Table
of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark
One)
x
|
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 January 31, 2010
|
|
|
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)
Delaware
|
|
84-0772991
|
(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)
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303-297-2200
(Registrants 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 has submitted
electronically and posted on its corporate web site, if any, every interactive
data file required to be submitted and posted pursuant to Rule 405 of
Regulation S-Y during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files.) Yes
o
No
o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. (See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2
of the Act.)
Large accelerated filer
o
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Accelerated filer
x
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|
|
|
Non-accelerated filer
o
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Smaller Reporting Company
o
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(Do not check if a smaller reporting company)
|
|
|
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 issuers
classes of common stock, net of treasury
stock, as of the latest practicable date.
Date
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Class
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Outstanding
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March 10, 2010
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Common stock, $.10 par value
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10,150,000
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Table
of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly
Report on Form 10-Q For the Period Ended January 31, 2010
TABLE OF
CONTENTS
The terms CREDO,
Company, we, our, and us refer to CREDO Petroleum Corporation and its
subsidiaries unless the context suggests otherwise.
2
Table of Contents
PART I - FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Balance Sheets
(Unaudited)
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January 31,
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October 31,
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2010
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2009
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ASSETS
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Current Assets:
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|
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Cash and cash equivalents
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$
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12,129,000
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$
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12,348,000
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Short-term investments
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573,000
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635,000
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Receivables:
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Accrued oil and natural gas sales
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1,850,000
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1,566,000
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Trade
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420,000
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487,000
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Derivative Assets
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214,000
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104,000
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Other current assets
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715,000
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859,000
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Total current assets
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15,901,000
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15,999,000
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Long-term assets:
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Oil and natural gas properties, at cost, using full
cost method:
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Unevaluated oil and natural gas properties
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7,878,000
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7,363,000
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Evaluated oil and natural gas properties
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76,533,000
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76,127,000
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Less: accumulated depreciation, depletion and
amortization
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(53,956,000
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)
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(53,211,000
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)
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Net oil and natural gas properties
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30,455,000
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30,279,000
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Intangible
assets, net of amortization of $545,000 in 2010 and $436,000 in 2009
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3,904,000
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4,013,000
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Compressor
and tubular inventory to be used in development of oil and gas properties
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1,875,000
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1,865,000
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Other, net
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402,000
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396,000
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Total assets
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$
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52,537,000
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$
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52,552,000
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LIABILITIES AND STOCKHOLDERS EQUITY
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Current Liabilities:
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Accounts payable
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$
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414,000
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$
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407,000
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Revenue distribution payable
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859,000
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653,000
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Accrued compensation
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494,000
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948,000
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Other accrued liabilities
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298,000
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394,000
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Derivative Liability
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114,000
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Income taxes payable
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55,000
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55,000
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Total current liabilities
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2,234,000
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2,457,000
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Long Term Liabilities:
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Deferred income taxes, net
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2,762,000
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2,537,000
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Asset retirement obligation
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1,505,000
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1,502,000
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Total liabilities
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6,501,000
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6,496,000
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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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Common
stock, $.10 par value, 20,000,000 shares authorized, 10,660,000 issued
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1,066,000
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1,066,000
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Capital in excess of par value
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31,480,000
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31,472,000
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Treasury
stock at cost, 487,000 shares in 2010 and 419,000 shares in 2009
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(3,470,000
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)
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(2,803,000
|
)
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Retained earnings
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16,960,000
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16,321,000
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Total stockholders equity
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46,036,000
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46,056,000
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Total liabilities and stockholders equity
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$
|
52,537,000
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$
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52,552,000
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|
The accompanying
notes are an integral part of these consolidated financial statements.
3
Table
of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Operations
(Unaudited)
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Three Months Ended
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January 31,
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2010
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2009
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Oil sales
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$
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1,724,000
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$
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622,000
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Natural gas sales
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1,418,000
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1,486,000
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3,142,000
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2,108,000
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Costs and expenses:
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Oil and natural gas production
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856,000
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886,000
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Depreciation, depletion
and amortization
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865,000
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1,336,000
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Write-down
of oil and natural gas properties (Note 3) and impairment of long lived
assets (Note 8)
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16,623,000
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General and administrative
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542,000
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868,000
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2,263,000
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19,713,000
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Income (loss) from operations
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879,000
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(17,605,000
|
)
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Other income and (expense)
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|
|
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Realized and unrealized
gain (loss) on derivative contracts
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(14,000
|
)
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1,466,000
|
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|
|
|
|
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Investment and other
income (loss)
|
|
(1,000
|
)
|
(142,000
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)
|
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|
(15,000
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)
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1,324,000
|
|
|
|
|
|
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Income (loss) before income taxes
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864,000
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(16,281,000
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)
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Income taxes
|
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(225,000
|
)
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6,390,000
|
|
|
|
|
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Net income (loss)
|
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$
|
639,000
|
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$
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(9,891,000
|
)
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Earnings (loss) per share of
Common Stock - Basic
|
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$
|
.06
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$
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(.95
|
)
|
|
|
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Earnings (loss) per share of
Common Stock - Diluted
|
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$
|
.06
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$
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(.95
|
)
|
|
|
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Weighted
average number of shares of common stock and dilutive securities:
|
|
|
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Basic
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10,204,000
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10,386,000
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Diluted
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10,251,000
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10,386,000
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|
The accompanying
notes are an integral part of these consolidated financial statements.
4
Table of
Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
(Unaudited)
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Three Months Ended
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January 31,
|
|
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2010
|
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2009
|
|
|
|
|
|
|
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Cash Flows From Operating
Activities:
|
|
|
|
|
|
Net income (loss)
|
|
$
|
639,000
|
|
$
|
(9,891,000
|
)
|
Adjustments
to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
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Non-cash
write-down of oil and natural gas properties and impairment of intangible
assets
|
|
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16,623,000
|
|
Depreciation, depletion and amortization
|
|
865,000
|
|
1,336,000
|
|
ARO liability accretion
|
|
14,000
|
|
19,000
|
|
Unrealized (gains) losses on derivative contracts
|
|
4,000
|
|
(541,000
|
)
|
Deferred income taxes
|
|
225,000
|
|
(6,440,000
|
)
|
Loss on short term investments
|
|
6,000
|
|
210,000
|
|
Compensation expense related to stock options
granted
|
|
8,000
|
|
8,000
|
|
Other
|
|
(2,000
|
)
|
21,000
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
Proceeds from short-term investments
|
|
56,000
|
|
916,000
|
|
Accrued oil and natural gas sales
|
|
(284,000
|
)
|
139,000
|
|
Trade receivables
|
|
67,000
|
|
(130,000
|
)
|
Other current assets
|
|
144,000
|
|
(168,000
|
)
|
Accounts payable and accrued liabilities
|
|
(430,000
|
)
|
(871,000
|
)
|
Income taxes payable
|
|
|
|
50,000
|
|
|
|
|
|
|
|
Net Cash Provided By Operating Activities
|
|
1,312,000
|
|
1,281,000
|
|
|
|
|
|
|
|
Cash Flows From Investing
Activities
:
|
|
|
|
|
|
Additions to oil and natural gas properties
|
|
(839,000
|
)
|
(7,118,000
|
)
|
Changes in other long-term assets
|
|
(25,000
|
)
|
(16,000
|
)
|
Purchase of intangible assets
|
|
|
|
(4,400,000
|
)
|
|
|
|
|
|
|
Net Cash Used In Investing Activities
|
|
(864,000
|
)
|
(11,534,000
|
)
|
|
|
|
|
|
|
Cash Flows Used By Financing
Activities:
|
|
|
|
|
|
Purchase of treasury
stock
|
|
(667,000
|
)
|
(690,000
|
)
|
|
|
|
|
|
|
Net Cash Used By Financing Activities
|
|
(667,000
|
)
|
(690,000
|
)
|
|
|
|
|
|
|
Decrease In Cash And Cash Equivalents
|
|
(219,000
|
)
|
(10,943,000
|
)
|
|
|
|
|
|
|
Cash And Cash Equivalents:
|
|
|
|
|
|
Beginning of period
|
|
12,348,000
|
|
22,332,000
|
|
|
|
|
|
|
|
End of period
|
|
$
|
12,129,000
|
|
$
|
11,389,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
5
Table of
Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To
Consolidated Financial Statements (Unaudited)
January 31,
2010
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 companys results for the
periods presented. Management has
evaluated events and transactions occurring after the balance sheet date
through the date the financial statements were issued. For a more complete understanding of the
companys financial condition and accounting policies, these consolidated
financial statements should be read in conjunction with the companys Annual
Report on Form 10-K for the fiscal year ended October 31, 2009. The results for interim periods are not
necessarily indicative of annual results.
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.
2. CONCENTRATION OF CREDIT RISK
CREDOs
accounts receivable are primarily from purchasers of the companys oil and
natural gas production and from other exploration and production companies
which own joint working interests in the properties that the company
operates. This industry concentration
could adversely impact the companys overall credit risk, because the companys
customers and working interest owners may be similarly affected by changes in
economic and financial market conditions, commodity prices, and other
conditions. CREDOs oil and gas
production is sold to various purchasers in accordance with the companys
credit policies and procedures. These
policies and procedures take into account, among other things, the
creditworthiness of potential purchasers and concentrations of credit
risk. For most joint working interest
partners, the company may have the right of offset against related oil and
natural gas revenues.
3. OIL AND NATURAL GAS PROPERTIES
Depreciation,
depletion and amortization of oil and natural gas properties for the three
months ended January 31, 2010 and 2009 were $745,000 and $1,192,000
respectively. 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. All costs
incurred in the acquisition, exploration, and development of properties
(including costs of surrendered and abandoned leaseholds, delay lease rentals,
dry holes, and overhead related to exploration and development activities) and
the fair value of estimated future costs of site restoration, dismantlement,
and abandonment activities are capitalized.
Costs for unevaluated properties, which typically include lease bonus,
geology and seismic costs, are capitalized but are excluded from the
amortizable pool during the evaluation period. When determinations are made
whether the property has proved recoverable reserves or not, or if there is an
impairment, the costs are reclassified to the full cost pool.
6
Table of
Contents
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. The ceiling test is calculated using oil and
natural gas prices in effect as of the balance sheet date. 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, unless the company considers price increases subsequent to
the balance sheet date which may reduce or eliminate a write-down. A write-down may not be reversed in future
periods, even though higher oil and natural gas prices may subsequently
increase the ceiling.
At
January 31, 2010 the estimated present value of future net revenues from
proved reserves, net of related income tax considerations, exceeded the
capitalized costs of the companys oil and natural gas properties. Therefore, a ceiling test write-down was not
required. For the three months ended January 31,
2009, the company recorded a non-cash ceiling test write-down of $15,697,000.
Changes in oil and natural gas prices have historically had the most
significant impact on the companys 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 companys 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 companys assessment of future prices or costs,
but rather are based on prices and costs in effect as of the end of the test
period.
4. STOCK-BASED
COMPENSATION
For
each of the three month periods ended January 31, 2010 and 2009, the
company recognized stock based compensation expense of $8,000. The estimated unrecognized compensation cost
from unvested stock options as of January 31, 2010 was approximately
$25,000 which is expected to be recognized over 10 months.
No
options were granted during the three months ended January 31, 2010 or
2009.
7
Table of Contents
Plan activity for the three months ended January 31,
2010 is set forth below:
|
|
Three Months Ended
January 31, 2010
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
Aggregate
|
|
|
|
Number of
|
|
Exercise
|
|
Intrinsic
|
|
|
|
Options
|
|
Price
|
|
Value
|
|
Outstanding at
October 31, 2009
|
|
179,063
|
|
$
|
7.46
|
|
$
|
530,000
|
|
Granted
|
|
|
|
|
|
|
|
Exercised
|
|
|
|
|
|
|
|
Cancelled or forfeited
|
|
|
|
|
|
|
|
Outstanding at
January 31, 2010
|
|
179,063
|
|
$
|
7.46
|
|
$
|
427,000
|
|
|
|
|
|
|
|
|
|
Exercisable at
January 31, 2010
|
|
174,063
|
|
$
|
7.31
|
|
$
|
427,000
|
|
|
|
|
|
|
|
|
|
Weighted average
contractual life at January 31, 2010
|
|
|
|
4.15
|
years
|
|
|
|
Outstanding
|
|
Exercisable
|
|
|
|
Number
|
|
Weighted Average
|
|
Weighted
|
|
Number
|
|
|
|
Range of
|
|
Outstanding
|
|
Remaining
|
|
Average
|
|
Exercisable at
|
|
Weighted
|
|
Exercise
|
|
at January 31,
|
|
Contractual
|
|
Exercise
|
|
January 31,
|
|
Average
|
|
Prices
|
|
2010
|
|
Life in Years
|
|
Price
|
|
2010
|
|
Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$5.93
|
|
139,063
|
|
3.37
|
|
$
|
5.93
|
|
139,063
|
|
$
|
5.93
|
|
$12.78
|
|
40,000
|
|
6.85
|
|
$
|
12.78
|
|
35,000
|
|
$
|
12.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$5.93 -$12.78
|
|
179,063
|
|
4.15
|
|
$
|
7.46
|
|
174,063
|
|
$
|
7.31
|
|
5. NATURAL GAS DERIVATIVES
The company is exposed to certain commodity
price risks relating to its ongoing operations.
The company periodically uses natural gas derivatives as economic hedges
of the price of a portion of its estimated natural gas production when the
potential for significant downward price movement is anticipated. These transactions typically take the form of
forward short positions based upon the NYMEX futures market, and are closed by
purchasing offsetting positions. Such
contracts do not exceed estimated production volumes and are authorized by the
companys Board of Directors. Contracts
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.
For the quarters ended January 31, 2010 and 2009 the company had realized gains
(losses) on derivatives of ($10,000) and $925,000 respectively, and unrealized
gains (losses) of ($4,000) and $541,000, respectively. At January 31, 2010 the company held
open derivative contracts representing short sales positions for 640,000 MMBtus
at NYMEX basis prices ranging from $5.22 to $7.27 and covering the production
months of February 2010 through December 2010. The company also held open derivative
contracts with the same counterparty representing long positions for 390,000
MMBtus at NYMEX basis prices ranging from $5.15 to $5.83 and covering the
production months of February 2010 through December 2010. These positions are presented net due to the
contractual netting provisions with the counterparty. The open derivative contracts net to 250,000
MMBtus with a net unrealized gain of $214,210 at January 31,
2010. Average prices in the companys
primary market are currently 2% below NYMEX prices due to basis differentials
and transportation costs.
At January 31, 2010 the company also
held basis differential hedges on 440,000 MMBtus with NYMEX vs. Panhandle
Eastern Pipeline basis differentials of $0.47 and covering the production
months of
8
Table of
Contents
February 2010 through December 2010. These open basis differential contracts
represent unrealized losses of $114,000 at January 31, 2010.
Subsequent to January 31, the February and
March derivative contracts closed, resulting in realized derivative losses
of $2,000.
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 available
is $5,900,000 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 companys bank,
and prohibits funded debt in excess of $500,000. The line expires November 15, 2010.
The
company has elected not to designate its commodity derivatives as cash flow
hedges for accounting purposes.
Accordingly, such contracts are recorded at fair value on the balance
sheet and changes in fair value are recorded in the statement of operations as
they occur.
The
location and amount of derivative fair values and related gain (loss) are indicated
in the following tables (in thousands):
Derivatives
not designated as hedging instruments:
|
|
As of January 31, 2010
|
|
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Natural Gas Forward Positions
|
|
Derivative Asset
|
|
$
|
214
|
|
Natural Gas Basis Positions
|
|
Derivative Liability
|
|
(114
|
)
|
|
|
|
|
|
|
|
Amount
of Gain or (Loss) Recognized in Income on Derivatives:
Derivatives
not designated as hedging instruments:
|
|
Location of Gain/(Loss)
Recognized in
Income on Derivatives
|
|
Three Months
Ended
January 31, 2010
|
|
Natural Gas Forward Positions
|
|
Other
Income and (Expense)
|
|
$
|
38
|
|
Natural Gas Basis Positions
|
|
Other
Income and (Expense)
|
|
(52
|
)
|
|
|
|
|
|
|
|
6. EARNINGS PER SHARE
The companys calculation of earnings per
share of common stock is as follows:
|
|
Three Months Ended
January 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
Income
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per
share
|
|
$
|
639,000
|
|
10,204,000
|
|
$
|
.06
|
|
$
|
(9,891,000
|
)
|
10,386,000
|
|
$
|
(.95
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive shares
of common stock from stock options
|
|
|
|
47,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss)
per share
|
|
$
|
639,000
|
|
10,251,000
|
|
$
|
.06
|
|
$
|
(9,891,000
|
)
|
10,386,000
|
|
$
|
(.95
|
)
|
9
Table of
Contents
The companys outstanding options were not
included in the calculation of diluted loss per share for the period ended January 31,
2009 as their inclusion would have an antidilutive effect.
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 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.
As
of January 31, 2010 the companys 2007 Federal tax return had been audited
by the IRS. The company remains subject
to examination of 2006 and 2008 Federal and 2006 through 2008 state tax
returns, except Colorado, in which the 2005 tax year also remains open.
8. INTANGIBLE ASSETS
The
company owns all of the patents underlying the Calliope Gas Recovery Technology
and patents covering a new fluid lift technology for shallow wells known as
Tractor Seal. The patents are being
amortized on a straight line basis over the remaining lives ranging from 7.4 to
16.4 years.
|
|
January 31,
2010
|
|
|
|
Gross
Carrying
|
|
Accumulated
|
|
|
|
Amount
|
|
Amortization
|
|
|
|
|
|
|
|
Amortized intangible
assets:
|
|
|
|
|
|
Calliope intangible assets
|
|
$
|
4,449,000
|
|
$
|
545,000
|
|
|
|
|
|
|
|
Aggregate amortization
expense:
|
|
|
|
|
|
For the three months ended
January 31, 2010
|
|
|
|
$
|
109,000
|
|
|
|
|
|
|
|
|
|
The company reviews the
value of its intangible assets for impairment whenever events or changes in
business circumstances indicate that the carrying amount of the assets may not
be fully recoverable or that the useful lives of these assets are no longer
appropriate. For the period ended January 31,
2009, the company recorded a non-cash impairment expense of $926,000 related to
other intangible assets.
9. FAIR VALUE MEASUREMENTS
The company utilizes derivative contracts to hedge
against the variability in cash flows associated with the forecasted sale of
its anticipated future natural gas production.
These derivatives are carried at fair value on the consolidated balance
sheets. Additionally, the companys
short-term
investments consist primarily of professionally managed limited partnerships
which include investments that are not publicly traded and may have less
readily determinable market values.
Accounting standards established a valuation hierarchy for disclosure of
the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into
three broad levels as follows:
·
Level 1 inputs
are quoted prices (unadjusted) in active markets for identical assets or
liabilities.
·
Level 2 inputs
are quoted prices for similar assets and liabilities in active markets or
inputs that are
10
Table
of Contents
observable
for the asset or liability, either directly or indirectly through market
corroboration, for substantially the full term of the financial instrument.
·
Level 3 inputs
are measured based on prices or valuation models that require inputs that are
both significant to the fair value measurement and less observable from
objective sources.
The
classification of financial asset or liability within the hierarchy is
determined based on the lowest level input that is significant to the fair
value measurement. The determination of
the fair values below incorporates various factors required under fair value
accounting guidance, including the impact of the counterpartys non-performance
risk with respect to the companys financial assets and the companys
non-performance risk with respect to the companys financial liabilities. The following table provides the assets and
liabilities carried at fair value measured on a recurring basis as of January 31,
2010:
|
|
As of January 31, 2010
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Asset:
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
|
$
|
298
|
|
$
|
|
|
$
|
275
|
|
$
|
573
|
|
Derivative asset
|
|
$
|
|
|
$
|
214
|
|
$
|
|
|
$
|
214
|
|
Derivative Liability
|
|
$
|
|
|
$
|
(114
|
)
|
$
|
|
|
$
|
(114
|
)
|
Level 3 instruments are comprised of the
companys investments in professionally managed limited partnerships. The fair value represents the net asset value
of the companys share in each partnership.
The company identified the investments as Level 3 instruments due to the
fact that quoted prices for the underlying investments in the partnerships
cannot be obtained and there is not an active market for the underlying
investments or the partnerships shares.
The company utilizes the periodic fund statements along with current
fund redemption activity and communication with investment advisors to
determine the valuation of its investment.
All of the Level 3 investments are in the process of liquidation, and
redemption.
The
following table sets forth a reconciliation of changes in the fair value of
financial assets and liabilities classified as Level 3 in the fair value
hierarchy for the three months ended January 31, 2010:
|
|
Short Term Investments
|
|
|
|
Three Months Ended
|
|
|
|
January 31, 2010
|
|
|
|
(in thousands)
|
|
|
|
|
|
Balance as of October 31, 2009(1)
|
|
$
|
342
|
|
Total gains or losses (realized or unrealized):
|
|
|
|
Included in earnings(2)
|
|
(11
|
)
|
Redemptions
|
|
(56
|
)
|
Balance as of January 31, 2010(1)
|
|
$
|
275
|
|
(1)
This amount is included in short term investments on the balance sheet.
(2)
This amount is included in investment and other income (expense) on the
statement of operations.
11
Table of Contents
10. COMMON STOCK
On September 22, 2008, the companys
Board of Directors authorized a stock repurchase program. Under the program, the company could acquire
up to $2,000,000 of its common stock.
The Board subsequently authorized expanding the repurchase program to
$4,000,000. The repurchases may be made
on the open market, in block trades or otherwise. The stock repurchase program may be expanded,
suspended or discontinued at any time.
During the quarter ended January 31, 2010, the company acquired
67,457 shares of its common stock at an aggregate cost of $667,000.
Subsequent to January 31,
2010, and through March 10, 2010, the company has repurchased an
additional 23,800 shares, bringing the total shares repurchased to 386,691
at an average price per share of $8.85 under this program.
11. COMMITMENTS AND CONTINGENCIES
The company has been named as a defendant in
a lawsuit alleging breach of contract, and other issues, arising in the normal
course of its oil and gas activities.
The company believes that a contractual agreement requires that disputes
be resolved by arbitration. Although the
company believes the allegations are without merit and that the company will
ultimately prevail, the ultimate outcome of this lawsuit, or arbitration,
cannot be determined at this time.
The
company has also been named as a defendant in a lawsuit brought by a former
employee. The suit alleges breach of
contract and other employment issues.
Although the company believes the allegations are without merit and that
the company will ultimately prevail, the ultimate outcome of this lawsuit
cannot be determined at this time.
The company has no material outstanding
commitments at January 31, 2010.
12. RECENT ACCOUNTING PRONOUNCEMENTS
In February 2010, the FASB
issued authoritative guidance that eliminated the requirement to disclose the
date through which management evaluated subsequent events in the financial
statements. Such subsequent events must
still be evaluated by management through the date that financial statements are
issued. The new guidance was effective
immediately and the company adopted the guidance for financial statement issued
subsequent to February 24, 2010.
There was no impact on the companys financial position or results of
operations as a result of the adoption.
In January 2010, the FASB issued authoritative guidance titled
Improving Disclosures about Fair Value Measurements. This guidance amends existing authoritative
guidance to require additional disclosures regarding fair value measurements,
including the amounts and reasons for significant transfers between Level 1 and
Level 2 of the fair value hierarchy, the reasons for any transfers into or out
of Level 3 of the fair value hierarchy, and presentation on a gross basis of
information regarding purchases, sales, issuances, and settlements within the
Level 3 rollforward. This guidance also
clarifies certain existing disclosure requirements. The guidance is effective for interim and
annual reporting periods beginning after December 15, 2009, except for the
disclosures about purchases, sales, issuances, and settlements within the Level
3 rollforward, which are effective for interim and annual reporting periods
beginning after December 15, 2010. The
adoption of this authoritative guidance will have no impact on our financial
position or results of operations, but may require expanded disclosure about
fair value measurements.
In
December 2008, the Securities and Exchange Commission (SEC) adopted
revisions to its oil and gas disclosure requirements that are intended to align
them with current practices and changes in technology. Among other things, the
amendments will: replace the single-day year-end pricing assumption with a
twelve-month average pricing assumption; permit the disclosure of probable and
possible reserves; allow
12
Table of Contents
the
use of certain technologies to establish reserves; require the disclosure of
the qualifications of the technical person primarily responsible for preparing
the reserves estimates or conducting a reserves audit; require the filing of
the independent reserve engineers summary report; and permit the disclosure of
a reserves sensitivity analysis table to illustrate the impact of different
price and/or cost assumptions on reserves. These amendments are effective for
registration statements filed on or after January 1, 2010, and for annual
reports on Form 10-K for fiscal years ending on or after December 31,
2009 (October 31, 2010 for the company) with early adoption
prohibited. The company is currently evaluating the impact that the adoption of
these amendments will have on the companys financial position, results of
operations, and disclosures. In January 2010,
the Financial Accounting Standards Board (FASB) issued oil and gas reserve
estimation and disclosure authoritative accounting guidance effective for
reporting periods ending on or after December 31, 2009. This guidance was issued to align the
accounting oil and gas reserve estimation and disclosure requirements with the
requirements in the Securities and Exchange Commissions (SEC) final
rule. The new FASB guidance includes
changes to pricing used to estimate oil and gas reserves, broaden the types of
technologies that a company may use to establish oil and gas reserves
estimates, and broaden the definition of oil and gas producing activities to
include the extraction of non-traditional resources.
ITEM 2.
|
|
MANAGEMENTS
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 include, among other things, statements
relating to:
·
the companys future financial position,
including working capital and anticipated cash flow;
·
amounts and nature of future capital
expenditures;
·
projections of operating costs and other
expenses;
·
wells to be drilled or reworked including new
drilling expectations;
·
expectations regarding oil and natural gas
prices and demand;
·
existing fields, wells and prospects;
·
diversification of exploration, capital
exposure, risk and reserve potential of drilling activities;
·
estimates of proved oil and natural gas
reserves;
·
expectations and projections regarding joint
ventures;
·
reserve potential;
·
development and drilling potential;
·
expansion and other development trends in the
oil and natural gas industry;
·
the companys business strategy;
·
production and production potential of oil
and natural gas;
·
matters related to the Calliope Gas Recovery
System, including projections for future use of Calliope and the success of
Calliope;
·
effects of federal, state and local
regulation;
·
adequacy of insurance coverage;
·
employee relations;
13
Table
of Contents
·
effectiveness of the companys hedging
transactions;
·
investment strategy and risk; and
·
expansion and growth of the companys
business and operations.
Although the company believes that the
expectations reflected in such forward-looking statements are reasonable, it
can give no assurance that such expectations will prove to be correct. Disclosure of important factors that could
cause actual results to differ materially from the companys expectations, or
cautionary statements, are included under Risk Factors and elsewhere in this
Annual Report on Form 10-K, including, without limitation, in conjunction
with the forward-looking statements. The
following factors, among others that could cause actual results to differ
materially from the companys expectations, include:
·
unexpected changes in
business or economic conditions;
·
significant changes in
natural gas and oil prices;
·
timing and amount of
production;
·
unanticipated down-hole
mechanical problems in wells or problems related to producing reservoirs or
infrastructure;
·
changes in overhead costs;
·
material events resulting in
changes in estimates; and
·
competitive factors.
All forward-looking statements speak only as
of the date made. All subsequent written
and oral forward-looking statements attributable to the company, or persons
acting on the companys behalf, are expressly qualified in their entirety by
the cautionary statements. Except as
required by law, the company undertakes no obligation to update any
forward-looking statement to reflect events or circumstances after the date on
which it is made or to reflect the occurrence of anticipated or unanticipated
events or circumstances.
LIQUIDITY AND CAPITAL RESOURCES
At January 31, 2010, working capital was
$13,667,000 compared to $13,542,000 at October 31, 2009. For the three months ended January 31,
2010, net cash provided by operating activities was $1,312,000 compared to
$1,281,000 for the same period in 2009.
Income before income taxes increased $17,145,000 primarily due to
impairment losses of $16,623,000 in 2009, an increase in revenue of $1,034,000,
decreased other cost and expenses of $827,000, and decreased other income of
$1,339,000, which is mostly due to derivative transactions.
For the three months ended January 31,
2010 and 2009, net cash used in investing activities was $864,000 and
$11,534,000, respectively. Investing
activities primarily included oil and gas lease acquisition, exploration and
development expenditures, including Calliope, totaling $921,000 and $6,157,000
respectively.
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 January 31, 2010, the company
had no lines of credit or other bank financing arrangements except for the
hedging line of credit discussed in Note 5. 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 companys adjusted earnings before
interest, taxes, depreciation, depletion and amortization, including impairment
losses, (EBITDA) was $1,729,000 for the three months ended January 31,
2010 compared to $1,678,000 for the three months ended January 31, 2009. 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
14
Table of
Contents
consider this measure in isolation or as a
substitute for operating income, or any other measure for determining the
companys 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.
Reconciliation between EBITDA and net income is provided in the table
below:
|
|
Three Months Ended
January 31,
|
|
|
|
2010
|
|
2009
|
|
RECONCILIATION OF EBITDA:
|
|
|
|
|
|
Net Income (loss)
|
|
$
|
639,000
|
|
$
|
(9,891,000
|
)
|
Add Back (Deduct):
|
|
|
|
|
|
Income Tax Expense
(Benefit)
|
|
225,000
|
|
(6,390,000
|
)
|
Depreciation, Depletion
and Amortization Expense
Including Write-Down and Impairment
|
|
865,000
|
|
17,959,000
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
1,729,000
|
|
$
|
1,678,000
|
|
OFF-BALANCE SHEET FINANCING
The company has no off-balance sheet
arrangements at January 31, 2010.
PRODUCT PRICES AND PRODUCTION
Although
product prices are key to the companys ability to operate profitably and to
budget capital expenditures, they are beyond the companys 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 companys production. The companys current hedges are indexed to
NYMEX.
The
oil and natural gas average sales prices reflected in the table below exclude
the effects of commodity derivative instruments since the company has elected
not to designate derivative instruments as cash flow hedges. See Note 5 of the Notes to Consolidated
Financial Statements and comments at Results of Operations
for more information on gains and
losses relating to commodity derivative instruments.
|
|
Three Months Ended
January 31,
|
|
|
|
2010
|
|
2009
|
|
% Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls)
|
|
23,600
|
|
$
|
73.21
|
|
16,700
|
|
$
|
36.87
|
|
+41
|
%
|
+99
|
%
|
Gas (Mcf)
|
|
275,000
|
|
$
|
5.15
|
|
362,000
|
|
$
|
4.10
|
|
-24
|
%
|
+26
|
%
|
BOE (Barrels of Oil
Equivalent)
|
|
69,400
|
|
$
|
45.27
|
|
77,000
|
|
$
|
27.37
|
|
-10
|
%
|
+65
|
%
|
15
Table of
Contents
The effect of realized derivative gains and
losses on total price realizations are reflected in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended January 31,
|
|
|
|
|
|
2010
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
Realized
|
|
|
|
|
|
Realized
|
|
|
|
|
|
Net
|
|
Derivative
|
|
Effective
|
|
Net
|
|
Derivative
|
|
Effective
|
|
|
|
Wellhead
|
|
Gain
|
|
Price
|
|
Wellhead
|
|
Gain
|
|
Price
|
|
Product
|
|
Price
|
|
(Loss)
|
|
Realization
|
|
Price
|
|
(Loss)
|
|
Realization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
73.21
|
|
$
|
|
|
$
|
73.21
|
|
$
|
36.87
|
|
$
|
|
|
$
|
36.87
|
|
Gas
|
|
$
|
5.15
|
|
$
|
(0.03
|
)
|
$
|
5.12
|
|
$
|
4.10
|
|
$
|
2.55
|
|
$
|
6.65
|
|
OPERATIONS
During the first quarter of fiscal 2010, the
companys operations continued to focus on its two core projects oil and
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 2010, 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 companys
control, including but not limited to, the cost and quality of oil field
services such as drilling rigs, production equipment and related services, and
access to wells for application of the companys 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.
In recent years, the company has
significantly expanded both the volume and breadth of its drilling activities
with new projects in central Kansas, North Dakotas Williston Basin, and South Texas. Compared to drilling in Oklahoma, the North
Dakota and South Texas projects involve higher costs and greater risks but
significantly higher per well reserve potential. In contrast, drilling in central Kansas is
less expensive than the companys Oklahoma drilling projects while still
yielding excellent economics.
All of the companys oil and natural gas
properties are located on-shore in the continental United States. The companys 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 companys 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.
Recent Drilling Activities.
Bakken Shale
The companys first Bakken
horizontal well has been drilled and completed.
During testing the well flowed at 1,474 barrels of oil equivalent over a
24 hour period. The well is located on
the Fort Berthold Reservation in an area where there have been a significant
number of successful Bakken completions.
The well was drilled on a 1,280 acre spacing unit with a horizontal
lateral of approximately 9,200 feet. Credo
owns a 10% working interest.
16
Table of Contents
Credo
has leased approximately 8,000 gross (6,000 net) acres on the Reservation
containing about 50 drillable spacing units. The companys interests range up to 51%
depending on the size of the spacing unit.
It is expected that more than one well will be drilled on many spacing
units.
Horizontal
drilling targets the Bakken and Three Forks formations. The companys acreage is generally located
south and west of Parshall Field and is in the vicinity of several recently
announced significant Bakken discoveries.
The Reservation is surrounded on three sides by horizontal Bakken
production, and drilling activity on the Reservation is escalating rapidly.
Central Kansas Uplift
In Central Kansas, Credo currently owns
140,000 gross (77,000 net) acres where it is having excellent drilling
results. The acreage contains 31 blocks
in which the company owns interests ranging from 12.5% to 100%.
To
date, Credo has drilled 49 wells on its Central Kansas Uplift acreage, of which 48% have
been successful. The company is
continuing an aggressive lease acquisition and drilling program with two to
three wells per month scheduled. Based
on its historical experience in the play, the company plans to maintain that
drilling pace for at least the next few years.
Four
of the companys last seven wells are successful discoveries. One of those wells has been completed with an
initial production rate of about 100 barrels per day and three are currently
awaiting completion. Each of these
discoveries was the initial exploratory test on a seismically identified
anomaly, and additional development drilling is expected. The company owns working interests in the
discoveries ranging from 12.5% to 28.8%.
Last
year, Credo discovered a significant new field in Barton County, Kansas in
which it owns an 85% working interest.
That field has produced 96,000 barrels of oil in about 14 months.
Calliope Gas Recovery Technology
Calliope Gas Recovery System
We are
continuing to
actively discuss commercial Calliope terms with several companies. We have proven that Calliope will
perform as advertised. Credo has
previously published statistics on its Calliope wells which show finding costs
of about $0.50 per Mcf and total costs to deliver gas into the pipeline of
about $1.00 per Mcf. The statistics
also show that Calliope is very low risk when installed on suitable wells.
Calliopes low finding and production costs have become increasingly
attractive as the economics on many industry drilling projects deteriorate due
to lower product prices. We also believe
that lower natural gas prices may stimulate divestitures of marginal properties
by other companies, including properties that have Calliope potential.
Results of Operations
Three Months Ended January 31,
2010 Compared to Three Months Ended January 31, 2009
For the three months ended January 31,
2010, oil and gas revenues increased 49% to $3,142,000 compared to $2,108,000
during the same period last year. As the
oil and gas price/volume table on page 15 shows, natural gas sales prices
increased 26% to $5.15 per Mcf and oil sales prices increased 99% to $73.21 per
barrel. The net effect of these price changes was to increase oil and gas sales
by $984,000. For the three months ended January 31,
2010, the companys oil equivalent production (BOE) fell 10% but combined with
the change in oil and gas production mix, and due to the diversity between the
energy equivalency conversion rate of six to one compared to the price
equivalency rate of over fourteen to one at January 31, 2010, revenue
increased $50,000.
17
Table of
Contents
For the three months ended January 31,
2010, total costs and expenses, excluding the 2009 impairment loss of
$16,623,000, decreased 27% to $2,263,000 compared to $3,090,000 for the
comparable period in 2009. Oil and gas
production expenses decreased 3% as reduced field level expenses were partially
offset by an increased number of operating wells. DD&A decreased primarily due to a
decrease in the amortizable base. General and administrative expenses decreased
primarily due to legal and professional fees and decreased salaries and
benefits. The effective tax rate was
26.00% and 39.25% for the 2010 and 2009 periods, respectively. The effect of percentage depletion deductions
is the primary cause of the variation of the effective tax rate from the
statutory rate.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in
conformity with generally accepted accounting principles requires the company
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 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 natural gas reserves, and the estimate of its asset
retirement obligations.
Derivatives. The company has elected not to designate its
commodity derivatives as cash flow hedges for accounting purposes. Accordingly, such contracts are recorded at
fair value on its balance sheet and changes in fair value are recorded in the
Consolidated Statements of Operations as they occur.
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, unless the company considered price increases subsequent to
the quarterly balance sheet date which may reduce or eliminate a write-down. 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.
Changes in oil and natural gas prices have
historically had the most significant impact on the companys 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
companys 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 companys assessment of
future prices or costs, but rather are based on prices and costs in effect as
of the end the test period.
18
Table of
Contents
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 companys 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. New rules for the calculation of
recoverable reserves will not be adopted by the company until October 31,
2010. The new rules may impact
future calculations of ceiling tests and DD&A. See Footnote #3 for additional discussion of
DD&A and ceiling test calculations.
There are numerous uncertainties inherent in estimating oil and natural
gas reserves and their values, including many factors beyond the companys
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 are often different than the
estimated costs.
Estimates of reserve quantities and values
for certain properties must be viewed as being subject to significant change as
more data about the properties becomes available. Such properties include wells
with limited production histories and properties with proved undeveloped or
proved non-producing reserves. In
addition, the companys patented Calliope liquid lift system is generally
installed on mature wells. As such, they
contain older down-hole equipment that is more subject to failure than new
equipment. The failure of such
equipment, particularly casing, can result in complete loss of a well. Historically, performance of the companys
wells has not caused significant revisions in its proved reserves.
Asset Retirement Obligations.
The FASB authoritative guidance requires that
the company estimate the future cost of asset retirement obligations, discount
that cost to its present value, and record 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, 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.
ITEM 3.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The company manages exposure to commodity
price fluctuations by periodically hedging a portion of estimated natural gas
production through the use of derivatives, typically forward short positions in
the NYMEX futures market. At January 31,
2010 the company held open derivative contracts representing short sales
positions for 640,000 MMBtus at NYMEX basis prices ranging from $5.15 to $7.27
and covering the production months of February 2010 through December 2010. The company also held open derivative
contracts with the same counterparty representing long positions for 390,000
MMBtus at NYMEX basis prices ranging from $5.15 to $5.83 and covering the
production months of February 2010 through December 2010. These positions are presented net due to the
contractual netting provisions with the counterparty. The open derivative contracts net to 250,000
MMBtus with a net unrealized gain of $214,210 at January 31, 2010. Average prices in the companys primary
market are currently 2% below NYMEX prices due to basis differentials and
transportation costs. However, regional
weather conditions and other economic factors can periodically result in
substantially higher basis differentials.
At
January 31, 2010 the company also held basis differential hedges on
440,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of
$0.47 and covering the production months of February 2010 through December 2010. These open basis differential contracts
represent an unrealized loss of $114,000 at January 31, 2010.
19
Table of Contents
See Note 5 to the Consolidated Financial
Statements for more information regarding derivative transactions.
ITEM
4.
CONTROLS
AND PROCEDURES
Disclosure
Controls and Procedures
Our management, with the
participation of Marlis E. Smith, Jr., our Chief Executive Officer, and
Alford B. Neely, our Chief Financial Officer, evaluated the effectiveness of
our disclosure controls and procedures as of January 31, 2010. Based on the evaluation, these officers have
concluded that:
Our disclosure controls and
procedures are effective to ensure that information required to be disclosed by
us in the reports we file or submit under the Securities Exchange Act of 1934
is recorded, processed, summarized and reported within the time periods
specified in the SECs rules and forms; and
Our disclosure controls and
procedures were effective to ensure that information required to be disclosed
by us in the reports we file or submit under the Securities Exchange Act of
1934 was accumulated and communicated to our management, including our Chief
Executive Officer and Chief Financial Officer, as appropriate to allow timely
decisions regarding required disclosure.
Internal Control Over
Financial Reporting
There has not been any change in our internal
control over financial reporting that occurred during the quarter ended January 31,
2010 that has materially affected or is reasonably likely to materially affect,
our internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM 1.
|
|
LEGAL PROCEEDINGS
|
|
|
|
|
|
Reference
is made to Notes to Consolidated Financial Statements (Unaudited) Note 11,
Commitments and Contingencies, in Part I, Item I of this Form 10-Q
and incorporated by reference in this Part II, Item I.
|
|
|
|
ITEM 1A.
|
|
RISK FACTORS
|
|
|
|
|
|
There have been
no material changes from the risk factors previously disclosed in the companys
Annual Report on Form 10-K for the fiscal year ended October 31,
2009.
|
|
|
|
ITEM 2.
|
|
UNREGISTERED SALES OF EQUITY SECURITIES AND USE
OF PROCEEDS
|
|
|
|
|
|
Issuer Purchases of Equity Securities.
|
|
|
|
|
|
During the first quarter
of fiscal year 2010, the company repurchased 64,457 shares of its common
stock on the open market at a weighted average price of $9.87. The purchases
were made pursuant to a stock repurchase plan announced on
September 24, 2008 and extended by the Board of Directors on
April 9, 2009. The extended plan authorized repurchases up to
$4,000,000, but could be expanded, suspended or discontinued at any time. At
January 31, 2010, the company has repurchased 362,891 shares
of common stock at an average price per share of $8.84.
|
20
Table
of Contents
Subsequent to January 31,
2010, and through March 10, 2010, the company has repurchased an
additional 23,800 shares, bringing the total shares repurchased to 386,691 at
an average price per share of $8.85.
Issuer
Purchases of Equity Securities
|
|
|
|
|
|
Total
number
|
|
Maximum
|
|
|
|
|
|
|
|
of
shares
|
|
dollar
value
|
|
|
|
|
|
|
|
purchased
|
|
of
shares
|
|
|
|
|
|
|
|
as part
of
|
|
that may
yet
|
|
|
|
Total
number of
|
|
Average
price
|
|
publicly
|
|
be
purchased
|
|
Period
|
|
shares
purchased
|
|
paid per
share
|
|
announced
plan
|
|
under
the plan
|
|
|
|
|
|
|
|
|
|
|
|
November 1, 2008
October 31, 2009
|
|
295,434
|
|
$
|
8.61
|
|
295,434
|
|
$
|
1,456,000
|
|
November 1 - 30 2009
|
|
40,937
|
|
$
|
10.19
|
|
40,937
|
|
$
|
1,039,000
|
|
December 1 - 31 2009
|
|
|
|
$
|
|
|
|
|
$
|
|
|
January 1 - 31 2009
|
|
26,520
|
|
$
|
9.38
|
|
26,520
|
|
$
|
790,000
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
362,891
|
|
$
|
8.84
|
|
362,891
|
|
$
|
790,000
|
|
ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS
None
ITEM 5.
OTHER INFORMATION
None.
ITEM 6.
EXHIBITS
Exhibits are as follow:
31.1
Certification by Chief Executive Officer under Section 302
of the Sarbanes-Oxley Act of 2002
31.2
Certification by Chief Financial Officer under Section 302
of the Sarbanes-Oxley Act of 2002
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)
21
Table of
Contents
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.
|
CREDO Petroleum
Corporation
|
|
(Registrant)
|
|
|
|
By:
|
/s/ Marlis E.
Smith, Jr.
|
|
|
Marlis E.
Smith, Jr.
|
|
|
Chief Executive
Officer
|
|
|
(Principal
Executive Officer)
|
|
|
|
|
By:
|
/s/ Alford B.
Neely
|
|
|
Alford B. Neely
|
|
|
Chief Financial
Officer
|
|
|
(Principal
Financial and Accounting Officer)
|
|
|
|
Date:
March 10
, 2010
|
|
|
22
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