BPI Energy Holdings, Inc. 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended July 31, 2006

Commission File Number: 001-32695

BPI Energy Holdings, Inc.

(Exact name of registrant as specified in its charter)


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 registrant’s 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 registrant’s most recently completed second fiscal quarter: $152,972,282.

As of October 25, 2006, there were 71,872,540 shares of the Registrant’s Common Shares (without par value) outstanding.

Documents Incorporated by Reference:

Certain portions of Part III are incorporated by reference to the Registrant’s definitive proxy statement.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some of the statements contained in this report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Statements containing the words “believes,” “anticipates,” “expects,” “intends,” “plans,” “predict,” “strategy,” “budget,” “project,” “potential,” “should,” “may,” “might,” “continue” and “estimate” and similar words are used to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements, or the conditions in our industry, on our properties or in the Illinois Basin to be materially different from any future results, performance, achievements or conditions expressed or implied by such forward-looking statements. Some of the factors that could cause actual results or conditions to differ materially from our expectations include the factors discussed in this report under the heading “Risk Factors” and elsewhere.

Given these uncertainties, you should not place undue reliance on such forward-looking statements. Except as otherwise required by applicable law, we undertake no obligation to publicly update or revise any forward-looking statements, the risk factors or other information described in this report, whether as a result of new information, future events, changed circumstances or any other reason after the date of this report.

PART I


ITEM 1.	*Business.*

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. We currently intend to drill and produce from coal seams ranging in depth from 300 to 1,200 feet beneath the surface.

CBM gas is released from the coal by pressure changes when water is removed from coal. In contrast to conventional gas wells, new CBM wells initially produce mostly water for several months. As pressure decreases in the coal formation, methane gas is released from the coal.

To assist you in reading this report and understanding our business, we have included a glossary of selected natural gas terms that are used in this report. The glossary is set forth as Appendix A beginning on Page A-1.

Our Business

We focus on the acquisition, exploration, development and production of CBM reserves located in the Illinois Basin, which covers approximately 60,000 square miles in the mid to southern part of Illinois, southwest Indiana and northwest Kentucky. Through lease, option and farm-out agreements and ownership of a CBM estate, we have assembled CBM rights covering approximately 500,000 acres in the Illinois Basin. We believe that these rights currently give us control over more CBM acreage than any other company in the Illinois Basin.

A Gas Technology Institute report from 2001 estimates that 21 trillion cubic feet of CBM gas is in place in the Illinois Basin. Although the Illinois Basin is believed to have significant CBM potential, it is largely untested for commercial CBM production. In addition, we have evaluated the CBM potential in only a relatively small part of our acreage rights.

Our acreage rights in the Illinois Basin are currently divided into three projects. Our Southern Illinois Basin Project consists of approximately 10,000 acres in the southern part of the Illinois Basin. Our other acreage holdings include our Northern Illinois Basin Project, located in the north central part of the Illinois Basin, where we control through lease, option and farm-out agreements an aggregate of 353,531 acres of CBM rights. Our other project is our Western Illinois Basin Project, located in the northwestern part of the Illinois Basin, where we control through lease, option and farm-out agreements an aggregate of 135,948 acres of CBM rights. In addition, we continue to look for opportunities to acquire additional CBM acreage rights in the Illinois Basin.

As of July 31, 2006, we have drilled 125 wells. These wells include 86 productive wells, 14 shut-in wells, five plugged wells, two disposal wells and 18 wells that have been drilled but are not yet in production, including five test wells.

Our History

BPI Energy Holdings, Inc. was incorporated under the laws of British Columbia in 1980. Our corporate offices in the United States are located at 30775 Bainbridge Road, Suite 280, Solon, Ohio 44139, telephone (440) 248-4200. Our records office and registered office in Canada is located at 609 Granville Street, Suite 1600, Vancouver, British Columbia V7Y 1C3, telephone (604) 685-8688. Our operations are conducted from an office located in Edwardsville, Illinois.

Beginning in 1996, we had a minority involvement in the Southern Illinois Basin Project. In 2001, Methane Management, Inc. acquired the Southern Illinois Basin Project subject to our minority interest. In August 2001, we acquired Methane Management, Inc. and consolidated 100% of the Southern Illinois Basin Project within BPI. James G. Azlein, President of Methane Management, Inc. at the time, became our President, and we created a new management team. We have since divested all of our assets that are not related to CBM projects in the Illinois Basin.

Business Strategy

The objectives of our business strategy are to generate growth in gas reserves, production volumes and cash flows at a positive return on invested capital. The principal elements of our business strategy are to:


	•	Explore and Develop Properties. As of July 31, 2006, we have drilled 125 wells. These wells consist of 86 productive wells (all located at our Southern Illinois Basin Project), 14 shut-in wells, five plugged wells, two disposal wells and 18 wells that have been drilled but are not yet in production, including five test wells. During the 12-month period ending July 31, 2007, we plan to drill between 58 and 123 new wells. This plan contemplates capital expenditures of approximately $12.0 million to $30.0 million. The number of wells that we drill during the 12-month period ending July 31, 2007 will be dependent on (i) data obtained from test wells; (ii) data obtained from our initial pilot wells at our Northern Illinois Basin Project; and (iii) the additional capital that we are able to raise and the risk factors described in this report.


	•	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 acquire leases and options on large acreage blocks in areas where reservoir properties are more favorable and there is currently pipeline delivery infrastructure in place.

	•	Pursue Joint Ventures. We continue to consider joint venture opportunities. With our asset base and technical expertise, we believe that we are well positioned to attract industry joint venture partners for the purposes of providing capital, technical operating expertise and development opportunities to accelerate our growth.

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. We believe that we currently control more CBM acreage than any other company in the Illinois Basin. This substantial footprint should give us opportunities to leverage our knowledge of the Basin and realize significant economies of scale as our drilling and production activities grow throughout the Basin.

	•	Demonstrated Commercial Production. We believe that we have taken the initial steps to demonstrate the commercial production capabilities of the Illinois Basin. As of July 31, 2006, we have drilled 125 wells, including 86 productive wells located at our Southern Illinois Basin Project, most of which have not yet reached peak production. We believe that our increasing production at the Southern Illinois Basin Project demonstrates the commercial viability of the Illinois Basin. During our fiscal year ended July 31, 2005 we sold 17,885 Mcf of CBM, and during our fiscal year ended July 31, 2006 we sold 135,118 Mcf of CBM.

	•	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 the operating employees own common shares in the company.

CBM Acreage Rights

As of July 31, 2006, our CBM acreage rights, controlled through lease, option and farm-out agreements and ownership of a CBM estate, include the following:


	Developed		Undeveloped		Total
Project	Acres		Acres		Acres(1)

Southern Illinois Basin Project(2)		5,532		4,468		10,000
Northern Illinois Basin Project		0		353,531		353,531
Western Illinois Basin Project		0		135,948		135,948

Total		5,532		493,947		499,479


(1)		Because we are the exclusive owner of the CBM rights under each of our lease, option and farm-out agreements, our acreage totals reflect both gross and net acres.

(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 and option agreements pursuant to which we have acquired nearly all of our CBM rights, we are entitled to all of the CBM rights held by our lessors in the counties covered by these agreements. However, we face a number of uncertainties regarding what rights our lessors hold.

The issue of who owns CBM gas, as between the coal rights owner and the oil and gas rights owner, is uncertain in Illinois. Although the appellate court in Illinois for the district where most of our acreage rights are situated has ruled that CBM gas is owned by the coal rights owner, the issue has not been addressed by the highest court in Illinois. We believe, based on advice from legal counsel, that under Illinois law ownership will ultimately be found to lie with the coal rights owner. Based on this advice, we generally secure CBM rights from the coal owners. Some of the lessors from which we have acquired CBM rights may hold both the coal rights and the oil and gas rights for the applicable properties, but in some cases it is not certain that these lessors also hold the oil and gas rights. If any litigation in Illinois concludes that CBM rights lie with the oil and gas owner, we could lose some of our CBM rights.

In addition, in some cases the extent of the coal and/or oil and gas rights held by our lessors is uncertain. We conducted no title or deed examinations prior to executing our lease and option agreements, and our lessors made no warranties as to the acreage or rights covered by the agreements. Although we have now conducted title and deed examinations covering much of the CBM properties under our leases, these examinations are ongoing at all of our projects. There can be no assurance that our rights under our lease and option agreements include all of the acreage and rights identified in the agreements until title examinations on all of the underlying properties have been completed.

We have been subject to legal complaints regarding the extent of the surface rights that derive from our CBM rights. On occasion, the owners of properties that are adjacent to our drilling locations have challenged our right to cross their property in accessing our drilling locations and our right to lay gas and water flow lines across their property. The extent of our rights in respect of these issues is uncertain in Illinois. If disputes regarding our surface rights are not resolved in our favor, we may be required to acquire surface rights or access our drilling locations and lay gas and water flow lines in inefficient ways, which would cause us to incur increased operating costs. In addition, we could incur significant costs in legal disputes over our surface rights. During our fiscal year ended July 31, 2005 we incurred approximately $303,000 in legal fees in connection with legal disputes over surface rights, and during our fiscal year ended July 31, 2006 we incurred approximately $10,000 in legal fees in connection with such disputes. If for any reason these operating or legal costs increase significantly, our financial performance will suffer.

Southern Illinois Basin Project

Our CBM rights in the Southern Illinois Basin Project cover 10,000 acres in the southern part of the Illinois Basin. We hold our CBM rights on this acreage pursuant to a purchase agreement under which we acquired the

CBM estate in a settlement with our former lessor, the owner of the coal rights. Under the terms of the deed covering this acreage, our right to drill for and produce CBM takes precedence over coal mining operations for as long as CBM is being produced from the acreage. However, the owner of the coal rights has the right to acquire any CBM wells located in these 10,000 acres. If the coal rights owner exercises this option, it will be required to (i) immediately plug any such well so acquired and (ii) pay the fair market value (as established by a mutually agreed upon expert) of such well.

We are currently paying two overriding royalties of 3% and 4% on our production at this project, which are calculated based on 43.35% of our gross revenues.

We commenced sales of gas from our initial pilot production wells on this project in January 2005. As of July 31, 2006, we have drilled 108 wells at this project. These wells consist of 86 productive wells, 14 shut-in wells, of which eight are scheduled to be plugged in fiscal year 2007 (as a result of the Colt LLC settlement), four plugged wells, one disposal well and three wells that have been drilled but are not yet in production. Most of the productive wells drilled at this project were initially completed in a limited number of seams, intentionally excluding other seams. Our intention when we drilled these wells was to gather as much geological information as we could about CBM and dewatering characteristics of individual coal seams. During our 2006 fiscal year we went back and completed additional seams in most of these wells to begin dewatering and producing CBM from the additional seams penetrated by these wells. During fiscal year 2007, we will determine whether it is beneficial to complete additional seams in the remaining wells.

Northern Illinois Basin Project

Our CBM rights in the Northern Illinois Basin Project cover 353,531 acres in Montgomery, Shelby, Christian, Fayette and Macoupin Counties in Illinois, which are located in the north central part of the Illinois Basin. We hold our CBM rights on this acreage pursuant to mineral leases, an option to acquire a mineral lease and a farm-out agreement.

We have entered into a lease agreement with Montgomery County covering 120,951 acres of CBM rights in Montgomery County, Illinois. The lease agreement extends until November 27, 2010. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. Under the lease agreement, we will be required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage.

We have also entered into a lease agreement with Shelby County covering 63,250 acres of CBM rights in Shelby County, Illinois. This lease agreement extends until November 12, 2008. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage, with each productive vertical well holding 320 acres and each productive horizontal well holding 1,920 acres. We are required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage.

We have also entered into a lease agreement with IEC (Montgomery), LLC covering 102,000 acres of CBM rights in Christian, Fayette, Montgomery and Shelby Counties in Illinois. The lease agreement extends until April 26, 2026. After the initial term of the agreement, we can continue to hold the lease as to each acreage block where we are producing CBM in commercial quantities. We are required to pay royalties to the lessor on our gross proceeds from the sale of CBM produced from the covered acreage at rates ranging up to 12.5%.

We have also entered into a lease agreement with Christian Coal Holdings, LLC covering 12,044 acres of CBM rights in Christian and Montgomery Counties in Illinois. The lease agreement extends until April 26, 2026. After the initial term of the agreement, we can continue to hold the lease as to each acreage block where we are producing CBM in commercial quantities. We are required to pay royalties to the lessor on our gross proceeds from the sale of CBM produced from the covered acreage at a rate of 12.5%.

We also hold an option from Christian County to lease 14,033 acres of CBM rights in Christian County, Illinois. The option extends until January 20, 2007. The lease agreement underlying the option will extend for a period of five years from the date we exercise the option. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. Under the lease agreement, we will be

required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage.

Under the lease agreements with Montgomery and Shelby Counties and the lease agreement underlying the option agreement with Christian County, our right to drill for and produce CBM is expressly subject to the mining of coal on the covered acreage. We may not interfere with any existing coal mining operations and, under certain circumstances, may be required to cease drilling in locations where coal mining operations will be undertaken.

Under the lease agreements with IEC (Montgomery), LLC and Christian Coal Holdings, LLC, any drilling operations that we set up can be displaced by coal mining operations. However, the lessor is required to provide us with a mine plan for the leased acreage indicating the acreage blocks that the lessor plans to mine and the order of priority for the acreage blocks that it plans to mine. If the lessor displaces a well ahead of the schedule outlined in the mine plan, the lessor may be required to reimburse us for the cost of plugging the well and, depending on how long the well has been in production and the cumulative gross income generated by the well, the value of the CBM that could be recovered from the well in the remainder of an eight-year term.

Also included in the Northern Illinois Basin Project are 41,253 acres of CBM rights in Macoupin County, Illinois, which we can earn under a farm-out agreement with Addington Exploration, LLC, as described below.

As of July 31, 2006, we had just recently completed drilling of a 10-well pilot program at this project, and all wells were in the initial stages of dewatering as of that date. As of the same date, we have drilled three test wells at this project. In addition, we intend to drill two additional test wells at this project during the first quarter of 2007.

Western Illinois Basin Project

Our CBM rights in the Western Illinois Basin Project cover 135,948 acres in Clinton, Washington, Marion and Perry Counties in Illinois, which are located in the northwestern part of the Illinois Basin. We hold our CBM rights on this acreage pursuant to mineral leases, an option to acquire a mineral lease and a farm-out agreement.

We have entered into a lease agreement with Clinton County covering 55,900 acres of CBM rights in Clinton County, Illinois. The lease agreement extends until October 24, 2010. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. We are required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage.

We have also entered into a lease agreement with Washington County covering 39,169 acres of CBM rights in Washington County, Illinois. The lease agreement extends until September 9, 2011. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage, with each productive vertical well holding 320 acres and each productive horizontal well holding 1,920 acres. We are required to pay royalties to the lessor from our gross proceeds from the sale of CBM produced from the covered acreage. The royalty is equal to 12.5% or 6.25% of our gross proceeds, depending on whether it is determined that Washington County’s CBM rights, if any, are derived from coal rights or oil and gas rights.

We also hold an option from Marion County to lease 17,882 acres of CBM rights in Marion County, Illinois. The option extends until June 8, 2007. The lease agreement underlying the option will extend for a period of five years from the date we exercise the option. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. Under the lease agreement, we will be required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage. If we do not commence exploration of CBM within one year from the commencement of the lease, we will be required to pay advance royalties to the lessor equal to $8,941 for each one-year period that we delay commencing exploration. Any payment of advance royalties can be credited against royalties that may later become payable to the lessor from our production of CBM.

Under the lease agreement with Washington County and the lease agreement underlying the option agreement with Marion County, our right to drill for and produce CBM is expressly subject to the mining of coal on the covered acreage. We may not interfere with any existing coal mining operations and, under certain circumstances, may be

required to cease drilling in locations where coal mining operations will be undertaken. Under the lease agreement with Clinton County, coal mining rights granted to third parties do not take precedence over our CBM operations.

Also included in the Western Illinois Basin Project are 22,997 acres in Perry County, Illinois, which we can earn under a farm-out agreement with Addington Exploration, LLC, as described below.

As of July 31, 2006, we have drilled two wells at the Western Illinois Basin Project that have not yet been completed and from which we are still gathering and evaluating test data. We intend to drill three test wells at this project during the first quarter of fiscal 2007.

Farm-out Agreement with Addington Exploration, LLC

We have entered into a farm-out agreement with Addington Exploration, LLC covering 41,253 acres of CBM rights in Macoupin County, Illinois and 22,997 acres of CBM rights in Perry County, Illinois that Addington controls pursuant to coal seam gas leases. The farm-out agreement provides for an initial 36-month evaluation period, during which we may test and evaluate the covered properties. The 36-month evaluation period can be extended by us on unearned acreage through the payment of a fee equal to $0.50 per acre, increasing over five years to $2.50 per acre. For each vertical and horizontal well that we place into production during the term of the agreement, Addington will assign to us its CBM rights covering the surrounding 160 acres penetrated by one of our wells.

We are required to pay Addington a royalty equal to 3% of our proceeds from the sale of CBM produced from the covered acreage. In addition, we must pay royalties totaling 12.5% to the lessors under the coal seam gas leases underlying this farm-out agreement.

Technical Services Agreement with BHP Billiton

Our Technical Services Agreement with BHP Petroleum (Exploration) Inc., a wholly owned subsidiary of BHP Billiton, expired at the end of its term on September 30, 2006, and BHP did not exercise its right to extend the agreement. The right of first refusal to acquire us that was granted to BHP under the Technical Services Agreement lapsed as of the expiration date of the agreement, although the 4.0 million stock appreciation rights that we granted to BHP, which may be exercised by BHP only in connection with an acquisition of us, continue in effect until March 30, 2007.

Status of CBM Operations

The following table summarizes the status of wells we have drilled as of July 31, 2006:


			Nonproductive Wells
	Productive		Drilled — Not Yet
Project	Wells		Completed(1)		Shut-in(2)		Plugged		Disposal		Total

Southern Illinois Basin Project		86		3		14		4		1		108
Northern Illinois Basin Project		—		13		—		1		1		15
Western Illinois Basin Project		—		2		—		—		—		2

Total		86		18		14		5		2		125


(1)		Wells drilled — not yet completed includes our recently completed drilling of a 10-well pilot program and three test wells at the Northern Illinois Basin Project, two test wells at our Western Illinois Basin Project and three wells drilled at our Southern Illinois Basin Project in late fiscal year 2006 that were completed in early fiscal year 2007 and became productive wells.

(2)		Shut-in wells include eight wells that will be plugged during fiscal year 2007 in connection with our settlement agreement with Colt LLC. Of these eight wells to be plugged, Colt LLC has agreed to plug four wells at their expense and we will be responsible for plugging the remaining four wells.

The following table sets forth our drilling activities over the last three fiscal years:


	Fiscal Years Ended July 31,
	2006		2005		2004

Exploratory Wells(1):
Productive(2)		10		—		—
Nonproductive(3)		4		3		—

Total		14		3		—
Development Wells(1):						—
Productive(2)		49		37		—
Nonproductive(3)		5		17		—

Total		54		54		—
Total Wells:
Productive(2)		59		37		—
Nonproductive(3)		9		20		—

Total		68		57		—


(1)		An exploratory well is a well drilled either in search of a new, as yet undiscovered CBM reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of a CBM reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

(2)		A productive well is an exploratory or development well that has been completed and is tied into our gas and/or dewatering system. A productive well may produce only water for a period of time before gas begins to flow through the gas gathering system.

(3)		A nonproductive well is an exploratory or development well that is not currently a producing well.

As of July 31, 2006, all of the wells that we have drilled are vertical wells. We estimate that a typical vertical well will require about 24 months to reach peak production. Most of the productive wells were completed in a

limited number of seams, intentionally excluding other seams. Our intention when we drilled these wells was to gather as much geological information as we could about CBM and dewatering characteristics of individual coal seams. During our 2006 fiscal year we went back and completed additional seams in most of these wells to begin dewatering and producing CBM from the additional seams penetrated by these wells. During fiscal year 2007, we will determine whether it is beneficial to complete additional seams in the remaining wells. We began selling gas from our first productive wells in January 2005. As of July 31, 2006, we believe that most of our productive wells have not yet reached peak production. Although we have drilled wells on only a relatively small part of our acreage, we have not to date determined that any well we have drilled is a dry hole.

Production and Sales

The following table sets forth our net sales volume for the periods indicated.

Twelve Months Ended July 31,

2006(1)

2005(1)(2)

2004(2)

Total sales (Mcf)

135,118

17,885

—


(1)		Total sales volumes omits (i) gas consumed in operations and (ii) gas sales equivalent to royalty interests held by our various lessors.

(2)		No gas was produced until January 2005.

Average Sales Prices and Production Costs

The following table sets forth the average sales price and average production costs for all of our gas production for the periods indicated.


	Twelve Months Ended July 31,
	2006		2005		2004

Average gas sales price (per Mcf)	$	8.34	$	6.59	$	—
Average production cost (per Mcf)(1)		7.18		17.18		—


(1)		Production costs include a significant amount of fixed expenses required to operate a minimum number of wells. As the number of wells and production increase, these costs are expected to decrease on a per unit basis as they are spread over a greater amount of production.

Reserves

Proved reserves are the estimated quantities that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements (of which none existed as of July 31, 2005 and 2006, the dates of our estimates of proved reserves prepared by our independent reservoir engineer consultant, Schlumberger Data & Consulting Services), but not on escalations based on future conditions. The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interests owned by our lessors. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and undeveloped reserves are defined by SEC Rule 4-10(a)(2) of Regulation S-X.


	Net Reserves (MMcf)
	As of July 31,
	2006		2005		2004

Estimated proved developed reserves		8,983		2,971		—
Estimated proved undeveloped reserves		5,735		7,321		—

Total estimated proved developed and undeveloped reserves		14,718		10,292		—

Discounted Future Cash Flows

The following table shows our standardized measure of discounted future net cash flows, based on our estimated proved developed and undeveloped reserves (discounted at a rate of 10%), net of taxes:


	As of July 31,
	2006		2005		2004
	(In thousands)

Total standardized measure of discounted future net cash flows	$	32,734	$	23,068		—
Prices used in calculating reserves (per Mcf)		7.22		7.44		—

Sales and Distribution of Our Gas

Our current and future plans anticipate that we will sell all of our CBM to either (i) pipeline companies or (ii) natural gas marketing companies that secure space on pipelines. There are multiple pipeline and gas marketing companies we could choose to deal with in selling our CBM. There are multiple interstate and intrastate pipeline companies that have pipelines that cross or are in close proximity to all of our current acreage in the Illinois Basin. The interstate pipelines include lines owned by Texas Eastern, Northern Borders, NGPL and Ameren. These pipelines are available to the marketing companies to whom we anticipate selling CBM. We believe that these marketing companies will have adequate capacity from the existing pipelines in the Illinois Basin to be able to purchase all of the CBM we anticipate producing and selling within the next three to five years.

We currently sell all of our CBM production to one gas marketing company, Atmos Energy Marketing, LLC, pursuant to monthly contracts. Under these monthly contracts, Atmos is required to buy all of our CBM production, up to a maximum of 2,500 MMBtus per day (which equates to approximately four times our current daily production), at the NYMEX (New York Mercantile Exchange) price as of the close of business on the last day of the most recently ended month less twenty-five cents per MMBtu as a marketing charge. If we are unable to extend our monthly contracts with Atmos, we believe that we will have multiple gas marketing companies available to us for the sale of our CBM production.

We currently have no fixed price contracts for the sale of our CBM. We do not anticipate entering into any fixed price contracts for the sale of our CBM during the next 24 months. We will reevaluate the risks and benefits of entering into fixed price contracts after our projects and wells become more mature.

Availability of Drilling Equipment and Personnel

We utilize drilling contractors to perform all of the drilling on our projects. We maintain a limited number of supervisory and field personnel to oversee drilling and production operations. Our plans to drill additional wells are determined in large part by the anticipated availability of acceptable drilling equipment and crews. We believe that sufficient drilling equipment and crews will be available to us in the Illinois Basin to achieve our drilling plan for fiscal year 2007 (i.e., drilling between 58 and 123 CBM wells). However, we do not currently have any contractual commitments with drilling contractors, and we can provide no assurance that we will have adequate drilling equipment or crews to achieve our drilling plans.

Governmental Regulations

Our business is affected by numerous laws and regulations, including those relating to energy, the environment and conservation. Failure to comply with these laws and regulations may result in increased compliance costs and the assessment of administrative, civil or criminal penalties and/or the imposition of injunctive relief. Changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our current operations comply in all material respects with applicable laws and regulations, and that they have no more restrictive effect on us than on other similar companies in the energy industry.

The following discussion describes certain laws and regulations that apply to us and is qualified in its entirety by the foregoing.

State Regulations

Our operations are subject to regulation at the state level and, in some cases, county, municipal and local governmental levels. Such regulation includes:


	•	requiring permits for the drilling of wells;

	•	maintaining bonding requirements to drill or operate wells;

	•	regulating the location of wells, the method of drilling and casing wells, surface use and the restoration of properties upon which wells are drilled; and

	•	regulating the plugging and abandoning of wells and the disposing of fluids used and produced in connection with operations.

Our operations are also subject to various conservation laws and regulations relating to well spacing and safety issues for gas gathering systems.

Environmental Regulations

We are subject to extensive federal, state and local environmental laws and regulations that, among other things, regulate the discharge or disposal of substances into the environment and otherwise are intended to protect the environment. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil and/or criminal penalties and, in some cases, injunctive relief for failure to comply. Some laws and regulations relating to the protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination. Other laws and regulations may impose restrictions that prevent the rate of natural gas production from being economically optimal or restrict or prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action such as the closure of inactive pits and the plugging of abandoned wells to prevent pollution from former or suspended operations.

We believe that we are in substantial compliance with current applicable laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. However, from time to time, legislation or other initiatives are proposed to place more onerous conditions on our operations. Adoption of any such proposals could adversely impact our operating costs, capital expenditures, earnings or competitive position.

Our CBM operations require the hydraulic fracturing of coal seams. We believe that this technique is in compliance with applicable laws and regulations, but neither the Illinois Department of Natural Resources — Office of Mines and Minerals nor the U.S. Environmental Protection Agency regulates the hydraulic fracturing of coal bed formations as a form of underground injection. It is possible that the hydraulic fracturing of coal beds for CBM production will become regulated within the United States as a form of underground injection, resulting in the imposition of stricter performance standards, which, if not met, could result in diminished opportunities for CBM production enhancement and increased administrative and operating costs.

In CBM production, naturally occurring groundwater is pumped to the surface as a by-product. We currently dispose of water from our wells through water flow lines that re-inject the water into water disposal wells. Discharge of this water is subject to federal and local regulation, and we are required to obtain permits from the State of Illinois to re-inject the water that our wells produce. We have received permits from the State of Illinois that allow us to dispose of all the water that we anticipate producing at both our Southern Illinois Basin Project and Northern Illinois Basin Project during the fiscal year 2007. As we drill additional wells in areas not currently serviced by our existing water disposal wells, we believe that we will be able to obtain the necessary permits for additional disposal wells, although we can make no assurance in this regard. If the water produced from our wells increases substantially and/or the water quality falls below acceptable standards, other disposal or treatment methods may be required to be implemented.

Competition

We operate in the highly competitive natural gas market. We face competition from other companies in each of the following areas:


	•	acquiring CBM acreage rights;

	•	selling our natural gas production;

	•	identifying and employing new technologies; and

	•	acquiring the equipment, expertise and personnel necessary to develop and operate our properties.

Many of our competitors have financial, technological and other resources that are greater than ours. These companies may be able to pay more for CBM acreage rights and exploratory prospects and may be able to evaluate and purchase more acreage rights and prospects than our resources permit. To the extent our competitors are able to pay more for properties, technologies, equipment and qualified personnel than we are, we will be at a competitive disadvantage. In addition, many of our competitors may enjoy technological advantages and may be able to identify, develop or implement new technologies more rapidly than we can. Our ability to acquire additional acreage rights and explore for CBM prospects in the future will depend upon our ability to obtain the necessary equipment, attract and retain and qualified personnel, successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this competitive environment.

Employees

As of July 31, 2006, we have 16 full-time employees, including our executive officers. We utilize independent consultants and contractors to perform various professional services and for drilling, testing and completion work.

Executive Officers and Directors


Name	Age		Position

James G. Azlein		57	President, Chief Executive Officer and Director
James E. Craddock		47	Senior Vice President of Operations
Dennis Carlton		56	Director
William J. Centa		54	Director
David E. Preng		60	Director
Costa Vrisakis		72	Director

James G. Azlein has been President, Chief Executive Officer and a Director since August 23, 2001. From 1979 to 1998, Mr. Azlein held positions including President and Chief Financial Officer and was a principal of Cyrus Eaton Group (“CEG”), a private company that specialized in project development, including securing technologies, management, financing and marketing for a variety of projects, for hotels and resorts, agricultural projects and manufacturing plants. CEG concentrated on projects in conjunction with government authorities in Eastern Europe, the former U.S.S.R. and China. In 1998, Mr. Azlein and a partner acquired the interests of CEG when its founder retired, and formed International Resource Management, Inc., which continued project development in India and Mexico through June 2001. In early 2000, Mr. Azlein formed Methane Management, Inc. to acquire the interest of various partners in a 43,000 acre CBM project in southern Illinois in which BPI owned a minority interest. In August 2001, BPI acquired Methane Management, Inc. and Mr. Azlein became President of BPI and began assembling a new management team that refocused BPI’s attention on CBM development in the Illinois Basin, which started with the 43,000 acre project that is now referred to as the Southern Illinois Basin Project.

James E. Craddock has been Senior Vice President of Operations since April 2006. He oversees all of our operational activities, including engineering, geology and land management activities. In particular, he is integrally involved in planning and managing all aspects of our CBM exploration, drilling and production activities. Mr. Craddock joined us from Houston-based Burlington Resources Inc. (acquired on March 31, 2006 by ConocoPhillips), where he served as Chief Engineer. In this, his most recent capacity with Burlington, he was

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 Burlington’s $3 billion acquisition of the Louisiana Land & Exploration Company (LL&E). He was also involved in developing Burlington’s 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 play’s peak level of activity, this required drilling up to 300 new CBM wells per year, conducting up to 100 recompletions per year and participating in 100 non-operated wells each year. He began his career in 1981 with Superior Oil (later Mobil) upon graduating from Texas A&M University with a Bachelor of Science in Mechanical Engineering.

Dennis Carlton has been a Director since May 2005. Mr. Carlton has been involved in CBM since 1989. From 1995 through September 2004, he served as a director and worked in several senior executive positions with Evergreen Resources, Inc., serving most recently as Executive Vice President, Exploration and Chief Operating Officer, as well as President of Evergreen Operating Corp. His primary responsibilities included management of all geoscience, engineering, land matters and domestic and international business development activities. Since October 2004, when Evergreen was acquired by Pioneer Natural Resources, Inc., Mr. Carlton has served as a technical and business advisor to Pioneer’s Western Division. Prior to joining Evergreen Resources, he held positions in several companies including Mobil Oil Corporation. Mr. Carlton’s career and knowledge base in CBM spans a vast geographic area including the Rocky Mountain Basins, Mid-Continent, United Kingdom and Alaska. His efforts in the Raton Basin with Evergreen were recognized when he was named the Rocky Mountain Association of Geologists’ Outstanding Explorer in 2000.

William J. Centa has been a Director since March 2005. Mr. Centa has been actively involved in financial and business management for more than 30 years. His career has ranged from his role as president of middle-market manufacturing and distribution companies to executive management of financial firms. Since March 2004, he has served as Executive Vice President and is one of the co-founders of Mayfran Holdings, Inc., a multinational manufacturing and engineering company that designs conveyor and filtration equipment used in the machine tool industry. From October 2000 through March 2004, Mr. Centa served as Chief Operating and Financial Officer for iPower Logistics, a supply chain solutions and outsourcing firm providing services to industrial companies in North America. Mr. Centa remains a shareholder of both Mayfran and iPower. From February 1998 until October 2000, he served as Associate Director, Mergers & Acquisitions at the accounting firm Ernst & Young LLP. Prior to holding these positions, Mr. Centa served as Chief Operating Officer for several international manufacturing and distribution companies. Mr. Centa earned his MBA in 1977 from Cleveland State University. He is a certified public accountant and has been a member of the AICPA’s Business & Industry Executive Committee since 2002 and the Enhanced Business Reporting Task Force since 2003.

David E. Preng has been a Director since February 2006. Mr. Preng is the president of Preng & Associates, an executive recruiting company he founded in 1980. Preng & Associates focuses exclusively on matching senior-level business executives seeking board of director, chief executive and other upper-level assignments with energy and natural resources companies in both the United States and Europe. Mr. Preng, who has managed numerous global engagements for a variety of multinational clients, coordinates Preng & Associates’ worldwide practice and is directly responsible for Russian, CIS and Far East recruiting in North America. Prior to founding Preng & Associates, he spent six years in the executive search industry. His industry background includes financial, managerial and executive positions with Shell Oil Company, Litton Industries and Southwest Industries. Mr. Preng earned his Bachelor of Science from Marquette University and his MBA from DePaul University. Since 1997, he has been a director of Remington Oil and Gas where, in addition to chairing its Nomination & Governance Committee, he serves as lead independent director and as a Compensation Committee member. During his tenure on Remington’s board, Remington was acquired by Cal Dive International, Inc. Mr. Preng also serves on the board of directors of Maverick Oil & Gas, Inc., where he chairs its Compensation Committee. He is a director of Community National Bank as well as the Houston Chapter of the National Association of Corporate Directors. Additionally, he is a fellow of the Institute of Directors in London and has served three terms as director and two years as president of the British American Business Council.

Costa Vrisakis has been a Director since January 2002. Mr. Vrisakis is a financier and entrepreneur based in Sydney, Australia. He has been a founder and director of several Sydney Stock Exchange-listed companies. One of

his former ventures includes a printing company, Snap-Apart Pty. Ltd., which Mr. Vrisakis founded along with two employees in 1959. In 1985, Snap-Apart Pty. Ltd. was listed on the Sydney Stock Exchange under the name Computer Resources Ltd. In 1993, Moore Corp. of Toronto, Canada acquired Computer Resources. Since 1985, when Mr. Vrisakis sold his interest in Computer Resources Ltd., he has focused his attention on various real estate projects and stock market investments. Since 2000 through the present time, Mr. Vrisakis has devoted the majority of his time to managing his 50% interest in three hotels in Sydney, Australia.

Significant Employees

The following persons are not executive officers but make significant contributions to our business:

Randy Elkins, 40, assumed the position of Acting Chief Financial Officer in October 2006, and has been Controller since February 2005. He is a CPA with more than 14 years of experience in accounting and auditing. Prior to joining BPI, Mr. Elkins held a senior finance position with International Steel Group, Inc. (NYSE: ISG). From January 1992 through September 2004, he served in various increasingly responsible positions with Ernst & Young LLP, most recently as a senior manager in its Transaction Support Group. While at E&Y, he focused on audits of SEC public companies, mergers and acquisitions and bankruptcy restructurings.

Randy Oestreich, 49, has been Vice President of Field Operations since March 2005. Mr. Oestreich owns A-Strike Consulting, a private consulting company formed in April 2003 to provide consulting services to the CBM industry. From 1976 to 2003, Mr. Oestreich worked for Halliburton Energy Services. With Halliburton, Mr. Oestreich worked in conventional oil and gas exploration and development, as well as unconventional gas, including CBM, primarily in the Illinois Basin, but also in Michigan, Ohio, Kentucky, Pennsylvania and West Virginia. In addition, he was a member of Halliburton’s Coalbed Methane Solutions Team. For the past 10 years, his work has focused on CBM, mine methane and New Albany shale exploration and development. Mr. Oestreich has worked on, and is familiar with, the majority of unconventional gas projects that have been initiated in the Illinois Basin and has worked on the Southern Illinois Basin Project since its inception.

Dan Anderson, 57, has been Director of Property Acquisitions since January 2002. Mr. Anderson has over 25 years of oil and gas and real estate experience: from 1976 to 1983 as Land Department Manager with John Carey Oil Company, Inc.; from 1983 to 1989 as president of his own oil and gas investment consulting company, and as President of a private real estate development company, DAPA Investments, Inc. Prior to joining BPI, Mr. Anderson worked with DeMier Oil in securing oil, gas and CBM leases in central and southern Illinois, as well as pipeline right-of-way easements. He has extensive experience in the oil, gas and CBM business in the Illinois Basin, including oil and gas and CBM leasing terms and agreements. In addition, he has extensive experience in the workings of land title and registrar offices on both a local and state level. Mr. Anderson is a member of the Illinois Oil and Gas Association and holds an Illinois real estate broker license.

Michael Dawson, 56, has been Senior Geological Advisor since August 2006. He was most recently with Burlington Resources Inc. (recently acquired by ConocoPhillips) as a petroleum geologist. During his 26-year tenure with Burlington, he was involved in various exploration and exploitation projects. At Burlington’s 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 Burlington’s Amarillo and Houston offices where his responsibilities included prospect generation, wellsite geology, field development and economic analysis for projects in the Anadarko, Arkoma and other basins. Mr. Dawson began his career in 1978 with Conoco (later ConocoPhillips) upon graduating with a Master of Science in Geology from San Diego State University. He earned his Bachelor of Science in Geology from the University of Michigan.

James Erlandson, 31, also formerly of Burlington Resources, has been Senior Staff Reservoir Engineer since August 2006. Previously, he was team leader of the Kaybob Resource Assessment Team working in Calgary, Alberta, with responsibility for analyzing and developing regional unconventional gas plays in British Columbia and Alberta. As Mr. Erlandson progressed through assignments of increasing responsibility with Burlington, he was involved in strategic planning, acquisitions and exploitation of unconventional sand and CBM plays. He was also involved in the addition of proven gas reserves in the Western Canada Sedimentary Basin, infill program analysis and development, and the optimization of Fruitland coal wells in the San Juan Basin. Mr. Erlandson began his career

in 1997 as a production engineer with Marathon Oil Company after graduating with honors from Montana Tech, where he earned his Bachelor of Science in Petroleum Engineering.

Kelly Sutton, 29, has been Senior Staff Engineer since September 2006. Ms. Sutton was previously with Energen Resources, where she served as a reservoir/acquisitions engineer. While at Energen, she evaluated CBM properties in the Powder River, San Juan and Black Warrior Basins, oil properties in the Permian Basin and tight gas properties in East Texas and Northern Louisiana. Prior to Energen, she served in various reservoir and production engineering positions with Burlington Resources and Phillips Petroleum. Ms. Sutton received her Bachelor of Science in Chemical Engineering from the University of Alabama.

Bradford Sutton, 32, has been Senior Staff Engineer since September 2006. Mr. Sutton was previously with Energen Resources, where he focused on CBM and tight gas development in the San Juan Basin. Prior to joining Energen, Mr. Sutton was a production engineer at Burlington Resources. During his career, he has worked on CBM development in the San Juan and Powder River Basins and conventional gas and tertiary oil development in the Permian Basin. He holds a Bachelor of Science in Petroleum Engineering from the University of Alabama.

Internet Website

We must file annual, quarterly and other reports and proxy statements with the Securities and Exchange Commission (“SEC”). Our SEC filings are available to the public over the internet at the SEC’s 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 SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operations of the public reference room. In addition, we make available free of charge through our internet web site our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Additionally, charters for the committees of our Board of Directors and our Code of Business Conduct and Ethics can be found at our website under the heading “Highlights” on the “Corporate Governance” page. Stockholders may request copies of these documents by writing to the Investor Relations Department at 30775 Bainbridge Road, Suite 280, Solon, Ohio 44139.


ITEM 1A.	*Risk Factors.*

You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating us, you should consider carefully, among other things, the factors and specific risks set forth below, and in documents we incorporate by reference. This annual report contains forward-looking statements that involve risks and uncertainties.

Risk Factors Relating to Our Business

Our current revenues are minimal and not sufficient to support our operations. If we are unable to raise additional financing, we may not be able to carry out our long-term plans.

The wells that we have drilled began producing CBM for sale only in January 2005, and the amount of CBM that we are currently selling is not significant. We are not currently generating net income or positive cash flow from operations. Even if we achieve increased revenues and positive cash flow from operations in the future, we anticipate increased exploration, development and other capital expenditures as we continue to explore and develop our CBM rights. Therefore, in order to achieve our long-term plans and maintain a viable business, we will need to raise additional financing. If we are unable to raise additional financing, we will likely be unable to carry out our long-term plans, which would negatively impact the value of your investment in us.

Even if we continue to demonstrate the commercial viability of CBM wells in the Illinois Basin, we may encounter difficulty in raising additional capital on favorable terms. Interest rates and investor expectations and demands are subject to change, and any change in these areas could have a negative effect on the financing terms

that we are able to obtain. In addition, the terms of any new financing may adversely affect your investment. If we issue shares of preferred stock or additional common shares, institutional investors may negotiate terms equal to or more favorable than market prices or the terms of our prior offerings, resulting in dilution to existing shareholders. Debt financing could result in the lenders having a claim to assets prior to the rights of our shareholders, divert cash flow to service the debt, and restrict operations through compliance with lenders’ restrictions. Any such terms could adversely affect the return that you receive on your investment in us.

We have incurred significant operating losses since our inception and may not achieve profitability in the future.

We have experienced significant operating losses and negative cash flow from operations since our inception, and we currently have an accumulated deficit. During our fiscal year ended July 31, 2005 we incurred a net loss of $5,396,351, and during our fiscal year ended July 31, 2006 we incurred a net loss of $8,836,245. As of July 31, 2006, we have an accumulated deficit of $27,193,528. We anticipate that our operating costs and capital expenditures will continue to grow as we continue to explore and develop our CBM rights. Even if we significantly grow our revenues from the sale of CBM, it is possible that our increased operating costs and capital expenditures will prevent us from generating net income. In addition, in the future we could incur greater than expected drilling or other operating expenses, we could discover that our properties are not commercially viable, or gas prices could decline significantly. Any of these events would have a significantly negative impact on our ability to generate net income. If we are unable to achieve profitability at any time in the near future, the value of your investment in us could be adversely affected.

CBM exploration is speculative in nature and may not result in operating revenues or profits.

The Illinois Basin is largely untested for commercial CBM production. In addition, we have evaluated the CBM potential in only a relatively small part of our acreage rights. Only an extended production history of the wells that we drill will indicate whether our wells will be commercially productive over the long-term. We could determine in the future that the Illinois Basin does not contain enough CBM for commercially viable operations, or that the conditions in the Illinois Basin are not conducive for commercially viable operations. Any such determination would have a significantly negative effect on your investment in us.

Future wells that we drill may not be successful, due to low CBM content in the coal, low permeability, unusually low or high water quantities, low water quality, incorrect forecasts or other factors. We cannot be sure that completed wells will produce enough CBM to recover our capital investments. We can provide no assurance that the exploration and development of our projects will occur as scheduled, or that actual results will be in line with expectations.

The cost of drilling, completing and operating wells is often uncertain. Factors that can delay or prevent drilling operations, include:


	•	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.

We could experience delays in securing drilling equipment and crews, which would cause us to fail to meet our drilling plans and negatively impact our operations.

We utilize drilling contractors to perform all of the drilling on our projects. We maintain a limited number of supervisory and field personnel to oversee drilling and production operations. Our plans to drill additional wells are determined in large part by the anticipated availability of acceptable drilling equipment and crews. We do not currently have any contractual commitments that ensure we will have adequate drilling equipment or crews to achieve our drilling plans. If our anticipated levels of drilling equipment are not made available to us, we will have to modify our drilling plans, which would cause us to fail to meet our drilling plan and negatively impact our operations. If we cannot meet our drilling plans, the value of your investment in us may decline.

We could lose significant portions of our CBM acreage rights if we do not place into production a sufficient number of CBM wells.

The primary terms of the lease and farmout agreements pursuant to which we hold, or upon the exercise of options will hold, most of our CBM acreage rights will expire between November 2007 and April 2026, after which we will continue to hold our acreage rights only to the extent that we are producing CBM from the covered acreage. Under some of these leases we will retain only limited acreage rights for each CBM well that we place into production.

We could encounter strong competition for properties in the Illinois Basin.

The natural gas industry is highly competitive. We currently hold substantial CBM acreage rights in the Illinois Basin, but other companies may become active in the area. New entrants could have greater financial and technological resources, which might enable them to outbid us on new acreage or obtain leaseholds, option agreements or farm-out agreements for which we currently have agreements in place when our rights expire or lapse. Any loss of acreage would negatively impact the potential scope of our operations, which would likely have a negative impact on the value of your investment in us.

Because approximately 74% of our CBM acreage rights are inferior to coal mining rights covering the same properties, our affected operations could be displaced by coal mining operations, which would negatively impact our operations.

Under the agreements pursuant to which we hold approximately 74% of our CBM acreage rights, our right to drill for and produce CBM is expressly subject to the mining of coal on the acreage covered by the agreement. We may not interfere with any existing coal mining operations and, under certain circumstances, may be required to cease drilling in locations where coal mining operations will be undertaken. These superior coal rights may restrict the locations where we can drill CBM wells on our projects and may cause some of our CBM operations to be displaced by coal operations. Any such displacement could cover a significant portion of our CBM acreage rights. If we face significant restrictions on where we can drill our CBM wells or a significant number of our CBM wells are displaced by coal mining operations, our operations and financial performance will be negatively impacted.

The CBM rights that we have acquired under lease and option agreements are subject to a number of uncertainties, which, when resolved, could cause us to lose some of our CBM rights.

Under the terms of the lease and option agreements pursuant to which we have acquired most of our CBM rights, we are entitled to all of the CBM rights held by our lessors in the counties covered by these agreements. However, we face a number of uncertainties regarding what rights our lessors hold.

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.

If any of these uncertainties is resolved unfavorably to us, we could lose some of our CBM acreage rights. Any loss of our CBM acreage rights would negatively impact our growth potential, which could cause the value of your investment in us to decline.

We could incur significant costs in connection with disputes over surface rights, which would have a negative impact on our financial performance.

We could incur substantial costs to comply with environmental regulations, and our failure to comply with environmental regulations could result in significant fines and/or penalties, either of which could adversely affect our operations.

Our operations are subject to federal, state and local environmental laws and regulations. Although we believe that our operations to date have been conducted in compliance with these regulations, new more restrictive laws or regulations could be adopted, which could force us to expend significant resources to comply with the new requirements. Because CBM exploration is relatively new in the Illinois Basin, the governmental agencies that regulate us, including the Illinois Department of Natural Resources’ Office of Mines and Minerals, may determine that new laws and regulations are required to govern the growing industry. CBM operations are technologically different from conventional oil and gas operations, and these agencies may determine that existing regulations, which are generally focused on the oil and gas industry, are not sufficient for CBM operations. As CBM activity increases in the Illinois Basin, unexpected regulatory issues may develop, which could impose additional compliance costs on us. Any significant increase in compliance costs could have a negative impact on our results of operations and could prevent our properties from being commercially viable.

The occurrence of a significant adverse event that is not covered by insurance could have a material adverse effect on our financial condition.

The exploration for and development and production of CBM involves a variety of operating risks, including the possibility of fire, explosion and blow-out from abnormal formation pressure. It is not always possible to fully insure against such risks. An uninsured or underinsured loss could adversely impact our financial condition.

Our ability to attain profitable operations could be negatively impacted by any decline in natural gas prices.

Our ability to grow our revenues, and ultimately attain profitable operations, will depend not only on our ability to place CBM wells into production but on the market for natural gas. Natural gas prices have historically been volatile, and they are likely to continue to be volatile in the future. If natural gas prices decline significantly for extended periods of time, the CBM wells that we place into production may not be commercially viable and we might not be able to generate enough revenues to reach profitable operations. Our failure to reach profitable operations will negatively affect the value of your investment in us.

We will incur increased costs as a result of registering in the United States.

In December 2005, we became subject to the reporting requirements of the Securities Exchange Act of 1934. As an SEC registrant, we will incur significant legal, accounting and other expenses that we did not incur as a Canadian public company. We will incur costs associated with complying with the rules and regulations of the SEC, including those adopted under the Sarbanes-Oxley Act of 2002. We currently estimate that these costs will total approximately $1.0 million on an annual basis. In addition, we will continue to be subject to the securities laws and reporting requirements of the British Columbia Securities Commission and the Alberta Securities Commission. These dual reporting obligations will result in increased compliance costs, which could adversely affect our financial performance.

In addition, being subject to SEC regulation and the Sarbanes-Oxley Act may make it more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

There is not a substantial amount of trading in our common shares, which could prevent you from selling your common shares at acceptable prices or at all.

Our common shares are currently traded on the American Stock Exchange. There is not a substantial amount of trading in our common shares on the American Stock Exchange. We are not certain that a more active trading market in the stock will develop, or that it will be sustained if it does develop. Because the market for our common shares is limited and is likely to remain limited in the near future, you may not be able to sell your common shares at acceptable prices or at all.

The American Stock Exchange has adopted standards under which it will normally give consideration to removing a security from listing. However, the standards in no way limit the Exchange and it may at any time, in view of the circumstances in each case, remove a security from listing when in its opinion such security is unsuitable for continued trading on the Exchange. These standards include, but are not limited to, consideration of: (i) a company’s financial condition and/or operating results; (ii) whether the company has sold or otherwise disposed of its principal operating assets, ceased to be an operating company or discontinued a substantial portion of its operations; and (iii) whether a company’s common stock sells for a substantial period of time at a low price per share. It is possible that the Exchange could make a determination in the future that our stock is unsuitable for continued trading on the Exchange. If our stock is delisted from the Exchange, it will likely be difficult to effect sales of our stock.


ITEM 1B.	*Unresolved Staff Comments.*

None.


ITEM 2.	*Properties.*

Our corporate headquarters is located in a leased office in Solon, Ohio. Our operations are conducted from an office located in a leased facility in Edwardsville, Illinois. For information about our CBM acreage rights, production and gas reserves, see the section of this report entitled “CBM Acreage Rights.”


ITEM 3.	*Legal Proceedings.*

On June 23, 2006, our wholly owned subsidiary BPI Energy, Inc. entered into a Settlement and Mutual Release Agreement with Colt LLC (“Colt”), AFC Coal Properties, Inc. (“AFC”), American Premier Underwriters, Inc. (“APU”) and Central States Coal Reserves of Illinois, LLC (“Central States”). These parties were defendants in a lawsuit filed by BPI Energy, Inc. on March 15, 2006 relating to our Southern Illinois Basin Project.

The Settlement and Mutual Release Agreement provides that all parties to the lawsuit will release all of the other parties from any claims they may have had against each other. In addition, as conditions precedent to the settlement of claims, BPI Energy, Inc. (i) paid Colt $3,000,000; (ii) acknowledged that the Oil, Gas and Coalbed Methane Gas Lease dated April 3, 2001, as amended (the “Lease”), had lapsed and surrendered any interest it had in the Lease; and (iii) received a quitclaim deed from Colt with respect to the CBM estate covering a 10,000 acre portion of the 43,000 acres previously covered by the Lease.

Contemporaneously with the execution of the Settlement and Mutual Release Agreement, BPI Energy, Inc. entered into a Purchase and Sale Agreement with Colt pursuant to which it acquired ownership of the CBM estate covering approximately 10,000 of the 43,000 acres previously covered by the Lease. This acreage includes all of the currently producing CBM wells and proved reserves at our Southern Illinois Basin Project. The quitclaim deed executed by Colt provides that CBM operations take priority over coal mining operations for as long as CBM is being produced from the covered acreage. However, Colt has the right to acquire any CBM wells located in these 10,000 acres. If Colt exercises this option, it will be required to (i) to immediately plug any such well so acquired and (ii) pay the fair market value (as established by a mutually agreed upon expert) of such well.

As an additional condition precedent to the execution of the Settlement and Mutual Release Agreement, on June 23, 2006, the parties entered into a Termination Agreement with Colt, AFC, APU and Central States (collectively with BPI Energy, Inc., the “Parties”). This Termination Agreement acknowledged the termination and lapse of the Lease. All of the Parties agreed to discharge and release each of the other Parties from any and all obligations under the Lease.


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 2006.

PART II


ITEM 5.	*Market for Registrant’s 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.” Prior to December 13, 2005, our common shares were traded on the TSX Venture Exchange in Vancouver, British Columbia under the symbol “BPR.” The following table sets forth the high and low sales prices per share, in U.S. dollars, as reported by the American Stock Exchange or the TSX Venture Exchange, during each of our quarterly periods

ending in our 2005 and 2006 fiscal years. Prices reported on the TSX Venture Exchange in Canadian dollars have been converted to U.S. dollars based on exchange rates in effect on the applicable date.


	High		Low

Fiscal Year Ended July 31, 2005
Quarter ended October 31, 2004	$	0.98	$	0.57
Quarter ended January 31, 2005		2.05		0.78
Quarter ended April 30, 2005		2.02		1.31
Quarter ended July 31, 2005		1.96		1.37
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

As of October 25, 2006, we have 71,872,540 common shares outstanding, which are held by approximately 840 shareholders of record. The transfer agent and registrar for our common shares is Pacific Corporate Trust, Vancouver, British Columbia. In addition to our outstanding common shares, as of October 25, 2006, we have reserved 1,823,265 common shares for issuance upon the exercise of outstanding stock options and 5,311,600 common shares for issuance upon the exercise of outstanding warrants.

In fiscal year 2006, we issued the following unregistered securities. Except for the September 26, 2005 issuance, when KeyBanc Capital Markets, a division of McDonald Investments, Inc., and Sanders Morris Harris, Inc. acted as placement agents, we did not use a principal underwriter for any of the issuances listed in the table below. Each such sale was exempt from registration under the Securities Act of 1933 in reliance on Section 4(2) of the Securities Act and/or regulations issued thereunder as sales to qualified purchasers not involving a public offering.


				Aggregate Offering
Date of sale	Title and Amount of Securities Sold	Offering Price		Price

9/26/05	18,000,000 common shares(1)		USD$1.69		USD$30,500,000
8/1/05 through 7/31/06	911,600 common shares(2)		USD$1.50		USD$1,367,400
8/1/05 through 7/31/06	975,000 common shares(3)		CAD$0.80		CAD$780,000
8/1/05 through 7/31/06	634,375 common shares(4)		CAD$0.80		CAD$507,500
8/1/05 through 7/31/06	396,667 common shares(5)		USD$0.97		USD$384,767


(1)		These common shares were issued by us in a private placement that closed on September 26, 2005. KeyBanc Capital Markets, a division of McDonald Investments, Inc., and Sanders Morris Harris, Inc. acted as placement agents. The placement agents received commissions totaling $2,538,784 in connection with this sale of securities.

(2)		These sales relate to the exercise of warrants issued in conjunction with a private placement of common shares during the period December 30, 2004 to January 13, 2005.

(3)		These sales relate to the exercise of warrants issued in conjunction with a private placement of common shares on December 10, 2003.

(4)		These sales relate to the exercise of warrants issued in conjunction with a private placement of common shares on September 18, 2003.

(5)		These shares were sold pursuant to the exercise of options issued to individuals eligible to participate in our Incentive Stock Option Plan, which has been superseded by our 2005 Omnibus Stock Plan. The offering price is a weighted average exercise price expressed in U.S. Dollars based on the applicable exchange rate at the time of exercise.

Dividend Policy

We have not paid any cash dividends to date, and currently have no intention of paying any cash dividends on our common shares in the foreseeable future. The declaration and payment of dividends is subject to the discretion of our Board of Directors. The timing, amount and form of dividends, if any, will depend on our results of operations, financial condition and cash requirements.

Equity Compensation Plan Information

The following reflects certain information about our common shares authorized for issuance under compensation plans at July 31, 2006.

Number of

Securities Remaining

Securities to be Issued

Weighted-Average

Available for Future

Upon Exercise of

Exercise Price of

Issuance Under

Outstanding Options,

Equity Compensation

Plan Category

Warrants and Rights

Plans

Equity compensation plans approved by shareholders

1,823,265

(1)

1.17

2,835,000

(2)

Equity compensation plans not approved by shareholders

1,037,200

(3)

1.25

N/A

Total

2,860,465

N/A

2,835,000


(1)		Represents the number of common shares underlying options that were issued under our Incentive Stock Option Plan, which has been superseded by our 2005 Omnibus Stock Plan.

(2)		Represents the number of common shares remaining available for issuance under our 2005 Omnibus Stock Plan, which was approved by our shareholders at our annual meeting held on December 13, 2005. As of July 31, 2006, we have issued 2,165,000 restricted common shares and no options under our 2005 Omnibus Stock Plan.

(3)		Represents the number of common shares underlying warrants granted to Sanders Morris Harris, Inc. as compensation for serving as placement agent for our December 2005/January 2006 private placement.


ITEM 6.	*Selected Financial Data.*

The following sets forth our selected historical financial data as of July 31, 2006, 2005, 2004, 2003 and 2002 and for our five fiscal years then ended, which has been derived from our financial statements for those years. Our financial statements as of July 31, 2006 and 2005 and for our fiscal years ended July 31, 2006 and 2005 and related notes thereto have been audited by Meaden & Moore, Ltd., an independent registered public accounting firm. Our financial statements as of July 31, 2004, 2003 and 2002 and for our fiscal years ended July 31, 2004, 2003 and 2002 and related notes thereto have been audited by De Visser Gray, an independent registered public accounting firm.

This information should be read together with the section of this report entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this report.


	For the Year Ended July 31,
	2006			2005			2004			2003			2002

Statement of Operations Data:
Gas sales(1)	$	1,126,477		$	117,835		$	—		$	—		$	—
Stock-based compensation expense		1,377,440			3,344,738			193,796			515,286			439,860
Loss before income taxes		(8,836,245	)		(6,120,821	)		(1,091,227	)		(1,109,218	)		(1,245,853	)
Net loss		(8,836,245	)		(5,396,351	)		(793,116	)		(934,305	)		(1,129,209	)
Net loss per common share		(0.14	)		(0.14	)		(0.03	)		(0.04	)		(0.06	)
Weighted average number of shares outstanding		62,789,319			37,665,019			25,007,237			21,485,381			18,300,433


	As of July 31,
	2006		2005		2004		2003		2002

Balance Sheet Data:
Total assets	$	49,051,980	$	23,527,712	$	9,382,977	$	6,328,178	$	5,418,158
Long-term notes payable (including current maturities)		216,015		549,822		462,177		378,174		—
Cash dividends per common share		—		—		—		—		—


(1)		Gas sales commenced in January 2005.


ITEM 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations.*

The following Management’s Discussion and Analysis (“MD&A”) is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this report and our consolidated financial statements and related notes. Our MD&A includes the following sections:


	•	Overview and Outlook — a general description of our business; drilling plans and capital expenditures; key areas of management focus; measurements; and opportunities, challenges and risks.

	•	Critical Accounting Policies — a discussion of accounting policies that require critical judgments and estimates.

	•	Results of Operations — an analysis of our consolidated results of operations for the three years presented in our financial statements.

	•	Liquidity and Capital Resources — an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments.

Overview and Outlook

We are an independent energy company incorporated under the laws of British Columbia, Canada and primarily engaged, through our wholly owned U.S. subsidiary, BPI Energy, Inc., in the exploration, production and commercial sale of coalbed methane (“CBM”). Our exploration and production efforts are concentrated in the Illinois Basin (the “Basin”). Our Canadian activities are limited to administrative reporting obligations to the province of British Columbia and regulatory reporting to the British Columbia Securities Commission.

As of July 31, 2006, we owned or controlled CBM rights, through mineral leases, options to acquire mineral leases, a farm-out agreement and ownership of a CBM estate, covering approximately 500,000 total acres in the Basin (a substantial majority of which was undeveloped as of July 31, 2006). We are focused on 12 Pennsylvanian coal seams that we regard as having commercial CBM potential. The seams in the acreage covered by our CBM rights have an aggregate thickness of 11-27 feet with a 19-foot median. We plan to complete several individual seams per well that range from two to nine feet thick each. Gas desorption tests of these coals have yielded 13-113 scf/ton with a 63 scf/ton median. Extensive permeability testing of individual seams (before stimulation) indicates a range of 0.2-75 millidarcies and median of 4 millidarcies.

The state of Illinois (which includes most of the Basin) is estimated to be the number two state in the U.S. in terms of coal reserves; however, coal in the Basin is high in sulfur, discouraging coal mining operations. Recent advances in technology that can reduce the sulfur content of the coal and higher coal prices are combining to make coals in the Basin potentially attractive to mining operations. Although coal mining activities take priority over CBM operations in most of our acreage, we attempt to coordinate and plan our drilling and production activities in conjunction with the owners of the coal in order to minimize any potential disruptions. In addition, because of the long lead times involved in coal mining projects, our substantial acreage position, and our ability to be flexible with the timing and siting of our wells, we believe we can plan our work around coal mining operations in the vicinity of our projects.

We have been involved in the first two projects in the Basin that have commercially produced and sold CBM. We are the only company currently commercially producing and selling CBM in the state of Illinois and one of only two companies currently commercially producing and selling CBM in the Illinois Basin. We believe our position as the first mover has enabled us to secure a substantial and favorable acreage position at costs that we believe compare very favorably to other CBM basins that are more mature in terms of production history.

We are an early stage CBM exploration and production company. We commenced CBM sales from our first producing wells in January 2005. Gas sales during the fiscal year ended July 31, 2005 were $117,835. Gas sales were $1,126,477 for the fiscal year ended July 31, 2006, an increase of 856%. From early 2002 until 2005, our strategic focus was on building our acreage footprint in the Basin. We were built around the primary strategic objective of acquiring CBM rights in the Basin. As we began accumulating CBM rights we began testing our acreage to determine its CBM potential. Having accumulated CBM rights to approximately 500,000 acres in the

Basin and conducting extensive testing at our Southern Illinois Basin Project, we embarked (in late 2004) on a pilot production program at our Southern Illinois Basin Project. Encouraged by the results, we expanded our drilling and production activities and began installing the infrastructure necessary to enable us to begin sales of CBM at our Southern Illinois Basin Project.

As our drilling and production operations have grown, we have not abandoned our goal of adding additional acreage and mineral rights. However, we have committed ourselves to transitioning BPI from a company focused primarily on the acquisition of mineral rights to a company focused on expanding our drilling and production operations and growing our reserves. To accomplish this transition, we recognized that we needed to obtain additional capital, resources and technical expertise. We believe that we have made substantial progress in achieving these goals. In September 2005, we sold 18,000,000 common shares and raised approximately $28,000,000. In April 2006, we hired Jim Craddock as our Senior Vice President of Operations. Jim was with Burlington Resources for over 20 years, last serving as Chief Engineer. Jim immediately began building an in-house technical team by bringing in a geologist and three engineers, all with extensive experience in successful CBM projects in basins located in the United States and Canada. Our new technical team has over 130 years of experience in CBM exploration and development that they bring to BPI.

In April 2006, we initiated our second development front when we began drilling 10 pilot development wells in Shelby County at our Northern Illinois Basin Project. Our CBM rights in the Northern Illinois Basin Project cover 351,487 acres in Montgomery, Shelby, Christian, Fayette and Macoupin counties in Illinois, which are located in the north central part of the Basin. We believe that there are 12 prospective coal seams thick enough for commercial production at this project. The thickest seam, the Herrin Coal seam, is up to nine feet thick and has been mined in shallow parts of the Basin. We believe that a single thick seam such as this may offer an attractive target for horizontal drilling.

We are not currently generating net income or positive cash flow from operations. Although we capitalize exploration and development costs, we have historically experienced significant losses. The primary costs that generated these losses were compensation-related expenses and general and administrative expenses. Even if we achieve increased revenues and positive cash flow from operations in the future, we anticipate increased exploration, development and other capital expenditures as we continue to explore and develop our mineral rights.

We anticipate that the number of wells we drill during the fiscal year ending July 31, 2007 will be dependent to a significant degree on the data we obtain from our recently completed 10-well pilot program at our Northern Illinois Basin Project (“Northern Project”) as well as data obtained from five test wells we have recently drilled on other leases in our Western Illinois Basin Project (“Western Project”) and Northern Project. Our capital expenditure budget for our 2007 fiscal year is a range that totals $12.0 million to $30.0 million. These amounts correspond to drilling 58 wells at the low end of the range and 123 wells at the upper end. These amounts include installing a gathering system and processing yard to handle the anticipated production from the 10-well pilot program at our Northern Project and additional pilot wells and/or production wells at our three current projects. Our cash balance at July 31, 2006 of $19,279,015 is insufficient to fully fund the high end of the range of forecasted capital expenditures and net cash used by operating activities during our 2007 fiscal year or our operations beyond that date. Therefore, we will likely need to raise additional financing in the near future. We currently do not have any specific plans to raise financing in support of our operations. Although management has no specific plans in place to raise the additional capital necessary to fund our plan of operations and forecasted capital expenditures, management anticipates raising the additional required capital through a combination of additional stock sales, the issuance of debt securities, borrowing and/or entering into joint ventures. Management’s focus for fiscal year 2007 will be to:


	•	obtain test data and initiate pilot projects that demonstrate the commercial potential of CBM at our various acreage blocks and projects in the Illinois Basin;

	•	reduce well drilling and completion costs;

	•	increase total company reserves; and

	•	grow total production.

Gathering test data and siting pilot projects based on this data should lead to proving project viability in multiple areas in the Illinois Basin. These pilot projects should have the potential to grow into development projects that will increase total company reserves and production. As we drill new wells, our production should continue to increase, as the new wells come online and our existing wells continue to dewater. As our production increases in the future, we should be positioned to generate positive cash flow from our operations.

A thorough evaluation of the geological assets that we control should lead to the evaluation and implementation of more cost effective drilling and completion techniques that can be implemented to reduce overall costs, increase resource recovery and total reserves and improve internal rates of return from development projects.

We currently control approximately 500,000 acres of CBM rights and, assuming 80-acre vertical well spacing and the development of all of our acreage, have the possibility of up to 6,000 drilling locations. With our potential for drilling locations, we expect that our drilling activities will be taking place over many years. The type of test data we are interested in developing across all of our projects includes measurements of permeability, gas content and net pay (i.e., thickness of coal seams from which we believe CBM can be commercially produced). Our focus is to increase our technical and operational knowledge of the Illinois Basin and our acreage rights to assist us in (i) establishing the value of our CBM assets and (ii) optimizing the production we can obtain from our wells after we bring them online. The technical team we have assembled has extensive experience and expertise in all of these areas as well as implementation of large scale development of CBM projects.

Several factors, over which we have little or no control, could impact our future economic success. These factors include natural gas prices, limitations imposed by the terms and conditions of our lease agreements, possible court rulings concerning our property interests in CBM, availability of drilling rigs, operating costs, and environmental and other regulatory matters. In our planning process, we have attempted to address these issues by:


	•	negotiating to obtain leases that grant us the broadest possible rights to CBM for any given tract of land;

	•	conducting ongoing title reviews of existing mineral interests;

	•	where possible, negotiating and utilizing multiple service companies in order to increase competition and minimize the risk of disruptions caused by the loss of any one service provider; and

	•	attempting to create a low cost structure in order to reduce our vulnerability to many of these factors.

Critical Accounting Policies

Critical Accounting Policies and Estimates

Our consolidated financial statements and accompanying notes have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires our management to make estimates, judgments and assumptions that affect reported amounts of assets, liabilities, revenues and expenses. On an ongoing basis, we evaluate the accounting policies and estimates that we use to prepare financial statements. We base our estimates on historical experience and assumptions believed to be reasonable under current facts and circumstances. Actual amounts and results could differ from these estimates used by management.

Certain accounting policies that require significant management estimates and are deemed a critical component of our results of operations or financial position are discussed below. Our management reviews our critical accounting policies with the Audit Committee of our Board of Directors.

Accounting for CBM Projects

We follow the full cost method of accounting for our CBM properties. Under this method, all costs associated with the acquisition of, exploration for and development of our CBM reserves are capitalized in cost centers on a country-by-country basis (currently we have one cost center, the United States). Such costs include lease acquisition costs, geological and geophysical studies, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, and overhead expenses directly related to these activities. Internal costs associated with our CBM activities that are not directly attributable to acquisition, exploration or development activities are expensed as incurred.

Unproved CBM properties and major development projects are excluded from amortization until a determination of whether proved reserves can be assigned to the properties or impairment occurs. Unproved properties are assessed at least annually to ascertain whether an impairment has occurred. Sales or dispositions of properties are credited to their respective cost centers and a gain or loss is recognized when all the properties in a cost center have been disposed of, unless such sale or disposition significantly alters the relationship between capitalized costs and proved reserves attributable to the cost center.

Capitalized costs of proved CBM properties, including estimated future costs to develop the reserves and estimated abandonment cost, net of salvage, are amortized on the units-of-production method using estimates of proved reserves.

A ceiling test is applied to each cost center by comparing the net capitalized costs, less related deferred income taxes, to the estimated future net revenues from production of proved reserves, discounted at 10%, plus the costs of unproved properties net of impairment. Any excess capitalized costs are written-off in the current year. The calculation of future net revenues is based upon prices, costs and regulations in effect at each year end.

In general, we determine if an unproved property is impaired if one or more of the following conditions exist:


	•	there are no firm plans for further drilling on the unproved property;

	•	negative results were obtained from studies of the unproved property;

	•	negative results were obtained from studies conducted in the vicinity of the unproved property; or

	•	the remaining term of the unproved property does not allow sufficient time for further studies or drilling.

Our estimate of proved reserves is based on the quantities of gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows are derived from a report prepared by an independent engineering firm, in accordance with SEC guidelines, based in part on data provided by us. The accuracy of our reserve estimates depends in part on the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Share-Based Payment

Prior to December 13, 2005, we had a stock-based compensation plan (the “Incentive Stock Option Plan”) under which stock options were issued to directors, officers, employees and consultants as determined by the Board of Directors and subject to the provisions of the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted options to be issued with exercise prices at a discount to the market price of our common shares on the day prior to the date of grant. However, the majority of all stock options issued under the Incentive Stock Option Plan were issued with exercise prices equal to the quoted market price of the stock on the date of grant. Options granted under the Incentive Stock Option Plan vested immediately and were exercisable over a period not exceeding five years

On December 13, 2005, our shareholders approved the 2005 Omnibus Stock Plan (the “Omnibus Stock Plan”) and it became effective on that date. The Omnibus Stock Plan replaces the Incentive Stock Option Plan under which stock options were previously granted. The Omnibus Stock Plan is administered by the Compensation Committee of the Board of Directors (the “Committee”) and will remain in effect for five years. All of our employees and directors, and any of our consultants or agents designated by the Committee, are eligible to participate in the Omnibus Stock Plan. The Committee has authority to: grant awards; select the participants who will receive awards; determine the terms, conditions, vesting periods and restrictions applicable to the awards; determine how the exercise price is to be paid; modify or replace outstanding awards within the limits of the Omnibus Stock Plan; accelerate the date on which awards become exercisable; waive the restrictions and conditions applicable to awards; and establish rules governing the Omnibus Stock Plan. No stock options have been issued under the Omnibus Stock

Plan. During the current fiscal year, the Committee granted stock awards under the Omnibus Stock Plan in the form of restricted and unrestricted stock to our employees and directors.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. The key provision of SFAS No. 123(R) requires companies to record share-based payment transactions as compensation expense at fair market value based on the grant-date fair value of those awards. Previously under SFAS 123, companies had the option of either recording expense based on the fair value of stock options granted or continuing to account for stock-based compensation using the intrinsic value method prescribed by APB No. 25.

We adopted SFAS No. 123(R), using the modified-prospective method, effective August 1, 2005. Since August 1, 2001, we have followed the fair value provisions of SFAS 123 and have recorded all share-based payment transactions as compensation expense at fair market value based on the grant-date fair value of those awards. In addition, all stock options granted prior to the adoption of SFAS No. 123(R) vested immediately on the date of grant and, thus, there was no unvested portion of previous stock option grants that vested during fiscal year 2006. Therefore, SFAS 123(R) had no impact on our consolidated financial position or results of operations for fiscal year 2006. We use the Black-Scholes formula to estimate the fair value of stock options granted.

Revenue Recognition

All revenue from gas sales is recognized after the gas is produced and delivery takes place. We currently sell all of our gas to one gas marketing company, Atmos Energy Marketing, LLC.

Asset Retirement Obligations

We follow Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which it is incurred, if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the associated long-lived asset. Amortization of the capitalized asset retirement cost is determined on a units-of-production method. Accretion of the asset retirement obligation is recognized over time until the obligation is settled. The future cash outflows associated with settling the asset retirement obligations accrued on the accompanying consolidated balance sheets are excluded from the ceiling test calculation. Our asset retirement obligations relate to the plugging of wells upon exhaustion of gas reserves.

The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging costs, annual inflation of these costs, the productive life of the wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion. Because of the subjectivity of assumptions and the relatively long life of our wells, the costs to ultimately retire these assets may vary significantly from previous estimates.

Deferred Income Taxes

We operate in two tax jurisdictions, the United States and Canada. Primarily as a result of the net losses that we have generated, we have generated deferred tax benefits available for tax purposes to offset net income in future periods. However, a full valuation allowance has been recorded against all deferred tax assets in Canada as we historically have had no income generating operations in Canada. We have recorded tax benefits in the United States for our fiscal years ending July 31, 2005 and 2004. These benefits partially offset a previously recorded deferred tax liability.

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 enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This Interpretation is effective for fiscal years beginning after December 15, 2006. We are currently assessing the effect of this Interpretation, if any, on our consolidated financial statements.

Results of Operations

Year Ended July 31, 2006 Compared to Year Ended July 31, 2005

The following table presents our unaudited financial data for fiscal year 2006 compared to fiscal year 2005:


	Fiscal Year Ended July 31,						Dollar			%
	2006			2005			Variance			Change

Revenues:
Gas sales	$	1,126,477		$	117,835		$	1,008,642			856	%
Expenses:
Lease operating expense		970,791			307,178			663,613			216	%
General and administrative expense		6,576,131			5,805,121			771,010			13	%
Depreciation, depletion and amortization		570,303			260,141			310,162			119	%

		8,117,225			6,372,440			1,744,785			27	%
Other income (expenses):
Interest income		941,351			123,219			818,132			664	%
Interest expense		(22,405	)		(24,820	)		2,415			10	%
Other income (expense)		(2,764,443	)		35,385			(2,799,828	)		(7,912	)%

		(1,845,497	)		133,784			(1,979,281	)		(1,479	)%
Loss before income taxes		(8,836,245	)		(6,120,821	)		(2,715,424	)		(44	)%
Deferred income tax benefit		—			724,470			(724,470	)		(100	)%

Net loss	$	(8,836,245	)	$	(5,396,351	)	$	(3,439,894	)		(64	)%

Revenue — Revenue from gas sales increased $1,008,642 in fiscal year 2006, an increase of 856% over fiscal year 2005. We realized our first revenues from the sale of CBM in January 2005. Net sales of gas (net of royalties) were 135,118 Mcf for fiscal year 2006 compared to 17,885 Mcf for fiscal year 2005. Our average realized selling price per Mcf increased to $8.34 in fiscal year 2006 compared to $6.59 in fiscal year 2005.

Lease operating expense — Lease operating expense increased $663,613 in fiscal year 2006, an increase of 216% over fiscal year 2005. Lease operating expenses represent production expenses, consisting primarily of repairs and maintenance, fuel and electricity, equipment rental and other overhead expenses related to producing wells. The increase is primarily due to the increase in producing wells and the related increase in gas production.

General and administrative expense — General and administrative expense consisted of the following for fiscal year 2006 and 2005:


	Fiscal Year Ended July 31,				Dollar			%
	2006		2005		Variance			Change

Salaries and benefits	$	2,027,707	$	894,141	$	1,133,566			127	%
Stock-based compensation		1,377,440		3,344,738		(1,967,298	)		(59	)%
Professional and regulatory		2,637,916		1,183,402		1,454,514			1,229	%
Other		533,068		382,840		150,228			39	%

Total general and administrative expense	$	6,576,131	$	5,805,121	$	771,010			13	%

Salaries and benefits increased $1,133,566 in fiscal year 2006, an increase of 127% over fiscal year 2005. The increase was primarily the result of (i) hiring additional personnel to support our growth throughout fiscal years 2005 and 2006, including a Senior Vice President of Operations (April 2006), a Chief Financial Officer (January 2005) and a Controller (February 2005); (ii) executive bonuses paid during fiscal year 2006; and (iii) general salary increases. We had 16 full-time employees at July 31, 2006 compared to 10 full-time employees at July 31, 2005. In addition, we expanded our technical team, adding three engineers and a geologist during the first quarter of fiscal year 2007, which will result in additional annualized salaries of $600,000 beginning in fiscal year 2007.

Stock-based compensation expense decreased $1,967,298 in fiscal year 2006, a decrease of 59% from fiscal year 2005. During fiscal year 2006, 495,000 stock options were granted, whereas 4,276,056 stock options were granted to various employees and directors in fiscal year 2005. During fiscal year 2006, we issued stock-based awards to employees and directors as follows: (i) 300,000 unrestricted common shares and 300,000 restricted common shares to our newly hired Senior Vice President of Operations; (ii) 140,000 unrestricted common shares to a newly appointed director; and (iii) 495,000 stock options to various employees and directors. We also replaced 2,025,000 stock options with 2,025,000 restricted common shares for key employees and directors during fiscal year 2006. The expense related to the issuance of unrestricted common shares and stock options was fully recognized in fiscal year 2006. A portion of the expense related to the issuance of restricted common shares, representing the vested portion of such shares, was also recognized in fiscal year 2006. We expect to continue our practice of granting share-based awards to employees in order to attract and retain qualified individuals. Such awards may be in the form of stock options, unrestricted common shares, restricted common shares or other share-based awards. However, we most likely will increase our use of restricted stock awards as the preferred method of share-based compensation in lieu of granting stock options, which was our predominant practice in prior years.

Professional and regulatory fees increased $1,454,514 in fiscal year 2006, an increase of 1,229% over fiscal year 2005. The increase was primarily the result of increased legal fees incurred in connection with our lawsuit against Colt LLC and higher costs associated with being a public company in the United States. Specifically, the increase resulted from the following:


• Additional legal fees incurred in connection with Colt LLC lawsuit	$	582,528
• Increase in executive placement fees		293,325
• Increase in printing costs of SEC filings		258,809
• Increase in insurance costs		220,936
• Increase in AMEX listing fees		115,000
• Increase in fees related to accounting, auditing and tax services		68,030
• Increase in legal fees incurred in connection with SEC filings		69,920
• Decrease in legal fees incurred in connection with surface disputes		(293,305	)
• Net increase in other professional and regulatory fees		139,271

• Total increase over corresponding period in the preceding year	$	1,454,514

Other general and administrative expenses increased $150,228, an increase of 39% over fiscal year 2005, primarily as a result of increased office and travel-related expenses.

Depreciation, depletion and amortization expense — Depreciation, depletion and amortization expense (“DD&A”) increased $310,162 in fiscal year 2006, an increase of 119% over fiscal year 2005. We compute DD&A on capitalized drilling costs and gas collection equipment using the units-of-production method based on estimates of proved reserves, and on all other property and equipment using the straight-line method based on estimated useful lives ranging from three to 10 years. The increase is primarily due to the increase in capitalized development costs and an increase in production over fiscal year 2005. Additionally, depreciation expense increased due to additions to other support equipment.

Interest income — Interest income increased $818,132, an increase of 664% over fiscal year 2005 due to significantly higher average cash balances during fiscal year 2006. The higher cash balances are the result of the net proceeds of $27,883,954 we received in September 2005 related to the private placement of our common shares. We

invest our excess cash in overnight sweep accounts and high-grade commercial paper with maturities of 30 days or less.

Other income (expense) — Other income (expense) decreased $2,799,828, or 7,912%, in fiscal year 2006, primarily due to recognizing $2,951,608 of other expense related to settling our dispute with Colt LLC, partially offset by other income of $127,416 related to the sale of our investment in HCM and an increase in distributions from HCM of $44,837 during fiscal year 2006. We believe that these settlement costs will be more than recouped through reduced royalty payments in future years.

Deferred income tax benefit — Deferred income tax benefit decreased $724,470 in fiscal year 2006, a decrease of 100% over fiscal year 2005. We recorded a tax benefit in the United States in fiscal year 2005 to partially offset a net recorded deferred tax liability at July 31, 2005. However, no tax benefit was recognized for fiscal year 2006, as we had no net deferred tax liability to offset.

Year Ended July 31, 2005 Compared to Year Ended July 31, 2004

The following table presents our unaudited financial data for fiscal year 2005 compared to fiscal year 2004:


	Fiscal Year Ended July 31,						Dollar			%
	2005			2004			Variance			Change

Revenues:
Gas sales	$	117,835		$	—		$	117,835			100	%
Expenses:
Lease operating expense		307,178			—			307,178			100	%
General and administrative expense		5,805,121			1,000,107			4,805,014			480	%
Depreciation, depletion and amortization		260,141			80,417			179,724			223	%

		6,372,440			1,080,524			5,291,916			490	%
Other income (expenses):
Interest income		123,219			2,008			121,211			6,036	%
Interest expense		(24,820	)		(15,165	)		(9,655	)		(64	)%
Other income		35,385			2,454			32,931			1,342	%

		133,784			(10,703	)		144,487			1,350	%
Loss before income taxes		(6,120,821	)		(1,091,227	)		(5,029,594	)		(461	)%
Deferred income tax benefit		724,470			298,111			426,359			143	%

Net loss	$	(5,396,351	)	$	(793,116	)	$	(4,603,235	)		(580	)%

Revenue — We realized our first revenues from the sale of CBM in January 2005. Sales of CBM generated revenues of $117,835 during fiscal year 2005 (all in the period of January through July 2005) compared to $0 sales during fiscal year 2004. All of our productive wells during fiscal year 2005 were located at our Southern Illinois Basin Project.

Lease operating expense — Lease operating expenses represent production expenses, consisting primarily of repairs and maintenance, fuel and electricity, equipment rental and other overhead expenses related to producing wells. We commenced production toward the end of January 2005 and, thus, incurred no lease operating expense during fiscal year 2004.

General and administrative expense — General and administrative expense consisted of the following for fiscal years 2005 and 2004:


	Fiscal Year Ended July 31,				Dollar		%
	2005		2004		Variance		Change

Salaries and benefits	$	894,141	$	418,701	$	475,440		114	%
Stock-based compensation		3,344,738		193,796		3,150,942		1,626	%
Professional and regulatory		1,183,402		98,458		1,084,944		1,102	%
Other		382,840		289,152		93,688		32	%

Total general and administrative expense	$	5,805,121	$	1,000,107	$	4,805,014		480	%

Salaries and benefits increased $475,440 in fiscal year 2005, an increase of 114% over fiscal year 2004. The increase was primarily the result of bonuses paid to various employees, hiring a Vice President of Field Operations, a Chief Financial Officer and a Controller, and general salary increases.

Stock-based compensation increased $3,150,942 in fiscal year 2005, an increase of 1,626% over fiscal year 2004. The increase resulted primarily from the granting of additional options to various key employees and directors of the company and the general increase in our stock price. During fiscal year 2005, we granted options to purchase 4,276,056 common shares that were valued at $3,344,738. This compares with the options to purchase 475,000 common shares that were granted during fiscal year 2004 and were valued at $193,796. The award of these options was consistent with our belief that it is necessary to provide this form of compensation for us to attract and retain qualified individuals.

Professional and regulatory fees increased $1,084,944 in fiscal year 2005, an increase of 1,102% over fiscal year 2004. The increase resulted from the following:


• Additional legal fees incurred in connection with surface disputes	$	303,305
• Increase in fees related to accounting, auditing and tax services		193,046
• Increase in legal fees incurred in connection with SEC filings		175,567
• Increase in fees related to general corporate legal and professional advice		150,522
• Increase in fees related to outside investor relations services		141,757
• Net increase in other professional fees		120,747

• Total increase over corresponding period in the preceding year	$	1,084,944

Other general and administrative expenses increased $93,688 in fiscal year 2005, an increase of 32% over fiscal year 2004. The increase resulted primarily from additional costs incurred in opening our headquarters office in Solon, Ohio during fiscal year 2005.

Depreciation, depletion and amortization expense — Depreciation, depletion and amortization expense (“DD&A”) increased $179,724 in fiscal year 2005, an increase of 223% over fiscal year 2004. We compute DD&A on capitalized drilling costs and gas collection equipment using the units-of-production method based on estimates of proved reserves, and on all other property and equipment using the straight-line method based on estimated useful lives ranging from three to 10 years. The increase is primarily due to the fact that we had no production in fiscal year 2004. Additionally, depreciation expense increased due to additions to other support equipment.

Interest income — Interest income increased $121,211 in fiscal year 2005, an increase of 6,036% over fiscal year 2004 due to significantly higher average cash balances during fiscal year 2005.

Other income — Other income increased $32,931 in fiscal year 2005, an increase of 1,342% over fiscal year 2004. The increase is primarily due to us recognizing a gain of $42,276 on the sale of our remaining 432,000 shares of Pyng Technologies Corp., a TSX Venture listed public company, during fiscal year 2005.

Deferred income tax benefit — The deferred income tax benefit increased $426,359 in fiscal year 2005, an increase of 143% over fiscal year 2004. The increase resulted primarily from the increase in our loss before income

taxes. The effect of the increase in our loss before income taxes was partially offset by a decrease in the effective tax rate to 11.8% during fiscal year 2005, as compared to 27.3% in fiscal year 2004. The decrease in rate was primarily the result of an increase in stock-based compensation expense, which is non-deductible for U.S. tax purposes.

Liquidity and Capital Resources

Our primary source of liquidity historically has come from the sale of our common shares in private placements and the proceeds from the exercise of warrants and options to acquire our common shares. To date, we have not relied significantly on borrowing to finance our operations or provide cash. As of July 31, 2006, we had only $216,015 in long-term notes payable. From July 31, 2003 until July 31, 2006, we raised $43,198,616 from the sale of our common shares. Additionally, during that same period, we collected $6,728,810 as a result of the exercise of warrants and $2,042,280 as a result of the exercise of stock options. Our primary use of these funds has been the acquisition, exploration, testing and development of our CBM properties and rights.

We did not begin to generate revenues from CBM sales until January 2005. Revenues from CBM sales were $1,126,477 for fiscal year 2006 and $117,835 for fiscal year 2005. We expect revenue from the sale of our CBM to increase due to (i) increased production from existing wells as they proceed through the initial dewatering phase and (ii) additional production generated as a result of drilling additional wells. However, in view of our limited production history, we can provide no assurance that we will achieve a trend of increased production and CBM revenue in the future.

CBM wells typically must go through a lengthy dewatering phase before making any meaningful contribution to gas production. We estimate that a typical vertical well will require about 24 months to reach peak production. The impact on our cash position is that there will be a delay of up to 24 months between the time we initially invest in drilling and completing a well and the time when a typical well will begin to make a meaningful contribution to our cash from operations.

We had a cash balance of $19,279,015 at July 31, 2006, compared to $7,251,503 at July 31, 2005. The net increase in our cash balance is primarily due to the $27,883,954 of net proceeds we received from the sale of our common shares in a private placement that closed on September 26, 2005, $5,013,928 received as a result of the exercise of warrants during fiscal year 2006, and $382,239 received as a result of the exercise of stock options during fiscal year 2006. We raised an amount in the private placement we felt was required to fund our development plans through April 2006. However, because our drilling progress at our Southern Illinois Basin Project was slowed due to the dispute with one of the coal owners, we now believe our cash balance will be sufficient to fund the low end of our forecasted capital program through July 31, 2007. Our revenues and cash balances, however, will not likely be sufficient to fund the high end of our capital program for fiscal 2007 or our operations beyond that date. Therefore, we will likely need to raise additional financing in the near future. We currently do not have any specific plans to raise financing in support of our future operations. Although management has no specific plans in place to raise the additional capital necessary to fund our plan of operations and forecasted capital expenditures, management anticipates raising the additional required capital through a combination of additional stock sales, the issuance of debt securities, borrowing and/or entering into joint ventures.

Cash Used in Operating Activities

Net cash used in operating activities for fiscal year 2006 was $6,560,034. This compares with $2,474,443 net cash used in operating activities in the prior year. The increase in net cash used in operating activities resulted from the $3,000,000 paid to Colt LLC to settle a lawsuit and increased general and administrative expenses required to support the growth in the size of our projects in the Illinois Basin. Net cash used in operating activities for fiscal year 2004 was $906,849. Since July 31, 2003, we have substantially increased our exploration and operating activities, and therefore our personnel, in the Illinois Basin. Since we did not generate any CBM revenues until January 2005, the costs associated with the additional activities and personnel resulted in year-to-year increases in net cash used in operations.

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 2006 was $14,517,293. This compares with $6,338,082 net cash used in investing activities in fiscal year 2005 and $1,787,382 net cash used in investing activities in fiscal year 2004. The increases in net cash used in investing activities during fiscal years 2005 and 2006 are primarily the result of increased exploration and development costs at our projects, the installation of a gas gathering system at our Southern Illinois Basin Project, and additions to vehicles and other equipment to support our growth in operations.

Cash Provided by Financing Activities

Net cash provided by financing activities for fiscal year 2006 was $33,104,839. This compares with $15,093,233 net cash provided by financing activities in fiscal year 2005 and $3,498,439 net cash provided by financing activities in fiscal year 2004. The increases in net cash provided by financing activities during fiscal years 2005 and 2006 are primarily the result of increased proceeds from common shares issued in private placements and from the exercise of stock options and warrants. We received net proceeds from common shares issued in private placements in the amount of $27,883,954 during fiscal year 2006, $12,074,106 during fiscal year 2005 and $3,240,556 during fiscal year 2004. In addition, we received aggregate proceeds from the exercise of stock options and warrants in the amounts of $5,396,167 during fiscal year 2006, $3,331,887 during fiscal year 2005 and $43,036 during fiscal year 2004. We continue to pay down our long-term notes, making payments of $175,282 in fiscal year 2006, $42,320 in fiscal year 2005 and $26,014 in fiscal year 2004. Our long-term notes payable (including current maturities) decreased from $549,822 at July 31, 2005 to $216,015 at July 31, 2006. We expect to continue to reduce our long-term notes payable by making scheduled principal payments of $140,866 in fiscal year 2007.

Capital Expenditure Plan

We have no contractual commitments for capital expenditures. However, our plan anticipates that over the year ending July 31, 2007, we will spend approximately $12.0 million to $30.0 million on capital expenditures. These amounts correspond to drilling 58 wells at the low end of the range and 123 wells at the upper end. These amounts include installing a gathering system and processing yard to handle the anticipated production from our 10-well pilot program and additional pilot wells and/or production wells at our three current projects. In addition to our drilling program, we expect to pursue the acquisition of additional CBM rights during the fiscal year. We expect that this capital expenditure program and our other cash requirements will be funded by our cash balance, which as of October 25, 2006 is approximately $15.1 million, and cash raised through the sale of debt securities, equity securities, borrowings and/or joint ventures. Although we are currently evaluating the best methods of raising these funds, we can provide no assurance that we will be able to raise the necessary funds.

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, 2006:
Long-term debt	$	148,601	$	63,674	$	17,840	$	—	$	230,115
Equipment leases		82,875		13,813		—		—		96,688
Asset retirement obligations		9,600		—		—		70,754		80,354
Other leases(1)		136,266		197,272		29,784		262,557		625,879

Total	$	377,342	$	274,759	$	47,624	$	333,311	$	1,033,036


(1)		These amounts do not include annual minimum royalty payments required to hold mineral lease and farm-out agreements. Although we are not obligated to make these payments under existing mineral leases and farm-out agreements, these payments are required to maintain individual lease/farm-out agreements after the expiration of the initial terms of the lease/farm-out agreements. The lease/farm-out agreements in existence as of October 25, 2006 expire at various times beginning in November 2007. If we were to pay the total minimum royalty payments due under all lease/farm-out agreements in existence as of October 25, 2006, the amount would initially total approximately $100,000 annually and could increase to as much as $220,000 annually.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of July 31, 2006.


ITEM 7A.	*Qualitative and Quantitative Exposure to Market Risk.*

Commodity Risk

Our major risk exposure is the commodity pricing applicable to our CBM production. Realized commodity prices received for our production are primarily driven by the spot prices attributable to natural gas. The effects of price volatility are expected to continue.

Interest Rate Risk

All of our debt has fixed interest rates, so consequently we are not exposed to cash flow or fair value risk from market interest rate changes on this debt.

Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable and long-term notes payable. The carrying amount of cash equivalents, accounts receivable and accounts payable approximate fair market value due to the highly liquid nature of these short-term instruments.

Inflation and Changes in Prices

The general level of inflation affects our costs. Salaries and other general and administrative expenses are impacted by inflationary trends and the supply and demand of qualified professionals and professional services. Inflation and price fluctuations affect the costs associated with exploring for and producing CBM, which has a material impact on our financial performance.


ITEM 8.	*Financial Statements and Supplementary Data.*

Our consolidated financial statements are included in this report beginning on page F-1.


ITEM 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.*

None.


ITEM 9A.	*Controls and Procedures.*

Our management is responsible for establishing and maintaining effective disclosure controls and procedures, as defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. Our management, with participation of our Chief Executive Officer and Controller (who is currently responsible for performing certain functions of our principal financial officer), has evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15) as of July 31, 2006. Based on that evaluation, our CEO and Controller concluded that our disclosure controls and procedures were effective as of July 31, 2006 in alerting them on a timely basis to material information relating to BPI (including our consolidated subsidiaries) required to be included in our periodic filings under the Exchange Act.

On October 12, 2006, our Chief Financial Officer resigned. We have appointed our Controller to perform certain of the functions of the principal financial officer. Our Controller performed the evaluation of disclosure controls and procedures required to be conducted and performed the analysis necessary to provide the certifications to this report normally required of the principal financial officer who recently departed.

There were no significant changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended July 31, 2006 that materially affected, or are reasonably likely to affect, our internal control over financial reporting.

ITEM 9B. Other Information.

None.

PART III


ITEM 10.	*Directors and Executive Officers of the Registrant.*

We incorporate herein by reference the information appearing under the caption “Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance” and “Committees of the Board of Directors; Attendance” in our definitive proxy statement for our Annual General Meeting of Shareholders, which we will file with the Securities and Exchange Commission not later than November 28, 2006.

Information concerning our executive officers is contained in Item 1 of Part I of this annual report. We have adopted a Code of Business Conduct and Ethics for employees that applies to our principal executive officer, principal financial officer and controller, as well as all other employees. Our Code of Business Conduct and Ethics can be found on the our website at www.bpi-energy.com.


ITEM 11.	*Executive Compensation.*

We incorporate herein by reference the information appearing under the captions “Director Compensation” and “Executive Compensation” in our definitive proxy statement.


ITEM 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.*

We incorporate herein by reference the information appearing under the caption “Beneficial Ownership” in our definitive proxy statement.


ITEM 13.	*Certain Relationships and Related Transactions.*

We incorporate herein by reference the information appearing under the caption “Certain Relationships and Related Transactions” in our definitive proxy statement.

Appendix A

Glossary of Natural Gas Terms

The following are definitions of selected terms relating to the natural gas industry that are used in this prospectus:

Adsorption. The attachment, through physical or chemical bonding, of gas molecules to the coal surface. The adsorbed gas molecules are trapped within the coal, the stability of which is strongly affected by changes in temperature and pressure.

Casing. Steel pipe set in a well to prevent the hole from sloughing or caving and to enable formations to be isolated. There may be several strings of casing in a well, one inside the other.

Completion. The activities necessary to prepare a well for the production of gas.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Dewatering. A CBM well typically begins dewatering with almost all water production and little or no natural gas production. The continuous production of water from a well that is dewatering reduces the water reservoir pressure on the coals. The reduced reservoir pressure enables the release of the gas within the coal to the wellbore. This results in an increase in the amount of gas production relative to the amount of water production. Dewatering ceases when peak gas production is reached.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production will exceed production expenses and taxes.

Farm-out agreement. An agreement where the owner of a working interest in a gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease.

Fracture. A man-made or hydraulic fracture is formed when a fluid is pumped down a well at high pressures for short periods of time causing a split in the rock formation. As part of this technique, sand or other material may also be injected into the formation to keep the channel open. This technique allows gas to move more freely from the rock pores where they are trapped to a producing well that can bring the gas to the surface.

Horizontal drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.

Isotherm test. An adsorption isotherm test measures the storage capacity of coal in terms of gas content.

Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.

Mcfe. One thousand cubic feet of natural gas equivalent at standard atmospheric conditions, determined using the ratio of one barrel of oil to six Mcf of natural gas.

MMBtus. One million British thermal units. One British thermal unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

MMcf. One million cubic feet of natural gas at standard atmospheric conditions.

Permeability. The capacity of a geologic formation to allow water or natural gas to pass through it.

Productive well. A well that has been completed and is tied into our gas and/or dewatering system. A productive well may produce only water for a period of time before gas begins to flow through the gas gathering system.

A-1

Proved reserves. The estimated quantities of natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. This definition is consistent with Rule 4-10(a)(2) of Regulation S-X of the rules and regulations of the SEC. In reporting proved reserves, we are required to comply with Rule 4-10(a)(2).

Reserves. The quantity of natural gas that is estimated to be commercially recoverable from specific acreage.

Reservoir. A porous and permeable underground formation, including a coal seam, containing a natural accumulation of producible natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty interest. An interest in a natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Scf. Standard cubic feet.

Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, regardless of whether or not such acreage contains proved reserves.

Vertical drilling. A hole drilled vertically into the earth from which gas or water flows or is pumped.

Working interest. An interest in a natural gas lease that gives the owner of the interest the right to drill and produce natural gas on the leased acreage and requires the owner to pay its proportionate share of the costs of drilling and production operations.

A-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders of

BPI Energy Holdings, Inc.

Solon, Ohio

We have audited the accompanying consolidated balance sheets of BPI Energy Holdings, Inc. and its subsidiary as of July 31, 2006 and 2005, and the related statements of operations, shareholders’ equity, and cash flows for the fiscal years then ended. These financial statements are the responsibility of the Company’s 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 Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPI Energy Holdings, Inc. and its subsidiary as of July 31, 2006 and 2005, and the results of its operations and its cash flows for the fiscal years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ MEADEN & MOORE, LTD.

Certified Public Accountants

October 13, 2006

Cleveland, Ohio

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

DEVISSER GRAY
CHARTERED ACCOUNTANTS

401-905 West Pender Street
Vancouver, BC Canada
V6C 1L6

Tel: (604) 687-5447
Fax: (604) 687-6737

The Board of Directors and Shareholders of BPI Energy Holdings, Inc.,

We have audited the accompanying consolidated statement of operations, shareholders’ equity and cash flows of BPI Energy Holdings, Inc. and its subsidiary for the fiscal year ended July 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of BPI Energy Holdings, Inc. and its subsidiary for the fiscal year ended July 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

/s/ De Visser Gray

CHARTERED ACCOUNTANTS

Vancouver, British Columbia

October 12, 2004

F-3

BPI ENERGY HOLDINGS, INC.

Consolidated Balance Sheets


	July 31
	2006			2005

ASSETS
Current Assets
Cash and cash equivalents	$	19,279,015		$	7,251,503
Accounts receivable		105,711			34,671
Other current assets		164,764			23,534

Total current assets		19,549,490			7,309,708
Property and equipment, at cost:
Oil and gas properties, full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $331,150 and $58,523		20,766,898			10,190,929
Unproved, excluded from amortization		3,368,231			3,149,372

Net oil and gas properties		24,135,129			13,340,301
Other property and equipment, net of accumulated depreciation and amortization of $631,015 and $398,988		5,106,236			1,769,812

Net property and equipment		29,241,365			15,110,113
Investment in Hite Coalbed Methane, L.L.C.		—			846,766
Restricted cash		100,000			100,000
Other non-current assets		161,125			161,125

Total assets	$	49,051,980		$	23,527,712


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,492,239		$	2,144,066
Current maturities of long-term notes payable		140,866			42,227
Accrued liabilities and other		649,237			31,405

Total current liabilities		2,282,342			2,217,698
Long-term notes payable, less current maturities		75,149			507,595
Asset retirement obligation		70,754			—

Total liabilities		2,428,245			2,725,293
Shareholders’ Equity
Common shares, no par value, authorized 200,000,000 shares, 70,812,540 and 43,912,961 issued and outstanding		67,946,143			34,666,022
Additional paid-in capital		5,871,120			4,493,680
Accumulated deficit		(27,193,528	)		(18,357,283	)

Total shareholders’ equity		46,623,735			20,802,419

Total liabilities and shareholders’ equity	$	49,051,980		$	23,527,712

See notes to consolidated financial statements

F-4

BPI ENERGY HOLDINGS, INC.

Consolidated Statements of Operations


	Years Ended July 31
	2006			2005			2004

Revenue
Gas sales	$	1,126,477		$	117,835		$	—
Operating expenses
Lease operating expense		970,791			307,178			—
General and administrative expenses		6,576,131			5,805,121			1,000,107
Depreciation, depletion and amortization		570,303			260,141			80,417

Total operating expenses		8,117,225			6,372,440			1,080,524

Operating loss		(6,990,748	)		(6,254,605	)		(1,080,524	)
Other income (expense):
Interest income		941,351			123,219			2,008
Interest expense		(22,405	)		(24,820	)		(15,165	)
Other income (expense)		(2,764,443	)		35,385			2,454

		(1,845,497	)		133,784			(10,703	)

Loss before income taxes		(8,836,245	)		(6,120,821	)		(1,091,227	)
Deferred income tax benefit		—			724,470			298,111

Net loss	$	(8,836,245	)	$	(5,396,351	)	$	(793,116	)

Basic and diluted net loss per share	$	(0.14	)	$	(0.14	)	$	(0.03	)

Weighted average common shares outstanding		62,789,319			37,665,019			25,007,327

See notes to consolidated financial statements

F-5

BPI ENERGY HOLDINGS, INC.

Consolidated Statements of Shareholders’ Equity


					Additional						Common			Total
	Common Shares				Paid-in			Accumulated			Shares			Shareholders’
	Shares		Amount		Capital			Deficit			Issuable			Equity

Balance, July 31, 2003		22,278,752	$	15,953,188	$	968,972		$	(12,167,816	)	$	30,579		$	4,784,923
Proceeds from stock options exercised		69,444		43,036		—			—			—			43,036
Net proceeds from shares issued in Private placement — September 18, 2003		725,000		339,787		—			—			(30,579	)		309,208
Net proceeds from shares issued in Private placement — December 22, 2003(1)		1,975,000		928,259		—			—			—			928,259
Net proceeds from shares issued in Private placement — April 27, 2004		3,326,100		1,972,510		—			—			—			1,972,510
Proceeds from shares issuable for warrants exercised		—		—		—			—			271,440			271,440
Stock-based compensation		—		—		193,796			—			—			193,796
Net loss		—		—		—			(793,116	)		—			(793,116	)

Balance, July 31, 2004		28,374,296		19,236,780		1,162,768			(12,960,932	)		271,440			7,710,056
Proceeds from stock options exercised		2,254,333		1,617,005		—			—			—			1,617,005
Proceeds from warrants exercised		2,861,342		1,714,882		—			—			(271,440	)		1,443,442
Net proceeds from shares issued in Private placement — December 29, 2004(2)		2,400,000		2,793,854		—			—			—			2,793,854
Net proceeds from shares issued in Private placement — December 30, 2004(3)		4,032,000		4,693,675		—			—			—			4,693,675
Net proceeds from shares issued in Private placement — January 6, 2005(4)		3,723,200		4,334,199		—			—			—			4,334,199
Net proceeds from shares issued in Private placement — January 12, 2005(5)		216,800		252,378		—			—			—			252,378
Bonus shares		50,990		23,249		—			—			—			23,249
Stock-based compensation		—		—		3,344,738			—			—			3,344,738
Other		—		—		(13,826	)		—			—			(13,826	)
Net loss		—		—		—			(5,396,351	)		—			(5,396,351	)

Balance, July 31, 2005		43,912,961		34,666,022		4,493,680			(18,357,283	)		—			20,802,419

Proceeds from stock options exercised		396,667		382,239		—			—			—			382,239
Proceeds from warrants exercised		5,822,075		5,013,928		—			—			—			5,013,928
Net proceeds from shares issued in Private placement — September 23, 2005(6)		18,000,000		27,883,954		—			—			—			27,883,954
Stock-based compensation — stock options		—		—		527,327			—			—			527,327
Stock-based compensation — common shares, including vested portion of restricted stock		758,514		—		850,113			—			—			850,113
Restricted stock, less vested portion		1,922,323		—		—			—			—			—
Net loss		—		—		—			(8,836,245	)		—			(8,836,245	)

Balance, July 31, 2006		70,812,540	$	67,946,143	$	5,871,120		$	(27,193,528	)	$	—		$	46,623,735


(1)		net of share issuance costs of $18,730

(2)		net of share issuance costs of $206,146

(3)		net of share issuance costs of $346,325

(4)		net of share issuance costs of $319,801

(5)		net of share issuance costs of $18,622

(6)		net of share issuance costs of $2,619,953

See notes to consolidated financial statements

F-6

BPI ENERGY HOLDINGS, INC.

Consolidated Statements of Cash Flows


	Years Ended July 31
	2006			2005			2004

Cash Provided by (Used in):
Operating Activities
Net loss	$	(8,836,245	)	$	(5,396,351	)	$	(793,116	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		570,303			260,141			80,417
Stock-based compensation expense		1,377,440			3,344,738			193,796
Gain on sale of investments and marketable securities		(127,416	)		(42,276	)		(2,454	)
Loss on disposal of property and equipment		—			16,415			—
Deferred income tax benefit		—			(724,470	)		(298,111	)
Other		11,024			20,339			(564	)
Changes in assets and liabilities:
Accounts receivable		(71,040	)		(34,671	)		—
Other current assets		(141,230	)		21,392			(26,909	)
Accounts payable		8,116			80,913			7,699
Accrued liabilities and other		649,014			11,012			20,393
Other non-current assets		—			(31,625	)		(88,000	)

Net cash used in operating activities		(6,560,034	)		(2,474,443	)		(906,849	)
Investing Activities
Proceeds from sale of marketable securities and investments		551,000			113,557			5,407
Business acquisition, net of cash acquired		—			(857,638	)		—
Additions to oil and gas properties		(11,784,236	)		(4,032,681	)		(1,413,729	)
Additions to other property and equipment		(3,284,057	)		(1,383,208	)		(191,794	)
Acquisition of equity interest in joint venture		—			(78,112	)		(100,500	)
Investment in Hite Coalbed Methane, L.L.C.		—			—			(86,766	)
Increase in restricted cash		—			(100,000	)		—

Net cash used in investing activities		(14,517,293	)		(6,338,082	)		(1,787,382	)
Financing Activities:
Payments on long-term notes payable		(175,282	)		(41,320	)		(26,014	)
Net proceeds from issuance of common shares		33,280,121			15,134,553			3,524,453

Net cash provided by financing activities		33,104,839			15,093,233			3,498,439

Net increase in cash and cash equivalents		12,027,512			6,280,708			804,208
Cash and cash equivalents at the beginning of the year		7,251,503			970,795			166,587

Cash and cash equivalents at the end of the year	$	19,279,015		$	7,251,503		$	970,795

*Supplementary cash flow information:*
Cash payments
Interest paid	$	18,483		$	11,540		$	2,425
Non-cash investing and financing activities:
Acquisition of equipment by issuance of notes payable		233,475			118,049			105,847
Cancellation of convertible note payable		392,000			—			—
Cashless exercise of warrants		283,557			—			—

See notes to consolidated financial statements

F-7

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements

July 31, 2006, 2005 and 2004


1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Going Concern

These consolidated financial statements include the accounts of BPI Energy Holdings, Inc. and its wholly owned U.S. subsidiary, BPI Energy, Inc. (collectively, the “Company”). The Company has presented these financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.

BPI Energy Holdings, Inc. is incorporated in British Columbia, Canada and, through its wholly owned U.S. subsidiary, BPI Energy, Inc., is involved in the exploration, production and commercial sale of coalbed methane (“CBM”) located in the Illinois Basin. The Company conducts its operations in one reportable segment, which is oil and gas exploration and production. On December 13, 2005, the Company’s common shares began trading on the American Stock Exchange (“AMEX”) under the symbol BPG. As a result of the shares being listed on the AMEX, the Company voluntarily de-listed from trading its shares on the TSX Venture Exchange. Amounts shown are in U.S. Dollars unless otherwise indicated.

These consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplates the Company’s ability to realize its assets and discharge its liabilities in the normal course of business; however, the occurrence of significant losses to date raises doubt upon the validity of this assumption. The ability of the Company to realize the costs it has incurred to date on these properties is dependent upon the Company being able to sell the properties or to develop profitable operations, to finance their exploration and development costs and to resolve any environmental, regulatory or other constraints, which may hinder the successful development of the properties.

The Company has experienced significant losses over the past five years, including $8,836,245 in the current year, and has an accumulated deficit of $27,193,528 at July 31, 2006. The Company’s continued existence as a going concern is dependent upon its ability to continue to obtain adequate financing arrangements and to achieve and maintain profitable operations.

The Company has financed its activities primarily from the proceeds of various share issuances. As a result of the Company being in the early stages of operations, the recoverability of assets on the balance sheet will be dependent on the Company’s ability to obtain additional financing and to attain a level of profitable operations.

Use of Estimates

The preparation of these consolidated financial statements requires the use of certain estimates by management in determining the Company’s assets, liabilities, revenues and expenses. Actual results could differ from such estimates. Depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including the timing and costs associated with the Company’s asset retirement obligations. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. Proved reserves of oil and natural gas are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions.

Revenue Recognition and Customer Concentration

All revenue from gas sales is recognized after the gas is produced and delivery takes place. The Company currently sells all of its gas to one gas marketing company, Atmos Energy Marketing, LLC. Although the Company sells all of its production to a single purchaser, there are numerous other purchasers in the Illinois Basin to whom the

F-8

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Company believes it could sell its production; therefore, the loss of its single purchaser would not adversely affect the Company’s operations.

Investments in Unconsolidated Entities

The equity method of accounting is used to account for investments in and earnings or losses of affiliates that the Company does not control, but over which it does exert significant influence. The cost method of accounting is used for all other non-controlled investments. The Company used the cost method to account for its indirect interest in the Jericho Project through its 49% interest in Hite Coalbed Methane, L.L.C. (“HCM”), as the Company did not exert significant influence over HCM. As described in note 4 below, the Company sold its investment in HCM during the fiscal year ended July 31, 2006 and recognized a gain on the sale in the amount of $127,416. The Company considers whether the fair values of any of its investments have declined below their carrying value whenever adverse events or changes in circumstances indicate that recorded values may not be recoverable. If the Company considered any such decline to be other than temporary, a write-down would be recorded to estimated fair value.

Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with a maturity date of three months or less when purchased and are carried at cost, which approximates fair value.

Accounts Receivable

Accounts receivable represents amounts due from Atmos Energy Marketing, LLC for gas sales. Management regularly reviews accounts receivable to determine whether amounts are collectible and records a valuation allowance to reflect management’s best estimate of any amount that may not be collectible. At July 31, 2006 and 2005, the Company has determined that no allowance for uncollectible receivables was necessary.

Fair Value of Financial Instruments

The carrying amount reported in the balance sheet for cash, accounts receivable, accounts payable and accrued liabilities approximates fair value because of the immediate or short-term maturity of these financial instruments.

The carrying amount of long-term notes payable approximates fair value based on current rates available to the Company for instruments of the same remaining terms and maturities.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Under this method, all costs associated with the acquisition of, exploration for and development of oil and gas reserves are capitalized in cost centers on a country-by-country basis (currently the Company has one cost center, the United States). Such costs include lease acquisition costs, geological and geophysical studies, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, and overhead expenses directly related to these activities. Internal costs associated with oil and gas activities that are not directly attributable to acquisition, exploration or development activities are expensed as incurred.

Unproved oil and gas properties and major development projects are excluded from amortization until a determination of whether proved reserves can be assigned to the properties or impairment occurs. Unproved properties are assessed at least annually to ascertain whether an impairment has occurred. Sales or dispositions of properties are credited to their respective cost centers and a gain or loss is recognized when all the properties in a cost center have been disposed of, unless such sale or disposition significantly alters the relationship between capitalized costs and proved reserves attributable to the cost center.

F-9

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Capitalized costs of proved oil and gas properties, including estimated future costs to develop the reserves and estimated abandonment cost, net of salvage, are amortized on the units-of-production method using estimates of proved reserves.

In general, the Company determines if an unproved property is impaired if one or more of the following conditions exist:

i) there are no firm plans for further drilling on the unproved property;

ii) negative results were obtained from studies of the unproved property;

iii) negative results were obtained from studies conducted in the vicinity of the unproved property;

iv) the remaining term of the unproved property does not allow sufficient time for further studies or drilling.

No impairment existed as of July 31, 2006 and 2005.

Other Property and Equipment

Other property and equipment are stated at cost. Gas collection equipment primarily represents flowlines purchased and installed to transport the CBM from the wells to the compressor station. Support equipment includes vehicles, machinery and other equipment used in oil and gas activities. Other equipment primarily includes office furniture and fixtures and computer equipment. Gas collection equipment is depreciated on the units-of-production method using estimates of proved reserves. Support equipment and other property and equipment are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three to ten years. Major classes of other property and equipment consisted of the following:


	July 31
	2006			2005

Other Property and Equipment:
Gas collection equipment	$	4,342,400		$	1,332,012
Support equipment		1,046,989			760,467
Other		347,862			76,321
Less: Accumulated depreciation and amortization		(631,015	)		(398,988	)

	$	5,106,236		$	1,769,812

F-10

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Accrued Liabilities

Accrued liabilities consist of the following:


	At July 31
	2006		2005

Employee compensation	$	467,869	$	—
Professional fees		111,805		—
Directors’ fees		31,000		—
Other		34,428		31,405

	$	645,102	$	31,405

Asset Retirement Obligations

The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it is incurred, if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the associated long-lived asset. Amortization of the capitalized asset retirement cost is computed on a units-of-production method. Accretion of the asset retirement obligation is recognized over time until the obligation is settled. The future cash outflows associated with settling the asset retirement obligations accrued on the accompanying consolidated balance sheets are excluded from the ceiling test calculation. The Company’s asset retirement obligations relate to the plugging of wells upon exhaustion of gas reserves. The Company assessed its asset retirement obligation in prior periods and deemed it to be immaterial. The initial liability for our asset retirement obligations was recorded as of August 1, 2005 in the amount of $34,708.

The following table summarizes the activity for the Company’s asset retirement obligations for the fiscal year ended July 31, 2006:


Asset retirement obligation at beginning of period	$	34,708
Accretion expense		3,072
Change in estimates		7,952
Liabilities incurred		25,022

Asset retirement obligation at end of period	$	70,754

Accounting for Long-Lived Assets

The Company follows Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”). Under SFAS No. 144, all long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. An impairment loss is recognized when the carrying value of a long-lived asset is not recoverable and exceeds its fair value.

Income Taxes

Income taxes are accounted for under the asset and liability method that requires deferred income taxes to reflect the future tax consequences attributable to differences between the tax and financial reporting bases of assets and liabilities. Deferred tax assets and liabilities recognized are based on the tax rates in effect in the year in which differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance when, in the opinion of

F-11

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

management based on available evidence, it is more likely than not that some or all of any net deferred tax assets will not be realized.

Share-Based Payment

Prior to December 13, 2005, the Company administered a stock-based compensation plan (the “Incentive Stock Option Plan”) under which stock options were issued to directors, officers, employees and consultants as determined by the Board of Directors and subject to the provisions of the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted options to be issued with exercise prices at a discount to the market price of the Company’s common shares on the day prior to the date of grant. However, the majority of all stock options issued under the Incentive Stock Option Plan were issued with exercise prices equal to the quoted market price of the stock on the date of grant. Options granted under the Incentive Stock Option Plan vested immediately and were exercisable over a period not exceeding five years. The Company had 1,823,265 options outstanding under the Incentive Stock Option Plan at July 31, 2006.

On December 13, 2005, the shareholders of the Company approved the 2005 Omnibus Stock Plan (the “Omnibus Stock Plan”) and it became effective on that date. The Omnibus Stock Plan replaces the Incentive Stock Option Plan under which stock options were previously granted. The Omnibus Stock Plan is administered by the Compensation Committee of the Board of Directors (the “Committee”) and will remain in effect for five years. All employees and directors of the Company and its subsidiaries, and all consultants or agents of the Company designated by the Committee, are eligible to participate in the Omnibus Stock Plan. The Committee has authority to: grant awards; select the participants who will receive awards; determine the terms, conditions, vesting periods and restrictions applicable to the awards; determine how the exercise price is to be paid; modify or replace outstanding awards within the limits of the Omnibus Stock Plan; accelerate the date on which awards become exercisable; waive the restrictions and conditions applicable to awards; and establish rules governing the Omnibus Stock Plan. No options have been issued under the Omnibus Stock Plan. During the current fiscal year, the Committee granted stock awards under the Omnibus Stock Plan in the form of restricted and unrestricted stock to employees and directors of the Company. The transactions involving the granting of these stock awards are described more fully in Note 11.

The Company adopted SFAS No. 123(R), using the modified-prospective method, effective August 1, 2005. Since August 1, 2001, the Company followed the fair value provisions of SFAS 123 and recorded all share-based payment transactions as compensation expense at fair market value based on the grant-date fair value of those awards. In addition, all stock options previously granted by the Company vested immediately on the date of grant and, thus, there was no unvested portion of previous stock option grants that vested during the fiscal year ended July 31, 2006. Therefore, SFAS 123(R) had no impact on the Company’s consolidated financial position or results of operations for the fiscal year ended July 31, 2006. The Company uses the Black-Scholes formula to estimate the fair value of stock options granted.

Loss Per Share

Basic loss per share is calculated using the weighted average number of common shares outstanding during the year. Diluted loss per share reflects the potential dilution that could occur if securities or other contracts to issue

F-12

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

common shares were exercised or converted into common shares. Restricted common shares granted are included in the computation only after the shares become fully vested. Diluted loss per share is not disclosed as it is anti-dilutive. Outstanding options, warrants and unvested shares of restricted stock that were excluded from the computation of diluted loss per share, as the effect of their assumed exercises/vesting would be anti-dilutive, totaled 9,057,188, 15,786,491 and 10,427,910 at July 31, 2006, 2005 and 2004, respectively.

Reclassifications

Certain items included in prior years’ consolidated financial statements have been reclassified to conform to current year presentation.

Impact of Recently Issued Accounting Standards Not Yet Adopted

In June 2006, the FASB issued FASB Interpretation Number 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This Interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently assessing the effect of this Interpretation, if any, on its consolidated financial statements.


2.	MARKETABLE SECURITIES

The Company sold its remaining 432,000 shares of Pyng Technologies Corp. (“Pyng”), a TSX Venture listed public company, during the fiscal year ended July 31, 2005 and recognized a gain on the sale in the amount of $42,276. The gain is included within other income in the statement of operations. The Company considered these shares of Pyng to be trading securities and recorded unrealized holding gains and losses directly to earnings.


3.	PURCHASE OF ILLINOIS MINE GAS, L.L.C.

On March 3, 2005, the Company purchased the remaining interest in Illinois Mine Gas, L.L.C. (“IMG”), a 50% joint venture with Vessels Coal Gas, Inc. IMG was created to explore and develop abandoned mine works in the Illinois Basin for the extraction and sale of methane gas. The Company previously accounted for its 50% investment in IMG under the equity method of accounting. The aggregate purchase price of $899,681 in cash, less cash received in the amount of $42,043, was assigned entirely to IMG’s coal mine methane properties.


4.	SALE OF INVESTMENT IN HITE COALBED METHANE, L.L.C.

On January 4, 2006, the Company sold its 49% interest in Hite Coalbed Methane, L.L.C. (“HCM”) for $551,000 in cash and cancellation of the Company’s convertible note payable in the amount of $392,000, plus accrued interest of $31,182. The note was convertible into 390,537 of the Company’s common shares. The Company accounted for its investment in HCM under the cost method of accounting. The total consideration received of $974,182 resulted in a gain on the sale of the investment of $127,416, which is included in other income in the Company’s statement of operations for the fiscal year ended July 31, 2006. The Company also received its final distribution of net income from HCM during the fiscal year ended July 31, 2006 in the amount of $51,452, which is included as part of other income (expense), net in the statement of operations for the fiscal year ended July 31, 2006.


5.	RESTRICTED CASH

The Company negotiated an agreement (“Agreement”) with one of its surface rights owners to ensure the Company’s access to its wells and gas gathering systems. As part of the Agreement, the Company deposited $100,000 in a trust account to serve as a performance bond to ensure the Company performs its obligations under the terms of the Agreement. The Company has recorded this amount as a non-current asset at July 31, 2006 and 2005.

F-13

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

6. LONG-TERM NOTES PAYABLE

The Company has outstanding notes payable as follows:


	July 31
	2006			2005

Case Credit term note due in fiscal year 2007, 6.50%	$	15,410		$	32,833
GMAC term note due in fiscal year 2009, 6.50%		20,608			26,633
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%		80,849			98,356
Convertible note due in fiscal year 2008, 3.25%		—			392,000
Caterpillar Financial Services term note due in fiscal year 2007, 7.0%		99,148			—

		216,015			549,822
Less current maturities		(140,866	)		(42,227	)

Long-term notes payable	$	75,149		$	507,595

The notes are collateralized by the related vehicles and equipment. The convertible note payable outstanding at July 31, 2005 was issued in June 2003 with a face value of $392,000 and maturing on June 10, 2008, bearing interest at 3.25%, convertible at the option of the holder, prior to June 10, 2008, into 390,537 common shares of the Company. The convertible note payable was cancelled on January 4, 2005 pursuant to the sale of the Company’s interest in Hite Coalbed Methane, L.L.C. — see Note 4.

The annual maturities of all notes for the five fiscal years subsequent to July 31, 2006 are as follows:


	Principal		Interest		Total

2007	$	140,866	$	7,735	$	148,601
2008		27,982		3,855		31,837
2009		29,767		2,070		31,837
2010		17,400		440		17,840
2011		—		—		—

	$	216,015	$	14,100	$	230,115


7.	INCOME TAXES

The income tax benefit consists of the following:


	Year Ended July 31
	2006		2005			2004

Current	$	—	$	—		$	—
Deferred:
Canadian		—		—			—
United States		—		(581,582	)		(239,314	)
U.S. state taxes		—		(142,888	)		(58,797	)

Total deferred income taxes		—		(724,470	)		(298,111	)

Total income tax benefit	$	—	$	(724,470	)	$	(298,111	)

F-14

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

A reconciliation of income tax computed at the statutory Canadian tax rate and the Company’s effective rate is as follows:


	Year Ended July 31
	2006			2005			2004

Statutory Canadian income tax rate		(36.00	)%		(36.00	)%		(36.00	)%
Stock-based compensation		(4.71	)%		19.66	%		6.39	%
Non-deductible stock issuance costs		2.10	%		1.43	%		—	%
Current year Canadian loss with no tax benefit		4.61	%		2.32	%		6.14	%
Net change in deductible temporary differences due to foreign currency conversion and expired losses		3.16	%		(5.38	)%		(4.47	)%
Increase in valuation allowance		43.44	%		7.32	%		2.57	%
Other		(3.38	)%		(1.19	)%		(1.95	)%

Effective income tax rate		—	%		(11.84	)%		(27.32	)%

The components of the net deferred tax liability at July 31, 2006 and 2005 are shown below:


	July 31, 2006
	United States			Canada			Total

Deferred tax assets:
Net operating loss carryforwards	$	11,363,979		$	513,104		$	11,877,083
Stock-based compensation		769,416			—			769,416
Resource related allowances		—			1,762,037			1,762,037

Total non-current deferred tax asset		12,133,395			2,275,141			14,408,536
Valuation allowance		(4,465,611	)		(2,275,141	)		(6,740,752	)

Net deferred tax assets		7,667,784			—			7,667,784

Deferred tax liabilities:
Net property plant and equipment		(7,667,784	)		—			(7,667,784	)

Total non-current deferred tax liability		(7,667,784	)		—			(7,667,784	)

Net deferred tax liability	$	—		$	—		$	—


	July 31, 2005
	United States			Canada			Total

Deferred tax assets:
Net operating loss carryforwards	$	4,130,549		$	643,332		$	4,773,881
Resource related allowances		—			1,705,249			1,705,249
Investments and advances to subsidiaries		—			375,215			375,215

Total non-current deferred tax asset		4,130,549			2,723,796			6,854,345
Valuation allowance		(261,405	)		(2,640,396	)		(2,901,801	)

Net deferred tax assets		3,869,144			83,400			3,952,544

Deferred tax liabilities:
Net property plant and equipment		(3,869,144	)		(83,400	)		(3,952,544	)

Total non-current deferred tax liability		(3,869,144	)		(83,400	)		(3,952,544	)

Net deferred tax liability	$	—		$	—		$	—

F-15

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

The Company considers the need to record a valuation allowance against deferred tax assets on a country-by-country basis, taking into account the effects of local tax law. A valuation allowance is not recorded when it is determined that sufficient positive evidence exists to demonstrate that it is more likely than not that a deferred tax asset will be realized. The main factors considered are: (1) the nature, amount and expected timing of reversal of taxable temporary differences, and (2) opportunities to implement tax plans that affect whether tax assets can be realized. A valuation allowance has been recorded against the net deferred tax assets as of July 31, 2006 and 2005 because the Company believes it is more likely than not it will be unable to realize the benefit of these assets.

An increase in the U.S. valuation allowance of $4,204,206 has been recorded during the current fiscal year to reduce the amount of the U.S. deferred tax assets to an amount equal to the recorded U.S. deferred tax liabilities. A decrease in the Canadian valuation allowance of $365,255 has been recorded during the current fiscal year to reflect miscellaneous income and the expiration of net operating losses in Canada. Historically, the Company has had no income generating operations in Canada and any future income is too uncertain to justify not recording a valuation allowance.

The Company’s net operating loss carryforwards at July 31, 2006 expire as follows:


	Year Ended July 31
	2009		2010		2011 and Later		Total

Canadian	$	234,848	$	296,493	$	893,949	$	1,425,290
United States		—		—		29,138,408		29,138,408

	$	234,848	$	296,493	$	30,032,357	$	30,563,698

At July 31, 2006 the Company also has $4,894,546 of Canadian resource related deductions that have no expiration date.


8.	SHAREHOLDERS’ EQUITY

Common shares — The Company has authorized 200,000,000 shares without par value, of which 70,812,540 and 43,912,961 were issued and outstanding as of July 31, 2006 and 2005, respectively. Shares issued and outstanding at July 31, 2006 include 2,325,000 of restricted shares, of which 402,677 have vested as of July 31, 2006.

Additional paid-in capital — Amounts recorded of $5,871,120 and $4,493,680 at July 31, 2006 and 2005, respectively, represent the cumulative amounts charged to stock-based compensation expense as of each fiscal year-end.

Common shares issuable — Amount recorded of $271,440 at July 31, 2004 represents proceeds received in advance of the exercise of warrants to purchase common shares.

In September 2005, the Company sold 18,000,000 common shares in a private placement. The proceeds from this private placement of $27,883,954, net of $2,619,953 of share issuance costs, are being used to fund the Company’s plan of operations and for working capital and general corporate purposes.

During fiscal year 2005, the Company issued 10,372,000 shares at $1.25 per share with 5,186,000 share purchase warrants exercisable at $1.50 for a period of two years (“Investor Warrants”). The Company’s agent received a commission of 5% and 1,037,200 broker warrants exercisable at $1.25 for a period of two years (“Agent Warrants”). The shares and warrants, when issued, were restricted under the U.S. Securities Act, and the Company was required to register the resale of the shares and the shares underlying the warrants with the Securities and Exchange Commission. Upon registration of the shares underlying the warrants and the delisting of such shares from the TSX Venture Exchange, the Investor Warrants were extended to be exercisable for two years after such listing and the Agent warrants were extended to be exercisable for five years after the closing of the share placement.

F-16

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Share purchase warrants outstanding at July 31, 2006 are as follows:


Number		Exercise
Outstanding		Price		Expiry Date

	4,274,400	$	1.50	December 13, 2007
	643,200	$	1.25	December 31, 2009
	394,000	$	1.25	January 12, 2010

	5,311,600


9.	COMMITMENTS AND CONTINGENCIES

The Company has operating lease commitments expiring at various dates. Such leases generally contain renewal options. At July 31, 2006, future minimum lease payments under non-cancellable operating leases are as follows:


2007	$	219,141
2008		123,714
2009		87,371
2010		14,600
2011		15,184
Thereafter		262,557

	$	722,567

The leases are principally for office space and gas collection equipment. Rental payments for all operating leases amounted to approximately $143,000 during the fiscal year ended July 31, 2006.

Certain of the Company’s mineral leases and farm-out agreements are subject to annual minimum royalty payments required to hold the mineral leases and farm-out agreements. Although the Company is not obligated to make these payments under existing mineral leases and farm-out agreements, these payments are required to maintain individual leases/farm-out agreements after the expiration of the initial terms of the lease/farm-out agreements. The mineral leases/farm-out agreements in existence as of July 31, 2006 expire at various dates beginning in November 2007. If the Company were to pay the total minimum royalty payments due under all mineral leases/farm-out agreements in existence as of July 31, 2006, the amount would initially total approximately $100,000 annually and could increase to as much as $220,000 annually.


10.	CONCENTRATIONS

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 Company’s plans to drill additional wells are determined in large part by the anticipated availability of acceptable drilling equipment and crews. The Company does not currently have any contractual commitments that ensure it will have adequate drilling equipment or crews to achieve its drilling plans. The Company believes that it can secure the necessary commitments from drilling companies as required. However, it can provide no assurance that its expectations regarding the availability of drilling equipment and crews from these companies will be met. A

F-17

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

significant delay in securing the necessary drilling equipment and crews could cause a delay in production and sales, which would affect operating results adversely.


11.	STOCK-BASED COMPENSATION

Stock Options

The table below summarizes stock options activity for the three years ended July 31, 2006. All stock options were granted under the Incentive Stock Option Plan with exercise prices denominated in Canadian Dollars. U.S. Dollar amounts shown in the table below were derived using published exchange rates on the date of the transaction for grants, expirations, exercises and surrenders and at year-end exchange rates for options outstanding as of July 31.


				Weighted-Average
				Exercise Price
	Number of Options			CAD$		USD$

Outstanding at July 31, 2003		1,825,000		$	0.81	$	0.58
Granted — exercise price less than market price of stock on date of grant		475,000			0.65		0.49
Exercised		(69,444	)		0.82		0.62

Outstanding at July 31, 2004		2,230,556			0.78		0.59
Granted — exercise price equals market price of stock on date of grant		3,423,278			2.04		1.64
Granted — exercise price less than market price of stock on date of grant		852,778			1.19		0.96
Expired		(25,000	)		1.20		0.98
Exercised		(2,254,333	)		0.87		0.72

Outstanding at July 31, 2005		4,227,279			1.82		1.49
Granted — exercise price equals market price of stock on date of grant		495,000			2.05		1.79
Expired		(320,000	)		2.29		1.79
Exercised		(554,014	)		1.55		1.24
Exchanged for restricted stock		(2,025,000	)		2.23		1.82

Outstanding at July 31, 2006		1,823,265		$	1.46	$	1.17

Included in stock options exercised during fiscal year 2006 are 107,800 stock options surrendered by an officer/director of the Company in order to exercise 173,250 warrants for the Company’s common stock in lieu of transferring cash. The transaction occurred on April 28, 2006. The fair value of the stock options surrendered in this transaction equaled the total exercise price of the warrants using the Black-Scholes options pricing model to value the stock options on the date of the transaction. The assumptions used in the Black-Scholes option pricing model were as follows:


Risk-free interest rate		4.75%
Expected dividend yield		Nil
Expected stock price volatility		95%
Expected option life		3.6 years

F-18

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

the historical period equivalent to the expected option life. In estimating expected volatility, the Company used a combination of the historical volatility of its stock for the period that it began trading on the American Stock Exchange and the historical volatility of its stock on the TSX Venture Exchange for the necessary period in order to reflect the expected remaining life of the stock options. The expected option life represents the remaining contractual life of the stock options surrendered.

The Company recorded stock-based compensation expense for stock options granted to employees and directors in the amount of $527,327, $3,344,738 and $193,796 in fiscal years ended July 31, 2006, 2005 and 2004, respectively. The fair value of stock options granted was estimated using the Black-Scholes option pricing model with the following assumptions:


	Year Ended July 31,
	2006	2005	2004

Risk-free interest rate	3.3%	3.0 - 3.7%	4.1%
Expected dividend yield	Nil	Nil	Nil
Expected stock price volatility	95%	69-81%	105%
Expected option life	3 years	3 years	5 years

The risk-free interest rate for periods within the contractual life of the options was based on the U.S. Treasury yield curve in effect at the time of grant for options granted during fiscal year 2006 and based on the equivalent Canadian rate in prior fiscal years. The expected stock price volatility is based solely on the historical volatility of the Company’s common stock during the historical period equivalent to the expected option life. In estimating expected volatility, the Company used the historical volatility of its stock on the TSX Venture Exchange as the Company had not yet began trading on the AMEX at the time the options were granted. The expected option life represents the Company’s best estimate of the time that options granted are expected to be outstanding based on prior experience.

The weighted average fair value per option at the date of the grant for options granted in fiscal years ended July 31, 2006, 2005 and 2004 was as follows:


	2006		2005		2004

Exercise price equals market price of stock on date of grant	$	1.07	$	0.81	$	—
Exercise price is less than market price of stock on date of grant		—		0.66		0.55

Total grants	$	1.07	$	0.78	$	0.55

Option pricing models require the input of highly subjective assumptions, particularly as to the expected price volatility of the stock. Changes in these assumptions can materially affect the fair value estimate, and therefore it is management’s view that the existing models do not necessarily provide a single reliable measure of the fair value of the Company’s stock option grants.

F-19

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes information about options outstanding as of July 31, 2006:


Exercise		Number		Remaining
Price CAD$		Outstanding		Life (Years)		Expiry Date

$	0.65		345,000		2.3	November 3, 2008
	0.90		243,334		0.4	January 10, 2007
	0.90		10,000		3.1	September 22, 2009
	1.20		50,000		0.4	January 10, 2007
	1.49		695,666		3.3	November 29, 2009
	2.05		10,000		4.1	September 23, 2010
	2.19		136,000		3.7	March 27, 2010
	2.40		333,265		3.5	January 20, 2010

$	1.46		1,823,265		2.7

Restricted Stock Awards and Grants of Common Shares

On April 12, 2006, the Compensation Committee approved an exchange of common shares for outstanding stock options held by various key employees and directors of the Company (“Option Exchange”). The Option Exchange effectively cancelled stock option awards for 2,025,000 of the Company’s common shares previously granted during fiscal years ended 2005 and 2006. The Option Exchange replaced the cancelled options with restricted stock awards of 2,025,000 of the Company’s common shares. The restrictions on the shares of restricted stock are scheduled to lapse on three separate dates as follows:


January 1, 2007			680,000 shares
January 1, 2008			680,000 shares
January 1, 2009			665,000 shares

The Company accounted for the Option Exchange as a modification of the original shared-based payment awards (stock options) in accordance with SFAS No. 123(R). Accordingly, the Company recorded compensation expense based on the excess of the fair value of the restricted stock award grants over the fair value of the original award (stock options) measured immediately before the transaction based on current circumstances. The fair value of the restricted stock awards was determined based on the number of shares granted and the quoted price of the Company’s 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 Company’s common stock during the historical period equivalent to the expected option life. In estimating expected volatility, the Company used a combination of the historical volatility of its stock for the period that it began trading on the American Stock Exchange and the historical volatility of its stock on the TSX Venture Exchange for the necessary period in order to reflect the expected remaining life of the stock options. The expected option life represents the remaining contractual life of the stock options surrendered.

F-20

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

The Option Exchange resulted in incremental compensation expense of $989,650, which will be recognized over the requisite service period. The Company recorded $139,728 of compensation expense related to the Option Exchange in the fiscal year ended July 31, 2006. Future amortization of the unearned incremental compensation expense will result in additional compensation expense of $385,621, $303,216 and $118,294 in fiscal years ended July 31, 2007, 2008 and 2009, respectively.

On April 28, 2006, the vesting of 84,163 shares of restricted stock issued to an officer/director of the Company in the Option Exchange described above was accelerated and the shares were surrendered by the officer/director in order to exercise 165,000 warrants for the Company’s common stock in lieu of transferring cash. The accelerated vesting of the restricted stock resulted in $42,790 of compensation expense which was recorded in fiscal year 2006. The fair value of the stock surrendered in this transaction equalled the total exercise price of the warrants using the quoted market price of the Company’s stock on the AMEX from the previous day to value the stock surrendered.

On April 12, 2006, the Company granted 300,000 shares of restricted stock and 300,000 unrestricted common shares to its newly hired Senior Vice President of Operations. The grant was made outside the Omnibus Stock Plan in accordance with AMEX Company Guide Rule 711. The fair value of the restricted stock was determined based on the number of shares granted and the quoted price of the Company’s common shares on the date of the grant of $1.42 per share. The restrictions on the shares of restricted stock are scheduled to lapse on three separate dates in the amount of 100,000 shares each on April 12, 2007, 2008 and 2009. The grant of restricted stock resulted in compensation expense of $426,000, which will be recognized over the requisite service period. The Company recorded $42,795 of compensation expense related to this grant of restricted stock in the fiscal year ended July 31, 2006. Future amortization of the unearned compensation expense will result in additional compensation expense of $142,000, $142,000 and $99,205 in fiscal years ended July 31, 2007, 2008 and 2009, respectively. The Company recorded the fair value of the award of unrestricted common shares of $426,000 as compensation expense in the fiscal year ended July 31, 2006.

On April 12, 2006, the Company granted 140,000 unrestricted common shares to a newly appointed director. The Company recorded the fair value of the award of unrestricted common shares of $198,800 as compensation expense in the quarter ended April 30, 2006.

All restricted stock awards are subject to continuous employment. However, in the event employment is terminated before the restrictions lapse by reason of death, total disability or retirement, the restrictions will lapse on the date of termination as to a pro-rata portion of the number of shares of restricted stock scheduled to lapse on the next lapse date, based on the number of days continuously employed during the applicable vesting period. The Company includes all shares of restricted stock in common shares outstanding when issued, but only includes the vested portion of such shares in the computation of basic earnings per share.

The Company’s policy is to issue new shares to satisfy stock option exercises and restricted stock grants upon receiving approval from the AMEX for the issuance of such shares.


12.	LEGAL SETTLEMENT

On March 15, 2006, the Company filed a complaint against Colt LLC and other defendants alleging tortious interference with business relations and breach of contract relating to the interruptions of its development plans at the Company’s Southern Illinois Basin Project. The Company sought a preliminary injunction (which was denied by the court) against Colt LLC and related parties from terminating the lease agreement covering its CBM rights in 43,000 acres at the Southern Illinois Basin Project or taking any other action that interferes with the Company’s right to produce CBM under the lease agreement, pending a final judgment on the merits of the complaint.

On April 5, 2006, Colt filed an answer and counterclaim in response to the Company’s complaint. In its counterclaim, Colt sought a declaratory judgment asking the court to declare, among other things, that: (a) the Company committed multiple breaches of the lease agreement; (b) the lease agreement automatically terminated due to the Company’s failure to cure its alleged breaches; (c) the lease agreement automatically terminated by its

F-21

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

own terms on April 3, 2006; and (d) to the extent the lease agreement already terminated, the Company is wrongfully holding over and/or trespassing and Colt is entitled to an award of damages as a result.

In June 2006, the Company reached a settlement with the defendants in this lawsuit. The following list summarizes the key terms of the settlement:

1. All parties released all the other parties from any claims they may have had against each other;

2. The Company paid Colt $3,000,000;

3. The Company surrendered any interest it had in the lease;

4. The Company acquired ownership of the CBM estate covering approximately 10,000 of the 43,000 acres previously covered by the lease (which acreage includes all of our producing CBM wells and proved reserves at our Southern Illinois Basin Project);

5. The Company was relieved of any future obligation to make royalty payments as was previously required under the terms of the lease (under the terms of the lease the Company was obligated to make royalty payments of 15% of gross sales and minimum royalties totaling at least $42,000 per month); and

6. The deed made clear that CBM operations take priority over coal mining operations for as long as CBM is being produced from the covered acreage; however, Colt has the right to acquire any CBM wells located in these 10,000 acres. If Colt exercises this option, it will be required to pay the fair market value (as established by a mutually agreed upon expert) of such well (which fair market value will include the value of any reserves that can be produced by such well).

In conjunction with this proposed settlement, during the fiscal year ended July 31, 2006 the Company recorded $2,951,608 as other expense and reclassified $2,225,816 from the cost of Unevaluated Properties to the cost of Proved Properties to recognize the impairment resulting from the loss of approximately 33,000 acres of mineral rights.


13.	OTHER INCOME (EXPENSE), NET

Other income (expense), net consisted of the following for the fiscal years ended July 31, 2006, 2005 and 2004, respectively:


	Fiscal Year Ended July 31
	2005			2004			2003

Legal settlement with Colt LLC	$	(2,951,608	)	$	—		$	—
Gain on sale of investment in HCM		127,416			—			—
Gain on sale of marketable securities — trading		—			42,276			2,454
Distribution from Hite Coalbed Methane, L.L.C.		51,452			6,615			—
Other, net		8,297			(13,506	)		—

	$	(2,764,443	)	$	35,385		$	2,454


14.	OIL AND GAS PROPERTIES

The Company’s oil and gas properties are all located in the United States of America and consist solely of its coalbed methane projects in the Illinois Basin. The Company’s acreage rights in the Illinois Basin are currently divided into three projects: the Southern Illinois Basin Project; the Northern Illinois Basin Project; and the Western Illinois Basin Project.

F-22

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Southern Illinois Basin Project

The Company’s CBM rights in the Southern Illinois Basin Project (formerly called the Delta Project) cover approximately 10,000 acres in the southern part of the Illinois Basin. The Company’s CBM rights on this acreage previously covered approximately 43,000 acres pursuant to a lease agreement, the primary term of which ended on April 3, 2006. As described in note 12, the lease was subject to litigation during the fiscal year ended July 31, 2006 and the Company reached a settlement with the defendants in the lawsuit, resulting in the Company acquiring ownership of the CBM estate free of any royalty interest covering approximately 10,000 of the 43,000 acres previously covered by the lease (which acreage includes all of the Company’s producing CBM wells and proved reserves at our Southern Illinois Basin Project). The Company is still paying two overriding royalty interests of 3% and 4%, both of which are calculated based on 43.35% of gross revenues from the project.

Under the terms of the deed covering this acreage, the Company’s right to drill for and produce CBM takes precedence over coal mining operations for as long as CBM is being produced from the acreage. However, the owner of the coal rights has the right to acquire any CBM wells located in these 10,000 acres. If the coal rights owner exercises this option, it will be required to (i) to immediately plug any such well so acquired and (ii) pay the fair market value (as established by a mutually agreed upon expert) of such well.

The Company commenced sales of gas from the initial pilot production wells on this project in January 2005. As of July 31, 2006, the Company had drilled 108 wells at this project. These wells consist of 86 productive wells, 14 shut-in wells, of which eight are scheduled to be plugged in fiscal year 2007 (as a result of the Colt LLC settlement), four plugged wells, one disposal well and three wells that have been drilled but are not yet in production. Most of the wells drilled at this project were initially completed in a limited number of seams, intentionally excluding other seams. The Company’s intention when it drilled these wells was to gather as much geological information as it could about CBM and dewatering characteristics of individual coal seams. During the fiscal year ended July 31, 2006, the Company went back and completed additional seams in most of these wells to begin dewatering and producing CBM from the additional seams penetrated by these wells. During fiscal year 2007, we will determine whether it is beneficial to complete additional seams in the remaining wells.

Northern Illinois Basin Project

The Company’s CBM rights in the Northern Illinois Basin Project cover 353,531 acres in Montgomery, Shelby, Christian, Fayette and Macoupin Counties in Illinois, which are located in the north central part of the Illinois Basin. The Company holds its CBM rights on this acreage pursuant to mineral leases, an option to acquire a mineral lease and a farm-out agreement. As of July 31, 2006, the Company had drilled 15 wells at this project. These wells consist of a recent 10-well pilot project, one well plugged, one disposal wells and three test wells.

Montgomery County Lease

The lease agreement with Montgomery County covers 120,951 acres of CBM rights in Montgomery County, Illinois. The lease agreement extends until November 27, 2010. After the initial term of the agreement, the Company can continue to hold the lease as long as it is producing CBM from the covered acreage. Under the lease agreement, the Company will be required to pay royalties to the lessor equal to 12.5% of the Company’s gross proceeds from the sale of CBM produced from the covered acreage.

Shelby County Lease

The lease agreement with Shelby County covers 63,250 acres of CBM rights in Shelby County, Illinois. This lease agreement extends until November 12, 2008. After the initial term of the agreement, the Company can continue to hold the lease as long as it is producing CBM from the covered acreage, with each productive vertical well holding 320 acres and each productive horizontal well holding 1,920 acres. The Company is required to pay

F-23

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

royalties to the lessor equal to 12.5% of the Company’s 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 Company’s gross proceeds from the sale of CBM produced from the covered acreage at rates ranging up to 12.5%.

Christian Coal Holdings, LLC Lease

The lease agreement with Christian Coal Holdings, LLC covers approximately 12,044 acres of CBM rights in Christian and Montgomery Counties in Illinois. The lease agreement extends until April 26, 2026. After the initial term of the agreement, the Company can continue to hold the lease as to each acreage block where it is producing CBM in commercial quantities. The Company is required to pay royalties to the lessor on the Company’s gross proceeds from the sale of CBM produced from the covered acreage at a rate of 12.5%.

Christian County Option

The Company holds an option from Christian County to lease 14,033 acres of CBM rights in Christian County, Illinois. The option extends until January 20, 2007. The lease agreement underlying the option will extend for a period of five years from the date the Company exercises the option. After the initial term of the agreement, the Company can continue to hold the lease as long as it is producing CBM from the covered acreage. Under the lease agreement, the Company will be required to pay royalties to the lessor equal to 12.5% of the Company’s gross proceeds from the sale of CBM produced from the covered acreage.

Addington Exploration, LLC (Macoupin County) Farm-out Agreement

Also included in the Northern Illinois Basin Project are 41,253 acres of CBM rights in Macoupin County, Illinois, which the Company can earn under a farm-out agreement with Addington Exploration, LLC, as described in more detail below.

Under the lease agreements with Montgomery and Shelby Counties and the lease agreement underlying the option agreement with Christian County, the Company’s right to drill for and produce CBM is expressly subject to the mining of coal on the covered acreage. The Company may not interfere with any existing coal mining operations and, under certain circumstances, may be required to cease drilling in locations where coal mining operations will be undertaken.

Under the lease agreements with IEC (Montgomery), LLC and Christian Coal Holdings, LLC, any drilling operations that the Company sets up can be displaced by coal mining operations. However, the lessor is required to provide the Company with a mine plan for the leased acreage indicating the acreage blocks that the lessor plans to mine and the order of priority for the acreage blocks that it plans to mine. If the lessor displaces a well ahead of the schedule outlined in the mine plan, the lessor may be required to reimburse the Company for the cost of plugging the well and, depending on how long the well has been in production and the cumulative gross income generated by the well, the value of the CBM that could be recovered from the well in the remainder of an eight-year term.

As of July 31, 2006, the Company had just recently completed drilling of a 10-well pilot program at this project, and all wells were in the initial stages of dewatering as of that date. As of the same date, the Company has drilled three test wells at this project. In addition, the Company intends to drill two additional test wells at this project during the first quarter of fiscal year 2007.

F-24

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Western Illinois Basin Project

The Company’s CBM rights in the Western Illinois Basin Project cover 135,948 acres in Clinton, Washington, Marion and Perry Counties in Illinois, which are located in the northwestern part of the Illinois Basin. The Company holds its CBM rights on this acreage pursuant to mineral leases, an option to acquire a mineral lease and a farm-out agreement.

Clinton County Lease

The lease agreement with Clinton County covers 55,900 acres of CBM rights in Clinton County, Illinois. The lease agreement extends until October 24, 2010. After the initial term of the agreement, the Company can continue to hold the lease as long as it is producing CBM from the covered acreage. The Company is required to pay royalties to the lessor equal to 12.5% of the Company’s gross proceeds from the sale of CBM produced from the covered acreage.

Washington County Option

The lease agreement with Washington County covers 39,169 acres of CBM rights in Washington County, Illinois. The lease agreement extends until September 9, 2011. After the initial term of the agreement, the Company can continue to hold the lease as long as it is producing CBM from the covered acreage, with each productive vertical well holding 320 acres and each productive horizontal well holding 1,920 acres. Under the lease agreement, the Company is required to pay royalties to the lessor from the Company’s gross proceeds from the sale of CBM produced from the covered acreage. The royalty is equal to 12.5% or 6.25% of the Company’s gross proceeds, depending on whether it is determined that Washington Counties’ CBM rights, if any, are derived from coal rights or oil and gas rights.

Marion County Option

The Company holds an option from Marion County to lease 17,882 acres of CBM rights in Marion County, Illinois. The option extends until June 8, 2007. The lease agreement underlying the option will extend for a period of five years from the date the Company exercises the option. After the initial term of the agreement, the Company can continue to hold the lease as long as it is producing CBM from the covered acreage. Under the lease agreement, the Company will be required to pay royalties to the lessor equal to 12.5% of the Company’s gross proceeds from the sale of CBM produced from the covered acreage. If the Company does not commence exploration of CBM within one year from the commencement of the lease, the Company will be required to pay advance royalties to the lessor equal to $8,941 for each one-year period that the Company delays commencing exploration. Any payment of advance royalties can be credited against royalties that may later become payable to the lessor from the production of CBM.

Addington Exploration, LLC (Perry County) Farm-out Agreement

The Company entered into a farm-out agreement with Addington Exploration, LLC covering 41,253 acres of CBM rights in Macoupin County, Illinois (Northern Illinois Basin) and 22,997 acres of CBM rights in Perry County, Illinois (Western Illinois Basin) that Addington controls pursuant to coal seam gas leases. The farm-out agreement provides for an initial 36-month evaluation period, during which the Company may test and evaluate the covered properties. The 36-month evaluation period can be extended by the Company on unearned acreage through the payment of a fee equal to $0.50 per acre, increasing over five years to $2.50 per acre. For each vertical and horizontal well that the Company places into production during the term of the agreement, Addington will assign to the Company its CBM rights covering the surrounding 160 acres penetrated by one of the Company’s wells. The Company is required to pay Addington a royalty equal to 3% of the Company’s proceeds from the sale of CBM produced from the covered acreage. In addition, the Company must pay royalties totaling 12.5% to the lessors under the coal seam gas leases underlying this farm-out agreement.

F-25

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Under the lease agreement with Washington County and the lease agreement underlying the option agreement with Marion County, the Company’s 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 Company’s CBM operations.

As of July 31, 2006, the Company has drilled two test wells at the Western Illinois Basin Project. The Company intends to drill three test wells at this project during the first quarter of fiscal year 2007.

The following table sets forth a summary of oil and gas property costs not being amortized at July 31, 2006, by the fiscal year in which such costs were incurred:


									2003
	Total		2006		2005		2004		and Prior

Property acquisition costs	$	178,072	$	—	$	150,771	$	27,301	$	—
Exploration and development, net of transfers to proved oil and gas properties		3,190,159		2,445,674		742,005		2,480		—

	$	3,368,231	$	2,445,674	$	892,776	$	29,781	$	—

No interest has been capitalized and included in the cost of unproved properties as of July 31, 2003 or in the fiscal years ended July 31, 2006, 2005 and 2004, as such amounts were not material. The Company expects to include the costs associated with unproved properties in its amortization computation over the next one to three years when future development of the projects is expected to result in additional reserves being classified as proved. Depletion expense related to proved oil and gas properties was $331,150, $58,523 and $0 or $2.28/Mcf, $1.72/Mcf and $0/Mcf in the fiscal years ended July 31, 2006, 2005 and 2004, respectively.


15.	RELATED PARTY TRANSACTIONS

The Company enters into various transactions with related parties in the normal course of business operations.

Randy Oestreich, the Company’s Vice President of Field Operations, owns and operates A-Strike Consulting, a consulting company that provides, among other things, laboratory testing related to coalbed methane. Beginning in fiscal year ended July 31, 2005, the Company owns and maintains a lab testing facility and allows A-Strike Consulting to operate the facility. The Company pays all expenses related to the facility and, in return, receives 80% of the revenue generated from the operations of the facility as reimbursement of the Company’s expenses. The Company received approximately $70,000, $59,000 and $0 in expense reimbursement related to this arrangement during the fiscal years ended July 31, 2006, 2005 and 2004, respectively. Mr. Oestreich’s brother owns Dependable Service Company, a company that provides general labor services to the Company. The Company paid Dependable Services Company approximately $237,000, $147,000 and $16,000 during the fiscal years ended July 31, 2006, 2005 and 2004, respectively.

David Preng, a director of the Company owns Preng & Associates, an executive search firm specializing in the energy and natural resources industries. The Company paid Preng & Associates approximately $293,000, $0 and $0 for executive placement services during the fiscal years ended July 31, 2006, 2005 and 2004, respectively.


16.	SUBSEQUENT EVENTS

Officer Resignation

On October 10, 2006, the Company entered into a Separation Agreement and Waiver and Release (“Separation Agreement”) with George Zilich, the Company’s Chief Financial Officer and General Counsel. Under the terms of

F-26

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

the Separation Agreement, Mr. Zilich resigned as an employee, officer and director of the Company effective immediately and the Company will provide consideration to Mr. Zilich for entering into the Separation Agreement as follows:


	•	In connection with Mr. Zilich’s existing employment agreement, the Company is required to make a cash payment to Mr. Zilich in the amount of $250,000 within three business days of his resignation. Such amount will be recorded as compensation expense during the first quarter of fiscal year 2007.

	•	In connection with Mr. Zilich’s existing employment agreement, provide medical and dental insurance coverage to Mr. Zilich through the second anniversary of the separation date. The Company will pay all premiums for such insurance coverage; provided, however, that if, at any time prior to the second anniversary of the separation date, Mr. Zilich becomes eligible to participate in an employer sponsored and fully paid medical and dental insurance plan or policy with comparable coverage, the Company’s obligation to provide such coverage will terminate effective as of the date that Mr. Zilich becomes eligible to enroll in such plan or policy. Such amounts incurred for the premiums will be charged to expense as incurred in the future.

	•	In connection with a continuing services clause of the Separation Agreement, the Company is required to issue 40,000 unrestricted common shares to Mr. Zilich within three business days of his resignation and make cash payments to Mr. Zilich in the amount of $8,333.33 on each of the following dates: October 15, 2006; October 31, 2006; November 15, 2006; November 30, 2006; December 15, 2006; and December 31, 2006. In return, Mr. Zilich will provide the Company with consulting services as may be reasonably requested by the Company from time to time through January 2, 2008. The Company will recognize the expense related to these payments over the future period(s) in which it expects to receive consulting services from Mr. Zilich.

	•	In connection with a non-compete and non-solicitation clause of the Separation Agreement, the Company is required to make payments to Mr. Zilich in the amount of $100,000 on each of the following dates: January 2, 2007; August 1, 2007; and January 2, 2008. The Company is also required to take actions to provide that the 380,720 restricted common shares currently held by Mr. Zilich vest immediately on the separation date. In return, Mr. Zilich agrees not to (a) engage, either directly or indirectly, as an employee, officer or partner in a business that is competitive with the Company’s coal bed methane gas extraction business in the geographical territory known as the “Illinois Basin,” or (b) solicit or attempt to solicit, either on Zilich’s behalf or on behalf of any of third party, or assist any third party in soliciting, any employee of the Company to leave or terminate their employment with the Company. The Company will recognize expense related to these payments over the future period(s) in which it expects to benefit from the terms of this agreement.

New Technical Staff Compensation

During the first quarter of fiscal year 2007, the Company added four new members to its technical team: a Geologist and three Engineers. As an inducement to join the Company, the Company paid the new employees a total of $345,000 in signing bonuses and granted them a total of 350,000 shares of unrestricted stock (James Erlandson — 90,000; Michael Dawson — 100,000; Bradford Sutton — 80,000; and Kelly Sutton — 80,000) and 700,000 shares of restricted stock (James Erlandson — 180,000; Michael Dawson — 200,000; Bradford Sutton — 160,000; and Kelly Sutton — 160,000). These share grants were made outside the Omnibus Stock Plan in accordance with AMEX Company Guide Rule 711. The shares of restricted stock will vest based on service over a two-year period. In addition, the total annual salaries of these new employees will be $600,000.

F-27

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

17. SUPPLEMENTAL GAS DATA (UNAUDITED)

The following unaudited information was prepared in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” and related accounting rules.

The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves developed by our independent reservoir engineer consultant.

Summary of Changes in Proved Reserves


	Year Ended July 31
	2006			2005			2004
	MMcf			MMcf			MMcf

Proved reserves
Beginning of year		10,292			—			—
Purchase of reserves in place		2,229			—			—
Extensions and discoveries		4,528			10,326			—
Revisions of previous estimates		(2,186	)		—			—
Production		(145	)		(34	)		—

End of year		14,718			10,292			—

Proved developed reserves
Beginning of year		2,971			—			—
End of year		8,983			2,971			—

Capitalized Costs Related to Gas Producing Activities

The capitalized costs relating to gas producing activities and the related accumulated depletion, depreciation and accretion as of July 31, 2006 and 2005 were as follows:


	Fiscal Year Ended July 31
	2006			2005

Capitalized costs:
Proved oil and gas properties	$	21,098,048		$	10,248,652
Unproved oil and gas properties		3,368,231			3,149,372
Support equipment		1,046,989			760,467
Gas collection		4,342,400			1,332,012

Total capitalized costs		29,855,668			15,490,503
Less: Accumulated DD&A		(922,534	)		(426,485	)

Net capitalized costs	$	28,933,134		$	15,064,018

F-28

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

Costs Incurred in Gas Exploration and Development Activities

Costs related to gas activities of the Company were incurred as follows for the fiscal years ended July 31, 2006, 2005 and 2004:


	Fiscal Year Ended July 31
	2006		2005		2004

Property acquisition — proved	$	—	$	—	$	—
Property acquisition — unproved		—		341,634		2,664
Exploration		—		743,811		1,778,517
Development		11,007,725		5,541,022		—
Support equipment		286,522		238,153		201,643
Gas collection		3,010,388		1,225,113		106,899

	$	14,304,635	$	8,089,733	$	2,089,723

Prior to fiscal year 2005, the Company’s 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 Company’s results of operations from gas producing activities for the fiscal years ended July 31, 2006, 2005 and 2004. The Company commenced production and sales of gas during fiscal year ended July 31, 2005. The Company had no revenues or operating expenses of gas activities during the fiscal year ended July 31, 2004.


	Fiscal Year Ended July 31
	2006			2005			2004

Gas revenues	$	1,126,477		$	117,835		$	—
Production costs		(970,791	)		(307,178	)		—
Depreciation, depletion and amortization		(538,055	)		(238,366	)		—

Pre-tax operating loss		(382,369	)		(427,709	)		—
Income taxes		—			166,807			—

Loss from oil and gas producing activities	$	(382,369	)	$	(260,902	)	$	—

The following estimates of proved reserve quantities and related standardized measure of discounted net cash flows are estimates only and do not purport to reflect realizable values or fair market values of the Company’s 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 Company’s reserves are located in the United States.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods.

The standardized measure of discounted future net cash flows is computed by applying year-end prices of gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows

F-29

BPI ENERGY HOLDINGS, INC.

Notes to Consolidated Financial Statements — (Continued)

less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. The average net price per Mcf used at July 31, 2006 and 2005 was $7.22 and $7.44, respectively.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves

The standardized measure of discounted cash flows related to proved gas reserves at July 31, 2006, 2005 and 2004 were as follows:


	July 31
	2006			2005			2004
	(Amounts in thousands)

Future cash inflows	$	106,221		$	76,608		$	—
Future production costs and taxes		(24,937	)		(10,181	)		—
Future development costs		(8,930	)		(7,824	)		—
Future income tax expenses		(15,775	)		(14,663	)		—

Net future cash flows		56,579			43,940			—
Discounted at 10% for estimated timing of cash flows		(23,845	)		(20,872	)		—

Standardized measure of discounted future net cash flows	$	32,734		$	23,068		$	—

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves

The primary changes in the standardized measure of discounted future net cash flows for the fiscal years ended July 31, 2006, 2005 and 2004 were as follows:


	Year Ended July 31
	2006			2005			2004
	(Amounts in thousands)

Standardized measure, beginning of year	$	23,068		$	—		$	—
Sales, net of production costs and taxes		(156	)		189			—
Extensions and discoveries		14,633			27,758			—
Purchases of reserves in place		7,206			—			—
Net changes in prices and production costs		(5,606	)		—			—
Net changes in future development costs		(1,023	)		(5,541	)
Revisions of quantity estimates		(7,063	)		—			—
Interest factor — accretion of discount		3,077			—			—
Net change in income tax		(651	)		—			—
Net change in production rates (timing) and other		(751	)		662			—

Net increase		9,666			23,068			—

Standardized measure, end of year	$	32,734		$	23,068		$	—

F-30

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.


	By:	/s/ James G. Azlein

James G. Azlein,

President and Chief Executive Officer

Date: October 30, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature		Title

/s/ James G. Azlein James G. Azlein		President, Chief Executive Officer and Director

/s/ Randy Elkins Randy Elkins		Controller and Acting Chief Financial Officer (Principal Financial and Accounting Officer)

/s/ Costa Vrisakis* Costa Vrisakis		Director

/s/ William J. Centa* William J. Centa		Director

/s/ Dennis Carlton* Dennis Carlton		Director

/s/ David E. Preng* David E. Preng		Director

*By:	/s/ James G. Azlein James G. Azlein, Attorney-in-Fact for the directors signing in the capacities indicated

Date: October 30, 2006

EXHIBIT INDEX


Number			Description

	3	.1	Articles of Incorporation of BPI Energy Holdings, Inc. (Incorporated by reference to Appendix A of the Proxy Statement filed by BPI Energy Holdings, Inc. with the SEC on January 12, 2006).
	4	.1	Stock Purchase Agreement, dated September 20, 2005, by and among BPI Energy Holdings, Inc. and the investors party thereto.(***)
	4	.2	BPI Energy Holdings, Inc. 2005 Omnibus Stock Plan (Filed as Exhibit 99.1 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on December 15, 2005 and incorporated herein by reference).(#)
	4	.3	Incentive Stock Option Plan of BPI Energy Holdings, Inc., dated as of December 16, 2002.(*) (#)
	10	.1	Financial Advisor Agreement, dated as of September 29, 2004, by and between BPI Energy Holdings, Inc. and Sanders Morris Harris, Inc.(*)
	10	.2	Placement Agent Agreement, dated as of December 8, 2004, by and between BPI Energy Holdings, Inc. and Sanders Morris Harris, Inc.(*)
	10	.3	Registration Rights Agreement, dated as of December 30, 2004, by and between BPI Energy Holdings, Inc. and Sanders Morris Harris, Inc., individually and as Agent and Attorney-in-Fact for the Purchasers listed on Exhibit A thereto.(*)
	10	.4	Amendment No. 1 to Registration Rights Agreement, dated as of April 20, 2005, by and among BPI Energy Holdings, Inc. and the holders of its common shares executing signatures pages attached thereto.(*)
	10	.5	Technical Services Agreement, dated as of March 31, 2005, by and between BPI Energy Holdings, Inc. and BHP Petroleum (Exploration) Inc.(*)
	10	.6	Oil, Gas and Coalbed Methane Gas Lease, dated as of April 3, 2001, by and among BPI Industries (USA), Inc., AFC Coal Properties, Inc., American Premier Underwriters, Inc. and Methane Management, Inc. (Southern Illinois Basin Project).(*)
	10	.7	Amendment to Oil, Gas and Coalbed Methane Gas Lease, dated as of November 23, 2004, by and among BPI Industries (USA), Inc., AFC Coal Properties, Inc. and American Premier Underwriters, Inc. (Southern Illinois Basin Project).(*)
	10	.8	Option to Purchase Mineral Lease, dated as of October 10, 2002, by and between BPI Energy, Inc. and the County of Montgomery, Illinois (Northern Illinois Basin Project).(*)
	10	.9	Option to Purchase Mineral Lease, dated as of January 20, 2004, by and between BPI Energy, Inc. and the County of Christian, Illinois (Northern Illinois Basin Project).(*)
	10	.10	Mineral Lease, dated as of November 12, 2003, by and between BPI Energy, Inc. and the County of Shelby, Illinois (Northern Illinois Basin Project).(*)
	10	.11	Option to Purchase Mineral Lease, dated as of November 3, 2003, by and between BPI Energy, Inc. and the County of Clinton, Illinois (Western Illinois Basin Project).(*)
	10	.12	Mineral Lease, dated as of September 9, 2006, by and between BPI Energy, Inc. and the County of Washington, Illinois (Western Illinois Basin Project).(†)
	10	.13	Option to Purchase Mineral Lease, dated as of June 8, 2004, by and between BPI Energy, Inc. and the County of Marion, Illinois (Western Illinois Basin Project).(*)
	10	.14	Farm-out Agreement, dated as of November 2, 2004, by and between BPI Energy, Inc. and Addington Exploration, LLC (Northern Illinois Basin and Western Illinois Basin Projects).(*)
	10	.15	Employment Letter Agreement, dated as of January 6, 2005, by and between BPI Energy Holdings, Inc. and George J. Zilich.(*) (#)
	10	.16	Employment Letter Agreement, dated as of January 31, 2005, by and between BPI Energy Holdings, Inc. and Randy Elkins.(*) (#)
	10	.17	Agreement, dated as of April 17, 2004, by and between BPI Energy Holdings, Inc. and James G. Azlein.(*) (#)
	10	.18	Confidential Lock-up Agreement, dated as of December 31, 2004, by and between BPI Energy Holdings, Inc. and James G. Azlein.(*)(#)
	10	.19	Form of Confidential Lock-up Agreement, dated as of December 31, 2004.(*)
	10	.20	Letter agreement, dated as of July 7, 2005, by and among BPI Energy Holdings, Inc., KeyBanc Capital Markets, a division of McDonald Investments, Inc., and Sanders Morris Harris, Inc.(**)
	10	.21	Base Contract for Sale and Purchase of Natural Gas, dated as of December 1, 2004, by and between BPI Energy Holdings, Inc. and Atmos Energy Marketing, LLC.(**)
	10	.22	Transaction Confirmation for the Sale and Purchase of Natural Gas, dated January 30, 2006, by and between BPI Energy Holdings, Inc. and Atmos Energy Marketing, LLC.(†)
	10	.23	Form of Confidential Lock-up Agreement, dated September 26, 2005.(***)


Number			Description

	10	.24	Common Stock Purchase Warrant issued by BPI Energy Holdings, Inc. on December 31, 2004 to Sanders Morris Harris, Inc.(*)
	10	.25	Common Stock Purchase Warrant issued by BPI Energy Holdings, Inc. on January 12, 2005 to Sanders Morris Harris, Inc.(*)
	10	.26	Form of Warrant Certificate issued by BPI Energy Holdings, Inc. in its December 2004/January 2005 private placement.(*)
	10	.27	Form of Subscription Agreement entered into by the investors in the December 2004/January 2005 private placement of BPI Energy Holdings, Inc.(*)
	10	.28	Coal Seam Gas Lease Agreement, dated April 26, 2006, by and between BPI Energy, Inc. and IEC (Montgomery), LLC (Northern Illinois Basin Project) (Filed as Exhibit 10.1 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on April 28, 2006 and incorporated herein by reference).
	10	.29	Coal Seam Gas Lease Agreement, dated April 26, 2006, by and between BPI Energy, Inc. and Christian Coal Holdings, LLC (Northern Illinois Basin Project) (Filed as Exhibit 10.2 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on April 28, 2006 and incorporated herein by reference).
	10	.30	Settlement Memorandum of Understanding by and among BPI Energy, Inc., Colt LLC, AFC Coal Properties, Inc., American Premier Underwriters, Inc. and Central States Coal Reserves of Illinois, LLC, dated June 13, 2006 (Filed as Exhibit 10.1 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on June 15, 2006 and incorporated herein by reference).
	10	.31	Settlement and Mutual Release Agreement, dated June 23, 2006, by and among BPI Energy, Inc., for itself and as successor by merger or otherwise to Methane Management, Inc. and BPI Industries Inc., Colt LLC, AFC Coal Properties, Inc., American Premier Underwriters, Inc. and Central States Coal Reserves of Illinois, LLC (Filed as Exhibit 10.1 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on June 27, 2006 and incorporated herein by reference).
	10	.32	Purchase and Sale Agreement, dated June 23, 2006, by and between Colt LLC and BPI Energy, Inc. (Filed as Exhibit 10.2 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on June 27, 2006 and incorporated herein by reference).
	10	.33	Termination Agreement, dated June 23, 2006, by and between BPI Energy, Inc., for itself and as successor by merger or otherwise to Methane Management, Inc. and BPI Industries Inc., Colt LLC, AFC Coal Properties, Inc., American Premier Underwriters, Inc. and Central States Coal Reserves of Illinois, LLC, for itself and its predecessor Peabody Development Land Holdings, LLC (Filed as Exhibit 10.3 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on June 27, 2006 and incorporated herein by reference).
	10	.34	Separation Agreement and Waiver and Release by and between BPI Energy Holdings, Inc. and George J. Zilich, dated October 12, 2006 (Filed as Exhibit 10.1 to Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on October 16, 2006 and incorporated herein by reference).(#)
	21	.1	List of Subsidiaries.(†)
	23	.1	Consent of De Visser Gray, Chartered Accountants.(†)
	23	.2	Consent of Schlumberger Technology Corporation.(†)
	23	.3	Consent of Meaden & Moore, Ltd.(†)
	24	.1	Power of Attorney.(†)
	31	.1	Section 302 Certification of the Chief Executive Officer (Principal Executive Officer).(†)
	31	.2	Section 302 Certification of the Acting Chief Financial Officer (Principal Financial Officer).(†)
	32	.1	Section 906 Certification of the Chief Executive Officer (Principal Executive Officer).(†)
	32	.2	Section 906 Certification of the Acting Chief Financial Officer (Principal Financial Officer).(†)


(*)		Incorporated by reference to the S-1 Registration Statement filed by BPI Energy Holdings, Inc. with the SEC on June 3, 2005 (File No. 333-125483).

(**)		Incorporated by reference to Amendment No. 2 to the S-1 Registration Statement filed by BPI Energy Holdings, Inc. with the SEC on September 6, 2005 (File No. 333-125483).

(***)		Incorporated by reference to Amendment No. 3 to the S-1 Registration Statement filed by BPI Energy Holdings, Inc. with the SEC on October 28, 2005 (File No. 333-125483).

(†)		Filed herewith.

(#)		Management contract or compensatory plan or arrangement.


ITEM 15.	*Exhibits and Financial Statement Schedules.*


Reports of Independent Registered Public Accounting Firms			F-2
Consolidated Balance Sheets as of July 31, 2006 and 2005			F-4
Consolidated Statements of Operations for the years ended July 31, 2006, 2005 and 2004			F-5
Consolidated Statements of Shareholders’ Equity for the years ended July 31, 2006, 2005 and 2004			F-6
Consolidated Statements of Cash Flows for the years ended July 31, 2006, 2005 and 2004			F-7
Notes to Consolidated Financial Statements as of July 31, 2006 and 2005 and for the years ended July 31, 2006, 2005 and 2004			F-8


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter

Fiscal 2006:
Gas sales	$	209,694		$	327,811		$	262,860		$	326,112
Lease operating expenses		160,804			300,806			290,844			218,337
Net loss		(1,193,261	)		(854,225	)		(4,941,588	)		(1,847,171	)
Basic and diluted loss per common share	$	(.03	)	$	(.01	)	$	(.14	)	$	(.03	)
Fiscal 2005:
Gas sales	$	—		$	6,341		$	46,925		$	64,569
Lease operating expenses		—			—			203,289			103,889
Net loss		(388,347	)		(2,485,843	)		(1,734,199	)		(787,962	)
Basic and diluted loss per common share	$	(.01	)	$	(.07	)	$	(.04	)	$	(.02	)



MINERAL LEASE


Prepared by:

BPI Industries, Inc.
501 East DeYoung Street
Marion, Illinois 62959

	(a)		One-Eight (1/8) of the amount realized by Lessee from the sale of Coal Bed Gas. The payment of this royalty shall be based upon the assumption that the interest of Lessor in the Coal Bed Gas is based upon Lessor’s ownership of the coal as to the lands described herein.

	(b)		One-sixteenth (1/16) of the amount realized by Lessee from the sale of Coal Bed Gas. The payment of this royalty shall be based upon the assumption that the interest of Lessor in the Coal Bed Gas is based upon Lessor’s ownership of the gas within the Oil and Gas as to the lands described herein.

	(c)		One-eighth (1/8) of the oil and liquid hydrocarbons within the Oil and Gas produced and saved with the same to be delivered at the well or to the credit of the lessor in the pipeline to which a well may be connected, based upon Lessor’s ownership of the oil within the Oil and Gas as to the lands described herein.

	(d)		The market value at the mouth of the well of one-eight (1/8) of the gas within the Oil and Gas sold or used or one-eight (1/8) of the amount realized from the sale thereof at the well, based upon Lessor’s ownership of the gas within the Oil and Gas as to the lands described herein.

	a.		Inspect by all appropriate means Lessee’s facilities on the Land;

	b.		Test Lessee’s meters and other measuring and testing devices;

	c.		Sample, test measure and gage production of the wells, including the right, but not the obligation, to install meters on lines;

	d.		Observe Lessee in the performance of Lessee’s obligations under this lease; and

	e.		By appointment, examine or audit, during the term of this lease and for three years thereafter, the books, records, supporting documents, files and correspondence of Lessee maintained in connection with the lease and the production and /or sale of the coal gas or coal gas products from the Land at Lessee’s place of business.


	LESSOR WASHINGTON COUNTY, ILLINOIS
	BY		/s/ David A. Meyer
			Its Chairman


	LESSEE BPI ENERGY, INC.
	BY		/s/ James G. Azlein
			Its President



							Date: January 30, 2006 Transaction Confirmation #:
	Atmos Energy Marketing						Date: January 30, 2006 Transaction Confirmation #:



BUYER:
Atmos Energy Marketing, LLC			SELLER:
11251 Northwest Freeway, Suite 400, Houston, TX 77092			BPI Industries, Inc.
Attn: Contract Administration			30775 Bainbridge Road, Suite 280, Solon, OH 44139
Phone: 713-688-7771			Attn: James Azlein
Fax: 713-688-1625			jazlein@bpi-industries
Transporter: TETCO			(O) 618-993-1460
Transporter Contract Number:			(F) 618-993-1360


Firm (Fixed Quantity):	Firm (Variable Quantity):	Interruptible:
MMBtus/day	MMBtus/day Minimum	Up to MMBtus/day
EFP	Up to 2,500 MMBtus/day Maximum
	subject to Section 4.2 at election of
	o Buyer or o Seller



Buyer: Atmos Energy Marketing, LLC		Seller: BPI Industries, Inc.

By:	[illegible signature]	By:	/s/ James G. Azlein


Title: Senior VP		Title: CEO and President

Date: February 1, 2006		Date: February 1, 2006


Copyright ^© 2002 North American Energy Standards Board, Inc. All Rights Reserved		Page 1		NAESB Standard 6.3.1 April 19, 2002


Name of Subsidiary		State of Incorporation

BPI Energy, Inc.		Nevada



1310 Commerce Drive
Park Ridge 1
Pittsburgh, PA 15275-1011
Tel: 412-787-5403
Fax: 412-787-2906


Name	Title	Date

/s/ Dennis Carlton Dennis Carlton	Director	10/18/06

/s/ William J. Centa William J. Centa	Director	10/19/06

/s/ David E. Preng David E. Preng	Director	10/18/06

/s/ Costa Vrisakis Costa Vrisakis	Director	10/18/06


	By:	/s/ James G. Azlein Name: James G. Azlein Title: Chief Executive Officer and President