIABILITIES
AND SHARE HOLDERS’ EQUITY
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
Accounts
payable and accrued liabilities
|
|
$
|
5,635,186
|
|
Accrued
exploration, development, and leasehold costs
|
|
|
3,294,213
|
|
Short-term
bank borrowings
|
|
|
1,418,615
|
|
Current
portion of obligations under capital leases
|
|
|
6,561
|
|
Current
portion of note payable—other
|
|
|
100,768
|
|
Current
portion of mortgage payable
|
|
|
100,008
|
|
Drilling
advances
|
|
|
565,891
|
|
Total
current liabilities
|
|
|
11,121,242
|
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
Obligations
under capital leases, net of current portion
|
|
|
4,984
|
|
Asset
retirement obligation
|
|
|
989,885
|
|
Notes
payable
|
|
|
163,402
|
|
Mortgage
payable
|
|
|
3,028,733
|
|
Senior
secured credit facility
|
|
|
35,000,000
|
|
Mezzanine
financing
|
|
|
40,000,000
|
|
Total
long-term liabilities
|
|
|
79,187,004
|
|
Total
liabilities
|
|
|
90,308,246
|
|
Minority
interest in net assets of subsidiaries
|
|
|
85,828
|
|
|
|
|
|
|
COMMITMENTS,
CONTINGENCIES AND SUBSEQUENT EVENT
(Note
9 and Note 11 )
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS’
EQUITY
|
|
|
|
|
Common
stock, $0.01 par value; authorized 250,000,000 shares; issued and
outstanding 101,589,456 shares and 101,412,966 shares,
respectively
|
|
|
1,015,895
|
|
Additional
paid-in capital
|
|
|
139,347,287
|
|
Accumulated
other comprehensive income
|
|
|
2,762,434
|
|
Accumulated
deficit
|
|
|
(5,120,132
|
)
|
Total
shareholders’ equity
|
|
|
138,005,484
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
228,399,558
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
|
|
|
Six
Months Ended June 30
|
|
|
|
2007
|
|
2006
|
|
REVENUES:
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$
|
12,532,005
|
|
$
|
10,941,220
|
|
Pipeline
transportation and marketing
|
|
|
286,932
|
|
|
242,299
|
|
Field
service and sales
|
|
|
249,602
|
|
|
-
|
|
Interest
and other
|
|
|
474,758
|
|
|
181,631
|
|
Total
revenues
|
|
|
13,543,297
|
|
|
11,365,150
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
566,969
|
|
|
445,825
|
|
Production
and lease operating expense
|
|
|
4,126,700
|
|
|
2,853,374
|
|
Pipeline
operating expense
|
|
|
177,802
|
|
|
137,484
|
|
Field
services expense
|
|
|
200,096
|
|
|
-
|
|
General
and administrative expense
|
|
|
4,233,701
|
|
|
3,242,713
|
|
Oil
and natural gas depletion and amortization
|
|
|
1,523,460
|
|
|
2,010,383
|
|
Other
assets depreciation and amortization
|
|
|
1,142,104
|
|
|
1,013,783
|
|
Interest
expense
|
|
|
2,050,403
|
|
|
3,564,154
|
|
Taxes
(refunds), other
|
|
|
(53
|
)
|
|
29,361
|
|
Total
expenses
|
|
|
14,021,182
|
|
|
13,297,077
|
|
INCOME
(LOSS) BEFORE MINORITY INTEREST
|
|
|
(477,885
|
)
|
|
(1,931,927
|
)
|
MINORITY
INTEREST IN INCOME OF SUBSIDIARIES
|
|
|
(32,957
|
)
|
|
(17,919
|
)
|
NET
INCOME (LOSS)
|
|
$
|
(510,842
|
)
|
$
|
(1,949,846
|
)
|
NET
INCOME (LOSS) PER COMMON SHARE
—BASIC
|
|
$
|
(0.01
|
)
|
$
|
(0.03
|
)
|
—DILUTED
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE COMMON SHARES OUTSTANDING
—BASIC
|
|
|
101,602,875
|
|
|
70,265,281
|
|
—DILUTED
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Unaudited)
|
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
COMMON
STOCK:
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Balance,
beginning
|
|
|
101,412,966
|
|
$
|
1,014,130
|
|
|
61,536,261
|
|
$
|
615,363
|
|
Cashless
exercise of stock options and warrants
|
|
|
78,158
|
|
|
782
|
|
|
3,280,105
|
|
|
32,801
|
|
Conversion
of redeemable convertible preferred stock to common stock
|
|
|
-
|
|
|
-
|
|
|
23,334
|
|
|
233
|
|
Exercise
of stock options and warrants
|
|
|
173,332
|
|
|
1,733
|
|
|
15,565,457
|
|
|
155,655
|
|
Issuance
of stock to officers and directors in lieu of compensation
|
|
|
-
|
|
|
-
|
|
|
90,000
|
|
|
900
|
|
Issuance
of stock to related parties in lieu of commission relating to exercise
of
warrants
|
|
|
-
|
|
|
-
|
|
|
1,469,860
|
|
|
14,699
|
|
Adjustment
to stock ledger
|
|
|
(75,000
|
)
|
|
(750
|
)
|
|
-
|
|
|
-
|
|
Balance,
ending
|
|
|
101,589,456
|
|
|
1,015,895
|
|
|
81,965,017
|
|
|
819,651
|
|
ADDITIONAL
PAID-IN CAPITAL:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
beginning
|
|
|
|
|
|
138,105,626
|
|
|
|
|
|
58,670,698
|
|
Cashless
exercise of stock options and warrants
|
|
|
|
|
|
(782
|
)
|
|
|
|
|
(32,801
|
)
|
Conversion
of redeemable convertible preferred stock to common stock
|
|
|
|
|
|
-
|
|
|
|
|
|
39,768
|
|
Costs
of equity offerings
|
|
|
|
|
|
(10,096
|
)
|
|
|
|
|
-
|
|
Stock-based
compensation
|
|
|
|
|
|
1,335,523
|
|
|
|
|
|
757,442
|
|
Exercise
of stock options and warrants
|
|
|
|
|
|
63,266
|
|
|
|
|
|
17,988,794
|
|
Issuance
of stock to officers and directors in lieu of compensation
|
|
|
|
|
|
-
|
|
|
|
|
|
348,300
|
|
Issuance
of stock to related party in lieu of commission relating to exercise
of
warrants
|
|
|
|
|
|
-
|
|
|
|
|
|
(14,699
|
)
|
Adjustment
to stock ledger
|
|
|
|
|
|
(146,250
|
)
|
|
|
|
|
-
|
|
Balance,
ending
|
|
|
|
|
|
139,347,287
|
|
|
|
|
|
77,757,502
|
|
ACCUMULATED
OTHER COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
beginning
|
|
|
|
|
|
5,220,633
|
|
|
|
|
|
-
|
|
Changes
in fair value of derivative instruments
|
|
|
|
|
|
(1,099,949
|
)
|
|
|
|
|
1,754,365
|
|
Recognition
of gain on derivative instruments
|
|
|
|
|
|
(1,358,250
|
)
|
|
|
|
|
(792,350
|
)
|
Balance,
ending
|
|
|
|
|
|
2,762,434
|
|
|
|
|
|
962,015
|
|
ACCUMULATED
DEFICIT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
beginning
|
|
|
|
|
|
(4,609,290
|
)
|
|
|
|
|
(2,660,134
|
)
|
Dividends
accrued on redeemable convertible preferred stock
|
|
|
|
|
|
-
|
|
|
|
|
|
(4,295
|
)
|
Net
loss
|
|
|
|
|
|
(510,842
|
)
|
|
|
|
|
(1,949,846
|
)
|
Balance,
end
|
|
|
|
|
|
(5,120,132
|
)
|
|
|
|
|
(4,614,275
|
)
|
TOTAL
SHAREHOLDERS’ EQUITY
|
|
|
|
|
$
|
138,005,484
|
|
|
|
|
$
|
74,924,893
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
2006
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(510,842
|
)
|
$
|
(1,949,846
|
)
|
Adjustments
to reconcile net loss to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion, and amortization
|
|
|
2,665,564
|
|
|
3,024,166
|
|
Amortization
of debt issuance costs
|
|
|
446,790
|
|
|
383,422
|
|
Accretion
of asset retirement obligation
|
|
|
31,112
|
|
|
36,989
|
|
Stock-based
compensation
|
|
|
1,201,756
|
|
|
392,149
|
|
Equity
loss of other investments and other
|
|
|
(67,418
|
)
|
|
172,610
|
|
Realized
gain on sale of other investments
|
|
|
(418,147
|
)
|
|
-
|
|
Minority
interest income of subsidiaries
|
|
|
32,957
|
|
|
17,919
|
|
Changes
in operating assets and liabilities, net of effects of
merger:
|
|
|
|
|
|
|
|
Accounts
receivable - oil and natural gas sales
|
|
|
(900,656
|
)
|
|
219,790
|
|
Accounts
receivable - joint interest owners
|
|
|
2,150,169
|
|
|
(1,721,176
|
)
|
Drilling
advance - liabilities
|
|
|
546,508
|
|
|
622,537
|
|
Notes
receivable
|
|
|
221,788
|
|
|
17,000
|
|
Prepaid
expenses and other assets
|
|
|
(267,838
|
)
|
|
(75,597
|
)
|
Accounts
payable and accrued liabilities
|
|
|
280,032
|
|
|
2,467,539
|
|
Net
cash provided by operating activities
|
|
|
5,411,775
|
|
|
3,607,502
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Exploration
and development of oil and natural gas properties
|
|
|
(28,725,363
|
)
|
|
(20,429,090
|
)
|
Leasehold
expenditures, net
|
|
|
(5,614,924
|
)
|
|
(19,841,843
|
)
|
Acquisition
of oil and natural gas properties
|
|
|
-
|
|
|
(23,967,283
|
)
|
Sale
of oil and natural gas properties
|
|
|
1,024,663
|
|
|
6,990,681
|
|
Sale
and leaseback of gas compression equipment
|
|
|
1,202,000
|
|
|
-
|
|
Acquisitions/additions
of pipeline, property, and equipment
|
|
|
(356,288
|
)
|
|
(3,787,922
|
)
|
Additions
in other investments
|
|
|
(4,759
|
)
|
|
(475,000
|
)
|
Sales
of other investments
|
|
|
457,762
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
13,096
|
|
Net
cash used in investing activities
|
|
|
(32,016,909
|
)
|
|
(61,497,361
|
)
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Short-term
bank borrowings
|
|
|
5,335,000
|
|
|
830,000
|
|
Short-term
bank payments
|
|
|
(4,459,173
|
)
|
|
(7,030,000
|
)
|
Advances
on senior secured credit facility
|
|
|
26,000,000
|
|
|
40,000,000
|
|
Payments
on senior secured credit facility
|
|
|
(1,000,000
|
)
|
|
-
|
|
Payments
on mortgage obligations and notes payable
|
|
|
(157,115
|
)
|
|
(32,080
|
)
|
Payments
of financing fees on credit facilities
|
|
|
(152,826
|
)
|
|
(2,386,613
|
)
|
Capital
contributions from minority interest members
|
|
|
24,837
|
|
|
-
|
|
Distributions
to minority interest members
|
|
|
(49,839
|
)
|
|
-
|
|
Proceeds
from exercise of options and warrants
|
|
|
64,999
|
|
|
18,144,449
|
|
Other
|
|
|
(15,647
|
)
|
|
(21,582
|
)
|
Net
cash provided by financing activities
|
|
|
25,590,236
|
|
|
49,504,174
|
|
Net
decrease in cash and cash equivalents
|
|
|
(1,014,898
|
)
|
|
(8,385,685
|
)
|
Cash
and cash equivalents, beginning of the period
|
|
|
1,735,396
|
|
|
11,980,638
|
|
Cash
and cash equivalents, end of the period
|
|
$
|
720,498
|
|
$
|
3,594,953
|
|
|
|
|
|
|
|
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited-continued)
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
2007
|
|
|
2006
|
|
NONCASH
FINANCING AND INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Oil
and natural gas properties asset retirement obligation
|
|
$
|
(370,842
|
)
|
$
|
976,340
|
|
Accrued
exploration and development costs on oil and natural gas
properties
|
|
|
2,945,868
|
|
|
1,716,283
|
|
Accrued
leasehold costs
|
|
|
348,345
|
|
|
427,859
|
|
Pipeline
acquisition, transfer of investment to pipeline assets
|
|
|
-
|
|
|
1,100,973
|
|
Oil
and natural gas properties capitalized stock-based
compensation
|
|
|
133,767
|
|
|
365,293
|
|
Conversion
of redeemable convertible preferred stock to common stock
|
|
|
-
|
|
|
40,001
|
|
Conversion
of accounts receivable to long-term notes receivable
|
|
|
26,349
|
|
|
60,000
|
|
Vehicle
purchase through financing
|
|
|
94,407
|
|
|
-
|
|
Common
stock received in connection with the sale of mining
claims
|
|
|
56,885
|
|
|
-
|
|
SUPPLEMENTAL
INFORMATION OF INTEREST AND INCOME TAXES PAID:
|
|
|
|
Interest,
net of amount capitalized of $1,857,689 and $646,977,
respectively
|
|
$
|
1,352,151
|
|
$
|
2,783,248
|
|
Income
taxes
|
|
|
107,700
|
|
|
5,463
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
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 and the New Albany shale of Indiana and
Kentucky.
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 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
Reclassifications
Certain
reclassifications have been made to the condensed consolidated financial
statements for the six months ended June 30, 2006, in order to conform to the
December 31, 2006, and June 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 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.
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.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
following table sets forth a reconciliation of the Company’s ARO
liability:
Six
Months Ended June 30,
|
|
2007
|
|
2006
|
|
Beginning
balance
|
|
$
|
1,331,893
|
|
$
|
812,634
|
|
Liabilities
incurred
|
|
|
123,861
|
|
|
263,026
|
|
Liabilities
settled
|
|
|
(34,293
|
)
|
|
-
|
|
Accretion
expense
|
|
|
31,112
|
|
|
36,986
|
|
Revisions
of estimated liabilities
|
|
|
(462,688
|
)
|
|
(99,317
|
)
|
Ending
balance
|
|
$
|
989,885
|
|
$
|
1,013,329
|
|
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 June 30, 2007, and qualified as cash flow hedges:
Period
|
|
Type
of Contract
|
|
Natural
Gas Volume per Day
|
|
Price
per mmbtu
|
|
Fair
Value Asset (Liability)
|
|
April
2007—December 2008
|
|
|
Swap
|
|
|
5,000
mmbtu
|
|
$
|
9.00
|
|
$
|
2,481,798
|
|
April
2007—December 2008
|
|
|
Collar
|
|
|
2,000
mmbtu
|
|
$
|
7.55/$
9.00
|
|
|
129,597
|
|
January
2009—December 2009
|
|
|
Swap
|
|
|
7,000
mmbtu
|
|
$
|
8.72
|
|
|
72,968
|
|
January
2010—March 2011
|
|
|
Swap
|
|
|
7,000
mmbtu
|
|
$
|
8.68
|
|
|
78,071
|
|
Total
Estimated Fair Value
|
|
|
|
|
|
|
|
|
|
|
$
|
2,762,434
|
|
For
the
six months ended June 30, 2007, the Company has recognized in Comprehensive
Income changes in fair value of $(1,099,949) 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 six months
ended June 30, 2007, and 2006, the Company recognized $1,358,250 and $792,350,
respectively, in net gains from hedging activities included in oil and natural
gas revenues.
In
July
2007, the Company entered into the following fixed swap contracts: 1) 2,000
mmbtu per day with a fixed price of $8.41 per mmbtu for the period from January
1, 2008 through December 31, 2008; and 2) 7,000 mmbtu per day with a fixed
price
of $7.62 per mmbtu for the period from April 1, 2011 through September 30,
2011.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
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 Six Months Ended June 30,
|
|
2007
|
|
2006
|
|
General
and administrative expenses
|
|
$
|
1,201,756
|
|
$
|
392,149
|
|
Oil
and natural gas properties
|
|
|
133,767
|
|
|
365,293
|
|
Total
|
|
$
|
1,335,523
|
|
$
|
757,442
|
|
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:
Six
Months Ended June 30,
|
|
2007
|
|
2006
|
|
Net
loss
|
|
$
|
(510,842
|
)
|
$
|
(1,949,846
|
)
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
Change
in fair value of derivative instruments
|
|
|
(1,099,949
|
)
|
|
1,754,365
|
|
Comprehensive
Loss
|
|
$
|
(1,610,791
|
)
|
$
|
(195,481
|
)
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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. For the
three months ended June 30, 2007, the effect of stock options representing
2,395,780 common shares were excluded from the calculation of diluted earnings
per share as their inclusion would have been antidilutive because the exercise
price of the options was greater than the average market price of the common
stock during the period. All dilutive securities were excluded in the
computation of diluted loss per share for all other periods 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
- 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.
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 June 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 expects to develop definitive disposal plan in the upcoming months
and has currently removed properties held for sale from the balance
sheet.
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. As of June 30, 2007, our total borrowing
capacity available under this facility was $3.6 million. To secure this line
of
credit, two trusts controlled by an executive officer pledged certain shares
of
the Company’s common stock under his control. The interest rate under the
revolving line of credit is Wall Street prime (8.25% at June 30, 2007, and
2006,
respectively) 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 15, 2007. Northwestern Bank also
provides letters of credit for the drilling program (as described in Note 9
“Commitments and Contingencies”). Interest expense on the Northwestern Bank
revolving line for the six months ended June 30, 2007, and 2006, was $6,882
and
$178,454, 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 (8.25% at June 30, 2007) with interest payable monthly in arrears.
Principal is payable at the expiration of the revolving line of credit
agreement. The expiration date is October 1, 2007. Interest expense for the
six
months ended June 30, 2007, was $1,343.
Mortgage
and Notes Payable - Bach
As
of
June 30, 2007, Bach’s outstanding loans were as follows with interest expense
for the three and six months ended June 30, 2007:
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
Description
of Loan
|
|
Date
of Loan
|
|
Maturity
Date
|
|
Interest
Rate
|
|
Principal
Amount
Outstanding
|
|
Six
Months Ended
June
30, 2007
|
|
Mortgage
payable on building
|
|
|
10/06/06
|
|
|
10/15/09
|
|
|
6.00
|
%
|
$
|
374,587
|
|
$
|
11,344
|
|
Notes
payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vehicles
|
|
|
10/06/06
|
|
|
10/01/10
|
|
|
7.50
|
%
|
|
79,240
|
|
|
3,205
|
|
Equipment
|
|
|
10/06/06
|
|
|
09/01/07
|
|
|
5.50
|
%
|
|
3,093
|
|
|
232
|
|
Vehicles
|
|
|
12/18/06
|
|
|
12/20/09
|
|
|
7.25
|
%
|
|
59,492
|
|
|
2,437
|
|
Vehicles
|
|
|
04/23/07
|
|
|
04/25/11
|
|
|
7.00
|
%
|
|
91,003
|
|
|
569
|
|
Total
notes payable
|
|
|
|
|
|
|
|
|
|
|
$
|
232,828
|
|
$
|
6,443
|
|
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 June 30, 2007, the principal
amount outstanding was $2,754,154. Interest expense for the six months ended
June 30, 2007, and 2006, was $69,336 and $99,734, respectively.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
is
required beginning November 30, 2006, through August 1, 2007. The interest
rate
is 7.01% per year. As of June 30, 2007, the principal amount outstanding was
$31,342. Interest expense for the six months ended June 30, 2007,
$2,273.
Mezzanine
Financing
The
Company has a 5-year $50 million mezzanine credit facility with Trust Company
of
the West (“TCW”) for the Michigan Antrim drilling program. The borrower is
Aurora Antrim North (“North”), a wholly owned subsidiary of the Company. Upon
closing of the BNP Paribas (“BNP”) senior secured credit facility discussed
below, TCW now holds a second lien position in the Michigan Antrim natural
gas
properties. The interest rate is fixed at 11.5% per year, compounded quarterly,
and payable in arrears. Beginning September 28, 2006, and quarterly thereafter,
the required principal payment is 75% (100% if coverage deficiency or default
occurs) of adjusted net cash flow determined by deducting specific expenses,
including capital expenditures from “gross cash revenue.” The Company estimates
that no principal payments on the mezzanine financing will be required until
maturity because of the level of anticipated capital expenditures. The maturity
date is September 30, 2009 with a commitment expiration date of August 12,
2007.
The borrowing base is impacted by, among other factors, the fair value of the
Company’s natural gas reserves that are pledged to TCW. Changes in the fair
value of the natural gas reserves are caused by changes in prices for natural
gas, operating expenses, and the results of drilling activity. A significant
decline in the fair value of these reserves could reduce the borrowing base,
and
the Company may not be able to meet certain facility covenants.
The
mezzanine credit facility contains, among other things, certain covenants
relating to restricted payments (as defined), loans or advances to others,
additional indebtedness, and incurrence of liens and provides for the
maintenance of certain financial and operating ratios, including current ratio
and specified coverage ratios (collateral coverage and proved developed
producing reserves coverage ratios).
As
part
of the mezzanine credit facility, the Company provided an affiliate of TCW
an
overriding royalty interest in certain properties 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 is 4%, subject to
certain adjustments.
For
the
six months ended June 30, 2007, and 2006, interest and fees incurred for the
mezzanine credit facility was $2,350,834 and $2,351,111,
respectively.
Senior
Secured Credit Facility
On
January 31, 2006, the Company entered into a senior secured credit facility
with
BNP for drilling, development, and acquisitions, as well as other general
corporate purposes. The borrower is North with a current borrowing base of
$50
million. As proved reserves are added, this borrowing base may increase to
$100
million with TCW consent. A required semiannual reserve report may result in
an
increase or decrease in credit availability. The security for this facility
is a
first lien position in certain Michigan Antrim assets; a guarantee from Aurora;
and a guarantee from the Company secured by a pledge of its stock in Aurora.
This facility matures the earlier of January 31, 2010, or 91 days prior to
the
maturity of the mezzanine credit facility, unless the Company elects to
terminate the commitment earlier pursuant to the terms of the senior secured
credit facility.
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 June 30, 2007, interest on the borrowings had a weighted average
interest rate of 7.125%. For the six months ended June 30, 2007, and 2006,
interest and fees incurred for the senior secured credit facility was $979,235
and $1,106,397, respectively.
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, a prohibition on the Company’s ability to prepay the mezzanine credit
facility, geographic limitations on operations to the United States, and
maintenance of certain financial and operating ratios, including current ratio
and specified coverage ratios (collateral coverage and proved developed
producing reserves coverage ratios). Effective December 21, 2006, the senior
secured credit facility was amended to eliminate the interest coverage ratio
covenant for the fiscal quarter ending December 31, 2006, and to modify the
2007
fiscal quarters’ interest coverage ratio covenants.
On
June
22, 2007, the senior secured credit facility was amended to modify the interest
coverage ratio covenant for all remaining fiscal quarters in 2007. The interest
coverage ratio will not, as of the last day of any 2007 fiscal quarter, permit
the ratio of EBITDAX to Interest Expense for such period to be (i) less than
2.0
to 1.0 for the quarters ending June 30, 2007 and September 30, 2007 and (ii)
less than 2.25 to 1.0 for fiscal quarter ending December 31, 2007. In addition,
any swap agreements entered into by the parties may contain contingent
requirements, agreements or covenants for North to post collateral or margin
to
secure its obligations under such swap agreement to cover market exposures.
The
Company has engaged BNP to arrange and syndicate a second lien term loan
facility. The proposed loan facility provides for a 5-year term loan in an
initial amount up to $50 million which may increase up to $70 million over
the
life of the loan facility. The proceeds of the loan will be used to refinance
the Company’s existing mezzanine financing with TCW and for general corporate
purposes. BNP has identified several lenders willing to participate in this
syndication subsequent to the completion of due diligence and lenders internal
credit approvals. If this syndication is completed, the borrowing base under
the
existing BNP senior secured credit facility will increase from the current
authorized borrowing base of $50 million to $70 million. There is no assurance
that this proposed loan facility will be completed as currently
contemplated.
The
Company has incurred deferred financing fees of approximately $406,000 from
BNP
and approximately $2,850,000 from TCW. The deferred financing fees are being
amortized on a straight-line basis over the remaining terms of each debt
obligation. Amortization expense is estimated to be $0.8 million per year
through 2009. Amortization expense was $446,790 and $383,146 for the six months
ended June 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 $1,857,689 and $646,977 for the six months
ended June 30, 2007, and 2006, respectively.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE
7.
|
SHAREHOLDERS’
EQUITY
|
Common
Stock
In
January 2007, 78,158 shares of the Company’s common stock were issued in
connection with the exercise of outstanding warrants by an outside party in
a
net issue (cashless) exercise transaction.
In
February, March, and May 2007, 80,000 common stock options were exercised by
various Company employees under the existing stock option plans at an exercise
price of $0.375 per share. The Company received $30,000 in conjunction with
these exercises.
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
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.
Common
Stock Warrants
The
following table provides information related to stock warrant activity for
the
six months ended June 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
|
|
|
1.59
|
|
NOTE
8.
|
COMMON
STOCK OPTIONS
|
As
of
June 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 provides activity for the stock option plans referenced above
for the six months ended June 30, 2007:
|
|
Number
of Shares Underlying Options
|
|
Options
outstanding at beginning of period
|
|
|
3,432,496
|
|
Options
granted
|
|
|
185,000
|
|
Options
exercised
|
|
|
(173,332
|
)
|
Options
forfeited and other adjustments
|
|
|
(80,000
|
)
|
Options
outstanding at end of period
|
|
|
3,364,164
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
weighted average assumptions used in the Black-Scholes option-pricing model
used
to determine fair value 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 provides
activity with respect to all stock options awarded for the six months ended
June
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
|
|
|
(173,332
|
)
|
|
0.38
|
|
|
|
|
Forfeitures
and other adjustments
|
|
|
(80,000
|
)
|
|
5.03
|
|
|
|
|
Options
outstanding at end of period
|
|
|
4,794,444
|
|
$
|
2.30
|
|
$
|
3,339,505
|
|
Exercisable
at end of period
|
|
|
3,139,775
|
|
$
|
1.55
|
|
$
|
3,339,505
|
|
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 six
months
ended June 30, 2007, was approximately
$304,000.
|
The
following table provides the unrecognized compensation expense related to
unvested stock options as of June 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
|
|
$
|
-
|
|
$
|
428,053
|
|
$
|
31,996
|
|
$
|
1,146
|
|
|
|
|
2
nd
Quarter
|
|
|
-
|
|
|
360,689
|
|
|
14,664
|
|
|
-
|
|
|
|
|
3
rd
Quarter
|
|
|
587,474
|
|
|
117,728
|
|
|
5,194
|
|
|
-
|
|
|
|
|
4
th
Quarter
|
|
|
547,100
|
|
|
97,844
|
|
|
2,893
|
|
|
-
|
|
|
|
|
Total
|
|
$
|
1,134,574
|
|
$
|
1,004,314
|
|
$
|
54,747
|
|
$
|
1,146
|
|
$
|
2,194,781
|
|
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
weighted average remaining life by exercise price as of June 30, 2007, is
summarized below:
Range
of
Exercise
Prices
|
|
Outstanding
Shares
|
|
Weighted
Average Life
|
|
Exercisable
Shares
|
|
Weighted
Average Life
|
|
$0.25
- $0.38
|
|
|
576,664
|
|
|
3.7
|
|
|
576,664
|
|
|
3.7
|
|
$0.50
- $0.75
|
|
|
1,440,000
|
|
|
1.6
|
|
|
1,440,000
|
|
|
1.6
|
|
$1.25
- $1.75
|
|
|
352,000
|
|
|
7.2
|
|
|
352,000
|
|
|
7.2
|
|
$2.23
- $3.55
|
|
|
498,280
|
|
|
6.8
|
|
|
120,280
|
|
|
2.4
|
|
$3.62
|
|
|
1,140,000
|
|
|
3.5
|
|
|
300,000
|
|
|
3.4
|
|
$4.45
- $4.70
|
|
|
627,500
|
|
|
8.3
|
|
|
190,831
|
|
|
7.9
|
|
$5.19
- $5.54
|
|
|
160,000
|
|
|
3.3
|
|
|
160,000
|
|
|
3.3
|
|
$0.25
- $5.54
|
|
|
4,794,444
|
|
|
4.2
|
|
|
3,139,775
|
|
|
3.3
|
|
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 June 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 June 30, 2007, letters of
credit in the amount of $1,056,100 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.
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.
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES
TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Fry
Well Loss
The
Company is a participant with Savoy Energy, L.P. (“Savoy”) in a well known as
the Fry 1-13 located in Mecosta County, Michigan. In late December 2006, the
well experienced a blow-out event. Savoy currently is estimating costs of
approximately $5.6 million for expenses associated with controlling the well
and
other related costs. The Company has a 13.33% cost interest (10% working
interest) in this well to casing point and has paid approximately $762,000
to
cover its portion of the loss.
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 June 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.
NOTE
11.
|
SUBSEQUENT
EVENT
|
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.
APPENDIX A
GLOSSARY
OF OIL AND NATURAL GAS TERMS
The
following is a description of the meanings of some of the oil and natural gas
industry terms used in this prospectus.
bbl.
Stock
tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in
reference to crude oil or other liquid hydrocarbons.
bcf.
Billion
cubic feet of natural gas.
bcfe.
Billion
cubic feet equivalent, determined using the ratio of six mcf of natural gas
to
one bbl of crude oil, condensate or natural gas liquids.
Biogenic
gas.
Gas
produced by methanogenic bacteria or microbes. Predominately methane gas with
<1% higher chain hydrocarbons.
btu
or British thermal unit.
The
quantity of heat required to raise the temperature of one pound of water by
one
degree Fahrenheit.
Casing.
Steel
pipe used in wells to seal off fluids from the bore hole and to prevent the
walls of the hole from sloughing off or caving. There may be several strings
of
casing in a well, one inside the other.
Completion.
The
process of treating a drilled well followed by the installation of permanent
equipment for the production of natural gas or oil, or in the case of a dry
hole, the reporting of abandonment to the appropriate agency.
Compression.
Process
of taking a gas or compressible fluid from a low pressure to a higher
pressure.
Developed
acreage.
The
number of acres that are allocated or assignable to productive wells or wells
capable of production.
Development
well.
A
well drilled within the proved area of a natural gas or oil reservoir to the
depth of a stratigraphic horizon known to be productive.
Dewatering.
The
system whereby brine water is removed from the well in order to allow the
gas/oil to be released. Pumping mechanisms are usually used for this process.
New wells may have great amounts of water, which must first be removed. As
water
is removed, gas/oil production usually increases.
Drilling
locations.
Total
gross locations specifically quantified by management to be included in the
Company’s multi-year drilling activities on existing acreage. The Company’s
actual drilling activities may change depending on the availability of capital,
regulatory approvals, seasonal restrictions, oil and natural gas prices, costs,
drilling results and other factors.
Dry
well.
A
well found to be incapable of producing either oil or gas in sufficient
quantities to justify completion as an oil or gas well.
Exploratory
well.
A
well drilled to find and produce natural gas or oil reserves not classified
as
proved, to find a new reservoir in a field previously found to be productive
of
natural gas or oil in another reservoir or to extend a known
reservoir.
Field.
An
area consisting of either a single reservoir or multiple reservoirs, all grouped
on or related to the same individual geological structural feature and/or
stratigraphic condition.
Finding
and development costs.
Capital
costs incurred in the acquisition, exploitation and exploration of proved oil
and natural gas reserves divided by proved reserve additions and revisions
to
proved reserves.
Formation.
An
identifiable layer of rocks named after its geographical location and dominant
rock type.
Gross
acres, gross wells or gross reserves.
The
total acres, wells, or reserves as the case may be, in which a working interest
is owned.
Lease.
A
legal contract that specifies the terms of the business relationship between
an
energy company and a landowner or mineral rights holder on a particular tract
of
land.
Leasehold.
Mineral
rights leased in a certain area to form a project area.
mbbls.
Thousand
barrels of crude oil or other liquid hydrocarbons.
mcf.
Thousand
cubic feet of natural gas.
mcf/d.
mcf
per day.
mcfe.
Thousand
cubic feet equivalent, determined using the ratio of six mcf of natural gas
to
one bbl of crude oil, condensate or natural gas liquids.
mmbbls.
Million
barrels of crude oil or other liquid hydrocarbons.
mmbtu.
Million
British Thermal Units.
mmcf.
Million
cubic feet of natural gas.
mmcf/d.
mmcf
per day.
mmcfe.
Million
cubic feet equivalent, determined using the ratio of six mcf of natural gas
to
one bbl of crude oil, condensate or natural gas liquids.
mmcfe/d.
mmcfe
per day.
Net
acres, net wells, or net reserves.
The
sum of the fractional working interest owned in gross acres, gross wells, or
gross reserves, as the case may be.
Overriding
royalty interest.
Is
similar to a basic royalty interest except that it is created out of the working
interest. For example, an operator possesses a standard lease providing for
a
basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then
entitles the operator to retain 7/8 of the total oil and gas produced. The
7/8
in this case is the 100% working interest the operator owns. This operator
may
assign his working interest to another operator subject to a retained 1/8
overriding royalty. This would then result in a basic royalty of 1/8, an
overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty
interest owners have no obligation or responsibility for developing and
operating the property. The only expenses borne by the overriding royalty owner
are a share of the production or severance taxes and sometimes costs incurred
to
make the oil or gas salable.
Pay
zone.
The
geologic formation where the gas/oil is located.
PDP.
Proved
developed producing.
Play/Trend.
A
set of discovered or prospective oil and/or natural gas accumulations sharing
similar geologic, geographic and temporal properties, such as source rock,
reservoir structure, timing, trapping mechanism and hydrocarbon
type.
Plugging
and abandonment.
Refers
to the sealing off of fluids in the strata penetrated by a well so that the
fluids from one stratum will not escape into another or to the surface.
Regulations of all states require plugging of abandoned wells.
Present
value of future net revenues (PV-10).
The
present value of estimated future revenues to be generated from the production
of proved reserves, before income taxes, of proved reserves calculated in
accordance with Financial Accounting Standards Board guidelines, net of
estimated production and future development costs, using prices and costs as
of
the date of estimation without future escalation, without giving effect to
hedging activities, non-property related expenses such a general and
administrative expenses, debt service and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
PV-10.
Present
value of future net revenues.
Production.
Natural
resources, such as oil or gas, taken out of the ground.
Productive
well.
A
well that is found to be capable of producing either oil or gas in sufficient
quantities to justify completion as an oil or gas well.
Project.
A
targeted development area where it is probable that commercial gas can be
produced from new wells.
Prospect.
A
specific geographic area which, based on supporting geological, geophysical
or
other data and also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery of commercial
hydrocarbons.
Proved
developed non-producing reserves.
Proved
developed reserves that are shut-in or otherwise not producing.
Proved
developed producing reserves.
Reserves
that can be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved
reserves.
The
estimated quantities of oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be
commercially recoverable from known reservoirs under current economic and
operating conditions, operating methods, and government
regulations.
Proved
undeveloped reserves.
Proved
reserves that are expected to be recovered from new wells on undrilled acreage
or from existing wells where a relatively major expenditure is required for
recompletion.
Rat-hole.
An
additional well bore drilled below the pay zone, usually for the purpose of
collecting water and pumping water to the surface in a manner which keeps a
fluid level below the pay zone.
Recompletion.
The
process of re-entering an existing well bore that is either producing or not
producing and completing new reservoirs in an attempt to establish or increase
existing production.
Reserves.
Oil,
gas and gas liquids thought to be accumulated in known reservoirs.
Reservoir.
A
porous and permeable underground formation containing a natural accumulation
of
producible nature gas and/or oil that is confined by impermeable rock or water
barriers and is separate from other reservoirs.
Salt
water disposal well.
A
well into which salt water and other liquid substances are pumped for disposal
purposes.
Schlumberger
Holditch.
Schlumberger
Technology Corporation, formerly known as Schlumberger Holditch &
Associates.
Shale.
A
clastic (gr. Klastos, “broken”) rock composed of predominantly clay-sized
particles consisting of clay minerals, quartz and other minerals. Often found
as
thin layered organic rock rich in hydrocarbon deposits.
Shut-in.
A
well that has been capped (having the valves locked shut) for an undetermined
amount of time. This could be for additional testing, could be to wait for
pipeline or processing facility, or a number of other reasons.
Standardized
measure.
The
present value of estimated future cash inflows from proved oil and natural
gas
reserves, less future development, abandonment, production and income tax
expenses, discounted at 10% per annum to reflect timing of future cash
flows and using the same pricing assumptions as were used to calculate PV-10.
Standardized measure differs from PV-10 because standardized measure includes
the effect of future income taxes.
Successful.
A
well is determined to be successful if it is producing natural gas, dewatering,
or awaiting hookup, but not abandoned or plugged.
Undeveloped
acreage.
Lease
acreage on which wells have not been drilled or completed to appoint that would
permit the production of commercial quantities of oil and natural gas regardless
of whether such acreage contains proved reserves.
Well
bore.
The
hole of the well starting at the surface of the earth and descending downward
to
the bottom of the hole.
Working
interest.
The
operating interest that gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of production and
requires the owner to pay a share of the costs of drilling and production
operations.
8,900,000
Shares
Common
Stock
PROSPECTUS
We
have
not authorized any dealer, salesperson, or any other person to give any
information or to represent anything not contained in this prospectus. You
must
not rely on any unauthorized information. This prospectus does not offer to
sell
or buy any shares in any jurisdiction where it is unlawful. The information
in
this prospectus is current as of October
31
,
2007
PART II
INFORMATION
INFORMATION
NOT REQUIRED IN PROSPECTUS
ITEM.
24
INDEMNIFICATION
Limitation
of Liability of Directors, Officers and Others.
In
accordance with Utah law, our articles of incorporation eliminate or limit
the
liability of a director to the corporation or to its shareholders for monetary
damages for any action taken or any failure to take any action as a director,
except liability for (a) the amount of a financial benefit received by a
director to which he is not entitled; (b) an intentional infliction of harm
on the corporation or the shareholders; (c) specified unlawful
distributions; or (d) an intentional violation of criminal
law.
In
addition, in Utah, unless a corporation’s articles of incorporation provide
otherwise:
1. An
officer of the corporation is entitled to mandatory indemnification and is
entitled to apply for court-ordered indemnification, to the same extent as
a
director of the corporation;
2. The
corporation may indemnify and advance expenses to an officer, employee,
fiduciary or agent of the corporation to the same extent as to a
director; and
3. A
corporation may also indemnify and advance expenses to an officer, employee,
fiduciary or agent who is not a director to a greater extent, if not
inconsistent with public policy, and if provided for by its articles of
incorporation, bylaws, general or specific action of its board of directors,
or
contract.
Our
officers and directors are accountable to us as fiduciaries, which mean they
are
required to exercise good faith and fairness in all dealings affecting us.
In
the event that a shareholder believes the officers and/or director shave
violated their fiduciary duties to us, the shareholder may, subject to
applicable rules of civil procedure, be able to bring a class action or
derivative suit to enforce the shareholder’s rights, including rights under
certain federal and state securities laws and regulations to recover damages
from and require an accounting by management, shareholders who have suffered
losses in connection with the purchase or sale of their interest in Aurora
Oil & Gas Corporation in connection with such sale or purchase,
including the misapplication by any such officer or director of the proceeds
from the sale of these securities, may be able to recover such losses from
us.
ITEM.
25
OTHER
EXPENSES OF ISSUANCE AND DISTRIBUTION
The
following table sets forth the estimated expenses in connection with the
issuance and distribution of the securities covered by this registration
statement, other than underwriting discounts and commissions. All of the
expenses will be borne by the Company, except as otherwise
indicated.
Registration
fee
|
|
$
|
-0-
|
|
Fees
and expenses of accountants
|
|
|
9,000.00
|
|
Fees
and expenses of legal counsel
|
|
|
5,000.00
|
|
Fees
and expenses of engineers
|
|
|
1,000.00
|
|
Printing
and engraving expenses
|
|
|
10,000.00
|
|
Miscellaneous
expenses
|
|
|
1,000.00
|
|
Total
|
|
$
|
26,000.00
|
|
ITEM 26.
RECENT
SALES OF UNREGISTERED SECURITIES
At
the
time of issuance, each investor or recipient of unregistered securities
described below was either an accredited investor or a sophisticated investor.
Each investor had access to our most recent Form 10-KSB, all quarterly and
periodic reports filed subsequent to such Form 10-KSB and our most recent
proxy materials.
We
issued
21,959,922 shares of our common stock to various holders of our outstanding
warrants and options during the period from late December 2005 through early
February 2006. With respect to some of these warrant and option exercises,
we
reduced the exercise price for a limited period of time in order to encourage
their early exercise. Each holder who took advantage of the reduced exercise
price was required to execute a six-month lock-up agreement with respect to
the
shares issued in the exercise. In connection with certain of these warrant
exercises, we paid a commission to Sunrise Securities Corporation, an affiliate
of Nathan Low (a shareholder of Cadence) in the amount of $1,534,697. This
entire amount was used by Mr. Low to exercise certain of our outstanding
warrants, which are included in the foregoing total of shares issued in warrant
and option exercises. Of the 21,959,922 shares issued,
5,756,149 shares were registered for issuance by the Company in the S-4
Registration Statement declared effective by the SEC on September 22, 2005,
and the remaining 16,203,773 shares were issued pursuant to the exemption
from registration provided by Section 4(2) of the Securities Act of 1933,
as amended.
During
the period from April 1, 2006 through June 30, 2006, we issued
345,000 shares of our common stock to various holders of our outstanding
options. Some of the option exercises were paid for with cash, and some were
exercised using a net issue election pursuant to which some option shares were
forfeited to pay for the shares issued. We also issued 90,000 shares of
common stock to two directors and one officer as compensation under our 2006
Stock Incentive Plan. Of the 435,000 shares issued, 175,000 shares
were issued pursuant to the exemption from registration provided by
Section 4(2) of the Securities Act of 1933, as amended, and the balance
were issued pursuant to an effective registration statement.
On
October 6, 2006, we issued 1,378,299 shares of unregistered common stock to
Richard Bach and Robin Bach as partial consideration for our purchase of all
of
the assets of Bach Enterprises, Inc. and certain assets of Bach Energy, LLC.
The
number of shares issued was based on a purchase value of $4,700,000 divided
by
$3.41 per share, which was the average of the closing price for the Company’s
common stock for the 30-day calendar period immediately preceding October 6,
2006, the closing date for the acquisitions of assets. We paid an additional
$200,000 in cash for these assets.
On
December 29, 2006, one of our directors, Kevin D. Stulp exercised a warrant
that
was issued to him on March 1, 2002, to purchase 100,000 shares of our common
stock at an exercise price of $0.75 per share for a total exercise price of
$75,000.
The
shares issued in both of the foregoing transactions were issued in reliance
on
the exemption from registration provided by Section 4(2) of the Securities
Act
of 1933, as amended. All of the investors are accredited investors as that
term
is defined in Section 501 of Regulation D. There were no commissions paid
on these transactions.
We
did
not repurchase any of our outstanding equity securities during the quarter
ended
December 31, 2006. We did, however, agree to the rescission of three
previously exercised options, and return the exercise price. In January 2006,
three of our executive officers, William W. Deneau, John V. Miller, Jr., and
Thomas W. Tucker, each exercised an option to purchase 600,000 shares of our
common stock at an exercise price of $0.415 per share for a total exercise
price
of $249,000. In December 2006, these option exercises were rescinded, and we
returned the $249,000 exercise price to each of Mr. Deneau, Mr. Miller and
Mr.
Tucker.
During
the period from January 1, 2007, through September 30, 2007, we issued 78,158
shares of our common stock pursuant to an exercise of a warrant dated April
2,
2004, to purchase 127,500 shares of common stock. This exercise was made
pursuant to a net issue election and the balance of the shares under the warrant
was forfeited. The shares issued pursuant to the warrant exercise were issued
in
reliance on the exemption from registration provided by Section 4(2) of the
Securities Act of 1933, as amended.
ITEM
27.
EXHIBITS
3.1(1)
|
|
Restated
Articles of Incorporation of Aurora Oil & Gas
Corporation.
|
|
|
|
3.2
|
|
By-Laws
of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form
8-K dated August 16, 2007, filed with the SEC on August 22, 2007
and
incorporated herein by reference.)
|
|
|
|
5.1
|
|
Opinion
of Fraser Trebilcock Davis & Dunlap, P.C.
|
|
|
|
10.1
|
|
Securities
Purchase Agreement between Cadence Resources Corporation and the
investors
signatory thereto, dated April 2, 2004 (filed as Exhibit 99.3 to
our
Current Report on Form 8-K filed with the SEC on April 5, 2004,
and
incorporated herein by reference.)
|
10.2
|
|
Securities
Purchase Agreement between Cadence Resources Corporation and the
investors
signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2
to our
Current Report on Form 8-K filed with the SEC on February 2, 2005,
and
incorporated herein by reference.)
|
|
|
|
10.3(2)
|
|
Asset
Purchase Agreement with Nor Am Energy, L.L.C., Provins Family,
L.L.C. and
O.I.L. Energy Corp. dated January 10, 2006.
|
|
|
|
10.4
|
|
Note
Purchase Agreement between Aurora Antrim North, L.L.C. et al. and
TCW
Asset Management Company, dated August 12, 2004 (filed as an Exhibit
to
our Form S-4 registration statement filed with the SEC on May 13,
2005,
and incorporated herein by reference.)
|
|
|
|
10.5
|
|
First
Amended and Restated Note Purchase Agreement between Aurora Antrim
North,
L.L.C. et al. and TCW Asset Management Company, dated December
8, 2005
(filed as an Exhibit to our Annual Report on Form 10-KSB for the
fiscal
year ended September 30, 2005 filed with the SEC on December 29,
2005 and
incorporated herein by reference.)
|
|
|
|
10.6(2)
|
|
First
Amendment to First Amended and Restated Note Purchase Agreement
between
Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company,
dated January 31, 2006.
|
|
|
|
10.7
|
|
Amended
and Restated Credit Agreement dated August 20, 2007, among Aurora
Oil
& Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent
and the Lenders Party hereto. (filed as an Exhibit 10.7 to our
Form 8-K
dated August 16, 2007, filed with the SEC on August 22, 2007 and
incorporated herein by reference.)
|
|
|
|
10.8
|
|
Intercreditor
and Subordination Agreement among, BNP Paribas, et al., TCW Asset
Management Company, and Aurora Antrim North, L.L.C., dated January
31,
2006 (replaced and filed as Exhibit 10.26 to our Form 8-K dated
August 16,
2007, filed with the SEC on August 22, 2007, and incorporated herein
by
reference).
|
|
|
|
10.9(2)
|
|
Promissory
Note from Aurora Energy, Ltd. to Northwestern Bank dated January
31,
2006.
|
|
|
|
10.10(2)
|
|
Confirmation
from BNP Paribas to Aurora Antrim North, L.L.C., dated February
22, 2006
relating to gas sale commitment.
|
|
|
|
10.11
|
|
2006
Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration
Statement filed with the SEC on May 15, 2006 and incorporated herein
by
reference.)
|
|
|
|
10.12(1)
|
|
Employment
Agreement with Ronald E. Huff dated June 19, 2006.
|
|
|
|
10.13(1)
|
|
Letter
Agreement with Bach Enterprises dated July 10, 2006. This Agreement
is
confidential and has been filed separately with the
SEC.
|
|
|
|
10.14(1)
|
|
First
Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
et al.
and BNP Paribas dated July 14, 2006.
|
|
|
|
10.15(1)
|
|
The
Denthorn Trust Commercial Guaranty of obligations to Northwestern
Bank.
|
|
|
|
10.16(1)
|
|
William
W. Deneau Commercial Guaranty of obligations to Northwestern
Bank.
|
|
|
|
10.17(1)
|
|
The
Denthorn Trust Commercial Pledge Agreement to Northwestern
Bank.
|
|
|
|
10.18(3)
|
|
LLC
Membership Interest Purchase Agreement dated October 6, 2006 relating
to
Kingsley Development Company, L.L.C.
|
|
|
|
10.19(3)
|
|
Asset
Purchase Agreement with Bach Enterprises, Inc., et al., dated October
6,
2006.
|
|
|
|
10.20(3)
|
|
Promissory
Note from Aurora Energy, Ltd. to Northwestern Bank dated October
15,
2006.
|
|
|
|
10.21(3)
|
|
Form
of indemnification letter agreement between Aurora Oil & Gas
Corporation and Rubicon Master Fund.
|
|
|
|
10.22(3)
|
|
Patricia
A. Deneau Trust Commercial Guaranty of obligations to Northwestern
Bank.
|
|
|
|
10.23(3)
|
|
Patricia
A. Deneau Trust Commercial Pledge Agreement to Northwestern
Bank.
|
|
|
|
10.24
|
|
Second
Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
et al.
and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24
to our
Annual Report on Form 10-KSB for the fiscal year ended December
31, 2006,
filed with the SEC on March 15, 2007 and incorporated herein by
reference.)
|
|
|
|
10.25
|
|
Third
Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
et al.
and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25
to our
Form 10-Q for the period ended June 30, 2007, filed with the SEC
on August
9, 2007 and incorporated herein by reference.)
|
|
|
|
10.26
|
|
Intercreditor
Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation,
the Borrower, BNP Paribas, as Administrative Agent and the Lenders
Party
hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination
Agreement
among, BNP Paribas, et al., TCW Asset Management Company, and Aurora
Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit
10.26
to our Form 8-K dated August 16, 2007, filed with the SEC on August
22,
2007 and incorporated herein by
reference.)
|
10.27
|
|
Second
Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil
& Gas
Corporation, the Borrower, BNP Paribas, as Administrative Agent
and the
Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K
dated
August 16, 2007, filed with the SEC on August 22, 2007 and incorporated
herein by reference.)
|
|
|
|
21
|
|
Subsidiaries
of Aurora Oil & Gas Corporation.
|
|
|
|
23.1
|
|
Consent
of Ralph E. Davis Associates, Inc.
|
|
|
|
23.2
|
|
Consent
of Schlumberger Technology Corporation.
|
|
|
|
23.3
|
|
Consent
of Netherland, Sewell & Associates, Inc.
|
|
|
|
23.4
|
|
Consent
of Rachlin Cohen & Holtz LLP.
|
|
|
|
23.5
|
|
Awareness
of Weaver and Tidwell, L.L.P.
|
|
|
|
23.6
|
|
Consent
of Fraser Trebilcock Davis & Dunlap, P.C. (included in Exhibit
5.1).
|
(1)
|
Filed
as an exhibit to our Form 10-QSB for the period ended June 30,
2006, filed with the SEC on August 7, 2006, and incorporated herein
by reference.
|
(2)
|
Filed
as an exhibit to our Form 10-KSB for the fiscal year ended
December 31, 2005, filed with the SEC on March 31, 2006, and
incorporated herein by reference.
|
(3)
|
Filed
on October 27, 2006, with our Amendment No. 3 to Form SB-2 registration
statement filing, registration no. 333-137176, and incorporated herein
by
reference.
|
ITEM 28.
UNDERTAKINGS
Insofar
as indemnification for liabilities arising under the Securities Act may be
permitted to directors, officers and controlling persons of the small business
issuer pursuant to the foregoing provisions, or otherwise, the small business
issuer has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event that a claim
for
indemnification against such liabilities (other than the payment by the small
business issuer of expenses incurred or paid by a director, officer or
controlling person of the small business issuer in the successful defense of
any
action, suit or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the small business
issuer will, unless in the opinion of its counsel the matter has been settled
by
controlling precedent, submit to a court of appropriate jurisdiction the
question whether such indemnification by it is against public policy as
expressed in the Securities Act and will be governed by the final adjudication
of such issue.
For
determining any liability under the Securities Act, the small business issuer
will treat the information omitted from the form of prospectus filed as part
of
this registration statement in reliance upon Rule 430A and contained in a
form of prospectus filed by the small business issuer under Rule 424(b)(1),
or (4) or 497(h) under the Securities Act (§§230.424(b)(1), (4) or
230.497(h)), as part of this registration statement as of the time the
Commission declared it effective.
For
determining any liability under the Securities Act, the small business issuer
will treat each post-effective amendment that contains a form of prospectus
as a
new registration statement for the securities offered in the registration
statement, and that offering of the securities at that time as the initial
bona
fide offering of those securities.
SIGNATURES
In
accordance with the requirements of the Securities Act of 1933, the Registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements of filing on Form SB-2 and authorized this Form SB-2
Registration Statement to be signed on its behalf by the undersigned, in the
city of Traverse City, State of Michigan, on this 31st day of October,
2007.
|
|
|
|
AURORA
OIL & GAS CORPORATION
|
|
|
|
|
By:
|
/s/
William W. Deneau
|
|
William
W. Deneau, Chairman, Director, and
Chief
Executive Officer
|
Pursuant
to the requirements of the Securities Act of 1933, this Form SB-2
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated:
Signature
|
|
Title
|
|
Date
|
/s/
William W. Deneau
William
W. Deneau
|
|
Chairman,
Chief Executive Officer, and Director
(Principal
Executive Officer)
|
|
October 31,
2007
|
|
|
|
|
|
|
|
|
|
|
/s/
Ronald E. Huff
|
|
President,
Chief Financial Officer and Director
(Principal
Financial Officer and Principal
|
|
October 31,
2007
|
|
|
|
|
|
|
|
|
|
|
/s/
Kevin D. Stulp
|
|
Director
|
|
October 31,
2007
|
|
|
|
|
|
|
|
|
|
|
/s/
Richard M. Deneau
|
|
Director
|
|
October 31,
2007
|
|
|
|
|
|
|
|
|
|
|
/s/
Gary J. Myles
|
|
Director
|
|
October 31,
2007
|
|
|
|
|
|
|
|
|
|
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/s/
Earl V. Young
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Director
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October 31,
2007
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/s/
Wayne G. Schaeffer
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Director
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October 31,
2007
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INDEX
OF EXHIBITS
EXHIBITS
3.1(1)
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Restated
Articles of Incorporation of Aurora Oil & Gas
Corporation.
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3.2
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By-Laws
of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form
8-K dated August 16, 2007, filed with the SEC on August 22, 2007
and
incorporated herein by reference.)
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5.1
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Opinion
of Fraser Trebilcock Davis & Dunlap, P.C.
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10.1
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Securities
Purchase Agreement between Cadence Resources Corporation and the
investors
signatory thereto, dated April 2, 2004 (filed as Exhibit 99.3 to
our
Current Report on Form 8-K filed with the SEC on April 5, 2004,
and
incorporated herein by reference.)
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10.2
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Securities
Purchase Agreement between Cadence Resources Corporation and the
investors
signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2
to our
Current Report on Form 8-K filed with the SEC on February 2, 2005,
and
incorporated herein by reference.)
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10.3(2)
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Asset
Purchase Agreement with Nor Am Energy, L.L.C., Provins Family,
L.L.C. and
O.I.L. Energy Corp. dated January 10, 2006.
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10.4
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Note
Purchase Agreement between Aurora Antrim North, L.L.C. et al. and
TCW
Asset Management Company, dated August 12, 2004 (filed as an Exhibit
to
our Form S-4 registration statement filed with the SEC on May 13,
2005,
and incorporated herein by reference.)
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10.5
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First
Amended and Restated Note Purchase Agreement between Aurora Antrim
North,
L.L.C. et al. and TCW Asset Management Company, dated December
8, 2005
(filed as an Exhibit to our Annual Report on Form 10-KSB for the
fiscal
year ended September 30, 2005 filed with the SEC on December 29,
2005 and
incorporated herein by reference.)
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10.6(2)
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First
Amendment to First Amended and Restated Note Purchase Agreement
between
Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company,
dated January 31, 2006.
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10.7
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Amended
and Restated Credit Agreement dated August 20, 2007, among Aurora
Oil
& Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent
and the Lenders Party hereto. (filed as an Exhibit 10.7 to our
Form 8-K
dated August 16, 2007, filed with the SEC on August 22, 2007 and
incorporated herein by reference.)
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10.8
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Intercreditor
and Subordination Agreement among, BNP Paribas, et al., TCW Asset
Management Company, and Aurora Antrim North, L.L.C., dated January
31,
2006 (replaced and filed as Exhibit 10.26 to our Form 8-K dated
August 16,
2007, filed with the SEC on August 22, 2007, and incorporated herein
by
reference).
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10.9(2)
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Promissory
Note from Aurora Energy, Ltd. to Northwestern Bank dated January
31,
2006.
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10.10(2)
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Confirmation
from BNP Paribas to Aurora Antrim North, L.L.C., dated February
22, 2006
relating to gas sale commitment.
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10.11
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2006
Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration
Statement filed with the SEC on May 15, 2006 and incorporated herein
by
reference.)
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10.12(1)
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Employment
Agreement with Ronald E. Huff dated June 19, 2006.
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10.13(1)
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Letter
Agreement with Bach Enterprises dated July 10, 2006. This Agreement
is
confidential and has been filed separately with the
SEC.
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10.14(1)
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First
Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
et al.
and BNP Paribas dated July 14, 2006.
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10.15(1)
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The
Denthorn Trust Commercial Guaranty of obligations to Northwestern
Bank.
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10.16(1)
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William
W. Deneau Commercial Guaranty of obligations to Northwestern
Bank.
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10.17(1)
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The
Denthorn Trust Commercial Pledge Agreement to Northwestern
Bank.
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10.18(3)
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LLC
Membership Interest Purchase Agreement dated October 6, 2006 relating
to
Kingsley Development Company, L.L.C.
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10.19(3)
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Asset
Purchase Agreement with Bach Enterprises, Inc., et al., dated October
6,
2006.
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10.20(3)
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Promissory
Note from Aurora Energy, Ltd. to Northwestern Bank dated October
15,
2006.
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10.21(3)
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Form
of indemnification letter agreement between Aurora Oil & Gas
Corporation and Rubicon Master Fund.
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10.22(3)
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Patricia
A. Deneau Trust Commercial Guaranty of obligations to Northwestern
Bank.
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10.23(3)
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Patricia
A. Deneau Trust Commercial Pledge Agreement to Northwestern
Bank.
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10.24
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Second
Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
et al.
and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24
to our
Annual Report on Form 10-KSB for the fiscal year ended December
31, 2006,
filed with the SEC on March 15, 2007 and incorporated herein by
reference.)
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10.25
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Third
Amendment to Credit Agreement between Aurora Antrim North, L.L.C.,
et al.
and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25
to our
Form 10-Q for the period ended June 30, 2007, filed with the SEC
on August
9, 2007 and incorporated herein by reference.)
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10.26
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Intercreditor
Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation,
the Borrower, BNP Paribas, as Administrative Agent and the Lenders
Party
hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination
Agreement
among, BNP Paribas, et al., TCW Asset Management Company, and Aurora
Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit
10.26
to our Form 8-K dated August 16, 2007, filed with the SEC on August
22,
2007 and incorporated herein by reference.)
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10.27
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Second
Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil
& Gas
Corporation, the Borrower, BNP Paribas, as Administrative Agent
and the
Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K
dated
August 16, 2007, filed with the SEC on August 22, 2007 and incorporated
herein by reference.)
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21
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Subsidiaries
of Aurora Oil & Gas Corporation.
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23.1
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Consent
of Ralph E. Davis Associates, Inc.
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23.2
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Consent
of Schlumberger Technology Corporation.
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23.3
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Consent
of Netherland, Sewell & Associates, Inc.
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23.4
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Consent
of Rachlin Cohen & Holtz LLP.
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23.5
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Awareness
of Weaver and Tidwell, L.L.P.
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23.6
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Consent
of Fraser Trebilcock Davis & Dunlap, P.C. (included in Exhibit
5.1).
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(1)
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Filed
as an exhibit to our Form 10-QSB for the period ended June 30,
2006, filed with the SEC on August 7, 2006, and incorporated herein
by reference.
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(2)
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Filed
as an exhibit to our Form 10-KSB for the fiscal year ended
December 31, 2005, filed with the SEC on March 31, 2006, and
incorporated herein by reference.
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(3)
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Filed
on October 27, 2006, with our Amendment No. 3 to Form SB-2 registration
statement filing, registration no. 333-137176, and incorporated herein
by
reference.
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