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
For the quarterly period ended July 31,
2009
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period
from
to
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)
|
|
(IRS Employer Identification No.)
|
|
|
|
1801 Broadway, Suite 900, Denver, Colorado
|
|
80202
|
(Address of principal executive offices)
|
|
(Zip Code)
|
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
|
|
Accelerated filer
x
|
|
|
|
Non-accelerated filer
o
|
|
Smaller Reporting Company
o
|
(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
|
|
Class
|
|
Outstanding
|
|
September 9,
2008
|
|
Common stock,
$.10 par value
|
|
10,295,000
|
|
Table of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly
Report on Form 10-Q For the Period Ended July 31, 2009
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
|
|
July 31,
|
|
October 31,
|
|
|
|
2009
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
ASSETS
|
|
Current Assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
13,490,000
|
|
$
|
22,332,000
|
|
Short-term investments
|
|
687,000
|
|
3,044,000
|
|
Receivables:
|
|
|
|
|
|
Accrued oil and gas sales
|
|
1,260,000
|
|
1,733,000
|
|
Trade
|
|
398,000
|
|
995,000
|
|
Derivative Assets
|
|
699,000
|
|
1,745,000
|
|
Other current assets
|
|
328,000
|
|
205,000
|
|
Total current assets
|
|
16,862,000
|
|
30,054,000
|
|
|
|
|
|
|
|
Long-term assets:
|
|
|
|
|
|
Oil and gas properties, at cost, using full cost
method:
|
|
|
|
|
|
Unevaluated oil and gas properties
|
|
6,715,000
|
|
12,280,000
|
|
Evaluated oil and gas properties
|
|
74,651,000
|
|
59,730,000
|
|
Less: accumulated depreciation, depletion and
amortization of oil and gas properties
|
|
(52,392,000
|
)
|
(25,554,000
|
)
|
Net oil and gas properties, at cost, using full cost
method
|
|
28,974,000
|
|
46,456,000
|
|
|
|
|
|
|
|
Intangible Assets, net of accumulated amortization
of $327,000 in 2009 and $595,000 in 2008
|
|
4,122,000
|
|
1,079,000
|
|
Compressor and tubular inventory to be used in
development
|
|
1,798,000
|
|
2,592,000
|
|
Other, net
|
|
396,000
|
|
379,000
|
|
Total assets
|
|
$
|
52,152,000
|
|
$
|
80,560,000
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
569,000
|
|
$
|
3,857,000
|
|
Revenue distribution payable
|
|
643,000
|
|
982,000
|
|
Other accrued liabilities
|
|
633,000
|
|
931,000
|
|
Income taxes payable
|
|
171,000
|
|
124,000
|
|
Total current liabilities
|
|
2,016,000
|
|
5,894,000
|
|
|
|
|
|
|
|
Long Term Liabilities:
|
|
|
|
|
|
Deferred income taxes, net
|
|
1,958,000
|
|
11,117,000
|
|
Asset retirement obligation
|
|
1,423,000
|
|
1,338,000
|
|
Total liabilities
|
|
5,397,000
|
|
18,349,000
|
|
|
|
|
|
|
|
Commitments
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity:
|
|
|
|
|
|
Preferred stock, no par
value, 5,000,000 shares authorized, none issued
|
|
|
|
|
|
Common stock, $.10 par value, 20,000,000 shares
authorized, 10,660,000 shares issued
|
|
1,066,000
|
|
1,066,000
|
|
Capital in excess of par value
|
|
31,376,000
|
|
31,352,000
|
|
Treasury stock at cost, 361,594 shares in 2009 and
223,000 in 2008
|
|
(2,214,000
|
)
|
(982,000
|
)
|
Retained earnings
|
|
16,527,000
|
|
30,775,000
|
|
Total stockholders equity
|
|
46,755,000
|
|
62,211,000
|
|
Total liabilities and stockholders equity
|
|
$
|
52,152,000
|
|
$
|
80,560,000
|
|
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)
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
|
|
July 31,
|
|
July 31,
|
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
4,142,000
|
|
$
|
4,320,000
|
|
$
|
2,024,000
|
|
$
|
1,649,000
|
|
Natural gas sales
|
|
3,156,000
|
|
10,001,000
|
|
813,000
|
|
3,997,000
|
|
|
|
7,298,000
|
|
14,321,000
|
|
2,837,000
|
|
5,646,000
|
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
2,394,000
|
|
2,883,000
|
|
771,000
|
|
1,045,000
|
|
Depreciation, depletion
and amortization
|
|
3,499,000
|
|
2,594,000
|
|
960,000
|
|
843,000
|
|
Write-down of oil and natural gas properties (Note
3) and impairment of long lived assets (Note 8)
|
|
24,653,000
|
|
|
|
|
|
|
|
General and administrative
|
|
1,953,000
|
|
1,034,000
|
|
564,000
|
|
337,000
|
|
|
|
32,499,000
|
|
6,511,000
|
|
2,295,000
|
|
2,225,000
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM
OPERATIONS
|
|
(25,201,000
|
)
|
7,810,000
|
|
542,000
|
|
3,421,000
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND
(EXPENSE)
|
|
|
|
|
|
|
|
|
|
Realized and unrealized gains (losses) from
derivative contracts
|
|
1,911,000
|
|
(2,333,000
|
)
|
(16,000
|
)
|
1,139,000
|
|
Investment and other income (loss)
|
|
(66,000
|
)
|
118,000
|
|
54,000
|
|
47,000
|
|
|
|
1,845,000
|
|
(2,215,000
|
)
|
38,000
|
|
1,186,000
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAXES
|
|
(23,356,000
|
)
|
5,595,000
|
|
580,000
|
|
4,607,000
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES
|
|
9,108,000
|
|
(1,559,000
|
)
|
(227,000
|
)
|
(1,264,000
|
)
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
(14,248,000
|
)
|
$
|
4,036,000
|
|
$
|
353
,000
|
|
$
|
3,343,000
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) PER SHARE OF COMMON STOCK BASIC
|
|
$
|
(1.38
|
)
|
$
|
.43
|
|
$
|
0.03
|
|
$
|
.35
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) PER SHARE OF COMMON STOCK DILUTED
|
|
$
|
(1.38
|
)
|
$
|
.42
|
|
$
|
0.03
|
|
$
|
.34
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares of Common Stock
and dilutive securities:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
10,341,000
|
|
9,430,000
|
|
10,305,000
|
|
9,690,000
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
10,341,000
|
|
9,509,000
|
|
10,333,000
|
|
9,772,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
4
Table of
Contents
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENT OF STOCKHOLDERS EQUITY
For the Nine Months Ended July 31, 2009
(Unaudited)
|
|
|
|
|
|
Capital In
|
|
|
|
|
|
Total
|
|
|
|
Common Stock
|
|
Excess Of
|
|
Treasury
|
|
Retained
|
|
Stockholders
|
|
Description
|
|
Shares
|
|
Amount
|
|
Par Value
|
|
Stock
|
|
Earnings
|
|
Equity
|
|
Balance October 31,
2008
|
|
10,660,000
|
|
$
|
1,066,000
|
|
$
|
31,352,000
|
|
$
|
(982,000
|
)
|
$
|
30,775,000
|
|
$
|
62,211,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)
|
|
|
|
|
|
|
|
|
|
(14,248,000
|
)
|
(14,248,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
(1,232,000
|
)
|
|
|
(1,232,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation expense associated with unvested
portion of previously granted stock options
|
|
|
|
|
|
24,000
|
|
|
|
|
|
24,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance July 31, 2009
|
|
10,660,000
|
|
$
|
1,066,000
|
|
$
|
31,376,000
|
|
$
|
(2,214,000
|
)
|
$
|
16,527,000
|
|
$
|
46,755,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
5
Table of
Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
Nine Months Ended
|
|
|
|
July 31,
|
|
|
|
2009
|
|
2008
|
|
CASH FLOWS FROM
OPERATING ACTIVITIES:
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(14,248,000
|
)
|
$
|
4,036,000
|
|
Adjustments to reconcile net income to net cash
provided by operating activities:
|
|
|
|
|
|
Write-down of oil and natural gas properties and
impairment of long lived assets
|
|
24,653,000
|
|
|
|
Depreciation, depletion and amortization
|
|
3,499,000
|
|
2,594,000
|
|
ARO liability accretion
|
|
85,000
|
|
38,000
|
|
Unrealized (gains) loss on derivative instruments
|
|
1,046,000
|
|
1,309,000
|
|
Deferred income taxes
|
|
(9,159,000
|
)
|
1,170,000
|
|
Loss on short term investments
|
|
65,000
|
|
67,000
|
|
Compensation expense related to stock options
granted
|
|
24,000
|
|
44,000
|
|
Other
|
|
(5,000
|
)
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
Proceeds from short-term investments
|
|
2,292,000
|
|
2,721,000
|
|
Accrued oil and gas sales
|
|
473,000
|
|
(1,776,000
|
)
|
Trade receivables
|
|
597,000
|
|
22,000
|
|
Other current assets
|
|
(123,000
|
)
|
(8,000
|
)
|
Accounts payable and accrued liabilities
|
|
(1,103,000
|
)
|
(589,000
|
)
|
Income taxes payable
|
|
47,000
|
|
38,000
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
|
8,143,000
|
|
9,666,000
|
|
|
|
|
|
|
|
CASH FLOWS FROM
INVESTING ACTIVITIES:
|
|
|
|
|
|
Additions to oil and gas properties
|
|
(11,299,000
|
)
|
(8,414,000
|
)
|
Proceeds from sale of oil and gas properties
|
|
|
|
1,275,000
|
|
Changes in other long-term assets
|
|
(54,000
|
)
|
(1,494,000
|
)
|
Purchase intangible assets
|
|
(4,400,000
|
)
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES
|
|
(15,753,000
|
)
|
(8,633,000
|
)
|
|
|
|
|
|
|
CASH FLOWS FROM
FINANCING ACTIVITIES:
|
|
|
|
|
|
Sale of common stock
|
|
|
|
15,111,000
|
|
Purchase of treasury stock
|
|
(1,232,000
|
)
|
|
|
Proceeds from exercise of stock options
(62,000 options in 2008)
|
|
|
|
366,000
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
|
(1,232,000
|
)
|
15,477,000
|
|
|
|
|
|
|
|
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
(8,842,000
|
)
|
16,510,000
|
|
|
|
|
|
|
|
CASH AND CASH
EQUIVALENTS:
|
|
|
|
|
|
Beginning of period
|
|
22,332,000
|
|
7,285,000
|
|
|
|
|
|
|
|
End of period
|
|
$
|
13,490,000
|
|
$
|
23,795,000
|
|
|
|
|
|
|
|
Additions to oil and gas properties in current
liabilities
|
|
$
|
390,000
|
|
$
|
383,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
6
Table
of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To
Consolidated Financial Statements (Unaudited)
July 31,
2009
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 September 9,
2009, the date that 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, 2008. 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 has 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 nine
months ended July 31, 2009 and 2008 were $3,100,000 and $2,508,000
respectively, and were $838,000 and $811,000 for the three months ended July 31,
2009 and 2008, 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 rentals,
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.
7
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
July 31, 2009 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 nine months ended July 31, 2009, the company has recorded ceiling test
write-downs of $23,726,000. Given the
volatility of oil and natural gas prices, additional write-downs may be
required in fiscal 2009.
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
the nine months ended July 31, 2009 and 2008, the company recognized
stock based compensation expense of $24,000 and $44,000 respectively. For the three months ended July 31, 2009
and 2008, the company recognized stock based compensation expense of $8,000 and
$14,000, respectively. The estimated
unrecognized compensation cost from unvested stock options as of July 31, 2009
was approximately $41,000 which is expected to be recognized over an average of
1.3 years.
No
options were granted during the nine months ended July 31, 2009 or 2008.
8
Table
of Contents
Plan activity for the nine months ended July 31, 2009 is set forth
below:
|
|
Nine Months Ended July 31,
2009
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
Aggregate
|
|
|
|
Number of
|
|
Exercise
|
|
Intrinsic
|
|
|
|
Options
|
|
Price
|
|
Value
|
|
Outstanding at October 31, 2008
|
|
232,769
|
|
$
|
9.04
|
|
$
|
394,000
|
|
Granted
|
|
|
|
|
|
|
|
Exercised
|
|
|
|
|
|
|
|
Cancelled or forfeited
|
|
(53,706
|
)
|
14.31
|
|
|
|
Outstanding at July 31, 2009
|
|
179,063
|
|
$
|
7.46
|
|
$
|
936,000
|
|
|
|
|
|
|
|
|
|
Exercisable at July 31, 2009
|
|
169,063
|
|
$
|
7.15
|
|
$
|
936,000
|
|
|
|
|
|
|
|
|
|
Weighted average contractual life at July 31, 2009
|
|
|
|
4.6
|
years
|
|
|
|
Outstanding
|
|
Exercisable
|
|
|
|
Number
|
|
Weighted Average
|
|
Weighted
|
|
Number
|
|
|
|
Range of
|
|
Outstanding
|
|
Remaining
|
|
Average
|
|
Exercisable at
|
|
Weighted
|
|
Exercise
|
|
at July 31,
|
|
Contractual
|
|
Exercise
|
|
July 31,
|
|
Average
|
|
Prices
|
|
2009
|
|
Life in Years
|
|
Price
|
|
2009
|
|
Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 5.93
|
|
139,063
|
|
3.87
|
|
$
|
5.93
|
|
139,063
|
|
$
|
5.93
|
|
$12.78
|
|
40,000
|
|
7.35
|
|
$
|
12.78
|
|
30,000
|
|
$
|
12.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 5.93 -$12.78
|
|
179,063
|
|
4.65
|
|
$
|
7.46
|
|
169,063
|
|
$
|
7.15
|
|
5. NATURAL GAS DERIVATIVES
On February 1, 2009,
the company adopted SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities - an amendment of FASB Statement No. 133
(SFAS No. 161). SFAS No. 161 requires entities to provide
greater transparency about how and why an entity uses derivative instruments,
how derivative instruments and related hedged items are accounted for under
SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities (SFAS No. 133) and how derivative instruments and related
hedged items affect an entitys financial position, results of operations, and
cash flows.
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 nine months ended July 31, 2009 and 2008, the company had realized
gains (loss) on derivatives of $2,957,000 and ($1,024,000) respectively, and
unrealized losses of $1,046,000 and $1,309,000 respectively. For the quarter ended July 31, 2009 and 2008 the company had realized gains
(losses) on derivatives of $682,000 and ($1,876,000) respectively, and
unrealized gains (losses) of ($698,000) and $3,015,000, respectively. At July 31, 2009 open derivative
contracts covered 150,000 MMBtus at weighted average NYMEX basis prices of
$8.31, and cover the production months of August 2009
9
Table
of Contents
through
October 2009. Average prices in the
companys primary market are currently 8% below NYMEX prices due to basis
differentials and transportation costs.
Subsequent
to July 31, the August and September contracts closed resulting
in realized hedge gains of $512,000.
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.
At July 31, 2009 the company has outstanding natural gas swap
contracts for 50,000 Mmbtu per month through October 2009. 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 under SFAS No. 133:
|
|
As of July 31, 2009
|
|
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Natural Gas Forward Short Positions
|
|
Derivative Asset
|
|
$
|
699
|
|
|
|
|
|
|
|
|
Amount of Gain or (Loss) Recognized in Income on Derivatives:
Derivatives not designated as hedging instruments under SFAS No. 133:
|
|
Location of Gain/(Loss)
|
|
Nine Months
|
|
Three Months
|
|
|
|
Recognized in
|
|
Ended
|
|
Ended
|
|
|
|
Income on Derivatives
|
|
July 31, 2009
|
|
July 31, 2009
|
|
Natural Gas Forward Short Positions
|
|
Other Income and (Expense)
|
|
$
|
1,911
|
|
$
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
6. EARNINGS PER SHARE
The companys calculation of earnings (loss) per share of common stock
is as follows:
|
|
Nine
Months Ended July 31,
|
|
|
|
2009
|
|
2008
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
(Loss)
|
|
Net
|
|
|
|
Income
|
|
|
|
(Loss)
|
|
Shares
|
|
Per
Share
|
|
Income
|
|
Shares
|
|
Per
Share
|
|
Basic earnings (loss) per share
|
|
$
|
(14,248,000
|
)
|
10,341,000
|
|
$
|
(1.38
|
)
|
$
|
4,036,000
|
|
9,430,000
|
|
$
|
.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive shares of common stock from stock options
|
|
|
|
|
|
|
|
|
|
79,000
|
|
(.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss)
per share
|
|
$
|
(14,248,000
|
)
|
10,341,000
|
|
$
|
(1.38
|
)
|
$
|
4,036,000
|
|
9,509,000
|
|
$
|
.42
|
|
10
Table
of Contents
|
|
Three Months Ended
July 31,
|
|
|
|
2009
|
|
2008
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
Income
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Basic earnings (loss) per share
|
|
$
|
353,000
|
|
10,305,000
|
|
$
|
.03
|
|
$
|
3,343,000
|
|
9,690,000
|
|
$
|
.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive shares of common stock from stock options
|
|
|
|
28,000
|
|
|
|
|
|
82,000
|
|
(.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss)
per share
|
|
$
|
353,000
|
|
10,333,000
|
|
$
|
.03
|
|
$
|
3,343,000
|
|
9,772,000
|
|
$
|
.34
|
|
The companys outstanding options were not included in the calculation
of diluted income (loss) per share for the nine month period ended July 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 July 31, 2009 the companys 2007 Federal tax return had been
audited by the IRS, and the final report reflected approximately $24,000 in
additional tax due. The company remains
subject to examination of Federal and state tax returns, except Colorado, for
the tax years 2005 and 2006, and for the tax years 2004 through 2007 for
Colorado tax returns.
8. INTANGIBLE ASSETS
On
November 6, 2008 the company purchased all of the patents underlying the
Calliope Gas Recovery Technology, all of the related third party interests in
future installations of the technology and patents covering a new fluid lift
technology for shallow wells known as Tractor Seal for $4,400,000. The patents are being amortized on a straight
line basis over the remaining lives ranging from 8.4 to 17.4 years.
|
|
July 31, 2009
|
|
|
|
Gross Carrying
|
|
Accumulated
|
|
|
|
Amount
|
|
Amortization
|
|
Amortized intangible assets:
|
|
|
|
|
|
Calliope intangible assets
|
|
$
|
4,449,000
|
|
$
|
327,000
|
|
|
|
|
|
|
|
Aggregate amortization expense:
|
|
|
|
|
|
For the nine months ended
July 31, 2009
|
|
|
|
|
$
|
327,000
|
|
11
Table
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In
July 2008, the company acquired the third party rights related to certain
future Calliope installations for $975,000.
Those third party rights would have resulted principally from Calliope
installations of joint ventures between the company and other natural gas
producing companies.
As
a result of the natural gas market at January 31, 2009, the company
believed it to be more likely than not that the formation of joint ventures for
the installation of Calliope technology that would have been subject to these
third party rights would not occur within the foreseeable future. Based on that assumption, and in accordance
with FASB Statement No. 144
Accounting for the
Impairment or Disposal of Long-Lived Assets
(FAS 144), the
company determined that the sum of the undiscounted value of cash flows to be
derived from future installations of Calliope technology resulting from joint
ventures was minimal. Accordingly, the
company recorded an impairment loss of $927,000 for the quarter ended January 31, 2009.
The company reviews the value of its
intangible assets in accordance with SFAS 144,
Accounting
for the Impairment or Disposal of Long Lived Assets
, which requires
that it evaluate these 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.
9. FAIR VALUE MEASUREMENTS
On November 1, 2008, the company adopted SFAS No. 157
Fair Value Measurements
, which defines fair value,
establishes a framework for measuring fair value, and expands disclosures about
fair value measurements. SFAS No. 157
applies to other accounting pronouncements that require or permit fair value
measurements; however, it does not require any new 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.
SFAS No. 157 establishes 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 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.
A financial assets or liabilitys classification 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 SFAS No. 157,
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 July 31, 2009:
|
|
As of
July 31, 2009
|
|
|
|
Level
1
|
|
Level
2
|
|
Level
3
|
|
Total
|
|
|
|
(in
thousands)
|
|
Asset:
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
|
$
|
299
|
|
$
|
|
|
$
|
388
|
|
$
|
687
|
|
Derivative assets
(current)
|
|
$
|
|
|
$
|
699
|
|
$
|
|
|
$
|
699
|
|
12
Table of
Contents
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.
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 and nine months ended July 31, 2009:
|
|
Three Months
|
|
Nine Months
|
|
|
|
Ended
|
|
Ended
|
|
|
|
July 31, 2009
|
|
July 31, 2009
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
Balance
as of April 30, 2009 and October 31, 2008, respectively(1)
|
|
$
|
1,576
|
|
$
|
2,764
|
|
Total
gains (losses):
|
|
|
|
|
|
Included
in earnings(2)
|
|
14
|
|
(199
|
)
|
Redemptions
|
|
(1,202
|
)
|
(2,177
|
)
|
Balance
as of July 31, 2009
|
|
$
|
388
|
|
$
|
388
|
|
(1) This amount is included in short-term
investments on the balance sheet.
(2) This amount is included in investment and
other income (loss) on the statement of operations.
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. On
April 9, 2009, the Board 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 July 31, 2009, the company acquired 7,482
shares of its common stock at an aggregate cost of $80,185. For the nine months ended July 31, 2009,
the company acquired 138,982 shares of its common stock at an aggregate cost of
$1,232,000. At July 31, 2009 a
total of 237,922 shares have been repurchased under the program at an
average price per share of $8.22.
Subsequent to July 31, 2009, and through September 9, 2009,
the company has repurchased an additional 4,000 shares, bringing the total
shares repurchased to 241,922 at an average price per share of $8.26.
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 July 31,
2009.
13
Table
of Contents
12. RECENT ACCOUNTING
PRONOUNCEMENTS
In December 2008, the Securities and Exchange Commission 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 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 December 31,
2009, with early adoption prohibited.
The company is currently evaluating the impact that the adoption of this
pronouncement will have on the companys financial position, results of
operations, and disclosures.
In November 2007, the FASB issued Statement No. 141 (revised
2007),
Business Combination
(FAS 141(R)) and Statement No. 160,
Noncontrolling
Interests in Consolidated Financial Statements, an amendment of ARB No. 51
(FAS 160). FAS 141(R) will
change how business acquisitions are accounted for and will impact financial
statements both on the acquisition date and in subsequent periods. FAS 160 will change the accounting and
reporting for minority interests, which will be recharacterized as noncontrolling
interests and classified as a component of equity. FAS 141(R) and FAS 160 are
effective for both public and private companies for fiscal years beginning on
or after December 15, 2008 (fiscal 2010 for the company). FAS 141(R) will be applied
prospectively. FAS 160 requires
retroactive adoption of the presentation and disclosure requirements for
existing minority interests. All other
requirements of FAS 160 will be applied prospectively. Early adoption is prohibited for both
standards. Management is currently
evaluating the requirements of FAS 141(R) and FAS 160 and has
not yet determined the impact on its financial statements.
In April 2009, the FASB issued FSP No. FAS 107-1
and APB 28-1,
Interim Disclosures about
Fair Value of Financial Instruments
(FSP FAS 107-1 and
APB 28-1), which requires the disclosure of the fair value, together with
the carrying amount, of financial instruments, regardless of whether they are
recognized at fair value in the statement of financial position, for interim
reporting periods of publicly traded companies as well as in annual financial
statements. This pronouncement is
effective for interim reporting periods ending after June 15, 2009, with
earlier adoption permitted for periods ending after March 15, 2009. The Company adopted this pronouncement for
the quarter ended April 30, 2009.
As this pronouncement requires only additional disclosures, there was no
impact on the Companys financial position or results of operations as a result
of the adoption.
In April 2009, the FASB issued FSP No. FAS 157-4,
Determining Fair Value When the Volume and
Level of Activity for the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly
(FSP FAS 157-4),
which provides additional guidance for estimating fair value in accordance with
SFAS 157 in certain circumstances.
This pronouncement is effective for interim and annual reporting periods
ending after June 15, 2009, with earlier adoption permitted for periods
ending after March 15, 2009. The
company adopted this pronouncement for the quarter ended July 31, 2009;
however, there was no impact on the Companys financial position or results of
operations as a result of the adoption.
In April 2009, the FASB issued FSP No. FAS 115-2
and FAS 124-2,
Recognition and
Presentation of Other-Than-Temporary Impairments
(FSP
FAS 115-2 and FAS 124-2), which amends the existing
other-than-temporary impairment guidance for debt securities to make the
guidance more operational and to improve the presentation and disclosure of
other-than-temporary impairments on debt and equity securities in the financial
statements. Other-than-temporary
impairment relates to investments in debt and
14
Table
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equity securities for which changes in fair value are
not regularly recognized in earnings (such as securities classified as
held-to-maturity or available-for-sale).
This pronouncement is effective for interim and annual reporting periods
ending after June 15, 2009, with earlier adoption permitted for periods
ending after March 15, 2009. An
entity that early adopts FSP FAS 107-1 and APB 28-1 must also early
adopt FSP FAS 115-2 and FAS 124-2.
Accordingly, the Company has adopted this pronouncement for the quarter
ended March 31, 2009; however, since the Company has no such investments
in debt or equity securities, there was no impact on the Companys financial
position or results of operations as a result of the adoption.
In May 2009, the FASB issued SFAS No. 165,
Subsequent Events
(SFAS 165), which
provides general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued
or are available to be issued. This
topic was previously addressed only in auditing literature. SFAS 165 is similar to the existing
auditing guidance with some exceptions that are not intended to result in
significant changes to practice.
Entities are now required to disclose the date through which subsequent
events have been evaluated, with such date being the date the financial
statements were issued or available to be issued. SFAS 165 is effective on a prospective
basis for interim or annual reporting periods ending after June 15,
2009. Accordingly, the Company adopted
this pronouncement for the quarter ended July 31, 2009; however, there was
no impact on the Companys financial position or results of operations as a
result of the adoption.
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 relate to, among other things:
·
the companys
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 companys 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 companys
business and operations.
15
Table
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LIQUIDITY
AND CAPITAL RESOURCES
At July 31, 2009,
working capital decreased to $14,846,000 compared to $24,160,000 at October 31, 2008. For the nine months ended July 31, 2009,
net cash provided by operating activities was $8,143,000 compared to $9,666,000
for the same period in 2008. Net income
decreased $18,284,000 primarily due to impairment losses of $24,653,000, a
decrease in revenue of $7,023,000 and increased other costs and expenses of
$1,335,000.
For the nine months ended July 31, 2009 and 2008, net cash used in
investing activities was $15,753,000 and $8,633,000, respectively. Investing activities primarily included oil
and gas exploration and development expenditures, including Calliope, totaling
$11,299,000 and $8,414,000 respectively.
For the period ended July 31, 2009, the company also purchased the
patents underlying the Calliope Technology for $4,400,000.
At
July 31, 2009, 56% of the companys short term investments were being
liquidated.
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, 2009,
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 $4,796,000 for
the nine months ended July 31, 2009 compared to $8,196,000 for the nine
months ended July 31, 2008.
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 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:
|
|
Nine Months Ended
July 31,
|
|
|
|
2009
|
|
2008
|
|
RECONCILIATION OF EBITDA:
|
|
|
|
|
|
Net Income (loss)
|
|
$
|
(14,248,000
|
)
|
$
|
4,036,000
|
|
Add Back (Deduct):
|
|
|
|
|
|
Interest Expense
|
|
|
|
7,000
|
|
Income Tax Expense (Benefit)
|
|
(9,108,000
|
)
|
1,559,000
|
|
Depreciation,
Depletion and Amortization Expense
Including Write-Down and Impairment
|
|
28,152,000
|
|
2,594,000
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
4,796,000
|
|
$
|
8,196,000
|
|
OFF-BALANCE SHEET FINANCING
The
company has no off-balance sheet arrangements at July 31, 2009.
16
Table
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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. Refer to Note 5 of the Consolidated
Financial Statements for a complete discussion on the companys hedging
activities.
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 realized
hedging transactions.
|
|
Nine
Months Ended July 31,
|
|
|
|
2009
|
|
2008
|
|
%
Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls)
|
|
90,500
|
|
$
|
45.77
|
|
42,500
|
|
$
|
101.66
|
|
+113
|
%
|
- 55
|
%
|
Gas (Mcf)
|
|
940,000
|
|
$
|
6.50
|
(1)
|
1,221,000
|
|
$
|
7.87
|
(2)
|
- 23
|
%
|
- 17
|
%
|
|
|
Three
Months Ended July 31,
|
|
|
|
2009
|
|
2008
|
|
%
Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls)
|
|
35,500
|
|
$
|
56.98
|
|
13,400
|
|
$
|
122.91
|
|
+165
|
%
|
- 54
|
%
|
Gas (Mcf)
|
|
293,000
|
|
$
|
5.08
|
(3)
|
396,000
|
|
$
|
6.96
|
(4)
|
- 26
|
%
|
- 27
|
%
|
(1) Includes $3.14 Mcf realized hedging gain.
(2) Includes $0.32 Mcf realized hedging loss.
(3) Includes $2.33 Mcf realized hedging gain.
(4) Includes $3.13 Mcf realized hedging loss.
As
previously reported, during fiscal 2008 and the first two quarters of fiscal
2009, the company elected to postpone certain scheduled drilling due to the
historically high costs of equipment and field services. That decision came with the consequence that
less drilling would cause production to decline. The decline in gas production is evidenced by
the above table.
Beginning
in fiscal year 2008, the company has focused its drilling program primarily on
oil prospects. The results of the
drilling program are also evidenced by
the above table. Oil production has
increased 113% for the nine months ended July 31, 2009 compared to the
same period in 2008. In the quarter
ended July 31, 2009 oil production has increased 165% compared to the
same quarter in 2008.
On
a gas equivalent units basis, the production declines the company has
experienced in recent periods have been substantially overcome. Total production is unchanged for the nine
months ended July 31, 2009 from the same period a year ago and for
the three months ended July 31, 2009 gas equivalent production has
increased 6% from the same period last year.
More
importantly, recent drilling discoveries have begun to significantly improve
the balance between oil and gas reserves and oil and gas production.
17
Table
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OPERATIONS
During the first nine months of fiscal 2009, 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 2009, 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.
The
company delayed drilling scheduled for the second quarter 2009 for a period of
at least two months in anticipation of significant improvement in both the cost
and quality of drilling services and materials, which has begun to occur. Accordingly, the company re-instituted its
drilling program and drilled five wells during the third quarter 2009 and plans
to drill at least three wells per month during the remainder of 2009.
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.
Proprietary Drilling Results
The company recently
announced that it has
participated in drilling a wildcat discovery well that flowed oil at impressive
initial rates during completion testing.
For competitive reasons, we have not disclosed any detailed ownership,
location or technical information about the well. Production is being curtailed to between
100 and 200 barrels of oil per day.
Two confirmation wells have yielded positive results. A third confirmation well was not a commercial
producer. Two additional wells are
planned to be drilled during the remainder of the calendar year.
Northern Anadarko Basin
Oklahoma drilling has
historically been the primary driver for CREDOs production growth. CREDO owns approximately 75,000 gross
acres and has interests in almost 200 wells. During the first quarter of
fiscal 2009, CREDO completed two wells on its PoolProffitt Prospect to
test multiple carbonate reservoirs using new fracture stimulation technology. Both have proved to be commercial wells, and
there are up to 12 additional locations on CREDOs acreage. CREDO owns 50% to 73% working
interest in the wells.
In Hemphill
County, Texas, the company purchased an additional 3,800 gross acres and
assumed operatorship of 11 wells. The new acreage complements the companys
Humphreys Prospect and brings our total acreage in the area to approximately
8,300 gross acres. We have drilled
two successful wells on the acreage, and intend to drill more wells in the
future. CREDO owns interests ranging up
to 25%.
18
Table
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South Texas
CREDO entered the South
Texas joint venture to use 3-D seismic to explore for deep, highly faulted
prospects. The high potential,
17,000-foot wildcat well drilled to test the Deep Wilcox sand on the Gemini
Prospect confirmed the seismic interpretation and found porous sand. However, the sand was water wet and the well
was plugged and abandoned. CREDO
received approximately $1,300,000 in cash for the prospect package last year,
but retained an 11.25% carried interest in the test well. The prospect package consists of two
additional Deep Wilcox prospects which are geologically different from the
Gemini Prospect. They are being further
evaluated, and if drilled, CREDO will have an 11.25% carried interest in
the next well.
Central Kansas Uplift
The company has achieved
excellent drilling results on the Central Kansas Uplift. To date, CREDO has participated in 41 wells on the Uplift,
of which 46% have been successfully completed as oil
producers. That outstanding success
prompted us to increase CREDOs leasehold position to almost 150,000 gross
and 75,000 net acres. This acreage
provides a good inventory of future drilling opportunities where CREDO owns
interests ranging up to 85 percent.
Credo recently completed shooting 3-D seismic over approximately 100
square miles of the prospect, and the initial interpretation shows many
potential drilling locations in 11 prospect areas. The company expects to drill two to four
wells per month for the balance of the year.
Drilling on the Uplift is relatively shallow
and costs are moderate, yielding good economics even in the current product
price environment. In addition, the
project is oil targeted, thereby improving the balance between oil and natural
gas in CREDOs reserve base. We expect
Kansas to make a major contribution to our reserve and production growth in
2009.
Bakken Shale
CREDO entered the horizontal Bakken oil play in
2008 by leasing about 4,700 acres in North Dakota. The new leases have five or ten year terms
and they are located in the vicinity of the recently discovered and prolific
Parshall Field. Based on 640 acre
spacing units, CREDO has interests in up to 27 well locations. Approximately $2,258,000 (50%) of the
acquisition cost has been reclassified to the full cost pool. The companys first well is scheduled to be
drilled in early September in what has become the number one oil resource
play in the U.S. Breakthroughs in
precision horizontal drilling and multi-stage, high pressure fracture
stimulations have made the Bakken shale a very active resource play. The U.S. Geological Survey recently estimated
that the Bakken contains around 4.0 billion barrels of undiscovered oil.
Calliope Gas Recovery Technology
Calliope Gas Recovery System
We are continuing to actively discuss
commercial Calliope terms with several companies. One Calliope license agreement was entered
into in third quarter 2009 and an additional agreement is nearing
execution. 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.
At year-end, Credo
owned an exclusive license to the Calliope patents and the related
technology. However, in order to
establish absolute control over the technology and to eliminate future costs
for individual well licenses, we recently purchased all of the underlying patents
for $4,400,000. A portion of this
acquisition also covers an exciting series of new patents, known as Tractor
Seal, that is specifically designed to remove liquids from shallow wells more
efficiently than existing technologies.
If perfected, this new technology will be an excellent complement to
Calliopes focus on deeper wells.
19
Table
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Results of Operations
Nine Months Ended July 31,
2009 Compared to Nine Months Ended July 31, 2008
For the nine months ended July 31,
2009, oil and gas revenues decreased 49% to $7,298,000 compared to $14,321,000
during the same period last year. As the
oil and gas price/volume table on page 17 shows, total gas price realizations,
which reflect realized hedging transactions, decreased 17% to $6.50 per Mcf and
oil price realizations decreased 55% to $45.77 per barrel. The net effect of these price changes was to
decrease oil and gas realizations by $3,681,000 ($7,025,000 without realized
hedges). For the nine months ended July 31,
2009, the companys gas equivalent production was unchanged from the same
period last year. The company elected to
postpone certain scheduled drilling due to the historically high costs of equipment
and field services. That decision came
with the consequence that less drilling would cause production declines. Natural gas production has declined 23% but a
113% increase in oil production has offset the gas decline. Investment and other income decreased
$184,000, primarily due to market performance and liquidation of the companys
investments, compared to last year.
For the nine months ended July 31, 2009,
total costs and expenses, excluding the impairment loss of $24,653,000,
increased 21% to $7,846,000 compared to $6,511,000 for the comparable period in
2008. Oil and gas production expenses
decreased due primarily to reduced field level expenses. DD&A increased primarily due to an
increase in the amortizable cost base before the impairment adjustment. General and administrative expenses increased
primarily due to accounting and professional fees and increased salaries and
benefits. The effective tax rate was
39.0% and 27.9% for the 2009 and 2008 periods, respectively.
Three Months Ended July 31, 2009 Compared to Three Months Ended July 31,
2008
For the three months ended July 31, 2009, total revenues decreased
50% to $2,837,000 compared to $5,646,000 during the same period last year. As the oil and gas price/volume table on page 17
shows, total gas price realizations, which reflect realized hedging
transactions, decreased 27% to $5.08 per Mcf and oil price realizations
decreased 54% to $56.98 per barrel. The
net effect of these price changes was to decrease oil and gas realizations by
$894,000 ($2,815,000 without realized hedges).
For the three months ended July 31, 2009, the companys gas
equivalent production increased 6%.
Investment and other income improved slightly due to improved market
performance.
For the three months ended July 31,
2009, total costs and expenses rose 3% to $2,295,000 compared to $2,225,000 for
the comparable period in 2008. Oil and
gas production expenses decreased 26% due primarily to decreased field level
costs. Depreciation, depletion and
amortization (DD&A) increased primarily due to amortization of intangible
assets. General and administrative
expenses increased primarily due to accounting and professional fees and
increased salaries and benefits. The
effective tax rate was 39.1% and 27.4% for the 2009 and 2008 periods,
respectively.
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 and intangible assets, the
accounting for oil and gas reserves, revenue receivables, and the estimate of
its asset retirement obligations.
20
Table of
Contents
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. 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 rentals,
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.
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
considers price increases subsequent to the balance sheet date which may reduce
or eliminate a write-down.
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.
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. 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.
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.
INTANGIBLE ASSETS
The company reviews the value of its intangible
assets in accordance with FASB Statement No. 144 which requires that it
evaluate these 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.
21
Table of Contents
On
September 1, 2000, the company acquired an unrestricted, exclusive license
for patented Calliope Gas Recovery System technology. In July 2008, the company acquired the
third party rights resulting from certain future Calliope installations for
$975,000. Those third party rights would
have resulted principally from Calliope installations of joint ventures between
the company and other natural gas producing companies. As a result of the natural gas prices at
January 31, 2009, the company determined it to be more likely than not
that the formation of joint ventures for the installation of Calliope
technology that would have been subject to these third party rights will not
occur within the foreseeable future.
Based on this assumption, and in accordance with FAS 144
Accounting for the Impairment or Disposal of Long-Lived Assets
,
the company determined that the sum of the undiscounted value of cash flows to
be derived from future installations of Calliope technology resulting from
joint ventures is minimal. Accordingly, the
company recorded an impairment loss of $927,000.
On
November 6, 2008 the company purchased all of the patents underlying the
Calliope Gas Recovery Technology, all of the related third party interests in
future installations of the technology and patents covering a new fluid lift
technology for shallow wells known as Tractor Seal for $4,400,000. The patents are being amortized on a straight
line basis over the remaining lives ranging from 8.2 to 17.2 years. These costs are subject to potential future impairment
if anticipated future Calliope installations do not occur.
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. 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 companys 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.
HEDGING
The company recognizes all derivatives as
fair value hedges on its balance sheet at fair value at the end of each
period. Changes in the fair value of
hedges are recorded in the Consolidated Statement of Operations.
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 July 31 2009 open
derivative contracts covered 150,000 MMBtus, approximately 50% of the
companys anticipated 4
th
quarter 2009 natural gas production, at NYMEX
prices averaging $8.31 and covered the production months of
August, 2009 through October, 2009.
Average prices in the companys primary market are currently
8% 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. Relevant
terms of the open derivative contracts at July 31, 2009 are as
follows:
22
Table of
Contents
Natural
Gas Forward Short Positions
|
|
Contract
|
|
Weighted
Average
|
|
|
|
Fiscal Quarter Ending
|
|
Volumes
MMBtus
|
|
Price
per MMBtu
|
|
Fair
Value
|
|
|
|
|
|
|
|
|
|
Oct. 31, 2009
|
|
150,000
|
|
$
|
8.31
|
|
$
|
699,000
|
|
|
|
|
|
|
|
|
|
|
|
ITEM
4.
|
|
CONTROLS AND PROCEDURES
|
Disclosure
Controls and Procedures
Our management, with the
participation of James T. Huffman, our Chief Executive Officer, and Alford B.
Neely, our Chief Financial Officer, evaluated the effectiveness of our disclosure
controls and procedures as of July 31, 2009. 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 July 31, 2009 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 into 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, as amended, for the fiscal
year ended October 31, 2008.
|
|
|
|
ITEM 2.
|
|
UNREGISTERED SALES OF EQUITY
SECURITIES AND USE OF PROCEEDS
|
|
|
|
|
|
Issuer Purchases of Equity
Securities.
|
|
|
|
|
|
During the first nine
months of fiscal year 2009, the company repurchased 138,982 shares of its
common stock on the open market at a weighted average price of $8.86. 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.
|
23
Table of Contents
|
|
At
July 31, 2009, the company has repurchased 237,922 shares of common
stock at an average price per share of $8.22. Subsequent to July 31, 2009, and
through September 9, 2009, the company has repurchased an additional
4,000 shares, bringing the total shares repurchased to 241,922 at an average
price per share of $8.26.
|
Issuer Purchases of Equity Securities
Period
|
|
Total number of
shares purchased
|
|
Average price
paid per share
|
|
Total number
of shares
purchased
as part of
publicly
announced plans
|
|
Maximum
dollar value
of shares
that may yet
be purchased
under the plans
|
|
|
|
|
|
|
|
|
|
|
|
Sept.
22, 2008 Oct. 31, 2008
|
|
98,940
|
|
$
|
7.31
|
|
98,940
|
|
$
|
1,277,000
|
|
November 1
- 30 2008
|
|
45,954
|
|
$
|
9.45
|
|
45,954
|
|
$
|
843,000
|
|
December 1
- 31 2008
|
|
22,350
|
|
$
|
8.88
|
|
22,350
|
|
$
|
645,000
|
|
January 1
- 31 2009
|
|
6,182
|
|
$
|
9.16
|
|
6,182
|
|
$
|
588,000
|
|
February 1
28, 2009
|
|
29,104
|
|
$
|
8.56
|
|
29,104
|
|
$
|
338,000
|
|
March 1
31, 2009
|
|
15,110
|
|
$
|
7.49
|
|
15,110
|
|
$
|
225,000
|
|
April 1
30, 2009
|
|
12,800
|
|
$
|
7.76
|
|
12,800
|
|
$
|
2,126,000
|
|
June 1
30, 2009
|
|
1,031
|
|
$
|
9.58
|
|
1,031
|
|
$
|
2,116,000
|
|
July 1
31, 2009
|
|
6,451
|
|
$
|
10.90
|
|
6,451
|
|
$
|
2,045,000
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
237,922
|
|
$
|
8.22
|
|
237,922
|
|
|
|
ITEM
3.
|
|
DEFAULTS
UPON SENIOR SECURITIES
|
|
|
|
|
|
None.
|
|
|
|
ITEM
4.
|
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
|
|
|
|
|
None.
|
|
|
|
ITEM
5.
|
|
OTHER
INFORMATION
|
|
|
|
|
|
Subsequent
Events:
|
|
|
|
|
|
On
September 3, 2009 the company entered into basis hedging contracts for
480,000 MMBtu for Panhandle Eastern Pipeline Company vs NYMEX basis
differential. The hedged basis is $0.465. The contracts are for 40,000 MMBtu
per month for January through December 2010 and are estimated to
cover approximately 50% of estimated production for that period.
|
|
|
|
|
|
On September 8, 2009
the company filed an 8-K report disclosing that James T. Huffman, Chief
Executive Officer and Chairman of the Board had announced his intent to
retire from the position of Chief Executive Officer at year end. He will
continue in his position as Chairman of the Board. The Board of Directors has
initiated the process to search for a new CEO.
|
24
Table of
Contents
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)
|
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/
James T. Huffman
|
|
|
James
T. Huffman
|
|
|
Chief
Executive Officer
|
|
|
(Principal
Executive Officer)
|
|
|
|
|
By:
|
/s/
Alford B. Neely
|
|
|
Alford
B. Neely
|
|
|
Chief
Financial Officer
|
|
|
(Principal
Financial and Accounting Officer)
|
|
|
|
|
|
|
Date:
September 9
, 2009
|
|
|
25
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