BPI Energy Holdings 10-Q
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
10 - Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended January 31, 2007
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 |
(State or Other Jurisdiction of
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(I.R.S. Employer Identification No.) |
Incorporation or Organization) |
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30775 Bainbridge Road, Suite 280, Solon, Ohio
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44139 |
(Address of Principal Executive Offices)
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(Zip Code) |
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, or a non-accelerated filer. See definition of accelerated filer and
large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer o Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common
stock, as of the latest practicable date: Common Shares, without par value, as of March 14,
2007: 72,524,493
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
BPI Energy Holdings, Inc.
Consolidated Balance Sheets
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January 31, 2007 |
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July 31, 2006 |
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(Unaudited) |
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ASSETS |
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Current assets: |
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|
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|
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|
|
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Cash and cash equivalents |
|
$ |
10,255,781 |
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|
$ |
19,279,015 |
|
Accounts receivable |
|
|
93,974 |
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|
|
105,711 |
|
Other current assets |
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|
665,782 |
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|
|
164,764 |
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Total current assets |
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11,015,537 |
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|
|
19,549,490 |
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Property and equipment, at cost: |
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Gas properties, full cost method of accounting: |
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Proved, net of accumulated
depreciation, depletion and
amortization of $520,936 and $331,150 |
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20,847,472 |
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|
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20,766,898 |
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Unproved |
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6,096,085 |
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3,368,231 |
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Net gas properties |
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|
26,943,557 |
|
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|
24,135,129 |
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Other property and equipment, net of
accumulated depreciation and amortization of
$817,224 and $631,015 |
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5,878,767 |
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5,106,236 |
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|
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Net property and equipment |
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32,822,324 |
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|
|
29,241,365 |
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Restricted cash |
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100,000 |
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|
100,000 |
|
Other non-current assets |
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367,168 |
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|
|
161,125 |
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Total assets |
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$ |
44,305,029 |
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|
$ |
49,051,980 |
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LIABILITIES AND SHAREHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable |
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$ |
665,719 |
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$ |
1,492,239 |
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Current maturity of long-term notes payable |
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33,397 |
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140,866 |
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Accrued liabilities and other |
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284,097 |
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649,237 |
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Total current liabilities |
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983,213 |
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2,282,342 |
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Long-term notes payable, less current portion |
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62,346 |
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75,149 |
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Asset retirement obligation |
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96,721 |
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70,754 |
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Total liabilities |
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1,142,280 |
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2,428,245 |
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Shareholders equity: |
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Common shares, no par value, authorized
200,000,000 shares, 72,524,493 and 70,812,540
outstanding |
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67,946,143 |
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67,946,143 |
|
Additional paid-in capital |
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6,934,050 |
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5,871,120 |
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Accumulated deficit |
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|
(31,717,444 |
) |
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|
(27,193,528 |
) |
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Total shareholders equity |
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|
43,162,749 |
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46,623,735 |
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Total
liabilities and shareholders equity |
|
$ |
44,305,029 |
|
|
$ |
49,051,980 |
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|
|
|
See Notes to Unaudited Consolidated Financial Statements.
1
BPI Energy Holdings, Inc.
Consolidated Statements of Operations
(Unaudited)
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Three Months Ended January 31 |
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Six Months Ended January 31 |
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2007 |
|
2006 |
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2007 |
|
2006 |
Revenues: |
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|
|
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Gas sales |
|
$ |
246,906 |
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|
$ |
327,811 |
|
|
$ |
540,909 |
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$ |
537,505 |
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Expenses: |
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Lease operating expense |
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527,773 |
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300,806 |
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863,747 |
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461,610 |
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General and administrative expenses |
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1,469,516 |
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1,165,483 |
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|
4,204,226 |
|
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2,437,239 |
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Depreciation, depletion and amortization |
|
|
191,998 |
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|
117,890 |
|
|
|
375,995 |
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|
212,692 |
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|
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2,189,287 |
|
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1,584,179 |
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5,443,968 |
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3,111,541 |
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Operating loss |
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|
(1,942,381 |
) |
|
|
(1,256,368 |
) |
|
|
(4,903,059 |
) |
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(2,574,036 |
) |
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Other income (expenses): |
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Interest income |
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166,416 |
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|
270,186 |
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385,322 |
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|
402,804 |
|
Interest expense |
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|
(3,026 |
) |
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|
(6,234 |
) |
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|
(6,179 |
) |
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(13,778 |
) |
Other income |
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|
|
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138,191 |
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|
|
|
|
|
137,523 |
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|
|
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|
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|
163,390 |
|
|
|
402,143 |
|
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|
379,143 |
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526,549 |
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Net loss |
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$ |
(1,778,991 |
) |
|
$ |
(854,225 |
) |
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$ |
(4,523,916 |
) |
|
$ |
(2,047,487 |
) |
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Basic and diluted loss per share |
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($0.03 |
) |
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|
($0.01 |
) |
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|
($0.07 |
) |
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($0.04 |
) |
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|
Weighted average common shares outstanding |
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|
70,059,225 |
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|
|
63,654,794 |
|
|
|
69,427,874 |
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|
57,889,094 |
|
See Notes to Unaudited Consolidated Financial Statements.
2
BPI Energy Holdings, Inc.
Consolidated Statements of Shareholders Equity
(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 |
|
|
|
Balance, July 31, 2006 |
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|
70,812,540 |
|
|
$ |
67,946,143 |
|
|
$ |
5,871,120 |
|
|
$ |
(27,193,528 |
) |
|
$ |
46,623,735 |
|
Share-based payments
common shares, including
vesting of restricted
shares |
|
|
1,795,883 |
|
|
|
|
|
|
|
1,105,734 |
|
|
|
|
|
|
|
1,105,734 |
|
Surrender of shares |
|
|
(83,930 |
) |
|
|
|
|
|
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(42,804 |
) |
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|
|
|
|
(42,804 |
) |
Net loss |
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|
|
|
|
|
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|
(4,523,916 |
) |
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|
(4,523,916 |
) |
|
|
|
Balance, January 31, 2007 |
|
|
72,524,493 |
|
|
$ |
67,946,143 |
|
|
$ |
6,934,050 |
|
|
$ |
(31,717,444 |
) |
|
$ |
43,162,749 |
|
|
|
|
See Notes to Unaudited Consolidated Financial Statements.
3
BPI Energy Holdings, Inc.
Consolidated Statements of Cash Flows
(Unaudited)
|
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|
Six Months Ended January 31 |
|
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2007 |
|
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2006 |
|
Operating activities: |
|
|
|
|
|
|
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|
Net loss |
|
$ |
(4,523,916 |
) |
|
$ |
(2,047,487 |
) |
Adjustments to reconcile net loss to net cash used in
operating activities: |
|
|
|
|
|
|
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|
Depreciation, depletion and amortization |
|
|
375,995 |
|
|
|
212,692 |
|
Share-based payments |
|
|
834,498 |
|
|
|
397,586 |
|
Gain on sale of investment |
|
|
|
|
|
|
(127,416 |
) |
Accretion of asset retirement obligation |
|
|
2,797 |
|
|
|
1,334 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
11,737 |
|
|
|
(124,963 |
) |
Other current assets |
|
|
(278,629 |
) |
|
|
(246,911 |
) |
Accounts payable |
|
|
(14,029 |
) |
|
|
203,778 |
|
Accrued liabilities and other |
|
|
(565,140 |
) |
|
|
71,922 |
|
Other assets and liabilities |
|
|
|
|
|
|
44,615 |
|
|
|
|
Net cash used in operating activities |
|
|
(4,156,687 |
) |
|
|
(1,614,850 |
) |
|
|
|
|
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|
|
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Investing activities: |
|
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|
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|
Proceeds from sale of investment |
|
|
|
|
|
|
551,000 |
|
Additions to gas properties |
|
|
(3,719,803 |
) |
|
|
(6,819,644 |
) |
Additions to other property and equipment |
|
|
(1,026,472 |
) |
|
|
(2,560,216 |
) |
Increase in restricted cash |
|
|
|
|
|
|
(34,000 |
) |
|
|
|
Net cash used in investment activities |
|
|
(4,746,275 |
) |
|
|
(8,862,860 |
) |
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|
|
|
|
|
|
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Financing activities: |
|
|
|
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|
|
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|
Payments on long-term notes payable |
|
|
(120,272 |
) |
|
|
(57,458 |
) |
Net proceeds from issuance of common shares |
|
|
|
|
|
|
29,907,372 |
|
|
|
|
Net cash (used in) provided by financing activities |
|
|
(120,272 |
) |
|
|
29,849,914 |
|
|
|
|
Net (decrease) increase in cash and cash equivalents |
|
|
(9,023,234 |
) |
|
|
19,372,204 |
|
Cash and cash equivalents at the beginning of the period |
|
|
19,279,015 |
|
|
|
7,251,503 |
|
|
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|
Cash and cash equivalents at the end of the period |
|
$ |
10,255,781 |
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|
$ |
26,623,707 |
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Supplementary disclosure of cash flow information: |
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Cash payments: |
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Interest paid |
|
$ |
6,179 |
|
|
$ |
9,856 |
|
Non-cash investing activities acquisition of
equipment by issuance of notes payable |
|
|
|
|
|
|
233,475 |
|
See Notes to Unaudited Consolidated Financial Statements.
4
BPI Energy Holdings, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These unaudited consolidated interim financial statements include the accounts of BPI Energy
Holdings, Inc. and its wholly owned U.S. subsidiary, BPI Energy, Inc. (collectively, the
Company). All inter-company transactions and balances have been eliminated upon
consolidation.
BPI Energy Holdings, Inc. is incorporated in British Columbia, Canada and, through its wholly
owned U.S. subsidiary, BPI Energy, Inc., is involved in the exploration, production and
commercial sale of coalbed methane in the Illinois Basin. The Company conducts its operations
in one reportable segment, which is gas exploration and production. The Companys
common shares trade on the American Stock Exchange under the symbol BPG. Amounts shown are in
U.S. Dollars unless otherwise indicated.
The accompanying unaudited consolidated financial statements have been prepared in accordance
with generally accepted accounting principles for interim financial information and with the
instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include
all of the information and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all adjustments (consisting of
normal recurring accruals) considered necessary for a fair presentation have been included.
Operating results for the quarter and six months ended January 31, 2007 are not necessarily
indicative of the results that may be expected for the full fiscal year. For further
information, refer to the consolidated financial statements and notes thereto included in the
Companys Annual Report on Form 10-K for the fiscal year ended July 31, 2006. Certain prior
period amounts have been reclassified to conform to current period presentation.
The Company has financed its activities primarily from the proceeds of various share
issuances. As a result of the Company being in the early stages of operations, the
recoverability of assets on the balance sheet will be dependent on the Companys ability to
obtain additional financing and to attain a level of profitable operations.
Use of Estimates
The preparation of these unaudited consolidated financial statements requires the use of
certain estimates by management in determining the Companys assets, liabilities, revenues and
expenses. Actual results could differ from such estimates. Depreciation, depletion and
amortization of gas properties and the impairment of gas properties are determined using
estimates of gas reserves. There are numerous uncertainties in estimating the quantity of
reserves and in projecting the future rates of production and timing of development
expenditures, including the timing and costs associated with asset retirement obligations.
Gas reserve engineering must be recognized as a subjective process of estimating underground
accumulations of gas that cannot be measured in an exact way. Proved reserves of natural gas
are estimated quantities that geological and engineering data demonstrate with reasonable
certainty to be recoverable in the future from known reservoirs under
existing conditions.
5
Gas Properties
The Company follows the full cost method of accounting for gas properties. Under this method,
all costs associated with the acquisition of, exploration for and development of gas reserves
are capitalized in cost centers on a country-by-country basis (currently, the Company has one
cost center, the United States). Such costs include lease acquisition costs, geological and
geophysical studies, carrying charges on non-producing properties, costs of drilling both
productive and non-productive wells, and overhead expenses directly related to these
activities. Internal costs associated with gas activities that are not directly attributable to
acquisition, exploration or development activities are expensed as incurred.
Unproved gas properties and major development projects are excluded from amortization until a
determination of whether proved reserves can be assigned to the properties or impairment
occurs. Unproved properties are assessed at least annually to ascertain whether impairment has
occurred. Sales or dispositions of properties are credited to their respective cost centers
and a gain or loss is recognized when all the properties in a cost center have been disposed
of, unless such sale or disposition significantly alters the relationship between capitalized
costs and proved reserves attributable to the cost center.
Capitalized costs of proved gas properties, including estimated future costs to develop the
reserves and estimated abandonment cost, net of salvage, are amortized on the
units-of-production method using estimates of proved reserves.
A ceiling test is applied to each cost center by comparing the net capitalized costs, less
related deferred income taxes, to the estimated future net revenues from production of proved
reserves, discounted at 10%, plus the costs of unproved properties net of impairment. Any
excess capitalized costs are written-off in the current year. The calculation of future net
revenues is based upon prices, costs and regulations in effect at the
end of each reporting period.
In general, the Company determines if an unproved property is impaired if one or more of the
following conditions exist:
|
i) |
|
there are no firm plans for further drilling on the unproved property;
|
|
|
ii) |
|
negative results were obtained from studies of the unproved property; |
|
|
iii) |
|
negative results were obtained from studies conducted in the vicinity of the
unproved property; or |
|
|
iv) |
|
the remaining term of the unproved property does not allow sufficient time
for further studies or drilling. |
No impairment existed as of January 31, 2007 or July 31, 2006.
Other Property and Equipment
Other property and equipment are stated at cost. Gas collection equipment is depreciated on
the units-of-production method using estimates of proved reserves. Support equipment and
other property and equipment are depreciated using the straight-line method over the estimated
useful lives of the assets, ranging from three to 10 years. Major classes of other property
and equipment consisted of the following at January 31, 2007 and July 31, 2006, respectively:
6
|
|
|
|
|
|
|
|
|
|
|
January 31, |
|
|
July 31, |
|
|
|
2007 |
|
|
2006 |
|
Other
property and equipment: |
|
|
|
|
|
|
|
|
Gas collection equipment |
|
$ |
4,342,400 |
|
|
$ |
4,342,400 |
|
Support equipment |
|
|
1,832,444 |
|
|
|
1,046,989 |
|
Other |
|
|
521,147 |
|
|
|
347,862 |
|
Less: Accumulated depreciation and
amortization |
|
|
(817,224 |
) |
|
|
(631,015 |
) |
|
|
|
|
|
|
|
|
|
$ |
5,878,767 |
|
|
$ |
5,106,236 |
|
|
|
|
|
|
|
|
Loss Per Share
Basic loss per share is calculated using the weighted average number of common shares
outstanding during the year. Diluted loss per share reflects the potential dilution that could
occur if securities or other contracts to issue common shares were exercised or converted into
common shares. Restricted common shares granted are included in the computation only after
the shares become fully vested. Diluted loss per share is not disclosed as it is
anti-dilutive. The following items were excluded from the computation of diluted loss per
share at January 31, 2007 and 2006, respectively, as the effect of their assumed exercises
would be anti-dilutive:
|
|
|
|
|
|
|
|
|
|
|
January
31, |
|
|
January
31, |
|
|
|
2007 |
|
|
2006 |
|
Outstanding warrants |
|
|
5,311,600 |
|
|
|
10,763,603 |
|
Outstanding
stock options |
|
|
1,529,931 |
|
|
|
4,080,612 |
|
Nonvested portion of restricted shares issued |
|
|
2,537,338 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,378,869 |
|
|
|
14,844,215 |
|
|
|
|
|
|
|
|
2. STOCK-BASED COMPENSATION
SFAS No. 123 (R)
In
December 2004, the FASB issued Statement of Financial Accounting
Standards (SFAS)
No. 123(R), Share-Based Payment. This Statement revises
SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees. SFAS No. 123(R) focuses primarily on the
accounting for transactions in which an entity obtains employee services in share-based
payment transactions. The key provision of SFAS No. 123(R) requires companies to record
share-based payment transactions as compensation expense at fair market value based on the
grant-date fair value of those awards. Previously under SFAS 123, companies had the option of
either recording expense based on the fair value of stock options granted or continuing to
account for stock-based compensation using the intrinsic value method prescribed by APB No.
25.
The Company adopted SFAS No. 123(R), using the modified-prospective method, effective August
1, 2005. Since August 1, 2001, the Company followed the fair value provisions of SFAS 123 and
recorded all share-based payment transactions as compensation expense at fair market value
based on the grant-date fair value of those awards. In addition, all stock options previously
granted by the Company vested immediately on the date of grant and, thus, there
was no nonvested portion of previous stock option grants that vested during
the fiscal year ended July 31, 2006 or thereafter. Therefore, the adoption of SFAS 123(R) had
no impact on the Companys consolidated financial position or results of operations for the
periods presented. The Company uses the Black-Scholes formula to estimate the fair value of
stock options granted.
7
Incentive Stock Option Plan
Prior to December 13, 2005 the Company administered a stock-based compensation plan (the
Incentive Stock Option Plan) under which stock options were issued to directors, officers,
employees and consultants as determined by the Board of Directors and subject to the
provisions of the Incentive Stock Option Plan. The Incentive Stock Option Plan permitted
options to be issued with exercise prices at a discount to the market price of the Companys
common shares on the day prior to the date of grant. However, the majority of all stock
options issued under the Incentive Stock Option Plan were issued with exercise prices equal to
the quoted market price of the shares on the date of grant. Options granted under the
Incentive Stock Option Plan vested immediately and were exercisable over a period not
exceeding five years. The following table summarizes information about options outstanding
under the Incentive Stock Option Plan at January 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
Exercise |
|
|
|
|
|
|
|
|
Price |
|
Number |
|
|
Remaining |
|
|
Expiry |
CAD$ |
|
Outstanding |
|
|
Life (Years) |
|
|
Date |
$0.65 |
|
|
345,000 |
|
|
|
1.8 |
|
|
November
3, 2008 |
0.90 |
|
|
10,000 |
|
|
|
2.6 |
|
|
September
22, 2009 |
1.49 |
|
|
695,666 |
|
|
|
2.8 |
|
|
November
29, 2009 |
2.05 |
|
|
10,000 |
|
|
|
3.6 |
|
|
September
22, 2010 |
2.19 |
|
|
136,000 |
|
|
|
3.2 |
|
|
March
27, 2010 |
2.40 |
|
|
333,265 |
|
|
|
3.0 |
|
|
January
20, 2010 |
|
|
|
|
|
|
|
|
|
$1.56 |
|
|
1,529,931 |
|
|
|
2.7 |
|
|
|
|
|
|
|
|
|
|
|
|
Omnibus Stock Plan
On December 13, 2005, the shareholders of the Company approved the Companys 2005 Omnibus
Stock Plan (the Omnibus Stock Plan) and it became effective on that date. The Omnibus Stock
Plan replaces the Incentive Stock Option Plan under which stock options were previously
granted. The Omnibus Stock Plan is administered by the Compensation Committee of the Board of
Directors (the Committee) and will remain in effect until December 13, 2010. All employees
and directors of the Company and its subsidiaries, and all consultants or agents of the
Company designated by the Committee, are eligible to participate in the Omnibus Stock Plan.
The Committee has authority to: grant awards; select the participants who will receive awards;
determine the terms, conditions, vesting periods and restrictions applicable to the awards;
determine how the exercise price is to be paid; modify or replace outstanding awards within
the limits of the Omnibus Stock Plan; accelerate the date on which awards become exercisable;
waive the restrictions and conditions applicable to awards; and establish rules governing the
Omnibus Stock Plan.
The Omnibus Stock Plan provides that in any fiscal year of the plan the Company may grant up
to 5% of the number of common shares outstanding as of the first day of that fiscal year plus
the number of common shares that were available for the grant of awards, but not granted, in
prior years under the plan. In no event, however, may the number of common shares available
for the grant of awards in any fiscal year exceed 6% of the common shares outstanding as of
the first day of that fiscal year. 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 January 31, 2007, the Company
has issued 2,911,000 common shares (but no options) under the Omnibus Stock Plan and has
4,089,000 common shares available for future issuance under the Plan.
8
Share-Based Transactions
The following table summarizes the Companys restricted share activity during the quarter and
six months ended January 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Avg. |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Nonvested at July 31, 2006 |
|
|
2,325,000 |
|
|
$ |
0.61 |
|
Granted |
|
|
1,207,338 |
|
|
|
0.78 |
|
Vested |
|
|
(475,000 |
) |
|
|
0.49 |
|
|
|
|
|
|
|
|
Nonvested at October 31, 2006 |
|
|
3,057,338 |
|
|
|
0.70 |
|
Vested |
|
|
(520,000 |
) |
|
|
1.42 |
|
|
|
|
|
|
|
|
Nonvested at January 31, 2007 |
|
|
2,537,338 |
|
|
$ |
0.74 |
|
|
|
|
|
|
|
|
All restricted share awards are subject to continuous employment. However, in the event
employment is terminated before the restrictions lapse by reason of death, total disability or
retirement, the restrictions will lapse on the date of termination as to a pro-rata portion of
the number of restricted shares scheduled to lapse on the next lapse date, based on the number
of days continuously employed during the applicable vesting period. The Company includes all
restricted shares in common shares outstanding when issued, but only includes the vested
portion of such shares in the computation of basic earnings per share.
The 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 January 31, 2007, there was $1,572,468 of unrecognized compensation cost related to
restricted shares. The cost is expected to be amortized over a weighted average period of 1.3
years. The amount charged to expense related to restricted shares was $232,451 and $506,678
during the quarter and six months ended January 31, 2007,
respectively, and $0 during both the quarter and
six months ended January 31, 2006.
3. OTHER ASSETS
Other Current Assets
Other current assets consisted of the following at January 31, 2007 and July 31, 2006,
respectively:
|
|
|
|
|
|
|
|
|
|
|
January 31, |
|
|
July 31, |
|
|
|
2007 |
|
|
2006 |
|
Separation agreement |
|
$ |
352,353 |
|
|
$ |
|
|
Prepaid expenses |
|
|
313,429 |
|
|
|
164,764 |
|
|
|
|
|
|
|
|
|
|
$ |
665,782 |
|
|
$ |
164,764 |
|
|
|
|
|
|
|
|
9
Other Non-current Assets
Other non-current assets consisted of the following at January 31, 2007 and July 31, 2006,
respectively:
|
|
|
|
|
|
|
|
|
|
|
January 31, |
|
|
July 31, |
|
|
|
2007 |
|
|
2006 |
|
Separation agreement |
|
$ |
206,043 |
|
|
$ |
|
|
Advance royalties |
|
|
161,125 |
|
|
|
161,125 |
|
|
|
|
|
|
|
|
|
|
$ |
367,168 |
|
|
$ |
161,125 |
|
|
|
|
|
|
|
|
Prepaid expenses primarily represent amounts paid one year in advance for commercial insurance
premiums and monthly prepayments of rent, health benefits and other expenses. The separation
agreement represents amounts capitalized related to non-compete/non-solicitation and
continuing services clauses contained in a separation agreement entered into with a former
officer of the Company on October 12, 2006. See note 10 for further explanation of this
agreement.
4. ACCRUED LIABILITIES AND OTHER
Accrued liabilities and other consisted of the following at January 31, 2007 and July 31,
2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
January 31, |
|
|
July 31, |
|
|
|
2007 |
|
|
2006 |
|
Employee compensation |
|
$ |
|
|
|
$ |
467,869 |
|
Separation agreement |
|
|
200,000 |
|
|
|
|
|
Professional and regulatory |
|
|
52,952 |
|
|
|
111,805 |
|
Directors fees |
|
|
27,000 |
|
|
|
31,000 |
|
Other |
|
|
4,145 |
|
|
|
38,563 |
|
|
|
|
|
|
|
|
|
|
$ |
284,097 |
|
|
$ |
649,237 |
|
|
|
|
|
|
|
|
The separation agreement represents amounts due related to a non-compete/non-solicitation
clause contained in a separation agreement entered into with a former officer of the Company
on October 12, 2006. See note 10 for further explanation of this agreement.
5. LONG-TERM NOTES PAYABLE
Long-term notes payable consisted of the following at January 31, 2007 and July 31, 2006,
respectively:
|
|
|
|
|
|
|
|
|
|
|
January 31, |
|
|
July 31, |
|
|
|
2007 |
|
|
2006 |
|
Case Credit term note due in fiscal year 2006, 6.50% |
|
$ |
7,236 |
|
|
$ |
15,410 |
|
GMAC term note due in fiscal year 2009, 6.50% |
|
|
17,446 |
|
|
|
20,608 |
|
GMAC term notes due in fiscal year 2010, 6.1% to 6.50% |
|
|
71,061 |
|
|
|
80,849 |
|
Caterpillar Financial Services term note due in
fiscal year 2007, 7.0% |
|
|
|
|
|
|
99,148 |
|
|
|
|
|
|
|
|
|
|
|
95,743 |
|
|
|
216,015 |
|
Less current maturities |
|
|
(33,397 |
) |
|
|
(140,866 |
) |
|
|
|
|
|
|
|
Long-term notes payable |
|
$ |
62,346 |
|
|
$ |
75,149 |
|
|
|
|
|
|
|
|
10
The notes are collateralized by the related vehicles and equipment.
6. ASSET RETIREMENT OBLIGATIONS
The
Company follows SFAS No. 143, Accounting
for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value
of an asset retirement obligation as a liability in the period in which it is incurred, if a
reasonable estimate of fair value can be made. The present value of the estimated asset
retirement costs is capitalized as part of the carrying amount of the associated long-lived
asset. Amortization of the capitalized asset retirement cost is computed on a
units-of-production method. Accretion of the asset retirement obligation is recognized over
time until the obligation is settled. The Companys asset retirement obligations relate to
the plugging of wells upon exhaustion of gas reserves.
The following table summarizes the activity for the Companys asset retirement obligation for
the six months ended January 31, 2007 and 2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
January 31, |
|
|
2007 |
|
2006 |
|
|
|
Beginning asset retirement obligation |
|
$ |
70,754 |
|
|
$ |
34,708 |
|
Additional liability incurred |
|
|
6,994 |
|
|
|
9,907 |
|
Accretion expense |
|
|
2,797 |
|
|
|
1,334 |
|
Change in estimate |
|
|
35,377 |
|
|
|
|
|
Asset retirement costs incurred |
|
|
(36,239 |
) |
|
|
|
|
Loss on settlement of liability |
|
|
17,039 |
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
96,721 |
|
|
$ |
45,949 |
|
|
|
|
During
the six months ended January 31, 2007, the Company incurred $36,239 related to plugging
wells in conjunction with the legal settlement reached with Colt LLC in fiscal year 2006. The
actual cost of plugging the wells exceeded the Companys estimate resulting in a
loss on settlement of the liability of $17,039. The Company changed its
estimate of future costs associated with plugging wells, resulting in an increase to the asset
retirement obligation of $35,377, which was recorded in the current quarter.
7. CONCENTRATIONS
Financial instruments that potentially subject the Company to concentrations of credit
risk consist of cash and cash equivalents, which are held at one large high quality financial
institution. The Company periodically evaluates the credit worthiness of the financial
institution. The Company has not incurred any credit risk losses related to its cash and cash
equivalents.
The Company utilizes a limited number of drilling contractors to perform all of the drilling
on its projects. The Company maintains a limited number of supervisory and field personnel to
oversee drilling and production operations. The Companys plans to drill additional wells are
determined in large part by the anticipated availability of acceptable drilling equipment and
crews. The Company does not currently have any contractual commitments that ensure it will
have adequate drilling equipment or crews to achieve its drilling plans. The Company believes
that it can secure the necessary commitments from drilling companies as required. However,
it can provide no assurance that its expectations regarding the availability of drilling
equipment and crews from these companies will be met. A significant delay in securing the
necessary drilling
11
equipment and crews could cause a delay in production and sales, which would affect operating
results adversely.
8. INCOME TAXES
The
Company operates in two tax jurisdictions, the United States and Canada. Primarily as a result
of the net operating losses that the Company has generated (NOL Carryforwards) in both Canada and
the United States, the Company has generated deferred tax benefits available for tax purposes to
offset net income in future periods. SFAS No. 109,
Accounting for Income Taxes requires that
we record a valuation allowance when it is more likely than not that some portion or all of
the deferred tax assets will not be realized. The ultimate realization of deferred tax assets
is dependent upon the generation of sufficient future taxable income before the expiration of
the NOL Carryforwards. Because of the 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 January 31, 2007.
9. SHAREHOLDERS EQUITY
Common shares The Company has authorized 200,000,000 shares without par value for which
72,524,493 and 70,812,540 were issued and outstanding as of January 31, 2007 and July 31,
2006, respectively. Shares issued and outstanding at January 31, 2007 include 2,537,338 of
restricted shares expected to vest in future periods.
Additional paid-in capital Amounts recorded of $6,934,050 and $5,871,120 at January 31,
2007 and July 31, 2006, respectively, represent the cumulative value of share-based payments
made as of each date.
Share purchase warrants outstanding at January 31, 2007 are as follows:
|
|
|
|
|
|
|
Number |
|
|
Exercise |
|
|
Outstanding |
|
|
Price |
|
Expiry
Date |
|
4,724,400 |
|
|
$1.50 |
|
December 13, 2007 |
|
643,200 |
|
|
1.25 |
|
December 31, 2009 |
|
394,000 |
|
|
1.25 |
|
January 12, 2010 |
|
|
|
|
|
|
5,311,600 |
|
|
|
|
|
|
|
|
|
|
10. SEPARATION AGREEMENT
On October 12, 2006, the Company entered into a Separation Agreement and Waiver and Release
(Separation Agreement) with a former officer and director of the Company. Under the terms
of the Separation Agreement, the Company agreed to provide consideration to the former officer
and director upon his resignation as follows:
|
|
|
Severance cash payment of $250,000 and medical and dental insurance coverage for
two years from the date of the agreement. The cash payment of $250,000 was expensed
during the first quarter of fiscal year 2007 and the cost of medical and dental
coverage is being expensed as incurred. |
|
|
|
|
Consulting issuance of 40,000 unrestricted common shares and cash payments
totaling $50,000 in periodic installments from October 15, 2006 through December 31,
2006 in |
12
|
|
|
return for consulting services to be provided by the former officer and director as
may be reasonably requested by the Company from time to time through January 2, 2008. |
|
|
|
|
Non-Compete/Non-Solicitation cash payments of $100,000 on each of three dates
from January 2, 2007 through January 2, 2008 and immediate vesting of 475,000
restricted shares held by the former officer and director in return for his agreeing
not to compete with the Company or to solicit any of its employees for a period of
two years. |
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 unamortizing
the related expense ratably over the future periods in which it expects to receive the
related benefits. As of January 31, 2007, $558,397 of amortized value related to the
consulting services and the non-compete/non-solicitation agreement are recorded as other
assets on the balance sheet, including $206,043 shown as current and representing the
amount to be amortized over the next year. The amount capitalized includes $228,432 of
share-based payments representing the remaining unrecognized portion of expense related to
the vesting of the 475,000 restricted shares. As of January 31, 2007, $200,000 is
recorded as a current liability reflecting payments due under the
non-compete/non-solicitation agreement within the next year. During the quarter and six
months ended January 31, 2007, the Company expensed $90,061 and $108,660, respectively, in
connection with the consulting services and the
non-compete/non-solicitation agreement.
11. RELATED PARTY TRANSACTIONS
The Company enters into various transactions with related parties in the normal course of
business operations.
Randy Oestreich, the Companys Vice President of Field Operations, owns and operates A-Strike
Consulting, a consulting company that provides, among other things, laboratory testing related
to coalbed methane. 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 $38,451 in expense
reimbursement related to this arrangement during the six months ended January 31, 2007 and
2006, respectively. Mr. Oestreichs brother owns Dependable Service Company, a company that
previously provided general labor services to the Company. The Company paid Dependable
Services Company $0 and $160,679 during the six months ended January 31, 2007 and 2006,
respectively.
David Preng, a director of the Company, owns Preng & Associates, an executive search firm
specializing in the energy and natural resources industries. The Company paid Preng &
Associates $9,621 and $20,000 for executive placement services during the six months ended
January 31, 2007 and 2006, respectively.
12. SUBSEQUENT EVENT LEGAL PROCEEDINGS
BPI Energy, Inc. (BPI) is currently subject to litigation with respect to approximately
115,000 acres of its CBM rights that are located at the Northern Illinois Basin Project. To date,
BPI has drilled one well on this acreage, a test well that was drilled in September 2006. This
well is not currently at the production stage.
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 extract CBM from coal beds
prior to the Drummond affiliates mining of coal from those beds. Pursuant to and in reliance upon
this letter of intent and its relationship with Drummond, BPI arranged for the transfer of 163,109
acres of coal rights to the Drummond affiliates for a total purchase price of $5,845,500, which BPI
believes reflects a significant discount to current market prices. In light of its obligations to
Drummond, BPI charged no profit on its transfer of the coal rights to the Drummond affiliates.
Rather, in consideration for obtaining those coal rights, the Drummond affiliates were to lease
approximately 115,000 acres of CBM rights to BPI for a primary lease term of 20 years and with
favorable royalty rates. Although the Drummond affiliates entered into two CBM leases with BPI on
April 26, 2006, they have since sought in various ways to void or terminate the leases.
Ignoring mandatory arbitration provisions in the CBM 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. Specifically, although the CBM leases include no specific drilling commitments,
IEC and Christian allege that BPI has breached the CBM leases by failing to use best efforts to
commercially produce all economically recoverable gas. IEC and Christian also allege that BPI has
breached the CBM leases by failing to provide maps of existing and proposed gas wells and
facilities every six months and failing to maintain required insurance coverage. BPI refutes each
of these allegations and intends to vigorously defend the Drummond affiliates claims of breach.
In addition, BPI has moved to dismiss the lawsuit for lack of standing, lack of personal
jurisdiction and improper venue, or in the alternative to transfer the case to either Ohio or
Illinois.
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. 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, and has also asserted claims for money
damages for breach of contract, breach of fiduciary duty, unjust enrichment and promissory
estoppel.
We believe that Drummond and its affiliates, after having received favorable coal rights in
exchange for favorable CBM rights, now wish to obtain a significant windfall by seeking to renege
on the CBM rights that they were obligated to grant to BPI.
We believe that we will be successful in either having the lawsuit filed by the Drummond affiliates
dismissed or in defending against their claims of breach. However, there can be no
assurance that we will be successful in maintaining these acreage rights. The loss of these
acreage rights would not have a material impact on our financial position, results of operations or
cash flows.
13
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 and regulatory reporting to the British Columbia
Securities Commission.
As of January 31, 2007, we owned or controlled CBM rights, through mineral leases, options to
acquire mineral leases, a farm-out agreement and ownership of a CBM estate, covering approximately
500,000 total acres in the Basin (99% of this acreage is undeveloped as of January 31, 2007).
Approximately 115,000 acres of our CBM rights are currently subject to litigation, as described 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 4 millidarcies.
The State of Illinois (which includes most of the Basin) is estimated to be the number two state in
the United States in terms of coal reserves; however, coal in the Basin is high in sulfur, discouraging coal
mining operations. Recent advances in technology that can utilize higher sulfur coal and higher
coal prices are combining to make coals in the Basin potentially attractive to mining operations.
Although coal mining activities take priority over CBM operations in most of our acreage, we
attempt to coordinate and plan our drilling and production activities in conjunction with the
owners of the coal in order to minimize any potential disruptions. In addition, because of the long
lead times involved in coal mining projects, our substantial acreage position, and our ability to
be flexible with the timing and siting of our wells, we believe we can plan our work around coal
mining operations in the vicinity of our projects.
We have been involved in the first two projects in the Basin that have commercially produced and
sold CBM. We are the only company currently commercially producing and selling CBM in the State of
Illinois and one of only two companies currently commercially producing and selling CBM in the
Basin. We believe our position as a first mover has enabled us to secure a substantial
and favorable acreage position at costs that we believe compare very favorably to other CBM basins
that are more mature in terms of production history.
We are an early stage CBM exploration and production company. We commenced CBM sales from our first
producing wells in January 2005. Net gas sales during the fiscal year ended July 31, 2005 were
$117,835 on sales volume of 17,885 Mcf. Net gas sales were $1,126,477 on sales volume of 135,118
Mcf for the fiscal year ended July 31, 2006, an increase of 856% in net gas sales and 655% in sales
volume over the prior year. Net gas sales for the current quarter were $246,906 on sales volume of
37,352 Mcf compared to net gas sales of $327,811 on sales volume of 27,395 Mcf in the same prior
year quarter, representing a decrease of 25% in net gas sales and an increase of 36% in sales
volume over the same quarter from the previous year. Net gas sales
and sales volume for the quarter ended January 31, 2007 were lower by 16% and 27%, respectively, compared to the previous quarter
due primarily to a nitrogen-related pipeline curtailment that began in October and necessitated six
days of downtime followed by a period of constrained sales volume. The curtailment was caused by an increase in the nitrogen content of the sales
stream to approximately 5.5% versus a pipeline
14
quality specification of 4.0% total inert components. This is possibly due to adding new wells and
new coal seams in the field, since coals preferentially desorb
nitrogen, causing
the highest nitrogen content to be early in the life of a new well or
seam. A nitrogen-rejection unit is currently
being installed, with start-up anticipated during March 2007. In the meantime, the field remains
online, the coals are continuing to de-water, and we are selling gas at a constrained rate.
From early 2002 until 2005, our strategic focus was on building our acreage footprint in the Basin.
We were built around the primary strategic objective of acquiring CBM
rights in the Basin. As we
began accumulating CBM rights, we began testing our acreage to determine its CBM potential. Having
accumulated CBM rights to approximately 500,000 acres in the Basin and conducting extensive testing
at our Southern Illinois Basin Project, we embarked (in late 2004) on a pilot production program at
our Southern Illinois Basin Project. Encouraged by the results, we expanded our drilling and
production activities and began installing the infrastructure necessary to enable us to begin sales
of CBM at our Southern Illinois Basin Project.
As our drilling and production operations have grown, we have not abandoned our goal of adding
additional acreage and mineral rights. However, we have committed
ourselves to transitioning BPI from a company focused primarily on the acquisition of mineral rights to a company focused
on expanding our drilling and production operations and growing our reserves. To accomplish this
transition, we recognized that we needed to obtain additional capital, resources and technical
expertise. We believe that we have made substantial progress in achieving these goals. In September
2005, we sold 18,000,000 common shares and raised approximately $28,000,000. In April 2006, we
hired Jim Craddock as our Senior Vice President of Operations
(recently promoted to Chief Operating Officer). Prior
to joining us, Mr. Craddock was with Burlington Resources
for over 20 years, last serving as Chief Engineer. In his first
few months at BPI, Mr. Craddock built a strong in-house
technical team by adding a geologist and three engineers to our team, all with extensive experience in
successful CBM projects in basins located in the United States and Canada. Our new technical team
has over 130 years of experience in CBM exploration and
development that they bring to us.
In April 2006, we initiated our second development front when we began drilling 10 pilot
development wells in Shelby County at our Northern Illinois Basin Project. Pilot production is
being monitored and results to date continue to be encouraging. We
have completed drilling
two additional pilot wells and a pressure observation well at Shelby, which will be put into
operation by the end of March as our technical team continues its evaluation of the Shelby pilot
production. We plan to make a decision regarding development at Shelby by the end of April 2007.
The first of five test wells planned to be drilled during the balance of fiscal 2007 is currently
being drilled in Clinton County.
An additional water disposal well has been drilled at the Southern Illinois Basin Project and a
second rig has just started drilling additional production wells at the Southern Illinois Basin
Project.
We
previously announced plans to drill a total of 29 new production wells during the balance of fiscal
2007. This drilling plan will also include a new 10-well pilot program and a disposal well.
We are not currently generating net income or positive cash flow from operations. Although we
capitalize exploration and development costs, we have historically experienced significant losses.
The primary costs that generated these losses were compensation-related expenses and general and
administrative expenses. Even if we achieve increased revenues and positive cash flow from
operations in the future, we anticipate increased exploration, development and other capital
expenditures as we continue to explore and develop our mineral rights.
Our
current plan anticipates that for the remaining six months of fiscal
year 2007, we will spend approximately $10.5 million to drill 50 new
wells,
which includes 29 development wells, 12 pilot wells, three pressure observation wells, one water disposal well and five test wells. In addition to our drilling program, we
expect to continue to pursue the acquisition of additional CBM rights during the fiscal year.
Our cash balance at January 31, 2007 of $10,255,781 is insufficient to fully fund our forecasted capital expenditures and
net cash used by operating activities during our 2007 fiscal year or our operations beyond that date.
We expect that the capital expenditure requirements related to our drilling program and our other cash requirements will be funded by
our cash balance and cash raised through the issuance of debt securities, equity securities, borrowings and/or joint ventures, all of which we are actively pursuing. Although we are currently evaluating the best methods of raising those funds, we can provide no assurance that we will be able to raise the necessary funds.
Managements
focus for the remainder of fiscal year 2007 will be to:
|
|
|
obtain test data and initiate pilot projects that demonstrate the commercial
potential of CBM at our various acreage blocks and projects in the Basin; |
15
|
|
|
continue to reduce well drilling and completion costs; |
|
|
|
|
increase total company reserves; and |
|
|
|
|
grow total production. |
Gathering test data and siting pilot projects based on this data should lead to proving project
viability in multiple areas in the Basin. These pilot projects may have the potential to
grow into development projects that will increase our total reserves and production. As we
drill new wells, our production should continue to increase, as the new wells come online and our
existing wells continue to dewater. As our production increases in the future, we should be
positioned to generate positive cash flow from our operations.
A thorough technical evaluation of the assets that we control should lead to more cost effective
drilling and completion techniques that can be implemented to improve capital efficiency, increase
resource recovery and total reserves and improve internal rates of return from development
projects.
We currently control approximately 500,000 acres of CBM rights and, assuming 80-acre vertical well
spacing and the development of all of our acreage, have the possibility for up to 6,000 drilling
locations. With our potential for drilling locations, we expect that our drilling activities will
be taking place over many years. The type of test data we are interested in developing across all
of our projects includes measurements of permeability, gas content and net pay (i.e., thickness of
coal seams from which we believe CBM can be commercially produced). Our focus is to increase our
technical and operational knowledge of the Basin and our acreage rights to assist us in
(i) establishing the value of our CBM assets and (ii) optimizing the production we can obtain from
our wells after we bring them online. The technical team we have assembled has extensive experience
and expertise in all of these areas as well as implementation of large scale development of CBM
projects.
Several factors, over which we have little or no control, could impact our future economic success.
These factors include natural gas prices, limitations imposed by the terms and conditions of our
lease agreements, possible court rulings concerning our property interests in CBM, availability of
drilling rigs, operating costs, and environmental and other regulatory matters. In our planning
process, we have attempted to address these issues by:
|
|
|
negotiating to obtain leases that grant us the broadest possible rights to
CBM for any given tract of land; |
|
|
|
|
conducting ongoing title reviews of existing mineral interests; |
|
|
|
|
where possible, negotiating 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. |
16
Results of Operations
Three Months Ended January 31, 2007 Compared to Three Months Ended January 31, 2006
The following table presents our unaudited financial data for the second quarter of fiscal year
2007 compared to the second quarter of fiscal year 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended January 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar |
|
% |
|
|
2007 |
|
2006 |
|
Variance |
|
Change |
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales |
|
$ |
246,906 |
|
|
$ |
327,811 |
|
|
$ |
(80,905 |
) |
|
|
(25 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
527,773 |
|
|
|
300,806 |
|
|
|
226,967 |
|
|
|
75 |
% |
General and
administrative expense |
|
|
1,496,516 |
|
|
|
1,165,483 |
|
|
|
304,033 |
|
|
|
26 |
% |
Depreciation,
depletion and
amortization |
|
|
191,998 |
|
|
|
117,890 |
|
|
|
74,108 |
|
|
|
63 |
% |
|
|
|
|
|
|
2,189,287 |
|
|
|
1,584,179 |
|
|
|
605,108 |
|
|
|
38 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss |
|
|
(1,942,381 |
) |
|
|
(1,256,368 |
) |
|
|
(686,013 |
) |
|
|
(55 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
166,416 |
|
|
|
270,186 |
|
|
|
(103,770 |
) |
|
|
(38 |
%) |
Interest expense |
|
|
(3,026 |
) |
|
|
(6,234 |
) |
|
|
3,208 |
|
|
|
51 |
% |
Other income |
|
|
|
|
|
|
138,191 |
|
|
|
(138,191 |
) |
|
|
(100 |
%) |
|
|
|
|
|
|
163,390 |
|
|
|
402,143 |
|
|
|
(238,753 |
) |
|
|
(59 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(1,778,991 |
) |
|
$ |
(854,225 |
) |
|
$ |
(924,766 |
) |
|
|
(108 |
%) |
|
|
|
Revenue During the second quarter of fiscal year 2007, revenue decreased $80,905 over the second
quarter of fiscal year 2006. Net sales of gas (net of royalties) were 37,352 Mcf for the second
quarter of fiscal year 2007 or 36% higher compared to 27,395 Mcf for the second quarter of 2006.
Our average realized selling price per Mcf was $6.61 for the second quarter of fiscal year 2007
compared to $11.97 for the second quarter of fiscal year 2006. Net sales were also negatively
impacted during the second quarter of fiscal year 2007 due to a nitrogen-related pipeline
curtailment. A nitrogen-rejection unit is currently being constructed, with start-up anticipated
during March 2007.
Lease operating expense During the second quarter of fiscal year 2007, lease operating expense
increased $226,967 over the second quarter of fiscal year 2006. Lease operating expenses represent
production expenses, consisting primarily of repairs and maintenance, fuel and electricity,
equipment rental, workovers and labor and overhead expenses directly related to producing wells.
The increase is primarily due to expenses associated with non-recurring workover projects in
process at the Southern Illinois Basin Project designed to increase production of existing wells,
as well as an increase in the number of producing wells and the related costs incurred due to the
increase in gas production at the Southern Illinois Basin Project, new lease operating expenses at
our pilot project in the Northern Illinois Basin, and the hiring of additional personnel.
17
General and administrative expense General and administrative expense consisted of the following
for the second quarter of fiscal years 2007 and 2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months ended January 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar |
|
% |
|
|
2007 |
|
2006 |
|
Variance |
|
Change |
|
|
|
Salaries and benefits |
|
$ |
568,305 |
|
|
$ |
503,368 |
|
|
$ |
64,937 |
|
|
|
13 |
% |
Share-based payments |
|
|
232,451 |
|
|
|
|
|
|
|
232,451 |
|
|
|
100 |
% |
Professional and regulatory |
|
|
497,730 |
|
|
|
511,904 |
|
|
|
(14,174 |
) |
|
|
(3 |
%) |
Other |
|
|
171,030 |
|
|
|
150,211 |
|
|
|
20,819 |
|
|
|
14 |
% |
|
|
|
Total general and
administrative expense |
|
$ |
1,469,516 |
|
|
$ |
1,165,483 |
|
|
$ |
304,033 |
|
|
|
26 |
% |
|
|
|
During the second quarter of fiscal year 2007, salaries and benefits increased $64,937 over the
second quarter of fiscal year 2006. Salaries and benefits associated with base salaries increased
approximately $260,000 primarily as a result of hiring additional personnel to support our growth,
including our Chief Operating Officer, three engineers and a geologist. This increase was
partially offset by approximately $200,000 of expense associated with executive bonuses recognized
during the second quarter of fiscal year 2006.
During the second quarter of fiscal year 2007, expense associated with share-based payments
increased $232,451 over the second quarter of fiscal year 2006. Share-based payments for the
second quarter of fiscal year 2007 represent non-cash expense recognized for the anticipated
vesting of restricted shares outstanding. We intend to continue to rely on the granting of
equity-based awards, primarily restricted shares, in order to attract and retain qualified
individuals and to conserve cash so that it may be utilized in executing our drilling program.
Depreciation, depletion and amortization expense During the second quarter of fiscal year 2007,
depreciation, depletion and amortization expense (DD&A) increased $74,108 over the second quarter
of fiscal year 2006. We compute DD&A on capitalized acquisition and development costs (including
gas collection equipment) using the units-of-production method based on estimates of proved
reserves, and on all other property and equipment using the straight-line method based on estimated
useful lives ranging from three to 10 years. The increase is primarily due to the increase in
capitalized development costs and an increase in production over the second quarter of fiscal year
2006. Additionally, depreciation expense increased due to additions to other support equipment
utilized in our development of gas reserves.
Interest income During the second quarter of fiscal year 2007, interest income decreased $103,770
over the second quarter of fiscal year 2006 due to lower average cash balances during the second
quarter of fiscal year 2007.
Other
income During the second quarter of fiscal year 2007, other income decreased
$138,191 from the second quarter of fiscal year 2006 primarily due to
the gain of $127,416 that we
recognized on the sale of our investment in Hite Coalbed Methane L.L.C. in January 2006.
18
Six Months Ended January 31, 2007 Compared to Six Months Ended January 31, 2006
The following table presents our unaudited financial data for the first six months of fiscal year
2007 compared to the first six months of fiscal year 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended January 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar |
|
|
% |
|
|
|
2007 |
|
|
2006 |
|
|
Variance |
|
|
Change |
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales |
|
$ |
540,909 |
|
|
$ |
537,505 |
|
|
$ |
3,404 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
863,747 |
|
|
|
461,610 |
|
|
|
402,137 |
|
|
|
87 |
% |
General and
administrative expense |
|
|
4,204,226 |
|
|
|
2,437,239 |
|
|
|
1,766,987 |
|
|
|
72 |
% |
Depreciation, depletion
and amortization |
|
|
375,995 |
|
|
|
212,692 |
|
|
|
163,303 |
|
|
|
77 |
% |
|
|
|
|
|
|
5,443,968 |
|
|
|
3,111,541 |
|
|
|
2,332,427 |
|
|
|
75 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss |
|
|
(4,903,059 |
) |
|
|
(2,574,036 |
) |
|
|
(2,329,023 |
) |
|
|
(90 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
385,322 |
|
|
|
402,804 |
|
|
|
(17,482 |
) |
|
|
(4 |
%) |
Interest expense |
|
|
(6,179 |
) |
|
|
(13,778 |
) |
|
|
7,599 |
|
|
|
55 |
% |
Other income |
|
|
|
|
|
|
137,523 |
|
|
|
(137,523 |
) |
|
|
(100 |
%) |
|
|
|
|
|
|
379,143 |
|
|
|
526,549 |
|
|
|
(147,406 |
) |
|
|
(28 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(4,523,916 |
) |
|
$ |
(2,047,487 |
) |
|
$ |
(2,476,429 |
) |
|
|
(121 |
%) |
|
|
|
Revenue During the first six months of fiscal year 2007, revenue increased $3,404 over the first
six months of fiscal year 2006. Net sales of gas (net of royalties) were 88,842 Mcf for the first
six months of fiscal year 2007 or 88% higher compared to 47,183 Mcf for the first six months of
2006. Our average realized selling price per Mcf was $6.09 for the first six months of fiscal year
2007 compared to $11.39 for the first six months of fiscal year 2006. Net sales were also
negatively impacted by a nitrogen-related pipeline curtailment that began in October and
necessitated six days of downtime followed by a period of constrained sales volume during the
second quarter of fiscal year 2007. A nitrogen-rejection unit is currently being constructed, with
start-up anticipated during March 2007.
Lease operating expense During the first six months of fiscal year 2007, lease operating expense
increased $402,137 over the first six months of fiscal year 2006. Lease operating expense
represents production expenses, consisting primarily of repairs and maintenance, fuel and
electricity, equipment rental, workovers and labor and overhead expenses directly related to
producing wells. The increase is primarily due to expenses associated with non-recurring workover
projects in process at the Southern Illinois Basin Project designed to increase production of
existing wells, as well as an increase in the number of producing wells and the related costs
incurred due to the increase in gas production at the Southern Illinois Basin Project, new lease
operating expenses at our pilot project in the Northern Illinois Basin and the hiring of
additional personnel.
19
General and administrative expense General and administrative expense consisted of the following
for the first six months of fiscal years 2007 and 2006, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months ended January 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar |
|
|
% |
|
|
|
2007 |
|
|
2006 |
|
|
Variance |
|
|
Change |
|
|
|
|
Salaries and benefits |
|
$ |
1,779,051 |
|
|
$ |
727,240 |
|
|
$ |
1,051,811 |
|
|
|
145 |
% |
Share-based payments |
|
|
877,302 |
|
|
|
397,586 |
|
|
|
479,716 |
|
|
|
121 |
% |
Professional and regulatory |
|
|
1,204,122 |
|
|
|
1,072,142 |
|
|
|
131,980 |
|
|
|
12 |
% |
Other |
|
|
343,751 |
|
|
|
240,271 |
|
|
|
103,480 |
|
|
|
43 |
% |
|
|
|
Total general and
administrative expense |
|
$ |
4,204,226 |
|
|
$ |
2,437,239 |
|
|
$ |
1,766,987 |
|
|
|
72 |
% |
|
|
|
During the first six months of fiscal year 2007, salaries and benefits increased $1,051,811 over
the first six months of fiscal year 2006. The net increase was primarily the result of annual
bonuses incurred during the first quarter of fiscal year 2007 and increased compensation associated
with hiring additional personnel to support our growth, including our Chief Operating Officer,
three engineers and a geologist, including cash signing bonuses totaling $350,000 paid to such
personnel during the quarter. In addition, expense for the first six months of fiscal year 2007 includes
$250,000 severance paid to our former Chief Financial Officer and General Counsel who resigned in
October 2006.
During the first six months of fiscal year 2007, expense associated with share-based payments
increased $479,716 over the first six months of fiscal year 2006. Share-based payments for the
first six months of fiscal year 2007 represent non-cash expense recognized for the anticipated
vesting of restricted shares outstanding, the grant of 350,000 unrestricted common shares to newly
hired members of our technical team and the grant of 248,661 unrestricted common shares
to certain executive officers, employees and non-employee directors related to
bonuses and directors fees. During the first six months of
fiscal year 2006, we granted options to
purchase 495,000 common shares that were valued at $.80 per option using the Black-Scholes
valuation method. 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 six months of fiscal year 2007, professional and regulatory expenses increased
$131,980 over the first six months of fiscal year 2006. The net increase is due to higher
professional advisory fees of approximately $160,000, higher I.T. consulting fees of approximately
$65,000 related to implementation of our new management reporting and ERP system, and employee
relocation fees of approximately $155,000 incurred related to the hiring of our new technical team.
These increases were partially offset by lower professional and regulatory fees associated with
filing initial SEC registration statements and listing on the American Stock Exchange, including
legal, accounting, financial printing and initial listing fees, which decreased in the aggregate by
approximately $250,000 from the first six months of fiscal year 2006.
During the first six months of fiscal year 2007, other general and administrative expenses
increased $103,480 over the first six months of fiscal year 2006, primarily due to additional rent
and office expenses related to the Edwardsville, Illinois office,
which opened in May 2006, and
higher travel-related expenses associated with increased investor relations activities.
Depreciation, depletion and amortization expense During the first six months of fiscal year 2007,
DD&A increased $163,303 over the first six
months of fiscal year 2006. We compute DD&A on capitalized acquisition and development costs
(including gas collection equipment) using the units-of-production method based on estimates of
proved reserves, and on all other property and equipment using the straight-line method based on
estimated useful lives ranging from three to 10 years. The increase is primarily due to the
increase in capitalized development costs and an increase in production over the first six months
of fiscal year 2006. Additionally, depreciation expense increased due to additions to other
support equipment.
20
Other income During the first six months of fiscal year 2007, other income decreased
$137,523 from the first six months of fiscal year 2006, primarily due
to the gain of $127,416 that we
recognized on the sale of our investment in Hite Coalbed Methane L.L.C. in January 2006.
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, 2006. There were no material changes in these policies during the
current quarter.
Financial Condition
Our primary source of liquidity historically has come from the sale of our common shares in private
placements and the proceeds from the exercise of warrants and options to acquire our common shares.
To date, we have not relied significantly on borrowing to finance our operations or provide cash.
As of January 31, 2007, we had only $95,743 in long-term notes payable. From July 31, 2003 until
January 31, 2007, we raised $43,198,616 from the sale of our common shares. Additionally, during
that same period, we collected $6,728,810 and $2,042,280 as a result of the exercise of warrants
and stock options, respectively. Our primary use of these funds has been the acquisition,
exploration, testing and development of our CBM properties and rights
and payment of general and
administrative expenses required to support our operations.
We did not begin to generate revenues from CBM sales until January 2005. Revenues from CBM sales
were $540,909 and $537,505 for the first six months of fiscal years 2007 and 2006, respectively,
and $246,906 and $327,811 for the quarters ended January 31, 2007 and 2006, respectively. Subject
to the various risks described in this report, we expect revenue from the sale of our CBM to
increase due to (i) increased production from existing wells as
they continue to
dewater and (ii) additional production generated as a result of drilling and production
from additional wells. However, in view of the fact that we have very little historical experience
of dewatering and gas production in the Basin, we can provide no assurance that we will achieve a
trend of increased production and revenue in the future.
In addition, CBM wells typically must go through a lengthy dewatering phase before making a
significant contribution to gas production. We estimate that a typical vertical well will require
about 24 months to reach peak production. The impact on our cash position is that there will be a
delay of up to 24 months between the time we initially invest in drilling and completing a well and
the time when a typical well will begin to make a significant contribution to our cash from
operations. Additionally, net cash generated (used) by operating activities is dependent on a
number of factors over which we have little or no control. These factors include, but are not
limited to:
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the price of, and demand for, natural gas; |
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availability of drilling equipment; |
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lease terms; |
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availability of sufficient capital resources; and |
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the accuracy of production estimates for current and future wells. |
21
We had a cash balance of $10,255,781 as of January 31, 2007, compared to $19,279,015 at July 31,
2006. The net decrease in our cash balance is primarily due to the net cash used in operating
activities of $4,156,687, consisting primarily of payments for salaries and benefits, professional
fees and lease operating expenses adjusted for changes in working capital, and net cash used in
investing activities of $4,746,275, consisting of $3,719,803 of development costs, primarily at our
Northern Illinois Basin Project, and $1,026,472 of other property and equipment, which includes a
nitrogen rejection unit being installed at our Southern Illinois Basin Project, vehicles and
equipment to support development and other support equipment. We also made repayments of long-term
notes in the amount of $120,272 during the current fiscal year.
We have no significant contractual commitments for capital expenditures. However, our plan
anticipates that for the remaining six months of fiscal year 2007, we will spend approximately
$10.5 million to drill 50 new wells, which includes 29 development wells, 12 pilot wells, three
pressure observation wells, one water disposal well and five test wells. In addition to our
drilling program, we expect to continue to pursue the acquisition of additional CBM rights during
the fiscal year. We expect that the capital expenditure requirements related to our drilling
program and our other cash requirements will be funded by our cash balance and cash raised through
the sale of debt securities, equity securities, borrowings and/or joint ventures, all of which we
are actively pursuing. Although we are currently evaluating the best methods of raising these
funds, we can provide no assurance that we will be able to raise the necessary funds.
Cautionary Statement Concerning Forward-Looking Statements
Some of the statements contained in this report that are not historical facts, including statements
containing the words believes, anticipates, expects, intends, plans, should, may,
might, continue and estimate and similar words, constitute forward-looking statements under
the federal securities laws. These forward-looking statements involve known and unknown risks,
uncertainties and other factors that may cause our actual results, performance or achievements, or
the conditions in our industry, on our properties or in the Basin, to be materially
different from any future results, performance, achievements or conditions expressed or implied by
such forward-looking statements. Some of the factors that could cause actual results or conditions
to differ materially from our expectations, include, but are not
limited to: (a) our inability to
generate sufficient income or obtain sufficient financing to fund our operations or drilling plan
through July 31, 2007 or thereafter; (b) our inability to retain our acreage rights at our projects, at the
expiration of our lease agreements, due to insufficient CBM production, or for other reasons; (c)
our failure to accurately forecast CBM production; (d) displacement of our CBM operations by coal
mining operations, which have superior rights in most of our acreage; (e) our failure to accurately
forecast the number of wells that we can drill; (f) a decline in the prices that we receive for our
CBM production; (g) our failure to accurately forecast operating and capital expenditures and
capital needs due to rising costs or different drilling or production
conditions in the field; (h)
our inability to attract or retain qualified personnel with the
requisite CBM or other experience;
and (i) unexpected economic and market conditions, in the general economy or the market for natural
gas. We caution readers not to place undue reliance on these forward-looking statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk
Our major risk exposure is the commodity pricing applicable to our CBM production. Realized
commodity prices received for our production are primarily driven by the spot prices attributable
to natural gas. The effects of price volatility are expected to continue.
Interest Rate Risk
All of our debt has fixed interest rates, so consequently we are not exposed to cash flow or fair
value risk from market interest rate changes on this debt.
22
Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable and long-term
notes payable. The carrying amount of cash equivalents, accounts receivable and accounts payable
approximate fair market value due to the highly liquid nature of these short-term instruments.
Inflation and Changes in Prices
The general level of inflation affects our costs. Salaries and other general and administrative
expenses are impacted by inflationary trends and the supply and demand of qualified professionals
and professional services. Inflation and price fluctuations affect the costs associated with
exploring for and producing CBM, which has a material impact on our financial performance.
Item 4. Controls and Procedures
As of the end of the period covered by this report, we conducted an evaluation, under the
supervision and with the participation of our Chief Executive Officer and Controller (who is
currently responsible for performing certain functions of our principal financial officer), of the
effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)). Based on this
evaluation, our Chief Executive Officer and Controller have concluded that our disclosure controls
and procedures are effective to ensure that information required to be disclosed by us in reports
that we file or submit under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission rules and forms.
There have been no changes in our internal control over financial reporting identified in
connection with the evaluation required by Rule 13a-15(d) of the Exchange Act that occurred during
our last fiscal quarter that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
BPI Energy, Inc. (BPI) is currently subject to litigation with respect to approximately
115,000 acres of its CBM rights that are located at the Northern Illinois Basin Project. To date,
BPI has drilled one well on this acreage, a test well that was drilled in September 2006. This
well is not currently at the production stage.
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 extract CBM from coal beds
prior to the Drummond affiliates mining of coal from those beds. Pursuant to and in reliance upon
this letter of intent and its relationship with Drummond, BPI arranged for the transfer of 163,109
acres of coal rights to the Drummond affiliates for a total purchase price of $5,845,500, which BPI
believes reflects a significant discount to current market prices. In light of its obligations to
Drummond, BPI charged no profit on its transfer of the coal rights to the Drummond affiliates.
Rather, in consideration for obtaining those coal rights, the Drummond affiliates were to lease
approximately 115,000 acres of CBM rights to BPI for a primary lease term of 20 years and with
favorable royalty rates. Although the Drummond affiliates entered into two CBM leases with BPI on
April 26, 2006, they have since sought in various ways to void or terminate the leases.
Ignoring mandatory arbitration provisions in the CBM 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. Specifically, although the CBM leases include no specific drilling commitments,
IEC and Christian allege that BPI has breached the CBM leases by failing to use best efforts to
commercially produce all economically recoverable gas. IEC and Christian also allege that BPI has
breached the CBM leases by failing to provide maps of existing and proposed gas wells and
facilities every six months and failing to maintain required insurance coverage. BPI refutes each
of these allegations and intends to vigorously defend the Drummond affiliates claims of breach.
In addition, BPI has moved to dismiss the lawsuit for lack of standing, lack of personal
jurisdiction and improper venue, or in the alternative to transfer the case to either Ohio or
Illinois.
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. 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, and has also asserted claims for money
damages for breach of contract, breach of fiduciary duty, unjust enrichment and promissory
estoppel.
We believe that Drummond and its affiliates, after having received favorable coal rights in
exchange for favorable CBM rights, now wish to obtain a significant windfall by seeking to renege
on the CBM rights that they were obligated to grant to BPI.
We believe that we will be successful in either having the lawsuit filed by the Drummond affiliates
dismissed or in defending against their claims of breach. However, there can be no
assurance that we will be successful in maintaining these acreage rights. The loss of these
acreage rights would not have a material impact on our financial position, results of operations or
cash flows.
Item 1A. Risk Factors
There are no material changes to the risk factors previously reported in our Annual Report on Form
10-K for the fiscal year ended July 31, 2006. For more information regarding such risk factors,
please refer to Item 1A of our Annual Report on Form 10-K for the fiscal year ended July 31, 2006.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
We held our Annual Meeting of Shareholders on December 18, 2006. As described in the Proxy
Statement for the Annual Meeting, the following actions were taken:
(a) Election of Directors. The shareholders voted in favor of electing the following persons as
Directors:
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Name of Director |
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Number of Shares Voted For |
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Number of Shares Withheld |
James G. Azlein |
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37,043,661 |
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1,697,688 |
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Dennis Carlton |
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36,303,414 |
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2,437,935 |
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William J. Centa |
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36,285,691 |
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2,455,658 |
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David E. Preng |
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37,112,913 |
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1,628,436 |
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Costa Vrisakis |
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37,087,140 |
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1,654,209 |
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(b) |
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Appointment of Independent Registered Public Accounting Firm. The shareholders ratified the
appointment of Meaden & Moore, Ltd. as our independent registered public accounting firm for
2007. |
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Votes For |
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38,020,559 |
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Votes Against |
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0 |
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Abstentions |
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720,789 |
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Broker Non-Votes |
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1 |
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(c) |
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Approval of Amendment to the Omnibus Stock Plan. The shareholders approved an amendment to
the Omnibus Stock Plan to increase the cap on the aggregate
number of common shares that we can issue under the Plan from 5,000,000 to 7,000,000: |
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Votes For |
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10,099,906 |
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Votes Against |
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6,234,600 |
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Abstentions |
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0 |
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Broker Non-Votes |
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22,406,843 |
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Item 5. Other Information
None.
Item 6. Exhibits
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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. |
23
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:
March 19, 2007
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/s/ James G. Azlein
James G. Azlein,
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President and Chief Executive Officer |
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/s/ Randy L. Elkins |
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Randy L. Elkins, |
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Controller and Acting Chief Financial Officer |
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