UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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x |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the quarterly period ended July 31, 2007 |
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period from to |
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Commission File Number: 0-8877
CREDO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Colorado |
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84-0772991 |
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(State or other jurisdiction of incorporation or organization) |
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(IRS Employer Identification No.) |
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1801 Broadway, Suite 900, Denver, Colorado |
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80202 |
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(Address of principal executive offices) |
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(Zip Code) |
303-297-2200
(Registrant’s telephone number, including area code)
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 x 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 Act.)
Large accelerated filer o Accelerated filer x Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, net of treasury stock, as of the latest practicable date.
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Date |
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Class |
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Outstanding |
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Sept. 10, 2007 |
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Common stock, $.10 par value |
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9,329,000 |
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CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly Report on Form 10-Q For the Period Ended July 31, 2007
TABLE OF CONTENTS
The terms “CREDO”, “Company”, “we”, “our”, and “us” refer to CREDO Petroleum Corporation and its subsidiaries unless the context suggests otherwise.
2
PART I - FINANCIAL INFORMATION
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
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July 31, |
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October 31, |
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2007 |
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2006 |
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(Unaudited) |
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ASSETS |
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Current Assets: |
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Cash and cash equivalents |
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$ |
6,702,000 |
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$ |
4,577,000 |
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Short-term investments |
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6,301,000 |
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5,624,000 |
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Receivables: |
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Accrued oil and gas sales |
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1,783,000 |
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1,963,000 |
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Trade |
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406,000 |
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777,000 |
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Derivative Assets |
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1,320,000 |
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897,000 |
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Other current assets |
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229,000 |
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71,000 |
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Total current assets |
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16,741,000 |
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13,909,000 |
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Long-term assets: |
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Oil and gas properties, at cost, using full cost method: |
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Unevaluated oil and gas properties |
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9,071,000 |
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7,060,000 |
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Evaluated oil and gas properties |
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48,200,000 |
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43,588,000 |
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Less: accumulated depreciation, depletion and amortization of oil and gas properties |
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(21,417,000 |
) |
(18,556,000 |
) |
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Net oil and gas properties, at cost, using full cost method |
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35,854,000 |
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32,092,000 |
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Exclusive license agreement, net of amortization of $466,000 in 2007 and $431,000 in 2006 |
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216,000 |
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268,000 |
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Compressor and tubular inventory to be used in development |
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1,137,000 |
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1,293,000 |
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Other (net) |
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282,000 |
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197,000 |
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Total assets |
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$ |
54,230,000 |
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$ |
47,759,000 |
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LIABILITIES AND STOCKHOLDERS’ EQUITY |
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Current Liabilities: |
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Accounts payable |
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$ |
1,245,000 |
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$ |
1,581,000 |
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Revenue distribution payable |
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1,180,000 |
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1,273,000 |
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Other accrued liabilities |
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406,000 |
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808,000 |
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Income taxes payable |
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400,000 |
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174,000 |
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Total current liabilities |
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3,231,000 |
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3,836,000 |
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Long Term Liabilities: |
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Deferred income taxes, net |
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9,605,000 |
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8,039,000 |
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Exclusive license obligation, less current obligations of $70,000 in 2007 and 2006 |
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163,000 |
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163,000 |
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Asset retirement obligation |
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1,016,000 |
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954,000 |
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Total liabilities |
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14,015,000 |
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12,992,000 |
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Commitments |
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Stockholders’ Equity: |
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Preferred stock, no par value, 5,000,000 shares authorized, none issued |
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— |
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— |
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Common stock, $.10 par value, 20,000,000 shares authorized, 9,510,000 shares issued in 2007 and in 2006 |
|
951,000 |
|
951,000 |
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Capital in excess of par value |
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15,204,000 |
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14,794,000 |
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Treasury stock at cost, 181,000 shares in 2007 and 249,000 in 2006 |
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— |
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— |
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Accumulated other comprehensive income |
|
951,000 |
|
650,000 |
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Retained earnings |
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23,109,000 |
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18,372,000 |
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Total stockholders’ equity |
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40,215,000 |
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34,767,000 |
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Total liabilities and stockholders’ equity |
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$ |
54,230,000 |
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$ |
47,759,000 |
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The accompanying notes are an integral part of these consolidated financial statements.
3
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
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Nine Months Ended |
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Three Months Ended |
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July 31, |
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July 31, |
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||||||||
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2007 |
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2006 |
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2007 |
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2006 |
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REVENUES: |
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Oil and gas sales |
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$ |
12,308,000 |
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$ |
11,809,000 |
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$ |
3,814,000 |
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$ |
3,966,000 |
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Investment income and other |
|
685,000 |
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446,000 |
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233,000 |
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3,000 |
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||||
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12,993,000 |
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12,255,000 |
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4,047,000 |
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3,969,000 |
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COSTS AND EXPENSES: |
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Oil and gas production |
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2,546,000 |
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2,604,000 |
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837,000 |
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861,000 |
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Depreciation, depletion and amortization |
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2,782,000 |
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2,568,000 |
|
883,000 |
|
939,000 |
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General and administrative |
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1,020,000 |
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940,000 |
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376,000 |
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361,000 |
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Interest |
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20,000 |
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27,000 |
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6,000 |
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9,000 |
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||||
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6,368,000 |
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6,139,000 |
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2,102,000 |
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2,170,000 |
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INCOME BEFORE INCOME TAXES |
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6,625,000 |
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6,116,000 |
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1,945,000 |
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1,799,000 |
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INCOME TAXES |
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(1,888,000 |
) |
(1,743,000 |
) |
(554,000 |
) |
(513,000 |
) |
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NET INCOME |
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$ |
4,737,000 |
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$ |
4,373,000 |
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$ |
1,391,000 |
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$ |
1,286,000 |
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EARNINGS PER SHARE OF COMMON STOCK BASIC |
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$ |
.51 |
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$ |
.48 |
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$ |
.15 |
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$ |
.14 |
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EARNINGS PER SHARE OF COMMON STOCK DILUTED |
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$ |
.50 |
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$ |
.46 |
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$ |
.15 |
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$ |
.14 |
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Weighted average number of shares of Common Stock and dilutive securities: |
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|
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|
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|
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|
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||||
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Basic |
|
9,268,000 |
|
9,191,000 |
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9,282,000 |
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9,231,000 |
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||||
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Diluted |
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9,402,000 |
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9,512,000 |
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9,406,000 |
|
9,498,000 |
|
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The accompanying notes are an integral part of these consolidated financial statements.
4
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Statement of Stockholders’ Equity and Comprehensive Income
(Unaudited)
For the Nine Months Ended July 31, 2007
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Accumulated |
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Capital In |
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Other |
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Total |
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Common Stock |
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Excess Of |
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Comprehensive |
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Retained |
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Stockholders’ |
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Shares |
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Amount |
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Par Value |
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Income |
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Earnings |
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Equity |
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|||||
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Balance, October 31, 2006 |
|
9,510,000 |
|
$ |
951,000 |
|
$ |
14,794,000 |
|
$ |
650,000 |
|
$ |
18,372,000 |
|
$ |
34,767,000 |
|
|
Comprehensive income: |
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|
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|
|
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|
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Net income |
|
— |
|
— |
|
— |
|
— |
|
4,737,000 |
|
4,737,000 |
|
|||||
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Other comprehensive income: |
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|
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|
|
|
|
|
|
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|
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|||||
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Change in fair value of derivatives, net of tax |
|
— |
|
— |
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— |
|
301,000 |
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— |
|
301,000 |
|
|||||
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Exercise of common stock options |
|
— |
|
— |
|
272,000 |
|
— |
|
— |
|
272,000 |
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|||||
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Compensation expense associated with unvested portion of previously granted stock options |
|
— |
|
— |
|
138,000 |
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— |
|
— |
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138,000 |
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Balance, July 31, 2007 |
|
9,510,000 |
|
$ |
951,000 |
|
$ |
15,204,000 |
|
$ |
951,000 |
|
$ |
23,109,000 |
|
$ |
40,215,000 |
|
The accompanying notes are an integral part of these consolidated financial statements.
5
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
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|
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Nine Months Ended |
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July 31, |
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2007 |
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2006 |
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CASH FLOWS FROM OPERATING ACTIVITIES: |
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Net income |
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$ |
4,737,000 |
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$ |
4,373,000 |
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|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
||
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Depreciation, depletion and amortization |
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2,782,000 |
|
2,568,000 |
|
||
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Deferred income taxes |
|
1,566,000 |
|
1,409,000 |
|
||
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Compensation expense related to stock options granted |
|
138,000 |
|
165,000 |
|
||
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Other |
|
63,000 |
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(98,000 |
) |
||
|
Changes in operating assets and liabilities: |
|
|
|
|
|
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Proceeds from short-term investments |
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1,492,000 |
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193,000 |
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Purchase of short-term investments |
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(2,169,000 |
) |
(556,000 |
) |
||
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Accrued oil and gas sales |
|
180,000 |
|
658,000 |
|
||
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Trade receivables |
|
371,000 |
|
(123,000 |
) |
||
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Other current assets |
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(281,000 |
) |
336,000 |
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||
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Accounts payable and accrued liabilities |
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(831,000 |
) |
623,000 |
|
||
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Income taxes payable |
|
226,000 |
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(199,000 |
) |
||
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NET CASH PROVIDED BY OPERATING ACTIVITIES |
|
8,274,000 |
|
9,349,000 |
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CASH FLOWS FROM INVESTING ACTIVITIES: |
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|
|
|
|
||
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Additions to oil and gas properties |
|
(6,794,000 |
) |
(9,054,000 |
) |
||
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Proceeds from sale of oil and gas properties |
|
171,000 |
|
824,000 |
|
||
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Changes in other long-term assets |
|
202,000 |
|
(26,000 |
) |
||
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|
|
|
|
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||
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NET CASH USED IN INVESTING ACTIVITIES |
|
(6,421,000 |
) |
(8,256,000 |
) |
||
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CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
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|
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Proceeds from exercise of stock options (67,000 options in 2007 and 130,000 options in 2006) |
|
272,000 |
|
756,000 |
|
||
|
|
|
|
|
|
|
||
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NET CASH PROVIDED BY FINANCING ACTIVITIES |
|
272,000 |
|
756,000 |
|
||
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|
|
|
|
|
|
||
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INCREASE IN CASH AND CASH EQUIVALENTS |
|
2,125,000 |
|
1,849,000 |
|
||
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|
|
|
|
|
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||
|
CASH AND CASH EQUIVALENTS: |
|
|
|
|
|
||
|
Beginning of period |
|
4,577,000 |
|
1,935,000 |
|
||
|
|
|
|
|
|
|
||
|
End of period |
|
$ |
6,702,000 |
|
$ |
3,784,000 |
|
|
|
|
|
|
|
|
||
|
Supplemental cash flow information: |
|
|
|
|
|
||
|
Cash paid during the period for income taxes |
|
$ |
207,000 |
|
$ |
615,000 |
|
The accompanying notes are an integral part of these consolidated financial statements.
6
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To Consolidated Financial Statements (Unaudited)
July 31, 2007
1. BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been prepared in accordance with U. S. generally accepted accounting principles for interim financial information and with the instructions for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U. S. generally accepted accounting principles for complete financial statements. In the opinion of management, the consolidated financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the company’s results for the periods presented. These consolidated financial statements should be read in conjunction with the company’s Annual Report on Form 10-K for the fiscal year ended October 31, 2006.
2. SIGNIFICANT ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts.
The company has changed its estimate with respect to estimated salvage value of lease and well equipment. This change in estimate resulted in a decrease in depreciation, depletion and amortization of approximately $65,000 and $195,000 for the three and nine month periods ended July 31, 2007.
The company previously had one stock-based employee compensation plan, the CREDO Petroleum Corporation 1997 Stock Option Plan (the 1997 Plan) which is described in the Notes to Consolidated Financial Statements in the company’s Annual Report on Form 10-K for the year ended October 31, 2006. This Plan expired on July 29, 2007. The CREDO Petroleum Corporation 2007 Stock Option Plan (the 2007 Plan), which is similar in all respects to the 1997 Plan, was approved by the shareholders at the Annual Meeting of Shareholders on March 22, 2007. No additional options can be granted under the 1997 Plan. However, all outstanding options granted under the 1997 Plan will continue to be governed by the rules of the 1997 Plan.
The company recognized compensation expense related to its stock option plan of $138,000 and $165,000 for the nine months ended July 31, 2007 and 2006 respectively. For the three months ended July 31, 2007 and 2006, the company recognized compensation expense of $28,000 and $46,000, respectively.
No options were granted during fiscal year 2006 and the fair value of the 40,000 options granted during the nine months ended July 31, 2007 was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions: volatility, 50.84%; expected option term, 2 to 3 years; risk-free interest rate, 4.58% and; expected dividend yield, 0%. If option grants are made in the future, compensation expense for all such share-based payments granted, based upon the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R) will also be included in compensation expense.
7
Plan activity for the nine months ended July 31, 2007 is set forth below:
|
|
|
Nine Months Ended July 31,2007 |
|
|||
|
|
|
Number of |
|
Weighted |
|
|
|
Outstanding at October 31, 2006 |
|
315,002 |
|
$ |
5.52 |
|
|
Granted |
|
40,000 |
|
12.78 |
|
|
|
Exercised |
|
(67,937 |
) |
4.02 |
|
|
|
Cancelled or forfeited |
|
(564 |
) |
5.93 |
|
|
|
Outstanding at July 31, 2007 |
|
286,501 |
|
$ |
6.89 |
|
|
|
|
|
|
|
|
|
|
Exercisable at July 31, 2007 |
|
253,168 |
|
$ |
6.11 |
|
|
|
|
|
|
|
|
|
|
Weighted average contractual life at July 31, 2007 |
|
|
|
6.36 |
years |
|
|
|
|
|
|
|
|
|
|
Weighted average market price at date of exercise for options exercised |
|
|
|
$ |
13.47 |
|
The following table summarizes information about stock options currently outstanding and exercisable at July 31, 2007:
|
|
|
Outstanding |
|
Exercisable |
|
||||||||
|
Range of |
|
Number |
|
Weighted Average |
|
Weighted |
|
Number |
|
Weighted |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
$ 5.93 |
|
246,501 |
|
5.87 |
|
$ |
5.93 |
|
246,501 |
|
$ |
5.93 |
|
|
$12.78 |
|
40,000 |
|
9.35 |
|
$ |
12.78 |
|
6,667 |
|
$ |
12.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
$ 5.93 -$12.78 |
|
286,501 |
|
6.36 |
|
$ |
6.89 |
|
253,168 |
|
$ |
6.11 |
|
Total estimated unrecognized compensation cost from unvested stock options as of July 31, 2007 was approximately $138,000, which is expected to be recognized over an average period of approximately 2.0 years.
4. NATURAL GAS PRICE HEDGING
The company periodically hedges the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated. Hedging transactions typically take the form of forward short positions and collars on the NYMEX futures market, and are closed by purchasing offsetting positions. Such hedges, which are accounted for as cash flow hedges, do not exceed estimated production volumes, are expected to have reasonable correlation between price movements in the futures market and the cash markets where the company’s production is located, and are authorized by the company’s Board of Directors. Hedges are expected to be closed as related production occurs but may be closed earlier if the anticipated downward price movement occurs or if the company believes that the potential for such movement has abated.
The company recognizes all derivatives (consisting solely of cash flow hedges) on its balance sheet at fair value at the end of each period. Changes in the fair value of a cash flow hedge are recorded in Stockholders’ Equity as Accumulated Other Comprehensive Income on the Consolidated Balance Sheets
8
and then are transferred into the Consolidated Statement of Operations as the underlying hedged item affects earnings. Amounts reclassified into earnings related to natural gas hedges are included in oil and gas sales.
Hedging gains and losses are recognized as adjustments to gas sales as the hedged product is produced. The company had hedging gains of $1,187,000 in the nine months ended July 31, 2007, and hedging losses of $266,000 for the same period in 2006. Hedging gains were $201,000 for the quarter ended July 31, 2007. There was no hedging activity in the same period in 2006. Any hedge ineffectiveness, which was not material for any period, is immediately recognized in gas sales.
Current hedging positions, indexed to NYMEX, for production months after third quarter end totaled 1.13 Bcf covering the production months of August 2007 through March 2008. These hedges are intended to cover between 65% and 80% of the company’s current production base without taking into consideration estimates of new production from future operations. The average monthly hedge price (NYMEX basis) ranges from $7.90 in the fall to $9.53 in the winter. Deferred hedging gains at July 31, 2007 related to such hedging positions were $1,320,000 ($951,000 net of income tax). These amounts have been included in Accumulated Other Comprehensive Income of $951,000 and Derivative Assets of $1,320,000.
The company has a hedging line of credit with its bank which is available, at the discretion of the company, to meet margin calls. To date, the company has not used this facility and maintains it only as a precaution related to possible margin calls. The maximum credit line is $4,500,000 with interest calculated at the prime rate. The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments, none of which are required to be maintained at the company’s bank, and prohibits unfunded debt in excess of $500,000. It expires on October 31, 2007.
5. COMPREHENSIVE INCOME
Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The components of comprehensive income for the three and nine months ended July 31, 2007 and 2006 are as follows:
|
|
|
Nine Months Ended |
|
Three Months Ended |
|
||||||||
|
|
|
July 31, |
|
July 31, |
|
||||||||
|
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net income |
|
$ |
4,737,000 |
|
$ |
4,373,000 |
|
$ |
1,391,000 |
|
$ |
1,286,000 |
|
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
||||
|
Change in fair value of derivatives |
|
423,000 |
|
425,000 |
|
1,466,000 |
|
— |
|
||||
|
Income tax expense |
|
(122,000 |
) |
(119,000 |
) |
(410,000 |
) |
— |
|
||||
|
Total comprehensive income |
|
$ |
5,038,000 |
|
$ |
4,679,000 |
|
$ |
2,447,000 |
|
$ |
1,286,000 |
|
9
6. EARNINGS PER SHARE
The company’s calculation of earnings per share of common stock is as follows:
|
|
|
Nine Months Ended July 31, |
|
||||||||||||||
|
|
|
2007 |
|
2006 |
|
||||||||||||
|
|
|
|
|
|
|
Net |
|
|
|
|
|
Net |
|
||||
|
|
|
Net |
|
|
|
Income |
|
Net |
|
|
|
Income |
|
||||
|
|
|
Income |
|
Shares |
|
Per Share |
|
Income |
|
Shares |
|
Per Share |
|
||||
|
Basic earnings per share |
|
$ |
4,737,000 |
|
9,268,000 |
|
$ |
.51 |
|
$ |
4,373,000 |
|
9,191,000 |
|
$ |
.48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Effect of dilutive shares of common stock from stock options |
|
— |
|
134,000 |
|
(.01 |
) |
— |
|
321,000 |
|
(.02 |
) |
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Diluted earnings per share |
|
$ |
4,737,000 |
|
9,402,000 |
|
$ |
.50 |
|
$ |
4,373,000 |
|
9,512,000 |
|
$ |
.46 |
|
|
|
|
Three Months Ended July 31, |
|
||||||||||||||
|
|
|
2007 |
|
2006 |
|
||||||||||||
|
|
|
|
|
|
|
Net |
|
|
|
|
|
Net |
|
||||
|
|
|
Net |
|
|
|
Income |
|
Net |
|
|
|
Income |
|
||||
|
|
|
Income |
|
Shares |
|
Per Share |
|
Income |
|
Shares |
|
Per Share |
|
||||
|
Basic earnings per share |
|
$ |
1,391,000 |
|
9,282,000 |
|
$ |
.15 |
|
$ |
1,286,000 |
|
9,231,000 |
|
$ |
.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Effect of dilutive shares of common stock from stock options |
|
— |
|
124,000 |
|
— |
|
— |
|
267,000 |
|
— |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Diluted earnings per share |
|
$ |
1,391,000 |
|
9,406,000 |
|
$ |
.15 |
|
$ |
1,286,000 |
|
9,498,000 |
|
$ |
.14 |
|
7. INCOME TAXES
The company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.
The total future deferred income tax liability is extremely complicated for any energy company to estimate due in part to the long-lived nature of depleting oil and gas reserves and variables such as product prices. Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.
8. COMMITMENTS
The company has no material outstanding commitments at July 31, 2007.
10
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes certain statements that may be deemed to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included in this Quarterly Report on Form 10-Q, other than statements of historical facts, address matters that the company reasonably expects, believes or anticipates will or may occur in the future. Forward-looking statements may relate to, among other things:
· the company’s future financial position, including working capital and anticipated cash flow;
· amounts and nature of future capital expenditures;
· operating costs and other expenses;
· wells to be drilled or reworked;
· oil and natural gas prices and demand;
· existing fields, wells and prospects;
· diversification of exploration;
· estimates of proved oil and natural gas reserves;
· reserve potential;
· development and drilling potential;
· expansion and other development trends in the oil and natural gas industry;
· the company’s business strategy;
· production of oil and natural gas;
· matters related to the Calliope Gas Recovery System;
· effects of federal, state and local regulation;
· insurance coverage;
· employee relations;
· investment strategy and risk; and
· expansion and growth of the company’s business and operations.
LIQUIDITY AND CAPITAL RESOURCES
At July 31, 2007, working capital increased $4,590,000, or 51% to $13,510,000 compared to $8,920,000 at July 31, 2006. For the nine months ended July 31, 2007, net cash provided by operating activities decreased $1,075,000 to $8,274,000 compared to net cash provided by operating activities of $9,349,000 for the same period in 2006. Net income increased $364,000 primarily due to an increase in revenues of $738,000, partially offset by an increase in depreciation, depletion and amortization (DD&A) of $214,000.
For the nine months ended July 31, 2007 and 2006, net cash used in investing activities was $6,421,000 and $8,256,000, respectively. Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $6,794,000 and $9,054,000 respectively.
The average return on the company’s investments for the nine months ended July 31, 2007 and 2006 was 9.2% and 6.0%, respectively. At July 31, 2007, approximately 46% of the investments were directly invested in mutual funds and were managed by professional money managers. Remaining investments are in managed partnerships (generally known as hedge funds) that use various strategies to minimize their correlation to stock market movements. Most of the investments are highly liquid and the company
11
believes they represent a responsible approach to cash management. In the company’s opinion, the greatest investment risk is the potential for negative market impact from unexpected, major adverse news.
Existing working capital and anticipated cash flow are expected to be sufficient to fund operations and capital commitments for at least the next 12 months. At July 31, 2007, the company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in Note 4. Because earnings are anticipated to be reinvested in operations, cash dividends are not expected to be paid. The company has no defined benefit plans and no obligations for post retirement employee benefits.
The company’s earnings before interest, taxes, depreciation, depletion and amortization, (“EBITDA”) increased to $9,427,000 for the nine months ended July 31, 2007 from $8,711,000 for the nine months ended July 31, 2006. EBITDA is not a GAAP measure of operating performance. The company uses this non-GAAP performance measure primarily to compare its performance with other companies in the industry that make a similar disclosure. The company believes that this performance measure may also be useful to investors for the same purpose. Investors should not consider this measure in isolation or as a substitute for operating income, or any other measure for determining the company’s operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. A reconciliation between EBITDA and net income is provided in the table below:
|
|
Nine Months Ended July 31, |
|
|||||
|
|
|
2007 |
|
2006 |
|
||
|
RECONCILIATION OF EBITDA: |
|
|
|
|
|
||
|
Net Income |
|
$ |
4,737,000 |
|
$ |
4,373,000 |
|
|
Add Back: |
|
|
|
|
|
||
|
Interest Expense |
|
20,000 |
|
27,000 |
|
||
|
Income Tax Expense |
|
1,888,000 |
|
1,743,000 |
|
||
|
Depreciation, Depletion and Amortization Expense |
|
2,782,000 |
|
2,568,000 |
|
||
|
EBITDA |
|
$ |
9,427,000 |
|
$ |
8,711,000 |
|
OFF-BALANCE SHEET FINANCING
The company has no significant off-balance sheet financing arrangements at July 31, 2007.
PRODUCT PRICES AND PRODUCTION
Although product prices are key to the company’s ability to operate profitably and to budget capital expenditures, they are beyond the company’s control and are difficult to predict. Since 1991, the company has periodically hedged the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated. Hedging transactions typically take the form of forward short positions, swaps and collars which are executed on the NYMEX futures market or by indexing to regional index prices associated with pipelines in proximity to the company’s production. The company’s current hedges are indexed to NYMEX. Refer to Note 4 of the Consolidated Financial Statements for a complete discussion on the company’s hedging activities.
12
Gas and oil sales volume and price realization comparisons for the indicated periods are set forth below. Price realizations include the sales price and the effect of hedging transactions.
|
|
|
Nine Months Ended July 31, |
|
||||||||||||
|
|
|
2007 |
|
2006 |
|
% Change |
|
||||||||
|
Product |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Gas (Mcf) |
|
1,517,000 |
|
$ |
6.72 |
(1) |
1,528,000 |
|
$ |
6.46 |
(2) |
- 1 |
% |
+ 4 |
% |
|
Oil (bbls) |
|
37,200 |
|
$ |
56.52 |
|
31,400 |
|
$ |
61.74 |
|
+ 19 |
% |
- 8 |
% |
|
|
|
Three Months Ended July 31, |
|
||||||||||||
|
|
|
2007 |
|
2006 |
|
% Change |
|
||||||||
|
Product |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Gas (Mcf) |
|
494,000 |
|
$ |
6.21 |
(3) |
563,000 |
|
$ |
5.70 |
|
- 12 |
% |
+ 9 |
% |
|
Oil (bbls) |
|
12,100 |
|
$ |
62.36 |
|
11,600 |
|
$ |
65.80 |
|
+ 4 |
% |
- 5 |
% |
(1) Includes $0.77 per Mcf hedging gain.
(2) Includes $0.18 per Mcf hedging loss.
(3) Includes $0.41 per Mcf hedging gain.
OPERATIONS
During the first nine months of fiscal 2007, the company’s operations continued to focus on its two core projects – natural gas drilling and application of its patented Calliope Gas Recovery System.
The company believes that, in combination, its drilling and Calliope projects provide an excellent (and possibly unique) balance for achieving its goal of adding long-lived natural gas reserves and production at reasonable costs and risks. However, it should be expected that successful results will occur unevenly for both the drilling and Calliope projects. Drilling results are dependent on both the timing of drilling and on the drilling success rate. Calliope results are primarily dependent on the timing, volume and quality of Calliope installations available to the company.
The company will continue to actively pursue adding reserves through its two core projects in fiscal 2007, and expects these activities to be a reliable source of reserve additions. However, the timing and extent of such activities can be dependent on many factors which are beyond the company’s control, including but not limited to, the availability, cost and quality of oil field services such as drilling rigs, production equipment and related services, and access to wells for application of the company’s patented gas recovery system on low pressure gas wells. The prevailing price of oil and natural gas has a significant effect on demand and, thus, the related cost of such services and wells.
The cost of field services, particularly the cost of drilling wells, has increased dramatically during the past several years, driven by higher energy prices. Concurrently, the quality of field services has diminished markedly due to manpower shortages. The combination of much higher field service costs and degradation in the quality of the services is having a materially negative impact on drilling economics. Accordingly, the company continues to high-grade its drilling prospects, and in some cases postpone less robust projects pending improvement in the field services sector. In the short term, this will reduce the number of drilling prospects which may, in turn, impede the growth of the company’s production and reserves
The company is currently experiencing delays in securing drilling rigs and delivery of production equipment, primarily compressors and coil tubing. These delays are extending the time it takes the
13
company to conduct its field operations. As a result, the company could be at risk for price increases related to these types of services and equipment.
All of the company’s oil and natural gas properties are located on-shore in the continental United States. The company’s future drilling activities may not be successful, and its overall drilling success rate may change. Unsuccessful drilling activities could have a material adverse effect on the company’s results of operations and financial condition. Also, the company may not be able to obtain the right to drill in areas where it believes there is significant potential for the company.
Drilling Activities.
Oklahoma and Texas Panhandle—The company drills primarily on its significant Northern Anadarko Basin acreage inventory (totaling over 75,000 gross acres) where it has drilled about 80 wells. Wells target the Morrow, Oswego and Chester formations between 7,000 and 11,000 feet.
In Canadian County, Oklahoma, the 11,500-foot Chappell #1-14 well is the fourth well drilled on the 640 gross acre Loosen Prospect. The well encountered pay zones in five separate formations. Electric logs and drilling data indicate that the well contains 119 feet of productive interval, including the Redfork and Skinner sands and the Oswego limestone. The Chappell well is a north offset to the recently drilled Hazel well which was completed producing 2.0 MMcf (million cubic feet of gas) and 72 barrels of oil per day. Drilling data and electric logs indicate that the Chappell well contains more pay zones and more total productive interval than the Hazel well. The well is currently awaiting completion for pipeline sales. CREDO owns a 16.5% working interest. Additional drilling is expected to further develop this multiple pay prospect.
In Harper County, Oklahoma, a 3-D seismic survey was recently completed over the company’s 3,840 gross acre Buffalo Creek Prospect. Six producing wells have previously been completed on the prospect. Initially, four to six new locations have been identified, based on the seismic survey. Two locations have been drilled and one is currently being readied for drilling. Additional locations are expected to be identified as drilling progresses.
The first well drilled based on the new 3-D survey encountered 13 feet of productive sand in the Oswego formation with porosity averaging 22%. The 6,500-foot Lauer #2-21 flowed oil from a natural completion. On pump, the well is currently producing at rates of approximately 60 barrels of oil and 80 Mcfg (thousand cubic feet of gas) per day. An offset well is scheduled to be drilled this Fall. CREDO owns a 30% working interest and is the operator.
The Owens A-3, the second well, was recently drilled and encountered 26 feet of Morrow and Chester sand which electric logs indicate are productive. The well is currently being completed for production. CREDO owns a 30% working interest in the well.
Elsewhere on the Buffalo Creek Prospect, two wells are being readied for drilling based on the 3-D seismic survey. Both wells target the Oswego, Morrow and Chester formations. CREDO will own a 31% working interest in one of the wells and a 45% working interest in the other well.
In Ellis County, Oklahoma, the fifth producing well has been drilled on the 1,280 gross acre Gage Prospect. The 9,500-foot Gottshall #1-32 well encountered 31 feet of productive Morrow sands, and has been completed flowing about 800 Mcfd. CREDO owns a 31% working interest in the well.
In Carter County, Oklahoma, the Southeast Hewitt Waterflood Unit has produced over 550,000 incremental barrels of oil and has significantly outperformed initial expectations. As a result of development drilling, production from the unit has recently increased about 40% to 265 barrels of oil per day. CREDO owns a 17% working interest.
14
As previously reported, the Humphreys #1D was the first well drilled on the Humphreys Prospect in the Texas Panhandle. The wildcat well encountered excellent quality Morrow sands at 11,200 feet, and initially tested at rates of about 3.0 MMcfd. However, a rapid decline in production indicates that the reservoir is limited in size at the well location. The well is currently producing at a stabilized rate of 150 Mcf per day. The company has recently acquired seismic and additional acreage to expand the prospect from 2,500 to 3,780 gross acres. Based on a preliminary interpretation of 3-D seismic, additional drilling is expected to commence this fall. CREDO owns a 25% working interest.
The third well drilled on the company’s 1,280 gross acre Saddle Prospect located in Harper County, Oklahoma was a dry hole. The 6,900-foot well encountered thin and tight sands in the Morrow formation. Also in Harper County, the wildcat well on the 1,920 gross acre Randall Prospect encountered thin and tight Morrow sands and was a dry hole.
South Texas—As previously reported, the first two South Texas prospects have been drilled and both wells are producers. Drilling is expected to commence shortly on a third prospect, and five prospects are currently being marketed to drilling participants.
In Jim Hogg County, a wildcat well is scheduled to commence shortly to test the company’s 1,160 gross acre West Mestena Prospect. The 10,500-foot well targets Queen City sands which produce prolifically in nearby fields. To reduce its risk, the company sold a portion of its interest to a drilling participant for cash consideration and a “carried interest” in the first well. The company will own a 9.375% working interest in the wildcat well and in all future drilling on the prospect. If the wildcat well is successful, there are up to eight additional drilling locations.
Five South Texas prospects are currently being marketed to drilling participants. Two of the prospects are located in Hidalgo County and target Upper Frio sands between 8,000 and 12,500 feet. In Jim Hogg County, three wildcat prospects will test Wilcox sands at 15,000 to 17,000 feet. The company will sell a portion of its interest in these prospects for cash consideration and a “carried interest” on the initial test well to be drilled on each prospect. The company will preserve its option to participate in all wells for a portion of its interest which is expected to range from 9% to 18%.
North-Central Kansas—CREDO has assembled three separate oil drilling projects located along the Central Kansas Uplift in Kansas. The three projects encompass about 30,000 gross acres in which the company owns interests ranging from 12.5% to 90%. The acreage is located in prolific oil producing areas where 3-D seismic has recently proven to be an effective exploration tool. Drilling targets the Lansing-Kansas City and Arbuckle formations at 3,500 to 4,000 feet. Well costs are moderate at about $300,000. Four wells are scheduled to be drilled during the next 90 days.
Two wells have recently been drilled on the company’s 4,000 gross acre Lucerne Prospect. The Slipke #1-23 is a step-out from the recently drilled Ficken #1 well, which is an excellent oil well having produced 25,000 barrels in nine months. The Ficken well is currently producing about 100 barrels of oil per day and no water. The Slipke well encountered four feet of Lansing-Kansas City that electric logs indicate is productive. The well has swab tested at 10 barrels of oil per hour and a pumping unit is currently being installed. The second well, Brandt #1-22, encountered wet Lansing-Kansas City sands resulting in a dry hole. Additional drilling will commence shortly on two prospects. CREDO owns a 30% working interest in the prospects.
15
Calliope Gas Recovery Technology.
The company owns the exclusive right to a patented technology known as the Calliope Gas Recovery System. There are currently three U.S. patents and one Canadian patent related to the technology. Two additional patents that mirror the U.S. patents have been applied for in Canada.
Calliope can achieve substantially lower flowing bottom-hole pressure than conventional production methods because it does not rely on reservoir pressure to lift liquids. In many reservoirs, lower bottom-hole pressure can translate into recovery of substantial additional natural gas reserves.
Calliope has proven to be reliable and flexible over a wide range of applications on wells the company owns and operates. It has also proven to be consistently successful. Accordingly, the company is implementing strategies designed to expand the population of wells on which it can install Calliope.
Realizing Calliope’s value continues to be one of the company’s top priorities. The company is focused on three fronts to increase the number of Calliope installations: expanding the geographic region for purchasing Calliope candidate wells from third parties, joint ventures with larger companies, and drilling wells into low-pressure gas reservoirs for the purpose of using Calliope to recover stranded natural gas reserves.
Purchasing Calliope Candidate Wells—Calliope systems are currently installed on 18 wells owned and operated by the company. The wells are located in Oklahoma, Texas and Louisiana, and range in depth from 6,500 to 18,400 feet. They represent the most rigorous applications for Calliope because the wells were either totally dead or uneconomic at the time Calliope was installed. In addition, prior to the time Calliope was installed, many of the reservoirs were damaged by the “parting shots” of previous operators. Initial Calliope production rates range up to 650 Mcfd (thousand cubic feet of gas per day) and average per well Calliope reserves for non-prototype wells are estimated to be 1.10 Bcf. One of the company’s early Calliope installations, the J.C. Carroll well, has now produced over a billion cubic feet of gas since the Calliope installation.
Calliope operations have been expanded into Texas and Louisiana with two installations in southwest Texas and one in Louisiana. The company considers Texas and Louisiana to be very fertile areas for Calliope and has retained personnel and opened a Houston office to focus exclusively on Calliope.
In general, higher gas prices have made it increasingly difficult for the company to purchase wells for its Calliope system. In addition, higher gas prices have provided the incentive for other companies to perform high risk procedures (“parting shots”) in an attempt to revive wells prior to abandoning or selling the wells. These parting shots often result in severe reservoir damage that renders wells unsuitable for Calliope.
Joint Ventures With Third Parties—In an effort to increase the number of Calliope installations, the company is seeking joint ventures with larger companies. Presentations have been made to a select group of companies, including majors and large independents. All of the companies have expressed a keen interest in Calliope. The company has recently entered into a joint venture agreement with an independent oil and gas operator covering a pilot Calliope installation. The two companies are in the process of selecting a pilot location. Joint venture discussions are continuing with a number of the companies, including evaluation of candidate wells.
The joint venture negotiation process has taken longer than expected because there are many decision points within large companies that cause delays. Nevertheless, the company continues to dedicate resources and make efforts as it believes that the company will eventually be successful in the joint venture area.
16
In June 2007, CREDO entered into a joint venture to purchase the 11,000-foot Simpson well, located in a prolific producing area of Texas. The previous operator drilled the well and encountered low reservoir pressure. After unsuccessful attempts to make the well produce, the operator sold the well to the CREDO joint venture for $65,000 (salvage value). Calliope was installed and immediately brought the well to life, producing at the rate of 250 Mcf (thousand cubic of gas) per day.
Also, in July, a joint venture was entered into to purchase an 11,500-foot well located in Hemphill County, Texas. Calliope is expected to be installed this fall. CREDO owns a 70% interest in the venture.
Results of Operations
For the nine months ended July 31, 2007, total revenues increased 6% to $12,993,000 compared to $12,255,000 last year. As the oil and gas price/volume table on page 13 shows, total gas price realizations, which reflect hedging transactions, increased 4% to $6.72 per Mcf and oil price realizations fell 8% to $56.52 per barrel. The net effect of these price changes was to increase oil and gas sales by $234,000. For the nine months ended July 31, 2007, the company’s gas equivalent production increased 1%. The effect of the volume change was to increase oil and gas sales by $265,000. Investment income and other increased $239,000 primarily due to improved performance of the company’s investments.
For the nine months ended July 31, 2007, total costs and expenses rose 4% to $6,368,000 compared to $6,139,000 for the comparable period in 2006. Oil and gas production expenses fell 2% due primarily to a decrease in production taxes. Depreciation, depletion and amortization (“DD&A”) increased primarily due to an increase in the amortizable cost base. General and administrative expenses increased 9% primarily due to accounting and professional fees. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28.5% for the 2007 and 2006 periods. This differs from an expected rate of 34% due to the availability of statutory depletion deduction.
Three Months Ended July 31, 2007 Compared to Three Months Ended July 31, 2006
For the three months ended July 31, 2007, total revenues increased 2% to $4,047,000 compared to $3,969,000 during the same period last year. As the oil and gas price/volume table on page 13 shows, total gas price realizations, which reflect hedging transactions, increased 9% to $6.21 per Mcf and oil price realizations declined 5% to $62.36 per barrel. The net effect of these price changes was to increase oil and gas sales by $222,000. For the three months ended July 31, 2007, the company’s gas equivalent production fell 11% resulting in an oil and gas sales decrease of $374,000. Investment and other income increased $230,000 primarily due to performance of the company’s investments, compared to last year.
For the three months ended July 31, 2007, total costs and expenses fell 3% to $2,102,000 compared to $2,170,000 for the comparable period in 2006. Oil and gas production expenses fell due primarily to a decrease in production taxes. DD&A declined primarily due to lower production partially offset by an increase in the amortizable cost base. General and administrative expenses increased primarily due to accounting and professional fees. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28.5% for both periods.
SIGNIFICANT ACCOUNTING POLICIES
The company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and natural gas properties, the accounting for oil and gas reserves, and the estimate of its asset retirement obligations.
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OIL AND GAS PROPERTIES. The company uses the full cost method of accounting for costs related to its oil and natural gas properties. Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method. Depreciation, depletion and amortization is a significant component of oil and natural gas properties. A change in proved reserves without a corresponding change in capitalized costs will cause the depletion rate to increase or decrease.
Both the volume of proved reserves and any estimated future expenditures used for the depletion calculation are based on estimates such as those described under “Oil and Gas Reserves” below.
The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling.
The company has made only one ceiling write-down in its 28-year history. That write down was made in 1986 after oil prices fell 51% and natural gas prices fell 45% between fiscal year end 1985 and 1986.
Changes in oil and natural gas prices have historically had the most significant impact on the company’s ceiling test. In general, the ceiling is lower when prices are lower. Even though oil and natural gas prices can be highly volatile over weeks and even days, the ceiling calculation dictates that prices in effect as of the last day of the test period be used and held constant. The resulting valuation is a snapshot as of that day and, thus, is generally not indicative of a true fair value that would be placed on the company’s reserves by the company or by an independent third party. Therefore, the future net revenues associated with the estimated proved reserves are not based on the company’s assessment of future prices or costs, but rather are based on prices and costs in effect as of the end the test period.
OIL AND GAS RESERVES. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the company’s oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves. Oil and natural gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the company’s control. Accordingly, reserve estimates are often different from the quantities of oil and natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
ASSET RETIREMENT OBLIGATIONS. The company estimates the future cost of asset retirement obligations, discounts that cost to its present value, and records a corresponding asset and liability in its Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, market risk premiums, useful life, and cost of capital. The nature of these estimates requires the company to make judgments based on historical experience and future expectations. Revisions to the estimates may be required based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis.
REVENUE RECOGNITION. The company derives its revenue primarily from the sale of produced natural gas and crude oil. The company reports revenue gross for the amounts received before taking into account production taxes and transportation costs which are reported as oil and gas production expenses.
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Revenue is recorded in the month production is delivered to the purchaser at which time title changes hands. The company makes estimates of the amount of production delivered to purchasers and the prices it will receive. The company uses its knowledge of its properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received.
A majority of the company’s sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined based upon a percentage of a pre-determined and published monthly index price. The terms of these contracts have not had an effect on how the company recognizes its revenue.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The company manages exposure to commodity price fluctuations by periodically hedging a portion of expected production through the use of derivatives, typically collars and forward short positions in the NYMEX or other regional indexes futures market. See Note 4 for more information on the company’s hedging activities.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, the company carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation the Chief Executive Officer and Chief Financial Officer concluded that the company’s disclosure controls and procedures were effective as of October 31, 2006 to provide reasonable assurance that information required to be disclosed in the company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. The company’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to the company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
There has been no change in the company’s internal control over financial reporting that occurred during the nine months ended July 31, 2007 that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting.
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ITEM 1. |
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None. |
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ITEM 1A. |
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There have been no material changes from the risk factors previously disclosed in the company’s Annual Report on Form 10-K for the fiscal year ended October 31, 2006. |
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ITEM 2. |
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None. |
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ITEM 3. |
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None. |
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ITEM 4. |
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None |
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ITEM 5. |
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None. |
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ITEM 6. |
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Exhibits are as follow: |
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31.1 |
Certification by Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002 |
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31.2 |
Certification by Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002 |
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32.1 |
Certification by Chief Executive Officer and Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act (18 U.S.C. Section 1350) |
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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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CREDO Petroleum Corporation |
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(Registrant) |
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By: |
/s/ James T. Huffman |
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James T. Huffman |
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President and Chief Executive Officer |
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(Principal Executive Officer) |
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By: |
/s/ David E. Dennis |
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David E. Dennis |
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Chief Financial Officer |
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(Principal Financial and Accounting Officer) |
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Date: September 10, 2007 |
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