UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
| ž | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended January 31,
2007
| 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
(Registrant’s 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 ž No o
Indicate by check mark whether the registrant is a
large accelerated filer, an accelerated filer, or a non-accelerated
filer. (See definition of “accelerated filer” and “large
accelerated filer” in Rule 12b-2 of the Act.)
Large accelerated filer o
Accelerated filer ž
Non-accelerated filer 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 ž
Indicate the number of shares outstanding of each
of the issuer’s classes of common stock, net of treasury stock, as of
the latest practicable date.
| Date | Class | Outstanding | ||
| March 12, 2007 | Common stock, $.10 par value | 9,261,000 | ||
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly Report on Form 10-Q For the Period
Ended January 31, 2007
TABLE OF CONTENTS
| Page No. | ||||||||
|
|
||||||||
|
|
||||||||
| 3 | ||||||||
|
|
||||||||
| 4 | ||||||||
|
|
||||||||
| 5 | ||||||||
|
|
||||||||
| 6 | ||||||||
|
|
||||||||
| 7 | ||||||||
|
|
||||||||
| 10 | ||||||||
|
|
||||||||
| 19 | ||||||||
|
|
||||||||
| 19 | ||||||||
|
|
||||||||
|
|
||||||||
| 19 | ||||||||
|
|
||||||||
| 19 | ||||||||
|
|
||||||||
| 19 | ||||||||
|
|
||||||||
| 19 | ||||||||
|
|
||||||||
| 20 | ||||||||
|
|
||||||||
| 20 | ||||||||
|
|
||||||||
| 20 | ||||||||
|
|
||||||||
| 21 | ||||||||
| Certification by Chief Executive Officer | ||||||||
| Certification by Chief Financial Officer | ||||||||
| Certification by CEO and CFO Pursuant to Section 906 | ||||||||
The terms “CREDO”, “Company”, “we”,
“our”, and “us” refer to CREDO Petroleum Corporation and its
subsidiaries unless the context suggests otherwise.
2
Table of Contents
PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
| January 31, | October 31, | |||||||
| 2007 | 2006 | |||||||
| (Unaudited) | ||||||||
|
ASSETS
|
||||||||
|
Current Assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 3,055,000 | $ | 4,577,000 | ||||
|
Short-term investments
|
6,136,000 | 5,624,000 | ||||||
|
Receivables:
|
||||||||
|
Accrued oil and gas sales
|
1,656,000 | 777,000 | ||||||
|
Trade
|
1,143,000 | 1,963,000 | ||||||
|
Derivative Assets
|
526,000 | 897,000 | ||||||
|
Other current assets
|
240,000 | 71,000 | ||||||
|
|
||||||||
|
Total current assets
|
12,756,000 | 13,909,000 | ||||||
|
|
||||||||
|
|
||||||||
|
Long-term assets:
|
||||||||
|
Oil and gas properties, at cost, using
full cost method:
|
||||||||
|
Unevaluated oil and gas properties
|
8,962,000 | 7,060,000 | ||||||
|
Evaluated oil and gas properties
|
44,691,000 | 43,588,000 | ||||||
|
Less: accumulated depreciation,
depletion and amortization of oil and gas properties
|
(19,488,000 | ) | (18,556,000 | ) | ||||
|
|
||||||||
|
Net oil and gas properties, at cost,
using full cost method
|
34,165,000 | 32,092,000 | ||||||
|
|
||||||||
|
|
||||||||
|
Exclusive license agreement, net of
amortization of $449,000 in 2007 and $431,000 in 2006
|
251,000 | 268,000 | ||||||
|
|
||||||||
|
Compressor and tubular inventory to be
used in development
|
1,308,000 | 1,293,000 | ||||||
|
|
||||||||
|
Other (net)
|
229,000 | 197,000 | ||||||
|
|
||||||||
|
|
||||||||
|
Total assets
|
$ | 48,709,000 | $ | 47,759,000 | ||||
|
|
||||||||
|
|
||||||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||
|
|
||||||||
|
Current Liabilities:
|
||||||||
|
Accounts payable
|
$ | 1,400,000 | $ | 1,581,000 | ||||
|
Revenue distribution payable
|
1,122,000 | 1,273,000 | ||||||
|
Other accrued liabilities
|
510,000 | 808,000 | ||||||
|
Income taxes payable
|
273,000 | 174,000 | ||||||
|
|
||||||||
|
Total current liabilities
|
3,305,000 | 3,836,000 | ||||||
|
|
||||||||
|
Long Term Liabilities:
|
||||||||
|
Deferred income taxes, net
|
8,367,000 | 8,039,000 | ||||||
|
Exclusive license obligation, less
current obligations of $70,000 in 2007 and 2006
|
163,000 | 163,000 | ||||||
|
Asset retirement obligation
|
957,000 | 954,000 | ||||||
|
|
||||||||
|
Total liabilities
|
12,792,000 | 12,992,000 | ||||||
|
|
||||||||
|
|
||||||||
|
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 2007 and 2006
|
951,000 | 951,000 | ||||||
|
Capital in excess of par value
|
14,851,000 | 14,794,000 | ||||||
|
Treasury stock at cost, 249,000 shares
in 2007 and 2006
|
— | — | ||||||
|
Accumulated other comprehensive income
(loss)
|
379,000 | 650,000 | ||||||
|
Retained earnings
|
19,736,000 | 18,372,000 | ||||||
|
|
||||||||
|
Total stockholders’ equity
|
35,917,000 | 34,767,000 | ||||||
|
|
||||||||
|
|
||||||||
|
Total liabilities and stockholders’
equity
|
$ | 48,709,000 | $ | 47,759,000 | ||||
|
|
||||||||
The accompanying notes are an integral part of
these consolidated financial statements.
3
Table of Contents
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
The accompanying notes are an integral part of
these consolidated financial statements.
4
Table of Contents
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Statement of Stockholders’ Equity and
Comprehensive Income
(Unaudited)
For the Three Months Ended January 31, 2007
For the Three Months Ended January 31, 2007
| Accumulated | ||||||||||||||||||||||||||||||||
| Capital In | Other | Total | ||||||||||||||||||||||||||||||
| Common Stock | Excess Of | Treasury | Comprehensive | Comprehensive | Retained | Stockholders’ | ||||||||||||||||||||||||||
| Shares | Amount | Par Value | Stock | Income | Income | Earnings | Equity | |||||||||||||||||||||||||
|
Balance, October 31, 2006
|
9,510,000 | $ | 951,000 | $ | 14,794,000 | $ | — | $ | 650,000 | $ | 18,372,000 | $ | 34,767,000 | |||||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | — | — | — | $ | 1,364,000 | 1,364,000 | 1,364,000 | |||||||||||||||||||||||
|
Other comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Change in fair value of derivatives, net
of tax
|
— | — | — | — | (271,000 | ) | (271,000 | ) | — | (271,000 | ) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Total comprehensive income
|
— | — | — | — | — | $ | 1,093,000 | — | — | |||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Compensation expense associated with
unvested portion of previously granted stock options
|
— | — | 57,000 | — | — | — | 57,000 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Balance, January 31, 2007
|
9,510,000 | $ | 951,000 | $ | 14,851,000 | $ | — | $ | 379,000 | $ | 19,736,000 | $ | 35,917,000 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
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)
The accompanying notes are an integral part of
these consolidated financial statements.
6
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To Consolidated Financial Statements
(Unaudited)
January 31, 2007
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 company’s results for the periods presented. These consolidated
financial statements should be read in conjunction with the company’s
Annual Report on Form 10-K for the fiscal year ended October 31,
2006.
Certain financial statement amounts have been
reclassified to conform to the presentation used for the 2007 periods.
Effective with the second quarter of 2006, the company has reclassified
reimbursed overhead from operating revenue to general and administrative
expense. For the three months ended January 31, 2007 and 2006, the
reclassified amounts were $186,000 and $173,000, respectively.
2. SIGNIFICANT ACCOUNTING POLICIES
The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. The company bases its estimates on historical
experience and on various other assumptions it believes to be reasonable
under the circumstances. Although actual results may differ from these
estimates under different assumptions or conditions, the company
believes that its estimates are reasonable and that actual results will
not vary significantly from the estimated amounts.
The company has changed its estimate with respect
to estimated salvage value of lease and well equipment. This change in
estimate resulted in a decrease in depreciation, depletion and
amortization of approximately $65,000 for the quarter ended January 31,
2007.
3. STOCK-BASED COMPENSATION
The company currently has one stock-based employee
compensation plan, the CREDO Petroleum Corporation 1997 Stock Option
Plan (the 1997 Plan) which is described in the Notes to Consolidated
Financial Statements in the company’s Annual Report on Form 10-K for
the year ended October 31, 2006. This Plan will expire on July 29,
2007. The CREDO Petroleum Corporation 2007 Stock Option Plan (the 2007
Plan), which is similar in all respects to the 1997 Plan has been
proposed to the shareholders for approval at the Annual Meeting of
Shareholders on March 22, 2007. If the 2007 Plan is approved, no
additional options will be granted under the 1997 Plan. However, all
outstanding options granted under the 1997 Plan will continue to be
governed by the rules of the 1997 Plan. Effective November 1, 2005,
the company adopted the fair value recognition provisions of SFAS No. 123
(R), Share Based Payment, using the modified-retrospective-transition
method. Under this transition method, the company restated the results
of all prior periods back to the beginning of fiscal 1997 (the fiscal
year of inception for this stock-based compensation plan) in accordance
with the original provisions of SFAS No. 123. For the three months
ended January 31, 2007 and 2006, the company recognized
compensation expense of $57,000 and $60,000, respectively.
No options were granted during fiscal year 2006
and the fair value of the 40,000 options granted during the three months
ended January 31, 2007 was estimated as of the grant date using the
Black-Scholes option pricing model with the following assumptions:
volatility, 50.84%; expected option term, 2 and 3 years; risk-free
interest rate, 4.58% and; expected dividend yield, 0%. If option grants
are made in the future, compensation expense for all such share-based
payments granted, based upon the grant-date fair value estimated in
accordance with the provisions of SFAS No. 123(R) will also be
included in compensation expense.
7
Table of Contents
Plan activity for the three months ended January 31,
2007 is set forth below.
| Three Months Ended January 31, 2007 | ||||||||
| Weighted | ||||||||
| Average | ||||||||
| Number of | Exercise | |||||||
| Options | Price | |||||||
|
Outstanding at October 31, 2006
|
315,002 | $ | 5.52 | |||||
|
Granted
|
40,000 | 12.78 | ||||||
|
Exercised
|
— | — | ||||||
|
Cancelled or forfeited
|
— | — | ||||||
|
|
||||||||
|
Outstanding at January 31, 2007
|
355,002 | $ | 6.34 | |||||
|
|
||||||||
|
|
||||||||
|
Exercisable at January 31, 2007
|
274,543 | $ | 5.70 | |||||
|
|
||||||||
|
|
||||||||
|
Weighted average contractual life at
January 31, 2007
|
6.70 | |||||||
|
|
||||||||
The following table summarizes information about
stock options currently outstanding and exercisable at January 31,
2007:
| Outstanding | Exercisable | |||||||||||||||||||
| Number | Weighted Average | Weighted | Number | |||||||||||||||||
| Range of | Outstanding | Remaining | Average | Exercisable at | Weighted | |||||||||||||||
| Exercise | at January 31, | Contractual | Exercise | January 31, | Average | |||||||||||||||
| Prices | 2007 | Life in Years | Price | 2007 | Exercise Price | |||||||||||||||
|
$3.09-$3.72
|
54,750 | 5.87 | $ | 3.56 | 44,625 | $ | 3.52 | |||||||||||||
|
$5.93-$5.93
|
260,252 | 5.54 | $ | 5.93 | 223,251 | $ | 5.93 | |||||||||||||
|
$12.78-$12.78
|
40,000 | 9.82 | $ | 12.78 | 6,667 | $ | 12.78 | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
$3.09-$12.78
|
355,002 | 6.70 | $ | 6.34 | 274,543 | $ | 5.70 | |||||||||||||
|
|
||||||||||||||||||||
Total estimated unrecognized compensation cost
from unvested stock options as of January 31, 2007 was
approximately $219,000, which is expected to be recognized over an
average period of approximately 1.44 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 company’s production is located, and are authorized
by the company’s 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 oil and gas sales.
8
Table of Contents
Hedges include contracts indexed to the NYMEX and
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.
Hedging gains and losses are recognized as
adjustments to gas sales as the hedged product is produced. The company
had hedging gains of $396,000 in first quarter of fiscal 2007, and
hedging losses of $265,000 for the same period in 2006. Any hedge
ineffectiveness, which was not material for any period is immediately
recognized in gas sales.
Realized (February 2007) and unrealized
(March 2007 through October 2007) gains on hedge contracts at
January 31, 2007 totaled $526,000 and were included in
“Accumulated Other Comprehensive Income”. These contracts covered
930 MMBtus at NYMEX basis prices ranging from $7.56 to $8.95.
Subsequent to January 31, 2007, the company
entered into additional hedge contracts covering 1,070 MMBtus at NYMEX
basis prices ranging from $7.76 to $9.47 and including production months
from March 2007 through March 2008.
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 $4,500,000 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 company’s bank, and
prohibits unfunded debt in excess of $500,000. It expires on October 31,
2007.
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 months ended January 31, 2007 and 2006 are as follows:
| Three Months Ended | ||||||||
| January 31, | ||||||||
| 2007 | 2006 | |||||||
|
Net income
|
$ | 1,364,000 | $ | 1,695,000 | ||||
|
Other comprehensive income:
|
||||||||
|
Change in fair value of derivatives
|
(371,000 | ) | 425,000 | |||||
|
Income tax expense
|
100,000 | (119,000 | ) | |||||
|
|
||||||||
|
Total comprehensive income
|
$ | 1.093,000 | $ | 2,001,000 | ||||
|
|
||||||||
9
Table of Contents
6. EARNINGS PER SHARE
The company’s calculation of earnings per share
of common stock is as follows:
| Three Months Ended January 31, | ||||||||||||||||||||||||||||
| 2007 | 2006 | |||||||||||||||||||||||||||
| Net | Net | |||||||||||||||||||||||||||
| Net | Income | Net | Income | |||||||||||||||||||||||||
| Income | Shares | Per Share | Income | Shares | Per Share | |||||||||||||||||||||||
|
Basic earnings per share
|
$ | 1,364,000 | 9,261,000 | $ | .15 | $ | 1,695,000 | 9,137,000 | $ | .19 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||
|
Effect of dilutive shares of common
stock from stock options
|
— | 126,000 | (.00 | ) | — | 338,000 | (.01 | ) | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
|
Diluted earnings per share
|
$ | 1,364,000 | 9,387,000 | $ | .15 | $ | 1,695,000 | 9,475,000 | $ | .18 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||
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.
8. COMMITMENTS
The company has no material outstanding
commitments at January 31, 2007.
| ITEM 2. | MANAGEMENT’S 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 company’s 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; |
10
Table of Contents
| • | 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 company’s 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 company’s business and operations. |
LIQUIDITY AND CAPITAL RESOURCES
At January 31, 2007, working capital
increased $1,487,000 or 19% to $9,451,000 compared to $7,964,000 at
January 31, 2006. For the three months ended January 31, 2007,
net cash provided by operating activities decreased $2,639,000 to
$1,530,000 compared to net cash provided by operating activities of
$4,169,000 for the same period in 2006. Net income decreased $331,000
primarily due to a decrease in revenues of $310,000, and an increase in
depreciation, depletion and amortization (DD&A) of $220,000, net of
a $65,000 decrease in DD&A due to an increase in estimated salvage
values.
For the three months ended January 31, 2007
and 2006, net cash used in investing activities was $3,061,000 and
$3,221,000, respectively. During the first quarter of fiscal 2007 and
2006 investing activities primarily included oil and gas exploration and
development expenditures, including Calliope, totaling $3,005,000 and
$3,539,000 respectively.
The average return on the company’s investments
for the three months ended January 31, 2007 and 2006 was 4.5% and
3.2%, respectively. At January 31, 2007, approximately 57% of the
investments were directly invested in mutual funds and were managed by
professional money managers. Remaining investments are in managed
partnerships 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 company’s 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, 2007, 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 company’s earnings before interest, taxes,
depreciation, depletion and amortization, (“EBITDA”) decreased to
$2,864,000 for the three months ended January 31, 2007 from
$3,101,000 for the three months ended January 31, 2006. 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 company’s 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:
11
Table of Contents
| Three Months Ended January, | ||||||||
| 2007 | 2006 | |||||||
|
RECONCILIATION OF EBITDA:
|
||||||||
|
Net Income
|
$ | 1,364,000 | $ | 1,695,000 | ||||
|
Add Back:
|
||||||||
|
Interest Expense
|
6,000 | 9,000 | ||||||
|
Income Tax Expense
|
536,000 | 659,000 | ||||||
|
Depreciation, Depletion and Amortization
Expense
|
958,000 | 738,000 | ||||||
|
|
||||||||
|
EBITDA
|
$ | 2,864,000 | $ | 3,101,000 | ||||
|
|
||||||||
OFF-BALANCE SHEET FINANCING
The company has no off-balance sheet financing
arrangements at January 31, 2007.
PRODUCT PRICES AND PRODUCTION
Although product prices are key to the company’s
ability to operate profitably and to budget capital expenditures, they
are beyond the company’s control and are difficult to predict. Since
1991, the company has periodically hedged the price of a portion of its
estimated natural gas production when the potential for significant
downward price movement is anticipated. Hedging transactions typically
take the form of forward short positions, swaps and collars which are
executed on the NYMEX futures market or by indexing to regional index
prices associated with pipelines in proximity to the company’s
production. A portion of the company’s current hedges are indexed to
Panhandle Eastern Pipeline Company for Texas, Oklahoma (mainline) (“PEPL”)
which serves the regions where the company produces the majority of its
gas. Refer to Note 4 of the Consolidated Financial Statements for a
complete discussion on the company’s 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 hedging gains and losses.
| Three Months Ended January 31, | ||||||||||||||||||||||||
| 2007 | 2006 | % Change | ||||||||||||||||||||||
| Product | Volume | Price | Volume | Price | Volume | Price | ||||||||||||||||||
|
Gas (Mcf)
|
528,000 | $ | 6.03 | (1) | 437,000 | $ | 8.19 | (2) | +21 | % | -26 | % | ||||||||||||
|
Oil (bbls)
|
11,900 | $ | 52.06 | 9,500 | $ | 56.94 | +25 | % | - 8 | % | ||||||||||||||
| (1) | Includes $0.75 Mcf hedging gain. | |
| (2) | Includes $0.61 Mcf hedging loss. |
OPERATIONS
During the first quarter of fiscal 2007, the
company’s operations were focused on its two core projects — natural
gas drilling and application of its patented Calliope Gas Recovery
System.
As discussed below, the company has expanded into
South Texas through an exploration program using 3-D seismic to define
the Vicksburg, Frio, Queen City and Wilcox prospects in Hidalgo and Jim
Hogg counties. The company has also expanded into north-central Kansas
through an exploration program using 3-D seismic to define
Lansing-Kansas City oil prospects along the Central Kansas Uplift.
Also as discussed below, the company has expanded
its Calliope operations into Texas and Louisiana. The company believes
these are fertile areas for Calliope and will continue to expand as
opportunities allow. During 2007, the company plans to commence drilling
operations on a new project to drill wells into existing reservoirs for
the specific purpose of using Calliope to recover stranded gas.
12
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 2007, 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 company’s control, including but not
limited to, the availability of oil field services such as drilling
rigs, production equipment and related services, and access to wells for
application of the company’s patented gas recovery system on low
pressure gas wells. The prevailing price of oil and natural gas has a
significant effect on demand and, thus, the related cost of such
services and wells.
The company 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.
Drilling Activities.
Northern Anadarko Basin —The company
drills primarily on its significant inventory of acreage (approximately
68,000 gross acres) located along the northern portion of the Anadarko
Basin where it has drilled approximately 77 wells. The wells 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.
During the first quarter of fiscal 2007, the
company drilled the ninth well on its 5,760 Glacier Prospect located in
Harper and Woodward Counties, Oklahoma. The Carmella State well is an
east extension from the high rate Garnet State and Scarlet State wells
that were completed last year. The well encountered excellent quality
Morrow sands. Initial production rates are in excess of 2.0 million
cubic feet of gas per day. The well has been on production for only a
few days and is still being lined-out. Accordingly, all well data is
very preliminary. The company owns a 72% working interest and is the
operator.
The initial test well on the 2,500 gross acre
Humphries Prospect located in the Texas Panhandle was drilled in the
first quarter of 2007. The 11,200-foot well encountered excellent
quality, over-pressured Upper Morrow sands. The well commenced
production in February and is currently producing about 330 thousand
cubic of gas per day. Initial pressure information indicates that the
reservoir is limited in size at the location of the well. However, the
well established the presence of high quality Morrow sand on the
prospect. The company intends to acquire and reprocess 3-D seismic over
the prospect to assess whether the well is separated from a larger
reservoir by faulting. Additional acreage is also being acquired in the
area and further drilling is expected on the prospect. The company owns
a 25% working interest.
The company has completed interpretation of the
recent 3-D seismic program over its 3,840 gross acre Buffalo Creek
Prospect. To date, six producing wells have been drilled on the
prospect. Based on the seismic interpretation, the company has initially
identified another four to six drilling locations for the Morrow,
Chester and Oswego sands. The company owns varying interest in different
portions of the prospect that generally range from 30% to 45%.
Additional drilling is expected in the second quarter of fiscal 2007.
An excellent well has been drilled on the 640
gross acre Loosen Prospect located in Canadian County, Oklahoma. The
11,500-foot Hazel well encountered excellent sands in the Redfork and
Skinner formations, and is producing approximately 2.5 million
cubic of gas per day. The company owns a small overriding royalty
interest in the Hazel well but has the right to participate for a 12.5%
interest in any offset well.
13
Table of Contents
Drilling Program Expansion and Diversification —During
the past two years, the company significantly expanded both the volume
and breadth of its exploration program with new projects in South Texas
and north-central Kansas. It is the company’s intention to diversify
its exploration geographically, scientifically, and in terms of capital,
risk and reserve potential. Compared to drilling in Oklahoma, the South
Texas project involves significantly higher costs and greater risks but
significantly higher per well reserve potential. The north central
Kansas project is geared to oil exploration and has excellent potential
to add significant reserves at moderate costs and risks. Both projects
are in areas where 3-D seismic is a proven exploration tool and where
continuing refinements are providing excellent exploration success.
Equally as important, both exploration teams specialize in their
respective geographic areas and have been highly successful finding new
reserves using 3-D seismic.
South Texas —The company’s new
exploration project in South Texas is 3-D seismic driven and focuses on
the Vicksburg, Frio, Queen City and Wilcox sands in Hidalgo and Jim Hogg
Counties ranging in depth from 7,500 to 17,000 feet. Both the cost and
the potential of this project far exceed any of the company’s previous
projects.
In return for a 75% interest before investment
payout (calculated on a prospect by prospect basis) and 37.5% interest
after investment payout, the company initially committed $1,500,000 for
prospect generation and leasing costs. The commitment has been fully
funded and all future project funding is at the company’s discretion.
The company has the option to participate in drilling each prospect for
all, or a portion, of its interest. If the company does not participate
for its full interest, the remaining portion will be sold to industry
participants on a promoted basis.
The exploration team has generated a significant
number of high quality 3-D seismic drilling prospects, and will generate
more prospects in the future. Seven prospects have been fully leased and
two of those prospects have been drilled.
As previously reported, the company participated
for its full 37.5% interest in the first project well which was drilled
on the 1,700 gross acre Robertson Prospect in Hidalgo County. Production
casing has been set on the 10,500-foot well, and Upper Frio sands have
been tested at rates of approximately 1.0 MMcfe per day. However,
pressure data indicates that the reservoir may be limited in size. An
additional up-hole sand appears on logs to be productive and may be
evaluated before a final commercial production decision is made. The
well is currently being evaluated for pipeline connection.
A 6,850-foot well has recently been drilled on the
600 gross acre Vela Prospect located in Jim Hogg County, Texas. The well
encountered Queen City sands that appear to be productive on electric
logs and is currently awaiting completion for production. The company
sold its interest in the prospect to third parties in return for cash
and a carried interest in the drilling and completion of the well. The
company will own an 18% working interest in production from the well
before payout and a 9% interest after payout.
Fully leased prospects that are in the process of
being sold to third parties include the 800 gross acre Esparza Prospect
which targets Marks sands at approximately 12,500 feet, the 2,300 gross
acre Sam Houston Prospect which targets Frio sands at approximately
10,500 feet, the 1,200 gross acre West Mestena Prospect which targets
Queen City sands at approximately 10,500 feet, the 1,120 gross acre
Millennium Prospect which targets Wilcox sands at approximately 15,000,
and the 960 gross acre Gemini Prospect which targets Wilcox sands at
approximately 17,000 feet. The company expects a number of these
prospects to be drilled during 2007.
In response to drilling costs which have almost
doubled since the project began, beginning with the Vela Prospect
(discussed above), the company recently elected to reduce its exposure
to drilling participation in the next four prospects by selling all, or
a significant portion, of its 37.5% interest to industry drilling
participants. The company expects to recover its investment in each
prospect and retain a promoted interest in exploratory wells with the
option to participate in development drilling. Because the project has
significant potential to increase production and reserves, the company
has reserved the option to participate for its full 37.5% interest in
all other prospects. This strategy will reduce the company’s South
Texas exploration risk and improve its staying power.
14
Table of Contents
North-Central Kansas —The company’s new
exploration project in Central Kansas includes interests in three
different drilling projects encompassing about 30,000 gross acres
located on the Central Kansas Uplift. The acreage is located in a
prolific producing area of the Central Kansas Uplift where 3-D seismic
has recently proven to be an effective exploration tool. The project
provides diversification to the company’s drilling program, both
geographically and scientifically, through the use of 3-D seismic. It
also exclusively targets oil reserves which will help bring better
product balance to the company’s reserve base.
The company owns interests in the projects ranging
from 12.5% to 100%. Drilling targets the Lansing-Kansas City formation
at 4,000 feet. Completed costs for individual wells are averaging
approximately $300,000.
The largest of the three drilling projects is
approximately 21,000 gross acres located in Graham and Sheridan
Counties, Kansas. The company owns a 30% interest and committed to shoot
seismic and participate in drilling five test wells. The commitment has
been fully funded and all future project funding is at the company’s
discretion. Approximately 28 square miles of 3-D seismic have been shot
and evaluated, and six exploratory wells have been drilled, of which one
well is an excellent producer and five wells are dry holes. The new
producer is making 115 BO per day after four months of production. It is
located on a prospect containing approximately 1,000 gross acres.
Additional development drilling is scheduled for the prospect.
The project is in an early stage and the learning
curve is steep. Seismic data is currently being reprocessed and
re-evaluated to incorporate data obtained from drilling the initial
wells. The company believes drilling results will improve as it gains
additional experience in the area. Drilling is expected on approximately
30 prospects.
Calliope Drilling Project —See discussion
under Calliope Gas Recovery Technology below.
All of the company’s oil and natural gas
properties are located on-shore in the continental United States. The
company’s 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 company’s
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.
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 one Canadian patent related to the
technology. Two additional patents that mirror the U.S. patents have
been applied for in Canada.
Calliope can achieve substantially lower flowing
bottom-hole pressure than conventional 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.
Realizing Calliope’s value continues to be one
of the company’s top priorities. The company is 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.
Calliope Drilling Project —During 2006,
the company entered into a 50/50 joint venture with Redman Energy
Holdings II, L.P. to drill wells for the purpose of using its patented
Calliope Gas Recovery System to recover stranded gas reserves. Redman
Energy Holdings is an affiliate of Redman Energy Corporation, a
privately-held, Houston-based exploration and production company. Redman
is affiliated with Natural Gas Partners, a highly
15
Table of Contents
respected industry funding source, and brings a
wealth of knowledge and a solid operating foundation in the project
area. Drilling will concentrate on previously mature, prolific fields
containing significant stranded gas.
In its initial phases, the joint venture plans to
invest up to $35,000,000 to acquire leases, drill new wells, and install
Calliope principally in South and East Texas. Drilling will target large
gas fields that were abandoned when natural gas prices were considerably
lower than today, and when technologies to remove fluids from wellbores
were much less effective than Calliope. The company presently expects to
fund its 50% share of the joint venture from existing cash and future
cash flow.
Access to fields and drilling locations are
generally available through leasing or acquiring interests in old
fields. The company believes this project is a target-rich opportunity
for the company to take control of expanding its Calliope operations.
Wells are expected to range in depth from 8,000 to 13,000 feet. Reserves
are projected to range from 1.0 to 3.0 Bcfe (billion cubic feet of gas
equivalent) per well, with beginning production rates ranging from 500
to 1,500 Mcf per day. Average drilling economics are expected to include
payouts of approximately two years.
Several prospects are located in old fields
currently owned by Redman, and several prospects are in various stages
of leasing. The old fields currently owned by Redman contain very
significant stranded gas reserves due to their large reservoir volume
and high remaining pressure. The company believes that Calliope will
recover billions of cubic feet of gas from these fields by pulling-down
reservoir pressure to previously unachievable levels.
The first well to be proposed under the joint
venture is an 11,500-foot well located in a field that has produced 110 billion
cubic of gas from the Smackover formation. Drilling is expected to
commence during the second quarter of fiscal 2007.
In addition to the Redman joint venture, the
company is developing other Calliope drilling prospects. The Redman
joint venture applies largely to South and East Texas. There are many
other areas, including Oklahoma, Louisiana, Mississippi and North Texas,
that are highly prospective for Calliope drilling.
The Calliope drilling project will be the
company’s first opportunity to use Calliope to recover stranded
reserves from an entire field. The company believes that drilling new
wells for Calliope will provide a repeatable opportunity to lease large
areas for systematic re-development. In addition, the company intends to
install optimum casing and tubular sizes to substantially improve
reserves and production compared to installing Calliope on existing
wells where undersized tubulars often impede Calliope’s performance.
Although there are always risks associated with
drilling, the company considers this to be low risk, development type
drilling because it involves areas known to be productive. The company
believes that drilling wells into under-pressured reservoirs without
damaging the reservoir with drilling fluids is key to the success of the
project. If that can be done successfully, the company believes that
Calliope can be used to recover stranded gas reserves that can estimated
with a high degree of confidence.
Purchasing Calliope Candidate Wells —Calliope
systems are currently installed on 18 wells owned and operated by the
company. The wells are located in Oklahoma, Texas and Louisiana, and
range in depth from 6,500 to 18,400 feet. They represent the most
rigorous applications for Calliope because the wells were either totally
dead or uneconomic at the time Calliope was installed. In addition,
prior to the time Calliope was installed, many of the reservoirs were
damaged by the “parting shots” of previous operators. Initial
Calliope production rates range up to 650 Mcfd (thousand cubic feet of
gas per day) and average per well Calliope reserves for non-prototype
wells are estimated to be 1.10 Bcf. One of the company’s early
Calliope installations, the J.C. Carroll well, has now produced almost a
billion cubic feet of gas using Calliope.
Calliope operations have recently been expanded
into Texas and Louisiana with two installations in southwest Texas and
one in Louisiana. 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 Calliope.
16
Table of Contents
In general, higher 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.
Joint Ventures With Third Parties —In an
effort to increase the number of Calliope installations, the company is
seeking 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 a keen interest in
Calliope, and joint venture discussions are continuing 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 resources and make efforts as it believes that the company will
eventually be successful in the joint venture area.
Results of Operations
Three Months Ended January 31, 2007
Compared to Three Months Ended January 31, 2006
For the three months ended January 31, 2007,
total revenues decreased 7% to $4,055,000 compared to $4,365,000 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, decreased 26% to $6.03 per Mcf and oil price realizations
decreased 8% to $52.06 per barrel. The net effect of these price changes
was to decrease oil and gas sales by $989,000. For the three months
ended January 31, 2007, the company’s gas equivalent production
increased 21% resulting in an oil and gas sales increase of $678,000.
Investment and other income was $247,000 for the first quarter of 2007
and $245,000 for 2006.
For the three months ended January 31, 2007,
total costs and expenses rose 7% to $2,155,000 compared to $2,011,000
for the comparable period in 2006. Oil and gas production expenses
decreased 9% due to a decrease in production taxes and lease operating
expense. The decrease in production taxes is due to lower oil and gas
revenue and hedging gains of $396,000 on which there is no production
tax. Depreciation, depletion and amortization (DD&A) rose 30%
primarily due to an increase in the amortizable full cost pool and
increased production. A change in estimated salvage values resulted in a
decrease in DD&A of approximately $65,000. General and
administrative expenses increased 7%. Interest expense relates to the
exclusive license agreement note payment. The effective tax rate was
28.2% and 28% for the 2007 and 2006 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
17
Table of Contents
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 company’s 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 company’s
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 company’s 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 company’s 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 company’s
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. SFAS
No. 143, Accounting for Asset Retirement Obligations requires
that the company estimate the future cost of asset retirement
obligations, discount that cost to its present value, and record a
corresponding asset and liability in its Consolidated Balance Sheets.
The values ultimately derived are based on many significant estimates,
including future abandonment costs, inflation, 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 separate 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 company’s 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.
18
Table of Contents
The company’s operating revenue is comprised of
contractually based payments made to the company, as operator, to drill
and supervise oil and gas wells. The company reports these revenues
gross for the amounts received before taking into account related costs
which are recorded as separate expenses. Revenue is recorded in the
month it is earned. The company views providing these services as a way
to control the operations on wells in which it owns an interest.
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 company’s hedging activities.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with the Securities Exchange Act of
1934 Rules 13a-15 and 15d-15, the Company carried out an
evaluation, under the supervision and with the participation of
management, including the Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the Company’s disclosure controls and
procedures as of the end of the period covered by this report. Based on
that evaluation the Chief Executive Officer and Chief Financial Officer
concluded that the Company’s disclosure controls and procedures were
effective as of January 31, 2007 to provide reasonable assurance
that information required to be disclosed in the Company’s reports
filed or submitted under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the
Securities and Exchange Commission’s rules and forms. The Company’s
disclosure controls and procedures include controls and procedures
designed to ensure that information required to be disclosed in reports
filed or submitted under the Exchange Act is accumulated and
communicated to the Company’s management, including the Chief
Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.
There has been no change in the Company’s
internal control over financial reporting that occurred during the three
months ended January 31, 2007 that has materially affected, or is
reasonably likely to materially affect, the Company’s internal control
over financial reporting.
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk
factors previously disclosed in the company’s Annual Report on Form
10-K for the fiscal year ended October 31, 2006.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES
AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
19
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 pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended | ||
| 31.2 | Certification by Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended | ||
| 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) |
20
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/ David E. Dennis | |||
| David E. Dennis | ||||
| Chief Financial
Officer (Principal Financial and Accounting Officer) |
||||
Date: March 12, 2007
21
Table of Contents
Exhibit Index
| 31.1 | Certification by Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended | ||
| 31.2 | Certification by Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended | ||
| 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) |
Exhibit 31.1
CERTIFICATION PURSUANT TO RULE 15D-14 OF THE
SECURITIES
EXCHANGE ACT OF 1934, AS AMENDED AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
EXCHANGE ACT OF 1934, AS AMENDED AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, James T. Huffman, Chief Executive Officer of
CREDO Petroleum Corporation, certify that:
| 1. | I have reviewed this quarterly report on Form 10-Q of CREDO Petroleum Corporation; |
| 2. | Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such controls and procedures to be established and maintained, for the registrant and have; |
| a) | Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
| b) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
| c) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s independent registered public accounting firm and the audit committee of registrant’s board of directors (or persons performing the equivalent function): |
| a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and | ||
| b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: March 12, 2007
|
/s/ James T. Huffman
|
||
|
|
||
|
President and Chief
Executive Officer
|
Exhibit 31.2
CERTIFICATION PURSUANT TO RULE 15D-14 OF THE
SECURITIES
EXCHANGE ACT OF 1934, AS AMENDED AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
EXCHANGE ACT OF 1934, AS AMENDED AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, David E. Dennis, Chief Financial Officer of
CREDO Petroleum Corporation, certify that:
| 1. | I have reviewed this quarterly report on Form 10-Q of CREDO Petroleum Corporation; |
| 2. | Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such controls and procedures to be established and maintained, for the Registrant and have; |
| a) | Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
| b) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
| c) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s independent registered public accounting firm and the audit committee of registrant’s board of directors (or persons performing the equivalent function): |
| a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and | ||
| b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: March 12, 2007
|
/s/ David E. Dennis
|
||
|
|
||
|
Chief Financial
Officer
|
Exhibit 32.1
Certification of Chief Executive Officer and
Chief Financial Officer of
CREDO Petroleum Corporation (Pursuant To 18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)
CREDO Petroleum Corporation (Pursuant To 18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)
In connection with this Quarterly Report of CREDO
Petroleum Corporation (the “company”) on Form 10-Q for the period
ending January 31, 2007 as filed with the Securities and Exchange
Commission on the date hereof (the “Report”), we, James T. Huffman,
President and Chief Executive Officer of the company, and David E.
Dennis, Chief Financial Officer of the company, each hereby certify,
pursuant to 18 U.S.C., § 1350, as adopted pursuant to § 906 of the
Sarbanes-Oxley Act of 2002, that to our knowledge:
| 1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company. |
March 12, 2007
|
/s/ James T. Huffman
|
||
|
|
||
|
President and Chief Executive Officer
|
|
/s/ David E. Dennis
|
||
|
|
||
|
Chief Financial Officer
|
A signed original of this written statement
required by Section 906 of the Sarbanes-Oxley Act of 2002 has been
provided to CREDO Petroleum Corporation and will be retained by CREDO
Petroleum Corporation and furnished to the Securities and Exchange
Commission upon request.
End of Filing
©2000-2005 CREDO Petroleum Corporation. All rights
reserved. |
