Table
of Contents
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form 10-Q/A
(Mark One)
x
|
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
For the quarterly period ended January 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
|
|
9,295,000
|
|
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/A
For the Period Ended January 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
|
|
January 31,
|
|
October 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Restated)
|
|
(Restated)
|
|
ASSETS
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
5,708,000
|
|
$
|
7,285,000
|
|
Short-term
investments
|
|
6,305,000
|
|
6,383,000
|
|
Receivables:
|
|
|
|
|
|
Accrued oil and
gas sales
|
|
2,219,000
|
|
1,647,000
|
|
Trade
|
|
694,000
|
|
602,000
|
|
Derivative
Assets
|
|
127,000
|
|
443,000
|
|
Other current
assets
|
|
145,000
|
|
55,000
|
|
Total current
assets
|
|
15,198,000
|
|
16,415,000
|
|
|
|
|
|
|
|
Long-term
assets:
|
|
|
|
|
|
Oil and gas
properties, at cost, using full cost method: Unevaluated oil and gas
properties
|
|
9,593,000
|
|
7,791,000
|
|
Evaluated oil
and gas properties
|
|
52,732,000
|
|
51,691,000
|
|
Less:
accumulated depreciation, depletion and amortization of oil and gas
properties
|
|
(22,934,000
|
)
|
(22,108,000
|
)
|
Net oil and gas
properties, at cost, using full cost method
|
|
39,391,000
|
|
37,374,000
|
|
|
|
|
|
|
|
Exclusive
license agreement, net of amortization of $519,000 in 2008 and $466,000 in
2007
|
|
181,000
|
|
198,000
|
|
|
|
|
|
|
|
Compressor and
tubular inventory to be used in development
|
|
1,066,000
|
|
1,090,000
|
|
|
|
|
|
|
|
Other, net
|
|
290,000
|
|
272,000
|
|
Total assets
|
|
$
|
56,126,000
|
|
$
|
55,349,000
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
870,000
|
|
$
|
1,639,000
|
|
Revenue
distribution payable
|
|
1,005,000
|
|
979,000
|
|
Other accrued
liabilities
|
|
194,000
|
|
852,000
|
|
Income taxes
payable
|
|
486,000
|
|
434,000
|
|
Total current
liabilities
|
|
2,555,000
|
|
3,904,000
|
|
|
|
|
|
|
|
Long Term
Liabilities:
|
|
|
|
|
|
Deferred income
taxes, net
|
|
9,718,000
|
|
9,204,000
|
|
Exclusive
license obligation, less current obligations of $77,000 in 2008 and $70,000
in 2007
|
|
85,000
|
|
85,000
|
|
Asset retirement
obligation
|
|
1,040,000
|
|
1,016,000
|
|
Total
liabilities
|
|
13,398,000
|
|
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
|
|
15,928,000
|
|
15,913,000
|
|
Treasury stock
at cost, 215,000 shares in 2008 and 2007
|
|
(506,000
|
)
|
(506,000
|
)
|
Retained
earnings
|
|
26,355,000
|
|
24,782,000
|
|
Total
stockholders equity
|
|
42,728,000
|
|
41,140,000
|
|
|
|
|
|
|
|
Total
liabilities and stockholders equity
|
|
$
|
56,126,000
|
|
$
|
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)
|
|
Three Months Ended
|
|
|
|
January 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Restated)
|
|
(Restated)
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
Oil and gas
sales
|
|
$
|
3,733,000
|
|
$
|
3,412,000
|
|
Investment
income (loss) and other
|
|
(5,000
|
)
|
247,000
|
|
|
|
3,728,000
|
|
3,659,000
|
|
|
|
|
|
|
|
COSTS AND
EXPENSES:
|
|
|
|
|
|
Oil and gas
production
|
|
852,000
|
|
913,000
|
|
Depreciation,
depletion and amortization
|
|
853,000
|
|
958,000
|
|
General and
administrative
|
|
332,000
|
|
278,000
|
|
Interest
|
|
1,000
|
|
6,000
|
|
|
|
2,038,000
|
|
2,155,000
|
|
|
|
|
|
|
|
INCOME FROM
OPERATIONS
|
|
1,690,000
|
|
1,504,000
|
|
|
|
|
|
|
|
GAIN (LOSS) ON
DERIVATIVE CONTRACTS:
|
|
|
|
|
|
Realized gains
(losses) from derivative contracts
|
|
847,000
|
|
396,000
|
|
Unrealized
(gains) losses from derivative contracts
|
|
(316,000
|
)
|
(371,000
|
)
|
|
|
531,000
|
|
25,000
|
|
|
|
|
|
|
|
INCOME BEFORE
INCOME TAXES
|
|
2,221,000
|
|
1,529,000
|
|
|
|
|
|
|
|
INCOME TAXES
|
|
(648,000
|
)
|
(436,000
|
)
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
1,573,000
|
|
$
|
1,093,000
|
|
|
|
|
|
|
|
EARNINGS PER
SHARE OF COMMON STOCK BASIC
|
|
$
|
.17
|
|
$
|
.12
|
|
|
|
|
|
|
|
EARNINGS PER
SHARE OF COMMON STOCK DILUTED
|
|
$
|
.17
|
|
$
|
.12
|
|
|
|
|
|
|
|
Weighted average number
of shares of Common Stock and dilutive securities:
|
|
|
|
|
|
Basic
|
|
9,295,000
|
|
9,261,000
|
|
|
|
|
|
|
|
Diluted
|
|
9,356,000
|
|
9,387,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
5
Table of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
Three Months Ended
|
|
|
|
January 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Restated)
|
|
(Restated)
|
|
|
|
|
|
|
|
CASH FLOWS FROM
OPERATING ACTIVITIES:
|
|
|
|
|
|
Net income
|
|
$
|
1,573,000
|
|
$
|
1,093,000
|
|
Adjustments to
reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
853,000
|
|
958,000
|
|
Unrealized loss
on derivative contracts
|
|
316,000
|
|
371,000
|
|
Deferred income
taxes
|
|
514,000
|
|
328,000
|
|
(Gain) loss on
short term investments
|
|
78,000
|
|
(231,000
|
)
|
Compensation
expense related to stock options granted
|
|
15,000
|
|
57,000
|
|
Other
|
|
24,000
|
|
3,000
|
|
Changes in
operating assets and liabilities:
|
|
|
|
|
|
Proceeds from
short-term investments
|
|
|
|
719,000
|
|
Purchase of
short-term investments
|
|
|
|
(1,000,000
|
)
|
Accrued oil and
gas sales
|
|
(572,000
|
)
|
307,000
|
|
Trade
receivables
|
|
(92,000
|
)
|
(367,000
|
)
|
Other current
assets
|
|
(90,000
|
)
|
(169,000
|
)
|
Accounts payable
and accrued liabilities
|
|
(1,045,000
|
)
|
(629,000
|
)
|
Income taxes
payable
|
|
52,000
|
|
99,000
|
|
|
|
|
|
|
|
NET CASH
PROVIDED BY OPERATING ACTIVITIES
|
|
1,626,000
|
|
1,539,000
|
|
|
|
|
|
|
|
CASH FLOWS FROM
INVESTING ACTIVITIES:
|
|
|
|
|
|
Additions to oil
and gas properties
|
|
(3,200,000
|
)
|
(3,005,000
|
)
|
Changes in other
long-term assets
|
|
(3,000
|
)
|
(56,000
|
)
|
|
|
|
|
|
|
NET CASH USED IN
INVESTING ACTIVITIES
|
|
(3,203,000
|
)
|
(3,061,000
|
)
|
|
|
|
|
|
|
CASH FLOWS FROM
FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH
PROVIDED BY FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
DECREASE IN CASH
AND CASH EQUIVALENTS
|
|
(1,577,000
|
)
|
(1,522,000
|
)
|
|
|
|
|
|
|
CASH AND CASH
EQUIVALENTS:
|
|
|
|
|
|
Beginning of
period
|
|
7,285,000
|
|
4,577,000
|
|
|
|
|
|
|
|
End of period
|
|
$
|
5,708,000
|
|
$
|
3,055,000
|
|
|
|
|
|
|
|
Supplemental
cash flow information:
|
|
|
|
|
|
Cash paid during
the period for income taxes
|
|
$
|
100,000
|
|
$
|
|
|
|
|
|
|
|
|
Additions to oil
and gas properties in current liabilities
|
|
$
|
356,000
|
|
$
|
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
6
Table of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To Consolidated Financial Statements
(Unaudited)
January 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/A 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.
Certain
2007 amounts have been reclassified to conform to the current year
presentation. Such reclassification had
no effect on net income or shareholder equity.
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. The primary financial statement
items impacted by this restatement are indicated below:
7
Table
of Contents
Consolidated Statements of Income
|
|
January 31, 2008
|
|
January 31, 2007
|
|
|
|
As Previously
|
|
|
|
As Previously
|
|
|
|
Three Months Ended
|
|
Reported
|
|
Restated
|
|
Reported
|
|
Restated
|
|
|
|
|
|
|
|
|
|
|
|
Oil &
Gas Sales
|
|
4,580,000
|
|
3,733,000
|
|
3,808,000
|
|
3,412,000
|
|
Total Revenues
|
|
4,575,000
|
|
3,728,000
|
|
4,055,000
|
|
3,659,000
|
|
|
|
|
|
|
|
|
|
|
|
Income from
Operations
|
|
2,537,000
|
|
1,690,000
|
|
1,900,000
|
|
1,504,000
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gains
(Losses) from derivative contracts
|
|
|
|
847,000
|
|
|
|
396,000
|
|
Unrealized Gains
(Losses) from derivative contracts
|
|
|
|
(316,000
|
)
|
|
|
(371,000
|
)
|
|
|
|
|
|
|
|
|
|
|
Income Before
Taxes
|
|
2,537,000
|
|
2,221,000
|
|
1,900,000
|
|
1,529,000
|
|
Income Taxes
|
|
(736,000
|
)
|
(648,000
|
)
|
(536,000
|
)
|
(436,000
|
)
|
Net Income
|
|
1,801,000
|
|
1,573,000
|
|
1,364,000
|
|
1,093,000
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per
share -
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.19
|
|
$
|
0.17
|
|
$
|
0.15
|
|
$
|
0.12
|
|
Diluted
|
|
$
|
0.19
|
|
$
|
0.17
|
|
$
|
0.15
|
|
$
|
0.12
|
|
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 31, 2008
|
|
October 31, 2007
|
|
|
|
As Previously
|
|
|
|
As Previously
|
|
|
|
|
|
Reported
|
|
Restated
|
|
Reported
|
|
Restated
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
other comprehensive income (loss)
|
|
91,000
|
|
|
|
319,000
|
|
|
|
Retained
earnings
|
|
26,264,000
|
|
26,355,000
|
|
24,463,000
|
|
24,782,000
|
|
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 31, 2008
|
|
January 31, 2007
|
|
|
|
As Previously
|
|
|
|
As Previously
|
|
|
|
Three Months Ended
|
|
Reported
|
|
Restated
|
|
Reported
|
|
Restated
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
1,801,000
|
|
1,573,000
|
|
1,364,000
|
|
1,093,000
|
|
Unrealized loss
on derivative contracts
|
|
|
|
316,000
|
|
|
|
371,000
|
|
Changes in
operating assets and liabilities
|
|
|
|
|
|
|
|
|
|
Other current
assets
|
|
(2,000
|
)
|
(90,000
|
)
|
(69,000
|
)
|
(169,000
|
)
|
8
Table
of Contents
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, in the ordinary course
of business.
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 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 three months ended January 31,
2008 and 2007, the company recognized stock based compensation expense of
$15,000 ($11,000 net of tax) and $57,000 ($41,000 net of tax)
respectively. The estimated unrecognized
compensation cost from unvested stock options as of January 31, 2008 was
approximately $108,000 which is expected to be recognized over an average of
2.3 years.
No options were granted during the three
months ended January 31, 2008. The
fair value of each stock option granted is 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 three months ended January 31, 2007 were: volatility, 50.84%; expected
option term, 2.5 years; risk-free interest rate, 4.58%; and expected dividend
yield, 0%.
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
9
Table
of Contents
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 January 31, 2008
the company has realized hedging gains of $847,000 and unrealized hedging
losses of $316,000. Realized hedging
gains were $396,000 and unrealized hedging losses were $371,000 for the same
period in 2007.
Subsequent to January 31, 2008, the
company entered into additional hedge contracts covering 620 MMBtus at
NYMEX basis prices, ranging from $8.13 to $9.95 for the production months of October 2008
through October 2009.
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. EARNINGS PER SHARE
The
companys calculation of earnings per share of common stock is as follows:
|
|
Three Months Ended January 31,
|
|
|
|
2008 (Restated)
|
|
2007 (Restated)
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
Income
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Basic earnings
per share
|
|
$
|
1,573,000
|
|
9,295,000
|
|
$
|
.17
|
|
$
|
1,093,000
|
|
9,261,000
|
|
$
|
.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of
dilutive shares of common stock from stock options
|
|
|
|
61,000
|
|
|
|
|
|
126,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings
per share
|
|
$
|
1,573,000
|
|
9,356,000
|
|
$
|
.17
|
|
$
|
1,093,000
|
|
9,387,000
|
|
$
|
.12
|
|
10
Table of Contents
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 January 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.
As of January 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
The company has no material outstanding commitments at January 31,
2008.
8.
RECENT
ACCOUNTING PRONOUNCEMENTS
In July 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxesan
interpretation of FASB Statement No. 109 (FIN 48).
This interpretation clarifies the application
of SFAS 109 by defining the criterion that an individual tax position must
meet for any part of the benefit of that position to be recognized in an
enterprises financial statements and also provides guidance on measurement,
de-recognition, classification, interest and penalties, accounting in interim
periods and disclosure. The company
adopted FIN 48 November 1, 2007.
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.
11
Table of
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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 159 and has not yet determined the
impact on its financial statements.
ITEM 2.
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This
Quarterly Report on Form 10-Q/A 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/A,
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 January 31, 2008, working capital increased $3,192,000, or 34%
to $12,643,000 compared to $9,451,000 at January 31, 2007. For the three months ended January 31,
2008, net cash provided by operating activities increased $87,000, or 6%, to
$1,626,000 compared to net cash provided by operating activities of $1,539,000
for the same period in 2007. Net income
increased $480,000 primarily due to an increase in net derivative gains of
$506,000, and an increase in revenue of $69,000, and a decrease in total costs
and expenses of $117,000, offset by an increase in income taxes of $212,000.
12
Table of
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For the three months ended January 31, 2008 and 2007, net cash
used in investing activities was $3,203,000 and $3,061,000, respectively. Investing activities primarily included oil
and gas exploration and development expenditures, including Calliope, totaling
$2,844,000 and $3,005,000 respectively.
The average return on the companys investments was a loss of 1.2% for
the three months ended January 31, 2008 compared to 4.5% return for the
same period last year. At January 31,
2008, approximately 46% of the investments were directly invested in mutual
funds and were managed by professional money managers. Remaining investments are in managed
partnerships (generally known as hedge funds) that use various strategies to
minimize their correlation to stock market movements. Most of the investments are highly liquid and
the company 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 January 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 $3,391,000 for the three months ended January 31,
2008 from $2,864,000 for the three months ended January 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 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:
|
|
Three Months Ended January 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
(Restated)
|
|
(Restated)
|
|
RECONCILIATION
OF EBITDA:
|
|
|
|
|
|
Net Income
|
|
$
|
1,573,000
|
|
$
|
1,093,000
|
|
Add Back:
|
|
|
|
|
|
Unrealized
Derivative Losses
|
|
316,000
|
|
371,000
|
|
Interest Expense
|
|
1,000
|
|
6,000
|
|
Income Tax
Expense
|
|
648,000
|
|
436,000
|
|
Depreciation,
Depletion and Amortization Expense
|
|
853,000
|
|
958,000
|
|
EBITDA
|
|
$
|
3,391,000
|
|
$
|
2,864,000
|
|
OFF-BALANCE SHEET FINANCING
The
company has no significant off-balance sheet financing arrangements at January 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
13
Table of Contents
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.
|
|
Three Months Ended January 31,
|
|
|
|
2008
|
|
2007
|
|
% Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
392,000
|
|
$
|
8.24
|
(1)
|
528,000
|
|
$
|
6.03
|
(2)
|
-26
|
%
|
+37
|
%
|
Oil (bbls)
|
|
15,700
|
|
$
|
86.39
|
|
11,900
|
|
$
|
52.06
|
|
+31
|
%
|
+66
|
%
|
(1) Includes $2.16 per Mcf realized hedging gain.
(2) Includes $0.75 per Mcf realized hedging gain.
OPERATIONS
During the first quarter 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 material
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
14
Table of Contents
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.
Northern Anadarko Basin
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 11,200-foot wildcat well drilled in
fiscal 2007 to test the 3,780 gross acre Humphreys Prospect encountered
excellent quality Morrow sands, and tested at the rate of 3.0 MMcf per
day. However, production declined rapidly
but stabilized at 150 Mcf per day.
The stabilized production rate suggests that the first well is
indirectly connected to a larger Morrow reservoir. The company subsequently purchased and
reprocessed 3-D seismic over the prospect, and believes that it has identified
the primary Morrow channel. A second
well was drilled in January 2008 to test the seismic interpretation. That
well encountered Tonkawa and Cherokee sands that appear to be productive based
on drilling data and electric logs, but it did not encounter the high potential
Morrow sands. The well is currently
awaiting completion for production. The
company owns a 25% working interest.
Additional drilling is expected on the prospect.
In Canadian
County, Oklahoma, the 640 gross acre Loosen Prospect continues to yield
excellent drilling results from the Redfork and Skinner formations. The 11,500-foot Marcia #1-14 was
recently drilled and encountered Skinner and Mississippi sands. The well is currently awaiting completion and
pipeline connection. The Marcia well is
a north extension to the recently completed Chappell well which encountered pay
zones in five separate formations. The
well is currently completed in three of the five zones and is producing 1.9
MMcf and 30 barrels of oil per day.
The remaining zones will be opened for production at a later date. The Chappell well was a north extension to
the Hazel well, drilled in December 2006, which is still producing 2.0
MMcf (million cubic feet of gas) and about 20 barrels of oil per day.
The company owns working
interests in the new wells as follows:
Hazel - 6.25%; Chappell - 16.3%, Marcia - 14.5%.
In Harper County, Oklahoma, the 3,840 gross acre Buffalo Creek Prospect
continues to be a very active drilling area for the company based on a recently
completed 3-D seismic program. Nine
wells have now been completed on the prospect with production from the Chester,
Morrow and Oswego formations. The most
recent well encountered 14 feet of excellent Morrow sand porosity, however,
production testing has indicated that the reservoir is extremely limited in
size. The company owns working interests
in the prospect ranging from 31% to 37%.
Three to five new drilling locations are currently planned for 2008, and
more are expected based on the results of future wells.
In Ellis County, Oklahoma, the first well was drilled on the companys
3,200 gross acre North Boxer Prospect.
The 8,500-foot well is currently classified as a tight hole, meaning
information is not being released for proprietary business reasons. A second wildcat well drilled about one mile
to the south was completed but produced water from the objective sand. Two additional wells are currently being
readied for drilling. The company owns
working interests in the prospect ranging from 30% to 40%.
In Kingfisher County, Oklahoma, the first two wells have been drilled
on the 1,280 gross acre Okarche Prospect to test the Hunton, Meramec,
Chester and Redfork formations. The
wells are each currently producing 200 Mcf and 10 barrels of oil per day. The company owns working interests ranging
from 9.5% to 11%.
15
Table
of Contents
In Carter County, Oklahoma, the Southeast
Hewitt Deese Sand Waterflood Unit has produced over 600,000 incremental
barrels of oil, and continues to significantly outperform initial
expectations. As a result of
development drilling, production from the unit has recently increased about 40% to 270 barrels
of oil per day. Further development is
under consideration. The company owns a
17% working interest.
In Love County, Oklahoma, a new Deese sand waterflood project is
currently in the approval process. The
company owns a 10% to 12% working interest in various phases of the project.
South Texas
The companys
South Texas drilling projects diversify it exploration geographically,
scientifically, and in terms of capital, risk and reserve potential. Compared to the companys Oklahoma drilling,
the South Texas project involves higher costs and greater risks but offers
significantly higher per well production and reserve potential.
The most significant of the companys two South Texas projects is 3-D
seismic driven and focuses on the Vicksburg, Frio and Queen City sands in
Hidalgo County and the Wilcox sands in Jim Hogg County at depths ranging from
7,200 feet to 17,500 feet. To date, the
company has invested approximately $1,900,000 (net) in the project,
exclusive of drilling. Prior to sale or
farmout of the prospects, the company owns a 75% interest before recovery of
its investment, exclusive of drilling, and 37.5% thereafter. The company has the option to participate in
drilling any of the prospects for its full interest or to reduce its costs and
risks by selling or farming-out its interest to third parties in return for
cash consideration and a carried interest on the initial wildcat well(s).
The primary objective of this project has
been identification, leasing and sale of three deep Wilcox prospects located
in Jim Hogg County. The prospects cover
about 3,600 gross acres, range in
depth from 16,500 to 17,500 feet, and are located in an area where
several nearby fields have produced hundreds of billions of cubic feet of gas
from the Wilcox formation. The companys
3-D seismic interpretation indicates that the prospects are large enough in size to have very substantial production
and reserve potential in relation to the companys existing production and
reserves. However, the prospects are
high risk, rank wildcat prospects and per well drilling costs far exceed those
normally incurred by the company. Therefore, the company has elected to sell a
portion of its interest for cash consideration and a carried interest on two
initial wildcat wells. Third parties
have committed to purchase the three prospects and to drill a wildcat well on
one prospect. The second wildcat well is
optional based on the outcome of the first well. Paperwork is in the process of being
completed. The Operator has indicated
the intent to commence drilling early in 2008.
In addition to recovering a significant portion its cash investment in
the project and being carried for an interest in the initial test well(s),
the company has preserved its option to participate in other wells drilled on
the prospects with interests ranging from 11.25% before recovery of its
investment to 5.625% after recovery. 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 prospect is fault separated from the
Heyser Field which has produced 738,000 barrels of oil and 17 Bcf from the Frio
sands. The 8,600-foot Briggs Ranch #1
encountered 11 feet of Frio sands and is currently producing about 1.0
MMcf per day. The company owns a
9% working interest.
North-Central Kansas
The companys
Central Kansas drilling project provides additional diversification to the
companys drilling program through the use of 3-D seismic to identify shallow
oil prospects. The acreage is located in
prolific oil producing areas where 3-D seismic has proven effective in
identifying satellite structures near mature producing fields. Higher oil prices have justified using
3-D seismic technology to locate undrilled structures that are very
difficult to find with old technology.
Drilling targets the Lansing-Kansas City and Arbuckle formations at
about 4,000 feet and, compared to the companys Northern Anadarko Basin
and South Texas projects, is relatively low cost, low risk, and exclusively
targets oil reserves in an effort to bring better product balance to the
companys reserve base.
16
Table
of Contents
Thus far, the company has assembled four
separate drilling projects which encompass about 41,000 gross acres and is
continuing to seek opportunities to increase its exposure to the play. The company owns working interests in the
existing prospects ranging from 12.5% to 75%.
The companys recent drilling results have
improved dramatically as it continues to find the keys to successful seismic
and geologic interpretation. Four of the
last seven wells have been completed as producers, and three of those appear to
be outstanding wells.
In Graham County, two of the first three wells on the 3,280 gross acre
White Anticline and Mt. Vernon prospects resulted in Lansing Kansas City
formation discoveries. Five
additional
wells have been approved for drilling.
The company owns a 12.5% working interest in both prospects.
In Rawlins County, seismic is scheduled to commence shortly on the companys
3,560 gross acre Beaver Jenks prospect.
The company owns a 30% working interest in the prospect.
In Sheridan County, three of the last six wells have resulted in
discoveries on the companys 8,000 gross acre Lucerne Prospect. Three additional wells have been approved for
drilling. The company owns a
30% working interest in the prospect.
In Barton and Rice Counties, seismic is scheduled to commence shortly
on the companys 7,000 net acre prospect.
The company owns a 75% working interest in the prospect.
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
17
Table of Contents
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.
|
|
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Average
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Total
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Total
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|
|
|
Calliope
|
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Calliope
|
|
Projected
|
|
|
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|
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
18
Table of Contents
an interest in Calliope. Two
joint venture agreements were completed during 2007. Another joint venture agreement was completed
in the first quarter of 2008. 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, as it
believes that the company will eventually be successful in the joint venture
area.
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
Three Months Ended January 31, 2008 Compared to Three Months Ended
January 31, 2007
For the three months ended January 31, 2008, total revenues
increased 2% to $3,728,000 compared to $3,659,000 during the same period last
year. As the oil and gas price/volume table
on page 13 shows, total gas price realizations, which reflect realized
hedging transactions, increased 37% to $8.24 per Mcf and oil price realizations
increased 66% to $86.39 per barrel. The
net effect of these price changes was to increase oil and gas sales by
$1,282,000 ($832,000 without realized hedges).
For the three months ended January 31, 2008, the companys gas
equivalent production fell 19% resulting in an oil and gas sales decrease of
$510,000. Investment and other income
decreased $252,000 primarily due to performance of the companys
investments, compared to last year.
For the three months ended January 31,
2008, total costs and expenses fell 5% to $2,038,000 compared to $2,155,000 for
the comparable period in 2007. Oil and
gas production expenses fell due primarily to a decrease in production taxes
and a decrease in lease operating expenses related to several major workovers
in 2007. DD&A declined primarily due
to lower production partially offset by an increase in the amortizable cost
base. General and administrative
expenses increased primarily due to accounting and professional fees. Interest expense relates to the exclusive
license agreement note payment. The effective tax rate was 29.2% and 28.5% 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.
19
Table of Contents
OIL AND GAS PROPERTIES.
The company uses the full cost method of
accounting for costs related to its oil and natural gas properties. Capitalized costs included in the full cost
pool are depleted on an aggregate basis using the units-of-production
method. 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
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.
20
Table of Contents
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.
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/A. 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 quarter of fiscal
2008 management designed and implemented enhanced and accelerated training
for its senior financial staff and 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
None.
21
Table
of Contents
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
None.
ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5.
OTHER INFORMATION
None.
ITEM 6.
EXHIBITS
Exhibits are as follow:
31.1
|
|
Certification by
Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act
of 2002
|
|
|
|
31.2
|
|
Certification by
Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act
of 2002
|
|
|
|
32.1
|
|
Certification by
Chief Executive Officer and Chief Financial Officer under Section 906 of
the Sarbanes-Oxley Act (18 U.S.C. Section 1350)
|
22
Table of Contents
SIGNATURES
Pursuant to the
requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.
|
CREDO Petroleum
Corporation
|
|
(Registrant)
|
|
|
|
|
|
|
|
By:
|
/s/ James T.
Huffman
|
|
|
James T. Huffman
|
|
|
President and
Chief Executive Officer
|
|
|
(Principal
Executive Officer)
|
|
|
|
|
By:
|
/s/ Alford B.
Neely
|
|
|
Alford B. Neely
|
|
|
Chief Financial
Officer
|
|
|
(Principal
Financial and Accounting Officer)
|
|
|
|
|
|
|
Date:
September 15
, 2008
|
|
|
23
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