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 April 30,
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 the definitions of large accelerated filer,
accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act.
|
Large accelerated filer
o
|
|
|
Accelerated filer
x
|
|
|
|
|
|
|
Non-accelerated filer
o
|
(Do not check if a smaller reporting company)
|
|
Smaller reporting company
o
|
Indicate by check mark whether the registrant is a
shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
o
No
x
Indicate the number of shares outstanding of each of the issuers
classes of common stock, net of treasury
stock, as of the latest
practicable date.
Date
|
|
Class
|
|
Outstanding
|
June 9,
2008
|
|
Common stock,
$.10 par value
|
|
9,325,000
|
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly
Report on Form 10-Q For the Period Ended April 30, 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.
2
PART I - FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Balance Sheets
|
|
April 30,
|
|
October 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
ASSETS
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
6,805,000
|
|
$
|
7,285,000
|
|
Short-term
investments
|
|
6,337,000
|
|
6,383,000
|
|
Receivables:
|
|
|
|
|
|
Accrued oil and
gas sales
|
|
2,663,000
|
|
1,647,000
|
|
Trade
|
|
772,000
|
|
602,000
|
|
Derivative
Assets
|
|
|
|
443,000
|
|
Other current
assets
|
|
1,434,000
|
|
55,000
|
|
Total current
assets
|
|
18,011,000
|
|
16,415,000
|
|
Long-term
assets:
|
|
|
|
|
|
Oil and gas
properties, at cost, using full cost method:
|
|
|
|
|
|
Unevaluated oil
and gas properties
|
|
9,079,000
|
|
7,791,000
|
|
Evaluated oil
and gas properties
|
|
55,063,000
|
|
51,691,000
|
|
Less:
accumulated depreciation, depletion and amortization of oil and gas
properties
|
|
(23,805,000
|
)
|
(22,108,000
|
)
|
Net oil and gas
properties, at cost, using full cost method
|
|
40,337,000
|
|
37,374,000
|
|
|
|
|
|
|
|
Exclusive
license agreement, net of amortization of $536,000 in 2008 and $501,000 in
2007
|
|
163,000
|
|
198,000
|
|
Compressor and
tubular inventory to be used in development
|
|
1,408,000
|
|
1,090,000
|
|
Other, net
|
|
402,000
|
|
272,000
|
|
Total assets
|
|
$
|
60,321,000
|
|
$
|
55,349,000
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,255,000
|
|
$
|
1,639,000
|
|
Revenue
distribution payable
|
|
1,254,000
|
|
979,000
|
|
Derivative
liabilities
|
|
3,433,000
|
|
|
|
Other accrued
liabilities
|
|
1,060,000
|
|
852,000
|
|
Income taxes
payable
|
|
440,000
|
|
434,000
|
|
Total current
liabilities
|
|
7,442,000
|
|
3,904,000
|
|
Long Term
Liabilities:
|
|
|
|
|
|
Deferred income
taxes, net
|
|
9,210,000
|
|
9,204,000
|
|
Derivative
liabilities due in more than 1 year
|
|
448,000
|
|
|
|
Exclusive
license obligation, less current obligations of $77,000 in 2008 and 2007
|
|
85,000
|
|
85,000
|
|
Asset retirement
obligation
|
|
1,098,000
|
|
1,016,000
|
|
Total
liabilities
|
|
18,283,000
|
|
14,209,000
|
|
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, 9,510,000 shares issued in 2008
and in 2007
|
|
951,000
|
|
951,000
|
|
Capital in
excess of par value
|
|
16,047,000
|
|
15,913,000
|
|
Treasury stock
at cost, 186,000 shares in 2008 and 215,000 in 2007
|
|
(437,000
|
)
|
(506,000
|
)
|
Accumulated
other comprehensive income (loss)
|
|
(2,775,000
|
)
|
319,000
|
|
Retained
earnings
|
|
28,252,000
|
|
24,463,000
|
|
Total
stockholders equity
|
|
42,038,000
|
|
41,140,000
|
|
Total
liabilities and stockholders equity
|
|
$
|
60,321,000
|
|
$
|
55,349,000
|
|
The accompanying notes
are an integral part of these consolidated financial statements.
3
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Operations
(Unaudited)
|
|
Six Months Ended
|
|
Three Months Ended
|
|
|
|
April 30,
|
|
April 30,
|
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
Oil and gas
sales
|
|
$
|
9,527,000
|
|
$
|
8,493,000
|
|
$
|
4,947,000
|
|
$
|
4,685,000
|
|
Investment
income and other
|
|
76,000
|
|
453,000
|
|
81,000
|
|
206,000
|
|
|
|
9,603,000
|
|
8,946,000
|
|
5,028,000
|
|
4,891,000
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND
EXPENSES:
|
|
|
|
|
|
|
|
|
|
Oil and gas
production
|
|
1,838,000
|
|
1,709,000
|
|
986,000
|
|
796,000
|
|
Depreciation,
depletion and amortization
|
|
1,751,000
|
|
1,900,000
|
|
898,000
|
|
942,000
|
|
General and
administrative
|
|
697,000
|
|
644,000
|
|
365,000
|
|
366,000
|
|
Interest
|
|
5,000
|
|
13,000
|
|
4,000
|
|
7,000
|
|
|
|
4,291,000
|
|
4,266,000
|
|
2,253,000
|
|
2,111,000
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE
INCOME TAXES
|
|
5,312,000
|
|
4,680,000
|
|
2,775,000
|
|
2,780,000
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES
|
|
(1,525,000
|
)
|
(1,334,000
|
)
|
(789,000
|
)
|
(798,000
|
)
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
3,787,000
|
|
$
|
3,346,000
|
|
$
|
1,986,000
|
|
$
|
1,982,000
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER
SHARE OF COMMON STOCK BASIC
|
|
$
|
.41
|
|
$
|
.36
|
|
$
|
.22
|
|
$
|
.21
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER
SHARE OF COMMON STOCK DILUTED
|
|
$
|
.40
|
|
$
|
.36
|
|
$
|
.21
|
|
$
|
.21
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
number of shares of Common Stock and dilutive securities:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
9,299,000
|
|
9,261,000
|
|
9,302,000
|
|
9,261,000
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
9,363,000
|
|
9,395,000
|
|
9,368,000
|
|
9,395,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
4
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
Six Months Ended
|
|
|
|
April 30,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
CASH FLOWS FROM
OPERATING ACTIVITIES:
|
|
|
|
|
|
Net income
|
|
$
|
3,787,000
|
|
$
|
3,346,000
|
|
Adjustments to
reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
1,751,000
|
|
1,900,000
|
|
Deferred income
taxes
|
|
1,525,000
|
|
834,000
|
|
Loss on short
term investments
|
|
46,000
|
|
|
|
Compensation
expense related to stock options granted
|
|
30,000
|
|
110,000
|
|
Other
|
|
84,000
|
|
30,000
|
|
Changes in
operating assets and liabilities:
|
|
|
|
|
|
Proceeds from
short-term investments
|
|
|
|
1,492,000
|
|
Purchase of
short-term investments
|
|
|
|
(1,885,000
|
)
|
Accrued oil and
gas sales
|
|
(1,016,000
|
)
|
(185,000
|
)
|
Trade
receivables
|
|
(170,000
|
)
|
192,000
|
|
Other current
assets
|
|
(387,000
|
)
|
(43,000
|
)
|
Accounts payable
and accrued liabilities
|
|
(881,000
|
)
|
(845,000
|
)
|
Income taxes
payable
|
|
|
|
113,000
|
|
|
|
|
|
|
|
NET CASH
PROVIDED BY OPERATING ACTIVITIES
|
|
4,769,000
|
|
5,059,000
|
|
|
|
|
|
|
|
CASH FLOWS FROM
INVESTING ACTIVITIES:
|
|
|
|
|
|
Additions to oil
and gas properties
|
|
(4,955,000
|
)
|
(4,404,000
|
)
|
Proceeds from
sale of oil and gas properties
|
|
|
|
171,000
|
|
Changes in other
long-term assets
|
|
(467,000
|
)
|
(134,000
|
)
|
|
|
|
|
|
|
NET CASH USED IN
INVESTING ACTIVITIES
|
|
(5,422,000
|
)
|
(4,367,000
|
)
|
|
|
|
|
|
|
CASH FLOWS FROM
FINANCING ACTIVITIES:
|
|
|
|
|
|
Proceeds from
exercise of stock options
|
|
173,000
|
|
5,000
|
|
|
|
|
|
|
|
NET CASH PROVIDED
BY FINANCING ACTIVITIES
|
|
173,000
|
|
5,000
|
|
|
|
|
|
|
|
INCREASE
(DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
(480,000
|
)
|
697,000
|
|
|
|
|
|
|
|
CASH AND CASH
EQUIVALENTS:
|
|
|
|
|
|
Beginning of
period
|
|
7,285,000
|
|
4,577,000
|
|
|
|
|
|
|
|
End of period
|
|
$
|
6,805,000
|
|
$
|
5,274,000
|
|
|
|
|
|
|
|
Supplemental
cash flow information:
|
|
|
|
|
|
Cash paid during
the period for income taxes
|
|
$
|
282,000
|
|
$
|
90,000
|
|
|
|
|
|
|
|
Additions to oil
and gas properties in current liabilities
|
|
$
|
1,369,000
|
|
$
|
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
5
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To
Consolidated Financial Statements (Unaudited)
April 30, 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 for the fiscal year ended October 31,
2007.
Certain 2007 amounts have been reclassified to conform
to the current year presentation. Such
reclassifications had no effect on net income or shareholders equity.
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, costs
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 in the
ordinary course of business.
3.
STOCK-BASED
COMPENSATION
The
CREDO Petroleum Corporation 2007 Stock Option Plan (the 2007 Plan) is described
in the Notes to Consolidated Financial Statements in the companys Annual
Report on Form 10-K 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 six months ended April 30, 2008 and 2007, the company recognized stock
based compensation expense of $30,000 and $110,000 respectively. For the three months ended April 30, 2008
and 2007, the company recognized compensation expense of $15,000 and $53,000,
respectively. The estimated unrecognized
compensation cost from unvested stock options as of April 30, 2008
was approximately $93,000 which is expected to be recognized over an average of
2 years.
No
options were granted during the six months ended April 30, 2008 and the
fair value of the 40,000 options granted during the six months ended April 30,
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 six months ended April 30, 2007
were: volatility, 50.84%; expected option term, 2.5 years; risk-free interest
rate, 4.58%; and expected dividend yield, 0%.
6
Plan
activity for the six months ended April 30, 2008 is set forth below:
|
|
Six Months Ended April 30, 2008
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
Aggregate
|
|
|
|
Number of
|
|
Exercise
|
|
Intrinsic
|
|
|
|
Options
|
|
Price
|
|
Value
|
|
Outstanding at
October 31, 2007
|
|
270,251
|
|
$
|
6.94
|
|
754,000
|
|
Granted
|
|
|
|
|
|
|
|
Exercised
|
|
29,250
|
|
5.93
|
|
117,000
|
|
Cancelled or
forfeited
|
|
|
|
|
|
|
|
Outstanding at
April 30, 2008
|
|
241,001
|
|
$
|
7.07
|
|
793,000
|
|
|
|
|
|
|
|
|
|
Exercisable at
April 30, 2008
|
|
219,335
|
|
$
|
6.50
|
|
847,000
|
|
|
|
|
|
|
|
|
|
Weighted average
contractual life at April 30, 2008
|
|
|
|
5.82
|
years
|
4.
NATURAL GAS PRICE HEDGING
The
company periodically hedges the price of a portion of its estimated natural gas
production when the potential for significant downward price movement is
anticipated. Hedging transactions
typically take the form of forward short positions and collars on the NYMEX
futures market, and are closed by purchasing offsetting positions. Such hedges, which are accounted for as cash
flow hedges, do not exceed estimated production volumes, are expected to have
reasonable correlation between price movements in the futures market and the
cash markets where the 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 (consisting solely of cash flow hedges) on
its balance sheet at fair value at the end of each period. Changes in the fair value of a cash flow
hedge are recorded in Stockholders Equity as Accumulated Other Comprehensive
Income on the Consolidated Balance Sheets and then are transferred into the
Consolidated Statement of Operations as the underlying hedged item affects
earnings. Amounts reclassified into
earnings related to natural gas hedges are included in gas sales.
Hedging gains and losses are recognized as adjustments to gas sales as
the hedged product is produced. The
company had hedging gains of $852,000 ($605,000 net of income tax) and $986,000
($705,000 net of income tax) in the six months ended April 30, 2008 and
2007, respectively. For the three months
ended April 30, 2008, the company had hedging gains of $5,000 ($4,000
after tax) and $590,000 ($422,000 after tax) for the same period in 2007. Any hedge ineffectiveness, which was not
material for any period, is immediately recognized in gas sales.
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.
Unrecognized gains and losses on hedge contracts
at April 30, 2008 totaled a loss of $3,881,000 ($2,775,000 after income
tax). These amounts have been included
in Accumulated Other Comprehensive Income ($2,775,000), Derivative
Liabilities ($3,433,000) and Derivative Liabilities Due in More than
7
1 Year ($ 448,000) and deferred income taxes of
$1,106,000. These contracts covered
1,660 MMBtus at average monthly NYMEX basis prices ranging from $7.83 to
$10.05.
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.
5.
COMPREHENSIVE INCOME
Comprehensive income includes all changes in equity during a period
except those resulting from investments by owners and distributions to
owners. The components of comprehensive
income for the three and six months ended April 30, 2008 and 2007 are as
follows:
|
|
Six Months Ended
|
|
Three Months Ended
|
|
|
|
April 30,
|
|
April 30,
|
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
3,787,000
|
|
$
|
3,346,000
|
|
$
|
1,986,000
|
|
$
|
1,982,000
|
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
|
|
Change in fair
value of derivatives
|
|
(4,324,000
|
)
|
(1,043,000
|
)
|
(4,008,000
|
)
|
(672,000
|
)
|
Income tax
expense
|
|
1,230,000
|
|
288,000
|
|
1,142,000
|
|
188,000
|
|
Total
comprehensive income (loss)
|
|
$
|
693,000
|
|
$
|
2,591,000
|
|
$
|
(880,000
|
)
|
$
|
1,498,000
|
|
6.
EARNINGS PER SHARE
The companys calculation of
earnings per share of common stock is as follows:
|
|
Six Months Ended April 30,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
Income
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Basic earnings
per share
|
|
$
|
3,787,000
|
|
9,299,000
|
|
$
|
.41
|
|
$
|
3,346,000
|
|
9,261,000
|
|
$
|
.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of
dilutive shares of common stock from stock options
|
|
|
|
64,000
|
|
(.01
|
)
|
|
|
134,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings
per share
|
|
$
|
3,787,000
|
|
9,363,000
|
|
$
|
.40
|
|
$
|
3,346,000
|
|
9,395,000
|
|
$
|
.36
|
|
8
|
|
Three Months Ended April 30,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
Income
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Basic earnings
per share
|
|
$
|
1,986,000
|
|
9,302,000
|
|
$
|
.22
|
|
$
|
1,982,000
|
|
9,261,000
|
|
$
|
.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of
dilutive shares of common stock from stock options
|
|
|
|
66,000
|
|
(.01
|
)
|
|
|
134,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings
per share
|
|
$
|
1,986,000
|
|
9,368,000
|
|
$
|
.21
|
|
$
|
1,982,000
|
|
9,395,000
|
|
$
|
.21
|
|
7.
INCOME
TAXES
The company uses the asset and liability method of accounting for
deferred income taxes. Deferred tax
assets and liabilities are determined based on the temporary differences
between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end
of each period are determined using the tax rate in effect at that time.
The total future
deferred income tax liability is extremely complicated for any energy company
to estimate due in part to the long-lived nature of depleting oil and gas
reserves and variables such as product prices.
Accordingly, the liability is subject to continual recalculation,
revision of the numerous estimates required, and may change significantly in
the event of such things as major acquisitions, divestitures, product price
changes, changes in reserve estimates, changes in reserve lives, and changes in
tax rates or tax laws.
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 April 30, 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.
As
of April 30, 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.
8.
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 April 30, 2008.
9
9.
SUBSEQUENT
EVENT
On
June 3, 2008, the company, and certain of its directors, entered into
agreements with RCH Energy Opportunity Fund II, LP (RCH) to sell 1,837,000
shares of CREDOs common stock to RCH at a price of $14.50 per share. CREDO will sell 1,150,000 newly issued common
shares, or approximately 11% of the companys total outstanding shares on a
pro-forma basis. Directors Huffman,
Stevens and Skewes will sell 425,000, 192,000 and 70,000 shares, respectively.
CREDOs
Board will be expanded from six to seven members and RCH will nominate two
directors, one to fill a current vacancy on the Board and another to fill the
newly created Board seat.
All
of the shares acquired by RCH will initially be restricted and not freely tradable
in the open market, however, RCH will have certain future registration
rights. The company agreement contains a
standstill provision providing that RCH will not purchase additional CREDO
stock for a period of two years from the date of the agreement without the
consent of the Board of Directors.
Proceeds
from the RCH investment totaling $16,675,000 will be used, among other things,
to fund increased exploration and development of properties where the company
currently has un-booked reserves. In addition, the company will consolidate
ownership in its Calliope Gas Recovery System by purchasing the Calliope
patents together with the 13.75% ownership in Calliope and related intellectual
property that the company does not already own.
10.
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 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.
10
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.
LIQUIDITY AND CAPITAL RESOURCES
At
April 30, 2008, working capital was $10,569,000 compared to
$11,175,000 at April 30, 2007.
The decrease is due to the unrecognized hedge loss of $3,433,000
included in current liabilities at April 30, 2008. For the six months ended April 30, 2008,
net cash provided by operating activities was $4,769,000 compared to net cash
provided by operating activities of $5,059,000 for the same period in
2007. Net income increased $441,000
primarily due to an increase in revenues of $657,000, partially offset by an
increase in production expenses, general and administrative expenses and income
taxes.
For
the six months ended April 30, 2008 and 2007, net cash used in investing
activities was $5,422,000 and $4,367,000, respectively. Investing activities primarily included oil
and gas exploration and development expenditures, including Calliope, totaling
$4,955,000 and $4,404,000 respectively.
The average return on the companys investments for the six months
ended April 30, 2008 and 2007 was 1.3% and 7.3%,
respectively. At April 30, 2008,
approximately 45% of the investments were directly invested in mutual funds and
were managed by professional money managers.
Remaining investments are in managed partnerships (generally known as
hedge funds) that use various strategies to minimize their correlation to stock
market movements. Most of the
investments are highly liquid and the company
11
believes they represent a responsible approach to cash management. In the 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 April 30, 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 earnings before interest, taxes, depreciation, depletion
and amortization, (EBITDA) increased 7% to $7,068,000 for the six months
ended April 30, 2008 from $6,593,000 for the six months ended April 30, 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 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:
|
|
Six Months Ended April 30,
|
|
|
|
2008
|
|
2007
|
|
RECONCILIATION
OF EBITDA:
|
|
|
|
|
|
Net Income
|
|
$
|
3,787,000
|
|
$
|
3,346,000
|
|
Add Back:
|
|
|
|
|
|
Interest Expense
|
|
5,000
|
|
13,000
|
|
Income Tax
Expense
|
|
1,525,000
|
|
1,334,000
|
|
Depreciation,
Depletion and Amortization Expense
|
|
1,751,000
|
|
1,900,000
|
|
EBITDA
|
|
$
|
7,068,000
|
|
$
|
6,593,000
|
|
OFF-BALANCE SHEET FINANCING
The
company has no off-balance sheet financing arrangements at April 30, 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 and swaps on the NYMEX
futures market or by indexing to regional index prices associated with
pipelines in proximity to the companys production. Refer to Note 4 to the Consolidated Financial
Statements for a complete discussion on the companys hedging activities.
12
Gas and oil sales volume and price realization comparisons for the
indicated periods are set forth below.
Price realizations include the sales price and the effect of hedging
transactions.
|
|
Six Months Ended April 30,
|
|
|
|
2008
|
|
2007
|
|
% Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
825,000
|
|
$
|
8.31
|
(1)
|
1,024,000
|
|
$
|
6.99
|
(2)
|
-19
|
%
|
+19
|
%
|
Oil (bbls)
|
|
29,100
|
|
$
|
91.87
|
|
25,100
|
|
$
|
53.73
|
|
+16
|
%
|
+71
|
%
|
|
|
Three Months Ended April 30,
|
|
|
|
2008
|
|
2007
|
|
% Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
433,000
|
|
$
|
8.37
|
(3)
|
495,000
|
|
$
|
7.99
|
(4)
|
-13
|
%
|
+5
|
%
|
Oil (bbls)
|
|
13,400
|
|
$
|
98.25
|
|
13,200
|
|
$
|
55.24
|
|
+1
|
%
|
+78
|
%
|
(1) Includes $1.03 Mcf hedging gain.
(2) Includes $0.96 Mcf hedging gain.
(3) Includes $0.01 Mcf hedging gain
(4) Includes $1.19 Mcf hedging gain.
OPERATIONS
During the first half 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
13
company to conduct its field operations. As a result, the company could be at risk for
price increases related to these types of services and equipment.
All of the 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, the company recently purchased interests in over 6,000 gross acres
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 9,000 gross acres.
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 is testing at good
rates of both oil and gas. The well is
currently waiting on a pipeline connection.
The company owns a 25% working interest.
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 650,000 barrels of
oil and is projected to ultimately produce about 1,200,000 barrels. The company also owns about 23% in Phase 1,
and 12.5% in Phase 2, of a Martin 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.
Also in Carter
County, CREDO is preparing to drill a twin well to its Schaff #1 which has
produced 235,000 barrels of oil.
The Schaff will become part of the Martin 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 50% working interest and is the
operator.
During the second fiscal quarter of 2008, CREDO has placed five wells
on production and has drilled two new gas wells in Oklahoma that are awaiting
completion for production. The recent
drilling includes three new wells on the companys 5,800 gross acre Arroyo
Prospect where the first well is now producing 750 Mcfd. The company owns varying working interest in
the prospect ranging up to 40%.
Elsewhere in Oklahoma, the company is preparing to drill on its 1,280
gross acre Pool-Proffitt property where it expects to ultimately drill
10 to 12 wells, to develop a thick package of stacked carbonate
zones. CREDO owns working interest in
the prospect ranging from 50% to 70%.
South Texas
In South Texas, drilling is underway on the Kenedy Foundation #1 well
on the companys 17,500 foot Gemini Prospect. The prospect is located in Jim Hogg County
and targets the deep Wilcox
sands which produce prolifically in the area.
The 3-D seismic interpretation indicates that the prospect contains 1,200 acres of total
closure, making its net reserve potential very substantial in relation to CREDOs
existing proved reserves.
14
At a depth of 17,000 feet, Gemini is a very
high cost, rank wildcat drilling prospect.
Therefore, the company elected to sell a portion of its interest for
cash consideration and a carried interest on the two initial wells. The consideration is approximately $1,300,000
cash and an 11.25% carried interest before cost recovery on the first
two wells (6.75% after cost recovery) including all costs of drilling,
completion and connecting the wells for pipeline sales.
If
drilling is successful, the company
expects that its retained interest in the prospects will have a very
significant impact on its production and reserve growth.
Elsewhere in South Texas, the first well has been drilled on the 2,500
gross acre Briggs Ranch Prospect located in Victoria County. The 8,600-foot Briggs Ranch #1 encountered 11
feet of Frio sands and is currently producing about 520 Mcf per day (thousand
cubic feet of gas per day). The company
owns a 9% working interest. Also in
South Texas where the company recently purchased a 15.5% working interest
in the Escobas Field, a recompletion is underway on an existing well and
drilling is underway on a 15,500 foot Wilcox test where the company has a
carried interest through the production facilities.
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, 20 wells have been drilled on company acreage with a 40%
success rate. Four of the eight
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 45,000 barrels of oil in 18 months and is still
producing 80 barrels of oil per day.
That well is expected to produce around 130,000 barrels of oil.
CREDO currently owns interests in nine separate projects covering
approximately 75,000 gross acres, and plans to expand its acreage position in
the play to at least 100,000 gross acres.
The companys interest in the projects varies from 12.5% to
75%. The recent drilling successes have
occurred primarily on prospects where the company owns a 12.5% interest.
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
15
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 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.
16
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.
In January 2008, the company entered into a Calliope joint venture
agreement with RCH Opportunity Fund II, LP. Under the joint venture, RCH was granted
certain rights to license Calliope systems where CREDO would have the
opportunity to participate in the ownership of all wells on which Calliope was
installed. Subsequent to the Calliope
joint venture agreement, RCH requested and was provided, subject to a
confidentiality agreement, more information about Calliope and the company,
ultimately culminating in RCH purchasing a significant 17.5% stake in the
company and becoming part of CREDOs policy and direction-setting team as
described in Note 9 to the Financial Statements on page 10.
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
Six
Months Ended April 30, 2008 Compared to Six Months Ended April 30,
2007
For the six months ended April 30, 2008, total revenues increased
7% to $9,603,000 compared to $8,946,000 last year. As the oil and gas price/volume table on page 14
shows, total gas price realizations, which reflect hedging transactions,
increased 19% to $8.31 per Mcf and oil price realizations increased 71% to
$91.87 per barrel. The net effect of
these price changes was to increase oil and gas sales by $2,122,000. For the six months ended April 30, 2008,
the companys gas equivalent production decreased 15% resulting in an oil
and gas sales decrease of $1,088,000.
The production decrease is primarily due to the continued steep decline
of the Glacier Scarlet State and Glacier Garnet State wells. Investment income
17
and other fell $377,000 due to a generally poorer investment
environment and more bearish investment market conditions than last year.
For the six months ended April 30, 2008,
total costs and expenses rose less than 1% to $4,291,000 compared to $4,266,000
for the comparable period in 2007. Oil
and gas production expense rose 8% primarily due to escalating field
service costs. Depreciation, depletion
and amortization fell 8% due to decreased production, partially offset by an
increase in the amortizable full cost pool.
General and administrative expenses increased 8% primarily due to
increased accounting and professional fees.
Interest expense relates to the exclusive license agreement note
payment. The effective tax rate was
28.75% and 28.5% for the 2008 and 2007 periods, respectively.
Three Months Ended April 30, 2008 Compared to Three Months Ended April 30,
2007
For the three months ended April 30, 2008, total revenues
increased 3% to $5,028,000 compared to $4,891,000 during the same period last
year. As the oil and gas price/volume
table on page 13 shows, total gas price realizations, which reflect
hedging transactions, increased 5% to $8.37 per Mcf and oil price realizations
increased 78% to $98.25 per barrel. The
net effect of these price changes was to increase oil and gas sales by
$761,000. For the three months ended April 30,
2008, the companys gas equivalent production fell 11% resulting in an oil and
gas sales decrease of $500,000.
Investment and other income fell $125,000 due to a generally poorer
investment environment and more bearish investment market conditions than last
year.
For the three months ended April 30,
2008, total costs and expenses rose 7% to $2,253,000 compared to $2,111,000 for
the comparable period in 2007. Oil and
gas production expenses increased 24% due primarily to the addition of new
wells and escalating field service costs.
Depreciation, depletion and amortization (DD&A) fell 5% due to
decreased production partially offset by an increase in the amortizable full
cost pool. General and administrative
expenses remained virtually unchanged.
Interest expense relates to the exclusive license agreement note
payment. The effective tax rate was
28.75% and 28.7% for the 2008 and 2007 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, 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.
18
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
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.
19
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.
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
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.
We believe that, as of the date of this filing, we have remediated the
material weakness previously reported in our internal control. 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 8,
Commitments and Contingencies, in Part I, Item I of this Form 10-Q
and incorporated by reference in this Part II, Item I.
ITEM 1A.
RISK
FACTORS
There have been no
material changes from the risk factors previously disclosed in the companys
Annual Report on Form 10-K for the fiscal year ended October 31,
2007.
ITEM 2.
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None during the period
ended April 30, 2008, however, see the subsequent event described in
Item 5 below.
20
ITEM 3.
DEFAULTS
UPON SENIOR SECURITIES
None.
ITEM 4.
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
The companys annual meeting of stockholders was held on March 20,
2008, for the purpose of electing one Class III director and ratifying the
appointment of Hein & Associates LLP as the companys independent
registered public accounting firm.
Proxies for the meeting were solicited pursuant to Section 14(a) of
the Securities Exchange Act of 1934 and there was no solicitation in opposition
to managements solicitation. Managements
nominee for Class III director, as listed in the proxy statement, was
elected with the number of votes set forth below.
Name
|
|
For
|
|
Withheld
|
|
Richard B.
Stevens
|
|
8,378,056
|
|
37,402
|
|
Continuing Directors:
After the companys annual meeting on March 20, 2008, the
following directors continue to serve their three year term as Class I
directors, which terms will expire at the companys 2010 annual meeting:
Oakley Hall
William F. Skewes
After the companys annual meeting on March 20, 2008, the
following directors continue to serve their three year terms as Class II
directors, which terms will expire at the companys 2009 annual meeting:
James T. Huffman
Clarence H. Brown
The results of the other matters voted upon at the company annual
meeting are as follows:
The appointment of Hein & Associates LLP as the companys
independent registered public accounting firm:
For
|
|
Against
|
|
Abstain
|
|
7,578,828
|
|
209,025
|
|
627,605
|
|
The matters mentioned above are described in detail in the companys
definitive proxy statement dated February 5, 2008 for the annual meeting
of shareholders held on March 20, 2008.
ITEM 5.
OTHER
INFORMATION
Subsequent Event:
On June 3, 2008, the company, and certain of its directors,
entered into agreements with RCH Energy Opportunity Fund II, LP (RCH) to sell
1,837,000 shares of CREDOs common stock to RCH at a price of $14.50 per
share. CREDO will sell 1,150,000 newly
issued common shares, or approximately 11% of the companys total outstanding
shares on a pro-forma basis. Directors
Huffman, Stevens and Skewes will sell 425,000, 192,000 and 70,000 shares,
respectively.
21
CREDOs Board will be expanded from six to
seven members and RCH will nominate two directors, one to fill a current
vacancy on the Board and another to fill the newly created Board seat.
All of the shares acquired by RCH will
initially be restricted and not freely tradable in the open market, however RCH
will have certain future registration rights.
The company agreement contains a standstill provision providing that RCH
will not purchase additional CREDO stock for a period of two years from the
date of the agreement without the consent of the Board of Directors.
Proceeds from the RCH investment totaling
$16,675,000 will be used, among other things, to fund increased exploration and
development of properties where the company currently has un-booked reserves. In
addition, the company will consolidate ownership in its Calliope Gas Recovery
System by purchasing the Calliope patents together with the 13.75% ownership in
Calliope and related intellectual property that the company does not already
own.
All documents related to this transaction
were filed with the SEC on Form 8-K dated June 4, 2008.
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)
|
22
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
|
|
|
|
President and
Chief Executive Officer
|
|
|
|
(Principal
Executive Officer)
|
|
|
|
|
|
|
By:
|
/s/ David E.
Dennis
|
|
|
|
David E. Dennis
|
|
|
|
Chief Financial
Officer
|
|
|
|
(Principal Financial
and Accounting Officer)
|
Date: June 9,
2008
23
iShares Trust (NASDAQ:CRED)
Historical Stock Chart
From Jun 2024 to Jul 2024
iShares Trust (NASDAQ:CRED)
Historical Stock Chart
From Jul 2023 to Jul 2024