BPI Energy Holdings, Inc. 10-K
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF
1934
For the Fiscal Year Ended July 31, 2006
Commission File Number:
001-32695
BPI Energy Holdings,
Inc.
(Exact name of registrant as
specified in its charter)
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British Columbia,
Canada
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75-3183021
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(State or other jurisdiction
of
incorporation or
organization)
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(I.R.S. Employer
Identification No.)
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30775
Bainbridge Road, Suite 280
Solon, Ohio 44139
(440) 248-4200
(Address
and telephone number of principal executive
offices)
Securities
registered under Section 12(b) of the Exchange
Act:
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Name of Exchange on
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Title of Each Class
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Which Registered
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Common Shares, without par value
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American
Stock Exchange
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Securities registered under Section 12(g) of the
Exchange Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months, and (2) has been subject to such filing
requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers in
response to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act. (Check One):
Large Accelerated
Filer o Accelerated
Filer o Non-Accelerated
Filer þ
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
State the aggregate market value of the voting and non-voting
common equity held by non-affiliates computed by reference to
the price at which the common equity was last sold, or the
average bid and asked price of such common equity, as of the
last business day of the registrants most recently
completed second fiscal quarter: $152,972,282.
As of October 25, 2006, there were 71,872,540 shares
of the Registrants Common Shares (without par value)
outstanding.
Documents
Incorporated by Reference:
Certain portions of Part III are incorporated by reference
to the Registrants definitive proxy statement.
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
Some of the statements contained in this report and other
materials we file with the SEC, or in other written or oral
statements made or to be made by us, other than statements of
historical fact are forward-looking statements as
defined in the Private Securities Litigation Reform Act of 1995.
Forward-looking statements give our current expectations or
forecasts of future events. Statements containing the words
believes, anticipates,
expects, intends, plans,
predict, strategy, budget,
project, potential, should,
may, might, continue and
estimate and similar words are used to identify
forward-looking statements. These forward-looking statements
involve known and unknown risks, uncertainties and other factors
that may cause our actual results, performance or achievements,
or the conditions in our industry, on our properties or in the
Illinois Basin to be materially different from any future
results, performance, achievements or conditions expressed or
implied by such forward-looking statements. Some of the factors
that could cause actual results or conditions to differ
materially from our expectations include the factors discussed
in this report under the heading Risk Factors and
elsewhere.
Given these uncertainties, you should not place undue reliance
on such forward-looking statements. Except as otherwise required
by applicable law, we undertake no obligation to publicly update
or revise any forward-looking statements, the risk factors or
other information described in this report, whether as a result
of new information, future events, changed circumstances or any
other reason after the date of this report.
PART
I
Coalbed
Methane
We are engaged in the exploration, production and commercial
sale of coalbed methane (CBM). CBM is a form of
natural gas that is generated during coal formation and is
contained in underground coal seams and abandoned mines.
Methane is the primary commercial component of natural gas
produced from conventional gas wells. Natural gas produced from
conventional wells generally contains other hydrocarbons in
varying amounts that require the natural gas to be processed.
CBM is generally pipeline-quality gas after simple water
dehydration and removal of traces of nitrogen and other
impurities.
CBM production is similar to conventional natural gas production
in terms of the physical producing facilities. However, the
subsurface mechanisms that allow gas movement to the wellbore
are very different. Conventional natural gas wells require a
subsurface that is porous, allows the gas to migrate easily, and
contains a natural trap to capture and hold the gas reservoir.
In contrast, CBM is held in place within coal seams in four ways:
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as free gas within the micropores (pores with a diameter of less
than .0025 inch) and cleats (set of natural fractures) of
coal;
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as dissolved gas in water within the coal;
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as adsorbed gas held by molecular attraction on the surface of
macerals (organic constituents that comprise the coal mass),
micropores and cleats in the coal; and
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as adsorbed gas within the molecular structure of the coal.
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Coal at shallower depths with good cleat development contains
high concentrations of free and dissolved methane gas.
Adsorption is generally higher in coal that contains a higher
percentage of fixed carbon and generally increases with higher
pressure, which occurs at deeper depths. We currently intend to
drill and produce from coal seams ranging in depth from 300 to
1,200 feet beneath the surface.
CBM gas is released from the coal by pressure changes when water
is removed from coal. In contrast to conventional gas wells, new
CBM wells initially produce mostly water for several months. As
pressure decreases in the coal formation, methane gas is
released from the coal.
1
To assist you in reading this report and understanding our
business, we have included a glossary of selected natural gas
terms that are used in this report. The glossary is set forth as
Appendix A beginning on
Page A-1.
Our
Business
We focus on the acquisition, exploration, development and
production of CBM reserves located in the Illinois Basin, which
covers approximately 60,000 square miles in the mid to
southern part of Illinois, southwest Indiana and northwest
Kentucky. Through lease, option and farm-out agreements and
ownership of a CBM estate, we have assembled CBM rights covering
approximately 500,000 acres in the Illinois Basin. We believe
that these rights currently give us control over more CBM
acreage than any other company in the Illinois Basin.
A Gas Technology Institute report from 2001 estimates that 21
trillion cubic feet of CBM gas is in place in the Illinois
Basin. Although the Illinois Basin is believed to have
significant CBM potential, it is largely untested for commercial
CBM production. In addition, we have evaluated the CBM potential
in only a relatively small part of our acreage rights.
Our acreage rights in the Illinois Basin are currently divided
into three projects. Our Southern Illinois Basin Project
consists of approximately 10,000 acres in the southern part of
the Illinois Basin. Our other acreage holdings include our
Northern Illinois Basin Project, located in the north central
part of the Illinois Basin, where we control through lease,
option and farm-out agreements an aggregate of
353,531 acres of CBM rights. Our other project is our
Western Illinois Basin Project, located in the northwestern part
of the Illinois Basin, where we control through lease, option
and farm-out agreements an aggregate of 135,948 acres of
CBM rights. In addition, we continue to look for opportunities
to acquire additional CBM acreage rights in the Illinois Basin.
As of July 31, 2006, we have drilled 125 wells. These
wells include 86 productive wells, 14 shut-in wells, five
plugged wells, two disposal wells and 18 wells that have
been drilled but are not yet in production, including five test
wells.
Our
History
BPI Energy Holdings, Inc. was incorporated under the laws of
British Columbia in 1980. Our corporate offices in the United
States are located at 30775 Bainbridge Road, Suite 280,
Solon, Ohio 44139, telephone
(440) 248-4200.
Our records office and registered office in Canada is located at
609 Granville Street, Suite 1600, Vancouver, British
Columbia V7Y 1C3, telephone
(604) 685-8688.
Our operations are conducted from an office located in
Edwardsville, Illinois.
Beginning in 1996, we had a minority involvement in the Southern
Illinois Basin Project. In 2001, Methane Management, Inc.
acquired the Southern Illinois Basin Project subject to our
minority interest. In August 2001, we acquired Methane
Management, Inc. and consolidated 100% of the Southern Illinois
Basin Project within BPI. James G. Azlein, President of Methane
Management, Inc. at the time, became our President, and we
created a new management team. We have since divested all of our
assets that are not related to CBM projects in the Illinois
Basin.
Business
Strategy
The objectives of our business strategy are to generate growth
in gas reserves, production volumes and cash flows at a positive
return on invested capital. The principal elements of our
business strategy are to:
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Explore and Develop Properties. As of
July 31, 2006, we have drilled 125 wells. These wells
consist of 86 productive wells (all located at our Southern
Illinois Basin Project), 14 shut-in wells, five plugged wells,
two disposal wells and 18 wells that have been drilled but are
not yet in production, including five test wells. During the
12-month
period ending July 31, 2007, we plan to drill between 58
and 123 new wells. This plan contemplates capital expenditures
of approximately $12.0 million to $30.0 million. The
number of wells that we drill during the
12-month
period ending July 31, 2007 will be dependent on
(i) data obtained from test wells; (ii) data obtained
from our initial pilot wells at our Northern Illinois Basin
Project; and (iii) the additional capital that we are able
to raise and the risk factors described in this report.
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Become a World Class CBM Exploration and Production
Company. We are expanding our technical
management team by recruiting and attracting engineers,
geologists and production personnel with substantial experience
at some of the most successful CBM projects in North America.
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Expand CBM Acreage Rights. We continue to look
for opportunities to acquire additional CBM acreage rights in
the Illinois Basin. Our strategy has been to acquire leases and
options on large acreage blocks in areas where reservoir
properties are more favorable and there is currently pipeline
delivery infrastructure in place.
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Pursue Joint Ventures. We continue to consider
joint venture opportunities. With our asset base and technical
expertise, we believe that we are well positioned to attract
industry joint venture partners for the purposes of providing
capital, technical operating expertise and development
opportunities to accelerate our growth.
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Competitive
Strengths
We believe our competitive strengths include the following:
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Substantial CBM Acreage Position. The Illinois
Basin is one of the few remaining unexploited CBM areas in North
America. Because we were the first company to begin acquiring
substantial blocks of CBM acreage rights in the Illinois Basin,
we have been able to assemble several large contiguous blocks.
We believe that we currently control more CBM acreage than any
other company in the Illinois Basin. This substantial footprint
should give us opportunities to leverage our knowledge of the
Basin and realize significant economies of scale as our drilling
and production activities grow throughout the Basin.
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Demonstrated Commercial Production. We believe
that we have taken the initial steps to demonstrate the
commercial production capabilities of the Illinois Basin. As of
July 31, 2006, we have drilled 125 wells, including 86
productive wells located at our Southern Illinois Basin Project,
most of which have not yet reached peak production. We believe
that our increasing production at the Southern Illinois Basin
Project demonstrates the commercial viability of the Illinois
Basin. During our fiscal year ended July 31, 2005 we sold
17,885 Mcf of CBM, and during our fiscal year ended
July 31, 2006 we sold 135,118 Mcf of CBM.
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Short Drilling Permit Lead Times. We typically
experience short turnaround times in obtaining drilling permits
as compared to CBM drillers in other CBM basins.
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Low Water Disposal Costs. A significant
advantage of operating in the Illinois Basin is that we are not
required to build costly water disposal facilities. We have
disposed of the water we encounter in connection with our
drilling and production by re-injecting the water into disposal
wells drilled and operated by us.
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Substantial Interstate Pipeline Capacity and Low
Transportation Costs. A significant advantage
that we have over CBM producers in other basins is our proximity
to a large number of interstate gas pipelines that have
substantial take-away capacity. Because our operations and CBM
acreage are located near several large metropolitan gas
consuming markets (e.g., Chicago, St. Louis, Nashville,
Indianapolis and Detroit) and the fact that many interstate
pipelines headed to the East Coast pass through the Illinois
Basin, we expect to incur little or no pipeline-related
transportation charges. In addition, we do not expect to
experience any lost production or sales due to insufficient
local or interstate pipeline capacity to transport the CBM that
we produce and sell.
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Experienced and Incentivized Management and Operating
Teams. Our operating team includes individuals
that have participated in the drilling or operating of CBM wells
in North America since the early 1980s and in the Illinois Basin
since 1996. In addition, all of our management team and the
majority of the operating employees own common shares in the
company.
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CBM
Acreage Rights
As of July 31, 2006, our CBM acreage rights, controlled
through lease, option and farm-out agreements and ownership of a
CBM estate, include the following:
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Developed
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Undeveloped
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Total
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Project
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Acres
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Acres
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Acres(1)
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Southern Illinois Basin Project(2)
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5,532
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4,468
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10,000
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Northern Illinois Basin Project
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0
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353,531
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353,531
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Western Illinois Basin Project
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0
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135,948
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135,948
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Total
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5,532
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493,947
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499,479
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(1) |
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Because we are the exclusive owner of the CBM rights under each
of our lease, option and farm-out agreements, our acreage totals
reflect both gross and net acres. |
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We acquired ownership of the CBM estate covering
10,000 acres in our Southern Illinois Basin Project in a
settlement with our former lessor, which is the owner of the
coal rights. |
Under the terms of the lease and option agreements pursuant to
which we have acquired nearly all of our CBM rights, we are
entitled to all of the CBM rights held by our lessors in the
counties covered by these agreements. However, we face a number
of uncertainties regarding what rights our lessors hold.
The issue of who owns CBM gas, as between the coal rights owner
and the oil and gas rights owner, is uncertain in Illinois.
Although the appellate court in Illinois for the district where
most of our acreage rights are situated has ruled that CBM gas
is owned by the coal rights owner, the issue has not been
addressed by the highest court in Illinois. We believe, based on
advice from legal counsel, that under Illinois law ownership
will ultimately be found to lie with the coal rights owner.
Based on this advice, we generally secure CBM rights from the
coal owners. Some of the lessors from which we have acquired CBM
rights may hold both the coal rights and the oil and gas rights
for the applicable properties, but in some cases it is not
certain that these lessors also hold the oil and gas rights. If
any litigation in Illinois concludes that CBM rights lie with
the oil and gas owner, we could lose some of our CBM rights.
In addition, in some cases the extent of the coal
and/or oil
and gas rights held by our lessors is uncertain. We conducted no
title or deed examinations prior to executing our lease and
option agreements, and our lessors made no warranties as to the
acreage or rights covered by the agreements. Although we have
now conducted title and deed examinations covering much of the
CBM properties under our leases, these examinations are ongoing
at all of our projects. There can be no assurance that our
rights under our lease and option agreements include all of the
acreage and rights identified in the agreements until title
examinations on all of the underlying properties have been
completed.
We have been subject to legal complaints regarding the extent of
the surface rights that derive from our CBM rights. On occasion,
the owners of properties that are adjacent to our drilling
locations have challenged our right to cross their property in
accessing our drilling locations and our right to lay gas and
water flow lines across their property. The extent of our rights
in respect of these issues is uncertain in Illinois. If disputes
regarding our surface rights are not resolved in our favor, we
may be required to acquire surface rights or access our drilling
locations and lay gas and water flow lines in inefficient ways,
which would cause us to incur increased operating costs. In
addition, we could incur significant costs in legal disputes
over our surface rights. During our fiscal year ended
July 31, 2005 we incurred approximately $303,000 in legal
fees in connection with legal disputes over surface rights, and
during our fiscal year ended July 31, 2006 we incurred
approximately $10,000 in legal fees in connection with such
disputes. If for any reason these operating or legal costs
increase significantly, our financial performance will suffer.
Southern
Illinois Basin Project
Our CBM rights in the Southern Illinois Basin Project cover
10,000 acres in the southern part of the Illinois Basin. We
hold our CBM rights on this acreage pursuant to a purchase
agreement under which we acquired the
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CBM estate in a settlement with our former lessor, the owner of
the coal rights. Under the terms of the deed covering this
acreage, our right to drill for and produce CBM takes precedence
over coal mining operations for as long as CBM is being produced
from the acreage. However, the owner of the coal rights has the
right to acquire any CBM wells located in these
10,000 acres. If the coal rights owner exercises this
option, it will be required to (i) immediately plug any
such well so acquired and (ii) pay the fair market value
(as established by a mutually agreed upon expert) of such well.
We are currently paying two overriding royalties of 3% and 4% on
our production at this project, which are calculated based on
43.35% of our gross revenues.
We commenced sales of gas from our initial pilot production
wells on this project in January 2005. As of July 31, 2006,
we have drilled 108 wells at this project. These wells
consist of 86 productive wells, 14 shut-in wells, of which eight
are scheduled to be plugged in fiscal year 2007 (as a result of
the Colt LLC settlement), four plugged wells, one disposal
well and three wells that have been drilled but are not yet
in production. Most of the productive wells drilled at this
project were initially completed in a limited number of seams,
intentionally excluding other seams. Our intention when we
drilled these wells was to gather as much geological information
as we could about CBM and dewatering characteristics of
individual coal seams. During our 2006 fiscal year we went back
and completed additional seams in most of these wells to begin
dewatering and producing CBM from the additional seams
penetrated by these wells. During fiscal year 2007, we will
determine whether it is beneficial to complete additional seams
in the remaining wells.
Northern
Illinois Basin Project
Our CBM rights in the Northern Illinois Basin Project cover
353,531 acres in Montgomery, Shelby, Christian, Fayette and
Macoupin Counties in Illinois, which are located in the north
central part of the Illinois Basin. We hold our CBM rights on
this acreage pursuant to mineral leases, an option to acquire a
mineral lease and a farm-out agreement.
We have entered into a lease agreement with Montgomery County
covering 120,951 acres of CBM rights in Montgomery County,
Illinois. The lease agreement extends until November 27,
2010. After the initial term of the agreement, we can continue
to hold the lease as long as we are producing CBM from the
covered acreage. Under the lease agreement, we will be required
to pay royalties to the lessor equal to 12.5% of our gross
proceeds from the sale of CBM produced from the covered acreage.
We have also entered into a lease agreement with Shelby County
covering 63,250 acres of CBM rights in Shelby County,
Illinois. This lease agreement extends until November 12,
2008. After the initial term of the agreement, we can continue
to hold the lease as long as we are producing CBM from the
covered acreage, with each productive vertical well holding
320 acres and each productive horizontal well holding
1,920 acres. We are required to pay royalties to the lessor
equal to 12.5% of our gross proceeds from the sale of CBM
produced from the covered acreage.
We have also entered into a lease agreement with IEC
(Montgomery), LLC covering 102,000 acres of CBM rights in
Christian, Fayette, Montgomery and Shelby Counties in Illinois.
The lease agreement extends until April 26, 2026. After the
initial term of the agreement, we can continue to hold the lease
as to each acreage block where we are producing CBM in
commercial quantities. We are required to pay royalties to the
lessor on our gross proceeds from the sale of CBM produced from
the covered acreage at rates ranging up to 12.5%.
We have also entered into a lease agreement with Christian Coal
Holdings, LLC covering 12,044 acres of CBM rights in
Christian and Montgomery Counties in Illinois. The lease
agreement extends until April 26, 2026. After the initial
term of the agreement, we can continue to hold the lease as to
each acreage block where we are producing CBM in commercial
quantities. We are required to pay royalties to the lessor on
our gross proceeds from the sale of CBM produced from the
covered acreage at a rate of 12.5%.
We also hold an option from Christian County to lease
14,033 acres of CBM rights in Christian County, Illinois.
The option extends until January 20, 2007. The lease
agreement underlying the option will extend for a period of five
years from the date we exercise the option. After the initial
term of the agreement, we can continue to hold the lease as long
as we are producing CBM from the covered acreage. Under the
lease agreement, we will be
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required to pay royalties to the lessor equal to 12.5% of our
gross proceeds from the sale of CBM produced from the covered
acreage.
Under the lease agreements with Montgomery and Shelby Counties
and the lease agreement underlying the option agreement with
Christian County, our right to drill for and produce CBM is
expressly subject to the mining of coal on the covered acreage.
We may not interfere with any existing coal mining operations
and, under certain circumstances, may be required to cease
drilling in locations where coal mining operations will be
undertaken.
Under the lease agreements with IEC (Montgomery), LLC and
Christian Coal Holdings, LLC, any drilling operations that we
set up can be displaced by coal mining operations. However, the
lessor is required to provide us with a mine plan for the leased
acreage indicating the acreage blocks that the lessor plans to
mine and the order of priority for the acreage blocks that it
plans to mine. If the lessor displaces a well ahead of the
schedule outlined in the mine plan, the lessor may be required
to reimburse us for the cost of plugging the well and, depending
on how long the well has been in production and the cumulative
gross income generated by the well, the value of the CBM that
could be recovered from the well in the remainder of an
eight-year term.
Also included in the Northern Illinois Basin Project are
41,253 acres of CBM rights in Macoupin County, Illinois,
which we can earn under a farm-out agreement with Addington
Exploration, LLC, as described below.
As of July 31, 2006, we had just recently completed
drilling of a 10-well pilot program at this project, and all
wells were in the initial stages of dewatering as of that date.
As of the same date, we have drilled three test wells at this
project. In addition, we intend to drill two additional test
wells at this project during the first quarter of 2007.
Western
Illinois Basin Project
Our CBM rights in the Western Illinois Basin Project cover
135,948 acres in Clinton, Washington, Marion and Perry
Counties in Illinois, which are located in the northwestern part
of the Illinois Basin. We hold our CBM rights on this acreage
pursuant to mineral leases, an option to acquire a mineral lease
and a farm-out agreement.
We have entered into a lease agreement with Clinton County
covering 55,900 acres of CBM rights in Clinton County, Illinois.
The lease agreement extends until October 24, 2010. After
the initial term of the agreement, we can continue to hold the
lease as long as we are producing CBM from the covered acreage.
We are required to pay royalties to the lessor equal to 12.5% of
our gross proceeds from the sale of CBM produced from the
covered acreage.
We have also entered into a lease agreement with Washington
County covering 39,169 acres of CBM rights in Washington County,
Illinois. The lease agreement extends until September 9,
2011. After the initial term of the agreement, we can continue
to hold the lease as long as we are producing CBM from the
covered acreage, with each productive vertical well holding
320 acres and each productive horizontal well holding
1,920 acres. We are required to pay royalties to the lessor
from our gross proceeds from the sale of CBM produced from the
covered acreage. The royalty is equal to 12.5% or 6.25% of our
gross proceeds, depending on whether it is determined that
Washington Countys CBM rights, if any, are derived from
coal rights or oil and gas rights.
We also hold an option from Marion County to lease
17,882 acres of CBM rights in Marion County, Illinois. The
option extends until June 8, 2007. The lease agreement
underlying the option will extend for a period of five years
from the date we exercise the option. After the initial term of
the agreement, we can continue to hold the lease as long as we
are producing CBM from the covered acreage. Under the lease
agreement, we will be required to pay royalties to the lessor
equal to 12.5% of our gross proceeds from the sale of CBM
produced from the covered acreage. If we do not commence
exploration of CBM within one year from the commencement of the
lease, we will be required to pay advance royalties to the
lessor equal to $8,941 for each one-year period that we delay
commencing exploration. Any payment of advance royalties can be
credited against royalties that may later become payable to the
lessor from our production of CBM.
Under the lease agreement with Washington County and the lease
agreement underlying the option agreement with Marion County,
our right to drill for and produce CBM is expressly subject to
the mining of coal on the covered acreage. We may not interfere
with any existing coal mining operations and, under certain
circumstances, may be
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required to cease drilling in locations where coal mining
operations will be undertaken. Under the lease agreement with
Clinton County, coal mining rights granted to third parties do
not take precedence over our CBM operations.
Also included in the Western Illinois Basin Project are
22,997 acres in Perry County, Illinois, which we can earn
under a farm-out agreement with Addington Exploration, LLC, as
described below.
As of July 31, 2006, we have drilled two wells at the
Western Illinois Basin Project that have not yet been completed
and from which we are still gathering and evaluating test data.
We intend to drill three test wells at this project during the
first quarter of fiscal 2007.
Farm-out
Agreement with Addington Exploration, LLC
We have entered into a farm-out agreement with Addington
Exploration, LLC covering 41,253 acres of CBM rights in
Macoupin County, Illinois and 22,997 acres of CBM rights in
Perry County, Illinois that Addington controls pursuant to coal
seam gas leases. The farm-out agreement provides for an initial
36-month
evaluation period, during which we may test and evaluate the
covered properties. The
36-month
evaluation period can be extended by us on unearned acreage
through the payment of a fee equal to $0.50 per acre,
increasing over five years to $2.50 per acre. For each
vertical and horizontal well that we place into production
during the term of the agreement, Addington will assign to us
its CBM rights covering the surrounding 160 acres
penetrated by one of our wells.
We are required to pay Addington a royalty equal to 3% of our
proceeds from the sale of CBM produced from the covered acreage.
In addition, we must pay royalties totaling 12.5% to the lessors
under the coal seam gas leases underlying this farm-out
agreement.
Technical
Services Agreement with BHP Billiton
Our Technical Services Agreement with BHP Petroleum
(Exploration) Inc., a wholly owned subsidiary of BHP Billiton,
expired at the end of its term on September 30, 2006, and
BHP did not exercise its right to extend the agreement. The
right of first refusal to acquire us that was granted to BHP
under the Technical Services Agreement lapsed as of the
expiration date of the agreement, although the 4.0 million
stock appreciation rights that we granted to BHP, which may be
exercised by BHP only in connection with an acquisition of us,
continue in effect until March 30, 2007.
7
Status
of CBM Operations
The following table summarizes the status of wells we have
drilled as of July 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonproductive Wells
|
|
|
|
Productive
|
|
|
Drilled Not Yet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project
|
|
Wells
|
|
|
Completed(1)
|
|
|
Shut-in(2)
|
|
|
Plugged
|
|
|
Disposal
|
|
|
Total
|
|
|
Southern Illinois Basin Project
|
|
|
86
|
|
|
|
3
|
|
|
|
14
|
|
|
|
4
|
|
|
|
1
|
|
|
|
108
|
|
Northern Illinois Basin Project
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
15
|
|
Western Illinois Basin Project
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
86
|
|
|
|
18
|
|
|
|
14
|
|
|
|
5
|
|
|
|
2
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Wells drilled not yet completed includes our
recently completed drilling of a 10-well pilot program and three
test wells at the Northern Illinois Basin Project, two test
wells at our Western Illinois Basin Project and three wells
drilled at our Southern Illinois Basin Project in late fiscal
year 2006 that were completed in early fiscal year 2007 and
became productive wells. |
|
(2) |
|
Shut-in wells include eight wells that will be plugged
during fiscal year 2007 in connection with our settlement
agreement with Colt LLC. Of these eight wells to be
plugged, Colt LLC has agreed to plug four wells at their
expense and we will be responsible for plugging the remaining
four wells. |
The following table sets forth our drilling activities over the
last three fiscal years:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Years Ended July 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Exploratory Wells(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2)
|
|
|
10
|
|
|
|
|
|
|
|
|
|
Nonproductive(3)
|
|
|
4
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
14
|
|
|
|
3
|
|
|
|
|
|
Development Wells(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2)
|
|
|
49
|
|
|
|
37
|
|
|
|
|
|
Nonproductive(3)
|
|
|
5
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
54
|
|
|
|
54
|
|
|
|
|
|
Total Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2)
|
|
|
59
|
|
|
|
37
|
|
|
|
|
|
Nonproductive(3)
|
|
|
9
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
68
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
An exploratory well is a well drilled either in search of a new,
as yet undiscovered CBM 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
a CBM reservoir, as indicated by reasonable interpretation of
available data, with the objective of completing in that
reservoir. |
|
(2) |
|
A productive well is an exploratory or development well that has
been completed and is tied into our gas and/or dewatering
system. A productive well may produce only water for a period of
time before gas begins to flow through the gas gathering system. |
|
(3) |
|
A nonproductive well is an exploratory or development well that
is not currently a producing well. |
As of July 31, 2006, all of the wells that we have drilled
are vertical wells. We estimate that a typical vertical well
will require about 24 months to reach peak production. Most
of the productive wells were completed in a
8
limited number of seams, intentionally excluding other seams.
Our intention when we drilled these wells was to gather as much
geological information as we could about CBM and dewatering
characteristics of individual coal seams. During our 2006 fiscal
year we went back and completed additional seams in most of
these wells to begin dewatering and producing CBM from the
additional seams penetrated by these wells. During fiscal year
2007, we will determine whether it is beneficial to complete
additional seams in the remaining wells. We began selling gas
from our first productive wells in January 2005. As of
July 31, 2006, we believe that most of our productive wells
have not yet reached peak production. Although we have drilled
wells on only a relatively small part of our acreage, we have
not to date determined that any well we have drilled is a dry
hole.
Production and
Sales
The following table sets forth our net sales volume for the
periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended July 31,
|
|
|
2006(1)
|
|
2005(1)(2)
|
|
2004(2)
|
|
Total sales (Mcf)
|
|
|
135,118
|
|
|
|
17,885
|
|
|
|
|
|
|
|
|
(1) |
|
Total sales volumes omits (i) gas consumed in operations
and (ii) gas sales equivalent to royalty interests held by
our various lessors. |
|
(2) |
|
No gas was produced until January 2005. |
Average
Sales Prices and Production Costs
The following table sets forth the average sales price and
average production costs for all of our gas production for the
periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended July 31,
|
|
|
2006
|
|
2005
|
|
2004
|
|
Average gas sales price (per Mcf)
|
|
$
|
8.34
|
|
|
$
|
6.59
|
|
|
$
|
|
|
Average production cost (per
Mcf)(1)
|
|
|
7.18
|
|
|
|
17.18
|
|
|
|
|
|
|
|
|
(1) |
|
Production costs include a significant amount of fixed expenses
required to operate a minimum number of wells. As the number of
wells and production increase, these costs are expected to
decrease on a per unit basis as they are spread over a greater
amount of production. |
Reserves
Proved reserves are the estimated quantities that geological and
engineering data demonstrate with reasonable certainty to be
commercially 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 (of which none existed as of
July 31, 2005 and 2006, the dates of our estimates of
proved reserves prepared by our independent reservoir engineer
consultant, Schlumberger Data & Consulting Services),
but not on escalations based on future conditions. The following
table shows our estimated proved developed and proved
undeveloped reserves. Reserve information is net of royalty
interests owned by our lessors. Proved developed and proved
undeveloped reserves are reserves that could be commercially
recovered under current economic conditions, operating methods
and government regulations. Proved developed and undeveloped
reserves are defined by SEC Rule 4-10(a)(2) of
Regulation S-X.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves (MMcf)
|
|
|
|
As of July 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Estimated proved developed reserves
|
|
|
8,983
|
|
|
|
2,971
|
|
|
|
|
|
Estimated proved undeveloped
reserves
|
|
|
5,735
|
|
|
|
7,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated proved developed
and undeveloped reserves
|
|
|
14,718
|
|
|
|
10,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
Discounted
Future Cash Flows
The following table shows our standardized measure of discounted
future net cash flows, based on our estimated proved developed
and undeveloped reserves (discounted at a rate of 10%), net of
taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of July 31,
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
(In thousands)
|
|
Total standardized measure of
discounted future net cash flows
|
|
$
|
32,734
|
|
|
$
|
23,068
|
|
|
|
|
|
Prices used in calculating
reserves (per Mcf)
|
|
|
7.22
|
|
|
|
7.44
|
|
|
|
|
|
Sales and
Distribution of Our Gas
Our current and future plans anticipate that we will sell all of
our CBM to either (i) pipeline companies or
(ii) natural gas marketing companies that secure space on
pipelines. There are multiple pipeline and gas marketing
companies we could choose to deal with in selling our CBM. There
are multiple interstate and intrastate pipeline companies that
have pipelines that cross or are in close proximity to all of
our current acreage in the Illinois Basin. The interstate
pipelines include lines owned by Texas Eastern, Northern
Borders, NGPL and Ameren. These pipelines are available to the
marketing companies to whom we anticipate selling CBM. We
believe that these marketing companies will have adequate
capacity from the existing pipelines in the Illinois Basin to be
able to purchase all of the CBM we anticipate producing and
selling within the next three to five years.
We currently sell all of our CBM production to one gas marketing
company, Atmos Energy Marketing, LLC, pursuant to monthly
contracts. Under these monthly contracts, Atmos is required to
buy all of our CBM production, up to a maximum of
2,500 MMBtus per day (which equates to approximately four
times our current daily production), at the NYMEX (New York
Mercantile Exchange) price as of the close of business on the
last day of the most recently ended month less twenty-five cents
per MMBtu as a marketing charge. If we are unable to extend our
monthly contracts with Atmos, we believe that we will have
multiple gas marketing companies available to us for the sale of
our CBM production.
We currently have no fixed price contracts for the sale of our
CBM. We do not anticipate entering into any fixed price
contracts for the sale of our CBM during the next
24 months. We will reevaluate the risks and benefits of
entering into fixed price contracts after our projects and wells
become more mature.
Availability
of Drilling Equipment and Personnel
We utilize drilling contractors to perform all of the drilling
on our projects. We maintain a limited number of supervisory and
field personnel to oversee drilling and production operations.
Our plans to drill additional wells are determined in large part
by the anticipated availability of acceptable drilling equipment
and crews. We believe that sufficient drilling equipment and
crews will be available to us in the Illinois Basin to achieve
our drilling plan for fiscal year 2007 (i.e., drilling between
58 and 123 CBM wells). However, we do not currently have any
contractual commitments with drilling contractors, and we can
provide no assurance that we will have adequate drilling
equipment or crews to achieve our drilling plans.
Governmental
Regulations
Our business is affected by numerous laws and regulations,
including those relating to energy, the environment and
conservation. Failure to comply with these laws and regulations
may result in increased compliance costs and the assessment of
administrative, civil or criminal penalties
and/or the
imposition of injunctive relief. Changes in any of these laws
and regulations could have a material adverse effect on our
business. In view of the many uncertainties with respect to
current and future laws and regulations, including their
applicability to us, we cannot predict the overall effect of
such laws and regulations on our future operations.
We believe that our current operations comply in all material
respects with applicable laws and regulations, and that they
have no more restrictive effect on us than on other similar
companies in the energy industry.
10
The following discussion describes certain laws and regulations
that apply to us and is qualified in its entirety by the
foregoing.
State
Regulations
Our operations are subject to regulation at the state level and,
in some cases, county, municipal and local governmental levels.
Such regulation includes:
|
|
|
|
|
requiring permits for the drilling of wells;
|
|
|
|
maintaining bonding requirements to drill or operate wells;
|
|
|
|
regulating the location of wells, the method of drilling and
casing wells, surface use and the restoration of properties upon
which wells are drilled; and
|
|
|
|
regulating the plugging and abandoning of wells and the
disposing of fluids used and produced in connection with
operations.
|
Our operations are also subject to various conservation laws and
regulations relating to well spacing and safety issues for gas
gathering systems.
Environmental
Regulations
We are subject to extensive federal, state and local
environmental laws and regulations that, among other things,
regulate the discharge or disposal of substances into the
environment and otherwise are intended to protect the
environment. Numerous governmental agencies issue rules and
regulations to implement and enforce such laws, which are often
difficult and costly to comply with and which carry substantial
administrative, civil
and/or
criminal penalties and, in some cases, injunctive relief for
failure to comply. Some laws and regulations relating to the
protection of the environment may, in certain circumstances,
impose strict liability for environmental
contamination. Other laws and regulations may impose
restrictions that prevent the rate of natural gas production
from being economically optimal or restrict or prohibit
exploration or production activities in environmentally
sensitive areas. In addition, state laws often require some form
of remedial action such as the closure of inactive pits and the
plugging of abandoned wells to prevent pollution from former or
suspended operations.
We believe that we are in substantial compliance with current
applicable laws and regulations and that continued compliance
with existing requirements will not have a material adverse
impact on us. However, from time to time, legislation or other
initiatives are proposed to place more onerous conditions on our
operations. Adoption of any such proposals could adversely
impact our operating costs, capital expenditures, earnings or
competitive position.
Our CBM operations require the hydraulic fracturing of coal
seams. We believe that this technique is in compliance with
applicable laws and regulations, but neither the Illinois
Department of Natural Resources Office of
Mines and Minerals nor the U.S. Environmental Protection
Agency regulates the hydraulic fracturing of coal bed formations
as a form of underground injection. It is possible that the
hydraulic fracturing of coal beds for CBM production will become
regulated within the United States as a form of underground
injection, resulting in the imposition of stricter performance
standards, which, if not met, could result in diminished
opportunities for CBM production enhancement and increased
administrative and operating costs.
In CBM production, naturally occurring groundwater is pumped to
the surface as a by-product. We currently dispose of water from
our wells through water flow lines that re-inject the water into
water disposal wells. Discharge of this water is subject to
federal and local regulation, and we are required to obtain
permits from the State of Illinois to re-inject the water that
our wells produce. We have received permits from the State of
Illinois that allow us to dispose of all the water that we
anticipate producing at both our Southern Illinois Basin Project
and Northern Illinois Basin Project during the fiscal year 2007.
As we drill additional wells in areas not currently serviced by
our existing water disposal wells, we believe that we will be
able to obtain the necessary permits for additional disposal
wells, although we can make no assurance in this regard. If the
water produced from our wells increases substantially
and/or the
water quality falls below acceptable standards, other disposal
or treatment methods may be required to be implemented.
11
Competition
We operate in the highly competitive natural gas market. We face
competition from other companies in each of the following areas:
|
|
|
|
|
acquiring CBM acreage rights;
|
|
|
|
selling our natural gas production;
|
|
|
|
identifying and employing new technologies; and
|
|
|
|
acquiring the equipment, expertise and personnel necessary to
develop and operate our properties.
|
Many of our competitors have financial, technological and other
resources that are greater than ours. These companies may be
able to pay more for CBM acreage rights and exploratory
prospects and may be able to evaluate and purchase more acreage
rights and prospects than our resources permit. To the extent
our competitors are able to pay more for properties,
technologies, equipment and qualified personnel than we are, we
will be at a competitive disadvantage. In addition, many of our
competitors may enjoy technological advantages and may be able
to identify, develop or implement new technologies more rapidly
than we can. Our ability to acquire additional acreage rights
and explore for CBM prospects in the future will depend upon our
ability to obtain the necessary equipment, attract and retain
and qualified personnel, successfully conduct operations,
implement advanced technologies, evaluate and select suitable
properties and consummate transactions in this competitive
environment.
Employees
As of July 31, 2006, we have 16 full-time employees,
including our executive officers. We utilize independent
consultants and contractors to perform various professional
services and for drilling, testing and completion work.
Executive
Officers and Directors
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
James G. Azlein
|
|
|
57
|
|
|
President, Chief Executive Officer
and Director
|
James E. Craddock
|
|
|
47
|
|
|
Senior Vice President of Operations
|
Dennis Carlton
|
|
|
56
|
|
|
Director
|
William J. Centa
|
|
|
54
|
|
|
Director
|
David E. Preng
|
|
|
60
|
|
|
Director
|
Costa Vrisakis
|
|
|
72
|
|
|
Director
|
James G. Azlein has been President, Chief Executive
Officer and a Director since August 23, 2001. From 1979 to
1998, Mr. Azlein held positions including President and
Chief Financial Officer and was a principal of Cyrus Eaton
Group (CEG), a private company that specialized in
project development, including securing technologies,
management, financing and marketing for a variety of projects,
for hotels and resorts, agricultural projects and manufacturing
plants. CEG concentrated on projects in conjunction with
government authorities in Eastern Europe, the former U.S.S.R.
and China. In 1998, Mr. Azlein and a partner acquired the
interests of CEG when its founder retired, and formed
International Resource Management, Inc., which continued project
development in India and Mexico through June 2001. In early
2000, Mr. Azlein formed Methane Management, Inc. to acquire
the interest of various partners in a 43,000 acre CBM
project in southern Illinois in which BPI owned a minority
interest. In August 2001, BPI acquired Methane Management, Inc.
and Mr. Azlein became President of BPI and began assembling
a new management team that refocused BPIs attention on CBM
development in the Illinois Basin, which started with the
43,000 acre project that is now referred to as the Southern
Illinois Basin Project.
James E. Craddock has been Senior Vice President of
Operations since April 2006. He oversees all of our operational
activities, including engineering, geology and land management
activities. In particular, he is integrally involved in planning
and managing all aspects of our CBM exploration, drilling and
production activities. Mr. Craddock joined us from
Houston-based Burlington Resources Inc. (acquired on
March 31, 2006 by ConocoPhillips), where he served as Chief
Engineer. In this, his most recent capacity with Burlington, he
was
12
responsible for reserve estimation, corporate operations,
recruitment and development of the engineering staff and growth
of a technical center. As Director of Strategic Planning at
Burlington, Mr. Craddock was involved in Burlingtons
$3 billion acquisition of the Louisiana Land &
Exploration Company (LL&E). He was also involved in
developing Burlingtons Farmington, New Mexico CBM project.
As head of Reservoir Engineering, and later as Engineering
Manager, he was responsible for leading the technical team that
grew the Fruitland CBM Project to over 400 MMcf per day. During
the plays peak level of activity, this required drilling
up to 300 new CBM wells per year, conducting up to 100
recompletions per year and participating in 100 non-operated
wells each year. He began his career in 1981 with Superior Oil
(later Mobil) upon graduating from Texas A&M University with
a Bachelor of Science in Mechanical Engineering.
Dennis Carlton has been a Director since May 2005.
Mr. Carlton has been involved in CBM since 1989. From 1995
through September 2004, he served as a director and worked in
several senior executive positions with Evergreen Resources,
Inc., serving most recently as Executive Vice President,
Exploration and Chief Operating Officer, as well as President of
Evergreen Operating Corp. His primary responsibilities included
management of all geoscience, engineering, land matters and
domestic and international business development activities.
Since October 2004, when Evergreen was acquired by Pioneer
Natural Resources, Inc., Mr. Carlton has served as a
technical and business advisor to Pioneers Western
Division. Prior to joining Evergreen Resources, he held
positions in several companies including Mobil Oil Corporation.
Mr. Carltons career and knowledge base in CBM spans a
vast geographic area including the Rocky Mountain Basins,
Mid-Continent, United Kingdom and Alaska. His efforts in the
Raton Basin with Evergreen were recognized when he was named the
Rocky Mountain Association of Geologists Outstanding
Explorer in 2000.
William J. Centa has been a Director since March 2005.
Mr. Centa has been actively involved in financial and
business management for more than 30 years. His career has
ranged from his role as president of middle-market manufacturing
and distribution companies to executive management of financial
firms. Since March 2004, he has served as Executive Vice
President and is one of the co-founders of Mayfran Holdings,
Inc., a multinational manufacturing and engineering company that
designs conveyor and filtration equipment used in the machine
tool industry. From October 2000 through March 2004,
Mr. Centa served as Chief Operating and Financial Officer
for iPower Logistics, a supply chain solutions and outsourcing
firm providing services to industrial companies in North
America. Mr. Centa remains a shareholder of both Mayfran
and iPower. From February 1998 until October 2000, he served as
Associate Director, Mergers & Acquisitions at the
accounting firm Ernst & Young LLP. Prior to holding
these positions, Mr. Centa served as Chief Operating
Officer for several international manufacturing and distribution
companies. Mr. Centa earned his MBA in 1977 from Cleveland
State University. He is a certified public accountant and has
been a member of the AICPAs Business & Industry
Executive Committee since 2002 and the Enhanced Business
Reporting Task Force since 2003.
David E. Preng has been a Director since February 2006.
Mr. Preng is the president of Preng & Associates,
an executive recruiting company he founded in 1980.
Preng & Associates focuses exclusively on matching
senior-level business executives seeking board of director,
chief executive and other upper-level assignments with energy
and natural resources companies in both the United States and
Europe. Mr. Preng, who has managed numerous global
engagements for a variety of multinational clients, coordinates
Preng & Associates worldwide practice and is
directly responsible for Russian, CIS and Far East recruiting in
North America. Prior to founding Preng & Associates, he
spent six years in the executive search industry. His industry
background includes financial, managerial and executive
positions with Shell Oil Company, Litton Industries and
Southwest Industries. Mr. Preng earned his Bachelor of
Science from Marquette University and his MBA from DePaul
University. Since 1997, he has been a director of Remington Oil
and Gas where, in addition to chairing its Nomination &
Governance Committee, he serves as lead independent director and
as a Compensation Committee member. During his tenure on
Remingtons board, Remington was acquired by Cal Dive
International, Inc. Mr. Preng also serves on the board of
directors of Maverick Oil & Gas, Inc., where he chairs
its Compensation Committee. He is a director of Community
National Bank as well as the Houston Chapter of the National
Association of Corporate Directors. Additionally, he is a fellow
of the Institute of Directors in London and has served three
terms as director and two years as president of the British
American Business Council.
Costa Vrisakis has been a Director since January 2002.
Mr. Vrisakis is a financier and entrepreneur based in
Sydney, Australia. He has been a founder and director of several
Sydney Stock Exchange-listed companies. One of
13
his former ventures includes a printing company, Snap-Apart Pty.
Ltd., which Mr. Vrisakis founded along with two employees
in 1959. In 1985, Snap-Apart Pty. Ltd. was listed on the Sydney
Stock Exchange under the name Computer Resources Ltd. In 1993,
Moore Corp. of Toronto, Canada acquired Computer Resources.
Since 1985, when Mr. Vrisakis sold his interest in Computer
Resources Ltd., he has focused his attention on various real
estate projects and stock market investments. Since 2000 through
the present time, Mr. Vrisakis has devoted the majority of
his time to managing his 50% interest in three hotels in Sydney,
Australia.
Significant
Employees
The following persons are not executive officers but make
significant contributions to our business:
Randy Elkins, 40, assumed the position of Acting Chief
Financial Officer in October 2006, and has been Controller since
February 2005. He is a CPA with more than 14 years of
experience in accounting and auditing. Prior to joining BPI,
Mr. Elkins held a senior finance position with
International Steel Group, Inc. (NYSE: ISG). From January 1992
through September 2004, he served in various increasingly
responsible positions with Ernst & Young LLP, most
recently as a senior manager in its Transaction Support Group.
While at E&Y, he focused on audits of SEC public companies,
mergers and acquisitions and bankruptcy restructurings.
Randy Oestreich, 49, has been Vice President of Field
Operations since March 2005. Mr. Oestreich owns A-Strike
Consulting, a private consulting company formed in April 2003 to
provide consulting services to the CBM industry. From 1976 to
2003, Mr. Oestreich worked for Halliburton Energy Services.
With Halliburton, Mr. Oestreich worked in conventional oil
and gas exploration and development, as well as unconventional
gas, including CBM, primarily in the Illinois Basin, but also in
Michigan, Ohio, Kentucky, Pennsylvania and West Virginia.
In addition, he was a member of Halliburtons Coalbed
Methane Solutions Team. For the past 10 years, his work has
focused on CBM, mine methane and New Albany shale exploration
and development. Mr. Oestreich has worked on, and is
familiar with, the majority of unconventional gas projects that
have been initiated in the Illinois Basin and has worked on the
Southern Illinois Basin Project since its inception.
Dan Anderson, 57, has been Director of Property
Acquisitions since January 2002. Mr. Anderson has over
25 years of oil and gas and real estate experience: from
1976 to 1983 as Land Department Manager with John Carey Oil
Company, Inc.; from 1983 to 1989 as president of his own oil and
gas investment consulting company, and as President of a private
real estate development company, DAPA Investments, Inc. Prior to
joining BPI, Mr. Anderson worked with DeMier Oil in
securing oil, gas and CBM leases in central and southern
Illinois, as well as pipeline
right-of-way
easements. He has extensive experience in the oil, gas and CBM
business in the Illinois Basin, including oil and gas and CBM
leasing terms and agreements. In addition, he has extensive
experience in the workings of land title and registrar offices
on both a local and state level. Mr. Anderson is a member
of the Illinois Oil and Gas Association and holds an Illinois
real estate broker license.
Michael Dawson, 56, has been Senior Geological Advisor
since August 2006. He was most recently with Burlington
Resources Inc. (recently acquired by ConocoPhillips) as a
petroleum geologist. During his
26-year
tenure with Burlington, he was involved in various exploration
and exploitation projects. At Burlingtons Farmington, New
Mexico office, he was involved in the Fruitland CBM play. Most
recently, Mr. Dawson helped design and implement a
comprehensive (San Juan Basin) Pictured Cliffs Sandstone
reservoir optimization program. Previously, he worked in
Burlingtons Amarillo and Houston offices where his
responsibilities included prospect generation, wellsite geology,
field development and economic analysis for projects in the
Anadarko, Arkoma and other basins. Mr. Dawson began his
career in 1978 with Conoco (later ConocoPhillips) upon
graduating with a Master of Science in Geology from San Diego
State University. He earned his Bachelor of Science in Geology
from the University of Michigan.
James Erlandson, 31, also formerly of Burlington
Resources, has been Senior Staff Reservoir Engineer since August
2006. Previously, he was team leader of the Kaybob Resource
Assessment Team working in Calgary, Alberta, with responsibility
for analyzing and developing regional unconventional gas plays
in British Columbia and Alberta. As Mr. Erlandson
progressed through assignments of increasing responsibility with
Burlington, he was involved in strategic planning, acquisitions
and exploitation of unconventional sand and CBM plays. He was
also involved in the addition of proven gas reserves in the
Western Canada Sedimentary Basin, infill program analysis and
development, and the optimization of Fruitland coal wells in the
San Juan Basin. Mr. Erlandson began his career
14
in 1997 as a production engineer with Marathon Oil Company after
graduating with honors from Montana Tech, where he earned his
Bachelor of Science in Petroleum Engineering.
Kelly Sutton, 29, has been Senior Staff Engineer since
September 2006. Ms. Sutton was previously with Energen
Resources, where she served as a reservoir/acquisitions
engineer. While at Energen, she evaluated CBM properties in the
Powder River, San Juan and Black Warrior Basins, oil properties
in the Permian Basin and tight gas properties in East Texas and
Northern Louisiana. Prior to Energen, she served in various
reservoir and production engineering positions with Burlington
Resources and Phillips Petroleum. Ms. Sutton received her
Bachelor of Science in Chemical Engineering from the University
of Alabama.
Bradford Sutton, 32, has been Senior Staff Engineer since
September 2006. Mr. Sutton was previously with Energen
Resources, where he focused on CBM and tight gas development in
the San Juan Basin. Prior to joining Energen, Mr. Sutton
was a production engineer at Burlington Resources. During his
career, he has worked on CBM development in the San Juan and
Powder River Basins and conventional gas and tertiary oil
development in the Permian Basin. He holds a Bachelor of Science
in Petroleum Engineering from the University of Alabama.
Internet
Website
We must file annual, quarterly and other reports and proxy
statements with the Securities and Exchange Commission
(SEC). Our SEC filings are available to the public
over the internet at the SECs website at www.sec.gov
or from our website at www.bpi-energy.com. You may
also read and copy any documents that we file at the SECs
public reference room located at 100 F Street, N.E., Washington,
D.C. 20549. Please call the SEC at
1-800-SEC-0330
for further information on the operations of the public
reference room. In addition, we make available free of charge
through our internet web site our annual report on
Form 10-K,
quarterly reports on
Form 10-Q
and current reports on
Form 8-K
filed or furnished pursuant to Section 13(a) or 15(d) of
the Securities Exchange Act of 1934 as soon as reasonably
practicable after we electronically file such material with, or
furnish it to, the SEC.
Additionally, charters for the committees of our Board of
Directors and our Code of Business Conduct and Ethics can be
found at our website under the heading Highlights on
the Corporate Governance page. Stockholders may
request copies of these documents by writing to the Investor
Relations Department at 30775 Bainbridge Road, Suite 280,
Solon, Ohio 44139.
You should be aware that the occurrence of any of the events
described in this Risk Factors section and elsewhere in this
annual report could have a material adverse effect on our
business, financial position, results of operations and cash
flows. In evaluating us, you should consider carefully, among
other things, the factors and specific risks set forth below,
and in documents we incorporate by reference. This annual report
contains forward-looking statements that involve risks and
uncertainties.
Risk
Factors Relating to Our Business
Our
current revenues are minimal and not sufficient to support our
operations. If we are unable to raise additional financing, we
may not be able to carry out our long-term plans.
The wells that we have drilled began producing CBM for sale only
in January 2005, and the amount of CBM that we are currently
selling is not significant. We are not currently generating net
income or positive cash flow from operations. Even if we achieve
increased revenues and positive cash flow from operations in the
future, we anticipate increased exploration, development and
other capital expenditures as we continue to explore and develop
our CBM rights. Therefore, in order to achieve our long-term
plans and maintain a viable business, we will need to raise
additional financing. If we are unable to raise additional
financing, we will likely be unable to carry out our long-term
plans, which would negatively impact the value of your
investment in us.
Even if we continue to demonstrate the commercial viability of
CBM wells in the Illinois Basin, we may encounter difficulty in
raising additional capital on favorable terms. Interest rates
and investor expectations and demands are subject to change, and
any change in these areas could have a negative effect on the
financing terms
15
that we are able to obtain. In addition, the terms of any new
financing may adversely affect your investment. If we issue
shares of preferred stock or additional common shares,
institutional investors may negotiate terms equal to or more
favorable than market prices or the terms of our prior
offerings, resulting in dilution to existing shareholders. Debt
financing could result in the lenders having a claim to assets
prior to the rights of our shareholders, divert cash flow to
service the debt, and restrict operations through compliance
with lenders restrictions. Any such terms could adversely
affect the return that you receive on your investment in us.
We
have incurred significant operating losses since our inception
and may not achieve profitability in the future.
We have experienced significant operating losses and negative
cash flow from operations since our inception, and we currently
have an accumulated deficit. During our fiscal year ended
July 31, 2005 we incurred a net loss of $5,396,351, and
during our fiscal year ended July 31, 2006 we incurred a
net loss of $8,836,245. As of July 31, 2006, we have an
accumulated deficit of $27,193,528. We anticipate that our
operating costs and capital expenditures will continue to grow
as we continue to explore and develop our CBM rights. Even if we
significantly grow our revenues from the sale of CBM, it is
possible that our increased operating costs and capital
expenditures will prevent us from generating net income. In
addition, in the future we could incur greater than expected
drilling or other operating expenses, we could discover that our
properties are not commercially viable, or gas prices could
decline significantly. Any of these events would have a
significantly negative impact on our ability to generate net
income. If we are unable to achieve profitability at any time in
the near future, the value of your investment in us could be
adversely affected.
CBM
exploration is speculative in nature and may not result in
operating revenues or profits.
The Illinois Basin is largely untested for commercial CBM
production. In addition, we have evaluated the CBM potential in
only a relatively small part of our acreage rights. Only an
extended production history of the wells that we drill will
indicate whether our wells will be commercially productive over
the long-term. We could determine in the future that the
Illinois Basin does not contain enough CBM for commercially
viable operations, or that the conditions in the Illinois Basin
are not conducive for commercially viable operations. Any such
determination would have a significantly negative effect on your
investment in us.
Future wells that we drill may not be successful, due to low CBM
content in the coal, low permeability, unusually low or high
water quantities, low water quality, incorrect forecasts or
other factors. We cannot be sure that completed wells will
produce enough CBM to recover our capital investments. We can
provide no assurance that the exploration and development of our
projects will occur as scheduled, or that actual results will be
in line with expectations.
The cost of drilling, completing and operating wells is often
uncertain. Factors that can delay or prevent drilling
operations, include:
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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shortages or delays in the availability of drilling rigs or the
delivery of equipment;
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the inability to hire personnel or engage other third parties
for drilling and completion services;
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the inability to obtain regulatory approvals to drill CBM wells
where planned;
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litigation initiated by surface owners attempting to prevent us
from utilizing the surface land for our operations; and
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the inability to sell CBM production, due to the loss of access
to the pipelines into which CBM production is sold or an
oversupply of natural gas in the market.
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16
Wells on some projects could require substantial dewatering
ahead of production, which could delay the start of production
by months and increase completion costs. Continued high volume
water pumping during production would increase operating costs.
If we experience significant setbacks in drilling, completing
and operating wells, or significantly increased costs due to
unexpected conditions, our financial performance will suffer.
We
could experience delays in securing drilling equipment and
crews, which would cause us to fail to meet our drilling plans
and negatively impact our operations.
We utilize drilling contractors to perform all of the drilling
on our projects. We maintain a limited number of supervisory and
field personnel to oversee drilling and production operations.
Our plans to drill additional wells are determined in large part
by the anticipated availability of acceptable drilling equipment
and crews. We do not currently have any contractual commitments
that ensure we will have adequate drilling equipment or crews to
achieve our drilling plans. If our anticipated levels of
drilling equipment are not made available to us, we will have to
modify our drilling plans, which would cause us to fail to meet
our drilling plan and negatively impact our operations. If we
cannot meet our drilling plans, the value of your investment in
us may decline.
We
could lose significant portions of our CBM acreage rights if we
do not place into production a sufficient number of CBM
wells.
The primary terms of the lease and farmout agreements pursuant
to which we hold, or upon the exercise of options will hold,
most of our CBM acreage rights will expire between November 2007
and April 2026, after which we will continue to hold our acreage
rights only to the extent that we are producing CBM from the
covered acreage. Under some of these leases we will retain only
limited acreage rights for each CBM well that we place into
production.
We
could encounter strong competition for properties in the
Illinois Basin.
The natural gas industry is highly competitive. We currently
hold substantial CBM acreage rights in the Illinois Basin, but
other companies may become active in the area. New entrants
could have greater financial and technological resources, which
might enable them to outbid us on new acreage or obtain
leaseholds, option agreements or farm-out agreements for which
we currently have agreements in place when our rights expire or
lapse. Any loss of acreage would negatively impact the potential
scope of our operations, which would likely have a negative
impact on the value of your investment in us.
Because
approximately 74% of our CBM acreage rights are inferior to coal
mining rights covering the same properties, our affected
operations could be displaced by coal mining operations, which
would negatively impact our operations.
Under the agreements pursuant to which we hold approximately 74%
of our CBM acreage rights, our right to drill for and produce
CBM is expressly subject to the mining of coal on the acreage
covered by the agreement. We may not interfere with any existing
coal mining operations and, under certain circumstances, may be
required to cease drilling in locations where coal mining
operations will be undertaken. These superior coal rights may
restrict the locations where we can drill CBM wells on our
projects and may cause some of our CBM operations to be
displaced by coal operations. Any such displacement could cover
a significant portion of our CBM acreage rights. If we face
significant restrictions on where we can drill our CBM wells or
a significant number of our CBM wells are displaced by coal
mining operations, our operations and financial performance will
be negatively impacted.
The
CBM rights that we have acquired under lease and option
agreements are subject to a number of uncertainties, which, when
resolved, could cause us to lose some of our CBM
rights.
Under the terms of the lease and option agreements pursuant to
which we have acquired most of our CBM rights, we are entitled
to all of the CBM rights held by our lessors in the counties
covered by these agreements. However, we face a number of
uncertainties regarding what rights our lessors hold.
The issue of who owns CBM gas, as between the coal rights owner
and the oil and gas rights owner, is uncertain in Illinois.
Although the appellate court in Illinois for the district where
most of our acreage rights are situated has
17
ruled that CBM gas is owned by the coal rights owner, the issue
has not been addressed by the highest court in Illinois. We
believe, based on advice from legal counsel, that under Illinois
law ownership will ultimately be found to lie with the coal
rights owner. Based on this advice, we generally secure CBM
rights from the coal owners. Some of the lessors from which we
have acquired CBM rights may hold both the coal rights and the
oil and gas rights for the applicable properties, but in some
cases it is not certain that these lessors also hold the oil and
gas rights. If any litigation in Illinois concludes that CBM
rights lie with the oil and gas owner, we could lose some of our
CBM rights.
In addition, in some cases the extent of the coal
and/or oil
and gas rights held by our lessors is uncertain. We conducted no
title or deed examinations prior to executing our lease and
option agreements, and our lessors made no warranties as to the
acreage or rights covered by the agreements. Although we have
now conducted title and deed examinations covering much of the
CBM properties under our leases, these examinations are ongoing
at all of our projects. There can be no assurance that our
rights under our lease and option agreements include all of the
acreage and rights identified in the agreements until title
examinations on all of the underlying properties have been
completed.
If any of these uncertainties is resolved unfavorably to us, we
could lose some of our CBM acreage rights. Any loss of our CBM
acreage rights would negatively impact our growth potential,
which could cause the value of your investment in us to decline.
We
could incur significant costs in connection with disputes over
surface rights, which would have a negative impact on our
financial performance.
We have been subject to legal complaints regarding the extent of
the surface rights that derive from our CBM rights. On occasion,
the owners of properties that are adjacent to our drilling
locations have challenged our right to cross their property in
accessing our drilling locations and our right to lay gas and
water flow lines across their property. The extent of our rights
in respect of these issues is uncertain in Illinois. If disputes
regarding our surface rights are not resolved in our favor, we
may be required to acquire surface rights or access our drilling
locations and lay gas and water flow lines in inefficient ways,
which would cause us to incur increased operating costs. In
addition, we could incur significant costs in legal disputes
over our surface rights. During our fiscal year ended
July 31, 2005 we incurred approximately $303,000 in legal
fees in connection with legal disputes over surface rights, and
during our fiscal year ended July 31, 2006 we incurred
approximately $10,000 in legal fees in connection with such
disputes. If for any reason these operating or legal costs
increase significantly, our financial performance will suffer.
We
could incur substantial costs to comply with environmental
regulations, and our failure to comply with environmental
regulations could result in significant fines
and/or
penalties, either of which could adversely affect our
operations.
Our operations are subject to federal, state and local
environmental laws and regulations. Although we believe that our
operations to date have been conducted in compliance with these
regulations, new more restrictive laws or regulations could be
adopted, which could force us to expend significant resources to
comply with the new requirements. Because CBM exploration is
relatively new in the Illinois Basin, the governmental agencies
that regulate us, including the Illinois Department of Natural
Resources Office of Mines and Minerals, may determine that
new laws and regulations are required to govern the growing
industry. CBM operations are technologically different from
conventional oil and gas operations, and these agencies may
determine that existing regulations, which are generally focused
on the oil and gas industry, are not sufficient for CBM
operations. As CBM activity increases in the Illinois Basin,
unexpected regulatory issues may develop, which could impose
additional compliance costs on us. Any significant increase in
compliance costs could have a negative impact on our results of
operations and could prevent our properties from being
commercially viable.
18
The
occurrence of a significant adverse event that is not covered by
insurance could have a material adverse effect on our financial
condition.
The exploration for and development and production of CBM
involves a variety of operating risks, including the possibility
of fire, explosion and blow-out from abnormal formation
pressure. It is not always possible to fully insure against such
risks. An uninsured or underinsured loss could adversely impact
our financial condition.
Our
ability to attain profitable operations could be negatively
impacted by any decline in natural gas prices.
Our ability to grow our revenues, and ultimately attain
profitable operations, will depend not only on our ability to
place CBM wells into production but on the market for natural
gas. Natural gas prices have historically been volatile, and
they are likely to continue to be volatile in the future. If
natural gas prices decline significantly for extended periods of
time, the CBM wells that we place into production may not be
commercially viable and we might not be able to generate enough
revenues to reach profitable operations. Our failure to reach
profitable operations will negatively affect the value of your
investment in us.
We
will incur increased costs as a result of registering in the
United States.
In December 2005, we became subject to the reporting
requirements of the Securities Exchange Act of 1934. As an SEC
registrant, we will incur significant legal, accounting and
other expenses that we did not incur as a Canadian public
company. We will incur costs associated with complying with the
rules and regulations of the SEC, including those adopted under
the Sarbanes-Oxley Act of 2002. We currently estimate that these
costs will total approximately $1.0 million on an annual
basis. In addition, we will continue to be subject to the
securities laws and reporting requirements of the British
Columbia Securities Commission and the Alberta Securities
Commission. These dual reporting obligations will result in
increased compliance costs, which could adversely affect our
financial performance.
In addition, being subject to SEC regulation and the
Sarbanes-Oxley Act may make it more expensive for us to obtain
director and officer liability insurance, and we may be required
to accept reduced policy limits and coverage or incur
substantially higher costs to obtain the same or similar
coverage. As a result, it may be more difficult for us to
attract and retain qualified individuals to serve on our board
of directors or as executive officers.
There
is not a substantial amount of trading in our common shares,
which could prevent you from selling your common shares at
acceptable prices or at all.
Our common shares are currently traded on the American Stock
Exchange. There is not a substantial amount of trading in our
common shares on the American Stock Exchange. We are not certain
that a more active trading market in the stock will develop, or
that it will be sustained if it does develop. Because the market
for our common shares is limited and is likely to remain limited
in the near future, you may not be able to sell your common
shares at acceptable prices or at all.
The American Stock Exchange has adopted standards under which it
will normally give consideration to removing a security from
listing. However, the standards in no way limit the Exchange and
it may at any time, in view of the circumstances in each case,
remove a security from listing when in its opinion such security
is unsuitable for continued trading on the Exchange. These
standards include, but are not limited to, consideration of:
(i) a companys financial condition
and/or
operating results; (ii) whether the company has sold or
otherwise disposed of its principal operating assets, ceased to
be an operating company or discontinued a substantial portion of
its operations; and (iii) whether a companys common
stock sells for a substantial period of time at a low price per
share. It is possible that the Exchange could make a
determination in the future that our stock is unsuitable for
continued trading on the Exchange. If our stock is delisted from
the Exchange, it will likely be difficult to effect sales of our
stock.
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ITEM 1B.
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Unresolved
Staff Comments.
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None.
19
Our corporate headquarters is located in a leased office in
Solon, Ohio. Our operations are conducted from an office located
in a leased facility in Edwardsville, Illinois. For information
about our CBM acreage rights, production and gas reserves, see
the section of this report entitled CBM Acreage
Rights.
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ITEM 3.
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Legal
Proceedings.
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On June 23, 2006, our wholly owned subsidiary BPI Energy,
Inc. entered into a Settlement and Mutual Release Agreement with
Colt LLC (Colt), AFC Coal Properties, Inc.
(AFC), American Premier Underwriters, Inc.
(APU) and Central States Coal Reserves of Illinois,
LLC (Central States). These parties were defendants
in a lawsuit filed by BPI Energy, Inc. on March 15, 2006
relating to our Southern Illinois Basin Project.
The Settlement and Mutual Release Agreement provides that all
parties to the lawsuit will release all of the other parties
from any claims they may have had against each other. In
addition, as conditions precedent to the settlement of claims,
BPI Energy, Inc. (i) paid Colt $3,000,000;
(ii) acknowledged that the Oil, Gas and Coalbed Methane Gas
Lease dated April 3, 2001, as amended (the
Lease), had lapsed and surrendered any interest it
had in the Lease; and (iii) received a quitclaim deed from
Colt with respect to the CBM estate covering a 10,000 acre
portion of the 43,000 acres previously covered by the Lease.
Contemporaneously with the execution of the Settlement and
Mutual Release Agreement, BPI Energy, Inc. entered into a
Purchase and Sale Agreement with Colt pursuant to which it
acquired ownership of the CBM estate covering approximately
10,000 of the 43,000 acres previously covered by the Lease.
This acreage includes all of the currently producing CBM wells
and proved reserves at our Southern Illinois Basin Project. The
quitclaim deed executed by Colt provides that CBM operations
take priority over coal mining operations for as long as CBM is
being produced from the covered acreage. However, Colt has the
right to acquire any CBM wells located in these 10,000 acres. If
Colt exercises this option, it will be required to (i) to
immediately plug any such well so acquired and (ii) pay the
fair market value (as established by a mutually agreed upon
expert) of such well.
As an additional condition precedent to the execution of the
Settlement and Mutual Release Agreement, on June 23, 2006,
the parties entered into a Termination Agreement with Colt, AFC,
APU and Central States (collectively with BPI Energy, Inc., the
Parties). This Termination Agreement acknowledged
the termination and lapse of the Lease. All of the Parties
agreed to discharge and release each of the other Parties from
any and all obligations under the Lease.
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ITEM 4.
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Submission
of Matters to a Vote of Security Holders.
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There were no matters submitted to a shareholder vote during the
fourth quarter of 2006.
PART II
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ITEM 5.
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Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchase of Equity Securities.
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Our common shares are currently traded on the American Stock
Exchange under the symbol BPG. Prior to
December 13, 2005, our common shares were traded on the TSX
Venture Exchange in Vancouver, British Columbia under the symbol
BPR. The following table sets forth the high and low
sales prices per share, in U.S. dollars, as reported by the
American Stock Exchange or the TSX Venture Exchange, during each
of our quarterly periods
20
ending in our 2005 and 2006 fiscal years. Prices reported on the
TSX Venture Exchange in Canadian dollars have been converted to
U.S. dollars based on exchange rates in effect on the
applicable date.
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High
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Low
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Fiscal Year Ended July 31,
2005
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Quarter ended October 31, 2004
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$
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0.98
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$
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0.57
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Quarter ended January 31, 2005
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2.05
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0.78
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Quarter ended April 30, 2005
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2.02
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1.31
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Quarter ended July 31, 2005
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1.96
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1.37
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Fiscal Year Ended July 31,
2006
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Quarter ended October 31, 2005
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$
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2.25
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$
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1.37
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Quarter ended January 31, 2006
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4.00
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1.92
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Quarter ended April 30, 2006
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3.55
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1.20
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Quarter ended July 31, 2006
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1.60
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1.03
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As of October 25, 2006, we have 71,872,540 common shares
outstanding, which are held by approximately
840 shareholders of record. The transfer agent and
registrar for our common shares is Pacific Corporate Trust,
Vancouver, British Columbia. In addition to our outstanding
common shares, as of October 25, 2006, we have reserved
1,823,265 common shares for issuance upon the exercise of
outstanding stock options and 5,311,600 common shares for
issuance upon the exercise of outstanding warrants.
In fiscal year 2006, we issued the following unregistered
securities. Except for the September 26, 2005 issuance,
when KeyBanc Capital Markets, a division of McDonald
Investments, Inc., and Sanders Morris Harris, Inc. acted as
placement agents, we did not use a principal underwriter for any
of the issuances listed in the table below. Each such sale was
exempt from registration under the Securities Act of 1933 in
reliance on Section 4(2) of the Securities Act
and/or
regulations issued thereunder as sales to qualified purchasers
not involving a public offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Offering
|
|
Date of sale
|
|
Title and Amount of Securities Sold
|
|
Offering Price
|
|
|
Price
|
|
|
9/26/05
|
|
18,000,000 common shares(1)
|
|
|
USD$1.69
|
|
|
|
USD$30,500,000
|
|
8/1/05 through 7/31/06
|
|
911,600 common shares(2)
|
|
|
USD$1.50
|
|
|
|
USD$1,367,400
|
|
8/1/05 through 7/31/06
|
|
975,000 common shares(3)
|
|
|
CAD$0.80
|
|
|
|
CAD$780,000
|
|
8/1/05 through 7/31/06
|
|
634,375 common shares(4)
|
|
|
CAD$0.80
|
|
|
|
CAD$507,500
|
|
8/1/05 through 7/31/06
|
|
396,667 common shares(5)
|
|
|
USD$0.97
|
|
|
|
USD$384,767
|
|
|
|
|
(1) |
|
These common shares were issued by us in a private placement
that closed on September 26, 2005. KeyBanc Capital Markets,
a division of McDonald Investments, Inc., and Sanders Morris
Harris, Inc. acted as placement agents. The placement agents
received commissions totaling $2,538,784 in connection with this
sale of securities. |
|
(2) |
|
These sales relate to the exercise of warrants issued in
conjunction with a private placement of common shares during the
period December 30, 2004 to January 13, 2005. |
|
(3) |
|
These sales relate to the exercise of warrants issued in
conjunction with a private placement of common shares on
December 10, 2003. |
|
(4) |
|
These sales relate to the exercise of warrants issued in
conjunction with a private placement of common shares on
September 18, 2003. |
|
(5) |
|
These shares were sold pursuant to the exercise of options
issued to individuals eligible to participate in our Incentive
Stock Option Plan, which has been superseded by our 2005 Omnibus
Stock Plan. The offering price is a weighted average exercise
price expressed in U.S. Dollars based on the applicable
exchange rate at the time of exercise. |
21
Dividend
Policy
We have not paid any cash dividends to date, and currently have
no intention of paying any cash dividends on our common shares
in the foreseeable future. The declaration and payment of
dividends is subject to the discretion of our Board of
Directors. The timing, amount and form of dividends, if any,
will depend on our results of operations, financial condition
and cash requirements.
Equity
Compensation Plan Information
The following reflects certain information about our common
shares authorized for issuance under compensation plans at
July 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
Number of
|
|
|
|
|
|
Securities Remaining
|
|
|
|
Securities to be Issued
|
|
|
Weighted-Average
|
|
|
Available for Future
|
|
|
|
Upon Exercise of
|
|
|
Exercise Price of
|
|
|
Issuance Under
|
|
|
|
Outstanding Options,
|
|
|
Outstanding Options,
|
|
|
Equity Compensation
|
|
Plan Category
|
|
Warrants and Rights
|
|
|
Warrants and Rights
|
|
|
Plans
|
|
|
Equity compensation plans approved
by shareholders
|
|
|
1,823,265
|
(1)
|
|
$
|
1.17
|
|
|
|
2,835,000
|
(2)
|
Equity compensation plans not
approved by shareholders
|
|
|
1,037,200
|
(3)
|
|
$
|
1.25
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,860,465
|
|
|
|
N/A
|
|
|
|
2,835,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the number of common shares underlying options that
were issued under our Incentive Stock Option Plan, which has
been superseded by our 2005 Omnibus Stock Plan. |
|
(2) |
|
Represents the number of common shares remaining available for
issuance under our 2005 Omnibus Stock Plan, which was approved
by our shareholders at our annual meeting held on
December 13, 2005. As of July 31, 2006, we have issued
2,165,000 restricted common shares and no options under our 2005
Omnibus Stock Plan. |
|
(3) |
|
Represents the number of common shares underlying warrants
granted to Sanders Morris Harris, Inc. as compensation for
serving as placement agent for our December 2005/January 2006
private placement. |
22
|
|
ITEM 6.
|
Selected
Financial Data.
|
The following sets forth our selected historical financial data
as of July 31, 2006, 2005, 2004, 2003 and 2002 and for our
five fiscal years then ended, which has been derived from our
financial statements for those years. Our financial statements
as of July 31, 2006 and 2005 and for our fiscal years ended
July 31, 2006 and 2005 and related notes thereto have been
audited by Meaden & Moore, Ltd., an independent
registered public accounting firm. Our financial statements as
of July 31, 2004, 2003 and 2002 and for our fiscal years
ended July 31, 2004, 2003 and 2002 and related notes
thereto have been audited by De Visser Gray, an independent
registered public accounting firm.
This information should be read together with the section of
this report entitled Managements Discussion and
Analysis of Financial Condition and Results of Operations
and our consolidated financial statements and related notes
included elsewhere in this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended July 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales(1)
|
|
$
|
1,126,477
|
|
|
$
|
117,835
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Stock-based compensation expense
|
|
|
1,377,440
|
|
|
|
3,344,738
|
|
|
|
193,796
|
|
|
|
515,286
|
|
|
|
439,860
|
|
Loss before income taxes
|
|
|
(8,836,245
|
)
|
|
|
(6,120,821
|
)
|
|
|
(1,091,227
|
)
|
|
|
(1,109,218
|
)
|
|
|
(1,245,853
|
)
|
Net loss
|
|
|
(8,836,245
|
)
|
|
|
(5,396,351
|
)
|
|
|
(793,116
|
)
|
|
|
(934,305
|
)
|
|
|
(1,129,209
|
)
|
Net loss per common share
|
|
|
(0.14
|
)
|
|
|
(0.14
|
)
|
|
|
(0.03
|
)
|
|
|
(0.04
|
)
|
|
|
(0.06
|
)
|
Weighted average number of shares
outstanding
|
|
|
62,789,319
|
|
|
|
37,665,019
|
|
|
|
25,007,237
|
|
|
|
21,485,381
|
|
|
|
18,300,433
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of July 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
49,051,980
|
|
|
$
|
23,527,712
|
|
|
$
|
9,382,977
|
|
|
$
|
6,328,178
|
|
|
$
|
5,418,158
|
|
Long-term notes payable (including
current maturities)
|
|
|
216,015
|
|
|
|
549,822
|
|
|
|
462,177
|
|
|
|
378,174
|
|
|
|
|
|
Cash dividends per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gas sales commenced in January 2005. |
23
|
|
ITEM 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
The following Managements Discussion and Analysis
(MD&A) is intended to help the reader understand
our business, financial condition, results of operations,
liquidity and capital resources. MD&A is provided as a
supplement to, and should be read in conjunction with, the other
sections of this report and our consolidated financial
statements and related notes. Our MD&A includes the
following sections:
|
|
|
|
|
Overview and Outlook a general description of
our business; drilling plans and capital expenditures; key areas
of management focus; measurements; and opportunities, challenges
and risks.
|
|
|
|
Critical Accounting Policies a discussion of
accounting policies that require critical judgments and
estimates.
|
|
|
|
Results of Operations an analysis of our
consolidated results of operations for the three years presented
in our financial statements.
|
|
|
|
Liquidity and Capital Resources an analysis
of our cash flows, sources and uses of cash, contractual
obligations and commercial commitments.
|
Overview
and Outlook
We are an independent energy company incorporated under the laws
of British Columbia, Canada and primarily engaged, through our
wholly owned U.S. subsidiary, BPI Energy, Inc., in the
exploration, production and commercial sale of coalbed methane
(CBM). Our exploration and production efforts are
concentrated in the Illinois Basin (the Basin). Our
Canadian activities are limited to administrative reporting
obligations to the province of British Columbia and regulatory
reporting to the British Columbia Securities Commission.
As of July 31, 2006, we owned or controlled CBM rights,
through mineral leases, options to acquire mineral leases, a
farm-out agreement and ownership of a CBM estate, covering
approximately 500,000 total acres in the Basin (a substantial
majority of which was undeveloped as of July 31, 2006). We
are focused on 12 Pennsylvanian coal seams that we regard as
having commercial CBM potential. The seams in the acreage
covered by our CBM rights have an aggregate thickness of
11-27 feet with a 19-foot median. We plan to complete
several individual seams per well that range from two to nine
feet thick each. Gas desorption tests of these coals have
yielded
13-113 scf/ton
with a 63 scf/ton median. Extensive permeability testing of
individual seams (before stimulation) indicates a range of
0.2-75 millidarcies and median of 4 millidarcies.
The state of Illinois (which includes most of the Basin) is
estimated to be the number two state in the U.S. in terms
of coal reserves; however, coal in the Basin is high in sulfur,
discouraging coal mining operations. Recent advances in
technology that can reduce the sulfur content of the coal and
higher coal prices are combining to make coals in the Basin
potentially attractive to mining operations. Although coal
mining activities take priority over CBM operations in most of
our acreage, we attempt to coordinate and plan our drilling and
production activities in conjunction with the owners of the coal
in order to minimize any potential disruptions. In addition,
because of the long lead times involved in coal mining projects,
our substantial acreage position, and our ability to be flexible
with the timing and siting of our wells, we believe we can plan
our work around coal mining operations in the vicinity of our
projects.
We have been involved in the first two projects in the Basin
that have commercially produced and sold CBM. We are the only
company currently commercially producing and selling CBM in the
state of Illinois and one of only two companies currently
commercially producing and selling CBM in the Illinois Basin. We
believe our position as the first mover has enabled us to secure
a substantial and favorable acreage position at costs that we
believe compare very favorably to other CBM basins that are more
mature in terms of production history.
We are an early stage CBM exploration and production company. We
commenced CBM sales from our first producing wells in January
2005. Gas sales during the fiscal year ended July 31, 2005
were $117,835. Gas sales were $1,126,477 for the fiscal year
ended July 31, 2006, an increase of 856%. From early 2002
until 2005, our strategic focus was on building our acreage
footprint in the Basin. We were built around the primary
strategic objective of acquiring CBM rights in the Basin. As we
began accumulating CBM rights we began testing our acreage to
determine its CBM potential. Having accumulated CBM rights to
approximately 500,000 acres in the
24
Basin and conducting extensive testing at our Southern Illinois
Basin Project, we embarked (in late 2004) on a pilot
production program at our Southern Illinois Basin Project.
Encouraged by the results, we expanded our drilling and
production activities and began installing the infrastructure
necessary to enable us to begin sales of CBM at our Southern
Illinois Basin Project.
As our drilling and production operations have grown, we have
not abandoned our goal of adding additional acreage and mineral
rights. However, we have committed ourselves to transitioning
BPI from a company focused primarily on the acquisition of
mineral rights to a company focused on expanding our drilling
and production operations and growing our reserves. To
accomplish this transition, we recognized that we needed to
obtain additional capital, resources and technical expertise. We
believe that we have made substantial progress in achieving
these goals. In September 2005, we sold 18,000,000 common shares
and raised approximately $28,000,000. In April 2006, we hired
Jim Craddock as our Senior Vice President of Operations. Jim was
with Burlington Resources for over 20 years, last serving
as Chief Engineer. Jim immediately began building an in-house
technical team by bringing in a geologist and three engineers,
all with extensive experience in successful CBM projects in
basins located in the United States and Canada. Our new
technical team has over 130 years of experience in CBM
exploration and development that they bring to BPI.
In April 2006, we initiated our second development front when we
began drilling 10 pilot development wells in Shelby County at
our Northern Illinois Basin Project. Our CBM rights in the
Northern Illinois Basin Project cover 351,487 acres in
Montgomery, Shelby, Christian, Fayette and Macoupin counties in
Illinois, which are located in the north central part of the
Basin. We believe that there are 12 prospective coal seams thick
enough for commercial production at this project. The thickest
seam, the Herrin Coal seam, is up to nine feet thick and has
been mined in shallow parts of the Basin. We believe that a
single thick seam such as this may offer an attractive target
for horizontal drilling.
We are not currently generating net income or positive cash flow
from operations. Although we capitalize exploration and
development costs, we have historically experienced significant
losses. The primary costs that generated these losses were
compensation-related expenses and general and administrative
expenses. Even if we achieve increased revenues and positive
cash flow from operations in the future, we anticipate increased
exploration, development and other capital expenditures as we
continue to explore and develop our mineral rights.
We anticipate that the number of wells we drill during the
fiscal year ending July 31, 2007 will be dependent to a
significant degree on the data we obtain from our recently
completed
10-well
pilot program at our Northern Illinois Basin Project
(Northern Project) as well as data obtained from
five test wells we have recently drilled on other leases in our
Western Illinois Basin Project (Western Project) and
Northern Project. Our capital expenditure budget for our 2007
fiscal year is a range that totals $12.0 million to
$30.0 million. These amounts correspond to drilling
58 wells at the low end of the range and 123 wells at
the upper end. These amounts include installing a gathering
system and processing yard to handle the anticipated production
from the
10-well
pilot program at our Northern Project and additional pilot wells
and/or
production wells at our three current projects. Our cash balance
at July 31, 2006 of $19,279,015 is insufficient to fully
fund the high end of the range of forecasted capital
expenditures and net cash used by operating activities during
our 2007 fiscal year or our operations beyond that date.
Therefore, we will likely need to raise additional financing in
the near future. We currently do not have any specific plans to
raise financing in support of our operations. Although
management has no specific plans in place to raise the
additional capital necessary to fund our plan of operations and
forecasted capital expenditures, management anticipates raising
the additional required capital through a combination of
additional stock sales, the issuance of debt securities,
borrowing
and/or
entering into joint ventures. Managements focus for fiscal
year 2007 will be to:
|
|
|
|
|
obtain test data and initiate pilot projects that demonstrate
the commercial potential of CBM at our various acreage blocks
and projects in the Illinois Basin;
|
|
|
|
reduce well drilling and completion costs;
|
|
|
|
increase total company reserves; and
|
|
|
|
grow total production.
|
25
Gathering test data and siting pilot projects based on this data
should lead to proving project viability in multiple areas in
the Illinois Basin. These pilot projects should have the
potential to grow into development projects that will increase
total company reserves and production. As we drill new wells,
our production should continue to increase, as the new wells
come online and our existing wells continue to dewater. As our
production increases in the future, we should be positioned to
generate positive cash flow from our operations.
A thorough evaluation of the geological assets that we control
should lead to the evaluation and implementation of more cost
effective drilling and completion techniques that can be
implemented to reduce overall costs, increase resource recovery
and total reserves and improve internal rates of return from
development projects.
We currently control approximately 500,000 acres of CBM
rights and, assuming 80-acre vertical well spacing and the
development of all of our acreage, have the possibility of up to
6,000 drilling locations. With our potential for drilling
locations, we expect that our drilling activities will be taking
place over many years. The type of test data we are interested
in developing across all of our projects includes measurements
of permeability, gas content and net pay (i.e., thickness of
coal seams from which we believe CBM can be commercially
produced). Our focus is to increase our technical and
operational knowledge of the Illinois Basin and our acreage
rights to assist us in (i) establishing the value of our
CBM assets and (ii) optimizing the production we can obtain
from our wells after we bring them online. The technical team we
have assembled has extensive experience and expertise in all of
these areas as well as implementation of large scale development
of CBM projects.
Several factors, over which we have little or no control, could
impact our future economic success. These factors include
natural gas prices, limitations imposed by the terms and
conditions of our lease agreements, possible court rulings
concerning our property interests in CBM, availability of
drilling rigs, operating costs, and environmental and other
regulatory matters. In our planning process, we have attempted
to address these issues by:
|
|
|
|
|
negotiating to obtain leases that grant us the broadest possible
rights to CBM for any given tract of land;
|
|
|
|
conducting ongoing title reviews of existing mineral interests;
|
|
|
|
where possible, negotiating and utilizing multiple service
companies in order to increase competition and minimize the risk
of disruptions caused by the loss of any one service
provider; and
|
|
|
|
attempting to create a low cost structure in order to reduce our
vulnerability to many of these factors.
|
Critical
Accounting Policies
Critical
Accounting Policies and Estimates
Our consolidated financial statements and accompanying notes
have been prepared in accordance with accounting principles
generally accepted in the United States. The preparation of
these financial statements requires our management to make
estimates, judgments and assumptions that affect reported
amounts of assets, liabilities, revenues and expenses. On an
ongoing basis, we evaluate the accounting policies and estimates
that we use to prepare financial statements. We base our
estimates on historical experience and assumptions believed to
be reasonable under current facts and circumstances. Actual
amounts and results could differ from these estimates used by
management.
Certain accounting policies that require significant management
estimates and are deemed a critical component of our results of
operations or financial position are discussed below. Our
management reviews our critical accounting policies with the
Audit Committee of our Board of Directors.
Accounting
for CBM Projects
We follow the full cost method of accounting for our CBM
properties. Under this method, all costs associated with the
acquisition of, exploration for and development of our CBM
reserves are capitalized in cost centers on a
country-by-country
basis (currently we have one cost center, the United States).
Such costs include lease acquisition costs, geological and
geophysical studies, carrying charges on non-producing
properties, costs of drilling both productive and non-productive
wells, and overhead expenses directly related to these
activities. Internal costs associated with our CBM activities
that are not directly attributable to acquisition, exploration
or development activities are expensed as incurred.
26
Unproved CBM properties and major development projects are
excluded from amortization until a determination of whether
proved reserves can be assigned to the properties or impairment
occurs. Unproved properties are assessed at least annually to
ascertain whether an impairment has occurred. Sales or
dispositions of properties are credited to their respective cost
centers and a gain or loss is recognized when all the properties
in a cost center have been disposed of, unless such sale or
disposition significantly alters the relationship between
capitalized costs and proved reserves attributable to the cost
center.
Capitalized costs of proved CBM properties, including estimated
future costs to develop the reserves and estimated abandonment
cost, net of salvage, are amortized on the
units-of-production
method using estimates of proved reserves.
A ceiling test is applied to each cost center by comparing the
net capitalized costs, less related deferred income taxes, to
the estimated future net revenues from production of proved
reserves, discounted at 10%, plus the costs of unproved
properties net of impairment. Any excess capitalized costs are
written-off in the current year. The calculation of future net
revenues is based upon prices, costs and regulations in effect
at each year end.
In general, we determine if an unproved property is impaired if
one or more of the following conditions exist:
|
|
|
|
|
there are no firm plans for further drilling on the unproved
property;
|
|
|
|
negative results were obtained from studies of the unproved
property;
|
|
|
|
negative results were obtained from studies conducted in the
vicinity of the unproved property; or
|
|
|
|
the remaining term of the unproved property does not allow
sufficient time for further studies or drilling.
|
Our estimate of proved reserves is based on the quantities of
gas that engineering and geological analysis demonstrate, with
reasonable certainty, to be recoverable from established
reservoirs in the future under current operating and economic
parameters. Reserves and their relation to estimated future net
cash flows impact our depletion and impairment calculations. As
a result, adjustments to depletion and impairment are made
concurrently with changes to reserve estimates. Our reserve
estimates and the projected cash flows are derived from a report
prepared by an independent engineering firm, in accordance with
SEC guidelines, based in part on data provided by us. The
accuracy of our reserve estimates depends in part on the quality
and quantity of available data, the interpretation of that data,
the accuracy of various mandated economic assumptions, and the
judgments of the individuals preparing the estimates.
Share-Based
Payment
Prior to December 13, 2005, we had a stock-based
compensation plan (the Incentive Stock Option Plan)
under which stock options were issued to directors, officers,
employees and consultants as determined by the Board of
Directors and subject to the provisions of the Incentive Stock
Option Plan. The Incentive Stock Option Plan permitted options
to be issued with exercise prices at a discount to the market
price of our common shares on the day prior to the date of
grant. However, the majority of all stock options issued under
the Incentive Stock Option Plan were issued with exercise prices
equal to the quoted market price of the stock on the date of
grant. Options granted under the Incentive Stock Option Plan
vested immediately and were exercisable over a period not
exceeding five years
On December 13, 2005, our shareholders approved the 2005
Omnibus Stock Plan (the Omnibus Stock Plan) and it
became effective on that date. The Omnibus Stock Plan replaces
the Incentive Stock Option Plan under which stock options were
previously granted. The Omnibus Stock Plan is administered by
the Compensation Committee of the Board of Directors (the
Committee) and will remain in effect for five years.
All of our employees and directors, and any of our consultants
or agents designated by the Committee, are eligible to
participate in the Omnibus Stock Plan. The Committee has
authority to: grant awards; select the participants who will
receive awards; determine the terms, conditions, vesting periods
and restrictions applicable to the awards; determine how the
exercise price is to be paid; modify or replace outstanding
awards within the limits of the Omnibus Stock Plan; accelerate
the date on which awards become exercisable; waive the
restrictions and conditions applicable to awards; and establish
rules governing the Omnibus Stock Plan. No stock options have
been issued under the Omnibus Stock
27
Plan. During the current fiscal year, the Committee granted
stock awards under the Omnibus Stock Plan in the form of
restricted and unrestricted stock to our employees and directors.
In December 2004, the FASB issued SFAS No. 123(R),
Share-Based Payment. This Statement revises
SFAS No. 123, Accounting for Stock-Based
Compensation and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees.
SFAS No. 123(R) focuses primarily on the accounting
for transactions in which an entity obtains employee services in
share-based payment transactions. The key provision of
SFAS No. 123(R) requires companies to record
share-based payment transactions as compensation expense at fair
market value based on the grant-date fair value of those awards.
Previously under SFAS 123, companies had the option of
either recording expense based on the fair value of stock
options granted or continuing to account for stock-based
compensation using the intrinsic value method prescribed by APB
No. 25.
We adopted SFAS No. 123(R), using the
modified-prospective method, effective August 1, 2005.
Since August 1, 2001, we have followed the fair value
provisions of SFAS 123 and have recorded all share-based
payment transactions as compensation expense at fair market
value based on the grant-date fair value of those awards. In
addition, all stock options granted prior to the adoption of
SFAS No. 123(R) vested immediately on the date of
grant and, thus, there was no unvested portion of previous stock
option grants that vested during fiscal year 2006. Therefore,
SFAS 123(R) had no impact on our consolidated financial
position or results of operations for fiscal year 2006. We use
the Black-Scholes formula to estimate the fair value of stock
options granted.
Revenue
Recognition
All revenue from gas sales is recognized after the gas is
produced and delivery takes place. We currently sell all of our
gas to one gas marketing company, Atmos Energy Marketing, LLC.
Asset
Retirement Obligations
We follow Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 requires us to record
the fair value of an asset retirement obligation as a liability
in the period in which it is incurred, if a reasonable estimate
of fair value can be made. The present value of the estimated
asset retirement costs is capitalized as part of the carrying
amount of the associated long-lived asset. Amortization of the
capitalized asset retirement cost is determined on a
units-of-production
method. Accretion of the asset retirement obligation is
recognized over time until the obligation is settled. The future
cash outflows associated with settling the asset retirement
obligations accrued on the accompanying consolidated balance
sheets are excluded from the ceiling test calculation. Our asset
retirement obligations relate to the plugging of wells upon
exhaustion of gas reserves.
The fair value of the liability associated with these retirement
obligations is determined using significant assumptions,
including current estimates of the plugging costs, annual
inflation of these costs, the productive life of the wells and
our risk-adjusted interest rate. Changes in any of these
assumptions can result in significant revisions to the estimated
asset retirement obligation. Revisions to the asset retirement
obligation are recorded with an offsetting change to the
carrying amount of the related long-lived asset, resulting in
prospective changes to depreciation, depletion and amortization
expense and accretion. Because of the subjectivity of
assumptions and the relatively long life of our wells, the costs
to ultimately retire these assets may vary significantly from
previous estimates.
Deferred
Income Taxes
We operate in two tax jurisdictions, the United States and
Canada. Primarily as a result of the net losses that we have
generated, we have generated deferred tax benefits available for
tax purposes to offset net income in future periods. However, a
full valuation allowance has been recorded against all deferred
tax assets in Canada as we historically have had no income
generating operations in Canada. We have recorded tax benefits
in the United States for our fiscal years ending July 31,
2005 and 2004. These benefits partially offset a previously
recorded deferred tax liability.
28
Impact
of Recently Issued Accounting Standards Not Yet
Adopted
In June 2006, the FASB issued FASB Interpretation Number 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109. This
Interpretation clarifies the accounting for uncertainty in
income taxes recognized in an enterprises financial
statements in accordance with FASB Statement No. 109,
Accounting for Income Taxes. This Interpretation is
effective for fiscal years beginning after December 15,
2006. We are currently assessing the effect of this
Interpretation, if any, on our consolidated financial statements.
Results
of Operations
Year
Ended July 31, 2006 Compared to Year Ended July 31,
2005
The following table presents our unaudited financial data for
fiscal year 2006 compared to fiscal year 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
1,126,477
|
|
|
$
|
117,835
|
|
|
$
|
1,008,642
|
|
|
|
856
|
%
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
970,791
|
|
|
|
307,178
|
|
|
|
663,613
|
|
|
|
216
|
%
|
General and administrative expense
|
|
|
6,576,131
|
|
|
|
5,805,121
|
|
|
|
771,010
|
|
|
|
13
|
%
|
Depreciation, depletion and
amortization
|
|
|
570,303
|
|
|
|
260,141
|
|
|
|
310,162
|
|
|
|
119
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,117,225
|
|
|
|
6,372,440
|
|
|
|
1,744,785
|
|
|
|
27
|
%
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
941,351
|
|
|
|
123,219
|
|
|
|
818,132
|
|
|
|
664
|
%
|
Interest expense
|
|
|
(22,405
|
)
|
|
|
(24,820
|
)
|
|
|
2,415
|
|
|
|
10
|
%
|
Other income (expense)
|
|
|
(2,764,443
|
)
|
|
|
35,385
|
|
|
|
(2,799,828
|
)
|
|
|
(7,912
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,845,497
|
)
|
|
|
133,784
|
|
|
|
(1,979,281
|
)
|
|
|
(1,479
|
)%
|
Loss before income taxes
|
|
|
(8,836,245
|
)
|
|
|
(6,120,821
|
)
|
|
|
(2,715,424
|
)
|
|
|
(44
|
)%
|
Deferred income tax benefit
|
|
|
|
|
|
|
724,470
|
|
|
|
(724,470
|
)
|
|
|
(100
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(8,836,245
|
)
|
|
$
|
(5,396,351
|
)
|
|
$
|
(3,439,894
|
)
|
|
|
(64
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue Revenue from gas sales increased
$1,008,642 in fiscal year 2006, an increase of 856% over fiscal
year 2005. We realized our first revenues from the sale of CBM
in January 2005. Net sales of gas (net of royalties) were
135,118 Mcf for fiscal year 2006 compared to
17,885 Mcf for fiscal year 2005. Our average realized
selling price per Mcf increased to $8.34 in fiscal year 2006
compared to $6.59 in fiscal year 2005.
Lease operating expense Lease operating
expense increased $663,613 in fiscal year 2006, an increase of
216% over fiscal year 2005. Lease operating expenses represent
production expenses, consisting primarily of repairs and
maintenance, fuel and electricity, equipment rental and other
overhead expenses related to producing wells. The increase is
primarily due to the increase in producing wells and the related
increase in gas production.
General and administrative expense General
and administrative expense consisted of the following for fiscal
year 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Salaries and benefits
|
|
$
|
2,027,707
|
|
|
$
|
894,141
|
|
|
$
|
1,133,566
|
|
|
|
127
|
%
|
Stock-based compensation
|
|
|
1,377,440
|
|
|
|
3,344,738
|
|
|
|
(1,967,298
|
)
|
|
|
(59
|
)%
|
Professional and regulatory
|
|
|
2,637,916
|
|
|
|
1,183,402
|
|
|
|
1,454,514
|
|
|
|
1,229
|
%
|
Other
|
|
|
533,068
|
|
|
|
382,840
|
|
|
|
150,228
|
|
|
|
39
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative
expense
|
|
$
|
6,576,131
|
|
|
$
|
5,805,121
|
|
|
$
|
771,010
|
|
|
|
13
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
Salaries and benefits increased $1,133,566 in fiscal year 2006,
an increase of 127% over fiscal year 2005. The increase was
primarily the result of (i) hiring additional personnel to
support our growth throughout fiscal years 2005 and 2006,
including a Senior Vice President of Operations (April 2006), a
Chief Financial Officer (January 2005) and a Controller
(February 2005); (ii) executive bonuses paid during fiscal
year 2006; and (iii) general salary increases. We had
16 full-time employees at July 31, 2006 compared to
10 full-time employees at July 31, 2005. In addition,
we expanded our technical team, adding three engineers and a
geologist during the first quarter of fiscal year 2007, which
will result in additional annualized salaries of $600,000
beginning in fiscal year 2007.
Stock-based compensation expense decreased $1,967,298 in fiscal
year 2006, a decrease of 59% from fiscal year 2005. During
fiscal year 2006, 495,000 stock options were granted, whereas
4,276,056 stock options were granted to various employees and
directors in fiscal year 2005. During fiscal year 2006, we
issued stock-based awards to employees and directors as follows:
(i) 300,000 unrestricted common shares and 300,000
restricted common shares to our newly hired Senior Vice
President of Operations; (ii) 140,000 unrestricted common
shares to a newly appointed director; and (iii) 495,000
stock options to various employees and directors. We also
replaced 2,025,000 stock options with 2,025,000 restricted
common shares for key employees and directors during fiscal year
2006. The expense related to the issuance of unrestricted common
shares and stock options was fully recognized in fiscal year
2006. A portion of the expense related to the issuance of
restricted common shares, representing the vested portion of
such shares, was also recognized in fiscal year 2006. We expect
to continue our practice of granting share-based awards to
employees in order to attract and retain qualified individuals.
Such awards may be in the form of stock options, unrestricted
common shares, restricted common shares or other share-based
awards. However, we most likely will increase our use of
restricted stock awards as the preferred method of share-based
compensation in lieu of granting stock options, which was our
predominant practice in prior years.
Professional and regulatory fees increased $1,454,514 in fiscal
year 2006, an increase of 1,229% over fiscal year 2005. The
increase was primarily the result of increased legal fees
incurred in connection with our lawsuit against Colt LLC and
higher costs associated with being a public company in the
United States. Specifically, the increase resulted from the
following:
|
|
|
|
|
Additional legal fees
incurred in connection with Colt LLC lawsuit
|
|
$
|
582,528
|
|
Increase in executive
placement fees
|
|
|
293,325
|
|
Increase in printing
costs of SEC filings
|
|
|
258,809
|
|
Increase in insurance
costs
|
|
|
220,936
|
|
Increase in AMEX
listing fees
|
|
|
115,000
|
|
Increase in fees
related to accounting, auditing and tax services
|
|
|
68,030
|
|
Increase in legal fees
incurred in connection with SEC filings
|
|
|
69,920
|
|
Decrease in legal fees
incurred in connection with surface disputes
|
|
|
(293,305
|
)
|
Net increase in other
professional and regulatory fees
|
|
|
139,271
|
|
|
|
|
|
|
Total increase over
corresponding period in the preceding year
|
|
$
|
1,454,514
|
|
|
|
|
|
|
Other general and administrative expenses increased $150,228, an
increase of 39% over fiscal year 2005, primarily as a result of
increased office and travel-related expenses.
Depreciation, depletion and amortization
expense Depreciation, depletion and amortization
expense (DD&A) increased $310,162 in fiscal year
2006, an increase of 119% over fiscal year 2005. We compute
DD&A on capitalized drilling costs and gas collection
equipment using the
units-of-production
method based on estimates of proved reserves, and on all other
property and equipment using the straight-line method based on
estimated useful lives ranging from three to 10 years. The
increase is primarily due to the increase in capitalized
development costs and an increase in production over fiscal year
2005. Additionally, depreciation expense increased due to
additions to other support equipment.
Interest income Interest income increased
$818,132, an increase of 664% over fiscal year 2005 due to
significantly higher average cash balances during fiscal year
2006. The higher cash balances are the result of the net
proceeds of $27,883,954 we received in September 2005 related to
the private placement of our common shares. We
30
invest our excess cash in overnight sweep accounts and
high-grade commercial paper with maturities of 30 days or
less.
Other income (expense) Other income (expense)
decreased $2,799,828, or 7,912%, in fiscal year 2006, primarily
due to recognizing $2,951,608 of other expense related to
settling our dispute with Colt LLC, partially offset by other
income of $127,416 related to the sale of our investment in HCM
and an increase in distributions from HCM of $44,837 during
fiscal year 2006. We believe that these settlement costs will be
more than recouped through reduced royalty payments in future
years.
Deferred income tax benefit Deferred income
tax benefit decreased $724,470 in fiscal year 2006, a decrease
of 100% over fiscal year 2005. We recorded a tax benefit in the
United States in fiscal year 2005 to partially offset a net
recorded deferred tax liability at July 31, 2005. However,
no tax benefit was recognized for fiscal year 2006, as we had no
net deferred tax liability to offset.
Year
Ended July 31, 2005 Compared to Year Ended July 31,
2004
The following table presents our unaudited financial data for
fiscal year 2005 compared to fiscal year 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2005
|
|
|
2004
|
|
|
Variance
|
|
|
Change
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
117,835
|
|
|
$
|
|
|
|
$
|
117,835
|
|
|
|
100
|
%
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
307,178
|
|
|
|
|
|
|
|
307,178
|
|
|
|
100
|
%
|
General and administrative expense
|
|
|
5,805,121
|
|
|
|
1,000,107
|
|
|
|
4,805,014
|
|
|
|
480
|
%
|
Depreciation, depletion and
amortization
|
|
|
260,141
|
|
|
|
80,417
|
|
|
|
179,724
|
|
|
|
223
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,372,440
|
|
|
|
1,080,524
|
|
|
|
5,291,916
|
|
|
|
490
|
%
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
123,219
|
|
|
|
2,008
|
|
|
|
121,211
|
|
|
|
6,036
|
%
|
Interest expense
|
|
|
(24,820
|
)
|
|
|
(15,165
|
)
|
|
|
(9,655
|
)
|
|
|
(64
|
)%
|
Other income
|
|
|
35,385
|
|
|
|
2,454
|
|
|
|
32,931
|
|
|
|
1,342
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
133,784
|
|
|
|
(10,703
|
)
|
|
|
144,487
|
|
|
|
1,350
|
%
|
Loss before income taxes
|
|
|
(6,120,821
|
)
|
|
|
(1,091,227
|
)
|
|
|
(5,029,594
|
)
|
|
|
(461
|
)%
|
Deferred income tax benefit
|
|
|
724,470
|
|
|
|
298,111
|
|
|
|
426,359
|
|
|
|
143
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(5,396,351
|
)
|
|
$
|
(793,116
|
)
|
|
$
|
(4,603,235
|
)
|
|
|
(580
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue We realized our first revenues from
the sale of CBM in January 2005. Sales of CBM generated revenues
of $117,835 during fiscal year 2005 (all in the period of
January through July 2005) compared to $0 sales during
fiscal year 2004. All of our productive wells during fiscal year
2005 were located at our Southern Illinois Basin Project.
Lease operating expense Lease operating
expenses represent production expenses, consisting primarily of
repairs and maintenance, fuel and electricity, equipment rental
and other overhead expenses related to producing wells. We
commenced production toward the end of January 2005 and, thus,
incurred no lease operating expense during fiscal year 2004.
31
General and administrative expense General
and administrative expense consisted of the following for fiscal
years 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2005
|
|
|
2004
|
|
|
Variance
|
|
|
Change
|
|
|
Salaries and benefits
|
|
$
|
894,141
|
|
|
$
|
418,701
|
|
|
$
|
475,440
|
|
|
|
114
|
%
|
Stock-based compensation
|
|
|
3,344,738
|
|
|
|
193,796
|
|
|
|
3,150,942
|
|
|
|
1,626
|
%
|
Professional and regulatory
|
|
|
1,183,402
|
|
|
|
98,458
|
|
|
|
1,084,944
|
|
|
|
1,102
|
%
|
Other
|
|
|
382,840
|
|
|
|
289,152
|
|
|
|
93,688
|
|
|
|
32
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative
expense
|
|
$
|
5,805,121
|
|
|
$
|
1,000,107
|
|
|
$
|
4,805,014
|
|
|
|
480
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Salaries and benefits increased $475,440 in fiscal year 2005, an
increase of 114% over fiscal year 2004. The increase was
primarily the result of bonuses paid to various employees,
hiring a Vice President of Field Operations, a Chief Financial
Officer and a Controller, and general salary increases.
Stock-based compensation increased $3,150,942 in fiscal year
2005, an increase of 1,626% over fiscal year 2004. The increase
resulted primarily from the granting of additional options to
various key employees and directors of the company and the
general increase in our stock price. During fiscal year 2005, we
granted options to purchase 4,276,056 common shares that were
valued at $3,344,738. This compares with the options to purchase
475,000 common shares that were granted during fiscal year 2004
and were valued at $193,796. The award of these options was
consistent with our belief that it is necessary to provide this
form of compensation for us to attract and retain qualified
individuals.
Professional and regulatory fees increased $1,084,944 in fiscal
year 2005, an increase of 1,102% over fiscal year 2004. The
increase resulted from the following:
|
|
|
|
|
Additional legal fees
incurred in connection with surface disputes
|
|
$
|
303,305
|
|
Increase in fees
related to accounting, auditing and tax services
|
|
|
193,046
|
|
Increase in legal fees
incurred in connection with SEC filings
|
|
|
175,567
|
|
Increase in fees
related to general corporate legal and professional advice
|
|
|
150,522
|
|
Increase in fees
related to outside investor relations services
|
|
|
141,757
|
|
Net increase in other
professional fees
|
|
|
120,747
|
|
|
|
|
|
|
Total increase over
corresponding period in the preceding year
|
|
$
|
1,084,944
|
|
|
|
|
|
|
Other general and administrative expenses increased $93,688 in
fiscal year 2005, an increase of 32% over fiscal year 2004. The
increase resulted primarily from additional costs incurred in
opening our headquarters office in Solon, Ohio during fiscal
year 2005.
Depreciation, depletion and amortization
expense Depreciation, depletion and amortization
expense (DD&A) increased $179,724 in fiscal year
2005, an increase of 223% over fiscal year 2004. We compute
DD&A on capitalized drilling costs and gas collection
equipment using the
units-of-production
method based on estimates of proved reserves, and on all other
property and equipment using the straight-line method based on
estimated useful lives ranging from three to 10 years. The
increase is primarily due to the fact that we had no production
in fiscal year 2004. Additionally, depreciation expense
increased due to additions to other support equipment.
Interest income Interest income increased
$121,211 in fiscal year 2005, an increase of 6,036% over fiscal
year 2004 due to significantly higher average cash balances
during fiscal year 2005.
Other income Other income increased $32,931
in fiscal year 2005, an increase of 1,342% over fiscal year
2004. The increase is primarily due to us recognizing a gain of
$42,276 on the sale of our remaining 432,000 shares of Pyng
Technologies Corp., a TSX Venture listed public company, during
fiscal year 2005.
Deferred income tax benefit The deferred
income tax benefit increased $426,359 in fiscal year 2005, an
increase of 143% over fiscal year 2004. The increase resulted
primarily from the increase in our loss before income
32
taxes. The effect of the increase in our loss before income
taxes was partially offset by a decrease in the effective tax
rate to 11.8% during fiscal year 2005, as compared to 27.3% in
fiscal year 2004. The decrease in rate was primarily the result
of an increase in stock-based compensation expense, which is
non-deductible for U.S. tax purposes.
Liquidity
and Capital Resources
Our primary source of liquidity historically has come from the
sale of our common shares in private placements and the proceeds
from the exercise of warrants and options to acquire our common
shares. To date, we have not relied significantly on borrowing
to finance our operations or provide cash. As of July 31,
2006, we had only $216,015 in long-term notes payable. From
July 31, 2003 until July 31, 2006, we raised
$43,198,616 from the sale of our common shares. Additionally,
during that same period, we collected $6,728,810 as a result of
the exercise of warrants and $2,042,280 as a result of the
exercise of stock options. Our primary use of these funds has
been the acquisition, exploration, testing and development of
our CBM properties and rights.
We did not begin to generate revenues from CBM sales until
January 2005. Revenues from CBM sales were $1,126,477 for fiscal
year 2006 and $117,835 for fiscal year 2005. We expect revenue
from the sale of our CBM to increase due to (i) increased
production from existing wells as they proceed through the
initial dewatering phase and (ii) additional production
generated as a result of drilling additional wells. However, in
view of our limited production history, we can provide no
assurance that we will achieve a trend of increased production
and CBM revenue in the future.
CBM wells typically must go through a lengthy dewatering phase
before making any meaningful contribution to gas production. We
estimate that a typical vertical well will require about
24 months to reach peak production. The impact on our cash
position is that there will be a delay of up to 24 months
between the time we initially invest in drilling and completing
a well and the time when a typical well will begin to make a
meaningful contribution to our cash from operations.
We had a cash balance of $19,279,015 at July 31, 2006,
compared to $7,251,503 at July 31, 2005. The net increase
in our cash balance is primarily due to the $27,883,954 of net
proceeds we received from the sale of our common shares in a
private placement that closed on September 26, 2005,
$5,013,928 received as a result of the exercise of warrants
during fiscal year 2006, and $382,239 received as a result of
the exercise of stock options during fiscal year 2006. We raised
an amount in the private placement we felt was required to fund
our development plans through April 2006. However, because our
drilling progress at our Southern Illinois Basin Project was
slowed due to the dispute with one of the coal owners, we now
believe our cash balance will be sufficient to fund the low end
of our forecasted capital program through July 31, 2007.
Our revenues and cash balances, however, will not likely be
sufficient to fund the high end of our capital program for
fiscal 2007 or our operations beyond that date. Therefore, we
will likely need to raise additional financing in the near
future. We currently do not have any specific plans to raise
financing in support of our future operations. Although
management has no specific plans in place to raise the
additional capital necessary to fund our plan of operations and
forecasted capital expenditures, management anticipates raising
the additional required capital through a combination of
additional stock sales, the issuance of debt securities,
borrowing
and/or
entering into joint ventures.
Cash
Used in Operating Activities
Net cash used in operating activities for fiscal year 2006 was
$6,560,034. This compares with $2,474,443 net cash used in
operating activities in the prior year. The increase in net cash
used in operating activities resulted from the $3,000,000 paid
to Colt LLC to settle a lawsuit and increased general and
administrative expenses required to support the growth in the
size of our projects in the Illinois Basin. Net cash used in
operating activities for fiscal year 2004 was $906,849. Since
July 31, 2003, we have substantially increased our
exploration and operating activities, and therefore our
personnel, in the Illinois Basin. Since we did not generate any
CBM revenues until January 2005, the costs associated with the
additional activities and personnel resulted in
year-to-year
increases in net cash used in operations.
33
Net cash used by operating activities is dependent on a number
of factors over which we have little or no control. These
factors include, but are not limited to:
|
|
|
|
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the price of, and demand for, natural gas;
|
|
|
|
availability of drilling and service equipment and personnel;
|
|
|
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lease terms;
|
|
|
|
availability of sufficient capital resources; and
|
|
|
|
the accuracy of production estimates for current and future
wells.
|
Cash
Used in Investing Activities
Net cash used in investing activities for fiscal year 2006 was
$14,517,293. This compares with $6,338,082 net cash used in
investing activities in fiscal year 2005 and $1,787,382 net
cash used in investing activities in fiscal year 2004. The
increases in net cash used in investing activities during fiscal
years 2005 and 2006 are primarily the result of increased
exploration and development costs at our projects, the
installation of a gas gathering system at our Southern Illinois
Basin Project, and additions to vehicles and other equipment to
support our growth in operations.
Cash
Provided by Financing Activities
Net cash provided by financing activities for fiscal year 2006
was $33,104,839. This compares with $15,093,233 net cash
provided by financing activities in fiscal year 2005 and
$3,498,439 net cash provided by financing activities in
fiscal year 2004. The increases in net cash provided by
financing activities during fiscal years 2005 and 2006 are
primarily the result of increased proceeds from common shares
issued in private placements and from the exercise of stock
options and warrants. We received net proceeds from common
shares issued in private placements in the amount of $27,883,954
during fiscal year 2006, $12,074,106 during fiscal year 2005 and
$3,240,556 during fiscal year 2004. In addition, we received
aggregate proceeds from the exercise of stock options and
warrants in the amounts of $5,396,167 during fiscal year 2006,
$3,331,887 during fiscal year 2005 and $43,036 during fiscal
year 2004. We continue to pay down our long-term notes, making
payments of $175,282 in fiscal year 2006, $42,320 in fiscal year
2005 and $26,014 in fiscal year 2004. Our long-term notes
payable (including current maturities) decreased from $549,822
at July 31, 2005 to $216,015 at July 31, 2006. We
expect to continue to reduce our long-term notes payable by
making scheduled principal payments of $140,866 in fiscal year
2007.
Capital
Expenditure Plan
We have no contractual commitments for capital expenditures.
However, our plan anticipates that over the year ending
July 31, 2007, we will spend approximately
$12.0 million to $30.0 million on capital
expenditures. These amounts correspond to drilling 58 wells
at the low end of the range and 123 wells at the upper end.
These amounts include installing a gathering system and
processing yard to handle the anticipated production from our
10-well
pilot program and additional pilot wells
and/or
production wells at our three current projects. In addition to
our drilling program, we expect to pursue the acquisition of
additional CBM rights during the fiscal year. We expect that
this capital expenditure program and our other cash requirements
will be funded by our cash balance, which as of October 25,
2006 is approximately $15.1 million, and cash raised
through the sale of debt securities, equity securities,
borrowings
and/or joint
ventures. Although we are currently evaluating the best methods
of raising these funds, we can provide no assurance that we will
be able to raise the necessary funds.
34
Contractual
Obligations
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Payments Due by Period
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Less Than
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|
|
|
|
|
More Than
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|
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|
1 Year
|
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1-3 Years
|
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|
3-5 Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Contractual Obligations As of
July 31, 2006:
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|
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|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
Long-term debt
|
|
$
|
148,601
|
|
|
$
|
63,674
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|
|
$
|
17,840
|
|
|
$
|
|
|
|
$
|
230,115
|
|
Equipment leases
|
|
|
82,875
|
|
|
|
13,813
|
|
|
|
|
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|
|
|
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|
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96,688
|
|
Asset retirement obligations
|
|
|
9,600
|
|
|
|
|
|
|
|
|
|
|
|
70,754
|
|
|
|
80,354
|
|
Other leases(1)
|
|
|
136,266
|
|
|
|
197,272
|
|
|
|
29,784
|
|
|
|
262,557
|
|
|
|
625,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
377,342
|
|
|
$
|
274,759
|
|
|
$
|
47,624
|
|
|
$
|
333,311
|
|
|
$
|
1,033,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1) |
|
These amounts do not include annual minimum royalty payments
required to hold mineral lease and farm-out agreements. Although
we are not obligated to make these payments under existing
mineral leases and farm-out agreements, these payments are
required to maintain individual lease/farm-out agreements after
the expiration of the initial terms of the lease/farm-out
agreements. The lease/farm-out agreements in existence as of
October 25, 2006 expire at various times beginning in
November 2007. If we were to pay the total minimum royalty
payments due under all lease/farm-out agreements in existence as
of October 25, 2006, the amount would initially total
approximately $100,000 annually and could increase to as much as
$220,000 annually. |
Off-Balance
Sheet Arrangements
We had no off-balance sheet arrangements as of July 31,
2006.
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ITEM 7A.
|
Qualitative
and Quantitative Exposure to Market Risk.
|
Commodity
Risk
Our major risk exposure is the commodity pricing applicable to
our CBM production. Realized commodity prices received for our
production are primarily driven by the spot prices attributable
to natural gas. The effects of price volatility are expected to
continue.
Interest
Rate Risk
All of our debt has fixed interest rates, so consequently we are
not exposed to cash flow or fair value risk from market interest
rate changes on this debt.
Financial
Instruments
Our financial instruments consist of cash and cash equivalents,
accounts receivable and long-term notes payable. The carrying
amount of cash equivalents, accounts receivable and accounts
payable approximate fair market value due to the highly liquid
nature of these short-term instruments.
Inflation
and Changes in Prices
The general level of inflation affects our costs. Salaries and
other general and administrative expenses are impacted by
inflationary trends and the supply and demand of qualified
professionals and professional services. Inflation and price
fluctuations affect the costs associated with exploring for and
producing CBM, which has a material impact on our financial
performance.
|
|
ITEM 8.
|
Financial
Statements and Supplementary Data.
|
Our consolidated financial statements are included in this
report beginning on
page F-1.
|
|
ITEM 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure.
|
None.
35
|
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ITEM 9A.
|
Controls
and Procedures.
|
Our management is responsible for establishing and maintaining
effective disclosure controls and procedures, as defined under
Rules 13a-15(e)
and
15d-15(e) of
the Securities Exchange Act of 1934. Our management, with
participation of our Chief Executive Officer and Controller (who
is currently responsible for performing certain functions of our
principal financial officer), has evaluated the effectiveness of
our disclosure controls and procedures (as defined in Exchange
Act
Rule 13a-15)
as of July 31, 2006. Based on that evaluation, our CEO and
Controller concluded that our disclosure controls and procedures
were effective as of July 31, 2006 in alerting them on a
timely basis to material information relating to BPI (including
our consolidated subsidiaries) required to be included in our
periodic filings under the Exchange Act.
On October 12, 2006, our Chief Financial Officer resigned.
We have appointed our Controller to perform certain of the
functions of the principal financial officer. Our Controller
performed the evaluation of disclosure controls and procedures
required to be conducted and performed the analysis necessary to
provide the certifications to this report normally required of
the principal financial officer who recently departed.
There were no significant changes in our internal controls over
financial reporting or in other factors that occurred during the
fiscal quarter ended July 31, 2006 that materially
affected, or are reasonably likely to affect, our internal
control over financial reporting.
ITEM 9B. Other
Information.
None.
PART III
|
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ITEM 10.
|
Directors
and Executive Officers of the Registrant.
|
We incorporate herein by reference the information appearing
under the caption Election of Directors,
Section 16(a) Beneficial Ownership Reporting
Compliance and Committees of the Board of Directors;
Attendance in our definitive proxy statement for our
Annual General Meeting of Shareholders, which we will file with
the Securities and Exchange Commission not later than
November 28, 2006.
Information concerning our executive officers is contained in
Item 1 of Part I of this annual report. We have adopted a
Code of Business Conduct and Ethics for employees that applies
to our principal executive officer, principal financial officer
and controller, as well as all other employees. Our Code of
Business Conduct and Ethics can be found on the our website at
www.bpi-energy.com.
|
|
ITEM 11.
|
Executive
Compensation.
|
We incorporate herein by reference the information appearing
under the captions Director Compensation and
Executive Compensation in our definitive proxy
statement.
|
|
ITEM 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Shareholder Matters.
|
We incorporate herein by reference the information appearing
under the caption Beneficial Ownership in our
definitive proxy statement.
|
|
ITEM 13.
|
Certain
Relationships and Related Transactions.
|
We incorporate herein by reference the information appearing
under the caption Certain Relationships and Related
Transactions in our definitive proxy statement.
36
|
|
ITEM 14.
|
Principal
Accountant Fees and Services.
|
We incorporate herein by reference the information appearing
under the caption Ratification of Appointment of
Independent Registered Accounting Firm in our definitive
proxy statement.
PART IV
|
|
ITEM 15.
|
Exhibits
and Financial Statement Schedules.
|
(a) The following documents are filed as part of this
report:
(1) Financial Statements
The consolidated financial statements filed as part of this Form
10-K are
located as set forth in the index on
page F-1
of this report.
(2) Financial Statement Schedules
Not applicable.
(3) Exhibits
The list of exhibits included in the attached Exhibit Index
is hereby incorporated herein by reference.
37
Appendix A
Glossary
of Natural Gas Terms
The following are definitions of selected terms relating to the
natural gas industry that are used in this prospectus:
Adsorption. The attachment, through physical
or chemical bonding, of gas molecules to the coal surface. The
adsorbed gas molecules are trapped within the coal, the
stability of which is strongly affected by changes in
temperature and pressure.
Casing. Steel pipe set in a well to prevent
the hole from sloughing or caving and to enable formations to be
isolated. There may be several strings of casing in a well, one
inside the other.
Completion. The activities necessary to
prepare a well for the production of gas.
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Dewatering. A CBM well typically begins
dewatering with almost all water production and little or no
natural gas production. The continuous production of water from
a well that is dewatering reduces the water reservoir pressure
on the coals. The reduced reservoir pressure enables the release
of the gas within the coal to the wellbore. This results in an
increase in the amount of gas production relative to the amount
of water production. Dewatering ceases when peak gas production
is reached.
Dry hole. A well found to be incapable of
producing hydrocarbons in sufficient quantities such that
proceeds from the sale of the production will exceed production
expenses and taxes.
Farm-out agreement. An agreement where the
owner of a working interest in a gas lease assigns the working
interest or a portion thereof to another party who desires to
drill on the leased acreage. Generally, the assignee is required
to drill one or more wells in order to earn its interest in the
acreage. The assignor usually retains a royalty or reversionary
interest in the lease.
Fracture. A man-made or hydraulic fracture is
formed when a fluid is pumped down a well at high pressures for
short periods of time causing a split in the rock formation. As
part of this technique, sand or other material may also be
injected into the formation to keep the channel open. This
technique allows gas to move more freely from the rock pores
where they are trapped to a producing well that can bring the
gas to the surface.
Horizontal drilling. A drilling operation in
which a portion of the well is drilled horizontally within a
productive or potentially productive formation. This operation
typically yields a well that has the ability to produce higher
volumes than a vertical well drilled in the same formation. A
horizontal well is designed to replace multiple vertical wells,
resulting in lower capital expenditures for draining like
acreage and limiting surface disruption.
Isotherm test. An adsorption isotherm test
measures the storage capacity of coal in terms of gas content.
Mcf. One thousand cubic feet of natural gas at
standard atmospheric conditions.
Mcfe. One thousand cubic feet of natural gas
equivalent at standard atmospheric conditions, determined using
the ratio of one barrel of oil to six Mcf of natural gas.
MMBtus. One million British thermal units. One
British thermal unit is the quantity of heat required to raise
the temperature of one pound of water by one degree Fahrenheit.
MMcf. One million cubic feet of natural gas at
standard atmospheric conditions.
Permeability. The capacity of a geologic
formation to allow water or natural gas to pass through it.
Productive well. A well that has been
completed and is tied into our gas and/or dewatering system. A
productive well may produce only water for a period of time
before gas begins to flow through the gas gathering system.
A-1
Proved reserves. The estimated quantities of
natural gas that geological and engineering data demonstrate
with reasonable certainty to be commercially recoverable in
future years from known reservoirs under existing economic and
operating conditions. This definition is consistent with
Rule 4-10(a)(2)
of
Regulation S-X
of the rules and regulations of the SEC. In reporting proved
reserves, we are required to comply with
Rule 4-10(a)(2).
Reserves. The quantity of natural gas that is
estimated to be commercially recoverable from specific acreage.
Reservoir. A porous and permeable underground
formation, including a coal seam, containing a natural
accumulation of producible natural gas that is confined by
impermeable rock or water barriers and is separate from other
reservoirs.
Royalty interest. An interest in a natural gas
lease that gives the owner of the interest the right to receive
a portion of the production from the leased acreage, but
generally does not require the owner to pay any portion of the
costs of drilling or operating the wells on the leased acreage.
Royalties may be either landowners royalties, which are
reserved by the owner of the leased acreage at the time the
lease is granted, or overriding royalties, which are usually
reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.
Scf. Standard cubic feet.
Undeveloped acreage. Acreage on which wells
have not been drilled or completed to a point that would permit
the production of commercial quantities of natural gas,
regardless of whether or not such acreage contains proved
reserves.
Vertical drilling. A hole drilled vertically
into the earth from which gas or water flows or is pumped.
Working interest. An interest in a natural gas
lease that gives the owner of the interest the right to drill
and produce natural gas on the leased acreage and requires the
owner to pay its proportionate share of the costs of drilling
and production operations.
A-2
BPI
ENERGY HOLDINGS, INC.
Index to
Consolidated Financial Statements
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders of
BPI Energy Holdings, Inc.
Solon, Ohio
We have audited the accompanying consolidated balance sheets of
BPI Energy Holdings, Inc. and its subsidiary as of July 31,
2006 and 2005, and the related statements of operations,
shareholders equity, and cash flows for the fiscal years
then ended. These financial statements are the responsibility of
the Companys management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material 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 also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of BPI Energy Holdings, Inc. and its subsidiary as of
July 31, 2006 and 2005, and the results of its operations
and its cash flows for the fiscal years then ended, in
conformity with accounting principles generally accepted in the
United States of America.
/s/ MEADEN &
MOORE, LTD.
Certified Public Accountants
October 13, 2006
Cleveland, Ohio
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
DEVISSER
GRAY
CHARTERED ACCOUNTANTS
401-905 West Pender Street
Vancouver, BC Canada
V6C 1L6
Tel:
(604) 687-5447
Fax:
(604) 687-6737
The Board of Directors and Shareholders of BPI Energy Holdings,
Inc.,
We have audited the accompanying consolidated statement of
operations, shareholders equity and cash flows of BPI
Energy Holdings, Inc. and its subsidiary for the fiscal year
ended July 31, 2004. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform an audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the results
of operations and cash flows of BPI Energy Holdings, Inc. and
its subsidiary for the fiscal year ended July 31, 2004 in
conformity with accounting principles generally accepted in the
United States of America.
/s/ De Visser Gray
CHARTERED ACCOUNTANTS
Vancouver, British Columbia
October 12, 2004
F-3
BPI
ENERGY HOLDINGS, INC.
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|
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July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
19,279,015
|
|
|
$
|
7,251,503
|
|
Accounts receivable
|
|
|
105,711
|
|
|
|
34,671
|
|
Other current assets
|
|
|
164,764
|
|
|
|
23,534
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
19,549,490
|
|
|
|
7,309,708
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost
method of accounting:
|
|
|
|
|
|
|
|
|
Proved, net of accumulated
depreciation, depletion and amortization of $331,150 and $58,523
|
|
|
20,766,898
|
|
|
|
10,190,929
|
|
Unproved, excluded from
amortization
|
|
|
3,368,231
|
|
|
|
3,149,372
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
|
24,135,129
|
|
|
|
13,340,301
|
|
Other property and equipment, net
of accumulated depreciation and amortization of $631,015 and
$398,988
|
|
|
5,106,236
|
|
|
|
1,769,812
|
|
|
|
|
|
|
|
|
|
|
Net property and equipment
|
|
|
29,241,365
|
|
|
|
15,110,113
|
|
Investment in Hite Coalbed
Methane, L.L.C.
|
|
|
|
|
|
|
846,766
|
|
Restricted cash
|
|
|
100,000
|
|
|
|
100,000
|
|
Other non-current assets
|
|
|
161,125
|
|
|
|
161,125
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
49,051,980
|
|
|
$
|
23,527,712
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
SHAREHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,492,239
|
|
|
$
|
2,144,066
|
|
Current maturities of long-term
notes payable
|
|
|
140,866
|
|
|
|
42,227
|
|
Accrued liabilities and other
|
|
|
649,237
|
|
|
|
31,405
|
|
|
|
|
|
|
|
|
|
|
Total current
liabilities
|
|
|
2,282,342
|
|
|
|
2,217,698
|
|
Long-term notes payable, less
current maturities
|
|
|
75,149
|
|
|
|
507,595
|
|
Asset retirement obligation
|
|
|
70,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,428,245
|
|
|
|
2,725,293
|
|
Shareholders
Equity
|
|
|
|
|
|
|
|
|
Common shares, no par value,
authorized 200,000,000 shares, 70,812,540 and 43,912,961
issued and outstanding
|
|
|
67,946,143
|
|
|
|
34,666,022
|
|
Additional paid-in capital
|
|
|
5,871,120
|
|
|
|
4,493,680
|
|
Accumulated deficit
|
|
|
(27,193,528
|
)
|
|
|
(18,357,283
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholders
equity
|
|
|
46,623,735
|
|
|
|
20,802,419
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
shareholders equity
|
|
$
|
49,051,980
|
|
|
$
|
23,527,712
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-4
BPI
ENERGY HOLDINGS, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
1,126,477
|
|
|
$
|
117,835
|
|
|
$
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
970,791
|
|
|
|
307,178
|
|
|
|
|
|
General and administrative expenses
|
|
|
6,576,131
|
|
|
|
5,805,121
|
|
|
|
1,000,107
|
|
Depreciation, depletion and
amortization
|
|
|
570,303
|
|
|
|
260,141
|
|
|
|
80,417
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
8,117,225
|
|
|
|
6,372,440
|
|
|
|
1,080,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(6,990,748
|
)
|
|
|
(6,254,605
|
)
|
|
|
(1,080,524
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
941,351
|
|
|
|
123,219
|
|
|
|
2,008
|
|
Interest expense
|
|
|
(22,405
|
)
|
|
|
(24,820
|
)
|
|
|
(15,165
|
)
|
Other income (expense)
|
|
|
(2,764,443
|
)
|
|
|
35,385
|
|
|
|
2,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,845,497
|
)
|
|
|
133,784
|
|
|
|
(10,703
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(8,836,245
|
)
|
|
|
(6,120,821
|
)
|
|
|
(1,091,227
|
)
|
Deferred income tax benefit
|
|
|
|
|
|
|
724,470
|
|
|
|
298,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(8,836,245
|
)
|
|
$
|
(5,396,351
|
)
|
|
$
|
(793,116
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net loss per
share
|
|
$
|
(0.14
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding
|
|
|
62,789,319
|
|
|
|
37,665,019
|
|
|
|
25,007,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-5
BPI
ENERGY HOLDINGS, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Common
|
|
|
Total
|
|
|
|
Common Shares
|
|
|
Paid-in
|
|
|
Accumulated
|
|
|
Shares
|
|
|
Shareholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Deficit
|
|
|
Issuable
|
|
|
Equity
|
|
|
Balance, July 31,
2003
|
|
|
22,278,752
|
|
|
$
|
15,953,188
|
|
|
$
|
968,972
|
|
|
$
|
(12,167,816
|
)
|
|
$
|
30,579
|
|
|
$
|
4,784,923
|
|
Proceeds from stock options
exercised
|
|
|
69,444
|
|
|
|
43,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,036
|
|
Net proceeds from shares issued in
Private placement September 18, 2003
|
|
|
725,000
|
|
|
|
339,787
|
|
|
|
|
|
|
|
|
|
|
|
(30,579
|
)
|
|
|
309,208
|
|
Net proceeds from shares issued in
Private placement December 22, 2003(1)
|
|
|
1,975,000
|
|
|
|
928,259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
928,259
|
|
Net proceeds from shares issued in
Private placement April 27, 2004
|
|
|
3,326,100
|
|
|
|
1,972,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,972,510
|
|
Proceeds from shares issuable for
warrants exercised
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
271,440
|
|
|
|
271,440
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
193,796
|
|
|
|
|
|
|
|
|
|
|
|
193,796
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(793,116
|
)
|
|
|
|
|
|
|
(793,116
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, July 31,
2004
|
|
|
28,374,296
|
|
|
|
19,236,780
|
|
|
|
1,162,768
|
|
|
|
(12,960,932
|
)
|
|
|
271,440
|
|
|
|
7,710,056
|
|
Proceeds from stock options
exercised
|
|
|
2,254,333
|
|
|
|
1,617,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,617,005
|
|
Proceeds from warrants exercised
|
|
|
2,861,342
|
|
|
|
1,714,882
|
|
|
|
|
|
|
|
|
|
|
|
(271,440
|
)
|
|
|
1,443,442
|
|
Net proceeds from shares issued in
Private placement December 29, 2004(2)
|
|
|
2,400,000
|
|
|
|
2,793,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,793,854
|
|
Net proceeds from shares issued in
Private placement December 30, 2004(3)
|
|
|
4,032,000
|
|
|
|
4,693,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,693,675
|
|
Net proceeds from shares issued in
Private placement January 6, 2005(4)
|
|
|
3,723,200
|
|
|
|
4,334,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,334,199
|
|
Net proceeds from shares issued in
Private placement January 12, 2005(5)
|
|
|
216,800
|
|
|
|
252,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
252,378
|
|
Bonus shares
|
|
|
50,990
|
|
|
|
23,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,249
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
3,344,738
|
|
|
|
|
|
|
|
|
|
|
|
3,344,738
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
(13,826
|
)
|
|
|
|
|
|
|
|
|
|
|
(13,826
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,396,351
|
)
|
|
|
|
|
|
|
(5,396,351
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, July 31,
2005
|
|
|
43,912,961
|
|
|
|
34,666,022
|
|
|
|
4,493,680
|
|
|
|
(18,357,283
|
)
|
|
|
|
|
|
|
20,802,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from stock options
exercised
|
|
|
396,667
|
|
|
|
382,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
382,239
|
|
Proceeds from warrants exercised
|
|
|
5,822,075
|
|
|
|
5,013,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,013,928
|
|
Net proceeds from shares issued in
Private placement September 23, 2005(6)
|
|
|
18,000,000
|
|
|
|
27,883,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27,883,954
|
|
Stock-based
compensation stock options
|
|
|
|
|
|
|
|
|
|
|
527,327
|
|
|
|
|
|
|
|
|
|
|
|
527,327
|
|
Stock-based
compensation common shares, including vested portion
of restricted stock
|
|
|
758,514
|
|
|
|
|
|
|
|
850,113
|
|
|
|
|
|
|
|
|
|
|
|
850,113
|
|
Restricted stock, less vested
portion
|
|
|
1,922,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,836,245
|
)
|
|
|
|
|
|
|
(8,836,245
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, July 31,
2006
|
|
|
70,812,540
|
|
|
$
|
67,946,143
|
|
|
$
|
5,871,120
|
|
|
$
|
(27,193,528
|
)
|
|
$
|
|
|
|
$
|
46,623,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
net of share issuance costs of $18,730 |
|
(2) |
|
net of share issuance costs of $206,146 |
|
(3) |
|
net of share issuance costs of $346,325 |
|
(4) |
|
net of share issuance costs of $319,801 |
|
(5) |
|
net of share issuance costs of $18,622 |
|
(6) |
|
net of share issuance costs of $2,619,953 |
See notes to consolidated financial statements
F-6
BPI
ENERGY HOLDINGS, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Cash Provided by (Used
in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(8,836,245
|
)
|
|
$
|
(5,396,351
|
)
|
|
$
|
(793,116
|
)
|
Adjustments to reconcile net loss
to net cash used in operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
570,303
|
|
|
|
260,141
|
|
|
|
80,417
|
|
Stock-based compensation expense
|
|
|
1,377,440
|
|
|
|
3,344,738
|
|
|
|
193,796
|
|
Gain on sale of investments and
marketable securities
|
|
|
(127,416
|
)
|
|
|
(42,276
|
)
|
|
|
(2,454
|
)
|
Loss on disposal of property and
equipment
|
|
|
|
|
|
|
16,415
|
|
|
|
|
|
Deferred income tax benefit
|
|
|
|
|
|
|
(724,470
|
)
|
|
|
(298,111
|
)
|
Other
|
|
|
11,024
|
|
|
|
20,339
|
|
|
|
(564
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(71,040
|
)
|
|
|
(34,671
|
)
|
|
|
|
|
Other current assets
|
|
|
(141,230
|
)
|
|
|
21,392
|
|
|
|
(26,909
|
)
|
Accounts payable
|
|
|
8,116
|
|
|
|
80,913
|
|
|
|
7,699
|
|
Accrued liabilities and other
|
|
|
649,014
|
|
|
|
11,012
|
|
|
|
20,393
|
|
Other non-current assets
|
|
|
|
|
|
|
(31,625
|
)
|
|
|
(88,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in operating
activities
|
|
|
(6,560,034
|
)
|
|
|
(2,474,443
|
)
|
|
|
(906,849
|
)
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of marketable
securities and investments
|
|
|
551,000
|
|
|
|
113,557
|
|
|
|
5,407
|
|
Business acquisition, net of cash
acquired
|
|
|
|
|
|
|
(857,638
|
)
|
|
|
|
|
Additions to oil and gas properties
|
|
|
(11,784,236
|
)
|
|
|
(4,032,681
|
)
|
|
|
(1,413,729
|
)
|
Additions to other property and
equipment
|
|
|
(3,284,057
|
)
|
|
|
(1,383,208
|
)
|
|
|
(191,794
|
)
|
Acquisition of equity interest in
joint venture
|
|
|
|
|
|
|
(78,112
|
)
|
|
|
(100,500
|
)
|
Investment in Hite Coalbed Methane,
L.L.C.
|
|
|
|
|
|
|
|
|
|
|
(86,766
|
)
|
Increase in restricted cash
|
|
|
|
|
|
|
(100,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(14,517,293
|
)
|
|
|
(6,338,082
|
)
|
|
|
(1,787,382
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments on long-term notes payable
|
|
|
(175,282
|
)
|
|
|
(41,320
|
)
|
|
|
(26,014
|
)
|
Net proceeds from issuance of
common shares
|
|
|
33,280,121
|
|
|
|
15,134,553
|
|
|
|
3,524,453
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
33,104,839
|
|
|
|
15,093,233
|
|
|
|
3,498,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash
equivalents
|
|
|
12,027,512
|
|
|
|
6,280,708
|
|
|
|
804,208
|
|
Cash and cash equivalents at the
beginning of the year
|
|
|
7,251,503
|
|
|
|
970,795
|
|
|
|
166,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at the
end of the year
|
|
$
|
19,279,015
|
|
|
$
|
7,251,503
|
|
|
$
|
970,795
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow
information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
18,483
|
|
|
$
|
11,540
|
|
|
$
|
2,425
|
|
Non-cash investing and financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of equipment by
issuance of notes payable
|
|
|
233,475
|
|
|
|
118,049
|
|
|
|
105,847
|
|
Cancellation of convertible note
payable
|
|
|
392,000
|
|
|
|
|
|
|
|
|
|
Cashless exercise of warrants
|
|
|
283,557
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-7
BPI
ENERGY HOLDINGS, INC.
July 31,
2006, 2005 and 2004
|
|
1.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis
of Presentation and Going Concern
These consolidated financial statements include the accounts of
BPI Energy Holdings, Inc. and its wholly owned
U.S. subsidiary, BPI Energy, Inc. (collectively, the
Company). The Company has presented these financial
statements in accordance with U.S. generally accepted
accounting principles (GAAP). All inter-company
transactions and balances have been eliminated upon
consolidation.
BPI Energy Holdings, Inc. is incorporated in British Columbia,
Canada and, through its wholly owned U.S. subsidiary, BPI
Energy, Inc., is involved in the exploration, production and
commercial sale of coalbed methane (CBM) located in
the Illinois Basin. The Company conducts its operations in one
reportable segment, which is oil and gas exploration and
production. On December 13, 2005, the Companys common
shares began trading on the American Stock Exchange
(AMEX) under the symbol BPG. As a result of the
shares being listed on the AMEX, the Company voluntarily
de-listed from trading its shares on the TSX Venture Exchange.
Amounts shown are in U.S. Dollars unless otherwise
indicated.
These consolidated financial statements have been prepared on
the basis of accounting principles applicable to a going
concern, which contemplates the Companys ability to
realize its assets and discharge its liabilities in the normal
course of business; however, the occurrence of significant
losses to date raises doubt upon the validity of this
assumption. The ability of the Company to realize the costs it
has incurred to date on these properties is dependent upon the
Company being able to sell the properties or to develop
profitable operations, to finance their exploration and
development costs and to resolve any environmental, regulatory
or other constraints, which may hinder the successful
development of the properties.
The Company has experienced significant losses over the past
five years, including $8,836,245 in the current year, and has an
accumulated deficit of $27,193,528 at July 31, 2006. The
Companys continued existence as a going concern is
dependent upon its ability to continue to obtain adequate
financing arrangements and to achieve and maintain profitable
operations.
The Company has financed its activities primarily from the
proceeds of various share issuances. As a result of the Company
being in the early stages of operations, the recoverability of
assets on the balance sheet will be dependent on the
Companys ability to obtain additional financing and to
attain a level of profitable operations.
Use of
Estimates
The preparation of these consolidated financial statements
requires the use of certain estimates by management in
determining the Companys assets, liabilities, revenues and
expenses. Actual results could differ from such estimates.
Depreciation, depletion and amortization of oil and gas
properties and the impairment of oil and gas properties are
determined using estimates of oil and gas reserves. There are
numerous uncertainties in estimating the quantity of reserves
and in projecting the future rates of production and timing of
development expenditures, including the timing and costs
associated with the Companys asset retirement obligations.
Oil and gas reserve engineering must be recognized as a
subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way. Proved
reserves of oil and natural gas are estimated quantities that
geological and engineering data demonstrate with reasonable
certainty to be recoverable in the future from known reservoirs
under existing conditions.
Revenue
Recognition and Customer Concentration
All revenue from gas sales is recognized after the gas is
produced and delivery takes place. The Company currently sells
all of its gas to one gas marketing company, Atmos Energy
Marketing, LLC. Although the Company sells all of its production
to a single purchaser, there are numerous other purchasers in
the Illinois Basin to whom the
F-8
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Company believes it could sell its production; therefore, the
loss of its single purchaser would not adversely affect the
Companys operations.
Investments
in Unconsolidated Entities
The equity method of accounting is used to account for
investments in and earnings or losses of affiliates that the
Company does not control, but over which it does exert
significant influence. The cost method of accounting is used for
all other non-controlled investments. The Company used the cost
method to account for its indirect interest in the Jericho
Project through its 49% interest in Hite Coalbed Methane, L.L.C.
(HCM), as the Company did not exert significant
influence over HCM. As described in note 4 below, the
Company sold its investment in HCM during the fiscal year ended
July 31, 2006 and recognized a gain on the sale in the
amount of $127,416. The Company considers whether the fair
values of any of its investments have declined below their
carrying value whenever adverse events or changes in
circumstances indicate that recorded values may not be
recoverable. If the Company considered any such decline to be
other than temporary, a write-down would be recorded to
estimated fair value.
Cash
and Cash Equivalents
Cash and cash equivalents consist of highly liquid investments
with a maturity date of three months or less when purchased and
are carried at cost, which approximates fair value.
Accounts
Receivable
Accounts receivable represents amounts due from Atmos Energy
Marketing, LLC for gas sales. Management regularly reviews
accounts receivable to determine whether amounts are collectible
and records a valuation allowance to reflect managements
best estimate of any amount that may not be collectible. At
July 31, 2006 and 2005, the Company has determined that no
allowance for uncollectible receivables was necessary.
Fair
Value of Financial Instruments
The carrying amount reported in the balance sheet for cash,
accounts receivable, accounts payable and accrued liabilities
approximates fair value because of the immediate or short-term
maturity of these financial instruments.
The carrying amount of long-term notes payable approximates fair
value based on current rates available to the Company for
instruments of the same remaining terms and maturities.
Oil
and Gas Properties
The Company follows the full cost method of accounting for oil
and gas properties. Under this method, all costs associated with
the acquisition of, exploration for and development of oil and
gas reserves are capitalized in cost centers on a
country-by-country
basis (currently the Company has one cost center, the United
States). Such costs include lease acquisition costs, geological
and geophysical studies, carrying charges on non-producing
properties, costs of drilling both productive and non-productive
wells, and overhead expenses directly related to these
activities. Internal costs associated with oil and gas
activities that are not directly attributable to acquisition,
exploration or development activities are expensed as incurred.
Unproved oil and gas properties and major development projects
are excluded from amortization until a determination of whether
proved reserves can be assigned to the properties or impairment
occurs. Unproved properties are assessed at least annually to
ascertain whether an impairment has occurred. Sales or
dispositions of properties are credited to their respective cost
centers and a gain or loss is recognized when all the properties
in a cost center have been disposed of, unless such sale or
disposition significantly alters the relationship between
capitalized costs and proved reserves attributable to the cost
center.
F-9
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Capitalized costs of proved oil and gas properties, including
estimated future costs to develop the reserves and estimated
abandonment cost, net of salvage, are amortized on the
units-of-production
method using estimates of proved reserves.
A ceiling test is applied to each cost center by comparing the
net capitalized costs, less related deferred income taxes, to
the estimated future net revenues from production of proved
reserves, discounted at 10%, plus the costs of unproved
properties net of impairment. Any excess capitalized costs are
written-off in the current year. The calculation of future net
revenues is based upon prices, costs and regulations in effect
at each year end.
In general, the Company determines if an unproved property is
impaired if one or more of the following conditions exist:
i) there are no firm plans for further drilling on the
unproved property;
ii) negative results were obtained from studies of the
unproved property;
iii) negative results were obtained from studies conducted
in the vicinity of the unproved property;
iv) the remaining term of the unproved property does not
allow sufficient time for further studies or drilling.
No impairment existed as of July 31, 2006 and 2005.
Other
Property and Equipment
Other property and equipment are stated at cost. Gas collection
equipment primarily represents flowlines purchased and installed
to transport the CBM from the wells to the compressor station.
Support equipment includes vehicles, machinery and other
equipment used in oil and gas activities. Other equipment
primarily includes office furniture and fixtures and computer
equipment. Gas collection equipment is depreciated on the
units-of-production
method using estimates of proved reserves. Support equipment and
other property and equipment are depreciated using the
straight-line method over the estimated useful lives of the
assets, ranging from three to ten years. Major classes of other
property and equipment consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
Other Property and Equipment:
|
|
|
|
|
|
|
|
|
Gas collection equipment
|
|
$
|
4,342,400
|
|
|
$
|
1,332,012
|
|
Support equipment
|
|
|
1,046,989
|
|
|
|
760,467
|
|
Other
|
|
|
347,862
|
|
|
|
76,321
|
|
Less: Accumulated depreciation and
amortization
|
|
|
(631,015
|
)
|
|
|
(398,988
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,106,236
|
|
|
$
|
1,769,812
|
|
|
|
|
|
|
|
|
|
|
F-10
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Accrued
Liabilities
Accrued liabilities consist of the following:
|
|
|
|
|
|
|
|
|
|
|
At July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
Employee compensation
|
|
$
|
467,869
|
|
|
$
|
|
|
Professional fees
|
|
|
111,805
|
|
|
|
|
|
Directors fees
|
|
|
31,000
|
|
|
|
|
|
Other
|
|
|
34,428
|
|
|
|
31,405
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
645,102
|
|
|
$
|
31,405
|
|
|
|
|
|
|
|
|
|
|
Asset
Retirement Obligations
The Company follows Statement of Financial Accounting Standards
(SFAS) No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 requires the Company to
record the fair value of an asset retirement obligation as a
liability in the period in which it is incurred, if a reasonable
estimate of fair value can be made. The present value of the
estimated asset retirement costs is capitalized as part of the
carrying amount of the associated long-lived asset. Amortization
of the capitalized asset retirement cost is computed on a
units-of-production
method. Accretion of the asset retirement obligation is
recognized over time until the obligation is settled. The future
cash outflows associated with settling the asset retirement
obligations accrued on the accompanying consolidated balance
sheets are excluded from the ceiling test calculation. The
Companys asset retirement obligations relate to the
plugging of wells upon exhaustion of gas reserves. The Company
assessed its asset retirement obligation in prior periods and
deemed it to be immaterial. The initial liability for our asset
retirement obligations was recorded as of August 1, 2005 in
the amount of $34,708.
The following table summarizes the activity for the
Companys asset retirement obligations for the fiscal year
ended July 31, 2006:
|
|
|
|
|
Asset retirement obligation at
beginning of period
|
|
$
|
34,708
|
|
Accretion expense
|
|
|
3,072
|
|
Change in estimates
|
|
|
7,952
|
|
Liabilities incurred
|
|
|
25,022
|
|
|
|
|
|
|
Asset retirement obligation at end
of period
|
|
$
|
70,754
|
|
|
|
|
|
|
Accounting
for Long-Lived Assets
The Company follows Statement of Financial Accounting Standards
No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets (SFAS No. 144). Under
SFAS No. 144, all long-lived assets are tested for
recoverability whenever events or changes in circumstances
indicate that their carrying value may not be recoverable. The
carrying amount of a long-lived asset is not recoverable if it
exceeds the sum of the undiscounted cash flows expected to
result from its use and eventual disposition. An impairment loss
is recognized when the carrying value of a long-lived asset is
not recoverable and exceeds its fair value.
Income
Taxes
Income taxes are accounted for under the asset and liability
method that requires deferred income taxes to reflect the future
tax consequences attributable to differences between the tax and
financial reporting bases of assets and liabilities. Deferred
tax assets and liabilities recognized are based on the tax rates
in effect in the year in which differences are expected to
reverse. Deferred tax assets are reduced by a valuation
allowance when, in the opinion of
F-11
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
management based on available evidence, it is more likely than
not that some or all of any net deferred tax assets will not be
realized.
Share-Based
Payment
Prior to December 13, 2005, the Company administered a
stock-based compensation plan (the Incentive Stock Option
Plan) under which stock options were issued to directors,
officers, employees and consultants as determined by the Board
of Directors and subject to the provisions of the Incentive
Stock Option Plan. The Incentive Stock Option Plan permitted
options to be issued with exercise prices at a discount to the
market price of the Companys common shares on the day
prior to the date of grant. However, the majority of all stock
options issued under the Incentive Stock Option Plan were issued
with exercise prices equal to the quoted market price of the
stock on the date of grant. Options granted under the Incentive
Stock Option Plan vested immediately and were exercisable over a
period not exceeding five years. The Company had 1,823,265
options outstanding under the Incentive Stock Option Plan at
July 31, 2006.
On December 13, 2005, the shareholders of the Company
approved the 2005 Omnibus Stock Plan (the Omnibus Stock
Plan) and it became effective on that date. The Omnibus
Stock Plan replaces the Incentive Stock Option Plan under which
stock options were previously granted. The Omnibus Stock Plan is
administered by the Compensation Committee of the Board of
Directors (the Committee) and will remain in effect
for five years. All employees and directors of the Company and
its subsidiaries, and all consultants or agents of the Company
designated by the Committee, are eligible to participate in the
Omnibus Stock Plan. The Committee has authority to: grant
awards; select the participants who will receive awards;
determine the terms, conditions, vesting periods and
restrictions applicable to the awards; determine how the
exercise price is to be paid; modify or replace outstanding
awards within the limits of the Omnibus Stock Plan; accelerate
the date on which awards become exercisable; waive the
restrictions and conditions applicable to awards; and establish
rules governing the Omnibus Stock Plan. No options have been
issued under the Omnibus Stock Plan. During the current fiscal
year, the Committee granted stock awards under the Omnibus Stock
Plan in the form of restricted and unrestricted stock to
employees and directors of the Company. The transactions
involving the granting of these stock awards are described more
fully in Note 11.
In December 2004, the FASB issued SFAS No. 123(R),
Share-Based Payment. This Statement revises
SFAS No. 123, Accounting for Stock-Based
Compensation and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees.
SFAS No. 123(R) focuses primarily on the accounting
for transactions in which an entity obtains employee services in
share-based payment transactions. The key provision of
SFAS No. 123(R) requires companies to record
share-based payment transactions as compensation expense at fair
market value based on the grant-date fair value of those awards.
Previously under SFAS 123, companies had the option of
either recording expense based on the fair value of stock
options granted or continuing to account for stock-based
compensation using the intrinsic value method prescribed by APB
No. 25.
The Company adopted SFAS No. 123(R), using the
modified-prospective method, effective August 1, 2005.
Since August 1, 2001, the Company followed the fair value
provisions of SFAS 123 and recorded all share-based payment
transactions as compensation expense at fair market value based
on the grant-date fair value of those awards. In addition, all
stock options previously granted by the Company vested
immediately on the date of grant and, thus, there was no
unvested portion of previous stock option grants that vested
during the fiscal year ended July 31, 2006. Therefore,
SFAS 123(R) had no impact on the Companys
consolidated financial position or results of operations for the
fiscal year ended July 31, 2006. The Company uses the
Black-Scholes formula to estimate the fair value of stock
options granted.
Loss
Per Share
Basic loss per share is calculated using the weighted average
number of common shares outstanding during the year. Diluted
loss per share reflects the potential dilution that could occur
if securities or other contracts to issue
F-12
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
common shares were exercised or converted into common shares.
Restricted common shares granted are included in the computation
only after the shares become fully vested. Diluted loss per
share is not disclosed as it is anti-dilutive. Outstanding
options, warrants and unvested shares of restricted stock that
were excluded from the computation of diluted loss per share, as
the effect of their assumed exercises/vesting would be
anti-dilutive, totaled 9,057,188, 15,786,491 and 10,427,910 at
July 31, 2006, 2005 and 2004, respectively.
Reclassifications
Certain items included in prior years consolidated
financial statements have been reclassified to conform to
current year presentation.
Impact
of Recently Issued Accounting Standards Not Yet
Adopted
In June 2006, the FASB issued FASB Interpretation Number 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109. This
Interpretation clarifies the accounting for uncertainty in
income taxes recognized in an enterprises financial
statements in accordance with FASB Statement No. 109,
Accounting for Income Taxes. This Interpretation is
effective for fiscal years beginning after December 15,
2006. The Company is currently assessing the effect of this
Interpretation, if any, on its consolidated financial statements.
The Company sold its remaining 432,000 shares of Pyng
Technologies Corp. (Pyng), a TSX Venture listed
public company, during the fiscal year ended July 31, 2005
and recognized a gain on the sale in the amount of $42,276. The
gain is included within other income in the statement of
operations. The Company considered these shares of Pyng to be
trading securities and recorded unrealized holding gains and
losses directly to earnings.
|
|
3.
|
PURCHASE
OF ILLINOIS MINE GAS, L.L.C.
|
On March 3, 2005, the Company purchased the remaining
interest in Illinois Mine Gas, L.L.C. (IMG), a 50%
joint venture with Vessels Coal Gas, Inc. IMG was created to
explore and develop abandoned mine works in the Illinois Basin
for the extraction and sale of methane gas. The Company
previously accounted for its 50% investment in IMG under the
equity method of accounting. The aggregate purchase price of
$899,681 in cash, less cash received in the amount of $42,043,
was assigned entirely to IMGs coal mine methane properties.
|
|
4.
|
SALE OF
INVESTMENT IN HITE COALBED METHANE, L.L.C.
|
On January 4, 2006, the Company sold its 49% interest in
Hite Coalbed Methane, L.L.C. (HCM) for $551,000 in
cash and cancellation of the Companys convertible note
payable in the amount of $392,000, plus accrued interest of
$31,182. The note was convertible into 390,537 of the
Companys common shares. The Company accounted for its
investment in HCM under the cost method of accounting. The total
consideration received of $974,182 resulted in a gain on the
sale of the investment of $127,416, which is included in other
income in the Companys statement of operations for the
fiscal year ended July 31, 2006. The Company also received
its final distribution of net income from HCM during the fiscal
year ended July 31, 2006 in the amount of $51,452, which is
included as part of other income (expense), net in the statement
of operations for the fiscal year ended July 31, 2006.
The Company negotiated an agreement (Agreement) with
one of its surface rights owners to ensure the Companys
access to its wells and gas gathering systems. As part of the
Agreement, the Company deposited $100,000 in a trust account to
serve as a performance bond to ensure the Company performs its
obligations under the terms of the Agreement. The Company has
recorded this amount as a non-current asset at July 31,
2006 and 2005.
F-13
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
6.
|
LONG-TERM
NOTES PAYABLE
|
The Company has outstanding notes payable as follows:
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
Case Credit term note due in
fiscal year 2007, 6.50%
|
|
$
|
15,410
|
|
|
$
|
32,833
|
|
GMAC term note due in fiscal year
2009, 6.50%
|
|
|
20,608
|
|
|
|
26,633
|
|
GMAC term notes due in fiscal year
2010, 6.1% to 6.50%
|
|
|
80,849
|
|
|
|
98,356
|
|
Convertible note due in fiscal
year 2008, 3.25%
|
|
|
|
|
|
|
392,000
|
|
Caterpillar Financial Services
term note due in fiscal year 2007, 7.0%
|
|
|
99,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
216,015
|
|
|
|
549,822
|
|
Less current maturities
|
|
|
(140,866
|
)
|
|
|
(42,227
|
)
|
|
|
|
|
|
|
|
|
|
Long-term notes payable
|
|
$
|
75,149
|
|
|
$
|
507,595
|
|
|
|
|
|
|
|
|
|
|
The notes are collateralized by the related vehicles and
equipment. The convertible note payable outstanding at
July 31, 2005 was issued in June 2003 with a face value of
$392,000 and maturing on June 10, 2008, bearing interest at
3.25%, convertible at the option of the holder, prior to
June 10, 2008, into 390,537 common shares of the Company.
The convertible note payable was cancelled on January 4,
2005 pursuant to the sale of the Companys interest in Hite
Coalbed Methane, L.L.C. see Note 4.
The annual maturities of all notes for the five fiscal years
subsequent to July 31, 2006 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal
|
|
|
Interest
|
|
|
Total
|
|
|
2007
|
|
$
|
140,866
|
|
|
$
|
7,735
|
|
|
$
|
148,601
|
|
2008
|
|
|
27,982
|
|
|
|
3,855
|
|
|
|
31,837
|
|
2009
|
|
|
29,767
|
|
|
|
2,070
|
|
|
|
31,837
|
|
2010
|
|
|
17,400
|
|
|
|
440
|
|
|
|
17,840
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
216,015
|
|
|
$
|
14,100
|
|
|
$
|
230,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The income tax benefit consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Current
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
(581,582
|
)
|
|
|
(239,314
|
)
|
U.S. state taxes
|
|
|
|
|
|
|
(142,888
|
)
|
|
|
(58,797
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income taxes
|
|
|
|
|
|
|
(724,470
|
)
|
|
|
(298,111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax benefit
|
|
$
|
|
|
|
$
|
(724,470
|
)
|
|
$
|
(298,111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-14
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
A reconciliation of income tax computed at the statutory
Canadian tax rate and the Companys effective rate is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Statutory Canadian income tax rate
|
|
|
(36.00
|
)%
|
|
|
(36.00
|
)%
|
|
|
(36.00
|
)%
|
Stock-based compensation
|
|
|
(4.71
|
)%
|
|
|
19.66
|
%
|
|
|
6.39
|
%
|
Non-deductible stock issuance costs
|
|
|
2.10
|
%
|
|
|
1.43
|
%
|
|
|
|
%
|
Current year Canadian loss with no
tax benefit
|
|
|
4.61
|
%
|
|
|
2.32
|
%
|
|
|
6.14
|
%
|
Net change in deductible temporary
differences due to foreign currency conversion and expired losses
|
|
|
3.16
|
%
|
|
|
(5.38
|
)%
|
|
|
(4.47
|
)%
|
Increase in valuation allowance
|
|
|
43.44
|
%
|
|
|
7.32
|
%
|
|
|
2.57
|
%
|
Other
|
|
|
(3.38
|
)%
|
|
|
(1.19
|
)%
|
|
|
(1.95
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
|
%
|
|
|
(11.84
|
)%
|
|
|
(27.32
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The components of the net deferred tax liability at
July 31, 2006 and 2005 are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31, 2006
|
|
|
|
United States
|
|
|
Canada
|
|
|
Total
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
11,363,979
|
|
|
$
|
513,104
|
|
|
$
|
11,877,083
|
|
Stock-based compensation
|
|
|
769,416
|
|
|
|
|
|
|
|
769,416
|
|
Resource related allowances
|
|
|
|
|
|
|
1,762,037
|
|
|
|
1,762,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax
asset
|
|
|
12,133,395
|
|
|
|
2,275,141
|
|
|
|
14,408,536
|
|
Valuation allowance
|
|
|
(4,465,611
|
)
|
|
|
(2,275,141
|
)
|
|
|
(6,740,752
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
7,667,784
|
|
|
|
|
|
|
|
7,667,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property plant and equipment
|
|
|
(7,667,784
|
)
|
|
|
|
|
|
|
(7,667,784
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax
liability
|
|
|
(7,667,784
|
)
|
|
|
|
|
|
|
(7,667,784
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31, 2005
|
|
|
|
United States
|
|
|
Canada
|
|
|
Total
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
4,130,549
|
|
|
$
|
643,332
|
|
|
$
|
4,773,881
|
|
Resource related allowances
|
|
|
|
|
|
|
1,705,249
|
|
|
|
1,705,249
|
|
Investments and advances to
subsidiaries
|
|
|
|
|
|
|
375,215
|
|
|
|
375,215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax
asset
|
|
|
4,130,549
|
|
|
|
2,723,796
|
|
|
|
6,854,345
|
|
Valuation allowance
|
|
|
(261,405
|
)
|
|
|
(2,640,396
|
)
|
|
|
(2,901,801
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
3,869,144
|
|
|
|
83,400
|
|
|
|
3,952,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property plant and equipment
|
|
|
(3,869,144
|
)
|
|
|
(83,400
|
)
|
|
|
(3,952,544
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax
liability
|
|
|
(3,869,144
|
)
|
|
|
(83,400
|
)
|
|
|
(3,952,544
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-15
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Company considers the need to record a valuation allowance
against deferred tax assets on a
country-by-country
basis, taking into account the effects of local tax law. A
valuation allowance is not recorded when it is determined that
sufficient positive evidence exists to demonstrate that it is
more likely than not that a deferred tax asset will be realized.
The main factors considered are: (1) the nature, amount and
expected timing of reversal of taxable temporary differences,
and (2) opportunities to implement tax plans that affect
whether tax assets can be realized. A valuation allowance has
been recorded against the net deferred tax assets as of
July 31, 2006 and 2005 because the Company believes it is
more likely than not it will be unable to realize the benefit of
these assets.
An increase in the U.S. valuation allowance of $4,204,206
has been recorded during the current fiscal year to reduce the
amount of the U.S. deferred tax assets to an amount equal
to the recorded U.S. deferred tax liabilities. A decrease
in the Canadian valuation allowance of $365,255 has been
recorded during the current fiscal year to reflect miscellaneous
income and the expiration of net operating losses in Canada.
Historically, the Company has had no income generating
operations in Canada and any future income is too uncertain to
justify not recording a valuation allowance.
The Companys net operating loss carryforwards at
July 31, 2006 expire as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2009
|
|
|
2010
|
|
|
2011 and Later
|
|
|
Total
|
|
|
Canadian
|
|
$
|
234,848
|
|
|
$
|
296,493
|
|
|
$
|
893,949
|
|
|
$
|
1,425,290
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
29,138,408
|
|
|
|
29,138,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
234,848
|
|
|
$
|
296,493
|
|
|
$
|
30,032,357
|
|
|
$
|
30,563,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At July 31, 2006 the Company also has $4,894,546 of
Canadian resource related deductions that have no expiration
date.
Common shares The Company has authorized
200,000,000 shares without par value, of which 70,812,540
and 43,912,961 were issued and outstanding as of July 31,
2006 and 2005, respectively. Shares issued and outstanding at
July 31, 2006 include 2,325,000 of restricted shares, of
which 402,677 have vested as of July 31, 2006.
Additional paid-in capital Amounts recorded
of $5,871,120 and $4,493,680 at July 31, 2006 and 2005,
respectively, represent the cumulative amounts charged to
stock-based compensation expense as of each fiscal year-end.
Common shares issuable Amount recorded of
$271,440 at July 31, 2004 represents proceeds received in
advance of the exercise of warrants to purchase common shares.
In September 2005, the Company sold 18,000,000 common shares in
a private placement. The proceeds from this private placement of
$27,883,954, net of $2,619,953 of share issuance costs, are
being used to fund the Companys plan of operations and for
working capital and general corporate purposes.
During fiscal year 2005, the Company issued
10,372,000 shares at $1.25 per share with
5,186,000 share purchase warrants exercisable at $1.50 for
a period of two years (Investor Warrants). The
Companys agent received a commission of 5% and 1,037,200
broker warrants exercisable at $1.25 for a period of two years
(Agent Warrants). The shares and warrants, when
issued, were restricted under the U.S. Securities Act, and
the Company was required to register the resale of the shares
and the shares underlying the warrants with the Securities and
Exchange Commission. Upon registration of the shares underlying
the warrants and the delisting of such shares from the TSX
Venture Exchange, the Investor Warrants were extended to be
exercisable for two years after such listing and the Agent
warrants were extended to be exercisable for five years after
the closing of the share placement.
F-16
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Share purchase warrants outstanding at July 31, 2006 are as
follows:
|
|
|
|
|
|
|
|
|
Number
|
|
|
Exercise
|
|
|
|
Outstanding
|
|
|
Price
|
|
|
Expiry Date
|
|
|
4,274,400
|
|
|
$
|
1.50
|
|
|
December 13, 2007
|
|
643,200
|
|
|
$
|
1.25
|
|
|
December 31, 2009
|
|
394,000
|
|
|
$
|
1.25
|
|
|
January 12, 2010
|
|
|
|
|
|
|
|
|
|
|
5,311,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.
|
COMMITMENTS
AND CONTINGENCIES
|
The Company has operating lease commitments expiring at various
dates. Such leases generally contain renewal options. At
July 31, 2006, future minimum lease payments under
non-cancellable operating leases are as follows:
|
|
|
|
|
2007
|
|
$
|
219,141
|
|
2008
|
|
|
123,714
|
|
2009
|
|
|
87,371
|
|
2010
|
|
|
14,600
|
|
2011
|
|
|
15,184
|
|
Thereafter
|
|
|
262,557
|
|
|
|
|
|
|
|
|
$
|
722,567
|
|
|
|
|
|
|
The leases are principally for office space and gas collection
equipment. Rental payments for all operating leases amounted to
approximately $143,000 during the fiscal year ended
July 31, 2006.
Certain of the Companys mineral leases and farm-out
agreements are subject to annual minimum royalty payments
required to hold the mineral leases and farm-out agreements.
Although the Company is not obligated to make these payments
under existing mineral leases and farm-out agreements, these
payments are required to maintain individual leases/farm-out
agreements after the expiration of the initial terms of the
lease/farm-out agreements. The mineral leases/farm-out
agreements in existence as of July 31, 2006 expire at
various dates beginning in November 2007. If the Company were to
pay the total minimum royalty payments due under all mineral
leases/farm-out agreements in existence as of July 31,
2006, the amount would initially total approximately $100,000
annually and could increase to as much as $220,000 annually.
Financial instruments that potentially subject the Company to
concentrations of credit risk consist of cash and cash
equivalents, which are held at one large high quality financial
institution. The Company periodically evaluates the credit
worthiness of the financial institution. The Company has not
incurred any credit risk losses related to its cash and cash
equivalents.
The Company utilizes a limited number of drilling contractors to
perform all of the drilling on its projects. The Company
maintains a limited number of supervisory and field personnel to
oversee drilling and production operations. The Companys
plans to drill additional wells are determined in large part by
the anticipated availability of acceptable drilling equipment
and crews. The Company does not currently have any contractual
commitments that ensure it will have adequate drilling equipment
or crews to achieve its drilling plans. The Company believes
that it can secure the necessary commitments from drilling
companies as required. However, it can provide no assurance that
its expectations regarding the availability of drilling
equipment and crews from these companies will be met. A
F-17
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
significant delay in securing the necessary drilling equipment
and crews could cause a delay in production and sales, which
would affect operating results adversely.
|
|
11.
|
STOCK-BASED
COMPENSATION
|
Stock
Options
The table below summarizes stock options activity for the three
years ended July 31, 2006. All stock options were granted
under the Incentive Stock Option Plan with exercise prices
denominated in Canadian Dollars. U.S. Dollar amounts shown
in the table below were derived using published exchange rates
on the date of the transaction for grants, expirations,
exercises and surrenders and at year-end exchange rates for
options outstanding as of July 31.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
|
|
|
|
|
|
|
Exercise Price
|
|
|
|
Number of Options
|
|
|
CAD$
|
|
|
USD$
|
|
|
Outstanding at July 31, 2003
|
|
|
1,825,000
|
|
|
$
|
0.81
|
|
|
$
|
0.58
|
|
Granted exercise price
less than market price of stock on date of grant
|
|
|
475,000
|
|
|
|
0.65
|
|
|
|
0.49
|
|
Exercised
|
|
|
(69,444
|
)
|
|
|
0.82
|
|
|
|
0.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at July 31, 2004
|
|
|
2,230,556
|
|
|
|
0.78
|
|
|
|
0.59
|
|
Granted exercise price
equals market price of stock on date of grant
|
|
|
3,423,278
|
|
|
|
2.04
|
|
|
|
1.64
|
|
Granted exercise price
less than market price of stock on date of grant
|
|
|
852,778
|
|
|
|
1.19
|
|
|
|
0.96
|
|
Expired
|
|
|
(25,000
|
)
|
|
|
1.20
|
|
|
|
0.98
|
|
Exercised
|
|
|
(2,254,333
|
)
|
|
|
0.87
|
|
|
|
0.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at July 31, 2005
|
|
|
4,227,279
|
|
|
|
1.82
|
|
|
|
1.49
|
|
Granted exercise price
equals market price of stock on date of grant
|
|
|
495,000
|
|
|
|
2.05
|
|
|
|
1.79
|
|
Expired
|
|
|
(320,000
|
)
|
|
|
2.29
|
|
|
|
1.79
|
|
Exercised
|
|
|
(554,014
|
)
|
|
|
1.55
|
|
|
|
1.24
|
|
Exchanged for restricted stock
|
|
|
(2,025,000
|
)
|
|
|
2.23
|
|
|
|
1.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at July 31, 2006
|
|
|
1,823,265
|
|
|
$
|
1.46
|
|
|
$
|
1.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in stock options exercised during fiscal year 2006 are
107,800 stock options surrendered by an officer/director of the
Company in order to exercise 173,250 warrants for the
Companys common stock in lieu of transferring cash. The
transaction occurred on April 28, 2006. The fair value of
the stock options surrendered in this transaction equaled the
total exercise price of the warrants using the Black-Scholes
options pricing model to value the stock options on the date of
the transaction. The assumptions used in the Black-Scholes
option pricing model were as follows:
|
|
|
Risk-free interest rate
|
|
4.75%
|
Expected dividend yield
|
|
Nil
|
Expected stock price volatility
|
|
95%
|
Expected option life
|
|
3.6 years
|
The risk-free interest rate used was based on the
U.S. Treasury yield curve at the time of the transaction.
The expected stock price volatility was based solely on the
historical volatility of the Companys common stock during
F-18
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
the historical period equivalent to the expected option life. In
estimating expected volatility, the Company used a combination
of the historical volatility of its stock for the period that it
began trading on the American Stock Exchange and the historical
volatility of its stock on the TSX Venture Exchange for the
necessary period in order to reflect the expected remaining life
of the stock options. The expected option life represents the
remaining contractual life of the stock options surrendered.
The Company recorded stock-based compensation expense for stock
options granted to employees and directors in the amount of
$527,327, $3,344,738 and $193,796 in fiscal years ended
July 31, 2006, 2005 and 2004, respectively. The fair value
of stock options granted was estimated using the Black-Scholes
option pricing model with the following assumptions:
|
|
|
|
|
|
|
|
|
Year Ended July 31,
|
|
|
2006
|
|
2005
|
|
2004
|
|
Risk-free interest rate
|
|
3.3%
|
|
3.0 - 3.7%
|
|
4.1%
|
Expected dividend yield
|
|
Nil
|
|
Nil
|
|
Nil
|
Expected stock price volatility
|
|
95%
|
|
69-81%
|
|
105%
|
Expected option life
|
|
3 years
|
|
3 years
|
|
5 years
|
The risk-free interest rate for periods within the contractual
life of the options was based on the U.S. Treasury yield
curve in effect at the time of grant for options granted during
fiscal year 2006 and based on the equivalent Canadian rate in
prior fiscal years. The expected stock price volatility is based
solely on the historical volatility of the Companys common
stock during the historical period equivalent to the expected
option life. In estimating expected volatility, the Company used
the historical volatility of its stock on the TSX Venture
Exchange as the Company had not yet began trading on the AMEX at
the time the options were granted. The expected option life
represents the Companys best estimate of the time that
options granted are expected to be outstanding based on prior
experience.
The weighted average fair value per option at the date of the
grant for options granted in fiscal years ended July 31,
2006, 2005 and 2004 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Exercise price equals market price
of stock on date of grant
|
|
$
|
1.07
|
|
|
$
|
0.81
|
|
|
$
|
|
|
Exercise price is less than market
price of stock on date of grant
|
|
|
|
|
|
|
0.66
|
|
|
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total grants
|
|
$
|
1.07
|
|
|
$
|
0.78
|
|
|
$
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option pricing models require the input of highly subjective
assumptions, particularly as to the expected price volatility of
the stock. Changes in these assumptions can materially affect
the fair value estimate, and therefore it is managements
view that the existing models do not necessarily provide a
single reliable measure of the fair value of the Companys
stock option grants.
F-19
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes information about options
outstanding as of July 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise
|
|
|
Number
|
|
|
Remaining
|
|
|
|
Price CAD$
|
|
|
Outstanding
|
|
|
Life (Years)
|
|
|
Expiry Date
|
|
$
|
0.65
|
|
|
|
345,000
|
|
|
|
2.3
|
|
|
November 3, 2008
|
|
0.90
|
|
|
|
243,334
|
|
|
|
0.4
|
|
|
January 10, 2007
|
|
0.90
|
|
|
|
10,000
|
|
|
|
3.1
|
|
|
September 22, 2009
|
|
1.20
|
|
|
|
50,000
|
|
|
|
0.4
|
|
|
January 10, 2007
|
|
1.49
|
|
|
|
695,666
|
|
|
|
3.3
|
|
|
November 29, 2009
|
|
2.05
|
|
|
|
10,000
|
|
|
|
4.1
|
|
|
September 23, 2010
|
|
2.19
|
|
|
|
136,000
|
|
|
|
3.7
|
|
|
March 27, 2010
|
|
2.40
|
|
|
|
333,265
|
|
|
|
3.5
|
|
|
January 20, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.46
|
|
|
|
1,823,265
|
|
|
|
2.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
Stock Awards and Grants of Common Shares
On April 12, 2006, the Compensation Committee approved an
exchange of common shares for outstanding stock options held by
various key employees and directors of the Company (Option
Exchange). The Option Exchange effectively cancelled stock
option awards for 2,025,000 of the Companys common shares
previously granted during fiscal years ended 2005 and 2006. The
Option Exchange replaced the cancelled options with restricted
stock awards of 2,025,000 of the Companys common shares.
The restrictions on the shares of restricted stock are scheduled
to lapse on three separate dates as follows:
|
|
|
|
|
January 1, 2007
|
|
|
680,000 shares
|
|
January 1, 2008
|
|
|
680,000 shares
|
|
January 1, 2009
|
|
|
665,000 shares
|
|
The Company accounted for the Option Exchange as a modification
of the original shared-based payment awards (stock options) in
accordance with SFAS No. 123(R). Accordingly, the
Company recorded compensation expense based on the excess of the
fair value of the restricted stock award grants over the fair
value of the original award (stock options) measured immediately
before the transaction based on current circumstances. The fair
value of the restricted stock awards was determined based on the
number of shares granted and the quoted price of the
Companys common shares on the date of the grant of
$1.42 per share. The value of the stock options surrendered
was computed immediately before the modification using the
Black-Scholes valuation model with the following assumptions:
|
|
|
Risk-free interest rate
|
|
4.75%
|
Expected dividend yield
|
|
Nil
|
Expected stock price volatility
|
|
94% - 98%
|
Expected option remaining life
|
|
3.8 - 4.5 years
|
The risk-free interest rate used was based on the
U.S. Treasury yield curve at the time of the transaction.
The expected stock price volatility was based solely on the
historical volatility of the Companys common stock during
the historical period equivalent to the expected option life. In
estimating expected volatility, the Company used a combination
of the historical volatility of its stock for the period that it
began trading on the American Stock Exchange and the historical
volatility of its stock on the TSX Venture Exchange for the
necessary period in order to reflect the expected remaining life
of the stock options. The expected option life represents the
remaining contractual life of the stock options surrendered.
F-20
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Option Exchange resulted in incremental compensation expense
of $989,650, which will be recognized over the requisite service
period. The Company recorded $139,728 of compensation expense
related to the Option Exchange in the fiscal year ended
July 31, 2006. Future amortization of the unearned
incremental compensation expense will result in additional
compensation expense of $385,621, $303,216 and $118,294 in
fiscal years ended July 31, 2007, 2008 and 2009,
respectively.
On April 28, 2006, the vesting of 84,163 shares of
restricted stock issued to an officer/director of the Company in
the Option Exchange described above was accelerated and the
shares were surrendered by the officer/director in order to
exercise 165,000 warrants for the Companys common stock in
lieu of transferring cash. The accelerated vesting of the
restricted stock resulted in $42,790 of compensation expense
which was recorded in fiscal year 2006. The fair value of the
stock surrendered in this transaction equalled the total
exercise price of the warrants using the quoted market price of
the Companys stock on the AMEX from the previous day to
value the stock surrendered.
On April 12, 2006, the Company granted 300,000 shares
of restricted stock and 300,000 unrestricted common shares to
its newly hired Senior Vice President of Operations. The grant
was made outside the Omnibus Stock Plan in accordance with AMEX
Company Guide Rule 711. The fair value of the restricted
stock was determined based on the number of shares granted and
the quoted price of the Companys common shares on the date
of the grant of $1.42 per share. The restrictions on the
shares of restricted stock are scheduled to lapse on three
separate dates in the amount of 100,000 shares each on
April 12, 2007, 2008 and 2009. The grant of restricted
stock resulted in compensation expense of $426,000, which will
be recognized over the requisite service period. The Company
recorded $42,795 of compensation expense related to this grant
of restricted stock in the fiscal year ended July 31, 2006.
Future amortization of the unearned compensation expense will
result in additional compensation expense of $142,000, $142,000
and $99,205 in fiscal years ended July 31, 2007, 2008 and
2009, respectively. The Company recorded the fair value of the
award of unrestricted common shares of $426,000 as compensation
expense in the fiscal year ended July 31, 2006.
On April 12, 2006, the Company granted 140,000 unrestricted
common shares to a newly appointed director. The Company
recorded the fair value of the award of unrestricted common
shares of $198,800 as compensation expense in the quarter ended
April 30, 2006.
All restricted stock awards are subject to continuous
employment. However, in the event employment is terminated
before the restrictions lapse by reason of death, total
disability or retirement, the restrictions will lapse on the
date of termination as to a pro-rata portion of the number of
shares of restricted stock scheduled to lapse on the next lapse
date, based on the number of days continuously employed during
the applicable vesting period. The Company includes all shares
of restricted stock in common shares outstanding when issued,
but only includes the vested portion of such shares in the
computation of basic earnings per share.
The Companys policy is to issue new shares to satisfy
stock option exercises and restricted stock grants upon
receiving approval from the AMEX for the issuance of such shares.
On March 15, 2006, the Company filed a complaint against
Colt LLC and other defendants alleging tortious interference
with business relations and breach of contract relating to the
interruptions of its development plans at the Companys
Southern Illinois Basin Project. The Company sought a
preliminary injunction (which was denied by the court) against
Colt LLC and related parties from terminating the lease
agreement covering its CBM rights in 43,000 acres at the
Southern Illinois Basin Project or taking any other action that
interferes with the Companys right to produce CBM under
the lease agreement, pending a final judgment on the merits of
the complaint.
On April 5, 2006, Colt filed an answer and counterclaim in
response to the Companys complaint. In its counterclaim,
Colt sought a declaratory judgment asking the court to declare,
among other things, that: (a) the Company committed
multiple breaches of the lease agreement; (b) the lease
agreement automatically terminated due to the Companys
failure to cure its alleged breaches; (c) the lease
agreement automatically terminated by its
F-21
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
own terms on April 3, 2006; and (d) to the extent the
lease agreement already terminated, the Company is wrongfully
holding over
and/or
trespassing and Colt is entitled to an award of damages as a
result.
In June 2006, the Company reached a settlement with the
defendants in this lawsuit. The following list summarizes the
key terms of the settlement:
1. All parties released all the other parties from any
claims they may have had against each other;
2. The Company paid Colt $3,000,000;
3. The Company surrendered any interest it had in the lease;
4. The Company acquired ownership of the CBM estate
covering approximately 10,000 of the 43,000 acres
previously covered by the lease (which acreage includes all of
our producing CBM wells and proved reserves at our Southern
Illinois Basin Project);
5. The Company was relieved of any future obligation to
make royalty payments as was previously required under the terms
of the lease (under the terms of the lease the Company was
obligated to make royalty payments of 15% of gross sales and
minimum royalties totaling at least $42,000 per
month); and
6. The deed made clear that CBM operations take priority
over coal mining operations for as long as CBM is being produced
from the covered acreage; however, Colt has the right to acquire
any CBM wells located in these 10,000 acres. If Colt
exercises this option, it will be required to pay the fair
market value (as established by a mutually agreed upon expert)
of such well (which fair market value will include the value of
any reserves that can be produced by such well).
In conjunction with this proposed settlement, during the fiscal
year ended July 31, 2006 the Company recorded $2,951,608 as
other expense and reclassified $2,225,816 from the cost of
Unevaluated Properties to the cost of Proved Properties to
recognize the impairment resulting from the loss of
approximately 33,000 acres of mineral rights.
|
|
13.
|
OTHER
INCOME (EXPENSE), NET
|
Other income (expense), net consisted of the following for the
fiscal years ended July 31, 2006, 2005 and 2004,
respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Legal settlement with Colt LLC
|
|
$
|
(2,951,608
|
)
|
|
$
|
|
|
|
$
|
|
|
Gain on sale of investment in HCM
|
|
|
127,416
|
|
|
|
|
|
|
|
|
|
Gain on sale of marketable
securities trading
|
|
|
|
|
|
|
42,276
|
|
|
|
2,454
|
|
Distribution from Hite Coalbed
Methane, L.L.C.
|
|
|
51,452
|
|
|
|
6,615
|
|
|
|
|
|
Other, net
|
|
|
8,297
|
|
|
|
(13,506
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(2,764,443
|
)
|
|
$
|
35,385
|
|
|
$
|
2,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14.
|
OIL AND
GAS PROPERTIES
|
The Companys oil and gas properties are all located in the
United States of America and consist solely of its coalbed
methane projects in the Illinois Basin. The Companys
acreage rights in the Illinois Basin are currently divided into
three projects: the Southern Illinois Basin Project; the
Northern Illinois Basin Project; and the Western Illinois Basin
Project.
F-22
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Southern
Illinois Basin Project
The Companys CBM rights in the Southern Illinois Basin
Project (formerly called the Delta Project) cover approximately
10,000 acres in the southern part of the Illinois Basin.
The Companys CBM rights on this acreage previously covered
approximately 43,000 acres pursuant to a lease agreement,
the primary term of which ended on April 3, 2006. As
described in note 12, the lease was subject to litigation
during the fiscal year ended July 31, 2006 and the Company
reached a settlement with the defendants in the lawsuit,
resulting in the Company acquiring ownership of the CBM estate
free of any royalty interest covering approximately 10,000 of
the 43,000 acres previously covered by the lease (which
acreage includes all of the Companys producing CBM wells
and proved reserves at our Southern Illinois Basin Project). The
Company is still paying two overriding royalty interests of 3%
and 4%, both of which are calculated based on 43.35% of gross
revenues from the project.
Under the terms of the deed covering this acreage, the
Companys right to drill for and produce CBM takes
precedence over coal mining operations for as long as CBM is
being produced from the acreage. However, the owner of the coal
rights has the right to acquire any CBM wells located in these
10,000 acres. If the coal rights owner exercises this option, it
will be required to (i) to immediately plug any such well
so acquired and (ii) pay the fair market value (as
established by a mutually agreed upon expert) of such well.
The Company commenced sales of gas from the initial pilot
production wells on this project in January 2005. As of
July 31, 2006, the Company had drilled 108 wells at
this project. These wells consist of 86 productive wells, 14
shut-in wells, of which eight are scheduled to be plugged in
fiscal year 2007 (as a result of the Colt LLC settlement), four
plugged wells, one disposal well and three wells that have been
drilled but are not yet in production. Most of the wells drilled
at this project were initially completed in a limited number of
seams, intentionally excluding other seams. The Companys
intention when it drilled these wells was to gather as much
geological information as it could about CBM and dewatering
characteristics of individual coal seams. During the fiscal year
ended July 31, 2006, the Company went back and completed
additional seams in most of these wells to begin dewatering and
producing CBM from the additional seams penetrated by these
wells. During fiscal year 2007, we will determine whether it is
beneficial to complete additional seams in the remaining wells.
Northern
Illinois Basin Project
The Companys CBM rights in the Northern Illinois Basin
Project cover 353,531 acres in Montgomery, Shelby,
Christian, Fayette and Macoupin Counties in Illinois, which are
located in the north central part of the Illinois Basin. The
Company holds its CBM rights on this acreage pursuant to mineral
leases, an option to acquire a mineral lease and a farm-out
agreement. As of July 31, 2006, the Company had drilled
15 wells at this project. These wells consist of a recent
10-well
pilot project, one well plugged, one disposal wells and three
test wells.
Montgomery
County Lease
The lease agreement with Montgomery County covers
120,951 acres of CBM rights in Montgomery County, Illinois.
The lease agreement extends until November 27, 2010. After
the initial term of the agreement, the Company can continue to
hold the lease as long as it is producing CBM from the covered
acreage. Under the lease agreement, the Company will be required
to pay royalties to the lessor equal to 12.5% of the
Companys gross proceeds from the sale of CBM produced from
the covered acreage.
Shelby
County Lease
The lease agreement with Shelby County covers 63,250 acres
of CBM rights in Shelby County, Illinois. This lease agreement
extends until November 12, 2008. After the initial term of
the agreement, the Company can continue to hold the lease as
long as it is producing CBM from the covered acreage, with each
productive vertical well holding 320 acres and each
productive horizontal well holding 1,920 acres. The Company
is required to pay
F-23
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
royalties to the lessor equal to 12.5% of the Companys
gross proceeds from the sale of CBM produced from the covered
acreage.
IEC
(Montgomery), LLC Lease
The lease agreement with IEC (Montgomery), LLC covers
approximately 102,000 acres of CBM rights in Christian, Fayette,
Montgomery and Shelby Counties in Illinois. The lease agreement
extends until April 26, 2026. After the initial term of the
agreement, the Company can continue to hold the lease as to each
acreage block where it is producing CBM in commercial
quantities. The Company is required to pay royalties to the
lessor on the Companys gross proceeds from the sale of CBM
produced from the covered acreage at rates ranging up to 12.5%.
Christian
Coal Holdings, LLC Lease
The lease agreement with Christian Coal Holdings, LLC covers
approximately 12,044 acres of CBM rights in Christian and
Montgomery Counties in Illinois. The lease agreement extends
until April 26, 2026. After the initial term of the
agreement, the Company can continue to hold the lease as to each
acreage block where it is producing CBM in commercial
quantities. The Company is required to pay royalties to the
lessor on the Companys gross proceeds from the sale of CBM
produced from the covered acreage at a rate of 12.5%.
Christian
County Option
The Company holds an option from Christian County to lease
14,033 acres of CBM rights in Christian County, Illinois.
The option extends until January 20, 2007. The lease
agreement underlying the option will extend for a period of five
years from the date the Company exercises the option. After the
initial term of the agreement, the Company can continue to hold
the lease as long as it is producing CBM from the covered
acreage. Under the lease agreement, the Company will be required
to pay royalties to the lessor equal to 12.5% of the
Companys gross proceeds from the sale of CBM produced from
the covered acreage.
Addington
Exploration, LLC (Macoupin County) Farm-out Agreement
Also included in the Northern Illinois Basin Project are
41,253 acres of CBM rights in Macoupin County, Illinois,
which the Company can earn under a farm-out agreement with
Addington Exploration, LLC, as described in more detail below.
Under the lease agreements with Montgomery and Shelby Counties
and the lease agreement underlying the option agreement with
Christian County, the Companys right to drill for and
produce CBM is expressly subject to the mining of coal on the
covered acreage. The Company may not interfere with any existing
coal mining operations and, under certain circumstances, may be
required to cease drilling in locations where coal mining
operations will be undertaken.
Under the lease agreements with IEC (Montgomery), LLC and
Christian Coal Holdings, LLC, any drilling operations that the
Company sets up can be displaced by coal mining operations.
However, the lessor is required to provide the Company with a
mine plan for the leased acreage indicating the acreage blocks
that the lessor plans to mine and the order of priority for the
acreage blocks that it plans to mine. If the lessor displaces a
well ahead of the schedule outlined in the mine plan, the lessor
may be required to reimburse the Company for the cost of
plugging the well and, depending on how long the well has been
in production and the cumulative gross income generated by the
well, the value of the CBM that could be recovered from the well
in the remainder of an eight-year term.
As of July 31, 2006, the Company had just recently
completed drilling of a 10-well pilot program at this project,
and all wells were in the initial stages of dewatering as of
that date. As of the same date, the Company has drilled three
test wells at this project. In addition, the Company intends to
drill two additional test wells at this project during the first
quarter of fiscal year 2007.
F-24
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Western
Illinois Basin Project
The Companys CBM rights in the Western Illinois Basin
Project cover 135,948 acres in Clinton, Washington, Marion and
Perry Counties in Illinois, which are located in the
northwestern part of the Illinois Basin. The Company holds its
CBM rights on this acreage pursuant to mineral leases, an
option to acquire a mineral lease and a farm-out agreement.
Clinton
County Lease
The lease agreement with Clinton County covers 55,900 acres
of CBM rights in Clinton County, Illinois. The lease agreement
extends until October 24, 2010. After the initial term of
the agreement, the Company can continue to hold the lease as
long as it is producing CBM from the covered acreage. The
Company is required to pay royalties to the lessor equal to
12.5% of the Companys gross proceeds from the sale of CBM
produced from the covered acreage.
Washington
County Option
The lease agreement with Washington County covers
39,169 acres of CBM rights in Washington County, Illinois.
The lease agreement extends until September 9, 2011. After
the initial term of the agreement, the Company can continue to
hold the lease as long as it is producing CBM from the covered
acreage, with each productive vertical well holding
320 acres and each productive horizontal well holding
1,920 acres. Under the lease agreement, the Company is
required to pay royalties to the lessor from the Companys
gross proceeds from the sale of CBM produced from the covered
acreage. The royalty is equal to 12.5% or 6.25% of the
Companys gross proceeds, depending on whether it is
determined that Washington Counties CBM rights, if any,
are derived from coal rights or oil and gas rights.
Marion
County Option
The Company holds an option from Marion County to lease
17,882 acres of CBM rights in Marion County, Illinois. The
option extends until June 8, 2007. The lease agreement
underlying the option will extend for a period of five years
from the date the Company exercises the option. After the
initial term of the agreement, the Company can continue to hold
the lease as long as it is producing CBM from the covered
acreage. Under the lease agreement, the Company will be required
to pay royalties to the lessor equal to 12.5% of the
Companys gross proceeds from the sale of CBM produced from
the covered acreage. If the Company does not commence
exploration of CBM within one year from the commencement of the
lease, the Company will be required to pay advance royalties to
the lessor equal to $8,941 for each one-year period that the
Company delays commencing exploration. Any payment of advance
royalties can be credited against royalties that may later
become payable to the lessor from the production of CBM.
Addington
Exploration, LLC (Perry County) Farm-out Agreement
The Company entered into a farm-out agreement with Addington
Exploration, LLC covering 41,253 acres of CBM rights in
Macoupin County, Illinois (Northern Illinois Basin) and
22,997 acres of CBM rights in Perry County, Illinois
(Western Illinois Basin) that Addington controls pursuant to
coal seam gas leases. The farm-out agreement provides for an
initial
36-month
evaluation period, during which the Company may test and
evaluate the covered properties. The
36-month
evaluation period can be extended by the Company on unearned
acreage through the payment of a fee equal to $0.50 per
acre, increasing over five years to $2.50 per acre. For
each vertical and horizontal well that the Company places into
production during the term of the agreement, Addington will
assign to the Company its CBM rights covering the surrounding
160 acres penetrated by one of the Companys wells.
The Company is required to pay Addington a royalty equal to 3%
of the Companys proceeds from the sale of CBM produced
from the covered acreage. In addition, the Company must pay
royalties totaling 12.5% to the lessors under the coal seam gas
leases underlying this farm-out agreement.
F-25
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Under the lease agreement with Washington County and the lease
agreement underlying the option agreement with Marion County,
the Companys right to drill for and produce CBM is
expressly subject to the mining of coal on the covered acreage.
The Company may not interfere with any existing coal mining
operations and, under certain circumstances, may be required to
cease drilling in locations where coal mining operations will be
undertaken. Under the lease agreement with Clinton County, coal
mining rights granted to third parties do not take precedence
over the Companys CBM operations.
As of July 31, 2006, the Company has drilled two test wells
at the Western Illinois Basin Project. The Company intends to
drill three test wells at this project during the first quarter
of fiscal year 2007.
The following table sets forth a summary of oil and gas property
costs not being amortized at July 31, 2006, by the fiscal
year in which such costs were incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
|
|
Total
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
and Prior
|
|
|
Property acquisition costs
|
|
$
|
178,072
|
|
|
$
|
|
|
|
$
|
150,771
|
|
|
$
|
27,301
|
|
|
$
|
|
|
Exploration and development, net
of transfers to proved oil and gas properties
|
|
|
3,190,159
|
|
|
|
2,445,674
|
|
|
|
742,005
|
|
|
|
2,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,368,231
|
|
|
$
|
2,445,674
|
|
|
$
|
892,776
|
|
|
$
|
29,781
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No interest has been capitalized and included in the cost of
unproved properties as of July 31, 2003 or in the fiscal
years ended July 31, 2006, 2005 and 2004, as such amounts
were not material. The Company expects to include the costs
associated with unproved properties in its amortization
computation over the next one to three years when future
development of the projects is expected to result in additional
reserves being classified as proved. Depletion expense related
to proved oil and gas properties was $331,150, $58,523 and $0 or
$2.28/Mcf, $1.72/Mcf and $0/Mcf in the fiscal years ended
July 31, 2006, 2005 and 2004, respectively.
|
|
15.
|
RELATED
PARTY TRANSACTIONS
|
The Company enters into various transactions with related
parties in the normal course of business operations.
Randy Oestreich, the Companys Vice President of Field
Operations, owns and operates A-Strike Consulting, a consulting
company that provides, among other things, laboratory testing
related to coalbed methane. Beginning in fiscal year ended
July 31, 2005, the Company owns and maintains a lab testing
facility and allows A-Strike Consulting to operate the facility.
The Company pays all expenses related to the facility and, in
return, receives 80% of the revenue generated from the
operations of the facility as reimbursement of the
Companys expenses. The Company received approximately
$70,000, $59,000 and $0 in expense reimbursement related to this
arrangement during the fiscal years ended July 31, 2006,
2005 and 2004, respectively. Mr. Oestreichs brother
owns Dependable Service Company, a company that provides general
labor services to the Company. The Company paid Dependable
Services Company approximately $237,000, $147,000 and $16,000
during the fiscal years ended July 31, 2006, 2005 and 2004,
respectively.
David Preng, a director of the Company owns Preng &
Associates, an executive search firm specializing in the energy
and natural resources industries. The Company paid
Preng & Associates approximately $293,000, $0 and $0
for executive placement services during the fiscal years ended
July 31, 2006, 2005 and 2004, respectively.
Officer
Resignation
On October 10, 2006, the Company entered into a Separation
Agreement and Waiver and Release (Separation
Agreement) with George Zilich, the Companys Chief
Financial Officer and General Counsel. Under the terms of
F-26
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
the Separation Agreement, Mr. Zilich resigned as an
employee, officer and director of the Company effective
immediately and the Company will provide consideration to
Mr. Zilich for entering into the Separation Agreement as
follows:
|
|
|
|
|
In connection with Mr. Zilichs existing employment
agreement, the Company is required to make a cash payment to
Mr. Zilich in the amount of $250,000 within three business
days of his resignation. Such amount will be recorded as
compensation expense during the first quarter of fiscal year
2007.
|
|
|
|
In connection with Mr. Zilichs existing employment
agreement, provide medical and dental insurance coverage to
Mr. Zilich through the second anniversary of the separation
date. The Company will pay all premiums for such insurance
coverage; provided, however, that if, at any time prior to the
second anniversary of the separation date, Mr. Zilich
becomes eligible to participate in an employer sponsored and
fully paid medical and dental insurance plan or policy with
comparable coverage, the Companys obligation to provide
such coverage will terminate effective as of the date that
Mr. Zilich becomes eligible to enroll in such plan or
policy. Such amounts incurred for the premiums will be charged
to expense as incurred in the future.
|
|
|
|
In connection with a continuing services clause of the
Separation Agreement, the Company is required to issue 40,000
unrestricted common shares to Mr. Zilich within three
business days of his resignation and make cash payments to
Mr. Zilich in the amount of $8,333.33 on each of the
following dates: October 15, 2006; October 31, 2006;
November 15, 2006; November 30, 2006;
December 15, 2006; and December 31, 2006. In return,
Mr. Zilich will provide the Company with consulting
services as may be reasonably requested by the Company from time
to time through January 2, 2008. The Company will recognize
the expense related to these payments over the future period(s)
in which it expects to receive consulting services from
Mr. Zilich.
|
|
|
|
In connection with a non-compete and non-solicitation clause of
the Separation Agreement, the Company is required to make
payments to Mr. Zilich in the amount of $100,000 on each of
the following dates: January 2, 2007; August 1, 2007;
and January 2, 2008. The Company is also required to take
actions to provide that the 380,720 restricted common shares
currently held by Mr. Zilich vest immediately on the
separation date. In return, Mr. Zilich agrees not to
(a) engage, either directly or indirectly, as an employee,
officer or partner in a business that is competitive with the
Companys coal bed methane gas extraction business in the
geographical territory known as the Illinois Basin,
or (b) solicit or attempt to solicit, either on
Zilichs behalf or on behalf of any of third party, or
assist any third party in soliciting, any employee of the
Company to leave or terminate their employment with the Company.
The Company will recognize expense related to these payments
over the future period(s) in which it expects to benefit from
the terms of this agreement.
|
New
Technical Staff Compensation
During the first quarter of fiscal year 2007, the Company added
four new members to its technical team: a Geologist and three
Engineers. As an inducement to join the Company, the Company
paid the new employees a total of $345,000 in signing bonuses
and granted them a total of 350,000 shares of unrestricted
stock (James Erlandson 90,000; Michael
Dawson 100,000; Bradford Sutton 80,000;
and Kelly Sutton 80,000) and 700,000 shares of
restricted stock (James Erlandson 180,000; Michael
Dawson 200,000; Bradford Sutton 160,000;
and Kelly Sutton 160,000). These share grants were
made outside the Omnibus Stock Plan in accordance with AMEX
Company Guide Rule 711. The shares of restricted stock will
vest based on service over a two-year period. In addition, the
total annual salaries of these new employees will be $600,000.
F-27
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
17.
|
SUPPLEMENTAL
GAS DATA (UNAUDITED)
|
The following unaudited information was prepared in accordance
with Statement of Financial Accounting Standards No. 69,
Disclosures About Oil and Gas Producing Activities
and related accounting rules.
The following summaries of changes in reserves and standardized
measure of discounted future net cash flows were prepared from
estimates of proved reserves developed by our independent
reservoir engineer consultant.
Summary
of Changes in Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
MMcf
|
|
|
MMcf
|
|
|
MMcf
|
|
|
Proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
10,292
|
|
|
|
|
|
|
|
|
|
Purchase of reserves in place
|
|
|
2,229
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
4,528
|
|
|
|
10,326
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(2,186
|
)
|
|
|
|
|
|
|
|
|
Production
|
|
|
(145
|
)
|
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
14,718
|
|
|
|
10,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
2,971
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
8,983
|
|
|
|
2,971
|
|
|
|
|
|
Capitalized
Costs Related to Gas Producing Activities
The capitalized costs relating to gas producing activities and
the related accumulated depletion, depreciation and accretion as
of July 31, 2006 and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
Capitalized costs:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
21,098,048
|
|
|
$
|
10,248,652
|
|
Unproved oil and gas properties
|
|
|
3,368,231
|
|
|
|
3,149,372
|
|
Support equipment
|
|
|
1,046,989
|
|
|
|
760,467
|
|
Gas collection
|
|
|
4,342,400
|
|
|
|
1,332,012
|
|
|
|
|
|
|
|
|
|
|
Total capitalized costs
|
|
|
29,855,668
|
|
|
|
15,490,503
|
|
Less: Accumulated DD&A
|
|
|
(922,534
|
)
|
|
|
(426,485
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
28,933,134
|
|
|
$
|
15,064,018
|
|
|
|
|
|
|
|
|
|
|
F-28
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Costs
Incurred in Gas Exploration and Development
Activities
Costs related to gas activities of the Company were incurred as
follows for the fiscal years ended July 31, 2006, 2005 and
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Property acquisition
proved
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Property acquisition
unproved
|
|
|
|
|
|
|
341,634
|
|
|
|
2,664
|
|
Exploration
|
|
|
|
|
|
|
743,811
|
|
|
|
1,778,517
|
|
Development
|
|
|
11,007,725
|
|
|
|
5,541,022
|
|
|
|
|
|
Support equipment
|
|
|
286,522
|
|
|
|
238,153
|
|
|
|
201,643
|
|
Gas collection
|
|
|
3,010,388
|
|
|
|
1,225,113
|
|
|
|
106,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
14,304,635
|
|
|
$
|
8,089,733
|
|
|
$
|
2,089,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior to fiscal year 2005, the Companys properties were
all considered unproved and all costs to drill and equip wells
and gain access to and prepare well locations for drilling were
classified as exploration costs.
Results
of Operations from Gas Producing Activities
The table below sets forth the Companys results of
operations from gas producing activities for the fiscal years
ended July 31, 2006, 2005 and 2004. The Company commenced
production and sales of gas during fiscal year ended
July 31, 2005. The Company had no revenues or operating
expenses of gas activities during the fiscal year ended
July 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Gas revenues
|
|
$
|
1,126,477
|
|
|
$
|
117,835
|
|
|
$
|
|
|
Production costs
|
|
|
(970,791
|
)
|
|
|
(307,178
|
)
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
(538,055
|
)
|
|
|
(238,366
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax operating loss
|
|
|
(382,369
|
)
|
|
|
(427,709
|
)
|
|
|
|
|
Income taxes
|
|
|
|
|
|
|
166,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from oil and gas producing
activities
|
|
$
|
(382,369
|
)
|
|
$
|
(260,902
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following estimates of proved reserve quantities and related
standardized measure of discounted net cash flows are estimates
only and do not purport to reflect realizable values or fair
market values of the Companys reserves. The Company
emphasizes that reserve estimates are inherently imprecise and
that estimates of new discoveries are more imprecise than those
of producing gas properties. Accordingly, these estimates are
expected to change as future information becomes available. All
of the Companys reserves are located in the United States.
Proved reserves are estimated reserves of crude oil (including
condensate and natural gas liquids) and natural gas that
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved developed reserves are those expected to be recovered
through existing wells, equipment and operating methods.
The standardized measure of discounted future net cash flows is
computed by applying year-end prices of gas (with consideration
of price changes only to the extent provided by contractual
arrangements) to the estimated future production of proved gas
reserves, less estimated future expenditures (based on year-end
costs) to be incurred in developing and producing the proved
reserves, less estimated future income tax expenses (based on
year-end statutory tax rates, with consideration of future tax
rates already legislated) to be incurred on pretax net cash
flows
F-29
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
less tax basis of the properties and available credits, and
assuming continuation of existing economic conditions. The
estimated future net cash flows are then discounted using a rate
of 10% per year to reflect the estimated timing of the
future cash flows. The average net price per Mcf used at
July 31, 2006 and 2005 was $7.22 and $7.44, respectively.
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Gas Reserves
The standardized measure of discounted cash flows related to
proved gas reserves at July 31, 2006, 2005 and 2004 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Amounts in thousands)
|
|
|
Future cash inflows
|
|
$
|
106,221
|
|
|
$
|
76,608
|
|
|
$
|
|
|
Future production costs and taxes
|
|
|
(24,937
|
)
|
|
|
(10,181
|
)
|
|
|
|
|
Future development costs
|
|
|
(8,930
|
)
|
|
|
(7,824
|
)
|
|
|
|
|
Future income tax expenses
|
|
|
(15,775
|
)
|
|
|
(14,663
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net future cash flows
|
|
|
56,579
|
|
|
|
43,940
|
|
|
|
|
|
Discounted at 10% for estimated
timing of cash flows
|
|
|
(23,845
|
)
|
|
|
(20,872
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
32,734
|
|
|
$
|
23,068
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Gas Reserves
The primary changes in the standardized measure of discounted
future net cash flows for the fiscal years ended July 31,
2006, 2005 and 2004 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Amounts in thousands)
|
|
|
Standardized measure, beginning of
year
|
|
$
|
23,068
|
|
|
$
|
|
|
|
$
|
|
|
Sales, net of production costs and
taxes
|
|
|
(156
|
)
|
|
|
189
|
|
|
|
|
|
Extensions and discoveries
|
|
|
14,633
|
|
|
|
27,758
|
|
|
|
|
|
Purchases of reserves in place
|
|
|
7,206
|
|
|
|
|
|
|
|
|
|
Net changes in prices and
production costs
|
|
|
(5,606
|
)
|
|
|
|
|
|
|
|
|
Net changes in future development
costs
|
|
|
(1,023
|
)
|
|
|
(5,541
|
)
|
|
|
|
|
Revisions of quantity estimates
|
|
|
(7,063
|
)
|
|
|
|
|
|
|
|
|
Interest factor
accretion of discount
|
|
|
3,077
|
|
|
|
|
|
|
|
|
|
Net change in income tax
|
|
|
(651
|
)
|
|
|
|
|
|
|
|
|
Net change in production rates
(timing) and other
|
|
|
(751
|
)
|
|
|
662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase
|
|
|
9,666
|
|
|
|
23,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, end of year
|
|
$
|
32,734
|
|
|
$
|
23,068
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-30
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
18.
|
SELECTED
QUARTERLY DATA (UNAUDITED)
|
Summarized below are the unaudited results of operations by
quarter for fiscal years ended July 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
Second Quarter
|
|
|
Third Quarter
|
|
|
Fourth Quarter
|
|
|
Fiscal 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
209,694
|
|
|
$
|
327,811
|
|
|
$
|
262,860
|
|
|
$
|
326,112
|
|
Lease operating expenses
|
|
|
160,804
|
|
|
|
300,806
|
|
|
|
290,844
|
|
|
|
218,337
|
|
Net loss
|
|
|
(1,193,261
|
)
|
|
|
(854,225
|
)
|
|
|
(4,941,588
|
)
|
|
|
(1,847,171
|
)
|
Basic and diluted loss per common
share
|
|
$
|
(.03
|
)
|
|
$
|
(.01
|
)
|
|
$
|
(.14
|
)
|
|
$
|
(.03
|
)
|
Fiscal 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
|
|
|
$
|
6,341
|
|
|
$
|
46,925
|
|
|
$
|
64,569
|
|
Lease operating expenses
|
|
|
|
|
|
|
|
|
|
|
203,289
|
|
|
|
103,889
|
|
Net loss
|
|
|
(388,347
|
)
|
|
|
(2,485,843
|
)
|
|
|
(1,734,199
|
)
|
|
|
(787,962
|
)
|
Basic and diluted loss per common
share
|
|
$
|
(.01
|
)
|
|
$
|
(.07
|
)
|
|
$
|
(.04
|
)
|
|
$
|
(.02
|
)
|
F-31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
BPI Energy Holdings, Inc.
James G. Azlein,
President and Chief Executive Officer
Date: October 30, 2006
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
Signature
|
|
Title
|
|
/s/ James
G. Azlein
James
G. Azlein
|
|
President, Chief Executive Officer
and Director
|
|
|
|
/s/ Randy
Elkins
Randy
Elkins
|
|
Controller and Acting Chief
Financial Officer
(Principal Financial and Accounting Officer)
|
|
|
|
/s/ Costa
Vrisakis*
Costa
Vrisakis
|
|
Director
|
|
|
|
/s/ William
J. Centa*
William
J. Centa
|
|
Director
|
|
|
|
/s/ Dennis
Carlton*
Dennis
Carlton
|
|
Director
|
|
|
|
/s/ David
E. Preng*
David
E. Preng
|
|
Director
|
|
|
|
|
|
*By:
|
|
/s/ James
G. Azlein
James
G. Azlein,
Attorney-in-Fact
for the directors signing in the capacities indicated
|
|
|
Date: October 30, 2006
EXHIBIT INDEX
|
|
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Articles of Incorporation of BPI
Energy Holdings, Inc. (Incorporated by reference to
Appendix A of the Proxy Statement filed by BPI Energy
Holdings, Inc. with the SEC on January 12, 2006).
|
|
4
|
.1
|
|
Stock Purchase Agreement, dated
September 20, 2005, by and among BPI Energy Holdings, Inc.
and the investors party thereto.(***)
|
|
4
|
.2
|
|
BPI Energy Holdings, Inc. 2005
Omnibus Stock Plan (Filed as Exhibit 99.1 to the
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
December 15, 2005 and incorporated herein by reference).(#)
|
|
4
|
.3
|
|
Incentive Stock Option Plan of BPI
Energy Holdings, Inc., dated as of December 16,
2002.(*) (#)
|
|
10
|
.1
|
|
Financial Advisor Agreement, dated
as of September 29, 2004, by and between BPI Energy
Holdings, Inc. and Sanders Morris Harris, Inc.(*)
|
|
10
|
.2
|
|
Placement Agent Agreement, dated
as of December 8, 2004, by and between BPI Energy Holdings,
Inc. and Sanders Morris Harris, Inc.(*)
|
|
10
|
.3
|
|
Registration Rights Agreement,
dated as of December 30, 2004, by and between BPI Energy
Holdings, Inc. and Sanders Morris Harris, Inc., individually and
as Agent and
Attorney-in-Fact
for the Purchasers listed on Exhibit A thereto.(*)
|
|
10
|
.4
|
|
Amendment No. 1 to
Registration Rights Agreement, dated as of April 20, 2005,
by and among BPI Energy Holdings, Inc. and the holders of its
common shares executing signatures pages attached thereto.(*)
|
|
10
|
.5
|
|
Technical Services Agreement,
dated as of March 31, 2005, by and between BPI Energy
Holdings, Inc. and BHP Petroleum (Exploration) Inc.(*)
|
|
10
|
.6
|
|
Oil, Gas and Coalbed Methane Gas
Lease, dated as of April 3, 2001, by and among BPI
Industries (USA), Inc., AFC Coal Properties, Inc., American
Premier Underwriters, Inc. and Methane Management, Inc.
(Southern Illinois Basin Project).(*)
|
|
10
|
.7
|
|
Amendment to Oil, Gas and Coalbed
Methane Gas Lease, dated as of November 23, 2004, by and
among BPI Industries (USA), Inc., AFC Coal Properties, Inc. and
American Premier Underwriters, Inc. (Southern Illinois Basin
Project).(*)
|
|
10
|
.8
|
|
Option to Purchase Mineral Lease,
dated as of October 10, 2002, by and between BPI Energy,
Inc. and the County of Montgomery, Illinois (Northern Illinois
Basin Project).(*)
|
|
10
|
.9
|
|
Option to Purchase Mineral Lease,
dated as of January 20, 2004, by and between BPI Energy,
Inc. and the County of Christian, Illinois (Northern Illinois
Basin Project).(*)
|
|
10
|
.10
|
|
Mineral Lease, dated as of
November 12, 2003, by and between BPI Energy, Inc. and the
County of Shelby, Illinois (Northern Illinois Basin Project).(*)
|
|
10
|
.11
|
|
Option to Purchase Mineral Lease,
dated as of November 3, 2003, by and between BPI Energy,
Inc. and the County of Clinton, Illinois (Western Illinois Basin
Project).(*)
|
|
10
|
.12
|
|
Mineral Lease, dated as of
September 9, 2006, by and between BPI Energy, Inc. and
the County of Washington, Illinois (Western Illinois Basin
Project).()
|
|
10
|
.13
|
|
Option to Purchase Mineral Lease,
dated as of June 8, 2004, by and between BPI Energy, Inc.
and the County of Marion, Illinois (Western Illinois Basin
Project).(*)
|
|
10
|
.14
|
|
Farm-out Agreement, dated as of
November 2, 2004, by and between BPI Energy, Inc. and
Addington Exploration, LLC (Northern Illinois Basin and Western
Illinois Basin Projects).(*)
|
|
10
|
.15
|
|
Employment Letter Agreement, dated
as of January 6, 2005, by and between BPI Energy Holdings,
Inc. and George J. Zilich.(*) (#)
|
|
10
|
.16
|
|
Employment Letter Agreement, dated
as of January 31, 2005, by and between BPI Energy Holdings,
Inc. and Randy Elkins.(*) (#)
|
|
10
|
.17
|
|
Agreement, dated as of
April 17, 2004, by and between BPI Energy Holdings, Inc.
and James G. Azlein.(*) (#)
|
|
10
|
.18
|
|
Confidential Lock-up Agreement,
dated as of December 31, 2004, by and between BPI Energy
Holdings, Inc. and James G. Azlein.(*)(#)
|
|
10
|
.19
|
|
Form of Confidential Lock-up
Agreement, dated as of December 31, 2004.(*)
|
|
10
|
.20
|
|
Letter agreement, dated as of
July 7, 2005, by and among BPI Energy Holdings, Inc.,
KeyBanc Capital Markets, a division of McDonald Investments,
Inc., and Sanders Morris Harris, Inc.(**)
|
|
10
|
.21
|
|
Base Contract for Sale and
Purchase of Natural Gas, dated as of December 1, 2004, by
and between BPI Energy Holdings, Inc. and Atmos Energy
Marketing, LLC.(**)
|
|
10
|
.22
|
|
Transaction Confirmation for the
Sale and Purchase of Natural Gas, dated January 30, 2006,
by and between BPI Energy Holdings, Inc. and Atmos Energy
Marketing, LLC.()
|
|
10
|
.23
|
|
Form of Confidential
Lock-up
Agreement, dated September 26, 2005.(***)
|
|
|
|
|
|
Number
|
|
Description
|
|
|
10
|
.24
|
|
Common Stock Purchase Warrant
issued by BPI Energy Holdings, Inc. on December 31, 2004 to
Sanders Morris Harris, Inc.(*)
|
|
10
|
.25
|
|
Common Stock Purchase Warrant
issued by BPI Energy Holdings, Inc. on January 12, 2005 to
Sanders Morris Harris, Inc.(*)
|
|
10
|
.26
|
|
Form of Warrant Certificate issued
by BPI Energy Holdings, Inc. in its December 2004/January 2005
private placement.(*)
|
|
10
|
.27
|
|
Form of Subscription Agreement
entered into by the investors in the December 2004/January 2005
private placement of BPI Energy Holdings, Inc.(*)
|
|
10
|
.28
|
|
Coal Seam Gas Lease Agreement,
dated April 26, 2006, by and between BPI Energy, Inc. and
IEC (Montgomery), LLC (Northern Illinois Basin Project) (Filed
as Exhibit 10.1 to the
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
April 28, 2006 and incorporated herein by reference).
|
|
10
|
.29
|
|
Coal Seam Gas Lease Agreement,
dated April 26, 2006, by and between BPI Energy, Inc. and
Christian Coal Holdings, LLC (Northern Illinois Basin Project)
(Filed as Exhibit 10.2 to the
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
April 28, 2006 and incorporated herein by reference).
|
|
10
|
.30
|
|
Settlement Memorandum of
Understanding by and among BPI Energy, Inc., Colt LLC, AFC Coal
Properties, Inc., American Premier Underwriters, Inc. and
Central States Coal Reserves of Illinois, LLC, dated
June 13, 2006 (Filed as Exhibit 10.1 to the
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 15,
2006 and incorporated herein by reference).
|
|
10
|
.31
|
|
Settlement and Mutual Release
Agreement, dated June 23, 2006, by and among BPI Energy,
Inc., for itself and as successor by merger or otherwise to
Methane Management, Inc. and BPI Industries Inc., Colt LLC, AFC
Coal Properties, Inc., American Premier Underwriters, Inc. and
Central States Coal Reserves of Illinois, LLC (Filed as
Exhibit 10.1 to the
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 27,
2006 and incorporated herein by reference).
|
|
10
|
.32
|
|
Purchase and Sale Agreement, dated
June 23, 2006, by and between Colt LLC and BPI Energy, Inc.
(Filed as Exhibit 10.2 to the
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 27,
2006 and incorporated herein by reference).
|
|
10
|
.33
|
|
Termination Agreement, dated
June 23, 2006, by and between BPI Energy, Inc., for itself
and as successor by merger or otherwise to Methane Management,
Inc. and BPI Industries Inc., Colt LLC, AFC Coal Properties,
Inc., American Premier Underwriters, Inc. and Central States
Coal Reserves of Illinois, LLC, for itself and its predecessor
Peabody Development Land Holdings, LLC (Filed as
Exhibit 10.3 to the
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 27,
2006 and incorporated herein by reference).
|
|
10
|
.34
|
|
Separation Agreement and Waiver
and Release by and between BPI Energy Holdings, Inc. and George
J. Zilich, dated October 12, 2006 (Filed as
Exhibit 10.1 to
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
October 16, 2006 and incorporated herein by reference).(#)
|
|
21
|
.1
|
|
List of Subsidiaries.()
|
|
23
|
.1
|
|
Consent of De Visser Gray,
Chartered Accountants.()
|
|
23
|
.2
|
|
Consent of Schlumberger Technology
Corporation.()
|
|
23
|
.3
|
|
Consent of Meaden &
Moore, Ltd.()
|
|
24
|
.1
|
|
Power of Attorney.()
|
|
31
|
.1
|
|
Section 302 Certification of
the Chief Executive Officer (Principal Executive
Officer).()
|
|
31
|
.2
|
|
Section 302 Certification of
the Acting Chief Financial Officer (Principal Financial
Officer).()
|
|
32
|
.1
|
|
Section 906 Certification of
the Chief Executive Officer (Principal Executive
Officer).()
|
|
32
|
.2
|
|
Section 906 Certification of
the Acting Chief Financial Officer (Principal Financial
Officer).()
|
|
|
|
(*) |
|
Incorporated by reference to the
S-1
Registration Statement filed by BPI Energy Holdings, Inc. with
the SEC on June 3, 2005 (File
No. 333-125483). |
|
(**) |
|
Incorporated by reference to Amendment No. 2 to the
S-1
Registration Statement filed by BPI Energy Holdings, Inc. with
the SEC on September 6, 2005 (File
No. 333-125483). |
|
(***) |
|
Incorporated by reference to Amendment No. 3 to the
S-1
Registration Statement filed by BPI Energy Holdings, Inc. with
the SEC on October 28, 2005 (File
No. 333-125483). |
|
() |
|
Filed herewith. |
|
(#) |
|
Management contract or compensatory plan or arrangement. |