UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

BPI Energy Holdings, Inc.

(Exact Name of Registrant as Specified in Its Charter)

British Columbia, Canada		75-3183021
(State or Other Jurisdiction of		(I.R.S. Employer Identification No.)
Incorporation or Organization)
30775 Bainbridge Road, Suite 280, Solon, Ohio		44139
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code: (440) 248-4200

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Common Shares, without par value, as of June 12, 2006: 70,812,540

 

 

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BPI Energy Holdings, Inc.
Consolidated Balance Sheets

		April 30, 2006				July 31, 2005
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	24,793,727			$	7,251,503
Accounts receivable			126,102				34,671
Other current assets			225,024				23,534
Total current assets			25,144,853				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 $226,927 and $58,523			20,973,084				10,190,929
Unproved			1,274,205				3,149,372
Net oil and gas properties			22,247,289				13,340,301
Other property and equipment, net of accumulated depreciation and amortization of $567,614 and $398,988			4,723,150				1,769,812
Net property and equipment			26,970,439				15,110,113
Investment in Hite Coalbed Methane, L.L.C.			—				846,766
Restricted cash			134,173				100,000
Other non-current assets			161,125				161,125
			52,410,590				23,527,712
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable			897,010				2,144,066
Current maturity of long-term notes payable			201,533				42,227
Accrued liabilities and other			3,038,601				31,405
Total current liabilities			4,137,144				2,217,698
Long-term notes payable, less current portion			83,458				507,595
Other non-current liabilities			51,678				—
Total liabilities			4,272,280				2,725,293
Shareholders’ equity:
Common shares, no par value, authorized 200,000,000 shares, 70,812,540 and 43,912,961 outstanding			68,593,404				34,666,022
Additional paid-in capital			4,891,266				4,493,680
Accumulated deficit			(25,346,360	)			(18,357,283	)
Total shareholders’ equity			48,138,310				20,802,419
		$	52,410,590			$	23,527,712

See Notes to Unaudited Consolidated Financial Statements.

BPI Energy Holdings, Inc.
Consolidated Statements of Operations
(Unaudited)

		Three Months Ended April 30								Nine Months Ended April 30
		2006				2005				2006				2005
Revenues:
Gas sales		$	262,860			$	46,925			$	800,365			$	53,266
Expenses:
Lease operating expense			290,844				203,289				752,454				203,289
General and administrative expenses			2,054,434				1,847,554				4,491,676				5,012,641
Depreciation, depletion and amortization			189,988				83,129				402,680				140,801
			2,535,266				2,133,972				5,646,810				5,356,731
Other income (expenses):
Interest income			229,888				62,012				632,693				66,859
Interest expense			(4,276	)			(3,804	)			(18,054	)			(14,386	)
Other income (expense), net			(2,894,794	)			24,053				(2,757,271	)			27,299
			(2,669,182	)			82,261				(2,142,632	)			79,772
Loss before income taxes			(4,941,588	)			(2,004,786	)			(6,989,077	)			(5,223,693	)
Deferred income tax benefit			—				270,587				—				615,304
Net loss		$	(4,941,588	)		$	(1,734,199	)		$	(6,989,077	)		$	(4,608,389	)
Basic and diluted loss per share		($	0.07	)		($	0.04	)		($	0.12	)		($	0.13	)
Weighted average common shares outstanding			66,395,782				43,128,791				60,686,413				35,640,418

See Notes to Unaudited Consolidated Financial Statements.

BPI Energy Holdings, Inc.
Consolidated Statements of Shareholders’ Equity
(Unaudited)

										Additional								Total
		Common Shares								Paid-in				Accumulated				Shareholders’
		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			396,667				382,239				—				—				382,239
Proceeds from warrants exercised			5,822,075				5,013,928				—				—				5,013,928
Net proceeds from shares issued in private placement – September 23, 2005 (1)			18,000,000				27,883,954				—				—				27,883,954
Stock-based compensation – stock options			—				—				397,586				—				397,586
Stock-based compensation – common stock, including vesting of restricted stock			496,339				647,261				—				—				647,261
Unvested portion of restricted shares issued			2,184,498				—				—				—				—
Net loss			—				—				—				(6,989,077	)			(6,989,077	)
Balance, April 30, 2006			70,812,540			$	68,593,404			$	4,891,266			$	(25,346,360	)		$	48,138,310

See Notes to Unaudited Consolidated Financial Statements.

BPI Energy Holdings, Inc.
Consolidated Statements of Cash Flows
(Unaudited)

		Nine Months Ended April 30
		2006				2005
Operating activities:
Net loss		$	(6,989,077	)		$	(4,608,389	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization			402,680				140,801
Stock-based compensation expense			1,044,847				3,240,183
Gain on sale of investment			(127,416	)			(14,844	)
Deferred income tax benefit			—				(615,304	)
Other			—				17,610
Changes in assets and liabilities:
Accounts receivable			(91,431	)			(23,910	)
Other current assets			(201,490	)			(12,902	)
Accounts payable			(1,247,056	)			236,852
Accrued liabilities and other			3,038,378				8,277
Other non-current liabilities			51,678				—
Net cash used in operating activities			(4,118,887	)			(1,631,626	)
Investing activities:
Proceeds from sale of investments			551,000				62,160
Business acquisition, net of cash acquired			—				(857,638	)
Additions to oil and gas properties			(9,075,392	)			(2,969,450	)
Additions to other property and equipment			(2,954,139	)			(414,041	)
Acquisition of equity interest in joint venture			—				(78,112	)
Increase in restricted cash			(34,173	)			(100,000	)
Net cash used in investment activities			(11,512,704	)			(4,357,081	)
Financing activities:
Payments on long-term notes payable			(106,306	)			(28,843	)
Net proceeds from issuance of common shares			33,280,121				14,942,359
Net cash provided by financing activities			33,173,815				14,913,516
Net increase in cash and cash equivalents			17,542,224				8,924,809
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		$	24,793,727			$	9,895,604
Supplementary disclosure of cash flow information:
Non-cash investing and financing activity:
Acquisition of equipment by issuance of notes payable		$	233,475			$	—
Interest paid		$	14,132			$	12,043

See Notes to Unaudited Consolidated Financial Statements.

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 for and production 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 nine months ended April 30, 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 Post-Effective Amendment No.1 to Form S-1 filed with the Securities and Exchange Commission on May 11, 2006. Certain prior period amounts have been reclassified to conform to the 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, 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
		The Company follows the full cost method of accounting for oil and gas properties. Under this

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

		April 30				July 31
		2006				2005
Other Property and Equipment:
Gas collection equipment		$	4,149,653			$	1,332,012
Support equipment			1,046,989				760,467
Other			94,122				76,321
Less: Accumulated depreciation and amortization			(567,614	)			(398,988	)
		$	4,723,150			$	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 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 nine months ended April 30, 2006 and 2005:

		Nine Months Ended April 30
		2006				2005
Asset retirement obligation at beginning of period		$	19,778			$	—
Accretion expense			2,464				—
Liabilities incurred			29,436				—
Asset retirement obligation at end of period		$	51,678			$	—

		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 quarters and nine months ended April 30, 2006 and 2005. The following items were excluded from the computation of diluted loss per share at April 30, 2006 and 2005, respectively, as the effect of their assumed exercises would be anti-dilutive:

		2006				2005
Outstanding warrants			5,311,600				11,306,175
Outstanding stock options			1,872,812				4,245,612
Unvested portion of restricted shares issued			2,184,498				—
			9,368,910				15,551,787

		Share-Based Payment
		Prior to December 13, 2005 the Company administered a stock-based compensation plan (the “Incentive Stock Option Plan”) under which stock options were issued to directors, officers, employees and consultants as determined by the Board of Directors and subject to the provisions of the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted options to be issued with exercise prices at a discount to the market price of the Company’s common 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 1,872,812 options outstanding under the Incentive Stock Option Plan at April 30, 2006.

		On December 13, 2005, the shareholders of the Company approved the 2005 Omnibus Stock Plan (the “Omnibus Stock Plan”) and it became effective on that date. The Omnibus Stock Plan replaces the Incentive Stock Option Plan under which stock options were previously granted. The Omnibus Stock Plan 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. No options have been issued under the Omnibus Stock Plan. During the current quarter, the Committee granted stock awards under the Omnibus Stock Plan in the form of restricted and unrestricted stock to employees and directors of the Company. The transactions involving the granting of these stock awards are described more fully in Note 2.
		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 there was thus no unvested portion of previous stock option grants which vested during the quarter or nine months ended April 30, 2006. Therefore, SFAS 123(R) had no impact on the Company’s consolidated financial position or results of operations for the quarter and nine months ended April 30, 2006. The Company continues to use the Black-Scholes formula to estimate the fair value of stock options granted under the Incentive Stock Option Plan.
2.		STOCK-BASED COMPENSATION
		Stock Options
		The tables below summarize stock options activity for the nine months ended April 30, 2006. All stock options were granted with exercise prices denominated in Canadian Dollars and equal to the quoted market price of the stock on the date of grant. 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 at April 30, 2006 and July 31, 2005.

						Weighted-Average
						Exercise Price
		Number of options				CAD$				USD$
Outstanding at July 31, 2005			4,227,279			$	1.82			$	1.49
Granted			495,000				2.05				1.79
Exercised			(396,667	)			1.22				0.97
Cancelled or surrendered			(2,452,800	)			2.23				1.81
Outstanding at April 30, 2006			1,872,812			$	1.48			$	1.19

The Company recorded stock-based compensation expense for stock options granted to employees and directors in the amount of $397,586 and $2,200,777 during the nine months ended April 30, 2006 and 2005, respectively, which is included in general and administrative expenses in the Statements of Operations. The fair value of stock options granted was estimated using the Black-Scholes Option Pricing Model with the following assumptions:

		Nine Months Ended April 30,
		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

		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.
		The following table summarizes information about options outstanding as of April 30, 2006:

	Exercise
	Price		Number				Remaining				Expiry
CAD$			Outstanding				Life (Years)				Date
$	0.65			345,000				2.5				November 3, 2008
	0.90			293,334				0.7				January 10, 2007
	0.90			10,000				3.4				September 22, 2009
	1.49			695,666				3.6				November 29, 2009
	2.05			10,000				4.4				September 22, 2010
	2.19			136,000				3.9				March 27, 2010
	2.40			382,812				3.7				January 20, 2010
$	1.48			1,872,812				3.0

		Restricted Stock Awards and Grants of Common Shares
		On April 12, 2006, the Compensation Committee approved an exchange of common shares for outstanding stock options held by various key employees and directors of the Company (“Option Exchange”). The Option Exchange effectively cancelled stock option awards for 2,025,000 of the Company’s common shares previously granted during fiscal years 2005 and 2006. The Option Exchange replaced the cancelled options with restricted stock awards of 2,025,000 of the Company’s common shares. The shares of restricted stock are included in common shares outstanding when issued, but only the vested portion of such shares are included in the

computation of basic earnings per share. The restrictions required the covered individuals to be continuously employed through certain vesting dates. Vesting of some or all of the restricted shares will be accelerated in the event an employee is no longer employed due to death, disability or discharge by the Company for any reason other than just cause or if a director stands for reelection to the board and does not receive enough votes to be reelected to the board. The restricted shares are scheduled to vest over the requisition service period as follows:

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

The Company accounted for the Option Exchange as a modification of the original shared-based payment awards (stock options) in accordance with SFAS No. 123(R). Accordingly, the Company recorded compensation expense based on the excess of the fair value of the restricted stock award grants over the fair value of the original award (stock options) measured immediately before the transaction based on current circumstances. The fair value of the restricted stock awards was determined based on the number of shares granted and the quoted price of our common stock on the date of the grant of $1.42 per share. The value of the stock options surrendered was computed immediately before the modification using the Black Scholes valuation model with the following assumptions:

Risk-free interest rate			4.75	%
Expected dividend yield			Nil
Expected stock price volatility			171% - 178	%
Expected option remaining life		3.8 – 4.5 years

		In estimating expected volatility, the Company considered its historical volatility for the period that its stock began trading on the American Stock Exchange (approximately 120 days) and the historical volatility of a similar entity (“guideline company”) whose share price was publicly available for the necessary period in order to reflect the expected remaining life of the stock options.
		The Option Exchange resulted in incremental compensation expense of $230,900, which will be recognized over the requisite service period. The Company recorded $15,458 of compensation expense related to the Option Exchange in the quarter ended April 30, 2006. Future amortization of the unearned incremental compensation expense will result in additional compensation expense of $27,020 in the fourth quarter of fiscal year ended 2006 and $89,971, $70,806 and $27,645 in fiscal years ended July 31, 2007, 2008 and 2009, respectively.
		On April 12, 2006, the Company granted 300,000 shares of restricted stock and 300,000 shares of unrestricted common stock to its newly hired senior vice president of operations. On that same date, the Company granted 140,000 shares of unrestricted common stock to its newly appointed independent director. The fair value of the restricted stock was determined based on the number of shares granted and the quoted price of our common stock on the date of the grant of $1.42 per share. The restricted stock is scheduled to vest over the requisition service period in the amount of 100,000 shares each on January 1, 2007, 2008 and 2009. The Company recorded $7,003 of compensation expense related to this grant of restricted stock in the quarter ended April 30, 2006. Future amortization of the unearned compensation expense will result in additional compensation expense of $35,792 in the fourth quarter of fiscal year ended 2006 and $142,000, $142,000 and $99,205 in fiscal years ended July 31, 2007, 2008 and 2009, respectively. The Company recorded the fair value of the award of unrestricted common shares of $624,800 as compensation expense in the quarter ended April 30, 2006.

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 April 30, 2006.
		We recorded a tax benefit in the United States for the nine months ended April 30, 2005 to partially offset a net deferred tax liability at April 30, 2005; however, no tax benefit was recognized for the nine months ended April 30, 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:

		April 30,				July 31,
		2006				2005
Case Credit term note due in fiscal year 2006, 6.50%		$	19,872			$	32,833
GMAC term notes due in fiscal year 2009, 6.50%			22,151				26,633
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%			85,632				98,356
Convertible note due in fiscal year 2008, 3.25%			—				392,000
Caterpillar Financial Services Corp			157,336				—
			284,991				549,822
Less current maturities			(201,533	)			(42,227	)
Long-term notes payable		$	83,458			$	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 principal maturities of all notes for the remaining three months of fiscal year 2006 and the four fiscal years thereafter are as follows:

2006										$	68,977
2007											140,862
2008											27,982
2009											29,767
2010											17,403
										$	284,991

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 April 30, 2006 as follows:

Number		Exercise					Expiry
Outstanding		Price				Date
4,274,400		USD $1.50				January 12, 2009
1,037,200		USD $1.25				January 12, 2010
5,311,600

		During the third quarter of fiscal year 2006, the shareholders voted to increase the number of shares of common stock the Company is authorized to issue from 100,000,000 shares to 200,000,000 shares.

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 coalbed methane. Beginning in fiscal year ended July 31, 2005, the Company owns and maintains a lab testing facility and allows A-Strike Consulting to operate the facility. The Company pays all expenses related to the facility and, in return, receives 80% of the revenue generated from the operations of the facility as reimbursement of the Company’s expenses. The Company received approximately $68,674 and $59,000 in expense reimbursement related to this arrangement during the nine months ended April 30, 2006 and 2005, respectively. Mr. Ostreich’s brother owns Dependable Service Company, a company that provides general labor services to the Company. The Company paid Dependable Services Company $227,626 and $54,929 during the nine months ended April 30, 2006 and 2005, respectively.
		David Preng, a director of the Company, is a principal in the executive search firm Preng & Associates. The Company paid Preng & Associates approximately $150,000 and $0 for executive placement services during the nine months ended April 30, 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

In conjunction with this proposed settlement, during the quarter ended April 30, 2006 the Company recorded $2,949,907 as other expense, approximately $50,000 as a deduction to sales for royalties due on production that Colt, LLC had previously rejected, and $3,000,000 as accrued liabilities for the pending payment. In addition, the Company reclassified approximately $2,226,000 from the cost of Unevaluated Properties to the cost of Proved Properties to recognize the impairment resulting from the loss of approximately 33,000 acres of mineral rights.

Item 2. 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 unaudited consolidated financial statements and notes related thereto that are included under Item 1.

Overview and Outlook

We are an independent energy company incorporated in British Columbia, Canada and headquartered in Solon, Ohio, U.S.A. The Company engages, through its wholly owned U.S. subsidiary, BPI Energy, Inc., in the exploration, production and commercial sale of coalbed methane (“CBM”) 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 approximately 500,000 total acres in the Basin. A substantial majority of the acreage under our control was undeveloped as of April 30, 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 nine months ended April 30, 2006, we generated gas sales of $802,066. 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 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 ensure 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 approximately 500,000 acres in the Basin and conducted 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 now have 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;
	•		raising the capital necessary to achieve our plans and goals;
	•		transitioning BPI from a company focused primarily on the acquisition of mineral rights to a company focused on producing CBM; and
	•		developing and expanding our in-house technical team necessary for large scale development and production of CBM assets.

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 February 2006, we added a sixth member, David Preng, to our board of directors. Mr. Preng is an experienced public company board member and has been appointed chairman of the compensation committee of our board.

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.

In April 2006, we stopped drilling new wells at our Southern Illinois Basin Project due to a dispute with our lessors and the coal owners. In June 2006 we settled all claims and counterclaims related to a lawsuit we had filed in federal court against our lessors and certain coal owners in order to preserve our rights under the lease covering our Southern Illinois Basin Project. For more information about the terms of the settlement of the litigation relating to our Southern Illinois Basin Project, refer to Part II, Item  1— Legal Proceedings below.

The events leading up to the dispute and litigation substantially interfered with drilling and operations at our Southern Illinois Basin Project. This settlement should increase our ability to drill, complete and operate our current and future CBM wells in a manner we believe will maximize the efficiency and productivity of CBM operations at our Southern Illinois Basin Project. We do not anticipate drilling any horizontal wells in the CBM acreage we will own as a result of the settlement. Although we will have the right to drill additional wells in the acreage subject to the settlement, we may choose to use our available resources to focus our drilling activity at our Northern Illinois Basin Project or in other acreage. We will

assess the opportunities and commit our resources where we feel we will maximize the overall return to BPI.

We will continue to negotiate for additional CBM rights and opportunities to expand our Southern Illinois Basin Project. We believe that the testing we have done at our Southern Illinois Basin Project will prove to be valuable in assisting us with siting, drilling and producing CBM from horizontal wells we hope to locate in additional acreage we may add to our Southern Illinois Basin Project.

In April 2006, we began our second development front by beginning drilling of the 10 pilot development wells at our Northern Illinois Basin Project. Our CBM rights in the Northern Illinois Basin Project cover 353,531 acres in Montgomery, Shelby, Christian, Fayette and Macoupin counties in Illinois, which are located in the north central part of the Basin. We believe that 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.

In April, we increased our acreage position in our Northern Illinois Basin Project by approximately 114,000 acres with the signing of two new leases. A key part of these new leases involves the coordination of CBM production and coal-mining operations on a long-term basis. We anticipate that this coordination will eliminate disputes such as those we encountered at our initial Southern Illinois Basin drilling project (i.e., the Delta lease).

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. Our current goal for the coming years is to increase our internal engineering and operating resources. 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.

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			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

As of May 1, 2006, all of the wells that we have drilled are vertical wells.

Results of Operations

Three Months Ended April 30, 2006 Compared to Three Months Ended April 30, 2005

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

		Three Months Ended April 30
										Dollar				%
		2006				2005				Variance				Change
Revenues:
Gas sales		$	262,860			$	46,925			$	215,935				460	%
Expenses:
Lease operating expense			290,844				203,289				87,555				43	%
General and administrative expense			2,054,434				1,847,554				206,880				11	%
Depreciation, depletion and amortization			189,988				83,129				106,859				129	%
			2,535,266				2,133,972				401,294				19	%
Other income (expenses):
Interest income			229,888				62,012				167,876				271	%
Interest expense			(4,276	)			(3,804	)			(472	)			(12	%)
Other income (expense), net			(2,894,794	)			24,053				(2,918,847	)			(12,135	%)
			(2,669,182	)			82,261				(2,751,443	)			(3,345	%)
Loss before income taxes			(4,941,588	)			(2,004,786	)			(2,936,802	)			(146	%)
Deferred income tax benefit			—				270,587				(270,587	)			(100	%)
Net loss		$	(4,941,588	)		$	(1,734,199	)		$	(3,207,389	)			(185	%)

Revenue – During the third quarter of fiscal year 2006, revenue increased $215,935 over the third quarter 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 36,102 Mcf for the third quarter of fiscal year 2006 compared to 8,388 Mcf for the third quarter of 2005. Our average realized selling price per Mcf was $7.28 for the third quarter of fiscal year 2006 compared to $5.59 for the third quarter of fiscal year 2005.

Lease operating expense — During the third quarter of fiscal year 2006, lease operating expense increased $87,555 over the third quarter of fiscal year 2005. Lease operating expenses represent production expenses, consisting primarily of repairs and maintenance, fuel and electricity, equipment rental and other overhead expenses related to producing wells. The increase is primarily due to the increase in producing wells and the related increase in gas production.

General and administrative expense — General and administrative expense consisted of the following for the third quarter of fiscal years ended 2006 and 2005, respectively:

		Three Months ended April 30
										Dollar				%
		2006				2005				Variance				Change
Salaries and benefits		$	422,436			$	257,778			$	164,658				64	%
Stock-based compensation			647,261				1,039,406				(392,145	)			(38	%)
Professional fees			853,324				387,605				465,719				120	%
Other			131,413				162,765				(31,352	)			(19	%)
Total general and administrative expense		$	2,054,434			$	1,847,554			$	206,880				11	%

During the third quarter of fiscal year 2006, salaries and benefits increased $164,658 over the third quarter of fiscal year 2005. The increase was primarily the result of hiring additional personnel to support our growth, including a Senior Vice President of Operations.

During the third quarter of fiscal year 2006, stock-based compensation decreased $392,145 over the third quarter of fiscal year 2005. No stock options were granted in the third quarter of fiscal year 2006, whereas 2,950,056 stock options were granted to employees and directors in the third quarter of fiscal year 2005. However, we issued both restricted and unrestricted common shares during the third quarter of fiscal year 2006. Stock-based compensation expense for the third quarter of fiscal year 2006 primarily relates to 300,000 unrestricted common shares issued to our newly hired senior vice president of operations and 140,000 unrestricted common shares issued to our newly appointed independent director. We also issued 300,000 restricted shares and replaced 2,025,000 stock options with 2,025,000 of restricted shares for various employees, officers and directors of the Company during the third quarter of fiscal year 2006. A portion of the expense related to the issuance of these restricted shares was recorded in the third quarter of fiscal year 2006.

During the third quarter of fiscal year 2006, professional fees increased $465,719 over the third quarter of fiscal year 2005. The increase was primarily the result of increased legal fees incurred in connection with our lawsuit against Colt LLC and higher costs associated with being a public company in the United States including the cost of SEC filings, American Stock Exchange listing fees, higher audit related fees, and additional legal services.

Depreciation, depletion and amortization expense - During the third quarter of fiscal year 2006, depreciation, depletion and amortization expense (“DD&A”) increased $106,859 over the third quarter of fiscal year 2005. We compute DD&A on capitalized acquisition and development costs (including 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 increase in capitalized development costs and an increase in production over the third quarter of fiscal year 2005. Additionally, depreciation expense increased due to additions to other support equipment.

Interest income - During the third quarter of fiscal year 2006, interest income increased $167,876 over the third quarter of fiscal year 2005 due to significantly higher average cash balances during the third quarter 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 (expense), net - During the third quarter of fiscal year 2006, other income (expense), net decreased $2,918,847 over the third quarter of fiscal year 2005 primarily due to recognizing approximately $2,950,000 of other expense related to settling our dispute with Colt LLC.

Deferred income tax benefit - During the third quarter of fiscal year 2006, deferred income tax benefit decreased $270,587 over the third quarter of fiscal year 2005. We recorded a tax benefit in the United States

in the third quarter of fiscal year 2005 to partially offset a net recorded deferred tax liability at April 30, 2005; however, no tax benefit was recognized for the third quarter of fiscal year 2006, as the Company had no net deferred tax liability to offset.

Nine Months Ended April 30, 2006 Compared to Nine Months Ended April 30, 2005

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

		Nine Months Ended April 30
										Dollar				%
		2006				2005				Variance				Change
Revenues:
Gas sales		$	800,365			$	53,266			$	747,099				1,403	%
Expenses:
Lease operating expense			752,454				203,289				549,165				270	%
General and administrative expense			4,491,676				5,012,641				(520,965	)			(10	%)
Depreciation, depletion and amortization			402,680				140,801				261,879				186	%
			5,646,810				5,356,731				290,079				5	%
Other income (expenses):
Interest income			632,693				66,859				565,834				846	%
Interest expense			(18,054	)			(14,386	)			(3,668	)			(25	%)
Other income (expense), net			(2,757,271	)			27,299				(2,784,570	)			(10,200	%)
			(2,142,632	)			79,772				(2,222,404	)			(2,786	%)
Loss before income taxes			(6,989,077	)			(5,223,693	)			(1,765,384	)			(34	%)
Deferred income tax benefit			—				615,304				(615,304	)			(100	%)
Net loss		$	(6,989,077	)		$	(4,608,389	)		$	(2,380,688	)			(52	%)

Revenue – During the first nine months of fiscal year 2006, revenue increased $747,099 over the first nine 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 83,288 Mcf for the first nine months of fiscal year 2006 compared to 9,635 Mcf for the first nine months of 2005. Our average realized selling price per Mcf was $9.61 for the first nine months of fiscal year 2006 compared to $5.53 for the first nine months of fiscal year 2005.

Lease operating expense — During the first nine months of fiscal year 2006, lease operating expense increased $549,165 over the first nine months of fiscal year 2005. Lease operating expenses represent production expenses, consisting primarily of repairs and maintenance, fuel and electricity, equipment rental and other overhead expenses related to producing wells. The increase is primarily due to the increase in producing wells and the related increase in gas production.

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

		Nine Months ended April 30
										Dollar				%
		2006				2005				Variance				Change
Salaries and benefits		$	1,149,675			$	766,283			$	383,392				50	%
Stock-based compensation			1,044,847				3,240,184				(2,195,337	)			(68	%)
Professional fees			1,871,393				555,785				1,315,608				237	%
Other			425,761				450,389				(24,628	)			(5	%)
Total general and administrative expense		$	4,491,676			$	5,012,641			$	(520,965	)			(10	%)

During the first nine months of fiscal year 2006, salaries and benefits increased $383,392 over the first nine months of fiscal year 2005. The increase was primarily the result of hiring additional personnel to support our growth, including a Senior Vice President of Operations, a Chief Financial Officer and a Controller.

During the first nine months of fiscal year 2006, stock-based compensation decreased $2,195,337 over the first nine months of fiscal year 2005. 495,000 stock options were granted in the first nine months of fiscal year 2006, whereas 2,950,056 stock options were granted to employees and directors in the first nine months of fiscal year 2005. However, we issued both restricted and unrestricted common shares during the first nine months of fiscal year 2006. Stock-based compensation expense for the first nine months of fiscal year 2006 primarily relates to 300,000 unrestricted common shares issued to our newly hired senior vice president of operations, 140,000 unrestricted common shares issued to our newly appointed independent director and 495,000 stock options issued to various employees, officers and directors of the Company. We also issued 300,000 restricted shares and replaced 2,025,000 stock options with 2,025,000 of restricted shares for various employees, officers and directors of the Company during the first nine months of fiscal year 2006. A portion of the expense related to the issuance of these restricted shares was recorded in the first nine months of fiscal year 2006.

During the first nine months of fiscal year 2006, professional fees increased $1,315,608 over the first nine months of fiscal year 2005. The increase was primarily the result of increased legal fees incurred in connection with our lawsuit against Colt LLC and higher costs associated with being a public company in the United States, including the cost of SEC filings, American Stock Exchange listing fees, higher audit related fees, and additional legal services.

Depreciation, depletion and amortization expense - During the first nine months of fiscal year 2006, depreciation, depletion and amortization expense (“DD&A”) increased $261,879 over the first nine months of fiscal year 2005. We compute DD&A on capitalized acquisition and development costs (including 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 increase in capitalized development costs and an increase in production over the first nine months of fiscal year 2005. Additionally, depreciation expense increased due to additions to other support equipment.

Interest income - During the first nine months of fiscal year 2006, interest income increased $565,834 over the first nine months of fiscal year 2005 due to significantly higher average cash balances during the first nine 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 (expense), net - During the first nine months of fiscal year 2006, other income (expense), net decreased $2,784,570 over the first nine months of fiscal year 2005 primarily due to recognizing approximately $2,950,000 of other expense related to settling our dispute with Colt LLC.

Deferred income tax benefit - During the first nine months of fiscal year 2006, deferred income tax benefit decreased $615,304 over the first nine months of fiscal year 2005. We recorded a tax benefit in the United

States in the first nine months of fiscal year 2005 to partially offset a net recorded deferred tax liability at April 30, 2005; however, no tax benefit was recognized for the first nine months of fiscal year 2006, as the Company had no net deferred tax liability to offset.

Critical Accounting Policies and Estimates

Our unaudited 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 were discussed in our Post-Effective Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on May 11, 2006.

Financial Condition

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 April 30, 2006, we had only $284,991 in long-term notes payable. From July 31, 2002 until April 30, 2006, we raised $43,866,649 from the sale of our common stock. Additionally, during that same period, we collected $7,100,359 and $2,121,180 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 $800,365 and $53,266 for the nine months ended April 30, 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 Basin, we can provide no assurance that we will achieve a trend of increased production and revenue in the future.

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 with $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.

Cautionary Statement Concerning Forward-Looking Statements

Some of the statements contained in this report that are not historical facts, 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, but are not limited to, (a) our inability to generate sufficient income or obtain sufficient financing to fund our operating plan through April 30, 2007, (b) our inability to retain our acreage rights at our projects at the expiration of our lease agreements, due to insufficient CBM production or other reasons; (c) our failure to accurately forecast CBM production, (d) displacement of our CBM operations by coal mining operations, which have superior rights in most of our acreage, (e) our failure to accurately forecast the number of wells that we can drill, (f) a decline in the prices that we receive for our CBM production, (g) our failure to accurately forecast operating and capital expenditures and capital needs due to rising costs or different drilling or production conditions in the field, (h) our inability to attract or retain qualified personnel with the requisite CBM or other experience, and (i) unexpected economic and market conditions, in the general economy or the market for natural gas. We caution readers not to place undue reliance on these forward-looking statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk

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

Interest Rate Risk

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

Financial Instruments

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

Inflation and Changes in Prices

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

Item 4. Controls and Procedures

As of the end of the period covered by this report, the Company conducted an evaluation, under the supervision and with the participation of the principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)). Based on this evaluation, the principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

There have been no changes in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) of the Exchange Act that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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 (which was denied by the court) against Colt LLC and related parties from terminating the lease agreement covering our CBM rights in 43,000 acres 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.

On April 5, 2006, Colt filed an answer and counterclaim in response to our complaint. In its counterclaim, Colt sought 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.

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

	1.		All parties to the suit will release all of the other parties from any claims they may have had against each other;
	2.		BPI will pay Colt $3,000,000;
	3.		BPI will surrender any interest it had in the lease;
	4.		BPI acquired ownership of the CBM estate covering approximately 10,000 of the 43,000 acres previously covered by the lease (which acreage includes all of the currently producing CBM wells and proved reserves at our Southern Illinois Basin Project);
	5.		BPI will be relieved of any future obligation to make royalty payments as was previously required under the terms of the lease (under the terms of the lease we were obligated to make royalty payments of 15% of gross sales and minimum royalties totaling at least $42,000 per month); and

(b)

Increase authorized capital. The shareholders voted to increase the number of shares of our common stock that we are authorized to issue to 200,000,000 shares:

Votes For			25,970,829
Votes Against			288,280
Abstentions			12,031
Broker Non-Votes			26,781

(c)

Increase quorum. The shareholders voted to increase the quorum requirement for meetings of shareholders to 33 and 1/3 percent of our shares of common stock:

Votes For			12,034,147
Votes Against			115,589
Abstentions			56,331
Broker Non-Votes			14,091,854

(d)

Permit meetings outside of British Columbia. The shareholders voted to permit shareholder meetings to be held outside British Columbia, Canada:

Votes For			26,264,525
Votes Against			296
Abstentions			6,319
Broker Non-Votes			26,781

Item 5. Other Information

None.

Item 6. Exhibits

10.1		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).
10.2		Coal Seam Gas Lease Agreement, dated April 26, 2006, by and between BPI Energy, Inc. and Christian Coal Holdings, LLC (Northern Illinois Basin Project) (Filed as Exhibit 10.2 to the Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on April 28, 2006 and incorporated herein by reference).
10.3		Settlement Memorandum of Understanding by and among BPI Energy, Inc., Colt LLC, AFC Coal Properties, Inc., American Premier Underwriters, Inc. and Central States Coal Reserves of Illinois, LLC, dated June 13, 2006.
31.1		Section 302 Certification By Chief Executive Officer (Principal Executive Officer)
31.2		Section 302 Certification By Chief Financial Officer (Principal Financial Officer)
32.1		Section 906 Certification of Principal Executive Officer and Principal Financial Officer

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

				BPI ENERGY HOLDINGS, INC.
DATE: June 14, 2006				/s/ James G. Azlein
				James G. Azlein,
				President and Chief Executive Officer
				/s/ George J. Zilich
				George J. Zilich,
				Chief Financial Officer and General Counsel