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,
2008
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)
Colorado
|
|
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 is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See definitions of
large accelerated filer, accelerated filer, and smaller reporting company
in Rule 12b-2 of the Exchange Act. (Check one):
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
|
Sept. 15, 2008
|
|
Common stock, $.10 par value
|
|
10,507,000
|
Table of
Contents
EXPLANATORY NOTE
On
September 2, 2008, in connection with preparing its quarterly report for
third quarter 2008, management of CREDO Petroleum Corporation (the company)
and the Audit Committee of its Board of Directors determined that the
contemporaneous formal documentation it had historically prepared to support
its initial hedge designations in connection with the companys natural gas
hedging program does not meet the technical requirements to qualify for cash
flow hedge accounting treatment in accordance with SFAS 133. The primary reason for this determination was
that the formal hedge documentation lacks specificity of the hedged items and
therefore, the cash flow designations failed to meet hedge documentation
requirements for cash flow hedge accounting treatment. Consequently, the unrealized gain or loss
should have been recorded in the consolidated statements of operations as a
component of income before income taxes.
Under the cash flow accounting
treatment used by the company, the fair values of the hedge contracts
was recognized in the consolidated balance sheets with the resulting unrealized
gain or loss, net of income taxes, recorded initially in accumulated other
comprehensive income and later reclassified through earnings when the hedged
production affected earnings.
The
company will restate its consolidated financial statements for fiscal years
ended October 31, 2005, 2006, 2007 and the first and second quarters
of fiscal year ending October 31, 2008. There is no effect in any period on overall
cash flows, EBITDA, total assets, total liabilities or total stockholders
equity. The restatement did not have any
impact on any of the Companys financial covenants under its line of
credit. Details of the effect of the
restatement are indicated in Note 1 to the Consolidated Financial Statements.
2
Table of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly
Report on Form 10-Q For the Period Ended July 31, 2008
TABLE OF CONTENTS
The terms CREDO,
Company, we, our, and us refer to CREDO Petroleum Corporation and its
subsidiaries unless the context suggests otherwise.
3
Table
of Contents
PART I - FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Balance Sheets
|
|
July 31,
|
|
October 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Unaudited)
|
|
(Restated)
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
23,795,000
|
|
$
|
7,285,000
|
|
Short-term
investments
|
|
3,595,000
|
|
6,383,000
|
|
Receivables:
|
|
|
|
|
|
Accrued oil and
gas sales
|
|
3,423,000
|
|
1,647,000
|
|
Trade
|
|
580,000
|
|
602,000
|
|
Derivative
Assets
|
|
|
|
443,000
|
|
Other current
assets
|
|
63,000
|
|
55,000
|
|
Total current
assets
|
|
31,456,000
|
|
16,415,000
|
|
|
|
|
|
|
|
Long-term
assets:
|
|
|
|
|
|
Oil and gas
properties, at cost, using full cost method:
|
|
|
|
|
|
Unevaluated oil
and gas properties
|
|
11,427,000
|
|
7,791,000
|
|
Evaluated oil
and gas properties
|
|
55,258,000
|
|
51,691,000
|
|
Less:
accumulated depreciation, depletion and amortization of oil and gas
properties
|
|
(24,616,000
|
)
|
(22,108,000
|
)
|
Net oil and gas
properties, at cost, using full cost method
|
|
42,069,000
|
|
37,374,000
|
|
Exclusive
license agreement, net of amortization of $553,000 in 2008 and $501,000 in
2007
|
|
146,000
|
|
198,000
|
|
Compressor and
tubular inventory to be used in development
|
|
2,478,000
|
|
1,090,000
|
|
Other, net
|
|
344,000
|
|
272,000
|
|
Total assets
|
|
$
|
76,493,000
|
|
$
|
55,349,000
|
|
LIABILITIES AND STOCKHOLDERS
EQUITY
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
882,000
|
|
$
|
1,639,000
|
|
Revenue
distribution payable
|
|
1,493,000
|
|
979,000
|
|
Derivative
liabilities
|
|
673,000
|
|
|
|
Other accrued
liabilities
|
|
506,000
|
|
852,000
|
|
Income taxes
payable
|
|
472,000
|
|
434,000
|
|
Total current
liabilities
|
|
4,026,000
|
|
3,904,000
|
|
|
|
|
|
|
|
Long Term
Liabilities:
|
|
|
|
|
|
Deferred income
taxes, net
|
|
10,374,000
|
|
9,204,000
|
|
Derivative
liabilities due in more than one year
|
|
193,000
|
|
|
|
Exclusive
license obligation, less current obligations of $77,000 in 2008 and 2007
|
|
85,000
|
|
85,000
|
|
Asset retirement
obligation
|
|
1,118,000
|
|
1,016,000
|
|
Total
liabilities
|
|
15,796,000
|
|
14,209,000
|
|
|
|
|
|
|
|
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 in
2008 and 9,510,000 in 2007
|
|
1,066,000
|
|
951,000
|
|
Capital in
excess of par value
|
|
31,174,000
|
|
15,913,000
|
|
Treasury stock
at cost, 153,000 shares in 2008 and 215,000 in 2007
|
|
(361,000
|
)
|
(506,000
|
)
|
Retained
earnings
|
|
28,818,000
|
|
24,782,000
|
|
Total
stockholders equity
|
|
60,697,000
|
|
41,140,000
|
|
|
|
|
|
|
|
Total
liabilities and stockholders equity
|
|
$
|
76,493,000
|
|
$
|
55,349,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
4
Table
of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Operations
(Unaudited)
|
|
Nine Months Ended
|
|
Three Months Ended
|
|
|
|
July 31,
|
|
July 31,
|
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
|
|
|
(Restated)
|
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
Oil and gas
sales
|
|
$
|
14,321,000
|
|
$
|
11,121,000
|
|
$
|
5,646,000
|
|
$
|
3,613,000
|
|
Investment
income and other
|
|
125,000
|
|
685,000
|
|
49,000
|
|
233,000
|
|
|
|
14,446,000
|
|
11,806,000
|
|
5,695,000
|
|
3,846,000
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND
EXPENSES:
|
|
|
|
|
|
|
|
|
|
Oil and gas
production
|
|
2,883,000
|
|
2,546,000
|
|
1,045,000
|
|
837,000
|
|
Depreciation,
depletion and amortization
|
|
2,594,000
|
|
2,782,000
|
|
843,000
|
|
883,000
|
|
General and
administrative
|
|
1,034,000
|
|
1,020,000
|
|
337,000
|
|
376,000
|
|
Interest
|
|
7,000
|
|
20,000
|
|
2,000
|
|
6,000
|
|
|
|
6,518,000
|
|
6,368,000
|
|
2,227,000
|
|
2,102,000
|
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM OPERATIONS
|
|
7,928,000
|
|
5,438,000
|
|
3,468,000
|
|
1,744,000
|
|
|
|
|
|
|
|
|
|
|
|
GAIN (LOSS) ON
DERIVATIVE CONTRACTS
|
|
|
|
|
|
|
|
|
|
Realized gains
(losses) from derivative contracts
|
|
(1,024,000
|
)
|
1,187,000
|
|
(1,876,000
|
)
|
201,000
|
|
Unrealized gains
(losses) from derivative contracts
|
|
(1,309,000
|
)
|
423,000
|
|
3,015,000
|
|
1,466,000
|
|
|
|
(2,333,000
|
)
|
1,610,000
|
|
1,139,000
|
|
1,667,000
|
|
INCOME BEFORE
INCOME TAXES
|
|
5,595,000
|
|
7,048,000
|
|
4,607,000
|
|
3,411,000
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES
|
|
(1,559,000
|
)
|
(2,010,000
|
)
|
(1,264,000
|
)
|
(964,000
|
)
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
4,036,000
|
|
$
|
5,038,000
|
|
$
|
3,343,000
|
|
$
|
2,447,000
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER
SHARE OF COMMON STOCK BASIC
|
|
$
|
.43
|
|
$
|
.54
|
|
$
|
.35
|
|
$
|
.26
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER
SHARE OF COMMON STOCK DILUTED
|
|
$
|
.42
|
|
$
|
.54
|
|
$
|
.34
|
|
$
|
.26
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
number of shares of Common Stock and dilutive securities:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
9,430,000
|
|
9,268,000
|
|
9,690,000
|
|
9,282,000
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
9,509,000
|
|
9,402,000
|
|
9,772,000
|
|
9,406,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
5
Table
of Contents
CREDO PETROLEUM
CORPORATION AND SUBSIDIARIES
Statement
of Stockholders Equity and Comprehensive Income
(Unaudited)
For the Nine Months Ended July 31,
2008
|
|
|
|
|
|
Capital In
|
|
|
|
|
|
Total
|
|
|
|
Common Stock
|
|
Excess Of
|
|
Treasury
|
|
Retained
|
|
Stockholders
|
|
|
|
Shares
|
|
Amount
|
|
Par Value
|
|
Stock
|
|
Earnings
|
|
Equity
|
|
Balance,
October 31, 2007 Restated
|
|
9,510,000
|
|
$
|
951,000
|
|
$
|
15,913,000
|
|
$
|
(506,000
|
)
|
$
|
24,782,000
|
|
$
|
41,140,000
|
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
4,036,000
|
|
4,036,000
|
|
Sale of Common
Stock
|
|
1,150,000
|
|
115,000
|
|
14,996,000
|
|
|
|
|
|
15,111,000
|
|
Exercise of
common stock options
|
|
|
|
|
|
221,000
|
|
145,000
|
|
|
|
366,000
|
|
Compensation
expense associated with unvested portion of previously granted stock options
|
|
|
|
|
|
44,000
|
|
|
|
|
|
44,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
July 31, 2008
|
|
10,660,000
|
|
$
|
1,066,000
|
|
$
|
31,174,000
|
|
$
|
(361,000
|
)
|
$
|
28,818,000
|
|
$
|
60,697,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
6
Table of
Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
Nine Months Ended
|
|
|
|
July 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
(Restated)
|
|
CASH FLOWS FROM
OPERATING ACTIVITIES:
|
|
|
|
|
|
Net income
|
|
$
|
4,036,000
|
|
$
|
5,038,000
|
|
Adjustments to
reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
2,594,000
|
|
2,782,000
|
|
Unrealized
(gains) loss on derivative contracts
|
|
1,309,000
|
|
(423,000
|
)
|
Deferred income
taxes
|
|
1,170,000
|
|
1,566,000
|
|
Compensation
expense related to stock options granted
|
|
44,000
|
|
138,000
|
|
Other
|
|
38,000
|
|
62,000
|
|
|
|
|
|
|
|
Changes in
operating assets and liabilities:
|
|
|
|
|
|
(Gain) loss on
short term investments
|
|
67,000
|
|
|
|
Proceeds from
short-term investments
|
|
2,721,000
|
|
1,492,000
|
|
Purchase of
short-term investments
|
|
|
|
(2,169,000
|
)
|
Accrued oil and
gas sales
|
|
(1,776,000
|
)
|
180,000
|
|
Trade
receivables
|
|
22,000
|
|
371,000
|
|
Other current
assets
|
|
(8,000
|
)
|
(158,000
|
)
|
Accounts payable
and accrued liabilities
|
|
(589,000
|
)
|
(831,000
|
)
|
Income taxes
payable
|
|
38,000
|
|
226,000
|
|
|
|
|
|
|
|
NET CASH
PROVIDED BY OPERATING ACTIVITIES
|
|
9,666,000
|
|
8,274,000
|
|
|
|
|
|
|
|
CASH FLOWS FROM
INVESTING ACTIVITIES:
|
|
|
|
|
|
Additions to oil
and gas properties
|
|
(8,414,000
|
)
|
(6,794,000
|
)
|
Proceeds from
sale of oil and gas properties
|
|
1,275,000
|
|
171,000
|
|
Changes in other
long-term assets
|
|
(1,494,000
|
)
|
202,000
|
|
|
|
|
|
|
|
NET CASH USED IN
INVESTING ACTIVITIES
|
|
(8,633,000
|
)
|
(6,421,000
|
)
|
|
|
|
|
|
|
CASH FLOWS FROM
FINANCING ACTIVITIES:
|
|
|
|
|
|
Sale of common
stock
|
|
15,111,000
|
|
|
|
Proceeds from
exercise of stock options (62,000 options in 2008 and 67,000 options in 2007)
|
|
366,000
|
|
272,000
|
|
|
|
|
|
|
|
NET CASH
PROVIDED BY FINANCING ACTIVITIES
|
|
15,477,000
|
|
272,000
|
|
|
|
|
|
|
|
INCREASE
(DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
16,510,000
|
|
2,125,000
|
|
|
|
|
|
|
|
CASH AND CASH
EQUIVALENTS:
|
|
|
|
|
|
Beginning of
period
|
|
7,285,000
|
|
4,577,000
|
|
|
|
|
|
|
|
End of period
|
|
$
|
23,795,000
|
|
$
|
6,702,000
|
|
Supplemental
cash flow information:
|
|
|
|
|
|
Cash paid during
the period for income taxes
|
|
$
|
352,000
|
|
$
|
207,000
|
|
Additions to
oil & gas properties in current liabilities
|
|
$
|
383,000
|
|
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
7
Table of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To
Consolidated Financial Statements (Unaudited)
July 31,
2008
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. These consolidated
financial statements should be read in conjunction with the companys Annual
Report on Form 10-K/A for the fiscal year ended October 31, 2007.
On
September 2, 2008, in connection with preparing its quarterly report for
third quarter 2008, management of CREDO Petroleum Corporation (the company)
and the Audit Committee of its Board of Directors determined that the
contemporaneous formal documentation it had historically prepared to support
its initial hedge designations in connection with the companys natural gas
hedging program does not meet the technical requirements to qualify for cash
flow hedge accounting treatment in accordance with SFAS 133. The primary reason for this determination was
that the formal hedge documentation lacks specificity of the hedged items and
therefore, the cash flow designations failed to meet hedge documentation
requirements for cash flow hedge accounting treatment. Consequently, the unrealized gain or loss
should have been recorded in the consolidated statements of operations as a
component of income before income taxes.
Under the cash flow accounting
treatment used by the company, the fair values of the hedge contracts
was recognized in the consolidated balance sheets with the resulting unrealized
gain or loss, net of income taxes, recorded initially in accumulated other
comprehensive income and later reclassified through earnings when the hedged
production affected earnings.
The
company will restate its consolidated financial statements for fiscal years
ended October 31, 2005, 2006, 2007 and the first and second quarters
of fiscal year ending October 31, 2008. There is no effect in any period on overall
cash flows, EBITDA, total assets, total liabilities or total stockholders
equity. The cumulative effect on all
periods of the restatement and the correction to the third quarter of 2008 was
to reduce net income by $182,000 and diluted income per share by $.03. For the three years ended October 31,
2007, the cumulative effect of the restatement was to increase net income by
$756,000 and to increase diluted income per share by $.08. For the nine months ended July 31, 2008,
the cumulative effect of the restatement and the correction to third quarter
2008 income was to reduce net income by $938,000 and to reduce diluted income
per share by $.11. The restatement did
not have any impact on any of the Companys financial covenants under its line
of credit. The primary financial
statement items impacted by this restatement are indicated below:
8
Table
of Contents
Consolidated Statements of Operations
|
|
Nine Months Ended July 31, 2007
|
|
Three Months Ended July 31, 2007
|
|
|
|
As Previously
|
|
|
|
As Previously
|
|
|
|
|
|
Reported
|
|
Restated
|
|
Reported
|
|
Restated
|
|
Oil &
Gas Sales
|
|
12,308,000
|
|
11,121,000
|
|
3,814,000
|
|
3,613,000
|
|
Total Revenues
|
|
12,993,000
|
|
11,806,000
|
|
4,047,000
|
|
3,846,000
|
|
|
|
|
|
|
|
|
|
|
|
Income from
Operations
|
|
6,625,000
|
|
5,438,000
|
|
1,945,000
|
|
1,744,000
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gains
(Losses) from derivative contracts
|
|
|
|
1,187,000
|
|
|
|
201,000
|
|
Unrealized Gains
(Losses) from derivative contracts
|
|
|
|
423,000
|
|
|
|
1,466,000
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Taxes
|
|
6,625,000
|
|
7,048,000
|
|
1,945,000
|
|
3,411,000
|
|
Income Taxes
|
|
(1,888,000
|
)
|
(2,010,000
|
)
|
(554,000
|
)
|
(964,000
|
)
|
Net Income
|
|
4,737,000
|
|
5,038,000
|
|
1,391,000
|
|
2,447,000
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per
share -
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.51
|
|
$
|
0.54
|
|
$
|
0.15
|
|
$
|
0.26
|
|
Diluted
|
|
$
|
0.50
|
|
$
|
0.54
|
|
$
|
0.15
|
|
$
|
0.26
|
|
Consolidated
Statements of Cash Flows
|
|
July 31, 2007
|
|
|
|
As Previously
|
|
|
|
|
|
Reported
|
|
Restated
|
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Net Income
|
|
4,737,000
|
|
5,038,000
|
|
Unrealized gains
on derivative contracts
|
|
|
|
(423,000
|
)
|
Changes in
operating assets and liabilities
|
|
|
|
|
|
Other current
assets
|
|
(281,000
|
)
|
(158,000
|
)
|
2.
SIGNIFICANT ACCOUNTING POLICIES
The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. The company bases its estimates on historical
experience and on various other assumptions it believes to be reasonable under
the circumstances. Although actual
results may differ from these estimates under different assumptions or
conditions, the company believes that its estimates are reasonable and that actual
results will not vary significantly from the estimated amounts.
The
company 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 now recorded in the Consolidated
Statement of Operations
3.
STOCK-BASED COMPENSATION
The
CREDO Petroleum Corporation 2007 Stock Option Plan (the 2007 Plan) is described
in the Notes to
9
Table of Contents
Consolidated
Financial Statements in the companys Annual Report on Form 10-K/A for the
year ended October 31, 2007. No
options have been granted under the 2007 Plan.
The CREDO Petroleum Corporation 1997 Stock Option Plan (the 1997 Plan)
expired on July 29, 2007. No
additional options can be granted under the 1997 Plan. However, all outstanding options granted
under the 1997 Plan will continue to be governed by the terms of that Plan.
For
the nine months ended July 31, 2008 and 2007, the company recognized stock
based compensation expense of $44,000 and $138,000 respectively. For the three months ended July 31, 2008
and 2007, the company recognized compensation expense of $14,000 and $28,000, respectively. The estimated unrecognized compensation cost
from unvested stock options as of July 31, 2008 was approximately
$79,000 which is expected to be recognized over an average of 2 years.
No
options were granted during the nine months ended July 31, 2008 and the
fair value of the 40,000 options granted during the nine months ended July 31,
2007 was estimated on the date of grant using a Black-Scholes option pricing
model. The weighted average assumptions
used in the option pricing model for the nine months ended July 31, 2007
were: volatility, 50.84%; expected option term, 2.5 years; risk-free interest
rate, 4.58%; and expected dividend yield, 0%.
Plan activity for the nine months ended July 31, 2008 is set forth
below:
|
|
Nine Months Ended July 31,2008
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
Aggregate
|
|
|
|
Number of
|
|
Exercise
|
|
Intrinsic
|
|
|
|
Options
|
|
Price
|
|
Value
|
|
Outstanding at
October 31, 2007
|
|
270,251
|
|
$
|
6.94
|
|
642,000
|
|
Granted
|
|
|
|
|
|
|
|
Exercised
|
|
(61,938
|
)
|
5.93
|
|
407,000
|
|
Cancelled or
forfeited
|
|
|
|
|
|
|
|
Outstanding at
July 31, 2008
|
|
208,313
|
|
$
|
7.25
|
|
490,000
|
|
|
|
|
|
|
|
|
|
Exercisable at
July 31, 2008
|
|
186,697
|
|
$
|
6.60
|
|
599,000
|
|
|
|
|
|
|
|
|
|
Weighted average
contractual life at July 31, 2008
|
|
|
|
5.54 years
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
market price at date of exercise for options exercised
|
|
|
|
$
|
12.50
|
|
|
|
The following table summarizes information about stock options
currently outstanding and exercisable at July 31, 2008:
|
|
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
|
|
2007
|
|
Life in Years
|
|
Price
|
|
2008
|
|
Exercise Price
|
|
$5.93
|
|
168,313
|
|
4.87
|
|
$
|
5.93
|
|
168,313
|
|
$
|
5.93
|
|
$12.78
|
|
40,000
|
|
8.35
|
|
$
|
12.78
|
|
18,334
|
|
$
|
12.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$5.93 -$12.78
|
|
208,313
|
|
5.54
|
|
$
|
7.25
|
|
186,647
|
|
$
|
6.60
|
|
10
Table of
Contents
4.
NATURAL GAS PRICE HEDGING
On
September 2, 2008, in connection with preparing its quarterly report for
third quarter 2008, management of CREDO Petroleum Corporation (the company)
and the Audit Committee of its Board of Directors determined that the
contemporaneous formal documentation it had historically prepared to support
its initial hedge designations in connection with the companys natural gas
hedging program does not meet the technical requirements to qualify for cash
flow hedge accounting treatment in accordance with SFAS 133. The primary reason for this determination was
that the formal hedge documentation lacks specificity of the hedged items and
therefore, the cash flow designations failed to meet hedge documentation
requirements for cash flow hedge accounting treatment. Consequently, the unrealized gain or loss
should have been recorded in the consolidated statements of operations as a
component of income before income taxes.
Under the cash flow accounting treatment
used by the company, the fair values of the hedge contracts was recognized in
the consolidated balance sheets with the resulting unrealized gain or loss, net
of income taxes, recorded initially in accumulated other comprehensive income
and later reclassified through earnings when the hedged production affected
earnings.
The
company periodically hedges the price of a portion of its estimated natural gas
production when the potential for significant downward price movement is
anticipated. Hedging transactions
typically take the form of forward short positions and collars on the NYMEX
futures market, and are closed by purchasing offsetting positions. Such hedges do not exceed estimated
production volumes, are expected to have reasonable correlation between price
movements in the futures market and the cash markets where the companys
production is located, and are authorized by the companys Board of
Directors. Hedges are expected to be
closed as related production occurs but may be closed earlier if the
anticipated downward price movement occurs or if the company believes that the
potential for such movement has abated.
The company recognizes all
derivatives 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 now recorded in the Consolidated Statement of Operations.
Open
hedge contracts are indexed to the NYMEX.
Periodically, the company enters into contracts indexed to Panhandle
Eastern Pipeline Company for Texas, Oklahoma mainline. For comparative purposes, hedges indexed to
Panhandle Eastern Pipeline Company are expressed on a NYMEX basis. For hedges indexed to Panhandle Eastern
Pipeline Company, the individual month price (basis) differentials between the
NYMEX and Panhandle Eastern Pipeline Company range from minus $1.45 in the
winter months to minus $0.90 in the spring months.
For the quarter ended July 31,
2008 the company has realized hedging losses of $1,876,000 and unrealized
hedging gains of $3,015,000. Realized hedging
gains were $201,000 and unrealized hedging gains were $1,466,000 for the same
period in 2007.
For the nine months ended July 31,
2008 the company has realized hedging
losses of $1,024,000 and unrealized hedging losses of $1,309,000. For the nine months ended July 31, 2007
the company had realized hedging gains of $1,187,000 and unrealized gains of
$423,000.
The company has a hedging line of credit with
its bank which is available, at the discretion of the company, to meet margin
calls. To date, the company has not used
this facility and maintains it only as a precaution related to possible margin
calls. The maximum credit line is
$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. It expires on November 15, 2010.
11
Table
of Contents
5.
EARNINGS PER SHARE
The companys calculation of earnings per share of common stock is as
follows:
|
|
Nine Months Ended July 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
Net
|
|
|
|
(Restated)
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
Income
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Basic earnings
per share
|
|
$
|
4,036,000
|
|
9,430,000
|
|
$
|
.43
|
|
$
|
5,038,000
|
|
9,268,000
|
|
$
|
.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of
dilutive shares of common stock from stock options
|
|
|
|
79,000
|
|
(.01
|
)
|
|
|
134,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings
per share
|
|
$
|
4,036,000
|
|
9,509,000
|
|
$
|
.42
|
|
$
|
5,038,000
|
|
9,402,000
|
|
$
|
.54
|
|
|
|
Three Months Ended July 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
Net
|
|
|
|
(Restated)
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
Income
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Basic earnings
per share
|
|
$
|
3,343,000
|
|
9,690,000
|
|
$
|
.35
|
|
$
|
2,447,000
|
|
9,282,000
|
|
$
|
.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of
dilutive shares of common stock from stock options
|
|
|
|
82,000
|
|
(.01
|
)
|
|
|
124,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings
per share
|
|
$
|
3,343,000
|
|
9,772,000
|
|
$
|
.34
|
|
$
|
2,447,000
|
|
9,406,000
|
|
$
|
.26
|
|
6.
INCOME TAXES
The
company uses the asset and liability method of accounting for deferred income
taxes. Deferred tax assets and
liabilities are determined based on the temporary differences between the
financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end
of each period are determined using the tax rate in effect at that time.
The total future deferred income tax liability is extremely complicated
for any energy company to estimate due in part to the long-lived nature of
depleting oil and gas reserves and variables such as product prices. Accordingly, the liability is subject to
continual recalculation, revision of the numerous estimates required, and may
change significantly in the event of such things as major acquisitions,
divestitures, product price changes, changes in reserve estimates, changes in
reserve lives, and changes in tax rates or tax laws.
On
November 1, 2007 the company adopted the provisions of FASB Interpretation
No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). In implementing FIN 48, we found no
significant uncertain tax positions. Our
policy is to recognize potential accrued interest and penalties related to
unrecognized tax benefits in income tax expense, which is consistent with the
recognition of these items in prior reporting periods. No interest and penalties related to
uncertain tax positions were accrued at July 31, 2008.
We
have not had any material changes to our unrecognized tax benefits since
adoption, nor do we anticipate significant changes to the total amount of
unrecognized tax benefits within the next twelve months.
12
Table of Contents
As
of July 31, 2008 we remain subject to examination of our Federal and state
tax returns, except Colorado, for the tax years 2004 through 2006, and for the
tax years 2003 through 2006 for our Colorado tax returns.
7.
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 no material outstanding commitments at July 31, 2008.
8.
STOCK SALE
During
the quarter ended July 31, 2008 the company entered into, and closed, a
Company Stock Purchase Agreement with RCH Energy Opportunity Fund II, LP
(RCH). Under the terms of the agreement
the company sold to RCH 1,150,000 shares of newly-issued common stock, par
value $0.10 at a price of $14.50 per share, in cash. Transaction fees paid from the proceeds of
sale were $1,564,000.
Also
under the terms of the agreement, RCH nominated, and the companys Board of
Directors elected, two new directors to serve on the companys Board of
Directors for so long as RCH beneficially owns at least 15% of the companys
outstanding stock and one director for so long as RCH beneficially owns at
least 10% of the companys outstanding stock.
The
Purchase Agreement contains a standstill provision that prohibits RCH from
acquiring any additional shares of the companys stock for a period of two
years without the consent of the company.
In
connection with the Company Stock Purchase Agreement with RCH the company
amended its Rights Agreement, dated as of April 11, 1989, as amended, in
order to exempt the Purchase Agreement from application of the Rights
Agreement.
9.
RECENT ACCOUNTING PRONOUNCEMENTS
In November 2007, the FASB issued SFAS No. 141 (revised
2007),
Business Combination
(FAS 141(R)) and SFAS 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 December 2007, the
FASB issued SFAS No. 157
, Fair Value Measurements
. This Statement does not require any new fair
value measurements, but rather, it provides enhanced guidance to other
pronouncements that require or permit assets or liabilities to be measured at
fair value. However, the application of
this Statement may change how fair value is determined. The Statement is effective for financial
statements issued for fiscal years beginning after November 15, 2007, and
interim periods within
13
Table of Contents
those fiscal years. As of December 1, 2007 the FASB has
proposed a one-year deferral for the implementation of the Statement for
nonfinancial assets and nonfinancial liabilities that are recognized or
disclosed at fair value in the financial statements on a nonrecurring
basis. Management is currently
evaluating the requirements of FAS 157 and has not yet determined the impact on
its financial statements.
In March 2008, the FASB
issued SFAS No. 161,
Disclosures about
Derivative Instruments and Hedging Activities, an Amendment to FASB Statement No. 133
. This statement expands the disclosures, and
form of disclosures, that must be presented regarding derivatives and hedging
activities. The Statement is effective
for financial statements issued for fiscal years beginning after November 15,
2008, and interim periods within those fiscal years. Management is currently evaluating the
requirements of FAS 161 and has not yet determined the impact on its financial
statements.
ITEM 2.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
EXPLANATORY NOTE
On
September 2, 2008, in connection with preparing its quarterly report for
third quarter 2008, management of CREDO Petroleum Corporation (the company)
and the Audit Committee of its Board of Directors determined that the
contemporaneous formal documentation it had historically prepared to support
its initial hedge designations in connection with the companys natural gas
hedging program does not meet the technical requirements to qualify for cash
flow hedge accounting treatment in accordance with SFAS 133. The primary reason for this determination was
that the formal hedge documentation lacks specificity of the hedged items and
therefore, the cash flow designations failed to meet hedge documentation
requirements for cash flow hedge accounting treatment. Consequently, the unrealized gain or loss
should have been recorded in the consolidated statements of operations as a
component of income before income taxes.
Under the cash flow accounting
treatment used by the company, the fair values of the hedge contracts
was recognized in the consolidated balance sheets with the resulting unrealized
gain or loss, net of income taxes, recorded initially in accumulated other
comprehensive income and later reclassified through earnings when the hedged
production affected earnings.
The
company will restate its consolidated financial statements for fiscal years
ended October 31, 2005, 2006, 2007 and the first and second quarters
of fiscal year ending October 31, 2008. There is no effect in any period on overall
cash flows, EBITDA, total assets, total liabilities or total stockholders
equity. The restatement did not have any
impact on any of the Companys financial covenants under its line of
credit. Details of the effect of the
restatement are indicated in Note 1 to the Consolidated Financial Statements.
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;
14
Table of Contents
·
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.
LIQUIDITY
AND CAPITAL RESOURCES
At
July 31, 2008, working capital increased $13,920,000, or 103% to
$27,430,000 compared to $13,510,000 at July 31, 2007. For the nine months ended July 31, 2008,
net cash provided by operating activities increased $1,392,000 to $9,666,000
compared to net cash provided by operating activities of $8,274,000 for the
same period in 2007. Net income
decreased $1,002,000 primarily due to the recognition of unrealized hedging
losses.
For
the nine months ended July 31, 2008 and 2007, net cash used in investing
activities was $8,633,000 and $6,421,000, respectively. Investing activities primarily included oil
and gas exploration and development expenditures, including Calliope, totaling
$8,414,000 and $6,794,000 respectively.
During
the quarter ended July 31, 2008, the company sold 1,150,000 shares of
newly issued $.10 par value common stock.
The sales price was $14.50 per share, resulting in gross proceeds of
$16,675,000. Transaction fees of
$1,564,000 were paid from the proceeds.
The company also purchased joint interest holders rights to future
Calliope installation revenues for $975,000 with a portion of the proceeds.
The average return on the companys investments for the nine months
ended July 31, 2008 and 2007 was (3.0%) and 9.2%,
respectively. At July 31, 2008,
approximately 92% of the investments are in managed partnerships (generally
known as hedge funds) that use various strategies to minimize their correlation
to stock market movements. The remaining
investments were directly invested in mutual funds. Most of the investments are highly liquid and
the company believes they represent a responsible approach to cash
management. In the companys opinion,
the greatest investment risk is the potential for negative market impact from
unexpected, major adverse news.
Existing working capital and anticipated cash
flow are expected to be sufficient to fund operations and capital commitments
for at least the next 12 months. At July 31, 2008,
the company had no lines of credit or other bank financing arrangements except
for the hedging line of credit discussed in Note 4. Because earnings are anticipated to be
reinvested in operations, cash dividends are not expected to be paid. The company has no defined benefit plans and
no obligations for post retirement employee benefits.
The companys adjusted earnings before unrealized gains/losses on
derivative contracts, interest, taxes, depreciation, depletion and
amortization, (EBITDA) increased to $9,505,000 for the nine months ended July 31,
2008 from $9,427,000 for the nine months ended July 31, 2007. 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
15
Table of
Contents
measure, it may not necessarily be comparable to similarly titled
measures employed by other companies. A
reconciliation between EBITDA and net income is provided in the table below:
|
|
Nine Months Ended July 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
(Restated)
|
|
RECONCILIATION
OF EBITDA:
|
|
|
|
|
|
Net Income
|
|
$
|
4,036,000
|
|
$
|
5,038,000
|
|
Add Back:
|
|
|
|
|
|
Unrealized Gain
(Loss) on Derivatives
|
|
1,309,000
|
|
(423,000
|
)
|
Interest Expense
|
|
7,000
|
|
20,000
|
|
Income Tax
Expense
|
|
1,559,000
|
|
2,010,000
|
|
Depreciation,
Depletion and Amortization Expense
|
|
2,594,000
|
|
2,782,000
|
|
EBITDA
|
|
$
|
9,505,000
|
|
$
|
9,427,000
|
|
OFF-BALANCE SHEET FINANCING
The
company has no significant off-balance sheet financing arrangements at July 31,
2008.
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 4 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,
|
|
|
|
2008
|
|
2007
|
|
% Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
1,221,000
|
|
$
|
7.87
|
(1)
|
1,517,000
|
|
$
|
6.72
|
(2)
|
-19
|
%
|
+17
|
%
|
Oil (bbls)
|
|
42.500
|
|
$
|
101.66
|
|
37,200
|
|
$
|
56.52
|
|
+14
|
%
|
+80
|
%
|
|
|
Three Months Ended July 31,
|
|
|
|
2008
|
|
2007
|
|
% Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
396,000
|
|
$
|
6.96
|
(3)
|
494,000
|
|
$
|
6.21
|
(4)
|
-20
|
%
|
+12
|
%
|
Oil (bbls)
|
|
13,400
|
|
$
|
122.91
|
|
12,100
|
|
$
|
62.36
|
|
+11
|
%
|
+97
|
%
|
(1) Includes $0.32 per Mcf realized hedging loss.
(2) Includes $0.77 per Mcf realized hedging gain.
(3) Includes $3.13 per Mcf realized hedging loss.
(4) Includes $0.41 per Mcf realized hedging gain.
16
Table of Contents
OPERATIONS
During the first three
quarters of fiscal 2008, the companys operations continued to focus on its two
core projects natural gas drilling and application of its patented
Calliope Gas Recovery System.
The company believes that, in combination, its drilling and Calliope
projects provide an excellent (and possibly unique) balance for achieving its
goal of adding long-lived natural gas reserves and production at reasonable
costs and risks. However, it should be
expected that successful results will occur unevenly for both the drilling and
Calliope projects. Drilling results are
dependent on both the timing of drilling and on the drilling success rate. Calliope results are primarily dependent on
the timing, volume and quality of Calliope installations available to the
company.
The company will continue to actively pursue adding reserves through
its two core projects in fiscal 2008, 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 availability, cost and quality of oil field services such as drilling
rigs, production equipment and related services, and access to wells for
application of the 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 cost of field services, particularly the cost of drilling wells,
has increased dramatically during the past several years, driven by higher
energy prices. Concurrently, the quality
of field services has diminished markedly due to manpower shortages. The combination of much higher field service
costs and degradation in the quality of the services is having a materially
negative impact on drilling economics.
Accordingly, the company continues to high-grade its drilling prospects,
and in some cases postpone less robust projects pending improvement in the
field services sector. In the short
term, this will reduce the number of drilling prospects which may, in turn,
impede the growth of the companys production and reserves
The company is currently experiencing delays in securing drilling rigs
and delivery of production equipment, primarily compressors and coil
tubing. These delays are extending the
time it takes the company to conduct its field operations. As a result, the company could be at risk for
price increases related to these types of services and equipment.
All of the 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.
Drilling Activities.
Oklahoma and Texas Panhandle
The company owns a significant inventory of
acreage (approximately 70,000 gross acres) located along the northern
portion of the Anadarko Basin where it conducts an active drilling
program. Wells generally target the
Morrow, Oswego and Chester formations between 7,000 and 11,000 feet. The company expects to drill a substantial
number of additional wells on this acreage.
In Hemphill County, Texas, the second well on the companys 3,780 gross
acre Humphreys Prospect encountered sands in the Tonkawa and Cleveland
formations that appear to be productive on electric logs. The vertical well has been completed in the
Tonkawa sand and tested at good rates for both oil and gas. The well is currently waiting on pipeline
connection. The company owns a 25%
working interest.
17
Table of Contents
The company
recently purchased interests in over 3,800 gross acres in Hemphill County
and has taken over as operator of 11 wells.
The new acreage complements the companys Humphreys Prospect and brings
its total acreage in the area to approximately 8,300 gross acres.
In Oklahoma, three new
wells are awaiting pipeline connection and six wells are scheduled for
drilling. CREDO
owns approximately
70,000 gross acres located primarily along the northern portion of the
Anadarko Basin where it conducts an active drilling program. Wells generally target the Morrow, Oswego and
Chester formations between 7,000 and 11,000 feet.
In Carter County, CREDO
is waiting on rig arrival to drill a twin well to its Schaff #1 which has
produced 235,000 barrels of oil.
The Schaff will become part of the Twin Forks Deese sand waterflood, and
the new well will develop three oil sands that the Schaff well logs indicate
are productive and which produce in the immediate area. CREDO owns a 41% working interest and is the
operator.
In
Major County, drilling is expected to commence shortly on the companys 1,280
gross acre Pool-Proffitt property. The
9,600-foot Lemmons #1-7 and Ball #1-18 wells will test a thick package of
stacked carbonate zones. CREDO owns an
approximate 70% working interest in the Lemmons and 50% of the Ball. Ultimately, the company expects to drill 10
to 12 wells on the prospect.
In
Harper County, drilling will commence shortly on two wells located on the
company 3,840 gross acre Buffalo Creek Prospect where 11 wells have previously
been completed for production. Both of
the new wells will test the Chester formation at approximately 6,900 feet. CREDO owns working interests of 30% and 37%
in the two wells.
In Southern Oklahoma, the
company is participating in three waterflood projects as part of its overall
strategy to improve the oil ratio in its reserve base. In Carter County, CREDO owns 17% of the
Southeast Hewitt waterflood unit which has already produced 685,000 barrels of
oil and is projected to ultimately produce about 1,200,000 barrels. The company also owns about 22% in Phase 1,
and 12.3% in Phase 2, of a Twin Forks Deese sand waterflood unit that is being
formed and is expected to produce about 1,000,000 barrels of oil. In Love County, CREDO owns 13% in Phase 1,
and 9.5% in Phase 2, of the Eastman Hills waterflood unit that is expected
to produce about 500,000 barrels of oil.
South Texas
In South Texas, the initial test well on the Gemini Prospect resulted
in a dry hole. The 17,000-foot well
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 of cash for the multiple prospect package and
retained an 11.25% carried interest in the test well.
The prospect package
consists of two additional Deep Wilcox prospects located to the north of Gemini
Prospect. These two prospects are
structurally different and unique compared to the Gemini Prospect. Those prospects are being further evaluated,
and if drilled, CREDO will have the same 11.25% carried interest in the next
well as it did in the Gemini Prospect test well.
Elsewhere
in South Texas, the company has recently purchased a 15.5% working
interest in the Escobas Field. A major
workover is underway on an existing well, and a new 15,500-foot Wilcox well has
been drilled in which the company has a small carried interest. That well is currently producing 2.7 MMcfd
(million cubic of gas per day) on a 12/64ths choke.
North-Central Kansas
The companys Kansas acreage is located in prolific oil producing areas where 3-D seismic has proven
effective in identifying undrilled structures.
Drilling targets the Lansing-Kansas City and Arbuckle formations at
about 4,000 feet, making the cost of drilling very inexpensive in relation to
potential reserve value.
To
date, 26 wells have been drilled on company acreage, of which 46% have
been successful. Five of the
18
Table
of Contents
12 successful wells had
initial production rates of about 100 barrels of oil per day. Average proved reserves are estimated to be
50,000 to 55,000 barrels of oil per well.
The companys first discovery in the play has already produced about
56,000 barrels of oil in 21 months and is still producing 75 barrels of
oil per day. That well is expected to
produce around 130,000 barrels of oil.
Since
the companys last report, six wells have been drilled of which four are
producers, yielding a 67% success rate.
Six new wells are scheduled for the next few months, half of which will be on prospects where the
company owns an 80% working interest.
Credo has acquired approximately
100,000 gross acres (35,000 net acres) located
in prolific oil producing areas of the play
and is continuing to expand its acreage position. The company currently owns interests ranging
from 12.5% to 80% in 16 separate projects.
Three dimensional (3-D) seismic has proven effective in identifying
undrilled structures. Drilling targets
the Lansing-Kansas City and Arbuckle formations at about 4,000 feet, making the
cost of drilling moderate in relation to potential reserve value. Recent drilling successes have occurred
primarily on prospects where the company owns smaller working interests.
Drilling
success in this play is progressing well.
In addition to providing good diversification to our other drilling
activities, this project is 100% oil oriented and is expected to improve the
balance between oil and natural gas in the companys reserve base.
Calliope Gas Recovery Technology.
The
company owns the exclusive right to a patented technology known as the Calliope
Gas Recovery System. There are currently
three U.S. patents and two Canadian patents related to the technology. One additional patent that mirrors the
U.S. patents has been applied for in Canada.
Calliope systems are installed on wells located in Oklahoma, Texas and
Louisiana.
Calliope can achieve substantially lower
flowing bottom-hole pressure than other production methods because it does not
rely on reservoir pressure to lift liquids.
In many reservoirs, lower bottom-hole pressure can translate into
recovery of substantial additional natural gas reserves.
Calliope has proven to be reliable and flexible over a wide range of
applications on wells the company owns and operates. It has also proven to be consistently
successful. Accordingly, the company is
implementing strategies designed to expand the population of wells on which it
can install Calliope.
Calliopes Track Record
Calliope wells are located in Oklahoma, Texas, and Louisiana and
produce from both sandstone and carbonate reservoirs, including the Chester,
Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Redfork and Springer
formations. The Calliope wells range in
depth from 6,400 to 18,400 feet. These
wells represent rigorous applications for Calliope because at the time
Calliope was installed, 14 of the wells were dead (an average of two to
three years), nine were uneconomic and two were marginal. In addition, prior to the time Calliope was
installed, many of the reservoirs were damaged by the parting shots of
previous operators. Twenty-three of the
wells were acquired from other operators after the operators had given-up
on these wells. The previous operators
were mostly medium to large independent oil and gas companies.
Initial Calliope production rates range up to 650 Mcfd and average
per well Calliope reserves for non-experimental wells are estimated to be 1.0
Bcf. One of the companys early Calliope
installations, the J.C. Carroll well, has now produced over a billion cubic
feet of gas using Calliope.
The 25 Calliope installed applications are grouped into two categories
experimental wells and non-experimental wells, also referred to as go-forward
applications. Eleven of the
25 wells are experimental applications and 14 are go-forward
applications. Experimental wells
generally represent the
19
Table of
Contents
first experimental application of a Calliope configuration in a
wellbore. For example, the first
installation of Calliope inside a particular tubing size is classified as an
experimental application.
Calliope has achieved compelling results on these less than ideal wells
as is shown in the table below. For
example, the entire group of 14 non-experimental wells were producing a total
of only 88 Mcfd when Calliope was installed.
Without Calliope, the wells represented a substantial plugging
liability. However, with Calliope, those
same 14 wells have now produced an incremental 3.4 Bcfe to date, and they
are still producing about 2.0 MMcfed.
With Calliope, the 14 wells were projected to have estimated ultimate
incremental Calliope reserves totaling 13.6 Bcfe.
|
|
|
|
Average
|
|
Total
|
|
Total
|
|
|
|
|
|
Calliope
|
|
Calliope
|
|
Projected
|
|
|
|
|
|
Reserves
|
|
Production
|
|
Calliope
|
|
|
|
No. of
|
|
Per Well
|
|
to Date
|
|
Reserves
|
|
Group
|
|
Wells
|
|
(Bcfe)
|
|
(Bcfe)
|
|
(Bcfe)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Experimental
Wells
|
|
14
|
|
1.0
|
|
3.4
|
|
13.6
|
|
|
|
|
|
|
|
|
|
|
|
Experimental
Wells
|
|
11
|
|
0.2
|
|
0.6
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
All Wells
|
|
25
|
|
0.6
|
|
4.0
|
|
15.0
|
|
Calliope has proven to be a low risk and low cost liquid lift
technology. Calliope has never failed to
lift the liquids out of a wellbore. The
average cost of a Calliope system is $400,000 for a 12,000-foot
application. Based on average per well
Calliope reserves of 1.0 Bcfe for go-forward applications, cost of Calliope in
terms of units of natural gas reserves added is low compared to industry
averages. Based on current natural gas
prices, Calliope can economically be installed on wells which will yield
significantly less than 1.0 Bcf of Calliope reserves. This will enable the company to significantly
expand the range of Calliope applications to include many low permeability
reservoirs, possibly including those in shale and other resource plays.
Realizing Calliopes value continues to be one of the companys top
priorities. The company has been focused
on three fronts to increase the number of Calliope installations: expanding the geographic region for
purchasing Calliope candidate wells from third parties, joint ventures with
larger companies, and drilling wells into low-pressure gas reservoirs for the
purpose of using Calliope to recover stranded natural gas reserves.
Purchasing Calliope Candidate Wells
Calliope operations were expanded into Texas
and Louisiana in fiscal 2006. The
company considers Texas and Louisiana to be very fertile areas for Calliope and
has retained personnel and opened a Houston office to focus exclusively on
purchasing wells for Calliope and on Calliope joint ventures.
In general, higher natural gas prices have made it increasingly
difficult for the company to purchase wells for its Calliope system. In addition, higher gas prices have provided
the incentive for other companies to perform high risk procedures (parting
shots) in an attempt to revive wells prior to abandoning or selling the
wells. These parting shots often result
in severe reservoir damage that renders wells unsuitable for Calliope. Accordingly, viable Calliope candidate wells
available to be purchased by the company have been very restricted.
Joint Ventures With Third Parties
In an effort to increase the number of
Calliope installations, the company has been discussing joint ventures
with larger companies. Presentations
have been made to a select group of companies, including majors and large
independents. All of the companies have
expressed an interest in Calliope. Two
joint venture agreements were completed during 2007.
20
Table of
Contents
Joint venture discussions are in progress with a number of the
companies, including evaluation of candidate wells. The joint venture negotiation process has
taken longer than expected because there are many decision points within large
companies that cause delays.
Nevertheless, the company continues to dedicate substantial resources to
joint venture projects because it believes joint venturing holds substantial
promise for Calliope.
Calliope
Drilling Project
The company believes that there is a huge amount of
gas stranded in abandoned and low pressure reservoirs that can be recovered
using Calliope. It believes drilling new
wells for Calliope into such reservoirs will provide a repeatable opportunity
to lease large areas for systematic re-development. In addition, new wells allow optimum casing
and tubular sizes to be installed which will substantially improve reserves and
production compared to installing Calliope on existing wells where undersized
tubulars often restrict Calliopes optimum performance.
In June 2007, the company entered into a joint venture to purchase
an 11,000-foot well located in East Texas.
The previous operator drilled the well and encountered low reservoir
pressure. After unsuccessful attempts to
make the well produce, the operator sold the well to the company joint venture
for $65,000 (salvage value). Calliope
was installed and immediately brought the well to life, producing at the rate
of 250 Mcf per day. The well
provided a successful test of the Calliope drilling concept and demonstrated
that Calliope will successfully solve liquid loading problems that are
difficult, if not impossible, to address with other liquid lift technologies.
Results of Operations
Nine Months Ended July 31,
2008 Compared to Nine Months Ended July 31, 2007
For the nine months ended July 31,
2008, total revenues increased 22% to $14,446,000 compared to
$11,806,000 last year. As the oil
and gas price/volume table on page 16 shows, total gas price realizations,
which reflect realized hedging transactions, increased 17% to $7.87 per Mcf and
oil price realizations increased 80% to $101.66 per barrel. The net effect of these price changes was to
increase oil and gas sales by $3,509,000 ($5,069,000 before realized hedge
losses). For the nine months ended July 31,
2008, the companys gas equivalent production decreased 15%. The effect of the volume change was to
decrease oil and gas sales by $1,881,000.
The production decrease is primarily due to the continued steep decline
of the Glacier property wells.
Investment income and other decreased $560,000 primarily due to
performance of the companys investments.
For the nine months ended July 31, 2008,
total costs and expenses rose 2% to $6,518,000 compared to $6,368,000 for the
comparable period in 2007. Oil and gas
production expenses increased 13% due to the addition of new wells and
escalating field service costs.
Depreciation, depletion and amortization (DD&A) decreased
primarily due to decreased production partially offset by an increase in the
amortizable cost base. General and
administrative expenses increased 1% primarily due to accounting and
professional fees. Interest expense
relates to the exclusive license agreement note payment. The effective tax rate was 28.0% for 2008 and
28.5% for 2007.
21
Table of
Contents
Three Months Ended July 31,
2008 Compared to Three Months Ended July 31, 2007
For the three months ended July 31,
2008, total revenues increased 48% to $5,695,000 compared to $3,846,000 during
the same period last year. As the oil
and gas price/volume table on page 16 shows, total gas price realizations,
which reflect realized hedging transactions, increased 12% to $6.96 per Mcf and
oil price realizations increased 97% to $122.91 per barrel. The net effect of these price changes was to
increase oil and gas sales by $1,400,000 ($2,840,000 before realized hedge
losses). For the three months ended July 31,
2008, the companys gas equivalent production fell 16% resulting in an oil and
gas sales decrease of $807,000.
Investment and other income decreased $184,000 primarily due to
performance of the companys investments, compared to last year.
For the three months ended July 31,
2008, total costs and expenses increased 6% to $2,227,000 compared to
$2,102,000 for the comparable period in 2007.
Oil and gas production expenses increased 25% primarily due to the
addition of new wells and escalating field service costs. DD&A declined primarily due to lower
production partially offset by an increase in the amortizable cost base. General and administrative expenses decreased
primarily due to an increase in geology and engineering costs capitalized to
drilling projects. Interest expense
relates to the exclusive license agreement note payment. The effective tax rate was $27.4% for 2008
and 28.3% for 2007.
SIGNIFICANT ACCOUNTING POLICIES
The company believes the following accounting policies and estimates
are critical in the preparation of its consolidated financial statements: the
carrying value of its oil and natural gas properties, the accounting for oil
and gas reserves, and the estimate of its asset retirement obligations.
OIL AND GAS PROPERTIES.
The
company uses the full cost method of accounting for costs related to its oil
and natural gas properties. Capitalized
costs included in the full cost pool are depleted on an aggregate basis using
the units-of-production method.
Depreciation, depletion and amortization is a significant component of
oil and natural gas properties. A change
in proved reserves without a corresponding change in capitalized costs will
cause the depletion rate to increase or decrease.
Both the volume of proved reserves and any estimated future
expenditures used for the depletion calculation are based on estimates such as
those described under Oil and Gas Reserves below.
The capitalized costs in the full cost pool are subject to a quarterly
ceiling test that limits such pooled costs to the aggregate of the present
value of future net revenues attributable to proved oil and natural gas
reserves discounted at 10 percent plus the lower of cost or market value of
unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling,
the company will record a write-down to the extent of such excess as a non-cash
charge to earnings. Any such write-down
will reduce earnings in the period of occurrence and result in lower depreciation
and depletion in future periods. A
write-down may not be reversed in future periods, even though higher oil and
natural gas prices may subsequently increase the ceiling.
The company has made only one ceiling write-down in its 28-year
history. That write down was made in
1986 after oil prices fell 51% and natural gas prices fell 45% between
fiscal year end 1985 and 1986.
Changes in oil and natural gas prices have historically had the most
significant impact on the 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
22
Table of
Contents
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.
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.
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 now 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 expected
production through the use of derivatives, typically collars and forward short
positions in the NYMEX or other regional indexes futures market. See Note 4 for more information on the
companys hedging activities.
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Table of Contents
ITEM 4.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and
Procedures
Our management evaluated, with the participation and under
the supervision of our Chief Executive Officer and Chief Financial Officer, the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this Quarterly Report on Form 10-Q. Based on this
evaluation, our Chief Executive Officer and our Chief Financial Officer
concluded that our disclosure controls and procedures are effective to ensure
that information we are required to disclose in reports that we file or submit
under the Securities Exchange Act of 1934 is accumulated and communicated to our
management, including our Chief Executive Officer and our Chief Financial
Officer, as appropriate to allow timely decisions regarding required disclosure
and that such information is recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission rules and
forms.
Changes in Internal Control Over
Financial Reporting
There has been no change in our internal control over
financial reporting that occurred during our last fiscal quarter that has
materially affected or is reasonably likely to materially affect our internal
control over financial reporting, except as follows: In Item 9A, Managements
Report on Internal Control over Financial Reporting included in our Annual
Report on Form 10-K/A for the year ended October 31, 2007 we reported
a material weakness in the companys internal control. During the first and second quarters of
fiscal 2008: 1) management designed and
implemented enhanced and accelerated training for its senior financial staff
and invested time and resources to enhance their knowledge and skills; and 2)
the company hired an expert consultant to assist with review and financial
statement disclosure. Management has not
completed all of the testing of internal controls in these areas for fiscal
2008.
PART II
- OTHER INFORMATION
ITEM 1.
LEGAL
PROCEEDINGS
Reference
is made to Notes to Consolidated Financial Statements (Unaudited) Note 7,
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/A for the fiscal year ended October 31,
2007.
ITEM 2.
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On
July 3, 2008 the company completed the sale of 1,150,000 shares of its
$0.10 par value common stock. The sales
price was $14.50 per share resulting in total proceeds of $16,675,000.
Proceeds
were used to pay transaction fees of $1,564,000 and purchase joint venture
holders rights to future Calliope installation revenues of $975,000.
ITEM 3.
DEFAULTS
UPON SENIOR SECURITIES
None.
24
Table of
Contents
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)
25
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.
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CREDO Petroleum Corporation
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(Registrant)
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By:
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/s/ James T. Huffman
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James T. Huffman
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President and Chief Executive Officer
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(Principal Executive Officer)
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By:
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/s/ Alford B. Neely
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Alford B. Neely
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Vice President & Chief Financial Officer
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(Principal Financial and Accounting Officer)
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Date: September 15, 2008
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26
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