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

For the Quarterly Period Ended October 31, 2006

BPI Energy Holdings, Inc.

(Exact Name of Registrant as Specified in Its Charter)

British Columbia, Canada (State or Other Jurisdiction of Incorporation or Organization)		75-3183021 (I.R.S. Employer Identification No.)
30775 Bainbridge Road, Suite 280, Solon, Ohio (Address of Principal Executive Offices)		44139 (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 December 13, 2006: 72,608,423

 

 

Item 1. Financial Statements.

BPI Energy Holdings, Inc.
Consolidated Balance Sheets

		October 31, 2006				July 31, 2006
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	14,697,615			$	19,279,015
Accounts receivable			53,125				105,711
Other current assets			405,168				164,764
Total current assets			15,155,908				19,549,490
Property and equipment, at cost:
Gas properties, full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $434,833 and $331,150			20,683,383				20,766,898
Unproved			5,558,243				3,368,231
Net gas properties			26,241,626				24,135,129
Other property and equipment, net of accumulated depreciation and amortization of $711,330 and $631,015			5,348,946				5,106,236
Net property and equipment			31,590,572				29,241,365
Restricted cash			100,000				100,000
Other non-current assets			418,940				161,125
Total assets		$	47,265,420			$	49,051,980
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,125,212			$	1,492,239
Current maturity of long-term notes payable			77,527				140,866
Accrued liabilities and other			1,080,108				649,237
Total current liabilities			2,282,847				2,282,342
Long-term notes payable, less current portion			68,315				75,149
Asset retirement obligation			62,167				70,754
Other non-current liabilities			100,000				—
Total liabilities			2,513,329				2,428,245
Shareholders’ equity:
Common shares, no par value, authorized 200,000,000 shares, 72,608,423 and 70,812,540 outstanding			67,946,143				67,946,143
Additional paid-in capital			6,744,403				5,871,120
Accumulated deficit			(29,938,455	)			(27,193,528	)
Total shareholders’ equity			44,752,091				46,623,735
Total liabilities and shareholders’ equity		$	47,265,420			$	49,051,980

See Notes to Unaudited Consolidated Financial Statements.

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

		Three Months Ended October 31
		2006				2005
Revenues:
Gas sales		$	294,002			$	209,694
Expenses:
Lease operating expense			335,974				160,804
General and administrative expense			2,734,710				1,272,424
Depreciation, depletion and amortization			183,998				94,802
			3,254,682				1,528,030
Operating loss			(2,960,860	)			(1,318,336	)
Other income (expense):
Interest income			218,906				132,619
Interest expense			(3,153	)			(7,544	)
			215,753				125,075
Net loss		$	(2,744,927	)		$	(1,193,261	)
Basic and diluted loss per share			($0.04	)			($0.03	)
Weighted average common shares outstanding			68,796,522				45,982,440

See Notes to Unaudited Consolidated Financial Statements.

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

		Common Shares								Additional Paid-in				Accumulated				Total
		Shares				Amounts				Capital				Deficit				Shareholders’ Equity
Balance, July 31, 2006			70,812,540			$	67,946,143			$	5,871,120			$	(27,193,528	)		$	46,623,735
Share-based payments — common shares, including vesting of restricted shares			979,381				—				873,283				—				873,283
Nonvested portion of restricted shares issued			816,502				—				—				—				—
Net loss			—				—				—				(2,744,927	)			(2,744,927	)
Balance, October 31, 2006			72,608,423			$	67,946,143			$	6,744,403			$	(29,938,455	)		$	44,752,091

See Notes to Unaudited Consolidated Financial Statements.

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

		Three Months Ended October 31
		2006				2005
Operating activities:
Net loss		$	(2,744,927	)		$	(1,193,261	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization			183,998				94,802
Share-based payments			873,283				397,586
Accretion of asset retirement obligation			952				669
Changes in assets and liabilities:
Accounts receivable			52,586				(87,113	)
Other current assets			(240,404	)			(10,816	)
Accounts payable			282,802				167,274
Accrued liabilities and other			430,871				146,922
Other assets and liabilities			(157,815	)			—
Net cash used in operating activities			(1,318,654	)			(483,937	)
Investing activities:
Additions to gas properties			(2,777,749	)			(3,878,281	)
Additions to other property and equipment			(414,824	)			(683,721	)
Net cash used in investment activities			(3,192,573	)			(4,562,002	)
Financing activities:
Payments on long-term notes payable			(70,173	)			(9,098	)
Net proceeds from issuance of common shares			—				28,702,478
Net cash (used in) provided by financing activities			(70,173	)			28,693,380
Net (decrease) increase in cash and cash equivalents			(4,581,400	)			23,647,441
Cash and cash equivalents at the beginning of the period			19,279,015				7,251,503
Cash and cash equivalents at the end of the period		$	14,697,615			$	30,898,944
Supplementary disclosure of cash flow information:
Cash payments:
Interest paid		$	3,153			$	3,646

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 exploration, production and commercial sale of coalbed methane in the Illinois Basin. The Company conducts its operations in one reportable segment, which is gas exploration and production. The Company’s common shares trade on the American Stock Exchange under the symbol “BPG.” 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 ended October 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 Annual Report on Form 10-K for the fiscal year ended July 31, 2006. Certain prior period amounts have been reclassified to conform to current period presentation.

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

     Use of Estimates

     The preparation of these 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 gas properties and the impairment of gas properties are determined using estimates of gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including the timing and costs associated with asset retirement obligations. Gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of gas that cannot be measured in an exact way. Proved reserves of 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.

     Gas Properties

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

     Unproved gas properties and major development projects are excluded from amortization until a determination of whether proved reserves can be assigned to the properties or impairment occurs. Unproved properties are assessed at least annually to ascertain whether 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 gas properties, including estimated future costs to develop the reserves and estimated abandonment cost, net of salvage, are amortized on the units-of-production method using estimates of proved reserves.

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

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

	i)		there are no firm plans for further drilling on the unproved property;
	ii)		negative results were obtained from studies of the unproved property;
	iii)		negative results were obtained from studies conducted in the vicinity of the unproved property; or
	iv)		the remaining term of the unproved property does not allow sufficient time for further studies or drilling.

     No impairment existed as of October 31, 2006 or July 31, 2006.

     Other Property and Equipment

     Other property and equipment are stated at cost. Gas collection equipment is depreciated on the units-of-production method using estimates of proved reserves. Support equipment and other property and equipment are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three to 10 years. Major classes of other property and equipment consisted of the following at October 31, 2006 and July 31, 2006, respectively:

		October 31,				July 31,
		2006				2006
Other property and equipment:
Gas collection equipment		$	4,342,400			$	4,342,400
Support equipment			1,245,188				1,046,989
Other			472,688				347,862
Less: Accumulated depreciation and amortization			(711,330	)			(631,015	)
		$	5,348,946			$	5,106,236

     Loss Per Share

     Basic loss per share is calculated using the weighted average number of common shares outstanding during the year. Diluted loss per share reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted into common shares. Restricted common shares granted are included in the computation only after the shares become fully vested. Diluted loss per share is not disclosed as it is anti-dilutive. The following items were excluded from the computation of diluted loss per share at October 31, 2006 and 2005, respectively, as the effect of their assumed exercise would be anti-dilutive:

		October 31,				October 31,
		2006				2005
Outstanding warrants			5,311,600				10,763,603
Outstanding stock options			1,823,265				4,080,612
Nonvested portion of restricted shares issued			3,057,338				—
			10,192,203				14,844,215

2.		STOCK-BASED COMPENSATION

     SFAS No. 123 (R)

     In December 2004, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment.” This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. The key provision of SFAS No. 123(R) requires companies to record share-based payment transactions as compensation expense at fair market value based on the grant-date fair value of those awards. Previously under SFAS 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 nonvested immediately on the date of grant and, thus, there was no nonvested portion of previous

stock option grants that vested during the fiscal year ended July 31, 2006. Therefore, SFAS 123(R) had no impact on the Company’s consolidated financial position or results of operations for the fiscal year ended July 31, 2006. The Company uses the Black-Scholes valuation model to estimate the fair value of stock options granted.

     Incentive Stock Option Plan

     Prior to December 13, 2005, the Company administered a stock-based compensation plan (the “Incentive Stock Option Plan”) under which stock options were issued to directors, officers, employees and consultants as determined by the Board of Directors and subject to the provisions of the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted options to be issued with exercise prices at a discount to the market price of the Company’s common shares on the day prior to the date of grant. However, the majority of all stock options issued under the Incentive Stock Option Plan were issued with exercise prices equal to the quoted market price of the shares 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 following table summarizes information about options outstanding under the Incentive Stock Option Plan at October 31, 2006.

Exercise				Number				Remaining
Price CAD$				Outstanding				Life (Years)				Expiry Date
$	0.65				345,000				2.0			November 3, 2008
	0.90				243,334				0.2			January 10, 2007
	0.90				10,000				2.9			September 22, 2009
	1.20				50,000				0.2			January 10, 2007
	1.49				695,666				3.1			November 29, 2009
	2.05				10,000				3.9			September 22, 2010
	2.19				136,000				3.4			March 27, 2010
	2.40				333,265				3.2			January 20, 2010
$	1.46				1,823,265				2.5

     Omnibus Stock Plan

     On December 13, 2005, the shareholders of the Company approved the Company’s 2005 Omnibus Stock Plan (the “Omnibus Stock Plan”) and it became effective on that date. The Omnibus Stock Plan replaces the Incentive Stock Option Plan under which stock options were previously granted. The Omnibus Stock Plan is administered by the Compensation Committee of the Board of Directors (the “Committee”) and will remain in effect until December 13, 2010. All employees and Directors of the Company and its subsidiaries, and all consultants or agents of the Company designated by the Committee, are eligible to participate in the Omnibus Stock Plan. The Committee has authority to: grant awards; select the participants who will receive awards; determine the terms, conditions, vesting periods and restrictions applicable to the awards; determine how the exercise price is to be paid; modify or replace outstanding awards within the limits of the Omnibus Stock Plan; accelerate the date on which awards become exercisable; waive the restrictions and conditions applicable to awards; and establish rules governing the Omnibus Stock Plan.

     The Omnibus Stock Plan provides that in any fiscal year of the plan the Company may grant up to 5% of the number of common shares outstanding as of the first day of that fiscal year plus the number of common shares that were available for the grant of awards, but not granted, in prior years under the plan. In no event, however, may the number of common shares available for the grant of awards in any fiscal year exceed 6% of the common shares outstanding as of the first day of that fiscal year.

     In the proxy statement for the Company’s 2005 Annual Meeting of Shareholders, the Company committed to limit the number of common shares that could be issued under the Plan to an aggregate cap of 5,000,000. In the proxy statement for the Company’s 2006 Annual Meeting of Shareholders, the Company is proposing to increase the cap on the aggregate number of common shares that can be issued under the Plan from 5,000,000 to 7,000,000. As of October 31, 2006, the Company has issued 2,911,000 common shares (but no options) under the Omnibus Stock Plan and has 2,089,000 common shares available for future issuance. If the Company’s shareholders approve the increased cap at the 2006 Annual Meeting of Shareholders, the Company will be permitted to issue an aggregate of up to at least 4,089,000 common shares under the Omnibus Stock Plan.

     Share-Based Transactions

     The following share-based transactions occurred during the current quarter:

	•		Granted 248,661 fully vested common shares and 507,338 restricted shares under the Omnibus Stock Plan, all at a market price of $0.58 per share, to certain executive officers, employees and non-employee directors of the Company. The restricted shares vest one-half on November 6, 2007 and one-half on November 6, 2008.
	•		Granted 350,000 fully vested common shares at a weighted average market price of $0.93 per share and 700,000 restricted shares at a weighted average market price of $0.93 per share in connection with the hiring of a geologist and three engineers. These grants were made outside of the Omnibus Stock Plan pursuant to American Stock Exchange rules that allow the Company to make equity grants to newly hired employees outside of a shareholder-approved plan. These restricted shares vest on various dates over a weighted average period of 1.4 years.
	•		Accelerated vesting of 475,000 restricted shares held by a former officer and director of the Company in connection with a separation agreement entered into with the former officer and director. See note 10 for further explanation of the separation agreement.

     The following table summarizes the Company’s restricted share activity during the current quarter:

						Weighted Avg.
						Grant Date
		Shares				Fair Value
Nonvested at July 31, 2006			2,325,000			$	0.61
Granted			1,207,338				0.78
Vested			(475,000	)			0.49
Forfeited			—				—
Nonvested at October 31, 2006			3,057,338				0.70

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

     The Company’s policy is to issue new shares to satisfy stock option exercises and restricted share grants upon receiving approval from the American Stock Exchange, when required, for the issuance of such shares.

     As of October 31, 2006, there was $1,793,835 of unrecognized compensation cost related to restricted shares. The cost is expected to be amortized over a weighted average period of 1.3 years. The amount charged to expense related to restricted shares was $274,227 and $0 in the three months ended October 31, 2006 and 2005, respectively.

3.		OTHER ASSETS

     Other Current Assets

     Other current assets consisted of amounts capitalized related to the following at October 31, 2006 and July 31, 2006, respectively:

		October 31,				July 31,
		2006				2006
Separation agreement		$	357,309			$	—
Prepaid expenses and other			47,859				164,764
		$	405,168			$	164,764

     Other Non-current Assets

     Other non-current assets consisted of amounts capitalized related to the following at October 31, 2006 and July 31, 2006, respectively:

		October 31,				July 31,
		2006				2006
Separation agreement		$	257,815			$	—
Advance royalties			161,125				161,125
		$	418,940			$	161,125

     The separation agreement represents amounts capitalized related to non-compete/non-solicitation and continuing services clauses contained in a separation agreement entered into with a former officer of the Company on October 12, 2006. See note 10 for further explanation of this agreement.

4.		ACCRUED LIABILITIES AND OTHER

     Accrued liabilities and other consisted of amounts due for the following at October 31, 2006 and July 31, 2006, respectively:

		October 31,				July 31,
		2006				2006
Employee compensation		$	595,000			$	467,869
Separation agreement			200,000				—
Professional and regulatory			180,000				111,805
Directors’ fees			100,000				31,000
Other			5,108				38,563
		$	1,080,108			$	649,237

     The separation agreement represents amounts due related to a non-compete/non-solicitation clause contained in a separation agreement entered into with a former officer of the Company on October 12, 2006. See note 10 for further explanation of this agreement.

5.		LONG-TERM NOTES PAYABLE

     Long-term notes payable consisted of the following at October 31, 2006 and July 31, 2006, respectively:

		October 31,				July 31,
		2006				2006
Case Credit term note due in fiscal year 2006, 6.50%		$	10,874			$	15,410
GMAC term note due in fiscal year 2009, 6.50%			19,039				20,608
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%			75,992				80,849
Caterpillar Financial Services term note due in fiscal year 2007, 7.0%			39,937				99,148
			145,842				216,015
Less current maturities			(77,527	)			(140,866	)
Long-term notes payable		$	68,315			$	75,149

     The notes are collateralized by the related vehicles and equipment.

6.		ASSET RETIREMENT OBLIGATIONS

     The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it is incurred, if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the associated long-lived asset. Amortization of the capitalized asset retirement cost is computed on a units-of-production method. Accretion of the asset retirement obligation is recognized over time until the obligation is settled. The Company’s asset retirement obligations relate to the plugging of wells upon exhaustion of gas reserves.

     The following table summarizes the activity for the Company’s asset retirement obligation for the three months ended October 31, 2006 and 2005, respectively:

		Three Months Ended
		October 31,
		2006				2005
Beginning asset retirement obligation		$	70,754			$	13,531
Additional liability incurred			3,261				19,800
Accretion expense			952				669
Asset retirement costs incurred			(26,681	)			—
Loss on settlement of liability			13,881				—
Ending asset retirement obligation		$	62,167			$	34,000

7.		CONCENTRATIONS

     Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, which are held at one large high quality financial institution. The

Company periodically evaluates the credit worthiness of the financial institution. The Company has not incurred any credit risk losses related to its cash and cash equivalents.

     The Company utilizes a limited number of drilling contractors to perform all of the drilling on its projects. The Company maintains a limited number of supervisory and field personnel to oversee drilling and production operations. The Company’s plans to drill additional wells are determined in large part by the anticipated availability of acceptable drilling equipment and crews. The Company does not currently have any contractual commitments that ensure it will have adequate drilling equipment or crews to achieve its drilling plans. The Company believes that it can secure the necessary commitments from drilling companies as required. However, it can provide no assurance that its expectations regarding the availability of drilling equipment and crews from these companies will be met. A significant delay in securing the necessary drilling equipment and crews could cause a delay in production and sales, which would affect operating results adversely.

8.		INCOME TAXES

     The Company operates in two tax jurisdictions, the United States and Canada. Primarily as a result of the net operating losses that the Company has generated (“NOL Carryforwards”) in both Canada and the United States, the Company has generated deferred tax benefits available for tax purposes to offset net income in future periods. SFAS No. 109, “Accounting for Income Taxes,” requires that the Company 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 October 31, 2006.

9.		SHAREHOLDERS’ EQUITY

     Common shares — The Company has authorized 200,000,000 common shares, without par value, of which 72,608,423 and 70,812,540 were issued and outstanding as of October 31, 2006 and July 31, 2006, respectively. Common shares issued and outstanding at October 31, 2006 include 3,057,338 restricted shares expected to vest in future periods.

     Additional paid-in capital — Amounts recorded of $6,744,403 and $5,871,120 at October 31, 2006 and July 31, 2006, respectively, represent the cumulative amounts incurred for share-based payments as of each date.

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

Number				Exercise
Outstanding				Price				Expiry Date
	4,274,400			$	1.50			December 13, 2007
	643,200			$	1.25			December 31, 2009
	394,000			$	1.25			January 12, 2010
	5,311,600

10.		SEPARATION AGREEMENT

     On October 12, 2006, the Company entered into a Separation Agreement and Waiver and Release (“Separation Agreement”) with George J. Zilich, the Company’s former Chief Financial

Officer and General Counsel. Under the terms of the Separation Agreement, Mr. Zilich resigned as an employee, officer and director of the Company effective immediately and the Company agreed to provide consideration to Mr. Zilich for entering into the Separation Agreement as follows:

	•		In connection with Mr. Zilich’s existing employment agreement, the Company agreed to make a cash payment to Mr. Zilich in the amount of $250,000 and provide medical and dental insurance coverage for two years. Such amounts were paid and recorded as expense during the current quarter.
	•		In connection with a continuing services clause of the Separation Agreement, the Company agreed to issue 40,000 unrestricted common shares to Mr. Zilich and make cash payments totaling $50,000 to be paid in semi-monthly equal installments from October 15, 2006 through December 31, 2006. In return, Mr. Zilich agreed to provide the Company with consulting services as may be reasonably requested by the Company from time to time through January 2, 2008. The Company is amortizing the expense associated with Mr. Zilich’s continuing services ratably through January 2, 2008. In connection with these continuing services, the Company expensed $3,247 during the current quarter and recorded other assets for prepaid amounts of $39,819 at October 31, 2006.
	•		In connection with a non-compete and non-solicitation clause of the Separation Agreement, the Company agreed to make cash payments of $100,000 on each of three dates from January 2, 2007 through January 2, 2008 and provide immediate vesting of 475,000 restricted shares held by Mr. Zilich. In return, Mr. Zilich agreed not to compete with the Company or solicit any of its employees for a period of two years. The Company capitalized the value of the non-compete and non-solicitation clause and is amortizing the related expense ratably through October 12, 2008. The amount capitalized includes $228,432 of share-based payments representing the remaining unrecognized portion of expense related to the vesting of the 475,000 restricted shares. In connection with this clause, the Company expensed $15,352 during the current quarter and recorded other assets of $575,305 and other liabilities of $300,000 at October 31, 2006.

11.		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 $0 and $12,352 in expense reimbursement related to this arrangement during the three months ended October 31, 2006 and 2005, respectively. Mr. Oestreich’s brother owns Dependable Service Company, a company that previously provided general labor services to the Company. The Company paid Dependable Services Company $0 and $79,419 during the three months ended October 31, 2006 and 2005, respectively.

     David Preng, a director of the Company, owns Preng & Associates, an executive search firm specializing in the energy and natural resources industries. The Company paid Preng & Associates $9,621 and $0 for executive placement services during the three months ended October 31, 2006 and 2005, respectively.

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 under the laws of British Columbia, Canada and primarily engaged, through our wholly owned U.S. subsidiary, BPI Energy, Inc., in the exploration, production and commercial sale of coalbed methane (“CBM”). Our exploration and production efforts are concentrated in the Illinois Basin (the “Basin”), which encompasses a total area of approximately 60,000 square miles in southern Illinois, southwestern Indiana and northwestern Kentucky. Our Canadian activities are limited to administrative reporting obligations to the province of British Columbia and regulatory reporting to the British Columbia Securities Commission.

     As of October 31, 2006, we owned or controlled CBM rights, through mineral leases, options to acquire mineral leases, a farm-out agreement and ownership of a CBM estate, covering approximately 500,000 total acres in the Basin (98% of this acreage is undeveloped as of October 31, 2006). We are focused on 12 Pennsylvanian coal seams that we regard as having commercial CBM potential. The seams in the acreage covered by our CBM rights have an aggregate thickness of 11-27 feet with a 19-foot median. We plan to complete several individual seams per well that range from two to nine feet thick each. Gas desorption tests of these coals have yielded 13-113 scf/ton with a 63 scf/ton median. Extensive permeability testing of individual seams (before stimulation) indicates a range of 0.2-75 millidarcies and median of 4 millidarcies.

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

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

     We are an early stage CBM exploration and production company. We commenced CBM sales from our first producing wells in January 2005. Gas sales during the fiscal year ended July 31, 2005 were $117,835. Gas sales were $1,126,477 for the fiscal year ended July 31, 2006, an increase of 856%. Gas sales for the quarter ending October 31, 2006 were $294,002, representing an increase of 40% over the same quarter from the previous year. However, sales for the period ending October 31, 2006 were 9.8% lower than the previous quarter due to lower commodity prices and a pipeline curtailment occurring at the end of October for approximately six days. The curtailment was caused by an increase in the nitrogen content of the sales stream to approximately 5.5% versus a pipeline quality specification of 4% total inert components. This is possibly due to adding new wells and new

coal seams in the field, since coals preferentially desorb nitrogen, causing the highest nitrogen content to be early in the life of a new well or seam. Our technical and management team has reviewed a number of cost-effective solutions available to mitigate the increase in nitrogen. A nitrogen rejection unit has been ordered and is scheduled to be installed in February 2007. We expect to incur approximately $600,000 acquiring the unit, transporting it to our Southern Illinois Basin Project and installing the unit for operation. In the meantime, the field remains online, the coals are continuing to de-water, and we are selling gas at a constrained rate of approximately 550 Mcf per day. Our pipeline service provider has indicated to us that it will resume accepting our entire sales at the end of December, prior to the installation of the nitrogen rejection unit.

     From early 2002 until 2005, our strategic focus was on building our acreage footprint in the Basin. We were built around the primary strategic objective of acquiring CBM rights in the Basin. As we began accumulating CBM rights, we began testing our acreage to determine its CBM potential. Having accumulated CBM rights to approximately 500,000 acres in the Basin and conducting extensive testing at our Southern Illinois Basin Project, we embarked (in late 2004) on a pilot production program at our Southern Illinois Basin Project. Encouraged by the results, we expanded our drilling and production activities and began installing the infrastructure necessary to enable us to begin sales of CBM at our Southern Illinois Basin Project.

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

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

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

     We anticipate that the number of wells we drill during the fiscal year ending July 31, 2007 will be dependent to a significant degree on the data we obtain from our recently completed 10-well pilot program at our Northern Project as well as data obtained from five test wells we have recently drilled on other leases in our Western Illinois Basin Project (“Western Project”) and Northern Project. Information from these test wells will continue to be gathered over the next 90 days. Our capital expenditure budget for our 2007 fiscal year is a range that totals $12.0 million to $30.0 million. These amounts correspond to drilling 58 wells at the low end of the range

and 123 wells at the upper end. These amounts include installing a gathering system and processing yard to handle the anticipated production from the 10-well pilot program at our Northern Project, the five test wells completed in this past quarter and additional pilot wells and/or production wells at our three current projects. Our cash balance at October 31, 2006 of $14.7 million is insufficient to fully fund the high end of the range of forecasted capital expenditures and net cash used by operating activities during our 2007 fiscal year or our operations beyond that date. Therefore, we will likely need to raise additional financing in the near future. We currently do not have any specific plans to raise financing in support of our operations. Although management has no specific plans in place to raise the additional capital necessary to fund our plan of operations and forecasted capital expenditures, management anticipates raising the additional required capital through a combination of additional stock sales, the issuance of debt securities, borrowing and/or entering into joint ventures. Management’s focus for fiscal year 2007 will be to:

	•		obtain test data and initiate pilot projects that demonstrate the commercial potential of CBM at our various acreage blocks and projects in the Basin;
	•		reduce well drilling and completion costs;
	•		increase total company reserves; and
	•		grow total production.

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

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

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

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

•

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

	•		conducting ongoing title reviews of existing mineral interests;
	•		where possible, negotiating and utilizing multiple service companies to increase competition and minimize the risk of disruptions caused by the loss of any one service provider; and
	•		attempting to create a low cost structure in order to reduce our vulnerability to many of these factors.

Results of Operations

Three Months Ended October 31, 2006 Compared to Three Months Ended October 31, 2005

     The following table presents our unaudited financial data for the first quarter of fiscal year 2007 compared to the first quarter of fiscal year 2006:

		Three Months Ended October 31,								Dollar				%
		2006				2005				Variance				Change
Revenues:
Gas sales		$	294,002			$	209,694			$	84,308				40	%
Expenses:
Lease operating expense			335,974				160,804				175,170				109	%
General and administrative expense			2,734,710				1,272,424				1,462,286				115	%
Depreciation, depletion and amortization			183,998				94,802				89,196				94	%
			3,254,682				1,528,030				1,726,652				113	%
Other income (expense):
Interest income			218,906				132,619				86,287				65	%
Interest expense			(3,153	)			(7,544	)			4,391				58	%
			215,753				125,075				91,347				73	%
Net loss		$	(2,744,927	)		$	(1,193,261	)		$	(1,551,666	)			(130	%)

     Revenue — During the first quarter of fiscal year 2007, revenue increased $84,308 over the first quarter of fiscal year 2006. Net sales of gas (net of royalties) were 51,490 Mcf for the first quarter of fiscal year 2007 compared to 19,789 Mcf for the first quarter of 2006. Our average realized selling price per Mcf was $5.71 for the first quarter of fiscal year 2007 compared to $10.60 for the first quarter of fiscal year 2006. Net sales were negatively impacted during the first quarter of fiscal year 2007 by lower commodity prices and a pipeline curtailment incurred at the end of October for approximately six days. The curtailment was caused by an increase in the nitrogen content of the sales stream to approximately 5.5% versus a pipeline quality specification of 4% total inert components. A nitrogen rejection unit has been ordered and is scheduled to be installed in February 2007. We expect to incur approximately $600,000 acquiring the unit, transporting it to our Southern Illinois Basin Project and installing the unit for operation.

     Lease operating expense — During the first quarter of fiscal year 2007, lease operating expense increased $175,170 over the first quarter of fiscal year 2006. Lease operating expense represents 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 at the Southern Illinois Basin Project, new lease operating expenses at our pilot project in the Northern Illinois Basin and the hiring of additional field personnel.

     General and administrative expense — General and administrative expense consisted of the following for the first quarter of fiscal years 2007 and 2006, respectively:

		Three Months ended
		October 31,								Dollar				%
		2006				2005				Variance				Change
Salaries and benefits		$	1,210,746			$	223,871			$	986,875				441	%
Stock-based compensation			644,851				397,586				247,265				62	%
Professional and regulatory			586,913				542,123				44,790				8	%
Other			292,200				108,844				183,356				168	%
Total general and administrative expense		$	2,734,710			$	1,272,424			$	1,462,286				115	%

     During the first quarter of fiscal year 2007, salaries and benefits increased $986,875 over the first quarter of fiscal year 2006. The increase was primarily the result of hiring additional personnel to support our growth, including a Senior Vice President of Operations, a geologist and three engineers, including cash signing bonuses totaling $350,000 paid to such personnel during the quarter. In addition, the first quarter of fiscal year 2007 includes $250,000 in severance paid to our former Chief Financial Officer who resigned in October 2006.

     During the first quarter of fiscal year 2007, stock-based compensation increased $247,265 over the first quarter of fiscal year 2006. No stock options were granted in the first quarter of fiscal year 2007, whereas during the first quarter of fiscal year 2006 we granted options to purchase 495,000 common shares that were valued at $.80 per option share under the Black-Scholes valuation model. Stock-based compensation expense for the first quarter of fiscal year 2007 primarily relates to the vesting of restricted shares, the grant of 350,000 unrestricted common shares to newly hired members of our technical team and the grant of 248,661 unrestricted common shares to certain of our executive officers, employees and non-employee directors related to bonuses and directors’ fees. Stock-based compensation expense excludes $228,432 related to share-based payments made to our former Chief Financial Officer during the first quarter of fiscal year 2007. This amount was capitalized and is being amortized over the term of the non-compete clause of the separation agreement we entered into with our former Chief Financial Officer. We intend to continue to rely on the granting of equity awards, primarily restricted shares, in order to attract and retain qualified individuals.

     Depreciation, depletion and amortization expense — During the first quarter of fiscal year 2007, depreciation, depletion and amortization expense (“DD&A”) increased $89,196 over the first quarter of fiscal year 2006. 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 three to 10 years. The increase is primarily due to the increase in capitalized development costs and an increase in production over the first quarter of fiscal year 2006. Additionally, depreciation expense increased due to additions to other support equipment.

     Interest income — During the first quarter of fiscal year 2007, interest income increased $86,287 over the first quarter of fiscal year 2006 due to higher average cash balances during the first quarter of fiscal year 2007. 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.

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 the Company’s results of operations or financial position were discussed in Item 7 of our Annual Report on Form 10-K for the fiscal year ended July 31, 2006. There were no material changes in these policies during the current quarter.

Financial Condition

     Our primary source of liquidity historically has come from the sale of our common shares in private placements and the proceeds from the exercise of warrants and options to acquire our common shares. To date, we have not relied significantly on borrowing to finance our operations or provide cash. As of October 31, 2006, we had only $145,842 in long-term notes payable. From July 31, 2003 until October 31, 2006, we raised $43,198,616 from the sale of our common shares. Additionally, during that same period, we collected $6,728,810 and $2,042,280 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 $294,002 and $209,694 for the three months ended October 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 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 about 24 months to reach peak production. The impact on our cash position is that there will be a delay of up to 24 months between the time we initially invest in drilling and completing a well and the time when a typical well will begin to make a 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 $14,697,615 as of October 31, 2006, compared to $19,279,015 at July 31, 2006. The net decrease in our cash balance is primarily due to the net cash used in operating activities of $1,318,654, consisting primarily of payments for salaries and benefits, professional fees and lease operating expenses, adjustments for changes in working capital, and net cash used in investing activities of $3,192,573, consisting primarily of development costs at our Northern Illinois Basin Project and purchases of other supporting property and equipment. We also made repayments of long-term notes in the amount of $70,173 during the quarter ended October 31, 2006.

     We have no contractual commitments for capital expenditures. However, our plan anticipates that for the fiscal year ending July 31, 2007, we will spend approximately $12.0 million to $30.0 million on capital expenditures. These amounts correspond to drilling 58 wells at the low end of the range and 123 wells at the upper end. These amounts include installing a gathering system and processing yard to handle the anticipated production from our 10-well pilot program, the five test wells completed in the past quarter and additional pilot wells and/or production wells at our three current projects. In addition to our drilling program, we expect to pursue the acquisition of additional CBM rights during the fiscal year. Our cash balance as of October 31, 2006 is insufficient to fully fund the high end of the range of forecasted capital expenditures and net cash used by operating activities during our 2007 fiscal year or our operations beyond that date. Therefore, we will likely need to raise additional funds in the near future. We currently do not have any specific plans to raise financing in support of our operations. Although management has no specific plans in place to raise the additional capital necessary to fund our plan of operations and forecasted capital expenditures, management anticipates raising the additional required capital through a combination of additional stock sales, the issuance of debt securities, borrowing and/or entering into joint ventures. 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.

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 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 capital expenditures and operations through July 31, 2007 or thereafter, (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, we conducted an evaluation, under the supervision and with the participation of our Chief Executive Officer and Controller (who is currently responsible for performing certain functions of our principal financial officer), of the effectiveness of our 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, our Chief Executive Officer and Controller have concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

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

     There have been no significant 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.

     We are a party to legal actions that arise in the ordinary course of our business. Based in part on consultation with legal counsel, we believe that (i) the liability, if any, under these claims will not have a material adverse effect on us, and (ii) the likelihood that the liability, if any, under these claims is material is remote.

Item 1A. Risk Factors.

     There are no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the fiscal year ended July 31, 2006. For more information regarding such risk factors, please refer to Item 1A of our Annual Report on Form 10-K for the fiscal year ended July 31, 2006.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

     In our fiscal quarter ended October 31, 2006, we issued the following unregistered securities:

	•		a grant of 350,000 fully vested common shares at a weighted average market price of $0.93 per share; and
	•		a grant of 700,000 restricted shares at a weighted average market price of $0.93 per share.

     We made both of these grants in connection with the hiring of a geologist and three engineers. We made these grants outside of our Omnibus Stock Plan pursuant to American Stock Exchange rules that allow us to make equity grants to newly hired employees outside of a shareholder-approved plan. Each issuance was exempt from registration under the Securities Act of 1933 in reliance on Section 4(2) of the Securities Act and/or regulations issued thereunder as sales to qualified purchasers not involving a public offering.

Item 3. Defaults Upon Senior Securities.

     None.

Item 4. Submission of Matters to a Vote of Security Holders.

     None.

Item 5. Other Information.

     None.

Item 6. Exhibits.

10.1		Separation Agreement and Waiver and Release by and between BPI Energy Holdings, Inc. and George J. Zilich, dated October 12, 2006 (Filed as Exhibit 10.1 to Form 8-K of BPI Energy Holdings, Inc. filed with the SEC on October 16, 2006 and incorporated herein by reference).
10.2		Mineral Lease, dated as of September 9, 2006, by and between BPI Energy, Inc. and the County of Washington, Illinois (Western Illinois Basin Project) (Filed as Exhibit 10.12 to Form 10-K of BPI Energy Holdings, Inc. filed on October 30, 2006 and incorporated hereinby reference).

31.1		Section 302 Certification of the Chief Executive Officer (Principal Executive Officer).
31.2		Section 302 Certification of the Acting Chief Financial Officer (Principal Financial Officer).
32.1		Section 906 Certification of the 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.