UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended April 30, 2008
Commission File No. 001-32695
BPI Energy Holdings, Inc.
(Exact Name of Registrant as Specified in Its Charter)
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British Columbia, Canada
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75-3183021
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(State or Other Jurisdiction of
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(I.R.S. Employer Identification No.)
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Incorporation or Organization)
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30775 Bainbridge Road, Suite 280, Solon, Ohio
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44139
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(Address of Principal Executive Offices)
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(Zip Code)
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Registrants telephone number, including area code:
(440) 248-4200
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes
þ
No
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer
o
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Accelerated filer
o
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Non-accelerated filer
o
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Smaller reporting company
þ
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).Yes
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No
þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as
of the latest practicable date: Common Shares, without par value, as of June 10, 2008: 73,484,395.
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
BPI ENERGY HOLDINGS, INC.
Consolidated Balance Sheets
(Dollars in thousands)
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April 30,
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July 31,
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2008
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2007
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(Unaudited)
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ASSETS
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Current Assets
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Cash and cash equivalents
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$
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1,081
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$
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11,292
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Accounts receivable
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145
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94
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Other current assets
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979
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1,348
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Total current assets
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2,205
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12,734
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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,
amortization and impairment of $12,955 and $12,621
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32,535
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16,631
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Unproved, excluded from amortization
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8,533
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Support equipment, net of accumulated depreciation
and amortization of $809 and $741
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352
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552
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Net gas properties
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32,887
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25,716
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Other property and equipment, net of accumulated
depreciation and amortization of $244 and $152
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428
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473
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Net property and equipment
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33,315
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26,189
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Restricted cash
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100
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100
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Other non-current assets
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220
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Total assets
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$
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35,620
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$
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39,243
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LIABILITIES AND SHAREHOLDERS EQUITY
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Current Liabilities
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Accounts payable
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$
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880
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$
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1,371
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Current maturities of long-term debt and notes payable
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11,434
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8,488
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Accrued liabilities and other
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667
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1,503
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Total current liabilities
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12,981
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11,362
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Long-term debt and notes payable, less current maturities
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35
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48
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Asset retirement obligation
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161
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114
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Other long-term liabilities
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40
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Total liabilities
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13,217
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11,524
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Shareholders Equity
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Common shares, no par value, authorized 200,000,000
shares, 73,484,395 and 72,524,493 issued and
outstanding
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67,946
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67,946
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Additional paid-in capital
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8,421
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7,608
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Accumulated deficit
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(53,964
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)
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(47,835
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Total shareholders equity
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22,403
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27,719
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Total liabilities and shareholders equity
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$
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35,620
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$
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39,243
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See notes to unaudited consolidated financial statements
2
BPI ENERGY HOLDINGS, INC.
Consolidated Statements of Operations
(Dollars in thousands, except per share data)
(Unaudited)
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Three Months Ended
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Nine Months Ended
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April 30,
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April 30,
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2008
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2007
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2008
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2007
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Revenue
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Gas sales
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$
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535
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$
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335
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$
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1,292
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$
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876
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Operating expenses
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Lease operating expense
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403
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412
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1,038
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1,276
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General and administrative expenses
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1,250
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1,885
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4,654
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6,089
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Lease rentals and other operating expense
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168
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247
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Depreciation, depletion and amortization
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204
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215
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552
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591
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Total operating expenses
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2,025
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2,512
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6,491
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7,956
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Operating loss
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(1,490
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(2,177
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(5,199
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(7,080
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Other income (expense):
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Interest income
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10
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109
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141
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494
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Interest expense
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(735
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(1
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(767
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(8
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Other expense, net
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(323
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(304
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(1,048
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108
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(930
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486
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Net loss
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$
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(2,538
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$
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(2,069
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$
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(6,129
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$
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(6,594
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Basic and diluted net loss per share
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$
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(0.04
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$
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(0.03
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$
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(0.09
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$
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(0.09
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)
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Weighted average common shares outstanding
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71,721,318
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70,036,326
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70,774,984
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69,642,804
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See notes to unaudited consolidated financial statements
3
BPI ENERGY HOLDINGS, INC.
Consolidated Statements of Shareholders Equity
(Dollars in thousands)
(Unaudited)
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Additional
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Total
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Common Shares
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Paid-in
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Accumulated
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Shareholders
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Shares
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Amount
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Capital
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Deficit
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Equity
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Balance, July 31, 2007
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72,524,493
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$
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67,946
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$
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7,608
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$
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(47,835
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)
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$
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27,719
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Share-based compensation
common shares (number of shares
includes non-vested portion of
restricted stock)
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2,246,235
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861
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861
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Shares forfeited
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(941,667
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)
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Surrender of shares to pay taxes
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(344,666
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)
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(48
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)
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(48
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Net loss
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(6,129
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)
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(6,129
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Balance, April 30, 2008
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73,484,395
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$
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67,946
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$
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8,421
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$
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(53,964
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)
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$
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22,403
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See notes to unaudited consolidated financial statements
4
BPI ENERGY HOLDINGS, INC.
Consolidated Statements of Cash Flows
(Dollars in thousands)
(Unaudited)
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Nine Months Ended
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April 30,
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2008
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2007
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Cash Provided by (Used in):
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Operating Activities
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Net loss
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$
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(6,129
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)
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$
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(6,594
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)
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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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552
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591
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Share-based payments
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861
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1,046
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Loss on fair
value of commodity derivative contracts
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345
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Amortization of debt discount
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275
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Accretion of asset retirement obligation
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7
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5
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Changes in assets and liabilities:
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Accounts receivable
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(51
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)
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(25
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Other current assets
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496
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(159
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Accounts payable
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68
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(152
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)
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Accrued liabilities and other
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(1,141
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)
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7
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Other assets and liabilities
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220
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Net cash used in operating activities
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(4,497
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)
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(5,281
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)
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Investing Activities
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Additions to property and equipment
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(7,245
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)
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(6,795
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)
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Net cash used in investing activities
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(7,245
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)
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(6,795
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)
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Financing Activities
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Proceeds from issuance of debt
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1,721
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Payments on long-term debt and notes payable
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(15
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)
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(132
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)
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Payment of deferred financing costs
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(127
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)
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Payments for surrender of shares
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(48
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)
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Net cash provided by (used in) financing activities
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1,531
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(132
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)
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Net decrease in cash and cash equivalents
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(10,211
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)
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|
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(12,208
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)
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Cash and cash equivalents at the beginning of the year
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|
11,292
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|
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19,279
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Cash and cash equivalents at the end of the period
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$
|
1,081
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|
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$
|
7,071
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|
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Supplementary disclosure of cash flow information:
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Interest paid
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|
$
|
185
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|
|
$
|
4
|
|
Non-cash financing activity interest paid-in-kind
(added to debt principal)
|
|
$
|
996
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|
$
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|
|
See notes to unaudited consolidated financial statements
5
BPI ENERGY HOLDINGS, INC.
Notes to Consolidated Financial Statements
Unaudited
(Dollars in thousands)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These unaudited consolidated interim financial statements include the accounts of BPI Energy
Holdings, Inc. and its wholly owned U.S. subsidiary, BPI Energy, Inc. (collectively, the
Company). All inter-company transactions and balances have been eliminated upon consolidation.
BPI Energy Holdings, Inc. is incorporated in British Columbia, Canada and, through its wholly owned
U.S. subsidiary, BPI Energy, Inc. (BPI Energy), is involved in the exploration, production and
commercial sale of coalbed methane (CBM) located 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. Dollar amounts shown are in
thousands of U.S. Dollars, except for per share and per unit amounts and 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 three and nine months ended April 30, 2008 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, 2007. Certain prior period amounts have been reclassified to conform to
the current periods presentation.
Going Concern
These unaudited consolidated financial statements have been prepared on the basis of accounting
principles applicable to a going concern, which contemplates the Companys ability to realize its
assets and discharge its liabilities in the normal course of business. The Company has experienced
significant losses in recent periods and has an accumulated deficit of $53,964 at April 30, 2008.
As of April 30, 2008, the Companys cash balance and accounts receivable total $1,226 compared to
its accounts payable and accrued liabilities (excluding debt and loss position on hedge contracts)
totaling $1,242. The Company is not currently drilling new wells; however, based on its current
working capital situation, the Company still needs to raise cash in order to be able to settle its
accounts payable and accrued liabilities as of April 30, 2008 and to fund future operations. In
order to continue as a going concern, the Company must be able to finance its current operations,
pay amounts due under its Advancing Term Credit Agreement with GasRock Capital LLC (GasRock), as
amended (the GasRock Credit Agreement), when such amounts become due on January 30, 2009 and
finance any future exploration and development costs.
The Company has historically financed its activities primarily from the proceeds of private
placements of its common shares and most recently from advances under the GasRock Credit Agreement
as discussed in Note 6. The Company currently has a request pending with GasRock to fund its cash
shortfall through the end of fiscal year 2008 along with a request for capital development funds
for new development activities. GasRock has sole discretion over all future advances under the
GasRock Credit Agreement.
In addition, the Company is currently evaluating what additional options are available to finance
current and future operations and to be able to pay amounts due under the GasRock Credit Agreement
when such amounts become due on January 30, 2009. The Company has explored additional potential
funding sources,
6
including the issuance of new debt and/or equity securities, joint ventures, mergers/combinations,
asset sales and selling rights relating to the Companys litigation against Drummond, but to date
has not been successful in obtaining additional funding. Although the Company is still exploring
all of these financing options, it can provide no assurance that it will be successful in
completing a financing transaction. Failure to raise adequate funds in the near term would have a
material adverse effect on the Company and may cause the Company to have to cease operations and
liquidate.
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 the Companys 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 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.
Accounts Receivable
Accounts receivable at April 30, 2008 represent amounts due from GasRock in accordance with the
terms of the GasRock Credit Agreement under which GasRock receives directly all proceeds from the
Companys gas sales and then reimburses the Company for eligible operating expenses, as defined
under the GasRock Credit Agreement. Accounts receivable at July 31, 2007 represent amounts due from
Atmos Energy Marketing, LLC for gas sales. Management regularly reviews accounts receivable to
determine whether amounts are collectible and records a valuation allowance to reflect managements
best estimate of any amount that may not be collectible. At April 30, 2008 and July 31, 2007, the
Company has determined that no allowance for uncollectible receivables was necessary.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with borrowings or establishment of credit
facilities. These costs are amortized as an adjustment to interest expense over the life of the
borrowing or life of the credit facility using the interest method. In the case of early debt
principal repayments, the Company adjusts the value of the corresponding deferred financing costs
with a charge to other expense, and similarly adjusts the future amortization expense. The Company
recorded approximately $173 and $385 of non-cash amortization expense related to deferred financing
costs during the three months and nine months ended April, 2008, respectively. The amortization was
included as interest expense and was subject to capitalization as unproved gas properties during
the three and nine months ended April 30, 2008. However, no interest expense was capitalized
during the current quarter
Commodity Derivatives
The Company accounts for derivative instruments or hedging activities under the provisions of
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 133 requires the Company to record derivative
instruments at their fair value.
Under the terms of the GasRock Credit Agreement, the Company is required to enter into derivative
contracts covering approximately 75% of its proved developed producing reserves scheduled to be
produced during a two-year period at a guaranteed price of not less than $7.00 per one million of
British thermal units (MMBtu). The objective is to reduce the Companys exposure to commodity
price risk associated with expected gas production.
7
The Companys risk management strategy is to enter into commodity derivatives that set price
floors and price ceilings for its natural gas production. On July 31, 2007, the Company entered
into costless collar contracts with BP Corporation North America Inc. (BP) for the notional
amount of 20,000 MMBtus per month beginning September 1, 2007 through July 31, 2009 (460,000 MMBtus
in total). Under the terms of the contracts, BP is required to cover any shortfall below the floor
of $7.00 per MMBtu and the Company 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 (New
York Mercantile Exchange) forward price for each month. The Company expects that it will enter into
additional derivative contracts in the future to cover the entire 75% of its proved developed
producing reserves scheduled to be produced during each period.
The
Company has elected not to designate its commodity derivatives as
hedges, and accordingly, such
contracts are recorded at fair value on its consolidated balance sheets and changes in such fair
value are recognized in current earnings as other income or expense as they occur. As of April 30,
2008, the fair value of the contracts with BP was estimated to be approximately $345, in a net
liability position of which $305 is considered current and is included in accrued liabilities and
other, and $40 is non-current and is recorded as an other non-current liability in the April 30,
2008 unaudited consolidated balance sheet. In addition, the change in fair value (loss) of $329
and $345 during the three and nine months ended April 30, 2008, respectively, has been recorded as
other expense in the unaudited consolidated statements of operations.
The Company does not hold or issue commodity derivatives for speculative or trading purposes. The
Company is exposed to credit losses in the event of nonperformance by the counterparty to its
commodity derivatives. It is anticipated, however, that its counterparty, BP, will be able to fully
satisfy its obligations under the commodity derivative contracts. The Company does not obtain
collateral or other security to support its commodity derivative
contracts subject to credit risk
but does monitor the credit standing of the counterparty.
Realized gains or losses from the settlement of gas derivative contracts are reported as other
income or expense on the consolidated statements of operations. On July 31, 2007, the Company
entered into the first commodity derivative contracts with the first settlement month designated as
September 2007. The Company recorded net realized gains on
settlement of its derivative contracts of
$0 and $41 during the three and nine months ended April 30, 2008, respectively. Such amounts are
included as other income in the unaudited consolidated statements of operations.
As discussed in Note 14, on June 9, 2008, the Company entered into an arrangement with BP whereby
its costless collar contracts described above for the notional amount of 20,000 MMBtus per month
through July 31, 2009 were cancelled effective July 1, 2008 and replaced with a swap agreement at a
fixed price of $10.26 per MMBtu (based on NYMEX final settlement) for the notional amount of 20,000
MMBtus per month beginning July 1, 2008 through July 31, 2010 (500,000 MMBtus in total). The
contract is net-settled on a monthly basis, meaning that if the NYMEX final settlement price for a
month is below $10.26 per MMBtu, BP will pay the Company the difference in price multiplied by the
notional amount for the month, and if the NYMEX final settlement price for a month is above $10.26
per MMBtu, the Company will pay BP the difference in price multiplied by the notional amount for
the month.
Capitalized Interest
The Company capitalizes interest costs to gas properties on expenditures made in connection with
unproved properties that are not subject to current depletion. Interest is capitalized only for the
period during which activities are in progress to bring these properties to their intended use.
Total interest expense incurred during the three months and nine months ended April 30, 2008,
including the amortization of deferred financing costs and debt discount, was approximately $735
and $1,850. Of these amounts, interest costs capitalized to unproved gas properties during the
three and nine months ended April 30, 2008 was $0 and $1,083, respectively. No interest costs were
capitalized in prior periods.
8
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 directly attributable to acquisition, exploration or
development activities are capitalized as properties and equipment on the balance sheet. The
Company capitalized internal labor and benefit costs determined to be directly attributable to
acquisition, exploration or development activities in the amount of $18 and $219 during the three
and nine months ended April 30, 2008, respectively, and $131 and $349 during the three and nine
months ended April 30, 2007, respectively. Costs associated with production and general corporate
activities are expensed in the period incurred.
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 period. The calculation of future net revenues is based upon
prices, costs and regulations in effect at each period-end. At April 30, 2008, the carrying amount
of net gas properties was less than the full cost ceiling limitation based on an April 30, 2008
Henry Hub gas price of $10.81 per MMBtu, and, therefore, no ceiling cost write-down was recognized.
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. Support equipment represents vehicles and other mobile
equipment used in gas operations and is depreciated using the straight-line method over the
estimated useful lives of the assets, ranging from three to five years.
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, the Company determines if an unproved property is impaired if one or more of the
following conditions exist:
|
i)
|
|
there are no firm plans for further drilling on the unproved property;
|
|
|
ii)
|
|
negative results were obtained from studies of the unproved property;
|
|
|
iii)
|
|
negative results were obtained from studies conducted in the vicinity of the unproved
property; or
|
|
|
iv)
|
|
the remaining term of the unproved property does not allow sufficient time for
further studies or drilling.
|
As of April 30, 2008, the Company determined that all of its unproved properties are impaired due
to the uncertainty as to whether the Company will be able to obtain the additional financing
necessary to (i) continue effectively evaluating such properties for a sufficient period of time
and (ii) commence development on such properties, if warranted, based on the results of the
Companys ongoing evaluation. Therefore, the capitalized costs associated with these properties
totaling $9,846 were reclassified to proved gas properties as of April 30, 2008 and were amortized
on the units-of-production method during the current quarter.
9
The Company determined that no impairment of unproved properties existed as of July 31, 2007.
Other Property and Equipment
Other property and equipment is stated at cost, net of depreciation and amortization, and includes
fixed assets such as office equipment, computer hardware and software, and furniture and fixtures
and is depreciated using the straight-line method over the estimated useful lives of the assets,
ranging from three to five years.
Income Taxes
Income taxes are accounted for under the asset and liability method that requires deferred income
taxes to reflect the future tax consequences attributable to differences between the tax and
financial reporting bases of assets and liabilities. Deferred tax assets and liabilities recognized
are based on the tax rates in effect in the year in which differences are expected to reverse.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management based
on available evidence, it is more likely than not that some or all of any net deferred tax assets
will not be realized.
The Company adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation
No. 48, Accounting for Uncertainty in Income Taxes An interpretation of FASB Statement No. 109
(FIN 48) on August 1, 2007. The adoption of FIN 48 had no effect on the Companys unaudited
interim financial statements as of and for the three and nine months ended April 30, 2008.
The Companys policy is to recognize interest accrued related to unrecognized tax benefits as
interest expense and penalties as operating expenses. The Company was not subject to any such
interest or penalties during the three and nine months ended April 30, 2008 and 2007, respectively.
Loss Per Share
Basic loss per share is calculated using the weighted average number of common shares outstanding
during the period. 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 April 30, 2008 and 2007,
respectively, as the effect of their assumed exercises or vesting would be anti-dilutive:
|
|
|
|
|
|
|
|
|
|
|
April 30,
|
|
April 30,
|
|
|
2008
|
|
2007
|
Outstanding warrants
|
|
|
1,037,200
|
|
|
|
5,311,600
|
|
Outstanding stock options
|
|
|
1,579,931
|
|
|
|
1,529,931
|
|
Nonvested portion of restricted shares issued
|
|
|
1,433,438
|
|
|
|
2,437,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,050,569
|
|
|
|
9,278,869
|
|
|
|
|
|
|
|
|
|
|
Recently Issued Accounting Standards
In June 2006, the FASB issued FIN 48. This Interpretation clarifies the accounting for uncertainty
in income taxes recognized in an enterprises 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. As discussed above, the Company adopted FIN 48 on August 1,
2007. The adoption of FIN 48 by the Company had no effect on its 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
10
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, the Company will need to comply with SFAS No. 157 beginning
in the fiscal year ending July 31, 2009. The Company is currently evaluating the statement to
determine what impact, if any, it will have on its 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. The fair value option may be elected on an instrument-by-instrument basis, with a
few exceptions, as long as it is applied 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 entitys election on
earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after
November 15, 2007. Therefore, the Company will need to comply with SFAS No. 159 beginning in the
fiscal year ending July 31, 2009. Early adoption is permitted. The Company is currently evaluating
the statement to determine what impact, if any, it will have on its consolidated financial
statements.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging
Activities. SFAS No. 161 requires enhanced disclosures about how and why companies use
derivatives, how companies account for derivative instruments and related hedged items and how
derivative instruments and related hedged items affect a companys financial position, financial
performance and cash flows. The provisions of SFAS No. 161 are effective for financial statements
issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption
encouraged. Consequently, SFAS No. 161 will be effective for the Companys quarter ended April 30,
2009. The Company is in the process of determining the impact, if any, the adoption of SFAS No. 161
will have on its financial statement disclosures.
2. SHARE-BASED COMPENSATION
SFAS No. 123(R)
The Company follows the provisions of SFAS No. 123(R), Share-Based Payment. 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 expense at fair market value based on the grant-date
fair value of those awards. The companys share-based compensation expense represents the cost
related to share-based awards granted to employees and directors. The Company measures share-based
compensation expense at grant date, based on the estimated fair value of the award, and recognizes
the cost as expense on a straight-line basis (net of estimated forfeitures) over the requisite
service period. 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 share-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 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.
11
Omnibus Stock Plan
On December 18, 2006, the Companys shareholders approved the Amended and Restated 2005 Omnibus
Stock Plan (the Omnibus Stock Plan), which the Companys 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 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 awards up
to 5% of the number of common shares outstanding as of the first day of that fiscal year plus the
number of common shares that were available for the grant of awards, but not granted, in prior
years under the plan. In no event, however, may the number of common shares available for the grant
of awards in any fiscal year exceed 6% of the common shares outstanding as of the first day of that
fiscal year. In addition, the aggregate number of common shares that could be issued under the
Omnibus Stock Plan is capped at 7,000,000. As of April 30, 2008, the Company has issued 50,000
stock options, 3,557,109 restricted common shares and 1,610,126 fully vested common shares under
the Omnibus Stock Plan, and there are 1,782,765 awards available for future issuance under the
Plan. Stock options granted under the Omnibus Stock Plan were granted with exercise prices
denominated in U.S. Dollars equal to the quoted market price of the Companys common shares on the
date of grant and were fully vested on the date of grant.
The following table summarizes information about the options outstanding at April 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Weighted Average
|
|
Number
|
|
Remaining
|
|
|
|
Exercise Price
|
|
Outstanding
|
|
Life (Years)
|
|
Expiry Date
|
|
$ 0.49
|
|
|
345,000
|
|
|
|
0.5
|
|
|
November 3, 2008
|
0.70
|
|
|
10,000
|
|
|
|
1.4
|
|
|
September 22, 2009
|
0.83
|
|
|
50,000
|
|
|
|
4.1
|
|
|
June 7, 2012
|
1.26
|
|
|
695,666
|
|
|
|
1.6
|
|
|
November 29, 2009
|
1.75
|
|
|
10,000
|
|
|
|
2.4
|
|
|
September 23, 2010
|
1.80
|
|
|
136,000
|
|
|
|
1.9
|
|
|
March 27, 2010
|
1.95
|
|
|
333,265
|
|
|
|
1.7
|
|
|
January 20, 2010
|
|
|
|
|
|
|
|
|
|
$ 1.27
|
|
|
1,579,931
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All outstanding options are fully vested at April 30, 2008. The intrinsic value of outstanding
options is $0 at April 30, 2008.
12
A summary of the status of the Companys nonvested restricted shares as of April 30, 2008 and
changes during the three and nine months ended April 30, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
Nonvested Shares
|
|
Shares
|
|
|
Grant-Date Fair Value
|
|
Nonvested at July 31, 2007
|
|
|
2,437,338
|
|
|
$
|
0.71
|
|
Granted
|
|
|
1,024,770
|
|
|
|
0.55
|
|
Vested
|
|
|
(350,000
|
)
|
|
|
0.93
|
|
Forfeited
|
|
|
(259,000
|
)
|
|
|
0.50
|
|
|
|
|
|
|
|
|
Nonvested at October 31, 2007
|
|
|
2,853,108
|
|
|
$
|
0.64
|
|
Granted
|
|
|
10,000
|
|
|
|
0.35
|
|
Vested
|
|
|
(647,004
|
)
|
|
|
0.52
|
|
Forfeited
|
|
|
(172,666
|
)
|
|
|
0.87
|
|
|
|
|
|
|
|
|
Nonvested at January 31, 2008
|
|
|
2,043,438
|
|
|
$
|
0.66
|
|
Granted
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(100,000
|
)
|
|
|
1.42
|
|
Forfeited
|
|
|
(510,000
|
)
|
|
|
0.85
|
|
|
|
|
|
|
|
|
Nonvested at April 30, 2008
|
|
|
1,433,438
|
|
|
$
|
0.96
|
|
|
|
|
|
|
|
|
During the three and nine months ended April 30, 2008, the Committee granted share awards under the
Omnibus Stock Plan in the form of restricted and unrestricted shares to employees and directors as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares
|
|
|
Fully Vested Shares
|
|
|
Total Shares
|
|
Three Months Ended October 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee bonuses
|
|
|
754,500
|
|
|
|
512,500
|
|
|
|
1,267,000
|
|
Directors fees
|
|
|
270,270
|
|
|
|
|
|
|
|
270,270
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,024,770
|
|
|
|
512,500
|
|
|
|
1,537,270
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended January 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee bonuses
|
|
|
10,000
|
|
|
|
|
|
|
|
10,000
|
|
Directors fees
|
|
|
|
|
|
|
316,465
|
|
|
|
316,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,000
|
|
|
|
316,465
|
|
|
|
326,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended April 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee bonuses
|
|
|
|
|
|
|
|
|
|
|
|
|
Directors fees
|
|
|
|
|
|
|
382,500
|
|
|
|
382,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
382,500
|
|
|
|
382,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total number of shares granted
|
|
|
1,034,770
|
|
|
|
1,211,465
|
|
|
|
2,246,235
|
|
|
|
|
|
|
|
|
|
|
|
Employee Bonuses
On August 2, 2007, the Company granted 754,500 restricted shares and 512,500 fully vested common
shares to employees for performance bonuses related to the fiscal year ended July 31, 2007. The
restrictions on the restricted shares will lapse based on service two years from the date of grant
and the related expense will be recognized on a straight-line basis over the requisite service
period of the employees. The expense related to the fully vested shares was recognized during the
fiscal year ended July 31, 2007. On January 31, 2008, the Company granted 10,000 restricted shares
to a newly hired employee as a signing bonus. The restrictions on these shares will lapse evenly
over a three-year period from the date of grant and the related expense will be recognized on a
straight-line basis over the requisite service period of the employee.
Directors Fees
On October 31, 2007, the Company granted 270,270 restricted shares to a new director. The
restrictions on these shares will lapse evenly over a three-year period from the date of grant
subject to the director standing for re-election in the year the shares are scheduled to vest. The
related expense will be recognized on a straight-line basis over the requisite service period of
the director.
13
On January 15, 2008, the Company granted 316,465 fully vested common shares to certain directors
who elected to have their cash compensation converted into the Companys common shares for fees
earned for their attendance at Board and Committee meetings during fiscal 2007. The expense related
to these fully vested shares was recognized as share-based compensation expense during the periods
incurred.
On March 31, 2008, the Company granted 382,500 fully vested common shares to directors who elected
to have their cash compensation converted into the Companys common shares for fees earned for
their attendance at Board and Committee meetings during the first three months of the calendar year
2008 and each directors quarterly retainer. The expense related to these fully
vested shares was recognized as share-based compensation expense during the periods incurred.
The Omnibus Stock Plan allows participants to surrender common shares to satisfy the Companys tax
withholding obligations related to the vesting of shares. During the three and nine months ended
April 30, 2008, employees surrendered 0 and 344,666 shares, respectively, to satisfy tax
withholding obligations totaling $0 and $142, respectively. Of these amounts, $94 was paid during
the fiscal year ended July 31, 2007. The amount paid by the Company for withholding taxes related
to shares surrendered is recorded as a decrease to additional paid-in capital in the period such
taxes are paid.
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 vest on the next vesting date, based on the number of days
continuously employed during the applicable vesting period. The Company includes all restricted
shares in common shares outstanding when issued, but only includes the vested portion of such
shares in the computation of basic earnings per share.
The 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 April 30, 2008, there was approximately $479 of unrecognized compensation cost related to
restricted shares. The cost is expected to be amortized over a weighted average period of
approximately 1.0 years. The amount charged to expense related to the pro rata vesting of
restricted shares was $98 and $576 during the three and nine months ended April 30, 2008,
respectively, and $211 and $718 during the three and nine months ended April 30, 2007,
respectively.
3. OTHER CURRENT ASSETS
Other current assets consisted of the following at April 30, 2008 and July 31, 2007, respectively:
|
|
|
|
|
|
|
|
|
|
|
April 30,
|
|
|
July 31,
|
|
|
|
2008
|
|
|
2007
|
|
Deferred financing costs
|
|
$
|
577
|
|
|
$
|
836
|
|
Separation agreement costs
|
|
|
133
|
|
|
|
322
|
|
Prepaid expenses and other
|
|
|
269
|
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
$
|
979
|
|
|
$
|
1,348
|
|
|
|
|
|
|
|
|
Deferred financing costs consist of investment banking fees, legal fees and other fees and expenses
incurred directly in connection with the establishment of the GasRock Credit Agreement. These
costs are being amortized as an adjustment to interest expense over the life of the GasRock Credit
Agreement using the interest method. The Company incurred approximately $0 and $127 additional
deferred financing costs and recorded approximately $173 and $386 of amortization expense related
to deferred financing costs during the three and nine months ended April 30, 2008, respectively.
14
Separation agreement costs represent unamortized costs associated with a Separation Agreement and
Waiver and Release (Separation Agreement) with a former officer and director of the Company
entered into on October 12, 2006. Under the terms of the Separation Agreement, the Company agreed
to provide consideration to the former officer and director upon his resignation for severance,
consulting services and his agreement not to compete or solicit the Companys employees. The
Company capitalized the value of the expected future benefit to be received from both the
consulting services and the non-compete/non-solicitation agreement and is amortizing the related
expense ratably over the future periods in which it expects to receive the related benefits. As of
April 30, 2008, $133 of unamortized value related to the consulting services and the
non-compete/non-solicitation agreement are recorded as an other current asset on the balance sheet,
representing the amount to be amortized over the next year. The Company recognized expense in
connection with the Separation Agreement in the amount of $73 and $248 during the three and nine
months ended April 30, 2008, respectively, and $87 and $196 during the three and nine months ended
April 30, 2007, respectively.
4. OTHER NON-CURRENT ASSETS
Other non-current assets consisted of the following at April 30, 2008 and July 31, 2007,
respectively:
|
|
|
|
|
|
|
|
|
|
|
April 30,
|
|
|
July 31,
|
|
|
|
2008
|
|
|
2007
|
|
Separation Agreement
|
|
$
|
|
|
|
$
|
59
|
|
Advance royalties
|
|
|
|
|
|
|
161
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
220
|
|
|
|
|
|
|
|
|
Advance royalties represent lease bonuses and minimum lease royalties that are recoverable against
future production royalties. During the three months ended April 30, 2008, the Company wrote-off
$168 that was previously recorded as advance royalties due to the uncertainty associated with
future development of the related leases. This amount is included in lease rentals and other
operating expense in the consolidated statements of operations for the three and nine months ended
April 30, 2008.
5. ACCRUED LIABILITIES AND OTHER
Accrued liabilities and other consisted of the following at April 30, 2008 and July 31, 2007,
respectively:
|
|
|
|
|
|
|
|
|
|
|
April 30,
|
|
|
July 31,
|
|
|
|
2008
|
|
|
2007
|
|
Professional fees
|
|
$
|
319
|
|
|
$
|
133
|
|
Unrealized loss on derivatives contracts
|
|
|
305
|
|
|
|
|
|
Employee compensation
|
|
|
43
|
|
|
|
1,112
|
|
Separation agreement
|
|
|
|
|
|
|
100
|
|
Other
|
|
|
|
|
|
|
158
|
|
|
|
|
|
|
|
|
|
|
$
|
667
|
|
|
$
|
1,503
|
|
|
|
|
|
|
|
|
6. LONG-TERM DEBT AND NOTES PAYABLE
On July 27, 2007, the Company entered into the GasRock Credit Agreement. The GasRock Credit
Agreement provides for an initial commitment to the Company of $10,200 and the possibility of
future advances to the Company of up to an additional $64,800. All future advances under the
GasRock Credit Agreement beyond the initial commitment will be made in GasRocks discretion. Under
the original terms of the GasRock Credit Agreement, the Company could request advances under the
GasRock Credit Agreement at any time before July 25, 2008, which GasRock could, at its discretion,
extend until July 27, 2010. All amounts then outstanding under the original terms of the GasRock
Credit Agreement were due and payable on July 25, 2008, which GasRock could, at its discretion,
extend until July 29, 2011. On November 29, 2007, the Company entered into an amendment to the
GasRock Credit Agreement that extended the date until which the Company may request advances under
the GasRock Credit Agreement, and the date upon which all amounts outstanding under the GasRock
Credit Agreement will be due and payable, from July 25, 2008 to January 30, 2009 (the Loan
Termination Date). The date to which GasRock may, at its option, extend the GasRock Credit
Agreement was also extended from July 29, 2011
15
to January 30, 2013. The amendment also increased the initial commitment under the GasRock Credit
Agreement from $10,200 to $10,700.
The Company has received advances totaling $10,781 under the GasRock Credit Agreement, resulting in
net cash proceeds to the Company of $9,818 after the deduction of GasRocks facility fees,
investment banking fees, legal fees and other fees and expenses incurred by the Company in
connection with the GasRock Credit Agreement totaling $963. The Company has capitalized such fees
and expenses incurred in connection with the GasRock Credit Agreement as a deferred charge (asset)
that is being amortized over the initial term of the GasRock Credit Agreement using the interest
method.
For the term of the GasRock Credit Agreement ending on the Loan Termination Date, all amounts
outstanding under the GasRock 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 GasRock 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 Company is required to make monthly interest payments on the amounts outstanding under
the GasRock Credit Agreement based on available funds existing after deducting all monthly
operating expenses of the Companys wells from monthly revenue, as defined by the GasRock Credit
Agreement. Any accrued but unpaid interest and fees due each month during the first year of the
term of the GasRock Credit Agreement is included in the principal amount of the loan. As of April
30, 2008, approximately $1,005 of interest and fees incurred to date has been added to the
principal amount of the loan. The Company is not required to make any principal payments until the
Loan Termination Date. The Company may prepay the amounts outstanding under the GasRock Credit
Agreement at any time without penalty.
The Company is required to pay GasRock a facility fee upon the receipt of any advances under the
GasRock Credit Agreement in an amount equal to 2% of the amount advanced. The Company is also
required to reimburse GasRock for all of the expenses incurred by GasRock in connection with
entering into and administering the GasRock Credit Agreement. The facility fee related to the
initial advance and GasRocks expenses in connection with entering into the GasRock Credit
Agreement were included in the principal amount of the initial advance.
The Companys obligations under the GasRock Credit Agreement are secured by a first priority
security interest in substantially all of the Companys properties and assets, including all of the
Companys CBM rights under its leases, farm-out agreements and fee interests, all of the Companys
wells at its Southern Illinois Basin Project, all of the Companys equipment, and all of the common
stock of BPI Energy. A guaranty of all of BPI Energys obligations under the GasRock Credit
Agreement was provided by BPI Energy Holdings, Inc.
In connection with the execution of the GasRock Credit Agreement, the Company granted GasRock a 1%
royalty in all CBM produced and saved from the Companys existing leased and owned CBM properties
and an additional 4% royalty interest in all CBM produced and saved from the Companys existing
wells at its Southern Illinois Basin Project. As long as any of the Companys obligations remain
outstanding under the GasRock Credit Agreement, the Company will be required to grant the same 1%
royalty interest to GasRock on new mineral interests acquired by the Company and the same 4%
royalty interest on new wells drilled by the Company that are funded by draws under the GasRock
Credit Agreement. The Company estimated the fair value of the royalty interests granted to GasRock
to be approximately $600 and recorded this amount as a debt discount. The debt discount is being
amortized as an adjustment to interest expense over the life of the loan using the interest method.
The Company recorded approximately $124 and $275 of non-cash amortization expense related to the
debt discount during the three and nine months ended April 30, 2008, respectively. The amortization
was included as interest expense subject to capitalization as unproved gas properties during the
three and nine months ended April 30, 2008; however, no interest was capitalized during the
current quarter. The unamortized amount of the debt discount of $325 and $600 at April 30, 2008 and
July 31, 2007, respectively, is deducted directly from long-term debt reflected in the unaudited
consolidated balance sheets as of each period-end.
BPI Energy is subject to various restrictive covenants under the GasRock 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 GasRock Credit
16
Agreement and excluding from current assets and current liabilities any unrealized gains and losses
from unliquidated commodity derivative contracts 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. Although the Company believes it is in compliance with its debt covenants as of April
30, 2008, it is very likely that the Company will be in breach of the current ratio covenant in the
near term if the Company does not obtain financing.
The GasRock Credit Agreement contains customary events of default. In addition, GasRock may declare
an event of default if, at any time after July 25, 2008, the Companys most recent reserve report
indicates that (i) the Companys projected net revenue attributable to its proved reserves is
insufficient to fully amortize the amounts outstanding under the GasRock Credit Agreement within a
48-month period and (ii) the Company is unable to demonstrate to GasRocks reasonable satisfaction
that the Company would be able to satisfy such outstanding amounts through a sale of the Companys
assets or equity.
The
GasRock Credit Agreement also contains an event of default if James
E. Craddock, the Companys former
Chief Operating Officer, ceases to be materially involved in the management of the Company and is
not replaced within 90 days with a person acceptable to GasRock. Mr. Craddock resigned as the
Companys Chief Operating Officer effective March 31, 2008. Although Mr. Craddock will continue to
make himself available as a technical advisor to the Companys Board of Directors as needed to
assist in an orderly transition and further advance the Companys development and financing efforts
through September 30, 2008, the Company has not replaced Mr. Craddock as Chief Operating
Officer. The Company promptly notified GasRock of Mr. Craddocks resignation. However, GasRock has
not formally advised the Company as to whether they intend to consider this an event of default
should the Company fail to replace Mr. Craddock with a person acceptable to GasRock within the
90-day period allowed (by June 29, 2008).
Upon the occurrence of an event of default under the GasRock Credit Agreement, GasRock may
accelerate the Companys outstanding obligations. Upon certain events of bankruptcy, the Companys
obligations under the GasRock Credit Agreement would automatically accelerate. In addition, at any
time that an event of default exists under the GasRock Credit Agreement, the Company will be
required to pay interest on all amounts outstanding under the GasRock Credit Agreement at a default
rate, which is equal to the then-prevailing interest rate under the GasRock Credit Agreement plus
4% per annum.
In addition to the loans outstanding under the GasRock Credit Agreement, the Company has
outstanding term notes payable related to vehicles and equipment. The term notes are collateralized
by the related vehicles and equipment. Following is a summary of all long-term debt and notes
payable outstanding at April 30, 2008 and July 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
April 30,
|
|
|
July 31,
|
|
|
|
2008
|
|
|
2007
|
|
Advances under GasRock Credit Agreement
|
|
$
|
11,732
|
|
|
$
|
9,060
|
|
GMAC term note due in fiscal year 2009, 6.50%
|
|
|
10
|
|
|
|
14
|
|
GMAC term notes due in fiscal year 2010, 6.1% to 6.50%
|
|
|
52
|
|
|
|
62
|
|
|
|
|
|
|
|
|
|
|
|
11,794
|
|
|
|
9,136
|
|
Less unamortized debt discount
|
|
|
(325
|
)
|
|
|
(600
|
)
|
Less current maturities
|
|
|
(11,434
|
)
|
|
|
(8,488
|
)
|
|
|
|
|
|
|
|
Long-term debt and notes payable
|
|
$
|
35
|
|
|
$
|
48
|
|
|
|
|
|
|
|
|
The annual principal maturities of advances under the GasRock Credit Agreement and the long-term
notes payable for periods subsequent to April 30, 2008 are as follows:
|
|
|
|
|
Remaining Fiscal Year 2008
|
|
$
|
10
|
|
Fiscal Year 2009
|
|
|
11,761
|
|
Fiscal Year 2010
|
|
|
23
|
|
|
|
|
|
|
|
$
|
11,794
|
|
|
|
|
|
17
7. 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 obligations for the
nine months ended April 30, 2008 and 2007, respectively:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended April 30,
|
|
|
|
2008
|
|
|
2007
|
|
Beginning asset retirement obligation
|
|
$
|
114
|
|
|
$
|
71
|
|
Additional liability incurred
|
|
|
19
|
|
|
|
7
|
|
Accretion expense
|
|
|
7
|
|
|
|
3
|
|
Change in estimate
|
|
|
33
|
|
|
|
35
|
|
Asset retirement costs incurred
|
|
|
(58
|
)
|
|
|
(36
|
)
|
Loss on settlement of liability
|
|
|
46
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
$
|
161
|
|
|
$
|
97
|
|
|
|
|
|
|
|
|
8. CONCENTRATIONS
Financial instruments that potentially subject the Company to concentrations of credit risk consist
of cash and cash equivalents, which are held at one large high quality financial institution. The
Company periodically evaluates the credit worthiness of the financial institution. The Company has
not incurred any credit risk losses related to its cash and cash equivalents.
The Company utilizes a limited number of drilling contractors to perform all of the drilling on its
projects. The Company maintains a limited number of supervisory and field personnel to oversee
drilling and production operations. The 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 ensuring that 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.
9. INCOME TAXES
The Company files income tax returns in the U.S. federal jurisdiction, in Canada and in the State
of Illinois. Primarily as a result of the net operating losses that the Company has generated, the
Company has substantial net operating loss carryforwards (NOL Carryforwards) in all tax
jurisdictions in which it files, none of which have been recognized for financial statement
purposes. These NOL Carryforwards and other deferred tax benefits generated by the Company are
available for tax purposes to offset net income in future periods. Although the Company has never
been audited by any taxing authority, when and if the Company uses its NOL Carryforwards, they will
be subject to audit and potential adjustment by the respective taxing authority. FASB Statement 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 April 30, 2008.
18
10. SHAREHOLDERS EQUITY
Common shares
The Company has authorized 200,000,000 shares without par value, of which
73,484,395 and 72,524,493 were issued and outstanding as of April 30, 2008 and July 31, 2007,
respectively. Shares issued and outstanding at April 30, 2008 and July 31, 2007 include 1,433,438
and 2,437,338 restricted shares, respectively, expected to vest in future periods.
Additional paid-in capital
Amounts recorded of $8,421 and $7,608 at April 30, 2008 and July 31,
2007, respectively, represent the cumulative amounts of share-based compensation as of the end of
each period.
Share purchase warrants
During fiscal year 2005, the Company issued 10,372,000 shares at $1.25
per share with 5,186,000 share purchase warrants exercisable at $1.50 for a period of two years
(Investor Warrants). The Companys agent received a commission of 5% and 1,037,200 broker
warrants exercisable at $1.25 for a period of two years (Agent Warrants). The shares and
warrants, when issued, were restricted under the Securities Act of 1933, as amended, and the
Company was required to register the resale of the shares and the shares underlying the warrants
with the Securities and Exchange Commission. Upon registration of the shares underlying the
warrants and the delisting of such shares from the TSX Venture Exchange, the Investor Warrants were
extended to be exercisable for two years after such listing and the Agent Warrants were extended to
be exercisable for five years after the closing of the share placement. The Investor Warrants
expired on December 13, 2007. Share purchase warrants outstanding at April 30, 2008 are as
follows:
|
|
|
|
|
Number
|
|
Exercise
|
|
|
Outstanding
|
|
Price
|
|
Expiry Date
|
643,200
|
|
$1.25
|
|
December 31, 2009
|
394,000
|
|
$1.25
|
|
January 12, 2010
|
1,037,200
|
|
|
|
|
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
CBM. 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 in expense reimbursement related to this
arrangement during the nine months ended April 30, 2008 and 2007, respectively.
David Preng, a director of the Company, is an owner of Preng & Associates, an executive search firm
specializing in the energy and natural resources industries. The Company paid Preng & Associates $0
and approximately $13 for executive placement services during the nine months ended April 30, 2008
and 2007, respectively.
12. LEGAL PROCEEDINGS
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
19
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, 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 BPIs
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 courts 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 parties are currently engaged in written
discovery. During the course of discovery, defendants produced an additional agreement between BPI
and Christian that BPI believes supports an additional claim for breach of contract, and as a
result, BPI filed a Third Amended Complaint. The Defendants then moved to stay the case pending
arbitration on the basis that the agreement contains an arbitration provision. The court denied
that motion. Defendants have also filed two partial motions to dismiss various claims in the Third
Amended Complaint. The first partial motion to dismiss has been fully briefed and is awaiting the
courts decision. The second partial motion to dismiss will be ready for a ruling later this
summer. The Company anticipates that if the Court denies all or part of the motions 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.
The Company believes 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, the Company believes that it will
be successful in defending against their claims of breach. However, there can be no assurance that
the Company will be successful in maintaining these acreage rights. The loss of these acreage
rights would not have a material impact on the Companys 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
20
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 the leases were executed and that there
is a lack of mutuality under the leases. BPI denied ICGs claims, and moved for summary judgment.
On May 20, 2008, the court granted BPIs motion, finding the leases to be valid. ICG has not yet
indicated whether it will appeal this decision.
BPI has drilled 10 pilot wells, one water disposal well and three test wells on the acreage covered
by the farm-out agreement. In February 2008, BPI shut down its Macoupin pilot and suspended testing
in Perry County in response to a demand by ICG that it do so until the litigation is resolved.
The Company believes that if ICG elects to continue to pursue this litigation by appealing the
courts decision to grant summary judgment, BPI will ultimately be successful in defending against
ICGs claims; however, there can be no assurance that BPI will ultimately be successful in
retaining the acreage under this farm-out agreement. The loss of these acreage rights would not
have a material impact on the Companys financial position, results of operations or cash flows.
13. OTHER EXPENSE, NET
Other expense, net consisted of the following for the three and nine months ended April 30, 2008,
respectively:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
April 30, 2008
|
|
|
April 30, 2008
|
|
Gain on
settlements of derivative contracts
|
|
$
|
|
|
|
$
|
41
|
|
Change in
fair value of derivative contracts
|
|
|
(329
|
)
|
|
|
(345
|
)
|
Other
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(323
|
)
|
|
$
|
(304
|
)
|
|
|
|
|
|
|
|
Other income (expense) was $0 for both the three and nine months ended April 30, 2007.
14. SUBSEQUENT EVENT
On June 9, 2008, the Company entered into an arrangement with BP whereby its costless collar
contracts described above for the notional amount of 20,000 MMBtus per month through July 31, 2009
were cancelled effective July 1, 2008 and replaced with a swap agreement at a fixed price of $10.26
per MMBtu (based on NYMEX final settlement) for the notional amount of 20,000 MMBtus per month
beginning July 1, 2008 through July 31, 2010 (500,000 MMBtus in total). The contract is
net-settled on a monthly basis, meaning that if the NYMEX final settlement price for a month is
below $10.26 per MMBtu, BP will pay the Company the difference in price multiplied by the notional
amount for the month, and if the NYMEX final settlement price for a month is above $10.26 per
MMBtu, the Company will pay BP the difference in price multiplied by the notional amount for the
month. This transaction did not materially impact the Companys consolidated financial statements.
Item 2. 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 under Item 1.
Overview and Outlook
We are an independent energy company incorporated under the laws of British Columbia, Canada and
primarily engaged, through our wholly owned U.S. subsidiary, BPI Energy, Inc., in the exploration,
production and commercial sale of coalbed methane (CBM). Our exploration and production efforts
are concentrated in the Illinois Basin (the Basin), which encompasses a total area of
approximately 60,000 square miles 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.
21
As of April 30, 2008, we owned or controlled CBM rights, through mineral leases, a farm-out
agreement and ownership of a CBM estate, covering approximately 531,000 total acres in the Basin
(approximately 98% of this acreage is undeveloped as of April 30, 2008). This total reflects an
increase of approximately 2,000 acres in the second quarter of fiscal year 2008. Portions of our
CBM rights are currently subject to litigation, as discussed in Item 1 of Part II below. 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 during fiscal year 2005 (January 2005) and net gas sales volume for that fiscal
year was 17,885 thousand cubic feet (Mcf). Since then, net sales volume has steadily grown to
135,118 Mcf in fiscal year 2006 and 185,305 Mcf in fiscal year 2007. During the current quarter,
net gas sales volume increased approximately 32% from the third quarter of fiscal year 2007 and
decreased approximately 1% from the previous quarter. We received an average price of $8.38 per Mcf
for gas sales of 63.9 million cubic feet (MMcf) during the current quarter versus an average
price of $6.81 per Mcf on sales of 48.6 MMcf during the same prior-year period and an average price
of $6.79 per Mcf on sales of 64.5 MMcf during the second quarter of fiscal year 2008. Third
quarter of fiscal year 2008 net revenues from gas sales increased to $535,467 from the $334,706
generated in the same period a year ago and $437,866 in the second quarter of fiscal year 2008.
During the first nine months of fiscal year 2008, net gas sales volume increased approximately 35%
from the first nine months of fiscal year 2007. We received an average price of $6.97 per Mcf for
gas sales of 185.2 MMcf during the first nine months of the current fiscal year versus an average
of $6.34 per Mcf on sales of 137.4 MMcf during the same prior-year period. Net revenues from gas
sales increased to $1,291,520 from $875,615 generated during the first nine months of fiscal year
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. Since the last quarter of fiscal year 2007, we have
increased our acreage by approximately 31,000 acres, a 6% increase in total acreage. However, we
have committed
22
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 recognize we need to obtain additional capital, resources and
technical expertise.
In July 2007, we entered into a $75 million Advancing Term Credit Agreement (the GasRock Credit
Agreement) with GasRock Capital LLC (GasRock). The initial commitment under this agreement was
$10.2 million, of which we drew $9.1 million at closing. In the first quarter of fiscal year 2008,
GasRock increased the initial commitment to $10.7 million and extended the initial term of the
GasRock Credit Agreement to January 30, 2009. As of April 30, 2008, we have drawn the entire $10.7
million commitment. We currently have a request pending with GasRock for an additional commitment
to fund our cash shortfall through the end of fiscal year 2008 along with a request for capital
development funds for new development activities. All advances under the GasRock Credit Agreement
are at the sole discretion of GasRock.
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 531,000-acre leasehold position.
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. All 12 wells were drilled, completed and
started pumping by July 2007. To date, we have not seen encouraging results from this pilot
project. As discussed in Part II, Item 1 below, the acreage comprising the Macoupin Pilot has been
the subject of litigation and, in February 2008, we shut down the project in response to a demand
by other parties in the litigation that we do so until the litigation is resolved.
As of April 30, 2008, we determined that all of our unproved properties, which include the Shelby
and Macoupin Pilots, are impaired under the full cost method of accounting for gas properties due
to the uncertainty as to whether we will be able to obtain the additional financing necessary to
(i) continue effectively evaluating such properties for a sufficient period of time and (ii)
commence development on such properties, if warranted, based on the results of our ongoing
evaluation. To the extent funds are available, we intend to continue monitoring pressure and
production results at the Shelby Pilot in order to try to determine the likelihood of commercial
success. We will reassess our plans for the Macoupin Pilot once the litigation is resolved.
We did not drill any new wells during the third quarter of fiscal year 2008, but have continued to
focus on high-grading the Basin and acquiring acreage in areas that we feel offer the highest
probability of success. We have also continued to focus on trying to improve our financial
condition by evaluating all options and engaging in discussions with potential funding sources and
transaction partners to raise the necessary funds to develop our acreage.
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
and we expect that such losses will continue in the near term. The primary costs that generate
these losses are compensation-related expenses and general and administrative expenses.
As of June 13, 2008, we have a cash balance of approximately $550,000 and accounts receivable (for
eligible expenses reimbursable from GasRock) of approximately $125,000. We estimate that our
accounts payable and accrued liabilities as of June 13, 2008 (excluding debt and loss position on
hedge contracts)
23
total approximately $1,200,000. A significant portion of our accounts payable and accrued
liabilities are past due and approximately 50% of the balance is owed to two vendors with whom we
are in discussions to negotiate extended payment terms. We are currently paying our lease
operating expenses from a portion of our sales that are reimbursed by GasRock, so our production
operations are not currently affected. However, we are not able to pay general and administrative
expenses from such funds. We are not currently drilling new wells; however, based on our current
working capital situation, we need to raise cash in the near term in order to be able to settle our
accounts payable and accrued liabilities and to fund future operations. We have made substantial
reductions in our general and administrative expenses during the third quarter of fiscal year 2008
but we do not have the ability to reduce costs sufficiently to obtain positive cash flow from
operations. We currently have a request pending with GasRock to fund our cash shortfall through
the end of fiscal year 2008 along with a request for capital development funds for new development
activities. All advances under the GasRock Credit Agreement are at the sole discretion of GasRock.
In addition, we are currently evaluating what additional options are available to finance current
and future operations. We have explored additional potential funding sources, including the
issuance of new debt and/or equity securities, joint ventures, mergers/combinations, asset sales
and selling rights relating to our litigation against Drummond, but to date have not been
successful in obtaining additional funding. We are still exploring all of these options and we are
engaging in discussions with a company that may provide additional development funds to expand our
Southern Illinois Basin Project. However, we do not believe such funds would provide any
significant reimbursement for general and administrative expenses and can provide no assurance that
we will be successful in completing this or any other financing transaction. If we cannot raise
adequate funds in the near term, we may have to cease operations and liquidate.
Managements current focus is to raise the necessary capital to continue as a going concern so that
we may continue focusing on our business strategy.
In addition to our immediate need to raise cash, there are several factors, over which we have
little or no control, which could impact our future economic success. These factors include natural
gas prices, limitations imposed by the terms and conditions of our lease agreements, possible court
rulings concerning our property interests in CBM, availability of drilling rigs, operating costs,
and environmental and other regulatory matters. In our planning process, we have attempted to
address these issues by:
|
|
|
negotiating to obtain leases that grant us the broadest possible rights to CBM for
any given tract of land;
|
|
|
|
|
conducting ongoing title reviews of existing mineral interests;
|
|
|
|
|
where possible, negotiating with and utilizing multiple service companies in order to
increase competition and minimize the risk of disruptions caused by the loss of any one
service provider; and
|
|
|
|
|
attempting to create a low cost structure in order to reduce our vulnerability to
many of these factors.
|
24
Results of Operations
Three Months Ended April 30, 2008 Compared to Three Months Ended April 30, 2007
The following table presents our unaudited financial data for the third quarter of fiscal year 2008
compared to the third quarter of fiscal year 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended April 30,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2008
|
|
|
2007
|
|
|
Variance
|
|
|
Change
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
535,467
|
|
|
$
|
334,706
|
|
|
$
|
200,761
|
|
|
|
60
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
402,571
|
|
|
|
411,938
|
|
|
|
(9,367
|
)
|
|
|
(2
|
%)
|
General and administrative expense
|
|
|
1,250,359
|
|
|
|
1,885,061
|
|
|
|
(634,702
|
)
|
|
|
(34
|
%)
|
Lease rentals and other operating expense
|
|
|
168,142
|
|
|
|
|
|
|
|
168,142
|
|
|
|
100
|
%
|
Depreciation, depletion and amortization
|
|
|
203,989
|
|
|
|
215,280
|
|
|
|
(11,291
|
)
|
|
|
(5
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
2,025,061
|
|
|
|
2,512,279
|
|
|
|
(487,218
|
)
|
|
|
(19
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(1,489,594
|
)
|
|
|
(2,177,573
|
)
|
|
|
687,979
|
|
|
|
(32
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
10,214
|
|
|
|
108,660
|
|
|
|
(98,446
|
)
|
|
|
(91
|
%)
|
Interest expense
|
|
|
(734,570
|
)
|
|
|
(1,437
|
)
|
|
|
(733,133
|
)
|
|
|
(51,018
|
%)
|
Other expense, net
|
|
|
(322,571
|
)
|
|
|
|
|
|
|
(322,571
|
)
|
|
|
(100
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net
|
|
|
(1,046,927
|
)
|
|
|
107,223
|
|
|
|
(1,154,150
|
)
|
|
|
(1,071
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(2,536,521
|
)
|
|
$
|
(2,070,350
|
)
|
|
$
|
(466,172
|
)
|
|
|
(23
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
During the third quarter of fiscal year 2008, net gas sales increased $200,761 compared
to the third quarter of fiscal year 2007. Net sales of gas (net of royalties) were 63,897 Mcf for
the third quarter of fiscal year 2008, or approximately 32% higher, compared to 48,558 Mcf for the
third quarter of fiscal year 2007. Our average realized selling price per Mcf was $8.38 for the
third quarter of fiscal year 2008, compared to $6.81 for the third quarter of fiscal year 2007.
Lease operating expense
During the third quarter of fiscal year 2008, lease operating expense
decreased $9,367 compared to the third quarter of fiscal year 2007. Lease operating expense
represents production expenses, consisting primarily of repairs and maintenance, fuel and
electricity, equipment rental, workovers and labor and overhead expenses related to producing
wells. The decrease is primarily due to non-recurring repairs and maintenance that occurred during
the third quarter of fiscal year 2007.
General and administrative expense
General and administrative expense consisted of the following
for the third quarter of fiscal years 2008 and 2007, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months ended April 30,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2008
|
|
|
2007
|
|
|
Variance
|
|
|
Change
|
|
Salaries and benefits
|
|
$
|
275,026
|
|
|
$
|
956,479
|
|
|
$
|
(681,453
|
)
|
|
|
(71
|
%)
|
Share-based payments
|
|
|
189,376
|
|
|
|
211,381
|
|
|
|
(22,005
|
)
|
|
|
(10
|
%)
|
Professional and regulatory
|
|
|
587,763
|
|
|
|
479,373
|
|
|
|
108,390
|
|
|
|
23
|
%
|
Other
|
|
|
198,194
|
|
|
|
237,828
|
|
|
|
(39,634
|
)
|
|
|
(17
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expense
|
|
$
|
1,250,359
|
|
|
$
|
1,885,061
|
|
|
$
|
(634,702
|
)
|
|
|
(34
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the third quarter of fiscal year 2008, salaries and benefits decreased $681,453 compared to
the third quarter of fiscal year 2007. The net decrease primarily relates to lower salaries and
accrued bonuses during the current quarter. Our Chief Operating Officer and two engineers resigned
during the current quarter and one engineer resigned in the previous quarter, which reduced base
salaries by approximately $80,000
25
during the current quarter and is expected to reduce base salaries by approximately $175,000 per
quarter going forward. Salaries and benefits included $500,000 of expense for accrued bonuses
(annual deferred compensation) in the third quarter of fiscal year 2007, whereas accrued bonuses of
approximately $90,000 were eliminated in the current quarter. The elimination of accrued bonuses
in the current quarter reflects the downsizing of our technical staff and our current working
capital situation.
During the third quarter of fiscal year 2008, non-cash expense associated with share-based payments
decreased $22,005 compared to the third quarter of fiscal year 2007. Share-based payments for the
third quarter of fiscal year 2008 represent $97,876 of expense recognized on a pro rata basis for
the anticipated vesting of restricted shares outstanding and $91,500 of expense recognized for
directors fees. Share-based payments for the third quarter of fiscal year 2007 consisted solely
of expense recognized on a pro rata basis for the anticipated vesting of restricted shares
outstanding. The reduction in expense recognized on a pro rata basis for the anticipated vesting
of restricted shares outstanding decreased due to forfeitures primarily resulting from the
resignation of our Chief Operating Officer and two engineers during the current quarter and the
resignation of one engineer in the previous quarter. 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.
During the third quarter of fiscal year 2008, professional and regulatory expenses increased
$108,390 compared to the third quarter of fiscal year 2007. The net increase is due to higher legal
fees of approximately $250,000, primarily incurred in connection with litigation, and higher
reserve engineering consulting fees of approximately $30,000, offset by lower information
technology consulting costs fees of approximately $40,000, lower investor relations expenses of
approximately $34,000, lower American Stock Exchange (AMEX) listing fees (due to timing) of
approximately $33,000, and net lower other professional fees totaling approximately $65,000.
During the third quarter of fiscal year 2008, other general and administrative expenses decreased
$39,634 compared to the third quarter of fiscal year 2007. Other general and administrative
expenses consist of rent, travel related expenses, telephone and utilities, other office expenses
and non-cash amortization of costs capitalized in connection with the separation agreement entered
into with our former Chief Financial Officer in October 2006. The net decrease is due primarily to
lower non-cash amortization of costs capitalized in connection with the separation agreement.
Lease rentals and other operating expense
During the third quarter of fiscal year 2008, lease
rentals and other operating expense increased $168,142 compared to the third quarter of fiscal year
2007. Lease rentals and other operating expense during the current quarter represents the write-off
of lease bonuses and minimum lease rentals that are recoverable from future production royalties
and that were recorded as advance royalties on the consolidated balance sheets. We wrote-off this
amount during the current quarter due to the uncertainty associated with future development of the related
leases.
Depreciation, depletion and amortization expense
During the third quarter of fiscal year 2008,
depreciation, depletion and amortization (DD&A) decreased $11,291 compared to the third quarter
of fiscal year 2007. We compute DD&A on capitalized acquisition and development costs using the
units-of-production method based on estimates of proved reserves, and on other property and
equipment using the straight-line method based on estimated useful lives ranging from three to five
years. The net decrease primarily resulted from the decrease in capitalized development costs due
to a ceiling write-down of $11,722,153 at July 31, 2007 and the sale of vehicles in connection with
the downsizing of our technical staff, partially offset by an increase in depletion expense due to
the reclassification of costs in the amount of $9,846,230 associated with unevaluated properties to
the full cost pool during the current quarter and increased production during the third quarter of
fiscal year 2008.
Interest income
During the third quarter of fiscal year 2008, interest income decreased $98,446
compared to the third quarter of fiscal year 2007 due to significantly lower average cash balances
during the third quarter of fiscal year 2008.
26
Interest expense
During the third quarter of fiscal year 2008, interest expense increased
$733,133 compared to the third quarter of fiscal year 2007. Interest expense during the current
quarter includes amortization of deferred financing costs and debt discount. This increase is due
to the increase in debt outstanding under the GasRock Credit Agreement entered into on July 27,
2007.
Other expense
During the third quarter of fiscal year 2008, other expense increased $322,571
compared to the third quarter of fiscal year 2007. We recognized a $329,000 unrealized loss
related to the change in fair value of our commodity derivative contracts during the current
quarter.
Nine Months Ended April 30, 2008 Compared to Nine Months Ended April 30, 2007
The following table presents our unaudited financial data for the first nine months of fiscal year
2008 compared to the first nine months of fiscal year 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months Ended April 30,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2008
|
|
|
2007
|
|
|
Variance
|
|
|
Change
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
1,291,520
|
|
|
$
|
875,615
|
|
|
$
|
415,905
|
|
|
|
47
|
%
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
1,038,065
|
|
|
|
1,275,685
|
|
|
|
(237,620
|
)
|
|
|
(19
|
%)
|
General and administrative expense
|
|
|
4,653,830
|
|
|
|
6,089,287
|
|
|
|
(1,435,457
|
)
|
|
|
(24
|
%)
|
Lease rentals and other operating expense
|
|
|
246,982
|
|
|
|
|
|
|
|
246,982
|
|
|
|
100
|
%
|
Depreciation, depletion and amortization
|
|
|
551,872
|
|
|
|
591,275
|
|
|
|
(39,403
|
)
|
|
|
(7
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
6,490,749
|
|
|
|
7,956,247
|
|
|
|
(1,465,499
|
)
|
|
|
(18
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(5,199,229
|
)
|
|
|
(7,080,632
|
)
|
|
|
1,881.404
|
|
|
|
27
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
140,745
|
|
|
|
493,982
|
|
|
|
(353,237
|
)
|
|
|
(72
|
%)
|
Interest expense
|
|
|
(766,764
|
)
|
|
|
(7,616
|
)
|
|
|
(759,148
|
)
|
|
|
(9,968
|
%)
|
Other expense, net
|
|
|
(304,394
|
)
|
|
|
|
|
|
|
(304,394
|
)
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net
|
|
|
(930,413
|
)
|
|
|
486,366
|
|
|
|
(1,416,779
|
)
|
|
|
(291
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(6,129,642
|
)
|
|
$
|
(6,594,266
|
)
|
|
$
|
464,625
|
|
|
|
(7
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
During the first nine months of fiscal year 2008, revenue increased $415,905 compared to
the first nine months of fiscal year 2007. Net sales of gas (net of royalties) were 185,210 Mcf for
the first nine months of fiscal year 2008, or approximately 35% higher, compared to 137,400 Mcf for
the first nine months of 2007. Our average realized selling price per Mcf was $6.97 for the first
nine months of fiscal year 2008 compared to $6.34 for the first nine months of fiscal year 2007.
Lease operating expense
During the first nine months of fiscal year 2008, lease operating expense
decreased $237,620 compared to the first nine months of fiscal year 2007. Lease operating expense
represents production expenses, consisting primarily of repairs and maintenance, fuel and
electricity, equipment rental, workovers and labor and overhead expenses related to producing
wells. The decrease is primarily due to non-recurring repairs and maintenance that occurred during
the first nine months of fiscal year 2007.
27
General and administrative expense
General and administrative expense consisted of the following
for the first nine months of fiscal years 2008 and 2007, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended April 30,
|
|
|
Dollar
|
|
|
%
|
|
|
|
2008
|
|
|
2007
|
|
|
Variance
|
|
|
Change
|
|
Salaries and benefits
|
|
$
|
1,292,853
|
|
|
$
|
2,526,871
|
|
|
$
|
(1,234,018
|
)
|
|
|
(49
|
%)
|
Share-based payments
|
|
|
860,856
|
|
|
|
1,088,684
|
|
|
|
(227,828
|
)
|
|
|
(21
|
%)
|
Professional and regulatory
|
|
|
1,816,709
|
|
|
|
1,797,909
|
|
|
|
18,800
|
|
|
|
1
|
%
|
Other
|
|
|
683,412
|
|
|
|
675,823
|
|
|
|
7,589
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expense
|
|
$
|
4,653,830
|
|
|
$
|
6,089,287
|
|
|
$
|
(1,435,457
|
)
|
|
|
(24
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the first nine months of fiscal year 2008, salaries and benefits decreased $1,234,018
compared to the first nine months of fiscal year 2007. The net decrease primarily reflects lower
salaries and accrued bonuses during the current fiscal year. Our Chief Operating Officer and three
engineers resigned during the current fiscal quarter, which reduced base salaries by approximately
$80,000 during the first nine months of fiscal year 2008 and is expected to reduce base salaries by
approximately $685,000 on an annual basis. In addition, salaries and benefits for the first nine
months of fiscal year 2007 included $500,000 of accrued bonuses, $350,000 of cash signing bonuses
paid to newly hired members of our technical team and $300,000 of salaries and severance paid to
our former Chief Financial Officer. The reduction in accrued bonuses during the current fiscal year
reflects the downsizing of our technical staff and our current working capital situation.
During the first nine months of fiscal year 2008, expense associated with share-based payments
decreased $227,828 compared to the first nine months of fiscal year 2007. Share-based payments for
the first nine months of fiscal year 2008 represent $575,856 of expense recognized on a pro rata
basis for the anticipated vesting of restricted shares outstanding and $285,000 of expense
recognized for directors fees. Share-based payments for the first nine months of fiscal year 2007
represent $619,075 of expense recognized on a pro rata basis for the anticipated vesting of
restricted shares outstanding and $469,609 of expense related to the grant of fully vested shares
as inducement grants to newly hired members of our technical team, bonuses to officers and other
employees and fees to our directors. The reduction in expense recognized on a pro rata basis for
the anticipated vesting of restricted shares outstanding decreased due to forfeitures primarily
resulting from the resignation of our Chief Operating Officer and three engineers during the first
nine months of fiscal year 2008. 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.
During the first nine months of fiscal year 2008, professional and regulatory expenses increased
$18,800 compared to the first nine months of fiscal year 2007. The net increase is due to the
following (amounts are approximate): (i) higher legal fees of $510,000, primarily incurred in
connection with litigation, (ii) higher financial advisory fees of $100,000, (iii) higher AMEX fees
of $43,000, (iv) lower recruiting and relocation fees associated with hiring our technical staff in
fiscal year 2007 of $262,000, (v) lower cash-based directors fees (incurred as share-based
compensation expense during the first nine months of fiscal year 2008) of $135,000, (vi) lower
investor relations expenses of $110,000, (vii) lower information technology consulting costs of
$70,000, and (viii) lower accounting and other professional fees of $57,000.
During the first nine months of fiscal year 2008, other general and administrative expenses
increased $7,589 over the first nine months of fiscal year 2007. Other general and administrative
expenses consist of rent, travel related expenses, telephone and utilities, other office expenses
and non-cash amortization of costs capitalized in connection with the separation agreement entered
into with our former Chief Financial Officer in October 2006. The net increase is due primarily to
higher non-cash amortization expense associated with the separation agreement, partially offset by
lower travel related expenses.
Lease rentals and other operating expense
During the first nine months of fiscal year 2008, lease
rentals and other operating expense increased $246,982 compared to the first nine months of fiscal
year 2007.
28
Lease rentals and other operating
expense represents (i) minimum lease rentals and shut-in royalties totaling $32,825 that were
incurred on our leases during the current fiscal period and that are not recoverable from future
royalties, (ii) losses on settlement of asset retirement obligations (plugging wells) of $46,015,
and (iii) the write-off of lease bonuses and minimum lease rentals totaling $168,142 that were
incurred in prior fiscal periods and that are recoverable from future
production royalties. We recorded such amounts as advance royalties on the consolidated balance sheets, but wrote them
off during the current quarter due to the uncertainty associated with future development of the
related leases.
Depreciation, depletion and amortization expense
During the first nine months of fiscal year
2008, DD&A decreased $39,403 compared to the first nine months of fiscal year 2007. We compute
DD&A on capitalized acquisition and development costs using the units-of-production method based on
estimates of proved reserves, and on other property and equipment using the straight-line method
based on estimated useful lives ranging from three to five years. The net decrease primarily
resulted from the decrease in capitalized development costs due to a ceiling write-down of
$11,722,153 at July 31, 2007 and the sale of vehicles in connection with the downsizing of our
technical staff, partially offset by an increase in depletion expense due to the reclassification
of costs in the amount of $9,846,230 associated with unevaluated properties to the full cost pool
during the current quarter and increased production during the first nine months of fiscal year
2008.
Interest income
During the first nine months of fiscal year 2008, interest income decreased
$353,237 compared to the first nine months of fiscal year 2007 due to significantly lower average
cash balances during the first nine months of fiscal year 2008.
Interest expense
During the first nine months of fiscal year 2008, interest expense increased
$759,148 compared to the first nine months of fiscal year 2007. Interest incurred on debt during
the first nine months of fiscal year 2008, including amortization of deferred financing costs and
debt discount, was $1,850,026 compared to $7,616 in the comparable prior fiscal year period. This
increase is due to the increase in debt outstanding under the GasRock Credit Agreement entered into
on July 27, 2007. However, we capitalized $1,083,262 of interest expense incurred during the first
nine months of fiscal year 2008 to unproved gas properties in accordance with Statement of
Financial Accounting Standards No. 34, Capitalization of Interest Cost (SFAS No. 34).
Other expense
During the first nine months of fiscal year 2008, other expense increased $304,394
compared to the third quarter of fiscal year 2007. We recognized a $40,940 gain on settlements and
a $345,000 unrealized loss related to the change in fair value of our commodity derivative
contracts during the first nine months of fiscal year 2008.
Critical Accounting Policies and Estimates
Our unaudited consolidated financial statements and accompanying notes have been prepared in
accordance with accounting principles generally accepted in the United States. The preparation of
these financial statements requires our management to make estimates, judgments and assumptions
that affect reported amounts of assets, liabilities, revenues and expenses. On an ongoing basis, we
evaluate the accounting policies and estimates that we use to prepare financial statements. We base
our estimates on historical experience and assumptions believed to be reasonable under current
facts and circumstances. Actual amounts and results could differ from these estimates used by
management.
Certain accounting policies that require significant management estimates and are deemed critical
to our results of operations or financial position are discussed in Item 7 of our Annual Report on
Form 10-K for the fiscal year ended July 31, 2007. There were no material changes in these policies
during the current quarter; however, due to the addition of interest expense associated with the
GasRock credit facility, we began applying the following policy during the current fiscal year:
Capitalized Interest
In accordance with SFAS No. 34, we capitalize interest costs to gas properties on expenditures made
in connection with unproved properties that are not subject to current depletion. Interest is
capitalized only for the period that activities are in progress to bring these properties to their
intended use. Total interest expense incurred during the three and nine months ended April 30,
2008, including the amortization of deferred financing costs and debt discount, was $734,570 and
$1,850,026, respectively. Of these amounts,
29
interest costs capitalized to unproved gas properties during the three and nine months ended April
30, 2008 were $0 and $1,083,262, respectively. No interest costs were capitalized in the comparable
prior periods.
Financial Condition
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 the GasRock Credit Agreement, as amended on November 29, 2007.
The GasRock Credit Agreement provides for an initial commitment to us of $10.7 million and the
possibility of future advances to us of up to an additional $64.3 million. All future advances
under the GasRock Credit Agreement beyond the initial commitment will be made in GasRocks
discretion. We may request advances under the GasRock Credit Agreement at any time before January
30, 2009, which GasRock may in its discretion extend until January 30, 2011. All amounts then
outstanding under the GasRock Credit Agreement are due and payable on January 30, 2009, which
GasRock may in its discretion extend until January 30, 2013. We have received advances totaling
$10,780,719 under the GasRock Credit Agreement, resulting in net cash proceeds to us of $9,817,995
after the deduction of GasRocks facility fees, investment banking fees, legal fees and other fees
and expenses incurred by us in connection with the GasRock Credit Agreement totaling $962,724.
We did not begin to generate revenues from CBM sales until fiscal year 2005 (January 2005) and net
gas sales volume for that fiscal year was only 17,885 Mcf. Since then, net sales volume has
steadily grown to 135,118 Mcf in fiscal year 2006, 185,305 Mcf in fiscal year 2007 and 185,210 Mcf
in the first nine months of fiscal year 2008, compared to 137,400 Mcf in the first nine months of
fiscal year 2007. Subject to the various risks described in this report, we expect revenue from
the sale of our CBM to continue to increase due to (i) increased production from existing wells as
they continue to dewater and (ii) additional production generated as a result of drilling and
production from additional wells. However, in view of our limited 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
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. Additionally, net cash generated (used) by operating activities is dependent on a
number of factors over which we have little or no control. These factors include, but are not
limited to:
|
|
|
the price of, and demand for, natural gas;
|
|
|
|
|
availability of drilling equipment;
|
|
|
|
|
lease terms;
|
|
|
|
|
availability of sufficient capital resources; and
|
|
|
|
|
the accuracy of production estimates for current and future wells.
|
We had a cash balance of $1,080,633 as of April 30, 2008, compared to $11,291,575 at July 31, 2007.
The net decrease in our cash balance is the result of net cash used in operating activities of
$4,495,915, consisting primarily of payments for salaries and benefits, professional fees and lease
operating expenses, adjusted for changes in working capital, net cash used in investing activities
of $7,246,295, consisting of capital expenditures related primarily to development costs, and net
cash provided by financing activities of $1,531,268, consisting of $1,721,152 in additional
borrowings from GasRock, less $127,070 of financing related costs associated with the GasRock
Credit Agreement, $14,562 of payments on term notes and $48,252 of tax payments related to the
vesting of employees common shares, which the employees surrendered to satisfy tax withholding
obligations.
30
We have experienced significant losses in recent periods and, as of June 13, 2008, we have a cash
balance of approximately $550,000 and accounts receivable (for eligible expenses reimbursable from
GasRock) of approximately $125,000. We estimate that our accounts payable and accrued liabilities
as of June 13, 2008 (excluding debt and loss position on hedge contracts) total approximately
$1,200,000. A significant portion of our accounts payable and accrued liabilities are past due and
approximately 50% of the balance is owed to two vendors with whom we are in discussions to
negotiate extended payment terms. We are currently paying our lease operating expenses from a
portion of our sales that are reimbursed by GasRock, so our production operations are not currently
affected. However, we are not able to pay general and administrative expenses from such funds. We
have made substantial reductions in our general and administrative expenses during the third
quarter of fiscal year 2008 but we do not have the ability to reduce costs sufficiently to obtain
positive cash flow from operations. We are not currently drilling new wells; however, based on our
current working capital situation, we need to raise cash in the near term in order to be able to
settle our accounts payable and accrued liabilities and to fund
future operations. In order to continue as a going concern, we
must be able to finance our current operations, pay amounts due under the GasRock Credit Agreement
when such amounts become due on January 30, 2009 and finance any future exploration and development
costs.
The GasRock Credit Agreement contains an event of default if James E. Craddock, our former Chief
Operating Officer, ceases to be materially involved in our management and is not replaced within 90
days with a person acceptable to GasRock. Mr. Craddock resigned as our Chief Operating Officer
effective March 31, 2008. Although Mr. Craddock will continue to make himself available as a
technical advisor to our Board of Directors as needed to assist in an orderly transition and
further advance our development and financing efforts through September 30, 2008, we
have not replaced Mr. Craddock as Chief Operating Officer. We promptly notified GasRock of Mr. Craddocks
resignation. However, GasRock has not formally advised us as to whether they intend to consider
this an event of default should we fail to replace Mr. Craddock with a person acceptable to GasRock
within the 90-day period allowed (by June 29, 2008).
In addition, the GasRock Credit Agreement requires us to maintain a current ratio of 1.0, excluding
from the calculation of current liabilities any advances outstanding under the GasRock Credit
Agreement and excluding from current assets and current liabilities any unrealized gains and losses
from unliquidated commodity derivative contracts. Although we believe that we are in compliance
with this covenant as of June 13, 2008, it is very likely that we will be in breach of this
covenant in the near term if we do not obtain financing.
Upon the occurrence of an event of default under the GasRock Credit Agreement, GasRock may
accelerate our outstanding obligations. In addition, at any time that an event of default exists
under the GasRock Credit Agreement, we will have to pay interest on all amounts outstanding under
the GasRock Credit Agreement at a default rate, which is equal to the then-prevailing interest rate
under the GasRock Credit Agreement plus 4% per annum.
We have historically financed our activities primarily from the proceeds of private placements of
our common shares and most recently from advances under the GasRock Credit Agreement. We currently
have a request pending with GasRock to fund our cash shortfall through the end of fiscal 2008 along
with a request for capital development funds for new development activities. GasRock has sole
discretion over all future advances under the GasRock Credit Agreement.
In addition, we are currently evaluating what additional options are available to finance current
and future operations and to be able to pay amounts due under the GasRock Credit Agreement when
such amounts become due on January 30, 2009. We have explored additional potential funding sources,
including the issuance of new debt and/or equity securities, joint ventures, mergers/combinations,
asset sales and selling rights relating to our litigation against Drummond, but to date have not
been successful in obtaining additional funding. We are still exploring all of these options and
we are engaging in discussions with a company that may provide additional development funds to
expand our Southern Illinois Basin Project. However, we do not believe such funds would provide
any significant reimbursement for general and administrative expenses and can provide no assurance
that we will be successful in completing this or any
31
other financing transaction. If we cannot raise adequate funds in the near term, we may have to
cease operations and liquidate.
We have no contractual commitments for capital expenditures. Any future plans to drill new wells
and acquire additional CBM rights depend on (i) our ability to secure additional financing; (ii)
data obtained from test wells; (iii) data obtained from our pilot wells; and (iv) the risk factors
described in this report. We expect that any capital expenditure program we develop and our other
cash requirements will be funded by cash raised through additional financing sources, if available,
as previously discussed.
Cautionary Statement Concerning Forward-Looking Statements
Some of the statements contained in this report that are not historical facts, including statements
containing the words believes, anticipates, expects, intends, plans, should, may,
might, continue and estimate and similar words, constitute forward-looking statements under
the federal securities laws. These forward-looking statements involve known and unknown risks,
uncertainties and other factors that may cause our actual results, performance or achievements, or
the conditions in our industry, on our properties or in the Basin, to be materially different from
any future results, performance, achievements or conditions expressed or implied by such
forward-looking statements. Some of the factors that could cause actual results or conditions to
differ materially from our expectations, include, but are not limited to: (a) our inability to
raise the funds necessary to satisfy our existing accounts payable and accrued liabilities; (b) a
refusal by GasRock to make any additional advances under the GasRock Credit Agreement, which are in
GasRocks discretion; (c) our inability to repay or refinance the amounts advanced to us by GasRock
when such amounts become due on January 30, 2009; (d) a breach by us of a covenant under the
GasRock Credit Agreement or other event of default that allows GasRock to accelerate our
outstanding obligations; (e) our inability to obtain sufficient financing, close an offering of
debt or equity securities, or complete a merger/combination, joint venture, asset sale, selling of
rights relating to our litigation against Drummond or other transaction that would enable us to
fund our future operations; (f) our failure to accurately forecast CBM production; (g) a decline in
the prices that we receive for our CBM production; (h) 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; (i) our inability to attract or retain qualified personnel with the
requisite CBM or other experience; (j) unexpected economic and market conditions, in the general
economy or the market for natural gas; (k) limitations imposed on us by the GasRock Credit
Agreement; and (l) potential exposure to losses caused by our
derivative contracts. We caution
readers not to place undue reliance on these forward-looking statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Commodity Risk
Our major risk exposure is the commodity pricing applicable to our CBM production. Realized
commodity prices received for our production are primarily driven by the spot prices attributable
to natural gas. The effects of price volatility are expected to continue.
Under the terms of the GasRock Credit Agreement, we are required to enter into derivative contracts
covering approximately 75% of 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 one million of British
thermal units (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 the GasRock 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 costless
collar contracts 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 contracts, 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
32
month. We expect that we will enter into additional derivative contracts in the future to cover the
entire 75% of our proved developed producing reserves scheduled to be produced during each period.
We have
elected not to designate our commodity derivative contracts 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 other income or expense as they occur. As of April
30, 2008, the fair value of the contracts with BP was estimated to be approximately $345, in a net
liability position of which $305 is considered current and is included in accrued liabilities and
other, and $40 is non-current and is recorded as an other non-current liability in our unaudited
consolidated balance sheet. In addition, the change in fair value (loss) of $329 and $345 during
the three and nine months ended April 30, 2008, respectively, has been recorded as other expense in
the unaudited consolidated statements of operations.
Realized gains or losses from the settlement of commodity derivative contracts are reported as
other income or expense on the consolidated statements of operations. On July 31, 2007, we entered
into the first commodity derivative contracts with the first settlement month designated as
September 2007. We recorded net realized gains on settlement of our derivative contracts of $0 and
$41 during the three and nine months ended April 30, 2008, respectively. Such amounts are included
as other income in the unaudited consolidated statements of operations.
On
June 9, 2008, we entered into an arrangement with BP whereby our costless collar contracts
described above for the notional amount of 20,000 MMBtus per month
through July 31, 2009 were
cancelled effective July 1, 2008 and replaced with a swap agreement at a fixed price of $10.26 per
MMBtu (based on NYMEX final settlement) for the notional amount of 20,000 MMBtus per month
beginning July 1, 2008 through July 31, 2010 (500,000 MMBtus in total). The contract is net-settled
on a monthly basis, meaning that if the NYMEX final settlement price for a month is below $10.26
per MMBtu, BP will pay us the difference in price multiplied by the notional amount for the month,
and if the NYMEX final settlement price for a month is above $10.26 per MMBtu, we will pay BP the
difference in price multiplied by the notional amount for the month.
Interest Rate Risk
Our exposure to changes in interest rates results from the GasRock Credit Agreement. For the first
year of the term of the GasRock Credit Agreement, all amounts outstanding under the GasRock 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
GasRock 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 April 30, 2008 was $11,732,158. A 1% change in interest rates would affect pre-tax net
loss by approximately $118,000 per year.
Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, commodity
derivatives and long-term debt and notes payable. Commodity derivatives are carried at estimated
fair value. The carrying amount of cash and cash equivalents, accounts receivable and accounts
payable approximate fair market value due to the highly liquid nature of these short-term
instruments. The carrying amount of our long-term debt with GasRock approximates fair value due to
its variable interest rate structure and its relatively short-term nature.
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.
33
Item 4. Controls and Procedures.
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
(the Exchange Act). As of the end of the period covered by this report, we conducted an
evaluation, under the supervision and with the participation of our Chief Executive Officer and
Acting Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as
defined in Rule 13a-15(e)) as of April 30, 2008. Based on this evaluation, our Chief Executive
Officer and Acting Chief Financial Officer concluded that our disclosure controls and procedures
were effective as of April 30, 2008 in ensuring that information required to be disclosed in our
periodic filings under the Exchange Act is recorded, processed, summarized and reported within the
time periods specified in the Securities and Exchange Commissions rules and forms and is
accumulated and communicated to our management, including our Chief Executive Officer and Acting
Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
There were no changes in our internal control over financial reporting or in other factors that
occurred during our last fiscal quarter that materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
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 $5,845,000, 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 BPIs
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 courts 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
34
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 parties are
currently engaged in written discovery. During the course of discovery, defendants produced an
additional agreement between BPI and Christian that BPI believes supports an additional claim for
breach of contract, and as a result, BPI filed a Third Amended Complaint. The Defendants then moved
to stay the case pending arbitration on the basis that the agreement contains an arbitration
provision. The court denied that motion. Defendants have also filed two partial motions to dismiss
various claims in the Third Amended Complaint. The first partial motion to dismiss has been fully
briefed and is awaiting the courts decision. The second partial motion to dismiss will be ready
for a ruling later this summer. The Company anticipates that if the Court denies all or part of the
motions 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.
The Company believes 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, the Company believes that it will
be successful in defending against their claims of breach. However, there can be no assurance that
the Company will be successful in maintaining these acreage rights. The loss of these acreage
rights would not have a material impact on the Companys 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 the leases were executed and that there
is a lack of mutuality under the leases. BPI denied ICGs claims and moved for summary judgment. On
May 20, 2008, the court granted BPIs motion, finding the leases to be valid. ICG has not yet
indicated whether it will appeal this decision.
BPI has drilled 10 pilot wells, one water disposal well and three test wells on the acreage covered
by the farm-out agreement. In February 2008, BPI shut down its Macoupin pilot and suspended testing
in Perry County in response to a demand by ICG that it do so until the litigation is resolved.
The Company believes that if ICG elects to continue to pursue this litigation by appealing the
courts decision to grant summary judgment, BPI will ultimately be successful in defending against
ICGs claims; however, there can be no assurance that BPI will ultimately be successful in
retaining the acreage under this farm-out agreement. The loss of these acreage rights would not
have a material impact on the Companys financial position, results of operations or cash flows.
Item 1A. Risk Factors.
We may be unable to raise adequate capital in the near term, which would have a material adverse
effect on our ability to continue as a going concern.
We have experienced significant losses in recent periods and, as of June 13, 2008, we have a cash
balance of approximately $550,000 and accounts receivable (for eligible expenses reimbursable from
GasRock) of approximately $125,000. We estimate that our accounts payable and accrued liabilities
as of June 13, 2008 (excluding debt and loss position on hedge contracts) total approximately
$1,200,000. A significant portion of our accounts payable and accrued liabilities are past due and
approximately 50% of the balance is owed
35
to two vendors with whom we are in discussions to negotiate extended payment terms. We are
currently paying our lease operating expenses from a portion of our sales that are reimbursed by
GasRock, so our production operations are not currently affected. However, we are not able to pay
general and administrative expenses from such funds. We have made substantial reductions in our
general and administrative expenses during the third quarter of fiscal year 2008 but we do not have
the ability to reduce costs sufficiently to obtain positive cash flow from operations. We are not
currently drilling new wells; however, based on our current working capital situation, we need to
raise cash in the near term in order to be able to settle our accounts payable and accrued
liabilities and to fund future operations. In order to continue as a going concern, we must be able to finance our current
operations, pay amounts due under the GasRock Credit Agreement when such amounts become due on
January 30, 2009 and finance any future exploration and development costs.
The GasRock Credit Agreement contains an event of default if James E. Craddock, our former Chief
Operating Officer, ceases to be materially involved in our management and is not replaced within 90
days with a person acceptable to GasRock. Mr. Craddock resigned as our Chief Operating Officer
effective March 31, 2008. Although Mr. Craddock will continue to make himself available as a
technical advisor to our Board of Directors as needed to assist in an orderly transition and
further advance our development and financing efforts through
September 30, 2008, we have not replaced Mr. Craddock as Chief Operating Officer. We promptly notified GasRock of Mr. Craddocks
resignation. However, GasRock has not formally advised us as to whether they intend to consider
this an event of default should we fail to replace Mr. Craddock with a person acceptable to GasRock
within the 90-day period allowed (by June 29, 2008).
In addition, the GasRock Credit Agreement requires us to maintain a current ratio of 1.0, excluding
from the calculation of current liabilities any advances outstanding under the GasRock Credit
Agreement and excluding from current assets and current liabilities any unrealized gains and losses
from unliquidated commodity derivative contracts. Although we believe that we are in compliance
with this covenant as of June 13, 2008, it is very likely that we will be in breach of this
covenant in the near term if we do not obtain financing.
If GasRock declares an event of default under the GasRock Credit Agreement, GasRock may accelerate
our outstanding obligations. In addition, at any time that an event of default exists under the
GasRock Credit Agreement, we will have to pay interest on all amounts outstanding under the GasRock
Credit Agreement at a default rate, which is equal to the then-prevailing interest rate under the
GasRock Credit Agreement plus 4% per annum.
We have historically financed our activities primarily from the proceeds of private placements of
our common shares and most recently from advances under the GasRock Credit Agreement. We currently
have a request pending with GasRock to fund our cash shortfall through the end of fiscal 2008 along
with a request for capital development funds for new development activities. GasRock has sole
discretion over all future advances under the GasRock Credit Agreement.
In addition, we are currently evaluating what additional options are available to finance current
and future operations and to be able to pay amounts due under the GasRock Credit Agreement when
such amounts become due on January 30, 2009. We have explored additional potential funding sources,
including the issuance of new debt and/or equity securities, joint ventures, mergers/combinations,
asset sales and selling rights relating to our litigation against Drummond, but to date have not
been successful in obtaining additional funding. We are still exploring all of these options and
we are engaging in discussions with a company that may provide additional development funds to
expand our Southern Illinois Basin Project. However, we do not believe such funds would provide
any significant reimbursement for general and administrative expenses and can provide no assurance
that we will be successful in completing this or any other financing transaction. If we cannot
raise adequate funds in the near term, we may have to cease operations and liquidate.
36
There are no other material changes to the risk factors previously reported in our Annual Report on
Form 10-K for the fiscal year ended July 31, 2007. For more information regarding such risk
factors, please refer to Item 1A of our Annual Report on Form 10-K for the fiscal year ended July
31, 2007.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
None.
Item 6. Exhibits.
31.1
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Section 302 Certification of the Chief Executive Officer (Principal Executive Officer).
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31.2
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Section 302 Certification of the Acting Chief Financial Officer (Principal Financial
Officer).
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32.1
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Section 906 Certification of the Principal Executive Officer and Principal Financial
Officer.
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37
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
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BPI ENERGY HOLDINGS, INC.
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Date: June 16, 2008
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/s/ James G. Azlein
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James G. Azlein,
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President and Chief Executive Officer
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/s/ Randall L. Elkins
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Randall L. Elkins,
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Controller and Acting Chief Financial Officer
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38
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