UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Fiscal Year Ended July 31, 2007

 

Commission File Number: 001-32695

 

 

 

 

BPI Energy Holdings, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

 

 

30775 Bainbridge Road, Suite 280

Solon, Ohio 44139

(440) 248-4200

(Address and telephone number of principal executive offices)

 

 

 

 

Securities registered under Section 12(b) of the Exchange Act:

 

 

Securities registered under Section 12(g) of the Exchange Act:

 

None

 

 

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

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

 

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

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

 

Large Accelerated Filer o     Accelerated Filer o     Non-Accelerated Filer þ

 

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

 

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $26,149,553.

 

As of October 22, 2007, there were 73,792,493 shares of the Registrant’s Common Shares (without par value) outstanding.          

 

 

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

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

 

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

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

PART I

 

 

Coalbed Methane

 

We are engaged in the exploration, production and commercial sale of coalbed methane (“CBM”). CBM is a form of natural gas that is generated during coal formation and is contained in underground coal seams and abandoned mines.

 

Methane is the primary commercial component of natural gas produced from conventional gas wells. Natural gas produced from conventional wells generally contains other hydrocarbons in varying amounts that require the natural gas to be processed. CBM is generally pipeline-quality gas after simple water dehydration and removal of traces of nitrogen and other impurities.

 

CBM production is similar to conventional natural gas production in terms of the physical producing facilities. However, the subsurface mechanisms that allow gas movement to the wellbore are very different. Conventional natural gas wells require a subsurface that is porous, allows the gas to migrate easily, and contains a natural trap to capture and hold the gas reservoir. In contrast, CBM is held in place within coal seams in four ways:

 

 

Coal at shallower depths with good cleat development contains high concentrations of free and dissolved methane gas. Adsorption is generally higher in coal that contains a higher percentage of fixed carbon and generally increases with higher pressure, which occurs at deeper depths. Our current wells range in depths from 450 to 1,300 feet beneath the surface.

 

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

 

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

 

Our Business

 

We focus on the acquisition, exploration, development and production of CBM reserves located in the Illinois Basin, which covers approximately 60,000 square miles in the mid to southern part of Illinois, southwest Indiana and northwest Kentucky. Through lease and farm-out agreements and ownership of a CBM estate, we have assembled CBM rights covering approximately 512,000 acres in the Illinois Basin.

 

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

 

Our acreage rights in the Illinois Basin are currently divided into three projects. Our Southern Illinois Basin Project consists of approximately 10,000 acres in the southern part of the Illinois Basin. Our other acreage holdings include our Northern Illinois Basin Project, located in the north central part of the Illinois Basin, where we control through lease and farm-out agreements an aggregate of 366,364 acres of CBM rights. Our other project is our Western Illinois Basin Project, located in the northwestern part of the Illinois Basin, where we control through lease

and farm-out agreements an aggregate of 135,948 acres of CBM rights. In addition, we continue to look for opportunities to acquire additional CBM acreage rights in the Illinois Basin.

 

As of July 31, 2007, we have drilled 170 wells. These wells include 111 productive wells, six shut-in wells, 10 plugged wells, four disposal wells, three pressure observation wells, four divested wells, and 32 wells that have been drilled but are not yet in production, including 12 test wells.

 

Our History

 

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

 

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

 

Recent Developments — GasRock Financing

 

On July 27, 2007, BPI Energy, Inc. (“BPI Energy”), our wholly owned subsidiary, entered into an Advancing Term Credit Agreement (the “Credit Agreement”) with GasRock Capital LLC (“GasRock”). The Credit Agreement provides for an initial commitment to BPI Energy of $10.2 million and the possibility of future advances to BPI Energy of up to an additional $64.8 million. All future advances under the Credit Agreement beyond the initial commitment will be made in GasRock’s discretion. BPI Energy has received an initial advance of $9.1 million under the Credit Agreement, which resulted in net proceeds to BPI Energy of $8.2 million after the deduction of GasRock’s facility fee, investment banking fees, legal fees and other fees and expenses incurred by BPI Energy in connection with the transaction totaling $0.8 million. The initial advance is expected to be used for continued drilling of development wells at our Southern Illinois Basin Project, drilling of new test wells, pilot projects, possible lease acquisitions and general and administrative expenses.

 

BPI Energy may request advances under the Credit Agreement at any time before July 25, 2008, which GasRock may in its discretion extend until July 27, 2010. All amounts then outstanding under the Credit Agreement are due and payable on July 25, 2008 (the “Loan Termination Date”), which GasRock may in its discretion extend until July 29, 2011. For the first year of the term of the Credit Agreement, all amounts outstanding under the Credit Agreement will bear interest at a rate equal to the greater of (i) 15% per annum and (ii) the LIBOR rate plus 9% per annum. If GasRock extends the Loan Termination Date, amounts outstanding under the Credit Agreement will thereafter bear interest at a rate equal to the greater of (i) 12% per annum and (ii) the LIBOR rate plus 6% per annum. BPI Energy is required to make monthly interest payments on the amounts outstanding under the Credit Agreement but is not required to make any principal payments until the Loan Termination Date. BPI Energy may prepay the amounts outstanding under the Credit Agreement at any time without penalty.

 

BPI Energy is required to pay GasRock a facility fee upon the receipt of any advances under the Credit Agreement in an amount equal to two percent of the amount advanced. BPI Energy is also required to reimburse GasRock for all of the expenses GasRock incurs in connection with entering into and administering the Credit Agreement.

 

BPI Energy’s obligations under the Credit Agreement are secured by a first priority security interest in substantially all of BPI Energy’s properties and assets, including all of BPI Energy’s CBM rights under its leases, farm-out agreements and fee interests, all of BPI Energy’s wells at its Southern Illinois Basin Project, all of BPI Energy’s equipment and all of the common stock of BPI Energy (which has been pledged by us). We have provided a guaranty to GasRock of all of BPI Energy’s obligations under the Credit Agreement.

In connection with the execution of the Credit Agreement, BPI Energy granted GasRock a one percent royalty in all CBM produced and saved from BPI Energy’s existing leased and owned CBM properties and an additional four percent royalty interest in all CBM produced and saved from BPI Energy’s existing wells at its Southern Illinois Basin Project. As long as any of BPI Energy’s obligations remain outstanding under the Credit Agreement, BPI Energy will be required to grant the same one percent royalty interest to GasRock on new mineral interests acquired by BPI Energy after July 25, 2008 and the same four percent royalty interest on new wells drilled by BPI Energy that are funded by draws under the Credit Agreement.

 

The Credit Agreement requires BPI Energy to enter into a swap agreement under which approximately 75% of BPI Energy’s proved developed producing reserves scheduled to be produced during a two-year period will be guaranteed a price of not less than $7.00 per MMBtu. Pursuant to this requirement, BPI Energy has initially entered into a 23-month “costless collar” with BP Corporation North America Inc. (“BP”) under which BP is required to cover any shortfall below $7.00 per MMBtu that BPI Energy may receive for its CBM production (as determined by a reference market price) as to an aggregate notional amount of 460,000 MMBtu and BPI Energy must pay to BP any amounts above $11.00 per MMBtu that it receives for its CBM production (as determined by a reference market price) as to the notional amount. BPI Energy expects that it will enter into additional hedging arrangements during the next two years to cover the entire 75% of its proved developed producing reserves scheduled to be produced during that period.

 

BPI Energy is subject to various restrictive covenants under the Credit Agreement, including limitations on its ability to sell properties and assets, make distributions, extend credit, amend its material contracts, incur indebtedness, provide guarantees, effect mergers or acquisitions, cancel claims, create liens, create subsidiaries, amend its formation documents, make investments, enter into transactions with its affiliates, and enter into swap agreements. BPI Energy must maintain (i) a current ratio of at least 1.0 (excluding from the calculation of current liabilities any advances outstanding under the Credit Agreement) and (ii) a loan-to-value ratio greater than 1.0 to 1.0 for the period commencing on September 30, 2008 and ending on March 31, 2010 and 0.7 to 1.0 thereafter.

 

The Credit Agreement contains customary events of default. In addition, GasRock may declare an event of default if, at any time after July 25, 2008, BPI Energy’s most recent reserve report indicates that BPI Energy’s projected net revenue attributable to its proved reserves is insufficient to fully amortize the amounts outstanding under the Credit Agreement within a 48-month period and BPI Energy is unable to demonstrate to GasRock’s reasonable satisfaction that BPI Energy would be able to satisfy such outstanding amounts through a sale of BPI Energy’s assets or equity. Upon the occurrence of an event of default under the Credit Agreement, GasRock may accelerate BPI Energy’s obligations under the Credit Agreement. Upon certain events of bankruptcy, BPI Energy’s obligations under the Credit Agreement would automatically accelerate. In addition, at any time that an event of default exists under the Credit Agreement, BPI Energy will be required to pay interest on all amounts outstanding under the Credit Agreement at a default rate, which is equal to the then-prevailing interest rate under the Credit Agreement plus four percent per annum.

 

Business Strategy

 

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

 

 

 

Competitive Strengths

 

We believe our competitive strengths include the following:

 

 

CBM Acreage Rights

 

As of July 31, 2007, our CBM acreage rights, controlled through lease and farm-out agreements and ownership of a CBM estate, include the following:

 

 

 

 

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

 

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

 

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

 

We have been subject to legal complaints regarding the extent of the surface rights that derive from our CBM rights. On occasion, the owners of properties that are adjacent to our drilling locations have challenged our right to cross their property in accessing our drilling locations and our right to lay gas and water flow lines across their property. The extent of our rights in respect of these issues is uncertain in Illinois. If disputes regarding our surface rights are not resolved in our favor, we may be required to acquire surface rights or access our drilling locations and lay gas and water flow lines in inefficient ways, which would cause us to incur increased operating costs. In addition, we could incur significant costs in legal disputes over our surface rights.

 

Southern Illinois Basin Project

 

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

In addition to the GasRock royalties, we are currently paying royalties of 3.03% on our production at this project. The GasRock royalties will also apply to our acreage rights discussed below at the time we produce and sell CBM from the applicable acreage.

 

We commenced sales of gas from our initial pilot production wells on this project in January 2005. As of July 31, 2007, we have drilled 131 wells at this project. These wells consist of 91 productive wells, six shut-in wells, four divested wells (as a result of the Colt LLC settlement), nine plugged wells, two disposal wells, one pressure observation well, and 18 wells that have been drilled but are not yet in production. Most of the productive wells drilled at this project were initially completed in a limited number of seams, intentionally excluding other seams. Our intention when we drilled these wells was to gather as much geological information as we could about CBM and dewatering characteristics of individual coal seams. During fiscal year 2006, we completed additional seams in most of these wells to begin dewatering and producing CBM from the additional seams penetrated by these wells. During fiscal year 2007, we determined it was beneficial to complete additional seams in the remaining wells, which we plan to begin doing in fiscal year 2008.

 

All of our proved reserves are currently located at the Southern Illinois Basin Project.

 

Northern Illinois Basin Project

 

Our CBM rights in the Northern Illinois Basin Project cover 366,364 acres in Montgomery, Shelby, Christian, Fayette and Macoupin Counties in Illinois, which are located in the north central part of the Illinois Basin. We hold our CBM rights on this acreage pursuant to mineral leases and a farm-out agreement.

 

We have entered into a lease agreement with Montgomery County covering 133,788 acres of CBM rights in Montgomery County, Illinois. The lease agreement extends until November 27, 2010. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. Under the lease agreement, we are required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage.

 

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

 

We have also entered into a lease agreement with IEC (Montgomery), LLC covering 102,000 acres of CBM rights in Christian, Fayette, Montgomery and Shelby Counties in Illinois. The lease agreement extends until April 26, 2026. After the initial term of the agreement, we can continue to hold the lease as to each acreage block where we are producing CBM in commercial quantities. We are required to pay royalties to the lessor on our gross proceeds from the sale of CBM produced from the covered acreage at rates ranging up to 12.5%. We have also entered into a lease agreement with Christian Coal Holdings, LLC covering 12,040 acres of CBM rights in Christian and Montgomery Counties in Illinois. The lease agreement extends until April 26, 2026. After the initial term of the agreement, we can continue to hold the lease as to each acreage block where we are producing CBM in commercial quantities. We are required to pay royalties to the lessor on our gross proceeds from the sale of CBM produced from the covered acreage at a rate of 12.5%. As discussed in Item 3 below, these lease agreements with IEC (Montgomery), LLC and Christian Coal Holdings, LLC are currently subject to litigation.

 

We have also entered into a lease agreement with Christian County to lease 14,033 acres of CBM rights in Christian County, Illinois. The lease agreement extends until January 20, 2012. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. Under the lease agreement, we are required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage.

 

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

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

 

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

 

As of July 31, 2006, we completed drilling a 10-well pilot program at this project that we refer to as the Shelby Pilot. In fiscal year 2007 at the Shelby Pilot, we added one pressure observation well and drilled two additional producers that are not currently completed. Also in fiscal year 2007, we drilled two new test wells in other parts of the Shelby County acreage block. During the fourth quarter of fiscal year 2007, we announced our decision to continue production activities at our Shelby Pilot, while deferring additional development pending further production and pressure information.

 

As of July 31, 2007, we drilled and completed a second 10-well pilot project, the Macoupin Pilot, in the Northern Illinois Basin Project. Those wells have just started the dewatering process. The Macoupin Pilot also includes one pressure observation well and one disposal well.

 

We currently have no proved reserves located at the Northern Illinois Basin Project.

 

Western Illinois Basin Project

 

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

 

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

 

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

 

We have also entered into a lease agreement with Marion County covering 17,882 acres of CBM rights in Marion County, Illinois. The lease agreement extends until June 7, 2012. After the initial term of the agreement, we can continue to hold the lease as long as we are producing CBM from the covered acreage. Under the lease agreement, we will be required to pay royalties to the lessor equal to 12.5% of our gross proceeds from the sale of CBM produced from the covered acreage. If we do not commence exploration of CBM within one year from the commencement of the lease, we will be required to pay advance royalties to the lessor equal to $8,941 for each one-year period that we delay commencing exploration. Any payment of advance royalties can be credited against royalties that may later become payable to the lessor from our production of CBM.

 

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

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

 

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

 

As of July 31, 2007, we have drilled four test wells at the Western Illinois Basin Project from which we are still gathering and evaluating data. We currently have no proved reserves located at the Western Illinois Basin Project.

 

Farm-out Agreement with Addington Exploration, LLC

 

We have entered into a farm-out agreement with Addington Exploration, LLC covering 41,253 acres of CBM rights in Macoupin County, Illinois (part of our Northern Illinois Basin Project) and 22,997 acres of CBM rights in Perry County, Illinois (part of our Western Illinois Basin Project) that Addington controls pursuant to coal seam gas leases. The farm-out agreement provides for an initial 36-month evaluation period, during which we may test and evaluate the covered properties. The evaluation period can be extended by us on unearned acreage through the payment of a fee equal to $0.50 per acre, increasing over five years to $2.50 per acre. For each vertical and horizontal well that we place into production during the term of the agreement, Addington will assign to us its CBM rights covering the surrounding 160 acres penetrated by one of our wells. We plan to extend the 36-month evaluation period on unearned acreage when it expires in November 2007.

 

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

 

As discussed in Item 3 below, our farm-out agreement with Addington is currently subject to litigation.

 

Technical Services Agreement with BHP Billiton

 

Our Technical Services Agreement with BHP Petroleum (Exploration) Inc., a wholly owned subsidiary of BHP Billiton, expired at the end of its term on September 30, 2006, and BHP did not exercise its right to extend the agreement. BHP’s right of first refusal to acquire us lapsed as of the expiration date of the agreement, and the 4 million stock appreciation rights that we granted to BHP, which could be exercised by BHP only in connection with an acquisition of us, expired on March 30, 2007.

 

Status of CBM Operations

 

The following table summarizes the status of wells we have drilled as of July 31, 2007:

 

 

 

 

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

 

 

 

 

As of July 31, 2007, all of the wells that we have drilled are vertical wells. We estimate that a typical vertical well will require about 24 to 48 months to reach peak production. We completed most of our productive wells in a limited number of seams, intentionally excluding other seams. Our intention when we drilled these wells was to gather as much geological information as we could about CBM and dewatering characteristics of individual coal seams. During our 2006 fiscal year, we went back and completed additional seams in most of these wells to begin dewatering and producing CBM from the additional seams penetrated by these wells. During fiscal year 2007, we determined it was beneficial to complete additional seams in the remaining wells, which we will begin doing in fiscal year 2008. We began selling gas from our first productive wells in January 2005. As of July 31, 2007, we believe that most of our productive wells have not yet reached peak production. Although we have drilled wells on only a relatively small part of our acreage, we have not to date determined that any well we have drilled is a dry hole.

 

Production and Sales

 

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

 

 

 

 

Average Sales Prices and Production Costs

 

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

 

 

 

 

Reserves

 

Proved reserves are the estimated quantities that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements (of which none existed as of July 31, 2005, 2006 and 2007, the dates of our estimates of proved reserves prepared by our independent reservoir engineer consultant, Schlumberger Data & Consulting Services), but not on escalations based on future conditions. We did not file any reserve information with any other federal authority or agency during the fiscal year ended July 31, 2007. The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of our royalty obligations. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and undeveloped reserves are defined by SEC Rule 4-10(a)(2) of Regulation S-X.

 

 

Since July 31, 2007 we have completed and tied in 10 wells previously classified as proved undeveloped and representing 1,342 MMcf in Schlumberger’s reserve report. In addition, since July 31, 2007 we have drilled, completed and tied in three wells representing 403 MMcf that are not included as proved reserves in Schlumberger’s reserve report as of July 31, 2007.

 

Discounted Future Cash Flows

 

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

 

 

Sales and Distribution of our Gas

 

Our current and future plans anticipate that we will sell all of our CBM to either (i) pipeline companies or (ii) natural gas marketing companies that secure space on pipelines. There are multiple pipeline and gas marketing

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

 

We currently sell all of our CBM production to one gas marketing company, Atmos Energy Marketing, LLC, pursuant to monthly contracts. Under these monthly contracts, Atmos is required to buy all of our CBM production, up to a maximum of 2,500 MMBtus per day (which equates to approximately three times our current daily production), at the NYMEX (New York Mercantile Exchange) price as of the close of business on the last day of the most recently ended month less 25 cents per MMBtu as a marketing charge. If we are unable to extend our monthly contracts with Atmos, we believe that we will have multiple gas marketing companies available to us for the sale of our CBM production.

 

On July 31, 2007, pursuant to requirements in our Credit Agreement with GasRock, we entered into a 23-month “costless collar” with BP for the notional amount of 20,000 MMBtu per month beginning in September 1, 2007. For a more detailed description of this arrangement, see the discussion under Item 7A of Part II below.

 

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

 

Availability of Drilling Equipment and Personnel

 

We utilize drilling contractors to perform all of the drilling on our projects. We maintain a limited number of supervisory and field personnel to oversee drilling and production operations. Our plans to drill additional wells are determined in large part by the anticipated availability of acceptable drilling equipment and crews. We believe that sufficient drilling equipment and crews will be available to us in the Illinois Basin to achieve our drilling plan for fiscal year 2008. However, we do not currently have any contractual commitments with drilling contractors, and we can provide no assurance that we will have adequate drilling equipment or crews to achieve our drilling plans.

 

Governmental Regulations

 

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

 

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

 

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

 

State Regulations

 

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

 

 

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

 

Environmental Regulations

 

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

 

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

 

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

 

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

 

Competition

 

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

 

 

Many of our competitors have financial, technological and other resources that are greater than ours. These companies may be able to pay more for CBM acreage rights and exploratory prospects and may be able to evaluate and purchase more acreage rights and prospects than our resources permit. To the extent our competitors are able to pay more for properties, technologies, equipment and qualified personnel than we are, we will be at a competitive

disadvantage. In addition, many of our competitors may enjoy technological advantages and may be able to identify, develop or implement new technologies more rapidly than we can. Our ability to acquire additional acreage rights and explore for CBM prospects in the future will depend upon our ability to obtain the necessary equipment, attract and retain and qualified personnel, successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this competitive environment.

 

Employees

 

As of July 31, 2007, we have 21 full-time employees, including our executive officers. We utilize independent consultants and contractors to perform various professional services and for drilling, testing and completion work.

 

Executive Officers and Directors

 

 

James G. Azlein has been President, Chief Executive Officer and a Director since August 23, 2001. From 1979 to 1998, Mr. Azlein held positions including President and Chief Financial Officer and was a principal of Cyrus Eaton Group (“CEG”), a private company that specialized in project development, including securing technologies, management, financing and marketing for a variety of projects, for hotels and resorts, agricultural projects and manufacturing plants. In early 2000, Mr. Azlein formed Methane Management, Inc. to acquire the interest of various partners in a 43,000 acre CBM project in southern Illinois in which we owned a minority interest. In August 2001, we acquired Methane Management, Inc. and Mr. Azlein became our President. He has assembled a new management team and is guiding our transition from a primary focus on property acquisition to one of CBM development in the Illinois Basin.

 

James E. Craddock has been Chief Operating Officer since December 19, 2006 and a Director since January 30, 2007. He previously served as our Senior Vice President of Operations. He oversees all of our operational activities, including engineering, geology and land management activities. In particular, he is integrally involved in planning and managing all aspects of our CBM exploration, drilling and production activities. Mr. Craddock joined us from Houston-based Burlington Resources Inc. (acquired by ConocoPhillips on March 31, 2006), where he served as Chief Engineer. In this, his most recent capacity with Burlington, he was responsible for reserve estimation, corporate operations, recruitment and development of the engineering staff and growth of a technical center. As Director of Strategic Planning at Burlington, Mr. Craddock was involved in Burlington’s $3 billion acquisition of the Louisiana Land & Exploration Company (LL&E). He was also involved in developing Burlington’s Farmington, New Mexico CBM project. As head of Reservoir Engineering, and later as Engineering Manager, he was responsible for leading the technical team that grew the Fruitland CBM Project to over 400 MMcf per day. During the play’s peak level of activity, this required drilling up to 300 new CBM wells per year, conducting up to 100 recompletions per year and participating in 100 non-operated wells each year. He began his career in 1981 with Superior Oil (later Mobil) upon graduating from Texas A&M University with a Bachelor of Science in Mechanical Engineering.

 

Randy L. Elkins assumed the position of Acting Chief Financial Officer in October 2006, and has been Controller since February 2005. He is a Certified Public Accountant with more than 15 years of experience in accounting and auditing. Prior to joining us, Mr. Elkins held a senior finance position with International Steel Group, Inc. (NYSE: ISG). From January 1992 through September 2004, he served in various increasingly responsible positions with Ernst & Young LLP, most recently as a senior manager in its Transaction Support Group. While at E&Y, he focused on audits of SEC public companies, mergers and acquisitions and bankruptcy restructurings. Mr. Elkins earned his Bachelor of Business Administration in Accounting from Cleveland State University. He is a member of the Ohio Society of Certified Accountants.

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

 

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

 

Costa Vrisakis has been a Director since January 2002. Mr. Vrisakis is a financier and entrepreneur based in Sydney, Australia. He has been a founder and director of several Sydney Stock Exchange-listed companies. One of his former ventures includes a printing company, Snap-Apart Pty. Ltd., which Mr. Vrisakis founded along with two employees in 1959. In 1985, Snap-Apart Pty. Ltd. was listed on the Sydney Stock Exchange under the name Computer Resources Ltd. In 1993, Moore Corp. of Toronto, Canada acquired Computer Resources. Since 1985, when Mr. Vrisakis sold his interest in Computer Resources Ltd., he has focused his attention on various real estate projects and stock market investments. Since 2000 through the present time, Mr. Vrisakis has devoted the majority of his time to managing his 50% interest in three hotels in Sydney, Australia.

 

William J. Centa served as a Director from March 2005 until his resignation on September 13, 2007.

 

Significant Employees

 

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

 

Randy Oestreich, 51, has been Vice President of Field Operations since March 2005. Mr. Oestreich owns A-Strike Consulting, a private consulting company formed in April 2003 to provide consulting services to the CBM industry. From 1976 to 2003, Mr. Oestreich worked for Halliburton Energy Services. With Halliburton, Mr. Oestreich worked in conventional oil and gas exploration and development, as well as unconventional gas, including CBM, primarily in the Illinois Basin, but also in Michigan, Ohio, Kentucky, Pennsylvania and West Virginia. In addition, he was a member of Halliburton’s Coalbed Methane Solutions Team. For the past 15 years, his work has focused on CBM, mine methane and New Albany shale exploration and development. Mr. Oestreich has worked on, and is familiar with, the majority of unconventional gas projects that have been initiated in the Illinois Basin and has worked on the Southern Illinois Basin Project since its inception.

 

Dan Anderson, 60, has been Director of Property Acquisitions since January 2002. Mr. Anderson has more than 30 years of oil and gas and real estate experience: from 1976 to 1983 as Land Department Manager with John Carey Oil

Company, Inc.; from 1983 to 1989 as president of his own oil and gas investment consulting company; and as President of a private real estate development company, DAPA Investments, Inc. Prior to joining us, Mr. Anderson worked with DeMier Oil in securing oil, gas and CBM leases in central and southern Illinois, as well as pipeline right-of-way easements. He has extensive experience in the oil, gas and CBM business in the Illinois Basin, including oil and gas and CBM leasing terms and agreements. In addition, he has extensive experience in the workings of land title and registrar procedures on both a local and state level. Mr. Anderson is a member of the Illinois Oil and Gas Association and the American Association of Professional Landmen.

 

Michael Dawson, 57, has been Senior Geological Advisor since August 2006. He was most recently with Burlington Resources Inc. (acquired by ConocoPhillips on March 31, 2006) as a petroleum geologist. During his 26-year tenure with Burlington, he was involved in various exploration and exploitation projects. At Burlington’s Farmington, New Mexico office, he was involved in the Fruitland CBM play. Most recently, Mr. Dawson helped design and implement a comprehensive (San Juan Basin) Pictured Cliffs Sandstone reservoir optimization program. Previously, he worked in Burlington’s Amarillo and Houston offices where his responsibilities included prospect generation, wellsite geology, field development and economic analysis for projects in the Anadarko, Arkoma and other basins. Mr. Dawson began his career in 1978 with Conoco (now ConocoPhillips) upon graduating with a Master of Science in Geology from San Diego State University. He earned his Bachelor of Science in Geology from the University of Michigan.

 

James Erlandson, 32, also formerly of Burlington Resources, has been Senior Staff Reservoir Engineer since August 2006. Previously, he was team leader of the Kaybob Resource Assessment Team working in Calgary, Alberta, with responsibility for analyzing and developing regional unconventional gas plays in British Columbia and Alberta. As Mr. Erlandson progressed through assignments of increasing responsibility with Burlington, he was involved in strategic planning, acquisitions and exploitation of unconventional sand and CBM plays. He was also involved in the addition of proven gas reserves in the Western Canada Sedimentary Basin, infill program analysis and development, and the optimization of Fruitland coal wells in the San Juan Basin. Mr. Erlandson began his career in 1997 as a production engineer with Marathon Oil Company after graduating with honors from Montana Tech, where he earned his Bachelor of Science in Petroleum Engineering.

 

Kelly Sutton, 30, has been Senior Staff Engineer since September 2006. Ms. Sutton was previously with Energen Resources, where she served as a reservoir/acquisitions engineer. While at Energen, she evaluated CBM properties in the Powder River, San Juan and Black Warrior Basins, oil properties in the Permian Basin and tight gas properties in East Texas and Northern Louisiana. Prior to Energen, she served in various reservoir and production engineering positions with Burlington Resources and Phillips Petroleum. Ms. Sutton received her Bachelor of Science in Chemical Engineering from the University of Alabama.

 

Bradford Sutton, 33, has been Senior Staff Engineer since September 2006. Mr. Sutton was previously with Energen Resources, where he focused on CBM and tight gas development in the San Juan Basin. Prior to joining Energen, Mr. Sutton was a production engineer at Burlington Resources. During his career, he has worked on CBM development in the San Juan and Powder River Basins and conventional gas and tertiary oil development in the Permian Basin. He holds a Bachelor of Science in Petroleum Engineering from the University of Alabama.

 

Internet Website

 

We are required to file annual, quarterly and other reports and proxy statements with the SEC. Our SEC filings are available to the public over the internet at the SEC’s website at www.sec.gov or from our website at www.bpi-energy.com. You may also read and copy any documents that we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operations of the public reference room. In addition, we make available free of charge through our internet website our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

 

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

 

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

 

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

 

The wells that we have drilled began producing CBM for sale only in January 2005, and the amount of CBM that we are currently selling is not significant. We are not currently generating net income or positive cash flow from operations. Even if we achieve increased revenues and positive cash flow from operations in the future, we anticipate increased exploration, development and other capital expenditures as we continue to explore and develop our CBM rights. Our Credit Agreement with GasRock provides for an initial commitment of $10.2 million, of which we have drawn $9.1 million. Additional advances beyond the initial $10.2 million commitment are at GasRock’s discretion. Therefore, in order to achieve our long-term plans and maintain a viable business, we will need to raise additional financing, either by convincing GasRock to advance additional funds or obtaining financing from new sources. If we are unable to raise additional financing, we will likely be unable to carry out our long-term plans, which would negatively impact the value of your investment in us.

 

Even if we continue to demonstrate the commercial viability of CBM wells in the Illinois Basin, we may encounter difficulty in raising additional capital on favorable terms. Interest rates and investor expectations and demands are subject to change, and any change in these areas could have a negative effect on the financing terms that we are able to obtain. In addition, the terms of any new financing may adversely affect your investment. If we issue shares of preferred stock or additional common shares, institutional investors may negotiate terms equal to or more favorable than market prices or the terms of our prior offerings, resulting in dilution to existing shareholders. As with our current GasRock financing, debt financing could result in the lenders having a claim to assets prior to the rights of our shareholders, divert cash flow to service the debt, and restrict operations through compliance with lenders’ restrictions. Any such terms could adversely affect the return that you receive on your investment in us.

 

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

 

We have experienced significant operating losses and negative cash flow from operations since our inception, and we currently have an accumulated deficit. During our fiscal year ended July 31, 2006 we incurred a net loss of $8,836,244, and during our fiscal year ended July 31, 2007 we incurred a net loss of $20,640,488. As of July 31, 2007, we have an accumulated deficit of $47,834,016. We anticipate that our operating costs and capital expenditures will continue to grow as we continue to explore and develop our CBM rights. Even if we significantly grow our revenues from the sale of CBM, it is possible that our increased operating costs and capital expenditures will prevent us from generating net income. In addition, in the future we could incur greater than expected drilling or other operating expenses, we could discover that our properties are not commercially viable, or gas prices could decline significantly. Any of these events would have a significantly negative impact on our ability to generate net income. If we are unable to achieve profitability at any time in the near future, the value of your investment in us could be adversely affected.

 

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

 

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

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

 

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

 

 

Wells on some projects could require substantial dewatering ahead of production, which could delay the start of production by months and increase completion costs. Continued high volume water pumping during production would increase operating costs. If we experience significant setbacks in drilling, completing and operating wells, or significantly increased costs due to unexpected conditions, our financial performance will suffer.

 

Any decline in natural gas prices could negatively impact our ability to attain profitable operations.

 

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

 

If we are unable to repay or refinance the amounts advanced to us by GasRock when they become due, GasRock could enforce its security interest in our assets.

 

The obligations under our Credit Agreement with GasRock are due and payable on July 25, 2008, unless GasRock extends this due date. In addition, if we default under the Credit Agreement, such as by breaching a restrictive covenant or one of the other provisions of the agreement, GasRock could accelerate the due date of our obligations. BPI Energy’s obligations under the Credit Agreement are secured by a first priority security interest in substantially all of BPI Energy’s properties and assets, including all of our CBM acreage rights and all of our wells at our Southern Illinois Basin Project. If we are unable to repay or refinance the amounts advanced to us by GasRock when they become due, GasRock could enforce its security interest in our assets. If GasRock took such action, the value of your investment in us would be significantly and adversely affected.

 

The limits imposed on our subsidiary BPI Energy in our Credit Agreement with GasRock could prevent us from acquiring additional acreage or completing joint ventures or cause us to lose access to the facility.

 

Our Credit Agreement with GasRock imposes various restrictive covenants on our subsidiary BPI Energy, including limitations on its ability to effect mergers or acquisitions and make investments. In addition, BPI Energy must maintain (i) a current ratio of at least 1.0 (excluding from the calculation of current liabilities any advances outstanding under the Credit Agreement) and (ii) a loan-to-value ratio greater than 1.0 to 1.0 for the period

commencing on September 30, 2008 and ending on March 31, 2010 and 0.7 to 1.0 thereafter. If BPI Energy fails to maintain these ratios a default under the Credit Agreement could result. Such a default would permit GasRock to accelerate the due date of our obligations and deny us access to further advances. BPI Energy’s compliance with these restrictive covenants and ratios could also prevent us from acquiring additional acreage or entering into joint ventures or other strategic transactions. If BPI Energy’s compliance with these provisions overly restricts our business activities, or its breach of such provisions causes us to lose access to the facility, our business and your investment in us could be adversely affected.

 

Our hedging transactions may limit our potential gains or expose us to losses.

 

Under the terms of our Credit Agreement with GasRock, we are required to hedge at least 75% of projected production from our proved developed producing properties. These transactions could limit our potential gains if natural gas prices were to rise substantially over the prices established by the contracts. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

 

The financial loss resulting from any of these events could be significant in relation to our revenues and cash balances, which could have a significantly negative effect on our business.

 

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

 

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

 

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

 

The primary terms of the lease and farm-out agreements pursuant to which we hold our CBM acreage rights will expire between November 2008 and April 2026, after which we will continue to hold our acreage rights only to the extent that we are producing CBM from the covered acreage. Under some of these agreements we will retain only limited acreage rights for each CBM well that we place into production. For us to maintain all of our CBM acreage rights beyond the initial terms of our lease and farm-out agreements, we will be required to significantly expand our drilling operations or renegotiate the terms of these agreements. If we are unable to retain our CBM acreage rights, our growth potential will be negatively impacted, which could cause the value of your investment in us to decline.

 

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

 

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

Because approximately 75% of our CBM acreage rights are inferior to coal mining rights covering the same properties, our affected operations could be displaced by coal mining operations, which would negatively impact our operations.

 

Under the agreements pursuant to which we hold approximately 75% of our CBM acreage rights, our right to drill for and produce CBM is expressly subject to the mining of coal on the acreage covered by the agreement. We may not interfere with any existing coal mining operations and, under certain circumstances, may be required to cease drilling in locations where coal mining operations will be undertaken. These superior coal rights may restrict the locations where we can drill CBM wells on our projects and may cause some of our CBM operations to be displaced by coal operations. Any such displacement could cover a significant portion of our CBM acreage rights. If we face significant restrictions on where we can drill our CBM wells or a significant number of our CBM wells are displaced by coal mining operations, our operations and financial performance will be negatively impacted.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

 

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

 

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

 

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

 

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

 

In December 2005, we became subject to the reporting requirements of the Securities Exchange Act of 1934. As an SEC registrant, we will incur significant legal, accounting and other expenses that we did not incur as a Canadian public company. We will incur costs associated with complying with the rules and regulations of the SEC, including those adopted under the Sarbanes-Oxley Act of 2002. We currently estimate that these costs will total approximately $1 million on an annual basis. In addition, we continue to be subject to certain securities laws and reporting requirements of the British Columbia Securities Commission and the Alberta Securities Commission. These dual reporting obligations will result in increased compliance costs, which could adversely affect our financial performance.

 

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

 

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

 

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

 

 

None.

 

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

 

 

Drummond Coal Co. Litigation

 

Approximately 115,000 acres of CBM rights of BPI Energy, Inc. (“BPI”) that are located at the Northern Illinois Basin Project are currently subject to litigation. To date, BPI has drilled one well on this acreage, a test well that was drilled in September 2006.

 

In 2004, BPI and affiliates of the Drummond Coal Co. (“Drummond”), including IEC (Montgomery), LLC (“IEC”), entered into a letter of intent to obtain coal and CBM gas rights for one another in the Illinois Basin and to work together in a relationship in which BPI would produce CBM from coal beds prior to the Drummond affiliates’ mining of coal from those beds. Pursuant to and in reliance upon this letter of intent and its relationship with Drummond, BPI arranged for the transfer of 163,109 acres of coal rights to the Drummond affiliates for a total purchase price of $5,845,500, which BPI believes reflects a significant discount to current market prices. In light of its obligations to Drummond, BPI charged no profit on its transfer of the coal rights to the Drummond affiliates. Rather, in consideration for obtaining those coal rights, the Drummond affiliates were to lease approximately 115,000 acres of CBM rights to BPI for a primary lease term of 20 years and with favorable royalty rates. Although the Drummond affiliates entered into two CBM leases with BPI on April 26, 2006, they have since sought in various ways to void or terminate the leases.

 

Drummond affiliates IEC and Christian Coal Holdings, LLC (“Christian”) filed suit against BPI on February 9, 2007 in the United States District Court for the Northern District of Alabama, claiming that BPI has breached the CBM leases in various ways. On May 14, 2007, the Court granted BPI’s motion to dismiss the case in its entirety on the ground of improper venue. IEC and Christian did not appeal that decision.

 

On March 13, 2007, BPI filed suit against IEC, Christian and additional Drummond affiliates Shelby Coal Holdings, LLC, Clinton Coal Holdings, LLC and Marion Coal Holdings, LLC in the United States District Court for the Southern District of Illinois. At the court’s direction, BPI filed an amended complaint, and subsequently filed a second amended complaint that named BPI Energy Holdings, Inc. as an additional plaintiff, named Drummond Company Inc. and Drummond affiliate Vandalia Energy, LLC as additional defendants, and asserted additional claims. In its lawsuit, BPI seeks to rescind its transfers of coal rights to the Drummond affiliates for failure of consideration due to the Drummond affiliates’ efforts to avoid the CBM leases, has asserted claims for money damages for breach of the various agreements between the parties (including the CBM leases), breach of fiduciary duty, unjust enrichment, promissory estoppel, and tortious interference with contracts, and seeks to pierce the corporate veil to recover from Drummond and IEC for the actions of the other Drummond affiliates. The defendants filed a motion to dismiss the second amended complaint, which has been fully briefed and awaits a decision by the Court. We anticipate that if the Court denies all or part of the motion to dismiss, Drummond and its affiliates will file counterclaims against BPI for breach of the CBM leases, citing the same bases set forth in the Alabama lawsuit.

 

We believe that Drummond and its affiliates, after having received favorable coal rights in exchange for favorable CBM rights, now wish to obtain a significant windfall by seeking to renege on the CBM rights that they were obligated to grant to BPI.

 

If the Drummond affiliates reinstitute their claims against BPI, we believe that we will be successful in defending against their claims of breach. However, there can be no assurance that we will be successful in maintaining these acreage rights. The loss of these acreage rights would not have a material impact on our financial position, results of operations or cash flows.

ICG Litigation

 

In November 2004, BPI entered into a farm-out agreement under which it acquired the right to develop certain CBM in Macoupin and Perry Counties in Illinois. The farm-out agreement covers 41,253 acres of CBM rights in Macoupin County and 22,997 acres of CBM rights in Perry County. The farmor was Addington Exploration, LLC, which leased the CBM rights from Meadowlark Farms, Inc. and Ayrshire Land Company. Meadowlark and Ayrshire went into bankruptcy, and ICG Natural Resources, LLC purchased their assets, including the CBM rights underlying the Addington leases. On April 9, 2007, ICG filed suit against BPI in Perry County, Illinois, in an effort to avoid the Addington leases, claiming that there was a lack of consideration at the time they were originally entered into. BPI has filed a motion to dismiss the lawsuit under the doctrine of estoppel by deed, arguing that ICG cannot challenge the leases because it acquired the CBM rights subject to those leases, as set forth in the deed from Addington and Meadowlark to ICG, the purchase agreement between those parties, and numerous bankruptcy court filings and orders associated with the approval of the sale. Addington was subsequently acquired by Nytis Exploration Company, LLC, which has intervened in the action and joined in BPI’s motion. ICG has opposed BPI’s motion, and the Court has held a hearing upon it. BPI has recently learned that, subsequent to filing suit, ICG may have transferred its Perry County coal and CBM rights to Arch Minerals, which is not currently a party to the lawsuit. It is unknown whether Arch will challenge the farm-out agreement. To date, BPI has drilled 10 pilot wells, one pressure observation well, one water disposal well and two test wells on the acreage covered by the farm-out agreement.

 

We believe that we will be successful in either having the case dismissed or in defending against ICG’s claims. However, there can be no assurance that we will be successful in retaining the acreage under this farm-out agreement. The loss of these acreage rights would not have a material impact on our financial position, results of operations or cash flows.

 

 

There were no matters submitted to a shareholder vote during the fourth quarter of fiscal 2007.

 

PART II

 

 

Our common shares are currently traded on the American Stock Exchange under the symbol “BPG.” The following table sets forth the high and low sales prices per share, in U.S. dollars, as reported by the American Stock Exchange during each of our quarterly periods ending in our 2006 and 2007 fiscal years.

 

 

As of October 22, 2007, we have 73,792,493 common shares outstanding, which are held by approximately 379 shareholders of record. The transfer agent and registrar for our common shares is Computershare Investor Services Inc., a Vancouver, British Columbia company. In addition to our outstanding common shares, as of October 22, 2007, we have reserved 1,579,931 common shares for issuance upon the exercise of outstanding stock options and 5,311,600 common shares for issuance upon the exercise of outstanding warrants.

Performance Graph

 

The following graph compares the yearly changes in total shareholder return on our common shares with the total return of the AMEX Composite Index and the S&P Energy Index from July 31, 2002 through July 31, 2007. We assumed an initial investment of $100 on July 31, 2002 and the reinvestment of all dividends. We did not pay any dividends during this five-year period.

 

Performance Graph

 

 

Cumulative Total Return as of July 31, 2007
(assumes a $100 investment at the close of trading on July 31, 2002)

 

 

Issuance of Unregistered Securities

 

In fiscal year 2007, we did not issue any unregistered securities. In fiscal year 2006, we issued the following unregistered securities. Except for the September 26, 2005 issuance, when KeyBanc Capital Markets, a division of McDonald Investments, Inc., and Sanders Morris Harris, Inc. acted as placement agents, we did not use a principal underwriter for any of the issuances listed in the table below. Each such sale was exempt from registration under the Securities Act of 1933, as amended, 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.

 

 

 

Dividend Policy

 

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

 

Equity Compensation Plan Information

 

The following reflects certain information about our common shares authorized for issuance under compensation plans at July 31, 2007.

 

 

 

 

The following sets forth our selected historical financial data as of July 31, 2007, 2006, 2005, 2004 and 2003 and for our five fiscal years then ended, which has been derived from our financial statements for those years. Our financial statements as of July 31, 2007, 2006 and 2005 and for our fiscal years ended July 31, 2007, 2006 and 2005 and related notes thereto have been audited by Meaden & Moore, Ltd., an independent registered public accounting firm. Our financial statements as of July 31, 2004 and 2003 and for our fiscal years ended July 31, 2004 and 2003 and related notes thereto have been audited by De Visser Gray, an independent registered public accounting firm.

 

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

 

 

 

 

 

 

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

 

Overview and Outlook

 

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 covering the southern two-thirds of 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 and Alberta Securities Commissions.

 

As of July 31, 2007, we owned or controlled CBM rights, through mineral leases, a farm-out agreement and ownership of a CBM estate, covering approximately 512,000 total acres in the Basin (approximately 99% of this acreage is undeveloped as of July 31, 2007). Portions of our CBM rights are currently subject to litigation, as described in Item 3 of Part I above. 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 four 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. 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. Net gas sales during the fiscal year ended July 31, 2005 were $117,835 on sales volume of 17,885 Mcf. Net gas sales were $1,126,477 on sales volume of 135,118 Mcf for the fiscal year ended July 31, 2006, an increase of 856% in net gas sales and 655% in sales volume over the prior year. Net gas sales for the fiscal year ended July 31, 2007 were $1,204,252 on sales volume of 185,305 Mcf reflecting an increase of 7% in net gas sales and an increase of 37% in sales volume compared to the fiscal year ended July 31, 2006. As previously disclosed, net gas sales in the second quarter of fiscal year 2007 were adversely affected by a nitrogen-related pipeline curtailment that began in October and necessitated six days of downtime followed by a period of constrained sales volume. A nitrogen-rejection unit was installed and began operating in March 2007.

 

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. In the last quarter of fiscal year 2007 and the first quarter of fiscal year 2008 we have increased our acreage by approximately 12,000 acres, a 2% increase in total acreage. However, we have committed

ourselves to transitioning 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 million. In July 2007, we secured a $75 million advancing term credit facility from GasRock. The initial commitment under this facility was $10.2 million of which we drew $9.1 million at closing.

 

In April 2006, we hired James E. Craddock, our Chief Operating Officer. Prior to joining us, Mr. Craddock was with Burlington Resources for over 20 years, last serving as Chief Engineer. Mr. Craddock has built a strong in-house technical 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. In May 2007, we announced our decision to continue production activities at our Shelby Pilot, while deferring additional development pending further production and pressure information. We use pilot projects to cost-effectively high-grade our extensive acreage position before committing development capital in a particular area. In the case of the Shelby Pilot, the pressure and production results to date do not provide a sufficient likelihood of commercial success to move into development at this early stage. Production history, as well as our ongoing work to reduce development costs and improve well performance, may make development at the Shelby Pilot area viable in the future. The Shelby Pilot represents only 400 acres of our 512,000-acre leasehold position.

 

During fiscal year 2007, we drilled 45 new wells, including 15 productive wells, seven test wells, two pressure observation wells, two water disposal wells and 19 wells drilled but waiting on completion. Two of these wells are in the Western Illinois Basin Project, 23 are in the Southern Illinois Basin Project, and 20 are in the Northern Illinois Basin Project.

 

In April 2007, we initiated our third pilot project in Macoupin County. This 12-well pilot program was completed at the end of the fourth quarter of fiscal year 2007 and consists of 10 pilot wells, one pressure observation well and one water disposal well (part of the 20 Northern Illinois Basin Project wells listed above). All 12 wells were drilled, completed and started pumping by July 2007.

 

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.

 

Management’s focus for fiscal year 2008 will be to:

 

 

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 may 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 technical evaluation of the assets that we control should lead to more cost effective drilling and completion techniques that can be implemented to improve capital efficiency, increase resource recovery and total reserves and improve internal rates of return from development projects.

 

We currently control approximately 512,000 acres of CBM rights and, assuming 80-acre vertical well spacing and the development of all of our acreage, have the possibility of over 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 in 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:

 

 

Critical Accounting Policies

 

Critical Accounting Policies and Estimates

 

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

 

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

 

Accounting for CBM Projects

 

We follow the full cost method of accounting for 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 we have one cost center, the United States). Such costs include lease acquisition costs, geological and geophysical studies, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, and overhead expenses directly related to these activities. Internal costs associated with gas activities that are directly attributable to acquisition, exploration or development activities capitalized to properties and equipment on the balance sheet. During the fiscal year ended July 31, 2007, we capitalized approximately $532,000 of internal labor and benefit costs determined to be directly attributable to acquisition, exploration or development activities.

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. During the fiscal year ended July 31, 2007, we recognized a ceiling write-down of $11,722,153 as a result of the carrying amount of net gas properties exceeding the full cost ceiling limitation, which was based on a year-end gas price of $6.51 per Mcf.

 

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

 

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 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.

 

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

 

 

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

 

Share-Based Payment

 

Prior to December 13, 2005, we had a stock-based compensation plan (the “Incentive Stock Option Plan”) under which stock options were issued to directors, officers, employees and consultants as determined by the Board of Directors and subject to the provisions of the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted options to be issued with exercise prices at a discount to the market price of our common shares on the day prior to the date of grant. However, the majority of all stock options issued under the Incentive Stock Option Plan were issued with exercise prices equal to the quoted market price of the stock on the date of grant. Options granted under the Incentive Stock Option Plan vested immediately and were exercisable over a period not exceeding five years. We had 1,579,931 options outstanding under the Incentive Stock Option Plan at July 31, 2007.

 

On December 18, 2006, our shareholders approved the Amended and Restated 2005 Omnibus Stock Plan (the “Omnibus Stock Plan”), which our shareholders had originally approved on December 13, 2005. The Omnibus Stock Plan replaces the Incentive Stock Option Plan under which stock options were previously granted. The Omnibus Stock Plan is administered by the Compensation Committee of the Board of Directors (the “Committee”) and will remain in effect for five years. All of our employees and directors, and any of our consultants or agents designated by the Committee, are eligible to participate in the Omnibus Stock Plan. The Committee has authority to: grant awards; select the participants who will receive awards; determine the terms, conditions, vesting periods and restrictions applicable to the awards; determine how the exercise price is to be paid; modify or replace

outstanding awards within the limits of the Omnibus Stock Plan; accelerate the date on which awards become exercisable; waive the restrictions and conditions applicable to awards; and establish rules governing the Omnibus Stock Plan. No stock options have been issued under the Omnibus Stock Plan. During the current fiscal year, the Committee granted stock awards under the Omnibus Stock Plan in the form of restricted and unrestricted stock to our employees and directors.

 

In December 2004, the Financial Accounting Standards Board (“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 No. 123, companies had the option of either recording expense based on the fair value of stock options granted or continuing to account for stock-based compensation using the intrinsic value method prescribed by APB Opinion No. 25.

 

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

 

Revenue Recognition

 

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

 

Asset Retirement Obligations

 

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

 

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

 

Deferred Income Taxes

 

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

Impact of Recently Issued Accounting Standards Not Yet Adopted

 

In June 2006, the FASB issued FASB Interpretation Number 48, “Accounting for Uncertainty in Income Taxes — An interpretation of FASB Statement No. 109.” This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This Interpretation is effective for fiscal years beginning after December 15, 2006. Therefore, FASB Interpretation Number 48 will be effective for us beginning in the fiscal year ending July 31, 2008. We are currently assessing the effect of this Interpretation, if any, on our consolidated financial statements.

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” The standard provides guidance for using fair value to measure assets and liabilities. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Therefore, SFAS No. 157 will be effective for us beginning in the fiscal year ending July 31, 2009. We are currently evaluating the statement to determine what impact, if any, it will have on our consolidated financial statements.

 

During February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115.” The standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. An entity may elect the fair value option on an instrument-by-instrument basis, with a few exceptions, as long as it applies the fair value option to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS No. 159 establishes presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. Therefore, we will need to comply with SFAS No. 159 beginning in the fiscal year ending July 31, 2009, unless we adopt it earlier. We are currently evaluating the statement to determine what impact, if any, it will have on our consolidated financial statements.

 

Results of Operations

 

Year Ended July 31, 2007 Compared to Year Ended July 31, 2006

 

The following table presents our financial data for fiscal year 2007 compared to fiscal year 2006:

 

Revenue — Revenue from gas sales increased $77,776 in fiscal year 2007, an increase of 7% over fiscal year 2006. Net sales of gas (net of royalties) were 185,305 Mcf for fiscal year 2007 compared to 135,118 Mcf for fiscal year 2006, an increase of 37%. However, our average realized selling price per Mcf decreased to $6.50 in fiscal year 2007 compared to $8.34 in fiscal year 2006. The increase in net sales volume would have been greater except that it was negatively impacted by a nitrogen-related pipeline curtailment that began in October 2006 and necessitated six days of downtime followed by a period of constrained sales volume during the second quarter and a portion of the third quarter of fiscal year 2007. A nitrogen-rejection unit was constructed and began operating in March 2007 and daily production and sales have since reached new highs.

 

Lease operating expense — Lease operating expense increased $637,122 in fiscal year 2007, an increase of 66% over fiscal year 2006. Lease operating expenses represent production expenses, consisting primarily of repairs and maintenance, fuel and electricity, equipment rental, workovers and labor and other overhead expenses related to producing wells. The increase is primarily due to expenses associated with non-recurring workover projects incurred during the second quarter of fiscal year 2007 at the Southern Illinois Basin Project designed to increase production of existing wells, as well as an increase in the number of producing wells and the related costs incurred due to the increase in gas production at the Southern Illinois Basin Project, new lease operating expenses at our pilot projects in the Northern Illinois Basin and the hiring of additional personnel.

 

General and administrative expense — General and administrative expense consisted of the following for fiscal year 2007 and 2006:

 

 

Salaries and benefits increased $1,390,295 in fiscal year 2007, an increase of 69% over fiscal year 2006. The net increase was primarily the result of increased base salaries associated with hiring additional personnel to support our growth, including our Chief Operating Officer during the fourth quarter of fiscal year 2006 and three engineers and a geologist during the first quarter of fiscal year 2007, and cash signing bonuses totaling $350,000 paid to such personnel. In addition, fiscal year 2007 expense includes $250,000 severance paid to our former Chief Financial Officer and General Counsel, who resigned in the first quarter of fiscal year 2007.

 

Non-cash expense associated with share-based compensation increased $268,550 in fiscal year 2007, a 19% increase over fiscal year 2006. Share-based compensation expense in fiscal year 2007 represents approximately $838,000 of expense recognized on a pro rata basis for the anticipated vesting of restricted shares outstanding, approximately $326,000 of expense related to the grant of 350,000 unrestricted common shares to newly hired members of our technical team and approximately $482,000 of expense related to the grant of 811,161 unrestricted common shares and 50,000 stock options to certain executive officers, employees, non-employee directors and advisory board members primarily in connection with bonuses and directors’ fees. Share-based compensation expense in fiscal year 2006 represented approximately $527,000 of expense related to the grant of 495,000 stock options to employees and directors, approximately $625,000 of expense related to fully vested shares granted to a new officer and a new director and approximately $225,000 of expense recognized on a pro rata basis for the anticipated vesting of restricted shares outstanding. We intend to continue to rely on the granting of equity-based awards, primarily restricted shares, in order to attract and retain qualified individuals and to conserve cash so that it may be utilized in executing our drilling program.

 

Professional and regulatory fees decreased $682,754 in fiscal year 2007, a decrease of 26% over fiscal year 2006. The net decrease is primarily due to decreased legal fees due to the settlement of the Colt LLC litigation during fiscal year 2006 and lower professional and regulatory fees associated with the filing of our initial SEC registration statements and listing on the American Stock Exchange during fiscal year 2006. These decreases were partially offset by increases in insurance costs, investor relations fees and information technology consulting fees.

Other general and administrative expenses increased $685,617 in fiscal year 2007, an increase of 132% over fiscal year 2006. The increase is primarily due to amortization of costs associated with a separation agreement entered into with our former Chief Financial Officer, newly incurred directors’ fees, employee relocation costs related to the hiring of our new technical team and additional rent and office expenses related to the Edwardsville, Illinois office, which opened during the fourth quarter of fiscal year 2006.

 

Depreciation, depletion and amortization expense — Depreciation, depletion and amortization expense (“DD&A”) increased $258,851 in fiscal year 2007, an increase of 45% over fiscal year 2006. We compute DD&A on proved gas properties related to capitalized drilling costs and gas collection equipment using the units-of-production method based on estimates of proved reserves, and on all other property and equipment using the straight-line method based on estimated useful lives ranging from three to 10 years. The increase is primarily due to the increase in development costs we incurred on proved gas properties and an increase in our production over fiscal year 2006.

 

Interest income — Interest income decreased $377,281 in fiscal year 2007, a decrease of 40% over fiscal year 2006 due to lower cash balances during fiscal year 2007. We invest our excess cash in overnight sweep accounts and high-grade commercial paper with maturities of 30 days or less.

 

Ceiling write-down of gas properties — We recognized a ceiling write-down of $11,722,153 during the fiscal year ended July 31, 2007 as a result of the carrying amount of net gas properties exceeding the full cost ceiling limitation, which was based on a year-end gas price of $6.51 per Mcf. No ceiling write-down was required during fiscal year 2006.

 

Other income (expense) — Other income (expense) decreased $2,764,443 from fiscal year 2006 due primarily to the loss that was recognized in fiscal year 2006 related to the Colt LLC settlement.

 

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

 

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

 

 

Revenue — Revenue from gas sales increased $1,008,642 in fiscal year 2006, an increase of 864% over fiscal year 2005. We realized our first revenues from the sale of CBM in January 2005. Net sales of gas (net of royalties) were 135,118 Mcf for fiscal year 2006 compared to 17,885 Mcf for fiscal year 2005. Our average realized selling price per Mcf increased to $8.34 in fiscal year 2006 compared to $6.59 in fiscal year 2005.

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

 

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

 

 

Salaries and benefits increased $1,133,566 in fiscal year 2006, an increase of 127% over fiscal year 2005. The increase was primarily the result of (i) hiring additional personnel to support our growth throughout fiscal years 2005 and 2006, including a Senior Vice President of Operations (April 2006), a Chief Financial Officer (January 2005) and a Controller (February 2005); (ii) executive bonuses paid during fiscal year 2006; and (iii) general salary increases. We had 16 full-time employees at July 31, 2006 compared to 10 full-time employees at July 31, 2005.

 

Share-based compensation expense decreased $1,967,298 in fiscal year 2006, a decrease of 59% from fiscal year 2005. During fiscal year 2006, 495,000 stock options were granted, whereas 4,276,056 stock options were granted to various employees and directors in fiscal year 2005. During fiscal year 2006, we issued stock-based awards to employees and directors as follows: (i) 300,000 unrestricted common shares and 300,000 restricted common shares to our newly hired Senior Vice President of Operations; (ii) 140,000 unrestricted common shares to a newly appointed director; and (iii) 495,000 stock options to various employees and directors. We also replaced 2,025,000 stock options with 2,025,000 restricted common shares for key employees and directors during fiscal year 2006. The expense related to the issuance of unrestricted common shares and stock options was fully recognized in fiscal year 2006. A portion of the expense related to the issuance of restricted common shares, representing the vested portion of such shares, was also recognized in fiscal year 2006.

 

Professional and regulatory fees increased $1,468,982 in fiscal year 2006, an increase of 124% over fiscal year 2005. The increase was primarily the result of increased legal fees incurred in connection with our lawsuit against Colt LLC and higher costs associated with being a public company in the United States. Specifically, the increase resulted from the following:

 

 

Other general and administrative expenses increased $135,760, an increase of 35% over fiscal year 2005, primarily as a result of increased office and travel-related expenses.

 

Depreciation, depletion and amortization expense — DD&A increased $310,162 in fiscal year 2006, an increase of 119% over fiscal year 2005. We compute DD&A on capitalized drilling costs and gas collection

equipment using the units-of-production method based on estimates of proved reserves, and on all other property and equipment using the straight-line method based on estimated useful lives ranging from three to 10 years. The increase is primarily due to the increase in capitalized development costs and an increase in production over fiscal year 2005. Additionally, depreciation expense increased due to additions to other support equipment.

 

Interest income — Interest income increased $818,132, an increase of 664% over fiscal year 2005 due to significantly higher average cash balances during fiscal year 2006. The higher cash balances were the result of the net proceeds of $27,883,954 we received in September 2005 related to the private placement of our common shares. We invest our excess cash in overnight sweep accounts and high-grade commercial paper with maturities of 30 days or less.

 

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

 

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

 

Liquidity and Capital Resources

 

Historically, our primary source of liquidity 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. On July 27, 2007, we closed an Advancing Term Credit Agreement (the “Credit Agreement”) with GasRock Capital LLC (“GasRock”). The Credit Agreement provides for an initial commitment to us of $10.2 million and the possibility of future advances to us of up to an additional $64.8 million. All future advances under the Credit Agreement beyond the initial commitment will be made in GasRock’s discretion. Proceeds are expected to be used for continued development-well drilling at the Southern Illinois Basin Project, drilling of new test wells, pilot projects, lease acquisitions and general and administrative expenses. We may request advances under the Credit Agreement at any time before July 25, 2008, which GasRock may in its discretion extend until July 27, 2010. All amounts then outstanding under the Credit Agreement are due and payable on July 25, 2008, which GasRock may in its discretion extend until July 29, 2011. On July 27, 2007, we received an initial advance of $9,059,566 under the Credit Agreement, which resulted in net proceeds to us of $8,223,912 after the deduction of GasRock’s facility fee, investment banking fees, legal fees and other fees and expenses incurred by us in connection with the transaction totaling $835,654.

 

As of July 31, 2007, we had $9,135,616 in long-term debt and notes payable, of which $9,087,551 is classified as current. Over the past five fiscal years, we raised $43.8 million from the sale of our common shares. Additionally, during that same period, we collected $6.8 million as a result of the exercise of warrants and $2.1 million as a result of the exercise of stock options. Our primary use of these funds has been the acquisition, exploration, testing and development of our CBM properties and rights and payment of lease operating and general and administrative expenses required to support our operations.

 

We did not begin to generate revenues from CBM sales until January 2005. Revenues from CBM sales were $1,204,252, $1,126,477 and $117,835 in fiscal years ended July 31, 2007, 2006 and 2005, respectively. We expect revenue from the sale of our CBM to continue to increase due to (i) increased production from existing wells as they proceed through the initial dewatering phase and (ii) additional production generated as a result of drilling additional wells. However, in view of our limited production history, we can provide no assurance that we will achieve a trend of increased production and CBM revenue in the future.

 

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 about 24 months to reach peak production. The impact on our cash position is that there will be a delay of up to 24 months between the time we

initially invest in drilling and completing a well and the time when a typical well will begin to make a meaningful contribution to our cash from operations.

 

We had a cash balance of $11,291,575 at July 31, 2007, compared to $19,279,015 at July 31, 2006. Our revenues and current cash balance will not be sufficient to fund our capital program for fiscal 2008 or our operations beyond July 31, 2008. Therefore, we will need to obtain additional commitments from GasRock under the Credit Agreement and/or raise additional financing in the near future. We currently do not have any specific plans to raise financing in support of our future operations and forecasted capital expenditures, but we anticipate raising the additional required capital through one or a combination of the following:

 

 

Cash Used in Operating Activities

 

Net cash used in operating activities for fiscal year 2007 was $5,491,048 compared with $6,560,034 and $2,474,443 in fiscal years 2006 and 2005, respectively. Net cash used in operating activities increased significantly in fiscal years 2005 and 2006 over previous fiscal years as we added the resources and expertise necessary to support the growth in the size of our projects in the Basin and substantially increased our exploration, development and operating activities. In addition, in order to provide liquidity to our shareholders, we took the steps necessary in fiscal year 2005 to have our stock listed on the American Stock Exchange, which required us to incur a higher level of general and administrative expenses. In fiscal year 2007, our net cash used in operating activities stabilized, decreasing slightly from the prior year.

 

Net cash used by operating activities is dependent on a number of factors over which we have little or no control. These factors include, but are not limited to:

 

 

Cash Used in Investing Activities

 

Net cash used in investing activities for fiscal year 2007 was $10,443,037 compared with $14,517,293 and $6,338,082 in fiscal years 2006 and 2005, respectively. The increase in net cash used in investing activities during fiscal year 2006 over fiscal year 2005 and the decrease in net cash used in investing activities during fiscal year 2007 over fiscal year 2006 are primarily the result of exploration and development costs at our projects.

 

Cash Provided by Financing Activities

 

Net cash provided by financing activities for fiscal year 2007 was $7,946,646 compared with $33,104,839 and $15,093,233 during fiscal years 2006 and 2005, respectively. The increases in net cash provided by financing activities during fiscal year 2006 is primarily the result of increased proceeds from common shares issued in private placements and from the exercise of stock options and warrants during fiscal year 2006. During fiscal year 2007, our sole proceeds were from the initial advance of $9,059,566 under the Credit Agreement, which resulted in net proceeds to us of $8,223,912 after the deduction of GasRock’s facility fee, investment banking fees, legal fees and other fees and expenses incurred by us in connection with the transaction totaling $835,654. We continue to pay down our long-term notes, making payments of $139,966 in fiscal year 2007, $175,282 in fiscal year 2006 and $41,320 in fiscal year 2005. Our long-term debt and notes payable (including current maturities) increased from $216,015 at July 31, 2006 to $9,135,616 at July 31, 2007. We expect to continue to reduce our long-term notes

payable by making scheduled principal payments of approximately $9,087,551 in fiscal year 2008. There are no principal payments scheduled to be made under the Credit Agreement until July 25, 2008, at which time the entire amount, including capitalized interest, is payable unless extended in GasRock’s discretion.

 

Capital Expenditure Plan

 

We have no contractual commitments for capital expenditures. During the 12-month period ending July 31, 2008, we plan to drill between 30 and 70 new wells. This plan contemplates capital expenditures of approximately $10 million to $23 million. The number of wells that we drill during the 12-month period ending July 31, 2008 will be dependent on (i) data obtained from test wells; (ii) data obtained from our pilot wells; (iii) additional financing we are able to secure, including additional advances we are able to make under the Credit Agreement; and (iv) the risk factors described in this report. In addition to our drilling program, we expect to pursue the acquisition of additional CBM rights during fiscal year 2008. We expect that this capital expenditure program and our other cash requirements will be funded by our cash balance, which as of October 22, 2007 is approximately $5.7 million, and cash raised through additional financing sources that may include additional advances under the Credit Agreement, issuance of new debt and/or equity securities and/or joint ventures. Although we are currently evaluating the best options to raise the necessary funds, we can provide no assurance that we will be able to raise the necessary funds.

 

Contractual Obligations

 

 

 

 

Off-Balance Sheet Arrangements

 

We had no off-balance sheet arrangements as of July 31, 2007.

 

 

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.

 

Under the terms of our Credit Agreement with GasRock, we are required to enter into derivatives contracts covering approximately 75% of the our proved developed producing reserves scheduled to be produced during a two-year period at a guaranteed price of not less than $7.00 per MMBtu. The objective is to reduce our exposure to commodity price risk associated with expected gas production. By achieving this objective, we may protect the

outstanding debt amounts and maximize the funds available under our existing credit agreement, which helps us to support our annual capital budgeting and expenditure plans.

 

Our risk management strategy is to enter into commodity derivatives that set “price floors” and “price ceilings” for our natural gas production. On July 31, 2007, we entered into a “costless collar” contract with BP for the notional amount of 20,000 MMBtu per month beginning September 1, 2007 through July 31, 2009. Under the terms of the contract, BP is required to cover any shortfall below the floor of $7.00 per MMBtu and we must pay to BP any amounts above the ceiling of $11.00 per MMBtu as to the notional amount, with the price being based on the second to last close of the NYMEX forward price for each month. We expect that we will enter into additional hedging arrangements during the next two years to cover the entire 75% of our proved developed producing reserves scheduled to be produced during that period.

 

We have elected not to designate the commodity derivatives to which we are a party as hedges, and accordingly, such contracts are recorded at fair value on our consolidated balance sheets and changes in such fair value are recognized in current earnings as they occur. We do not hold or issue commodity derivatives for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparty to our commodity derivatives. It is anticipated, however, that our counterparty, BP, will be able to fully satisfy its obligations under the commodity derivatives contracts. We do not obtain collateral or other security to support our commodity derivatives contracts subject to credit risk but we do monitor the credit standing of the counterparty.

 

Realized gains or losses from the settlement of gas derivative contracts are reported as natural gas revenue on the consolidated statements of operations. Our first commodity derivatives contract was entered into on July 31, 2007 with the first settlement month designated as September 2007. Thus, no settlements occurred during the fiscal year ended July 31, 2007.

 

Interest Rate Risk

 

Our exposure to changes in interest rates results from the Credit Agreement with GasRock. For the first year of the term of the Credit Agreement, all amounts outstanding under the Credit Agreement will bear interest at a rate equal to the greater of (i) 15% per annum and (ii) the LIBOR rate plus 9% per annum. If GasRock extends the loan termination date of July 25, 2008, amounts outstanding under the Credit Agreement will thereafter bear interest at a rate equal to the greater of (i) 12% per annum and (ii) the LIBOR rate plus 6% per annum. The principal amount due under the credit facility at July 31, 2007 was $9,059,566. A 1% change in interest rates would affect pre-tax net loss by approximately $90,000 per year.

 

Financial Instruments

 

Our financial instruments consist of cash and cash equivalents, accounts receivable and debt 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.

 

 

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

 

 

None.

 

Our management is responsible for establishing and maintaining effective disclosure controls and procedures, as defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. Our management, with participation of our Chief Executive Officer and Acting Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15) as of July 31, 2007. Based on that evaluation, our Chief Executive Officer and Acting Chief Financial Officer concluded that our disclosure controls and procedures were effective as of July 31, 2007 in alerting them on a timely basis to material information relating to us (including our consolidated subsidiaries) required to be included in our periodic filings under the Exchange Act.

 

There were no significant changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended July 31, 2007 that materially affected, or are reasonably likely to affect, our internal control over financial reporting.

 

 

None.

 

PART III

 

 

We incorporate herein by reference the information appearing under the caption “Proposal No. 1 — Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance” and “Committees of the Board of Directors; Attendance” in our definitive proxy statement for our Annual General Meeting of Shareholders, which we will file with the SEC within 120 days after the end of our fiscal year.

 

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

 

 

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

 

 

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

 

See Part II, Item 5 for information regarding our equity compensation plans.

 

 

We incorporate herein by reference the information appearing under the caption “Certain Relationships and Related Transactions” and “Proposal No. 1 — Election of Directors” in our definitive proxy statement.

 

 

We incorporate herein by reference the information appearing under the caption “Proposal No. 2 — Ratification of Appointment of Independent Registered Accounting Firm” in our definitive proxy statement.

PART IV

 

 

(a) The following documents are filed as part of this report:

 

(1) Financial Statements

 

The consolidated financial statements filed as part of this Form 10-K are located as set forth in the index on page F-1 of this report.

 

(2) Financial Statement Schedules

 

Not applicable.

 

(3) Exhibits

 

The list of exhibits included in the attached Exhibit Index is hereby incorporated herein by reference.

Appendix A

 

Glossary of Natural Gas Terms

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

 

Royalty interest.  An interest in a natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.

 

Scf.  Standard cubic feet.

 

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

 

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

 

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

BPI ENERGY HOLDINGS, INC.

 

Index to Consolidated Financial Statements

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Shareholders of

BPI Energy Holdings, Inc.

Solon, Ohio

 

We have audited the accompanying consolidated balance sheets of BPI Energy Holdings, Inc. and its subsidiary as of July 31, 2007 and 2006, and the related statements of operations, shareholders’ equity, and cash flows for the three years ended July 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPI Energy Holdings, Inc. and its subsidiary as of July 31, 2007 and 2006, and the results of its operations and its cash flows for the three years ended July 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

 

Certified Public Accountants

 

October 24, 2007

Cleveland, Ohio

BPI ENERGY HOLDINGS, INC.

 

Consolidated Balance Sheets

 

 

See notes to consolidated financial statements

BPI ENERGY HOLDINGS, INC.

 

Consolidated Statements of Operations

 

 

See notes to consolidated financial statements

BPI ENERGY HOLDINGS, INC.

 

Consolidated Statements of Shareholders’ Equity