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, 2007
Commission File Number:
001-32695
BPI Energy Holdings,
Inc.
(Exact name of registrant as
specified in its charter)
|
|
|
|
|
British Columbia, Canada
|
|
|
75-3183021
|
|
(State or other jurisdiction
of
incorporation or organization)
|
|
|
(I.R.S. Employer
Identification No.
|
)
|
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:
|
|
|
|
|
|
|
Name of Exchange on
|
Title of Each Class
|
|
Which Registered
|
Common Shares, without par value
|
|
|
American Stock Exchange
|
|
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: $26,149,553.
As of October 22, 2007, there were 73,792,493 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 Securities and Exchange Commission
(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:
|
|
|
|
|
as free gas within the micropores (pores with a diameter of less
than .0025 inch) and cleats (set of natural fractures) of
coal;
|
|
|
|
as dissolved gas in water within the coal;
|
|
|
|
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
|
|
|
|
as adsorbed gas within the molecular structure of the coal.
|
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. Our current wells range
in depths from 450 to 1,300 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.
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 and farm-out agreements and ownership of
a CBM estate, we have assembled CBM rights covering
approximately 512,000 acres 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 and
farm-out agreements an aggregate of 366,364 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
1
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, 2007, we have drilled 170 wells. These
wells include 111 productive wells, six shut-in wells, 10
plugged wells, four disposal wells, three pressure observation
wells, four divested wells, and 32 wells that have been
drilled but are not yet in production, including 12 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.
Recent
Developments GasRock Financing
On July 27, 2007, BPI Energy, Inc. (BPI
Energy), our wholly owned subsidiary, entered into an
Advancing Term Credit Agreement (the Credit
Agreement) with GasRock Capital LLC (GasRock).
The Credit Agreement provides for an initial commitment to BPI
Energy of $10.2 million and the possibility of future
advances to BPI Energy of up to an additional
$64.8 million. All future advances under the Credit
Agreement beyond the initial commitment will be made in
GasRocks discretion. BPI Energy has received an initial
advance of $9.1 million under the Credit Agreement, which
resulted in net proceeds to BPI Energy of $8.2 million
after the deduction of GasRocks facility fee, investment
banking fees, legal fees and other fees and expenses incurred by
BPI Energy in connection with the transaction totaling
$0.8 million. The initial advance is expected to be used
for continued drilling of development wells at our Southern
Illinois Basin Project, drilling of new test wells, pilot
projects, possible lease acquisitions and general and
administrative expenses.
BPI Energy may request advances under the Credit Agreement at
any time before July 25, 2008, which GasRock may in its
discretion extend until July 27, 2010. All amounts then
outstanding under the Credit Agreement are due and payable on
July 25, 2008 (the Loan Termination Date),
which GasRock may in its discretion extend until July 29,
2011. For the first year of the term of the Credit Agreement,
all amounts outstanding under the Credit Agreement will bear
interest at a rate equal to the greater of (i) 15% per
annum and (ii) the LIBOR rate plus 9% per annum. If GasRock
extends the Loan Termination Date, amounts outstanding under the
Credit Agreement will thereafter bear interest at a rate equal
to the greater of (i) 12% per annum and (ii) the LIBOR
rate plus 6% per annum. BPI Energy is required to make monthly
interest payments on the amounts outstanding under the Credit
Agreement but is not required to make any principal payments
until the Loan Termination Date. BPI Energy may prepay the
amounts outstanding under the Credit Agreement at any time
without penalty.
BPI Energy is required to pay GasRock a facility fee upon the
receipt of any advances under the Credit Agreement in an amount
equal to two percent of the amount advanced. BPI Energy is also
required to reimburse GasRock for all of the expenses GasRock
incurs in connection with entering into and administering the
Credit Agreement.
BPI Energys obligations under the Credit Agreement are
secured by a first priority security interest in substantially
all of BPI Energys properties and assets, including all of
BPI Energys CBM rights under its leases, farm-out
agreements and fee interests, all of BPI Energys wells at
its Southern Illinois Basin Project, all of BPI Energys
equipment and all of the common stock of BPI Energy (which has
been pledged by us). We have provided a guaranty to GasRock of
all of BPI Energys obligations under the Credit Agreement.
2
In connection with the execution of the Credit Agreement, BPI
Energy granted GasRock a one percent royalty in all CBM produced
and saved from BPI Energys existing leased and owned CBM
properties and an additional four percent royalty interest in
all CBM produced and saved from BPI Energys existing wells
at its Southern Illinois Basin Project. As long as any of BPI
Energys obligations remain outstanding under the Credit
Agreement, BPI Energy will be required to grant the same one
percent royalty interest to GasRock on new mineral interests
acquired by BPI Energy after July 25, 2008 and the same
four percent royalty interest on new wells drilled by BPI Energy
that are funded by draws under the Credit Agreement.
The Credit Agreement requires BPI Energy to enter into a swap
agreement under which approximately 75% of BPI Energys
proved developed producing reserves scheduled to be produced
during a two-year period will be guaranteed a price of not less
than $7.00 per MMBtu. Pursuant to this requirement, BPI Energy
has initially entered into a
23-month
costless collar with BP Corporation North America
Inc. (BP) under which BP is required to cover any
shortfall below $7.00 per MMBtu that BPI Energy may receive for
its CBM production (as determined by a reference market price)
as to an aggregate notional amount of 460,000 MMBtu and BPI
Energy must pay to BP any amounts above $11.00 per MMBtu that it
receives for its CBM production (as determined by a reference
market price) as to the notional amount. BPI Energy expects that
it will enter into additional hedging arrangements during the
next two years to cover the entire 75% of its proved developed
producing reserves scheduled to be produced during that period.
BPI Energy is subject to various restrictive covenants under the
Credit Agreement, including limitations on its ability to sell
properties and assets, make distributions, extend credit, amend
its material contracts, incur indebtedness, provide guarantees,
effect mergers or acquisitions, cancel claims, create liens,
create subsidiaries, amend its formation documents, make
investments, enter into transactions with its affiliates, and
enter into swap agreements. BPI Energy must maintain (i) a
current ratio of at least 1.0 (excluding from the calculation of
current liabilities any advances outstanding under the Credit
Agreement) and (ii) a loan-to-value ratio greater than 1.0
to 1.0 for the period commencing on September 30, 2008 and
ending on March 31, 2010 and 0.7 to 1.0 thereafter.
The Credit Agreement contains customary events of default. In
addition, GasRock may declare an event of default if, at any
time after July 25, 2008, BPI Energys most recent
reserve report indicates that BPI Energys projected net
revenue attributable to its proved reserves is insufficient to
fully amortize the amounts outstanding under the Credit
Agreement within a
48-month
period and BPI Energy is unable to demonstrate to GasRocks
reasonable satisfaction that BPI Energy would be able to satisfy
such outstanding amounts through a sale of BPI Energys
assets or equity. Upon the occurrence of an event of default
under the Credit Agreement, GasRock may accelerate BPI
Energys obligations under the Credit Agreement. Upon
certain events of bankruptcy, BPI Energys obligations
under the Credit Agreement would automatically accelerate. In
addition, at any time that an event of default exists under the
Credit Agreement, BPI Energy will be required to pay interest on
all amounts outstanding under the Credit Agreement at a default
rate, which is equal to the then-prevailing interest rate under
the Credit Agreement plus four percent per annum.
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:
|
|
|
|
|
Explore and Develop Properties.
As of
July 31, 2007, we have drilled 170 wells. These wells
consist of 111 productive wells, six shut-in wells, 10 plugged
wells, four disposal wells, three pressure observation wells,
four divested wells, and 32 wells that have been drilled
but are not yet in production, including 12 test wells. During
the
12-month
period ending July 31, 2008, we plan to drill between 30
and 70 new wells. This plan contemplates capital expenditures of
approximately $10 million to $23 million. The number
of wells that we drill during the
12-month
period ending July 31, 2008 will be dependent on
(i) data obtained from test wells; (ii) data obtained
from our initial pilot wells; (iii) additional financing we
are able to secure, including additional advances we are able to
make under our Credit Agreement with GasRock; and (iv) the
risk factors described in this report.
|
3
|
|
|
|
|
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.
|
|
|
|
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 utilize our test
data and all basin-wide data we have been able to access to
high-grade areas in the Basin for pilot testing. Successful
pilot tests have the potential to lead to future development
projects. With this approach in mind, we are acquiring leases
and options on acreage blocks in areas where reservoir
properties are more favorable and there is currently pipeline
delivery infrastructure in place.
|
|
|
|
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 purpose of providing
capital, technical operating expertise and development
opportunities to accelerate our growth.
|
Competitive
Strengths
We believe our competitive strengths include the following:
|
|
|
|
|
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.
This substantial footprint should give us opportunities to
leverage our knowledge of the Illinois Basin and realize
significant economies of scale as our drilling and production
activities grow throughout the Illinois Basin.
|
|
|
|
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, 2007, we have drilled 170 wells, including 91
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, 2006 we sold
135,118 Mcf of CBM, and during our fiscal year ended
July 31, 2007 we sold 185,305 Mcf of CBM.
|
|
|
|
Short Drilling Permit Lead Times.
We typically
experience short turnaround times in obtaining drilling permits
as compared to CBM drillers in other CBM basins.
|
|
|
|
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.
|
|
|
|
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.
|
|
|
|
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 our operating employees own common shares of BPI.
|
4
CBM
Acreage Rights
As of July 31, 2007, our CBM acreage rights, controlled
through lease and farm-out agreements and ownership of a CBM
estate, include the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
Project
|
|
Acres
|
|
|
Acres
|
|
|
Acres(1)
|
|
|
Southern Illinois Basin Project(2)
|
|
|
6,976
|
|
|
|
3,024
|
|
|
|
10,000
|
|
Northern Illinois Basin Project
|
|
|
|
|
|
|
366,364
|
|
|
|
366,364
|
|
Western Illinois Basin Project
|
|
|
|
|
|
|
135,948
|
|
|
|
135,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,976
|
|
|
|
505,336
|
|
|
|
512,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Because we are the exclusive owner of the CBM rights under each
of our lease and farm-out agreements, our acreage totals reflect
both gross and net acres.
|
|
(2)
|
|
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 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
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 agreements include all of the acreage 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.
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 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.
5
In addition to the GasRock royalties, we are currently paying
royalties of 3.03% on our production at this project. The
GasRock royalties will also apply to our acreage rights
discussed below at the time we produce and sell CBM from the
applicable acreage.
We commenced sales of gas from our initial pilot production
wells on this project in January 2005. As of July 31, 2007,
we have drilled 131 wells at this project. These wells
consist of 91 productive wells, six shut-in wells, four divested
wells (as a result of the Colt LLC settlement), nine plugged
wells, two disposal wells, one pressure observation well, and
18 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 fiscal year 2006, we 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 determined it was beneficial
to complete additional seams in the remaining wells, which we
plan to begin doing in fiscal year 2008.
All of our proved reserves are currently located at the Southern
Illinois Basin Project.
Northern
Illinois Basin Project
Our CBM rights in the Northern Illinois Basin Project cover
366,364 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 and a farm-out agreement.
We have entered into a lease agreement with Montgomery County
covering 133,788 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 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 Shelby County
covering 63,250 acres of CBM rights in Shelby County,
Illinois. The 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 12,040 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%. As discussed in Item 3 below, these
lease agreements with IEC (Montgomery), LLC and Christian Coal
Holdings, LLC are currently subject to litigation.
We have also entered into a lease agreement with Christian
County to lease 14,033 acres of CBM rights in Christian
County, Illinois. The lease agreement extends until
January 20, 2012. 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 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.
Under the lease agreements with Montgomery, Shelby and Christian
Counties, 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.
6
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 completed drilling a 10-well pilot
program at this project that we refer to as the Shelby Pilot. In
fiscal year 2007 at the Shelby Pilot, we added one pressure
observation well and drilled two additional producers that are
not currently completed. Also in fiscal year 2007, we drilled
two new test wells in other parts of the Shelby County acreage
block. During the fourth quarter of fiscal year 2007, we
announced our decision to continue production activities at our
Shelby Pilot, while deferring additional development pending
further production and pressure information.
As of July 31, 2007, we drilled and completed a second
10-well pilot project, the Macoupin Pilot, in the Northern
Illinois Basin Project. Those wells have just started the
dewatering process. The Macoupin Pilot also includes one
pressure observation well and one disposal well.
We currently have no proved reserves located at the Northern
Illinois Basin Project.
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 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. Under the lease agreement, 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 have also entered into a lease agreement with Marion County
covering 17,882 acres of CBM rights in Marion County,
Illinois. The lease agreement extends until June 7, 2012.
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 agreements with Washington and Marion Counties,
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
7
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, 2007, we have drilled four test wells at the
Western Illinois Basin Project from which we are still gathering
and evaluating data. We currently have no proved reserves
located at the Western Illinois Basin Project.
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 (part of our Northern Illinois Basin
Project) and 22,997 acres of CBM rights in Perry County,
Illinois (part of our Western Illinois Basin Project) 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 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 plan to extend the 36-month
evaluation period on unearned acreage when it expires in
November 2007.
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.
As discussed in Item 3 below, our farm-out agreement with
Addington is currently subject to litigation.
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.
BHPs right of first refusal to acquire us lapsed as of the
expiration date of the agreement, and the 4 million stock
appreciation rights that we granted to BHP, which could be
exercised by BHP only in connection with an acquisition of us,
expired on March 30, 2007.
Status
of CBM Operations
The following table summarizes the status of wells we have
drilled as of July 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonproductive Wells
|
|
|
|
|
|
|
|
|
|
Drilled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
Not Yet
|
|
|
|
|
|
|
|
|
Pressure
|
|
|
|
|
|
|
|
|
|
|
Project
|
|
Wells
|
|
|
Completed(1)
|
|
|
Shut-in(2)
|
|
|
Plugged
|
|
|
Observation(3)
|
|
|
Disposal
|
|
|
Divested(4)
|
|
|
Total
|
|
|
Southern Illinois Basin Project
|
|
|
91
|
|
|
|
18
|
|
|
|
6
|
|
|
|
9
|
|
|
|
1
|
|
|
|
2
|
|
|
|
4
|
|
|
|
131
|
|
Northern Illinois Basin Project
|
|
|
20
|
|
|
|
10
|
|
|
|
|
|
|
|
1
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
|
|
35
|
|
Western Illinois Basin Project
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
111
|
|
|
|
32
|
|
|
|
6
|
|
|
|
10
|
|
|
|
3
|
|
|
|
4
|
|
|
|
4
|
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Wells drilled not yet completed includes
18 wells drilled but not yet completed at our Southern
Illinois Basin Project, four test wells at our Western Illinois
Basin Project, two wells drilled but not yet completed at our
Shelby Pilot project, and eight test wells at our Northern
Illinois Basin Project.
|
|
(2)
|
|
Shut-in wells include six coal mine methane wells at our
Southern Illinois Basin Project.
|
|
(3)
|
|
Pressure observation wells are non-producing wells that are used
to measure
seam-by-seam
pressures within the drainage pattern of our CBM fields.
|
|
(4)
|
|
Under the terms of the Colt LLC settlement, we divested our
ownership interests in four wells.
|
8
The following table sets forth our drilling activities over the
last three fiscal years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Exploratory Wells(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2)
|
|
|
10
|
|
|
|
10
|
|
|
|
|
|
Nonproductive(3)
|
|
|
12
|
|
|
|
4
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22
|
|
|
|
14
|
|
|
|
3
|
|
Development Wells(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2)
|
|
|
5
|
|
|
|
49
|
|
|
|
37
|
|
Nonproductive(3)
|
|
|
18
|
|
|
|
5
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
23
|
|
|
|
54
|
|
|
|
54
|
|
Total Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2)
|
|
|
15
|
|
|
|
59
|
|
|
|
37
|
|
Nonproductive(3)
|
|
|
30
|
|
|
|
9
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
45
|
|
|
|
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, including pressure
observation wells, disposals wells, test wells, and wells
drilled but not yet completed.
|
As of July 31, 2007, all of the wells that we have drilled
are vertical wells. We estimate that a typical vertical well
will require about 24 to 48 months to reach peak
production. We completed most of our productive wells 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 determined it was beneficial to complete additional
seams in the remaining wells, which we will begin doing in
fiscal year 2008. We began selling gas from our first productive
wells in January 2005. As of July 31, 2007, 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,
|
|
|
|
2007(1)
|
|
|
2006(1)
|
|
|
2005(1)(2)
|
|
|
Total net sales (Mcf)
|
|
|
185,305
|
|
|
|
135,118
|
|
|
|
17,885
|
|
|
|
|
(1)
|
|
Total sales volumes omit (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.
|
9
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Average net gas sales price (per Mcf)
|
|
$
|
6.50
|
|
|
$
|
8.34
|
|
|
$
|
6.59
|
|
Average net production cost (per Mcf)(1)
|
|
|
8.68
|
|
|
|
7.18
|
|
|
|
17.18
|
|
|
|
|
(1)
|
|
Production costs include a significant amount of fixed expenses
required to operate a minimum number of our 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, 2006 and 2007, 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. We did not
file any reserve information with any other federal authority or
agency during the fiscal year ended July 31, 2007. The
following table shows our estimated proved developed and proved
undeveloped reserves. Reserve information is net of our royalty
obligations. 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Estimated proved developed reserves
|
|
|
10,639
|
|
|
|
8,983
|
|
|
|
2,971
|
|
Estimated proved undeveloped reserves
|
|
|
5,635
|
|
|
|
5,735
|
|
|
|
7,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated proved developed and undeveloped reserves
|
|
|
16,274
|
|
|
|
14,718
|
|
|
|
10,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Since July 31, 2007 we have completed and tied in 10 wells
previously classified as proved undeveloped and representing
1,342 MMcf in Schlumbergers reserve report. In addition,
since July 31, 2007 we have drilled, completed and tied in three
wells representing 403 MMcf that are not included as proved
reserves in Schlumbergers reserve report as of
July 31, 2007.
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,
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
(Dollars in thousands,
|
|
|
except per unit amounts)
|
|
Total standardized measure of discounted future net cash flows
|
|
$
|
17,183
|
|
|
$
|
32,734
|
|
|
$
|
23,068
|
|
Prices used in calculating reserves (per Mcf)
|
|
|
5.29
|
|
|
|
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
10
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 three
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 25 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.
On July 31, 2007, pursuant to requirements in our Credit
Agreement with GasRock, we entered into a
23-month
costless collar with BP for the notional amount of
20,000 MMBtu per month beginning in September 1, 2007.
For a more detailed description of this arrangement, see the
discussion under Item 7A of Part II below.
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 2008. 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.
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 disposal
of fluids used and produced in connection with operations.
|
11
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.
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
12
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, 2007, we have 21 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
|
|
|
58
|
|
|
President, Chief Executive Officer and Director
|
James E. Craddock
|
|
|
48
|
|
|
Chief Operating Officer and Director
|
Randy L. Elkins
|
|
|
41
|
|
|
Controller and Acting Chief Financial Officer
|
Dennis Carlton
|
|
|
57
|
|
|
Director
|
David E. Preng
|
|
|
61
|
|
|
Director
|
Costa Vrisakis
|
|
|
73
|
|
|
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. 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
we owned a minority interest. In August 2001, we acquired
Methane Management, Inc. and Mr. Azlein became our
President. He has assembled a new management team and is guiding
our transition from a primary focus on property acquisition to
one of CBM development in the Illinois Basin.
James E. Craddock
has been Chief Operating Officer since
December 19, 2006 and a Director since January 30,
2007. He previously served as our Senior Vice President of
Operations. 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 by
ConocoPhillips on March 31, 2006), where he served as Chief
Engineer. In this, his most recent capacity with Burlington, he
was 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.
Randy L. Elkins
assumed the position of Acting Chief
Financial Officer in October 2006, and has been Controller since
February 2005. He is a Certified Public Accountant with more
than 15 years of experience in accounting and auditing.
Prior to joining us, 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. Mr. Elkins earned his Bachelor of Business
Administration in Accounting from Cleveland State University. He
is a member of the Ohio Society of Certified Accountants.
13
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,
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.
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. From 1997 to 2006, he was a director of Remington
Oil and Gas, where, in addition to chairing its
Nomination & Governance Committee, he served 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, the
Houston Chapter of the National Association of Corporate
Directors and a member of Texas A&Ms International
Board. 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 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.
William J. Centa
served as a Director from March 2005
until his resignation on September 13, 2007.
Significant
Employees
The following persons are not executive officers but make
significant contributions to our business:
Randy Oestreich
, 51, 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 15 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
, 60, has been Director of Property
Acquisitions since January 2002. Mr. Anderson has more than
30 years of oil and gas and real estate experience: from
1976 to 1983 as Land Department Manager with John Carey Oil
14
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 us, 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 procedures on both a local
and state level. Mr. Anderson is a member of the Illinois
Oil and Gas Association and the American Association of
Professional Landmen.
Michael Dawson
, 57, has been Senior Geological Advisor
since August 2006. He was most recently with Burlington
Resources Inc. (acquired by ConocoPhillips on March 31,
2006) 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 (now 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
, 32, 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 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,
30, 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
, 33, 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 are required to file annual, quarterly and other reports and
proxy statements with the 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 website 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. Shareholders may
request copies of these documents by writing to our Investor
Relations Department at 30775 Bainbridge Road, Suite 280,
Solon, Ohio 44139.
15
You should be aware that the occurrence of any of the events
described in this Risk Factors section or elsewhere in this
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.
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. Our Credit Agreement with GasRock provides for
an initial commitment of $10.2 million, of which we have
drawn $9.1 million. Additional advances beyond the initial
$10.2 million commitment are at GasRocks discretion.
Therefore, in order to achieve our long-term plans and maintain
a viable business, we will need to raise additional financing,
either by convincing GasRock to advance additional funds or
obtaining financing from new sources. 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 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. As
with our current GasRock financing, 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, 2006 we incurred a net loss of $8,836,244, and
during our fiscal year ended July 31, 2007 we incurred a
net loss of $20,640,488. As of July 31, 2007, we have an
accumulated deficit of $47,834,016. 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.
16
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:
|
|
|
|
|
unexpected drilling conditions;
|
|
|
|
pressure or irregularities in formations;
|
|
|
|
equipment failures or accidents;
|
|
|
|
shortages or delays in the availability of drilling rigs or the
delivery of equipment;
|
|
|
|
the inability to hire personnel or engage other third parties
for drilling and completion services;
|
|
|
|
the inability to obtain regulatory approvals to drill CBM wells
where planned;
|
|
|
|
litigation initiated by surface owners attempting to prevent us
from utilizing the surface land for our operations; and
|
|
|
|
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.
|
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.
Any
decline in natural gas prices could negatively impact our
ability to attain profitable operations.
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 also 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 would negatively affect the value of your
investment in us.
If we
are unable to repay or refinance the amounts advanced to us by
GasRock when they become due, GasRock could enforce its security
interest in our assets.
The obligations under our Credit Agreement with GasRock are due
and payable on July 25, 2008, unless GasRock extends this
due date. In addition, if we default under the Credit Agreement,
such as by breaching a restrictive covenant or one of the other
provisions of the agreement, GasRock could accelerate the due
date of our obligations. BPI Energys obligations under the
Credit Agreement are secured by a first priority security
interest in substantially all of BPI Energys properties
and assets, including all of our CBM acreage rights and all of
our wells at our Southern Illinois Basin Project. If we are
unable to repay or refinance the amounts advanced to us by
GasRock when they become due, GasRock could enforce its security
interest in our assets. If GasRock took such action, the value
of your investment in us would be significantly and adversely
affected.
The
limits imposed on our subsidiary BPI Energy in our Credit
Agreement with GasRock could prevent us from acquiring
additional acreage or completing joint ventures or cause us to
lose access to the facility.
Our Credit Agreement with GasRock imposes various restrictive
covenants on our subsidiary BPI Energy, including limitations on
its ability to effect mergers or acquisitions and make
investments. In addition, BPI Energy must maintain (i) a
current ratio of at least 1.0 (excluding from the calculation of
current liabilities any advances outstanding under the Credit
Agreement) and (ii) a loan-to-value ratio greater than 1.0
to 1.0 for the period
17
commencing on September 30, 2008 and ending on
March 31, 2010 and 0.7 to 1.0 thereafter. If BPI Energy
fails to maintain these ratios a default under the Credit
Agreement could result. Such a default would permit GasRock to
accelerate the due date of our obligations and deny us access to
further advances. BPI Energys compliance with these
restrictive covenants and ratios could also prevent us from
acquiring additional acreage or entering into joint ventures or
other strategic transactions. If BPI Energys compliance
with these provisions overly restricts our business activities,
or its breach of such provisions causes us to lose access to the
facility, our business and your investment in us could be
adversely affected.
Our
hedging transactions may limit our potential gains or expose us
to losses.
Under the terms of our Credit Agreement with GasRock, we are
required to hedge at least 75% of projected production from our
proved developed producing properties. These transactions could
limit our potential gains if natural gas prices were to rise
substantially over the prices established by the contracts. In
addition, such transactions may expose us to the risk of
financial loss in certain circumstances, including instances in
which:
|
|
|
|
|
our production is less than expected;
|
|
|
|
the counterparties to our contracts fail to perform under the
contracts; or
|
|
|
|
our production costs on the contracted production significantly
increase.
|
The financial loss resulting from any of these events could be
significant in relation to our revenues and cash balances, which
could have a significantly negative effect on our business.
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 plans 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 farm-out agreements pursuant
to which we hold our CBM acreage rights will expire between
November 2008 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 agreements we
will retain only limited acreage rights for each CBM well that
we place into production. For us to maintain all of our CBM
acreage rights beyond the initial terms of our lease and
farm-out agreements, we will be required to significantly expand
our drilling operations or renegotiate the terms of these
agreements. If we are unable to retain our CBM acreage rights,
our growth potential will be negatively impacted, which could
cause the value of your investment in us to decline.
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.
18
Because
approximately 75% 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 75%
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 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 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
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 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 negatively impact 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. If for any reason these operating or
legal costs increase significantly, our financial performance
will suffer.
19
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 negatively impact our results of
operations and could prevent our properties from being
commercially viable.
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.
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 million on an annual
basis. In addition, we continue to be subject to certain
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.
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) the companys aggregate market
value; (iii) whether a companys common stock sells
for a substantial period of time at a low price per share; and
(iv) whether a company has complied with its obligations
under American Stock Exchange and SEC rules. 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.
|
|
ITEM 1B.
|
Unresolved
Staff Comments.
|
None.
20
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 titled CBM Acreage Rights.
|
|
ITEM 3.
|
Legal
Proceedings.
|
Drummond
Coal Co. Litigation
Approximately 115,000 acres of CBM rights of BPI Energy,
Inc. (BPI) that are located at the Northern Illinois
Basin Project are currently subject to litigation. To date, BPI
has drilled one well on this acreage, a test well that was
drilled in September 2006.
In 2004, BPI and affiliates of the Drummond Coal Co.
(Drummond), including IEC (Montgomery), LLC
(IEC), entered into a letter of intent to obtain
coal and CBM gas rights for one another in the Illinois Basin
and to work together in a relationship in which BPI would
produce CBM from coal beds prior to the Drummond
affiliates mining of coal from those beds. Pursuant to and
in reliance upon this letter of intent and its relationship with
Drummond, BPI arranged for the transfer of 163,109 acres of
coal rights to the Drummond affiliates for a total purchase
price of $5,845,500, which BPI believes reflects a significant
discount to current market prices. In light of its obligations
to Drummond, BPI charged no profit on its transfer of the coal
rights to the Drummond affiliates. Rather, in consideration for
obtaining those coal rights, the Drummond affiliates were to
lease approximately 115,000 acres of CBM rights to BPI for
a primary lease term of 20 years and with favorable royalty
rates. Although the Drummond affiliates entered into two CBM
leases with BPI on April 26, 2006, they have since sought
in various ways to void or terminate the leases.
Drummond affiliates IEC and Christian Coal Holdings, LLC
(Christian) filed suit against BPI on
February 9, 2007 in the United States District Court for
the Northern District of Alabama, claiming that BPI has breached
the CBM leases in various ways. On May 14, 2007, the Court
granted BPIs motion to dismiss the case in its entirety on
the ground of improper venue. IEC and Christian did not appeal
that decision.
On March 13, 2007, BPI filed suit against IEC, Christian
and additional Drummond affiliates Shelby Coal Holdings, LLC,
Clinton Coal Holdings, LLC and Marion Coal Holdings, LLC in the
United States District Court for the Southern District of
Illinois. At the courts direction, BPI filed an amended
complaint, and subsequently filed a second amended complaint
that named BPI Energy Holdings, Inc. as an additional plaintiff,
named Drummond Company Inc. and Drummond affiliate Vandalia
Energy, LLC as additional defendants, and asserted additional
claims. In its lawsuit, BPI seeks to rescind its transfers of
coal rights to the Drummond affiliates for failure of
consideration due to the Drummond affiliates efforts to
avoid the CBM leases, has asserted claims for money damages for
breach of the various agreements between the parties (including
the CBM leases), breach of fiduciary duty, unjust enrichment,
promissory estoppel, and tortious interference with contracts,
and seeks to pierce the corporate veil to recover from Drummond
and IEC for the actions of the other Drummond affiliates. The
defendants filed a motion to dismiss the second amended
complaint, which has been fully briefed and awaits a decision by
the Court. We anticipate that if the Court denies all or part of
the motion to dismiss, Drummond and its affiliates will file
counterclaims against BPI for breach of the CBM leases, citing
the same bases set forth in the Alabama lawsuit.
We believe that Drummond and its affiliates, after having
received favorable coal rights in exchange for favorable CBM
rights, now wish to obtain a significant windfall by seeking to
renege on the CBM rights that they were obligated to grant to
BPI.
If the Drummond affiliates reinstitute their claims against BPI,
we believe that we will be successful in defending against their
claims of breach. However, there can be no assurance that we
will be successful in maintaining these acreage rights. The loss
of these acreage rights would not have a material impact on our
financial position, results of operations or cash flows.
21
ICG
Litigation
In November 2004, BPI entered into a farm-out agreement under
which it acquired the right to develop certain CBM in Macoupin
and Perry Counties in Illinois. The farm-out agreement covers
41,253 acres of CBM rights in Macoupin County and
22,997 acres of CBM rights in Perry County. The farmor was
Addington Exploration, LLC, which leased the CBM rights from
Meadowlark Farms, Inc. and Ayrshire Land Company. Meadowlark and
Ayrshire went into bankruptcy, and ICG Natural Resources, LLC
purchased their assets, including the CBM rights underlying the
Addington leases. On April 9, 2007, ICG filed suit against
BPI in Perry County, Illinois, in an effort to avoid the
Addington leases, claiming that there was a lack of
consideration at the time they were originally entered into. BPI
has filed a motion to dismiss the lawsuit under the doctrine of
estoppel by deed, arguing that ICG cannot challenge the leases
because it acquired the CBM rights subject to those leases, as
set forth in the deed from Addington and Meadowlark to ICG, the
purchase agreement between those parties, and numerous
bankruptcy court filings and orders associated with the approval
of the sale. Addington was subsequently acquired by Nytis
Exploration Company, LLC, which has intervened in the action and
joined in BPIs motion. ICG has opposed BPIs motion,
and the Court has held a hearing upon it. BPI has recently
learned that, subsequent to filing suit, ICG may have
transferred its Perry County coal and CBM rights to Arch
Minerals, which is not currently a party to the lawsuit. It is
unknown whether Arch will challenge the farm-out agreement. To
date, BPI has drilled 10 pilot wells, one pressure observation
well, one water disposal well and two test wells on the acreage
covered by the farm-out agreement.
We believe that we will be successful in either having the case
dismissed or in defending against ICGs claims. However,
there can be no assurance that we will be successful in
retaining the acreage under this farm-out agreement. The loss of
these acreage rights would not have a material impact on our
financial position, results of operations or cash flows.
|
|
ITEM 4.
|
Submission
of Matters to a Vote of Security Holders.
|
There were no matters submitted to a shareholder vote during the
fourth quarter of fiscal 2007.
PART II
|
|
ITEM 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchase of Equity Securities.
|
Our common shares are currently traded on the American Stock
Exchange under the symbol BPG. The following table
sets forth the high and low sales prices per share, in
U.S. dollars, as reported by the American Stock Exchange
during each of our quarterly periods ending in our 2006 and 2007
fiscal years.
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
Fiscal Year Ended July 31, 2006
|
|
|
|
|
|
|
|
|
Quarter ended October 31, 2005
|
|
$
|
2.25
|
|
|
$
|
1.37
|
|
Quarter ended January 31, 2006
|
|
|
4.00
|
|
|
|
1.92
|
|
Quarter ended April 30, 2006
|
|
|
3.55
|
|
|
|
1.20
|
|
Quarter ended July 31, 2006
|
|
|
1.60
|
|
|
|
1.03
|
|
Fiscal Year Ended July 31, 2007
|
|
|
|
|
|
|
|
|
Quarter ended October 31, 2006
|
|
$
|
1.24
|
|
|
$
|
0.48
|
|
Quarter ended January 31, 2007
|
|
|
0.70
|
|
|
|
0.45
|
|
Quarter ended April 30, 2007
|
|
|
1.65
|
|
|
|
0.49
|
|
Quarter ended July 31, 2007
|
|
|
1.51
|
|
|
|
0.58
|
|
As of October 22, 2007, we have 73,792,493 common shares
outstanding, which are held by approximately
379 shareholders of record. The transfer agent and
registrar for our common shares is Computershare Investor
Services Inc., a Vancouver, British Columbia company. In
addition to our outstanding common shares, as of
October 22, 2007, we have reserved 1,579,931 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.
22
Performance
Graph
The following graph compares the yearly changes in total
shareholder return on our common shares with the total return of
the AMEX Composite Index and the S&P Energy Index from
July 31, 2002 through July 31, 2007. We assumed an
initial investment of $100 on July 31, 2002 and the
reinvestment of all dividends. We did not pay any dividends
during this five-year period.
Performance
Graph
Cumulative
Total Return as of July 31, 2007
(assumes a $100 investment at the close of trading on
July 31, 2002)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7/31/02
|
|
|
7/31/03
|
|
|
7/31/04
|
|
|
7/31/05
|
|
|
7/31/06
|
|
|
7/31/07
|
BPI Energy Holdings, Inc.
|
|
|
|
100.00
|
|
|
|
|
89.58
|
|
|
|
|
96.11
|
|
|
|
|
260.09
|
|
|
|
|
206.16
|
|
|
|
|
107.34
|
|
AMEX Composite Index
|
|
|
|
100.00
|
|
|
|
|
112.81
|
|
|
|
|
148.13
|
|
|
|
|
191.64
|
|
|
|
|
235.33
|
|
|
|
|
271.19
|
|
S&P 600 Energy Index
|
|
|
|
100.00
|
|
|
|
|
117.28
|
|
|
|
|
190.52
|
|
|
|
|
295.32
|
|
|
|
|
402.06
|
|
|
|
|
431.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of Unregistered Securities
In fiscal year 2007, we did not issue any unregistered
securities. In fiscal year 2006, we issued the following
unregistered securities. Except for the September 26, 2005
issuance, when KeyBanc Capital Markets, a division of McDonald
Investments, Inc., and Sanders Morris Harris, Inc. acted as
placement agents, we did not use a principal underwriter for any
of the issuances listed in the table below. Each such sale was
exempt from registration under the Securities Act of 1933, as
amended, in reliance on Section 4(2) of the Securities Act
and/or
regulations issued thereunder as sales to qualified purchasers
not involving a public offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
Date of Sale
|
|
Title and Amount of Securities Sold
|
|
|
Offering Price
|
|
|
Aggregate Offering Price
|
|
|
9/26/05
|
|
|
18,000,000 common shares(1
|
)
|
|
USD$
|
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
|
|
23
|
|
|
(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 Amended and
Restated 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.
|
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, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
Number of
|
|
|
|
|
|
Common Shares Remaining
|
|
|
|
Common Shares to be Issued
|
|
|
Weighted-Average
|
|
|
Available for Future
|
|
|
|
Upon Exercise of
|
|
|
Exercise Price of
|
|
|
Issuance Under
|
|
|
|
Outstanding Options and
|
|
|
Outstanding Options
|
|
|
Equity Compensation
|
|
Plan Category
|
|
Warrants
|
|
|
and Warrants
|
|
|
Plans
|
|
|
Equity compensation plans approved by shareholders
|
|
|
1,579,931
|
(1)
|
|
$
|
1.27
|
|
|
|
4,029,000
|
(2)
|
Equity compensation plans not approved by shareholders
|
|
|
1,037,200
|
(3)
|
|
$
|
1.25
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,617,131
|
|
|
|
N/A
|
|
|
|
4,029,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Represents the number of common shares underlying outstanding
options that were issued under our Incentive Stock Option Plan,
which has been superseded by our Amended and Restated 2005
Omnibus Stock Plan.
|
|
(2)
|
|
Represents the number of common shares remaining available for
issuance under our Amended and Restated 2005 Omnibus Stock Plan.
As of July 31, 2007, we have issued 2,921,000 restricted
common shares and 50,000 options under our Amended and Restated
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 2004/January 2005
private placement.
|
24
|
|
ITEM 6.
|
Selected
Financial Data.
|
The following sets forth our selected historical financial data
as of July 31, 2007, 2006, 2005, 2004 and 2003 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, 2007, 2006 and 2005 and for our fiscal years
ended July 31, 2007, 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 and 2003 and for our fiscal
years ended July 31, 2004 and 2003 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 titled 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands, except per share amounts)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales(1)
|
|
$
|
1,204
|
|
|
$
|
1,126
|
|
|
$
|
118
|
|
|
$
|
|
|
|
$
|
|
|
Operating expenses
|
|
|
22,397
|
|
|
|
8,117
|
|
|
|
6,372
|
|
|
|
1,081
|
|
|
|
1,095
|
|
Ceiling write-down of gas properties
|
|
|
11,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(20,641
|
)
|
|
|
(8,836
|
)
|
|
|
(6,121
|
)
|
|
|
(1,091
|
)
|
|
|
(1,109
|
)
|
Net loss
|
|
|
(20,641
|
)
|
|
|
(8,836
|
)
|
|
|
(5,397
|
)
|
|
|
(793
|
)
|
|
|
(934
|
)
|
Net loss per common share
|
|
|
(0.30
|
)
|
|
|
(0.14
|
)
|
|
|
(0.14
|
)
|
|
|
(0.03
|
)
|
|
|
(0.04
|
)
|
Weighted average number of shares outstanding
|
|
|
69,755,778
|
|
|
|
62,789,319
|
|
|
|
37,665,019
|
|
|
|
25,007,237
|
|
|
|
21,485,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of July 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands, except per share amounts)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
39,843
|
|
|
$
|
49,052
|
|
|
$
|
23,528
|
|
|
$
|
9,383
|
|
|
$
|
6,328
|
|
Long-term notes payable (including current maturities)
|
|
|
9,136
|
|
|
|
216
|
|
|
|
550
|
|
|
|
462
|
|
|
|
378
|
|
Cash dividends per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Gas sales commenced in January 2005.
|
|
|
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 you 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.
|
25
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),
which encompasses a total area of approximately
60,000 square miles covering the southern two-thirds of
Illinois, southwestern Indiana and northwestern Kentucky. Our
Canadian activities are limited to administrative reporting
obligations to the province of British Columbia and regulatory
reporting to the British Columbia and Alberta Securities
Commissions.
As of July 31, 2007, we owned or controlled CBM rights,
through mineral leases, a farm-out agreement and ownership of a
CBM estate, covering approximately 512,000 total acres in the
Basin (approximately 99% of this acreage is undeveloped as of
July 31, 2007). Portions of our CBM rights are currently
subject to litigation, as described in Item 3 of
Part I above. 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 four millidarcies.
The State of Illinois (which includes most of the Basin) is
estimated to be the number two state in the United States in
terms of coal reserves; however, coal in the Basin is high in
sulfur, discouraging coal mining operations. Recent advances in
technology that can utilize higher sulfur 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. We believe our position as a 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. Net gas sales during the fiscal year ended July 31,
2005 were $117,835 on sales volume of 17,885 Mcf. Net gas
sales were $1,126,477 on sales volume of 135,118 Mcf for
the fiscal year ended July 31, 2006, an increase of 856% in
net gas sales and 655% in sales volume over the prior year. Net
gas sales for the fiscal year ended July 31, 2007 were
$1,204,252 on sales volume of 185,305 Mcf reflecting an
increase of 7% in net gas sales and an increase of 37% in sales
volume compared to the fiscal year ended July 31, 2006. As
previously disclosed, net gas sales in the second quarter of
fiscal year 2007 were adversely affected by a nitrogen-related
pipeline curtailment that began in October and necessitated six
days of downtime followed by a period of constrained sales
volume. A nitrogen-rejection unit was installed and began
operating in March 2007.
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 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. In the last quarter of fiscal year 2007 and the first
quarter of fiscal year 2008 we have increased our acreage by
approximately 12,000 acres, a 2% increase in total acreage.
However, we have committed
26
ourselves to transitioning 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 million. In July
2007, we secured a $75 million advancing term credit
facility from GasRock. The initial commitment under this
facility was $10.2 million of which we drew
$9.1 million at closing.
In April 2006, we hired James E. Craddock, our Chief Operating
Officer. Prior to joining us, Mr. Craddock was with
Burlington Resources for over 20 years, last serving as
Chief Engineer. Mr. Craddock has built a strong in-house
technical team, 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 us.
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. In May 2007, we announced
our decision to continue production activities at our Shelby
Pilot, while deferring additional development pending further
production and pressure information. We use pilot projects to
cost-effectively high-grade our extensive acreage position
before committing development capital in a particular area. In
the case of the Shelby Pilot, the pressure and production
results to date do not provide a sufficient likelihood of
commercial success to move into development at this early stage.
Production history, as well as our ongoing work to reduce
development costs and improve well performance, may make
development at the Shelby Pilot area viable in the future. The
Shelby Pilot represents only 400 acres of our 512,000-acre
leasehold position.
During fiscal year 2007, we drilled 45 new wells, including 15
productive wells, seven test wells, two pressure observation
wells, two water disposal wells and 19 wells drilled but
waiting on completion. Two of these wells are in the Western
Illinois Basin Project, 23 are in the Southern Illinois Basin
Project, and 20 are in the Northern Illinois Basin Project.
In April 2007, we initiated our third pilot project in Macoupin
County. This 12-well pilot program was completed at the end of
the fourth quarter of fiscal year 2007 and consists of 10 pilot
wells, one pressure observation well and one water disposal well
(part of the 20 Northern Illinois Basin Project wells listed
above). All 12 wells were drilled, completed and started
pumping by July 2007.
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.
Managements focus for fiscal year 2008 will be to:
|
|
|
|
|
continue development drilling at the Southern Illinois Basin
Project;
|
|
|
|
continue to obtain test data and initiate pilot projects that
demonstrate the commercial potential of CBM at our various
acreage blocks and projects in the Basin;
|
|
|
|
continue to reduce well drilling and completion costs;
|
|
|
|
continue acreage acquisitions;
|
|
|
|
increase total company reserves; and
|
|
|
|
grow total production.
|
Gathering test data and siting pilot projects based on this data
should lead to proving project viability in multiple areas in
the Basin. These pilot projects may have the potential to grow
into development projects that will increase our total reserves
and production. As we drill new wells, our production should
continue to increase, as the
27
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 technical evaluation of the assets that we control
should lead to more cost effective drilling and completion
techniques that can be implemented to improve capital
efficiency, increase resource recovery and total reserves and
improve internal rates of return from development projects.
We currently control approximately 512,000 acres of CBM
rights and, assuming
80-acre
vertical well spacing and the development of all of our acreage,
have the possibility of over 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 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 in 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 with 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 gas properties.
Under this method, all costs associated with the acquisition of,
exploration for and development of gas 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 gas activities that
are directly attributable to acquisition, exploration or
development activities capitalized to properties and equipment
on the balance sheet. During the fiscal year ended July 31,
2007, we capitalized approximately $532,000 of internal labor
and benefit costs determined to be directly attributable to
acquisition, exploration or development activities.
28
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. During the fiscal year ended July 31,
2007, we recognized a ceiling write-down of $11,722,153 as a
result of the carrying amount of net gas properties exceeding
the full cost ceiling limitation, which was based on a year-end
gas price of $6.51 per Mcf.
Capitalized costs of proved gas properties, including estimated
future costs to develop the reserves and estimated abandonment
costs, net of salvage, are amortized on the units-of-production
method using estimates of proved reserves.
Unproved 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.
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 demonstrates, 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. We had 1,579,931 options outstanding under
the Incentive Stock Option Plan at July 31, 2007.
On December 18, 2006, our shareholders approved the Amended
and Restated 2005 Omnibus Stock Plan (the Omnibus Stock
Plan), which our shareholders had originally approved on
December 13, 2005. 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
29
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 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 Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting
Standards (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 No. 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 Opinion
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 No. 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 valuation model 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 SFAS 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 a tax benefit
in the United States for our fiscal year ended July 31,
2005 to partially offset a previously recorded deferred tax
liability.
30
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. Therefore, FASB Interpretation Number 48 will be effective
for us beginning in the fiscal year ending July 31, 2008.
We are currently assessing the effect of this Interpretation, if
any, on our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements. The standard provides
guidance for using fair value to measure assets and liabilities.
Under the standard, fair value refers to the price that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants in the market in
which the reporting entity transacts. The standard clarifies the
principle that fair value should be based on the assumptions
market participants would use when pricing the asset or
liability. In support of this principle, the standard
establishes a fair value hierarchy that prioritizes the
information used to develop those assumptions. The statement is
effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods
within those fiscal years. Therefore, SFAS No. 157
will be effective for us beginning in the fiscal year ending
July 31, 2009. We are currently evaluating the statement to
determine what impact, if any, it will have on our consolidated
financial statements.
During February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities Including an amendment of FASB Statement
No. 115. The standard permits an entity to make an
irrevocable election to measure most financial assets and
financial liabilities at fair value. An entity may elect the
fair value option on an instrument-by-instrument basis, with a
few exceptions, as long as it applies the fair value option to
the instrument in its entirety. Changes in fair value would be
recorded in income. SFAS No. 159 establishes presentation
and disclosure requirements intended to help financial statement
users understand the effect of the entitys election on
earnings. SFAS No. 159 is effective as of the beginning of
the first fiscal year beginning after November 15, 2007.
Therefore, we will need to comply with SFAS No. 159
beginning in the fiscal year ending July 31, 2009, unless
we adopt it earlier. We are currently evaluating the statement
to determine what impact, if any, it will have on our
consolidated financial statements.
Results
of Operations
Year
Ended July 31, 2007 Compared to Year Ended July 31,
2006
The following table presents our financial data for fiscal year
2007 compared to fiscal year 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
1,204,252
|
|
|
$
|
1,126,477
|
|
|
$
|
77,776
|
|
|
|
7
|
%
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
1,607,913
|
|
|
|
970,791
|
|
|
|
637,122
|
|
|
|
66
|
%
|
General and administrative expense
|
|
|
8,237,838
|
|
|
|
6,576,131
|
|
|
|
1,661,708
|
|
|
|
25
|
%
|
Depreciation, depletion and amortization
|
|
|
829,154
|
|
|
|
570,303
|
|
|
|
258,851
|
|
|
|
45
|
%
|
Ceiling write-down of gas properties
|
|
|
11,722,153
|
|
|
|
|
|
|
|
11,722,153
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
22,397,058
|
|
|
|
8,117,224
|
|
|
|
14,279,834
|
|
|
|
176
|
%
|
Operating loss
|
|
|
(21,192,806
|
)
|
|
|
(6,990,748
|
)
|
|
|
(14,202,058
|
)
|
|
|
(203
|
)%
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
564,070
|
|
|
|
941,351
|
|
|
|
(377,281
|
)
|
|
|
(40
|
)%
|
Interest expense
|
|
|
(11,752
|
)
|
|
|
(22,405
|
)
|
|
|
10,653
|
|
|
|
48
|
%
|
Other income (expense)
|
|
|
|
|
|
|
(2,764,443
|
)
|
|
|
2,764,443
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
552,318
|
|
|
|
(1,845,497
|
)
|
|
|
2,397,815
|
|
|
|
130
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(20,640,488
|
)
|
|
|
(8,836,244
|
)
|
|
|
(11,804,244
|
)
|
|
|
(136
|
)%
|
Deferred income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(20,640,488
|
)
|
|
$
|
(8,836,244
|
)
|
|
$
|
(11,804,244
|
)
|
|
|
(136
|
)%
|
31
Revenue
Revenue from gas sales increased
$77,776 in fiscal year 2007, an increase of 7% over fiscal year
2006. Net sales of gas (net of royalties) were 185,305 Mcf
for fiscal year 2007 compared to 135,118 Mcf for fiscal
year 2006, an increase of 37%. However, our average realized
selling price per Mcf decreased to $6.50 in fiscal year 2007
compared to $8.34 in fiscal year 2006. The increase in net sales
volume would have been greater except that it was negatively
impacted by a nitrogen-related pipeline curtailment that began
in October 2006 and necessitated six days of downtime followed
by a period of constrained sales volume during the second
quarter and a portion of the third quarter of fiscal year 2007.
A nitrogen-rejection unit was constructed and began operating in
March 2007 and daily production and sales have since reached new
highs.
Lease operating expense
Lease operating
expense increased $637,122 in fiscal year 2007, an increase of
66% over fiscal year 2006. Lease operating expenses represent
production expenses, consisting primarily of repairs and
maintenance, fuel and electricity, equipment rental, workovers
and labor and other overhead expenses related to producing
wells. The increase is primarily due to expenses associated with
non-recurring workover projects incurred during the second
quarter of fiscal year 2007 at the Southern Illinois Basin
Project designed to increase production of existing wells, as
well as an increase in the number of producing wells and the
related costs incurred due to the increase in gas production at
the Southern Illinois Basin Project, new lease operating
expenses at our pilot projects in the Northern Illinois Basin
and the hiring of additional personnel.
General and administrative expense
General
and administrative expense consisted of the following for fiscal
year 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Salaries and benefits
|
|
$
|
3,418,001
|
|
|
$
|
2,027,707
|
|
|
$
|
1,390,295
|
|
|
|
69
|
%
|
Share-based compensation expense
|
|
|
1,645,990
|
|
|
|
1,377,440
|
|
|
|
268,550
|
|
|
|
19
|
%
|
Professional and regulatory
|
|
|
1,969,631
|
|
|
|
2,652,384
|
|
|
|
(682,754
|
)
|
|
|
(26
|
)%
|
Other
|
|
|
1,204,216
|
|
|
|
518,600
|
|
|
|
685,617
|
|
|
|
132
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expense
|
|
$
|
8,237,838
|
|
|
$
|
6,576,131
|
|
|
$
|
1,661,708
|
|
|
|
25
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Salaries and benefits increased $1,390,295 in fiscal year 2007,
an increase of 69% over fiscal year 2006. The net increase was
primarily the result of increased base salaries associated with
hiring additional personnel to support our growth, including our
Chief Operating Officer during the fourth quarter of fiscal
year 2006 and three engineers and a geologist during the first
quarter of fiscal year 2007, and cash signing bonuses totaling
$350,000 paid to such personnel. In addition, fiscal year 2007
expense includes $250,000 severance paid to our former Chief
Financial Officer and General Counsel, who resigned in the first
quarter of fiscal year 2007.
Non-cash expense associated with share-based compensation
increased $268,550 in fiscal year 2007, a 19% increase over
fiscal year 2006. Share-based compensation expense in fiscal
year 2007 represents approximately $838,000 of expense
recognized on a pro rata basis for the anticipated vesting of
restricted shares outstanding, approximately $326,000 of expense
related to the grant of 350,000 unrestricted common shares to
newly hired members of our technical team and approximately
$482,000 of expense related to the grant of 811,161 unrestricted
common shares and 50,000 stock options to certain executive
officers, employees, non-employee directors and advisory board
members primarily in connection with bonuses and directors
fees. Share-based compensation expense in fiscal year 2006
represented approximately $527,000 of expense related to the
grant of 495,000 stock options to employees and directors,
approximately $625,000 of expense related to fully vested shares
granted to a new officer and a new director and approximately
$225,000 of expense recognized on a pro rata basis for the
anticipated vesting of restricted shares outstanding. We intend
to continue to rely on the granting of equity-based awards,
primarily restricted shares, in order to attract and retain
qualified individuals and to conserve cash so that it may be
utilized in executing our drilling program.
Professional and regulatory fees decreased $682,754 in fiscal
year 2007, a decrease of 26% over fiscal year 2006. The net
decrease is primarily due to decreased legal fees due to the
settlement of the Colt LLC litigation during fiscal year 2006
and lower professional and regulatory fees associated with the
filing of our initial SEC registration statements and listing on
the American Stock Exchange during fiscal year 2006. These
decreases were partially offset by increases in insurance costs,
investor relations fees and information technology consulting
fees.
32
Other general and administrative expenses increased $685,617 in
fiscal year 2007, an increase of 132% over fiscal year 2006. The
increase is primarily due to amortization of costs associated
with a separation agreement entered into with our former Chief
Financial Officer, newly incurred directors fees, employee
relocation costs related to the hiring of our new technical team
and additional rent and office expenses related to the
Edwardsville, Illinois office, which opened during the fourth
quarter of fiscal year 2006.
Depreciation, depletion and amortization
expense
Depreciation, depletion and amortization
expense (DD&A) increased $258,851 in fiscal
year 2007, an increase of 45% over fiscal year 2006. We compute
DD&A on proved gas properties related to 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 development costs we incurred on proved gas
properties and an increase in our production over fiscal year
2006.
Interest income
Interest income decreased
$377,281 in fiscal year 2007, a decrease of 40% over fiscal year
2006 due to lower cash balances during fiscal year 2007. We
invest our excess cash in overnight sweep accounts and
high-grade commercial paper with maturities of 30 days or
less.
Ceiling write-down of gas properties
We
recognized a ceiling write-down of $11,722,153 during the fiscal
year ended July 31, 2007 as a result of the carrying amount
of net gas properties exceeding the full cost ceiling
limitation, which was based on a year-end gas price of $6.51 per
Mcf. No ceiling write-down was required during fiscal year 2006.
Other income (expense)
Other income (expense)
decreased $2,764,443 from fiscal year 2006 due primarily to the
loss that was recognized in fiscal year 2006 related to the Colt
LLC settlement.
Year
Ended July 31, 2006 Compared to Year Ended July 31,
2005
The following table presents our 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
|
|
|
|
864
|
%
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
971,791
|
|
|
|
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
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
8,117,224
|
|
|
|
6,372,440
|
|
|
|
1,744,784
|
|
|
|
27
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(6,990,748
|
)
|
|
|
(6,254,605
|
)
|
|
|
(736,143
|
)
|
|
|
(12
|
)%
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(1,845,497
|
)
|
|
|
133,784
|
|
|
|
(1,979,281
|
)
|
|
|
(1,479
|
)%
|
Loss before income taxes
|
|
|
(8,836,244
|
)
|
|
|
(6,120,821
|
)
|
|
|
(2,715,423
|
)
|
|
|
(44
|
)%
|
Deferred income tax benefit
|
|
|
|
|
|
|
724,470
|
|
|
|
(724,470
|
)
|
|
|
(100
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(8,836,244
|
)
|
|
$
|
(5,397,351
|
)
|
|
$
|
(3,439,893
|
)
|
|
|
(64
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
Revenue from gas sales increased
$1,008,642 in fiscal year 2006, an increase of 864% 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.
33
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
years 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
|
%
|
Share-based payments
|
|
|
1,377,440
|
|
|
|
3,344,738
|
|
|
|
(1,967,298
|
)
|
|
|
(59
|
)%
|
Professional and regulatory
|
|
|
2,652,384
|
|
|
|
1,183,402
|
|
|
|
1,468,982
|
|
|
|
124
|
%
|
Other
|
|
|
518,600
|
|
|
|
382,840
|
|
|
|
135,760
|
|
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expense
|
|
$
|
6,576,131
|
|
|
$
|
5,805,121
|
|
|
$
|
771,010
|
|
|
|
13
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
Share-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.
Professional and regulatory fees increased $1,468,982 in fiscal
year 2006, an increase of 124% 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
|
|
|
153,739
|
|
|
|
|
|
|
Total increase over corresponding period in the
preceding year
|
|
$
|
1,468,982
|
|
|
|
|
|
|
Other general and administrative expenses increased $135,760, an
increase of 35% over fiscal year 2005, primarily as a result of
increased office and travel-related expenses.
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
34
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 were 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 invest our excess
cash in overnight sweep accounts and high-grade commercial paper
with maturities of 30 days or less.
Other income
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 Hite Coalbed
Methane, L.L.C. (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.
Liquidity
and Capital Resources
Historically, our primary source of liquidity 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. On July 27, 2007, we closed an Advancing Term
Credit Agreement (the Credit Agreement) with GasRock
Capital LLC (GasRock). The Credit Agreement provides
for an initial commitment to us of $10.2 million and the
possibility of future advances to us of up to an additional
$64.8 million. All future advances under the Credit
Agreement beyond the initial commitment will be made in
GasRocks discretion. Proceeds are expected to be used for
continued development-well drilling at the Southern Illinois
Basin Project, drilling of new test wells, pilot projects, lease
acquisitions and general and administrative expenses. We may
request advances under the Credit Agreement at any time before
July 25, 2008, which GasRock may in its discretion extend
until July 27, 2010. All amounts then outstanding under the
Credit Agreement are due and payable on July 25, 2008,
which GasRock may in its discretion extend until July 29,
2011. On July 27, 2007, we received an initial advance of
$9,059,566 under the Credit Agreement, which resulted in net
proceeds to us of $8,223,912 after the deduction of
GasRocks facility fee, investment banking fees, legal fees
and other fees and expenses incurred by us in connection with
the transaction totaling $835,654.
As of July 31, 2007, we had $9,135,616 in long-term debt
and notes payable, of which $9,087,551 is classified as current.
Over the past five fiscal years, we raised $43.8 million
from the sale of our common shares. Additionally, during that
same period, we collected $6.8 million as a result of the
exercise of warrants and $2.1 million 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 and payment of lease operating and
general and administrative expenses required to support our
operations.
We did not begin to generate revenues from CBM sales until
January 2005. Revenues from CBM sales were $1,204,252,
$1,126,477 and $117,835 in fiscal years ended July 31,
2007, 2006 and 2005, respectively. We expect revenue from the
sale of our CBM to continue 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.
In addition, 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
35
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 $11,291,575 at July 31, 2007,
compared to $19,279,015 at July 31, 2006. Our revenues and
current cash balance will not be sufficient to fund our capital
program for fiscal 2008 or our operations beyond July 31,
2008. Therefore, we will need to obtain additional commitments
from GasRock under the Credit Agreement
and/or
raise
additional financing in the near future. We currently do not
have any specific plans to raise financing in support of our
future operations and forecasted capital expenditures, but we
anticipate raising the additional required capital through one
or a combination of the following:
|
|
|
|
|
additional advances under the Credit Agreement;
|
|
|
|
issuance of new debt
and/or
equity securities; or
|
|
|
|
joint ventures.
|
Cash
Used in Operating Activities
Net cash used in operating activities for fiscal year 2007 was
$5,491,048 compared with $6,560,034 and $2,474,443 in fiscal
years 2006 and 2005, respectively. Net cash used in operating
activities increased significantly in fiscal years 2005 and 2006
over previous fiscal years as we added the resources and
expertise necessary to support the growth in the size of our
projects in the Basin and substantially increased our
exploration, development and operating activities. In addition,
in order to provide liquidity to our shareholders, we took the
steps necessary in fiscal year 2005 to have our stock listed on
the American Stock Exchange, which required us to incur a higher
level of general and administrative expenses. In fiscal year
2007, our net cash used in operating activities stabilized,
decreasing slightly from the prior year.
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:
|
|
|
|
|
the price of, and demand for, natural gas;
|
|
|
|
availability of drilling and service equipment and personnel;
|
|
|
|
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 2007 was
$10,443,037 compared with $14,517,293 and $6,338,082 in fiscal
years 2006 and 2005, respectively. The increase in net cash used
in investing activities during fiscal year 2006 over fiscal year
2005 and the decrease in net cash used in investing activities
during fiscal year 2007 over fiscal year 2006 are primarily the
result of exploration and development costs at our projects.
Cash
Provided by Financing Activities
Net cash provided by financing activities for fiscal year 2007
was $7,946,646 compared with $33,104,839 and $15,093,233 during
fiscal years 2006 and 2005, respectively. The increases in net
cash provided by financing activities during fiscal year 2006 is
primarily the result of increased proceeds from common shares
issued in private placements and from the exercise of stock
options and warrants during fiscal year 2006. During fiscal year
2007, our sole proceeds were from the initial advance of
$9,059,566 under the Credit Agreement, which resulted in net
proceeds to us of $8,223,912 after the deduction of
GasRocks facility fee, investment banking fees, legal fees
and other fees and expenses incurred by us in connection with
the transaction totaling $835,654. We continue to pay down our
long-term notes, making payments of $139,966 in fiscal year
2007, $175,282 in fiscal year 2006 and $41,320 in fiscal year
2005. Our long-term debt and notes payable (including current
maturities) increased from $216,015 at July 31, 2006 to
$9,135,616 at July 31, 2007. We expect to continue to
reduce our long-term notes
36
payable by making scheduled principal payments of approximately
$9,087,551 in fiscal year 2008. There are no principal payments
scheduled to be made under the Credit Agreement until
July 25, 2008, at which time the entire amount, including
capitalized interest, is payable unless extended in
GasRocks discretion.
Capital
Expenditure Plan
We have no contractual commitments for capital expenditures.
During the
12-month
period ending July 31, 2008, we plan to drill between 30
and 70 new wells. This plan contemplates capital expenditures of
approximately $10 million to $23 million. The number
of wells that we drill during the
12-month
period ending July 31, 2008 will be dependent on
(i) data obtained from test wells; (ii) data obtained
from our pilot wells; (iii) additional financing we are
able to secure, including additional advances we are able to
make under the Credit Agreement; and (iv) the risk factors
described in this report. In addition to our drilling program,
we expect to pursue the acquisition of additional CBM rights
during fiscal year 2008. We expect that this capital expenditure
program and our other cash requirements will be funded by our
cash balance, which as of October 22, 2007 is approximately
$5.7 million, and cash raised through additional financing
sources that may include additional advances under the Credit
Agreement, issuance of new debt
and/or
equity securities
and/or
joint
ventures. Although we are currently evaluating the best options
to raise the necessary funds, we can provide no assurance that
we will be able to raise the necessary funds.
Contractual
Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
|
|
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Contractual Obligations as of July 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
9,087,551
|
|
|
$
|
48,065
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
9,135,616
|
|
Equipment leases
|
|
|
164,472
|
|
|
|
328,944
|
|
|
|
|
|
|
|
|
|
|
|
493,416
|
|
Asset retirement obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
114,172
|
|
|
|
114,172
|
|
Other leases(1)
|
|
|
121,260
|
|
|
|
109,171
|
|
|
|
54,598
|
|
|
|
230,343
|
|
|
|
515,373,284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
9,373,283
|
|
|
$
|
486,180
|
|
|
$
|
54,598
|
|
|
$
|
344,515
|
|
|
$
|
10,258,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 22, 2007 expire at various times beginning in
November 2008. If we were to pay the total minimum royalty
payments due under all lease/farm-out agreements in existence as
of October 22, 2007, 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,
2007.
|
|
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.
Under the terms of our Credit Agreement with GasRock, we are
required to enter into derivatives contracts covering
approximately 75% of the our proved developed producing reserves
scheduled to be produced during a two-year period at a
guaranteed price of not less than $7.00 per MMBtu. The objective
is to reduce our exposure to commodity price risk associated
with expected gas production. By achieving this objective, we
may protect the
37
outstanding debt amounts and maximize the funds available under
our existing credit agreement, which helps us to support our
annual capital budgeting and expenditure plans.
Our risk management strategy is to enter into commodity
derivatives that set price floors and price
ceilings for our natural gas production. On July 31,
2007, we entered into a costless collar contract
with BP for the notional amount of 20,000 MMBtu per month
beginning September 1, 2007 through July 31, 2009.
Under the terms of the contract, BP is required to cover any
shortfall below the floor of $7.00 per MMBtu and we must pay to
BP any amounts above the ceiling of $11.00 per MMBtu as to the
notional amount, with the price being based on the second to
last close of the NYMEX forward price for each month. We expect
that we will enter into additional hedging arrangements during
the next two years to cover the entire 75% of our proved
developed producing reserves scheduled to be produced during
that period.
We have elected not to designate the commodity derivatives to
which we are a party as hedges, and accordingly, such contracts
are recorded at fair value on our consolidated balance sheets
and changes in such fair value are recognized in current
earnings as they occur. We do not hold or issue commodity
derivatives for speculative or trading purposes. We are exposed
to credit losses in the event of nonperformance by the
counterparty to our commodity derivatives. It is anticipated,
however, that our counterparty, BP, will be able to fully
satisfy its obligations under the commodity derivatives
contracts. We do not obtain collateral or other security to
support our commodity derivatives contracts subject to credit
risk but we do monitor the credit standing of the counterparty.
Realized gains or losses from the settlement of gas derivative
contracts are reported as natural gas revenue on the
consolidated statements of operations. Our first commodity
derivatives contract was entered into on July 31, 2007 with
the first settlement month designated as September 2007. Thus,
no settlements occurred during the fiscal year ended
July 31, 2007.
Interest
Rate Risk
Our exposure to changes in interest rates results from the
Credit Agreement with GasRock. For the first year of the term of
the Credit Agreement, all amounts outstanding under the Credit
Agreement will bear interest at a rate equal to the greater of
(i) 15% per annum and (ii) the LIBOR rate plus 9% per
annum. If GasRock extends the loan termination date of
July 25, 2008, amounts outstanding under the Credit
Agreement will thereafter bear interest at a rate equal to the
greater of (i) 12% per annum and (ii) the LIBOR rate
plus 6% per annum. The principal amount due under the credit
facility at July 31, 2007 was $9,059,566. A 1% change in
interest rates would affect pre-tax net loss by approximately
$90,000 per year.
Financial
Instruments
Our financial instruments consist of cash and cash equivalents,
accounts receivable and debt 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.
38
|
|
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 Acting Chief
Financial Officer, has evaluated the effectiveness of our
disclosure controls and procedures (as defined in Exchange Act
Rule 13a-15)
as of July 31, 2007. Based on that evaluation, our Chief
Executive Officer and Acting Chief Financial Officer concluded
that our disclosure controls and procedures were effective as of
July 31, 2007 in alerting them on a timely basis to
material information relating to us (including our consolidated
subsidiaries) required to be included in our periodic filings
under the Exchange Act.
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, 2007 that materially
affected, or are reasonably likely to affect, our internal
control over financial reporting.
|
|
ITEM 9B.
|
Other
Information.
|
None.
PART III
|
|
ITEM 10.
|
Directors,
Executive Officers and Corporate Governance.
|
We incorporate herein by reference the information appearing
under the caption Proposal No. 1
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 SEC within 120 days after the end of
our fiscal year.
Information concerning our executive officers is contained in
Item 1 of Part I of this 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 our website at
www.bpi-energy.com
.
|
|
ITEM 11.
|
Executive
Compensation.
|
We incorporate herein by reference the information appearing
under the captions Compensation Discussion and
Analysis, 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.
See Part II, Item 5 for information regarding our
equity compensation plans.
|
|
ITEM 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
We incorporate herein by reference the information appearing
under the caption Certain Relationships and Related
Transactions and
Proposal No. 1 Election of
Directors in our definitive proxy statement.
|
|
ITEM 14.
|
Principal
Accountant Fees and Services.
|
We incorporate herein by reference the information appearing
under the caption Proposal No. 2
Ratification of Appointment of Independent Registered Accounting
Firm in our definitive proxy statement.
39
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.
40
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 report:
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.
Mcf.
One thousand cubic feet of natural gas at
standard atmospheric conditions.
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.
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 SECs rules and regulations. 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.
A-1
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.
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,
2007 and 2006, and the related statements of operations,
shareholders equity, and cash flows for the three years
ended July 31, 2007. 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, 2007 and 2006, and the results of its operations
and its cash flows for the three years ended July 31, 2007,
in conformity with accounting principles generally accepted in
the United States of America.
Certified Public Accountants
October 24, 2007
Cleveland, Ohio
F-2
BPI
ENERGY HOLDINGS, INC.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
11,292
|
|
|
$
|
19,279
|
|
Accounts receivable
|
|
|
94
|
|
|
|
106
|
|
Other current assets
|
|
|
1,948
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
13,334
|
|
|
|
19,550
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
Gas properties, full cost method of accounting:
|
|
|
|
|
|
|
|
|
Proved, net of accumulated depreciation, depletion and
amortization of $899 and $375 and ceiling write-down of $11,722
and $0
|
|
|
16,631
|
|
|
|
25,065
|
|
Unproved, excluded from amortization
|
|
|
8,533
|
|
|
|
3,368
|
|
Support equipment, net of accumulated depreciation and
amortization of $741 and $548
|
|
|
552
|
|
|
|
499
|
|
|
|
|
|
|
|
|
|
|
Net gas properties
|
|
|
25,716
|
|
|
|
28,932
|
|
Other property and equipment, net of accumulated depreciation
and amortization of $152 and $39
|
|
|
473
|
|
|
|
309
|
|
|
|
|
|
|
|
|
|
|
Net property and equipment
|
|
|
26,189
|
|
|
|
29,241
|
|
Restricted cash
|
|
|
100
|
|
|
|
100
|
|
Other non-current assets
|
|
|
220
|
|
|
|
161
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
39,843
|
|
|
$
|
49,052
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,371
|
|
|
$
|
1,493
|
|
Current maturities of long-term debt and notes payable
|
|
|
9,088
|
|
|
|
141
|
|
Accrued liabilities and other
|
|
|
1,503
|
|
|
|
649
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,962
|
|
|
|
2,283
|
|
Long-term debt and notes payable, less current maturities
|
|
|
48
|
|
|
|
75
|
|
Asset retirement obligation
|
|
|
114
|
|
|
|
71
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
12,124
|
|
|
|
2,429
|
|
Shareholders Equity
|
|
|
|
|
|
|
|
|
Common shares, no par value, authorized 200,000,000 shares,
72,524,493 and 70,812,540 issued and outstanding
|
|
|
67,946
|
|
|
|
67,946
|
|
Additional paid-in capital
|
|
|
7,608
|
|
|
|
5,871
|
|
Accumulated deficit
|
|
|
(47,835
|
)
|
|
|
(27,194
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
27,719
|
|
|
|
46,623
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity
|
|
$
|
39,843
|
|
|
$
|
49,052
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-3
BPI
ENERGY HOLDINGS, INC.
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands, except per share data)
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
1,204
|
|
|
$
|
1,126
|
|
|
$
|
118
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
1,608
|
|
|
|
971
|
|
|
|
307
|
|
General and administrative expenses
|
|
|
8,238
|
|
|
|
6,576
|
|
|
|
5,805
|
|
Depreciation, depletion and amortization
|
|
|
829
|
|
|
|
570
|
|
|
|
260
|
|
Ceiling write-down of gas properties
|
|
|
11,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
22,397
|
|
|
|
8,117
|
|
|
|
6,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(21,193
|
)
|
|
|
(6,991
|
)
|
|
|
(6,254
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
564
|
|
|
|
941
|
|
|
|
123
|
|
Interest expense
|
|
|
(12
|
)
|
|
|
(22
|
)
|
|
|
(25
|
)
|
Other income (expense)
|
|
|
|
|
|
|
(2,764
|
)
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
552
|
|
|
|
(1,845
|
)
|
|
|
133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(20,641
|
)
|
|
|
(8,836
|
)
|
|
|
(6,121
|
)
|
Deferred income tax benefit
|
|
|
|
|
|
|
|
|
|
|
724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(20,641
|
)
|
|
$
|
(8,836
|
)
|
|
$
|
(5,397
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net loss per share
|
|
$
|
(0.30
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
(0.14
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
69,755,778
|
|
|
|
62,789,319
|
|
|
|
37,665,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-4
BPI
ENERGY HOLDINGS, INC.
Consolidated Statements of Shareholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Total
|
|
|
|
Common Shares
|
|
|
Paid-in
|
|
|
Accumulated
|
|
|
Shareholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Deficit
|
|
|
Equity
|
|
|
|
(Dollars in thousands)
|
|
|
Balance, July 31, 2004
|
|
|
28,374,296
|
|
|
$
|
19,508
|
|
|
$
|
1,163
|
|
|
$
|
(12,961
|
)
|
|
$
|
7,710
|
|
Proceeds from stock options exercised
|
|
|
2,254,333
|
|
|
|
1,617
|
|
|
|
|
|
|
|
|
|
|
|
1,617
|
|
Proceeds from warrants exercised
|
|
|
2,861,342
|
|
|
|
1,443
|
|
|
|
|
|
|
|
|
|
|
|
1,443
|
|
Net proceeds from shares issued in private placement
December 29, 2004(1)
|
|
|
2,400,000
|
|
|
|
2,794
|
|
|
|
|
|
|
|
|
|
|
|
2,794
|
|
Net proceeds from shares issued in private placement
December 30, 2004(2)
|
|
|
4,032,000
|
|
|
|
4,694
|
|
|
|
|
|
|
|
|
|
|
|
4,694
|
|
Net proceeds from shares issued in private placement
January 6, 2005(3)
|
|
|
3,723,200
|
|
|
|
4,334
|
|
|
|
|
|
|
|
|
|
|
|
4,334
|
|
Net proceeds from shares issued in private placement
January 12, 2005(4)
|
|
|
216,800
|
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
252
|
|
Bonus shares
|
|
|
50,990
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
Share-based compensation stock options
|
|
|
|
|
|
|
|
|
|
|
3,345
|
|
|
|
|
|
|
|
3,345
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
(14
|
)
|
|
|
|
|
|
|
(14
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,397
|
)
|
|
|
(5,397
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, July 31, 2005
|
|
|
43,912,961
|
|
|
|
34,665
|
|
|
|
4,494
|
|
|
|
(18,358
|
)
|
|
|
20,801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from stock options exercised
|
|
|
396,667
|
|
|
|
383
|
|
|
|
|
|
|
|
|
|
|
|
383
|
|
Proceeds from warrants exercised
|
|
|
5,822,075
|
|
|
|
5,014
|
|
|
|
|
|
|
|
|
|
|
|
5,014
|
|
Net proceeds from shares issued in private placement
September 23, 2005(5)
|
|
|
18,000,000
|
|
|
|
27,884
|
|
|
|
|
|
|
|
|
|
|
|
27,884
|
|
Share-based compensation stock options
|
|
|
|
|
|
|
|
|
|
|
527
|
|
|
|
|
|
|
|
527
|
|
Share-based compensation common shares (number of
shares include non-vested portion of restricted stock)
|
|
|
2,680,837
|
|
|
|
|
|
|
|
850
|
|
|
|
|
|
|
|
850
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,836
|
)
|
|
|
(8,836
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, July 31, 2006
|
|
|
70,812,540
|
|
|
|
67,946
|
|
|
|
5,871
|
|
|
|
(27,194
|
)
|
|
|
46,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation stock options
|
|
|
|
|
|
|
|
|
|
|
31
|
|
|
|
|
|
|
|
31
|
|
Share-based compensation common shares (number of
shares include non-vested portion of restricted stock)
|
|
|
1,795,883
|
|
|
|
|
|
|
|
1,843
|
|
|
|
|
|
|
|
1,843
|
|
Surrender of shares to pay taxes
|
|
|
(83,930
|
)
|
|
|
|
|
|
|
(137
|
)
|
|
|
|
|
|
|
(137
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,641
|
)
|
|
|
(20,641
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, July 31, 2007
|
|
|
72,524,493
|
|
|
$
|
67,946
|
|
|
$
|
7,608
|
|
|
$
|
(47,835
|
)
|
|
$
|
27,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
net of share issuance costs of $206
|
|
(2)
|
|
net of share issuance costs of $346
|
|
(3)
|
|
net of share issuance costs of $320
|
|
(4)
|
|
net of share issuance costs of $19
|
|
(5)
|
|
net of share issuance costs of $2,620
|
See notes to consolidated financial statements
F-5
BPI
ENERGY HOLDINGS, INC.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Cash Provided by (Used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(20,641
|
)
|
|
$
|
(8,836
|
)
|
|
$
|
(5,396
|
)
|
Adjustments to reconcile net loss to net cash used in operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and ceiling write-down
|
|
|
12,551
|
|
|
|
570
|
|
|
|
260
|
|
Share-based compensation expense
|
|
|
1,646
|
|
|
|
1,377
|
|
|
|
3,345
|
|
Gain on sale of marketable securities
|
|
|
|
|
|
|
(127
|
)
|
|
|
(42
|
)
|
Loss on disposal of property and equipment
|
|
|
|
|
|
|
|
|
|
|
16
|
|
Deferred income tax benefit
|
|
|
|
|
|
|
|
|
|
|
(725
|
)
|
Accretion of asset retirement obligation
|
|
|
4
|
|
|
|
3
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
7
|
|
|
|
21
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
12
|
|
|
|
(71
|
)
|
|
|
(35
|
)
|
Other current assets
|
|
|
(119
|
)
|
|
|
(141
|
)
|
|
|
21
|
|
Accounts payable
|
|
|
262
|
|
|
|
8
|
|
|
|
81
|
|
Accrued liabilities and other
|
|
|
854
|
|
|
|
649
|
|
|
|
11
|
|
Other assets and liabilities
|
|
|
(59
|
)
|
|
|
|
|
|
|
(32
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in operating activities
|
|
|
(5,490
|
)
|
|
|
(6,561
|
)
|
|
|
(2,475
|
)
|
Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of marketable securities
|
|
|
|
|
|
|
551
|
|
|
|
114
|
|
Business acquisition, net of cash acquired
|
|
|
|
|
|
|
|
|
|
|
(858
|
)
|
Additions to property and equipment
|
|
|
(10,444
|
)
|
|
|
(15,068
|
)
|
|
|
(5,416
|
)
|
Acquisition of equity interest in joint venture
|
|
|
|
|
|
|
|
|
|
|
(78
|
)
|
Increase in restricted cash
|
|
|
|
|
|
|
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(10,444
|
)
|
|
|
(14,517
|
)
|
|
|
(6,338
|
)
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of debt
|
|
|
9,060
|
|
|
|
|
|
|
|
|
|
Payments on long-term debt and notes payable
|
|
|
(140
|
)
|
|
|
(175
|
)
|
|
|
(41
|
)
|
Payment of deferred financing costs
|
|
|
(836
|
)
|
|
|
|
|
|
|
|
|
Payments for surrender of shares
|
|
|
(137
|
)
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of common shares
|
|
|
|
|
|
|
33,280
|
|
|
|
15,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
7,947
|
|
|
|
33,105
|
|
|
|
15,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(7,987
|
)
|
|
|
12,027
|
|
|
|
6,281
|
|
Cash and cash equivalents at the beginning of the year
|
|
|
19,279
|
|
|
|
7,252
|
|
|
|
971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at the end of the year
|
|
$
|
11,292
|
|
|
$
|
19,279
|
|
|
$
|
7,252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
12
|
|
|
$
|
19
|
|
|
$
|
12
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of shares in connection with separation agreement
|
|
|
228
|
|
|
|
|
|
|
|
|
|
Acquisition of equipment by issuance of notes payable
|
|
|
|
|
|
|
234
|
|
|
|
118
|
|
Cancellation of convertible note payable
|
|
|
|
|
|
|
392
|
|
|
|
|
|
Cashless exercise of warrants
|
|
|
|
|
|
|
284
|
|
|
|
|
|
Non-cash financing fees
|
|
|
600
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-6
BPI
ENERGY HOLDINGS, INC.
Notes to Consolidated Financial Statements
July 31, 2007, 2006 and 2005
(Dollars in thousands)
|
|
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. 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. (BPI Energy), 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 gas
exploration and production. The Companys common shares
trade on the American Stock Exchange under the symbol
BPG. Dollar amounts shown are in thousands of
U.S. Dollars, except for per share and per unit amounts and
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. The Company has experienced significant
losses in recent years, including $20,641 in the current year,
and has an accumulated deficit of $47,835 at July 31, 2007.
In addition, the current year net loss includes a full cost
ceiling write-down of the Companys gas properties in the
amount of $11,722. In order to continue as a going concern, the
Company must be able to finance both its current operations and
future exploration and development costs, and be able to resolve
any environmental, regulatory or other constraints, which may
hinder the successful development of its properties.
The Company has historically financed its activities primarily
from the proceeds of private placements of its common shares and
most recently from an advance on its $75 million advancing
term credit facility that closed on July 27, 2007, as
discussed in Note 9. The Company plans to finance future
operations through sources that may include additional advances
under its credit agreement, issuance of new debt
and/or
equity securities
and/or
joint
ventures. Although the Company is currently evaluating its
options to raise the necessary funds, it can provide no
assurance that it will be successful in doing so.
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 gas properties and
the impairment of gas properties are determined using estimates
of 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. Gas reserve engineering must be
recognized as a subjective process of estimating underground
accumulations of gas that cannot be measured in an exact way.
Proved reserves of 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 Company believes it could sell
its production; therefore, the loss of its single purchaser
would likely not have an adverse effect on the Companys
operations.
F-7
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
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 exerts 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 6, 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, which is included in other income (expense) in
the fiscal year ended July 31, 2006 consolidated statement
of operations. 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, 2007 and 2006, the Company has determined that no
allowance for uncollectible receivables was necessary.
Deferred
Financing Costs
The Company capitalizes costs incurred in connection with
borrowings or establishment of credit facilities. These costs
are amortized as an adjustment to interest expense over the life
of the borrowing or life of the credit facility using the
interest method. In the case of early debt principal repayments,
the Company adjusts the value of the corresponding deferred
financing costs with a charge to other expense, and similarly
adjusts the future amortization expense.
Commodity
Derivatives
The Company accounts for derivative instruments or hedging
activities under the provisions of Statement of Financial
Accounting Standards (SFAS) No. 133,
Accounting for Derivative Instruments and Hedging
Activities. SFAS No. 133 requires the Company to
record derivative instruments at their fair value.
Under the terms of the Companys Credit Agreement with
GasRock Capital LLC (GasRock), the Company is
required to enter into derivatives contracts covering
approximately 75% of its proved developed producing reserves
scheduled to be produced during a two-year period at a
guaranteed price of not less than $7.00 per MMBtu. The objective
is to reduce the Companys exposure to commodity price risk
associated with expected gas production.
The Companys risk management strategy is to enter into
commodity derivatives that set price floors and
price ceilings for its natural gas production. On
July 31, 2007, the Company has entered into a
costless collar contract with BP Corporation North
America Inc. (BP) for the notional amount of
20,000 MMBtu per month beginning September 1, 2007
through July 31, 2009. Under the terms of the contract, BP
is required to cover any shortfall below the floor of $7.00 per
MMBtu and the Company must pay to BP any amounts above the
ceiling of $11.00 per MMBtu as to the notional amount, with the
price being based on the second to last close of the NYMEX
forward price for each month. The Company expects that it will
enter into additional hedging arrangements during
F-8
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
the next two years to cover the entire 75% of its proved
developed producing reserves scheduled to be produced during
that period.
The Company has elected not to designate the commodity
derivatives to which they are a party as hedges, and
accordingly, such contracts are recorded at fair value on its
consolidated balance sheets and changes in such fair value are
recognized in current earnings as other income or expense as
they occur. The Company does not hold or issue commodity
derivatives for speculative or trading purposes. The Company is
exposed to credit losses in the event of nonperformance by the
counterparty to its commodity derivatives. It is anticipated,
however, that its counterparty, BP, will be able to fully
satisfy its obligations under the commodity derivatives
contracts. The Company does not obtain collateral or other
security to support its commodity derivatives contracts subject
to credit risk but does monitor the credit standing of the
counterparty.
Realized gains or losses from the settlement of gas derivative
contracts are reported as other income or expense on the
consolidated statements of operations. The Companys first
commodity derivatives contract was entered into on July 31,
2007 with the first settlement month designated as September
2007. Thus, no settlements occurred during the fiscal year ended
July 31, 2007.
Fair
Value of Financial Instruments
The carrying amount reported on 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 debt and other long-term notes payable
approximates fair value based on current rates available to the
Company for instruments of the same remaining terms and
maturities.
Restricted
Cash
The Company negotiated an 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 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, 2007 and 2006.
Gas
Properties
The Company follows the full cost method of accounting for gas
properties. Under this method, all costs associated with the
acquisition of, exploration for and development of 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 gas activities that
are directly attributable to acquisition, exploration or
development activities are capitalized as properties and
equipment on the balance sheet. During the fiscal year ended
July 31, 2007, the Company capitalized $532 of internal
labor and benefit costs determined to be directly attributable
to acquisition, exploration or development activities.
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. During the fiscal year ended July 31,
2007, the Company recognized a ceiling write-down of $11,722 as
a result of the carrying amount of net gas properties exceeding
the full cost ceiling limitation, which was based on a
year-end gas price of $6.51 per Mcf.
F-9
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Capitalized costs of proved 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. Support equipment
represents vehicles and other mobile equipment used in gas
operations and is depreciated using the straight-line method
over the estimated useful lives of the assets, ranging from
three to five years.
Unproved 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.
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; or
iv) the remaining term of the unproved property does not
allow sufficient time for further studies or drilling.
No impairment of unproved properties existed as of July 31,
2007 or July 31, 2006.
Other
Property and Equipment
Other property and equipment is stated at cost and includes
fixed assets such as office equipment, computer hardware and
software, and furniture and fixtures and is depreciated using
the straight-line method over the estimated useful lives of the
assets, ranging from three to five years.
Asset
Retirement Obligations
The Company follows 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 Companys asset
retirement obligations relate to the plugging of wells upon
exhaustion of gas reserves.
F-10
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes the activity for the
Companys asset retirement obligations for the fiscal years
ended July 31, 2007 and 2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
Beginning asset retirement obligation
|
|
$
|
71
|
|
|
$
|
35
|
|
Additional liability incurred
|
|
|
23
|
|
|
|
25
|
|
Accretion expense
|
|
|
4
|
|
|
|
3
|
|
Change in estimate
|
|
|
35
|
|
|
|
8
|
|
Asset retirement costs incurred
|
|
|
(38
|
)
|
|
|
|
|
Loss on settlement of liability
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
114
|
|
|
$
|
71
|
|
|
|
|
|
|
|
|
|
|
During the fiscal year ended July 31, 2007, the Company
incurred $38 related to plugging wells, primarily related to the
legal settlement reached with Colt LLC in fiscal year 2006. The
actual cost of plugging the wells exceeded the Companys
estimate, resulting in a loss on settlement of the liability of
$19. The Company changed its estimate of future costs associated
with plugging wells, resulting in an increase to the asset
retirement obligation of $35, which was recorded during the
fiscal year ended July 31, 2007.
Accounting
for Long-Lived Assets
The Company follows SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. 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 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
Compensation
Prior to December 13, 2005, the Company administered a
share-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 1,579,931
options outstanding under the Incentive Stock Option Plan at
July 31, 2007.
F-11
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
On December 18, 2006, the Companys shareholders
approved the Amended and Restated 2005 Omnibus Stock Plan (the
Omnibus Stock Plan), which the Companys
shareholders had originally approved on December 13, 2005.
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 until December 13, 2010. 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.
During the current fiscal year, the Committee granted stock
awards under the Omnibus Stock Plan in the form of stock options
and restricted and unrestricted stock to employees, directors,
and advisory board members of the Company. The transactions
involving the granting of these stock awards are described more
fully in Note 14.
The Omnibus Stock Plan provides that in any fiscal year of the
plan the Company may grant awards up to 5% of the number of
common shares outstanding as of the first day of that fiscal
year plus the number of common shares that were available for
the grant of awards, but not granted, in prior years under the
plan. In no event, however, may the number of common shares
available for the grant of awards in any fiscal year exceed 6%
of the common shares outstanding as of the first day of that
fiscal year. In addition, the aggregate number of common shares
that could be issued under the Omnibus Stock Plan is capped at
7,000,000. As of July 31, 2007, the Company has issued
50,000 stock options, 2,532,338 restricted common shares, and
388,662 unrestricted common shares under the Omnibus Stock Plan
and has 4,029,000 common shares available for future issuance
under the Plan.
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
Opinion 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 or in fiscal
years thereafter. Therefore, the adoption of SFAS 123(R)
had no impact on the Companys consolidated financial
position or results of operations for the periods presented. The
Company uses the Black-Scholes valuation model to estimate the
fair value of stock options granted. The vesting of stock awards
is recognized as share-based compensation expense using the
straight-line method.
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 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-
F-12
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
dilutive. The following items were excluded from the computation
of diluted loss per share at July 31, 2007, 2006, and 2005,
respectively, as the effect of their assumed exercises would be
anti-dilutive:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Outstanding warrants
|
|
|
5,311,600
|
|
|
|
5,311,600
|
|
|
|
11,168,675
|
|
Outstanding stock options
|
|
|
1,579,931
|
|
|
|
1,823,265
|
|
|
|
4,227,279
|
|
Nonvested portion of restricted shares issued
|
|
|
2,437,338
|
|
|
|
2,325,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,328,869
|
|
|
|
9,459,865
|
|
|
|
15,395,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. Therefore, the Company will need to comply with FASB
Interpretation Number 48 beginning in the fiscal year ending
July 31, 2008. The Company is currently assessing the
effect of this Interpretation, if any, on its consolidated
financial statements.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements. The standard provides
guidance for using fair value to measure assets and liabilities.
Under the standard, fair value refers to the price that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants in the market in
which the reporting entity transacts. The standard clarifies the
principle that fair value should be based on the assumptions
market participants would use when pricing the asset or
liability. In support of this principle, the standard
establishes a fair value hierarchy that prioritizes the
information used to develop those assumptions. The statement is
effective for financial statements issued for fiscal years
beginning after November 15, 2007 and interim periods
within those fiscal years. Therefore, the Company will need to
comply with SFAS No. 157 beginning in the fiscal year
ending July 31, 2009. The Company is currently evaluating
the statement to determine what impact, if any, it will have on
its consolidated financial statements.
During February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities Including an amendment of FASB Statement
No. 115. The standard permits an entity to make an
irrevocable election to measure most financial assets and
financial liabilities at fair value. The fair value option may
be elected on an instrument-by-instrument basis, with a few
exceptions, as long as it is applied to the instrument in its
entirety. Changes in fair value would be recorded in income.
SFAS No. 159 establishes presentation and disclosure
requirements intended to help financial statement users
understand the effect of the entitys election on earnings.
SFAS No. 159 is effective as of the beginning of the first
fiscal year beginning after November 15, 2007. Therefore, the
Company will need to comply with SFAS No. 159 beginning in the
fiscal year ending July 31, 2009. Early adoption is permitted.
The Company is currently evaluating the statement to determine
what impact, if any, it will have 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.
F-13
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The gain is included within other income (expense) in the fiscal
year ended July 31, 2005 consolidated statement of
operations. The Company considered these shares of Pyng to be
trading securities and recorded unrealized holding gains and
losses directly to earnings.
Other current assets consisted of the following at July 31,
2007 and 2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
Deferred financing costs
|
|
$
|
1,436
|
|
|
$
|
|
|
Separation Agreement
|
|
|
322
|
|
|
|
|
|
Prepaid expenses and other
|
|
|
190
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,948
|
|
|
$
|
165
|
|
|
|
|
|
|
|
|
|
|
Accrued liabilities consist of the following at July 31,
2007 and 2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
At July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
Employee compensation
|
|
$
|
1,112
|
|
|
$
|
468
|
|
Professional fees
|
|
|
133
|
|
|
|
112
|
|
Separation agreement
|
|
|
100
|
|
|
|
31
|
|
Directors fees
|
|
|
57
|
|
|
|
31
|
|
Other
|
|
|
101
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,503
|
|
|
$
|
649
|
|
|
|
|
|
|
|
|
|
|
The separation agreement represents amounts due related to
non-compete/non-solicitation and continuing services clauses
contained in a separation agreement entered into with a former
officer of the Company on October 12, 2006. See Note 8
for further explanation of this agreement.
|
|
5.
|
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 production 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
$900 in cash, less cash received in the amount of $42, was
assigned entirely to IMGs coal mine methane properties.
|
|
6.
|
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 in cash
and cancellation of the Companys convertible note payable
in the amount of $392, plus accrued interest of $31. 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 resulted in a gain on the sale of the investment of
$127, which is included in other income (expense) 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 $52, which is included as
part of other income (expense) in the statement of operations
for the fiscal year ended July 31, 2006.
F-14
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
7.
|
OTHER
NON-CURRENT ASSETS
|
Other non-current assets consisted of the following at
July 31, 2007 and 2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
Separation Agreement
|
|
$
|
59
|
|
|
$
|
|
|
Advance royalties
|
|
|
161
|
|
|
|
161
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
220
|
|
|
$
|
161
|
|
|
|
|
|
|
|
|
|
|
On October 12, 2006, the Company entered into a Separation
Agreement and Waiver and Release (Separation
Agreement) with a former officer and director of the
Company. Under the terms of the Separation Agreement, the
Company agreed to provide consideration to the former officer
and director upon his resignation as follows:
|
|
|
|
|
Severance
cash payment of $250 and medical
and dental insurance coverage for two years from the date of the
agreement. The cash payment of $250 was expensed during the
current fiscal year and the cost of medical and dental coverage,
which is not material, is being expensed as incurred.
|
|
|
|
Consulting
grant of 40,000 unrestricted
common shares and cash payments totaling $50 in periodic
installments from October 15, 2006 through
December 31, 2006 in return for consulting services to be
provided by the former officer and director as may be reasonably
requested by the Company from time to time through
January 2, 2008. In lieu of issuing the 40,000 shares
to the former officer and director, the Company deemed them to
have been contemporaneously surrendered in partial satisfaction
of tax withholding obligations paid in cash by the Company.
|
|
|
|
Non-compete/Non-solicitation
cash payments of
$100 on each of three dates from January 2, 2007 through
January 2, 2008 and immediate vesting of 475,000 restricted
shares held by the former officer and director in return for his
agreement not to compete with the Company or to solicit any of
its employees for a period of two years. Of the 475,000
restricted shares immediately vested, 84,163 had vested during
the fiscal year ended July 31, 2006 and were surrendered by
the former officer and director to pay for the exercise of
warrants obtained in an April 2004 private placement of the
Companys common shares.
|
The Company capitalized the value of the expected future benefit
to be received from both the consulting services and the
non-compete/non-solicitation agreement and is amortizing the
related expense ratably over the future periods in which it
expects to receive the related benefits. As of July 31,
2007, $381 of amortized value related to the consulting services
and the non-compete/non-solicitation agreement are recorded as
other assets on the balance sheet, including $322 shown as
current and representing the amount to be amortized over the
next year. As of July 31, 2007, $100 is recorded as a
current liability reflecting the final payment due under the
non-compete/non-solicitation agreement on January 2, 2008.
The Company expensed $236 and $50 in connection with the
consulting services and the non-compete/non-solicitation
agreement, respectively, during the fiscal year ended
July 31, 2007.
|
|
9.
|
LONG-TERM
DEBT AND NOTES PAYABLE
|
GasRock
Credit Facility
On July 27, 2007, the Company entered into an Advancing
Term Credit Agreement (the Credit Agreement) with
GasRock. The Credit Agreement provides for an initial commitment
to the Company of $10,200 and the possibility of future advances
to the Company of up to an additional $64,800. All future
advances under the Credit Agreement beyond the initial
commitment will be made in GasRocks discretion. The
Company may request advances under the Credit Agreement at any
time before July 25, 2008, which GasRock may in its
discretion extend
F-15
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
until July 27, 2010. All amounts then outstanding under the
Credit Agreement are due and payable on July 25, 2008 (the
Loan Termination Date), which GasRock may in its
discretion extend until July 29, 2011.
On July 27, 2007, the Company received an initial advance
of $9,060 under the Credit Agreement, which resulted in net
proceeds to the Company of $8,224 after the deduction of
GasRocks facility fee, investment banking fees, legal fees
and other fees and expenses incurred by the Company in
connection with the transaction totaling $836. The Company has
capitalized such fees and expenses incurred in connection with
this transaction as deferred financing fees and is amortizing
them over the initial term of the Credit Agreement using the
interest method. The initial advance is expected to be used for
continued drilling of development wells at the Southern Illinois
Basin Project, drilling of new test wells, pilot projects,
possible lease acquisitions and general and administrative
expenses.
For the first year of the term of the Credit Agreement, all
amounts outstanding under the Credit Agreement will bear
interest at a rate equal to the greater of (i) 15% per
annum and (ii) the LIBOR rate plus 9% per annum. If GasRock
extends the Loan Termination Date, amounts outstanding under the
Credit Agreement will thereafter bear interest at a rate equal
to the greater of (i) 12% per annum and (ii) the LIBOR
rate plus 6% per annum. The Company is required to make monthly
interest payments on the amounts outstanding under the Credit
Agreement based on available funds existing after deducting all
monthly operating expenses of the wells from monthly revenue, as
defined by the Credit Agreement. Any accrued but unpaid interest
due each month during the first year of the term of the Credit
Agreement is added to the principal amount of the loan. The
Company is not required to make any principal payments until the
Loan Termination Date. The Company may prepay the amounts
outstanding under the Credit Agreement at any time without
penalty.
The Company is required to pay GasRock a facility fee upon the
receipt of any advances under the Credit Agreement in an amount
equal to two percent of the amount advanced. The Company is also
required to reimburse GasRock for all of the expenses incurred
by GasRock in connection with entering into and administering
the Credit Agreement. The facility fee related to the initial
advance and GasRocks expenses in connection with entering
into the Credit Agreement were added to the principal amount of
the initial advance.
The Companys obligations under the Credit Agreement are
secured by a first priority security interest in substantially
all of the Companys properties and assets, including all
of the Companys CBM rights under its leases, farm-out
agreements and fee interests, all of the Companys wells at
its Southern Illinois Basin Project, all of the Companys
equipment, and all of the common stock of BPI Energy. A guaranty
of all of BPI Energys obligations under the Credit
Agreement was provided by BPI Energy Holdings, Inc.
In connection with the execution of the Credit Agreement, the
Company granted GasRock a one percent royalty in all CBM
produced and saved from the Companys existing leased and
owned CBM properties and an additional four percent royalty
interest in all CBM produced and saved from the Companys
existing wells at its Southern Illinois Basin Project. As long
as any of the Companys obligations remain outstanding
under the Credit Agreement, the Company will be required to
grant the same one percent royalty interest to GasRock on new
mineral interests acquired by the Company after July 25,
2008 and the same four percent royalty interest on new wells
drilled by the Company that are funded by draws under the Credit
Agreement. The Company estimates that the fair value of the
royalty interests granted to GasRock is approximately $600 and
has recorded this amount as an increase to deferred financing
costs included in other current assets and a decrease to the
full cost pool included as part of gas properties-proved on the
consolidated balance sheet as of July 31, 2007.
BPI Energy is subject to various restrictive covenants under the
Credit Agreement, including limitations on its ability to sell
properties and assets, make distributions, extend credit, amend
its material contracts, incur indebtedness, provide guarantees,
effect mergers or acquisitions, cancel claims, create liens,
create subsidiaries, amend its formation documents, make
investments, enter into transactions with its affiliates, and
enter into swap agreements. BPI Energy must maintain (i) a
current ratio of at least 1.0 (excluding from the calculation of
current liabilities any advances outstanding under the Credit
Agreement) and (ii) a loan-to-value ratio greater than 1.0
to 1.0 for the period commencing on September 30, 2008 and
ending on March 31, 2010 and 0.7 to 1.0 thereafter.
F-16
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Credit Agreement contains customary events of default. In
addition, GasRock may declare an event of default if, at any
time after July 25, 2008, the Companys most recent
reserve report indicates that (i) the Companys
projected net revenue attributable to its proved reserves is
insufficient to fully amortize the amounts outstanding under the
Credit Agreement within a
48-month
period and (ii) the Company is unable to demonstrate to
GasRocks reasonable satisfaction that the Company would be
able to satisfy such outstanding amounts through a sale of the
Companys assets or equity. Upon the occurrence of an event
of default under the Credit Agreement, GasRock may accelerate
the Companys obligations under the Credit Agreement. Upon
certain events of bankruptcy, the Companys obligations
under the Credit Agreement would automatically accelerate. In
addition, at any time that an event of default exists under the
Credit Agreement, the Company will be required to pay interest
on all amounts outstanding under the Credit Agreement at a
default rate, which is equal to the then-prevailing interest
rate under the Credit Agreement plus four percent per annum.
Long-Term
Notes Payable
The Company has outstanding term notes payable related to
vehicles and equipment as follows:
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
Case Credit term note due in fiscal year 2007, 6.50%
|
|
$
|
|
|
|
$
|
15
|
|
GMAC term note due in fiscal year 2009, 6.50%
|
|
|
14
|
|
|
|
21
|
|
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%
|
|
|
62
|
|
|
|
81
|
|
Caterpillar Financial Services term note due in fiscal year
2007, 7.0%
|
|
|
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76
|
|
|
|
216
|
|
Less current maturities
|
|
|
(28
|
)
|
|
|
(141
|
)
|
|
|
|
|
|
|
|
|
|
Long-term notes payable
|
|
$
|
48
|
|
|
$
|
75
|
|
|
|
|
|
|
|
|
|
|
The notes are collateralized by the related vehicles and
equipment.
The annual principal maturities of loans under the GasRock
credit facility and the long-term notes payable for the five
fiscal years subsequent to July 31, 2007 are as follows:
|
|
|
|
|
2008
|
|
$
|
9,088
|
|
2009
|
|
|
30
|
|
2010
|
|
|
18
|
|
|
|
|
|
|
|
|
$
|
9,136
|
|
|
|
|
|
|
The income tax benefit consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
(581
|
)
|
U.S. state taxes
|
|
|
|
|
|
|
|
|
|
|
(143
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income taxes
|
|
|
|
|
|
|
|
|
|
|
(724
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax benefit
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(724
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-17
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Statutory Canadian income tax rate
|
|
|
(36.00
|
)%
|
|
|
(36.00
|
)%
|
|
|
(36.00
|
)%
|
Stock-based compensation
|
|
|
|
%
|
|
|
(4.71
|
)%
|
|
|
19.66
|
%
|
Non-deductible stock issuance costs
|
|
|
|
%
|
|
|
2.10
|
%
|
|
|
1.43
|
%
|
Current year Canadian loss with no tax benefit
|
|
|
0.08
|
%
|
|
|
(4.61
|
)%
|
|
|
2.32
|
%
|
Gain on intercompany asset transfers
|
|
|
5.12
|
%
|
|
|
|
%
|
|
|
|
%
|
Net change in deductible temporary differences due to foreign
currency conversion and expired losses
|
|
|
(2.43
|
)%
|
|
|
3.16
|
%
|
|
|
(5.38
|
)%
|
Increase in valuation allowance
|
|
|
36.23
|
%
|
|
|
43.44
|
%
|
|
|
7.32
|
%
|
Other
|
|
|
(3.00
|
)%
|
|
|
(3.38
|
)%
|
|
|
(1.19
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
|
%
|
|
|
|
%
|
|
|
(11.84
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The components of the net deferred tax liability at
July 31, 2007 and 2006 are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31, 2007
|
|
|
|
United States
|
|
|
Canada
|
|
|
Total
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
18,808
|
|
|
$
|
570
|
|
|
$
|
19,378
|
|
Stock-based compensation
|
|
|
629
|
|
|
|
|
|
|
|
629
|
|
Resource related allowances
|
|
|
|
|
|
|
878
|
|
|
|
878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax asset
|
|
|
19,437
|
|
|
|
1,448
|
|
|
|
20,885
|
|
Valuation allowance
|
|
|
(12,771
|
)
|
|
|
(1,448
|
)
|
|
|
(14,219
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
6,666
|
|
|
|
|
|
|
|
6,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property plant and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax liability
|
|
|
(6,666
|
)
|
|
|
|
|
|
|
(6,666
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31, 2006
|
|
|
|
United States
|
|
|
Canada
|
|
|
Total
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
11,364
|
|
|
$
|
513
|
|
|
$
|
11,877
|
|
Resource related allowances
|
|
|
769
|
|
|
|
|
|
|
|
769
|
|
Investments and advances to subsidiaries
|
|
|
|
|
|
|
1,762
|
|
|
|
1,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax asset
|
|
|
12,133
|
|
|
|
2,275
|
|
|
|
14,408
|
|
Valuation allowance
|
|
|
(4,466
|
)
|
|
|
(2,275
|
)
|
|
|
(6,741
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
7,667
|
|
|
|
|
|
|
|
7,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property plant and equipment
|
|
|
(7,667
|
)
|
|
|
|
|
|
|
(7,667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current deferred tax liability
|
|
|
(7,667
|
)
|
|
|
|
|
|
|
(7,667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-18
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: (i) the nature, amount and
expected timing of reversal of taxable temporary differences,
and (ii) 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, 2007 and 2006 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 $8,305 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 $827 has been recorded
during the current fiscal year to reflect a gain recognized on
the transfer of assets 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, 2007 expire as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2011
|
|
|
2012
|
|
|
2013 and Later
|
|
|
Total
|
|
|
Canadian
|
|
$
|
322
|
|
|
$
|
315
|
|
|
$
|
992
|
|
|
$
|
1,629
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
48,224
|
|
|
|
48,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
322
|
|
|
$
|
315
|
|
|
$
|
49,216
|
|
|
$
|
49,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At July 31, 2007 the Company also has $2,439 of Canadian
resource related deductions that have no expiration date. The
Companys ability to utilize previously incurred net
operating losses to offset future taxable income, if any, could
be limited due to a recent ownership change within
the meaning of Section 382 of the Internal Revenue Code of
1986.
Common shares
The Company has authorized
200,000,000 shares without par value, of which 72,524,493
and 70,812,540 were issued and outstanding as of July 31,
2007 and 2006, respectively. Shares issued and outstanding at
July 31, 2007 and 2006 include 2,437,338 and 2,325,000
restricted shares, respectively, expected to vest in future
periods.
Additional paid-in capital
Amounts recorded
of $7,608 and $5,871 at July 31, 2007 and 2006,
respectively, represent the cumulative amounts of share-based
compensation as of each fiscal year-end.
Share purchase warrants
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 Securities Act of 1933,
as amended, 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-19
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Share purchase warrants outstanding at July 31, 2007 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
|
|
|
|
|
|
|
|
|
|
|
|
12.
|
COMMITMENTS
AND CONTINGENCIES
|
The Company has operating lease commitments expiring at various
dates. Such leases generally contain renewal options. At
July 31, 2007, future minimum lease payments under
non-cancellable operating leases are as follows:
|
|
|
|
|
2008
|
|
$
|
286
|
|
2009
|
|
|
255
|
|
2010
|
|
|
183
|
|
2011
|
|
|
19
|
|
2012
|
|
|
19
|
|
Thereafter
|
|
|
247
|
|
|
|
|
|
|
|
|
$
|
1,009
|
|
|
|
|
|
|
The leases are principally for office space and gas collection
equipment. Rental payments for all operating leases amounted to
approximately $253 during the fiscal year ended July 31,
2007.
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, 2007 expire at
various dates beginning in November 2008. 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,
2007, the amount would initially total approximately $100
annually and could increase to as much as $220 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 ensuring that 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
F-20
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
be met. A significant delay in securing the necessary drilling
equipment and crews could cause a delay in production and sales,
which would affect operating results adversely.
|
|
14.
|
SHARE-BASED
COMPENSATION
|
Stock
Options
The table below summarizes stock options activity for the three
years ended July 31, 2007. All stock options through the
fiscal year ended July 31, 2006 were granted under the
Incentive Stock Option Plan with exercise prices denominated in
Canadian Dollars. U.S. Dollar amounts shown in the tables
below through the fiscal year ended July 31, 2006 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
each fiscal year-end. Stock options granted during the fiscal
year ended July 31, 2007 were granted under the Omnibus
Stock Plan with exercise prices denominated in
U.S. Dollars. All stock options granted were fully vested
on the date of grant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Number of Options
|
|
|
Exercise Price
|
|
|
Outstanding at July 31, 2004
|
|
|
2,230,556
|
|
|
$
|
0.59
|
|
Granted exercise price equals market price of stock
on date of grant
|
|
|
3,423,278
|
|
|
|
1.64
|
|
Granted exercise price less than market price of
stock on date of grant
|
|
|
852,778
|
|
|
|
0.96
|
|
Expired
|
|
|
(25,000
|
)
|
|
|
0.98
|
|
Exercised
|
|
|
(2,254,333
|
)
|
|
|
0.72
|
|
|
|
|
|
|
|
|
|
|
Outstanding at July 31, 2005
|
|
|
4,227,279
|
|
|
|
1.49
|
|
Granted exercise price equals market price of stock
on date of grant
|
|
|
495,000
|
|
|
|
1.79
|
|
Expired
|
|
|
(320,000
|
)
|
|
|
1.79
|
|
Exercised
|
|
|
(554,014
|
)
|
|
|
1.24
|
|
Exchanged for restricted stock
|
|
|
(2,025,000
|
)
|
|
|
1.82
|
|
|
|
|
|
|
|
|
|
|
Outstanding at July 31, 2006
|
|
|
1,823,265
|
|
|
|
1.17
|
|
Granted exercise price equals market price of stock
on date of grant
|
|
|
50,000
|
|
|
|
0.83
|
|
Expired
|
|
|
(293,334
|
)
|
|
|
0.60
|
|
|
|
|
|
|
|
|
|
|
Outstanding at July 31, 2007
|
|
|
1,579,931
|
|
|
$
|
1.27
|
|
|
|
|
|
|
|
|
|
|
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 shares in lieu of transferring cash. The
fair value of the stock options surrendered in this transaction
equaled the total exercise price of the warrants using the
Black-Scholes valuation model to value the stock options on the
date of the transaction. The assumptions used in the
Black-Scholes valuation 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 shares during
F-21
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 common shares for the period
that they began trading on the American Stock Exchange and the
historical volatility of its common shares 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 share-based compensation expense for stock
options granted to employees and directors in the amount of $31,
$527 and $3,345 in fiscal years ended July 31, 2007, 2006
and 2005, respectively. The fair value of stock options granted
was estimated using the Black-Scholes valuation model with the
following assumptions:
|
|
|
|
|
|
|
|
|
Year Ended July 31,
|
|
|
2007
|
|
2006
|
|
2005
|
|
Risk-free interest rate
|
|
5.0%
|
|
3.3%
|
|
3.0 3.7%
|
Expected dividend yield
|
|
Nil
|
|
Nil
|
|
Nil
|
Expected stock price volatility
|
|
97%
|
|
95%
|
|
69-81%
|
Expected option life
|
|
5 years
|
|
3 years
|
|
3 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 years ended July 31, 2007 and 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 shares 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 or 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 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,
2007, 2006 and 2005 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Exercise price equals market price of stock on date of grant
|
|
$
|
0.63
|
|
|
$
|
1.07
|
|
|
$
|
0.81
|
|
Exercise price is less than market price of stock on date of
grant
|
|
|
|
|
|
|
|
|
|
|
0.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total grants
|
|
$
|
0.63
|
|
|
$
|
1.07
|
|
|
$
|
0.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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-22
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes information about options
outstanding as of July 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
Exercise
|
|
Number
|
|
|
Remaining
|
|
|
|
Price
|
|
Outstanding
|
|
|
Life (Years)
|
|
|
Expiry Date
|
|
$0.49
|
|
|
345,000
|
|
|
|
1.3
|
|
|
November 3, 2008
|
0.70
|
|
|
10,000
|
|
|
|
2.1
|
|
|
September 22, 2009
|
0.83
|
|
|
50,000
|
|
|
|
4.9
|
|
|
June 7, 2012
|
1.26
|
|
|
695,666
|
|
|
|
2.3
|
|
|
November 29, 2009
|
1.75
|
|
|
10,000
|
|
|
|
3.1
|
|
|
September 23, 2010
|
1.80
|
|
|
136,000
|
|
|
|
2.7
|
|
|
March 27, 2010
|
1.95
|
|
|
333,265
|
|
|
|
2.5
|
|
|
January 20, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.27
|
|
|
1,579,931
|
|
|
|
2.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All outstanding options are fully vested at July 31, 2007.
The intrinsic value of outstanding options is approximately $48
at July 31, 2007.
Restricted
Stock Awards
A summary of the status of the Companys nonvested shares
as of July 31, 2007 and changes during the fiscal year
ended July 31, 2007, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Grant-Date
|
|
Nonvested Shares
|
|
Shares
|
|
|
Fair Value
|
|
|
Nonvested at July 31, 2005
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
2,325,000
|
|
|
|
0.61
|
(1)
|
Vested
|
|
|
(84,163
|
)
|
|
|
0.51
|
|
Nonvested at July 31, 2006
|
|
|
2,240,837
|
|
|
|
0.61
|
|
Granted
|
|
|
1,207,338
|
|
|
|
0.87
|
|
Vested
|
|
|
(1,010,837
|
)
|
|
|
0.59
|
|
|
|
|
|
|
|
|
|
|
Nonvested at July 31, 2007
|
|
|
2,437,338
|
|
|
$
|
0.71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The calculation of weighted average grant-date fair value
includes the computed value of the option exchange, representing
the difference between the fair value of the options surrendered
and the fair value of the restricted shares granted in the
exchange. See below for a further description of the option
exchange.
|
The Company granted restricted shares during fiscal year 2007
and 2006 as follows:
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
Inducement grants
|
|
|
700,000
|
|
|
|
300,000
|
|
Employee bonuses
|
|
|
334,006
|
|
|
|
|
|
Directors fees
|
|
|
173,332
|
|
|
|
|
|
Option exchange
|
|
|
|
|
|
|
2,025,000
|
|
|
|
|
|
|
|
|
|
|
Total number of shares granted
|
|
|
1,207,338
|
|
|
|
2,325,000
|
|
|
|
|
|
|
|
|
|
|
Inducement
Grants
The Company granted 700,000 and 300,000 restricted shares in the
fiscal years ended July 31, 2007 and 2006, respectively, as
inducement grants to the new Chief Operating Officer and members
of his operational team. The
F-23
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
restrictions on the shares are scheduled to lapse based on
service evenly over periods ranging from two to three years from
the date of hire.
Employee
Bonuses
The Company granted 324,006 restricted shares to employees
for performance bonuses during the fiscal year ended
July 31, 2007. The restrictions lapse based on service
evenly over a two-year period from the date of grant. During the
fiscal year ended July 31, 2007, the Company also granted
10,000 shares to an employee as a relocation bonus. Such
shares will vest in three years from the date of grant.
Directors
Fees
The Company granted 173,332 restricted shares to the four
non-employee directors for annual retainer fees during the
fiscal year ended July 31, 2007. The restrictions lapse
evenly over a two-year period from the date of grant subject to
each director standing for re-election in the year the shares
are scheduled to vest.
Fiscal
Year Ended July 31, 2006 Option Exchange
During the fiscal year ended July 31, 2006, the
Compensation Committee approved an exchange of common shares for
outstanding stock options held by various key employees and
directors of the Company (the 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 July 31, 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 through January 1, 2009.
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.
All restricted share 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
restricted shares scheduled to vest on the next vesting date,
based on the number of days continuously employed during the
applicable vesting period. The
F-24
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Company includes all restricted shares 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 share grants upon
receiving approval from the American Stock Exchange, when
required, for the issuance of such shares.
As of July 31, 2007, there were $1,143 of unrecognized
compensation cost related to restricted shares. The cost is
expected to be amortized over a weighted average period of
0.8 years. The amount charged to expense related to the pro
rata vesting of restricted shares was $838, $225 and $0 during
the fiscal years ended July 31, 2007, 2006, and 2005,
respectively.
Fully
Vested Stock Awards
The Company granted fully vested shares during the fiscal years
ended July 31, 2007 and 2006 as follows:
|
|
|
|
|
|
|
|
|
Purpose
|
|
2007
|
|
|
2006
|
|
|
Inducement grants
|
|
|
350,000
|
|
|
|
300,000
|
|
Employee bonuses
|
|
|
161,994
|
|
|
|
|
|
Directors fees
|
|
|
86,668
|
|
|
|
140,000
|
|
|
|
|
|
|
|
|
|
|
Total number of shares granted
|
|
|
598,662
|
|
|
|
440,000
|
|
|
|
|
|
|
|
|
|
|
Inducement
Grants
The Company granted 350,000 and 300,000 fully vested shares
during the fiscal years ended July 31, 2007 and 2006,
respectively, as inducement grants to our Chief Operating
Officer and four new members of the Companys technical
team. The grant of these fully vested shares resulted in the
recognition of $326 and $426 of share-based compensation
expense in the fiscal years ended July 31, 2007 and 2006,
respectively.
Employee
Bonuses
The Company granted 161,994 fully vested shares to
employees for performance bonuses during the fiscal year ended
July 31, 2007. The grant of these fully vested shares
resulted in the recognition of $94 of share-based compensation
expense in the fiscal year ended July 31, 2007. In
addition, the Company accrued an additional $308 of share-based
compensation expense at July 31, 2007 related to
312,500 shares issued to executives in August 2008 for
fiscal year 2007 performance bonuses.
Directors
Fees
The Company granted 86,668 fully vested common shares to
the four non-employee directors for annual retainer fees during
the fiscal year ended July 31, 2007. The Company also
granted 140,000 fully vested shares to a newly appointed
director during the fiscal year ended July 31, 2006. The
grant of these fully vested shares resulted in the recognition
of $50 and $199 of share-based compensation expense in the
fiscal years ended July 31, 2007 and 2006, respectively.
Shares
Surrendered
The Omnibus Stock Plan allows participants to surrender common
shares to satisfy the Companys tax withholding obligations
related to the vesting of shares. During the fiscal year ended
July 31, 2007, the Company paid $137 in withholding taxes
for participants in return for the surrender of
83,930 shares surrendered during the fiscal year ended
July 31, 2007 and 157,494 shares to be surrendered
during the first quarter of the fiscal year ended July 31,
2008. The amount paid by the Company for withholding taxes
related to the shares surrendered was recorded as a decrease to
additional
paid-in
capital
in
the fiscal year ended July 31, 2007.
F-25
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Drummond
Coal Co. Litigation
Approximately 115,000 acres of CBM rights of BPI Energy,
Inc. (BPI) that are located at the Northern Illinois
Basin Project are currently subject to litigation. To date, BPI
has drilled one well on this acreage, a test well that was
drilled in September 2006.
In 2004, BPI and affiliates of the Drummond Coal Co.
(Drummond), including IEC (Montgomery), LLC
(IEC), entered into a letter of intent to obtain
coal and CBM gas rights for one another in the Illinois Basin
and to work together in a relationship in which BPI would
produce CBM from coal beds prior to the Drummond
affiliates mining of coal from those beds. Pursuant to and
in reliance upon this letter of intent and its relationship with
Drummond, BPI arranged for the transfer of 163,109 acres of
coal rights to the Drummond affiliates for a total purchase
price of $5,846, which BPI believes reflects a significant
discount to current market prices. In light of its obligations
to Drummond, BPI charged no profit on its transfer of the coal
rights to the Drummond affiliates.
Rather, in consideration for obtaining those coal rights, the
Drummond affiliates were to lease approximately
115,000 acres of CBM rights to BPI for a primary lease term
of 20 years and with favorable royalty rates. Although the
Drummond affiliates entered into two CBM leases with BPI on
April 26, 2006, they have since sought in various ways to
void or terminate the leases.
Drummond affiliates IEC and Christian Coal Holdings, LLC
(Christian) filed suit against BPI on
February 9, 2007 in the United States District Court for
the Northern District of Alabama, claiming that BPI has breached
the CBM leases in various ways. On May 14, 2007, the Court
granted BPIs motion to dismiss the case in its entirety on
the ground of improper venue. IEC and Christian did not appeal
that decision.
On March 13, 2007, BPI filed suit against IEC, Christian
and additional Drummond affiliates Shelby Coal Holdings, LLC,
Clinton Coal Holdings, LLC and Marion Coal Holdings, LLC in the
United States District Court for the Southern District of
Illinois. At the courts direction, BPI filed an amended
complaint, and subsequently filed a second amended complaint
that named BPI Energy Holdings, Inc. as an additional plaintiff,
named Drummond Company Inc. and Drummond affiliate Vandalia
Energy, LLC as additional defendants, and asserted additional
claims. In its lawsuit, BPI seeks to rescind its transfers of
coal rights to the Drummond affiliates for failure of
consideration due to the Drummond affiliates efforts to
avoid the CBM leases, has asserted claims for money damages for
breach of the various agreements between the parties (including
the CBM leases), breach of fiduciary duty, unjust enrichment,
promissory estoppel, and tortious interference with contracts,
and seeks to pierce the corporate veil to recover from Drummond
and IEC for the actions of the other Drummond affiliates. The
defendants filed a motion to dismiss the second amended
complaint, which has been fully briefed and awaits a decision by
the Court. We anticipate that if the Court denies all or part of
the motion to dismiss, Drummond and its affiliates will file
counterclaims against BPI for breach of the CBM leases, citing
the same bases set forth in the Alabama lawsuit.
We believe that Drummond and its affiliates, after having
received favorable coal rights in exchange for favorable CBM
rights, now wish to obtain a significant windfall by seeking to
renege on the CBM rights that they were obligated to grant to
BPI.
If the Drummond affiliates reinstitute their claims against BPI,
we believe that we will be successful in defending against their
claims of breach. However, there can be no assurance that we
will be successful in maintaining these acreage rights. The loss
of these acreage rights would not have a material impact on our
financial position, results of operations or cash flows.
ICG
Litigation
In November 2004, BPI entered into a farm-out agreement under
which it acquired the right to develop certain CBM in Macoupin
and Perry Counties in Illinois. The farm-out agreement covers
41,253 acres of CBM rights in Macoupin County and
22,997 acres of CBM rights in Perry County. The farmor was
Addington Exploration, LLC,
F-26
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
which leased the CBM rights from Meadowlark Farms, Inc. and
Ayrshire Land Company. Meadowlark and Ayrshire went into
bankruptcy, and ICG Natural Resources, LLC purchased their
assets, including the CBM rights underlying the Addington
leases. On April 9, 2007, ICG filed suit against BPI in
Perry County, Illinois, in an effort to avoid the Addington
leases, claiming that there was a lack of consideration at the
time they were originally entered into. BPI has filed a motion
to dismiss the lawsuit under the doctrine of estoppel by deed,
arguing that ICG cannot challenge the leases because it acquired
the CBM rights subject to those leases, as set forth in the deed
from Addington and Meadowlark to ICG, the purchase agreement
between those parties, and numerous bankruptcy court filings and
orders associated with the approval of the sale. Addington was
subsequently acquired by Nytis Exploration Company, LLC, which
has intervened in the action and joined in BPIs motion.
ICG has opposed BPIs motion, and the Court has held a
hearing upon it. BPI has recently learned that, subsequent to
filing suit, ICG may have transferred its Perry County coal and
CBM rights to Arch Minerals, which is not currently a party to
the lawsuit. It is unknown whether Arch will challenge the
farm-out agreement. To date, BPI has drilled 10 pilot wells, one
pressure observation well, one water disposal well and two test
wells on the acreage covered by the farm-out agreement.
We believe that we will be successful in either having the case
dismissed or in defending against ICGs claims. However,
there can be no assurance that we will be successful in
retaining the acreage under this farm-out agreement. The loss of
these acreage rights would not have a material impact on our
financial position, results of operations or cash flows.
|
|
16.
|
OTHER
INCOME (EXPENSE)
|
Other income (expense) consisted of the following for the fiscal
years ended July 31, 2007, 2006 and 2005, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Legal settlement with Colt LLC
|
|
$
|
|
|
|
$
|
(2,950
|
)
|
|
$
|
|
|
Gain on sale of investment in HCM
|
|
|
|
|
|
|
127
|
|
|
|
|
|
Gain on sale of marketable securities trading
|
|
|
|
|
|
|
|
|
|
|
42
|
|
Distribution from HCM
|
|
|
|
|
|
|
51
|
|
|
|
7
|
|
Other
|
|
|
|
|
|
|
8
|
|
|
|
(14
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
(2,764
|
)
|
|
$
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys gas properties are all located in the United
States and consist solely of its CBM 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.
Southern
Illinois Basin Project
The Companys CBM rights in the Southern Illinois Basin
Project cover 10,000 acres in the southern part of the
Illinois Basin. The Company holds its CBM rights on this acreage
pursuant to a purchase agreement under which it acquired the CBM
estate in a settlement with its former lessor, the owner of the
coal rights. 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) 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.
F-27
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
In addition to the GasRock royalties, the Company is currently
paying royalties of 3.03% on its production at this project. The
GasRock royalties will also apply to the Companys acreage
rights discussed below at the time the Company produces and
sells CBM from the applicable acreage.
The Company commenced sales of gas from the initial pilot
production wells on this project in January 2005. As of
July 31, 2007, the Company has drilled 131 wells at
this project. These wells consist of 91 productive wells, six
shut-in wells, four divested wells (as a result of the Colt LLC
settlement), nine plugged wells, two disposal wells, one
pressure observation well, and 18 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.
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
fiscal year 2006, the Company 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, the Company determined it was beneficial to complete
additional seams in the remaining wells, which it plans to do in
fiscal year 2008.
All of the Companys proved reserves are currently located
at its Southern Illinois Basin Project.
Northern
Illinois Basin Project
The Companys CBM rights in the Northern Illinois Basin
Project cover 366,364 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 and a farm-out agreement.
Montgomery
County Lease
The lease agreement with Montgomery County covers
133,788 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 the Company is producing CBM from the
covered acreage. Under the lease agreement, 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.
Shelby
County Lease
The lease agreement with Shelby County covers 63,250 acres
of CBM rights in Shelby County, Illinois. The 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 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 12,040 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
F-28
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
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 Lease
The lease agreement with Christian County covers approximately
14,033 acres of CBM rights in Christian County, Illinois.
The lease agreement extends until January 20, 2012. 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 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.
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 below.
Under the lease agreements with Montgomery, Shelby, and
Christian Counties, 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 completed drilling of a
10-well pilot program at this project referred to as the Shelby
Pilot. In the fiscal year ended July 31, 2007 at the Shelby
Pilot, the Company added one pressure observation well and
drilled two additional producers that are not currently
completed. Also during the fiscal year ended July 31, 2007,
the Company drilled two new test wells in other parts of the
Shelby County acreage block. During the fourth quarter of the
fiscal year ended July 31, 2007, the Company announced its
decision to continue production activities at the Shelby Pilot,
while deferring additional development pending further
production and pressure information.
As of July 31, 2007, the Company drilled and completed a
second 10-well pilot project, the Macoupin Pilot, in the
Northern Illinois Basin Project. Those wells have just started
the dewatering process. The Macoupin Pilot also includes one
pressure observation well and one disposal well. The Company
currently has no proved reserves located at the Northern
Illinois Basin Project.
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 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.
F-29
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Washington
County Lease
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 Lease
The lease agreement with Marion County covers 17,882 acres
of CBM rights in Marion County, Illinois. The lease agreement
extends until June 7, 2012. 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
Also included in the Western Illinois Basin Project are 22,997
acres in Perry County, Illinois, which the Company can earn
under a farm-out agreement with Addington Exploration, LLC, as
described below.
As of July 31, 2007, the Company has drilled four test
wells at the Western Illinois Basin Project from which the
Company is still gathering and evaluating data. The Company
currently has no proved reserves located at the Western Illinois
Basin Project.
Addington
Exploration, LLC 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 (part of the Northern Illinois Basin
Project) and 22,997 acres of CBM rights in Perry County,
Illinois (part of the Western Illinois Basin Project) 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 plans
to extend the
36-month
evaluation period on unearned acreage when it expires in
November 2007.
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.
Under the lease agreements with Washington and Marion Counties,
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.
F-30
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table sets forth a summary of gas property costs
not being amortized at July 31, 2007, by the fiscal year in
which such costs were incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
Total
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
and Prior
|
|
|
Property acquisition costs
|
|
$
|
215
|
|
|
$
|
37
|
|
|
$
|
|
|
|
$
|
151
|
|
|
$
|
27
|
|
Exploration and development, net of transfers to proved oil and
gas properties
|
|
|
8,318
|
|
|
|
5,127
|
|
|
|
2,446
|
|
|
|
742
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,533
|
|
|
$
|
5,164
|
|
|
$
|
2,446
|
|
|
$
|
893
|
|
|
$
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No interest has been capitalized and included in the cost of
unproved properties as of July 31, 2004 or in the fiscal
years ended July 31, 2005, 2006 and 2007, 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 gas properties was $524, $312 and $63 or $2.83/Mcf,
$2.31/Mcf and $3.48/Mcf in the fiscal years ended July 31,
2007, 2006 and 2005, respectively.
|
|
18.
|
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 CBM. 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 $12,
$70 and $59 in expense reimbursement related to this arrangement
during the fiscal years ended July 31, 2007, 2006 and 2005,
respectively. Mr. Oestreichs brother owns Dependable
Service Company, a company that previously provided general
labor services to the Company. The Company paid Dependable
Services Company approximately $0, $237 and $147 during the
fiscal years ended July 31, 2007, 2006 and 2005,
respectively.
David Preng, a director of the Company, is an owner of
Preng & Associates, an executive search firm
specializing in the energy and natural resources industries. The
Company paid Preng & Associates approximately $15,
$293 and $0 for executive placement services during the fiscal
years ended July 31, 2007, 2006 and 2005, respectively.
|
|
19.
|
SUPPLEMENTAL
GAS DATA
|
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.
F-31
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Summary
of Changes in Proved Reserves (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
MMcf
|
|
|
MMcf
|
|
|
MMcf
|
|
|
Proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
14,718
|
|
|
|
10,292
|
|
|
|
|
|
Purchase (sale) of reserves in place
|
|
|
(885
|
)
|
|
|
2,229
|
|
|
|
|
|
Extensions and discoveries
|
|
|
5,434
|
|
|
|
4,528
|
|
|
|
10,326
|
|
Revisions of previous estimates
|
|
|
(2,808
|
)
|
|
|
(2,186
|
)
|
|
|
|
|
Production
|
|
|
(185
|
)
|
|
|
(145
|
)
|
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
16,274
|
|
|
|
14,718
|
|
|
|
10,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
8,983
|
|
|
|
2,971
|
|
|
|
|
|
End of year
|
|
|
10,639
|
|
|
|
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, amortization
and impairment as of July 31, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
Capitalized costs:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
29,852
|
|
|
$
|
25,440
|
|
Unproved oil and gas properties
|
|
|
8,533
|
|
|
|
3,368
|
|
Support equipment
|
|
|
1,293
|
|
|
|
1,047
|
|
|
|
|
|
|
|
|
|
|
Total capitalized costs
|
|
|
39,678
|
|
|
|
29,855
|
|
Less: Accumulated DD&A and ceiling write-down
|
|
|
(13,962
|
)
|
|
|
(923
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
25,716
|
|
|
$
|
28,932
|
|
|
|
|
|
|
|
|
|
|
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, 2007, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Property acquisition proved
|
|
$
|
11
|
|
|
$
|
|
|
|
$
|
|
|
Property acquisition unproved
|
|
|
37
|
|
|
|
|
|
|
|
342
|
|
Exploration
|
|
|
4,351
|
|
|
|
|
|
|
|
744
|
|
Development
|
|
|
5,178
|
|
|
|
14,018
|
|
|
|
6,766
|
|
Support equipment
|
|
|
245
|
|
|
|
287
|
|
|
|
238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,822
|
|
|
$
|
14,305
|
|
|
$
|
8,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-32
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
All costs incurred on unproved properties, other than property
acquisition costs, are classified as exploration costs until
such time as the properties can be evaluated. Prior to the
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, 2007, 2006 and 2005. The Company commenced
production and sales of gas during the fiscal year ended
July 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Gas revenues
|
|
$
|
1,204
|
|
|
$
|
1,126
|
|
|
$
|
118
|
|
Production costs
|
|
|
(1,608
|
)
|
|
|
(971
|
)
|
|
|
(307
|
)
|
Depreciation, depletion, amortization and ceiling write-down
|
|
|
(12,439
|
)
|
|
|
(537
|
)
|
|
|
(239
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax operating loss
|
|
|
(12,843
|
)
|
|
|
(382
|
)
|
|
|
(428
|
)
|
Income taxes
|
|
|
|
|
|
|
|
|
|
|
167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from gas producing activities
|
|
$
|
(12,843
|
)
|
|
$
|
(382
|
)
|
|
$
|
(261
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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 less the tax bases 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 gross average price per MMBtu used at
July 31, 2007 and 2006 was $6.51 and $8.05, respectively,
based on the Henry Hub gas spot price on those dates. The prices
were adjusted for the Companys contractual basis
differential, lease usage, shrinkage and conversion from MMBtu
to Mcf to arrive at average net price per Mcf of $5.29 and $7.22
at July 31, 2007 and 2006, respectively. At July 31,
2005, the price was adjusted only for conversion from MMBtu to
Mcf to arrive at a net price of $7.44 per Mcf.
F-33
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Gas Reserves (Unaudited)
The standardized measure of discounted cash flows related to
proved gas reserves at July 31, 2007, 2006 and 2005 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Future cash inflows
|
|
$
|
86,039
|
|
|
$
|
106,221
|
|
|
$
|
76,608
|
|
Future production costs and taxes
|
|
|
(33,728
|
)
|
|
|
(24,937
|
)
|
|
|
(10,181
|
)
|
Future development costs
|
|
|
(9,406
|
)
|
|
|
(8,930
|
)
|
|
|
(7,824
|
)
|
Future income tax expenses
|
|
|
|
|
|
|
(15,775
|
)
|
|
|
(14,663
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net future cash flows
|
|
|
42,905
|
|
|
|
56,579
|
|
|
|
43,940
|
|
Discounted at 10% for estimated timing of cash flows
|
|
|
(25,722
|
)
|
|
|
(23,845
|
)
|
|
|
(20,872
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
17,183
|
|
|
$
|
32,734
|
|
|
$
|
23,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Gas Reserves (Unaudited)
The primary changes in the standardized measure of discounted
future net cash flows for the fiscal years ended July 31,
2007, 2006 and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended July 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Standardized measure, beginning of year
|
|
$
|
32,734
|
|
|
$
|
23,068
|
|
|
$
|
|
|
Sales, net of production costs and taxes
|
|
|
404
|
|
|
|
(156
|
)
|
|
|
189
|
|
Extensions and discoveries
|
|
|
12,167
|
|
|
|
14,633
|
|
|
|
27,758
|
|
Purchases (sales) of reserves in place
|
|
|
(1,981
|
)
|
|
|
7,206
|
|
|
|
|
|
Net changes in prices and production costs
|
|
|
(23,664
|
)
|
|
|
(5,606
|
)
|
|
|
|
|
Net changes in future development costs
|
|
|
(439
|
)
|
|
|
(1,023
|
)
|
|
|
(5,541
|
)
|
Revisions of quantity estimates
|
|
|
(6,288
|
)
|
|
|
(7,063
|
)
|
|
|
|
|
Interest factor accretion of discount
|
|
|
2,385
|
|
|
|
3,077
|
|
|
|
|
|
Net change in income tax
|
|
|
2,684
|
|
|
|
(651
|
)
|
|
|
|
|
Net change in production rates (timing) and other
|
|
|
(819
|
)
|
|
|
(751
|
)
|
|
|
662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease)
|
|
|
(15,551
|
)
|
|
|
9,666
|
|
|
|
23,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, end of year
|
|
$
|
17,183
|
|
|
$
|
32,734
|
|
|
$
|
23,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-34
BPI
ENERGY HOLDINGS, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
20.
|
SELECTED
QUARTERLY DATA (UNAUDITED)
|
Summarized below are the unaudited results of operations by
quarter for the fiscal years ended July 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
Second Quarter
|
|
|
Third Quarter
|
|
|
Fourth Quarter
|
|
|
Fiscal 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
294
|
|
|
$
|
247
|
|
|
$
|
335
|
|
|
$
|
328
|
|
Lease operating expenses
|
|
|
336
|
|
|
|
528
|
|
|
|
412
|
|
|
|
332
|
|
Net loss
|
|
|
(2,745
|
)
|
|
|
(1,779
|
)
|
|
|
(2,070
|
)
|
|
|
(14,047
|
)
|
Basic and diluted loss per common share
|
|
$
|
(.04
|
)
|
|
$
|
(.03
|
)
|
|
$
|
(.03
|
)
|
|
$
|
(.20
|
)
|
Fiscal 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
210
|
|
|
$
|
327
|
|
|
$
|
263
|
|
|
$
|
326
|
|
Lease operating expenses
|
|
|
161
|
|
|
|
301
|
|
|
|
291
|
|
|
|
218
|
|
Net loss
|
|
|
(1,193
|
)
|
|
|
(854
|
)
|
|
|
(4,942
|
)
|
|
|
(1,847
|
)
|
Basic and diluted loss per common share
|
|
$
|
(.03
|
)
|
|
$
|
(.01
|
)
|
|
$
|
(.14
|
)
|
|
$
|
(.03
|
)
|
F-35
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 29, 2007
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/ James
E. Craddock*
James
E. Craddock
|
|
Chief Operating Officer and Director
|
|
|
|
/s/ Dennis
Carlton*
Dennis
Carlton
|
|
Director
|
|
|
|
/s/ David
E. Preng*
David
E. Preng
|
|
Director
|
|
|
|
/s/ Costa
Vrisakis*
Costa
Vrisakis
|
|
Director
|
|
|
|
|
|
*By:
|
|
/s/ James
G.
Azlein
James
G.
Azlein,Attorney-in-Fact
for the directors signing in the capacities indicated
|
|
|
Date: October 29, 2007
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
|
|
Incentive Stock Option Plan of BPI Energy Holdings, Inc., dated
as of December 16, 2002.(*)(#)
|
|
4
|
.2
|
|
BPI Energy Holdings, Inc. Amended and Restated 2005 Omnibus
Stock Plan (Incorporated by reference to Appendix A of the
Proxy Statement filed by BPI Energy Holdings, Inc. with the SEC
on November 21, 2006).(#)
|
|
4
|
.3
|
|
Stock Purchase Agreement, dated September 20, 2005, by and
among BPI Energy Holdings, Inc. and the investors party
thereto.(***)
|
|
10
|
.1
|
|
Common Stock Purchase Warrant issued by BPI Energy Holdings,
Inc. on December 31, 2004 to Sanders Morris Harris, Inc.(*)
|
|
10
|
.2
|
|
Common Stock Purchase Warrant issued by BPI Energy Holdings,
Inc. on January 12, 2005 to Sanders Morris Harris, Inc.(*)
|
|
10
|
.3
|
|
Form of Warrant Certificate issued by BPI Energy Holdings, Inc.
in its December 2004/January 2005 private placement.(*)
|
|
10
|
.4
|
|
Advancing Term Credit Agreement, dated as of July 27, 2007,
by and between BPI Energy, Inc. and GasRock Capital LLC (Filed
as Exhibit 10.1 to
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
August 2, 2007 and incorporated herein by reference).
|
|
10
|
.5
|
|
Conveyance of Royalty Interest and Overriding Royalty Interest,
dated as of July 27, 2007, from and by BPI Energy, Inc. to
and in favor of GasRock Capital LLC (Filed as Exhibit 10.2
to
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
August 2, 2007 and incorporated herein by reference).
|
|
10
|
.6
|
|
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
|
.7
|
|
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
|
.8
|
|
Mineral Lease, dated as of October 25, 2005, by and between
BPI Energy, Inc. and the County of Clinton, Illinois (Western
Illinois Basin Project).()
|
|
10
|
.9
|
|
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
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
April 28, 2006 and incorporated herein by reference).
|
|
10
|
.10
|
|
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
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on
April 28, 2006 and incorporated herein by reference).
|
|
10
|
.11
|
|
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
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 15,
2006 and incorporated herein by reference).
|
|
10
|
.12
|
|
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
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 27,
2006 and incorporated herein by reference).
|
|
10
|
.13
|
|
Purchase and Sale Agreement, dated June 23, 2006, by and
between Colt LLC and BPI Energy, Inc. (Filed as
Exhibit 10.2 to
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 27,
2006 and incorporated herein by reference).
|
|
10
|
.14
|
|
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
Form 8-K
of BPI Energy Holdings, Inc. filed with the SEC on June 27,
2006 and incorporated herein by reference).
|
|
|
|
|
|
Number
|
|
Description
|
|
|
10
|
.15
|
|
Mineral Lease, dated as of September 9, 2006, by and
between BPI Energy, Inc. and the County of Washington, Illinois
(Western Illinois Basin Project) (Filed as Exhibit 10.12 to
Form 10-K
of BPI Energy Holdings, Inc. filed with the SEC on
October 30, 2006 and incorporated herein by reference).
|
|
10
|
.16
|
|
Mineral Lease, dated as of January 5, 2007, by and between
BPI Energy, Inc. and the County of Christian, Illinois (Northern
Illinois Basin Project).()
|
|
10
|
.17
|
|
Mineral Lease, dated as of June 7, 2007, by and between BPI
Energy, Inc. and the County of Marion, Illinois (Western
Illinois Basin Project).()
|
|
10
|
.18
|
|
Ratification of Mineral Lease, dated July 10, 2007, by and
between BPI Energy, Inc. and the County of Montgomery, Illinois
(Northern Illinois Basin Project).()
|
|
10
|
.19
|
|
Supplemental Memorandum of Mineral Lease, dated August 14,
2007, by and between BPI Energy, Inc. and the County of
Montgomery, Illinois (Northern Illinois Basin Project).()
|
|
10
|
.20
|
|
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
|
.21
|
|
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. (Filed as
Exhibit 10.22 to
Form 10-K
of BPI Energy Holdings, Inc. filed with the SEC on
October 30, 2006 and incorporated herein by reference).
|
|
10
|
.22
|
|
Agreement, dated as of April 17, 2004, by and between BPI
Energy Holdings, Inc. and James G. Azlein.(*)(#)
|
|
10
|
.23
|
|
Employment Letter Agreement, dated as of January 31, 2005,
by and between BPI Energy Holdings, Inc. and Randy Elkins.(*)(#)
|
|
10
|
.24
|
|
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).(#)
|
|
10
|
.25
|
|
BPI Energy Holdings, Inc. Senior Executive Severance Plan, dated
June 7, 2007 (Filed as Exhibit 10.1 to
Form 10-Q
of BPI Energy Holdings, Inc. filed with the SEC on June 13,
2007 and incorporated herein by reference).(#)
|
|
10
|
.26
|
|
BPI Energy Holdings, Inc. Key Employee Severance Plan, dated
June 7, 2007 (Filed as Exhibit 10.2 to
Form 10-Q
of BPI Energy Holdings, Inc. filed with the SEC on June 13,
2007 and incorporated herein by reference).(#)
|
|
21
|
.1
|
|
List of Subsidiaries.()
|
|
23
|
.1
|
|
Consent of Schlumberger Technology Corporation.()
|
|
23
|
.2
|
|
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.
|
Bpi (AMEX:BPG)
Graphique Historique de l'Action
De Juin 2024 à Juil 2024
Bpi (AMEX:BPG)
Graphique Historique de l'Action
De Juil 2023 à Juil 2024