BPI Energy Holdings, Inc. 424(b)(3)
Filed Pursuant to Rule 424(b)(3)
Registration No. 333-125483
Registration No. 333-130122
Prospectus Supplement
to Separate Prospectuses dated
May 11, 2006
This prospectus supplement amends and supplements the following prospectuses of BPI Energy
Holdings, Inc. (BPI):
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The prospectus dated May 11, 2006 that is contained in the Post-Effective
Amendment No. 1 to Form S-1 registration statement filed by BPI with the Securities and
Exchange Commission (SEC) on May 11, 2006 and declared effective by the SEC on May
22, 2006 (Registration No. 333-125483), which covers the offer and sale of 16,595,200
shares of common stock of BPI by the selling shareholders named therein (the 125483
Prospectus); |
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The prospectus dated May 11, 2006 that is contained in the Post-Effective Amendment No.
1 to Form S-1 registration statement filed by BPI with the SEC on May 11, 2006 and
declared effective by the SEC on May 22, 2006 (Registration No. 333-130122), which
covers the offer and sale of 18,000,000 shares of common stock of BPI by the selling
shareholders named therein (the 130122 Prospectus); and |
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The prospectus supplements dated November 3, 2006 filed by BPI with the SEC on
November 3, 2006 (Registration Nos. 333-125483 and 333-130122), which contained
information from BPIs Annual Report on Form 10-K filed with the SEC on October 30,
2006 (the 10K Prospectus). |
The 125483 Prospectus, the 10-K Prospectus and this prospectus supplement together constitute
the prospectus required to be delivered by Section 5(b) of the Securities Act of 1933 with respect
to the offering and sale of common stock of BPI covered by the 125483 Prospectus. The 130122
Prospectus, the 10-K Prospectus and this prospectus supplement together constitute the prospectus
required to be delivered by Section 5(b) of the Securities Act of 1933 with respect to the offering
and sale of common stock of BPI covered by the 130122 Prospectus.
You should rely only on the information contained in this prospectus supplement and the
related prospectuses identified above. We have not authorized any other person to provide you with
information that is different from or in addition to that contained in this prospectus supplement
and the related prospectuses. If anyone provides you with different or inconsistent information,
you should not rely on it.
Neither the Securities and Exchange Commission nor any state securities commission has
approved or disapproved of these securities or determined if this prospectus supplement is truthful
or complete. Any representation to the contrary is a criminal offense.
The date of this prospectus supplement is December 19, 2006
Table of Contents
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About this Prospectus Supplement |
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ii |
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Financial Statements for the Quarterly Period Ended October 31, 2006 |
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1 |
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Managements Discussion and Analysis of Financial Condition and Results of Operations |
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14 |
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i
ABOUT THIS PROSPECTUS SUPPLEMENT
Our disclosure consists of three parts. The first part is either the 125483 Prospectus or
the 130122 Prospectus, depending upon which prospectus is required to be delivered to you by the
selling shareholder. The second part is the 10K Prospectus. The third part is this prospectus
supplement. You should review this prospectus supplement and the related prospectuses in their
entirety before making a decision to invest in BPIs common shares. This prospectus supplement sets
forth BPIs financial statements for the quarterly period ended October 31, 2006 and managements
discussion and analysis of financial condition and results of operations. In the event of any
inconsistency between this prospectus supplement and the related prospectuses, you should rely on
the information contained in this prospectus supplement.
ii
FINANCIAL STATEMENTS FOR THE QUARTERLY PERIOD ENDED OCTOBER 31, 2006
BPI Energy Holdings, Inc.
Consolidated Balance Sheets
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October 31, 2006 |
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July 31, 2006 |
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(Unaudited) |
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ASSETS |
Current assets: |
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Cash and cash equivalents |
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$ |
14,697,615 |
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$ |
19,279,015 |
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Accounts receivable |
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53,125 |
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105,711 |
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Other current assets |
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405,168 |
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164,764 |
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Total current assets |
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15,155,908 |
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19,549,490 |
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Property and equipment, at cost: |
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Gas properties, full cost method of accounting: |
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Proved, net of accumulated
depreciation, depletion and
amortization of $434,833 and $331,150 |
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20,683,383 |
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20,766,898 |
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Unproved |
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5,558,243 |
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3,368,231 |
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Net gas properties |
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26,241,626 |
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24,135,129 |
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Other property and equipment, net of
accumulated depreciation and amortization of
$711,330 and $631,015 |
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5,348,946 |
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5,106,236 |
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Net property and equipment |
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31,590,572 |
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29,241,365 |
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Restricted cash |
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100,000 |
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100,000 |
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Other non-current assets |
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418,940 |
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161,125 |
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Total assets |
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$ |
47,265,420 |
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$ |
49,051,980 |
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LIABILITIES AND SHAREHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable |
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$ |
1,125,212 |
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$ |
1,492,239 |
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Current maturity of long-term notes payable |
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77,527 |
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140,866 |
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Accrued liabilities and other |
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1,080,108 |
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649,237 |
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Total current liabilities |
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2,282,847 |
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2,282,342 |
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Long-term notes payable, less current portion |
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68,315 |
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75,149 |
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Asset retirement obligation |
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62,167 |
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70,754 |
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Other non-current liabilities |
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100,000 |
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Total liabilities |
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2,513,329 |
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2,428,245 |
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Shareholders equity: |
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Common shares, no par value, authorized
200,000,000 shares, 72,608,423 and 70,812,540
outstanding |
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67,946,143 |
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67,946,143 |
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Additional paid-in capital |
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6,744,403 |
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5,871,120 |
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Accumulated deficit |
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(29,938,455 |
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(27,193,528 |
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Total shareholders equity |
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44,752,091 |
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46,623,735 |
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Total liabilities and shareholders equity |
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$ |
47,265,420 |
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$ |
49,051,980 |
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See Notes to Unaudited Consolidated Financial Statements.
1
BPI Energy Holdings, Inc.
Consolidated Statements of Operations
(Unaudited)
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Three Months Ended October 31 |
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2006 |
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2005 |
Revenues: |
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Gas sales |
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$ |
294,002 |
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$ |
209,694 |
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Expenses: |
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Lease operating expense |
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335,974 |
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160,804 |
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General and administrative expense |
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2,734,710 |
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1,272,424 |
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Depreciation, depletion and amortization |
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183,998 |
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94,802 |
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3,254,682 |
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1,528,030 |
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Operating loss |
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(2,960,860 |
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(1,318,336 |
) |
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Other income (expense): |
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Interest income |
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218,906 |
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132,619 |
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Interest expense |
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(3,153 |
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(7,544 |
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215,753 |
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125,075 |
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Net loss |
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$ |
(2,744,927 |
) |
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$ |
(1,193,261 |
) |
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Basic and diluted loss per share |
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($0.04 |
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($0.03 |
) |
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Weighted average common shares outstanding |
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68,796,522 |
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45,982,440 |
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See Notes to Unaudited Consolidated Financial Statements.
2
BPI Energy Holdings, Inc.
Consolidated Statements of Shareholders Equity
(Unaudited)
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Common Shares |
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Additional Paid-in |
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Accumulated |
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Total |
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Shares |
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Amounts |
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Capital |
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Deficit |
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Shareholders Equity |
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Balance, July 31, 2006 |
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70,812,540 |
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$ |
67,946,143 |
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$ |
5,871,120 |
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$ |
(27,193,528 |
) |
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$ |
46,623,735 |
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Share-based payments
common shares, including
vesting of restricted
shares |
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979,381 |
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873,283 |
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873,283 |
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Nonvested portion of
restricted shares issued |
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816,502 |
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Net loss |
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(2,744,927 |
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(2,744,927 |
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Balance, October 31, 2006 |
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72,608,423 |
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$ |
67,946,143 |
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$ |
6,744,403 |
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$ |
(29,938,455 |
) |
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$ |
44,752,091 |
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See Notes to Unaudited Consolidated Financial Statements.
3
BPI Energy Holdings, Inc.
Consolidated Statements of Cash Flows
(Unaudited)
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Three Months Ended October 31 |
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2006 |
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2005 |
Operating activities: |
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Net loss |
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$ |
(2,744,927 |
) |
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$ |
(1,193,261 |
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Adjustments to reconcile net loss to net cash used in
operating activities: |
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Depreciation, depletion and amortization |
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183,998 |
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94,802 |
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Share-based payments |
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873,283 |
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397,586 |
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Accretion of asset retirement obligation |
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952 |
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669 |
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Changes in assets and liabilities: |
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Accounts receivable |
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52,586 |
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(87,113 |
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Other current assets |
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(240,404 |
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(10,816 |
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Accounts payable |
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282,802 |
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167,274 |
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Accrued liabilities and other |
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430,871 |
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146,922 |
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Other assets and liabilities |
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(157,815 |
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Net cash used in operating activities |
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(1,318,654 |
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(483,937 |
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Investing activities: |
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Additions to gas properties |
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(2,777,749 |
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(3,878,281 |
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Additions to other property and equipment |
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(414,824 |
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(683,721 |
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Net cash used in investment activities |
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(3,192,573 |
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(4,562,002 |
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Financing activities: |
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Payments on long-term notes payable |
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(70,173 |
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(9,098 |
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Net proceeds from issuance of common shares |
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28,702,478 |
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Net cash (used in) provided by financing activities |
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(70,173 |
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28,693,380 |
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Net (decrease) increase in cash and cash equivalents |
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(4,581,400 |
) |
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23,647,441 |
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Cash and cash equivalents at the beginning of the period |
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19,279,015 |
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7,251,503 |
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Cash and cash equivalents at the end of the period |
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$ |
14,697,615 |
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$ |
30,898,944 |
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Supplementary disclosure of cash flow information: |
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Cash payments: |
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Interest paid |
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$ |
3,153 |
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$ |
3,646 |
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See Notes to Unaudited Consolidated Financial Statements.
4
BPI Energy Holdings, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
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1. |
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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Basis of Presentation
These unaudited consolidated interim financial statements include the accounts of BPI Energy
Holdings, Inc. and its wholly owned U.S. subsidiary, BPI Energy, Inc.
(collectively, the Company). All inter-company transactions and balances have been eliminated upon consolidation.
BPI Energy Holdings, Inc. is incorporated in British Columbia, Canada and, through its wholly
owned U.S. subsidiary, BPI Energy, Inc., is involved in the exploration, production and commercial
sale of coalbed methane in the Illinois Basin. The Company conducts its operations in one
reportable segment, which is gas exploration and production. The Companys common shares
trade on the American Stock Exchange under the symbol BPG. Amounts shown are in U.S. Dollars
unless otherwise indicated.
The accompanying unaudited consolidated financial statements have been prepared in accordance
with generally accepted accounting principles for interim financial information and with the
instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of
the information and footnotes required by generally accepted accounting principles for complete
financial statements. In the opinion of management, all adjustments (consisting of normal recurring
accruals) considered necessary for a fair presentation have been included. Operating results for
the quarter ended October 31, 2006 are not necessarily indicative of the results that may be
expected for the full fiscal year. For further information, refer to the consolidated financial
statements and notes thereto included in the Companys Annual Report on Form 10-K for the fiscal
year ended July 31, 2006. Certain prior period amounts have been reclassified to conform to current
period presentation.
The Company has financed its activities primarily from the proceeds of various share
issuances. As a result of the Company being in the early stages of operations, the recoverability
of assets on the balance sheet will be dependent on the Companys ability to obtain additional
financing and to attain a level of profitable operations.
Use of Estimates
The preparation of these unaudited consolidated financial statements requires the use of
certain estimates by management in determining the Companys assets, liabilities, revenues and
expenses. Actual results could differ from such estimates. Depreciation, depletion and amortization
of gas properties and the impairment of gas properties are determined using estimates of gas
reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting
the future rates of production and timing of development expenditures, including the timing and
costs associated with asset retirement obligations. Gas reserve engineering must be recognized
as a subjective process of estimating underground accumulations of gas that cannot be measured in
an exact way. Proved reserves of natural gas are estimated quantities that geological and
engineering data demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing conditions.
5
Gas Properties
The Company follows the full cost method of accounting for gas properties. Under this method,
all costs associated with the acquisition of, exploration for and development of gas reserves are
capitalized in cost centers on a country-by-country basis (currently the Company has one cost
center, the United States). Such costs include lease acquisition costs, geological and geophysical
studies, carrying charges on non-producing properties, costs of drilling both productive and
non-productive wells, and overhead expenses directly related to these activities. Internal costs
associated with gas activities that are not directly attributable to acquisition, exploration or
development activities are expensed as incurred.
Unproved gas properties and major development projects are excluded from amortization until a
determination of whether proved reserves can be assigned to the properties or impairment occurs.
Unproved properties are assessed at least annually to ascertain whether impairment has occurred.
Sales or dispositions of properties are credited to their respective cost centers and a gain or
loss is recognized when all the properties in a cost center have been disposed of, unless such sale
or disposition significantly alters the relationship between capitalized costs and proved reserves
attributable to the cost center.
Capitalized costs of proved gas properties, including estimated future costs to develop the
reserves and estimated abandonment cost, net of salvage, are amortized on the units-of-production
method using estimates of proved reserves.
A ceiling test is applied to each cost center by comparing the net capitalized costs, less
related deferred income taxes, to the estimated future net revenues from production of proved
reserves, discounted at 10%, plus the costs of unproved properties net of impairment. Any excess
capitalized costs are written-off in the current year. The calculation of future net revenues is
based upon prices, costs and regulations in effect at each year end.
In general, the Company determines if an unproved property is impaired if one or more of the
following conditions exist:
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there are no firm plans for further drilling on the unproved property; |
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ii) |
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negative results were obtained from studies of the unproved property; |
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iii) |
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negative results were obtained from studies conducted in the vicinity of the
unproved property; or |
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iv) |
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the remaining term of the unproved property does not allow sufficient time
for further studies or drilling. |
No impairment existed as of October 31, 2006 or July 31, 2006.
6
Other Property and Equipment
Other property and equipment are stated at cost. Gas collection equipment is depreciated on
the units-of-production method using estimates of proved reserves. Support equipment and other
property and equipment are depreciated using the straight-line method over the estimated useful
lives of the assets, ranging from three to 10 years. Major classes of other property and equipment
consisted of the following at October 31, 2006 and July 31, 2006, respectively:
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October 31, |
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July 31, |
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2006 |
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2006 |
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Other property and equipment: |
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Gas collection equipment |
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$ |
4,342,400 |
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$ |
4,342,400 |
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Support equipment |
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1,245,188 |
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1,046,989 |
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Other |
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472,688 |
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|
347,862 |
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Less: Accumulated depreciation and
amortization |
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(711,330 |
) |
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(631,015 |
) |
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$ |
5,348,946 |
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$ |
5,106,236 |
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Loss Per Share
Basic loss per share is calculated using the weighted average number of common shares
outstanding during the year. Diluted loss per share reflects the potential dilution that could
occur if securities or other contracts to issue common shares were exercised or converted into
common shares. Restricted common shares granted are included in the computation only after the
shares become fully vested. Diluted loss per share is not disclosed as it is anti-dilutive. The
following items were excluded from the computation of diluted loss per share at October 31, 2006
and 2005, respectively, as the effect of their assumed exercise would be anti-dilutive:
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October 31, |
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October 31, |
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2006 |
|
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2005 |
|
Outstanding warrants |
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|
5,311,600 |
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|
10,763,603 |
|
Outstanding stock options |
|
|
1,823,265 |
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|
4,080,612 |
|
Nonvested portion of restricted shares issued |
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|
3,057,338 |
|
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|
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|
|
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|
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|
10,192,203 |
|
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|
14,844,215 |
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2. |
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STOCK-BASED COMPENSATION |
SFAS No. 123 (R)
In
December 2004, the FASB issued Statement of Financial Accounting
Standards (SFAS) No. 123(R), Share-Based Payment. This Statement
revises SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees. SFAS No. 123(R) focuses primarily on the accounting for
transactions in which an entity obtains employee services in share-based payment transactions. The
key provision of SFAS No. 123(R) requires companies to record share-based payment transactions as
compensation expense at fair market value based on the grant-date fair value of those awards.
Previously under SFAS 123, companies had the option of either recording expense based on the fair
value of stock options granted or continuing to account for stock-based compensation using the
intrinsic value method prescribed by APB No. 25.
The Company adopted SFAS No. 123(R), using the modified-prospective method, effective August
1, 2005. Since August 1, 2001, the Company followed the fair value provisions of SFAS 123 and
recorded all share-based payment transactions as compensation expense at fair market value based on
the grant-date fair value of those awards. In addition, all stock options previously granted by
the Company nonvested immediately on the date of grant and, thus,
there was no nonvested portion of previous
7
stock option grants that vested during the fiscal year ended July 31, 2006. Therefore, SFAS
123(R) had no impact on the Companys consolidated financial position or results of operations for
the fiscal year ended July 31, 2006. The Company uses the Black-Scholes valuation model to
estimate the fair value of stock options granted.
Incentive Stock Option Plan
Prior to December 13, 2005, the Company administered a stock-based compensation plan (the
Incentive Stock Option Plan) under which stock options were issued to directors, officers,
employees and consultants as determined by the Board of Directors and subject to the provisions of
the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted options to be issued
with exercise prices at a discount to the market price of the Companys common shares on the day
prior to the date of grant. However, the majority of all stock options issued under the Incentive
Stock Option Plan were issued with exercise prices equal to the quoted market price of the shares
on the date of grant. Options granted under the Incentive Stock Option Plan vested immediately and
were exercisable over a period not exceeding five years. The following table summarizes
information about options outstanding under the Incentive Stock Option Plan at October 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise |
|
|
Number |
|
|
Remaining |
|
|
|
|
Price CAD$ |
|
|
Outstanding |
|
|
Life (Years) |
|
|
Expiry Date |
|
$ |
0.65 |
|
|
|
345,000 |
|
|
|
2.0 |
|
|
November 3, 2008 |
|
0.90 |
|
|
|
243,334 |
|
|
|
0.2 |
|
|
January 10, 2007 |
|
0.90 |
|
|
|
10,000 |
|
|
|
2.9 |
|
|
September 22, 2009 |
|
1.20 |
|
|
|
50,000 |
|
|
|
0.2 |
|
|
January 10, 2007 |
|
1.49 |
|
|
|
695,666 |
|
|
|
3.1 |
|
|
November 29, 2009 |
|
2.05 |
|
|
|
10,000 |
|
|
|
3.9 |
|
|
September 22, 2010 |
|
2.19 |
|
|
|
136,000 |
|
|
|
3.4 |
|
|
March 27, 2010 |
|
2.40 |
|
|
|
333,265 |
|
|
|
3.2 |
|
|
January 20, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1.46 |
|
|
|
1,823,265 |
|
|
|
2.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Omnibus Stock Plan
On December 13, 2005, the shareholders of the Company approved the Companys 2005 Omnibus
Stock Plan (the Omnibus Stock Plan) and it became effective on that date. The Omnibus Stock Plan
replaces the Incentive Stock Option Plan under which stock options were previously granted. The
Omnibus Stock Plan is administered by the Compensation Committee of the Board of Directors (the
Committee) and will remain in effect until December 13, 2010. All employees and Directors of the
Company and its subsidiaries, and all consultants or agents of the Company designated by the
Committee, are eligible to participate in the Omnibus Stock Plan. The Committee has authority to:
grant awards; select the participants who will receive awards; determine the terms, conditions,
vesting periods and restrictions applicable to the awards; determine how the exercise price is to
be paid; modify or replace outstanding awards within the limits of the Omnibus Stock Plan;
accelerate the date on which awards become exercisable; waive the restrictions and conditions
applicable to awards; and establish rules governing the Omnibus Stock Plan.
The Omnibus Stock Plan provides that in any fiscal year of the plan the Company may grant up
to 5% of the number of common shares outstanding as of the first day of that fiscal year plus the
number of common shares that were available for the grant of awards, but not granted, in prior
years under the plan. In no event, however, may the number of common shares available for the grant
of awards in any fiscal year exceed 6% of the common shares outstanding as of the first day of that
fiscal year.
8
In the proxy statement for the Companys 2005 Annual Meeting of Shareholders, the Company
committed to limit the number of common shares that could be issued under the Plan to an aggregate
cap of 5,000,000. In the proxy statement for the Companys 2006 Annual Meeting of Shareholders,
the Company is proposing to increase the cap on the aggregate number of common shares that can be
issued under the Plan from 5,000,000 to 7,000,000. As of October 31, 2006, the Company has issued
2,911,000 common shares (but no options) under the Omnibus Stock Plan and has 2,089,000 common
shares available for future issuance. If the Companys shareholders approve the increased cap at
the 2006 Annual Meeting of Shareholders, the Company will be permitted to issue an aggregate of up
to at least 4,089,000 common shares under the Omnibus Stock Plan.
Share-Based Transactions
The following share-based transactions occurred during the current quarter:
|
|
|
Granted 248,661 fully vested common shares and 507,338 restricted shares under the
Omnibus Stock Plan, all at a market price of $0.58 per share, to certain executive
officers, employees and non-employee directors of the Company. The restricted shares
vest one-half on November 6, 2007 and one-half on November 6, 2008. |
|
|
|
|
Granted 350,000 fully vested common shares at a weighted average market price of
$0.93 per share and 700,000 restricted shares at a weighted average market price of
$0.93 per share in connection with the hiring of a geologist and three engineers.
These grants were made outside of the Omnibus Stock Plan pursuant to American Stock
Exchange rules that allow the Company to make equity grants to newly hired employees
outside of a shareholder-approved plan. These restricted shares vest
on various dates over a weighted average period of 1.4 years. |
|
|
|
|
Accelerated vesting of 475,000 restricted shares held by a former officer and
director of the Company in connection with a separation agreement entered into with
the former officer and director. See note 10 for further explanation of the
separation agreement. |
The
following table summarizes the Companys restricted share activity during the current
quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Avg. |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Nonvested at July 31, 2006 |
|
|
2,325,000 |
|
|
$ |
0.61 |
|
Granted |
|
|
1,207,338 |
|
|
|
0.78 |
|
Vested |
|
|
(475,000 |
) |
|
|
0.49 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at October 31, 2006 |
|
|
3,057,338 |
|
|
|
0.70 |
|
|
|
|
|
|
|
|
All restricted share awards are subject to continuous employment. However, in the event
employment is terminated before the restrictions lapse by reason of death, total disability or
retirement, the restrictions will lapse on the date of termination as to a pro-rata portion of the
number of restricted shares scheduled to lapse on the next lapse date, based on the number of days
continuously employed during the applicable vesting period. The Company includes all restricted
shares in common shares outstanding when issued, but only includes the vested portion of such
shares in the computation of basic earnings per share.
9
The Companys policy is to issue new shares to satisfy stock option exercises and
restricted share grants upon receiving approval from the American
Stock Exchange, when required, for the issuance
of such shares.
As of October 31, 2006, there was $1,793,835 of unrecognized compensation cost related to
restricted shares. The cost is expected to be amortized over a
weighted average period of 1.3 years.
The amount charged to expense related to restricted shares was $274,227 and $0 in the three months
ended October 31, 2006 and 2005, respectively.
Other Current Assets
Other
current assets consisted of amounts capitalized related to the following at October 31, 2006 and July 31, 2006,
respectively:
|
|
|
|
|
|
|
|
|
|
|
October 31, |
|
|
July 31, |
|
|
|
2006 |
|
|
2006 |
|
Separation agreement |
|
$ |
357,309 |
|
|
$ |
|
|
Prepaid expenses and other |
|
|
47,859 |
|
|
|
164,764 |
|
|
|
|
|
|
|
|
|
|
$ |
405,168 |
|
|
$ |
164,764 |
|
|
|
|
|
|
|
|
Other Non-current Assets
Other non-current assets consisted of amounts capitalized related to the following at October 31, 2006 and July 31, 2006,
respectively:
|
|
|
|
|
|
|
|
|
|
|
October 31, |
|
|
July 31, |
|
|
|
2006 |
|
|
2006 |
|
Separation agreement |
|
$ |
257,815 |
|
|
$ |
|
|
Advance royalties |
|
|
161,125 |
|
|
|
161,125 |
|
|
|
|
|
|
|
|
|
|
$ |
418,940 |
|
|
$ |
161,125 |
|
|
|
|
|
|
|
|
The separation agreement represents amounts capitalized related to
non-compete/non-solicitation and continuing services clauses contained in a separation agreement
entered into with a former officer of the Company on October 12, 2006. See note 10 for further
explanation of this agreement.
|
|
|
4. |
|
ACCRUED LIABILITIES AND OTHER |
Accrued
liabilities and other consisted of amounts due for the following at October 31, 2006 and July 31,
2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
October 31, |
|
|
July 31, |
|
|
|
2006 |
|
|
2006 |
|
Employee compensation |
|
$ |
595,000 |
|
|
$ |
467,869 |
|
Separation agreement |
|
|
200,000 |
|
|
|
|
|
Professional and regulatory |
|
|
180,000 |
|
|
|
111,805 |
|
Directors fees |
|
|
100,000 |
|
|
|
31,000 |
|
Other |
|
|
5,108 |
|
|
|
38,563 |
|
|
|
|
|
|
|
|
|
|
$ |
1,080,108 |
|
|
$ |
649,237 |
|
|
|
|
|
|
|
|
10
The separation agreement represents amounts due related to a non-compete/non-solicitation
clause contained in a separation agreement entered into with a former officer of the Company on
October 12, 2006. See note 10 for further explanation of this agreement.
|
|
|
5. |
|
LONG-TERM NOTES PAYABLE |
Long-term notes payable consisted of the following at October 31, 2006 and July 31, 2006,
respectively:
|
|
|
|
|
|
|
|
|
|
|
October 31, |
|
|
July 31, |
|
|
|
2006 |
|
|
2006 |
|
Case Credit term note due in fiscal year 2006, 6.50% |
|
$ |
10,874 |
|
|
$ |
15,410 |
|
GMAC term note due in fiscal year 2009, 6.50% |
|
|
19,039 |
|
|
|
20,608 |
|
GMAC term notes due in fiscal year 2010, 6.1% to 6.50% |
|
|
75,992 |
|
|
|
80,849 |
|
Caterpillar Financial Services term note due in
fiscal year 2007, 7.0% |
|
|
39,937 |
|
|
|
99,148 |
|
|
|
|
|
|
|
|
|
|
|
145,842 |
|
|
|
216,015 |
|
Less current maturities |
|
|
(77,527 |
) |
|
|
(140,866 |
) |
|
|
|
|
|
|
|
Long-term notes payable |
|
$ |
68,315 |
|
|
$ |
75,149 |
|
|
|
|
|
|
|
|
The notes are collateralized by the related vehicles and equipment.
|
|
|
6. |
|
ASSET RETIREMENT OBLIGATIONS |
The Company follows SFAS No. 143, Accounting
for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value of
an asset retirement obligation as a liability in the period in which it is incurred, if a
reasonable estimate of fair value can be made. The present value of the estimated asset retirement
costs is capitalized as part of the carrying amount of the associated long-lived asset.
Amortization of the capitalized asset retirement cost is computed on a units-of-production method.
Accretion of the asset retirement obligation is recognized over time until the obligation is
settled. The Companys asset retirement obligations relate to the plugging of wells upon
exhaustion of gas reserves.
The following table summarizes the activity for the Companys asset retirement obligation for
the three months ended October 31, 2006 and 2005, respectively:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
October 31, |
|
|
2006 |
|
2005 |
Beginning asset retirement obligation |
|
$ |
70,754 |
|
|
$ |
13,531 |
|
Additional liability incurred |
|
|
3,261 |
|
|
|
19,800 |
|
Accretion expense |
|
|
952 |
|
|
|
669 |
|
Asset retirement costs incurred |
|
|
(26,681 |
) |
|
|
|
|
Loss on settlement of liability |
|
|
13,881 |
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
62,167 |
|
|
$ |
34,000 |
|
|
|
|
Financial instruments that potentially subject the Company to concentrations of credit risk
consist of cash and cash equivalents, which are held at one large high quality financial
institution. The
11
Company periodically evaluates the credit worthiness of the financial institution. The
Company has not incurred any credit risk losses related to its cash and cash equivalents.
The Company utilizes a limited number of drilling contractors to perform all of the drilling
on its projects. The Company maintains a limited number of supervisory and field personnel to
oversee drilling and production operations. The Companys plans to drill additional wells are
determined in large part by the anticipated availability of acceptable drilling equipment and
crews. The Company does not currently have any contractual commitments that ensure it will have
adequate drilling equipment or crews to achieve its drilling plans. The Company believes that it
can secure the necessary commitments from drilling companies as required. However, it can provide
no assurance that its expectations regarding the availability of drilling equipment and crews from
these companies will be met. A significant delay in securing the necessary drilling equipment and
crews could cause a delay in production and sales, which would affect operating results adversely.
The Company operates in two tax jurisdictions, the United States and Canada. Primarily as
a result of the net operating losses that the Company has generated (NOL Carryforwards) in both
Canada and the United States, the Company has generated deferred tax benefits available for tax purposes to
offset net income in future periods. SFAS No. 109, Accounting for Income Taxes, requires that
the Company record a valuation allowance when it is more likely than not that some portion or all
of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets
is dependent upon the generation of sufficient future taxable income before the expiration of the
NOL Carryforwards. Because of the Companys limited operating history, limited financial
performance and cumulative tax loss from inception, it is managements judgment that SFAS No. 109
requires the recording of a full valuation allowance for net deferred tax assets in both Canada and
the United States as of October 31, 2006.
Common
shares The Company has authorized 200,000,000 common
shares, without par value, of which
72,608,423 and 70,812,540 were issued and outstanding as of October 31, 2006 and July 31, 2006,
respectively. Common shares issued and outstanding at
October 31, 2006 include 3,057,338 restricted
shares expected to vest in future periods.
Additional paid-in capital Amounts recorded of $6,744,403 and $5,871,120 at October 31,
2006 and July 31, 2006, respectively, represent the cumulative
amounts incurred for share-based payments as of each date.
Share purchase warrants outstanding at October 31, 2006 are as follows:
|
|
|
|
|
|
|
|
|
Number |
|
Exercise |
|
|
Outstanding |
|
Price |
|
Expiry Date |
|
4,274,400 |
|
|
$ |
1.50 |
|
|
December 13, 2007 |
|
643,200 |
|
|
$ |
1.25 |
|
|
December 31, 2009 |
|
394,000 |
|
|
$ |
1.25 |
|
|
January 12, 2010 |
|
|
|
|
|
|
|
|
|
|
5,311,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On
October 12, 2006, the Company entered into a Separation Agreement and Waiver and Release
(Separation Agreement) with George J. Zilich, the Companys former Chief Financial
12
Officer and General Counsel. Under the terms of the Separation Agreement, Mr. Zilich resigned
as an employee, officer and director of the Company effective immediately and the Company agreed to
provide consideration to Mr. Zilich for entering into the Separation Agreement as follows:
|
|
|
In connection with Mr. Zilichs existing employment agreement, the Company agreed
to make a cash payment to Mr. Zilich in the amount of $250,000 and provide medical
and dental insurance coverage for two years. Such amounts were paid and recorded as
expense during the current quarter. |
|
|
|
|
In connection with a continuing services clause of the
Separation Agreement, the Company agreed to issue
40,000 unrestricted common shares to Mr. Zilich and make cash payments totaling $50,000 to
be paid in semi-monthly equal installments from October 15, 2006 through December 31,
2006. In return, Mr. Zilich agreed to provide the Company with consulting services as may
be reasonably requested by the Company from time to time through January 2, 2008.
The Company is amortizing the expense associated with Mr. Zilichs continuing
services ratably through January 2, 2008. In connection with these continuing
services, the Company expensed $3,247 during the current quarter and recorded other
assets for prepaid amounts of $39,819 at October 31, 2006. |
|
|
|
|
In connection with a non-compete and non-solicitation clause of the Separation
Agreement, the Company agreed to make cash payments of $100,000 on each of three
dates from January 2, 2007 through January 2, 2008 and provide immediate vesting of
475,000 restricted shares held by Mr. Zilich. In return, Mr. Zilich agreed
not to compete with the Company or solicit any of its employees for a period of two
years. The Company capitalized the value of the non-compete and non-solicitation
clause and is amortizing the related expense ratably through
October 12, 2008. The amount capitalized includes $228,432 of
share-based payments representing the remaining unrecognized portion
of expense related to the vesting of the 475,000 restricted shares. In
connection with this clause, the Company expensed $15,352 during the current quarter
and recorded other assets of $575,305 and other liabilities of $300,000 at October
31, 2006. |
|
|
|
11. |
|
RELATED PARTY TRANSACTIONS |
The Company enters into various transactions with related parties in the normal course of
business operations.
Randy Oestreich, the Companys Vice President of Field Operations, owns and operates A-Strike
Consulting, a consulting company that provides, among other things, laboratory testing related to
coalbed methane. Beginning in fiscal year ended July 31, 2005, the Company owns and maintains a
lab testing facility and allows A-Strike Consulting to operate the facility. The Company pays all
expenses related to the facility and, in return, receives 80% of the revenue generated from the
operations of the facility as reimbursement of the Companys expenses. The Company received $0 and $12,352 in expense reimbursement related to this arrangement during the three
months ended October 31, 2006 and 2005, respectively. Mr. Oestreichs brother owns Dependable
Service Company, a company that previously provided general labor services to the Company. The
Company paid Dependable Services Company $0 and $79,419 during the three months ended
October 31, 2006 and 2005, respectively.
David Preng, a director of the Company, owns Preng & Associates, an executive search firm
specializing in the energy and natural resources industries. The Company paid Preng & Associates $9,621 and $0 for executive placement services during the three months ended October
31, 2006 and 2005, respectively.
13
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The discussion and analysis that follows should be read together with the accompanying
unaudited consolidated financial statements and notes related thereto
that are included in this prospectus supplement.
Overview and Outlook
We are an independent energy company incorporated under the laws of British Columbia, Canada
and primarily engaged, through our wholly owned U.S. subsidiary, BPI Energy, Inc., in the
exploration, production and commercial sale of coalbed methane (CBM). Our exploration and
production efforts are concentrated in the Illinois Basin (the Basin), which encompasses a total
area of approximately 60,000 square miles in southern Illinois, southwestern Indiana and
northwestern Kentucky. Our Canadian activities are limited to administrative reporting obligations
to the province of British Columbia and regulatory reporting to the British Columbia Securities
Commission.
As of October 31, 2006, we owned or controlled CBM rights, through mineral leases, options to
acquire mineral leases, a farm-out agreement and ownership of a CBM estate, covering approximately
500,000 total acres in the Basin (98% of this acreage is undeveloped as of October 31, 2006). We
are focused on 12 Pennsylvanian coal seams that we regard as having commercial CBM potential. The
seams in the acreage covered by our CBM rights have an aggregate thickness of 11-27 feet with a
19-foot median. We plan to complete several individual seams per well that range from two to nine
feet thick each. Gas desorption tests of these coals have yielded 13-113 scf/ton with a 63 scf/ton
median. Extensive permeability testing of individual seams (before stimulation) indicates a range
of 0.2-75 millidarcies and median of 4 millidarcies.
The state of Illinois (which includes most of the Basin) is estimated to be the number two
state in the United States in terms of coal reserves; however, coal in the Basin is high in sulfur,
discouraging coal mining operations. Recent advances in technology that can utilize higher sulfur
coal and higher coal prices are combining to make coals in the Basin potentially attractive to
mining operations. Although coal mining activities take priority over CBM operations in most of our
acreage, we attempt to coordinate and plan our drilling and production activities in conjunction
with the owners of the coal in order to minimize any potential disruptions. In addition, because of
the long lead times involved in coal mining projects, our substantial acreage position and our
ability to be flexible with the timing and siting of our wells, we believe we can plan our work
around coal mining operations in the vicinity of our projects.
We have been involved in the first two projects in the Basin that have commercially produced
and sold CBM. We are the only company currently commercially producing and selling CBM in the state
of Illinois and one of only two companies currently commercially producing and selling CBM in the Basin. We believe our position as a first mover has enabled us to secure a substantial and
favorable acreage position at costs that we believe compare very favorably to other CBM basins that
are more mature in terms of production history.
We are an early stage CBM exploration and production company. We commenced CBM sales from our
first producing wells in January 2005. Gas sales during the fiscal year ended July 31, 2005 were
$117,835. Gas sales were $1,126,477 for the fiscal year ended July 31, 2006, an increase of 856%.
Gas sales for the quarter ending October 31, 2006 were $294,002, representing an increase of 40%
over the same quarter from the previous year. However, sales for the period ending October 31,
2006 were 9.8% lower than the previous quarter due to lower commodity prices and a pipeline
curtailment occurring at the end of October for approximately six days. The curtailment was caused
by an increase in the nitrogen content of the sales stream to approximately 5.5% versus a pipeline
quality specification of 4% total inert components. This is possibly due to adding new wells and
new
14
coal seams
in the field, since coals preferentially desorb nitrogen, causing the
highest nitrogen content to be early in the life of a new
well or seam. Our technical and management team has
reviewed a number of cost-effective solutions available to mitigate the increase in nitrogen. A
nitrogen rejection unit has been ordered and is scheduled to be installed in
February 2007. We expect to incur approximately $600,000 acquiring the unit, transporting it to
our Southern Illinois Basin Project and installing the unit for operation. In the meantime, the
field remains online, the coals are continuing to de-water, and we are selling gas at a
constrained rate of approximately 550 Mcf per day. Our pipeline service provider has indicated to us that it
will resume accepting our entire sales at the end of December, prior
to the installation of the nitrogen rejection unit.
From early 2002 until 2005, our strategic focus was on building our acreage footprint in the
Basin. We were built around the primary strategic objective of acquiring CBM rights in the Basin.
As we began accumulating CBM rights, we began testing our acreage to determine its CBM potential.
Having accumulated CBM rights to approximately 500,000 acres in the Basin and conducting extensive
testing at our Southern Illinois Basin Project, we embarked (in late 2004) on a pilot production
program at our Southern Illinois Basin Project. Encouraged by the results, we expanded our drilling
and production activities and began installing the infrastructure necessary to enable us to begin
sales of CBM at our Southern Illinois Basin Project.
As our drilling and production operations have grown, we have not abandoned our goal of adding
additional acreage and mineral rights. However, we have committed ourselves to transitioning BPI
from a company focused primarily on the acquisition of mineral rights to a company focused on
expanding our drilling and production operations and growing our reserves. To accomplish this
transition, we recognized that we needed to obtain additional capital, resources and technical
expertise. We believe that we have made substantial progress in achieving these goals. In September
2005, we sold 18,000,000 common shares and raised approximately $28,000,000. In April 2006, we
hired Jim Craddock as our Senior Vice President of Operations. Prior
to joining us, Mr. Craddock was with Burlington Resources
for over 20 years, last serving as Chief Engineer. In his first
few months at BPI, Mr. Craddock built a strong in-house
technical team by adding a geologist and three engineers to our team, all with extensive experience in
successful CBM projects in basins located in the United States and Canada. Our new technical team
has over 130 years of experience in CBM exploration and development that they bring to us.
In April 2006, we initiated our second development front when we began drilling 10 pilot
development wells in Shelby County at our Northern Illinois Basin
Project (Northern Project). Our CBM rights in the
Northern Project cover 351,487 acres in Montgomery, Shelby, Christian, Fayette and
Macoupin counties in Illinois, which are located in the north central
part of the Basin. We currently believe
that there are up to 12 prospective coal seams thick enough for commercial production at
this project. The thickest seam, the Herrin Coal seam, is up to nine feet thick and has been mined
in shallow parts of the Basin. We believe that a single thick seam such as this may offer an
attractive target for horizontal drilling.
We are not currently generating net income or positive cash flow from operations. Although we
capitalize exploration and development costs, we have historically experienced significant losses.
The primary costs that generated these losses were compensation-related expenses and general and
administrative expenses. Even if we achieve increased revenues and positive cash flow from
operations in the future, we anticipate increased exploration, development and other capital
expenditures as we continue to explore and develop our mineral rights.
We anticipate that the number of wells we drill during the fiscal year ending July 31, 2007
will be dependent to a significant degree on the data we obtain from our recently completed 10-well
pilot program at our Northern Project as well as data obtained
from five test wells we have recently drilled on other leases in our Western Illinois Basin Project
(Western Project) and Northern Project. Information from these test wells will continue to be
gathered over the next 90 days. Our capital expenditure budget for our 2007 fiscal year is a range
that totals $12.0 million to $30.0 million. These amounts correspond to drilling 58 wells at the
low end of the range
15
and 123 wells at the upper end. These amounts include installing a gathering system and processing
yard to handle the anticipated production from the 10-well pilot program at our Northern Project,
the five test wells completed in this past quarter and additional pilot wells and/or production
wells at our three current projects. Our cash balance at October 31, 2006 of $14.7 million is
insufficient to fully fund the high end of the range of forecasted capital expenditures and net
cash used by operating activities during our 2007 fiscal year or our operations beyond that date.
Therefore, we will likely need to raise additional financing in the near future. We currently do
not have any specific plans to raise financing in support of our operations. Although management
has no specific plans in place to raise the additional capital necessary to fund our plan of
operations and forecasted capital expenditures, management anticipates raising the additional
required capital through a combination of additional stock sales, the issuance of debt securities,
borrowing and/or entering into joint ventures. Managements focus for fiscal year 2007 will be to:
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|
|
obtain test data and initiate pilot projects that demonstrate the commercial
potential of CBM at our various acreage blocks and projects in the Basin; |
|
|
|
|
reduce well drilling and completion costs; |
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|
|
|
increase total company reserves; and |
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grow total production. |
Gathering test data and siting pilot projects based on this data should lead to proving
project viability in multiple areas in the Basin. These pilot projects should have the
potential to grow into development projects that will increase our total reserves and
production. As we drill new wells, our production should continue to increase, as the new wells
come online and our existing wells continue to dewater. As our production increases in the future,
we should be positioned to generate positive cash flow from our operations.
A thorough evaluation of the geological assets that we control should lead to the evaluation
and implementation of more cost-effective drilling and completion techniques that can be
implemented to reduce overall costs, increase resource recovery and total reserves and improve
internal rates of return from development projects.
We currently control approximately 500,000 acres of CBM rights and, assuming 80-acre vertical
well spacing and the development of all of our acreage, have the possibility of up to 6,000
drilling locations. With our potential for drilling locations, we expect that our drilling
activities will be taking place over many years. The type of test data we are interested in
developing across all of our projects includes measurements of permeability, gas content and net
pay (i.e., thickness of coal seams from which we believe CBM can be commercially produced). Our
focus is to increase our technical and operational knowledge of the Basin and our acreage
rights to assist us in (i) establishing the value of our CBM assets and (ii) optimizing the
production we can obtain from our wells after we bring them online. The technical team we have
assembled has extensive experience and expertise in all of these areas as well as implementation of
large scale development of CBM projects.
Several factors, over which we have little or no control, could impact our future economic
success. These factors include natural gas prices, limitations imposed by the terms and conditions
of our lease agreements, possible court rulings concerning our property interests in CBM,
availability of drilling rigs, operating costs, and environmental and other regulatory matters. In
our planning process, we have attempted to address these issues by:
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|
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negotiating to obtain leases that grant us the broadest possible rights to CBM for
any given tract of land; |
16
|
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|
conducting ongoing title reviews of existing mineral interests; |
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|
where possible, negotiating and utilizing multiple service companies to increase
competition and minimize the risk of disruptions caused by the loss of any one service
provider; and |
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|
attempting to create a low cost structure in order to reduce our vulnerability to
many of these factors. |
Results of Operations
Three Months Ended October 31, 2006 Compared to Three Months Ended October 31, 2005
The following table presents our unaudited financial data for the first quarter of fiscal year
2007 compared to the first quarter of fiscal year 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended October 31, |
|
Dollar |
|
% |
|
|
2006 |
|
2005 |
|
Variance |
|
Change |
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales |
|
$ |
294,002 |
|
|
$ |
209,694 |
|
|
$ |
84,308 |
|
|
|
40 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
335,974 |
|
|
|
160,804 |
|
|
|
175,170 |
|
|
|
109 |
% |
General and
administrative expense |
|
|
2,734,710 |
|
|
|
1,272,424 |
|
|
|
1,462,286 |
|
|
|
115 |
% |
Depreciation,
depletion and
amortization |
|
|
183,998 |
|
|
|
94,802 |
|
|
|
89,196 |
|
|
|
94 |
% |
|
|
|
|
|
|
3,254,682 |
|
|
|
1,528,030 |
|
|
|
1,726,652 |
|
|
|
113 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
218,906 |
|
|
|
132,619 |
|
|
|
86,287 |
|
|
|
65 |
% |
Interest expense |
|
|
(3,153 |
) |
|
|
(7,544 |
) |
|
|
4,391 |
|
|
|
58 |
% |
|
|
|
|
|
|
215,753 |
|
|
|
125,075 |
|
|
|
91,347 |
|
|
|
73 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(2,744,927 |
) |
|
$ |
(1,193,261 |
) |
|
$ |
(1,551,666 |
) |
|
|
(130 |
%) |
|
|
|
Revenue During the first quarter of fiscal year 2007, revenue increased $84,308 over
the first quarter of fiscal year 2006. Net sales of gas (net of royalties) were 51,490 Mcf for the
first quarter of fiscal year 2007 compared to 19,789 Mcf for the first quarter of 2006. Our
average realized selling price per Mcf was $5.71 for the first quarter of fiscal year 2007 compared
to $10.60 for the first quarter of fiscal year 2006. Net sales were negatively impacted during the
first quarter of fiscal year 2007 by lower commodity prices and a pipeline curtailment incurred at
the end of October for approximately six days. The curtailment was caused by an increase in the
nitrogen content of the sales stream to approximately 5.5% versus a pipeline quality specification
of 4% total inert components. A nitrogen rejection unit has been ordered and is
scheduled to be installed in February 2007. We expect to incur approximately $600,000 acquiring the
unit, transporting it to our Southern Illinois Basin Project and installing the unit for operation.
Lease operating expense During the first quarter of fiscal year 2007, lease operating
expense increased $175,170 over the first quarter of fiscal year 2006. Lease operating expense
represents production expenses, consisting primarily of repairs and maintenance, fuel and
electricity, equipment rental and other overhead expenses related to producing wells. The increase
is primarily
17
due to the increase in producing wells and the related increase in gas production at the Southern
Illinois Basin Project, new lease operating expenses at our pilot project in the Northern Illinois
Basin and the hiring of additional field personnel.
General and administrative expense General and administrative expense consisted of
the following for the first quarter of fiscal years 2007 and 2006, respectively:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months ended |
|
|
|
|
|
|
October 31, |
|
Dollar |
|
% |
|
|
2006 |
|
2005 |
|
Variance |
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Salaries and benefits |
|
$ |
1,210,746 |
|
|
$ |
223,871 |
|
|
$ |
986,875 |
|
|
|
441 |
% |
Stock-based compensation |
|
|
644,851 |
|
|
|
397,586 |
|
|
|
247,265 |
|
|
|
62 |
% |
Professional and regulatory |
|
|
586,913 |
|
|
|
542,123 |
|
|
|
44,790 |
|
|
|
8 |
% |
Other |
|
|
292,200 |
|
|
|
108,844 |
|
|
|
183,356 |
|
|
|
168 |
% |
|
|
|
Total general and
administrative expense |
|
$ |
2,734,710 |
|
|
$ |
1,272,424 |
|
|
$ |
1,462,286 |
|
|
|
115 |
% |
|
|
|
During the first quarter of fiscal year 2007, salaries and benefits increased $986,875
over the first quarter of fiscal year 2006. The increase was primarily the result of hiring
additional personnel to support our growth, including a Senior Vice
President of Operations, a geologist and three engineers, including cash signing bonuses totaling $350,000 paid to such personnel
during the quarter. In addition, the first quarter of fiscal year
2007 includes $250,000 in severance
paid to our former Chief Financial Officer who resigned in October 2006.
During the first quarter of fiscal year 2007, stock-based compensation increased $247,265 over
the first quarter of fiscal year 2006. No stock options were granted in the first quarter of
fiscal year 2007, whereas during the first quarter of fiscal year 2006 we granted options to
purchase 495,000 common shares that were valued at $.80 per option share under the Black-Scholes
valuation model. Stock-based compensation expense for the first quarter of fiscal year 2007
primarily relates to the vesting of restricted shares, the grant of 350,000 unrestricted common
shares to newly hired members of our technical team and the grant of 248,661 unrestricted common
shares to certain of our executive officers, employees and non-employee directors related
to bonuses and directors fees. Stock-based compensation expense
excludes $228,432 related to share-based payments made to our former
Chief Financial Officer during the first quarter of fiscal year 2007.
This amount was capitalized and is being amortized over the term of
the non-compete clause of the separation agreement we entered into
with our former Chief Financial Officer. We intend to continue to rely on the granting of equity
awards, primarily restricted shares, in order to attract and retain qualified individuals.
Depreciation, depletion and amortization expense During the first quarter of fiscal year
2007, depreciation, depletion and amortization expense
(DD&A) increased $89,196 over the first
quarter of fiscal year 2006. We compute DD&A on capitalized acquisition and development costs
(including gas collection equipment) using the units-of-production method based on estimates of
proved reserves, and on all other property and equipment using the straight-line method based on
estimated useful lives ranging from three to 10 years. The increase is primarily due to the
increase in capitalized development costs and an increase in production over the first quarter of
fiscal year 2006. Additionally, depreciation expense increased due to additions to other support
equipment.
Interest income During the first quarter of fiscal year 2007, interest income increased
$86,287 over the first quarter of fiscal year 2006 due to higher average cash balances during the
first quarter of fiscal year 2007. The higher cash balances are the result of net proceeds of
$27,883,954 we received in September 2005 related to the private placement of our common shares.
18
Critical Accounting Policies and Estimates
Our unaudited consolidated financial statements and accompanying notes have been prepared in
accordance with accounting principles generally accepted in the United States. The preparation of
these financial statements requires our management to make estimates, judgments and assumptions
that affect reported amounts of assets, liabilities, revenues and expenses. On an ongoing basis, we
evaluate the accounting policies and estimates that we use to prepare financial statements. We base
our estimates on historical experience and assumptions believed to be reasonable under current
facts and circumstances. Actual amounts and results could differ from these estimates used by
management.
Certain accounting policies that require significant management estimates and are deemed
critical to the Companys results of operations or financial position were discussed in Item 7 of
our Annual Report on Form 10-K for the fiscal year ended July 31, 2006. There were no material changes in these policies during
the current quarter.
Financial Condition
Our primary source of liquidity historically has come from the sale of our common shares in
private placements and the proceeds from the exercise of warrants and options to acquire our common
shares. To date, we have not relied significantly on borrowing to finance our operations or provide
cash. As of October 31, 2006, we had only $145,842 in long-term notes payable. From July 31, 2003
until October 31, 2006, we raised $43,198,616 from the sale of our common shares. Additionally,
during that same period, we collected $6,728,810 and $2,042,280 as a result of the exercise of
warrants and stock options, respectively. Our primary use of these funds has been the acquisition,
exploration, testing and development of our CBM properties and rights.
We did not begin to generate revenues from CBM sales until January 2005. Revenues from CBM
sales were $294,002 and $209,694 for the three months ended October 31, 2006 and 2005,
respectively. Subject to the various risks described in this
prospectus supplement, we expect revenue from the
sale of our CBM to increase due to (i) increased production from existing wells as they proceed
through the initial dewatering phase and (ii) additional production generated as a result of
drilling and production from additional wells. However, in view of the fact that we have very
little historical experience of dewatering and gas production in the Basin, we can provide no
assurance that we will achieve a trend of increased production and revenue in the future.
In addition, CBM wells typically must go through a lengthy dewatering phase before making a
significant contribution to gas production. We estimate that a typical vertical well will require
about 24 months to reach peak production. The impact on our cash position is that there will be a
delay of up to 24 months between the time we initially invest in drilling and completing a well and
the time when a typical well will begin to make a significant contribution to our cash from
operations. Additionally, net cash generated (used) by operating activities is dependent on a
number of factors over which we have little or no control. These factors include, but are not
limited to:
|
|
|
the price of, and demand for, natural gas; |
|
|
|
|
availability of drilling equipment; |
|
|
|
|
lease terms; |
|
|
|
|
availability of sufficient capital resources; and |
|
|
|
|
the accuracy of production estimates for current and future wells.
|
19
We had a cash balance of $14,697,615 as of October 31, 2006, compared to $19,279,015 at July
31, 2006. The net decrease in our cash balance is primarily due to the net cash used in operating
activities of $1,318,654, consisting primarily of payments for salaries and benefits, professional
fees and lease operating expenses, adjustments for changes in working capital, and net cash used in
investing activities of $3,192,573, consisting primarily of development costs at our Northern
Illinois Basin Project and purchases of other supporting property and equipment. We also made
repayments of long-term notes in the amount of $70,173 during the quarter ended October 31, 2006.
We have no contractual commitments for capital expenditures. However, our plan anticipates
that for the fiscal year ending July 31, 2007, we will spend approximately $12.0 million to $30.0
million on capital expenditures. These amounts correspond to drilling 58 wells at the low end of
the range and 123 wells at the upper end. These amounts include installing a gathering system and
processing yard to handle the anticipated production from our 10-well pilot program, the five test
wells completed in the past quarter and additional pilot wells and/or production wells at our three
current projects. In addition to our drilling program, we expect to pursue the acquisition of
additional CBM rights during the fiscal year. Our cash balance as of October 31, 2006 is
insufficient to fully fund the high end of the range of forecasted capital expenditures and net
cash used by operating activities during our 2007 fiscal year or our operations beyond that date.
Therefore, we will likely need to raise additional funds in the near future. We currently do
not have any specific plans to raise financing in support of our operations. Although management
has no specific plans in place to raise the additional capital necessary to fund our plan of
operations and forecasted capital expenditures, management anticipates raising the additional
required capital through a combination of additional stock sales, the issuance of debt securities,
borrowing and/or entering into joint ventures. Although we are currently evaluating the best methods of raising these funds, we can
provide no assurance that we will be able to raise the necessary funds.
Cautionary Statement Concerning Forward-Looking Statements
Some
of the statements contained in this prospectus supplement that are not historical facts, including
statements containing the words believes, anticipates, expects, intends, plans, should,
may, might, continue and estimate and similar words, constitute forward-looking statements
under the federal securities laws. These forward-looking statements involve known and unknown
risks, uncertainties and other factors that may cause our actual results, performance or
achievements, or the conditions in our industry, on our properties or in the Basin, to be
materially different from any future results, performance, achievements or conditions expressed or
implied by such forward-looking statements. Some of the factors that could cause actual results or
conditions to differ materially from our expectations, include, but are not limited to, (a) our
inability to generate sufficient income or obtain sufficient financing to fund our capital
expenditures and operations through July 31, 2007 or
thereafter, (b) our inability to retain our acreage
rights at our projects at the expiration of our lease agreements, due to insufficient CBM
production or other reasons, (c) our failure to accurately forecast CBM production, (d)
displacement of our CBM operations by coal mining operations, which have superior rights in most of
our acreage, (e) our failure to accurately forecast the number of wells that we can drill, (f) a
decline in the prices that we receive for our CBM production, (g) our failure to accurately
forecast operating and capital expenditures and capital needs due to rising costs or different
drilling or production conditions in the field, (h) our inability to attract or retain qualified
personnel with the requisite CBM or other experience, and (i) unexpected economic and market
conditions, in the general economy or the market for natural gas. We caution readers not to place
undue reliance on these forward-looking statements.
20
Prospectus Supplement
to Separate Prospectuses dated
May 11, 2006