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 January 31, 2006

Commission File No. 001-32695

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		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 ý No ¨

     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 ¨		Accelerated filer ¨		Non-accelerated filer ý

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

     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 March 13, 2006: 66,604,687

 

 

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

BPI Energy Holdings, Inc.
Consolidated Balance Sheets

ASSETS

		January 31, 2006				July 31, 2005
		(Unaudited)
Current Assets:
Cash and cash equivalents		$	26,623,707			$	7,251,503
Accounts receivable			159,634				34,671
Other current assets			270,445				23,534
Total current assets			27,053,786				7,309,708
Property and equipment, at cost:
Oil and gas properties, full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $142,023 and $58,523			15,970,561				10,190,929
Unproved			3,244,807				3,149,372
Net oil and gas properties			19,215,368				13,340,301
Other property and equipment, net of accumulated depreciation and amortization of $462,530 and $398,988			4,434,311				1,769,812
Net property and equipment			23,649,679				15,110,113
Investment in Hite Coalbed Methane, L.L.C.			—				846,766
Restricted cash			134,000				100,000
Other non-current assets			161,125				161,125
		$	50,998,590			$	23,527,712
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,486,767			$	2,144,066
Current maturity of long-term notes payable			239,071				42,227
Accrued liabilities and other			72,145				31,405
Total current liabilities			1,797,983				2,217,698
Long-term notes payable, less current portion			94,768				507,595
Other non-current liabilities			45,949				—
Total liabilities			1,938,700				2,725,293
Shareholders’ equity:
Common shares, no par value, authorized 100,000,000 shares, 64,378,087 and 43,912,961 outstanding			64,573,394				34,666,022
Additional paid-in capital			4,891,266				4,493,680
Accumulated deficit			(20,404,770	)			(18,357,283	)
Total shareholders’ equity			49,059,890				20,802,419
		$	50,998,590			$	23,527,712

See Notes to Unaudited Consolidated Financial Statements.

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

		Three Months Ended January 31								Six Months Ended January 31
		2006				2005				2006				2005
Revenues:
Gas sales		$	327,811			$	6,341			$	537,505			$	6,341
Expenses:
Lease operating expense			300,806				—				461,610				—
General and administrative expenses			1,165,483				2,752,852				2,437,239				3,165,087
Depreciation, depletion and amortization			117,890				34,086				212,692				57,672
			1,584,179				2,786,938				3,111,541				3,222,759
Other income (expenses):
Interest income			270,186				4,353				402,804				4,847
Interest expense			(6,234	)			(5,407	)			(13,778	)			(10,582	)
Other income (expense)			138,191				3,246				137,523				3,246
			402,143				2,192				526,549				(2,489	)
Loss before income taxes			(854,225	)			(2,778,405	)			(2,047,487	)			(3,218,907	)
Deferred income tax benefit			—				292,562				—				344,717
Net loss		$	(854,225	)		$	(2,485,843	)		$	(2,047,487	)		$	(2,874,190	)
Basic and diluted loss per share		$	(0.01	)		$	(0.07	)		$	(0.04	)		$	(0.09	)
Weighted average common shares outstanding			63,654,794				34,790,336				57,889,094				32,018,325

See Notes to Unaudited Consolidated Financial Statements.

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

										Additional								Total
		Common Shares								Paid-in				Accumulated				Shareholder
		Shares				Amounts				Capital				Deficit				Equity
Balance, July 31, 2005			43,912,961			$	34,666,022			$	4,493,680			$	(18,357,283	)		$	20,802,419
Proceeds from stock options exercised			391,667				379,379				—				—				379,379
Proceeds from warrants exercised			2,073,459				1,644,039				—				—				1,644,039
Net proceeds from shares issued in private placement — September 23, 2005(1)			18,000,000				27,883,954				—				—				27,883,954
Stock-based compensation			—				—				397,586				—				397,586
Net loss			—				—				—				(2,047,487	)			(2,047,487	)
Balance, January 31, 2006			64,378,087			$	64,573,394			$	4,891,266			$	(20,404,770	)		$	49,059,890

See Notes to Unaudited Consolidated Financial Statements.

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

		Six Months Ended January 31
		2006				2005
Operating activities:
Net loss		$	(2,047,487	)		$	(2,874,190	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization			212,692				57,672
Stock-based compensation expense			397,586				2,200,777
Gain on sale of investment			(127,416	)			(3,246	)
Deferred income tax benefit			—				(344,717	)
Other			—				14,881
Changes in assets and liabilities:
Accounts receivable			(124,963	)			(6,341	)
Other current assets			(246,911	)			(17,714	)
Accounts payable			(657,299	)			(99,039	)
Accrued liabilities and other			71,922				496
Other non-current liabilities			45,949				—
Net cash used in operating activities			(2,475,927	)			(1,071,421	)
Investing activities:
Proceeds from sale of investment			551,000				43,956
Additions to oil and gas properties			(5,958,567	)			(1,907,403	)
Additions to other property and equipment			(2,560,216	)			(371,736	)
Acquisition of equity interest in joint venture			—				(78,112	)
Increase in restricted cash			(34,000	)			—
Net cash used in investment activities			(8,001,783	)			(2,313,295	)
Financing activities:
Payments on long-term notes payable			(57,458	)			(14,828	)
Net proceeds from issuance of common shares			29,907,372				14,140,215
Net cash provided by financing activities			29,849,914				14,125,387
Net increase in cash and cash equivalents			19,372,204				10,740,671
Cash and cash equivalents at the beginning of the period			7,251,503				970,795
Cash and cash equivalents at the end of the period		$	26,623,707			$	11,711,466
Supplementary disclosure of cash flow information:
Non-cash investing and financing activity:
Acquisition of equipment by issuance of notes payable		$	233,475			$	—

Interest paid approximates interest expense.

See Notes to Unaudited Consolidated Financial Statements.

BPI Energy Holdings, Inc.
Notes to Consolidated Financial Statements
(Unaudited)

1.		SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
		Basis of Presentation
		These unaudited consolidated interim financial statements include the accounts of BPI Energy Holdings, Inc. and its wholly owned U.S. subsidiary, BPI Energy, Inc. (collectively, “the Company”). All inter-company transactions and balances have been eliminated upon consolidation.
		BPI Energy Holdings, Inc. is incorporated in British Columbia, Canada and, through its wholly owned U.S. subsidiary, BPI Energy, Inc., is involved in the acquisition, exploration and development of coalbed methane properties located in the United States of America. The Company conducts its operations in one reportable segment, which is oil and gas exploration and production. On December 13, 2005, the Company’s common shares began trading on the American Stock Exchange (“AMEX”) under the symbol BPG. As a result of the shares being listed on the AMEX, the Company voluntarily de-listed from trading its shares on the TSX Venture Exchange. Amounts shown are in U.S. Dollars unless otherwise indicated.
		The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the quarter and six months ended January 31, 2006 are not necessarily indicative of the results that may be expected for the full fiscal year. For further information, refer to the consolidated financial statements and notes thereto included in the Company’s Form S-1 filed with the Securities and Exchange Commission on December 5, 2005. Certain prior period amounts have been reclassified to conform to current period presentation.
		Use of Estimates
		The preparation of these unaudited consolidated financial statements requires the use of certain estimates by management in determining the Company’s assets, liabilities, revenues and expenses. Actual results could differ from such estimates. Depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose of, and restore the Company’s properties. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. Proved reserves of oil and natural gas are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions.
		Oil and Gas Properties
		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:

		January 31				July 31
		2006				2005
Other Property and Equipment:
Gas collection equipment		$	3,758,264			$	1,332,012
Support equipment			1,058,731				760,467
Other			79,846				76,321
Less: Accumulated depreciation and amortization			(462,530	)			(398,988	)
		$	4,434,311			$	1,769,812

		Asset Retirement Obligations
		The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it is incurred, if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the associated long-lived asset. Amortization of the capitalized asset retirement cost is determined on a units-of-production method. Accretion of the asset retirement obligation is recognized over time until the obligation is settled. The Company’s asset retirement obligations relate to the plugging of wells upon exhaustion of gas reserves. The Company assessed its asset retirement obligation in prior periods and deemed it to be immaterial. The initial liability for our asset retirement obligations was recorded as of August 1, 2005 in the amount of $19,778.

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

		Six Months Ended January 31
		2006				2005
Asset retirement obligation at beginning of period		$	19,778			$	—
Accretion expense			1,335				—
Liabilities incurred			24,836				—
Asset retirement obligation at end of period		$	45,949			$	—

		Loss Per Share
		Loss per share is calculated using the weighted average number of common shares outstanding during the year. Diluted loss per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted loss per share is not disclosed as all common share equivalents were anti-dilutive for the quarter and six months ended January 31, 2006. Outstanding options and warrants that were excluded from the computation of diluted loss per share, as the effect of their assumed exercises would be anti-dilutive, totaled 14,844,215 at October 31, 2005 and 13,150,828 at January 31, 2006.
		Share-Based Payment
		Prior to December 13, 2005 the Company had a stock-based compensation plan (the “Incentive Stock Option Plan”) under which stock options were issued to directors, officers, employees and consultants as determined by the Board of Directors and subject to the provisions of the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted options to be issued with exercise prices at a discount to the market price of the Company’s common stock on the day prior to the date of grant. However, the majority of all stock options issued under the Incentive Stock Option Plan were issued with exercise prices equal to the quoted market price of the stock on the date of grant. Options granted under the Incentive Stock Option Plan vested immediately and were exercisable over a period not exceeding five years. The Company had options to purchase 4,030,612 shares of common stock outstanding under the Incentive Stock Option Plan at January 31, 2006.
		On December 13, 2005, the shareholders of the Company approved the BPI Industries Inc. 2005 Omnibus Stock Plan (the “Omnibus Stock Plan”) and it became effective on that date. The Omnibus Stock Plan replaces the Incentive Stock Option Plan under which stock options were previously granted. The Omnibus Stock Plan will be administered by the Compensation Committee of the Board of Directors (the “Committee”) and will remain in effect for five years. All employees and Directors of the Company and its subsidiaries, and all consultants or agents of the Company designated by the Committee, are eligible to participate in the Omnibus Stock Plan. The Committee has authority to: grant awards, select the participants who will receive awards, determine the terms, conditions, vesting periods and restrictions applicable to the awards, determine how the exercise price is to be paid, modify or replace outstanding awards within the limits of the Omnibus Stock Plan, accelerate the date on which awards become exercisable, waive the restrictions and conditions applicable to awards, and establish rules governing the Omnibus Stock Plan. No options have been issued under the Omnibus Stock Plan as of January 31, 2006.
		In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment. This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. The key provision of SFAS No. 123(R) requires companies to record share-based payment transactions as compensation expense at fair market value based on the grant-date fair value of those awards. Previously under SFAS 123, companies had the option of either recording expense based on the fair value of stock options granted or continuing to account for stock-based compensation using the intrinsic value method prescribed by APB No. 25.

		The Company adopted SFAS No. 123(R), using the modified-prospective method, effective August 1, 2005. Since August 1, 2001, the Company followed the fair value provisions of SFAS 123 and recorded all share-based payment transactions as compensation expense at fair market value based on the grant-date fair value of those awards. In addition, all stock options previously granted by the Company vested immediately on the date of grant, and thus there was no unvested portion of previous stock option grants which vested during the quarter or six months ended January 31, 2006. Therefore, SFAS 123(R) had no impact on the Company’s consolidated financial position or results of operations for the quarter and six months ended January 31, 2006. The Company continues to use the Black-Scholes formula to estimate the fair value of stock options previously granted under the Incentive Stock Option Plan.
2.		STOCK-BASED COMPENSATION
		The tables below summarize stock options activity for the six months ended January 31, 2006 and 2005, respectively. All stock options were granted with exercise prices denominated in Canadian Dollars. U.S. Dollar amounts shown in the tables below were derived using published exchange rates on the date of the transaction for grants, cancellations, exercises and expirations and at period-end exchange rates for options outstanding as of July 31, 2005 and 2004 and January 31, 2006 and 2005.

						Weighted-Average
Six Months Ended January 31, 2006:						Exercise Price
		Number of options				CAD$				USD$
Outstanding at July 31, 2005			4,227,279			$	1.82			$	1.49
Granted — exercise price equal to market price of stock on date of grant			495,000				2.05				1.75
Exercised			(341,667	)			1.19				1.00
Cancelled			(300,000	)			1.82				1.52
Outstanding at October 31, 2005			4,080,612			$	1.88			$	1.60
Exercised			(50,000	)			1.43				1.22
Outstanding at January 31, 2006			4,030,612			$	1.88			$	1.64

						Weighted-Average
Six Months Ended January 31, 2005:						Exercise Price
		Number of options				CAD$				USD$
Outstanding at July 31, 2004			2,230,556			$	.78			$	0.59
Cancelled			(13,889	)			1.20				0.98
Outstanding at October 31, 2004			2,216,667			$	0.77			$	0.63
Granted — exercise price equal to market price of stock on date of grant			2,097,278				1.93				1.55
Granted — exercise price less than market price of stock on date of grant			852,778				1.19				.96
Exercised			(1,040,000	)			0.69				0.57
Cancelled			(11,111	)			1.20				0.98
Outstanding at January 31, 2005			4,115,612			$	1.47			$	1.19

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

		Six Months Ended January 31,
		2006				2005
Risk-free interest rate			3.3%				3.0 - 3.5%
Expected dividend yield		Nil				Nil
Expected stock price volatility			66%				74 - 81%
Expected option life		3 years				3 years

		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 January 31, 2006:

Exercise
Price				Number				Remaining				Expiry
CAD$				Outstanding				Life (Years)				Date
$	0.65				350,000				2.8			November 3, 2008
	0.90				143,334				0.9			January 10, 2007
	0.90				100,000				1.2			April 10, 2007
	0.90				15,000				3.6			September 22, 2009
	1.20				50,000				0.9			January 10, 2007
	1.49				710,666				3.8			November 29, 2009
	2.05				495,000				4.6			September 22, 2010
	2.19				911,000				4.2			March 27, 2010
	2.36				115,000				4.3			May 23, 2010
	2.40				1,140,612				4.0			January 20, 2010
$	1.88				4,030,612				3.8

3.		INCOME TAXES
		We operate in two tax jurisdictions, the United States and Canada. Primarily as a result of the net operating losses that we have generated (“NOL Carryforwards”) in both Canada and the United States, we have generated deferred tax benefits available for tax purposes to offset net income in future periods. SFAS No. 109, Accounting for Income Taxes, requires that we record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of sufficient future taxable income before the expiration of the NOL Carryforwards. Because of the Company’s limited operating history, limited financial performance and cumulative tax loss from inception, it is management’s judgment that SFAS No. 109 requires the recording of a full valuation allowance for net deferred tax assets in both Canada and the United States as of January 31, 2006.
		We recorded a tax benefit in the United States for the six months ended January 31, 2005 to partially offset a net deferred tax liability at January 31, 2005; however, no tax benefit was recognized for the six months ended January 31, 2006 as the Company had no net deferred tax liability to offset.

4.		LONG-TERM NOTES PAYABLE
		The Company has outstanding notes payable as follows:

		January 31,				July 31,
		2006				2005
Case Credit term note due in fiscal year 2006, 6.50%		$	28,582			$	32,833
GMAC term notes due in fiscal year 2009, 6.50%			25,163				26,633
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%			94,979				98,356
Convertible note due in fiscal year 2008, 3.25%			—				392,000
Caterpillar Financial Services Corp			195,568				—
			333,839				549,822
Less current maturities			(239,071	)			(42,227	)
Long-term notes payable		$	94,768			$	507,595

		The notes are collateralized by the related vehicles and equipment. The convertible note payable outstanding at July 31, 2005 was issued in June 2003 with a face value of $392,000 and maturing on June 10, 2008, bearing interest at 3.25%, convertible at the option of the holder, prior to June 10, 2008, into 390,537 common shares of the Company. The convertible note payable was cancelled on January 4, 2005 pursuant to the sale of the Company’s interest in Hite Coalbed Methane, L.L.C. — see Note 7.
		The annual maturities of all notes for the remaining six months of fiscal year 2006 and the four fiscal years thereafter are as follows:

		Principal				Interest				Total
2006		$	137,451			$	9,201			$	146,652
2007			121,239				7,160				128,399
2008			27,982				3,855				31,837
2009			29,767				2,070				31,837
2010			17,400				440				17,840
		$	333,839			$	22,726			$	356,565

5.		SHAREHOLDERS’ EQUITY
		In September 2005, the Company sold 18,000,000 common shares in a private placement. The proceeds from this private placement of $27,883,954 net of $2,619,953 of share issuance costs, will be used to fund the Company’s plan of operations and for working capital and general corporate purposes.
		The Company has share purchase warrants outstanding at January 31, 2006 as follows:

Number		Exercise		Expiry
Outstanding		Price		Date
3,177,016		CAD $1.00		April 29, 2006
4,906,000		USD $1.50		December 13, 2007
1,037,200		USD $1.25		January 15, 2010
9,120,216

6.		RELATED PARTY TRANSACTIONS
		The Company enters into various transactions with related parties in the normal course of business operations.
		Randy Oestreich, the Company’s Vice President of Field Operations, owns and operates A-Strike Consulting, a consulting company that provides, among other things, laboratory testing related to CBM. Beginning in the fiscal year ended July 31, 2005, the Company owns and maintains a lab testing facility and allows A-Strike Consulting to operate the facility. The Company pays all expenses related to the facility and, in return, receives 80% of the revenue generated from the operations of the facility as reimbursement of the Company’s expenses. The Company received approximately $38,451 and $0 in expense reimbursement related to this arrangement during the six months ended January 31, 2006 and 2005, respectively.
		Mr. Oestreich’s brother owns Dependable Service Company, a company that provides general labor services to the Company. The Company paid Dependable Services Company $160,679 and $54,929 during the six months ended January 31, 2006 and 2005, respectively.
7.		SALE OF INVESTMENT IN HITE COALBED METHANE, L.L.C.
		On January 4, 2006, the Company sold its 49% interest in Hite Coalbed Methane, L.L.C. (“HCM”) for $551,000 in cash and cancellation of the Company’s convertible note payable in the amount of $392,000, plus accrued interest of $31,182. The note was convertible into 390,537 of the Company’s common shares. The Company accounted for its investment in HCM under the cost method of accounting. The total consideration received of $974,182 resulted in a gain on the sale of the investment of $127,416, which is included in other income in the Company’s statement of operations for the quarter and six months ended January 31, 2006.
8.		LEGAL PROCEEDINGS
		On April 3, 2001 the Company entered into an Oil, Gas and Coalbed Methane Gas Lease (“Lease”) with American Premier Underwriters, Inc. and AFC Coal Properties, Inc. (collectively, the “Lessors”).
		The Lease has an initial term of five years that expires on April 3, 2006; however, the term is extended as to the 320 acre tract that surrounds each well so long as CBM is produced from such tract providing a royalty payment of at least $1.00 per acre per month; provided, however, after the initial five year term, if aggregate royalties do not exceed $42,000 in any month, the Lease shall terminate.
		In August 2005, the original Lessors transferred, subject to the Lease, certain of their rights under the Lease, including certain of their rights in and to the CBM to Colt, LLC and Peabody Land Holdings, LLC (collectively, the “Transferees”). The Company believes that at least one of the Transferees, Colt, LLC, has taken steps that have interfered with the Company’s ability to carry out its development plans and generate the royalties necessary to extend the Lease (including the establishment of additional wells prior to the April 3, 2006 deadline).
		On March 15, 2006, the Company filed a complaint against the Lessors and Transferees alleging (i) tortious interference with business relations and (ii) breach of contract. The Company is seeking a preliminary and permanent injunction, declaratory judgment and unspecified monetary damages. The complaint was filed in the United States District Court for the Southern District of Ohio.
		The Company believes that it should be successful in extending the term of the lease as to existing wells and certain other areas subject to the Lease where the Company believes the Lessors and Transferees have interfered with its ability to establish wells prior to the April 3, 2006 deadline. However, there exists a reasonable possibility that the Company will be unable to extend the Lease as to either or both of the existing wells or additional areas where the Lessors and Transferees have interfered with the Company’s establishment of wells. The effect of the loss of all of the Company’s acreage under the Lease may result in a write-down of capitalized net oil and gas and other

		properties in an amount up to approximately $22 million. The effect of the loss of only the Company’s non-producing acreage (those areas in which wells had not yet been established) may result in a write-down of capitalized net oil and gas and other properties in an amount up to approximately $4 million.
9.		SUBSEQUENT EVENT
		On February 9, 2006, at a special meeting of the Company’s shareholders, the shareholders voted to approve amendments to the Company’s governing documents that:

	1.		changed the name of the Company to BPI Energy Holdings, Inc.;
	2.		increased the number of shares of common stock that the Company is authorized to issue from 100 million shares to 200 million shares;
	3.		increased the quorum necessary to transact business at a meeting of the Company’s shareholders to the holders of 33 1/3% of the Company’s shares of common stock; and
	4.		permit meetings of the Company’s shareholders to be held outside of British Columbia, Canada.

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

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 primarily engaged, through our wholly owned U.S. subsidiary, BPI Energy, Inc., in the exploration for and development of coalbed methane (“CBM”). Our exploration and development efforts are concentrated in the Illinois Basin. 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 our second quarter ended January 31, 2006, we owned or controlled CBM rights, through mineral leases, options to acquire mineral leases, and farm-out agreements, covering 418,435 total acres. A substantial majority of the acreage under our control was undeveloped as of January 31, 2006.

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

We are not currently generating net income or positive cash flow from operations. Even if we achieve increased revenues and positive cash flow from operations in the future, we anticipate increased exploration, development and other capital expenditures as we continue to explore and develop our mineral rights.

We believe that our current cash balances are sufficient to fully fund our capital expenditures and fund our anticipated net cash used by operating activities through July 31, 2006. However, our revenues and cash balances may not be sufficient to fund our operations beyond that date. Therefore, in order to fund our operations after July 31, 2006, we will likely need to raise additional financing.

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 leases that grant us the broadest possible rights to CBM for any given tract of land;
	•		conducting ongoing title reviews of existing mineral interests;
	•		where possible, negotiating and securing long-term service company commitments to insure availability of equipment and services; and
	•		attempting to create a low cost structure in order to reduce our vulnerability to many of these factors.

From early 2002 until 2005, our strategic focus was on building our acreage footprint in the Illinois Basin. BPI was built around the primary strategic objective of acquiring CBM rights in the Basin. As we began accumulating CBM rights we began testing our acreage to determine its CBM potential. Having accumulated CBM rights to just over

418,000 acres and conducting extensive testing at our Delta Project (“Delta”), we embarked (in late 2004) on a pilot production program at Delta. 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 Delta.

As our drilling and production operations have grown, we have not abandoned our goal of adding additional acreage and mineral rights; however, we have new additional goals and we realize that we must build and add to our organization in other critical areas as well. These new goals require us to bring in additional capital, resources and people with the technical and managerial expertise to assist us in achieving these goals. These additional goals include the following:

	•		developing the in-house capabilities necessary to enable us to meet our regulatory and reporting obligations to various regulatory agencies, constituencies and our shareholders;
	•		raise the capital necessary to achieve our plans and goals; and
	•		transition BPI from a company focused primarily on acquisition of mineral rights to a company focused on producing CBM.

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

In September 2005 we sold 18,000,000 shares of our common stock to a limited number of institutional investors and brought in approximately $28 million of new capital. We are conscious of the dilution caused to existing shareholders as a result of selling stock. We raised the amount we felt was required to fund our development plans until the time we are able to raise capital on more favorable terms.

Our rate of drilling new wells at Delta has slowed due to a dispute with one of the coal owners. We are eager to step up our drilling program and get to our planned level of drilling activity of 15 wells per month at our Delta Project. In this regard, we will continue to attempt to negotiate a mutually satisfactory development plan and lease amendment with our lessor(s); however, we have initiated a lawsuit in federal court in order to preserve our rights under the lease covering our Delta Project (see Note 8 of our financial statements). As of the end of the second quarter of fiscal year 2006, we had 73 wells that were in production and an additional 22 wells that were drilled, but not yet in production. All of our productive wells are on our Delta Project. Most of these wells are still in the early stages of dewatering and represent only a small fraction of our total potential drilling locations.

We initiated production at Delta because this is where we began our testing program and had the most data. We made the decision at Delta to invest in a gathering system and the other infrastructure necessary to begin CBM production and sales. Our Delta Project covers approximately 50,000 acres in Southern Illinois. The results from our production at the Delta Project reinforce our belief that the Illinois Basin is not only commercially viable, but also that the Basin will become a meaningful contributor to the overall supply of natural gas to the Midwest.

We are currently performing testing at our Montgomery Project. Our CBM rights in the Montgomery Project cover 239,487 acres in Montgomery, Shelby and Macoupin counties in Illinois, which are located in the north central part of the Illinois Basin. The coal seams at our Montgomery Project are some of the thickest found in the Illinois Basin, with some seams as thick as 10 feet. We are currently testing nine seams that could be commercially viable. We expect to initiate our second development front at our Montgomery Project in Spring 2006.

Our plan for our Clinton/Washington project for the current fiscal year is to drill four test wells in each of the four separate lease blocks constituting this project. We will gain valuable test data that we believe will assist us in planning our future development of this acreage.

As a company, we have limited in-house CBM operating and engineering resources. As a result, in the initial stages of our drilling and production activities, we have utilized outside contractors to perform most of these activities. We have focused on increasing our internal engineering and operating resources as a primary goal of BPI over the coming years. In this regard, we have begun the process of identifying and interviewing candidates with the technical skills we believe are necessary to help BPI become a world class CBM drilling and production company. This will take considerable time, but we believe it is necessary in order to realize the value of the CBM assets we have assembled.

Results of Operations

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

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

		Three Months Ended January 31
										Dollar				%
		2006				2005				Variance				Change
Revenues:
Gas sales		$	327,811			$	6,341			$	321,470				5,070	%
Expenses:
Lease operating expense			300,806				—				300,806				100	%
General and administrative expense			1,165,483				2,752,852				(1,587,369	)			(58	)%
Depreciation, depletion and amortization			117,890				34,086				83,804				246	%
			1,584,179				2,786,938				(1,202,759	)			(43	%)
Other income (expenses):
Interest income			270,186				4,353				265,833				6,107	%
Interest expense			(6,234	)			(5,407	)			(827	)			(15	)%
Other income			138,191				3,246				134,945				4,157	%
			402,143				2,192				399,951				18,246	%
Loss before income taxes			(854,225	)			(2,778,405	)			1,924,180				69	%
Deferred income tax benefit			—				292,562				(292,562	)			(100	)%
Net loss		$	(854,225	)		$	(2,485,843	)		$	1,631,618				66	%

Revenue — During the second quarter of fiscal year 2006, revenue increased $321,470 over the second 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 27,556 Mcf and our average realized selling price per Mcf was $11.90 for the second quarter of fiscal year 2006.

Lease operating expense — During the second quarter of fiscal year 2006, lease operating expense increased $300,806 over the second 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. We commenced production toward the end of January 2005 and, thus, incurred no lease operating expense during the second quarter of fiscal year 2005.

General and administrative expense — General and administrative expense consisted of the following for the second quarters of fiscal year 2006 and 2005, respectively:

		Three Months ended January 31
										Dollar				%
		2006				2005				Variance				Change
Salaries and benefits		$	503,368			$	275,956			$	227,412				82	%
Stock-based compensation			—				2,200,777				(2,200,777	)			(100	)%
Professional fees			400,991				108,520				292,471				270	%
Other			261,124				167,599				93,525				56	%
Total general and administrative expense		$	1,165,483			$	2,752,852			$	(1,587,369	)			(58	)%

During the second quarter of fiscal year 2006, salaries and benefits increased $227,412 over the second quarter of fiscal year 2005. The increase was primarily the result of hiring additional personnel to support our growth, including both a chief financial officer and controller.

During the second quarter of fiscal year 2006, stock-based compensation decreased $2,200,777 over the second quarter of fiscal year 2005. No stock options were granted in the second quarter of fiscal year 2006, whereas options to purchase 2,950,056 shares of common stock were granted to employees and directors in the second quarter of fiscal year 2005.

During the second quarter of fiscal year 2006, professional fees increased $292,471 over the second quarter of fiscal year 2005. The increase was primarily the result of increased professional fees incurred in connection with SEC filings, American Stock Exchange listing fees, higher audit related fees and additional legal services.

During the second quarter of fiscal year 2006, other general and administrative expenses increased $93,525 over the second quarter of fiscal year 2005, primarily as a result of increased insurance costs.

Depreciation, depletion and amortization expense — During the second quarter of fiscal year 2006, depreciation, depletion and amortization expense (“DD&A”) increased $83,804 over the second quarter of fiscal year 2005. We compute DD&A on capitalized drillings costs and gas collection equipment using the units-of-production method based on estimates of proved reserves, and on all other property and equipment using the straight-line method based on estimated useful lives ranging from 3 to 10 years. The increase is primarily due to the fact that there was very little production in the second quarter of fiscal year 2005. Additionally, depreciation expense increased due to additions to other support equipment.

Interest income — During the second quarter of fiscal year 2006, interest income increased $265,833 over the second quarter of fiscal year 2005 due to significantly higher average cash balances during the second 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 — During the second quarter of fiscal year 2006, other income increased $134,945 over the second quarter of fiscal year 2005 primarily due to us recognizing a gain of $127,416 on the sale of our investment in Hite Coalbed Methane, L.L.C. in January 2006.

Deferred income tax benefit — During the second quarter of fiscal year 2006, deferred income tax benefit decreased $292,562 over the second quarter of fiscal year 2005. We recorded a tax benefit in the United States in the second quarter of fiscal year 2005 to partially offset a net recorded deferred tax liability at January 31, 2005; however, no

tax benefit was recognized for the second quarter of fiscal year 2006, as the Company had no net deferred tax liability to offset.

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

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

		Six Months Ended January 31
										Dollar				%
		2006				2005				Variance				Change
Revenues:
Gas sales		$	537,505			$	6,341			$	531,164				8,377	%
Expenses:
Lease operating expense			461,610				—				461,610				100	%
General and administrative expense			2,437,239				3,165,087				(727,848	)			(23	)%
Depreciation, depletion and amortization			212,692				57,562				155,130				270	%
			3,111,541				3,222,649				(111,108	)			(3	)%
Other income (expenses):
Interest income			402,804				4,847				397,957				8,210	%
Interest expense			(13,778	)			(10,582	)			(3,196	)			30	%
Other income			137,523				3,246				134,277				4,137	%
			526,549				(2,489	)			529,038				n/a
Loss before income taxes			(2,047,487	)			(3,218,797	)			1,171,310				36	%
Deferred income tax benefit			—				344,717				(344,717	)			(100	)%
Net loss		$	(2,047,487	)		$	(2,874,080	)		$	826,593				29	%

Revenue — During the first six months of fiscal year 2006, revenue increased $531,164 over the first six months of fiscal year 2005. We realized our first revenues from the sale of CBM in January 2005. Net sales of gas (net of royalties) were 47,462 Mcf and our average realized selling price per Mcf was $11.32 for the first six months of fiscal year 2006.

Lease operating expense — During the first six months of fiscal year 2006, lease operating expense increased $461,610 over the first six months of 2005. Lease operating expenses represent production expenses, consisting primarily of repairs and maintenance, fuel and electricity, equipment rental and other overhead expenses related to producing wells. We commenced production toward the end of January 2005 and, thus, incurred no lease operating expense during the first six months of fiscal year 2005.

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

		Six Months ended January 31
										Dollar				%
		2006				2005				Variance				Change
Salaries and benefits		$	727,240			$	410,249			$	316,991				77	%
Stock-based compensation			397,586				2,200,777				(1,803,191	)			(82	%)
Professional fees			858,002				240,125				617,877				257	%
Other			454,411				313,936				140,475				45	%
Total general and administrative expense		$	2,437,239			$	3,165,087			$	(727,848	)			(23	%)

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

During the first six months of fiscal year 2006, stock-based compensation decreased $1,803,191 over the first six months of fiscal year 2005. During the first six months of fiscal year 2006, we granted options to purchase 495,000 shares of our common stock that were valued at $.80 per option. During the first six months of fiscal year 2005, we granted options to purchase 2,950,056 shares of our common stock that were valued at $.75 per option. The award of these options was consistent with our belief that it is necessary to provide this form of compensation for us to attract and retain qualified individuals.

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

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

Depreciation, depletion and amortization expense — During the first six months of fiscal year 2006, depreciation, depletion and amortization expense (“DD&A”) increased $155,130 over the first six months of fiscal year 2005. We compute DD&A on capitalized drillings costs and gas collection equipment using the units-of-production method based on estimates of proved reserves, and on all other property and equipment using the straight-line method based on estimated useful lives ranging from 3 to 10 years. The increase is primarily due to the fact that there was very little production in the first six months of fiscal year 2005. Additionally, depreciation expense increased due to additions to other support equipment.

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

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

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

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 January 31, 2006, we had only $333,839 in long-term notes payable. From July 31, 2002 until January 31, 2006, we raised $43,866,649 from the sale of our common stock. Additionally, during that same period, we collected $3,730,470 and $2,118,320 as a result of the exercise of warrants and stock options, respectively. Our primary use of these funds has been the acquisition, exploration, testing and development of our CBM properties and rights.

We did not begin to generate revenues from CBM sales until January 2005. Revenues from CBM sales were $537,505 and $6,341 for the six months ended January 31, 2006 and 2005, respectively. Subject to the various risks described in this report, we expect revenue from the sale of our CBM to increase due to (i) increased production from existing wells as they proceed through the initial dewatering phase and (ii) additional production generated as a result of drilling and production from additional wells. However, in view of the fact that we have very little historical experience of dewatering and gas production in the Illinois Basin, we can provide no assurance that we will achieve a trend of increased production and revenue in the future.

In addition, CBM wells typically must go through a lengthy dewatering phase before making any meaningful contribution to gas production. We estimate that a typical vertical well will require 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 meaningful 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 $26,623,707 at January 31, 2006 compared to $7,251,503 at July 31, 2005. The net increase in our cash balance is primarily due to the $27,883,954 of net proceeds we received from the sale of common stock in a private placement that closed on September 26, 2005, and $1,644,039 and $379,379 received as a result of the exercise of warrants and stock options, respectively, during the first six months of fiscal year 2006. We raised an amount in the private placement we felt was required to fund our development plans through April 2006. However, because our drilling progress at our Delta Project has slowed due to a dispute with one of the coal

owners, we now believe our cash balance will be sufficient to fund the forecasted net cash used by operating activities and capital expenditures through July 31, 2006. Our revenues and cash balances, however, may not be sufficient to fund our operations beyond that date. Therefore, in order to fund our operations after July 31, 2006, we will likely need to raise additional financing. We currently do not have any specific plans to raise financing in support of our future operations.

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 Annual Report distributed to our shareholders in December 2005 and in our Form S-1 filed with the Securities and Exchange Commission on December 5, 2005.

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 retain our acreage rights at our Delta Project or other projects at the expiration of our lease agreements, due to insufficient CBM production or other reasons, (b) our inability to generate sufficient income or obtain sufficient financing to fund our operations after July 31, 2006, (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 April 3, 2001 the Company entered into an Oil, Gas and Coalbed Methane Gas Lease (“Lease”) with American Premier Underwriters, Inc. and AFC Coal Properties, Inc. (collectively, the “Lessors”).

The Lease has an initial term of five years that expires on April 3, 2006; however, the term is extended as to the 320 acre tract that surrounds each well so long as CBM is produced from such tract providing a royalty payment of at least $1.00 per acre per month; provided, however, after the initial five year term, if aggregate royalties do not exceed $42,000 in any month, the Lease shall terminate.

In August 2005, the original Lessors transferred, subject to the Lease, certain of their rights under the Lease, including certain of their rights in and to the CBM to Colt, LLC and Peabody Land Holdings, LLC (collectively, the “Transferees”). We believe that at least one of the Transferees, Colt, LLC, has taken steps that have interfered with

our ability to carry out our development plans and generate the royalties necessary to extend the Lease (including the establishment of additional wells prior to the April 3, 2006 deadline).

On March 15, 2006, we filed a complaint against the Lessors and Transferees alleging (i) tortious interference with business relations and (ii) breach of contract. We are seeking a preliminary and permanent injunction, declaratory judgment and unspecified monetary damages. The complaint was filed in the United States District Court for the Southern District of Ohio.

We believe that we should be successful in extending the term of the lease as to existing wells and certain other areas subject to the Lease where we believe the Lessors and Transferees have interfered with our ability to establish wells prior to the April 3, 2006 deadline. However, there exists a reasonable possibility that we will be unable to extend the Lease as to either or both of the existing wells or additional areas where the Lessors and Transferees have interfered with our establishment of wells. The effect of the loss of all of our acreage under the Lease may result in a write-down of capitalized net oil and gas and other properties in an amount up to approximately $22 million. The effect of the loss of only our non-producing acreage (those areas in which wells had not yet been established) may result in a write-down of capitalized net oil and gas and other properties in an amount up to approximately $4 million.

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

None.

Item 3. Defaults Upon Senior Securities

None.

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

BPI Energy Holdings, Inc. held its Annual General Meeting of Shareholders on December 13, 2005. As described in the Proxy Statement/Information Circular for the Annual Meeting, the following actions were taken:

(a)

Election of Directors. The shareholders voted in favor of electing the following persons as Directors:

Name of Director		Number of Shares Voted For				Number of Shares Withheld
James Azlein			23,400,372				11,726
George Zilich			23,400,192				11,740
Costa Vrisakis			23,396,396				19,736
William J. Centa			23,395,002				16,930
Dennis Carlton			23,398,006				13,926

(b)

Approval of the BPI Industries Inc. 2005 Omnibus Stock Plan. The shareholders approved the BPI Industries Inc. 2005 Omnibus Stock Plan.

Votes For			20,513,798
Votes Against			2,525,053
Abstentions			373,264
Broker Non-Votes			557,600

(c)

Appointment of Independent Registered Public Accounting Firm. The shareholders ratified the appointment of Meaden & Moore, Ltd. as the Company’s independent registered public accounting firm for 2006.

Votes For			23,380,942
Votes Against			11,841
Abstentions			19,323
Broker Non-Votes			557,600

Item 5. Other Information

None.

Item 6. Exhibits

	31.1		Section 302 Certification By Chief 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.