BPI ENERGY HOLDINGS, INC. POS AM

POS AM 1 l19977aposam.htm BPI ENERGY HOLDINGS, INC. POS AM BPI ENERGY HOLDINGS, INC. POS AM

As filed with the Securities and Exchange Commission on May 11, 2006

Registration No. 333-130122

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Post-Effective

Amendment No. 1

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

BPI ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)


British Columbia, Canada	1311	75-3183021
(State or other jurisdiction of	(Primary standard industrial	(I.R.S. employer
incorporation or organization)	classification code number)	identification number)

30775 Bainbridge Road, Suite 280

Solon, Ohio 44139

(440) 248-4200

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

George J. Zilich

Chief Financial Officer and General Counsel

30775 Bainbridge Road, Suite 280

Solon, Ohio 44139

(440) 248-4200

(Name, address, including zip code, and telephone number,

including area code, of agent for service)

Copies to:

Derek D. Bork

Thompson Hine LLP

127 Public Square, Suite 3900

Cleveland, Ohio 44114

(216) 566-5500

Approximate date of commencement of proposed sale to the public: From time to time after the registration statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. þ

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering: o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

18,000,000 Shares of Common Stock

This prospectus covers the offer and sale of 18,000,000 shares of our common stock, without par value, by the selling shareholders named in this prospectus. These shares consist of 18,000,000 shares that are currently outstanding.

The selling shareholders may offer the common stock from time to time through public or private transactions at prevailing market prices, at prices related to prevailing market prices or at other negotiated prices. The selling shareholders may sell none, some or all of the common stock offered by this prospectus. We cannot predict when or in what amounts the selling shareholders may sell the common stock offered by this prospectus. We will not receive any proceeds from the sale of common stock by the selling shareholders.

Our common stock is traded on the American Stock Exchange under the symbol “BPG.” On May 1, 2006, the closing price of our common stock was $1.46.

Investing in our common stock involves risks. See “Risk Factors” beginning on page 8.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is May 11, 2006.

Table of Contents


	Page

Prospectus Summary		1
Risk Factors		8
Cautionary Note Regarding Forward-Looking Statements		14
Use of Proceeds		14
Market for Our Common Stock		15
Dividend Policy		15
Capitalization		16
Selected Historical Financial Data		17
Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Business		30
Management		45
Certain Relationships and Related Transactions		51
Our Shareholders		52
Selling Shareholders		53
Plan of Distribution		55
Description of Our Common Stock		56
Material Tax Consequences to U.S. Holders		58
Where You Can Find More Information		60
Legal Matters		60
Change of Auditor		61
Experts		62
Appendix A: Glossary of Natural Gas Terms		A-1
Index to Consolidated Financial Statements		F-1
EX-5.1 Opinion of Anfield Sujir Kennedy & Durno
EX-21.1 Subsidiaries of BPI Energy Holdings
EX-23.1 Consent of De Visser, Gray,Chartered Accountants
EX-23.3 Consent of Schlumberger Technology Corp.
EX-23.4 Consent of Meaden & Moore, Ltd.
EX-24.1 Power of Attorney

Prospectus Summary

This summary highlights information contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information you should consider before investing in our common stock. You should read the entire prospectus carefully, including the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” and our consolidated financial statements and the related notes contained in this prospectus before making an investment decision. References in this prospectus to “we,” “us,” “our,” “company,” and “BPI” refer to BPI Energy Holdings, Inc. “You” refers to a prospective investor in the company through the purchase of shares offered by this prospectus.

In this prospectus, unless otherwise indicated, amounts are expressed in U.S. dollars. In addition, our financial statements included in this prospectus have been prepared in accordance with U.S. generally accepted accounting principles.

On February 9, 2006, the name of the company was changed from BPI Industries Inc. to BPI Energy Holdings, Inc. Some of the references to the company prior to that date, including in our financial statements, use our former name.

Coalbed Methane

We are engaged in the acquisition, exploration, development and production of coalbed methane (“CBM”) reserves. 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 400 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 water for several months. As the water pressure decreases in the coal formation, methane gas is released from the coal.

To assist you in reading this prospectus and understanding our business, we have included a glossary of selected natural gas terms that are used in this prospectus. 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, we have assembled CBM rights covering 530,435 acres in the Illinois Basin (including our 43,000 acre Southern Illinois Basin Project, where our acreage rights are currently subject to litigation, as described in this summary below). We believe that these rights currently give us control over more CBM acreage than any other CBM 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 (formerly called our Delta Project) consists of 43,000 acres in the southern part of the Illinois Basin. Our Southern Illinois Basin Project is currently subject to litigation that challenges our acreage rights, and we may therefore not retain any of these acreage rights. Our other acreage holdings include our Northern Illinois Basin Project (formerly called our Montgomery Project), located in the north central part of the Illinois Basin, where we control through lease, option and farm-out agreements an aggregate of 351,487 acres of CBM rights, and the Western Illinois Basin Project (formerly called our Clinton/ Washington 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 May 1, 2006, we have drilled 107 wells. These wells consist of 77 productive wells, 17 shut-in wells and 13 wells that have been drilled but are not in production, including three test wells. All of our productive wells are located at our Southern Illinois Basin Project. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of our productive wells existing as of May 1, 2006.

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 a field office located in Marion, 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 nearly all of our assets that are not related to CBM projects in the Illinois Basin.

Since 2001, we enlarged our acreage “footprint” from 43,000 acres to the 530,435 acres of CBM rights that we control today (including our 43,000 acre Southern Illinois Basin Project, where our acreage rights are currently subject to litigation), drilled CBM test and production wells at the Southern Illinois Basin and Northern Illinois Basin Projects, and installed gathering and production facilities for gas sales from the Southern Illinois Basin Project.

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 May 1, 2006, we have drilled 107 wells. These wells consist of 77 productive wells, 17 shut-in wells and 13 wells that have been drilled but are not in production, including three test wells. All of our productive wells are located at our Southern Illinois Basin Project. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of our productive wells existing as of May 1, 2006.



	Due to the litigation with respect to our Southern Illinois Basin Project, we are not drilling any new wells at our Southern Illinois Basin Project and have moved the focus of our drilling activities to our Northern Illinois Basin Project. During April 2006, we filed permit applications for drilling the first 10 CBM production wells at our Northern Illinois Basin Project.



	During the 12-month period ending April 30, 2007, we plan to drill 123 new wells, including 115 vertical wells, three horizontal wells and five test wells. This plan contemplates a capital expenditure budget of approximately $30.0 million. Our cash balance as of May 1, 2006 is approximately $25.0 million and therefore not sufficient to fully fund these capital expenditures and our anticipated cash needs through April 30, 2007. In order to fully fund our operations through April 30, 2007, we will need to raise additional financing.



	The number of wells that we drill during the 12-month period ending April 30, 2007 will be dependant on the success of our initial production wells at our Northern Illinois Basin Project, the additional capital that we are able to raise and the risk factors described in this prospectus.



	•	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 the coal seams are the thickest 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 high potential CBM areas in North America. We were the first company to begin acquiring substantial blocks of CBM acreage rights in the Illinois Basin. We believe that we currently control more CBM acreage than any other CBM company in the Illinois Basin.


	•	Demonstrated Commercial Production. We believe that we have taken the initial steps to demonstrate the commercial production capabilities of the Illinois Basin. As of May 1, 2006, we have drilled 107 wells, including 77 productive wells located at our Southern Illinois Basin Project, most of which have not yet reached peak production. For the six months ended January 31, 2006, our gas sales totaled $537,505. Although it is possible that we may lose our productive wells at our Southern Illinois Basin Project due to ongoing litigation, we believe that our production at the Southern Illinois Basin Project demonstrates the commercial viability of the Illinois Basin.



	•	Short Drilling Permit Lead Times. We typically experience short turnaround times in obtaining drilling permits as compared to CBM drillers in other CBM basins. Historically, we have enjoyed quick turnaround of vertical CBM well drilling permits from state regulatory bodies. We have not yet



		submitted any permit applications for drilling horizontal wells. However, we do not anticipate any significant delays in obtaining permits for these wells.



	•	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 been drilling or operating CBM wells in the Illinois Basin since 1996. In addition, James G. Azlein, our President and Chief Executive Officer, George J. Zilich, our Chief Financial Officer and General Counsel, and James E. Craddock, our Senior Vice President of Operations, beneficially own 6.97% of our common stock. In addition, the majority of BPI’s management and operating employees owns common stock and/or stock options in the company.

Risks Relating to BPI

In evaluating our business, you should consider that we are subject to a number of risks. Among these risks are:



	•	We are not currently generating net income or positive cash flow from operations. In addition, it is possible that, due to our ongoing litigation with respect to our CBM acreage rights at our Southern Illinois Basin Project, we may lose all of our productive wells existing as of May 1, 2006. 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. We will need to obtain additional financing in the near future to fund these activities.


	•	We may be unable to raise the additional financing necessary to fund our future operations. 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 in us.

	•	CBM exploration is speculative in nature and may not result in operating revenues or profits. The 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. In addition, we could determine in the future that the conditions in the Illinois Basin are not conducive to commercially viable CBM operations.

	•	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 and 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.


	•	We could lose significant portions of our CBM acreage rights and all of our existing productive wells if we do not place into production a sufficient number of CBM wells. The primary terms of the lease



		agreements pursuant to which we hold, or upon the exercise of options will hold, our CBM acreage rights have expired or will expire between April 2006 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. We are currently subject to litigation with respect to the lease agreement covering the 43,000 acres of CBM rights at our Southern Illinois Basin Project, where currently all of our productive wells are located. Due to the litigation, we could lose all of our acreage rights and productive wells at our Southern Illinois Basin Project.



	•	Approximately 77% of our CBM rights are inferior to coal mining rights covering the same properties, and our affected operations could be displaced by coal mining operations, which would negatively impact our operations.



	•	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 generally secure CBM rights from the coal owners. Some of our lessors hold both the coal rights and the oil and gas rights for the applicable properties, but in some cases it is not certain that they 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.


	•	We have granted BHP Billiton a right of first refusal to acquire us, which could deter other potential acquirors from seeking to acquire us. We also agreed to issue BHP 4.0 million stock appreciation rights, which may be exercised by BHP only if it acquires us. A potential acquiror might decide that it does not wish to expend its time and resources reviewing and negotiating an acquisition with us if BHP can thwart the transaction by exercising its right of first refusal.

For further discussion of these and other factors that you should carefully consider before making an investment decision, see “Risk Factors” beginning on page 8 of this prospectus.

Litigation Relating to Our CBM Rights at Our Southern Illinois Basin Project

On March 15, 2006, we filed a complaint against Colt, LLC and other defendants alleging tortious interference with business relations and breach of contract relating to the interruptions of our development plans at our Southern Illinois Basin Project. We sought a preliminary injunction against Colt, LLC and related parties from terminating the lease agreement covering our CBM rights at the Southern Illinois Basin Project or taking any other action that interferes with our right to mine CBM under the lease agreement, pending a final judgment on the merits of our complaint. We requested the preliminary injunction to preserve the status quo until the case is resolved.

On April 3, 2006, the United States District Court for the Southern District of Ohio denied our motion for a preliminary injunction. Although the court’s opinion provided that it did not state the court’s ultimate opinion on the merits of the case, the opinion provided that we had failed, in connection with our request for the preliminary injunction, to establish a substantial likelihood or probability of success on the merits.

On April 5, 2006, Colt filed an answer and counterclaim in response to our complaint. In its counterclaim, Colt seeks a declaratory judgment asking the court to declare, among other things, that: (a) we committed multiple breaches of the lease agreement; (b) the lease agreement automatically terminated due to our failure to cure our alleged breaches; (c) the lease agreement automatically terminated by its own terms on April 3, 2006; and (d) to the extent the lease agreement already terminated, we are wrongfully holding over and/or trespassing and Colt is entitled to an award of damages as a result.

Apart from the claims that we are currently pursuing in the litigation as to the entire 43,000 acres covered by the lease, we believe that we should hold our CBM acreage rights as to certain tracts of land subject to the lease. The lease has a primary term that extended until April 3, 2006. After the primary term, the lease provides that it shall extend as to a particular tract so long as CBM is being produced from such tract providing a royalty payment of not less than $1.00 per acre per month; provided that, after the primary term, in the event the aggregate royalties do no exceed $42,000 in any month, the lease shall terminate. We believe

that the wells that we have drilled (including both productive wells and shut-in wells) pursuant to the lease should hold tracts of land totaling approximately 10,550 acres. The remaining 32,450 acres under the lease do not have wells drilled.

These and related provisions of the lease, which we believe permit us to maintain our rights to at least 10,550 acres of CBM rights after the primary term of the lease, are subject to varying interpretations. It is likely that, ultimately, the interpretation of these lease provisions will be determined by the court in the ongoing litigation. It is possible that the court will not agree with our interpretation of the applicable lease provisions. In that case, we would lose all of our CBM acreage rights and productive wells at our Southern Illinois Basin Project.

The effect of the loss of all of our acreage under this lease would result in a write-down of capitalized net oil and gas and other properties in a total amount of approximately $26 million. The effect of the loss of only our non-producing acreage (those areas in which wells have not yet been established) may result in a write-down of capitalized net oil and gas and other properties in an amount up to approximately $4 million.

The Offering


Common stock available for offering by the selling shareholders		18,000,000 shares of our common stock. For additional information about the selling shareholders and the common stock available for sale by them, see the section of this prospectus entitled “Selling Shareholders.”


Common stock outstanding		As of May 1, 2006, we have 70,812,540 shares of our common stock outstanding. As of the same date, 5,311,600 shares of our common stock are issuable upon exercise of warrants held by third parties, and 1,872,812 shares of our common stock are issuable upon exercise of options held by our officers, directors, employees and others. See “Description of Our Common Stock.”


Use of proceeds		We will not receive any proceeds from the sale of common stock by the selling shareholders.

Plan of distribution		The offering is made by the selling shareholders named in this prospectus, to the extent they sell any shares of common stock. Sales may be made in the open market or in privately negotiated transactions, at fixed or negotiated prices. See “Plan of Distribution.”

Risk factors		An investment in our common stock is subject to risk. Please read “Risk Factors” and the other information included in this prospectus for a discussion of factors you should consider before deciding to invest in our common stock.

Risk Factors

An investment in our common stock is speculative in nature and involves a high degree of risk. You should carefully consider the following risks and the other information in this prospectus before investing.

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 gas that we are currently selling is not significant. We are not currently generating net income or positive cash flow from operations. In addition, it is possible that, due to ongoing litigation with respect to our CBM acreage rights at our Southern Illinois Basin Project, we may lose all of our productive wells existing as of May 1, 2006. 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 preferred stock or additional common stock, 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. During the six-month period ended January 31, 2006, we incurred a net loss of $2,047,487. As of January 31, 2006, we have an accumulated deficit of $20,404,770. 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 significant 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;

	•	adverse weather; 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 and all of our existing productive wells if we do not place into production a sufficient number of CBM wells.*

The primary terms of the lease agreements pursuant to which we hold, or upon the exercise of options will hold, our CBM acreage rights have expired or will expire between April 2006 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, the wells that we place into production must produce minimum royalties to the lessor and, in some cases, we will retain only limited acreage rights for each CBM well that we place into production. In addition, under our farm-out agreement with Addington Exploration, LLC, which covers 41,253 acres in the Northern Illinois Basin Project and 22,997 acres in the Western Illinois Basin Project, we earn CBM acreage rights only when we place CBM wells into production. For each well that we place into production, we will receive only a portion of the acreage rights covered by the agreement. As of May 1, 2006, we have 77 productive wells, 17 shut-in wells and 13 wells that have been drilled but are not in production, including three test wells. Since all of our productive wells existing as of May 1, 2006 are located at our Southern Illinois Basin Project, we could lose all of our productive wells in connection with our ongoing litigation. For us to maintain all of our CBM acreage rights beyond the primary terms of our lease and farm-out agreements, we will be required to significantly expand our drilling operations or renegotiate the terms of

these agreements. If we are unable to retain our CBM acreage rights, our growth potential will be negatively impacted, which could cause the value of your investment in us to decline.

We are currently subject to litigation with respect to the lease agreement covering the 43,000 acres of CBM rights at our Southern Illinois Basin Project, where currently all of our productive wells are located. The lease has a primary term that extended until April 3, 2006. After the primary term, the lease provides that it shall extend as to a particular tract so long as CBM is being produced from such tract providing a royalty payment of not less than $1.00 per acre per month; provided that, after the primary term, in the event the aggregate royalties do not exceed $42,000 in any month, the lease shall terminate. The litigation will determine whether we have satisfied these and related requirements to extend the lease. Although under these provisions of the lease agreement we believe the lease should extend at least as to certain acreage under the lease, it is possible that the court will not agree with our interpretation of these provisions. As a result, we could lose all of our acreage rights and productive wells at our Southern Illinois Basin Project. For more information about the litigation relating to our Southern Illinois Basin Project, see the section of the Summary entitled “Litigation Relating to Our CBM Rights at Our Southern Illinois Basin Project.” It is also possible that we will incur significant legal fees in pursuing this litigation and defending against the counterclaims.


	*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 77% 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 most of the agreements pursuant to which we hold 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. Approximately 77% of our acreage rights are subject to superior coal mining rights. 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 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.

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


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

We have been subject to legal complaints regarding the extent of the surface rights that derive from our CBM rights. On occasion, the owners of properties that are adjacent to our drilling locations have challenged our right to cross their property in accessing our drilling locations and our right to lay gas and water flow lines across their property. The extent of our rights in respect of these issues is uncertain in Illinois. If disputes regarding our surface rights are not resolved in our favor, we may be required to acquire surface rights or access our drilling locations and lay gas and water flow lines in inefficient ways, which would cause us to incur increased operating costs. In addition, we could incur significant costs in legal disputes over our surface rights. During our fiscal year ended July 31, 2005, we incurred approximately $303,000 in legal fees in connection with legal disputes over surface rights. We incurred approximately $7,500 in legal fees in connection with such disputes for the six-month period ended January 31, 2006. If for any reason these operating or legal costs increase significantly, our financial performance will suffer.


	*We have granted BHP Billiton a right of first refusal to acquire us, which could deter other potential acquirors from seeking to acquire us.*

In connection with the Technical Services Agreement that we entered into on March 31, 2005 with BHP Petroleum (Exploration) Inc., a wholly owned subsidiary of BHP Billiton, we granted BHP a right of first refusal to acquire us. Before we can extend or accept an offer for any third party to acquire a majority of our stock or assets, we must permit BHP to acquire the same stock or assets on the terms proposed to be extended to or accepted from the third party. The right of first refusal expires on September 30, 2006. We also agreed to issue BHP 4.0 million stock appreciation rights, which may be exercised by BHP only if it acquires us. The stock appreciation rights will have a value equal to the number of rights multiplied by the difference between the market price of our common stock on the date of exercise and the market price on March 31, 2005 (which was CAD$2.18 per share). We are required to issue BHP an additional 2.0 million stock appreciation rights if BHP elects to extend the term of the Technical Services Agreement for an additional six-month period. BHP’s right of first refusal and related stock appreciation rights may deter other potential acquirors from seeking to acquire us. A potential acquiror might decide that it does not wish to expend its time and resources reviewing and negotiating an acquisition with us if BHP can thwart the transaction by exercising its right of first refusal. If potential acquirors are deterred from considering an acquisition of us, we may not receive attractive acquisition offers, which might have a negative effect on the value of your investment in us.


	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, 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 (the “Exchange Act”). 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.

Risks Relating to this Offering


	*You will experience dilution of your ownership interest if we issue additional equity in the future.*

We are authorized to issue 200,000,000 shares of common stock. As of May 1, 2006, 70,812,540 shares of our common stock are issued and outstanding, 5,311,600 shares of our common stock are issuable upon exercise of warrants held by third parties, and 1,872,812 shares of our common stock are issuable upon exercise of options held by our officers, directors, employees and others. We expect that we may issue additional shares of our capital stock in the future to raise funds in support of our operations. We may also issue additional shares of capital stock in connection with hiring personnel, joint venture arrangements or other

strategic transactions. The issuance of any such shares of capital stock in the future will dilute your ownership interest in the company.


	*There is no significant market for our common stock, which could prevent you from selling your common stock at acceptable prices or at all.*

Our common stock is currently traded on the American Stock Exchange. There is not a substantial amount of trading in our common stock 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 stock is limited and is likely to remain limited in the near future, you may not be able to sell your common stock 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 (a) a company’s financial condition and/or operating results; (b) 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; or (c) 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.


	*The trading price of our common stock may be volatile, and resales under this prospectus may impact prices and liquidity.*

The trading price of our common stock has fluctuated widely and in the future may be subject to similar fluctuations. The trading price may be affected by a number of factors, including the risk factors described in this prospectus, developments in our prospects, our future results of operations and our future financial condition. In addition, the sale of a substantial number of shares of our common stock under this prospectus may depress share prices. In recent years, broad stock market indices, in general, and smaller capitalization companies, in particular, have experienced substantial price fluctuations. In a volatile market, we may experience wide fluctuations in the market price of our common stock, and this could adversely impact your investment in us.

Cautionary Note Regarding Forward-Looking Statements

Some of the statements contained in this prospectus, including statements containing the words “believes,” “anticipates,” “expects,” “intends,” “plans,” “should,” “may,” “might,” “continue” and “estimate” and similar words, constitute forward-looking statements under the federal securities laws. 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 following:


	•	failure to accurately forecast operating and capital expenditures and capital needs due to rising costs or different drilling or production conditions in the field;

	•	the inability to attract or retain qualified personnel with the requisite CBM or other experience;

	•	unexpected economic and market conditions, in the general economy or the market for natural gas; and

	•	the other factors discussed in this prospectus under the heading “Risk Factors” and elsewhere.

Given these uncertainties, you should not place undue reliance on such forward-looking statements. The forward-looking statements in this prospectus speak only as of the date of this prospectus. You should assume that the information contained in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations or prospects may have changed since that date. Neither the delivery of this prospectus nor the resale of our common stock means that information contained in this prospectus is correct after the date of this prospectus. 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 prospectus, whether as a result of new information, future events, changed circumstances or any other reason after the date of this prospectus.

You should rely only on the information contained in this prospectus. We have not authorized any other person to provide you with information that is different from or in addition to that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it.

Use of Proceeds

We will not receive any proceeds from sales of our common stock by the selling shareholders pursuant to this prospectus.

Market for Our Common Stock

Our common stock is currently traded on the American Stock Exchange under the symbol “BPG.” Prior to December 13, 2005, our common stock was 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 2004 and 2005 fiscal years and the first three quarters of our current fiscal year. 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. The last sales price reported on the American Stock Exchange on May 1, 2006 was $1.46.


		High		Low

Fiscal Year Ended July 31, 2004
	Quarter ended October 31, 2003	$	0.80	$	0.47
	Quarter ended January 31, 2004		0.79		0.48
	Quarter ended April 30, 2004		0.72		0.51
	Quarter ended July 31, 2004		0.66		0.47
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		3.60		1.20

As of May 1, 2006, we had 70,812,540 shares of our common stock outstanding, which were held by approximately 900 shareholders of record. The transfer agent and registrar for our common stock is Pacific Corporate Trust, Vancouver, British Columbia. In addition to our outstanding shares of common stock, as of May 1, 2006, we have reserved 1,872,812 shares of our common stock for issuance upon the exercise of outstanding stock options and 5,311,600 shares of our common stock for issuance upon the exercise of outstanding warrants.

Our outstanding shares of common stock may not be sold in the United States other than in compliance with the registration requirements of the Securities Act of 1933 (the “Securities Act”) or pursuant to Rule 144 or another exemption from such registration requirements.

Dividend Policy

We have not paid any cash dividends to date, and currently have no intention of paying any cash dividends on our common stock 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.

Capitalization

The following table sets forth our cash and cash equivalents and our capitalization as of January 31, 2006.


				As of
				January 31,
				2006

Cash and cash equivalents				$	26,623,707

Capitalization:
Long-term notes payable(1)					333,839
Shareholders’ equity:
	Common stock, no par value, 100,000,000 shares authorized, of which 64,378,087 shares issued and outstanding (actual)				64,573,394
	Paid-in capital				4,891,266
	Accumulated deficit				(20,404,770	)

		Total shareholders’ equity			49,059,890
			Total capitalization	$	49,393,729


(1)	Long-term notes payable (including current portion) consists of notes used to finance vehicles and equipment. The notes are secured by the underlying vehicles and equipment.

On September 26, 2005, we completed a private placement of the common stock covered by this prospectus to the selling shareholders. We issued 18,000,000 shares of our common stock at a per share price of CAD$2.00 (approximately USD$1.69), resulting in gross proceeds to us of approximately $30.5 million. After the payment of fees and expenses, the net proceeds to us from the private placement was approximately $28.0 million.

Our capitalization may change significantly in the near future, as we fund our plan of operations and if we issue additional shares of capital stock or incur indebtedness to fund our future plans of operations. See the section of this prospectus entitled “Business — Plan of Operations for the 12-Month Period Ending April 30, 2007.”

Selected Historical Financial Data

The following sets forth our selected historical financial data as of July 31, 2005, 2004, 2003, 2002 and 2001 and for our five fiscal years then ended, which has been derived from our financial statements for those years, and as of January 31, 2006 and for the six months ended January 31, 2006 and 2005, which were derived from our unaudited financial statements for those periods. Our financial statements as of July 31, 2005 and for our fiscal year ended July 31, 2005 and related notes thereto have been audited by Meaden & Moore, Ltd., an independent registered public accounting firm. Our financial statements as of July 31, 2004 and 2003 and for our fiscal years ended July 31, 2004, 2003 and 2002 and related notes thereto have been audited by De Visser Gray, an independent registered public accounting firm. The unaudited financial statements as of January 31, 2006 and for the six months ended January 31, 2006 and 2005, in our opinion, have been prepared on the same basis as our audited financial statements, and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information.

The period-to-period comparability of the financial data shown below is materially affected by our acquisition of Methane Management, Inc. in August 2001 and our consolidation of 100% of the Southern Illinois Basin Project within BPI in connection with that acquisition.

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


	For the Six Months
	Ended January 31,						For the Year Ended July 31,

	2006			2005			2005			2004			2003			2002			2001

	(Unaudited)			(Unaudited)															(Unaudited)
Statement of Operations Data:
Gas sales(1)	$	537,505		$	6,341		$	117,835		$	0		$	0		$	0		$	0
Stock-based compensation expense		397,586			2,200,777			3,344,738			193,796			515,286			439,860			256,684
Loss before income taxes		(2,047,487	)		(3,218,907	)		(6,120,821	)		(1,091,227	)		(1,109,218	)		(1,245,853	)		(184,475	)
Net loss		(2,047,487	)		(2,874,190	)		(5,396,351	)		(793,116	)		(934,305	)		(1,129,209	)		(184,475	)
Net loss per common share		(0.04	)		(0.09	)		(0.14	)		(0.03	)		(0.04	)		(0.06	)		(0.01	)
Weighted average number of shares outstanding		57,889,094			32,018,325			37,665,019			25,007,237			21,485,381			18,300,433			14,588,122


	As of		As of July 31,
	January 31,
	2006		2005		2004		2003		2002		2001

	(Unaudited)										(Unaudited)
Balance Sheet Data:
Total assets	$	50,998,590	$	23,527,712	$	9,382,977	$	6,328,178	$	5,418,158	$	1,970,104
Long-term notes payable (including current maturities)		333,839		549,822		462,177		378,174		0		0
Cash dividends per common share		0		0		0		0		0		0


(1)	Gas sales commenced in January 2005. All of our productive wells existing as of May 1, 2006 are located at our Southern Illinois Basin Project. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of these productive wells.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations

The discussion and analysis that follows should be read together with the accompanying financial statements and notes related thereto that are included elsewhere in this prospectus.

Overview and Outlook

We are an independent energy company incorporated in British Columbia, Canada and primarily engaged, through our wholly owned U.S. subsidiary, BPI Energy, Inc., in the exploration for and development of coalbed methane (“CBM”). Our exploration and development 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 May 1, 2006, we owned or controlled CBM rights, through mineral leases, options to acquire mineral leases, and a farm-out agreement, covering 530,435 total acres in the Basin (including our 43,000 acre Southern Illinois Basin Project, where our acreage rights are currently subject to litigation). A substantial majority of the acreage under our control was undeveloped as of May 1, 2006.

Although we capitalize exploration costs, we have historically experienced significant losses. The primary costs that generated these losses were compensation-related expenses and general and administrative expenses. We commenced CBM sales from our first producing wells in January 2005, generating $117,835 in gas sales during the fiscal year ended July 31, 2005. During the six months ended January 31, 2006, we generated gas sales of $537,505. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of our productive wells existing as of May 1, 2006. During the fiscal year ended July 31, 2004 and for the preceding fiscal year we had no revenues. Our focus during those years was the acquisition of CBM rights and exploration for CBM in the Illinois Basin. Future revenues are primarily dependent on our ability to produce and sell CBM.

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 mineral rights.

Our capital expenditure budget for the 12-month period ending April 30, 2007 totals approximately $30.0 million. This anticipates drilling 115 vertical wells, three horizontal wells and five test wells throughout the Basin. In addition, this amount includes installing a gathering system and processing yard to handle the anticipated production from the wells that we plan to drill at our Northern Illinois Basin Project. Our current cash balance is insufficient to fully fund our forecasted capital expenditures and net cash used by operating activities over the 12-month period ending April 30, 2007. Although management has no specific agreements in place to raise the additional capital necessary to fund our plan of operations and forecasted capital expenditures, management plans to raise the additional required capital through a combination of additional stock sales, the issuance of debt securities, borrowing and/or entering into joint ventures. However, we can provide no assurance that we will be able to raise the additional required capital to meet our plan or if we are able to raise the funds that it will be on terms similar to past financings.

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, the extent of our rights under mineral leases as determined by further title investigation, 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 securing long-term service company commitments to insure availability of equipment and services; and



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

From early 2002 until 2005, our strategic focus was on building our acreage footprint in the Basin. BPI was 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 just over 530,000 acres in the Basin (including our 43,000 acre Southern Illinois Basin Project, where our acreage rights are currently subject to litigation) 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 new additional goals and we realize that we must build and add to our organization in other critical areas as well. These new goals require us to bring in additional capital, resources and people with the technical and managerial expertise to assist us in achieving these goals. These additional goals include the following:



	•	developing the in-house capabilities necessary to enable us to meet our regulatory and reporting obligations to various regulatory agencies, constituencies and our shareholders;



	•	raise the capital necessary to achieve our plans and goals; and



	•	transition BPI from a company focused primarily on the acquisition of mineral rights to a company focused on producing CBM.

We have registered our stock with the U.S. Securities and Exchange Commission and our stock is now listed on the American Stock Exchange. These developments brought with them new and additional regulatory and reporting obligations, which meant we needed the personnel and resources to meet these obligations. We began addressing this aspect of our business when we moved our corporate headquarters to the United States from Vancouver, B.C. and brought in our CFO and General Counsel, George Zilich, and our controller, Randy Elkins, early in 2005. We will continue to add resources as necessary to meet our obligations in this area.

In September 2005 we sold 18,000,000 shares of our common stock to a limited number of institutional investors and brought in approximately $28 million of new capital.

We have stopped drilling new wells at our Southern Illinois Basin Project due to a dispute with our lessors and the coal owners. We have initiated a lawsuit in federal court in order to preserve our rights under the lease covering our Southern Illinois Basin Project. For more information about the litigation relating to our Southern Illinois Basin Project, see the section of the Summary entitled “Litigation Relating to Our CBM Rights at Our Southern Illinois Basin Project.” As of May 1, 2006, we had 77 wells that were in production, 17 shut-in wells and 13 wells that were drilled but not yet in production. All of our productive wells are on our Southern Illinois Basin Project.

In April 2006, we began our second development front by beginning drilling on 10 pilot development wells 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. The coal seams at our Northern Illinois Basin Project are some of the thickest found in the Basin, with some seams as thick as 10 feet. We believe there are up to nine seams that could be commercially viable.

Until recently, we have had limited in-house CBM operating and engineering resources. As a result, in the initial stages of our drilling and production activities, we have utilized outside contractors to perform most of these activities. We have focused on increasing our internal engineering and operating resources as a

primary goal of BPI over the coming years. In April 2006, we hired James Craddock as our Senior Vice President of Operations. Mr. Craddock is an engineer with extensive experience in CBM drilling and operations. We are continuing our efforts to add to our operating team individuals with the technical skills we believe are necessary to help BPI become a world class CBM drilling and production company. This will take time, but we believe it is necessary in order to realize the value of the CBM assets we have assembled.

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

Unevaluated 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. Unevaluated properties are assessed at least annually to ascertain whether an impairment occurs. 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 a 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 a 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 and employees as determined by the Board of Directors and subject to the provisions of the Incentive Stock Option Plan. We recognized compensation expense under the Incentive Stock Option Plan in accordance with the fair value provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation,” which permits the recognition of expense for stock-based compensation based on the fair value of the stock option on the measurement date.

The fair value of stock options granted under the Incentive Stock Option Plan was estimated using the Black-Scholes Option Pricing Model. Option pricing models require the input of highly subjective assumptions, particularly as to the expected price volatility of our stock. Changes in these assumptions can materially affect the fair value estimate, and therefore it is our view that the existing models do not necessarily provide a single reliable measure of the fair value of our stock option grants.

The Incentive Stock Option Plan permitted options to be issued with exercise prices at a discount to the market price of our common stock 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 BPI Energy Holdings, Inc. 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 will be 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.

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 No. 123, companies had the option of either recording expense based on the fair value of stock options granted or continuing to account for stock-based compensation using the intrinsic value method prescribed by APB 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 subsequent to the adoption of SFAS No. 123(R). Therefore, SFAS No. 123(R) had no impact on our consolidated financial position or results of operations for the quarter and six months ended January 31, 2006. No stock options have been issued under the Omnibus Stock Plan.


	*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. 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 there have historically been no income generating operations in Canada. We have recorded tax benefits in the United States for our fiscal years ending July 31, 2005, 2004 and 2003. These benefits partially offset a previously recorded deferred tax liability.

Results of Operations

Six Months Ended January 31, 2006 Compared to Six Months Ended January 31, 2005

The following table presents our unaudited financial data for the first six months of fiscal year 2006 compared to the first six months of fiscal year 2005:


	Six Months Ended January 31
							Dollar			%
	2006			2005			Variance			Change

Revenues:
Gas sales	$	537,505		$	6,341		$	531,164			8,377	%
Expenses:
Lease operating expense		461,610			—			461,610			100	%
General and administrative expense		2,437,239			3,165,087			(727,848	)		(23	)%
Depreciation, depletion and amortization		212,692			57,562			155,130			270	%

		3,111,541			3,222,649			(111,108	)		(3	)%
Other income (expenses):
Interest income		402,804			4,847			397,957			8,210	%
Interest expense		(13,778	)		(10,582	)		(3,196	)		(30	)%
Other income		137,523			3,246			134,277			4,137	%

		526,549			(2,489	)		529,038			n/a
Loss before income taxes		(2,047,487	)		(3,218,797	)		1,171,310			36	%
Deferred income tax benefit		—			344,717			(344,717	)		(100	)%

Net loss	$	(2,047,487	)	$	(2,874,080	)	$	826,593			29	%

Revenue — During the first six months of fiscal year 2006, revenue increased $531,164 over the first six months of fiscal year 2005. We realized our first revenues from the sale of CBM in January 2005. Net sales of gas (net of royalties) were 47,462 Mcf and our average realized selling price per Mcf was $11.32 for the first six months of fiscal year 2006. All of our productive wells during these periods are located at our Southern Illinois Basin Project. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of these wells.

Lease operating expense — During the first six months of fiscal year 2006, lease operating expense increased $461,610 over the first six months of 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. We commenced production toward the end of January 2005 and, thus, incurred no lease operating expense during the first six months of fiscal year 2005.

General and administrative expense — General and administrative expense consisted of the following for the first six months of fiscal year 2006 and 2005, respectively:


	Six Months Ended
	January 31
					Dollar			%
	2006		2005		Variance			Change

Salaries and benefits	$	727,240	$	410,249	$	316,991			77	%
Stock-based compensation		397,586		2,200,777		(1,803,191	)		(82	)%
Professional fees		858,002		240,125		617,877			257	%
Other		454,411		313,936		140,475			45	%

Total general and administrative expense	$	2,437,239	$	3,165,087	$	(727,848	)		(23	)%

During the first six months of fiscal year 2006, salaries and benefits increased $316,991 over the first six months of fiscal year 2005. The increase was primarily the result of hiring additional personnel to support our growth, including both a chief financial officer and controller.

During the first six months of fiscal year 2006, stock-based compensation decreased $1,803,191 over the first six months of fiscal year 2005. During the first six months of fiscal year 2006, we granted options to purchase 495,000 shares of our common stock that were valued at $.80 per option. During the first six months of fiscal year 2005, we granted options to purchase 2,950,056 shares of our common stock that were valued at $.75 per option. 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.

During the first six months of fiscal year 2006, professional fees increased $617,877 over the first six months of fiscal year 2005. The increase was primarily the result of increased professional fees incurred in connection with SEC filings, American Stock Exchange listing fees, higher audit and audit related fees and additional legal services.

During the first six months of fiscal year 2006, other general and administrative expenses increased $140,475 over the first six months of fiscal year 2005, primarily as a result of increased insurance costs.

Depreciation, depletion and amortization expense — During the first six months of fiscal year 2006, depreciation, depletion and amortization expense (“DD&A”) increased $155,130 over the first six months of fiscal year 2005. We compute DD&A on capitalized drillings 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 3 to 10 years. The increase is primarily due to the fact that there was very little production in the first six months of fiscal year 2005. Additionally, depreciation expense increased due to additions to other support equipment.

Interest income — During the first six months of fiscal year 2006, interest income increased $397,957 over the first six months of fiscal year 2005 due to significantly higher average cash balances during the first six months of fiscal year 2006. The higher cash balances are the result of net proceeds of $27,883,954 we received in September 2005 related to the private placement of our common shares.

Other income — During the first six months of fiscal year 2006, other income increased $134,277 over the first six months of fiscal year 2005, primarily due to us recognizing a gain of $127,416 on the sale of our investment in Hite Coalbed Methane, L.L.C. in January 2006.

Deferred income tax benefit — During the first six months of fiscal year 2006, deferred income tax benefit decreased $344,717 over the first six months of fiscal year 2005. We recorded a tax benefit in the United States in the first six months of fiscal year 2005 to partially offset a net recorded deferred tax liability at January 31, 2005; however, no tax benefit was recognized for the first six months of 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*


		For the Fiscal Year Ended

		July 31,			July 31,			Dollar			Percentage
		2005			2004			Variance			Change

Gas sales		$	117,835		$	—		$	117,835			100	%
Lease operating expenses			307,178			—			307,178			100	%
Salaries and benefits:
	Corporate		516,961			262,223			254,738			97	%
	Field administration		261,692			112,408			149,284			133	%
	Field operations		115,488			44,070			71,418			162	%

			894,141			418,701			475,440			114	%
Stock-based compensation			3,344,738			193,796			3,150,942			1626	%
General and administrative:
	Travel		161,371			139,273			22,098			16	%
	Office		266,875			146,969			119,906			82	%
	Professional and regulatory		1,137,996			98,458			1,039,538			1056	%
	Other		—			2,910			(2,910	)		(100	)%

			1,566,242			387,610			1,178,632			304	%
Depreciation, depletion and amortization			260,141			80,417			179,724			223	%
Other income (expense):
	Interest income		123,219			2,008			121,211			6036	%
	Interest expense		(24,820	)		(15,165	)		(9,655	)		(64	)%
	Other expense, net		35,385			2,454			32,931			1342	%

			133,784			(10,703	)		144,487			1350	%
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	)%

Loss before income taxes. We incurred a loss before income taxes of ($6,120,821) for the year ended July 31, 2005, compared to a loss before income taxes of ($1,091,227) for the preceding year. The largest factors in this 461% increase in net loss related to increases in salaries and benefits, stock-based compensation and general and administrative expenses as discussed below.

Revenue. We realized our first revenues from the sale of CBM in January 2005. Sales of CBM generated revenues of $117,835 during the year ended July 31, 2005 (all in the period of January through July 2005) compared to $0 sales during the preceding year. All of our productive wells during the fiscal year ended July 31, 2005 are located at our Southern Illinois Basin Project. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of these wells.

Salaries and benefits. Salaries and benefits increased $475,440 in the year ended July 31, 2005, a 114% increase over the preceding year. The increase was primarily the result of bonuses paid to various employees, hiring both a vice president of field operations and a chief financial officer, and general salary increases.

Stock-based compensation. Stock-based compensation increased $3,150,942 in the year ended July 31, 2005, an increase of 1626% over the preceding year. The increase in this expense 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 the year ended July 31, 2005, we granted options to purchase 4,276,056 shares of our common stock that were valued at $3,344,738. This compares with the options to purchase 475,000 shares of

our common stock that were granted during the preceding year 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.

General and administrative — office expense. The 82% increase over the comparable expenses during the preceding year resulted primarily from costs incurred in opening our headquarters office in Solon, Ohio.

General and administrative — professional and regulatory fees. The 1056% increase over the comparable expenses during the preceding year resulted from the following expense increases:


• 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
• Increase in other professional fees		75,341

• Total increase over corresponding period in the preceding year	$	1,039,538

Deferred income tax benefit. The 143% increase in the deferred income tax benefit over the preceding year 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 the period as compared to 27.3% for the preceding year. 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.

Year Ended July 31, 2004 Compared to Year Ended July 31, 2003


		For the Fiscal Year Ended

		July 31,			July 31,			Dollar			Percentage
		2004			2003			Variance			Change

Gas sales		$	—		$	—		$	—			0	%
Salaries and benefits:
	Corporate		262,223			220,198			42,025			19	%
	Field administration		112,408			68,704			43,704			64	%
	Field operations		44,070			16,890			27,180			161	%

			418,701			305,792			112,909			37	%
Stock-based compensation			193,796			515,286			(321,490	)		(62	)%
General and administrative:
	Travel		139,273			79,975			59,298			74	%
	Office		146,969			68,814			78,155			114	%
	Professional and regulatory		98,458			60,296			38,162			63	%
	Other		2,910			6,240			(3,330	)		(53	)%

			387,610			215,325			172,285			80	%
Depreciation, depletion and amortization			80,417			58,593			21,824			37	%
Other income (expense):
	Interest income		2,008			3,550			(1,542	)		(43	)%
	Interest expense		(15,165	)		(17,772	)		2,607			15	%
	Other expense, net		2,454			—			2,454			100	%

			(10,703	)		(14,222	)		3,519			25	%
Loss before income taxes		$	(1,091,227	)	$	(1,109,218	)	$	17,991			2	%
Deferred income tax benefit			298,111			174,913			123,198			70	%

Net loss		$	(793,116	)	$	(934,305	)	$	141,189			15	%

Loss before income taxes. Loss before income taxes decreased $17,991, or 2%, from the year ended July 31, 2003 to the year ended July 31, 2004. We incurred a loss before income taxes of ($1,091,227) for the year ended July 31, 2004, compared to a loss before income taxes of ($1,109,218) for the preceding year. The principal factor in the reduced loss was a $321,490 decrease in stock-based compensation expense. That decrease was partially offset by increases in salaries and benefits along with general and administrative expenses, which corresponded to an increase in the size of our CBM projects in the Illinois Basin.

Deferred income tax benefit. The 70% increase over the comparable deferred income tax benefit for the preceding year resulted primarily from the decrease in stock-based compensation expense, which is non-deductible for U.S. tax purposes. This reduction in stock-based compensation expense caused the effective tax rate for the year ended July 31, 2004 to increase to 27.3% as compared to 15.8% for the preceding year. Applying this higher effective tax rate to our loss before income taxes resulted in an increased deferred tax benefit.

Liquidity and Capital Resources

Our primary source of liquidity historically has come from the sale of shares of our common stock in private placements and the proceeds from the exercise of warrants and options to acquire our common stock. To date, we have not relied significantly on borrowing to finance our operations or provide cash. As of January 31, 2006, we had only $333,839 in long-term notes payable. From July 31, 2002 until January 31, 2006, we raised $43,866,649 from the sale of our common stock. Additionally, during that same period, we collected $3,730,470 and $2,118,320 as a result of the exercise of warrants and stock options, respectively. 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 $537,505 and $6,341 for the six months ended January 31, 2006 and 2005, respectively. Subject to the various risks described in this report, 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 and production from additional wells. However, in view of the fact that we have very little historical experience of dewatering and gas production in the Illinois Basin, we can provide no assurance that we will achieve a trend of increased production and revenue in the future. In addition, since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of our productive wells existing as of May 1, 2006.

In addition, CBM wells typically must go through a lengthy dewatering phase before making a significant contribution to gas production. We estimate that a typical vertical well will require an average of 18 months to reach peak production. (Note that when we talk about average dewatering times, the early wells at any of our projects are expected to take longer to dewater than are later wells that are drilled and tied into our gathering system after a field or area has been undergoing dewatering by previously drilled wells). The impact on our cash position is that there will be a delay of up to 18 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 significant contribution to our cash from operations. Additionally, net cash generated (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 equipment;



	•	lease terms;



	•	availability of sufficient capital resources; and



	•	the accuracy of production estimates for current and future wells.

We had a cash balance of approximately $25.0 million as of May 1, 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 common stock in a private placement that closed on September 26, 2005. 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 slowed due to a dispute and subsequent litigation with the lessors and coal owners, we have not yet spent the majority of the cash raised in this most recent private placement.

Our capital expenditure budget for the 12-month period ending April 30, 2007, totals approximately $30.0 million. Our current cash balance is insufficient to fully fund our forecasted capital expenditures and net cash used by operating activities over the 12-month period ending April 30, 2007. 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 is evaluating raising the additional required capital through a combination of additional stock sales, the issuance of debt securities, borrowing and/or entering into joint ventures. However, we can provide no assurance that we will be able to raise the additional required capital to meet our plan or if we are able to raise the funds that it will be on terms similar to past financings.

Cash Used in Operating Activities

Net cash used in operating activities for the year ended July 31, 2005 was $877,171. This compares with $591,167 net cash used in operating activities in the prior year. The increase in net cash used by operating activities corresponds with the growth in the size of our projects in the Illinois Basin. Net cash used in operating activities for the year ended July 31, 2003 was $709,333. Since July 31, 2002, we have substantially increased the amount of CBM rights we control in the Illinois Basin. This has resulted in increases in personnel and operating activities conducted by us. Since we did not generate any CBM revenues until January 2005, the costs associated with the additional personnel and activities resulted in year-to-year increases in net cash used in operations. The decrease in net cash used in operating activities between the year ended July 31, 2003 and the year ended July 31, 2004 was the result of timing of our accounts payable and is not indicative of any trend.

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 equipment;


	•	lease terms;


	•	availability of sufficient capital resources; and

	•	the accuracy of production estimates for current and future wells.

Capital Expenditure Plan

We have no contractual commitments for capital expenditures. However, our plan anticipates that over the 12-month period ending April 30, 2007, we will spend approximately $30.0 million on capital expenditures. We plan to drill 123 new wells during that period, including 115 new vertical production wells, three horizontal wells and five new test wells. In addition to our drilling program, we expect to pursue the acquisition of additional CBM rights during that 12-month period. We expect that this capital expenditure program and our other cash requirements will be funded by our cash balance, which as of May 1, 2006 is approximately $25.0 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.

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.

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, 2005
Long-term debt		$	26,624	$	50,075	$	15,158	$	0	$	91,857
Equipment leases			69,063		165,760		13,813		0		248,626
Other leases(1)			6,000		12,730		13,763		146,171		178,669
Long-term notes payable(2)			—		—		392,000		—		392,000

	Total	$	101,687	$	228,555	$	434,739	$	146,171	$	911,152


(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 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 November 1, 2005 expire at various times beginning in April 2006. If we were to pay the total minimum royalty payments due under all mineral leases/farm-out agreements in existence as of November 1, 2005, the amount would initially total approximately $702,000 annually and could increase to as much as $831,000 annually.


(2)	The long-term note payable was cancelled in connection with our sale of our interest in Hite Coalbed Methane, L.L.C. on January 4, 2006.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of July 31, 2005.

Business

Coalbed Methane


	•	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.

Overview

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, we have assembled CBM rights covering 530,435 acres in the Illinois Basin (including our 43,000 acre Southern Illinois Basin Project, where our acreage rights are currently subject to litigation). We believe that these rights currently give us control over more CBM acreage than any other CBM company in the Illinois Basin.

and we may therefore not retain any of these acreage rights. Our other acreage holdings include our Northern Illinois Basin Project (formerly called our Montgomery Project), located in the north central part of the Illinois Basin, where we control through lease, option and farm-out agreements an aggregate of 351,487 acres of CBM rights, and the Western Illinois Basin Project (formerly called our Clinton/ Washington 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.

On March 31, 2005, we entered into a Technical Services Agreement with BHP Petroleum (Exploration) Inc., a wholly owned subsidiary of BHP Billiton, a major international resources company. As part of this agreement, BHP agreed to provide us, on an exclusive basis in the Illinois Basin, technical services related to BHP’s techniques and know how in the areas of drilling and completion of CBM wells. BHP agreed to provide its medium radius drilling (MRD) techniques to assist BPI in drilling three initial pilot wells and to provide an assessment of the application of its tight radius drilling (TRD) technology at our projects. For more information about our Technical Services Agreement with BHP, see the section below entitled “Technical Services Agreement with BHP Billiton.”

History

Business Strategy


	•	Explore and Develop Properties. As of May 1, 2006, we have drilled 107 wells. These wells consist of 77 productive wells, 17 shut-in wells and 13 wells that have been drilled but are not in production, including three test wells. All of our productive wells are located at our Southern Illinois Basin Project. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of our productive wells existing as of May 1, 2006.


	Due to the litigation with respect to our Southern Illinois Basin Project, we are not drilling any new wells at our Southern Illinois Basin Project and have moved the focus of our drilling activities to our

Northern Illinois Basin Project. During April 2006, we filed permit applications for drilling the first 10 CBM production wells at our Northern Illinois Basin Project.

During the 12-month period ending April 30, 2007, we plan to drill 123 new wells, including 115 vertical wells, three horizontal wells and five test wells. This plan contemplates a capital expenditure budget of approximately $30.0 million. Our cash balance as of May 1, 2006 is approximately $25.0 million and therefore not sufficient to fully fund these capital expenditures and our anticipated cash needs through April 30, 2007. In order to fully fund our operations through April 30, 2007, we will need to raise additional financing.

The number of wells that we drill during the 12-month period ending April 30, 2007 will be dependant on the success of our initial production wells at our Northern Illinois Basin Project, the additional capital that we are able to raise and the risk factors described in this prospectus.



	•	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 the coal seams are the thickest 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 high potential CBM areas in North America. We were the first company to begin acquiring substantial blocks of CBM acreage rights in the Illinois Basin. We believe that we currently control more CBM acreage than any other CBM company in the Illinois Basin.


	•	Demonstrated Commercial Production. We believe that we have taken the initial steps to demonstrate the commercial production capabilities of the Illinois Basin. As of May 1, 2006, we have drilled 107 wells, including 77 productive wells located at our Southern Illinois Basin Project, most of which have not yet reached peak production. For the six months ended January 31, 2006, our gas sales totaled $537,505. Although it is possible that we may lose our productive wells at our Southern Illinois Basin Project due to ongoing litigation, we believe that our production at the Southern Illinois Basin Project demonstrates the commercial viability of the Illinois Basin.



	•	Short Drilling Permit Lead Times. We typically experience short turnaround times in obtaining drilling permits as compared to CBM drillers in other CBM basins. Historically, we have enjoyed quick turnaround of vertical CBM well drilling permits from state regulatory bodies. We have not yet submitted any permit applications for drilling horizontal wells. However, we do not anticipate any significant delays in obtaining permits for these wells.



	•	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 been drilling or operating CBM wells in the Illinois Basin since 1996. In addition, James G. Azlein, our President and Chief Executive Officer, George J. Zilich, our Chief Financial Officer and General Counsel, and James E. Craddock, our Senior Vice President of Operations, beneficially own 6.97% of our common stock. In addition, the majority of BPI’s management and operating employees owns common stock and/or stock options in the company.

CBM Acreage Rights

As of May 1, 2006, our CBM acreage rights, controlled through lease, option and farm-out agreements, include the following:


	Developed		Undeveloped		Total
Project	Acres		Acres		Acres(1)

Southern Illinois Basin Project(2)		10,550		32,450		43,000
Northern Illinois Basin Project		0		351,487		351,487
Western Illinois Basin Project		0		135,948		135,948

Total		10,550		519,885		530,435


(1)	Because we are the exclusive owner of the CBM rights under each of our lease, option and farm-out agreements, our acreage rights are shown on a gross (as opposed to net) basis.


(2)	In connection with ongoing litigation relating to our Southern Illinois Basin Project, it is possible that we will lose all of our acreage rights at this Project. For more information about the litigation relating to our Southern Illinois Basin Project, see the section of the Summary entitled “Litigation Relating to Our CBM Rights at Our Southern Illinois Basin Project.”

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. We incurred approximately $7,500 in legal fees in connection with such disputes for the six-month period ended January 31, 2006. 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 (formerly called our Delta Project) cover 43,000 acres in the southern part of the Illinois Basin. We hold our CBM rights on this acreage pursuant to a lease agreement the primary term of which extended until April 3, 2006. After the primary term, the lease provides that it shall extend as to a particular tract so long as CBM is being produced from such tract providing a royalty payment of not less than $1.00 per acre per month; provided that, after the primary term, in the event the aggregate royalties do not exceed $42,000 in any month, the lease shall terminate.

Our right to drill for and produce CBM under this lease is expressly subject to the mining of coal on the acreage covered by the lease. 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.

We are required to pay the lessor a royalty equal to 15% of our gross proceeds from the sale of CBM produced from the covered acreage. In addition, the lease is subject to two overriding royalty interests of 3% and 4%, both of which are calculated based on 43.35% of gross revenues.

As of May 1, 2006, we have 77 productive wells, 17 shut-in wells and eight wells that have been drilled but are not in production at our Southern Illinois Basin Project. In connection with ongoing litigation relating to our Southern Illinois Basin Project, it is possible that we will lose all of our acreage rights and wells at this Project. For more information about the litigation relating to our Southern Illinois Basin Project, see the section of the Summary entitled “Litigation Relating to Our CBM Rights at Our Southern Illinois Basin Project.”


	*Northern Illinois Basin Project*

Our CBM rights in the Northern Illinois Basin Project (formerly called our Montgomery 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 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 approximately 100,000 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 commercially reasonable quantities sufficient to yield a return in excess of operating costs. 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 6.25% until May 1, 2011 and thereafter at a rate between 6.25% to 12.5%, depending on the price we receive for CBM at the time.

We have also entered into a lease agreement with Christian Coal Holdings, LLC covering approximately 12,000 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 commercially reasonable quantities sufficient to yield a return in excess of operating costs. 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. 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 $7,016.50 for each one-year period that we delay commencing exploration. Any payment of advance royalties can be credited against royalties that may later become payable to the lessor from our production of CBM.

Under the lease agreements with 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 is 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.

Due to the litigation with respect to our Southern Illinois Basin Project, we are not drilling any new wells at our Southern Illinois Basin Project and have moved the focus of our drilling activities to our Northern Illinois Basin Project. During April 2006, we filed permit applications for drilling the first 10 CBM production wells at our Northern Illinois Basin Project.


	*Western Illinois Basin Project*

Our CBM rights in the Western Illinois Basin Project (formerly called our Clinton/Washington 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 a mineral lease, options to acquire mineral leases and a farm-out agreement.

We have entered into a lease agreement with Clinton County covering 55,900 acres of CBM rights in Clinton County, Illinois. The lease agreement extends until October 24, 2010. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. 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. 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 $27,950 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.

We also hold an option from Washington County to lease 39,169 acres of CBM rights in Washington County, Illinois. The option extends until September 9, 2006. 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, with each productive vertical well holding 320 acres and each productive horizontal well holding 1,920 acres. Under the lease agreement, we will be required to pay royalties to the lessor from our gross proceeds from the sale of CBM produced from the covered acreage. The royalty will be equal to 12.5% or 6.25% of our 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. 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 $18,084.50 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.

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

Also included in the Western Illinois Basin Project is 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 May 1, 2006, we have not yet undertaken any testing or development activities on the Western Illinois Basin Project.


	*Farm-out Agreement with Addington Exploration, LLC*

We have entered into a farm-out agreement with Addington Exploration, LLC covering 41,253 acres of CBM rights in Macoupin County, Illinois 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*



	•	BHP agreed to support us in connection with BPI’s drilling of three initial pilot wells utilizing BHP’s medium radius drilling (MRD) techniques and the appraisal and subsequent development and production of these wells; and



	•	BHP agreed to provide an assessment of its tight radius drilling (TRD) technology at our projects, and to provide a field test of the TRD technology at our projects at such time as BHP is satisfied that its TRD technology is commercially and technically viable.

If BHP becomes satisfied that its TRD technology is commercially and technically viable, BHP is required to offer us a right of first refusal to use its TRD technology at our projects on mutually acceptable terms during the term of the Technical Services Agreement and any extension of the term.

As of May 1, 2006, due to the dispute with our lessor at our Southern Illinois Basin Project, we have not yet drilled any MRD pilot wells but are in the process of identifying sites to drill these wells. In addition, as of May 1, 2006, BHP has not completed an assessment of its TRD technology at any of our projects.

BHP’s MRD techniques are refinements to the horizontal drilling techniques that are currently being used in North America. We believe BHP has demonstrated that MRD drilling techniques provide for a more cost effective approach to the production of CBM than many of the current horizontal drilling and standard vertical drilling techniques used in North America.

TRD technology would be utilized in the drilling and completion of vertical wells. TRD, if it proves technically and commercially viable, would drain more acreage than a traditional fractured vertical well, resulting in lower total capital costs and less surface disruption in draining a CBM reservoir.

During the term of the Technical Services Agreement, any extension of the term and the six-month period after the expiration of the term, none of BHP or any of its affiliates may enter into any agreement to provide technical assistance to a CBM operator within the Illinois Basin or acquire a direct or indirect interest in any CBM assets located in the Illinois Basin without our prior consent. However, BHP can terminate the Technical Services Agreement and these exclusivity restrictions if it acquires an equity interest in any company that holds mineral rights in the Illinois Basin, so long as such mineral rights do not constitute a majority of the economic value of the subject company.

In connection with the Technical Services Agreement, we have granted BHP a right of first refusal to acquire us. Before we can extend or accept an offer for any third party to acquire a majority of our stock or assets, we must permit BHP to acquire the same stock or assets on the terms proposed to be extended to or accepted from the third party. The right of first refusal expires on September 30, 2006.

In consideration for BHP entering into the Technical Services Agreement, we agreed to issue BHP 4.0 million stock appreciation rights. The stock appreciation rights, which may be exercised by BHP only in connection with its acquisition of us, will have a value equal to the number of stock appreciation rights multiplied by the difference between the market price of our common stock on the date of exercise and the market price on March 31, 2005 (which was CAD $2.18 per share). BHP may exercise the stock appreciation rights only during the term of the Technical Services Agreement, any extension of the term and the six-month period after the expiration of the term. In connection with the exercise of the stock appreciation rights, BHP may elect to convert the rights into cash or a credit against the consideration payable by BHP in connection with its acquisition of us. The stock appreciation rights will terminate if BHP materially breaches the Technical Services Agreement or we are sold to a third party or a majority of our stock or assets is acquired by a third party. We are required to issue BHP an additional 2.0 million stock appreciation rights upon the commencement of the first six-month extension of the term of the Technical Services Agreement.

The term of the Technical Services Agreement extends until September 30, 2006, and BHP may elect to extend the term of the agreement for additional six-month periods. BHP may terminate the agreement at any time upon 90 days notice to us, and we may terminate the agreement if BHP materially breaches the agreement. If BHP elects to terminate the agreement, its stock appreciation rights and right of first refusal will immediately expire. The agreement terminates if we are sold to a third party or a majority of our stock or assets is acquired by a third party.

Plan of Operations for the 12-Month Period Ending April 30, 2007


	*General and Administrative Operations*

We moved our corporate headquarters from Vancouver, British Columbia to Solon, Ohio in early 2005. We have added administrative, accounting and legal personnel to our staff to handle the increased responsibilities brought about by the growth of our Illinois Basin projects and our additional SEC and American Stock Exchange reporting obligations. Additionally, we expect our overall general and administrative activities and expenses will continue to increase as we drill additional wells and grow our projects in the Illinois Basin.


	*Status of CBM Operations*

The following table summarizes the status of wells we have drilled as of May 1, 2006:


			Wells Drilled
	Productive		but not yet in		Shut-in		Test		Total
Project	Wells		Production		Wells		Wells		Wells

Southern Illinois Basin Project(1)		77		8		17		0		102
Northern Illinois Basin Project		0		2		0		3		5
Western Illinois Basin Project		0		0		0		0		0

Total		77		10		17		3		107


(1)	In connection with ongoing litigation relating to our Southern Illinois Basin Project, it is possible that we will lose all of our wells at this Project. For more information about the litigation relating to our Southern Illinois Basin Project, see the section of the Summary entitled “Litigation Relating to Our CBM Rights at Our Southern Illinois Basin Project.”

As of May 1, 2006, all of the wells that we have drilled are vertical wells. We estimate that a typical vertical well will require an average of 18 months to reach peak production. (Note that when we talk about average dewatering times, the early wells at any of our projects are expected to take longer to dewater than are later wells that are drilled and tied into our gathering system after a field or area has been undergoing dewatering by previously drilled wells). We began selling gas from our first productive wells in January 2005. As of May 1, 2006, most of our productive wells have not yet reached peak production. Although we have drilled wells on only a relatively small part of our projects, we have not to date determined that any well we have drilled is a dry hole.


	*Production*

The following table sets forth BPI’s net sales volume for the periods indicated.

Twelve Months Ended July 31,

2005 (1) (2)

2004(2)

2003(2)

Total produced (Mcf)

17,885


(1)	Total production represents gross production and 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. All of our productive wells are located at our Southern Illinois Basin Project. Since our Southern Illinois Basin Project is currently subject to litigation, we may lose our right to continue to operate and produce CBM from all of our productive wells existing as of May 1, 2006.


	*Average Sales Prices and Lifting Costs*

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


	Twelve Months Ended
	July 31,

	2005		2004		2003

Average gas sales price (per Mcf)	$	6.59	$	0	$	0
Average lifting cost (per Mcf)		14.97		0		0


	*Drilling Plan*

The following table summarizes the wells that we plan to drill in the Illinois Basin during the 12-month period ending April 30, 2007:

Total

Vertical

Horizontal

Test

Additional

Wells

115

123

Our ability to drill additional wells is primarily limited by the availability of (i) capital, (ii) drilling contractors and (iii) equipment. Our drilling plan and our overall capital expenditure budget is based upon our available and anticipated cash resources. In addition to our drilling plan, we expect to pursue the acquisition of additional CBM rights during the 12-month period ending April 30, 2007.


	*Reserves*

Proved reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recovered 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, the date of our estimate of proved reserves prepared by our independent reservoir engineer consultants, 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) of Regulation S-X. All of our proved reserves are held pursuant to the lease relating to our Southern Illinois Basin Project, where our rights are currently subject to litigation.


	Net Reserves (MMcf)
	As of July 31,

	2005		2004		2003

Estimated proved developed reserves		2,971		0		0
Estimated proved undeveloped reserves		7,321		0		0

Total estimated proved developed and undeveloped reserves		10,292		0		0


	*Discounted Future Cash Flows*

The following table shows our estimated future net cash flows, based on estimated proved developed and undeveloped reserves (all of which are located at our Southern Illinois Basin Project, where our rights are

currently subject to litigation), and total standardized measure of discounted future net cash flows (discounted at a rate of 10%):


	Discounted Future Net
	Cash Flows (Dollars in
	thousands)
	As of July 31,

	2005		2004		2003

Future net cash flows (net of taxes)	$	43,940	$	0	$	0
Total standardized measure of discounted future net cash flows (net of taxes)		23,068		0		0
Total standardized measure of pre-tax discounted future net cash flows		30,767		0		0


	*Net Cash Used by Operations and Cash Resources*

We do not expect to generate any substantial cash contribution from operations during the 12-month period ending April 30, 2007. Our plan anticipates that over the 12-month period ending April 30, 2007, we will spend approximately $30.0 million on capital expenditures. We plan to drill 123 new wells during that period, including 120 new production wells and three new test wells. In addition to our drilling program, we expect to pursue the acquisition of additional CBM rights during that 12-month period. Our current cash balance is insufficient to fully fund our forecasted capital expenditures and net cash used by operating activities over the 12-month period ending April 30, 2007. 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 is evaluating raising the additional required capital through a combination of additional stock sales, the issuance of debt securities, borrowing and/or entering into joint ventures. However, we can provide no assurance that we will be able to raise the additional required capital to meet our plan or if we are able to raise the funds that it will be on terms similar to past financings.


	*Operational Needs as We Increase Our Drilling and Production*

Although we plan on drilling additional wells at other projects, our operating plan for the 12-month period ending April 30, 2007 anticipates that most of our CBM production will occur at our Southern Illinois Basin Project, assuming that we do not lose our productive wells at our Southern Illinois Basin Project due to our ongoing litigation. Our processing includes a glycol tower that removes excess moisture from the CBM and a compression facility that provides compression sufficient to allow our CBM to enter the pipeline transporting our CBM. During the 12-month period ending April 30, 2007, we anticipate adding additional compression and processing equipment as our production requires. In terms of personnel, in connection with our plan of operations for the 12-month period ending April 30, 2007 we believe that we will need additional personnel to handle the expected increased drilling, production and related activities. In the future, we may need to hire additional personnel and add additional equipment to handle future growth in development and production. We do not anticipate that we will experience any difficulties obtaining the appropriate personnel or processing equipment at any of our projects, although we can provide no assurance in this regard.

Sales and Distribution of Our Gas

Our current and future plans anticipate that we will sell all of our CBM to natural gas marketing companies. These marketing companies secure space on pipelines that they utilize to transport the CBM we sell them. There are multiple gas marketing companies we could choose to deal with in selling our CBM. These marketing companies have multiple pipeline companies they can secure space from to transport our CBM. There are multiple interstate pipeline companies that have pipelines that cross or are in close proximity to all of our current acreage in the Illinois Basin. These 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 our 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, although we can provide no assurance in this regard.

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 of 625 Mcfe), 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. 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 do not currently have any contractual commitments that ensure we will have adequate drilling equipment or crews to achieve our drilling plans. As of May 1, 2006, we have two drilling rigs in operation at our projects. We have working relationships with two drilling companies that we believe will make available to us on a continuous basis at least two drilling rigs for drilling vertical wells. In addition, we believe that we currently can secure a commitment from one of three other drilling companies to drill three pilot horizontal wells in the Fall of 2006. However, we can provide no assurance that our expectations regarding the availability of drilling equipment from these companies will be met.

If these levels of drilling equipment are made available to us and if we are able to raise the necessary capital, we expect to be able to achieve our drilling plan during the 12-month period ending April 30, 2007. This plan anticipates drilling 115 vertical wells, three horizontal wells and five test wells. If we are able to secure additional drilling equipment commitments and raise the necessary financing, we may modify our drilling plan accordingly.

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 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 reinject 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 reinject 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 our Southern Illinois Basin Project during the 12-month period ending April 30, 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 energy 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 and expertise 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 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 successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this competitive environment.

Legal Proceedings

ongoing litigation. It is possible that the court will not agree with our interpretation of the applicable lease provisions. In that case, we would lose all of our CBM acreage rights and productive wells at our Southern Illinois Basin Project.

Employees

We have 16 full-time employees, including our executive officers. We utilize independent consultants to perform various professional services and for drilling, testing and completion work.

Management

Executive Officers and Directors


Name	Age		Position

James G. Azlein		56	President, Chief Executive Officer and Director
George J. Zilich		48	Chief Financial Officer, General Counsel and Director
James E. Craddock		47	Senior Vice President — Operations
Costa Vrisakis		70	Director
William J. Centa		53	Director
Dennis Carlton		55	Director
David E. Preng		59	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.

George J. Zilich is an attorney and a certified public accountant. He was appointed to our Board of Directors and as our Chief Financial Officer and General Counsel on January 21, 2005. From June 2004 through January 2005, Mr. Zilich was an attorney at the law firm Jones Day where he concentrated in the areas of corporate finance and mergers and acquisitions. From 2001 through 2004, Mr. Zilich was an independent financial consultant and attended law school. Before entering the practice of law, Mr. Zilich worked for over 20 years as a certified public accountant and an entrepreneur. From 1994 through 2000, he was the Chief Financial Officer and a director for Archer Steel (a private company based in Aurora, Ohio). Mr. Zilich received his undergraduate degree from Ohio State University in 1979 where he graduated at the top of his class in accounting. In 2004, he received his juris doctorate from Cleveland-Marshall College of Law where he served as Editor-in-Chief of the Cleveland-Marshall Law Review and graduated at the top of his class. Mr. Zilich is a graduate of, and former graduate instructor for, the Dale Carnegie courses in human relations, leadership and public speaking. Mr. Zilich is a member of the American Bar Association, the Ohio Bar Association, the American Institute of Certified Public Accountants and the Ohio Society of Certified Public Accountants.

James E. Craddock has been Senior Vice President — Operations since April 2006. From 2004 to April 2006, Mr. Craddock served as Chief Engineer for Burlington Resources Inc., an independent oil and gas company that was recently acquired by ConocoPhillips. Mr. Craddock worked for Burlington Resources Inc. for 21 years and held various positions during that time including General Manager — Asset Development, General Manager — Production and Director of Strategic Planning.

Costa Vrisakis has been a Director since January 2002. Based in Sydney, Australia, Mr. Vrisakis is a financier and entrepreneur. In 1959, Mr. Vrisakis founded, along with two employees, Snap-Apart Pty. Ltd., a printing company. 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 1993, when he sold his interest in Computer Resources, 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 various hotels in Sydney, Australia.

William J. Centa has been a Director since March 28, 2005. Since March 2004, Mr. Centa has served as Executive Vice President and one of the co-founders of Mayfran Holdings, Inc., a multi-national 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. From February 1998 until October 2000, he served as Associate Director, Mergers & Acquisitions at the international accounting firm of Ernst & Young. 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.

Dennis Carlton has been a Director since May 2005. Mr. Carlton has been involved in CBM since 1989. In September 2005, Mr. Carlton became VP Exploration-Western Division for Pioneer Resources. 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 experience in CBM has included the Rocky Mountain Basins, Mid-Continent, United Kingdom and Alaska. His efforts in the Raton Basin with Evergreen were recognized when he was recognized as the Rocky Mountain Association of Geologists Outstanding Explorer in 2000.

David E. Preng has been a Director since February 2006. Mr. Preng is the Chief Executive Officer and President of Preng & Associates, an international executive search firm specializing in placements within the oil and gas industry. He has served in that position since he founded the company in 1980. 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 also serves on the board of directors of Maverick Oil & Gas, Inc., where he is chairperson of its compensation committee, and Remington Oil and Gas, Inc., which are both publicly held oil and gas companies.

Significant Employees

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

Randy Oestreich, 50, 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.

Advisory Board

Members of the Advisory Board are appointed by the Board of Directors to provide advice and guidance to the Board of Directors and our employees concerning various aspects of our business.

Clyde House, 72, has been involved in the oil and gas business most of his adult life. He has overseen field operations both domestically and internationally for major oil and gas exploration and development companies including Devon Energy. Over the past 15 years, Mr. House has focused his attention on development of CBM. Mr. House directed field operations and the development of the first 300 wells that the River Gas Company (subsequently acquired by Phillips Petroleum) drilled in the Black Warrior Basin. Mr. House originally identified the potential for a gas project in the Illinois Basin, and his research and past experience in CBM and shale production provided the basis for the Southern Illinois Basin Project.

William Ginn, 82, is currently a retired partner of Thompson Hine LLP in its Cleveland, Ohio office. In addition to his numerous community endeavors, Mr. Ginn is a long-standing member of the Board of Directors of Nordson Corporation. Mr. Ginn recently retired as a long-standing director of the Davey Tree Expert Company, where he was responsible for structuring and financing the employee acquisition of that once family owned company. Mr. Ginn graduated from Bates College and Yale Law School.

Kevin W. Reimer, 45, is a certified petroleum geologist and certified professional geologist with over 22 years of experience in oil and gas exploration and development, both as a principal and a consultant. Mr. Reimer has significant experience in research and evaluation of CBM projects in the United States and Western Europe. Mr. Reimer has expertise in the extraction of coal mine methane gas from abandoned underground coal mines and has seven years of research and experience in gas-fired power generation. Mr. Reimer was one of the first persons to successfully develop coal mine methane gas reserves and sell the resource to an interstate pipeline in Illinois. He has organized and operated three CBM pilot projects in the Illinois Basin starting in 1996. Mr. Reimer is currently a principal and President of Finite Resources, LTD. and a principal of KWR Ventures, LLC and KWR Consulting, LLC.

Dr. Luc Berthoud, 67, based in Zurich, Switzerland, holds a Ph.D. in Economics from the University of Lausanne, following an MBA in Paris. Since 1968, he has been active in international investment banking, holding senior management positions at both the Schroeder and Mercury (Warburg) groups in London. Since 1998, Dr. Berthoud has been a consultant to private clients for investment management and venture capital.

Summary Compensation Table

The following table sets forth the compensation paid to our executive officers in the three fiscal years ended July 31, 2005.


										Long-Term Compensation

										Awards				Payouts
				Annual Compensation
										Restricted		Securities
								Other Annual		Stock Wards		Underlying		LTIP		All Other
Name and Principal Position		Year		Salary		Bonus		Compensation		and SARs		Options		Payouts		Compensation

James G. Azlein			2005	$	163,000	$	100,000	$	0	$	0		1,422,278	$	0	$	0
	CEO and President		2004		111,286		7,808		0		0		320,000		0		0
			2003		145,917		6,500		0		0		320,000		0		0
George J. Zilich(1)			2005	$	65,000	$	0	$	0	$	0		475,000	$	0	$	0
	Chief Financial Officer		2004		—		—		—		—		—		—		—
	and General Counsel		2003		—		—		—		—		—		—		—
Keith A. Ebert(2)			2005	$	44,200	$	40,000	$	0	$	0		341,667	$	0	$	0
	Vice President		2004		58,338		7,479		0		0		0		0		0
			2003		47,272		6,705		0		0		125,000		0		0


(1)	Mr. Zilich became our Chief Financial Officer and General Counsel on January 21, 2005.
(2)	Mr. Ebert resigned as an officer and director on March 28, 2005.

Option Grants in Last Fiscal Year

The following options to purchase shares of our common stock were granted to our executive officers during the fiscal year ended July 31, 2005.


	Individual Grants

			Percent of							Potential Realizable Value
	Number of		Total							at Assumed Annual Rate of
	Securities		Options							Stock Price Appreciation
	Underlying		Granted to							for Option Term(2)
	Options		Employees in			Exercise		Expiration
	Granted		Fiscal Year			Price(1)		Date		5%		10%

James G. Azlein		456,666				$	1.25		11/29/09	$	157,949	$	349,026
		965,612					1.97		1/20/10		524,342		1,158,658

		1,422,278		51.91	%					$	682,291	$	1,507,684
George J. Zilich		175,000				$	1.97		1/20/10	$	95,028	$	209,986
		300,000					1.79		3/27/10		148,371		327,861

		475,000		17.34	%					$	243,399	$	537,847
Keith A. Ebert		341,667		12.47	%	$	1.00		11/29/09	$	94,380	$	208,556


(1)	The exercise price per share of each option is equal to the fair market value per share of the underlying stock on the date of grant, as determined by quoted market prices, and converted from Canadian dollars to U.S. dollars using the published exchange rate on the date of grant.

(2)	The potential realizable value shown is calculated based on the term of the option at the time of grant. Stock price appreciation of 5% and 10% is assumed pursuant to the rules and regulations of the SEC and does not represent our prediction of stock price performance. The potential realizable values at 5% and 10% appreciation are calculated by assuming that the U.S. dollar equivalent exercise price on the date of grant appreciates at the indicated rate for the entire term of the option and that the option is exercised at the U.S. dollar equivalent exercise price and sold on the last day of its term at the U.S. dollar equivalent appreciated price, assuming a constant exchange rate from the date of grant.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values

The following table shows the number of shares underlying options that were exercised by our executive officers in our fiscal year ended July 31, 2005. The table also shows the value as of July 31, 2005 of all outstanding options for our common stock held by our executive officers on that date.

Number of Shares

Underlying

Value of Unexercised

Unexercised

In-the-Money

Options at FY-End

Options at FY-End(1)

Shares

Acquired

Value

Exercisable/

Name

on Exercise

Realized

Unexercisable

James G. Azlein

445,555

317,569

1,985,612/0

660,983/$0

George J. Zilich

—

475,000/0

$0/$0

Keith A. Ebert

313,889

246,054

341,667/0

192,339/$0


(1)	Value is determined based on the closing market price of our common stock on July 31, 2005 as reported by the TSX Venture Exchange, converted from Canadian dollars to U.S. dollars using the published exchange rate on July 31, 2005.

Agreements with Our Employees

We entered into an employment agreement on January 6, 2005 with George J. Zilich, our Chief Financial Officer and General Counsel. Mr. Zilich’s employment agreement provides that he will be an at-will employee of the company. Mr. Zilich’s employment agreement entitles him to a base salary of $120,000 per year, a grant of options to purchase 175,000 shares of our common stock pursuant to our Incentive Stock Option Plan, and the right to participate in the benefits offered to our other senior executives. If Mr. Zilich is terminated by us without “cause,” he is entitled to receive a severance payment equal to two times his salary and benefits.

We also entered into an employment agreement on January 31, 2005 with Randy Elkins, our Controller. Mr. Elkins’ employment agreement provides that he will be an at-will employee of the company. Mr. Elkins’ employment agreement entitles him to a base salary of $80,000 per year, an immediate grant of 25,000 options, a grant of 25,000 options after three months, and additional grants of 25,000 options based upon the achievement of performance goals after 12 months and every six months thereafter, subject to a maximum of 175,000 options. Mr. Elkins’ employment agreement also gives him the right to receive health insurance through the plan that we maintain for our employees.

We also entered into an agreement on April 17, 2004 with James G. Azlein, our President and Chief Executive Officer, pursuant to which we agreed to grant to Mr. Azlein, in exchange for personally guaranteeing 11.025% of a $2,000,000 loan to a company 11.025% of which is indirectly owned by us, a number of shares of our common stock equal to 10% of the value of the guarantee. Pursuant to this agreement, we have issued 50,990 shares of our common stock to Mr. Azlein. Under the terms of this agreement, if Mr. Azlein is required to perform under the guarantee, he has no recourse to pursue any legal action for contribution or indemnification against us. On January 4, 2006, Mr. Azlein’s guarantee was released as part of our sale of our interest in Hite Coalbed Methane, L.L.C.

On April 18, 2006, we entered into an employment relationship with James E. Craddock pursuant to which Mr. Craddock agreed to serve as our Senior Vice President — Operations. As compensation for this position, Mr. Craddock is entitled to receive an initial base salary of $250,000 per year and a $100,000 signing bonus, a stock grant, on April 18, 2006, of 300,000 fully vested and unrestricted common shares, a stock grant, on April 18, 2006, of 300,000 restricted common shares, which will vest at the rate of 100,000 shares per year over the next three years, reimbursement of certain relocation expenses, participation in our stock-based compensation plans and our other standard benefit programs, a company car and five weeks vacation per year.

Stock-Based Compensation Plans

On November 9, 2005, our Board of Directors unanimously approved and adopted the BPI Energy Holdings, Inc. 2005 Omnibus Stock Plan, subject to approval by our shareholders at the 2005 Annual Meeting of Shareholders and our common stock being delisted from the TSX Venture Exchange. The Plan became effective on December 13, 2005, when our shareholders approved the Plan and our common stock was delisted from the TSX Venture Exchange. We have ceased making option grants under our existing Incentive Stock Option Plan and expect to make any future stock-based awards under the Omnibus Stock Plan.

The Omnibus Stock Plan is administered by the Compensation Committee of the Board of Directors and will remain in effect for five years. All of our employees and Directors, and any of our consultants or agents designated by the Compensation Committee, are eligible to participate in the Omnibus Stock Plan. The Omnibus Stock Plan provides for the grant of stock options (incentive stock options or “non-qualified” stock options), restricted stock, stock appreciation rights, stock purchase rights, cash awards and other stock or performance-based incentives. These awards are payable in cash or common stock, or any combination thereof, as established by the Compensation Committee. The Compensation Committee also 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.

As of May 1, 2006, we have options outstanding to purchase 1,872,812 shares of our common stock, all of which were issued with an exercise price equal to the market price of our common stock on the date of grant. All of the options granted by us to U.S. plan participants since November 2004 and all other participants since January 2005 have exercise prices equal to the closing market price of our common stock on the date of grant.

Directors’ Fees and Other Compensation

All non-management Directors are reimbursed for reasonable expenses incurred in connection with attending meetings. During the most recently completed fiscal year our independent Directors were granted options to purchase the following number of shares under our Incentive Stock Option Plan: Mr. Vrisakis — 600,000; Mr. Centa — 125,000; and Mr. Carlton — 115,000. There were no standard compensation arrangements (including any additional amounts payable for committee participation or special assignments) or any other arrangements in addition to, or in lieu of, standard arrangements under which our Directors were compensated by us in their capacity as Directors during such fiscal year. During the most recently completed fiscal year, none of our Directors were compensated for services rendered to us as consultants or experts.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has one or more executive officers who serve on our board of directors or compensation committee.

Certain Relationships and Related Transactions

Randy Oestreich, our Vice President of Field Operations, owns and operates A-Strike Consulting, a consulting company that provides, among other things, laboratory testing related to CBM. We own a lab testing facility and allow A-Strike Consulting to operate the facility. We pay all expenses related to the facility and, in return, receive 80% of the revenue generated from the operations of the facility as reimbursement of our expenses. During the year ended July 31, 2005, we received approximately $59,000 in expense reimbursement related to this arrangement.

Mr. Oestreich’s brother owns Dependable Service Company, a company that provides general labor services to us. We paid Dependable Services Company $147,000 and $16,000 in fiscal years ended July 31, 2005 and 2004, respectively.

Our Shareholders

The following table sets forth information regarding the beneficial ownership of our common stock as of May 1, 2006 by (i) each of our executive officers and directors; (ii) all of our executive officers and directors as a group; and (iii) each person or entity that, to our knowledge, beneficially owns more than 5% of our common stock. The table includes shares underlying options and warrants held by executive officers and directors and warrants held by shareholders that own more than 5% of our common stock. All of these options and warrants are currently exercisable. Percentage ownership is calculated in accordance with Rule 13d-3 of the Exchange Act based on the total number of shares outstanding as of May 1, 2006.


				Number of Shares
		Number of		Underlying Options		Percent
Name and Address		Shares		and Warrants		Ownership

James G. Azlein			2,124,296		1,402,812		4.88	%
	30775 Bainbridge Road, Suite 280
	Solon, Ohio 44139
George J. Zilich			841,523		40,000		1.24	%
	30775 Bainbridge Road, Suite 280
	Solon, Ohio 44139
James E. Craddock			600,000		0		0.85	%
	30775 Bainbridge Road, Suite 280
	Solon, Ohio 44139
Costa Vrisakis			1,945,522		0		2.75	%
	30775 Bainbridge Road, Suite 280
	Solon, Ohio 44139
William J. Centa			300,000		0		0.42	%
	30775 Bainbridge Road, Suite 280
	Solon, Ohio 44139
Dennis Carlton			300,000		0		0.42	%
	30775 Bainbridge Road, Suite 280
	Solon, Ohio 44139
David E. Preng			200,000		0		0.28	%
	30775 Bainbridge Road, Suite 280
	Solon, Ohio 44139
All directors and			6,311,341		1,442,812		10.73	%
	executive officers as a group
	(7 persons)
Advisory Research, Inc.(1)			9,372,500		0		13.23	%
	180 N. Stetson Street, Suite 5500
	Chicago, Illinois 60601
CFSIL a/c Colonial First			3,900,000		1,200,000		7.08	%
	State Wholesale Global
	Resources Fund
	Level 29, 52 Martin Place
	Sydney, Australia NSW 2001
Jennison Associates LLC(2)			6,400,000		1,200,000		10.55	%
	466 Lexington Avenue
	New York, New York 10017
Wellington Capital Management(3)			6,000,000		0		8.47	%
	227 West Monroe Street
	Chicago, Illinois 60606



(1)	The common stock listed was reported by Advisory Research, Inc. in a Schedule 13G filed with the Securities and Exchange Commission on January 10, 2006.



(2)	The common stock listed was reported by Jennison Associates LLC in a Schedule 13G/A filed with the Securities and Exchange Commission on February 14, 2006.



(3)	The common stock listed was reported by Wellington Capital Management in a Schedule 13G filed with the Securities and Exchange Commission on February 14, 2006.

Selling Shareholders

This prospectus covers the offer and sale by the selling shareholders of up to 18,000,000 shares of our common stock owned by the selling shareholders.

The following is a list of our shareholders that may sell shares of our common stock pursuant to this prospectus. Each of the shares offered by this prospectus was purchased in our September 2005 private placement. If a selling shareholder sells all of the shares of our common stock beneficially owned by the shareholder that are offered for sale by this prospectus, the shareholder will hold none of our shares, except as noted in the footnotes below. Percentage ownership is calculated in accordance with Rule 13d-3 under the Exchange Act using the 63,040,237 shares of our common stock outstanding as of May 1, 2006.


	Number of				Percent
	Shares Owned		Number of		Owned
	Before		Shares		Before this
Name of Selling Shareholder	Offering		Offered		Offering

Advisory Research, Inc.(1)		9,372,500		6,000,000		13.23%
Chilton Investment Company, LLC(2)		500,000		500,000		0.71%
Colonial First State Investments Limited(3)		5,100,000		1,500,000		7.08%
Jennison Associates LLC(4)		7,600,000		4,000,000		10.55%
Wellington Management Company, LLP(5)		6,000,000		6,000,000		8.47%



(1)	The aggregate ownership of 9,372,500 shares of common stock was reported by Advisory Research, Inc. in a Schedule 13G filed with the Securities and Exchange Commission on January 10, 2006. The 6,000,000 shares of common stock offered by this prospectus are certificated as follows: Advisory Research Microcap Value Fund, LP — 4,400,000 shares; and Advisory Research Energy Fund, LP — 1,600,000 shares. If Advisory Research, Inc. sells all of its shares offered by this prospectus, the remaining shares of our common stock beneficially owned by it will constitute 4.76% of our outstanding shares.


(2)	The 500,000 shares of common stock offered by this prospectus are certificated as follows: Chilton Investment Partners, LP — 40,100 shares; Chilton Global Partners, LP — 21,500 shares; Chilton QP Investment Partners, LP — 104,400 shares; Chilton Global Natural Resources Partners, LP — 35,000 shares; Chilton Opportunity Trust, LP — 33,600 shares; Chilton International, LP — 243,400 shares; and Chilton Opportunity International, LP — 22,000 shares. If Chilton Investment Company, LLC sells all of its shares offered by this prospectus, it will no longer beneficially own any of our outstanding shares.


(3)	The 1,500,000 shares of common stock offered by this prospectus are certificated as follows: Bershaw and Co. Ltd. FBO First State Global Resources Fund — 758,000 shares; Goldman Sachs & Co. FBO First State Investments Global Resources Long Short Master Fund Limited — 201,000 shares; Goldman Sachs & Co. FBO CSFIL a/ c Colonial First State Wholesale Global Resources Long Short Fund — 41,000 shares; and Bershaw and Co. Ltd. FBO Colonial First State Wholesale Global Resources Fund — 500,000 shares. If Colonial First State Investments Limited sells all of its shares offered by this prospectus, the remaining shares of our common stock beneficially owned by it will constitute 5.00% of our outstanding shares.



(4)	The 4,000,000 shares of common stock offered by this prospectus are certificated as follows: Hare and Co. FBO Jennison Natural Resources Fund, Inc. — 2,400,000 shares; and Hare and Co. FBO Natural Resources Portfolio of the Prudential Series Fund, Inc. — 1,600,000 shares. If Jennison Associates LLC sells all of its shares offered by this prospectus, the remaining shares of our common stock beneficially owned by it will constitute 5.00% of our outstanding shares.


(5)	The 6,000,000 shares of common stock offered by this prospectus are certificated as follows: Spindrift Partners, L.P. — 2,300,000 shares; Spindrift Investors (Bermuda) L.P. — 2,700,000 shares; Placer Creek Partners, L.P. — 550,000 shares; and Placer Creek Investors (Bermuda) L.P. — 450,000 shares. If

Wellington Management Company, LLP sells all of its shares offered by this prospectus, it will no longer beneficially own any of our outstanding shares.

The shares of our common stock covered by this prospectus were acquired by the selling shareholders from us in connection with our September 2005 private placement. In the private placement, we issued 18,000,000 shares of our common stock at a per share price of CAD$2.00 (approximately USD$1.69).

The common stock covered by this prospectus has been registered by us under the Securities Act pursuant to our obligations under the Stock Purchase Agreement, dated as of September 20, 2005, that we entered into in connection with our September 2005 private placement.

The shares beneficially owned by the selling shareholders are registered under Rule 415 under the Securities Act concerning delayed and continuous offers and sales of securities. In regard to the offer and sale of such shares, we have made certain undertakings in Part II of the registration statement of which this prospectus is part, by which, in general, we have committed to keep this prospectus current during any period in which the selling shareholders may make offers to sell the covered securities pursuant to Rule 415. We are required to make this prospectus available to the selling shareholders until the earlier of (i) such time as all of the selling shareholders may immediately sell all of their shares subject to this prospectus under Rule 144(b), without giving effect to the volume limitations of Rule 144(e), and (ii) such time as all of the selling shareholders have sold all of their shares subject to this prospectus.

All of the shares of common stock sold by the selling shareholders will be freely tradable without restriction or limitation under the Securities Act, except for any shares of common stock purchased by any of our “affiliates,” which generally includes our directors, executive officers and stockholders that hold at least 10% of our common stock. The common stock that is held by our affiliates is subject to Rule 144 under the Securities Act, and may not be sold by an affiliate other than in compliance with the registration requirements of the Securities Act or pursuant to Rule 144 or another exemption from such registration requirements.

Plan of Distribution

The selling shareholders and their assignees may, from time to time, sell any or all of their shares of our common stock that are covered by this prospectus on any stock exchange, market or trading facility on which the shares may then be listed or quoted or in private transactions. These sales may be at prevailing market prices, at prices related to prevailing market prices or at other negotiated prices. The selling shareholders may use any one or more of the following methods when selling shares:


	•	privately negotiated transactions;

	•	ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

	•	block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

	•	purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

	•	an exchange distribution in accordance with the rules of the applicable exchange;

	•	settlement of short sales entered into after the date of this prospectus (a short sale occurs when shares, not owned by the seller, are sold in hopes of a decline in market price so the seller can purchase shares in the market at a lower price to be able to replace the shares sold);

	•	broker-dealers may agree with the selling shareholders to sell a specified number of such shares at a stipulated price per share;

	•	through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

	•	a combination of any such methods of sale; or

	•	any other method permitted by applicable law.

The selling shareholders also may sell shares under Rule 144 under the Securities Act, if available, rather than under this prospectus. Broker-dealers engaged by the selling shareholders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling shareholders (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated. These commissions and discounts may or may not exceed what is customary in the types of transactions involved. Broker-dealers may agree to sell a specified number of such shares at a stipulated price per share and, to the extent such broker-dealer is unable to do so acting as agent for a selling shareholder, purchase as principal any unsold shares at the price required to fulfill the broker-dealer commitment. Broker-dealers who acquire shares as principal may thereafter resell such shares from time to time in transactions, which may involve block transactions and sales to and through other broker-dealers, including transactions of the nature described above, in the over-the-counter markets or otherwise at prices and on terms then prevailing at the time of sale, at prices related to the prevailing market price or in negotiated transactions. In connection with such resales, broker-dealers may pay to or receive from the purchasers such commissions as described above.

In connection with the sale of shares or interests therein, the selling shareholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the common stock in the course of hedging the positions they assume. The selling shareholders may also sell shares of our common stock short and deliver shares covered by this prospectus to close out their short positions, or loan or pledge such shares to broker-dealers that in turn may sell such shares. The selling shareholders may also enter into option or other transactions with broker-dealers or other financial institutions or create one or more derivative securities that require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus.

The selling shareholders also may transfer the shares of common stock in other circumstances, in which case the transferee, pledgee or other successor-in-interest will be the selling beneficial owners for purposes of this prospectus.

The selling shareholders and any broker-dealers or agents that are involved in selling the shares may be deemed to be “underwriters” within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act.

We have paid all fees and expenses incurred in connection with the registration of the resale of the shares of our common stock covered by this prospectus. We have agreed to indemnify the selling shareholders against certain losses, claims, damages and liabilities in connection with the registration of the shares of common stock that are subject to this prospectus, including certain liabilities under the Securities Act.

In some jurisdictions, the selling shareholders may be required to sell common stock only through registered or licensed brokers or dealers. In addition, in some states the selling shareholders may be required to register the common stock for sale in such state, unless an exemption from registration is available.

Because the selling shareholders may be deemed to be “underwriters” within the meaning of Section 2(11) of the Securities Act, the selling shareholders will be subject to the prospectus delivery requirements of the Securities Act.

Description of Our Common Stock

Common Stock

We are authorized to issue 200,000,000 shares of common stock, without par value. As of May 1, 2006, we have 70,812,540 shares of common stock outstanding. As of the same date, we also have outstanding warrants to purchase 5,311,600 shares of our common stock and outstanding options to purchase 1,872,812 shares of our common stock.

The following is a summary of the terms of our common stock. The rights of the holders of our common stock are defined by our Articles of Incorporation and the British Columbia Business Corporations Act. You should refer to those documents and provisions for more complete information regarding our common stock.

Holders of our common stock have one vote per share on all matters upon which our shareholders are entitled to vote, including the election of directors. In the election of directors, holders of our common stock do not have cumulative voting rights. The holders of our common stock have no preemptive right to purchase any of our securities or any securities that are convertible into or exchangeable for any of our securities. Our common stock is not subject to any provisions relating to redemption. Our common stock is not by its terms subject to any restrictions on alienation. Our common stock has no conversion rights and is not subject to further calls or assessments by us. All outstanding shares of our common stock are fully paid and nonassessable.

Holders of our common stock have equal rights to receive dividends when, as and if declared by our Board of Directors, out of funds legally available therefor. See the section of this prospectus entitled “Dividend Policy.” Holders of our common stock are entitled, upon the liquidation of the company, to share ratably in the net assets available for distribution, subject to the rights, if any, of holders of any preferred stock then outstanding. We currently have no class of preferred stock authorized or outstanding. To increase the authorized number of shares of common stock outstanding or create a class of preferred stock, the affirmative vote of the holders of two-thirds of our common stock represented in person or by proxy at a meeting of our shareholders would be required.

Our common stock is currently traded on the American Stock Exchange under the symbol “BPG.”

Comparison of Shareholder Rights Under British Columbia and Delaware Law

The shareholder rights that exist under the terms of our common stock and British Columbia law are in some instances different than what they would be, for example, under the laws of the State of Delaware, where many U.S. corporations are incorporated. Although some differences exist between the corporation laws of the two jurisdictions, we believe that the differences are not significant.

For example, neither British Columbia law nor Delaware law requires corporations to provide shareholders with cumulative voting rights. Neither British Columbia law nor Delaware law requires corporations to

provide shareholders with preemptive rights to purchase any securities of the corporation. Under both British Columbia law and Delaware law, shareholders have the right to dissent from most cash-for-stock mergers of a corporation and seek an appraisal of the value of their shares. Under British Columbia law such dissenters’ rights extend to the sale of all or substantially all of a corporation’s assets, although under Delaware law they do not.

Under both British Columbia law and Delaware law, shareholders may generally approve corporate matters in a written action taken without a formal meeting of shareholders. Although Delaware law does not require that shareholders have the right to call a special meeting, British Columbia law provides that one or more shareholders holding at least five percent of the voting shares of a corporation may cause a shareholders meeting to be called. Under our Articles of incorporation, holders of 33¹/3 % of our shares of common stock constitute a quorum for the purpose of transacting business at a meeting. Under Delaware law, a majority of the shares entitled to vote, unless the corporation’s certificate of incorporation provides for a lower percentage not less than one-third of the shares entitled to vote, constitute a quorum at a meeting of shareholders.

Under British Columbia law and our Articles of Incorporation, we may in general alter our Articles only with the approval of the holders of two-thirds of our common stock represented in person or by proxy at a meeting of our shareholders. Delaware law requires the approval of the holders of at least a majority of the outstanding stock of a corporation to amend a Delaware corporation’s certificate of incorporation. In addition, under British Columbia law and our Articles of Incorporation, shareholders that hold at least two-thirds of our common stock represented in person or by proxy at a meeting of our shareholders may remove a director before the end of the director’s term of office. Under Delaware law, a director may generally be removed from office before the end of the director’s term by the holders of a majority of the corporation’s outstanding stock.

Under British Columbia law, we may generally not enter into an amalgamation (which is referred to as a merger in the United States) or sell all or substantially all of our assets unless the transaction is approved by the holders of two-thirds of our common stock represented in person or by proxy at a meeting of our shareholders. Delaware law generally requires the approval of mergers, consolidations and sales of all or substantially all of a corporation’s assets by a majority of the voting power of the corporation.

Both British Columbia law and Delaware law generally permit corporations to issue preferred stock or shareholder rights (also known as a “poison pill”). A British Columbia or Delaware corporation may generally issue preferred stock or shareholder rights that would have the effect of deterring a takeover attempt, including a takeover attempt that might be in the best interests of the corporation or its shareholders. We do not currently have either preferred stock or shareholder rights outstanding, although our Articles of Incorporation permit us to issue preferred stock and do not restrict us from issuing shareholder rights. We currently have no plans to issue any preferred stock or shareholder rights, but we will be able to do so at any time in the future.

Investment Canada Act

There is no limitation imposed by the laws of Canada, the laws of British Columbia or our Articles of Incorporation on the right of a non-resident to hold or vote our common stock, other than as provided in the Investment Canada Act, which generally prohibits a reviewable investment by an entity that is not a “Canadian” entity, unless after review the applicable minister is satisfied that the investment is likely to be of “net benefit” to Canada.

An investment in our common stock by a non-Canadian who is not a “WTO investor,” at a time when we are not already controlled by a WTO investor, would be reviewable under the Investment Canada Act if it is an investment to acquire control and the value of our assets is CAD$5 million or more. Regardless of the value of the proposed transaction, an order for review may be made by the Canadian government if the investment is related to Canada’s cultural heritage or national identity.

An investment in our common stock by a WTO investor, or by a non-Canadian at a time when we are already controlled by a WTO investor, would be reviewable under the Investment Canada Act if it is an investment to acquire control and the value of our assets is not less than a specified amount (CAD$265 million in 2006).

The Investment Canada Act has detailed rules to determine control. For example, a non-Canadian would acquire control of us for purposes of the Investment Canada Act if a majority of our outstanding common stock was acquired; acquisition of less than a majority but more than one-third of our outstanding common stock would be a rebuttable presumption of a control acquisition having occurred. Control also could be deemed to occur through the acquisition of all or substantially all of our assets.

A “WTO investor” generally includes governments of, or individuals who are nationals of, member states of the World Trade Organization and corporations and other entities that are controlled by them. The United States and most all of the principal economies of the world are currently members of the World Trade Organization.

If any of the thresholds described above is exceeded, an application for review must be filed with the Investment Review Division of Industry Canada and/or, if the business is related to Canada’s cultural heritage or national identity, with the Department of Canadian Heritage. Reviews are undertaken by the Minister of Industry, the Minister of Cultural Heritage or both ministers, depending on the nature of the business under review.

The Investment Canada Act provides for an initial 45-day review period. The reviewing minister may unilaterally extend the review period for an additional 30 days and, with the consent of the proposed investor, for longer periods of time. In reviewing whether an investment is of “net benefit” to Canada, the reviewing minister is directed to take into account the following factors:


	•	the effect of the investment on the level and nature of economic activity in Canada;

	•	the degree of involvement by Canadians in the business;

	•	the effect of the investment on productivity, industrial efficiency, technological development, product innovation and product variety in Canada;

	•	the effect of the investment on competition within any industry in Canada;

	•	the compatibility of the investment with national industrial, economic and cultural policies; and

	•	the effect of the investment on Canada’s ability to compete in world markets.

If none of the thresholds described above are exceeded and no review is required, a notification may generally still be required to be filed with Industry Canada and/or the Department of Canadian Heritage.

Material Tax Consequences to U.S. Holders

A brief description is included below of certain taxes, including withholding taxes, to which U.S. security holders are subject under existing tax laws and regulations of Canada. The consequences, if any, of Canadian provincial taxes are not discussed. The following information is general, and holders of our common stock should seek the advice of their own tax advisors with respect to the applicability or effect on their own individual circumstances of the matters described below.

U.S. citizens and individual residents and domestic corporations are taxed on their worldwide income. Therefore, dividends and capital gains of U.S. taxpayers will be subject to U.S. income tax. U.S. holders should consult their own tax advisors regarding specific questions as to U.S. federal, state or local taxes.

The following summarizes the principal Canadian federal income tax consequences of acquiring, holding and disposing of our common stock by a shareholder who is not a resident of Canada but is a resident of the United States and who will acquire and hold our common stock as capital property. This summary does not apply to a shareholder who carries on business in Canada through a “permanent establishment” situated in Canada or performs independent personal services in Canada. This summary is based on the provisions of the Income Tax Act (Canada), the regulations thereunder and the administrative practices of the Canada Revenue Agency as of the date of this prospectus. It has been assumed that there will be no amendment of any applicable law, although no assurance can be given in this regard. This discussion is general only and is not a substitute for independent advice from a shareholder’s own Canadian and U.S. tax advisor.

The provisions of the Income Tax Act are subject to income tax treaties to which Canada is a party, including the Canada-United States Income Tax Convention (1980) (the “Convention”).

Dividends on Common Stock

Under the Income Tax Act, a nonresident of Canada is subject to Canadian withholding tax at the rate of 25% on dividends paid by a corporation resident in Canada. The Convention limits the rate to 15% if the shareholder is a resident of the United States and the dividends are beneficially owned by and paid to the shareholder, and to five percent if the shareholder is a corporation that beneficially owns at least 10% of our common stock.

The Convention generally exempts from Canadian income tax dividends paid to a religious, scientific, literary, educational or charitable organization if the organization is a resident of the United States and such dividend income is exempt from income tax under the laws of the United States or to an organization constituted and operated exclusively to administer a pension, retirement or employee benefit fund or plan.

Disposition of Common Stock

The Convention will relieve U.S. residents from liability for Canadian tax on capital gains derived on a disposition or deemed disposition of our common stock unless:


	•	the shareholder was resident in Canada for 120 months during any period of 20 consecutive years preceding, and at any time during the 10 years immediately preceding, the disposition and the shares were owned by the shareholder when the shareholder ceased to be resident in Canada; or

	•	the shares formed part of the business property of a “permanent establishment” that the shareholder has or had in Canada within the 12 months preceding the disposition.

If the Convention does not relieve a U.S. resident from Canadian tax on capital gains, the U.S. resident will, under the Income Tax Act, be subject to Canadian tax on “taxable capital gains” (as defined below), and may deduct “allowable capital losses” (as defined below), realized on a disposition of “taxable Canadian property.” Our common stock will constitute “taxable Canadian property” of a shareholder at a particular time if the shareholder used the shares in carrying on business in Canada, or if at any time in the five years immediately preceding the disposition 25% or more of the issued shares of any class or series of our capital stock belonged to one or more persons in a group comprising the shareholder and persons with whom the shareholder did not deal at arm’s length.

Under the Income Tax Act, a taxpayer’s capital gain (or capital loss) from the disposition of our common stock is the amount, if any, by which his or her proceeds of disposition exceed (or are exceeded by) the aggregate of his or her adjusted cost base of such shares and reasonable expenses of disposition. Fifty percent of a capital gain (the “taxable capital gain”) is included in income, and fifty percent of a capital loss in a year (the “allowable capital loss”) is deductible from taxable capital gains realized in the same year. The amount by which a shareholder’s allowable capital loss exceeds the taxable capital gain in a year may be deducted from a taxable capital gain realized by the shareholder in the three previous or any subsequent year, subject to certain restrictions in the case of a corporate shareholder and subject to adjustment when the capital gains inclusion rate in the year of disposition differs from the inclusion rate in the year the deduction is claimed.

When a holder dies holding shares of our common stock, such holder will be deemed for Canadian tax purposes to have disposed of such shares for an amount equal to the fair market value of the shares immediately before such holder’s death and will be subject to the tax treatment with respect to dispositions described above. Any person who acquires such shares as a consequence of the death of such holder will be deemed to have acquired such shares for the fair market value at that time. There is currently no Canadian federal estate tax.

Where You Can Find More Information

We have filed a post-effective amendment to our registration statement on Form S-1 with the SEC relating to the shares covered by this prospectus. This prospectus is a part of the post-effective amendment to the registration statement and does not contain all of the information in the post-effective amendment. Whenever a reference is made in this prospectus to one of our contracts or other documents, the reference is not necessarily complete and you should refer to the exhibits that are a part of the post-effective amendment to our registration statement for a copy of the contract or other document. You may review a copy of the post-effective amendment to our registration statement at the SEC’s public reference room located at Headquarters Office, 100 F Street, N.E., Room 1580, Washington, D.C. 20549 or through the SEC’s website located at http://www.sec.gov.

We are subject to the reporting requirements of the Exchange Act. In connection with such requirements, we are required to file annual, quarterly and current reports and other information with the SEC. You may read and copy any documents filed by us at the SEC’s public reference room located at Headquarters Office, 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information regarding the public reference room. Our periodic filings with the SEC are also available through the SEC’s website located at http://www.sec.gov. We maintain a website located at http://www.bpi-energy.com. The information contained on our website is not incorporated by reference in this prospectus, and you should not consider it to be a part of this prospectus.

Legal Matters

The validity of the common stock that may be offered pursuant to this prospectus has been passed upon by Anfield Sujir Kennedy & Durno. A copy of this opinion is included as an exhibit to the post-effective amendment to our registration statement that we have filed with the SEC and of which this prospectus is a part.

Change of Auditor

Effective August 15, 2005, De Visser Gray, Chartered Accountants, resigned as our auditor by mutual agreement between us and De Visser.

The audit report issued by De Visser dated October 12, 2004 was an unqualified opinion that included an explanatory paragraph describing conditions that raised substantial doubt about our ability to continue as a going concern due to our (1) lack of revenue and (2) dependence on our ability to raise funds via equity financings.

The decision to change auditors has been considered and approved by the Audit Committee of our Board of Directors.

During our two most recent fiscal years and all subsequent interim periods preceding De Visser’s resignation there were no disagreements with De Visser concerning accounting principles or practices, financial statement disclosure, or auditing scope or procedure.

During our two most recent fiscal years and all subsequent interim periods preceding De Visser’s resignation De Visser did not advise us of any of the following:


	•	that the internal controls necessary for us to develop reliable financial statements do not exist;

	•	that information came to De Visser’s attention that led it to no longer be able to rely on management’s representations, or that made it unwilling to be associated with the financial statements prepared by management;

	•	(1) the need for De Visser to expand significantly the scope of its audit, or that information came to its attention during our two most recent fiscal years or any subsequent interim period preceding De Visser’s resignation, that if further investigated may have: (i) materially impacted the fairness or reliability of either: a previously issued audit report or the underlying financial statements; or the financial statements issued or to be issued covering the fiscal period(s) subsequent to the date of the most recent financial statements covered by an audit report (including information that may have prevented it from rendering an unqualified audit report on those financial statements), or (ii) caused De Visser to be unwilling to rely on management’s representations or be associated with our financial statements, and

(2) that, due to their resignation, or for any other reason, De Visser did not so expand the scope of its audit or conduct such further investigation; or


	•	(1) that information has come to their attention that it has concluded materially impacts the fairness or reliability of either (i) a previously issued audit report or the underlying financial statements, or (ii) the financial statements issued or to be issued covering the fiscal period(s) subsequent to the date of the most recent financial statements covered by an audit report (including information that, unless resolved to De Visser’s satisfaction, would prevent it from rendering an unqualified audit report on those financial statements), and

(2) that, due to their resignation, or for any other reason, the issue has not been resolved to De Visser’s satisfaction prior to its resignation.

Effective August 15, 2005, we engaged a new independent accountant, Meaden & Moore, Ltd., Certified Public Accountants, to audit our financial statements. In addition, during our two most recent fiscal years, and subsequent interim periods prior to engaging Meaden & Moore, neither BPI nor someone on our behalf consulted Meaden & Moore regarding: (i) the application of accounting principles to a specified transaction, either completed or proposed; (ii) the type of audit opinion that might be rendered on our financial statements; or (iii) any matter that was either the subject of a disagreement (as defined in paragraph (a)(1)(iv) of Item 304 of Regulation S-K) or a reportable event (as described in paragraph (a)(1)(v) of Item 304 of Regulation S-K).

This disclosure first appeared in our registration statement on Form S-1 filed with the SEC on October 28, 2005 (File No. 333-125483). We provided De Visser with a copy of the disclosures set forth in this section above prior to the date of such registration statement. We also requested that De Visser furnish us

with a letter addressed to the SEC stating whether it agrees with the statements made above in response to Item 304(a) of Regulation S-K and, if not, stating the respects in which it does not agree. The letter of De Visser provided in response to that request, which states that De Visser is in agreement with the above disclosures (apart from the second sentence of the immediately preceding paragraph regarding Meaden & Moore, with which De Visser stated that it was not in a position to agree or disagree), was filed as an exhibit to such registration statement.

Experts

Our consolidated balance sheet as of July 31, 2005, and the consolidated statements of operations, shareholders’ equity and cash flows for the fiscal year ended July 31, 2005, have been audited by Meaden & Moore, Ltd., Certified Public Accountants, and are included in this prospectus, along with the audit report from Meaden & Moore, in reliance upon the authority of such firm as experts in accounting and auditing.

Our consolidated balance sheets as of July 31, 2004 and July 31, 2003, and the consolidated statements of operations, shareholders’ equity and cash flows for the two fiscal years ended July 31, 2004 and July 31, 2003, have been audited by De Visser Gray, Chartered Accountants, and are included in this prospectus, along with the audit report from De Visser Gray, in reliance upon the authority of such firm as experts in accounting and auditing.

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.

Average finding cost. The amount of total capital expenditures, including acquisition, exploration and abandonment costs, for natural gas activities divided by the amount of proved reserves added in a specified period.

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.

Core sample. A cylindrical sample taken from a formation for geological analysis. Typically, a conventional core barrel is substituted for the drill bit and procures a sample as it penetrates the formation.

Desorption. A test that measures the gas evolved from a core sample to determine gas content.

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.

Logging. The systematic recording of data obtained from the driller’s log and mud log at the surface, and electrical and radioactive logs obtained from instrumentation lowered into and retrieved from the drill hole after drilling.

A-1

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.

Operator. The individual or company responsible to the working interest owners for the exploration, development and production of a natural gas well or lease.

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 dewatering system. A productive well may produce only water for a period of time before gas begins to flow through the gas gathering system.

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

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

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

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

A-2

BPI Energy Holdings, Inc.

Index to Consolidated Financial Statements


Reports of Independent Registered Public Accounting Firms			F-2
Consolidated Balance Sheets as of July 31, 2005 and 2004			F-4
Consolidated Statements of Operations for the years ended July 31, 2005, 2004 and 2003			F-5
Consolidated Statements of Shareholders’ Equity for the years ended July 31, 2005, 2004 and 2003			F-6
Consolidated Statements of Cash Flows for the years ended July 31, 2005, 2004 and 2003			F-7
Notes to Consolidated Financial Statements as of July 31, 2005 and 2004 and for the years ended July 31, 2005, 2004 and 2003			F-8
Consolidated Balance Sheet as of January 31, 2006 (unaudited)			F-27
Consolidated Statements of Operations and Deficit for the three months ended and six months ended January 31, 2006 and 2005 (unaudited)			F-28
Consolidated Statement of Shareholders’ Equity for the six months ended January 31, 2006 (unaudited)			F-29
Consolidated Statements of Cash Flows for the six months ended January 31, 2006 and 2005 (unaudited)			F-30
Notes to Consolidated Financial Statements (unaudited) as of and for the six months ended January 31, 2006			F-31

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders of

BPI Industries Inc.

Solon, Ohio

We have audited the accompanying consolidated balance sheet of BPI Industries Inc. and Subsidiaries as of July 31, 2005, and the related statements of operations, shareholders’ equity, and cash flows for the fiscal year ended July 31, 2005. 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. The financial statements of BPI Industries Inc. and Subsidiaries as of July 31, 2004 and 2003 were audited by other auditors whose unqualified opinion dated October 12, 2004, on those statements included an explanatory paragraph describing conditions that raised substantial doubt about the Company’s ability to continue as a going concern as discussed in Note 1 to the financial statements.

We conducted our audit 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. 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 financial position of BPI Industries Inc. and Subsidiaries as of July 31, 2005, and the results of its operations and its cash flows for the fiscal year ended July 31, 2005, in conformity with U.S. generally accepted accounting principles.

MEADEN & MOORE, LTD.

Certified Public Accountants

September 21, 2005

Cleveland, Ohio

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of BPI Industries Inc.,

We have audited the accompanying consolidated balance sheet of BPI Industries Inc. and subsidiaries as of July 31, 2004 and the accompanying consolidated statements of operations, shareholders’ equity and cash flows for the fiscal years ended July 31, 2004 and 2003. 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 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 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 Industries Inc. and its subsidiaries as of July 31, 2004, and the results of their operations and their cash flows for the fiscal years ended July 31, 2004 and 2003 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. As discussed in note 1 to the financial statements, the Company has no established source of revenue and is dependent on its ability to raise funds via equity financings. This raises substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

CHARTERED ACCOUNTANTS

Vancouver, British Columbia

October 12, 2004

F-3

BPI INDUSTRIES INC.

Consolidated Balance Sheets


			July 31

			2005			2004

ASSETS
Current Assets
	Cash and cash equivalents		$	7,251,503		$	970,795
	Accounts receivable			34,671			—
	Marketable securities			—			71,281
	Other current assets			23,534			44,926

		Total current assets		7,309,708			1,087,002

Property and equipment, at cost:
	Oil and gas properties, full cost method of accounting:
		Proved, net of accumulated depreciation, depletion and
		amortization of $58,523 and $0		10,190,929			—
		Unproved		3,149,372			6,772,177

	Net oil and gas properties			13,340,301			6,772,177
	Other property and equipment, net of accumulated depreciation and amortization of $398,988 and $217,144			1,769,812			447,032

	Net property and equipment			15,110,113			7,219,209
Equity investment in joint venture				—			100,500
Investment in Hite Coalbed Methane, L.L.C.				846,766			846,766
Restricted cash				100,000			—
Other non-current assets				161,125			129,500

			$	23,527,712		$	9,382,977

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities
	Accounts payable		$	2,144,066		$	465,881
	Current maturity of long-term notes payable			42,227			21,977
	Accrued liabilities and other			31,405			20,393

		Total current liabilities		2,217,698			508,251
Long-term notes payable, less current portion				507,595			440,200
Deferred income taxes				—			724,470

		Total liabilities	$	2,725,293		$	1,672,921

Shareholders’ Equity
	Common shares, no par value, authorized 100,000,000 shares, 43,912,961 and 28,374,296 issued and outstanding			34,666,022			19,236,780

	Additional paid-in capital			4,493,680			1,162,768
	Common shares issuable			—			271,440
	Accumulated deficit			(18,357,283	)		(12,960,932	)

		Total shareholders’ equity		20,802,419			7,710,056

			$	23,527,712		$	9,382,977

See notes to consolidated financial statements

F-4

BPI Industries Inc.

Consolidated Statements of Operations


		Years Ended July 31

		2005			2004			2003

Revenue
	Gas sales	$	117,835		$	—		$	—
Expenses
	Lease operating expense		307,178			—			—
	Salaries and benefits		894,141			418,701			305,792
	Stock-based compensation		3,344,738			193,796			515,286
	General and administrative expenses		1,566,242			387,610			215,325
	Depreciation, depletion and amortization		260,141			80,417			58,593

			6,372,440			1,080,524			1,094,996

			(6,254,605	)		(1,080,524	)		(1,094,996	)
Other income (expense):
	Interest income		123,219			2,008			3,550
	Interest expense		(24,820	)		(15,165	)		(17,772	)
	Other income		35,385			2,454			—

			133,784			(10,703	)		(14,222	)

Loss before income taxes			(6,120,821	)		(1,091,227	)		(1,109,218	)
Deferred income tax benefit			724,470			298,111			174,913

Net loss		$	(5,396,351	)	$	(793,116	)	$	(934,305	)

Basic and diluted loss per share		$	(0.14	)	$	(0.03	)	$	(0.04	)

Weighted average common shares outstanding			37,665,019			25,007,327			21,485,381

See notes to consolidated financial statements

F-5

BPI Industries Inc.

Consolidated Statements of Shareholders’ Equity


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

Balance, July 31, 2002		19,283,035	$	14,874,211	$	439,860		$	(11,233,511	)	$	—		$	4,080,560
Proceeds from stock options exercised		150,000		78,900		—			—			—			78,900
Proceeds from warrants exercised		1,065,000		371,549		—			—			—			371,549
Proceeds from shares issued in private placement — November 7, 2002(1)		1,780,717		628,528		—			—			—			628,528
Proceeds from shares issuable in private placement		—		—		—			—			30,579			30,579
Other		—		—		13,826			—			—			13,826
Stock-based compensation		—		—		515,286			—			—			515,286
Net loss		—		—		—			(934,305	)		—			(934,305	)

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
Proceeds from shares issued in private placement — September 18, 2003		725,000		339,787		—			—			(30,579	)		309,208
Proceeds from shares issued in private placement — December 22, 2003(2)		1,975,000		928,259		—			—			—			928,259
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
Proceeds from shares issued in private placement — December 29, 2004(3)		2,400,000		2,793,854		—			—			—			2,793,854
Proceeds from shares issued in private placement — December 30, 2004(4)		4,032,000		4,693,675		—			—			—			4,693,675
Proceeds from shares issued in private placement — January 6, 2005(5)		3,723,200		4,334,199		—			—			—			4,334,199
Proceeds from shares issued in private placement — January 12, 2005(6)		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


(1)	net of share issue costs of $59,220

(2)	net of share issue costs of $18,730

(3)	net of share issue costs of $206,146

(4)	net of share issue costs of $346,325

(5)	net of share issue costs of $319,801

(6)	net of share issue costs of $18,622

See notes to consolidated financial statements

F-6

BPI Industries Inc.

Consolidated Statements of Cash Flows


			Years Ended July 31

			2005			2004			2003

Cash Provided by (Used in):
Operating Activities
	Net loss		$	(5,396,351	)	$	(793,116	)	$	(934,305	)
	Adjustments to reconcile net loss to net cash used in operating activities:
		Depreciation, depletion and amortization		260,141			80,417			58,593
		Stock-based compensation expense		3,344,738			193,796			515,286
		Gain on sale of marketable securities		(42,276	)		(2,454	)		—
		Loss on disposal of property and equipment		16,415			—			—
		Deferred income tax benefit		(724,470	)		(298,111	)		(174,913	)
		Other		20,339			(564	)		20,417
	Changes in assets and liabilities:
		Accounts receivable		(34,671	)		—			—
		Other current assets		21,392			(26,909	)		(14,035	)
		Other non-current assets		(31,625	)		(88,000	)		(41,500	)
		Accounts payable		1,678,185			323,381			(138,876	)
		Accrued liabilities and other		11,012			20,393			—

	Net cash used in operating activities			(877,171	)		(591,167	)		(709,333	)
Investing Activities
	Proceeds from sale of marketable securities			113,557			5,407			—
	Business acquisition, net of cash acquired			(857,638	)		—			—
	Additions to oil and gas properties			(5,629,953	)		(1,729,411	)		(78,522	)
	Additions to other property and equipment			(1,383,208	)		(191,794	)		(24,972	)
	Acquisition of equity interest in joint venture			(78,112	)		(100,500	)		—
	Investment in Hite Coalbed Methane, L.L.C.			—			(86,766	)		(340,097	)
	Increase in restricted cash			(100,000	)		—			—

	Net cash used in investing activities			(7,935,354	)		(2,103,064	)		(443,591	)
Financing Activities:
	Payments on long-term notes payable			(41,320	)		(26,014	)		—
	Net proceeds from issuance of common shares			15,134,553			3,524,453			1,109,556

	Net cash provided by financing activities			15,093,233			3,498,439			1,109,556

Net increase (decrease) in cash and cash equivalents				6,280,708			804,208			(43,368	)
Cash and cash equivalents at the beginning of the year				970,795			166,587			209,955

Cash and cash equivalents at the end of the year			$	7,251,503		$	970,795		$	166,587

*Supplementary cash flow information:*
	Interest paid		$	11,540		$	2,425		$	15,967
	Non-cash investing and financing activities:
	Acquisition of equipment by issuance of notes payable		$	118,049		$	105,847		$	—

F-7

BPI Industries Inc.

Notes to Consolidated Financial Statements

July 31, 2005, 2004 and 2003


1.	Summary of Significant Accounting Policies


	*Basis of Presentation and Going Concern*

The Company is incorporated in British Columbia, Canada and is involved in the acquisition, exploration and development of coalbed methane properties located in the United States of America. The Company conducts its operations in one reportable segment, which is oil and gas exploration and production.

These 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 $5,396,351 in the current year, and has an accumulated deficit of $18,357,283 at July 31, 2005. 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. As disclosed in Note 16, the Company has obtained approximately $28 million in net cash proceeds from the issuance of its common stock in September 2005 to fund its operations.

The Company has financed its activities primarily from the proceeds of various share issues. 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 from the existing facilities production and/or the disposition thereof.


	*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 future costs to dismantle, dispose of and restore the Company’s properties. 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*

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.


	*Investments in Unconsolidated Entities*

The equity method of accounting is used to account for investments in and earnings or losses of affiliates that it 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 uses 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

F-8

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

Company does not exert significant influence over HCM. 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.


	*Translation of Foreign Currency*

The Company’s Canadian operations were limited to its headquarters office in Vancouver, British Columbia until March 2005 when the Company moved its headquarters to Solon, Ohio. The Company maintains a registered records office in Vancouver, British Columbia and incurs expenses in Canada related to investor relations and regulatory matters in conjunction with its listing on the TSX Venture Exchange.

Amounts shown in the financial statements and footnotes are in U.S. dollars unless otherwise noted. The Company’s functional currency is U.S. Dollars.


	*Principles of Consolidation*

These consolidated financial statements include the accounts of the Company and its subsidiaries: Methane Management Inc. (100%), BPI Industries (USA), Inc. (100%), and Illinois Mine Gas, L.L.C. (100% – from acquisition date of March 3, 2005). 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.


	*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 the amount due from Atmos Energy Marketing, LLC as of July 31, 2005 for July 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, 2005, the Company has determined that no allowance for uncollectible receivables is 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

F-9

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

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.

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

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

In general, the Company determines if a 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, 2005 and 2004.


	*Impact of Recently Issued Accounting Pronouncements*

The Securities and Exchange Commission has issued Staff Accounting Bulletin (SAB) No. 106 regarding the application of SFAS 143, “Accounting for Asset Retirement Obligations,” on oil and gas producing entities that use the full cost accounting method. It states that the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the present value of estimated future net cash flows used for the full cost ceiling test calculation. SAB No. 106 currently has no effect on the Company’s financial statements.


	*Other Property and Equipment*

Property and equipment are stated at cost. Gas collection equipment is depreciated on the units-of-production method based on proved developed reserves. Support equipment and other property and equipment

F-10

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three to five years. Major classes of property and equipment consisted of the following at July 31:


		2005			2004

Other Property and Equipment:
	Gas collection equipment	$	1,332,012		$	106,899
	Support equipment		760,467			501,418
	Other		76,321			55,859
	Less: Accumulated depreciation and amortization		(398,988	)		(217,144	)

		$	1,769,812		$	447,032


	*Asset Retirement Obligations*

The Company follows Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). 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 incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets with a corresponding increase in the carrying amount of the related long-lived asset. The Company has assessed its asset retirement obligation as of July 31, 2005 and has currently deemed it to be immaterial.


	*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 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.

Stock-Based Compensation and Other Stock-Based Payments

The Company has a stock-based compensation plan (the “Plan”) under which stock options are issued to directors, officers, employees and consultants as determined by the Board of Directors and subject to the provisions of the Plan. The Company recognizes the compensation expense under the Plan in accordance with the Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation,” which requires the recognition of expense for stock-based compensation on their fair value on the measurement date. The Plan permits options to be issued with exercise prices at a discount to the market price of the Company’s common stock on the day prior to the date of grant. However, the majority of all stock options

F-11

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

issued under the Plan were issued with exercise prices equal to the quoted market price of the stock on the date of grant.

Options granted under the Plan are exercisable over a period not exceeding five years. The maximum number of shares that may be reserved for issuance under the Plan is a rolling number not to exceed 10% of the issued and outstanding shares of the Company at the time of the stock option grant. The Company had 4,227,279 options outstanding at July 31, 2005 and an additional 164,017 options available for issuance under the Plan.

Loss Per Share

Loss per share is calculated using the weighted average number of common shares outstanding during the year. Diluted loss per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted loss per share is not disclosed as it is anti-dilutive. Outstanding options and warrants that were excluded from the computation of diluted loss per share, as the effect of their assumed exercises would be anti-dilutive, totaled 15,786,491, 10,427,910 and 5,010,275 at July 31, 2005, 2004 and 2003, respectively.

Reclassifications

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


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. The unrealized holding gains and losses were not material for the fiscal years ended July 31, 2005, 2004 and 2003.


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. (“Vessels”) the Company’s original 50% interest in which was acquired in the fiscal year ended July 31, 2004. 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 Company’s share of the net earnings of IMG in the fiscal years ended July 31, 2005 and 2004 was not material.

The acquisition was made pursuant to a clause in the J.V. Agreement which grants the Company the option to purchase the remaining interest prior to June 30, 2005 at a stipulated priced computed based on a predetermined internal rate of return to Vessels on its capital contributions. 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. IMG has not yet commenced operations and thus has not recorded any revenue since its inception. In addition, the Company’s share of IMG’s expenses were not material.


4.	Investment in Hite Coalbed Methane, L.L.C.

The Company indirectly has an interest in the Jericho Project (“Jericho”), based on its 49% interest in Hite Coalbed Methane, L.L.C. (“HCM”). HCM has a 45% interest in Pulse Energy, L.L.C. (“Pulse”),

F-12

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

which in turn has an interest in Jericho. Pulse’s interest in Jericho currently entitles Pulse to receive 20% of any distributions made by Jericho. This interest can increase to 50% if Jericho’s cumulative distributions exceed $5,000,000. The Company made total cash contributions of $454,766 and issued a convertible note with a face value of $392,000 maturing on June 10, 2008 to acquire this interest (see Note 6). The investment in HCM is accounted for by the cost method and is included as an acquisition cost of the Jericho Project. Jericho obtained a $2 million line of credit to finance development of this project. The President of the Company personally guaranteed BPI’s portion of the line of credit and was subsequently issued 50,990 shares of the Company as consideration.


5.	Restricted Cash

The Company negotiated an agreement (“Agreement”) with one of the surface rights owners of its Southern Illinois Basin Project 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, 2005.


6.	Long-Term Notes Payable

The Company has outstanding notes payable as follows:


	July 31

	2005		2004

Case Credit term note due in fiscal year 2006, 6.50%	$	32,833	$	49,163
GMAC term notes due in fiscal year 2009, 6.50%		26,633		31,930
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%		98,356		—
Convertible note due in fiscal year 2008, 3.25%		392,000		381,084

		549,822		462,177
Less current maturities		42,227		21,977

Long-term notes payable	$	507,595	$	440,200

The Case Credit and GMAC notes are collateralized by the related vehicles and equipment. The convertible note payable outstanding was issued in June 2003 with a face value of $392,000 and maturing on June 10, 2008, bearing interest at 3.25%. The note is convertible at the option of the holder, prior to June 10, 2008, into 390,537 common shares of the Company.

The annual maturities of all notes for the five fiscal years subsequent to July 31, 2005 are as follows:


	Principal		Interest		Total

2006	$	42,227	$	8,654	$	50,881
2007		41,712		5,995		47,707
2008		419,981		67,555		487,536
2009		29,766		2,070		31,836
2010		16,136		1,702		17,838

	$	549,822	$	85,976	$	635,798

F-13

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)


7.	Income Taxes

The income tax benefit consists of the following:


		Year Ended July 31

		2005			2004			2003

Current		$	—		$	—		$	—
Deferred:
	Canadian		—			—			—
	United States		(581,582	)		(239,314	)		(140,415	)
	U.S. state taxes		(142,888	)		(58,797	)		(34,498	)

	Total deferred income taxes		(724,470	)		(298,111	)		(174,913	)

	Total income tax benefit	$	(724,470	)	$	(298,111	)	$	(174,913	)

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

		2005			2004			2003

Statutory Canadian income tax rate			(36.00	)%		(36.00	)%		(36.00	)%
Non-deductible stock compensation			21.09	%		6.39	%		16.72	%
Current year Canadian loss with no tax benefit			2.32	%		6.14	%		2.83	%
Net increase in deductible temporary differences due to foreign currency conversion and expired losses			(5.38	)%		(4.47	)%		(15.26	)%
Increase (decrease) in valuation allowance			7.32	%		2.57	%		17.31	%
Other			(1.19	)%		(1.95	)%		(1.37	)%

	Effective income tax rate		(11.84	)%		(27.32	)%		(15.77	)%

The components of the net deferred tax liability at July 31, 2005 and 2004 are shown below:


			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-14

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)


			July 31, 2004

			United States			Canada			Total

Deferred tax assets:
Net operating loss carryforwards			$	1,497,594		$	602,531		$	2,100,125
	Resource related allowances			—			1,573,717			1,573,717
	Investments and advances to subsidiaries			—			345,543			345,543

		Total non-current deferred tax asset		1,497,594			2,521,791			4,019,385
		Valuation allowance		—			(2,425,233	)		(2,425,233	)

		Net deferred tax assets		1,497,594			96,558			1,594,152

Deferred tax liabilities:
Net property plant and equipment				(2,222,064	)		(96,558	)		(2,318,622	)

		Total non-current deferred tax liability		(2,222,064	)		(96,558	)		(2,318,622	)

Net deferred tax liability			$	(724,470	)	$	—		$	(724,470	)

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.

Currently the Company has two brother-sister operating subsidiaries in the United States. The deferred tax liability of one is being used to justify not recording a valuation allowance on the deferred tax assets of the other. The Company plans to restructure the U.S. group to avail itself of the ability to file a consolidated return. This will allow the Company to offset any tax liability arising as a result of reversing deferred tax liabilities of one subsidiary with net operating loss carryforwards (deferred tax assets) of the other. There are no adverse consequences to this planned restructuring. A valuation allowance of $261,405 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 deferred tax liabilities. An increase in the valuation allowance of $215,163 has been recorded in the current fiscal year to offset the deferred tax assets 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 Carryforward at July 31, 2005 expires as follows:


	Year Ended July 31

	2006		2007		2008		2009		2010 and Later		Total

Canadian	$	338,308	$	292,245	$	46,297	$	442,034	$	668,151	$	1,787,035
United States		—		—		—		—		10,591,151		10,591,151

	$	338,308	$	292,245	$	46,297	$	442,034	$	11,259,302	$	12,378,186

At July 31, 2005 the Company also has $4,736,802 of Canadian Resource Related Deductions that have no expiration date.

F-15

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

8. Shareholders’ Equity

Common shares — The Company has authorized 100,000,000 shares without par value for which 43,912,961 and 28,374,296 were issued and outstanding as of July 31, 2005 and 2004, respectively.

Additional paid-in capital — Amounts recorded of $4,493,690 and $1,162,768 at July 31, 2005 and 2004, respectively, represent the cumulative amounts charged to stock-based compensation expense as of each fiscal year-end.

Common stock 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 January 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 is 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 will be extended to be exercisable for two years after such delisting and the Agent warrants will be extended to be exercisable for five years after the closing of the share placement.

Share purchase warrants outstanding at July 31, 2005 are as follows:


Number		Exercise
Outstanding		Price		Expiry Date

	644,375	CAD $	0.80		September 19, 2005
	1,000,000	CAD $	0.80		December 10, 2005
	3,301,100	CAD $	1.00		April 29, 2006
	1,037,200	USD $	1.25		January 15, 2007
	5,186,000	USD $	1.50		January 15, 2007

	11,168,675


9.	Commitments and Contingencies

The Company has operating lease commitments expiring at various dates. Such leases generally contain renewal options. At July 31, 2005, future minimum lease payments under non-cancelable operating leases are as follows:


2006	$	128,483
2007		107,409
2008		20,562
2009		7,019
2010		7,300
Thereafter		144,870

	$	415,643

The leases are principally for office space and gas collection equipment. Rental payments for all operating leases amounted to approximately $128,000 during the fiscal year ended July 31, 2005.

F-16

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

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, 2005 expire at various dates beginning in April 2006. 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, 2005, the amount would initially total approximately $702,000 annually and could increase to as much as $831,000 annually.


10.	Concentrations

Financial instruments which 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.

We utilize a limited number of 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. We believe that we can secure the necessary commitments from drilling companies as required. However, we can provide no assurance that our expectations regarding the availability of drilling equipment and crews from these companies will be met. A significant delay in securing the necessary drilling equipment and crews could cause a delay in production and sales, which would affect operating results adversely.


11.	Stock-Based Compensation

The table below summarizes stock options activity for the three years ended July 31, 2005. Stock options are granted 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, cancellations, exercises and expirations and at year-end exchange rates for options outstanding as of July 31, 2002, 2003, 2004 and 2005.


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

Outstanding at July 31, 2002		1,555,000		$	1.08	$	0.69
Granted — exercise price less than market price of stock on date of grant		650,000			0.56		0.38
Granted — exercise price exceeds market price of stock on date of grant		900,000			0.90		0.63
Cancelled		(800,000	)		1.20		0.84
Exercised/expired		(480,000	)		0.82		0.57

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/expired		(69,444	)		0.82		0.62

Outstanding at July 31, 2004		2,230,556			0.78		0.59

F-17

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)


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

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
Cancelled		(25,000	)		1.20		0.98
Exercised/expired		(2,254,333	)		0.87		0.72

Outstanding at July 31, 2005		4,227,279		$	1.82	$	1.49

The Company recorded stock-based compensation expense of $3,344,738, $193,796 and $515,286 in fiscal years ended July 31, 2005, 2004 and 2003, 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,

2005

2004

2003

Risk-free interest rate

3.0-3.7%

4.1%

4.0-4.3%

Expected dividend yield

Nil

Expected stock price volatility

69-81%

105%

109%

Expected option life

3 years

5 years

The weighted average fair value per option at the date of the grant for options granted in fiscal years ended July 31, 2005, 2004 and 2003 was as follows:


	2005		2004		2003

Exercise price equals market price of stock on date of grant	$	0.81	$	—	$	—
Exercise price is less than market price of stock on date of grant		0.66		0.41		0.34
Exercise price exceeds market price of stock on date of grant		—		—		0.33

Total grants	$	0.78	$	0.55	$	0.33

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-18

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes information about options outstanding as of July 31, 2005:


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

$	0.65		350,000		3.3		November 3, 2008
	0.90		143,334		1.4		January 10, 2007
	0.90		100,000		1.7		April 10, 2007
	0.90		20,000		4.1		September 22, 2009
	1.19		341,667		4.3		November 29, 2009
	1.20		50,000		1.4		January 10, 2007
	1.49		755,666		4.3		November 29, 2009
	2.19		911,000		4.5		March 27, 2010
	2.19		300,000		—		August 12, 2005
	2.36		115,000		4.7		May 23, 2010
	2.40		1,140,612		4.3		January 20, 2010

$	1.82		4,227,279		3.9


12.	Other Income (Expense), Net

Other income (expense), net consisted of the following for the fiscal years ended July 31, 2005, 2004, and 2003, respectively:


	2005			2004		2003

Gain on sale of marketable securities	$	42,276		$	2,454	$	—
Loss on disposal of property and equipment		(16,415	)		—		—
Distribution from Hite Coalbed Methane, L.L.C.		6,615			—		—
Other		2,909			—		—

	$	35,385		$	2,454	$	—


13.	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. Following is a discussion of each of the Company’s coalbed methane projects.

Southern Illinois Basin Project

On April 3, 2001, the Company acquired a 50% interest in a mineral lease on 43,000 acres of property in Williamson, Saline and Franklin Counties in the State of Illinois. On August 1, 2001, the Company acquired all the issued shares of Methane Management, Inc. (“MMI”), a private Ohio company that owned the other 50% interest in the mineral lease, through the issuance of 1,025,000 common shares of the Company.

The lease is subject to a 15% royalty and two overriding royalty interests of 3% and 4%, both of which are calculated on 43.35% of gross revenues. The lease expires in April 2006. After the initial term of the agreement, the Company can continue to hold the lease through the production of coalbed methane. For each well that continues to produce coalbed methane after the initial term of the agreement, providing a royalty payment to the lessor of the least $1.00 per acre per month, the lease will continue as to the 320 acres on

F-19

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

which the well is located, with the applicable well located in the center thereof, or, if the well is drilled into an abandoned mine works, the entire acreage of the mineworks that is drained by the applicable well. However, if at any time after the initial term of the lease the aggregate royalties do not exceed $42,000 per month, the lease will terminate.

Northern Illinois Basin Project


	Montgomery County

On October 10, 2002, the Company acquired an option to purchase a mineral lease for rights to coalbed methane gas, oil, natural gas and other hydrocarbons other than coal on approximately 121,000 acres in Montgomery County in the State of Illinois. The original option expired on July 14, 2004 but was extended for an additional 540 days. The lease, upon exercise of the option, has a primary term of five years, with production holding the lease thereafter, and is subject to a 12.5% royalty.


	Christian County

On January 20, 2004, the Company acquired an option to purchase a mineral lease for rights to coalbed methane gas, oil, natural gas and other hydrocarbons other than coal on approximately 14,000 acres in Christian County in the State of Illinois. The option expires January 20, 2007. The lease, upon exercise of the option, has a primary term of five years, with production holding the lease thereafter, and is subject to a 12.5% royalty.

Shelby County

On November 12, 2003, the Company acquired a mineral lease on approximately 63,000 acres of property in Shelby County in the State of Illinois. The lease grants the Company the mineral rights to coalbed methane gas, oil, natural gas and other hydrocarbons other than coal. The lease has a primary term of five years, with production holding the lease thereafter.

The lease is subject to a 12.5% royalty and requires the Company to commence operations for the exploration of minerals on the leased property within one year of the date of the lease or be subject to an advanced royalty payment of $0.50 per acre to defer commencement of such operations for an additional year.

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

Western Illinois Basin Project

Clinton County

On November 3, 2003, the Company acquired an option to purchase a mineral lease for rights to coalbed methane gas, oil, natural gas and other hydrocarbons other than coal on approximately 56,000 acres in Clinton County in the State of Illinois. The option expires November 3, 2005. The lease, upon exercise of the option, has a primary term of five years, with production holding the lease thereafter, and is subject to a 12.5% royalty.

Washington County

On September 9, 2003, the Company acquired an option to purchase a mineral lease for rights to coalbed methane gas, oil, natural gas and other hydrocarbons other than coal on approximately 39,000 acres in Washington County in the State of Illinois. The option expires September 9, 2006. The lease, upon exercise of

F-20

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

the option, has a primary term of five years, with production holding the lease thereafter, and is subject to a 12.5% royalty.

Marion County

On June 8, 2004, the Company acquired an option to purchase a mineral lease for rights to coalbed methane gas, oil, natural gas and other hydrocarbons other than coal on approximately 18,000 acres in Marion County in the State of Illinois.

The option expires June 8, 2007. The lease, upon exercise of the option, has a primary term of five years, with production holding the lease thereafter, and is subject to a 12.5% royalty.

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

As of July 31, 2005, the Company has not yet undertaken any testing or development activities on the Western Illinois Basin Project.

Farm-out Agreement with Addington Exploration, LLC

On November 2, 2004, the Company entered into a farm-out agreement with Addington Exploration, LLC covering 41,253 acres of coalbed methane rights in Macoupin County, Illinois and 22,997 acres 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 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. The Company has up to 24 months following this 36-month evaluation period to commence production. 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 coalbed methane 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 its proceeds from the sale of coalbed methane 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.

Costs Incurred in Oil and Gas Exploration and Development Activities

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


	2005		2004		2003

Property acquisition — proved	$	—	$	—	$	—
Property acquisition — unproved		341,634		2,664		2,896
Exploration		743,991		1,778,517		75,626
Development		5,541,022		—		—

	$	6,626,647	$	1,781,181	$	78,522

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.

F-21

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

The following table sets forth a summary of oil and gas property costs not being amortized at July 31, 2005, by the year in which such costs were incurred:


									2002
	Total		2005		2004		2003		and Prior

Property acquisition costs	$	2,404,887	$	341,634	$	2,664	$	2,896	$	2,057,693
Exploration and development, net of transfers to proved oil and gas properties		744,485		742,005		2,480		—		—

	$	3,149,372	$	1,083,639	$	5,144	$	2,896	$	2,057,693

No interest has been capitalized and included in the cost of unproved properties as of July 31, 2002 or in the fiscal years ended July 31, 2005, 2004 and 2003, as such amounts were not material. The Company expects to include the costs associated with unproved properties in its amortization computation over the next two to four 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 $58,523, $0, and $0 or $1.72/Mcf, $0/Mcf, and $0/Mcf in the fiscal years ended July 31, 2005, 2004 and 2003, respectively.


14.	Related Party Transaction

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. During the fiscal year ended July 31, 2005, the Company received approximately $59,000 in expense reimbursement related to this arrangement.

Mr. Oestreich’s brother owns Dependable Service Company, a company that provides general labor services to the Company. The Company paid Dependable Services Company $147,000 and $16,000 in fiscal years ended July 31, 2005 and 2004, respectively.

The President of the Company personally guaranteed the Company’s portion of the line of credit in the Jericho Project and was subsequently issued 50,990 shares of the Company as consideration during the fiscal year ended July 31, 2005.


15.	Technical Services Agreement

On March 31, 2005, the Company signed a Technical Services Agreement (“TSA”) with BHP Petroleum (Exploration) Inc., a wholly owned subsidiary of BHP Billiton, (“BHP”) to provide technical services related to BHP’s techniques and know-how in the areas of drilling and completion of in-seam coalbed methane wells as well as methane recovery from coal mining operations. These techniques and know-how will be utilized on the Company’s projects in the Illinois Basin.

During the term of the TSA, any extension of the term and the six-month period after the expiration of the term, none of BHP or any of its affiliates may enter into any agreement to provide technical assistance to a coalbed methane operator within the Illinois Basin or acquire a direct or indirect interest in any coalbed methane assets located in the Illinois Basin without our prior consent. However, BHP can terminate the TSA and these exclusivity restrictions if it acquires an equity interest in any company that holds mineral rights in

F-22

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

the Illinois Basin, so long as such mineral rights do not constitute a majority of the economic value of the subject company.

In connection with the TSA, we have granted BHP a right of first refusal to acquire us. Before we can extend or accept an offer for any third party to acquire a majority of our stock or assets, we must permit BHP to acquire the same stock or assets on the terms proposed to be extended to or accepted from the third party. The right of first refusal expires on September 30, 2006.

In consideration for BHP entering into the TSA, we agreed to issue BHP 4.0 million stock appreciation rights. The stock appreciation rights, which may be exercised by BHP only in connection with its acquisition of us, will have a value equal to the number of stock appreciation rights multiplied by the excess of the market price of our common stock on the date of exercise over CAD$2.18/share (the market price on March 31, 2005 as reported by the TSX Venture Exchange). BHP may exercise the stock appreciation rights only during the term of the TSA, any extension of the term and the six-month period after the expiration of the term. In connection with the exercise of the stock appreciation rights, BHP may elect to convert the rights into cash or a credit against the consideration payable by BHP in connection with its acquisition of us. The stock appreciation rights will terminate if BHP materially breaches the TSA or we are sold to a third party or a majority of our stock or assets is acquired by a third party. We are required to issue BHP an additional 2.0 million stock appreciation rights upon the commencement of the first six-month extension of the term of the TSA.

The term of the TSA extends until September 30, 2006, and BHP may elect to extend the term of the agreement for additional six-month periods. BHP may terminate the agreement at any time upon 90 days notice to us, and we may terminate the agreement if BHP materially breaches the agreement. If BHP elects to terminate the agreement, its stock appreciation rights and right of first refusal will immediately expire. The agreement terminates if we are sold to a third party or a majority of our stock or assets is acquired by a third party.

The Company has accounted for the stock appreciation rights granted to BHP in accordance with Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). Under SFAS No. 123, all transactions in which goods or services are the consideration received for the issuance of equity instruments shall be accounted for based on the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable, by recording an increase in “oil and gas properties — unproved” and recognizing an accrued liability for a corresponding amount. The Company has estimated the value of the stock appreciation rights granted to BHP to be $18,000 based on the estimated fair value of technical services to be received by the Company from BHP, because the fair value of such services was more readily determinable than the fair value of the stock appreciation rights.

The Company’s policy is to reassess the amount of liability associated with this TSA in each reporting period by first determining whether the fair value of the stock appreciation rights is more readily determinable than the fair market value of the technical services received by the Company from BHP. In reassessing the fair value of the technical services received, the reassessment is based on the services currently being provided by BHP, as well as any additional services the Company anticipates BHP will provide over the remaining term of the TSA. After determining which amount is more readily determinable, the Company’s policy is to record an additional liability for any increase in the estimated amount of the future liability over the liability previously recorded.

F-23

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)


16.	Subsequent Event

In September 2005, the Company sold 18,000,000 shares of common stock in a private placement to five institutional investors. The net proceeds from this private placement of approximately $28,000,000 will be used to fund the Company’s plan of operations and for working capital and general corporate purposes.

In connection with this private placement, the Company entered into an agreement with the investors that subjects the Company to cash penalties if the Company fails to file a registration statement and cause that registration statement to become effective within 90 days (or 150 days if the Securities and Exchange Commission decides to review the registration statement) after the September 26, 2005 closing date. In addition, the Company is subject to penalties if the investors covered by this agreement are prohibited from selling shares under the registration statement for a period exceeding 90 days during any 12 month period as a result of suspensions effected by the Company. The aggregate amount of payments to the investors under these provisions together may not exceed 13% of the aggregate purchase price paid by the investors. Based on this 13% cap, the Company will not be required to make payments to the investors under these provisions in excess of $3,965,508.


17.	Supplemental Oil and 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 table below sets forth the Company’s results of operations from oil and gas producing activities for the fiscal year ended July 31, 2005. The Company commenced production and sales of gas during fiscal year ended July 31, 2005. The Company had no revenues or operating expenses of oil and gas activities in fiscal years ended July 31, 2004 or 2003.


Gas revenues	$	117,835
Production costs		(307,178	)
Depreciation, depletion and amortization		(238,366	)

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

Loss from oil and gas producing activities	$	(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 oil and 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 oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and 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)

F-24

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

to be incurred on pretax net cash flows 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 used at July 31, 2005 was $7.44 per Mcf.

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 petroleum engineers.

Summary of Changes in Proved Reserves


		Year Ended July 31,

		2005			2004		2003

		Mcf			Mcf		Mcf

Proved reserves
	Beginning of year		—			—		—
	Purchase of reserves in place		—			—		—
	Extensions and discoveries		10,325,989			—		—
	Revisions of previous estimates		—			—		—
	Production		(33,967	)		—		—

	End of year		10,292,022			—		—

Proved developed reserves
	Beginning of year		—			—		—
	End of year		2,970,606			—		—

Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Gas Reserves


	July 31,

	2005			2004		2003

	(Amounts in thousands)
Future cash inflows	$	76,608		$	—	$	—
Future production costs and taxes		(10,181	)		—		—
Future development costs		(7,824	)		—		—
Future income tax expenses		(14,663	)		—		—

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

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

F-25

BPI Industries Inc.

Notes to Consolidated Financial Statements — (Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Gas Reserves


		Year Ended July 31,

		2005			2004		2003

		(Amounts in thousands)
Standardized measure, beginning of year		$	—		$	—	$	—
Sales, net of production costs and taxes			189			—		—
Extensions and discoveries			27,758			—		—
Purchases of reserves in place			—			—		—
Net changes in prices and production costs			—			—		—
Revisions of quantity estimates			—			—		—
Net changes in development costs			(5,541	)		—		—
Interest factor — accretion of discount			—			—		—
Net change in income taxes			—			—		—
Changes in production rates (timing) and other			662			—		—

	Net increase		23,068			—		—

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

F-26

BPI Energy Holdings, Inc.

Consolidated Balance Sheets

ASSETS


			January 31, 2006			July 31, 2005

			(Unaudited)
Current Assets:
	Cash and cash equivalents		$	26,623,707		$	7,251,503
	Accounts receivable			159,634			34,671
	Other current assets			270,445			23,534

		Total current assets		27,053,786			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 $142,023 and $58,523		15,970,561			10,190,929
		Unproved		3,244,807			3,149,372

	Net oil and gas properties			19,215,368			13,340,301
	Other property and equipment, net of accumulated depreciation and amortization of $462,530 and $398,988			4,434,311			1,769,812

	Net property and equipment			23,649,679			15,110,113
Investment in Hite Coalbed Methane, L.L.C.				—			846,766
Restricted cash				134,000			100,000
Other non-current assets				161,125			161,125

			$	50,998,590		$	23,527,712


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	1,486,767		$	2,144,066
	Current maturity of long-term notes payable			239,071			42,227
	Accrued liabilities and other			72,145			31,405

		Total current liabilities		1,797,983			2,217,698
Long-term notes payable, less current portion				94,768			507,595
Other non-current liabilities				45,949			—

		Total liabilities		1,938,700			2,725,293
Shareholders’ equity:
	Common shares, no par value, authorized 100,000,000 shares, 64,378,087 and 43,912,961 outstanding			64,573,394			34,666,022
	Additional paid-in capital			4,891,266			4,493,680
	Accumulated deficit			(20,404,770	)		(18,357,283	)

		Total shareholders’ equity		49,059,890			20,802,419
			$	50,998,590		$	23,527,712

See notes to unaudited consolidated financial statements.

F-27

BPI Energy Holdings, Inc.

Consolidated Statements of Operations

(Unaudited)


		Three Months Ended January 31						Six Months Ended January 31

		2006			2005			2006			2005

Revenues:
	Gas sales	$	327,811		$	6,341		$	537,505		$	6,341
Expenses:
	Lease operating expense		300,806			—			461,610			—
	General and administrative expenses		1,165,483			2,752,852			2,437,239			3,165,087
	Depreciation, depletion and amortization		117,890			34,086			212,692			57,672

			1,584,179			2,786,938			3,111,541			3,222,759

Other income (expenses):
	Interest income		270,186			4,353			402,804			4,847
	Interest expense		(6,234	)		(5,407	)		(13,778	)		(10,582	)
	Other income (expense)		138,191			3,246			137,523			3,246

			402,143			2,192			526,549			(2,489	)

Loss before income taxes			(854,225	)		(2,778,405	)		(2,047,487	)		(3,218,907	)
Deferred income tax benefit			—			292,562			—			344,717

Net loss		$	(854,225	)	$	(2,485,843	)	$	(2,047,487	)	$	(2,874,190	)

Basic and diluted loss per share		$	(0.01	)	$	(0.07	)	$	(0.04	)	$	(0.09	)

Weighted average common shares outstanding			63,654,794			34,790,336			57,889,094			32,018,325

See notes to unaudited consolidated financial statements.

F-28

BPI Energy Holdings, Inc.

Consolidated Statements of Shareholders’ Equity

(Unaudited)


	Common Shares				Additional					Total
					Paid-In		Accumulated			Shareholder
	Shares		Amounts		Capital		Deficit			Equity

Balance, July 31, 2005		43,912,961	$	34,666,022	$	4,493,680	$	(18,357,283	)	$	20,802,419
Proceeds from stock options exercised		391,667		379,379		—		—			379,379
Proceeds from warrants exercised		2,073,459		1,644,039		—		—			1,644,039
Net proceeds from shares issued in private placement — September 23, 2005(1)		18,000,000		27,883,954		—		—			27,883,954
Stock-based compensation		—		—		397,586		—			397,586
Net loss		—		—		—		(2,047,487	)		(2,047,487	)

Balance, January 31, 2006		64,378,087	$	64,573,394	$	4,891,266	$	(20,404,770	)	$	49,059,890


(1)	Net of share issuance costs of $2,619,953

See notes to unaudited consolidated financial statements.

F-29

BPI Energy Holdings, Inc.

Consolidated Statements of Cash Flows

(Unaudited)


			Six Months Ended January 31

			2006			2005

Operating activities:
	Net loss		$	(2,047,487	)	$	(2,874,190	)
	Adjustments to reconcile net loss to net cash used in operating activities:
		Depreciation, depletion and amortization		212,692			57,672
		Stock-based compensation expense		397,586			2,200,777
		Gain on sale of investment		(127,416	)		(3,246	)
		Deferred income tax benefit		—			(344,717	)
		Other		—			14,881
	Changes in assets and liabilities:
		Accounts receivable		(124,963	)		(6,341	)
		Other current assets		(246,911	)		(17,714	)
		Accounts payable		(657,299	)		(99,039	)
		Accrued liabilities and other		71,922			496
		Other non-current liabilities		45,949			—

	Net cash used in operating activities			(2,475,927	)		(1,071,421	)
Investing activities:
	Proceeds from sale of investment			551,000			43,956
	Additions to oil and gas properties			(5,958,567	)		(1,907,403	)
	Additions to other property and equipment			(2,560,216	)		(371,736	)
	Acquisition of equity interest in joint venture			—			(78,112	)
	Increase in restricted cash			(34,000	)		—

Net cash used in investment activities				(8,001,783	)		(2,313,295	)
Financing activities:
	Payments on long-term notes payable			(57,458	)		(14,828	)
	Net proceeds from issuance of common shares			29,907,372			14,140,215

	Net cash provided by financing activities			29,849,914			14,125,387

Net increase in cash and cash equivalents				19,372,204			10,740,671
Cash and cash equivalents at the beginning of the period				7,251,503			970,795

Cash and cash equivalents at the end of the period			$	26,623,707		$	11,711,466

*Supplementary disclosure of cash flow information:*
	Non-cash investing and financing activity:
	Acquisition of equipment by issuance of notes payable		$	233,475		$	—

Interest paid approximates interest expense.

See notes to unaudited consolidated financial statements.

F-30

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements

(Unaudited)


1.	Summary of Significant Accounting Policies

Basis of Presentation

These unaudited consolidated interim financial statements include the accounts of BPI Energy Holdings, Inc. and its wholly owned U.S. subsidiary, BPI Energy, Inc. (collectively, “the Company”). 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 acquisition, exploration and development of coalbed methane properties located in the United States of America. 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.

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the quarter and six months ended January 31, 2006 are not necessarily indicative of the results that may be expected for the full fiscal year. For further information, refer to the consolidated financial statements and notes thereto included in the Company’s Form S-1 filed with the Securities and Exchange Commission on December 5, 2005. Certain prior period amounts have been reclassified to conform to current period presentation.

Use of Estimates

The preparation of these unaudited 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 future costs to dismantle, dispose of, and restore the Company’s properties. 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.

Oil and Gas Properties

F-31

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements — (Continued)

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



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



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



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



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

Other Property and Equipment

Property and equipment are stated at cost. Gas collection equipment is depreciated on the units-of-production method based on 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 property and equipment consisted of the following:


		January 31,			July 31,
		2006			2005

Other Property and Equipment:
	Gas collection equipment	$	3,758,264		$	1,332,012
	Support equipment		1,058,731			760,467
	Other		79,846			76,321
	Less: Accumulated depreciation and amortization		(462,530	)		(398,988	)

		$	4,434,311		$	1,769,812

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

F-32

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 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 $19,778.

The following table summarizes the activity for the Company’s asset retirement obligations for the six months ended January 31, 2006 and 2005:


	Six Months
	Ended
	January 31,

	2006		2005

Asset retirement obligation at beginning of period	$	19,778	$	—
Accretion expense		1,335		—
Liabilities incurred		24,836		—

Asset retirement obligation at end of period	$	45,949	$	—

Loss Per Share

Loss per share is calculated using the weighted average number of common shares outstanding during the year. Diluted loss per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted loss per share is not disclosed as all common share equivalents were anti-dilutive for the quarter and six months ended January 31, 2006. Outstanding options and warrants that were excluded from the computation of diluted loss per share, as the effect of their assumed exercises would be anti-dilutive, totaled 14,844,215 at October 31, 2005 and 13,150,828 at January 31, 2006.

Share-Based Payment

Prior to December 13, 2005 the Company 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 the Company’s common stock 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 options to purchase 4,030,612 shares of common stock outstanding under the Incentive Stock Option Plan at January 31, 2006.

On December 13, 2005, the shareholders of the Company approved the BPI Industries Inc. 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 will be 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

F-33

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements — (Continued)

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 as of January 31, 2006.

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

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


2.	Stock-Based Compensation

The tables below summarize stock options activity for the six months ended January 31, 2006 and 2005, respectively. All stock options were granted with exercise prices denominated in Canadian Dollars. U.S. Dollar amounts shown in the tables below were derived using published exchange rates on the date of the transaction for grants, cancellations, exercises and expirations and at period-end exchange rates for options outstanding as of July 31, 2005 and 2004 and January 31, 2006 and 2005.


				Weighted-Average
				Exercise Price
	Number of
Six Months Ended January 31, 2006:	Options			CAD$		USD$

Outstanding at July 31, 2005		4,227,279		$	1.82	$	1.49
Granted — exercise price equal to market price of stock on date of grant		495,000			2.05		1.75
Exercised		(341,667	)		1.19		1.00
Cancelled		(300,000	)		1.82		1.52

Outstanding at October 31, 2005		4,080,612		$	1.88	$	1.60
Exercised		(50,000	)		1.43		1.22

Outstanding at January 31, 2006		4,030,612		$	1.88	$	1.64

F-34

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements — (Continued)


				Weighted-Average
				Exercise Price

Six Months Ended January 31, 2005:	Number of Options			CAD$		USD$

Outstanding at July 31, 2004		2,230,556		$	.78	$	0.59
Cancelled		(13,889	)		1.20		0.98

Outstanding at October 31, 2004		2,216,667		$	0.77	$	0.63
Granted — exercise price equal to market price of stock on date of grant		2,097,278			1.93		1.55
Granted — exercise price less than market price of stock on date of grant		852,778			1.19		.96
Exercised		(1,040,000	)		0.69		0.57
Cancelled		(11,111	)		1.20		0.98

Outstanding at January 31, 2005		4,115,612		$	1.47	$	1.19

The Company recorded stock-based compensation expense of $397,586 and $2,200,777 in the six months ended January 31, 2006, and 2005, respectively. The fair value of stock options granted was estimated using the Black-Scholes Option Pricing Model with the following assumptions:


	Six Months Ended
	January 31,

	2006			2005

Risk-free interest rate		3.3	%		3.0 - 3.5	%
Expected dividend yield		Nil			Nil
Expected stock price volatility		66	%		74 - 81	%
Expected option life		3 years			3 years

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


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

$	0.65		350,000		2.8		November 3, 2008
	0.90		143,334		0.9		January 10, 2007
	0.90		100,000		1.2		April 10, 2007
	0.90		15,000		3.6		September 22, 2009
	1.20		50,000		0.9		January 10, 2007
	1.49		710,666		3.8		November 29, 2009
	2.05		495,000		4.6		September 22, 2010
	2.19		911,000		4.2		March 27, 2010
	2.36		115,000		4.3		May 23, 2010
	2.40		1,140,612		4.0		January 20, 2010

$	1.88		4,030,612		3.8

F-35

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements — (Continued)


3.	Income Taxes

We operate in two tax jurisdictions, the United States and Canada. Primarily as a result of the net operating losses that we have generated (“NOL Carryforwards”) in both Canada and the United States, we have generated deferred tax benefits available for tax purposes to offset net income in future periods. SFAS No. 109, Accounting for Income Taxes, requires that we record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of sufficient future taxable income before the expiration of the NOL Carryforwards. Because of the Company’s limited operating history, limited financial performance and cumulative tax loss from inception, it is management’s judgment that SFAS No. 109 requires the recording of a full valuation allowance for net deferred tax assets in both Canada and the United States as of January 31, 2006.

We recorded a tax benefit in the United States for the six months ended January 31, 2005 to partially offset a net deferred tax liability at January 31, 2005; however, no tax benefit was recognized for the six months ended January 31, 2006 as the Company had no net deferred tax liability to offset.


4.	Long-Term Notes Payable

The Company has outstanding notes payable as follows:


	January 31,			July 31,
	2006			2005

Case Credit term note due in fiscal year 2006, 6.50%	$	28,582		$	32,833
GMAC term notes due in fiscal year 2009, 6.50%		25,163			26,633
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%		94,979			98,356
Convertible note due in fiscal year 2008, 3.25%		—			392,000
Caterpillar Financial Services Corp.		195,568			—

		333,839			549,822
Less current maturities		(239,071	)		(42,227	)

Long-term notes payable	$	94,768		$	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 7.

The annual maturities of all notes for the remaining six months of fiscal year 2006 and the four fiscal years thereafter are as follows:


	Principal		Interest		Total

2006	$	137,451	$	9,201	$	146,652
2007		121,239		7,160		128,399
2008		27,982		3,855		31,837
2009		29,767		2,070		31,837
2010		17,400		440		17,840

	$	333,839	$	22,726	$	356,565

F-36

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements — (Continued)


5.	Shareholders’ Equity

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, will be used to fund the Company’s plan of operations and for working capital and general corporate purposes.

The Company has share purchase warrants outstanding at January 31, 2006 as follows:


Number		Exercise
Outstanding		Price		Expiry Date

	3,177,016	CAD $	1.00		April 29, 2006
	4,906,000	USD $	1.50		December 13, 2007
	1,037,200	USD $	1.25		January 15, 2010

	9,120,216


6.	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 CBM. Beginning in the 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 $38,451 and $0 in expense reimbursement related to this arrangement during the six months ended January 31, 2006 and 2005, 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 $160,679 and $54,929 during the six months ended January 31, 2006 and 2005, respectively.


7.	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 quarter and six months ended January 31, 2006.


8.	Legal Proceedings

F-37

BPI Energy Holdings, Inc.

Notes to Consolidated Financial Statements — (Continued)


9.	Subsequent Event

On February 9, 2006, at a special meeting of the Company’s shareholders, the shareholders voted to approve amendments to the Company’s governing documents that:

1. changed the name of the Company to BPI Energy Holdings, Inc.;

2. increased the number of shares of common stock that the Company is authorized to issue from 100 million shares to 200 million shares;

3. increased the quorum necessary to transact business at a meeting of the Company’s shareholders to the holders of 33¹/3 % of the Company’s shares of common stock; and

4. permit meetings of the Company’s shareholders to be held outside of British Columbia, Canada.

Each of the amendments to the Company’s governing documents was previously approved by the unanimous vote of the Company’s Board of Directors.

F-38

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution*

The following are the estimated expenses in connection with the registration and sale of the securities covered by this registration statement:


SEC registration fee	$	4,695
Accounting		500
Legal fees and expenses		25,000
Printing		10,000

Total	$	40,195

The Registrant will pay all of these expenses.


Item 14.	*Indemnification of Directors and Officers*

In accordance with the British Columbia Business Corporations Act, we may indemnify our directors and officers against any judgment, penalty or fine awarded against or imposed upon them in connection with, or amounts paid in settlement by them of, any legal proceeding or investigative action and, after the final disposition of a legal proceeding or investigative action, may pay the costs, charges and expenses actually and reasonably incurred by them by reason of the fact that they were or are directors or officers of the corporation. Pursuant to the British Columbia Business Corporations Act, we are required to pay to our directors and officers the costs, charges and expenses (including legal and other fees) actually and reasonably incurred by them in connection with any legal proceeding or investigative action brought by third parties by reason of the fact that they were or are directors or officers of the corporation, if the directors or officers acted honestly and in good faith with a view to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable grounds to believe their conduct was unlawful. We may not indemnify our directors or officers or pay their expenses in connection with a derivative action against us (i.e., one that is brought by or on behalf of the corporation).

Subject to the British Columbia Business Corporations Act, our Articles require us to indemnify our directors and former directors and their heirs and legal personal representatives against all judgments, penalties and fines awarded or imposed in connection with, or an amount paid in settlement of, any legal proceeding or investigative action pursuant to which such person is or may be liable. We must, after the final disposition of a legal proceeding or investigative action, pay the expenses actually and reasonably incurred by such persons in respect of that proceeding. We may indemnify any other person, subject to the restrictions of the British Columbia Business Corporations Act.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the company pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the company of expenses incurred or paid by a director, officer or controlling person in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the Securities Act, and will be governed by the final adjudication of such issue.


Item 15.	*Recent Sales of Unregistered Securities*

In the three years prior to the filing of this registration statement, we issued the following unregistered securities. We did not use a principal underwriter for any of the issuances listed in the first table. Each such

II-1

sale was exempt from registration under the Securities Act in reliance on Section 4(2) of the Securities Act and/or regulations issued thereunder as sales principally to accredited investors not involving a public offering.


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

9/18/03	Units consisting of 725,000 shares of common stock and warrants to purchase 725,000 shares of common stock for CAD$0.80 per share.		USD$0.47 per Unit		USD$340,076
12/3/03	Units consisting of 1,950,000 shares of common stock and warrants to purchase 1,950,000 shares of common stock for CAD$0.80 per share.		USD$0.49 per Unit		USD$960,000
4/29/04	Units consisting of 3,326,100 shares of common stock and warrants to purchase 3,326,100 shares of common stock for CAD$1.00 per share.		USD$0.58 per Unit		USD$1,942,674

In December 2004 and January 2005, we issued the following unregistered securities. Included in these shares is the warrant to purchase 1,037,200 shares of our common stock, at a price equal to USD$1.25 per share, that we issued to Sanders Morris Harris Inc. as compensation for serving as placement agent for the offering. Each such sale was exempt from registration under the Securities Act in reliance on Section 4(2) of the Securities Act and/or regulations issued thereunder as sales to accredited investors not involving a public offering.


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

12/30/04 to 1/13/05	Units consisting of 10,372,000 shares of common stock and warrants to purchase 5,186,000 shares of common stock for USD$1.50 per share.		USD$2.50 per Unit		USD$12,965,000
	A warrant to purchase 1,037,200 shares of common stock for USD$1.25 per share.

On September 26, 2005, we issued the following unregistered securities. KeyBanc Capital Markets, a division of McDonald Investments, Inc., and Sanders Morris Harris, Inc. acted as placement agents. Each such sale was exempt from registration under the Securities Act 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 shares of common stock		USD$1.69		USD$30,500,000

During the three years prior to the filing of this registration statement, we issued the following unregistered securities to our employees and Directors: 5,346,056 options to purchase common stock, 2,325,000 shares of restricted common stock and 440,000 shares of unrestricted common stock. These issuances were exempt from registration under the Securities Act in reliance on Section 4(2) of the Securities Act, as sales not involving a public offering, and/or Rule 701 of the Securities Act, as an offering to employees under a compensatory benefit plan. As of May 1, 2006, there are 1,872,812 options to purchase common stock outstanding.

II-2


Item 16.	*Exhibits and Financial Statement Schedule*

(a) Exhibits:


	See the Exhibit Index, which is hereby incorporated herein by reference.

(b) Financial Statement Schedules:


	All schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedules, or because the information required is included in the financial statements and notes thereto.


Item 17.	*Undertakings*

(a) The undersigned registrant hereby undertakes:


	(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:


	(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

	(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or in the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

	(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;


	(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof; and

	(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(h) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers, and controlling persons of the registrant, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this post-effective amendment to registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Solon, Ohio, on May 11, 2006.


	BPI Energy Holdings, Inc.

Date: May 11, 2006


	By:	/s/ George J. Zilich



	George J. Zilich,
	Chief Financial Officer and General Counsel

Pursuant to the requirements of the Securities Act of 1933, this post-effective amendment to registration statement has been signed by the following persons in the capacities and on the date indicated.


Signature		Title


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

/s/ George J. Zilich George J. Zilich		Chief Financial Officer, General Counsel and Director

/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/ George J. Zilich George J. Zilich, Attorney-in-Fact for the officers and directors signing in the capacities indicated	Date: May 11, 2006

II-4

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).

	5	.1	Opinion of Anfield Sujir Kennedy & Durno.(+)

	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 shares of its common stock 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 Holdings, 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 Holdings, 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 Holdings, 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 Holdings, Inc. and the County of Clinton, Illinois (Western Illinois Basin Project).(*)

	10	.12	Option to Purchase Mineral Lease, dated as of September 9, 2003, by and between BPI Energy Holdings, 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 Holdings, Inc. and the County of Marion, Illinois (Western Illinois Basin Project).(*)

	10	.14	Farmout Agreement, dated as of November 2, 2004, by and between BPI Energy Holdings, Inc. and Addington Exploration, LLC (Northern Illinois Basin and Western Illinois Basin Projects).(*)

	10	.15	Incentive Stock Option Plan of BPI Energy Holdings, Inc., dated as of December 16, 2002.(*)

	10	.16	Employment Letter Agreement, dated as of January 6, 2005, by and between BPI Energy Holdings, Inc. and George J. Zilich.(*)

	10	.17	Employment Letter Agreement, dated as of January 31, 2005, by and between BPI Energy Holdings, Inc. and Randy Elkins.(*)

	10	.18	Agreement, dated as of April 17, 2004, by and between BPI Energy Holdings, Inc. and James G. Azlein.(*)

	10	.19	Confidential Lock-Up Agreement, dated as of December 31, 2004, by and between BPI Energy Holdings, Inc. and James G. Azlein.(*)

	10	.20	Form of Confidential Lock-Up Agreement, dated as of December 31, 2004.(*)


Number			Description


	10	.21	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	.22	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	.23	Form of Confidential Lock-up Agreement, dated September 26, 2005.(***)

	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).

	16	.1	Letter from former independent accounting firm, De Visser Gray, Chartered Accountants, pursuant to Item 304 of Regulation S-K.(***)

	21	.1	Subsidiaries of BPI Energy Holdings, Inc.(+)

	23	.1	Consent of De Visser Gray, Chartered Accountants.(+)

	23	.2	Consent of Anfield Sujir Kennedy & Durno (included in Exhibit 5.1).

	23	.3	Consent of Schlumberger Technology Corporation.(+)

	23	.4	Consent of Meaden & Moore, Ltd.(+)

	24	.1	Power of Attorney, dated as of April 28, 2006.(+)



(*)	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.