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0000950124-06-006431.txt : 20061103
0000950124-06-006431.hdr.sgml : 20061103
20061103165934
ACCESSION NUMBER: 0000950124-06-006431
CONFORMED SUBMISSION TYPE: POS AM
PUBLIC DOCUMENT COUNT: 23
FILED AS OF DATE: 20061103
DATE AS OF CHANGE: 20061103
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: Aurora Oil & Gas CORP
CENTRAL INDEX KEY: 0000933157
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 870306609
STATE OF INCORPORATION: UT
FISCAL YEAR END: 0930
FILING VALUES:
FORM TYPE: POS AM
SEC ACT: 1933 Act
SEC FILE NUMBER: 333-129695
FILM NUMBER: 061187569
BUSINESS ADDRESS:
STREET 1: 4110 COPPER RIDGE DRIVE
STREET 2: SUITE 100
CITY: TRAVERSE CITY
STATE: MI
ZIP: 49684
BUSINESS PHONE: (231) 941-0073
MAIL ADDRESS:
STREET 1: 4110 COPPER RIDGE DRIVE
STREET 2: SUITE 100
CITY: TRAVERSE CITY
STATE: MI
ZIP: 49684
FORMER COMPANY:
FORMER CONFORMED NAME: CADENCE RESOURCES CORP
DATE OF NAME CHANGE: 20010815
FORMER COMPANY:
FORMER CONFORMED NAME: ROYAL SILVER MINES INC
DATE OF NAME CHANGE: 19960223
FORMER COMPANY:
FORMER CONFORMED NAME: CONSOLIDATED ROYAL MINES INC
DATE OF NAME CHANGE: 19950908
POS AM
1
k09654p1posam.htm
POST-EFFECTIVE AMENDMENT NO.1 TO FORM SB-2
posam
As filed with the Securities and Exchange Commission on
November 3, 2006
Registration
No. 333-129695
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Post Effective Amendment
No. 1
to
Form SB-2
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
AURORA OIL & GAS
CORPORATION
(Name of Small Business Issuer
in its Charter)
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Utah
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1311
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87-0306609
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(State or other jurisdiction
of
incorporation or organization)
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(Primary Standard Industrial
Classification Code Number)
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(I.R.S. Employer
Identification No.)
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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,
President
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 NOVEMBER 3, 2006
21,860,000 Shares
Common Stock
Our common stock is traded on the American Stock Exchange under
the symbol AOG. On November 1, 2006, the last
sales price of our common stock as reported on the American
Stock Exchange was $3.01 per share.
Investing in our common stock
involves risks. See Risk Factors
beginning on page 10.
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 November , 2006.
TABLE OF
CONTENTS
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. Unless the
context otherwise requires, the information in this prospectus
assumes that the underwriters will not exercise their
over-allotment option.
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 E. 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 and the New Albany shale of Southern Indiana
and Western Kentucky. Our management and technical teams have an
extensive track record in the exploration and production
business as well as significant operating experience in shale
plays.
We own approximately 1,105,739 (621,290 net) leasehold
acres, of which 575,453 net leasehold acres are related to
shale where we have quantified approximately 2,665 net
potential drilling locations. 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. The following table sets forth our approximate leasehold
acreage and net potential drilling locations as of June 30,
2006:
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Net Potential
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Play/Trend
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Location
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Gross Acres
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Net Acres
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Drilling Locations(a)
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Antrim
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Michigan
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252,634
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125,993
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1,260
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New Albany
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Southern Indiana and Western
Kentucky
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784,816
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449,460
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1,405
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Other
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Various
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68,289
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45,837
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286
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Total
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1,105,739
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621,290
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2,951
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(a) |
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Net potential drilling locations are locations quantified by
management based on well spacing criteria for a particular
play/trend. For example, New Albany drilling locations are based
upon 320-acre spacing per well, Antrim drilling locations are
based upon 100-acre spacing per well and Other drilling
locations are based upon 160-acre spacing per well. |
As of December 31, 2005, our net proved reserves were
approximately 64 bcfe, of which 99% were natural gas reserves.
As of June 30, 2006, our estimated net proved reserves had
grown to 105 bcfe representing a 64% increase over our
December 31, 2005 net proved reserves. This increase
was attributable to our increased drilling activity and an
acquisition of oil and natural gas properties with proven
reserves of 24 bcfe completed in January 2006. During the first
six months of 2006, we invested $20.4 million in drilling
and related well activity and $40.1 million in net
leasehold interest and property acquisitions.
Unconventional shale plays tend to be characterized by high
drilling success rates. For the
18-month
period ending June 30, 2006, we invested $51.0 million
to drill and complete 225 (141.78 net) wells, of which 96%
were successful. In addition, we invested $51.3 million on
property and leasehold acquisitions. Average net daily
1
production increased from 609 mcfe/d in January 2005 to 7,392
mcfe/d in June 2006. The table below highlights our portfolio of
wells as of June 30, 2006.
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Gross
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Net
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Average Daily
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Average Daily
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Gross Wells
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Net Wells
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Production
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Production
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Gross Wells
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Net Wells
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Waiting
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Waiting
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(mcfe/d) in
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(mcfe/d) in
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Play /Trend
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Producing
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Producing
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Hook-Up
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Hook-Up
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June 2006
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June 2006
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Antrim
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325.00
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154.05
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59.00
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30.71
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15,015
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6,702
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New Albany
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8.00
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0.35
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19.00
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4.30
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2,001
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88
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Other
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45.00
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15.19
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8.00
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2.74
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1,434
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602
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Total
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378.00
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169.59
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86.00
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37.75
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18,450
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7,392
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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 575,453 net
leasehold acres in our shale areas, of which approximately 93%
were undeveloped as of June 30, 2006. As of that date, we
had approximately 2,665 net potential drilling locations on
this acreage. At our current planned drilling rate, this would
accommodate more than nine years of drilling activity.
Experienced management and technical
teams. Our four senior executive officers
average 23 years of experience in the natural gas
industry. In addition, we employ two senior geologists, one
staff geologist, one senior oil and gas petroleum engineer, one
drilling superintendent, one production supervisor and three
senior land professionals with an average of over 24 years
of oil and natural gas experience.
Operational control. As of
June 30, 2006, we operated approximately 38% of the wells
in which we have an interest, and we expect our 56% 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.
Financial flexibility. We seek to
maintain a conservative financial position and believe that our
operating cash flow and proceeds from a public offering that is
currently underway combined with additional debt financing will
provide us with the financial flexibility to pursue our planned
growth through exploration and development activities through
2007.
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 projects including approximately 575,453 net
leasehold acres on which we have approximately 2,665 net
potential drilling locations. In the Antrim shale play there
have been over 8,000 wells drilled since the inception of
the play with a historic success rate of approximately 95%. 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
2
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-oriented 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, 2006, we operated 38% of our wells. We believe
this percentage will continue to increase, and we plan to
operate approximately 44% of our wells drilled in 2007.
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
Challenges
Investing in our common stock involves risks. You should read
carefully the section of this prospectus entitled Risk
Factors beginning on page 10 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. For example, from January 1, 2006 to
October 19, 2006, natural gas prices quoted for the near
month NYMEX contract ranged from a low of $4.05 per mmbtu to a
high of $11.38 per mmbtu.
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. We will also require substantial amounts of
capital to develop our natural gas reserves.
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.
Summary
of Our Budgeted Exploration, Exploitation and Development
Activities
Our net capital expenditures for 2005 were $41.9 million,
including $30.6 million for drilling and related well work
and infrastructure, $15.6 million for leasehold interest
acquisitions, $8.3 million for property acquisitions, less
dispositions of $12.6 million. Our 2006 capital budget for
drilling and related well work and infrastructure is
approximately $51.2 million with participation in 221
(106 net) wells. Our 2006 capital budget for leasehold
interest and property acquisitions is approximately
$14.2 million and $39.3 million, respectively. Our
2007 capital budget for drilling and related well work and
infrastructure is estimated to be approximately
$105.6 million with participation in 410 (228 net)
wells. Our 2007 capital budget for leasehold interest and
property acquisitions is currently estimated to be approximately
$9 million and $1 million, respectively.
3
The following table summarizes information regarding our
drilling and related well work budget for our key exploration
and development areas for the 18 months commencing on
July 1, 2006 through December 31, 2007:
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July 2006 through December 2006
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January 2007 through December 2007
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Gross Wells
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Net Wells
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Net Capital
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Gross Wells
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Net Wells
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Net Capital
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Projected to
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Projected to
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Expenditure
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Projected to
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Projected to
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Expenditure
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Play / Trend
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be Drilled
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be Drilled
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Budget(a)
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be Drilled
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be Drilled
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Budget(a)
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Antrim
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124.0
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59.80
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$
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19,434,000
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285.0
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168.39
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$
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54,728,000
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New Albany
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19.0
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9.30
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7,901,000
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106.0
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43.10
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36,630,000
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Other
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6.0
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3.94
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3,358,000
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19.0
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16.75
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14,238,000
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Total
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149.0
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73.04
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$
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30,693,000
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410.0
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228.24
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$
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105,596,000
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Operated
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52.0
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46.54
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$
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18,395,000
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180.0
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156.94
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$
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62,279,000
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Non-operated
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97.0
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26.50
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12,298,000
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230.0
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71.30
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43,317,000
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Total
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149.0
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73.04
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$
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30,693,000
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410.0
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228.24
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$
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105,596,000
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(a) |
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Includes capital expenditures for drilling and related well work
infrastructure and does not include costs for leasehold interest
and property acquisitions. |
Our
Active Project Areas
The following is a summary of our activities in each of the two
plays/trends in which we have development projects.
Antrim shale. Our Antrim shale
properties are located in Michigan. 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.
Shale production is generally characterized by an initial
dewatering phase of six to 18 months followed by increasing
and then stabilized production prior to a natural decline. As of
June 30, 2006, we had 384 (185 net) wells in this
play/trend, of which 154 net wells are producing, and
31 net wells are awaiting hookup. Our Antrim wells are
drilled to a shale formation at depths ranging from 250 to
1,500 feet targeting reserves of 0.5 bcfe per well and,
based on our 2007 budget, cost approximately $325,000 to drill
and complete each well. As of June 30, 2006, we had a 48%
average working interest in the existing wells of our Antrim
project area, and our average working interest in total Antrim
leases was 50%. Key statistics for our position in this
play/trend include:
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|
125,993 total net acres, including 90,483 net undeveloped
acres, at June 30, 2006;
|
|
|
|
6,702 mcfe/d of estimated average net production for June 2006,
compared to 1,438 mcfe/d for June 2005;
|
|
|
|
325 (154 net) wells producing with another 59 (31 net)
wells awaiting hookup as of June 30, 2006; and
|
|
|
|
101 bcfe of estimated net proved reserves as of June 30,
2006.
|
New Albany shale. Our New Albany shale
properties are located in Southern Indiana and Western Kentucky.
Nearly all of our exploratory and developmental operations in
this play/trend are focused on unconventional shale plays. The
New Albany shale play is an emerging play with characteristics
that we believe will be similar to the Antrim shale play. As of
June 30, 2006, we had 27 (4.65 net) wells in this
play/trend, of which 8 (0.35 net) are producing, and 19 (4.30
net) are awaiting hookup. Our New Albany wells are drilled to a
shale formation at depths ranging from 500 to 3,000 feet
targeting reserves of 0.9 to 1.3 bcfe per well and, based on our
2007 budget, cost approximately $850,000 to drill and complete
each well. As of June 30, 2006, we had a 17% average
working interest in the wells of our New Albany project area,
and our average working interest in total New Albany leases was
57%. Key statistics for our position in this play/trend include:
|
|
|
|
|
449,460 total net acres, including 444,494 net undeveloped
acres, at June 30, 2006;
|
|
|
|
88 mcfe/d of estimated average net production for June 2006;
|
4
|
|
|
|
|
Eight (0.35 net) wells producing with another 19 (4.30 net)
wells awaiting hookup as of June 30, 2006;
|
|
|
|
Two bcfe of estimated net proved reserves at June 30,
2006; and
|
|
|
|
Our most recent Schlumberger reserve report included
38 well locations in the New Albany shale, of which nine
were classified as proved developed producing, four were
classified as proved developed non-producing, and 25 were
classified as proved undeveloped. The total gross reserves
assigned to these 38 well locations was 47.7 bcfe or
approximately 1.3 bcfe per well.
|
Other properties. We also have acreage
and leasehold interests outside our shale project areas. We are
currently in the process of evaluating this portfolio.
Recent
Developments
Letter of intent to acquire Antrim shale
project. On May 9, 2006, we entered into
a non-binding letter of intent to acquire Antrim shale producing
properties in Northern Michigan with estimated proved reserves
in excess of 10 bcfe. It is anticipated that this acquisition
will cost approximately $10.5 million, and closing is
subject to our due diligence and bank approval.
Bach acquisition. On October 6,
2006, we closed on the purchase all of the assets of Bach
Enterprises, Inc. and certain of its affiliates. Bach
Enterprises, Inc. is an oil and natural gas services company
whose services include building compressors,
CO2
removal, pipelining, and facility construction. We have been its
primary customer. Consideration paid in the form of stock and
cash is deemed to be non-material for financial reporting
purposes.
Disposition of DeSoto Parish assets. On
July 20, 2006, we sold oil and natural gas properties with
1.46 bcfe in estimated proven reserves located in DeSoto Parish,
Louisiana to BEUSA Energy, Inc. for $4.75 million.
Operations Update. We drilled or
participated in the drilling of 58 (19 net) wells in the third
quarter ending September 30, 2006 with a net success rate
of 92%. Thus, as of September 30, 2006 we have 425 (192
net) producing wells and 77 (27 net) wells awaiting hook-up. Our
estimated average daily production for September 2006 was 8,074
mcfe/d.
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.
5
The
Offering
|
|
|
Common stock offered by the selling security holders |
|
21,860,000 shares |
|
|
|
Use of proceeds |
|
We will not receive any of the proceeds form 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. |
|
|
|
Dividend policy |
|
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. |
|
AMEX market symbol |
|
AOG |
|
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 10 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:
|
|
|
|
|
assumes the underwriters do not exercise their over-allotment
option;
|
|
|
|
excludes 5,535,500 shares of common stock reserved for
issuance under our 2006 Stock Incentive Plan;
|
|
|
|
excludes 4,802,776 shares of our common stock issuable upon
exercise of outstanding options at a weighted average exercise
price of $2.16 per share; and
|
|
|
|
excludes 2,079,500 shares of our common stock issuable upon
exercise of outstanding warrants at a weighted average exercise
price of $1.71 per share.
|
6
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, 2005 and 2004 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, 2006 and 2005 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
Managements 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,(a)
|
|
|
Year Ended December 31,(a)
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
Statement of operations
data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
10,941,220
|
|
|
$
|
1,097,906
|
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
Other income
|
|
|
438,285
|
|
|
|
362,008
|
|
|
|
377,025
|
|
|
|
1,192,835
|
|
Interest income
|
|
|
244,214
|
|
|
|
165,910
|
|
|
|
243,013
|
|
|
|
47,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
11,623,719
|
|
|
|
1,625,824
|
|
|
|
7,363,482
|
|
|
|
2,200,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
3,242,713
|
|
|
|
1,126,396
|
|
|
|
3,435,507
|
|
|
|
2,057,333
|
|
Pipeline operating expenses
|
|
|
284,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and lease operating
|
|
|
3,411,051
|
|
|
|
652,957
|
|
|
|
2,047,028
|
|
|
|
614,338
|
|
Depletion, depreciation and
amortization
|
|
|
3,024,166
|
|
|
|
102,227
|
|
|
|
1,155,254
|
|
|
|
203,249
|
|
Interest
|
|
|
3,564,154
|
|
|
|
237,354
|
|
|
|
1,228,274
|
|
|
|
392,402
|
|
Taxes
|
|
|
29,361
|
|
|
|
237,697
|
|
|
|
29,651
|
|
|
|
75,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
13,555,646
|
|
|
|
2,356,631
|
|
|
|
7,895,714
|
|
|
|
3,342,322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before minority interest
|
|
|
(1,931,927
|
)
|
|
|
(730,807
|
)
|
|
|
(532,232
|
)
|
|
|
(1,141,798
|
)
|
Minority interest in (income) loss
of subsidiaries
|
|
|
(17,919
|
)
|
|
|
(6,190
|
)
|
|
|
15,960
|
|
|
|
38,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(1,949,846
|
)
|
|
|
(736,997
|
)
|
|
|
(516,272
|
)
|
|
|
(1,103,711
|
)
|
Less dividends on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(30,268
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common
shareholders
|
|
$
|
(1,949,846
|
)
|
|
$
|
(736,997
|
)
|
|
$
|
(516,272
|
)
|
|
$
|
(1,133,979
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common
share basic and diluted
|
|
$
|
(0.03
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding basic and diluted
|
|
|
76,011,115
|
|
|
|
36,157,838
|
|
|
|
40,622,000
|
|
|
|
23,636,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided (used) by operating
activities
|
|
$
|
2,636,906
|
|
|
$
|
(459,971
|
)
|
|
$
|
(411,196
|
)
|
|
$
|
218,441
|
|
Cash used by investing activities
|
|
|
(32,845,786
|
)
|
|
|
(7,946,216
|
)
|
|
|
(41,862,869
|
)
|
|
|
(8,716,784
|
)
|
Cash provided by financing
activities
|
|
|
21,823,195
|
|
|
|
16,743,071
|
|
|
|
49,075,121
|
|
|
|
12,632,173
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30,
|
|
|
As of December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Balance sheet data
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,594,953
|
|
|
$
|
11,980,638
|
|
|
$
|
5,179,582
|
|
Other current assets
|
|
|
11,158,265
|
|
|
|
7,274,869
|
|
|
|
2,636,114
|
|
Oil and gas properties, net (using
full cost accounting)
|
|
|
124,298,203
|
|
|
|
68,960,754
|
|
|
|
14,967,457
|
|
Other property and equipment, net
|
|
|
8,414,997
|
|
|
|
|
|
|
|
|
|
Other assets
|
|
|
22,069,765
|
|
|
|
28,605,884
|
|
|
|
662,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
169,536,183
|
|
|
$
|
116,822,145
|
|
|
$
|
23,445,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
10,826,542
|
|
|
$
|
13,832,112
|
|
|
$
|
6,109,156
|
|
Long-term debt, net of current
maturities
|
|
|
83,764,824
|
|
|
|
42,794,862
|
|
|
|
11,090,369
|
|
Deposit on sale of oil and gas
properties
|
|
|
|
|
|
|
3,509,319
|
|
|
|
|
|
Redeemable convertible preferred
stock
|
|
|
19,924
|
|
|
|
59,925
|
|
|
|
|
|
Shareholders equity
|
|
|
74,924,893
|
|
|
|
56,625,927
|
|
|
|
6,246,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
shareholders equity
|
|
$
|
169,536,183
|
|
|
$
|
116,822,145
|
|
|
$
|
23,445,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 condensed consolidated financial
statements for the six months ended June 30, 2005, and
years ended December 31, 2005 and 2004, 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,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls)
|
|
|
11,888
|
|
|
|
10,628
|
|
|
|
4,798
|
|
Natural gas (mcf)
|
|
|
1,224,551
|
|
|
|
687,271
|
|
|
|
151,241
|
|
Natural gas equivalent (mcfe)
|
|
|
1,295,879
|
|
|
|
751,039
|
|
|
|
180,029
|
|
Oil and natural gas
sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
741,110
|
|
|
$
|
558,455
|
|
|
$
|
226,599
|
|
Natural gas sales
|
|
|
10,200,110
|
|
|
|
6,184,989
|
|
|
|
733,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,941,220
|
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price (including
realized gains or losses from hedging)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($ per bbl)
|
|
$
|
62.34
|
|
|
$
|
52.54
|
|
|
$
|
47.23
|
|
Natural gas ($ per mcf)
|
|
|
8.33
|
|
|
|
9.00
|
|
|
|
4.85
|
|
Natural gas equivalent ($ per
mcfe)
|
|
|
8.44
|
|
|
|
8.98
|
|
|
|
5.33
|
|
Average production
cost
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas equivalent ($ per
mcfe)
|
|
$
|
2.63
|
|
|
$
|
2.73
|
|
|
$
|
3.41
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30,
|
|
|
As of December 31,
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
Estimated proved
reserves(a)(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (mbbls)
|
|
|
91
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf)
|
|
|
105,288
|
|
|
|
63,321
|
|
|
|
34,949
|
|
|
|
|
|
Natural gas equivalent (mmcfe)
|
|
|
105,834
|
|
|
|
63,915
|
|
|
|
34,949
|
|
|
|
|
|
PV-10(c)
|
|
$
|
136,038,320
|
|
|
$
|
199,507,440
|
|
|
$
|
47,910,500
|
|
|
|
|
|
Standardized measure(d)
|
|
$
|
116,722,099
|
|
|
$
|
152,868,240
|
|
|
$
|
32,159,710
|
|
|
|
|
|
|
|
|
(a) |
|
The information presented for New Albany and Antrim reserves at
June 30, 2006 is based on reserve reports prepared by
Schlumberger. Consistent with Schlumbergers standard
engineering practices, these reports and such reserves excluded
the impact of the following financial hedges: (i) 5,000
mmbtu/day at a price of $8.59/mmbtu through March 2007 and
(ii) 5,000 mmbtu/day at a price of $9.00/mmbtu from April
2007 through December 2008. |
|
|
|
(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) |
|
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 June 30, 2006, and December 31, 2005 and 2004,
respectively. 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, and at
December 31, 2004, without escalation, using $6.20 per
mmbtu, in each case adjusted by lease for transportation fees
and regional price differentials. The estimated future
production is priced at June 30, 2006, without escalation,
using $69.32 per bbl and $5.69 per mmbtu, in each case
adjusted by lease for transportation fees and regional price
differentials.
PV-10 is a
non-GAAP financial measure because it excludes income tax
effects. Management believes that the presentation of the
non-GAAP financial measure of
PV-10
provides useful information to investors because it is widely
used by professional analysts and sophisticated investors in
evaluating oil and natural gas companies.
PV-10 is not
a measure of financial or operating performance under GAAP.
PV-10 should
not be considered as an alternative to the standardized measure
as defined under GAAP. We have included a reconciliation of
PV-10 to the
most directly comparable GAAP measure standardized
measure of discounted future net cash flows in the
following table: |
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|
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|
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As of June 30,
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As of December 31,
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2006
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2005
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2004
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Standardized measure of discounted
future net cash flows
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$
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116,722,099
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$
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152,868,240
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$
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32,159,710
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Add: Present value of future
income tax discounted at 10%
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19,316,221
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46,639,200
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15,750,790
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PV-10
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$
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136,038,320
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$
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199,507,440
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$
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47,910,500
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(d) |
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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, the
June 30, 2006 information excludes the impact of our
hedges. If the impact of our hedges were included, the
standardized measure for June 30, 2006 would have been
increased by $8,960,351 to $125,682,450. |
9
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 to October 19, 2006, natural gas
prices quoted for the near month NYMEX contract ranged from a
low of $4.05 per mmbtu to a high of $11.38 per mmbtu. The prices
for natural gas are subject to a variety of factors beyond our
control, including:
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the level of consumer product demand;
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weather conditions;
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domestic and foreign governmental regulations;
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the price and availability of alternative fuels;
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political conditions in oil and natural gas producing regions;
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the domestic and foreign supply of oil and natural gas;
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speculative trading and other market uncertainty; and
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worldwide economic conditions.
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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, in
addition to the proceeds from the public offering that is
currently underway and the cash generated from our operations,
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.
10
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 this region
caused by weather conditions, governmental regulation, lack of
field infrastructure, or other events which impact this area. 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, 2006, we had approximately 2,665 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,
2005 and 2004, and the six months ended June 30, 2006. We
expect to report a net loss in the third quarter of 2006 and
also expect to show a net reduction in working capital and
shareholder equity in the third quarter of 2006. 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, 2006, we operated
38% 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:
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the number of wells to be drilled;
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the location of wells to be drilled;
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the timing of drilling and re-completing of wells;
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the field company hired to drill and maintain the wells;
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the timing and amounts of production;
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the approval of other participants in drilling wells;
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development and operating costs;
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capital calls on working interest owners; and
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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.
11
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, 2006, we had acquired
approximately 1,105,739 (621,290 net) acres with
105 bcfe 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, we recently closed on the acquisition of all of the
assets of Bach Enterprises, Inc. (or Bach) and certain of its
affiliates. Bach Enterprises, Inc. 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 services 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 in Antrim shale projects as
of June 30, 2006, 57% are classified as proved developed
producing, 13% are classified as proved developed non-producing,
and 30% 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:
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Reserves characterized as proved developed producing reserves
may be producing predominantly water and generate little or no
production revenue;
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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;
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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
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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 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 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
40 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, 2006, approximately 4%
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
13
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 recently 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 is
completed and permits are issued. The DEQ has also recently
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.
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.
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
14
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, including Louisiana and Texas, 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.
15
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 October 13, 2006, our outstanding debt includes a
senior credit facility with a current approved borrowing base of
$50 million, all 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
$3.6 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
16
and issue managements 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 managements 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 managements 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 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:
|
|
|
|
|
discharge permits for drilling operations;
|
|
|
|
drilling bonds;
|
|
|
|
reports concerning operations;
|
|
|
|
spacing of wells;
|
|
|
|
unitization and pooling of properties;
|
|
|
|
environmental protection; and
|
|
|
|
taxation.
|
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
17
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.
Since January 1, 2006, our stock has traded as high as
$7.44 per share and as low as $2.60 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.
|
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, 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 14% of our outstanding
shares prior to the close of this offering, 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 10.8 million shares of our common stock held
by such shareholders was subject to these proxies at
June 30, 2006. These provisions will limit our other
shareholders ability to influence the outcome of
shareholder votes 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 through
October 31, 2008.
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.
18
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 and purchasers of common
stock offered in this prospectus. 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. As of October 10, 2006,
83,462,966 shares of common stock were outstanding. We have
currently reserved 8,000,000 shares of common stock for
future issuance to employees as restricted stock or stock option
awards pursuant to our 2006 Stock Incentive Plan, of which stock
grants and options to purchase a total of 2,464,500 shares
have already been awarded, and 5,535,500 shares remain
available for future awards. We also have other warrants and
options outstanding which may be exercised for an additional
4,417,776 aggregate shares of our common stock. 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. 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 other shelf registration statements that are
currently effective, which together with this registration
statement have registered almost 40 million shares of
common stock for resale. We are in the process of selling up to
19,600,000 (16,000,000 primary; 3,600,000 for underwriters
over allotment option) shares in a fully underwritten
public offering. 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, the issuance of
additional shares in the public offering, 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.
After the completion of the public offering, we will have
approximately 99.5 million shares of common stock issued
and outstanding, including approximately 12.7 million
shares of our common stock held or controlled by our executive
officers and directors. Of those 12.7 million shares,
8.6 million are subject to lock-up agreements through
October 31, 2008, 0.7 million are eligible for resale
on an S-8
registration statement, and the balance are or will be eligible
for sale under Rule 144 after the expiration of the
90-day
lock-up period that is applicable to our executive officers,
directors and certain of our shareholders following the
completion of this offering. In addition, the remaining
3.75 million shares retained by Rubicon Master Fund
after closing of the public offering will be subject to lock-up
for a period of 90 days after the date of the public
offering prospectus. Additionally, we have filed an
S-8
registration statement with the Securities and Exchange
Commission (SEC) providing for the registration of
9,589,496 shares of our common stock issued or reserved for
issuance under our employee plans, all of which are eligible for
sale without further registration under the Securities Act.
We do
not intend to pay, and are prohibited from paying, any dividends
on our common stock.
We anticipate that we will retain all future earnings and other
cash resources for the future operation and development of our
business. Accordingly, we do not intend to declare or pay any
cash dividends on our common stock in the foreseeable future.
Payment of any future dividends will be at the discretion of our
board of directors after taking into account many factors,
including our operating results, financial condition, current
and anticipated cash needs and plans for expansion. In addition,
the declaration and payment of any dividends on our common stock
is prohibited by the terms of certain of our credit facilities
so long they are in effect. Our senior credit facility
terminates on the earlier of January 31, 2010 or
91 days prior to the maturity of our mezzanine credit
facility; however, prior to that time we may enter into a new
credit facility or other contractual arrangement that further
restricts our ability to pay dividends.
19
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements within the
meaning of Section 27A of 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 crude
oil and natural gas;
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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 under Risk Factors.
|
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 prospectus.
20
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.
21
CAPITALIZATION
The following table sets forth our cash and cash equivalents and
capitalization as of June 30, 2006:
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|
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on an actual basis; and
|
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|
on an as-adjusted basis to reflect our receipt of the estimated
net proceeds from the sale of 16 million shares in a public
offering that is currently underway, based on the public
offering price of $3.00 per share, after deducting the
underwriting discount and estimated offering expenses.
|
You should read this table in conjunction with the
Managements Discussion and Analysis of Financial
Condition and Results of Operations and our condensed
consolidated financial statements and related notes, which are
provided elsewhere in this prospectus.
|
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|
|
|
|
|
|
|
|
|
As of June 30, 2006
|
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|
|
Actual
|
|
|
As Adjusted
|
|
|
|
(Unaudited)
|
|
|
|
(Dollars in thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
3,595
|
|
|
$
|
8,134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt (including current
maturities)
|
|
$
|
82,850
|
|
|
$
|
42,850
|
|
|
|
|
|
|
|
|
|
|
Redeemable convertible preferred
stock
|
|
|
20
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
Shareholders Equity:
|
|
|
|
|
|
|
|
|
Common stock, $.01 par value,
250,000,000 authorized; 81,965,017 issued and outstanding
actual; 97,965,017 issued and outstanding as adjusted
|
|
|
820
|
|
|
|
980
|
|
Additional paid-in capital
|
|
|
77,757
|
|
|
|
122,136
|
|
Accumulated other comprehensive
income
|
|
|
962
|
|
|
|
962
|
|
Accumulated deficit
|
|
|
(4,614
|
)
|
|
|
(4,614
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
74,925
|
|
|
|
119,464
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
157,795
|
|
|
$
|
162,334
|
|
|
|
|
|
|
|
|
|
|
22
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 four quarters of 2006. 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.
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High Bid/
|
|
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Low Bid/
|
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Quarter Ended
|
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Sales Price
|
|
|
Sales Price
|
|
|
March 31, 2004
|
|
$
|
4.70
|
|
|
$
|
3.00
|
|
June 30, 2004
|
|
$
|
3.80
|
|
|
$
|
1.70
|
|
September 30, 2004
|
|
$
|
2.30
|
|
|
$
|
0.85
|
|
December 31, 2004
|
|
$
|
1.65
|
|
|
$
|
0.98
|
|
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 (through
November 1, 2006)
|
|
$
|
3.32
|
|
|
$
|
2.60
|
|
On November 1, 2006, the last reported per share sale price
of our common stock on AMEX was $3.01 and there were
83,587,966 shares of our common stock outstanding and 587
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.
23
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, 2005 and 2004 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, 2006 and 2005 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, 2006 are not necessarily
indicative of results that may be expected for the entire year
2006 or any future periods. You should review this information
together with Managements 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
|
|
|
Year Ended
|
|
|
|
June 30,(a)
|
|
|
December 31,(a)
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
Statement of operations
data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
10,941,220
|
|
|
$
|
1,097,906
|
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
Other income
|
|
|
438,285
|
|
|
|
362,008
|
|
|
|
377,025
|
|
|
|
1,192,835
|
|
Interest income
|
|
|
244,214
|
|
|
|
165,910
|
|
|
|
243,013
|
|
|
|
47,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
11,623,719
|
|
|
|
1,625,824
|
|
|
|
7,363,482
|
|
|
|
2,200,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
3,242,713
|
|
|
|
1,126,396
|
|
|
|
3,435,507
|
|
|
|
2,057,333
|
|
Pipeline operating expenses
|
|
|
284,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and lease operating
|
|
|
3,411,051
|
|
|
|
652,957
|
|
|
|
2,047,028
|
|
|
|
614,338
|
|
Depletion, depreciation and
amortization
|
|
|
3,024,166
|
|
|
|
102,227
|
|
|
|
1,155,254
|
|
|
|
203,249
|
|
Interest
|
|
|
3,564,154
|
|
|
|
237,354
|
|
|
|
1,228,274
|
|
|
|
392,402
|
|
Taxes
|
|
|
29,361
|
|
|
|
237,697
|
|
|
|
29,651
|
|
|
|
75,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
13,555,646
|
|
|
|
2,356,631
|
|
|
|
7,895,714
|
|
|
|
3,342,322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before minority interest
|
|
|
(1,931,927
|
)
|
|
|
(730,807
|
)
|
|
|
(532,232
|
)
|
|
|
(1,141,798
|
)
|
Minority interest in (income) loss
of subsidiaries
|
|
|
(17,919
|
)
|
|
|
(6,190
|
)
|
|
|
15,960
|
|
|
|
38,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(1,949,846
|
)
|
|
|
(736,997
|
)
|
|
|
(516,272
|
)
|
|
|
(1,103,711
|
)
|
Less dividends on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(30,268
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common
shareholders
|
|
$
|
(1,949,846
|
)
|
|
$
|
(736,997
|
)
|
|
$
|
(516,272
|
)
|
|
$
|
(1,133,979
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common
share basic and diluted
|
|
$
|
(0.03
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.05
|
)
|
Weighted average common shares
outstanding basic and diluted
|
|
|
76,011,115
|
|
|
|
36,157,838
|
|
|
|
40,622,000
|
|
|
|
23,636,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided (used) by operating
activities
|
|
$
|
2,636,906
|
|
|
$
|
(459,971
|
)
|
|
$
|
(411,196
|
)
|
|
$
|
218,441
|
|
Cash used by investing activities
|
|
|
(32,845,786
|
)
|
|
|
(7,946,216
|
)
|
|
|
(41,862,869
|
)
|
|
|
(8,716,784
|
)
|
Cash provided by financing
activities
|
|
|
21,823,195
|
|
|
|
16,743,071
|
|
|
|
49,075,121
|
|
|
|
12,632,173
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30,
|
|
|
As of December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Balance sheet data
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,594,953
|
|
|
$
|
11,980,638
|
|
|
$
|
5,179,582
|
|
Other current assets
|
|
|
11,158,265
|
|
|
|
7,274,869
|
|
|
|
2,636,114
|
|
Oil and gas properties, net (using
full cost accounting)
|
|
|
124,298,203
|
|
|
|
68,960,754
|
|
|
|
14,967,457
|
|
Other property and equipment, net
|
|
|
8,414,997
|
|
|
|
|
|
|
|
|
|
Other assets
|
|
|
22,069,765
|
|
|
|
28,605,884
|
|
|
|
662,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
169,536,183
|
|
|
$
|
116,822,145
|
|
|
$
|
23,445,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
10,826,542
|
|
|
$
|
13,832,112
|
|
|
$
|
6,109,156
|
|
Long-term debt, net of current
maturities
|
|
|
83,764,824
|
|
|
|
42,794,862
|
|
|
|
11,090,369
|
|
Deposit on sale of oil and gas
properties
|
|
|
|
|
|
|
3,509,319
|
|
|
|
|
|
Redeemable convertible preferred
stock
|
|
|
19,924
|
|
|
|
59,925
|
|
|
|
|
|
Shareholders equity
|
|
|
74,924,893
|
|
|
|
56,625,927
|
|
|
|
6,246,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
shareholders equity
|
|
$
|
169,536,183
|
|
|
$
|
116,822,145
|
|
|
$
|
23,445,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 condensed consolidated
financial statements for the six months ended June 30,
2005, and years ended December 31, 2005 and 2004, and
related notes have been retroactively adjusted to give effect to
the reverse merger on October 31, 2005. |
25
MANAGEMENTS
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 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.
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 businesses have been
included in the consolidated financial statements from the date
of acquisition. 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 natural gas reserves that are economically recoverable
based on prevailing prices of natural gas. 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
oil and natural gas prices could have a material adverse effect
on our financial position, results of operations, cash flows,
access to capital and on the quantities of oil and natural gas
that can be economically produced.
Recent
Highlights
For the first six months of 2006, we continued to execute our
strategy of focusing on lower risk shale development projects.
As of June 30, 2006, we held approximately 1,105,739
(621,290 net) leasehold acres, which represent a 71%
increase over our December 31, 2005 net acreage
position. Of the 290,274 (257,200 net) leasehold acres
acquired, 47,830 net acres were in the Antrim shale play
and 177,568 net acres were in the New Albany shale play.
With regard to our strategy to generate growth through drilling,
we drilled or participated in 72 (33 net) wells for the
first six months of 2006. As of June 30, 2006, we had 378
(170 net) producing wells and 86 (38 net) wells
awaiting hook-up. We also continued our strategy to have greater
control over our projects by operating 175 (151 net) wells,
operating 38% of our gross wells. We also supplemented our
drilling strategy with the Hudson properties acquisition. This
acquisition increased our proved reserves by approximately 24
bcfe in the Antrim shale play.
26
We began 2006 with estimated proved reserves of 64 bcfe and at
June 30, 2006 had 105 bcfe, an increase of 41 bcfe, or
64%. Of the 105 bcfe in estimated proved reserves, 101 bcfe was
from the Antrim shale play and two bcfe was from the New Albany
shale play.
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 financial swap contract for 5,000 mmbtu per day at a
fixed price of $8.59 per mmbtu covering the period of April
2006 through March 2007 and another financial swap contract on
July 14, 2006 for 5,000 mmbtu per day at a fixed price
of $9.00 per mmbtu for the period from April 2007 through
December 2008.
To further our growth, we entered into a senior secured credit
facility on January 31, 2006 with an initial borrowing base
of $40 million. Effective July 14, 2006, the borrowing
base was increased to $50 million. As proved reserves are
added, the borrowing base may increase to $100 million with
consent of our mezzanine lender.
From late December 2005 through early February 2006, we reduced
the exercise price of certain outstanding options and warrants
in order to encourage the early exercise of these securities. 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
20,315,422 shares were issued during the six months ended
June 30, 2006 representing 15,565,457 shares issued
for cash proceeds of $18,144,449 and 4,749,965 shares
issued pursuant to cashless exercises of the applicable warrants
or options. In December 2005, an additional
2,160,000 shares were issued for cash proceeds of
$2,916,000.
RESULTS
OF OPERATIONS
Operating
Statistics
The following table sets forth certain key operating statistics
for the six months ended June 30, 2006 and 2005 and for the
years ended December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Year Ended
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
Total net acreage held
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
125,993
|
|
|
|
59,428
|
|
|
|
78,163
|
|
|
|
55,538
|
|
New Albany
|
|
|
449,460
|
|
|
|
139,431
|
|
|
|
271,891
|
|
|
|
220,984
|
|
Other
|
|
|
45,837
|
|
|
|
3,520
|
|
|
|
14,036
|
|
|
|
2,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
621,290
|
|
|
|
202,379
|
|
|
|
364,090
|
|
|
|
279,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net wells drilled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
27
|
|
|
|
19
|
|
|
|
105
|
|
|
|
26
|
|
New Albany
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
4
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
33
|
|
|
|
19
|
|
|
|
106
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
170
|
|
|
|
47
|
|
|
|
123
|
|
|
|
25
|
|
Waiting hookup
|
|
|
37
|
|
|
|
20
|
|
|
|
60
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
207
|
|
|
|
67
|
|
|
|
183
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
1,224,551
|
|
|
|
147,899
|
|
|
|
687,271
|
|
|
|
151,241
|
|
Crude oil (bbls)
|
|
|
11,888
|
|
|
|
2,764
|
|
|
|
10,628
|
|
|
|
4,798
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Year Ended
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
Average daily production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
6,765
|
|
|
|
817
|
|
|
|
1,883
|
|
|
|
414
|
|
Crude oil (bbls)
|
|
|
66
|
|
|
|
15
|
|
|
|
29
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices (including
realized gains or losses from hedging)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($ per mcf)
|
|
$
|
8.33
|
|
|
$
|
6.55
|
|
|
$
|
9.00
|
|
|
$
|
4.85
|
|
Crude oil ($ per bbl)
|
|
$
|
62.34
|
|
|
$
|
46.60
|
|
|
$
|
52.54
|
|
|
$
|
47.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
10,200,110
|
|
|
$
|
968,738
|
|
|
$
|
6,184,989
|
|
|
$
|
733,412
|
|
Crude oil
|
|
|
741,110
|
|
|
|
129,168
|
|
|
|
558,455
|
|
|
|
226,599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,941,220
|
|
|
$
|
1,097,906
|
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expense per mcfe
|
|
$
|
2.63
|
|
|
$
|
3.97
|
|
|
$
|
2.73
|
|
|
$
|
3.41
|
|
Number of employees
|
|
|
53
|
|
|
|
32
|
|
|
|
36
|
|
|
|
19
|
|
RESULTS
OF OPERATIONS
Six
Months Ended June 30, 2006 (Current Period)
compared with Six Months Ended June 30, 2005 (Prior
Period)
General. For the Current Period, the
Company had a net loss of $1,949,846 on total revenues of
$11,623,719. This compares to a net loss of $736,997 on total
revenue of $1,625,824 during the Prior Period. The $9,997,895
increase in revenue represents the results of the initial steps
that we are taking as an early stage developer of properties. We
had 170 net wells producing at the end of the Current
Period as compared to 47 net wells producing at the end of
the Prior Period.
Oil and gas sales. During the Current
Period, oil and natural gas sales were $10,941,220 compared to
$1,097,906 in the Prior Period. We produced 1,295,879 mcfe
at a weighted average price of $8.44 compared to
164,483 mcfe at a weighted average price of $6.67. 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. Production from the Antrim shale play represented
approximately 81% of our oil and natural gas revenue for the
Current Period.
At the end of the Current Period, we had 170 net wells
producing compared to 47 net wells at the end of the Prior
Period. In addition, we placed 47 net wells into production
during the Current Period. The favorable average price variance
included $792,350 of realized gains from the natural gas hedging
instrument entered into during the Current Period.
Other income. Other income (exclusive
of equity in loss of unconsolidated subsidiary) for the Current
Period primarily includes pipeline revenue from the Hudson
acquisition while the Prior Period includes prospect fees
generated from joint ventures. During the Current Period, other
income was $596,999 compared to $349,611 in the Prior Period.
This increase was primarily due to the Hudson properties
acquisition that includes a revenue generating pipeline business.
General and administrative
expenses. Our general and administrative
expenses include officer and employee compensation, travel,
audit, tax and legal fees, office supplies, utilities,
insurance, other consulting fees and office related expenses.
Effective January 1, 2006, general and administrative
expenses excludes certain internal payroll and benefit costs
that can be directly identified with our acquisition,
exploration and development activities. For the Current Period,
$992,372 of payroll and benefit costs were capitalized to oil
and natural gas properties.
28
The $2,116,317 increase in general and administrative expenses
for the Current Period was the result of our growth strategy.
This growth has resulted in substantial increases in employees
and related costs, legal and accounting services related to SEC
filings as well as increased consulting services. The Prior
Period expenses reflect Aurora as a private entity whereas the
Current Period represents the costs associated with becoming a
public entity, execution of our growth strategy, and on-going
costs of being a public company.
Production and lease operating
expenses. Our production and lease operating
expenses include services related to producing oil and natural
gas, such as severance taxes, post production costs, including
marketing and transportation, and expenses to operate the wells
and equipment on producing leases.
Production and lease operating expenses were $3,411,051 for the
Current Period compared to $652,957 for the Prior Period. On a
unit of production basis, production expenses were
$2.63 per mcfe in the Current Period compared to $3.97 per
mcfe for the Prior Period. The unit cost decrease in the Current
Period was primarily attributable to the fixed costs of central
processing facilities and water disposal facilities being spread
over more production as new development wells come on-line. We
also recognized transportation expense reduction of $225,113 due
to the Hudson pipeline acquisition.
The following table sets forth the major components of
production and operating expenses for the Current Period and
Prior Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30, 2006
|
|
|
June 30, 2005
|
|
Expense Category
|
|
Per mcfe
|
|
|
Amount
|
|
|
Per mcfe
|
|
|
Amount
|
|
|
Severance taxes
|
|
$
|
.34
|
|
|
$
|
445,825
|
|
|
$
|
.30
|
|
|
$
|
49,079
|
|
Post-production expenses
|
|
|
.58
|
|
|
|
743,309
|
|
|
|
1.20
|
|
|
|
197,636
|
|
Lease operating expenses
|
|
|
1.71
|
|
|
|
2,221,917
|
|
|
|
2.47
|
|
|
|
406,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2.63
|
|
|
$
|
3,411,051
|
|
|
$
|
3.97
|
|
|
$
|
652,957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
(DD&A). DD&A was
$3,024,166 and $102,227 during the Current Period and the Prior
Period, respectively. DD&A of oil and natural gas properties
was $1,976,378 during the Current Period. This increase reflects
the increase to the full cost pool of approximately
$76.8 million. This represents wells being placed into
production with costs being transferred from unproven properties
to proven properties. In addition, there was an increase in
depletion rates associated with the producing assets from the
Cadence merger, since these assets have reserves with shorter
lives than the Michigan Antrim shale.
Other depreciation and amortization was $1,047,788 during the
Current Period of which $767,500 represented amortization of the
intangible assets recognized in connection with the Cadence
merger, $156,360 represented depreciation related to the Hudson
pipeline acquisition, $34,005 represented amortization of asset
retirement obligations and $89,923 represented depreciation of
other property and equipment.
Interest expense. Interest expense was
$3,564,154 in the Current Period compared to $237,354 in the
Prior Period. 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. The amount of capitalized interest has decreased
significantly from the Prior Period as our properties are
transferred from undeveloped to producing or as financing is
used for proven acquisition. As of June 30, 2006, we had
borrowed $82.8 million compared to $20 million as of
June 30, 2005.
Taxes. Tax expense was $29,361 in the
Current Period compared to $237,697 in the Prior Period. This
decrease resulted from the reversal of an accrual related to the
January 2005 sale of the 95% working interest to El Paso
Corporation in certain New Albany shale acreage.
Year
Ended December 31, 2005 compared with Year Ended
December 31, 2004
Revenues. We generate revenue primarily
from the following sources: the sale of oil and natural gas;
providing lease project management services; providing
administrative overhead services for certain producing
29
properties; and the sale of certain leasehold projects. A
comparative summary of the composition of our revenue for the
years ended 2005 and 2004 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
Amount
|
|
|
% of Total
|
|
|
Amount
|
|
|
% of Total
|
|
|
Oil and natural gas sales
|
|
$
|
6,743,444
|
|
|
|
92
|
%
|
|
$
|
960,011
|
|
|
|
44
|
%
|
Other income
|
|
|
452,621
|
|
|
|
6
|
%
|
|
|
1,192,835
|
|
|
|
54
|
%
|
Equity in loss of subsidiary
|
|
|
(75,596
|
)
|
|
|
(1
|
)%
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
243,013
|
|
|
|
3
|
%
|
|
|
47,678
|
|
|
|
2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
7,363,482
|
|
|
|
100
|
%
|
|
$
|
2,200,524
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2005, total revenues were $5,162,958 higher than the
total revenues for 2004, a 235% increase. Production revenues
for 2005 increased by $5,783,433 or a 602% increase from 2004.
This increase was due to increased drilling activity in 2005 and
late 2004, which resulted in an increased number of wells
generating natural gas production revenue. Other income for 2005
decreased $740,214, a 62% decrease from 2004. This decrease was
due largely to the reduction in management fees we received. The
decrease in management fees is due to our shift from leasehold
acquisitions through various joint ventures to the development
of leased properties to produce natural gas. The increase in
interest income of $195,335 was earned on the funds raised in
the private equity transaction.
In 2005, we reported net revenues of $65,643 from investments in
the Hudson Pipeline and Processing Company, LLC and net loss of
$(141,239) in GeoPetra Partners, LLC for a combined net loss
from equity interest in subsidiaries of $(75,596). Other
material sources of income from operations include: management
fees of $347,857 and $883,687 and operator revenues of $94,315
and $309,148 for December 31, 2005 and 2004, respectively.
Natural gas, oil and related product
sales. Our oil and natural gas product sales
for the years ended December 31, 2005 and December 31,
2004 were generated primarily from production from Michigan oil
and natural gas properties. Our production revenue was generated
from the sale of 687,271 net mcf of natural gas at an
average price of $9.00 per mcf from wells in the Antrim and
10,628 barrels of oil at an average price of
$52.54 per bbl from non-operated working interests in wells
located in Michigan, Texas, Kansas and New Mexico.
A summary of oil and natural gas revenue sources by play/trend
for the years ended December 31, 2005 and 2004 is as
follows:
|
|
|
|
|
|
|
|
|
Play/Trend
|
|
2005
|
|
|
2004
|
|
|
Antrim
|
|
$
|
6,099,274
|
|
|
$
|
960,011
|
|
New Albany
|
|
|
80,166
|
|
|
|
|
|
Other
|
|
|
564,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2005, nearly 64% of our
revenues were generated from the Hudson 34, Hudson SW and Hudson
NE units of the Hudson project, which went on-line in December
2004, February 2005 and late April 2005, respectively. The
remaining production revenue generated from natural gas sales
came from our interests in the Beyer, Black Bean, Paxton Quarry,
Treasure Island, Eastern Group, and Church Lake Field projects.
There were also minor overriding royalties and working interest
revenues received from certain New Albany shale projects.
Other revenues. In addition to oil and
natural gas production revenue, we also generate revenue from
two other sources: management fees from the administration of
certain lease projects and overhead fees charged for the
administration of certain producing properties.
Expenses. Our expenses break into five
general categories: General and Administrative; Production and
Lease Operating; Depletion, Depreciation and Amortization;
Interest; and Taxes.
30
Our general and administrative expenses include officer and
employee compensation, rent, travel, audit, tax and legal fees,
office supplies, utilities, insurance, other consulting fees and
office related expenses. Expenses from oil and natural gas
operations include services related to producing oil and natural
gas, such as severance taxes, post production costs (including
transportation), and lease operating expenses.
The following table is a comparison of our general categories of
expenses for the years ended December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
General and administrative
|
|
$
|
3,435,507
|
|
|
$
|
2,057,333
|
|
Production and lease operating
|
|
|
2,047,028
|
|
|
|
614,338
|
|
Depletion, depreciation and
amortization
|
|
|
1,155,254
|
|
|
|
203,249
|
|
Interest
|
|
|
1,228,274
|
|
|
|
392,402
|
|
Taxes
|
|
|
29,651
|
|
|
|
75,000
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
$
|
7,895,714
|
|
|
$
|
3,342,322
|
|
|
|
|
|
|
|
|
|
|
Our general and administrative expenses for 2005 increased
$1,378,174, or 67%, from 2004 due to the increase in personnel
added to accommodate our continued growth as we hire additional
personnel to oversee the drilling program and additional
accounting staff to meet SEC filing requirements. We also
incurred significant professional fees related to SEC filings in
late December 2005.
Production and lease operating expenses for 2005 increased
$1,432,690 compared to 2004. This increase was due to additional
producing wells on-line during 2005. This increase of 233% in
production costs is offset by the 602% increase in related
production revenue from 2004 to 2005.
Depletion, depreciation and amortization expense for 2005
increased $952,005 from 2004, or 468%, due to the increased
capitalized costs subject to depletion. There were no drilling
or completion related costs in the early quarters of 2004 that
were subject to amortization.
Interest expense for 2005 increased $835,872, or 213%, from the
year ended December 31, 2004. This increase is due to the
increase in mezzanine debt, offset by the capitalizing of
interest costs in 2005 during the drilling and development
phase. Limited drilling activity in the first three quarters of
2004 resulted in all interest being recorded as an expense for
those quarters.
Taxes recorded in the years ended December 31, 2005 and
2004 were property and other miscellaneous taxes and Indiana
income taxes, respectively.
LIQUIDITY
AND CAPITAL RESOURCES
We expect to fund our growth strategy using a combination of
debt, existing cash balances, internally generated cash flows
from natural gas production, and the proceeds from a public
offering that is currently underway. Our 2006 capital budget for
drilling and related well work and infrastructure is
approximately $51.2 million with an anticipated
participation in 221 (106 net) wells. Our 2006 capital
budget for leasehold interest and property acquisitions is
approximately $14.2 million and $39.3 million,
respectively. Our 2007 capital budget for drilling and related
well work and infrastructure is estimated to be approximately
$105.6 million with an anticipated participation in 410
(228 net) wells. Our 2007 capital budget for leasehold
interest and property acquisitions is estimated to be
approximately $9 million and $1 million, respectively.
We believe that the proceeds from the public offering, our
available credit facilities with anticipated increases in our
borrowing bases, and our operating cash flow will be sufficient
to fund our operations and capital expenditures for the next
18 months. However, future cash flows are subject to a
number of variables, including the level of production and
prices. 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.
Our mezzanine financing is a $50 million term credit
facility with certain affiliates of Trust Company of the West
(TCW) for the Michigan Antrim shale drilling
program. It is a non-revolving term loan facility that has a
commitment expiration date of August 12, 2007 and a
maturity date of September 29, 2009. Borrowings under the
31
TCW credit facility as of June 30, 2006 were
$40 million with available borrowing capacity of
$10 million. The interest rate is fixed at 11.5% per
year, compounded quarterly, and is payable in arrears. Beginning
September 28, 2006 and quarterly thereafter, the required
principal payment is 75% (100% if a coverage deficiency or
default occurs) of adjusted net cash flow determined
by deducting specified expenses, including capital expenditures
from gross cash revenue. We estimate that no
principal payments on the mezzanine financing will be required
until maturity because of the level of our anticipated capital
expenditures. We have granted TCW a security interest in certain
of our Michigan Antrim shale assets. This security interest is
subordinated to the security interest of our senior lender
described below. The TCW loan agreement contains, among other
things, a number of financial and non-financial covenants,
including covenants prohibiting the declaration or payment of
dividends and covenants requiring the maintenance of certain
financial and operating ratios, including collateral coverage
and proved developed producing coverage ratios. As of
June 30, 2006, we were in compliance with all of the
applicable covenants.
As additional consideration to induce TCW to enter into the
mezzanine term credit facility, we provided an affiliate of TCW
an overriding royalty interest in all of our 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 four percent, subject to
certain adjustments.
Our senior secured credit facility is a $100 million senior
secured revolving credit facility with BNP Paribas
(BNP). The amount that we can borrow under this
facility is limited to the amount of our borrowing base, which
is determined semi-annually and at certain other times by our
lenders. The initial borrowing base under this facility was
$40 million. 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. This facility matures on the earlier of
January 31, 2010 or 91 days prior to the maturity of
the mezzanine credit facility with TCW, unless we elect to
terminate the commitment earlier pursuant to the terms of the
credit facility. This facility provides for interest on
borrowings tied to BNPs prime rate (or, if higher, the
federal funds effective rate plus 0.5%) or a LIBOR-based rate
(LIBOR multiplied by a statutory reserve rate) plus 1.25 to 2.0%
depending on our borrowing base utilization. Our borrowing base
utilization is the percentage of our borrowing base that is
drawn under our senior credit facility from time to time. As our
borrowing base utilization increases, our LIBOR-based interest
rates increase under this facility. As of June 30, 2006,
interest on borrowings under our senior credit facility had a
weighted average interest rate of 7.02%. A required semi-annual
reserve report may result in an increase or decrease in our
borrowing base and hence our credit availability. On
July 14, 2006, the senior secured credit facility was also
amended to defer the application of the trailing 12-month
interest coverage ratio covenant until the fourth quarter of
2006, and to provide for a reduced ratio for that quarter. At
June 30, 2006, our total borrowings under this facility
were $40 million.
The security for our senior secured credit facility includes a
first lien position in certain of our Michigan Antrim shale
assets, a guarantee from Aurora, and a guarantee from us,
secured by a pledge of our stock in Aurora. The senior secured
credit facility contains, among other things, a number of
financial and non-financial covenants, including covenants
relating to restricted payments, loans or advances to others,
additional indebtedness, incurrence of liens, a prohibition on
our ability to prepay our mezzanine term credit facility with
TCW, geographic limitations on our operations to the United
States, and the maintenance of certain financial and operating
ratios, including a current ratio and an interest coverage
ratio. As of June 30, 2006, we were in compliance with all
of the applicable covenants.
Our short-term line of credit is a $5 million revolving
line of credit with Northwestern Bank for general corporate
purposes. At June 30, 2006, our total borrowings under this
facility were $10,000 with available borrowing capacity of
$4.9 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. Northwestern Bank has recently
agreed to extend the expiration date to October 15, 2007.
From late December 2005 through early February 2006, we 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 six-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 20,315,422 shares were issued
32
during the six months ended June 30, 2006 representing
15,565,457 shares issued for cash proceeds of $18,144,449
and 4,749,965 shares issued pursuant to cashless exercises
of the applicable warrants or options. In December 2005 an
additional 2,160,000 shares were issued for cash proceeds
of $2,916,000.
CAPITALIZATION
Our total capitalization was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Short-term bank borrowings
|
|
$
|
10,000
|
|
|
$
|
6,210,000
|
|
|
$
|
350,000
|
|
Obligations under capital lease
|
|
|
7,173
|
|
|
|
11,085
|
|
|
|
21,486
|
|
Related party notes payable
|
|
|
|
|
|
|
69,833
|
|
|
|
3,018,531
|
|
Mortgage payable
|
|
|
2,833,397
|
|
|
|
2,865,477
|
|
|
|
|
|
Mezzanine financing
|
|
|
40,000,000
|
|
|
|
40,000,000
|
|
|
|
10,000,000
|
|
Senior secured credit facility
|
|
|
40,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
82,850,570
|
|
|
|
49,156,395
|
|
|
|
13,390,017
|
|
Redeemable convertible preferred
stock
|
|
|
19,924
|
|
|
|
59,925
|
|
|
|
|
|
Shareholders equity
|
|
|
74,924,893
|
|
|
|
56,625,927
|
|
|
|
6,246,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
157,795,387
|
|
|
$
|
105,842,247
|
|
|
$
|
19,636,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The 439% increase in our capitalization from 2004 to 2005 was
primarily due to a combination of an increase in our borrowing
capacity and increases in shareholders equity. The
increase in borrowings included $30 million of additional
advances from our mezzanine facility and approximately
$9 million in short-term and long-term bank borrowings,
less approximately $3 million in payments of related party
notes payable. The increase in shareholders equity is due
primarily to the $36.3 million net increase recorded as a
result of the merger, $11.0 million in proceeds received
from a private equity infusion and $3.6 million in proceeds
from the issuance of additional equity securities.
CASH
FLOWS
Operating
activities
We generated $2,636,906 in net cash from operations in the
Current Period compared to using $459,971 in the Prior Period.
The $3,096,877 increase was primarily due to higher realized
prices and higher volumes of oil and natural gas production as
discussed in the Results of Operations.
We used $411,196 in net cash for the year ended
December 31, 2005 and generated $218,441 in net cash from
operations for the year ended December 31, 2004. The
decrease in 2005 from 2004 is due to changes in operating assets
and liabilities of $(1,166,550) and $1,063,757 for
December 31, 2005 and 2004, respectively. Specifically in
2005 we reported a revenue receivable from our joint venture
partners of $2,409,675, which was received early in the first
quarter of 2006.
Investing
activities
Net cash flows used in investing activities was $32,845,786 in
the Current Period compared to $7,946,216 used in the Prior
Period. This excludes asset retirement obligations of $976,343,
capitalized stock based compensation of $365,293 and investment
adjustment for the Hudson acquisition of $1,366,887.
Cash used in investing activities for the year ended
December 31, 2005 and December 31, 2004 was
($41,862,869) and ($8,716,784), respectively. This investing
activity included the purchase of leasehold and working
interests, drilling and development costs, purchase of office
computers and other equipment, advances on notes receivable, and
investments in Hudson Pipeline & Processing Co., LLC
and GeoPetra Partners, LLC. Cash
33
flows provided by investing activities for 2005 and 2004 include
$7,995,109 and $1,902,537, respectively, of proceeds received
from various sales of working interest and project interests.
The following table describes our significant investing
transactions that we completed in the periods set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
Six Months Ended June 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
Acquisitions of leaseholds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
$
|
3,342,686
|
|
|
$
|
1,059,396
|
|
|
$
|
7,195,372
|
|
|
$
|
2,447,028
|
|
New Albany(a)
|
|
|
18,036,545
|
|
|
|
2,429,786
|
|
|
|
8,376,805
|
|
|
|
980,985
|
|
Other
|
|
|
348,588
|
|
|
|
|
|
|
|
21,612
|
|
|
|
5,781
|
|
Drilling and development of oil
and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
13,889,316
|
|
|
|
10,958,670
|
|
|
|
30,343,249
|
|
|
|
5,184,398
|
|
New Albany
|
|
|
639,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
250,152
|
|
|
|
|
|
|
|
208,043
|
|
|
|
|
|
Infrastructure properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
5,615,861
|
|
|
|
|
|
|
|
|
|
|
|
1,541,471
|
|
Other
|
|
|
45,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of producing
properties
|
|
|
290,869
|
|
|
|
|
|
|
|
3,206,102
|
|
|
|
|
|
Additions to pipeline
|
|
|
162,108
|
|
|
|
|
|
|
|
928,956
|
|
|
|
230,396
|
|
Additions to other investments
|
|
|
475,000
|
|
|
|
515,956
|
|
|
|
485,741
|
|
|
|
|
|
Additions to other property and
equipment
|
|
|
219,694
|
|
|
|
105,674
|
|
|
|
3,594,750
|
|
|
|
74,166
|
|
Capitalized merger cost
|
|
|
|
|
|
|
263,092
|
|
|
|
|
|
|
|
|
|
Advances on note receivable
|
|
|
60,000
|
|
|
|
72,379
|
|
|
|
107,475
|
|
|
|
155,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal of capital expenditures
|
|
|
43,375,882
|
|
|
|
15,404,953
|
|
|
|
54,468,105
|
|
|
|
10,619,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Disposition of oil and natural gas
properties(a)
|
|
|
(10,500,000
|
)
|
|
|
(7,373,737
|
)
|
|
|
(11,504,428
|
)
|
|
|
(1,902,537
|
)
|
Divestiture of other receivable
and investment
|
|
|
(30,096
|
)
|
|
|
(85,000
|
)
|
|
|
(143,788
|
)
|
|
|
|
|
Net cash acquired in merger
|
|
|
|
|
|
|
|
|
|
|
(957,020
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal of capital divestitures
|
|
|
(10,530,096
|
)
|
|
|
(7,458,737
|
)
|
|
|
(12,605,236
|
)
|
|
|
(1,902,537
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(b)
|
|
$
|
32,845,786
|
|
|
$
|
7,946,216
|
|
|
$
|
41,862,869
|
|
|
$
|
8,716,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
On February 2, 2006, we closed an acquisition of certain
New Albany shale acreage located in Indiana, commonly called the
Wabash project. We acquired 64,000 acres of oil and natural
gas leases from Wabash Energy Partners, L.P. for a purchase
price of $11,840,000. We then sold half our interest in a
combined 95,000 acre lease position in the Wabash project
to New Albany-Indiana, L.L.C., an affiliate of Rex Energy
Operating Corporation for a sale price of $10,500,000. We used
internal funds to pay the net transaction cost of these
transactions. |
|
(b) |
|
On January 31, 2006, we 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 Antrim gas play. We acquired 24
bcfe in proved reserves plus a controlling interest in a related
pipeline company for a total purchase price of $27,615,993. This
transaction was treated as a non-cash financing transaction
since our financial institution paid the seller directly and is
not included in the above table. |
Financing
activities
Cash flows provided by financing activities for the Current
Period were $21,823,195 compared to $16,743,071 during the Prior
Period. Cash flows provided and used for the Current Period
included: 1) $37,613,387 of senior
34
secured borrowing, of which, $27,615,993 was paid directly for
the Hudson acquisition; 2) $18,144,449 of proceeds received
from exercise of common stock options and warrants; and
3) pay-down of $6,200,000 in short-term bank borrowings.
Cash flows provided and used by financing activities for the
Prior Period included: 1) $11,025,000 of proceeds received
from sales of common stock; 2) $9,850,000 of mezzanine
borrowing, net of financing costs of $150,000; 3) pay-off
of $2,948,698 of certain related-party notes; and
4) distributions of $805,000 to minority interest members
for their proportionate share of the El Paso sale proceeds.
During the year ended December 31, 2005, we covered our
capital budget through the combination of advances from our
mezzanine facility of $29.49 million in 2005 compared to
advances of $10.17 million in 2004, (net of financing fees
of $508,544 and $294,545, respectively) and from proceeds from
the sale of equities of $14.6 million in 2005, compared to
$2.9 million in 2004. The purchase of office space in 2005
was financed with a mortgage in the amount of $2.9 million.
In December 2005 we increased our mezzanine credit facility with
TCW from $30 million to $50 million under an amendment
to the original Note Purchase Agreement. Borrowings under
this facility as of December 31, 2005 were $40 million.
Cash flows provided by financing activities during the years
ended December 31, 2005 and December 31, 2004 include
the following:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Advances from short term bank
borrowings
|
|
$
|
5,860,000
|
|
|
$
|
350,000
|
|
Advances from mezzanine financing
(net of fees)
|
|
|
29,491,458
|
|
|
|
10,179,694
|
|
Proceeds from issuance of common
stock
|
|
|
14,666,625
|
|
|
|
2,920,000
|
|
Advances from building mortgage
|
|
|
2,865,477
|
|
|
|
|
|
Proceeds from notes payable
|
|
|
|
|
|
|
154,118
|
|
Proceeds from subsidiary
disposition
|
|
|
|
|
|
|
10,467
|
|
|
|
|
|
|
|
|
|
|
Total cash flows provided by
financing activities
|
|
$
|
52,883,560
|
|
|
$
|
13,614,279
|
|
|
|
|
|
|
|
|
|
|
RECENT
ACCOUNTING PRONOUNCEMENTS
The following is a summary of recent accounting pronouncements
issued in 2006. We do not expect any of the following
pronouncements to have a material effect on our consolidated
financial position, cash flows or results of operations.
In February 2006, the FASB issued SFAS 155,
Accounting for Certain Hybrid Financial Instrument
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 re-measurement 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.
In February 2006, the FASB issued Financial Staff Position
(FSP) No. 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 employees control. These
instruments are not required to be classified as a liability
until it becomes probable that the event will occur. We adopted
this FSP in the second quarter of 2006.
In April 2006, the FASB issued FSP No. FIN 46(R)-6,
Determining the Variability to Be Considered in Applying
FASB Interpretation No. 46(R), which requires the use
of a by design approach for determining whether an
interest is variable when applying FASB Interpretation
No. 46, Consolidation of Variable Interest
Entities. This approach includes evaluating whether an
interest is variable based on a thorough understanding of the
design of the potential variable interest entity
(VIE), including the nature of the risks that the
potential VIE was designed to create and pass along to interest
holders in the entity. The guidance in this FSP is effective for
35
reporting periods beginning after June 15, 2006. We will
adopt the guidance presented in this FSP in the third quarter of
2006 on a prospective basis.
In July 2006, the Financial Accounting Standards Board (FASB)
issued Interpretation No. 48, Accounting for
Uncertainty in Income Taxes, an Interpretation of SFAS Statement
No. 109. This Interpretation clarifies the accounting
for uncertainty in income taxes recognized in an
enterprises 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
de-recognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition. This
Interpretation is effective for fiscal years beginning after
December 15, 2006. We currently are assessing the impact of
Interpretation No. 48 on our results of operations and
financial position.
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 process of preparing consolidated financial statements in
conformity with accounting principles generally accepted in the
United States of America requires the use of estimates and
assumptions regarding certain types of assets, liabilities,
revenues, and expenses. These estimates primarily relate to the
valuation of oil and natural gas reserves and unsettled
transactions and events as of the date of the financial
statements. Accordingly, changes in facts and circumstances may
result in revised estimates and actual results may vary from
estimated amounts.
Oil
and natural gas properties
We employ the full cost method of accounting for our oil and
natural gas properties. Under the full cost method all costs
related to the acquisition, exploration and development of oil
and natural gas properties, including directly related overhead
costs, are capitalized and accumulated into a single cost center
referred to as a full cost pool. Proceeds from the sale or other
disposition of oil and natural gas properties are applied to
adjust the capitalized costs in the full cost pool with no gain
or loss recognized, unless the adjustment would significantly
alter the relationship between capitalized costs and proven
reserves of oil and natural gas, in which case the gain or loss
is recognized as income.
Oil
and natural gas reserves
Proved oil and natural gas reserves, as defined by SEC
Regulation S-X
Rule 4-10(a)(2),
(3) and (4), are the estimated quantities of crude oil,
natural gas and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions including prices and costs as
of the date the estimate is made. As of December 31, 2005,
we did not have any of our natural gas production hedged.
Therefore, the price used in the reserve report to calculate
value was $9.89 per mcf, the price at which we sold our gas
on December 31, 2005. The price used in the interim reserve
report to calculate value at June 30, 2006 was
$5.69 per mcf, which excluded any adjustments for natural
gas hedging activity.
Our estimates of proved reserves are made using available
geological and reservoir data as well as production performance
data. These estimates made by our engineers are reviewed
annually and revised, either upward or downward, as warranted by
additional data. Revisions are necessary due to changes in,
among other things reservoir performance, prices, economic
conditions and governmental restrictions. Decreases in prices,
for example, may
36
cause a reduction in some proved reserves due to reaching limits
sooner. A material change in the estimated volumes of reserves
could have an impact on the depletion rate calculation reported
in the consolidated financial statements.
Commodity
price management activities
We recognize all hedging contracts 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 Instruments and Hedging
Activities, as amended, is dependent upon whether or not a
contract 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 our balance sheet until the hedged item is recognized
in earnings as gas revenue. If a hedge contract has an
ineffective portion, that particular portion of the gain or loss
would be immediately reported in earnings.
Ceiling
test
Companies that use the full cost method of accounting for oil
and natural gas properties are required to perform the ceiling
test each quarter. The ceiling is an impairment test performed
as prescribed by SEC
Regulation S-X
Rule 4-10.
The test determines a limit, or ceiling, on the book value of
oil and natural gas properties. That limit is the after-tax
value of the future net cash flows from proved crude oil and
natural gas reserves discounted at ten percent per annum. This
ceiling is compared to the net book value of the oil and natural
gas properties and reduced by the related net deferred income
tax liability and asset retirement obligations. If the net book
value reduced by the related net deferred income tax liability
and asset retirement obligations exceeds the ceiling, impairment
or non-cash write down is required. A charge to income for
impairment could give us a significant loss for a particular
period. However, future depletion expense would be reduced.
The ceiling test is affected by a decrease in net cash flow from
reserves due to higher operating or capital costs or reduction
in market prices for natural gas and crude oil. These changes
can reduce the amount of economically producible reserves. We
were not required to record a charge for impairment during the
year ended December 31, 2005 or the six months ended
June 30, 2006.
Income
taxes
Income taxes are provided for based upon the liability method of
accounting pursuant to SFAS No. 109, Accounting for
Income Taxes. Under this approach, deferred income taxes
are recorded to reflect the tax consequences in future years of
differences between the tax basis of assets and liabilities and
their financial reporting amounts at each year-end. A valuation
allowance is recorded against deferred tax assets if we do not
believe that we have met the more likely than not
standard imposed by SFAS No. 109 to allow recognition
of such an asset.
At December 31, 2005, we had net deferred tax assets
calculated at an expected rate of 34% of approximately
$10,145,800. Because we cannot determine that it is more likely
than not that we will realize the benefit of the net deferred
tax asset, a valuation allowance equal to the net deferred tax
asset has been established at December 31, 2005.
Stock-based
compensation
On January 1, 2006, we 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. We 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.
37
SIGNIFICANT
ACCOUNTING PRINCIPLES RELATING TO THE MERGER
As a result of the reverse merger, we were required to conform
certain of Cadences 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 targets 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. These
increased capitalized costs were 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 are using SFAS No. 123R.
Aurora stock options outstanding as of the date of the merger
are not accounted for under APB Opinion 25 or SFAS 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 off-balance sheet arrangements, special purpose
entities, financing partnerships or guarantees.
38
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 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.
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 have been included in the
financial statements from the date of acquisition. Effective
May 11, 2006, Cadence Resources Corporation amended its
articles of incorporation to change its name to Aurora
Oil & Gas Corporation.
Our strategy is to maximize shareholder value by leveraging our
significant acreage position. As an early stage developer of
properties, we anticipate that reserve growth will be our
initial focus followed by a more traditional balance between
reserve and production growth. Our six-month drilling program
ending June 30, 2006 resulted in us participating in 72 (33
net) wells of which 52 (27 net) wells were waiting hook-up.
As of June 30, 2006, we operated 175 (151 net) wells
and participated in another 289 (57 net) wells operated by
other companies. This 2006 drilling activity and a 24 bcfe
acquisition increased our proved reserves by nearly 64% to 105
bcfe of which 99% were natural gas reserves.
OPERATING
AREAS
Antrim
shale
Our Antrim shale properties are located in Michigan and
represent our primary area of development over the next 12 to
18 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
8,000 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
CO2,
organic material, and the heavier oil and gases stored in the
shale.
39
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
CO2
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 managements opinion, based upon
performance information from over 8,000 wells with
comparable geologic characteristics, areas with natural
fractures in shale have compelling production potential.
At June 30, 2006, we owned working interests in 384 Antrim
wells. In the last 18 months, we have drilled 199
(135 net) Antrim wells and successfully completed 191 for a
success rate of 96%. In 2005, we drilled and successfully
completed or participated in a total of 143 (105 net)
Antrim wells including three horizontal wells. During the first
six months of 2006, we drilled and successfully completed or
participated in a total of 54 (28.30 net) wells. We have
budgeted for the drilling of 409 (228 net) Antrim wells
during the
18-month
period beginning June 30, 2006 and ending December 31,
2007. On average, our Antrim wells are drilled to depths ranging
from 250 to 1,500 feet targeting reserves of 0.5 bcfe per
well and, based on our 2007 budget, cost approximately $325,000
to drill and complete each well.
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. Nearly all 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 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 1900s, 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 15 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 is being implemented in 2006.
40
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 sixty days. Our New Albany
shale wells are drilled to depths ranging from 500 to
3,000 feet and based on a recent Schlumberger reserve
report could yield reserves of 0.9 to 1.3 bcfe per well and,
based on our 2007 budget, will cost approximately $850,000 to
drill and complete each well. At June 30, 2006, we owned
working interests in 27 (4.65 net) New Albany shale wells.
In the last 18 months, we have drilled 19 (4.17 net)
New Albany shale wells and successfully completed all of these
wells for a success rate of 100%. In 2005, we drilled and
successfully completed or participated in a total of 3
(.15 net) New Albany shale wells all of which were
horizontal wells. During the first six months of 2006, we
drilled and successfully completed 16 (4.02 net) New
Albany shale wells. We have planned for the drilling of
approximately 125 (52.4 net) New Albany shale wells, with
the majority being horizontal wells, during the
18-month
period beginning July 1, 2006 and ending December 31,
2007.
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 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.
For 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 gas
production that would otherwise be left in the reservoir.
In the Michigan Antrim, we usually use a simple proven
completion procedure. This procedure involves drilling through
several pay zones, setting and cementing casing, and drilling a
rat-hole, which is used for gas-water separation. The wells are
then hydraulically fractured with a specifically designed
four-stage fracture procedure. 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 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 fields
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.
41
Oil
and natural gas reserves
The following table presents information as of June 30,
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 for New Albany and Antrim
is based on reserve reports prepared by Schlumberger, copies of
which are attached as Appendices A and B. According to this
report, over 44% of our proved reserves in Antrim and New Albany
are classified as either proved developed non-producing or
proved undeveloped.
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|
|
As of June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
|
|
Oil and Natural Gas Reserves(a)
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
PV-10(d)
|
|
|
Measure(e)
|
|
|
|
(mbbls)
|
|
|
(mmcf)
|
|
|
(mmcfe)
|
|
|
(In thousands)
|
|
|
(In thousands)
|
|
|
Proved developed producing
|
|
|
24
|
|
|
|
59,592
|
|
|
|
59,736
|
|
|
$
|
86,395
|
|
|
$
|
74,039
|
|
Proved developed non-producing
|
|
|
|
|
|
|
13,498
|
|
|
|
13,498
|
|
|
|
20,894
|
|
|
|
14,527
|
|
Proved undeveloped
|
|
|
67
|
|
|
|
32,198
|
|
|
|
32,600
|
|
|
|
28,749
|
|
|
|
28,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved(b)(c)
|
|
|
91
|
|
|
|
105,288
|
|
|
|
105,834
|
|
|
$
|
136,038
|
|
|
$
|
116,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent of
|
|
|
|
|
Oil and Natural Gas Reserves by Play/Trend(a)
|
|
Total
|
|
|
Proved Reserves
|
|
|
PV-10
|
|
|
|
(mmcfe)
|
|
|
|
|
|
(In thousands)
|
|
|
Antrim
|
|
|
101,411
|
|
|
|
96
|
%
|
|
$
|
125,474
|
|
New Albany
|
|
|
1,922
|
|
|
|
2
|
%
|
|
|
3,457
|
|
Other(f)
|
|
|
2,501
|
|
|
|
2
|
%
|
|
|
7,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
105,834
|
|
|
|
100
|
%
|
|
$
|
136,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in reserve quantity information for the six months
ended June 30, 2006(a)
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
|
(mbbls)
|
|
|
(mmcf)
|
|
|
(mmcfe)
|
|
|
Proved reserves as of
December 31, 2005
|
|
|
99
|
|
|
|
63,322
|
|
|
|
63,916
|
|
Revisions of previous estimates
|
|
|
(38
|
)
|
|
|
(4,093
|
)
|
|
|
(4,321
|
)
|
Purchases of minerals in place
|
|
|
|
|
|
|
24,720
|
|
|
|
24,720
|
|
Extensions and discoveries
|
|
|
41
|
|
|
|
22,563
|
|
|
|
22,809
|
|
Production
|
|
|
(11
|
)
|
|
|
(1,224
|
)
|
|
|
(1,290
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves as of
June 30, 2006
|
|
|
91
|
|
|
|
105,288
|
|
|
|
105,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The information presented for New Albany and Antrim reserves is
based on reserve reports prepared by Schlumberger. Consistent
with Schlumbergers standard engineering practices, these
reports and such reserves excluded the impact of the following
financial hedges: (i) 5,000 mmbtu/day at a price of
$8.59/mmbtu through March 2007 and (ii) 5,000 mmbtu/day at
a price of $9.00/mmbtu from April 2007 through December 2008. |
|
(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
June 30, 2006. The estimated future production is priced at
June 30, |
42
|
|
|
|
|
2006, without escalation, using $69.32 per bbl and
$5.69 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 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 flow in
the following table: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30,
|
|
|
As of December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
116,722,099
|
|
|
$
|
152,868,240
|
|
|
$
|
32,159,710
|
|
Add: Present value of future
income tax discounted at 10%
|
|
|
19,316,221
|
|
|
|
46,639,200
|
|
|
|
15,750,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
|
|
$
|
136,038,320
|
|
|
$
|
199,507,440
|
|
|
$
|
47,910,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. If the impact of our hedges were included,
the standardized measure would have been increased by $8,960,351
to $125,682,450. |
|
(f) |
|
The reserves shown in the Other line were internally
generated numbers that are not derived from a report of
independent reserve engineers. |
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, 2006 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
|
|
|
95,457
|
|
|
|
35,510
|
|
|
|
157,177
|
|
|
|
90,483
|
|
|
|
252,634
|
|
|
|
125,993
|
|
New Albany
|
|
|
99,320
|
|
|
|
4,965
|
|
|
|
685,496
|
|
|
|
444,494
|
|
|
|
784,816
|
|
|
|
449,459
|
|
Other
|
|
|
16,178
|
|
|
|
1,821
|
|
|
|
52,111
|
|
|
|
44,017
|
|
|
|
68,289
|
|
|
|
45,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
210,955
|
|
|
|
42,296
|
|
|
|
894,784
|
|
|
|
578,994
|
|
|
|
1,105,739
|
|
|
|
621,290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
43
Production
and price information
The following tables summarize sales volumes, sales prices, and
production cost information for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
|
Ended June 30,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls)
|
|
|
11,888
|
|
|
|
10,628
|
|
|
|
4,798
|
|
Natural gas (mcf)
|
|
|
1,224,551
|
|
|
|
687,271
|
|
|
|
151,241
|
|
Natural gas equivalent (mcfe)
|
|
|
1,295,879
|
|
|
|
751,039
|
|
|
|
180,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
741,110
|
|
|
$
|
558,455
|
|
|
$
|
226,599
|
|
Natural gas sales
|
|
|
10,200,110
|
|
|
|
6,184,989
|
|
|
|
733,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,941,220
|
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price (including
realized gains or losses from hedging)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($ per bbl)
|
|
$
|
62.34
|
|
|
$
|
52.54
|
|
|
$
|
47.23
|
|
Natural gas ($ per mcf)
|
|
|
8.33
|
|
|
|
9.00
|
|
|
|
4.85
|
|
Natural gas equivalent ($ per
mcfe)
|
|
|
8.44
|
|
|
|
8.98
|
|
|
|
5.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average production
cost
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas equivalent ($ per
mcfe)
|
|
$
|
2.63
|
|
|
$
|
2.73
|
|
|
$
|
3.41
|
|
Productive
wells
The following table sets forth information at June 30,
2006, relating to the productive wells in which we owned a
working interest as of that date. 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
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Play/Trend
|
|
Wells
|
|
|
Wells
|
|
|
Wells
|
|
|
Wells
|
|
|
Antrim
|
|
|
384
|
|
|
|
184.76
|
|
|
|
|
|
|
|
|
|
New Albany
|
|
|
27
|
|
|
|
4.65
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
29
|
|
|
|
8.25
|
|
|
|
24
|
|
|
|
9.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
440
|
|
|
|
197.66
|
|
|
|
24
|
|
|
|
9.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
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
|
|
Period
|
|
Type of Well
|
|
Productive(b)
|
|
|
Dry(c)
|
|
|
Total
|
|
|
Productive(b)
|
|
|
Dry(c)
|
|
|
Total
|
|
|
Six Months Ended June 30, 2006
|
|
Exploratory(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Albany
|
|
|
8
|
|
|
|
|
|
|
|
8
|
|
|
|
3.62
|
|
|
|
|
|
|
|
3.62
|
|
|
|
Other
|
|
|
2
|
|
|
|
2
|
|
|
|
4
|
|
|
|
0.92
|
|
|
|
1
|
|
|
|
1.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
10
|
|
|
|
2
|
|
|
|
12
|
|
|
|
4.54
|
|
|
|
1
|
|
|
|
5.54
|
|
|
|
Development(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
54
|
|
|
|
2
|
|
|
|
56
|
|
|
|
28.30
|
|
|
|
1.05
|
|
|
|
29.35
|
|
|
|
New Albany
|
|
|
8
|
|
|
|
|
|
|
|
8
|
|
|
|
0.40
|
|
|
|
|
|
|
|
0.40
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
62
|
|
|
|
2
|
|
|
|
64
|
|
|
|
28.70
|
|
|
|
1.05
|
|
|
|
29.75
|
|
Year Ended December 31, 2005
|
|
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
|
|
|
|
3.4
|
|
|
|
104.77
|
|
|
|
New Albany
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
|
|
0.15
|
|
|
|
|
|
|
|
0.15
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
139
|
|
|
|
5
|
|
|
|
144
|
|
|
|
101.52
|
|
|
|
3.4
|
|
|
|
104.92
|
|
Year Ended December 31, 2004
|
|
Exploratory(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Albany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Antrim
|
|
|
84
|
|
|
|
3
|
|
|
|
87
|
|
|
|
25.06
|
|
|
|
1.18
|
|
|
|
26.24
|
|
|
|
New Albany
|
|
|
|
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
|
|
0.20
|
|
|
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
84
|
|
|
|
7
|
|
|
|
91
|
|
|
|
25.06
|
|
|
|
1.38
|
|
|
|
26.44
|
|
|
|
|
(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. |
45
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
CO2
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. 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 recently 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. We will be paid $0.01 per mcf less than the published
index for this gas. This contract will cover much of our
existing production.
We also have three 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. For example, demand for
natural gas has increased in recent years due to a trend in the
power plant industry to move away from using oil and coal as a
fuel source to using natural gas, because natural gas is a
cleaner fuel. 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.
Effective April 1, 2006, we entered into a financial swap
contract for 5,000 mmbtu per day at a fixed price of
$8.59 per mmbtu covering a
12-month
period. On July 14, 2006, we entered into another financial
swap contract for 5,000 mmbtu per day at a fixed price of
$9.00 per mmbtu for the period from April 1, 2007
through December 31, 2008.
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 June 30, 2006, we have 53 full time employees and two
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. Factors that affect our ability to acquire producing
properties include available funds, available information about
46
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 re-negotiation 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.
47
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 (Michigan) 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.
Legal
proceedings
Our management is unaware of any threatened or pending material
legal claims or procedures of a non-routine nature.
48
MANAGEMENT
The following table sets forth the name, age and position of
each of our executive officers and directors as of June 30,
2006.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position(s) with the Company
|
|
William W. Deneau
|
|
|
62
|
|
|
Director, Chairman and President
|
Ronald E. Huff
|
|
|
51
|
|
|
Director and Chief Financial
Officer
|
John V. Miller, Jr.
|
|
|
48
|
|
|
Vice President, Science and
Strategic Planning
|
Thomas W. Tucker
|
|
|
64
|
|
|
Vice President, Operations
|
Kevin D. Stulp
|
|
|
50
|
|
|
Director
|
Richard M. Deneau
|
|
|
60
|
|
|
Director
|
Gary J. Myles
|
|
|
61
|
|
|
Director
|
Earl V. Young
|
|
|
65
|
|
|
Director
|
Our Board of Directors is comprised of seven persons. We
currently have one vacancy and are conducting a search for a
person to fill this vacancy. Information about our incumbent
directors and executive officers follows.
William W. Deneau has served as our President and
Chairman of the Board of Directors since November 1, 2005.
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 Auroras stock on April 22, 1997. Since
April 1997, Mr. Deneau has been responsible for managing
Auroras affairs. He officially became a Director of Aurora
on June 25, 1997 and the President of Aurora on
July 17, 1997. Since 1987, Mr. Deneau has also been
the President, a Director, and the sole owner of White Pine Land
Services, Inc. of Traverse City, Michigan. Prior to
March 1, 1997, White Pine Land Services, Inc. was a
35-member company engaged in the business of providing real
estate services to oil and gas companies. On March 1, 1997,
White Pine Land Services, Inc. sold its business to a newly
formed corporation, White Pine Land Company. White Pine Land
Services, Inc. continues to exist for the purpose of managing
its investments. William W. Deneau is the brother of Richard M.
Deneau, another one of our Directors.
Ronald E. Huff, CPA, has served as our Chief Financial
Officer since June 19, 2006 and as a Director since
November 21, 2005. 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. Mr. Huff worked for
Belden & Blake Corporation from 1986 to 1999 as its
Chief Financial Officer and was also its President from 1997 to
1999. Belden & Blake Corporation acquired properties,
explored for and developed oil and gas reserves, and marketed
natural gas, primarily in the Appalachian and Michigan
Plays/trends. It went through a successful initial public
offering in 1992, and was acquired by Texas Pacific Group in
1997. From 1983 to 1986 Mr. Huff was the Chief Accounting
Officer of Zilkha Petroleum; from 1980 to 1983, he was a
financial analyst for Southern Natural Resources, a natural gas
marketing company; and from 1977 to 1980 he was a corporate
accountant with Transco Companies Incorporated.
John V. Miller has served as our Vice President, Science
and Strategic Planning, since May 2006, and served as Vice
President of Exploration and Production from November 1,
2005 to May 2006. 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 Auroras 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. In 1994,
Mr. Miller joined Jet Exploration, Inc. of Traverse City,
Michigan, as a Vice President with responsibility for getting
Jet Exploration, Inc. into the shale gas play in Michigan and
Indiana. He was the driving force behind the establishment of
Jet/LaVanway Exploration, L.L.C. and its effort in southern
Indiana. Mr. Miller left the position with Jet Exploration,
Inc. to join Aurora. From 1988 to 1994, Mr. Miller worked
for White Pine Land Services, Inc. of Traverse City, Michigan,
as Land Manager.
49
Thomas W. Tucker has served as our Vice President of
Operations since May 2006, and served as Vice President of Land
and Development from November 2005 to May 2006. 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
Auroras stock on April 22, 1997. From April 1997 to
the present, 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.
Mr. Tucker founded Jet Oil Corporation with his father in
1982. In 1987, after his fathers death, Mr. Tucker
founded Jet Exploration, Inc. Mr. Tucker has been the
President of Jet Exploration, Inc. since its inception. Jet
Exploration, Inc. no longer takes on any new projects, and its
existing projects are being allowed to run out their course.
Kevin D. Stulp has served on our Board of Directors since
March 1997. Since August 1995, Mr. Stulp has variously
worked as consultant with Forte Group, on the board of the Bible
League, and is active with various other non-profit
organizations. 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. Mr. Stulp holds a
B.S.L.E. from Calvin College, Grand Rapids, Michigan, and a
B.S.M.E. in Mechanical Engineering and an M.B.A. from the
University of Michigan.
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, was 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.
Prior to working for Anchor, Richard M. Deneau served in
management at Ball Foster Glass Container Corp., American
National Can, Foster Forbes Glass and First National Bank of
Lapeer. He served as an auditor with Ernst & Ernst
after graduating from Michigan State University in 1968. Richard
M. Deneau is the brother of William W. Deneau, our President and
Chairman of the Board of Directors.
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 $3,500,000
annually. Mr. Myles had been with Fifth Third Bank and its
predecessor, Old Kent Mortgage Company, since July 1988.
Mr. Myles also owns Foster Care, Ltd., a closely held
company for which he serves as a Director, President and
Treasurer. Mr. Myles is the chairperson of our Audit
Committee and Nominating and Corporate Governance Committee.
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 exploration in
Madagascar. From 1996 to 1999, Mr. Young was the Senior
Vice President of Corporate Development for American Mineral
Fields, Inc. of Dallas, Texas. From 1993 to 1996, Mr. Young
was a principal in Young & Lowe, which offered business
consulting services to small capitalization companies. Prior to
1993, Mr. Young was involved in the investment banking
business. He is President of the US/Madagascar Business Council
headquartered in Washington, D.C. and a Director of the
Corporate Council on Africa in Washington D.C. Mr. Young
was a gold medalist in the Summer Olympic Games in 1960 in
track, has served as President of the Southwest Chapter of
Olympians, and was the founding chairman of the Olympians for
Olympians Relief Committee. Mr. Young is the chairperson of
our Compensation Committee.
50
Indemnification
Our bylaws provide that our directors and officers will be
indemnified to the fullest extent permitted by the Utah
Corporation Code. However, such indemnification does not apply
to acts of intentional misconduct, a knowing violation of law,
or any transaction where an officer or director personally
received a benefit in money, property, or services to which the
director was not legally entitled.
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, we have been advised that in
the opinion of the SEC such indemnification is against public
policy as expressed in the Securities Act and is, therefore,
unenforceable.
BOARD
COMMITTEES
The composition of our board committees is as follows:
|
|
|
|
|
Audit Committee: Gary J. Myles (Chairman), Earl V.
Young and Kevin D. Stulp;
|
|
|
|
Compensation Committee: Earl V. Young (Chairman),
Kevin D. Stulp and Gary J. Myles; and
|
|
|
|
Nominating and Corporate Governance Committee: Gary
J. Myles (Chairman), Earl V. Young, and Kevin D. Stulp.
|
The board of directors has designated the following directors as
independent directors: Gary J. Myles, Kevin D. Stulp and
Earl V. Young.
Each of our Audit Committee members is an independent outside
director, and one, Gary J. Myles, is a financial expert with
knowledge of financial statements, generally accepted accounting
principles and accounting procedures and disclosure rules. His
credentials are described in greater detail above.
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
managements 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, Managements Discussion and Analysis of
Financial Conditions and Results of Operations, and disclosures
regarding internal controls before they are filed with the SEC.
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
Cadence operations. 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, 2004 and 2003, and
compensation paid by Cadence for the months of November and
December 2005.
51
SUMMARY
COMPENSATION TABLE
|
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|
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|
|
|
|
|
|
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|
|
|
|
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Long-Term Compensation Awards
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Annual Compensation
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Value of Restricted
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# of Securities
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Name and Principal Position
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|
Year
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Salary(a)
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Bonuses
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Stock Awards(b)
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Underlying Options
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|
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William W. Deneau
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2005
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$
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140,000
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|
|
$
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$
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|
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President, Chief Executive Officer
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2004
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90,000
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|
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|
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|
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|
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2003
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52,500
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|
|
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John V. Miller, Jr.
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2005
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125,000
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Vice President, Science and
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2004
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90,000
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Strategic Planning
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2003
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63,300
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Thomas W. Tucker,
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2005
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125,000
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Vice President, Operations
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2004
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90,000
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2003
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52,500
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Lorraine M. King,
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2005
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125,000
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116,400
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(d)
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20,000 shares
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(e)
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Chief Financial Officer(c)
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2004
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65,000
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25,000
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20,000 shares
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(f)
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2003
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65,000
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20,000 shares
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(f)
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(a) |
|
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. |
|
(b) |
|
Because all of the shares we issued in exchange for Aurora stock
in the merger were registered under the
Form S-4
registration statement, none of the named executive officers
held restricted stock at December 31, 2005. |
|
(c) |
|
Effective June 19, 2006, Lorraine M. King resigned her
position as Chief Financial Officer, and Ronald E. Huff became
our Chief Financial Officer. Ms. King is now our Treasurer. |
|
(d) |
|
Ms. King was awarded 30,000 shares of common stock by
the Board of Directors on December 8, 2005. The closing
price at which our stock traded on that date was $3.88 per
share. Issuance of these shares was deferred until a
Form S-8
registration statement was filed with the SEC, but the
compensation related to this award was recorded as an expense in
the 2005 consolidated financial statements. |
|
(e) |
|
Option to purchase 10,000 shares of Aurora common stock at
an exercise price of $3.50 per share; converted in the
merger into the right to purchase 20,000 shares of our
common stock at an exercise price of $1.75 per share. |
|
(f) |
|
Option to purchase 10,000 shares of Aurora common stock at
an exercise price of $0.75 per share; converted in the
merger into the right to purchase 20,000 shares of our
common stock at an exercise price of $0.375 per share. |
OPTION
GRANTS IN 2005
Individual
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# of Securities
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% of Total Options
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Exercise
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Underlying Options
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Granted to Employees
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Price per
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Expiration
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Name
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Granted
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in Fiscal Year
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Share (a)
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Date
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Lorraine M. King(b)
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|
20,000
|
(c)
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7
|
%
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$
|
1.75
|
(c)
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|
|
10/18/15
|
|
|
|
|
(a) |
|
At the date of grant, Aurora had not yet merged with Cadence,
and Aurora was not publicly traded. Accordingly, there was no
market price at the date of grant. |
|
(b) |
|
Effective June 19, 2006, Lorraine M. King resigned her
position as Chief Financial Officer and Ronald E. Huff became
our Chief Financial Officer. Ms. King is now our Treasurer. |
|
(c) |
|
This award was initially for 10,000 shares of Auroras
common stock with an exercise price of $3.50 per share, and
was converted in the merger as described in the table. |
52
AGGREGATED
OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES
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Shares
|
|
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# of Securities Underlying
|
|
|
Value of Unexercised
|
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|
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Acquired
|
|
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|
|
|
Unexercised Options at
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In-the-Money
Options at
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|
|
on
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Value
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|
|
12/31/05
|
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12/31/05(a)
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Name
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Exercise
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Realized
|
|
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Exercisable
|
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Unexercisable
|
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Exercisable
|
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|
Unexercisable
|
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William W. Deneau
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0
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0
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600,000
|
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|
0
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$
|
2,475,000
|
|
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John V. Miller, Jr.
|
|
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0
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0
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600,000
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0
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2,475,000
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Thomas W. Tucker
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0
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0
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600,000
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0
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|
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2,475,000
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Lorraine M. King(b)
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0
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0
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160,000
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|
|
|
0
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|
638,900
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|
|
|
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|
|
(a) |
|
Options are
in-the-money
if the market price of a share of common stock exceeds the
exercise price of the option. |
|
(b) |
|
Effective June 19, 2006, Lorraine M. King resigned her
position as Chief Financial Officer and Ronald E. Huff became
our Chief Financial Officer. Ms. King is now our Treasurer. |
We do not currently have any long term incentive compensation
plans in place.
As compensation for their services as directors of Aurora during
2005 and prior to the merger, on December 8, 2005, our
board voted to award Earl V. Young and Gary J. Myles each
30,000 shares of common stock, to be issued in 2006 after
the shares are registered on a
Form S-8
registration statement. These shares were awarded in lieu of
awarding stock options that would otherwise have been issued,
but were deferred due to the ongoing work on the merger, which
extended through most of 2005.
The following are our standard compensation arrangements for
service as a director, post-merger:
Option to purchase 200,000 shares of our common stock at an
exercise price of $3.62 per share; 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 meeting attended in person,
with additional payments of $1,000 per day for each travel
day from the directors place of residence to the location
of the board 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
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 chairman.
Prior to the merger, we had a different arrangement for
compensating directors, as follows:
All directors were reimbursed for
out-of-pocket
expenses in connection with attendance at meetings of the board
of directors. During the fiscal year ended September 30,
2005, each non-employee director received (1) $5,000 and
5,000 shares of restricted stock per quarter of completed
service, (2) 2,500 restricted shares of common stock for
each year of service on any committee of the board of directors,
(3) $2,500 for chair of the Audit Committee and $1,000 for
any other committee which they chaired, and each director
(employee or non-employee) was entitled to an option to purchase
50,000 shares of our common stock on the anniversary of his
appointment to the board.
During the fiscal year ended September 30, 2005,
Messrs. Christian, DeHekker and Stulp, the three
non-employee directors, each received options to purchase
50,000 shares of our common stock at an exercise price of
$1.42 per share, and Messrs. Crosby and Ryan, the
employee directors, each received options to purchase
50,000 shares of our common stock at an exercise price of
$1.21 per share. Also for the September 30, 2005
fiscal year, Messrs. Christian, Crosby, DeHekker, Ryan and
Stulp each received 15,000 shares of our common stock per
quarter for the first three quarters of 2005 as compensation for
their service on the board of directors.
53
Messrs. DeHekker and Stulp received an additional
4,000 shares of our common stock for their service on a
committee of the board of directors.
In addition, subsequent to September 30, 2005, each of
Messrs. Christian, DeHekker and Ryan, the directors
resigning because of the merger with Aurora, received warrants
to purchase an aggregate of 37,500 shares of our common
stock, consisting of a warrant to purchase 12,500 shares of
our common stock for a purchase price of $2.53 per share, a
warrant to purchase 12,500 shares of our common stock for a
purchase price of $2.23 per share, and a warrant to
purchase 12,500 shares of our common stock for a purchase
price of $3.28 per share.
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
approximately $2.1 million in stock-based compensation
expense over the contract period. If Mr. Huffs
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. Huffs 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 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.
We do not have any other contractual arrangements with our
executive officers or directors, nor do we have any compensatory
arrangements with our executive officers other than as described
above. Except as described above with respect to Mr. Huff,
we have not agreed to make any payments to our named executive
officers because of resignation, retirement or any other
termination of employment with us or our subsidiaries, or from a
change in control of us, or a change in the executives
responsibilities following a change in control.
54
PRINCIPAL
AND SELLING SECURITY HOLDERS
Principal
shareholders
The following table sets forth, as of October 10, 2006,
certain information regarding the ownership of our voting
securities by each shareholder known to our management 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. We believe that, except as otherwise
indicated, 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.
|
|
|
|
|
|
|
|
|
|
|
Amount and Nature
|
|
|
|
|
|
|
of Beneficial
|
|
|
Percent of
|
|
Name and Address of Beneficial Owner(a)
|
|
Ownership(b)
|
|
|
Outstanding Shares
|
|
|
Rubicon Master Fund(c)
|
|
|
11,750,000
|
|
|
|
14
|
%
|
c/o Rubicon Fund Management LLP
|
|
|
|
|
|
|
|
|
P103 Mount Street
|
|
|
|
|
|
|
|
|
London W1K 2TJ, UK
|
|
|
|
|
|
|
|
|
FMR Corp.(d)
|
|
|
9,836,246
|
|
|
|
12
|
%
|
82 Devonshire Street
|
|
|
|
|
|
|
|
|
Boston, Massachusetts 02109
|
|
|
|
|
|
|
|
|
Nathan A. Low Roth IRA and
affiliates
|
|
|
7,657,766
|
(e)
|
|
|
9
|
%
|
641 Lexington Avenue
|
|
|
|
|
|
|
|
|
New York, New York 10022
|
|
|
|
|
|
|
|
|
Crestview Capital Master, LLC
|
|
|
5,542,320
|
|
|
|
7
|
%
|
95 Revere Drive, Suite A
|
|
|
|
|
|
|
|
|
Northbrook, Illinois, 60062
|
|
|
|
|
|
|
|
|
William W. Deneau
|
|
|
4,232,500
|
(f)
|
|
|
5
|
%
|
Thomas W. Tucker
|
|
|
3,888,194
|
(g)
|
|
|
5
|
%
|
John V. Miller, Jr.
|
|
|
3,308,262
|
(h)
|
|
|
4
|
%
|
Kevin D. Stulp
|
|
|
527,500
|
(i)
|
|
|
*
|
|
Earl V. Young
|
|
|
416,204
|
(j)
|
|
|
*
|
|
Gary J. Myles
|
|
|
308,798
|
(k)
|
|
|
*
|
|
Richard M. Deneau(l)
|
|
|
|
|
|
|
|
|
Ronald E. Huff(m)
|
|
|
|
|
|
|
|
|
All executive officers and
directors as a group (8 persons)
|
|
|
12,681,458
|
(n)
|
|
|
15
|
%
|
|
|
|
(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 and Form 4 filed with the SEC
on August 8, 2006, pursuant to investment agreements, each
of Rubicon Fund Management Ltd., a company organized under the
laws of the Cayman Islands, which we refer to in this footnote
as Rubicon Fund Management Ltd., and Rubicon Fund Management
LLP, a limited liability partnership organized under the laws of
the United Kingdom, which we refer to in this footnote as
Rubicon Fund Management LLP, Mr. Paul Anthony Brewer,
Mr. Jeffrey Eugene Brummette, Mr. William Francis
Callanan, Mr. Vilas Gadkari, and Mr. Horace Joseph
Leitch III, share all investment and voting power with
respect to the securities held by Rubicon Master Fund.
Mr. Brewer, Mr. Brummette, Mr. Callanan,
Mr. Gadkari, and Mr. Leitch control both Rubicon Fund
Management Ltd. and Rubicon Fund |
55
|
|
|
|
|
Management LLP. Each of Rubicon Fund Management Ltd., Rubicon
Fund Management LLP, Mr. Brewer, Mr. Brummette,
Mr. Callanan, Mr. Gadkari, and Mr. Leitch
disclaim beneficial ownership of these securities. |
|
(d) |
|
Based on Schedule 13G/A filed with the SEC on
September 13, 2006, 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 9,768,546 shares of common stock.
Edward C. Johnson 3d and members of his family form a
controlling group with respect to FMR Corp. Accordingly, FMR
Corp. and Edward C. Johnson 3d have the sole power to
dispose of 9,768,546 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
67,700 shares of common stock, and FMR Corp and
Edward C. Johnson 3d have the sole dispositive power and
sole power to vote or direct the voting of the
67,700 shares of common stock beneficially owned by
Fidelity Management Trust Company. |
|
(e) |
|
Based on information included in an amendment to
Schedule 13D/A filed with the SEC on January 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. |
|
(f) |
|
Includes 3,272,000 shares of common stock held by the
Patricia A. Deneau Trust; 940,500 shares of common stock
held by the Denthorn Trust; and 20,000 shares of common
stock held by White Pine Land Services, Inc. Does not include an
option to purchase 200,000 shares of common stock vesting
as follows: 60,000 shares on January 1, 2007;
70,000 shares on January 1, 2008; and
70,000 shares on January 1, 2009. |
|
(g) |
|
Includes 1,607,574 shares of common stock held by the
Sandra L. Tucker Trust; 24,646 shares of common stock held
by Jet Exploration, Inc.; 1,615,974 shares of common stock
held by the Thomas W. Tucker Trust; and options currently
exercisable for 40,000 shares of common stock. |
|
(h) |
|
Includes 1,000,000 shares of common stock held by Miller
Resources, Inc.; 1,689,762 shares of common stock owned by
Circle M, LLC; 500,000 shares of common stock held by the
John V. Miller Jr. Living Trust DTD 7/21/05;
18,500 shares of common stock held by the Michelle R.
Miller and options currently exercisable for 40,000 shares
of common stock. |
|
(i) |
|
Includes options currently exercisable for 50,000 shares of
common stock and warrants currently exercisable for
100,000 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 200,000 shares of common
stock vesting as follows: 60,000 shares on January 1,
2007; 70,000 shares on January 1, 2008; and
70,000 shares on January 1, 2009. |
|
(j) |
|
Includes options currently exercisable for 199,998 shares
of common stock. Does not include an option to purchase
200,000 shares of common stock vesting as follows:
60,000 shares on January 1, 2007; 70,000 shares
on January 1, 2008; and 70,000 shares on
January 1, 2009. |
|
(k) |
|
Includes 77,800 shares of common stock held by the Gary J.
Myles & Rosemary Myles Inter Vivos Trust; and options
currently exercisable for 199,998 shares of common stock.
Does not include an option to purchase 200,000 shares of
common stock vesting as follows: 60,000 shares on
January 1, 2007; 70,000 shares on January 1,
2008; and 70,000 shares on January 1, 2009. |
|
(l) |
|
Does not include an option to purchase 200,000 shares of
common stock vesting as follows: 60,000 shares on
January 1, 2007; 70,000 shares on January 1,
2008; and 70,000 shares on January 1, 2009. |
|
(m) |
|
Does not include 500,000 shares of common stock to be
awarded on January 1, 2009, subject to vesting requirements. |
|
(n) |
|
Includes options and warrants currently exercisable for a total
of 629,996 shares of common stock. |
56
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 21,860,000 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 holders
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.
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Shares of Common
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Beneficial
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Percent of Class
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Stock Beneficially
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Ownership After
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Owned After
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Owned Prior to
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Shares of Common
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Offering If All
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Offering If All
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Selling Security Holders
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Offering*
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Stock to be Sold*
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Shares Are Sold*
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Shares Are Sold**
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Rubicon Master Fund(1)
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11,750,000
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10,800,000
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950,000
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***
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Crestview Capital Master, LLC
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5,819,500
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3,680,000
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2,139,500
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2.15
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%
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Union Spring Fund Ltd.
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2,160,000
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2,160,000
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0
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Nathan Low Family Trust, DTD
4/12/96(2)
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928,643
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720,000
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208,643
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***
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Bear Stearns as Custodian for
Nathan A. Low Roth IRA(2)
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7,657,766
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400,000
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7,257,766
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7.30
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%
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Ruth Low
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538,259
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480,000
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|
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58,259
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***
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Coghill Capital
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3,829,620
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|
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640,000
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|
|
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3,189,620
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3.2
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%
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Cordillera Fund L.P.
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800,000
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800,000
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0
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Enable Growth Partners LP(3)
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480,000
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480,000
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0
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Michael Weiss
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180,000
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|
|
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100,000
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|
|
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80,000
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|
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***
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Don Sanders
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|
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320,000
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|
|
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320,000
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|
|
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0
|
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Sanders Opportunity Fund
(Inst) LP
|
|
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493,646
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|
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493,646
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0
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Sanders Opportunity Fund LP
|
|
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154,354
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|
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154,354
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0
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Sanders 1998 Childrens Trust
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240,000
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240,000
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0
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Don Weir and Julie E. Weir
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160,000
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160,000
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0
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Ben T. Morris
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40,000
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|
|
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40,000
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0
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Fredrick Saalwachter(4)
|
|
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40,000
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|
|
|
40,000
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|
|
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0
|
|
|
|
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George L. Ball
|
|
|
40,000
|
|
|
|
40,000
|
|
|
|
0
|
|
|
|
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John Malanga and Jodi Malanga(5)
|
|
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32,000
|
|
|
|
32,000
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|
|
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0
|
|
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Bruce McMaken(6)
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|
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40,000
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|
|
|
40,000
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|
|
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0
|
|
|
|
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Mike Chadwick
|
|
|
40,000
|
|
|
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40,000
|
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0
|
|
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|
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|
TOTALS
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|
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35,743,788
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21,860,000
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13,883,788
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12.65
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%
|
57
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* |
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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. |
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** |
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The percent of class information assumes that the number of
shares outstanding includes shares issued in the public offering
that we expect to complete in the near future excluding the
underwriters over-allotment option shares, and is
therefore based upon a total of 99,462,966 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. |
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(1) |
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See footnote (c) above under the heading Principal
Shareholders. |
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(2) |
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See footnote (e) above under the heading Principal
Shareholders. |
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(3) |
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Shares of common stock beneficially owned and to be sold
includes warrants to purchase 240,000 shares of our common
stock. |
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(4) |
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Shares of common stock beneficially owned and to be sold
includes warrants to purchase 20,000 shares of our common
stock. |
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(5) |
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Shares of common stock beneficially owned and to be sold
includes warrants to purchase 16,000 shares of our common
stock. |
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(6) |
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Shares of common stock beneficially owned and to be sold
includes warrants to purchase 20,000 shares of our common
stock. |
RELATED
PARTY TRANSACTIONS
On January 31, 2005, we entered into a purchase agreement
(the Purchase Agreement) with 22 accredited
investors pursuant to which the investors purchased
7,810,000 shares of common stock and warrants to purchase
14,050,000 shares of common stock at an exercise price of
$1.75 per share for aggregate sales proceeds of $9,762,500.
The Nathan A. Low Family Trust dated 4/12/96 and Bear Stearns as
Custodian for Nathan A. Low Roth IRA, both of which are
controlled by Nathan Low, who was at that time a greater than
10% holder of our common stock, invested in us pursuant to the
Purchase Agreement. Sunrise Securities Corporation, an affiliate
of Nathan Low, received a commission equal to $976,250 and
a warrant to purchase 1,821,000 shares of our common stock
for services rendered as the placement agent in the transaction.
On January 31, 2005, we entered into an agreement with the
seven accredited investors in our April 2004 private placement
pursuant to which we were permitted to repay the $6,000,000 in
notes held by such investors without any prepayment penalties in
exchange for the exercise price of the warrants to purchase
765,000 shares of common stock issued in the April 2004
private placement being reduced from $4.00 per share to
$1.25 per share. $5,000,000 of the notes were repaid in
cash and $1,000,000 of the notes were converted into common
stock and warrants pursuant to the Purchase Agreement. Nathan
Low, who at that time was a greater than 10% holder of
Cadences common stock, and Lisa Low, Nathan Lows
wife, as Custodian for Gabriel S. Low UNYGMA were two of the
eight accredited investors involved in this transaction. In
connection with this transaction, the exercise price of the
warrants to purchase 76,500 shares of common stock held by
Nathan A. Low, who acted as a finder in the April 2004 private
placement, was also reduced to $1.25 per share.
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,
58
2005 on a lease extending through March 31, 2007. After we
moved our corporate offices in early December 2005, we no longer
had a need for the space in the South 31, L.L.C. property.
We entered into a Settlement Agreement and Mutual Release with
South 31, L.L.C. pursuant to which we made a payment to
South 31, L.L.C. in the amount of $65,250 on
January 27, 2006 and South 31, L.L.C. released us from
any further obligation on the lease.
Messrs. Deneau, Tucker and Miller, who are officers and
directors of us, 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 we also have an
interest, most of which are operated by unrelated third parties,
but some of which are operated by us. Existing affiliations
involving co-ownership of projects in which our Aurora
subsidiary is active, are itemized below.
Messrs. Deneau, Tucker and Miller own equal shares in JetX,
LLC, an exploration company that owns a 10% working interest in
the Treasure Island project. This project is operated by Samson
Resources Corporation.
Mr. Miller has an ownership interest in Miller Resources,
Inc., Miller Resources 1994-1, L.L.C., Miller Resources 1994-2,
L.L.C., and Miller Resources 1996-1, L.L.C., which own small
working interests in the Beyer project, and overriding royalty
interests in the Corner #1 project and various Alpena
County projects. Mr. Miller also has an ownership interest
in Energy Ventures, LLC, which owns a small working interest in
the Black Bean project. All of these projects are operated by
Samson Resources Corporation.
Messrs. Deneau, Tucker and Miller own Jet Exploration, Inc.
which owns a small working interest in the Beregasi well, which
is operated by West Bay Exploration.
Messrs. Deneau, Tucker and Miller own a controlling share
of Circle D, Ltd. Circle D, Ltd. owns overriding royalty
interests in several projects in which we participate, both
directly and indirectly, including projects operated by Samson
Resources Corporation and the Charlevoix, 1500 Antrim and 2000
Antrim projects, for which we serve as operator. Some of these
overriding royalty interests were assigned to Circle D, Ltd. by
Aurora, or affiliates of Aurora, within the last two years.
Circle D, Ltd. also owns a controlling interest in Northern Gas
Fields, LLC, which has entered into various agreements with
Aurora granting Aurora options to purchase specified leasehold
interests in areas operated by Samson Resources Corporation,
none of which involve material exercise prices.
Mr. Miller has an ownership interest in Miller Resources
1996-1, L.L.C., which owns overriding royalty interests in
several projects in which we participate, both directly and
indirectly, including projects operated by Samson Resources
Corporation and the Charlevoix, 1500 Antrim and 2000 Antrim
projects, for which we serve as operator. Some of these
overriding royalty interests were assigned to Miller Resources
1996-1, L.L.C. by Aurora, or affiliates of Aurora, within the
last two years.
Mr. Deneau, directly and indirectly, owns a controlling
interest in White Pine R.P., Inc., which owns overriding royalty
interests in, the Charlevoix, 1500 Antrim and 2000 Antrim
projects, all of which are operated by Aurora.
Mr. Deneau owns White Pine Land Services, Inc., which
received an assignment of overriding royalties from Aurora in
various Alpena County projects operated by Samson Resources
Corporation.
The Patricia A. Deneau Trust, DTD 10/19/95, which is controlled
by William W. Deneau, owns overriding royalty interests in
several projects for which Aurora serves as operator, including
the Charlevoix, 1500 Antrim and 2000 Antrim projects.
Kevin D. Stulp, one of our directors, owns a
331/3%
working interest in 10 wells drilled and operated by TN Oil
Company (six of which are dry). We own 650,000 shares of TN
Oil Company at a cost of $65,000, which represents approximately
a 14% equity interest in TN Oil Company.
It is probable that on occasion, we will find it necessary or
appropriate to deal with other entities in which
Messrs. Deneau, Tucker and Miller have an interest. From
time to time, we may also enter into transactions in which our
directors have an interest. Our Nominating and Corporate
Governance Committee Charter requires this Committee to review
and approve all related party transactions between the Company
and its management and directors.
On September 7, 2004, the Patricia A. Deneau Trust, DTD
10/12/95, borrowed $100,000 from our Aurora subsidiary to
purchase shares of Aurora common stock from an Aurora
shareholder. This trust is controlled by
59
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. The shares
purchased by the trust were subsequently sold by the trust to
Ms. King.
In connection with the December 2005 through February 2006
exercise of certain warrants that had previously been issued by
Cadence 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.
We believe that all of these related party transactions were
either on terms at least as favorable to us as could have been
obtained through arms-length negotiations with
unaffiliated third parties or were negotiated in connection with
acquisitions, the overall terms of which were as favorable to us
as could have been obtained through arms-length
negotiations with unaffiliated third parties. We intend to
address future material transactions with our affiliates by
having the transactions submitted for approval to a committee of
disinterested directors.
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.
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:
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|
|
ordinary brokerage transactions and transactions in which the
broker-dealer solicits purchasers;
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|
|
|
|
|
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;
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|
|
purchases by a broker-dealer as principal and resale by the
broker-dealer for its account;
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|
|
an exchange distribution in accordance with the rules of the
applicable exchange;
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|
|
privately negotiated transactions;
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|
|
|
broker-dealers may agree with the selling security holders to
sell a specified number of such shares at a stipulated price per
share;
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|
a combination of any such methods of sale; and
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|
|
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.
60
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 pledgees 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 pledgee, 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, pledgees 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 amending the list of
selling security holders to include the pledgee, 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, except with respect to the
Rubicon Master Fund, 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. We have been notified by Rubicon
Master Fund that it has entered into an underwriting agreement
for the sale of 8 million shares of common stock as a part
of our public offering described above. 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 October 10, 2006, we had
83,462,966 shares of common stock issued and outstanding
and no shares of preferred 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
61
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, 2006, there were 591 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 previously authorized the issuance of
2,500,000 shares of Class A Preferred Shares. As of the
date of this prospectus, all previously issued shares of
Class A Preferred stock have been converted to common stock.
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 LLC.
62
Securities
Authorized For Issuance Under Equity Compensation
Plans
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 814,706. Although we do not intend to
make any further awards under this plan, this plan currently
continues to exist.
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 480,000 shares of Auroras common
stock under this plan, which upon closing the merger, converted
into the right to acquire up to 960,000 shares of our
common stock. Because of the merger, no further awards can be
made under this plan.
In 2001, Auroras 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 Auroras 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 299,997 shares of Aurora
common stock under this plan, which upon closing the merger
converted to the right to acquire 599,994 shares of our
common stock. Because of the merger, no further awards can be
made under this plan.
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
August 25, 2006, we had awarded restricted stock and
options to purchase restricted stock in a total amount of
2,464,500 shares, leaving 5,535,500 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
December 31, 2005 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No. of Securities Remaining
|
|
|
|
No. of Securities to be
|
|
|
Weighted Average
|
|
|
Available for Future Issuance
|
|
|
|
Issued Upon Exercise of
|
|
|
Exercise Price of
|
|
|
Under Equity Compensation
|
|
|
|
Outstanding Options,
|
|
|
Outstanding Options,
|
|
|
Plans (Excluding Securities in
|
|
Plan Category
|
|
Warrants and Rights
|
|
|
Warrants and Rights
|
|
|
the First Column of this Table)
|
|
|
Equity compensation plans approved
by security holders
|
|
|
1,784,994
|
|
|
$
|
0.83
|
|
|
|
185,294
|
(a)
|
Equity compensation plans and
awards not approved by security holders
|
|
|
5,355,140
|
(b)
|
|
|
1.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total/combined
|
|
|
7,140,134
|
|
|
$
|
0.99
|
|
|
|
185,294
|
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Although technically still available for issuance, we do not
presently intend to issue these shares or options to issue these
shares. Instead, in March 2006, we adopted an entirely new plan
that includes 8,000,000 available shares. |
|
(b) |
|
These options and warrants to purchase shares were issued as
follows: |
|
|
|
Warrants and options to purchase 3,255,140 shares
(1,204,000 are Aurora conversion shares originally issued to
purchase 602,000 shares of Aurora common stock) were issued
to Nathan A. Low and his designees in compensation for
investment banking services rendered. |
63
|
|
|
|
|
Options to purchase 2,100,000 shares (which includes
1,800,000 Aurora conversion shares initially issued to purchase
900,000 shares of Aurora common stock) were issued in five
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
October 10, 2006, we had 83,462,966 shares of common
stock outstanding. Of this amount, 11,702,580 shares
(approximately 14% 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 other shelf registration statements that are
currently effective, which together with this registration
statement have registered almost 40 million shares of
common stock for resale. This includes approximately
2 million 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 a 2004 financing and in the financings
received by us and Aurora on January 31, 2005. We are also
in the process of selling up to 19,600,000 (including 3,600,000
for underwriters over-allotment options) new shares of
common stock in a fully underwritten public offering.
On October 10, 2006, we had options and warrants to
purchase 6,882,276 shares of common stock outstanding, and
we had still available 5,535,500 shares for issuance as
options or restricted stock under our 2006 Stock Incentive Plan.
Upon completion of the public offering, we will have outstanding
an aggregate of 99,462,966 shares of common stock, assuming
no exercise of the underwriters over-allotment option and
no exercise of outstanding options and warrants. All of the
shares sold in the public 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 994,629 shares immediately
after closing of closing of the public 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
64
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 has been passed upon for us by Fraser Trebilcock
Davis & Dunlap, P.C., Lansing, Michigan.
EXPERTS
Our consolidated financial statements for the years ended
December 31, 2005 and December 31, 2004, have been
audited by Rachlin Cohen & Holtz LLP, an independent
registered public accounting firm, as indicated in their
accompanying report. Our condensed consolidated financial
statements for the six months ended June 30, 2006 and
June 30, 2005 have been reviewed by Rachlin
Cohen & Holtz LLP, as indicated in their accompanying
report. Both of these financial statements and accompanying
reports 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, 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.
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 SECs 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.
65
FINANCIAL
STATEMENTS
|
|
|
|
|
|
|
Page
|
|
Cadence Resources Corporation (now
known as Aurora Oil & Gas Corporation) Financial Statements
for the years ended December 31, 2005 and 2004
|
|
|
|
|
|
|
|
F-2
|
|
Consolidated Financial Statements
|
|
|
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7 F-33
|
|
|
|
|
F-34 F-37
|
|
|
|
|
|
|
Aurora Oil & Gas
Corporation Condensed Consolidated Financial Statements for the
Six Months Ended June 30, 2006 and 2005
|
|
|
|
|
|
|
|
F-38
|
|
Consolidated Financial Statements
|
|
|
|
|
|
|
|
F-39
|
|
|
|
|
F-40
|
|
|
|
|
F-41
|
|
|
|
|
F-42
|
|
|
|
|
F-43 F-53
|
|
F-1
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Shareholders and Board of Directors
Cadence Resources Corporation and Subsidiaries
Traverse City, Michigan
We have audited the accompanying consolidated balance sheets of
Cadence Resources Corporation and Subsidiaries as of
December 31, 2005 and 2004 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
Companys 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 Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
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 Cadence Resources Corporation and Subsidiaries as of
December 31, 2005 and 2004 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 of America.
RACHLIN COHEN & HOLTZ LLP
Miami, Florida
February 24, 2006
F-2
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
11,980,638
|
|
|
$
|
5,179,582
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
2,409,675
|
|
|
|
1,893,051
|
|
Joint interest owners
|
|
|
4,380,606
|
|
|
|
376,856
|
|
Related parties
|
|
|
|
|
|
|
129,960
|
|
Notes receivable:
|
|
|
|
|
|
|
|
|
Related parties
|
|
|
15,000
|
|
|
|
135,096
|
|
Other
|
|
|
229,346
|
|
|
|
101,151
|
|
Prepaid expenses and other current
assets
|
|
|
240,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
19,255,507
|
|
|
|
7,815,696
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, using full
cost accounting:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
39,643,003
|
|
|
|
7,585,807
|
|
Unproved properties
|
|
|
37,279,889
|
|
|
|
7,981,727
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties
|
|
|
76,922,892
|
|
|
|
15,567,534
|
|
Less accumulated depletion and
amortization
|
|
|
7,962,138
|
|
|
|
600,077
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, net
|
|
|
68,960,754
|
|
|
|
14,967,457
|
|
|
|
|
|
|
|
|
|
|
Other assets:
|
|
|
|
|
|
|
|
|
Deposit on purchase of oil and gas
properties
|
|
|
3,206,102
|
|
|
|
|
|
Property and equipment, net
|
|
|
3,610,138
|
|
|
|
115,283
|
|
Goodwill
|
|
|
15,973,346
|
|
|
|
|
|
Intangibles, net
|
|
|
3,197,917
|
|
|
|
|
|
Other investments
|
|
|
1,855,977
|
|
|
|
230,396
|
|
Other assets
|
|
|
762,404
|
|
|
|
316,997
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
28,605,884
|
|
|
|
662,676
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
116,822,145
|
|
|
$
|
23,445,829
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
SHAREHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
7,053,288
|
|
|
$
|
3,221,533
|
|
Accrued expenses
|
|
|
417,291
|
|
|
|
200,800
|
|
Drilling advances
|
|
|
|
|
|
|
387,175
|
|
Short-term bank borrowings
|
|
|
6,210,000
|
|
|
|
350,000
|
|
Current portion of obligations
under capital leases
|
|
|
8,823
|
|
|
|
8,823
|
|
Current portion of note
payable related party
|
|
|
69,833
|
|
|
|
1,940,825
|
|
Current portion of mortgage payable
|
|
|
72,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
13,832,112
|
|
|
|
6,109,156
|
|
|
|
|
|
|
|
|
|
|
Deposit on sale of oil and gas
properties
|
|
|
3,509,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
Obligations under capital leases,
net of current portion
|
|
|
2,262
|
|
|
|
12,663
|
|
Notes payable related
parties
|
|
|
|
|
|
|
1,077,706
|
|
Mortgage payable
|
|
|
2,792,600
|
|
|
|
|
|
Mezzanine financing
|
|
|
40,000,000
|
|
|
|
10,000,000
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
42,794,862
|
|
|
|
11,090,369
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
60,136,293
|
|
|
|
17,199,525
|
|
|
|
|
|
|
|
|
|
|
Redeemable convertible preferred
stock
|
|
|
59,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments, contingencies and
subsequent events
|
|
|
|
|
|
|
|
|
Shareholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $1.50 par
value; authorized 500,000 shares; issued and outstanding
none in 2005 and 99,350 shares in 2004
|
|
|
|
|
|
|
149,025
|
|
Common stock, $.01 par value;
authorized 100,000,000 shares; issued and outstanding
61,536,261 shares in 2005 and 13,775,933 shares in 2004
|
|
|
615,363
|
|
|
|
13,776
|
|
Additional paid-in capital
|
|
|
58,670,698
|
|
|
|
8,183,025
|
|
Accumulated deficit
|
|
|
(2,660,134
|
)
|
|
|
(2,099,522
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
56,625,927
|
|
|
|
6,246,304
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
shareholders equity
|
|
$
|
116,822,145
|
|
|
$
|
23,445,829
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
Interest income
|
|
|
243,013
|
|
|
|
47,678
|
|
Equity in loss of unconsolidated
subsidiaries
|
|
|
(75,596
|
)
|
|
|
|
|
Other income
|
|
|
452,621
|
|
|
|
1,192,835
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
7,363,482
|
|
|
|
2,200,524
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
3,435,507
|
|
|
|
2,057,333
|
|
Production and lease operating
|
|
|
2,047,028
|
|
|
|
614,338
|
|
Depletion, depreciation and
amortization
|
|
|
1,155,254
|
|
|
|
203,249
|
|
Interest
|
|
|
1,228,274
|
|
|
|
392,402
|
|
Taxes
|
|
|
29,651
|
|
|
|
75,000
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
7,895,714
|
|
|
|
3,342,322
|
|
|
|
|
|
|
|
|
|
|
Loss before minority interest
|
|
|
(532,232
|
)
|
|
|
(1,141,798
|
)
|
Minority interest in loss of
subsidiaries
|
|
|
15,960
|
|
|
|
38,087
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(516,272
|
)
|
|
|
(1,103,711
|
)
|
Less dividends on preferred stock
|
|
|
|
|
|
|
(30,268
|
)
|
|
|
|
|
|
|
|
|
|
Loss attributable to common
shareholders
|
|
$
|
(516,272
|
)
|
|
$
|
(1,133,979
|
)
|
|
|
|
|
|
|
|
|
|
Net loss per common
share basic and diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding basic and diluted
|
|
|
40,622,000
|
|
|
|
23,636,000
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Total
|
|
|
|
Preferred Stock
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Accumulated
|
|
|
Shareholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Deficit
|
|
|
Equity
|
|
|
Balances at January 1, 2004
|
|
|
410,461
|
|
|
$
|
615,692
|
|
|
|
11,432,824
|
|
|
$
|
11,433
|
|
|
$
|
4,745,222
|
|
|
$
|
(868,699
|
)
|
|
$
|
4,503,648
|
|
Issuance of common stock for
consulting services
|
|
|
|
|
|
|
|
|
|
|
54,776
|
|
|
|
55
|
|
|
|
53,424
|
|
|
|
|
|
|
|
53,479
|
|
Sale of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issued in private placement
|
|
|
|
|
|
|
|
|
|
|
600,000
|
|
|
|
600
|
|
|
|
1,499,400
|
|
|
|
|
|
|
|
1,500,000
|
|
Issued to Cadence Resource
Corporation
|
|
|
|
|
|
|
|
|
|
|
300,000
|
|
|
|
300
|
|
|
|
749,700
|
|
|
|
|
|
|
|
750,000
|
|
Issued to others
|
|
|
|
|
|
|
|
|
|
|
145,000
|
|
|
|
145
|
|
|
|
362,355
|
|
|
|
|
|
|
|
362,500
|
|
Exercise of common stock options
|
|
|
|
|
|
|
|
|
|
|
310,000
|
|
|
|
310
|
|
|
|
307,190
|
|
|
|
|
|
|
|
307,500
|
|
Conversion of preferred stock to
common stock
|
|
|
(311,111
|
)
|
|
|
(466,667
|
)
|
|
|
933,333
|
|
|
|
933
|
|
|
|
465,734
|
|
|
|
|
|
|
|
|
|
Dividends paid on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(127,112
|
)
|
|
|
(127,112
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,103,711
|
)
|
|
|
(1,103,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2004
|
|
|
99,350
|
|
|
|
149,025
|
|
|
|
13,775,933
|
|
|
|
13,776
|
|
|
|
8,183,025
|
|
|
|
(2,099,522
|
)
|
|
|
6,246,304
|
|
Conversion of preferred stock to
common stock
|
|
|
(99,350
|
)
|
|
|
(149,025
|
)
|
|
|
298,050
|
|
|
|
298
|
|
|
|
148,727
|
|
|
|
|
|
|
|
|
|
Dividends paid on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,340
|
)
|
|
|
(44,340
|
)
|
Sale of common stock, net of
commissions and fees
|
|
|
|
|
|
|
|
|
|
|
4,972,200
|
|
|
|
4,972
|
|
|
|
11,020,028
|
|
|
|
|
|
|
|
11,025,000
|
|
Exercise of options prior to merger
|
|
|
|
|
|
|
|
|
|
|
10,000
|
|
|
|
10
|
|
|
|
7,490
|
|
|
|
|
|
|
|
7,500
|
|
Merger between Cadence and Aurora
|
|
|
|
|
|
|
|
|
|
|
39,592,510
|
|
|
|
567,431
|
|
|
|
35,706,179
|
|
|
|
|
|
|
|
36,273,610
|
|
Cashless exercise of options and
warrants
|
|
|
|
|
|
|
|
|
|
|
245,068
|
|
|
|
2,451
|
|
|
|
(2,451
|
)
|
|
|
|
|
|
|
|
|
Exercise of common stock options
and warrants
|
|
|
|
|
|
|
|
|
|
|
2,642,500
|
|
|
|
26,425
|
|
|
|
3,607,700
|
|
|
|
|
|
|
|
3,634,125
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(516,272
|
)
|
|
|
(516,272
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2005
|
|
|
|
|
|
$
|
|
|
|
|
61,536,261
|
|
|
$
|
615,363
|
|
|
$
|
58,670,698
|
|
|
$
|
(2,660,134
|
)
|
|
$
|
56,625,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(516,272
|
)
|
|
$
|
(1,103,711
|
)
|
Adjustments to reconcile net loss
to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
Depletion, depreciation and
amortization
|
|
|
1,155,254
|
|
|
|
203,249
|
|
Equity in loss of non-consolidated
investees
|
|
|
75,596
|
|
|
|
|
|
Unrealized loss on investments
|
|
|
31,237
|
|
|
|
|
|
Loss on disposal of property and
equipment
|
|
|
25,499
|
|
|
|
|
|
Services received in settlement of
note receivable
|
|
|
|
|
|
|
39,754
|
|
Common stock issued for services
|
|
|
|
|
|
|
53,479
|
|
Minority interest in loss of
subsidiaries
|
|
|
(15,960
|
)
|
|
|
(38,087
|
)
|
Changes in operating assets and
liabilities, net of effect of merger:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(3,957,497
|
)
|
|
|
(1,365,271
|
)
|
Accounts receivable
related parties
|
|
|
129,960
|
|
|
|
7,854
|
|
Prepaid expenses
|
|
|
41,634
|
|
|
|
76,110
|
|
Accounts payable
|
|
|
2,790,037
|
|
|
|
1,939,965
|
|
Drilling advances
|
|
|
(387,175
|
)
|
|
|
352,320
|
|
Accrued expenses
|
|
|
216,491
|
|
|
|
52,779
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by
operating activities
|
|
|
(411,196
|
)
|
|
|
218,441
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
Proceeds from sale of oil and gas
properties
|
|
|
7,995,109
|
|
|
|
1,902,537
|
|
Proceeds from sale of property and
equipment
|
|
|
23,693
|
|
|
|
|
|
Capital expenditures for oil and
gas development
|
|
|
(46,145,082
|
)
|
|
|
(10,159,663
|
)
|
Capital expenditures for property
and equipment
|
|
|
(3,594,750
|
)
|
|
|
(74,166
|
)
|
Advances of notes receivable
|
|
|
(107,475
|
)
|
|
|
(155,096
|
)
|
Payments on notes receivable,
related parties
|
|
|
120,096
|
|
|
|
|
|
Deposits made for the purchase of
oil and gas properties
|
|
|
(3,206,102
|
)
|
|
|
|
|
Deposits received for the sale of
oil and gas properties
|
|
|
3,509,319
|
|
|
|
|
|
Investment in Hudson Pipeline
|
|
|
(928,956
|
)
|
|
|
(230,396
|
)
|
Investment in GeoPetra
|
|
|
(485,741
|
)
|
|
|
|
|
Net cash acquired in merger
|
|
|
957,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(41,862,869
|
)
|
|
|
(8,716,784
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
Net short-term bank borrowings
|
|
|
5,860,000
|
|
|
|
350,000
|
|
Advances from mezzanine financing,
net of financing costs of approximately $500,000 in 2005
|
|
|
29,491,458
|
|
|
|
10,179,694
|
|
Mortgage financing advances
|
|
|
2,865,477
|
|
|
|
|
|
Payments on capital lease
obligations
|
|
|
(10,401
|
)
|
|
|
(128,278
|
)
|
Distributions to minority interest
members
|
|
|
(805,000
|
)
|
|
|
(41,347
|
)
|
Net proceeds from sales of common
stock
|
|
|
14,666,625
|
|
|
|
2,920,000
|
|
Dividends paid
|
|
|
(44,340
|
)
|
|
|
|
|
Net proceeds from subsidiary
disposition
|
|
|
|
|
|
|
10,467
|
|
Repayment of debt to related parties
|
|
|
(2,948,698
|
)
|
|
|
(504,546
|
)
|
Payments on notes
payable other
|
|
|
|
|
|
|
(307,935
|
)
|
Advances from related parties
|
|
|
|
|
|
|
154,118
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
49,075,121
|
|
|
|
12,632,173
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash
equivalents
|
|
|
6,801,056
|
|
|
|
4,133,830
|
|
Cash and cash equivalents,
beginning of year
|
|
|
5,179,582
|
|
|
|
1,045,752
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of
year
|
|
$
|
11,980,638
|
|
|
$
|
5,179,582
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
Years Ended December 31, 2005 and 2004
|
|
NOTE 1.
|
BUSINESS
AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
Nature
of Business
Cadence Resources Corporation is an independent oil and gas
exploration company engaged in the exploration, acquisition,
development, production and sale of natural gas. We generate
most of our revenues from the production and sale of natural
gas. While we do have some non-operated interest in oil wells,
nearly 100% of our proved reserves consist of natural gas from
our position in the Antrim Shale in Michigan. Additionally, we
have a substantial leasehold position in the New Albany Shale in
Indiana.
Our current operations consist primarily of the drilling for and
production of natural gas. The results of operations are
determined by the difference between the natural gas price
received for the gas produced, less the cost to drill, develop
and produce the gas. Natural gas prices are subject to
fluctuations in response to many factors such as quantities in
gas storage, level of consumer demand and the worldwide
political climate as well as the impact of certain weather
related disasters.
Principles
of Consolidation
The accompanying consolidated financial statements include the
accounts of Cadence Resources Corporation and the
entities identified below under the heading Organization and
Nature of Operations, hereinafter referred to as the
Company or Cadence.
All significant intercompany accounts and transactions have been
eliminated in consolidation.
As further described in Note 2, on October 31, 2005,
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.
While Cadence was the legal acquirer, the merger was accounted
for as a reverse acquisition, whereby Aurora was deemed to have
acquired Cadence for financial reporting purposes. This
determination was based on factors including relative stock
ownership and voting rights, board control, and senior
management composition. Consistent with the reverse acquisition
accounting treatment, 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 and related notes have been retroactively
adjusted to give effect to the reverse acquisition on
October 31, 2005 for all periods presented.
Organization
and Nature of Operations
The nature and composition of the Companys operations are
as follows:
Cadence Resources Corporation (formerly Royal Silver
Mines, Inc.) hereinafter (Cadence or
the Company) was incorporated in April 1969
under the laws of the State of Utah primarily for the purpose of
acquiring and developing mineral properties. The Company changed
its name from Royal Silver Mines, Inc. to Cadence Resources
Corporation on May 2, 2001.
Previously, the Company had presented its financial statements
on a September 30 fiscal year-end. Subsequent to the
closing of the merger with Aurora, the Company changed its
fiscal year-end to December 31, in order to conform with
the fiscal year-end of Aurora.
F-7
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cadence Resource Corporations subsidiaries operations as a
result of its merger with Aurora are as follows:
Aurora Energy, Ltd. (Aurora) is a Nevada
corporation, engaged primarily in the acquisition, development,
production, exploration and sale of oil, gas and natural gas
liquids. Aurora sells its oil and gas products primarily to
domestic pipelines and refineries.
Aurora Operating, LLC (Operating) is a
limited liability company, engaged primarily in oil and gas
operations and development. Operating was formed on
January 1, 2000 and its term of existence extends through
January 1, 2020. Operating holds certain oil and gas
properties in the New Albany Shale Project. Aurora owned a 71%
member interest in this entity. In December 2003, Aurora entered
into an agreement to sell 20% of its member interest in
Operating to an unrelated third party. This sale changed
Auroras ownership in Operating from 71% to 51%.
Restrictions related to this sale specify that the purchaser is
not entitled to receive any cash distributions nor are they
required to make any capital contributions within two years from
the closing date (December 9, 2003). The agreement also
includes put and call options at the same price that the 20% was
initially sold for. The call option allows Aurora to purchase
this interest back between December 10, 2005 and
December 9, 2008. The put option allows the purchaser to
sell their interest back to Aurora during the same time frame.
The Company has subsequently purchased this interest back on
January 31, 2006. See Subsequent Events, Note 26.
Aurora Antrim North, LLC (North) is a limited
liability company engaged primarily in any activity with the
purpose for which the LLC may be formed. North was formed on
January 18, 2001 and its term of existence extends through
January 18, 2021. Aurora holds a 100% interest in North. In
2003, certain oil and gas properties were conveyed from Aurora
to North in connection with mezzanine financing with Wells
Fargo. This financing facility was paid in full and terminated
during 2004, and Aurora entered into a new mezzanine financing
arrangement, which is more fully described in Note 12.
Aurora Holdings, LLC (Holdings) is a limited
liability company engaged primarily in any activity with the
purpose for which the LLC may be formed. Holdings was formed on
January 10, 2001 and its term of existence extends
through January 10, 2021. Aurora holds a 100% interest in
Holdings. Operations for Holdings for the period from inception
to December 31, 2005 were insignificant.
Indiana Royalty Trustory, LLC (IRT) is a
limited liability company engaged primarily in investments in
royalties and other financial instruments. IRT was formed on
January 1, 2001 and its term of existence extends through
January 1, 2021. The Company holds a 51% interest in IRT.
Operations for IRT during 2005 and 2004 were insignificant.
Aurora Investments, LLC (AIL) is a limited
liability company formed in October 2001 to raise funds
specifically earmarked for drilling of certain defined oil and
gas prospects. Under the terms outlined in the private placement
memorandum dated October 1, 2001, third party investors
contributed 95% of the funds needed to drill a specific project
and Aurora contributed 5% in the form of oil and gas properties.
As manager of AIL, Aurora made key decisions relating to
AILs operations and was conveyed an additional 12.5%
interest in AIL for a total membership interest of 17.5%. Once
all third party investor members received 100% of their initial
investment back, Aurora is to receive an additional 12.5%
interest for a total member interest of 30%. AIL was
consolidated into Aurora due to the control that Aurora
exercised over the operations of AIL. During 2004, Aurora
exchanged its 17.5% membership interests in AIL in exchange for
certain working interests, which resulted in the removal of AIL
from the consolidated financial statements as of
December 31, 2004. While the agreement covering a potential
12.5% additional interest is still in effect, management
believes the likelihood of receiving this additional interest is
remote.
F-8
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Beyer Antrim Company, LLC (BAC) is a limited
liability company formed in May 2002 to raise funds specifically
earmarked for drilling of certain defined oil and gas prospects.
Under the terms outlined in the private placement memorandum
dated April 20, 2002, third party investors contributed 95%
of the funds needed to drill a specific project and Aurora
contributed 5% in the form of oil and gas properties.
As manager of BAC, Aurora makes key decisions relating to
BACs operations and was conveyed an additional 12.5%
interest in BAC for a total membership interest of 17.5%. Once
all third party investor members received 100% of their initial
investment back, Aurora is to receive an additional 12.5%
interest for a total member interest of 30%. BAC was
consolidated into Aurora due to the control that Aurora
exercised over the operations of BAC. During 2004, Aurora
exchanged its 17.5% membership interests in BAC in exchange for
certain working interests, which resulted in the removal of BAC
from the consolidated financial statements as of
December 31, 2004. While the agreement covering a potential
12.5% additional interest is still in effect, management
believes the likelihood of receiving this additional interest is
remote.
Aurora Natural Gas Production, LLC (ANG) is a
limited liability company formed in June 2002 to raise funds
specifically earmarked for drilling of certain defined oil and
gas prospects. Under the terms outlined in the private placement
memorandum dated May 15, 2002, third party investors
contributed 95% of the funds needed to drill a specific project
and Aurora contributed 5% in the form of oil and gas properties.
As manager of ANG, Aurora made key decisions relating to
ANGs operations and was conveyed an additional 12.5%
interest in ANG for a total membership interest of 17.5%. Once
all third party investor members received 100% of their initial
investment back, Aurora is to receive an additional 12.5%
interest for a total member interest of 30%. ANG was
consolidated into Aurora due to the control that Aurora
exercised over the operations of ANG. During 2004, Aurora
exchanged its 17.5% membership interests in ANG in exchange for
certain working interests, which resulted in the removal of ANG
from the consolidated financial statements as of
December 31, 2004. While the agreement covering a potential
12.5% additional interest is still in effect, management
believes the likelihood of receiving this additional interest is
remote.
BFG Holdings, LLC (BFG) is a limited
liability company engaged primarily in any activity with the
purpose for which the LLC may be formed. BFG was formed on
September 18, 2002 and Aurora holds a 100% interest in BFG.
In 2003, certain oil and gas properties were conveyed from
Aurora to BFG in connection with the reserve base financing with
Texas Capital Bank, N.A. This financing vehicle has been paid in
full and terminated during 2004. These properties were
transferred to BFG at their net book value on the date of
transfer. During 2004, BFG was closed and transferred all oil
and gas properties to North at their net book value. All
operations of BFG have ceased as of December 31, 2004.
Consolidated Exploration, LLC (Conexco) is a
limited liability company engaged primarily in the acquisition,
development and sale of oil and gas leasehold interests. Conexco
owns certain leasehold interests in Indianas New Albany
Shale area, including an overriding royalty in the producing
Corydon fields.
Conexco was formed on April 4, 1994 and its term of
existence extends through April 4, 2014. On January 1,
1999, Aurora purchased a 100% interest in Conexco and this
entity became a wholly-owned subsidiary.
Indigas Energy, LLC (Indigas) is a limited
liability company engaged primarily in the acquisition,
development, production and sale of oil and gas leasehold
interests. Indigas owns certain leasehold interests in Indiana
and Kentuckys New Albany Shale area. Indigas was formed on
January 1, 1996 and its term of existence extends through
January 1, 2016. On January 1, 1999, Aurora purchased
a 100% interest in Indigas and this entity became a wholly-owned
subsidiary.
F-9
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Both Conexco and Indigas received certain proceeds from the
signing of an option agreement (the Option) related
to their leasehold interests. These proceeds were used to return
to investors their original investment plus the agreed-upon
return percentage. With all of the lease investors monies
returned, operations of both entities ceased as of
December 31, 2003. These entities continue to hold certain
overriding royalty interests in the undeveloped leases sold
under the agreement described above. Any future revenues that
may result from drilling on these leases from these overriding
royalty interests will be assigned directly to Aurora Energy,
Ltd.
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. We believe
our estimates and assumptions are reasonable; however, such
estimates and assumptions are subject to a number of risks and
uncertainties that may cause actual results to differ materially
from such estimates. Significant estimates underlying these
financial statements include:
|
|
|
|
|
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,
|
|
|
|
accruals related to oil and gas revenues and lease operating
expenses, and
|
|
|
|
estimates used in computation of our federal and state income
tax liabilities.
|
While we are not aware of any material revision to any of our
estimates, there will likely be future revisions to our
estimates as a result of changes in our joint venture
agreements, working interest ownership, payouts, and
reallocations by purchasers. These types of adjustments are not
currently predictable and will be recorded in the period they
occur.
Oil
and Gas Properties
Aurora uses the full cost method of accounting for oil and gas
properties. Prior to the merger, Cadence used the successful
efforts method of accounting; however, in connection with the
merger, Cadence adopted the full cost method in order to conform
with Auroras accounting principles. The adoption of the
full cost method by Cadence resulted in a net increase to oil
and gas properties of $774,912.
Under the full cost method, all costs associated with
acquisition, exploration and development of oil and gas
reserves, including directly related overhead costs, are
capitalized. Costs associated with production and general
corporate activities are expensed in the period incurred.
All capitalized costs of oil and gas properties, including the
estimated future costs to develop proven reserves, are amortized
on the
unit-of-production
method using estimates of proven reserves. Investments in
unproven properties and major development projects are not
amortized until proven reserves associated with the projects can
be determined or until impairment occurs. If the results of an
assessment indicate that the properties are impaired, the amount
of the impairment is added to the capitalized costs to be
amortized.
Capitalized costs of oil and gas properties, net of accumulated
amortization, are limited to the aggregate of estimated future
net revenues from proven reserves, discounted at ten percent,
based on current economic and operating conditions, plus the
lower of cost or fair value of unproven properties. Sales of
proven and unproven properties are applied to reduce the
capitalized costs with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between
capitalized costs and proven reserves of oil and gas, in which
case the gain or loss is recognized in income. Abandonment of
properties is accounted for as adjustments of capitalized costs
with no loss recognized.
F-10
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Full
Cost Ceiling Test
At the end of each reporting period, the unamortized cost of oil
and gas properties is limited to the sum of the estimated future
net revenues from proved properties (including future
development and abandonment costs of wells to be drilled, using
period-end prices, discounted at 10%, and the lower of cost or
fair value of unproved properties) adjusted for related income
tax effects (Ceiling Test).
The calculation of the Ceiling Test and provision for
depreciation and amortization is based on estimates of proved
reserves. There are numerous uncertainties inherent in
estimating quantities of proved reserves and in projecting the
future rates of production, timing, and plan of development. The
accuracy of any reserves estimate is a function of the quality
of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify
revision of such estimates. Accordingly, reserves estimates are
often different from the quantities of oil and gas that are
ultimately recovered. Our reserves estimates are prepared in
accordance with Securities and Exchange Commission guidelines
and, are reviewed on an annual basis at year-end by a firm of
independent petroleum engineers in accordance with standards
approved by the Board of Directors of the Society of Petroleum
Engineers.
Given the volatility of oil and gas prices, it is reasonably
possible that our estimate of discounted future net cash flows
from proved oil and gas reserves could change in the near term.
If oil and gas prices decline from our period-end prices used in
the Ceiling Test, even if only for a short period, it is
possible that non-cash write-downs of oil and gas properties
could occur in the future.
Capitalized
Interest
The Company capitalizes interest on debt related to expenditures
made in connection with exploration and development projects
that are not subject to current amortization. Interest is
capitalized only for the period that activities are in progress
to bring these projects to their intended use. Interest
capitalized amounted to $1,146,084 and $329,028 during 2005 and
2004, respectively.
Other
Mineral Properties
Costs of acquiring, exploring and developing mineral properties
are capitalized by project area. Costs to maintain the mineral
rights and leases are expensed as incurred. When a property
reaches the production stage, the related capitalized costs will
be amortized, using the units of production method on the basis
of periodic estimates of ore reserves. The cost of the
Companys mineral properties are included in other
investments in the accompanying financial statements, as the
Company has changed its focus from minerals exploration to oil
and gas exploration.
Derivative
Instruments
The Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 133,
Accounting for Derivative Instruments and Hedging
Activities, as amended by SFAS No. 137,
Accounting for Derivative Instruments and Hedging
Activities Deferral of the Effective Date of FASB
No. 133, and SFAS No. 138, Accounting
for Certain Derivative Instruments and Certain Hedging
Activities and SFAS No. 149, Amendment of
Statement No. 133 on Derivative Instruments and Hedging
Activities. These standards establish accounting and
reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and
for hedging activities. They require that an entity recognize
all derivatives as either assets or liabilities in the balance
sheet and measure those instruments at fair value. If certain
conditions are met, a derivative may be specifically designated
as a hedge, the objective of which is to match the timing of
gain or loss recognition on the hedging derivative with the
recognition of (i) the changes in the fair value of the
hedged asset or liability that are attributable to the hedged
risk or (ii) the earnings effect of the hedged forecasted
transaction.
F-11
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For a derivative not designated as a hedging instrument, the
gain or loss is recognized in income in the period of change.
Historically, the Company has not entered into derivatives
contracts to hedge existing risks or for speculative purposes.
At December 31, 2005 and for the periods covered in the
accompanying financial statements, the Company has not engaged
in any transactions that would be considered derivative
instruments or hedging activities.
Cash
and Cash Equivalents
The Company considers all highly liquid investments with an
initial maturity of three months or less to be cash equivalents.
Deferred
Loan Origination Costs
Loan origination costs related to mezzanine financing obtained
in late 2004 and also in 2005, as more fully described in
Note 12, are deferred and are included in other assets.
These costs are being amortized using the interest method over
the term of the related loan. Annual amortization expense during
2006 to 2009 will be approximately $160,000.
Environmental
Remediation and Compliance
Expenditures for ongoing compliance with environmental
regulations that relate to current operations are expensed or
capitalized as appropriate. Expenditures resulting from the
remediation of existing conditions caused by past operations
that do not contribute to future revenue generations are
expensed. Liabilities are recognized when environmental
assessments indicate that remediation efforts are probable and
the costs can be reasonably estimated.
Estimates of such liabilities are based upon currently available
facts, existing technology and presently enacted laws and
regulations taking into consideration the likely effects of
inflation and other societal and economic factors, and include
estimates of associated legal costs. These amounts also reflect
prior experience in remediating contaminated sites, other
companies
clean-up
experience and data released by The Environmental Protection
Agency or other organizations. Such estimates are by their
nature imprecise and can be expected to be revised over time
because of changes in government regulations, operations,
technology and inflation. Recoveries are evaluated separately
from the liability and, when recovery is assured the Company
records and reports an asset separately from the associated
liability. At December 31, 2005 and 2004, the Company had
no accrued liabilities for compliance with environmental
regulations.
Investments
in Unconsolidated 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. Under
the equity method of accounting, the Companys
proportionate share of the investees net income or loss is
included in the results of operations as equity in income or
loss of unconsolidated subsidiaries.
Revenue
Recognition
Oil and gas sales are generally recognized at the time of
extraction of product or performance of services. Revenues from
service contracts are recognized ratably over the term of the
contract.
Accounts
Receivable
Accounts receivable generally consist of amounts due from the
sale of oil and gas products and from working interest partners
for their proportionate share of expenses related to certain oil
and gas projects. Accounts receivable
F-12
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
may also include certain costs that are incurred on behalf of
joint partners which are billed subsequent to the end of the
reporting period.
The Company assesses the collectibility of accounts receivable
and, based on managements assessment of the current status
of individual accounts, the Company accrues a reserve when it is
believed that a receivable may not be collected. Losses on
collection of accounts receivable have not been material and,
accordingly, no allowance for doubtful accounts was considered
necessary in the accompanying financial statements.
Fair
Value of Financial Instruments
The Companys financial instruments consist primarily of
cash, accounts receivable, loans receivable, accounts payable
and 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. The estimated fair
value is not necessarily indicative of the amounts the Company
would realize in a current market exchange or from future
earnings or cash flows.
Property
and Equipment
Property and equipment are stated at cost. Major improvements
and renewals are capitalized while ordinary maintenance and
repairs are expensed. Management annually reviews these assets
to determine whether carrying values have been impaired.
Depreciation, which includes amortization of assets recorded as
capital leases, is computed using the straight-line method over
the estimated useful lives of the related assets, which range
from 5 to 20 years or lease term, if shorter.
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 discount rate reflecting the Companys average cost
of funds. Future impairment of goodwill could result if the
Companys estimated future operating cash flows are not
achieved. The carrying value of goodwill at December 31,
2005 was approximately $15,973,000. No impairment loss was
recorded for the year ended December 31, 2005.
Intangible
Assets
Acquired intangible assets, which consist of non-compete
agreements and proprietary business relationships, are recorded
at fair value. These intangible assets are amortized on a
straight-line basis over a three year period. Amortization
expense is estimated to be approximately $1,535,000 per
year through 2007.
Income
Taxes
Income taxes are provided based upon the liability method of
accounting pursuant to Statement of Financial Accounting
Standards No. 109, Accounting for Income
Taxes (SFAS No. 109). Under this
approach, deferred income taxes are recorded to reflect the tax
consequences in future years of differences between the tax
basis of assets and liabilities and their financial reporting
amounts at each year-end.
Deferred income tax assets and liabilities are computed annually
for differences between the consolidated financial statements
and federal income tax bases of assets and liabilities that will
result in taxable or deductible
F-13
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
amounts in the future, based on enacted tax laws and rates
applicable to the periods in which the differences are expected
to affect taxable income. Deferred income taxes arise from
temporary basis differences principally related to intangible
drilling costs incurred in connection with the development of
oil and gas properties, depreciation and net operating losses.
Valuation allowances are established when necessary to reduce
deferred tax assets to the amount expected to be realized.
Income tax expense is the tax payable or refundable for the year
plus or minus the change during the year in deferred tax assets
and liabilities.
Concentrations
of Credit Risk
Financial instruments that potentially subject the Company to
concentrations of credit risk are cash and cash equivalents and
accounts receivable.
Cash
and Cash Equivalents
The Companys bank accounts periodically exceed federally
insured limits. As of December 31, 2005 and 2004, cash in
excess of FDIC limits amounted to approximately $12,310,000 and
$1,055,000 respectively. The Company maintains its deposits with
high quality financial institutions and, accordingly, believes
that the Company is not exposed to any significant credit risk
on its cash deposits.
Accounts
Receivable
We extend credit, primarily in the form of uncollateralized oil
and gas sales and joint interest owners receivables, to
various companies in the oil and 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 our industry and may accordingly impact our overall
credit risk. However, we believe that the risk of these
unsecured receivables is mitigated by the size, reputation, and
nature of the companies to which we extend credit. During 2005,
oil and gas sales to one customer, CIMA Energy, Ltd., were
approximately 63% of total oil and gas sales.
Minority
Interest
The minority interest at December 31, 2005 and 2004 is
insignificant and is included in other asset in the accompanying
consolidated balance sheets. The balance represents the minority
members share of contributed capital, income or loss and
distributions.
Reclassifications
Certain amounts in the prior year financial statements have been
reclassified to conform to current year presentations.
Recent
Accounting Pronouncements
In November 2005, the FASB issued Staff Position
No. FAS 115-1,
The Meaning of
Other-Than-Temporary
Impairment and its Application to Certain Investments
(FSP 115-1). FSP 115-1 provides accounting guidance
for determining and measuring
other-than-temporary
impairments of debt and equity securities, and confirms the
disclosure requirements for investments in unrealized loss
positions as outlined in EITF
issue 03-01,
The Meaning of
Other-Than-Temporary
Impairments and its Application to Certain Investments. The
accounting requirements of FSP 115-1 are effective for us on
January 1, 2006 and will not have a material impact
on our consolidated financial position, results of operations or
cash flows.
In May 2005, the FASB issued SFAS No. 154,
Accounting for Changes and Error Corrections, a
Replacement of APB Opinion No. 20 and FASB Statement
No. 3 SFAS 154 applies to all voluntary
changes
F-14
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
in accounting principle and requires retrospective application
to prior periods financial statements of changes in
accounting principle. This statement also requires that a change
in depreciation, amortization, or depletion method for
long-lived, non-financial assets be accounted for as a change in
accounting estimate affected by a change in accounting
principle. SFAS 154 carries forward without change the
guidance contained in Opinion No. 20 for reporting the
correction of an error in previously issued financial statements
and a change in accounting estimate. This statement is effective
for accounting changes and corrections of errors made in fiscal
years beginning after December 15, 2005. The Company does
not expect the adoption of this standard to have a material
impact on its financial condition, results of operations, or
liquidity.
In March 2005, the Financial Accounting Standards Board issued
FASB Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations, an Interpretation of
FASB Statement No. 143. This Interpretation
clarifies that the term conditional asset retirement obligation
refers to a legal obligation to perform an asset retirement
activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the
control of the entity. 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. This Interpretation is effective no later than the
end of fiscal years ending after December 15, 2005. The
Company does not expect the adoption of this standard to have a
material impact on its financial condition, results of
operations, or liquidity.
In December 2004, the FASB issued SFAS No. 153,
Exchanges of Non-monetary Assets, an Amendment of APB
Opinion No. 29. SFAS No. 153 requires
exchanges of productive assets to be accounted for at fair
value, rather than at carryover basis, unless (1) neither
the asset received nor the asset surrendered has a fair value
that is determinable within reasonable limits or (2) the
transactions lack commercial substance. This Statement is
effective for non-monetary asset exchanges occurring in fiscal
periods beginning after June 15, 2005. The Company does not
expect the adoption of this standard to have a material impact
on its financial condition, results of operations, or liquidity.
In December 2004, the FASB issued SFAS No. 123
(revised 2004), Share-Based Payment.
SFAS No. 123(R) is a revision of
SFAS No. 123, Accounting for Stock-Based
Compensation, and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees.
Statement No. 123(R) will require the fair value of all
stock based awards issued to employees to be recorded as an
expense over the related vesting period. The statement also
requires the recognition of compensation expense for the fair
value of any unvested stock based awards outstanding at the date
of adoption. This statement becomes effective the beginning of
the first interim or annual reporting period that begins after
December 15, 2005. The Company is currently evaluating the
impact on its results from adopting SFAS No. 123(R).
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NOTE 2.
|
MERGER
WITH AURORA ENERGY, LTD.
|
On October 31, 2005, Cadence Resources Corporation
(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. Although the merger was
structured such that Aurora became a wholly-owned subsidiary of
Cadence, 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) Auroras 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) Auroras senior management prior to the merger
dominated the senior management of the combined company. As a
result of the reverse acquisition, the statements of operations
presented herein include the results of Aurora for the year
ended December 31, 2005 and include the results of Cadence
for the period from date of acquisition (November 1, 2005
through December 31, 2005). The financial information
reflected in the financial statements for 2004 are comprised of
the accounts and activities of Aurora.
F-15
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
assigned to this transaction is equal to $41,546,351 determined
as follows:
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Fair value of Cadences
common stock outstanding at January 31, 2005
|
|
$
|
33,951,817
|
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Fair value of Cadences stock
options outstanding at January 31, 2005
|
|
|
536,210
|
|
Fair value of Cadences
warrants outstanding at January 31, 2005
|
|
|
7,058,324
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
41,546,351
|
|
|
|
|
|
|
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 historical balance
sheet of Cadence was adjusted to the purchase price of
$41,546,351 with amounts in excess of historical book value
allocated among the following categories: (1) unproved oil
and gas properties and property and equipment, (2) other
investments, (3) intangible assets and (4) goodwill.
The following table summarizes the estimated fair value of the
assets acquired and the liabilities assumed at the date of
acquisition. The Company has obtained third party valuations of
certain tangible and intangible assets acquired from Cadence.
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|
Net working capital, adjusted for
Cadence operating activity from date of definitive merger
agreement to October 31, 2005
|
|
$
|
4,679,078
|
|
Oil and gas properties and
property and equipment
|
|
|
14,647,614
|
|
Investments
|
|
|
1,503,832
|
|
Other Mineral properties
|
|
|
197,406
|
|
Non-compete agreements
|
|
|
3,265,000
|
|
Proprietary business relationships
|
|
|
1,340,000
|
|
Goodwill
|
|
|
15,973,346
|
|
Redeemable convertible preferred
stock
|
|
|
(59,925
|
)
|
|
|
|
|
|
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|
$
|
41,546,351
|
|
|
|
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The Company has followed the guidance of SFAS No. 141
to record this purchase. SFAS No. 141 requires that
the purchase method of accounting be used for all business
combinations initiated after June 1, 2001 and that
goodwill, as well as any intangible assets believed to have an
indefinite life, shall not be amortized for financial accounting
purposes. The Company has recognized goodwill in the amount of
$15,973,346 in connection with this acquisition. In accordance
with SFAS No. 142, Goodwill and Other Intangible
Assets, the goodwill will be reviewed periodically to
determine if there has been any impairment to its value. The
Company will perform an impairment test as of December 31,
2006, unless circumstances or events indicate that an impairment
test should be performed sooner.
F-16
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
the periods presented, compared with the historical results of
operations of Aurora for the same periods.
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|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
Historical
|
|
|
Pro Forma
|
|
|
Historical
|
|
|
Pro Forma*
|
|
|
Oil and gas revenues
|
|
$
|
6,743,444
|
|
|
$
|
8,821,869
|
|
|
$
|
960,011
|
|
|
$
|
3,501,458
|
|
Production expenses
|
|
|
(2,047,028
|
)
|
|
|
(2,799,504
|
)
|
|
|
(614,338
|
)
|
|
|
(789,174
|
)
|
Net operating revenues
|
|
|
4,696,416
|
|
|
|
6,022,365
|
|
|
|
345,673
|
|
|
|
2,712,284
|
|
Net loss
|
|
|
(516,272
|
)
|
|
|
(4,293,053
|
)
|
|
|
(1,103,711
|
)
|
|
|
(7,989,175
|
)
|
Net loss per common
share basic and diluted
|
|
|
(0.01
|
)
|
|
|
(0.07
|
)
|
|
|
(0.05
|
)
|
|
|
(0.22
|
)
|
Weighted average number of common
shares outstanding basic and diluted
|
|
|
40,622,000
|
|
|
|
58,108,000
|
|
|
|
23,636,000
|
|
|
|
36,351,000
|
|
|
|
|
* |
|
Includes operations of Cadence for the year ended
September 30, 2004 |
|
|
NOTE 3.
|
ACCOUNTS
RECEIVABLE (INCLUDING RELATED PARTIES)
|
Accounts receivable generally consist of amounts due from the
sale of oil and gas products and from joint interest billings to
investors who have invested with the Company on specific oil and
gas projects. Accounts receivable may be offset by royalty
payments and are typically collateralized by the owners
interest in a specific oil and gas project. Potential credit
losses, in the aggregate, have not been significant and have not
exceeded managements expectations.
Receivables due from related parties at December 31, 2004
amounted to $129,960, and consisted of amounts due from
affiliates with common ownership for joint billings on projects
which they are involved in with the Company. The amounts at
December 31, 2005 were not material.
F-17
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 4.
|
NOTES RECEIVABLE
(INCLUDING RELATED PARTIES)
|
Notes receivable consist of the following amounts as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Related parties:
|
|
|
|
|
|
|
|
|
Unsecured notes receivable from
shareholder; due upon demand; interest at 4.5%
|
|
$
|
15,000
|
|
|
$
|
100,000
|
|
Unsecured note receivable from a
party related by common ownership, including interest at 6.0%
This note was collected in full in March 2005
|
|
|
|
|
|
|
35,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,000
|
|
|
|
135,096
|
|
|
|
|
|
|
|
|
|
|
Other:
|
|
|
|
|
|
|
|
|
Secured note receivable; interest
rate of 6%; collateralized by an assignable interest in cellular
Tower Sites. Payments of $35,000 are required when Assignor
completes a sale of any tower site
|
|
|
105,000
|
|
|
|
|
|
Unsecured note receivable; arising
from an agreement to provide funds to secure certain contract
services over a two year period. The agreement requires payments
to be made as the party renders services to the Company,
including interest at 6%
|
|
|
83,626
|
|
|
|
81,151
|
|
Other unsecured notes; due on
demand
|
|
|
40,720
|
|
|
|
20,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
229,346
|
|
|
|
101,151
|
|
|
|
|
|
|
|
|
|
|
Total notes receivable
|
|
$
|
244,346
|
|
|
$
|
236,247
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 5.
|
DEPOSIT
ON PURCHASE OF OIL AND GAS PROPERTIES
|
On November 30, 2005, the Company entered into a Purchase
and Sale Agreement with respect to certain New Albany Shale
acreage located in Indiana, commonly called the Wabash project.
Pursuant to the terms of this agreement, the Company was
required to deposit into escrow for the seller $3,200,000.
Interest earned from November 30, 2005 through
December 31, 2005 was $6,102. The total $3,206,102 is
reflected in the accompanying financial statements as deposit on
purchase of oil and gas properties.
This Purchase and Sale Agreement closed on February 1,
2006. At the closing, Aurora acquired 64,000 acres of oil
and gas leases from Wabash Energy Partners, L.P. and this
deposit was added to the cost pool as part of the purchase price
of these leasehold assets. See Subsequent Events, Note 26.
F-18
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 6.
|
SALE OF
INTERESTS IN OIL AND GAS PROPERTIES
|
The Company had the following transactions related to the sale
of oil and gas properties, all of which were applied to reduce
the full cost pool:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
Gross
|
Year
|
|
Type of Property
|
|
Description
|
|
Sold
|
|
Proceeds
|
|
2005
|
|
Unproved
|
|
Various Indiana leaseholds
|
|
95%
|
|
$
|
7,373,737
|
|
2005
|
|
Unproved
|
|
Corner #1 project
|
|
50%
|
|
|
344,114
|
|
2005
|
|
Unproved
|
|
Eastview & Gaston
leaseholds
|
|
25-100%
|
|
|
259,258
|
|
2005
|
|
Proved
|
|
Various
|
|
<5%
|
|
|
18,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
$
|
7,995,109
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
Unproven and Proved
|
|
Antrim leaseholds
|
|
80%
|
|
$
|
6,433,890
|
|
2004
|
|
Proved
|
|
Crossroads project
|
|
90%
|
|
|
292,132
|
|
2004
|
|
Unproved
|
|
New Albany shale
|
|
95%
|
|
|
349,829
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
$
|
7,075,851
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2004, Aurora entered into a sale agreement with an
unrelated third party for $6,433,890. As part of this agreement,
the third party assumed capital leases in the amount of
$847,025. Further, Aurora received $1,260,576 in proceeds net of
the payoff of the mezzanine facility obligation in the amount of
$4,674,639 and reserve base lending obligation in the amount of
$498,675 for the sale of an 80% interest in Auroras Antrim
leasehold units located in Northeast Michigan. Proceeds, net of
historical cost in the amount of $7,211,916, were recorded as a
reduction to the full cost pool as the reduction of capitalized
costs to the oil and gas reserve were not significantly altered.
|
|
NOTE 7.
|
OIL AND
GAS PROPERTIES NOT SUBJECT TO AMORTIZATION
|
The Company is currently participating in oil and gas
exploration and development activities on blocks of acreage in
the states of Indiana, Michigan, Ohio, and Kentucky. A
determination cannot be made about the extent, if any, of
additional oil and gas reserves that should be classified as
proven reserves in connection with these projects. Consequently,
the associated property and exploration costs have been excluded
in computing amortization of the full cost pool.
|
|
NOTE 8.
|
INTANGIBLE
ASSETS
|
Intangible assets consist of the following as of
December 31, 2005:
|
|
|
|
|
Non-compete agreements
|
|
$
|
3,265,000
|
|
Proprietary business relationships
|
|
|
1,340,000
|
|
|
|
|
|
|
Total
|
|
|
4,605,000
|
|
Less accumulated amortization
|
|
|
1,407,083
|
|
|
|
|
|
|
Intangibles, net
|
|
$
|
3,197,917
|
|
|
|
|
|
|
The intangible assets are being amortized over three years, and
the future annual amortization expense is estimated to be
approximately $1,535,000 through 2007.
F-19
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 9.
|
OTHER
INVESTMENTS
|
Other investments consist of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Investments in unconsolidated
subsidiaries:
|
|
|
|
|
|
|
|
|
Hudson Pipeline &
Processing Co., LLC
|
|
$
|
1,224,995
|
|
|
$
|
230,396
|
|
GeoPetra Partners, LLC
|
|
|
344,502
|
|
|
|
|
|
Mineral properties
|
|
|
197,406
|
|
|
|
|
|
Other
|
|
|
89,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,855,977
|
|
|
$
|
230,396
|
|
|
|
|
|
|
|
|
|
|
Hudson
Pipeline & Processing Co., LLC
(Hudson)
Hudson is a limited liability company that owns a facility
plant, pipeline,
rights-of-way
and meter used by nearby Antrim wells, and processes the gas
produced from those wells. North owns a 48.75% membership
interest in this limited liability company until the revenues
received from the pipeline facility equal 125% of the amount
spent on construction of the pipeline, after which Norths
membership interest will be 47.5%. As of January 31, 2006,
North increased its membership interest to approximately 91%
pursuant to a Purchase and Sales Agreement with O.I.L. Energy
Corp. See Subsequent Events, Note 26.
Ownership for this investment is accounted for using the equity
method, whereby the investment is stated at cost and adjusted
for the Companys equity in undistributed earnings and loss
since acquisition. The construction of the pipeline began in
late 2004. Operations for Hudson for the period ended
December 31, 2004 were insignificant; for 2005, the
Companys allocable share of net income was $65,643.
The following is condensed financial information concerning
Hudson:
Balance
Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(Unaudited)
|
|
|
Current assets
|
|
$
|
475,906
|
|
|
$
|
43,839
|
|
Construction projects in progress,
net
|
|
|
2,201,946
|
|
|
|
749,223
|
|
Other assets
|
|
|
15,592
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,693,444
|
|
|
$
|
793,062
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
240,086
|
|
|
$
|
563,009
|
|
Members equity
|
|
|
2,453,358
|
|
|
|
230,053
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
members equity
|
|
$
|
2,693,444
|
|
|
$
|
793,062
|
|
|
|
|
|
|
|
|
|
|
F-20
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Statements
of Operations
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(Unaudited)
|
|
|
Revenues
|
|
$
|
653,362
|
|
|
$
|
24,964
|
|
Costs and expenses
|
|
|
518,989
|
|
|
|
22,565
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
134,373
|
|
|
|
2,399
|
|
General and administrative
|
|
|
4,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before other
|
|
|
130,094
|
|
|
|
2,399
|
|
Interest income
|
|
|
2,161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
132,255
|
|
|
$
|
2,399
|
|
|
|
|
|
|
|
|
|
|
GeoPetra
Partners, LLC (GeoPetra)
In June 2005, the Company acquired a 30% interest in GeoPetra.
GeoPetra is a limited liability company engaged primarily in the
following activities (i) identification and evaluation for
acquisition of oil and 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 gas and
(iii) providing consultation, advice, and recommendations
to the members of GeoPetra in connection with other oil and gas
properties and interests, operations and activities. GeoPetra
was formed April 1, 2005.
The Company invested a total of $485,741 in GeoPetra in 2005,
and its allocable share of net loss for 2005 was ($141,239). The
following is condensed financial information concerning GeoPetra:
Balance
Sheet
December 31, 2005
(Unaudited)
|
|
|
|
|
Current assets
|
|
$
|
201,943
|
|
Prepaid expenses
|
|
|
48,000
|
|
Oil and gas properties, net
|
|
|
1,186,218
|
|
Property and equipment, net
|
|
|
48,992
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,485,153
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
289,130
|
|
Members equity
|
|
|
1,196,023
|
|
|
|
|
|
|
Total liabilities and
members equity
|
|
$
|
1,485,153
|
|
|
|
|
|
|
F-21
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Statement
of Operations
Period Ended December 31, 2005
(Unaudited)
|
|
|
|
|
Operating revenues
|
|
$
|
|
|
Operating costs and expenses
|
|
|
418,530
|
|
Other expense
|
|
|
5,187
|
|
|
|
|
|
|
Net loss
|
|
$
|
(423,717
|
)
|
|
|
|
|
|
Other
Mineral Properties
Utah
Property
The Company has retained a 25% undivided interest in the Vipont
Mine located in Northwest Utah. The Company has recorded its
undivided interest at $197,406, the carrying value previously
reflected by Cadence, which is considered to be equivalent to
its estimated fair value.
Mineral
Properties in North Idaho
At December 31, 2005, the Company held unpatented mining
claims in the Coeur dAlene Mining District in distinct
groups called the South Galena Group, Moe Group, Rock Creek
Group and Palisades Group. The Company has undertaken only
minimal exploration and development work on these properties,
such as general geological reconnaissance and claim-staking
activities. All of these claims have previously been written off
by Cadence as permanently impaired.
During 2005, the Company entered into a mineral lease with Gold
Creek Mines, Inc. on the Gold Creek claims consisting of 27
patented and 5 unpatented mining claims. The lease is for an
initial term of twenty years and so long thereafter as minerals
are produced from the property. The Company is obligated to
spend $50,000 during the first two years of the lease on mineral
exploration activities. Additionally, during the first two years
of the lease, the Company is obligated to pay advance royalty
payments of $750 per month, increasing to $1,000 per
month during the second two year period, and $1,500 per month
thereafter. At the inception of the lease, the Company made a
one time advance royalty payment of $53,000 to the lessor, which
was charged to expense.
|
|
NOTE 10.
|
PROPERTY
AND EQUIPMENT
|
Property and equipment consist of the following at
December 31:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Office condominium building
|
|
$
|
3,165,382
|
|
|
$
|
|
|
Furniture and fixtures
|
|
|
265,115
|
|
|
|
108,047
|
|
Office equipment
|
|
|
39,579
|
|
|
|
|
|
Computer equipment
|
|
|
148,601
|
|
|
|
77,509
|
|
Software
|
|
|
85,070
|
|
|
|
11,325
|
|
Leasehold improvements
|
|
|
|
|
|
|
19,042
|
|
Vehicles and other equipment
|
|
|
20,171
|
|
|
|
7,050
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment
|
|
|
3,723,918
|
|
|
|
222,973
|
|
Less accumulated depreciation
|
|
|
113,780
|
|
|
|
107,690
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$
|
3,610,138
|
|
|
$
|
115,283
|
|
|
|
|
|
|
|
|
|
|
F-22
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On April 26, 2005, the Company entered into a Condominium
Purchase agreement to purchase the entire second floor of a
commercial condominium project. On October 4, 2005, the
Company closed on the purchase of the office condominium
property, and executed a mortgage payable in the original amount
of $2,925,000 (see Note 12).
Depreciation expense amounted to $52,703 and $28,249 during 2005
and 2004, respectively.
|
|
NOTE 11.
|
LEASES
(INCLUDING RELATED PARTIES)
|
Oil and gas equipment which qualify as a capital lease with an
original cost of $42,400 in 2004 are capitalized into the oil
and gas cost pool and are amortized as part of the entire full
cost pool.
The following is a schedule of annual future minimum lease
payments required under capitalized lease obligations as of
December 31, 2005:
|
|
|
|
|
2006
|
|
$
|
9,960
|
|
2007
|
|
|
3,292
|
|
|
|
|
|
|
Total minimum payments due
|
|
|
13,252
|
|
Less amounts representing
interest, imputed at 6.5%
|
|
|
2,167
|
|
|
|
|
|
|
Present value of net minimum lease
payments
|
|
|
11,085
|
|
Current portion
|
|
|
8,823
|
|
|
|
|
|
|
Obligations under capital leases,
net of current portion
|
|
$
|
2,262
|
|
|
|
|
|
|
During 2003, the Company entered into a lease for office space
under an operating lease on a
month-to-month
basis. The leased office space was owned by an entity which was
owned one-third by one of the Companys principal
shareholders and one-third by a trust in the name of another of
the Companys principal shareholders. In 2004, the Company
extended this lease for a
3-year term
requiring monthly payments of $8,700 expiring in March 2007.
Rent charged to expense during 2005 and 2004 was $95,700 and
$106,800, respectively.
The Company purchased on a commercial condominium space on
October 4, 2005, as more fully described in Note 10. A
settlement payment of $62,250 made in 2006 released the Company
from future lease payments under the lease extension agreement.
|
|
NOTE 12.
|
DEBT
(INCLUDING RELATED PARTIES)
|
Short-Term
Bank Borrowings
On October 12, 2005, the Company entered into a revolving
line-of-credit
agreement with a bank. Under the terms of this agreement, the
Company can borrow up to a maximum of $7,500,000. Interest
payments are due monthly at a rate of 6.75%. The
line-of-credit
agreement expires on October 15, 2006. At December 31,
2005, a balance of $6,210,000 was outstanding on the line. A
payment of $2,130,000 on January 31, 2006 reduced the line
of credit and the agreement was amended to a maximum line of
$5,000,000. See Subsequent Events, Note 26.
During 2004, the Company entered into an unsecured revolving
line-of-credit
agreement with a bank. Under the terms of this agreement, the
Company was able to borrow up to a maximum of $350,000, with
monthly interest payments at prime plus 1% (effective rate at
December 31, 2004 of 6.0%). Subsequent to December 31,
2004, short-term borrowings in the amount of $350,000 were paid
in full. The
line-of-credit
agreement expired on April 1, 2005.
F-23
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-Term
Debt
Notes Payable
Related Parties
A summary of notes payable to related parties is as follows at
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
|
|
|
|
|
|
Related Party
|
|
|
|
Rate
|
|
Due Date
|
|
2005
|
|
|
2004
|
|
|
Affiliated entity
|
|
(1)
|
|
Prime
|
|
5/31/2005
|
|
**
|
|
$
|
|
|
|
$
|
1,700,000
|
|
Affiliated entity
|
|
*
|
|
6.00%
|
|
3/15/2005
|
|
**
|
|
|
|
|
|
|
86,650
|
|
Affiliated entity
|
|
*
|
|
10.50%
|
|
5/1/2006
|
|
|
|
|
69,833
|
|
|
|
69,833
|
|
Shareholder/director
|
|
(2)
|
|
9.50%
|
|
See below
|
|
**
|
|
|
|
|
|
|
400,000
|
|
Shareholder/director
|
|
(3)
|
|
4.68%
|
|
1/1/2006
|
|
**
|
|
|
|
|
|
|
50,000
|
|
Shareholders/directors
|
|
|
|
5.12% to 8%
|
|
From 3/15/2005 to 6/1/06
|
|
**
|
|
|
|
|
|
|
555,355
|
|
Accrued interest
|
|
|
|
|
|
|
|
**
|
|
|
|
|
|
|
156,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total notes payable
related parties
|
|
|
69,833
|
|
|
|
3,018,531
|
|
Current portion of notes
payable related parties
|
|
|
69,833
|
|
|
|
1,940,825
|
|
|
|
|
|
|
|
|
|
|
Notes payable related
parties, net of current portion
|
|
$
|
|
|
|
$
|
1,077,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This note required payments of interest monthly and also
required additional payments based upon the quantity of gas
extracted from certain oil and gas properties. Interest expense
related to this note amounted to $93,618 in 2004. |
|
(2) |
|
Monthly payments were required on this note with the principal
and interest determined based upon the quantity of oil and gas
extracted from certain oil and gas properties. Interest expense
amounted to $45,704 in 2004. |
|
(3) |
|
This interest rate adjusted annually based on the highest
applicable federal rate (4.68% at December 31, 2004). |
|
* |
|
These entities are affiliated through common ownership and
ultimate management control. |
|
** |
|
These notes were paid in full during March 2005. |
Mortgage
Payable
On October 4, 2005, the Company closed a mortgage loan from
Northwestern Bank in the amount of $2,925,000. The repayment
schedule is monthly interest only for three successive months
starting on November 1, 2005, and beginning on
February 1, 2006, principal and interest in 32 monthly
payments of $21,969. The loan bears interest at the rate of
6.5% per year. The maturity date is October 1, 2008.
Loan proceeds were used to purchase the condominium and to pay
for interior improvements to the premises.
The mortgage loan is secured by the personal guaranties of three
of the Companys directors. The mortgage had an outstanding
balance of $2,865,477 at December 31, 2005.
Mezzanine
Financing
In August 2004, North entered into a $30,000,000 mezzanine
credit facility to enable the Company to fund its 20%-50% share
of the Michigan Antrim drilling program. On December 8,
2005, North entered into an Amended Note Purchase
Agreement, increasing the borrowing capacity under the existing
credit facility to $50 million, representing an additional
$20 million available for development. The additional
commitment in the five-year
F-24
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
revolving credit facility was provided by the existing mezzanine
lender, Trust Company of the West (TCW). The terms
of this financing are as follows:
|
|
|
Facility Amount: |
|
Initially up to $30,000,000 ($50,000,000 as of December
2005) secured advancing
line-of-credit
with overriding royalty provisions. |
|
Interest Rate: |
|
11.5% |
|
Maturity: |
|
September 29, 2009 |
|
Use of Proceeds: |
|
To fund drilling, completion, gathering lines, and gas
processing facility for certain Michigan Antrim wells. |
|
Security: |
|
100% working interest in all wells completed. |
|
Payments: |
|
Beginning September 28, 2006 and quarterly thereafter. The
required payment is 75% (100% if coverage deficiency or default
occurs) of Adjusted Net Cash Flow (ANCF) determined
by deducting applicable operating expenses from gross revenue. |
On January 31, 2006, the Company entered into a new senior
secured revolving credit facility of up to $100 million
with a new lender (see Subsequent Events, Note 26). In this
connection, the TCW facility was subordinated to the new senior
credit facility.
Interest expense related to this debt amounted to $329,028 in
2004, all of which was capitalized. Interest expense in 2005
related to this debt amounted to $2,171,389, of which $1,146,084
was capitalized.
The loan agreement 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).
Maturities
of Long-Term Debt
Aggregate maturities of long-term debt at December 31, 2005
are as follows:
|
|
|
|
|
2006
|
|
$
|
151,533
|
|
2007
|
|
|
86,862
|
|
2008
|
|
|
2,708,000
|
|
2009
|
|
|
40,000,000
|
|
|
|
|
|
|
Total
|
|
$
|
42,946,395
|
|
|
|
|
|
|
The Company estimates that no principal payments on the
mezzanine financing will be required until maturity because of
the level of anticipated capital expenditures and the senior
lending credit facility entered into on January 31, 2006
(see Subsequent Events, Note 26).
|
|
NOTE 13.
|
DEPOSIT
ON SALE OF OIL AND GAS PROPERTIES
|
On November 30, 2005, after the execution of the agreement
to purchase 64,000 acres of leasehold interests in the
Wabash Project discussed in Note 5, the Company entered
into a second Purchase and Sale Agreement with respect to this
New Albany Shale acreage whereby the Company sold half of its
interest in a combined 95,000 acre lease to New
Albany-Indiana, LLC, an affiliate of Rex Energy Operating
Corporation. Of these 95,000 acres, 64,000 acres were
the interests acquired from Wabash Energy Partners, L.P., and
31,000 acres were acquired by Aurora in other transactions.
F-25
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Pursuant to the terms of this sales agreement, $3,500,000 was
placed in escrow by the purchaser on behalf of the Company as a
deposit until the closing in February 2006. Interest earned from
November 30, 2005 through December 31, 2005 was
$9,319. The total $3,509,319 is reflected in the accompanying
financial statements as a deposit on sale of oil and gas
properties.
|
|
NOTE 14.
|
REDEEMABLE
CONVERTIBLE PREFERRED STOCK
|
On April 23, 2001, the Companys 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 34,950 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 are 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. The Class A shares mature seven years
from the date of issuance. At maturity, the Class A shares
will be redeemed for cash or common stock at Cadences
option in an amount equal to the amount paid by the investors
for the shares plus any accrued and unpaid dividends. If shares
of common stock are to be issued at maturity, the conversion
price shall be determined by the average closing bid price for
the 20 trading days prior to the maturity date.
In February 2006, a total of 23,334 shares of redeemable
convertible preferred stock was converted into common stock.
A reconciliation of the provision for income taxes and the
amount computed by applying the statutory Federal income tax
rate to net income (loss) is as follows for the year ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Income tax (benefit) provision at
the statutory rate
|
|
$
|
(175,500
|
)
|
|
$
|
(375,300
|
)
|
Increase (decrease) in allowance
against net operating loss
|
|
|
173,500
|
|
|
|
335,500
|
|
Permanent differences/other
|
|
|
2,000
|
|
|
|
39,800
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
The Companys total deferred tax liabilities, deferred tax
assets and deferred tax asset valuation allowances as of
December 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Total deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryover
|
|
$
|
12,324,600
|
|
|
$
|
1,441,300
|
|
Section 1231 carryover
|
|
|
146,900
|
|
|
|
|
|
Capital loss carryover
|
|
|
66,000
|
|
|
|
|
|
Less valuation allowance
|
|
|
(2,391,700
|
)
|
|
|
(635,400
|
)
|
|
|
|
|
|
|
|
|
|
Deferred tax assets, net
|
|
|
10,145,800
|
|
|
|
805,900
|
|
Total deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Excess assigned acquisition value
|
|
|
(4,339,000
|
)
|
|
|
|
|
Intangible drilling costs and other
|
|
|
(5,806,800
|
)
|
|
|
(805,900
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
(liabilities)
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Management determined that the deferred tax assets do not
satisfy the recognition criteria of SFAS No. 109 and,
accordingly, a full valuation allowance has been recorded for
this amount.
F-26
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has net operating loss carryforwards available to
offset future Federal taxable income of approximately
$36,249,000, which expire from 2009 through 2025. Included in
this amount is a pre-merger net operating loss carryforward
incurred by Cadence of approximately $16,900,000. In addition,
Cadence had pre-merger section 1231 loss carryforwards of
approximately $432,000, which expire in 2006, and net capital
loss carryforwards of approximately $194,000, which expire in
the years 2006 through 2009.
The Tax Reform Act of 1986 imposed substantial restrictions on
the utilization of net operating losses and tax credits in the
event of an ownership change, as defined by the
Internal Revenue Code. Federal and State net operating losses
are subject to limitations as a result of these restrictions.
Under such circumstances, the Companys ability to utilize
its net operating losses against future income may be reduced.
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 Companys 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
$.75 per share.
As a result of the reverse merger, Auroras
shareholders equity reflects the following transactions:
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 Auroras equity.
The total outstanding Cadence shares, at the effective date of
the merger, of 21,136,327 were added to Auroras 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 $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
Companys stock.
2004
The Company issued 49,976 shares of common stock in
exchange for consulting services provided to the Company during
the previous three years. The value assigned per share was
contractual and was agreed to by the Company and the vendor in
June, 2001. The amount expensed as a result of this exchange
amounted to $41,479.
The Company sold 1,045,000 shares of common stock to
unrelated third parties at $2.50 per share, primarily in
the fourth quarter of 2004. Total proceeds from the sale of
these shares amounted to $2,612,500.
The Company issued 4,800 shares of common stock as payment
for consulting on the sale of the Companys common stock.
The price per share used for this exchange of $2.50 was based
upon comparable sales of the Companys common stock and
amounted to $12,000.
F-27
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company issued 310,000 shares of common stock to a
director upon the exercise of options at prices ranging from
$.75 to $1.00 per share.
During 2000, Aurora authorized 500,000 shares of
Series A preferred stock with the terms and amounts set at
the Board of Directors discretion. Preferred stock has
liquidation preference over common stock equal to the original
issue value, plus any accrued or arreared dividends.
Each share of Series A preferred stock is voting and is
convertible into three shares of common stock. During 2004,
311,111 shares of preferred stock were exchanged for
933,333 shares of the Companys common stock. The
preferred shares require dividends of 6% on a cumulative basis
commencing in 2001. Dividends were required to be accrued on
January 1 of each year. Dividends in the amount of $127,112 were
satisfied through issuance of a note payable. In early 2005, the
remaining 99,350 shares of preferred stock were converted
to 298,050 shares of common stock and all dividends
associated with these shares were paid in full.
|
|
NOTE 18.
|
COMMON
STOCK OPTIONS
|
Both Cadence and Aurora awarded stock options under plans and
other arrangements in place prior to the merger. The following
describes the plans that remain in place as of December 31,
2005.
On October 1, 1997, Aurora adopted an incentive qualified
stock option plan which authorized the issuance of up to
1,000,000 shares of Auroras common stock at an option
price which may not be less than 100% of the estimated fair
value on the date of grant (25% effective with a January 1,
2004 amendment to the plan). The maximum term of options granted
is ten years. The plan was created in an effort to retain key
employees, attract new employees, obtain the services of
consultants, encourage the sense of proprietorship of such
persons and to stimulate the active interest of such persons in
the development and financial success of the Company.
In April 2004, Cadence adopted an incentive stock option plan as
part of a larger equity incentive plan that includes
non-statutory stock options, stock bonuses and restricted stock
awards. The equity incentive plan provides that no more than
5,000,000 shares of stock may issued pursuant to the equity
awards and option prices may not be less than 100% of the
estimated fair value on the date of grant. The maximum term of
options granted is ten years. The purpose of the plan is to
attract and retain the services of employees, directors and
consultants and promote the interests of Cadence by aligning the
interests of selected eligible persons under the plan with the
interests of the stockholders of the Cadence and by providing to
such persons an opportunity to obtain the benefits from
ownership of Cadence stock.
Activity related to the two incentive stock option plans was as
follows for the years ended December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Options outstanding at beginning
of year
|
|
|
344,000
|
|
|
|
250,000
|
|
Granted during the year
|
|
|
146,000
|
|
|
|
94,000
|
|
Assumed upon merger:
|
|
|
|
|
|
|
|
|
2 for 1 exchange of Aurora options
|
|
|
490,000
|
|
|
|
|
|
Cadence options
|
|
|
400,000
|
|
|
|
|
|
Options exercised
|
|
|
(175,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at end of year
|
|
|
1,205,000
|
|
|
|
344,000
|
|
|
|
|
|
|
|
|
|
|
A majority of the Companys outstanding stock options have
been issued outside of the incentive stock option plans. These
include options for the purchase of 99,999 shares which
were issued to certain directors in 2004, as compensation in
exchange for serving on Auroras board of directors.
F-28
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Activity with respect to all stock options (including options
granted under the incentive stock option plans) is presented
below for the years ended December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Exercise
|
|
|
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Options outstanding at beginning
of year
|
|
|
2,700,664
|
|
|
$
|
0.99
|
|
|
|
2,816,665
|
|
|
$
|
1.01
|
|
Granted during the year
|
|
|
156,000
|
|
|
|
3.32
|
|
|
|
193,999
|
|
|
|
0.75
|
|
Assumed upon merger:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 for 1 exchange of Aurora options
|
|
|
2,856,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cadence options
|
|
|
1,124,349
|
|
|
|
1.79
|
|
|
|
|
|
|
|
|
|
Options exercised
|
|
|
(357,500
|
)
|
|
|
1.20
|
|
|
|
(310,000
|
)
|
|
|
0.99
|
|
Forfeitures and other adjustments
|
|
|
(31,709
|
)
|
|
|
0.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at end of year
|
|
|
6,448,468
|
|
|
|
0.72
|
|
|
|
2,700,664
|
|
|
|
0.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All of the above options are considered eligible for exercise as
such options vest immediately upon their grant. The weighted
average remaining life by exercise price as of December 31,
2005 is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Shares
|
|
|
Average
|
|
|
|
Outstanding
|
|
|
Remaining
|
|
|
|
and
|
|
|
Contractual
|
|
Range of Exercise Prices
|
|
Exercisable
|
|
|
Life
|
|
|
$0.25 - $0.38
|
|
|
1,187,994
|
|
|
|
5.9
|
|
$0.42 - $0.50
|
|
|
1,880,000
|
|
|
|
1.3
|
|
$0.63
|
|
|
2,333,334
|
|
|
|
0.8
|
|
$1.25 - $1.75
|
|
|
718,500
|
|
|
|
5.0
|
|
$2.00 - $2.50
|
|
|
253,640
|
|
|
|
2.4
|
|
$3.73
|
|
|
75,000
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,448,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company follows only the disclosure aspects of Statement of
Financial Accounting Standards (SFAS) No. 123,
Accounting for Stock-Based Compensation. The Company
continues to apply Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to
Employees, and related interpretations in accounting for
its plans. Under APB 25, the exercise price of the stock
options was more than the market value of the shares at the date
of grant and, accordingly, no compensation cost has been
recognized in the consolidated financial statements for the
outstanding stock options.
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 years ended
December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Net loss available to common
shareholders
|
|
$
|
(516,272
|
)
|
|
$
|
(1,133,979
|
)
|
Deduct total stock-based
compensation expense determined under fair value based method
for all awards, net of related tax effects
|
|
|
(298,745
|
)
|
|
|
(36,746
|
)
|
|
|
|
|
|
|
|
|
|
Pro forma net loss
|
|
$
|
(815,017
|
)
|
|
$
|
(1,170,725
|
)
|
|
|
|
|
|
|
|
|
|
F-29
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Loss per share basic
and diluted
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
(0.01
|
)
|
|
$
|
(0.05
|
)
|
Pro forma
|
|
$
|
(0.02
|
)
|
|
$
|
(0.05
|
)
|
The weighted average assumptions used in the Black-Scholes
option-pricing model used to determine fair value were as
follows:
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
Risk-free interest rate
|
|
|
4
|
%
|
|
3%
|
Expected years until exercise
|
|
|
10
|
|
|
5-10
|
Expected stock volatility
|
|
|
41
|
%
|
|
0%
|
Dividend yield
|
|
|
0
|
%
|
|
0%
|
|
|
NOTE 19.
|
COMMON
STOCK WARRANTS
|
During 2003, the Company issued 212,500 shares of stock
with 212,500 warrants attached, and 25,000 warrants related to a
July 2002 purchase. The warrants were valued at $51,375 using
the Black-Scholes Option Price calculation. The following
assumptions were made in estimating fair value: risk free
interest rate 5%, volatility 100%, expected life 3 years
and no expected dividends. These warrants may be used to
purchase 237,500 shares of the Companys common stock
at $1.35 per share. The warrants remained exercisable
through October 15, 2005.
During 2004, the Company issued certain note holders warrants to
purchase a total of 765,000 shares of common stock,
exercisable at $4.00 per share, expiring in three years.
Both the number of warrants and the exercise price are
adjustable, dependent upon certain future equity transactions of
the Company. The warrants were valued at $745,237 using the
Black-Scholes Option Price calculation. The following
assumptions were made in estimating fair value: risk-free
interest rate 5%, volatility 100%, expected life 3 three years
and no expected dividends. During 2005, the Company paid back
the notes which were related to these warrants. As an incentive
to the note holders to allow the Company to redeem the notes
prematurely, the Company modified the exercise price of the
warrants to $1.75. Using current Black-Scholes calculations, the
Company incurred no additional charges to its financial
statements with this modification.
During 2005, the Company issued warrants to purchase a total of
14,050,000 shares of stock. These warrants were attached to
7,810,000 shares of stock which were issued for cash and
debt. The warrants were valued at $3,685,875 using the
Black-Scholes Option Price calculation. The following
assumptions were made in estimating fair value during 2005: risk
free interest rate 4%, volatility 41%, expected life
3 years and no expected dividends.
Also during 2005, Aurora issued warrants to purchase
1,900,000 shares of stock. These warrants were attached to
4,972,200 shares which were issued for cash.
Components of other income presented in the accompanying
consolidated statements of operations are summarized as follows
for the year ended December 31:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Project management fees
|
|
$
|
347,857
|
|
|
$
|
883,687
|
|
Administrative fees for producing
properties
|
|
|
94,315
|
|
|
|
309,148
|
|
Miscellaneous income
|
|
|
10,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
|
|
$
|
452,621
|
|
|
$
|
1,192,835
|
|
|
|
|
|
|
|
|
|
|
F-30
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company maintains a SIMPLE 401(k) plan for substantially all
of its employees. Under this SIMPLE plan, eligible employees are
permitted to contribute up to 15% of gross compensation into the
retirement plan. The Company makes no matching contribution;
however, the Company can make a discretionary contribution to
the plan. There were no contributions to this plan in 2005 and
2004.
The Company is occasionally subject to various lawsuits arising
in the normal course of business. In the opinion of management,
the ultimate liability, if any, resulting from such matters will
not have a significant effect on the Companys results of
operations, liquidity, or financial position.
|
|
NOTE 23.
|
EARNINGS
(LOSS) PER SHARE
|
Basic earnings (loss) per share are computed by dividing net
income (loss) available to common shareholders by the weighted
average number of common shares outstanding for the period. The
computation of diluted net income (loss) per share reflects the
potential dilution that could occur if securities or other
instruments to issue common stock were exercised or converted
into common stock or resulted in the issuance of common stock
that would then share in the earnings of the Company.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
Basic and diluted earning (loss)
per share:
|
|
|
|
|
|
|
|
|
Loss available to common
shareholders
|
|
$
|
(516,272
|
)
|
|
$
|
(1,133,979
|
)
|
Weighted average common shares
outstanding
|
|
|
40,622,000
|
|
|
|
23,636,000
|
|
Basic loss per share
|
|
$
|
(0.01
|
)
|
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
The common stock and per share information have been
retroactively adjusted to give effect to the
two-for-one
exchange ratio in the reverse acquisition of and merger with
Cadence on October 31, 2005.
During 2005 and 2004, stock options and warrants and convertible
preferred stock were excluded in the computation of diluted loss
per share because their effect was anti-dilutive.
|
|
NOTE 24.
|
MINORITY
INTEREST IN NET ASSETS OF SUBSIDIARIES
|
The following is an analysis of changes in minority interest in
net assets of subsidiaries for the year ended December 31,
2004:
|
|
|
|
|
Balance at December 31, 2003
|
|
$
|
1,685,063
|
|
Distributions to minority members
|
|
|
(41,347
|
)
|
Income allocated to minority
interest owners prior to disposal
|
|
|
41,243
|
|
Disposition of subsidiary and
elimination of minority member interest
|
|
|
(90,518
|
)
|
Transfer of member interest in
subsidiary in exchange for working interest
|
|
|
(1,578,806
|
)
|
Minority interest reclassified as
other receivable
|
|
|
22,452
|
|
Net loss
|
|
|
(38,087
|
)
|
|
|
|
|
|
Balance at December 31, 2004
|
|
$
|
|
|
|
|
|
|
|
F-31
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 25.
|
SUPPLEMENTAL
CASH FLOWS INFORMATION
|
Non-Cash
Financing and Investing Activities
2005
None.
2004
During 2004, Aurora conveyed its entire interest totaling
$338,177 in AIL, BAC and ANG back to the respective consolidated
subsidiaries in exchange for oil and gas reserves in the same
amount. As a result of this conveyance, Aurora no longer
maintained a controlling interest in these subsidiaries.
Minority interests and oil and gas properties related to this
conveyance, in the amount $1,992,361, has been eliminated from
these consolidated financial statements.
Pursuant to the purchase and sale agreement with an unrelated
third party more fully described in Note 6, Aurora repaid
in full the mezzanine facility obligation in the amount of
$4,674,639, reserve base lending obligation in the amount of
$498,675 and transferred certain lease obligations in the amount
of $847,025.
During 2004, $127,112 of cumulative dividends on convertible
preferred stock were satisfied by issuance of a note payable.
Other
Cash Flows Information
Cash paid for interest amounted to $2,258,691 and $681,025 in
2005 and 2004, respectively.
|
|
NOTE 26.
|
SUBSEQUENT
EVENTS
|
Senior
Secured Credit Facility
On January 31, 2006, the Company entered into a Credit
Agreement with BNP Paribas. The new facility consists of a
senior secured revolving credit facility in an amount of up to
$100 million, having an initial borrowing base without
hedges of $40 million. The ability to increase the
borrowing base beyond $50 million is subject to certain
conditions in the Second Lien Notes held by TCW (see Note 12).
The proceeds from this facility are intended to be used for
drilling, development, and acquisitions as well as other general
corporate purposes. This facility matures the earlier of
January 31, 2010 or 91 days prior to the maturity of
the Second Lien Notes currently due September 2009. This
facility provides for borrowings tied to BNPs prime rate
(or if higher, the federal funds effective rate plus 0.5%) or
LIBOR plus 1.25 to 2.0% depending on the borrowing base
utilization, as selected by the Company.
O.I.L.
Acquisition
On January 31, 2006, the Company completed the acquisition
of additional working interests in the Hudson project area (see
Note 9). The total purchase price of approximately $27,500,000
was financed under the senior secured credit facility with BNP.
This acquisition increased the Companys working interest
in the project area from an average of approximately 49% to 96%
in the project. Additionally, pursuant to this acquisition was
the purchase of 48.75% member interest in Hudson, which pipeline
and production facilities related to the Hudson project. This
increased the Companys member ownership from 48.75% to 97%.
Rex/Wabash
Transaction
On February 1, 2006, the Company completed a transaction
involving the acquisition of 64,000 acres of New Albany
Shale acreage in the Wabash Project (see Note 5). The
Company then sold half interest in its accumulated
95,000 acres to an unrelated third party, resulting in a
net acreage gain to the Company.
F-32
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Stock
Option and Warrant Exercise
In February 2006, the Company reported the receipt of a total of
approximately $20.6 million in cash proceeds from the
exercise of certain options and warrants. Approximately
$18 million of this cash was received in 2006; the balance
of approximately $2.6 million was received in 2005.
Pro
Forma Presentation
The pro forma effect of these 2006 subsequent events on the
Companys financial position, assuming that they had
occurred as of December 31, 2005, is as follows:
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2005
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
Subsequent
|
|
|
|
|
|
|
Historical
|
|
|
Events
|
|
|
Pro Forma
|
|
|
Current assets
|
|
$
|
19,256,000
|
|
|
$
|
15,870,000
|
|
|
$
|
35,126,000
|
|
Oil and gas properties, using full
cost accounting
|
|
|
68,961,000
|
|
|
|
27,197,000
|
|
|
|
96,158,000
|
|
Property and equipment, net
|
|
|
3,610,000
|
|
|
|
|
|
|
|
3,610,000
|
|
Other Investments
|
|
|
1,856,000
|
|
|
|
|
|
|
|
1,856,000
|
|
Other Assets
|
|
|
762,000
|
|
|
|
2,500,000
|
|
|
|
3,262,000
|
|
Deposit on purchase of oil and gas
properties
|
|
|
3,206,000
|
|
|
|
(3,206,000
|
)
|
|
|
|
|
Goodwill and other intangibles
|
|
|
19,171,000
|
|
|
|
|
|
|
|
19,171,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
116,822,000
|
|
|
$
|
42,361,000
|
|
|
$
|
159,183,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
13,832,000
|
|
|
$
|
(2,130,000
|
)
|
|
$
|
11,702,000
|
|
Deposit on sale of oil and gas
properties
|
|
|
3,509,000
|
|
|
|
(3,509,000
|
)
|
|
|
|
|
Long-term debt
|
|
|
42,795,000
|
|
|
|
30,000,000
|
|
|
|
72,795,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
60,136,000
|
|
|
|
24,361,000
|
|
|
|
84,497,000
|
|
Redeemable preferred stock
|
|
|
60,000
|
|
|
|
|
|
|
|
60,000
|
|
Shareholders equity
|
|
|
56,626,000
|
|
|
|
18,000,000
|
|
|
|
74,626,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
shareholders equity
|
|
$
|
116,822,000
|
|
|
$
|
42,361,000
|
|
|
$
|
159,183,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-33
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL
OIL AND GAS INFORMATION
(UNAUDITED)
Supplemental
Reserve Information
The following information presents estimates of our proved oil
and gas reserves. The Company retained the services of an
independent petroleum consultant (Data & Consulting
Services, Division of Schlumberger Technology Corporation) to
estimate its proved natural gas reserves at December 31,
2005 and 2004. Included in the tables that follow are proved oil
and natural gas reserves located in Michigan that were acquired
as a separate property acquisition near the end of the year and
proved oil and 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, 2005 were estimated
under the Securities and Exchange Commission (SEC)
reporting standards. Natural gas reserves at December 31,
2004 were estimated under the SEC reporting standards with the
exception of operating costs assumptions. Operating costs were
calculated as a monthly amount for each individual unit which
amounts decline over the first eight years and remain constant
thereafter.
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
Estimates of Proved Reserves
|
|
(mbbl)
|
|
|
(mmcf)
|
|
|
Proved reserves as of
December 31, 2003
|
|
|
|
|
|
|
16,660
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
Purchases of minerals in place
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
|
|
|
|
18,440
|
|
Production
|
|
|
|
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
Proved reserves as of
December 31, 2004
|
|
|
|
|
|
|
34,949
|
|
Revisions of previous estimates
|
|
|
6
|
|
|
|
5,381
|
|
Purchases of minerals in place
|
|
|
103
|
|
|
|
1,572
|
|
Extensions and discoveries
|
|
|
|
|
|
|
22,107
|
|
Production
|
|
|
(10
|
)
|
|
|
(688
|
)
|
|
|
|
|
|
|
|
|
|
Proved reserves as of
December 31, 2005
|
|
|
99
|
|
|
|
63,321
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2004
|
|
|
|
|
|
|
12,520
|
|
December 31, 2005
|
|
|
70
|
|
|
|
45,205
|
|
The following table summarizes the weighted average year-end
prices (net of basis adjustments) used to estimate reserves in
accordance with SEC guidelines.
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Natural gas (per mcf)
|
|
$
|
9.89
|
|
|
$
|
6.195
|
|
Oil (per barrel)
|
|
$
|
56.41
|
|
|
|
n/a
|
|
F-34
(UNAUDITED)
Standardized
Measure of Discounted Future Net Cash Flow Relating to Proved
Oil and 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 Companys 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.
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 Companys 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 decisions are
based upon a wide range of factors, including estimates of
probable as well as proved reserves, and varying price and cost
assumptions 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 Companys crude oil and natural gas reserves for the
years ended December 31, 2005 and 2004.
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Future gross revenues(1)
|
|
$
|
632,058,720
|
|
|
$
|
216,162,240
|
|
Future production costs(2)
|
|
|
(182,710,406
|
)
|
|
|
(74,240,020
|
)
|
Future development costs(2)
|
|
|
(15,073,590
|
)
|
|
|
(13,659,320
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flows before
income taxes
|
|
|
434,274,724
|
|
|
|
128,262,900
|
|
Future income tax expense(3)
|
|
|
(101,521,160
|
)
|
|
|
(42,167,000
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flows after income
taxes
|
|
|
332,753,564
|
|
|
|
86,095,900
|
|
Discount at 10% per annum
|
|
|
(179,885,324
|
)
|
|
|
(53,936,190
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows relating to proved oil and gas reserves
|
|
$
|
152,868,240
|
|
|
$
|
32,159,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 gas producing activities and tax carry forwards. |
F-35
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS
INFORMATION (Continued)
(UNAUDITED)
Changes
in Standardized Measure of Discounted Future Cash
Flows
The following table sets forth the change in Standardized
Measure of Discounted Future Net Cash Flows for the years ended
December 31, 2005 and 2004.
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Beginning balance
|
|
$
|
32,159,710
|
|
|
$
|
15,708,150
|
|
|
|
|
|
|
|
|
|
|
Revisions to reserves proved in
prior years:
|
|
|
|
|
|
|
|
|
Net change in prices and
production costs
|
|
|
85,425,515
|
|
|
|
|
|
Net change in future development
costs
|
|
|
6,299,524
|
|
|
|
|
|
Net change due to revisions in
quantity estimates
|
|
|
33,335,739
|
|
|
|
|
|
Net change in accretion of discount
|
|
|
(66,761,600
|
)
|
|
|
|
|
Other
|
|
|
38,137,602
|
|
|
|
(6,025,690
|
)
|
|
|
|
|
|
|
|
|
|
Total revisions to reserves
provided in prior years
|
|
|
96,436,780
|
|
|
|
(6,025,690
|
)
|
New discoveries and extensions,
net of future development and production costs
|
|
|
76,487,826
|
|
|
|
12,272,113
|
|
Purchases of minerals in place
|
|
|
11,834,500
|
|
|
|
|
|
Sales of oil and gas produced, net
of production costs
|
|
|
(4,696,416
|
)
|
|
|
(345,673
|
)
|
Previously estimated development
costs incurred
|
|
|
|
|
|
|
10,550,810
|
|
Net change in income taxes
|
|
|
(59,354,160
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in standardized measure
of discounted cash flows
|
|
|
120,708,530
|
|
|
|
16,451,560
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
152,868,240
|
|
|
$
|
32,159,710
|
|
|
|
|
|
|
|
|
|
|
Capitalized
Costs Related to Oil and Gas Producing Activities
The following table sets forth the capitalized costs relating to
the Companys natural gas and crude oil producing
activities at December 31, 2005 and 2004.
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Proved properties
|
|
$
|
39,643,003
|
|
|
$
|
7,585,807
|
|
Unproved properties
|
|
|
37,279,889
|
|
|
|
7,981,727
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties
|
|
|
76,922,892
|
|
|
|
15,567,534
|
|
Less accumulated depreciation,
depletion and amortization
|
|
|
7,962,138
|
|
|
|
600,077
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties
net
|
|
$
|
68,960,754
|
|
|
$
|
14,967,457
|
|
|
|
|
|
|
|
|
|
|
Cadences share of equity
method investees net capitalized cost
|
|
$
|
355,865
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
F-36
CADENCE
RESOURCES CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS
INFORMATION (Continued)
(UNAUDITED)
Costs
Incurred in Oil and 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.
The following table sets forth costs incurred related to the
Companys oil and gas activities for the years ended
December 31, 2005 and 2004.
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
22,763,734
|
|
|
$
|
1,932,442
|
|
Unproved
|
|
|
16,400,997
|
|
|
|
6,836,229
|
|
Exploration
|
|
|
781,586
|
|
|
|
|
|
Development
|
|
|
29,927,619
|
|
|
|
1,782,139
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
69,873,936
|
|
|
$
|
10,550,810
|
|
|
|
|
|
|
|
|
|
|
Cadences share of equity
method investees costs of property acquisition,
exploration and development
|
|
$
|
355,865
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
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, 2005 and 2004.
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Oil and gas sales
|
|
$
|
6,743,444
|
|
|
$
|
960,011
|
|
Production and lease operating
costs
|
|
|
(2,047,028
|
)
|
|
|
(614,338
|
)
|
Depreciation and depletion
|
|
|
(1,155,254
|
)
|
|
|
(203,249
|
)
|
|
|
|
|
|
|
|
|
|
Results of producing activities
|
|
$
|
3,541,162
|
|
|
$
|
142,424
|
|
|
|
|
|
|
|
|
|
|
These results of operations do not include a provision for
income taxes due to the net operating loss carry forward
available to offset taxable income during both 2005 and 2004.
F-37
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Aurora Oil & Gas Corporation and Subsidiaries
Traverse City, Michigan
We have reviewed the accompanying condensed consolidated balance
sheet of Aurora Oil & Gas Corporation and Subsidiaries
as of June 30, 2006, and the related condensed consolidated
statements of operations and cash flows for the six months ended
June 30, 2006 and 2005, and shareholders equity for
the six months ended June 30, 2006. These consolidated
interim financial statements are the responsibility of the
Companys management.
We conducted our review in accordance with the standards of the
Public Company Accounting Oversight Board (United States). A
review of interim financial information consists principally of
applying analytical procedures and making inquiries of persons
responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting
Oversight Board (United States), the objective of which is the
expression of an opinion regarding the financial statements
taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material
modifications that should be made to the condensed consolidated
financial statements referred to above for them to be in
conformity with accounting principles generally accepted in the
United States of America.
RACHLIN COHEN & HOLTZ LLP
Miami, Florida
August 7, 2006
F-38
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
June 30, 2006
(Unaudited)
|
|
|
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,594,953
|
|
Accounts receivable
|
|
|
|
|
Oil and gas sales
|
|
|
2,189,886
|
|
Joint interest owners
|
|
|
6,401,514
|
|
Notes receivable
|
|
|
|
|
Related party
|
|
|
50,720
|
|
Other
|
|
|
236,626
|
|
Drilling advances
|
|
|
988,734
|
|
Prepaid expenses and other current
assets
|
|
|
328,770
|
|
Short-term derivative instruments
|
|
|
962,015
|
|
|
|
|
|
|
Total current assets
|
|
|
14,753,218
|
|
|
|
|
|
|
PROPERTY AND
EQUIPMENT:
|
|
|
|
|
Oil and gas properties, using full
cost accounting:
|
|
|
|
|
Proved properties
|
|
|
79,213,485
|
|
Unproved properties
|
|
|
33,791,338
|
|
Properties held for sale
|
|
|
21,365,575
|
|
Less: accumulated depletion and
amortization
|
|
|
(10,072,195
|
)
|
|
|
|
|
|
Total oil and gas properties, net
|
|
|
124,298,203
|
|
Pipelines
|
|
|
4,831,358
|
|
Other property and equipment
|
|
|
3,943,612
|
|
Less: accumulated depreciation
|
|
|
(359,973
|
)
|
|
|
|
|
|
Total property and equipment, net
|
|
|
132,713,200
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
Goodwill
|
|
|
15,973,346
|
|
Intangibles (net of accumulated
amortization of $2,174,583 and $1,407,083, respectively)
|
|
|
2,430,417
|
|
Other investments
|
|
|
934,606
|
|
Debt issuance costs (net of
accumulated amortization of $462,242 and $79,096, respectively)
|
|
|
2,731,396
|
|
|
|
|
|
|
Total other assets
|
|
|
22,069,765
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
169,536,183
|
|
|
|
|
|
|
|
LIABILITIES AND
SHAREHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
Accounts payable
|
|
$
|
10,062,326
|
|
Accrued liabilities
|
|
|
42,604
|
|
Short-term bank borrowings
|
|
|
10,000
|
|
Current portion of obligations
under capital leases
|
|
|
7,173
|
|
Current portion of mortgage payable
|
|
|
81,902
|
|
Drilling advances
|
|
|
622,537
|
|
|
|
|
|
|
Total current liabilities
|
|
|
10,826,542
|
|
|
|
|
|
|
LONG-TERM LIABILITIES:
|
|
|
|
|
Asset retirement obligation
|
|
|
1,013,329
|
|
Mortgage payable
|
|
|
2,751,495
|
|
Senior secured credit facility
|
|
|
40,000,000
|
|
Mezzanine financing
|
|
|
40,000,000
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
83,764,824
|
|
|
|
|
|
|
Total liabilities
|
|
|
94,591,366
|
|
|
|
|
|
|
COMMITMENTS, CONTINGENCIES AND
SUBSEQUENT EVENTS
|
|
|
|
|
|
|
|
|
|
REDEEMABLE CONVERTIBLE PREFERRED
STOCK
|
|
|
19,924
|
|
|
|
|
|
|
SHAREHOLDERS
EQUITY:
|
|
|
|
|
Common stock, $.01 par value;
authorized 250,000,000 shares; issued and outstanding
81,965,017 shares
|
|
|
819,651
|
|
Additional paid-in capital
|
|
|
77,757,502
|
|
Accumulated other comprehensive
income
|
|
|
962,015
|
|
Accumulated deficit
|
|
|
(4,614,275
|
)
|
|
|
|
|
|
Total shareholders equity
|
|
|
74,924,893
|
|
|
|
|
|
|
TOTAL LIABILITIES AND
SHAREHOLDERS EQUITY
|
|
$
|
169,536,183
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
F-39
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
Six Months Ended June 30, 2006 and 2005
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
10,941,220
|
|
|
$
|
1,097,906
|
|
Interest income
|
|
|
244,214
|
|
|
|
165,910
|
|
Equity in (loss) income of
unconsolidated subsidiary
|
|
|
(158,714
|
)
|
|
|
12,397
|
|
Other income
|
|
|
596,999
|
|
|
|
349,611
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
11,623,719
|
|
|
|
1,625,824
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
3,242,713
|
|
|
|
1,126,396
|
|
Pipeline operating expenses
|
|
|
284,201
|
|
|
|
|
|
Production and lease operating
|
|
|
3,411,051
|
|
|
|
652,957
|
|
Depletion, depreciation and
amortization
|
|
|
3,024,166
|
|
|
|
102,227
|
|
Interest expense
|
|
|
3,564,154
|
|
|
|
237,354
|
|
Taxes
|
|
|
29,361
|
|
|
|
237,697
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
13,555,646
|
|
|
|
2,356,631
|
|
|
|
|
|
|
|
|
|
|
LOSS BEFORE MINORITY
INTEREST
|
|
|
(1,931,927
|
)
|
|
|
(730,807
|
)
|
MINORITY INTEREST IN (INCOME)
OF SUBSIDIARIES
|
|
|
(17,919
|
)
|
|
|
(6,190
|
)
|
|
|
|
|
|
|
|
|
|
NET LOSS
|
|
$
|
(1,949,846
|
)
|
|
$
|
(736,997
|
)
|
|
|
|
|
|
|
|
|
|
NET LOSS PER COMMON
SHARE BASIC AND DILUTED
|
|
$
|
(0.03
|
)
|
|
$
|
(0.02
|
)
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING BASIC AND DILUTED
|
|
|
76,011,115
|
|
|
|
36,157,838
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
F-40
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
Six Months Ended June 30, 2006
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
COMMON STOCK:
|
|
|
|
|
|
|
|
|
Balance, beginning
|
|
|
61,536,261
|
|
|
$
|
615,363
|
|
Cashless exercise of common stock
options and warrants
|
|
|
3,280,105
|
|
|
|
32,801
|
|
Conversion of redeemable
convertible preferred stock to common stock
|
|
|
23,334
|
|
|
|
233
|
|
Exercise of common stock options
and warrants
|
|
|
15,565,457
|
|
|
|
155,655
|
|
Issuance of common stock to
related party
|
|
|
90,000
|
|
|
|
900
|
|
Issuance of common stock to
related party in lieu of commission relating to exercise of
warrants
|
|
|
1,469,860
|
|
|
|
14,699
|
|
|
|
|
|
|
|
|
|
|
Balance, end
|
|
|
81,965,017
|
|
|
|
819,651
|
|
|
|
|
|
|
|
|
|
|
ADDITIONAL PAID-IN
CAPITAL:
|
|
|
|
|
|
|
|
|
Balance, beginning
|
|
|
|
|
|
|
58,670,698
|
|
Cashless exercise of common stock
options and warrants
|
|
|
|
|
|
|
(32,801
|
)
|
Conversion of redeemable
convertible preferred stock to common stock
|
|
|
|
|
|
|
39,768
|
|
Stock-based compensation
|
|
|
|
|
|
|
757,442
|
|
Exercise of common stock options
and warrants
|
|
|
|
|
|
|
17,988,794
|
|
Issuance of common stock to
related party
|
|
|
|
|
|
|
348,300
|
|
Issuance of common stock to
related party in lieu of commission relating to exercise of
warrants
|
|
|
|
|
|
|
(14,699
|
)
|
|
|
|
|
|
|
|
|
|
Balance, end
|
|
|
|
|
|
|
77,757,502
|
|
|
|
|
|
|
|
|
|
|
ACCUMULATED OTHER COMPREHENSIVE
INCOME:
|
|
|
|
|
|
|
|
|
Balance, beginning
|
|
|
|
|
|
|
|
|
Unrealized gains on derivative
instrument
|
|
|
|
|
|
|
1,754,365
|
|
Reclassification of gain on
derivative instrument
|
|
|
|
|
|
|
(792,350
|
)
|
|
|
|
|
|
|
|
|
|
Balance, end
|
|
|
|
|
|
|
962,015
|
|
|
|
|
|
|
|
|
|
|
ACCUMULATED DEFICIT:
|
|
|
|
|
|
|
|
|
Balance, beginning
|
|
|
|
|
|
|
(2,660,134
|
)
|
Dividends accrued
|
|
|
|
|
|
|
(4,295
|
)
|
Net loss
|
|
|
|
|
|
|
(1,949,846
|
)
|
|
|
|
|
|
|
|
|
|
Balance, end
|
|
|
|
|
|
|
(4,614,275
|
)
|
|
|
|
|
|
|
|
|
|
TOTAL SHAREHOLDERS
EQUITY
|
|
|
|
|
|
$
|
74,924,893
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
F-41
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
Six Months Ended June 30, 2006 and 2005
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
CASH FLOWS FROM OPERATING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(1,949,846
|
)
|
|
$
|
(736,997
|
)
|
Adjustments to reconcile net loss
to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
3,024,166
|
|
|
|
117,504
|
|
Amortization of debt issuance costs
|
|
|
383,422
|
|
|
|
|
|
Accretion of asset retirement
obligation
|
|
|
36,989
|
|
|
|
|
|
Stock-based compensation
|
|
|
392,149
|
|
|
|
|
|
Equity in (loss) income of
non-consolidated entities
|
|
|
158,714
|
|
|
|
(12,397
|
)
|
Other
|
|
|
(20,950
|
)
|
|
|
|
|
Minority interest in income of
subsidiaries
|
|
|
17,919
|
|
|
|
6,190
|
|
Changes in operating assets and
liabilities, net
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,568,754
|
)
|
|
|
65,667
|
|
Accounts receivable
related party
|
|
|
|
|
|
|
(10,792
|
)
|
Drilling advance assets
|
|
|
(988,734
|
)
|
|
|
|
|
Prepaid expenses
|
|
|
(88,528
|
)
|
|
|
(36,752
|
)
|
Accounts payable
|
|
|
2,634,781
|
|
|
|
126,333
|
|
Drilling advance liabilities
|
|
|
622,537
|
|
|
|
(143,807
|
)
|
Accrued liabilities
|
|
|
(16,959
|
)
|
|
|
165,080
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
operating activities
|
|
|
2,636,906
|
|
|
|
(459,971
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
Capital expenditures for oil and
gas development
|
|
|
(42,459,080
|
)
|
|
|
(14,447,849
|
)
|
Capital expenditures for property
and equipment
|
|
|
(219,694
|
)
|
|
|
(105,677
|
)
|
Proceeds from sale of oil and gas
properties
|
|
|
10,500,000
|
|
|
|
7,373,737
|
|
Proceeds from sale of other
investments
|
|
|
13,096
|
|
|
|
|
|
Payments for capitalized merger
costs
|
|
|
|
|
|
|
(263,092
|
)
|
Advances of notes receivable
|
|
|
(30,000
|
)
|
|
|
(72,379
|
)
|
Advances of notes
receivable related parties
|
|
|
(30,000
|
)
|
|
|
|
|
Payments received on notes
receivable related parties
|
|
|
17,000
|
|
|
|
85,000
|
|
Purchase of member interest in
Hudson Pipelines and Processing Co., L.L.C.
|
|
|
(162,108
|
)
|
|
|
(501,956
|
)
|
Investment in unconsolidated
subsidiary
|
|
|
(475,000
|
)
|
|
|
(14,000
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(32,845,786
|
)
|
|
|
(7,946,216
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
Short-term bank borrowings
(payments)
|
|
|
(6,200,000
|
)
|
|
|
(350,000
|
)
|
Advances on senior secured credit
facility, net of financing costs of $2,386,613
|
|
|
9,997,394
|
|
|
|
|
|
Advances on mezzanine financing,
net of financing costs of $150,000
|
|
|
|
|
|
|
9,850,000
|
|
Payments on mortgage obligation
|
|
|
(32,080
|
)
|
|
|
|
|
Payments on notes
payable related party
|
|
|
(69,833
|
)
|
|
|
(2,948,698
|
)
|
Payments on capital lease
obligations
|
|
|
(3,912
|
)
|
|
|
(4,068
|
)
|
Distributions to minority interest
members
|
|
|
|
|
|
|
(805,000
|
)
|
Net proceeds from sales of common
stock
|
|
|
|
|
|
|
11,025,000
|
|
Net proceeds from exercise of
options and warrants
|
|
|
18,144,449
|
|
|
|
|
|
Dividends paid on preferred stock
|
|
|
(12,823
|
)
|
|
|
(44,340
|
)
|
Other
|
|
|
|
|
|
|
20,177
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
21,823,195
|
|
|
|
16,743,071
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and
cash equivalents
|
|
|
(8,385,685
|
)
|
|
|
8,336,884
|
|
Cash and cash equivalents,
beginning of the period
|
|
|
11,980,638
|
|
|
|
5,179,582
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of
the period
|
|
$
|
3,594,953
|
|
|
$
|
13,516,466
|
|
|
|
|
|
|
|
|
|
|
NON-CASH FINANCING AND INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
Oil and gas properties asset
retirement obligation
|
|
$
|
976,343
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of oil and gas working
interest through senior secured credit facility
|
|
$
|
27,615,993
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
CASH PAID FOR INTEREST
|
|
$
|
3,430,225
|
|
|
$
|
632,500
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
F-42
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
|
|
NOTE 1.
|
ORGANIZATION
AND NATURE OF BUSINESS
|
Effective May 11, 2006, Cadence Resources Corporation
(Cadence) and its wholly owned subsidiaries
(the Company) amended its articles of incorporation
to change the parent company name to Aurora Oil & Gas
Corporation (AOG). AOG is an oil and gas company
engaged in the exploration, acquisition, development, production
and sale of natural gas and crude oil. AOG 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, AOG (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. Although the merger was structured such
that Aurora became a wholly-owned subsidiary of AOG (formerly
Cadence), 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) Auroras 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) Auroras senior management prior to the merger
dominated the senior management of the combined company.
As an independent oil and gas producer, the Companys
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 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 Companys 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
|
The financial information included herein is unaudited. However,
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 amounts as reported in the 2005 financial
statements have been reclassified to conform with the 2006
presentation.
Certain information, accounting policies and footnote
disclosures normally included in the financial statements
prepared in accordance with accounting principles generally
accepted in the United States of America have been condensed or
omitted pursuant to certain rules and regulations of the
Securities and Exchange Commission. These financial statements
should be read in conjunction with the audited consolidated
financial statements and notes for the year ended
December 31, 2005.
As a result of the reverse acquisition discussed in Note 1,
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
condensed consolidated financial statements for the six months
ended June 30, 2005 and related notes have been
retroactively adjusted to give effect to the reverse merger on
October 31, 2005.
|
|
NOTE 3.
|
ACCOUNTING
FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS
|
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. This Interpretation
clarifies that the term conditional asset retirement
obligation refers to a legal obligation to perform an
asset retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity. Accordingly, an
entity is
F-43
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 fields surface
lands to ecological condition similar to that existing before
oil and gas extraction began. Prior to January 1, 2006,
such amount was not considered material.
Effective January 1, 2006, the Company recorded a liability
of $812,634 (an asset retirement obligation or
ARO) on the consolidated balance sheet and
capitalized the asset retirement cost to oil and gas properties.
In general, the amount of an 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 on the
condensed consolidated statement of operations.
The change in the ARO for the six months ended June 30,
2006 is as follows:
|
|
|
|
|
Balance as of January 1, 2006
|
|
$
|
812,634
|
|
Accretion expense
|
|
|
15,237
|
|
|
|
|
|
|
Balance as of March 31, 2006
|
|
|
827,871
|
|
Additions
|
|
|
263,026
|
|
Revisions
|
|
|
(99,317
|
)
|
Accretion expense
|
|
|
21,749
|
|
|
|
|
|
|
Balance as of June 30, 2006
|
|
$
|
1,013,329
|
|
|
|
|
|
|
|
|
NOTE 4.
|
RECENT
ACCOUNTING PRONOUNCEMENTS
|
In February 2006, the FASB issued SFAS 155,
Accounting for Certain Hybrid Financial Instrument
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 re-measurement 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.
Management believes the adoption of this standard will not have
a material impact on the consolidated financial position,
results of operations, or liquidity.
In February 2006, the FASB issued Financial Staff Position
(FSP) No. 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 employees control. These
instruments are not required to be classified as a liability
until it becomes probable that the event will occur. We adopted
this FSP in the second quarter of 2006. The implementation did
not have an effect on the results of operations or financial
position.
In April 2006, the FASB issued FSP No. FIN 46(R)-6,
Determining the Variability to Be Considered in Applying
FASB Interpretation No. 46(R), which requires the use
of a by design approach for determining whether an
interest is variable when applying FASB Interpretation
No. 46, Consolidation of Variable Interest
Entities. This approach includes evaluating whether an
interest is variable based on a thorough understanding of the
design of the potential variable interest entity
(VIE), including the nature of the risks that the
potential VIE
F-44
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
was designed to create and pass along to interest holders in the
entity. The guidance in this FSP is effective for reporting
periods beginning after June 15, 2006. We will adopt the
guidance presented in this FSP in the third quarter of 2006 on a
prospective basis. We do not expect the adoption of this FSP to
have a material impact on our results of operations or financial
position.
In July 2006, the Financial Accounting Standards Board (FASB)
issued Interpretation No. 48, Accounting for
Uncertainty in Income Taxes, an Interpretation of SFAS Statement
No. 109. This Interpretation clarifies the accounting
for uncertainty in income taxes recognized in an
enterprises 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
de-recognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition. This
Interpretation is effective for fiscal years beginning after
December 15, 2006. We currently are assessing the impact of
Interpretation No. 48 on our results of operations and
financial position.
|
|
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 a swap instrument in order to hedge a portion of
its production. The purpose of the swap is to provide a measure
of stability to the Companys cash flow in meeting
financial obligations while operating in a volatile gas market
environment. The derivative reduces the Companys 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 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 Companys balance sheet until
the hedged item is recognized in earnings as gas revenue. If
this hedge has an ineffective portion, that particular portion
of the gain or loss would be immediately reported in earnings.
Effective April 1, 2006, the Company entered into financial
swap contract for 5,000 mmbtu per day at a fixed price of
$8.59 per mmbtu covering a
12-month
period. For the six months ended June 30, 2006, the Company
has recognized in Accumulated Other Comprehensive Income, net
unrealized gain of $962,015 on a swap contract that has been
designated as a cash flow hedge on forecasted sales of natural
gas. The balance is expected to be reclassified into earnings
within the next nine months. The Company has also recorded as of
June 30, 2006, a corresponding short-term derivative
instrument asset totaling $962,015 in Current Assets. In
addition, for six months ended June 30, 2006, the Company
recorded a $792,350 net gain in earnings from hedging
activities (included in oil and gas revenues).
For the six months ended June 30, 2005, the Company had no
derivative instruments to manage price risk on its natural gas
production.
On July 14, 2006, the Company entered into another
financial swap contract for 5,000 mmbtu per day at a fixed
price of $9.00 per MMBtu for the period from April 1,
2007 through December 31, 2008.
Financial
Instruments
The Companys financial instruments consist primarily of
cash, accounts receivable, loans receivable, accounts payable,
accrued expenses and debt. The carrying amounts of such
financial instruments approximate
F-45
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 gas leases, working
interests, and interests in related pipelines and production
facilities that are located in the Hudson Township area of the
Michigan Antrim gas play. The interests acquired are
collectively referred to as the Hudson Properties. In addition,
the interests in the related pipelines and production facilities
were acquired through a membership interest in Hudson Pipeline
and Processing Co., L.L.C. (HPPC). North previously
owned a working interest in the properties and membership
interest in HPPC. This acquisition increased Norths
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%.
The total purchase price for the Hudson Properties and HPPC was
$27,500,000 subject to certain adjustments provided for in the
purchase agreement. North also acquired an additional 2.5%
membership interest in HPPC effective January 1, 2006 which
increased the membership interest to 93.44%.
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 Companys
accompanying 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 gas leases from Wabash
Energy Partners, L.P. for a purchase price of $11,840,000.
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. Internal funds of Aurora were used to pay the net
transaction cost of these transactions.
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 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 subsidiarys
share of anticipated future drilling expense, approximately
$5,500,000 of net proceeds was retained by Aurora.
2005-
GeoPetra Partners, L.L.C. Investment
In June 2005, the Company acquired a 30% 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 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 gas and
(iii) providing consultation, advice and recommendations to
the members of GeoPetra in connection with other oil and gas
properties and interests, operations and activities. GeoPetra
was formed April 1, 2005.
F-46
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, a Company executive
officer pledged certain shares of AOG common stock under his
control. The interest rate is Wall Street prime with interest
payable monthly in arrears. Principal is payable at the
expiration of the line of credit, October 15, 2006. As of
June 30, 2006, Northwestern Bank reduced the revolving
line-of-credit
by $90,000 for outstanding letters of credit (as described in
Note 13 Contingencies and Commitments).
Interest expense for the six months ended June 30, 2006 was
$178,454.
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.
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, plus personal guaranties of three of
the Companys officers. The payment schedule is monthly
interest only for the first three 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 six months ended June 30, 2006 was $99,734.
Mezzanine
Financing
On December 8, 2005, the Company entered into an Amended
Note Purchase Agreement, to increase its five-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, calculated 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
specified expenses including capital expenditures from
gross cash revenue. The maturity date is
September 29, 2009. The borrowing capacity is impacted by,
among other factors, the fair value of the Companys
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 capacity as 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).
Pursuant to the mezzanine financing arrangement, North conveyed
to TCW a 4% overriding royalty interest net to Norths
interest, in all of Norths existing oil and gas leases in
the counties of Alcona, Alpena, Charlevoix, Cheboygan,
Montmorency and Otsego in the State of Michigan. Additionally,
North is required to convey a 4%
F-47
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
overriding royalty interest, net to its interest, in any new
leases acquired in these counties while the loan is outstanding.
For the six months ended June 30, 2006, interest expense
for the mezzanine credit facility was $2,351,111 of which
$555,522 was capitalized. For the six months ended June 30,
2005 interest expense was $641,221 of which $456,667 was
capitalized.
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 is
$40 million without hedges. As proved reserves are added,
this borrowing base may increase to $50 million without TCW
consent, and $100 million with TCW consent. A required
semi-annual 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 AOG 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. This facility provides for
borrowings tied to BNPs prime rate (or, if higher, the
federal funds effective rate plus 0.5%) or a LIBOR-based rate
(LIBOR multiplied by a statutory reserve rate) plus 1.25 to 2.0%
depending on the borrowing base utilization under the facility.
For the six months ended June 30, 2006, interest expense
was $1,106,397 of which $91,455 was capitalized and interest
paid was $746,327.
On July 14, 2006, the senior secured credit facility was
amended in two respects. The credit availability was increased
to $50 million. In addition, the trailing
12-month
interest coverage ratio covenant was amended to defer this
requirement until the fourth quarter of 2006, and to provide for
a reduced ratio for that quarter. The latter 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 describe 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 first quarter of 2006.
The senior secured 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 a current ratio and an
interest coverage ratio.
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 six-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
20,315,422 shares were issued during the six months ended
June 30, 2006 representing 15,565,457 shares issued
for cash proceeds of $18,144,449, and 4,749,965 shares
issued pursuant to cashless exercises of the applicable and
other warrants or options. In December 2005 an additional
2,160,000 shares were issued for cash proceeds of
$2,916,000.
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 in June 2006, two directors of the Company were
issued 30,000 shares each for their services provided to
Aurora Energy, Ltd. as Board members prior to the merger with
Cadence. Compensation expense related to this activity was
recorded in 2005.
F-48
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 9.
|
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 six months ended June 30, 2006, the Company
recorded stock-based compensation of $757,442 under the 2006
Stock Incentive Plan (as described in Note 10 Common
Stock Options) and a certain employment agreement (as
described in Note 13 Contingencies and
Commitments). Of that amount, $392,149 has been included
in general and administrative expense on the condensed
consolidated statement of operations and $365,293 has been
capitalized in oil and gas properties. The impact on future net
income is estimated to be $4,538,193 recognized over the
applicable requisite service period of approximately three years.
Prior to 2006, the Company applied APB No. 25 and related
interpretations in accounting for its plans. Under APB 25,
the exercise price of the stock options was more than the market
value of the shares at the date of grant and, accordingly, no
compensation cost has been recognized in the condensed
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 six months ended June 30, 2005:
|
|
|
|
|
|
|
2005
|
|
|
Net loss
|
|
$
|
(736,997
|
)
|
Deduct total stock-based
compensation expense determined under fair value based method
for all awards, net of relaxed tax effects
|
|
|
|
|
|
|
|
|
|
Pro forma net loss
|
|
$
|
(736,997
|
)
|
|
|
|
|
|
Loss per share basic
and diluted
|
|
|
|
|
As reported
|
|
$
|
(0.02
|
)
|
Pro forma
|
|
$
|
(0.02
|
)
|
There were no options granted during the six months ended
June 30, 2005.
|
|
NOTE 10.
|
COMMON
STOCK OPTIONS
|
Stock
Option Plans
At December 31, 2005, the Company had two stock-based
compensation plans, which are more fully described in
Note 18 to the audited financial statements for the year
ended December 31, 2005. Prior to 2006, the Company
accounted for those plans under the recognition and measurement
provisions of Accounting Principles Board (APB)
Opinion No. 25, Accounting for Stock Issued to
Employees, and its related Interpretations. No stock-based
employee compensation cost was reflected in previously reported
results, as all options granted under those plans had an
exercise price equal to the market value of the underlying
common stock on the date of grant.
On March 16, 2006, the Companys Board of Directors
adopted an incentive stock option plan as part of a larger
equity incentive plan (the 2006 Stock Incentive
Plan) that also provides for non-statutory stock options,
stock bonuses and restricted stock awards. The stockholders
approved the Plan at the annual meeting of the stockholders on
May 19, 2006. 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 non-
F-49
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
employee directors of the Company and to provide incentives for
such persons to exert maximum efforts for the success of the
Company and affiliates. The 2006 Stock Incentive Plan provides
that no more than 8,000,000 shares of stock may be issued
in equity awards under the plan, the exercise price for
incentive stock options shall not be less than 100% of fair
market value on the date of grant, and unless otherwise
determined by the Board, the exercise price for non-statutory
stock options shall be not less than 100% of fair market value
on the date of grant. The maximum term of options granted is
10 years.
Activity related to the three stock option plans (2006 Stock
Incentive Plan, 2004 Equity Incentive Plan and the 1997 Stock
Option Plan) was as follows for the six months ended
June 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Options outstanding at beginning
of period
|
|
|
1,205,000
|
|
|
|
344,000
|
|
Options granted
|
|
|
2,333,500
|
|
|
|
|
|
Options forfeited and other
adjustments
|
|
|
(419,266
|
)
|
|
|
|
|
Options exercised
|
|
|
(254,734
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at end of
period
|
|
|
2,864,500
|
|
|
|
344,000
|
|
|
|
|
|
|
|
|
|
|
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
|
%
|
|
|
|
|
Expected years until exercise
|
|
|
2.5-6.0
|
|
|
|
|
|
Expected stock volatility
|
|
|
41
|
%
|
|
|
|
|
Dividend yield
|
|
|
0
|
%
|
|
|
|
|
For six months ended June 30, 2006, the Company recorded
stock-based compensation of $722,757 for the 2006 Stock
Incentive Plan. Of that amount, $357,464 has been included in
general and administrative expense on the consolidated statement
of operations and $365,293 has been capitalized.
All
Stock Options
Activity with respect to all stock options is presented below
for six months ended June 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
Weighted Average
|
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
Options outstanding at beginning
of period
|
|
|
6,448,468
|
|
|
$
|
0.72
|
|
|
|
2,700,664
|
|
|
$
|
0.99
|
|
Options granted
|
|
|
2,333,500
|
|
|
|
3.96
|
|
|
|
|
|
|
|
|
|
Options exercised
|
|
|
(3,642,926
|
)
|
|
|
0.67
|
|
|
|
|
|
|
|
|
|
Forfeitures and other adjustments
|
|
|
(344,266
|
)
|
|
|
4.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at end of
period
|
|
|
4,794,776
|
|
|
|
2.05
|
|
|
|
2,700,664
|
|
|
|
0.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
2,751,609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of
options granted
|
|
|
|
|
|
$
|
4.84
|
|
|
|
|
|
|
$
|
0.81
|
|
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 June 30, 2006 was
F-50
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
approximately $9,942,000 and intrinsic value of the options
exercisable at June 30, 2006 was approximately $8,605,000.
The intrinsic value of the options exercised during the six
months ended June 30, 2006 was $12,118,000.
The weighted average remaining life by exercise price as of
June 30, 2006 is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
|
|
|
Average
|
|
|
Exercisable
|
|
|
Average
|
|
Range of Exercise Prices
|
|
Shares
|
|
|
Life
|
|
|
Shares
|
|
|
Life
|
|
|
$0.25 - $0.38
|
|
|
857,996
|
|
|
|
3.9
|
|
|
|
857,996
|
|
|
|
3.9
|
|
$0.50 - $0.75
|
|
|
1,580,000
|
|
|
|
2.5
|
|
|
|
1,580,000
|
|
|
|
2.5
|
|
$1.25 - $1.75
|
|
|
402,000
|
|
|
|
7.4
|
|
|
|
110,000
|
|
|
|
2.2
|
|
$2.45 - $2.55
|
|
|
150,280
|
|
|
|
3.5
|
|
|
|
60,280
|
|
|
|
3.0
|
|
$3.62
|
|
|
1,000,000
|
|
|
|
4.4
|
|
|
|
|
|
|
|
|
|
$4.55 - $4.70
|
|
|
554,500
|
|
|
|
9.6
|
|
|
|
3,333
|
|
|
|
8.8
|
|
$5.19 - $5.54
|
|
|
250,000
|
|
|
|
6.2
|
|
|
|
140,000
|
|
|
|
4.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,794,776
|
|
|
|
4.5
|
|
|
|
2,751,609
|
|
|
|
3.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 11.
|
COMMON
STOCK WARRANTS
|
The following table provides information related to stock
warrant activity for the six months ended June 30, 2006:
|
|
|
|
|
|
|
Number of
|
|
|
|
Shares Underlying
|
|
|
|
Warrants
|
|
|
Outstanding at beginning of the
period
|
|
|
19,697,500
|
|
Granted
|
|
|
|
|
Exercised under early exercise
program
|
|
|
(13,182,625
|
)
|
Exercised
|
|
|
(3,489,871
|
)
|
Forfeited
|
|
|
(945,504
|
)
|
|
|
|
|
|
Outstanding at the end of the
period
|
|
|
2,079,500
|
|
|
|
|
|
|
As of June 30, 2006, these common stock warrants had an
average remaining contractual life of 2.39 years and
weighted average exercise price per share of $1.71.
|
|
NOTE 12.
|
NET
INCOME (LOSS) PER SHARE
|
Basic earnings (loss) per share are computed by dividing net
income (loss) by the weighted average number of common shares
outstanding for the period. The computation of diluted net
income (loss) per share reflects the potential dilution that
could occur if securities or other contracts to issue common
stock were exercised or converted into common stock or resulted
in the issuance of common stock that would then share in the
earnings of the Company.
During the six months ended June 30, 2006 and 2005, stock
options, warrants and convertible preferred stock were excluded
in the computation of diluted loss per share because their
effect was anti-dilutive.
F-51
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 13.
|
CONTINGENCIES
AND COMMITMENTS
|
Environmental
Risk
Due to the nature of the oil and 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, 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 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 set-off against all of the Companys deposit
accounts with Northwestern Bank. At June 30, 2006, a total
of $852,500 letters of credit to the Michigan Supervisor of
Wells were outstanding.
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 two-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 Companys common stock
on January 1, 2009, so long as he remains employed by the
Company through June 18, 2008. 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.
|
|
NOTE 14.
|
RETIREMENT
BENEFITS
|
Effective May 1, 2006, the Company established a qualified
retirement plan referred to as 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
twelve 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 non-elective contributions
to the Plan. Company-provided contributions are subject to
certain vesting schedules.
|
|
NOTE 15.
|
OIL AND
GAS PROPERTIES HELD FOR SALE
|
Management is currently in the process of evaluating the
Companys property portfolio to ensure that the oil and gas
properties portfolio properly matches the Companys
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 gas properties held for sale
amounted to $21,365,575 at June 30, 2006 of which
$11,857,821 is proved and $9,507,754 is unproved. These
properties are carried at the lower of historical cost
F-52
AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
or fair value. Under the full cost method, sales of oil and 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 and determined that there is no significant effect on
the proved reserves regarding the assets held for sale. At
June 30, 2005, no properties were classified as held for
sale.
|
|
NOTE 16.
|
SUBSEQUENT
EVENTS
|
Pending
Acquisition
On May 9, 2006, North signed a letter of intent with a
third party to acquire oil and gas leases, working interests,
and interests in related pipelines and production facilities
that are located in the Michigan Antrim. This encompasses two
projects that are 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. This
acquisition remains contingent on the review and approval of the
financial institutions providing financing to the Company.
Bach
Acquisition
On July 10, 2006, the Company entered into a binding letter
of intent to purchase all the assets of Bach Enterprises,
Inc., certain assets owned by Bach Energy, LLC and a limited
liability company known as Kingsley Development LLC (together
Bach). The letter of intent contemplates a
60 day due diligence period followed by notice and a
30 day cure period if material issues are identified in the
due diligence process. Closing is expected to occur within
90 days. Bach is primarily an oil and 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.
DeSoto
Parish, Louisiana Disposition
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) 14 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 is July 1, 2006.
F-53
APPENDIX
A
Reserve
and Economic Evaluation of
Proved Reserves of Certain
Aurora Oil & Gas Corporation
Michigan Properties
As of July 1, 2006
Unescalated Prices and Costs
Prepared For
Aurora Oil & Gas Corporation
Traverse City, Michigan
Prepared By
Data & Consulting Services
Division of Schlumberger Technology Corporation
Pittsburgh, Pennsylvania
September
2006
A-1
Data & Consulting Services
Division of Schlumberger Technology Corporation
1310 Commerce Drive
Park Ridge One
Pittsburgh, PA
15275-1011
Tel: 412-787-5403
Fax: 412-787-2906
14 September 2006
Aurora Oil & Gas Corporation
4110 Copper Ridge Drive
Suite 100
Traverse City, MI 49684
Dear Gentlemen:
At the request of Aurora Oil & Gas Corporation
(AURORA), Schlumberger Data & Consulting Services,
Division of Schlumberger Technology Corporation (DCS) has
prepared a reserve and economic evaluation of certain proved
reserves in several Antrim Shale projects as of July 1,
2006. Certain data from this project are required for disclosure
as required by the Securities and Exchange Commission (SEC)
Regulation S-K.
The SEC recognizes only proved reserves. As such the value of
the pipeline revenue and financial hedges should not be included
in filings with the SEC or summarized with the Proved values.
Unescalated prices and costs were used for all properties
contained in this evaluation. These projects were evaluated to a
maximum remaining reserve life of 40 years. All economics
presented are before federal income taxes (BFIT). The proved net
reserves and economic valuation thereof are summarized in
Table 1.
TABLE
1
ESTIMATED NET RESERVES & INCOME
CERTAIN PROVED OIL & GAS INTERESTS
AURORA OIL & GAS CORPORATION
AS OF JULY 1, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
Proved
|
|
|
|
|
|
Total
|
|
|
|
Developed
|
|
|
Developed
|
|
|
Proved
|
|
|
Proved
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Reserves
|
|
|
Remaining Net
Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMscf
|
|
|
57,645.62
|
|
|
|
13,293.90
|
|
|
|
30,471.95
|
|
|
|
101,411.47
|
|
Income Data
(M$)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Revenue
|
|
|
329,156.47
|
|
|
|
75,908.18
|
|
|
|
173,994.81
|
|
|
|
579,059.46
|
|
Deductions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production Taxes
|
|
|
19,749.39
|
|
|
|
4,554.49
|
|
|
|
10,439.69
|
|
|
|
34,743.57
|
|
Net AdValorem Taxes
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
Net Investment
|
|
|
0.00
|
|
|
|
1,062.69
|
|
|
|
24,886.80
|
|
|
|
25,949.49
|
|
Net Well Costs
|
|
|
71,002.85
|
|
|
|
10,657.69
|
|
|
|
32,656.49
|
|
|
|
114,317.03
|
|
Other Costs
|
|
|
69,262.60
|
|
|
|
16,779.97
|
|
|
|
34,041.61
|
|
|
|
120,084.18
|
|
Future Net Income (FNI)
|
|
|
169,141.64
|
|
|
|
42,853.98
|
|
|
|
71,970.23
|
|
|
|
283,965.85
|
|
Discounted PV@10% (M$)
|
|
|
81,252.03
|
|
|
|
20,508.01
|
|
|
|
23,714.66
|
|
|
|
125,474.70
|
|
A-2
Data & Consulting Services
Division of Schlumberger Technology Corporation
14 September 2006
Page 2
RESERVE
ESTIMATE
Reservoir simulation and history matching of analogous offset
projects provide the basis for the production forecasts for the
projects. The reservoir simulation was conducted using
SHALEGAStm,
DCSs multi-phase reservoir simulator designed specifically
for evaluating fractured shale formations. We used
SHALEGAStm
to history match the data from existing wells as supplied by
AURORA in the respective projects or offset projects. Using the
resulting reservoir properties and the proposed well spacing for
each project, we used
SHALEGAStm
to forecast a typical curve shape from which we could construct
a type curve for each project. The estimates of reserves are in
the Reserve Summaries and Reserve Details sections
of this report. We utilized PhdWin to generate these reports.
Reserve estimates are strictly technical judgments. The accuracy
of any reserve estimate is a function of the quality of data
available and of the engineering and geological interpretations.
The reserve estimates presented in this report are believed
reasonable; however, they are estimates only and should be
accepted with the understanding that reservoir performance
subsequent to the date of the estimate may justify their
revision.
RESERVE
CATEGORIES
Reserves were assigned to the proved developed producing (PDP),
proved non-producing (PDNP), and proved undeveloped (PUD)
reserve categories. Oil and gas reserves by definition fall into
one of the following categories: proved, probable, and possible.
The proved category is further divided into: developed and
undeveloped. The developed reserve category is even further
divided into the appropriate reserve status subcategories:
producing and non-producing. Non-producing reserves include
shut-in and behind-pipe reserves. All reserve categories used in
this report conform to the definitions approved by the
Securities and Exchange Commission (SEC);
Regulation S-X,
Rule 4-10
(A). These are presented in Reserves Definitions section
of this report.
The reserves and income attributable to the various reserve
categories included in this report have not been adjusted to
reflect the varying degrees of risk associated with them.
ECONOMIC
TERMS
Net revenue (sales) is defined as the total proceeds from the
sale of oil, condensate, natural gas liquids (NGL), and natural
gas before any deductions. Future net income (cashflow) is
future net revenue less net lease operating, transportation,
processing, and marketing expenses, and state severance or
production taxes. No provisions for State or Federal income
taxes are made in this evaluation. The present worth (discounted
cashflow) at various discount rates is calculated on a monthly
basis. Net well costs represent the per well lease
operating costs and other costs include variable
operating expenses together with PPC costs on a per unit basis.
These costs are listed in Table 2. State and local
production and AdValorem taxes are listed in Table 3. All
costs and prices were unescalated.
A-3
Data & Consulting Services
Division of Schlumberger Technology Corporation
14 September 2006
Page 3
TABLE
2
OPERATING COSTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE
|
|
|
LOE
|
|
|
PPC
|
|
State
|
|
Field
|
|
Unit
|
|
Operator
|
|
($/Well/Mo.)
|
|
|
($/MCF)
|
|
|
($/MCF)
|
|
|
Michigan
|
|
1500 Antrim
|
|
Greenwood 11/12
|
|
O.I.L. Energy Corp.
|
|
|
2,000
|
|
|
|
0.000
|
|
|
|
0.282
|
|
|
|
400 Antrim
|
|
Silver
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
1.500
|
|
|
|
Alcona
|
|
Mt. Mohican
|
|
Samson Resources Co.
|
|
|
2,000
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
Alpena
|
|
Beyer
|
|
Samson Resources Co.
|
|
|
1,900
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Black Bean #1
|
|
Samson Resources Co.
|
|
|
1,725
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Black Bean #2
|
|
Samson Resources Co.
|
|
|
1,250
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Black Bean #3
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Black Bean #4
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Discard
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
El Dorado
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Gehrke
|
|
Samson Resources Co.
|
|
|
1,200
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Green Bean #1
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Green Bean #2
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Leeseberg #1
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Leeseberg #2
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Mackinaw #1
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Mackinaw #2
|
|
Samson Resources Co.
|
|
|
2,475
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Nicholson Hill #1
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Nicholson Hill #2
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Nicholson Hill #3
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Paxton Quarry
|
|
Samson Resources Co.
|
|
|
2,125
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Seguin
|
|
Samson Resources Co.
|
|
|
1,300
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Spruce Up
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Treasure Island
|
|
Samson Resources Co.
|
|
|
2,200
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
|
|
Werth While
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
Arrowhead
|
|
Arrowhead South
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.250
|
|
|
|
|
|
Blue Chip
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.250
|
|
|
|
|
|
Blue Lakes
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.250
|
|
|
|
|
|
Gaylord Fishing Club
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.250
|
|
|
|
Black Bear
|
|
Black Bear Central
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
1.366
|
|
|
|
|
|
Black Bear West
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
1.366
|
|
|
|
Clear Lake
|
|
Clear Lake
|
|
Samson Resources Co.
|
|
|
1,775
|
|
|
|
0.000
|
|
|
|
0.520
|
|
|
|
Dover
|
|
Dover
|
|
Savoy Energy, LP
|
|
|
6,000
|
|
|
|
0.000
|
|
|
|
0.247
|
|
|
|
Hudson
|
|
Boyne Valley
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.936
|
|
|
|
|
|
Chandler
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.936
|
|
|
|
|
|
Corwith
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.936
|
|
|
|
|
|
Hudson 13
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.936
|
|
|
|
|
|
Hudson 19
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
2.110
|
|
|
|
1.280
|
|
|
|
|
|
Hudson 34
|
|
Aurora Energy, Ltd.
|
|
|
1,600
|
|
|
|
0.000
|
|
|
|
0.572
|
|
|
|
|
|
Hudson NE
|
|
Aurora Energy, Ltd.
|
|
|
1,050
|
|
|
|
0.414
|
|
|
|
0.623
|
|
|
|
|
|
Hudson North
|
|
Aurora Energy, Ltd.
|
|
|
850
|
|
|
|
0.500
|
|
|
|
0.939
|
|
|
|
|
|
Hudson NW
|
|
Aurora Energy, Ltd.
|
|
|
650
|
|
|
|
0.651
|
|
|
|
0.939
|
|
|
|
|
|
Hudson SW
|
|
Aurora Energy, Ltd.
|
|
|
1,600
|
|
|
|
0.000
|
|
|
|
0.855
|
|
|
|
|
|
Hudson West
|
|
Aurora Energy, Ltd.
|
|
|
700
|
|
|
|
2.620
|
|
|
|
1.284
|
|
|
|
Warner 36 VII
|
|
Warner 36 VII
|
|
O.I.L. Energy Corp.
|
|
|
1,650
|
|
|
|
0.000
|
|
|
|
0.344
|
|
A-4
Data & Consulting Services
Division of Schlumberger Technology Corporation
14 September 2006
Page 2
TABLE
3
TAXES
|
|
|
State Production Tax Rate
|
|
6% of Revenue
|
PRICING
AND ECONOMIC PARAMETERS
AURORA supplied all product prices, costs, and economic
parameters used in this report. Data from AURORA were accepted
as presented. All economics were run to economic life or
40 years which ever occurs first utilizing the gas price
deck provided to us by AURORA. Gas prices were held constant
through the evaluation life at $5.71/MMBtu
OTHER
INCOME (NOT TO BE REPORTED IN SEC FILINGS)
[Intentionally Omitted]
TABLE
4
ESTIMATED NET INCOME FROM PIPELINES & FINANCIAL
HEDGES
(NOT FOR INCLUSION IN SEC RESERVE REPORTS)
AURORA OIL & GAS CORPORATION
AS OF JULY 1, 2006
[Table Intentionally Omitted]
OWNERSHIP
The leasehold interests were supplied by AURORA and were
accepted as presented. No leasehold purchase costs were included
in this evaluation. No attempt was made by the undersigned to
verify the title or ownership of the interests evaluated.
GENERAL
All data used in this study were obtained from AURORA, public
industry information sources, or the non-confidential files of
DCS. A field inspection of the properties was not made in
connection with the preparation of this report.
The potential environmental liabilities attendant to ownership
and/or
operation of the properties have not been addressed in this
report. Abandonment and
clean-up
costs and possible salvage value of the equipment were not
considered in this report.
In evaluating the information at our disposal related to this
report, we have excluded from our consideration all matters
which require a legal or accounting interpretation, or any
interpretation other than those of an engineering or geological
nature. In assessing the conclusions expressed in this report
pertaining to all aspects of oil and gas evaluations, especially
pertaining to reserve evaluations, there are uncertainties
inherent in the interpretation of engineering data, and such
conclusions represent only informed professional judgments.
Data and worksheets used in the preparation of this evaluation
will be maintained in our files in Pittsburgh and will be
available for inspection by anyone having proper authorization
by AURORA.
This report was prepared solely for the use of the party to whom
it is addressed and any disclosure made of this report
and/or the
contents by said party thereof shall be solely the
responsibility of said party, and shall in no way constitute any
representation of any kind whatsoever of the undersigned with
respect to the matters being addressed.
A-5
Data & Consulting Services
Division of Schlumberger Technology Corporation
14 September 2006
Page 5
We appreciate the opportunity to perform this evaluation and are
available should you need further assistance in this matter.
|
|
|
|
|
Sincerely yours,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeron R. Williamson
Senior Petroleum Engineer
|
|
David A. Wozniak, P.E.
Senior Petroleum Engineer
|
|
Charles M. Boyer II, P.G.
Principle Consultant Group Leader
|
A-6
SECURITIES
AND EXCHANGE COMMISSION
REGULATION S-X,
RULE 4-10
(A)
RESERVES
DEFINITIONS
Oil and
Gas Producing Activities
Such activities include (A) the search for crude oil,
including condensate and natural gas liquids, or natural gas
(oil and gas) in their natural states and original
locations; (B) the acquisition of property rights or
properties for the purpose of further exploration
and/or for
the purpose of removing the oil or gas from existing reservoirs
on those properties; and (C) the construction, drilling and
production activities necessary to retrieve oil and gas from its
natural reservoirs, and the acquisition, construction,
installation, and maintenance of field gathering and storage
systems including lifting the oil and gas to the
surface and gathering, treating, field processing (as in the
case of processing gas to extract liquid hydrocarbons) and field
storage. For purposes of this section, the oil and gas
production function shall normally be regarded as terminating at
the outlet valve on the lease or field storage tank; if unusual
physical or operational circumstances exist, it may be
appropriate to regard the production functions as terminating at
the first point at which oil, gas, or gas liquids are delivered
to a main pipeline, a common carrier, a refinery, or a marine
terminal.
Oil and gas producing activities do not include (A) the
transporting, refining and marketing of oil and gas;
(B) activities relating to the production of natural
resources other than oil and gas; (C) the production of
geothermal steam or the extraction of hydrocarbons as a
by-product of the production of geothermal steam or associated
geothermal resources as defined in the Geothermal Steam Act of
1970; and (D) the extraction of hydrocarbons from shale,
tar sands, or coal.
The SEC stated in a September 18, 1989 accounting bulletin
since coalbed methane gas can be recovered from coal in
its natural state and location, it should be included in proved
reserves, provided that it complies in all other respects with
the SEC definitions of proved oil and gas reserves including the
requirement that methane production be economical at current
prices, costs (net of the tax credit) and existing operating
conditions. We have also interpreted this bulletin to
include shale gas.
Proved
Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions.
Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes
(A) that portion delineated by drilling and defined by
gas-oil
and/or
oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but
is classified separately as indicated additional
reserves; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir characteristics,
or economic factors; (C) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled
A-7
prospects; and (D) crude oil, natural gas, and natural gas
liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
Proved
Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a
pilot project or after the operation of an installed program has
confirmed through production response that increased recovery
will be achieved.
Proved
Undeveloped Reserves
Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
A-8
APPENDIX B
Reserve
and Economic Evaluation of
Proved Reserves of Certain
Aurora Oil & Gas Corporation
Indiana Properties
As of July 1, 2006
Unescalated Prices and Costs
Prepared For
Aurora Oil & Gas Corporation
Traverse City, Michigan
Prepared By
Data & Consulting Services
Division of Schlumberger Technology Corporation
Pittsburgh, Pennsylvania
September 2006
B-1
Data & Consulting Services
Division of Schlumberger Technology Corporation
1310 Commerce Drive
Park Ridge One
Pittsburgh, PA
15275-1011
Tel: 412-787-5403
Fax: 412-787-2906
6 September 2006
Aurora Oil & Gas Corporation
4110 Copper Ridge Drive
Suite 100
Traverse City, MI 49684
Dear Gentlemen:
At the request of Aurora Oil & Gas Corporation
(AURORA), Schlumberger Data & Consulting Services,
Division of Schlumberger Technology Corporation (DCS) has
prepared a reserve and economic evaluation of certain proved
reserves in several New Albany shale projects as of July 1,
2006. These projects were evaluated to a maximum remaining
reserve life of 40 years. The economics presented are
before federal income taxes (BFIT). The results of this study
for the proved reserves are summarized in Table 1.
TABLE
1
ESTIMATED NET RESERVES & INCOME
CERTAIN PROVED OIL & GAS INTERESTS
AURORA OIL & GAS CORPORATION
AS OF JULY 1, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
Proved
|
|
|
|
|
|
Total
|
|
|
|
Developed
|
|
|
Developed
|
|
|
Proved
|
|
|
Proved
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Reserves
|
|
|
Remaining Net
Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMscf
|
|
|
452.17
|
|
|
|
204.34
|
|
|
|
1,265.60
|
|
|
|
1,922.11
|
|
Income Data (M$)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Revenue
|
|
|
2,577.36
|
|
|
|
1,164.73
|
|
|
|
7,213.92
|
|
|
|
10,956.01
|
|
Deductions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production Taxes
|
|
|
25.77
|
|
|
|
11.65
|
|
|
|
72.14
|
|
|
|
109.56
|
|
Net AdValorem Taxes
|
|
|
38.66
|
|
|
|
17.47
|
|
|
|
108.21
|
|
|
|
164.34
|
|
Net Investment
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
Net Well Costs
|
|
|
429.44
|
|
|
|
191.04
|
|
|
|
1,168.26
|
|
|
|
1,788.74
|
|
Other Costs
|
|
|
158.26
|
|
|
|
71.52
|
|
|
|
442.96
|
|
|
|
672.74
|
|
Future Net Income (FNI)
|
|
|
1,925.23
|
|
|
|
873.06
|
|
|
|
5,422.35
|
|
|
|
8,220.64
|
|
Discounted PV@10% (M$)
|
|
|
862.67
|
|
|
|
385.86
|
|
|
|
2,208.44
|
|
|
|
3,456.97
|
|
RESERVE
ESTIMATE
Reservoir simulation and history matching of analogous offset
projects provide the basis for the production forecasts for the
projects. The reservoir simulation was conducted using
SHALEGAStm,
DCSs multi-phase reservoir simulator designed specifically
for evaluating fractured shale formations. We used
SHALEGAStm
to history match the wellhead production data from existing
wells as supplied by AURORA in the respective projects or offset
projects. Using the resulting reservoir properties and the
proposed well spacing for each project, we used
SHALEGAStm
to forecast a typical curve shape from which we could construct
a type curve for each project. The
B-2
Data & Consulting Services
Division of Schlumberger Technology Corporation
6 September 2006
Page 2
resultant production forecasts were input into PhdWin to
facilitate the generation of the economic valuation. To account
for the expected increase of carbon dioxide in the produced gas,
shrinkage values (Table 2) as supplied by AURORA were
applied to the forecasted wellhead volumes. The estimates of
reserves and economic valuation are in the Reserve Summaries
and Reserve Details sections of this report.
TABLE
2
GAS SHRINKAGE FACTORS
|
|
|
|
|
Date
|
|
% Shrink
|
|
|
from 07/2006
|
|
|
3.00
|
|
from 07/2010
|
|
|
4.00
|
|
from 07/2012
|
|
|
5.00
|
|
from 07/2014
|
|
|
6.00
|
|
from 07/2016
|
|
|
7.00
|
|
from 07/2018
|
|
|
8.00
|
|
from 07/2020
|
|
|
9.00
|
|
from 07/2022
|
|
|
10.00
|
|
from 07/2024
|
|
|
11.00
|
|
from 07/2006
|
|
|
12.00
|
|
Reserve estimates are strictly technical judgments. The accuracy
of any reserve estimate is a function of the quality of data
available and of the engineering and geological interpretations.
The reserve estimates presented in this report are believed
reasonable; however, they are estimates only and should be
accepted with the understanding that reservoir performance
subsequent to the date of the estimate may justify their
revision.
RESERVE
CATEGORIES
Reserves were assigned to the proved developed producing (PDP),
proved non-producing (PDNP), and proved undeveloped (PUD)
reserve categories. Oil and gas reserves by definition fall into
one of the following categories: proved, probable, and possible.
The proved category is further divided into: developed and
undeveloped. The developed reserve category is even further
divided into the appropriate reserve status subcategories:
producing and non-producing. Non-producing reserves include
shut-in and behind-pipe reserves. All reserve categories used in
this report conform to the definitions approved by the
Securities and Exchange Commission (SEC),
Regulation S-X,
Rule 4-10
(A). These are presented in Reserves Definitions section
of this report.
The reserves and income attributable to the various reserve
categories included in this report have not been adjusted to
reflect the varying degrees of risk associated with them.
ECONOMIC
TERMS
Net revenue (sales) is defined as the total proceeds from the
sale of oil, condensate, natural gas liquids (NGL), and natural
gas before any deductions. Future net income (cashflow) is
future net revenue less net lease operating, transportation,
processing, and marketing expenses, and state severance or
production taxes. No provisions for State or Federal income
taxes are made in this evaluation. The present worth (discounted
cashflow) at various discount rates is calculated on a monthly
basis. Total annual operating expenses are represented by a
fixed per well lease operating cost, net well cost
and a variable per unit cost, other cost.
B-3
Data & Consulting Services
Division of Schlumberger Technology Corporation
6 September 2006
Page 3
PRICING
AND ECONOMIC PARAMETERS
AURORA supplied all product prices, costs, and economic
parameters used in this report. Data from AURORA were accepted
as presented. All economics were run to economic life or
40 years which ever occurs first utilizing the gas price
deck provided to us by AURORA. All gas prices are net of any
transportation, marketing, and regional basis adjustments. The
operating costs, state and local production taxes and gas prices
are listed in Tables 3, 4, and 5
respectively. All costs and prices were unescalated.
TABLE
3
OPERATING COSTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State
|
|
Field
|
|
Operator
|
|
LOE
|
|
LOE
|
|
|
|
|
|
|
($/Well/Mo.)
|
|
($/MCF)
|
|
Indiana
|
|
|
Plainville
|
|
|
|
El Paso
|
|
|
|
2,000
|
|
|
|
0.35
|
|
TABLE
4
TAXES
|
|
|
|
|
State Production Tax Rate
|
|
|
1
|
%
|
Ad Valorem Tax Rate
|
|
|
1.5
|
%
|
CAPITAL
EXPENDITURES
Under pre-existing agreements, AURORA is carried for all capital
expenditures associated with the Proved Developed and
Undeveloped assets
TABLE
5
GAS PRICE ($/MMbtu)
|
|
|
|
|
Escalation
|
|
|
NYMEX
|
|
None
|
|
|
5.70
|
|
OWNERSHIP
The leasehold interests were supplied by AURORA and were
accepted as presented. No leasehold purchase costs were included
in this evaluation. No attempt was made by the undersigned to
verify the title or ownership of the interests evaluated.
GENERAL
All data used in this study were obtained from AURORA, public
industry information sources, or the non-confidential files of
DCS. A field inspection of the properties was not made in
connection with the preparation of this report.
The potential environmental liabilities attendant to ownership
and/or
operation of the properties have not been addressed in this
report. Abandonment and
clean-up
costs and possible salvage value of the equipment were not
considered in this report.
In evaluating the information at our disposal related to this
report, we have excluded from our consideration all matters
which require a legal or accounting interpretation, or any
interpretation other than those of an engineering or geological
nature. In assessing the conclusions expressed in this report
pertaining to all aspects of oil and gas
B-4
Data & Consulting Services
Division of Schlumberger Technology Corporation
6 September 2006
Page 4
evaluations, especially pertaining to reserve evaluations, there
are uncertainties inherent in the interpretation of engineering
data, and such conclusions represent only informed professional
judgments.
Data and worksheets used in the preparation of this evaluation
will be maintained in our files in Pittsburgh and will be
available for inspection by anyone having proper authorization
by AURORA.
This report was prepared solely for the use of the party to whom
it is addressed and any disclosure made of this report
and/or the
contents by said party thereof shall be solely the
responsibility of said party, and shall in no way constitute any
representation of any kind whatsoever of the undersigned with
respect to the matters being addressed.
We appreciate the opportunity to perform this evaluation and are
available should you need further assistance in this matter.
Sincerely yours,
|
|
|
|
|
/s/ Jeron
R.
Williamson
Jeron R. Williamson
Senior Petroleum Engineer
|
|
/s/ David
A. Wozniak
David A. Wozniak, P.E.
Senior Petroleum Engineer
|
|
/s/ Charles
M. Boyer II
Charles M. Boyer II, P.G.
Principal Consultant/Group Leader
|
B-5
SECURITIES
AND EXCHANGE COMMISSION
REGULATION S-X,
RULE 4-10
(A)
RESERVES
DEFINITIONS
Oil and
Gas Producing Activities
Such activities include (A) the search for crude oil,
including condensate and natural gas liquids, or natural gas
(oil and gas) in their natural states and original
locations; (B) the acquisition of property rights or
properties for the purpose of further exploration
and/or for
the purpose of removing the oil or gas from existing reservoirs
on those properties; and (C) the construction, drilling and
production activities necessary to retrieve oil and gas from its
natural reservoirs, and the acquisition, construction,
installation, and maintenance of field gathering and storage
systems including lifting the oil and gas to the
surface and gathering, treating, field processing (as in the
case of processing gas to extract liquid hydrocarbons) and field
storage. For purposes of this section, the oil and gas
production function shall normally be regarded as terminating at
the outlet valve on the lease or field storage tank; if unusual
physical or operational circumstances exist, it may be
appropriate to regard the production functions as terminating at
the first point at which oil, gas, or gas liquids are delivered
to a main pipeline, a common carrier, a refinery, or a marine
terminal.
Oil and gas producing activities do not include (A) the
transporting, refining and marketing of oil and gas;
(B) activities relating to the production of natural
resources other than oil and gas; (C) the production of
geothermal steam or the extraction of hydrocarbons as a
by-product of the production of geothermal steam or associated
geothermal resources as defined in the Geothermal Steam Act of
1970; and (D) the extraction of hydrocarbons from shale,
tar sands, or coal.
The SEC stated in a September 18, 1989 accounting bulletin
since coalbed methane gas can be recovered from coal in
its natural state and location, it should be included in proved
reserves, provided that it complies in all other respects with
the SEC definitions of proved oil and gas reserves including the
requirement that methane production be economical at current
prices, costs (net of the tax credit) and existing operating
conditions. We have also interpreted this bulletin to
include shale gas.
Proved
Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions.
Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes
(A) that portion delineated by drilling and defined by
gas-oil
and/or
oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but
is classified separately as indicated additional
reserves; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir characteristics,
or economic factors; (C) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled
B-6
prospects; and (D) crude oil, natural gas, and natural gas
liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
Proved
Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a
pilot project or after the operation of an installed program has
confirmed through production response that increased recovery
will be achieved.
Proved
Undeveloped Reserves
Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
B-7
APPENDIX C
January 30, 2006
Cadence Resources Corporation
11211 Katy Freeway; Suite 400
Houston, Texas 77079
Gentlemen:
In accordance with your request, we have appraised the interests
owned by Cadence Resources Corporation (Cadence) in certain oil
and gas properties. The subject properties are located in the
states of Kansas, Louisiana and Texas.
We have prepared estimates of the reserves, future production
and the income attributable to the leasehold interests as of
December 31, 2005. The income data has been estimated using
constant price and cost parameters. The results of our study are
summarized as follows:
ESTIMATED
NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD INTERESTS OF
CADENCE RESOURCES CORPORATION
AS OF DECEMBER 31, 2005
USING SEC GUIDELINES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Remaining
|
|
|
Income Data (M$)
|
|
|
|
Reserves
|
|
|
Future
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Gross
|
|
|
|
|
|
Oper.
|
|
|
Net
|
|
|
FNR
|
|
|
|
Mbbls.
|
|
|
Mmcf
|
|
|
Revenue
|
|
|
Taxes
|
|
|
Costs
|
|
|
Revenue
|
|
|
@ 10%
|
|
|
FIELD:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Seifried
|
|
|
18.4
|
|
|
|
0.0
|
|
|
|
1025.5
|
|
|
|
74.9
|
|
|
|
123.7
|
|
|
|
826.9
|
|
|
|
727.1
|
|
Bethany Longstreet
|
|
|
0.2
|
|
|
|
758.8
|
|
|
|
8247.0
|
|
|
|
77.7
|
|
|
|
1586.6
|
|
|
|
6582.7
|
|
|
|
4756.8
|
|
Markham
|
|
|
0.0
|
|
|
|
176.2
|
|
|
|
1236.8
|
|
|
|
115.6
|
|
|
|
14.4
|
|
|
|
1106.7
|
|
|
|
1018.3
|
|
Virgin Reef
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cadence A & B Leases
|
|
|
2.0
|
|
|
|
0.0
|
|
|
|
111.6
|
|
|
|
7.3
|
|
|
|
38.3
|
|
|
|
66.0
|
|
|
|
63.1
|
|
Wilbarger Co. Regular
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
W. Electra Lake Lease
|
|
|
41.4
|
|
|
|
0.0
|
|
|
|
2365.0
|
|
|
|
153.9
|
|
|
|
503.5
|
|
|
|
1707.6
|
|
|
|
1402.4
|
|
N. Electra Lake Lease
|
|
|
8.0
|
|
|
|
0.0
|
|
|
|
455.0
|
|
|
|
29.6
|
|
|
|
199.1
|
|
|
|
226.3
|
|
|
|
169.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sub Total
|
|
|
49.4
|
|
|
|
0.0
|
|
|
|
2820.0
|
|
|
|
183.5
|
|
|
|
702.6
|
|
|
|
1933.9
|
|
|
|
1571.6
|
|
Total
|
|
|
70.0
|
|
|
|
935.0
|
|
|
|
13440.9
|
|
|
|
459.0
|
|
|
|
2465.6
|
|
|
|
10516.3
|
|
|
|
8137.0
|
|
Note: Errors in addition are due to
rounding.
Oil and condensate volumes are expressed in standard 42 gallon
barrels. Gas volumes have been appropriately reduced to sales
volumes and are expressed in million cubic feet (MMcf) at the
official temperature and pressure measuring bases of the States
where the gas reserves are located.
METHOD
OF APPRAISAL
The properties have been evaluated on the basis of future net
cash flow which is defined as the amount of future net income,
which will accrue to the appraised interests by operating the
properties to the estimated limit of profitable operation. The
future net cash flow has been discounted at an annual effective
rate of 10 percent to determine the present worth. The
future net cash flow has also been discounted at various other
rates, as shown in the schedules. The present worth is shown to
indicate the effect of time on the value of money and should not
be construed to be the fair market value of the properties.
C-1
RESERVE
DEFINITIONS
Reserves are estimated volumes of
crude oil, condensate, natural gas, natural gas liquids and
associated substances anticipated to be commercially recoverable
from known accumulations from a given date forward, under
existing economic conditions, by established operating
practices, and under current government regulations. Reserve
estimates are based on interpretation of geologic
and/or
engineering data available at the time of the estimate.
Proved Reserves are quantities of
crude oil, condensate, natural gas and natural gas liquids that
can be estimated with reasonable certainty to be recoverable
under current economic conditions. Current economic conditions
include prices and costs prevailing at the time of the estimate.
Reserves are considered proved if commercial producibility of
the reservoir is supported by actual production or formation
tests. In certain instances proved reserves may be assigned on
the basis of electrical and other type logs
and/or core
analysis that indicate that the subject reservoir is hydrocarbon
bearing and is analogous to reservoirs in the same area that are
producing, or have demonstrated the ability to produce on a
formation test.
The area of a reservoir considered proved includes (1) the
area delineated by drilling and defined by fluid contracts, if
any and (2) the undrilled areas that can be reasonably
judged as commercially productive on the basis of available
geological and engineering data. In the absence of data on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limits. Proved reserves do not include
volumes of crude oil, condensate, natural gas or natural gas
liquids being held in inventory.
CLASSIFICATION
OF RESERVES
The reserves considered in this report are defined as proved and
were estimated in accordance with the definitions outlined in
the Securities and Exchange Commission (SEC) regulations S-X
Part 4-10
and Financial Accounting Standards Board Statement No. 69.
PRODUCING
STATUS CATEGORIES
Proved Producing Reserves As used
herein, are those reserves that are expected to be produced from
completion interval(s) open to production equipment and
producing to market.
Proved Non-Producing Reserves As used
herein, are those reserves which are shut in or are behind pipe.
Shut in reserves are reserves which are expected to be produced
from completion intervals open to production equipment but which
have not started producing or were shut in for mechanical,
pipeline or market reasons. Behind pipe reserves are reserves
which are expected to recovered from zones behind casing in
existing wells, which will need to be recompleted prior to the
start of production.
Proved Undeveloped Reserves As used
herein, are those reserves that are expected to be recovered
from new wells on undrilled acreage or from recompletion of
existing wells which require a relatively large expenditure.
RESERVE
DETERMINATION
The reserves presented herein have been determined by geological
and engineering procedures widely accepted in the industry. In
the estimation of these reserves, all available data relating to
pressure and production history, geologic and well test
information were utilized. Reserves were estimated by
performance methods, volumetrically or by analogy to surrounding
wells producing from the same productive horizon.
In general most of the properties have been producing for a
sufficient length of time to establish a definitive performance
trend. Reserves for these properties were determined by
extrapolation of the trend into the future. Additionally,
consideration has been given to water-oil ratio trends and
production characteristics generally exhibited in the area.
Where there was insufficient or inadequate performance data,
reserve estimates were determined by the volumetric method or by
analogy to nearby producing properties.
Actual production history was available through November, 2005.
The reserve estimates, at the effective date of the report,
should be accepted with the understanding that actual production
performance subsequent to the data that production history was
available, might require a reserve revision.
C-2
Future production rates may be subject to regulation by various
governmental agencies, changes in market demand or other
factors; consequently, actual producing rates may differ
materially from volumes predicted.
DISCUSSION
Production on the Waggoner Ranch leases are reported on a lease
basis. Production from the Cadence A & B lease wells,
1-A and 1-B
is now comingled at the surface. Production from the nine
completions on the W. Electra Lake lease is reported on a total
lease basis. Production from the two wells on the N. Electra
Lake lease is also reported on a lease basis.
ECONOMIC
PARAMETERS
Prices The oil and gas prices used
throughout this report were the actual sales prices received on
December 31, 2005. Prices were supplied by Cadence.
Costs Producing well operating costs
utilized were provided on a lease basis or an individual well
basis by Cadence. We have used the average of the period from
January, 2005 through November, 2005. For newer wells having
produced less than six months, the average of the available
operating costs was used. Operating costs were held constant
over the remaining producing life of the properties. No
provision has been made for the value of salvable equipment or
the leases at abandonment, nor were costs included to properly
plug and abandon the wells. It is considered that these costs
are minimal and generally offset each other.
GENERAL
No consideration has been given to Cadences corporate
overhead, income taxes, depletion, depreciation, or any other
indirect costs.
Titles to the appraised properties have not been examined by
Ralph E. Davis Associates, Inc., nor has the actual degree or
type of interest owned been independently confirmed. The data
used in our evaluation were obtained from Cadence, published
industry information sources
and/or the
nonconfidential files of Ralph E. Davis Associates, Inc., and
were considered to be accurate. A field inspection of the
properties was not made.
The reliability of any reserve estimate is a function of the
quality of available information and of engineering
interpretation and judgement. In our opinion, the reserve
estimates presented herein, in accordance with generally
accepted engineering and evaluation principles consistently
applied, are believed to be reasonable. These reserves should be
accepted with the understanding that drilling activity or
additional information subsequent to the effective date of this
report might require their revision.
In evaluating the information at our disposal concerning this
appraisal, we have excluded from our consideration all matters
as to which legal or accounting, rather than engineering
interpretation may be controlling. Finally, in assessing the
conclusions herein expressed, as in all aspects of oil and gas
evaluation, there are uncertainties inherent in the
interpretation of engineering data and such conclusions
necessarily represent only informed professional judgment.
Yours very truly,
RALPH E. DAVIS ASSOCIATES, INC.
/s/ Joseph
Mustacchia, Jr.
Joseph Mustacchia, Jr.
Executive Vice President
C-3
Appendix D
ESTIMATE
of
RESERVES AND FUTURE REVENUE
to the
AURORA ENERGY, LTD. INTEREST
in
CERTAIN OIL AND GAS PROPERTIES
located in
MICHIGAN
as of
DECEMBER 31, 2005
BASED ON
CONSTANT PRICES AND COSTS
in accordance with
SECURITIES AND EXCHANGE COMMISSION GUIDELINES
D-1
February 2,
2006
Mr. John V. Miller, Jr.
Aurora Energy, Ltd.
4110 Copper Ridge Dr., Suite 100
Traverse City, Michigan 49684
Dear Mr. Miller:
In accordance with your request, we have estimated the proved
undeveloped and probable reserves and future revenue, as of
December 31, 2005, to the Aurora Energy, Ltd. (Aurora)
interest in certain oil and gas properties located in Michigan,
as listed in the accompanying tabulations. This report has been
prepared using constant prices and costs, as discussed in
subsequent paragraphs of this letter. The estimates of proved
reserves and future revenue in this report conform to the
guidelines of the Securities and Exchange Commission (SEC).
However, inasmuch as the SEC does not recognize probable
reserves, the sections of this report dealing with such reserves
should not be used in filings with the SEC.
As presented in the accompanying summary projections, Tables I
and II, we estimate the net reserves and future net revenue to
the Aurora interest in these properties, as of December 31,
2005, to be:
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|
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|
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|
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|
|
Net Reserves
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Future Net Revenue ($)
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|
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Oil
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Gas
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Present Worth
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Category
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(Barrels)
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(MCF)
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Total
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at 10%
|
|
|
Proved Undeveloped
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|
|
28,564
|
|
|
|
624,072
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|
|
|
4,660,900
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|
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3,697,500
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Probable(1)
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|
|
79,928
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|
|
|
3,086,716
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|
|
|
27,202,500
|
|
|
|
17,987,200
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|
|
|
|
(1) |
|
These reserves and future revenue are not risk-weighted. |
The oil reserves shown include condensate only. Oil volumes are
expressed in barrels that are equivalent to 42 United States
gallons. Gas volumes are expressed in thousands of cubic feet
(MCF) at standard temperature and pressure bases.
The estimates shown in this report are for proved and probable
undeveloped reserves. Our estimates do not include any possible
reserves that may exist for these properties. This report does
not include any value that could be attributed to interests in
undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated. Definitions of all reserve
categories are presented immediately following this letter.
As shown in the Table of Contents, for each reserve category
this report includes a summary projection of reserves and
revenue; one-line summaries of reserves, economics, and basic
data by lease; and individual lease projections. Graphs showing
gross historical and projected production are presented opposite
the individual lease projections.
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4500
Thanksgiving Tower 1601 Elm Street Dallas, Texas
75201-4754 Ph: 214-969-5401 Fax: 214-969-5411
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nsai@nsai-petro.com
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1221
Lamar Street, Suite 1200 Houston, Texas 77010-3072
Ph: 713-654-4950 Fax: 713-654-4951
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netherlandsewell.com
|
D-2
Future gross revenue to the Aurora interest is prior to
deducting state production taxes and ad valorem taxes. Future
net revenue is after deductions for these taxes, future capital
costs, and operating expenses but before consideration of
federal income taxes. In accordance with SEC guidelines, the
future net revenue has been discounted at an annual rate of
10 percent to determine its present worth. The
present worth is shown to indicate the effect of time on the
value of money and should not be construed as being the fair
market value of the properties.
For the purposes of this report, we did not perform any field
inspection of the properties, nor did we examine the mechanical
operation or condition of the facilities. We have not
investigated possible environmental liability related to the
properties; therefore, our estimates do not include any costs
due to such possible liability. Also, our estimates do not
include any salvage value for the lease and well equipment or
the cost of abandoning the properties.
Oil prices used in this report are based on a December 31,
2005, West Texas intermediate posted price of $57.75 per
barrel and are adjusted by lease for quality and regional price
differentials. Gas prices used in this report are based on a
December 31, 2005, Henry Hub spot market price of
$10.08 per MMBTU and are adjusted for the regional price
differential. Since there are currently no sales from these
properties, a BTU content of 1,000 BTU per cubic foot of
gas was used. All prices are held constant in accordance with
SEC guidelines.
Based on our knowledge of similar wells in the area, we estimate
lease and well operating costs at $6,000 per completion per
month. These costs do not include the per-well overhead expenses
allowed under joint operating agreements, nor do they include
headquarters general and administrative overhead expenses of
Aurora. Lease and well operating costs are held constant in
accordance with SEC guidelines. Capital costs are included as
required for workovers, new development wells, and production
equipment.
The reserves shown in this report are estimates only and should
not be construed as exact quantities. The reserves may or may
not be recovered; if they are recovered, the revenues therefrom
and the costs related thereto could be more or less than the
estimated amounts. All of these reserves are for undeveloped
locations; therefore, they are based on estimates of reservoir
volumes and recovery efficiencies along with analogies to
similar production. Because such reserve estimates are usually
subject to greater revision than those based on substantial
production and pressure data, it may be necessary to revise
these estimates as performance data become available. Because of
governmental policies and uncertainties of supply and demand,
the sales rates, prices received for the reserves, and costs
incurred in recovering such reserves may vary from assumptions
made while preparing this report. Also, estimates of reserves
may increase or decrease as a result of future operations.
In evaluating the information at our disposal concerning this
report, we have excluded from our consideration all matters as
to which the controlling interpretation may be legal or
accounting, rather than engineering and geologic. As in all
aspects of oil and gas evaluation, there are uncertainties
inherent in the interpretation of engineering and geologic data;
therefore, our conclusions necessarily represent only informed
professional judgment.
D-3
The titles to the properties have not been examined by
Netherland, Sewell & Associates, Inc., nor has the
actual degree or type of interest owned been independently
confirmed. The data used in our estimates were obtained from
Aurora Energy, Ltd.; other interest owners; public data sources;
and the nonconfidential files of Netherland, Sewell &
Associates, Inc. and were accepted as accurate. Supporting
geologic, field performance, and work data are on file in our
office. We are independent petroleum engineers, geologists,
geophysicists, and petrophysicists; we do not own an interest in
these properties and are not employed on a contingent basis.
Very truly yours,
NETHERLAND, SEWELL & ASSOCIATES, INC.
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By:
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|
Frederic D. Sewell, P.E.
Chairman and Chief Executive Officer
G. Lance Binder
Executive Vice President
Date Signed: February 2, 2006
GLB:KBD
D-4
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
and
the 1997 Society of Petroleum Engineers and World Petroleum
Council Reserves Definitions
PROVED
RESERVES
The following definitions of proved reserves are set forth in
Securities and Exchange Commission (SEC)
Regulation S-X
Section 210.4-10(a).
Also included (in italics) are certain subsequent
interpretations set forth in the SECs Corporate Finance
Accounting Interpretations and Guidance [SEC Interpretations];
SEC Staff Accounting Bulletins: Topic 12 [SEC Topic 12]; and the
1997 reserves definitions approved by the Society of Petroleum
Engineers and World Petroleum Council [SPE/WPC Definitions].
Proved Oil and Gas Reserves. Proved oil and
gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the
estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but
not on escalations based upon future conditions.
The determination of reasonable certainty is generated by
supporting geological and engineering data. There must be data
available which indicate that assumptions such as decline rates,
recovery factors, reservoir limits, recovery mechanisms and
volumetric estimates, gas-oil ratios or liquid yield are valid.
If the area in question is new to exploration and there is
little supporting data for decline rates, recovery factors,
reservoir drive mechanisms etc., a conservative approach is
appropriate until there is enough supporting data to justify the
use of more liberal parameters for the estimation of proved
reserves. The concept of reasonable certainty implies that, as
more technical data becomes available, a positive, or upward,
revision is much more likely than a negative, or
downward, revision.
Existing economic and operating conditions are the product
prices, operating costs, production methods, recovery
techniques, transportation and marketing arrangements, ownership
and/or
entitlement terms and regulatory requirements that are extant on
the effective date of the estimate. An anticipated change in
conditions must have reasonable certainty of occurrence; the
corresponding investment and operating expense to make that
change must be included in the economic feasibility at the
appropriate time. These conditions include estimated net
abandonment costs to be incurred and duration of current
licenses and permits.
If oil and gas prices are so low that production is actually
shut-in because of uneconomic conditions, the reserves
attributed to the shut-in properties can no longer be classified
as proved and must be subtracted from the proved reserve data
base as a negative revision. Those volumes may be included as
positive revisions to a subsequent years proved reserves
only upon their return to economic status. [SEC
Interpretations]
Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes
(A) that portion delineated by drilling and defined by
gas-oil
and/or
oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
Proved reserves may be attributed to a prospective zone if a
conclusive formation test has been performed or if there is
production from the zone at economic rates. It is clear to the
SEC staff that wireline recovery of small volumes (e.g. 100
cc) or production of a few hundred barrels per day in
remote locations is not necessarily conclusive. Analyses of
open-hole well logs which imply that an interval is productive
are not sufficient for attribution of proved reserves. If there
is an indication of economic producibility by either formation
test or production, the reserves in the legal and technically
justified drainage area around the well
D-5
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
and
the 1997 Society of Petroleum Engineers and World Petroleum
Council Reserves Definitions
projected down to a known fluid contact or the lowest known
hydrocarbons, or LKH may be considered to be proved.
In order to attribute proved reserves to legal locations
adjacent to such a well (i.e. offsets), there must be
conclusive, unambiguous technical data which supports reasonable
certainty of production of such volumes and sufficient legal
acreage to economically justify the development without going
below the shallower of the fluid contact or the LKH. In the
absence of a fluid contact, no offsetting reservoir volume below
the LKH from a well penetration shall be classified as
proved.
Upon obtaining performance history sufficient to reasonably
conclude that more reserves will be recovered than those
estimated volumetrically down to LKH, positive reserve revisions
should be made. [SEC Interpretations]
Economic producibility of estimated proved reserves can be
supported to the satisfaction of the Office of Engineering if
geological and engineering data demonstrate with reasonable
certainty that those reserves can be recovered in future years
under existing economic and operating conditions. The relative
importance of the many pieces of geological and engineering data
which should be evaluated when classifying reserves cannot be
identified in advance. In certain instances, proved reserves may
be assigned to reservoirs on the basis of a combination of
electrical and other type logs and core analyses which indicate
the reservoirs are analogous to similar reservoirs in the same
field which are producing or have demonstrated the ability to
produce on a formation test. [SEC Topic 12]
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
If an improved recovery technique which has not been verified
by routine commercial use in the area is to be applied, the
hydrocarbon volumes estimated to be recoverable cannot be
classified as proved reserves unless the technique has been
demonstrated to be technically and economically successful by a
pilot project or installed program in that specific rock volume.
Such demonstration should validate the feasibility study leading
to the project. [SEC Interpretations]
Estimates of proved reserves do not include the following:
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(A)
|
oil that may become available from known reservoirs but is
classified separately as indicated additional
reserves;
|
|
|
|
|
(B)
|
crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as
to geology, reservoir characteristics, or economic factors;
|
|
|
(C)
|
crude oil, natural gas, and natural gas liquids, that may occur
in undrilled prospects; and
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|
(D)
|
crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such
sources.
|
Geologic and reservoir characteristic uncertainties such as
those relating to permeability, reservoir continuity, sealing
nature of faults, structure and other unknown characteristics
may prevent reserves from being classified as proved. Economic
uncertainties such as the lack of a market (e.g. stranded
hydrocarbons), uneconomic prices and marginal reserves that do
not show a positive cash flow can also prevent reserves from
D-6
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
and
the 1997 Society of Petroleum Engineers and World Petroleum
Council Reserves Definitions
being classified as proved. Hydrocarbons
manufactured through extensive treatment of
gilsonite, coal and oil shales are mining activities reportable
under Industry Guide 7. They cannot be called proved oil and gas
reserves. However, coal bed methane gas can be classified as
proved reserves if the recovery of such is shown to be
economically feasible.
In developing frontier areas, the existence of wells with a
formation test or limited production may not be enough to
classify those estimated hydrocarbon volumes as proved reserves.
Issuers must demonstrate that there is reasonable certainty that
a market exists for the hydrocarbons and that an economic method
of extracting, treating and transporting them to market exists
or is feasible and is likely to exist in the near future. A
commitment by the company to develop the necessary production,
treatment and transportation infrastructure is essential to the
attribution of proved undeveloped reserves. Significant lack of
progress on the development of such reserves may be evidence of
a lack of such commitment. Affirmation of this commitment may
take the form of signed sales contracts for the products;
request for proposals to build facilities; signed acceptance of
bid proposals; memos of understanding between the appropriate
organizations and governments; firm plans and timetables
established; approved authorization for expenditures to build
facilities; approved loan documents to finance the required
infrastructure; initiation of construction of facilities;
approved environmental permits etc. Reasonable certainty of
procurement of project financing by the company is a requirement
for the attribution of proved reserves. An inordinately long
delay in the schedule of development may introduce doubt
sufficient to preclude the attribution of proved reserves.
The history of issuance and continued recognition of permits,
concessions and commerciality agreements by regulatory bodies
and governments should be considered when determining whether
hydrocarbon accumulations can be classified as proved reserves.
Automatic renewal of such agreements cannot be expected if the
regulatory body has the authority to end the agreement unless
there is a long and clear track record which supports the
conclusion that such approvals and renewal are a matter of
course. [SEC Interpretations]
Companies should report reserves of natural gas liquids which
are net to their leasehold interests, i.e., that portion
recovered in a processing plant and allocated to the leasehold
interest. It may be appropriate in the case of natural gas
liquids not clearly attributable to leasehold interests
ownership to follow instructions to Item 3 of Securities
Act Industry Guide 2 and report such reserves separately and
describe the nature of the ownership. [SEC Topic 12]
Proved Developed Oil and Gas Reserves. Proved
developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment
and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a
pilot project or after the operation of an installed program has
confirmed through production response that increased recovery
will be achieved.
Currently producing wells and wells awaiting minor sales
connection expenditure, recompletion, additional perforations or
bore hole stimulation treatment would be examples of properties
with proved developed reserves since the majority of the
expenditures to develop the reserves has already been spent.
Proved developed reserves from improved recovery techniques
can be assigned after either the operation of an installed pilot
program shows a positive production response to the technique or
the project is fully installed and operational and has shown the
production response anticipated by earlier feasibility studies.
In the case with a pilot, proved developed reserves can be
assigned only to that volume attributable to the pilots
D-7
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
and
the 1997 Society of Petroleum Engineers and World Petroleum
Council Reserves Definitions
influence. In the case of the fully installed project,
response must be seen from the full project before all the
proved developed reserves estimated can be assigned. If a
project is not following original forecasts, proved developed
reserves can only be assigned to the extent actually supported
by the current performance. An important point here is that
attribution of incremental proved developed reserves from the
application of improved recovery techniques requires the
installation of facilities and a production increase. [SEC
Interpretations]
Proved Developed Producing
Reserves. Reserves subcategorized as
producing are expected to be recovered from completion intervals
that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after
the improved recovery project is in operation.
Proved Developed Non-Producing
Reserves. Reserves subcategorized as
non-producing include shut-in and behind-pipe reserves. Shut-in
reserves are expected to be recovered from (1) completion
intervals which are open at the time of the estimate but which
have not started producing, (2) wells which were shut-in
for market conditions or pipeline connections, or (3) wells
not capable of production for mechanical reasons. Behind-pipe
reserves are expected to be recovered from zones in existing
wells, which will require additional completion work or future
recompletion prior to the start of production. [SPE/WPC
Definitions]
Proved Undeveloped Reserves. Proved
undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited
to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
The SEC staff points out that this definition contains no
mitigating modifier for the word certainty. Also, continuity of
production requires more than the technical indication of
favorable structure alone (e.g. seismic data) to meet the test
for proved undeveloped reserves. Generally, proved undeveloped
reserves can be claimed only for legal and technically justified
drainage areas offsetting an existing productive well (but
structurally no lower than LKH). If there are at least two wells
in the same reservoir which are separated by more than one legal
location and which show communication (reservoir continuity),
proved undeveloped reserves could be claimed between the two
wells, even though the location in question might be more than
an offset well location away from any of the wells. In this
illustration, seismic data could be used to help support this
claim by showing reservoir continuity between the wells, but the
required data would be the conclusive evidence of communication
from production or pressure tests. The SEC staff emphasizes that
proved reserves cannot be claimed more than one offset location
away from a productive well if there are no other wells in the
reservoir, even though seismic data may exist The use of
high-quality, well calibrated seismic data can improve reservoir
description for performing volumetrics (e.g. fluid contacts).
However, seismic data is not an indicator of continuity of
production and, therefore, can not be the sole indicator of
additional proved reserves beyond the legal and technically
justified drainage areas of wells that were drilled. Continuity
of production would have to be demonstrated by something other
than seismic data.
In a new reservoir with only a few wells, reservoir
simulation or application of generalized hydrocarbon recovery
correlations would not be considered a reliable method to
show increased proved undeveloped
D-8
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
and
the 1997 Society of Petroleum Engineers and World Petroleum
Council Reserves Definitions
reserves. With only a few wells as data points from which to
build a geologic model and little performance history to
validate the results with an acceptable history match, the
results of a simulation or material balance model would be
speculative in nature. The results of such a simulation or
material balance model would not be considered to be reasonably
certain to occur in the field to the extent that additional
proved undeveloped reserves could be recognized. The application
of recovery correlations which are not specific to the field
under consideration is not reliable enough to be the sole source
for proved reserve calculations.
Reserves cannot be classified as proved undeveloped reserves
based on improved recovery techniques until such time that they
have been proved effective in that reservoir or an analogous
reservoir in the same geologic formation in the immediate area.
An analogous reservoir is one having at least the same values or
better for porosity, permeability, permeability distribution,
thickness, continuity and hydrocarbon saturations.
(g) Topic 12 of Accounting Series Release
No. 257 of the Staff Accounting Bulletins states:
In certain instances, proved reserves may be assigned to
reservoirs on the basis of a combination of electrical and other
type logs and core analyses which indicate the reservoirs are
analogous to similar reservoirs in the same field which are
producing or have demonstrated the ability to produce on a
formation test.
If the combination of data from open-hole logs and core
analyses is overwhelmingly in support of economic producibility
and the indicated reservoir properties are analogous to similar
reservoirs in the same field that have produced or demonstrated
the ability to produce on a conclusive formation test, the
reserves may be classified as proved. This would probably be a
rare event especially in an exploratory situation. The essence
of the SEC definition is that in most cases there must at least
be a conclusive formation test in a new reservoir before any
reserves can be considered to be proved. [SEC
Interpretations]
PROBABLE
AND POSSIBLE RESERVES
Reserves definitions approved by the Society of Petroleum
Engineers and World Petroleum Council in 1997 set forth
additional classifications for probable and possible reserves.
However, inasmuch as the SEC does not recognize probable or
possible reserves, the sections of this report dealing with such
reserves should not be used in filings with the SEC.
Probable Reserves. Probable reserves are those
unproved reserves which analysis of geological and engineering
data suggests are more likely than not to be recoverable. In
this context, when probabilistic methods are used, there should
be at least a 50% probability that the quantities actually
recovered will equal or exceed the sum of estimated proved plus
probable reserves.
In general, probable reserves may include (1) reserves
anticipated to be proved by normal step-out drilling where
sub-surface control is inadequate to classify these reserves as
proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data
or definitive tests and which are not analogous to producing or
proved reservoirs in the area, (3) incremental reserves
attributable to infill drilling that could have been classified
as proved if closer statutory spacing had been approved at the
time of the estimate, (4) reserves attributable to improved
recovery methods that have been established by repeated
commercially successful applications when (a) a project or
pilot is planned but not in operation and (b) rock, fluid,
and reservoir characteristics appear favorable for commercial
application, (5) reserves in an area of the formation that
appears to be separated from the proved area by faulting and the
geologic interpretation indicates the subject area is
structurally higher than the proved area, (6) reserves
attributable to a future workover, treatment, re-treatment,
D-9
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from Securities and Exchange Commission
Regulation S-X
Rule 4-10(a)
and
the 1997 Society of Petroleum Engineers and World Petroleum
Council Reserves Definitions
change of equipment, or other mechanical procedures, where such
procedure has not been proved successful in wells which exhibit
similar behavior in analogous reservoirs, and
(7) incremental reserves in proved reservoirs where an
alternative interpretation of performance or volumetric data
indicates more reserves than can be classified as proved.
Possible Reserves. Possible reserves are those
unproved reserves which analysis of geological and engineering
data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used,
there should be at least a 10% probability that the quantities
actually recovered will equal or exceed the sum of estimated
proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves
which, based on geological interpretations, could possibly exist
beyond areas classified as probable, (2) reserves in
formations that appear to be petroleum bearing based on log and
core analysis but may not be productive at commercial rates,
(3) incremental reserves attributed to infill drilling that
are subject to technical uncertainty, (4) reserves
attributed to improved recovery methods when (a) a project
or pilot is planned but not in operation and (b) rock,
fluid, and reservoir characteristics are such that a reasonable
doubt exists that the project will be commercial, and
(5) reserves in an area of the formation that appears to be
separated from the proved area by faulting and geological
interpretation indicates the subject area is structurally lower
than the proved area.
D-10
APPENDIX E
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
Companys multi-year drilling activities on existing
acreage. The Companys 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.
E-1
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.
E-2
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. Data & Consulting Services
Division of 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.
E-3
21,860,000 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 November 1,
2006.
PART II
INFORMATION
INFORMATION
NOT REQUIRED IN PROSPECTUS
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 corporations 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 shareholders 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.
Under the Underwriting Agreement, the underwriters are
obligated, under certain circumstances, to indemnify directors
and officers of the registrant against certain liabilities,
including liabilities under the Securities Act of 1933, as
amended. Reference is made to the form of Underwriting Agreement
to be filed as Exhibit 1.1 to this Registration Statement.
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ITEM
25.
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OTHER
EXPENSES OF ISSUANCE AND DISTRIBUTION
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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.
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Registration fee
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$
|
-0-
|
|
Fees and expenses of accountants
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$
|
1,000
|
|
Fees and expenses of legal counsel
|
|
$
|
1,000
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|
Fees and expenses of engineers
|
|
$
|
1,000
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|
Printing and engraving expenses
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|
$
|
10,000
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|
Miscellaneous expenses
|
|
$
|
1,000
|
|
|
|
|
|
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Total
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$
|
14,000
|
|
|
|
|
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II-1
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ITEM 26.
|
RECENT
SALES OF UNREGISTERED SECURITIES
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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.
Between April and June 2002, we sold an aggregate of
1,932,802 units to five accredited investors, each unit
consisting of one share of common stock and a warrant to
purchase one share of common stock, for aggregate proceeds of
$579,840.60. Each warrant was exercisable at a price of
$.15 per share and all of the warrants have been exercised.
No sales commissions were paid in connection with this
transaction. The units were issued in reliance upon the
exemption from registration provided by Section 4(2) of the
Securities Act. On October 23, 2002, we issued
1,815,316 shares of common stock to four accredited
investors upon the cashless exercise of the warrants granted in
the April through June 2002 offering. On September 15,
2003, we issued 141,668 shares of common stock to three
accredited investors upon the cashless exercise of the warrants
granted in the April through June 2002 offering. No sales
commissions were paid in connection with the exercise of the
warrants. The shares were issued in reliance upon the exemption
from registration provided by Section 4(2) of the
Securities Act.
Between November 2002 and March 2003, we issued
34,950 shares of Class A Preferred Stock to eight
investors who were not U.S. persons under Regulation S
of the Securities Act for aggregate sales proceeds of $52,425.
No sales commissions were paid in connection with this
transaction. The shares were issued in reliance upon the
exemption from registration provided by Regulation S of the
Securities Act.
During fiscal 2003, Howard M. Crosby made two loans to us. One
loan was made in December 2002 in the principal amount of
$70,000, bearing interest at 5% and the other loan was made in
February 2003 in the principal amount of $50,000 bearing
interest at a rate of 8%. We issued 14,000 shares of common
stock as an inducement to making the $70,000 loan and
20,000 shares as an inducement to making the $50,000 loan.
We repaid $60,000 of the $70,000 loan in cash and issued
4,000 shares of common stock in repayment of the remaining
$10,000 principal amount outstanding on the $70,000 loan. We
repaid $25,000 of the $50,000 loan in cash and issued
25,000 shares of common stock to repay the remaining
$25,000 principal amount outstanding. No sales commissions were
paid in connection with these transactions. The shares were
issued in reliance upon the exemption from registration provided
by Section 4(2) of the Securities Act.
In February 2003, Kevin Stulp, one of our directors, made a
bridge loan to us in the principal amount of $50,000, bearing
interest of 8% per annum. We issued 20,000 shares of
common stock to Mr. Stulp as an inducement to making the
loan. On May 28, 2003, we repaid $25,000 of the loan in
cash. On September 30, 2004, we issued 25,000 shares
of common stock in full payment of the remaining loan principal
of $25,000. In July 2003, we issued 100,000 shares of
common stock to Mr. Stulp upon the exercise of a warrant at
$.75 per share. No sales commissions were paid in
connection with these transactions. The shares were issued in
reliance upon the exemption from registration provided by
Section 4(2) of the Securities Act.
On February 4, 2003, we issued an aggregate of
150,000 shares of common stock to four of our officers
and/or
directors in consideration of services provided. No sales
commissions were paid in connection with this transaction. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
On February 19, 2003, we issued 5,000 shares of common
stock to one sophisticated investor in consideration of certain
consulting services provided. No sales commissions were paid in
connection with this transaction. The shares were issued in
reliance upon the exemption from registration provided by
Section 4(2) of the Securities Act.
On February 19, 2003, we issued 40,000 shares of
common stock to an accredited investor as an inducement for
making a loan to us of $100,000. No sales commissions were paid
in connection with this transaction. The shares were issued in
reliance upon the exemption from registration provided by
Section 4(2) of the Securities Act.
On February 19, 2003, we issued 6,000 shares of common
stock to one sophisticated investor in consideration for a loan
of $30,000, which was subsequently repaid.
Between April and May 2003, we issued an aggregate of
44,000 shares of common stock to two sophisticated
investors in consideration of certain consulting services
provided. No sales commissions were paid in connection
II-2
with this transaction. The shares were issued in reliance upon
the exemption from registration provided by Section 4(2) of
the Securities Act.
On May 7, 2003, we issued an aggregate of
75,000 shares of common stock to four of our officers
and/or
directors in consideration of services provided. No sales
commissions were paid in connection with this transaction. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
On May 7, 2003, we issued 10,000 shares of common
stock to one sophisticated investor in consideration of certain
consulting services provided. No sales commissions were paid in
connection with this transaction. The shares were issued in
reliance upon the exemption from registration provided by
Section 4(2) of the Securities Act.
Between May and August 2003, we sold an aggregate of
730,000 shares of common stock to 16 accredited investors
for aggregate sales proceeds of $710,000. No sales commissions
were paid in connection with this transaction. The shares were
issued in reliance upon the exemption from registration provided
by Section 4(2) of the Securities Act.
In June 2003, Nathan Low loaned $300,000 to Cadence Resources
Corporation Limited Partnership, of which we were the sole
general partner and Mr. Low was the sole limited partner.
As partial inducement for making this loan, we issued
Mr. Low 120,000 shares of common stock. No sales
commissions were paid in connection with this transaction. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
In July 2003, CGT Management, Ltd. loaned us $300,000 at 10%
interest. As an inducement for making the loan, we issued
120,000 shares of common stock to CGT Management. No sales
commissions were paid in connection with this transaction. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
On July 1, 2003, we issued an aggregate of
95,000 shares of common stock to four of our officers
and/or
directors in consideration of services provided. No sales
commissions were paid in connection with this transaction. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
In August 2003, we issued 102,000 shares of common stock to
four sophisticated investors in consideration of certain
consulting services provided. No sales commissions were paid in
connection with this transaction. The shares were issued in
reliance upon the exemption from registration provided by
Section 4(2) of the Securities Act.
On September 15, 2003, we issued an aggregate of
95,000 shares of common stock to four of our officers
and/or
directors in consideration of services provided. No sales
commissions were paid in connection with this transaction. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
Between September and October 2003, we sold an aggregate of
1,721,400 shares of common stock to 29 accredited investors
for aggregate sales proceeds of $4,303,500. Sales commissions
consisting of (i) $376,565 in cash,
(ii) 11,000 shares of common stock valued at
$2.90 per share ($31,900 in the aggregate) and
(iii) options to purchase 162,140 shares of common
stock at $2.50 per share to one finder or an entity
controlled by the finder, and additional fees totaling $11,250
to two other finders. All finders are accredited investors. The
shares and options were issued in reliance upon the exemption
from registration provided by Section 4(2) of the
Securities Act.
On January 23, 2004, we issued 5,000 shares of common
stock and an option to purchase 75,000 shares of common
stock to each of Glenn DeHekker and Jeffrey M. Christian in
consideration of their becoming directors. The shares and
options were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
On January 23, 2004, we issued an option to purchase
250,000 shares of common stock to Douglas Newby in
consideration of his becoming a Vice President. The options were
issued in reliance upon the exemption from registration provided
by Section 4(2) of the Securities Act.
II-3
On February 25, 2004, we issued 15,000 shares of
common stock to David Nahmias and 15,000 shares of common
stock to Lyons Capital, LLC in consideration of services
provided. The shares were issued in reliance upon the exemption
from registration provided by Section 4(2) of the
Securities Act.
On April 2, 2004, we sold 120 units, each of which
consisted of a note in the principal amount of $50,000 and a
warrant to purchase 6,375 shares of common stock
exercisable at $4.00 per share, to seven accredited
investors for an aggregate sales price of $6,000,000. As
compensation for his services in connection with this private
placement, we paid Nathan A. Low, an accredited investor,
$300,000 and issued him a warrant to purchase 76,500 shares
of common stock, exercisable at $4.00 per share. On
January 31, 2004, we paid off the notes without a
prepayment penalty in exchange for the exercise price of the
warrants being reduced to $1.25. The shares and warrant were
issued in reliance upon the exemption from registration provided
by Section 4(2) of the Securities Act.
On April 15, 2004, we issued 10,000 shares of common
stock each to Glenn DeHekker, Jeff Christian, and Kevin Stulp
for Director services for two quarters. On the same date, we
also issued 5,000 shares of common stock each to Howard
Crosby and John Ryan for Director services for one quarter, and
5,000 shares of common stock each to Howard Crosby, John
Ryan, and Doug Newby for Officer services for one quarter. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
On June 2, 2004, we issued 6,000 shares of common
stock to Proteus Capital Corp. in consideration of services
rendered to us. On the same date, we issued 10,000 shares
of common stock to Robert Denison upon exercise of warrants at
$1.35. The shares were issued in reliance upon the exemption
from registration provided by Section 4(2) of the
Securities Act.
On August 20, 2004 we issued 25,000 shares of common
stock to Howard Schraub and 17,500 shares of common stock
to Lyons Capital LLC for professional services rendered. On the
same date, we issued 5,000 shares of common stock to Glenn
DeHekker, Kevin Stulp and Jeff Christian for quarterly services
as Directors and issued 5,000 shares of common stock to
Douglas Newby for quarterly services as an Officer. Also on the
same date, we issued 15,000 shares of common stock to RMB
International (Dublin), Limited as a
break-up fee
for a proposed debt financing. In each case the shares were
issued in reliance upon the exemption from registration provided
by Section 4(2) of the Securities Act.
On January 31, 2005, we issued 7,810,000 shares of
common stock and warrants to purchase 14,050,000 shares of
common stock at an exercise price of $1.75 per share to 22
accredited investors for aggregate sales proceeds of $9,762,500.
Sunrise Securities Corporation, an affiliate of Nathan Low (a
shareholder of Cadence), received a cash commission equal to
$976,250 and a warrant to purchase 1,821,000 shares of
common stock at an exercise price of $1.75 per share for
services rendered as the placement agent in the transaction. The
shares were issued in reliance upon the exemption from
registration provided by Section 4(2) of the Securities Act.
On September 30, 2005, we issued options to purchase
50,000 shares of our common stock to each of the five
members of our board of directors (i.e., options to purchase an
aggregate of 250,000 shares). These options are exercisable
for $1.42 per share. The options were issued in reliance
upon the exemption from registration provided by
Section 4(2) of the Securities Act.
On October 31, 2005, we issued warrants to purchase
37,500 shares of our common stock to each of three
individuals (i.e., warrants to purchase an aggregate of
112,500 shares) upon the individuals resignations
from our Board of Directors. Of the warrants issued to each such
individual, warrants to purchase 12,500 shares (or an
aggregate of 37,500 for all three individuals) were exercisable
for $2.23 a share, warrants to purchase 12,500 shares (or
an aggregate of 37,500 for all three individuals) were
exercisable for $2.53 a share and warrants to purchase
12,500 shares (or an aggregate of 37,500 for all three
individuals) were exercisable for $3.28 a share. The warrants
were issued in reliance upon the exemption from registration
provided by Section 4(2) of the Securities Act.
From October through mid December, 2005, we issued
355,000 shares of common stock upon exercise of outstanding
warrants for cash, and 245,068 shares of common stock upon
cashless exercise of outstanding options and warrants held by
previous directors of the Company. All of these shares were
issued in reliance upon the exemption from registration provided
by Section 4(2) of the Securities Act of 1933, as amended.
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
II-4
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 closed on the acquisition of certain
assets for which we paid some cash and issued
1,378,299 shares of common stock. These shares are
unregistered, restricted stock, and were issued in reliance upon
the exemption from registration provided by Section 4(2) of
the Securities Act of 1933, as amended.
ITEM 27. EXHIBITS
INDEX OF
EXHIBITS
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3
|
.1(1)
|
|
Restated Articles of Incorporation
of Aurora Oil & Gas Corporation.
|
|
3
|
.2(1)
|
|
Bylaws of Aurora Oil &
Gas Corporation.
|
|
4
|
.1
|
|
Articles of Amendment to Articles
of Incorporation, relating to the Class A Preferred Stock.
(Filed as Exhibit 4 to our
Form 10-KSB
for the fiscal year ended September 30, 2003, filed with
the SEC on January 13, 2004, and incorporated herein by
reference.)
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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.)
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10
|
.2
|
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Agreement and Plan of Merger dated
as of January 31, 2005 between Cadence Resources
Corporation, Aurora Acquisition Corp. and Aurora Energy, Ltd.
(Filed as Exhibit 10.3 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
|
.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, LLC et al. and TCW Asset Management
Company, dated August 12, 2004 (filed as an Exhibit to the
Registrants 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, LLC et al. and
TCW Asset Management Company, dated December 8, 2005 (filed
as an Exhibit to the Registrants 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(2)
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Credit Agreement among Aurora
Antrim North, L.L.C., et al. and BNP Paribas, et al.,
dated January 31, 2006.
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10
|
.8(2)
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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.
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10
|
.9(2)
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Promissory Note from Aurora
Energy, Ltd. to Northwestern Bank dated January 31, 2006.
|
II-5
|
|
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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
|
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Letter Agreement with Bach
Enterprises dated July 10, 2006. This Agreement is
confidential, has been omitted from this filing, 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.
|
|
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(5)
|
|
LLC Membership Interest Purchase
Agreement dated October 6, 2006 relating to Kingsley
Development Company, L.L.C.
|
|
10
|
.19(5)
|
|
Asset Purchase Agreement with Bach
Enterprises, Inc., et al., dated October 6, 2006.
|
|
10
|
.20(5)
|
|
Promissory Note from Aurora
Energy, Ltd. to Northwestern Bank dated October 15, 2006.
|
|
10
|
.21(5)
|
|
Form of Indemnification letter
agreement between Aurora Oil & Gas Corporation and
Rubicon Master Fund.
|
|
10
|
.22(5)
|
|
Patricia A. Deneau Trust
Commercial Guaranty of obligations to Northwestern Bank.
|
|
10
|
.23(5)
|
|
Patricia A. Deneau Trust
Commercial Pledge Agreement to Northwestern Bank.
|
|
15
|
|
|
Awareness letter from Rachlin
Cohen & Holtz LLP.
|
|
21
|
(5)
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|
Subsidiaries of Aurora
Oil & Gas Corporation.
|
|
23
|
.1
|
|
Consent of Ralph E. Davis
Associates, Inc.
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|
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
|
|
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 September 8, 2006 with our Form SB-2
registration statement filing, registration no. 333-137176. |
|
|
|
(4) |
|
Filed on October 18, 2006 with our Amendment No. 1 to
Form SB-2 registration statement filing, registration
no. 333-137176. |
|
|
|
(5) |
|
Filed on October 27, 2006 with our Amendment No. 3 to
Form SB-2 registration statement filing, registration
no. 333-137176. |
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.
II-6
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.
The small business issuer will:
(1) File, during any period in which it offers or sells
securities, a post-effective amendment to this registration
statement to:
(i) Include any prospectus required by
section 10(a)(3) of the Securities Act;
(ii) Reflect in the prospectus any facts or events which,
individually or together, represent a fundamental change in the
information in the registration statement; and notwithstanding
the foregoing, any increase or decrease in volume of securities
offered (if the total dollar value of securities offered (if the
total dollar value of securities offered would not exceed that
which was registered) and any deviation from the low or high end
of the estimated maximum offering range may be reflected in the
form of prospectus filed with the Commission pursuant to
Rule 424(b) if, in the aggregate, the changes in the volume
and price represent no more than a 20% change in the maximum
aggregate offering price set forth in the Calculation of
Registration Fee table in the effective registration
statement.
(iii) Include any additional or changed material
information on the plan of distribution.
(2) For determining liability under the Securities Act,
treat each post-effective amendment as a new registration
statement of the securities offered, and the offering of the
securities at that time to be the initial bona fide offering.
(3) File a post-effective amendment to remove from
registration any of the securities that remain unsold at the end
of the offering.
(4) For determining liability of the undersigned small
business issuer under the Securities Act to any purchaser in the
initial distribution of the securities, the undersigned small
business issuer undertakes that in a primary offering of
securities of the undersigned small business issuer pursuant to
this registration statement, regardless of the underwriting
method used to sell the securities to the purchaser, if the
securities are offered or sold to such purchaser by means of any
of the following communications, the undersigned small business
issuer will be a seller to the purchaser and will be considered
to offer or sell such securities to such purchaser:
(i) Any preliminary prospectus or prospectus of the
undersigned small business issuer relating to the offering
required to be filed pursuant to Rule 424;
(ii) Any free writing prospectus relating to the offering
prepared by or on behalf of the undersigned small business
issuer or used or referred to by the undersigned small business
issuer;
(iii) The portion of any other free writing prospectus
relating to the offering containing material information about
the undersigned small business issuer or its securities provided
by or on behalf of the undersigned small business issuer; and
(iv) Any other communication that is an offer in the
offering made by the undersigned small business issuer to the
purchaser.
II-7
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 Post Effective Amended
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
3rd day
of November, 2006.
AURORA OIL & GAS CORPORATION
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|
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By:
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/s/ William
W. Deneau
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William W. Deneau, President and Chairman
Pursuant to the requirements of the Securities Act of 1933, this
Amended
Form SB-2
Registration Statement has been signed by the following persons
in the capacities and on the dates indicated:
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Signature
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Title
|
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Date
|
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/s/ William W.
Deneau
William
W. Deneau
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President, Chairman and Director
(Principal Executive Officer)
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|
November 3, 2006
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|
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/s/ Ronald E. Huff
Ronald
E. Huff
|
|
Chief Financial Officer and
Director (Principal Financial Officer and Principal Accounting
Officer)
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|
November 3, 2006
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/s/ Kevin D. Stulp
Kevin
D. Stulp
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Director
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November 3, 2006
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|
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/s/ Richard M.
Deneau
Richard
M. Deneau
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Director
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November 3, 2006
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/s/ Gary J. Myles
Gary
J. Myles
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Director
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November 3, 2006
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/s/ Earl V. Young
Earl
V. Young
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Director
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November 3, 2006
|
II-8
INDEX OF
EXHIBITS
|
|
|
|
|
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3
|
.1(1)
|
|
Restated Articles of Incorporation
of Aurora Oil & Gas Corporation.
|
|
3
|
.2(1)
|
|
Bylaws of Aurora Oil &
Gas Corporation.
|
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4
|
.1
|
|
Articles of Amendment to Articles
of Incorporation, relating to the Class A Preferred Stock.
(Filed as Exhibit 4 to our
Form 10-KSB
for the fiscal year ended September 30, 2003, filed with
the SEC on January 13, 2004, and incorporated herein by
reference.)
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5
|
.1
|
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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.)
|
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10
|
.2
|
|
Agreement and Plan of Merger dated
as of January 31, 2005 between Cadence Resources
Corporation, Aurora Acquisition Corp. and Aurora Energy, Ltd.
(Filed as Exhibit 10.3 to our
Form S-4
Registration Statement filed with the SEC on May 13, 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, LLC et al. and TCW Asset Management
Company, dated August 12, 2004 (filed as an Exhibit to the
Registrants 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, LLC et al. and
TCW Asset Management Company, dated December 8, 2005 (filed
as an Exhibit to the Registrants 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(2)
|
|
Credit Agreement among Aurora
Antrim North, L.L.C., et al. and BNP Paribas, et al.,
dated January 31, 2006.
|
|
10
|
.8(2)
|
|
Intercreditor and Subordination
Agreement among BNP Paribas, et al., TCW Asset Management
Company, and Aurora Antrim North, L.L.C., dated January 31,
2006.
|
|
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
|
|
Letter Agreement with Bach
Enterprises dated July 10, 2006. This Agreement is
confidential, has been omitted from this filing, 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(5)
|
|
LLC Membership Interest Purchase
Agreement dated October 6, 2006 relating to Kingsley
Development Company, L.L.C.
|
|
10
|
.19(5)
|
|
Asset Purchase Agreement with Bach
Enterprises, Inc., et al, dated October 6, 2006.
|
|
10
|
.20(5)
|
|
Promissory Note from Aurora
Energy, Ltd. to Northwestern Bank dated October 15, 2006.
|
|
10
|
.21(5)
|
|
Form of Indemnification letter
agreement between Aurora Oil & Gas Corporation and Rubicon
Master Fund.
|
|
10
|
.22(5)
|
|
Patricia A. Deneau Trust
Commercial Guaranty of obligations to Northwestern Bank.
|
|
10
|
.23(5)
|
|
Patricia A. Deneau Trust
Commercial Pledge Agreement to Northwestern Bank.
|
|
15
|
|
|
Awareness letter from Rachlin
Cohen & Holtz LLP.
|
|
21
|
(5)
|
|
Subsidiaries of Aurora
Oil & Gas Corporation.
|
II-9
|
|
|
|
|
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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
|
|
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 September 8, 2006 with our Form SB-2
registration statement filing, registration
no. 333-137176. |
|
|
|
(4) |
|
Filed on October 18, 2006 with our Amendment No. 1 to
Form SB-2 registration statement filing, registration
no. 333-137176. |
|
|
|
(5) |
|
Filed on October 27, 2006 with our Amendment No. 3 to
Form SB-2 registration statement filing, registration
no. 333-137176. |
II-10
EX-5.1
2
k09654p1exv5w1.htm
OPINION OF FRASER TREBILCOCK DAVIS & DUNLAP, P.C.
exv5w1
Exhibit 5.1
Fraser Trebilcock Davis & Dunlap, P.C.
Lawyers
|
|
|
|
|
|
|
PETER L. DUNLAP3
|
|
PETER D. HOUK1
|
|
124 West Allegan Street, Suite 1000
|
|
Detroit Office |
DOUGLAS J. AUSTIN
|
|
JONATHAN E. RAVEN
|
|
LANSING, MICHIGAN 48933
|
|
Telephone (313) 237-7300 |
MICHAEL E. CAVANAUGH
|
|
THADDEUS E. MORGAN
|
|
TELEPHONE (517) 482-5800
|
|
Facsimile: (313) 961-1651 |
JOHN J. LOOSE
|
|
ANNE BAGNO WIDLAK
|
|
FACSIMILE (517) 482-0887
|
|
|
DAVID E.S. MARVIN4
|
|
ANITA G. FOX4
|
|
website www.fraserlawfirm.com
|
|
Archie C. Fraser (1902-1998) |
STEPHEN L. BURLINGAME
|
|
ELIZABETH H. LATCHANA
|
|
|
|
Everett R. Trebilcock (1918-2002) |
DARRELL A. LINDMAN
|
|
TODD D. CHAMBERLAIN
|
|
|
|
James R. Davis (1918-2005) |
IRIS K. LINDER
|
|
RYAN M. WILSON
|
|
|
|
|
GARY C. ROGERS
|
|
KENNETH S. WILSON2
|
|
|
|
Of Counsel |
MARK A. BUSH
|
|
ROBERT B. NELSON
|
|
|
|
Donald A. Hines |
MICHAEL H. PERRY
|
|
BRIAN P. MORLEY6
|
|
|
|
Ronald R. Pentecost |
BRANDON W. ZUK
|
|
JOHN D. MILLER7
|
|
|
|
|
DAVID D. WADDELL
|
|
TONI L. HARRIS8 |
|
|
|
|
MICHAEL C. LEVINE
|
|
RYAN K. KAUFFMAN
|
|
Writers Direct Dial: (517)377-0803
|
|
1Retired Circuit Judge |
THOMAS J. WATERS
|
|
JOSHUA S. SMITH
|
|
Writers E-mail: ILINDER@FRASERLAWFIRM.C
|
|
OM 2Also Licensed in Florida |
MARK R. FOX2, 4
|
|
KATHERINE A. WEED
|
|
|
|
3Also Licensed in Colorado |
MICHAEL S. ASHTON
|
|
JENNIFER UTTER HESTON
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|
|
|
4Also Licensed in District of Columbia |
H. KIRBY ALBRIGHT
|
|
DOUGLAS L. MINKE
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|
5Also Certified Public Accountant |
GRAHAM K. CRABTREE
|
|
NICOLE L. PROULX
|
|
|
|
6Also Licensed in North Carolina |
MICHAEL P. DONNELLY
|
|
VINCENT M. PECORA
|
|
|
|
7Also Licensed in Georgia |
EDWARD J. CASTELLANI5
|
|
G. ALAN WALLACE
|
|
|
|
8Also Admitted by U.S. Patent and Trademark Office |
NAN ELIZABETH CASEY |
|
|
|
|
|
|
November
3, 2006
Aurora Oil & Gas Corporation
4110 Copper Ridge Drive, Suite 1000
Traverse City, MI 49684
Dear Ladies and Gentlemen:
We have acted as counsel to Aurora Oil & Gas Corporation, a Utah corporation (the
Company) in connection with the Companys filing of a Registration Statement on Form SB-2
(the Registration Statement) with the Securities and Exchange Commission (the
Commission) under the Securities Act of 1933, as amended (the Act), relating to
the resale of up to 21,860,000 shares of its common stock, par value $.01 per share (the
Common Stock) by investors named in the Registration Statement. Of the registered shares,
20,764,000 shares (the Issued and Outstanding Registered Shares) are currently issued and
outstanding, and 1,096,000 (the Warrant Shares) are issuable upon exercise of certain
warrants (the Warrants).
In connection with the foregoing, we have examined originals or copies satisfactory to us of:
(i) the Registration Statement, including the form of prospectus included therein; (ii) certain
resolutions of the Board of Directors the Company regarding the authorization of the Registered
Shares and the Warrants pursuant to which certain of the Registered Shares are issuable; (iii) the
form of the Warrants; (iv) the Companys Restated Articles of Incorporation; (v) the Companys
Bylaws; and (vi) a certificate as of a recent date from the State of Utah concerning the good
standing of the Company as a corporation in Utah.
We have also reviewed such other matters of law as we have deemed relevant and necessary as a
basis for the opinions hereinafter expressed. In such examination, we have assumed the genuineness
of all signatures, the authenticity of all documents submitted to us as originals and the
conformity with the original documents of all documents submitted to us as copies or facsimiles. As
to any facts material to such opinion, we have, to the extent that relevant facts were not
independently established by us, relied on certificates of public officials and certificates of
officers or other representatives of the Company.
Aurora Oil & Gas Corporation
November 3, 2006
Page 2
We have also assumed that: (i) all Registered Shares have been or will be issued and sold in
compliance with applicable federal and state securities laws; (ii) at the time of any offering or
sale of any shares of Common Stock, the Company will have such number of shares of Common Stock
authorized and available for issuance as may be offered and sold pursuant to the Registration
Statement; (iii) there shall be no change in law affecting the validity of any of the shares of
Common Stock (between the date hereof and the date of issuance and sale of such shares of Common
Stock); and (iv) all parties to agreements involving the issuance or sale of the shares of Common
Stock will perform their obligations thereunder in compliance with the terms of such documents.
Based upon and subject to the foregoing, we are of the opinion that the issued and outstanding
Registered Shares are legally issued, fully paid and non-assessable shares of Common Stock, and the
Warrant Shares will be, upon issuance in accordance with the terms of the Warrants, legally issued,
fully paid and non-assessable shares of Common Stock.
We hereby consent to the filing of this opinion as an exhibit to the Registration Statement
and to the reference made to us under the caption Legal Matters in the prospectus constituting
part of the Registration Statement. In giving this consent, we do not thereby admit that we are
within the category of persons whose consent is required under Section 7 of the Act, the rules and
regulations of the Commission promulgated pursuant to Section 7 of the Act or Item 509 of
Regulation S-B promulgated under the Act.
We are members of the Bar of the State of Michigan and do not hold ourselves out as being
experts on laws other than laws of the State of Michigan and the laws of the United States of
America. To the extent our opinion is based on Utah corporate law, we have relied on an unofficial
compilation of the Utah Revised Business Corporation Act.
Very truly yours,
FRASER TREBILCOCK DAVIS & DUNLAP, P.C.
EX-15
3
k09654p1exv15.htm
AWARENESS LETTER FROM RACHLIN COHEN & HOLTZ LLP
exv15
Exhibit 15
AWARENESS LETTER OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Aurora Oil & Gas Corporation
Traverse City, Michigan
We have made a review, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), of the unaudited interim condensed financial information of Aurora Oil & Gas
Corporation and subsidiaries for the six months ended June 30, 2006 and 2005, and have issued our
report dated August 7, 2006. As indicated in such report, because we did not perform an audit, we
expressed no opinion on that information.
We are aware that our report referred to above is included in the Prospectus constituting part of
this Post Effective Amendment No. 1 to the Registration Statement on Form SB-2 (No.
333-129695).
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RACHLIN COHEN & HOLTZ LLP |
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Miami, Florida
November 2, 2006
EX-23.1
4
k09654p1exv23w1.htm
CONSENT OF RALPH E. DAVIS ASSOCIATES, INC.
exv23w1
Exhibit 23.1
[RALPH E. DAVIS ASSOCIATES, INC. LOGO]
CONSENT OF
RALPH E. DAVIS ASSOCIATES, INC.
We hereby consent to the use of the name Ralph E. Davis Associates, Inc. and the
reference to Ralph E. Davis Associates, Inc., and the inclusion of and references to our
report, or information contained therein, dated January 30, 2006, prepared for Cadence Resources Corporation
in the Post Effective Amendment to Form SB-2 Registration Statement for the filing dated on or
about November 2, 2006.
Houston, Texas
November 2, 2006
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RALPH E. DAVIS ASSOCIATES, INC.
|
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By: |
/s/ Joseph Mustacchia, Jr.
|
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|
Joseph Mustacchia, Jr. |
|
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Executive Vice-President |
|
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EX-23.2
5
k09654p1exv23w2.htm
CONSENT OF SCHLUMBERGER TECHNOLOGY CORPORATION
exv23w2
Exhibit 23.2
Data & Consulting Services
Division of Schlumberger Technology Corporation
1310 Commerce Drive
Park Ridge 1
Pittsburgh, PA 15275-1011
Tel: 412-787-5403
Fax: 412-787-2906
CONSENT OF
SCHLUMBERGER DCS
We hereby consent to the use of the name Data & Consulting Services (DCS) Division of
Schlumberger Technology Corporation and the use of any references to such entities, and the
inclusion of and references to our reports, or information contained therein, dated February 7 and
February 8, 2006, prepared for Aurora Energy, Ltd. in the Post Effective Amendment to the SB-2
Registration Statement for the filing dated on or about November 2, 2006.
Pittsburgh, Pennsylvania
November 2, 2006
Charles M. Boyer II, P.G.
Operations Manager
Pittsburgh Consulting Services
EX-23.3
6
k09654p1exv23w3.htm
CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.
exv23w3
Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the use of the name Netherland, Sewell & Associates, Inc. and the
reference to Netherland, Sewell & Associates, Inc., and the
inclusion of and references to our
report, or information contained therein, dated February 2, 2006, prepared for Aurora Energy, Ltd.
in the Post Effective Amendment to the SB-2 Registration Statement for the filing dated on or
about November 2, 2006.
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NETHERLAND, SEWELL & ASSOCIATES, INC.
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By: |
/s/ C.H. (Scott) Rees III
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C.H. (Scott) Rees III |
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President and Chief Operating Officer |
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Dallas, Texas
November 2, 2006
EX-23.4
7
k09654p1exv23w4.htm
CONSENT OF RACHLIN COHEN & HOLTZ LLP.
exv23w4
Exhibit 23.4
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the use in the Prospectus constituting part of this Post Effective
Amendment No. 1 to the Registration Statement on Form SB-2 (No. 333-129695) of our report dated
February 24, 2006 relating to the consolidated balance sheets of Cadence Resources Corporation and
Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements
of operations, shareholders equity and cash flows for each of the years then ended, appearing in
such Prospectus.
We also consent to the reference to our firm under the heading Experts in the Prospectus.
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RACHLIN COHEN & HOLTZ LLP |
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Miami, Florida
November 2, 2006
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