|
|
|
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
For the quarterly period ended July 31, 2006
For the transition period from
to
Commission File Number: 0-8877
CREDO
PETROLEUM CORPORATION
(Exact name of registrant as specified in its
charter)
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 o No ž
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 o
Non-accelerated filer ž
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.
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly Report on Form 10-Q For the Period
Ended July 31, 2006
TABLE OF CONTENTS
The terms “CREDO”, “Company”, “we”,
“our”, and “us” refer to CREDO Petroleum Corporation and its
subsidiaries unless the context suggests otherwise.
2
Table of Contents
PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
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 (Loss)
(Unaudited)
For the Nine Months Ended July 31, 2006
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
Table of Contents
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To Consolidated Financial Statements (Unaudited)
July 31, 2006
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,
2005.
The company effected a three-for-two stock split in
the third fiscal quarter of 2005. All share and per share amounts
discussed and disclosed in this Quarterly Report on Form 10-Q reflect the
effect of that stock split.
Certain financial statement amounts have been
reclassified to conform to the presentation used for the 2006 periods.
Effective with the second quarter of 2006, the company has reclassified
reimbursed overhead from operating revenue to general and administrative
expense. For the nine months ended July 31, 2006 and 2005, the
reclassified amounts were $548,000 and $487,000, respectively and for the
three months ended July 31, 2006 and 2005, the reclassified amounts
were $193,000 and $164,000 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.
3. STOCK-BASED COMPENSATION
The company currently has one stock-based employee
compensation 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, 2005. Prior to November 1, 2005, the
company accounted for this plan under the recognition and measurement
provisions of Accounting Principles Board (“APB”) Opinion No. 25,
Accounting for Stock Issued to Employees, and related interpretations, as
permitted by Statement of Financial Accounting Standards (“SFAS”) No. 123,
Accounting for Stock-Based Compensation. No stock-based employee
compensation expense was recognized in the company’s Consolidated
Statement of Operations prior to November 1, 2005, as all options
granted under the company’s stock-based compensation plan had an
exercise price equal to the market value of the underlying common stock on
the date of grant. 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. The cumulative effect of this restatement
was an increase of $1,447,000 to capital in excess of par value and a
decrease to retained earnings in the same amount. For the nine months
ended July 31, 2006 and 2005, the company recognized compensation
expense related to its stock option plan of $165,000 and $217,000,
respectively and for the three months ended July 31, 2006 and 2005,
the company recognized compensation
7
Table of Contents
expense of $46,000 and $69,000, respectively. The
company has not made any option grants during fiscal 2006. The fair value
of the 33,750 options granted during the nine months ended July 31,
2005 was estimated as of the grant date using the Black-Scholes option
pricing model with the following assumptions: volatility, 48%; expected
option term, 5 years; risk-free interest rate, 3.7% 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.
Plan activity for the nine months ended July 31,
2006 is set forth below and has been adjusted for the 3-for-2 stock splits
in fiscal 2005 and 2004 and the 20% stock dividend in 2003.
The following table summarizes information about
stock options currently outstanding and exercisable at July 31, 2006:
Total estimated unrecognized compensation cost from
unvested stock options as of July 31, 2006 was approximately
$137,000, which is expected to be recognized over an average period of
approximately 0.83 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, 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. 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.
Such hedges, which are accounted for as cash flow hedges, do not exceed
estimated production volumes, where applicable, 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.
8
Table of Contents
The company recognizes all derivatives (consisting
solely of cash flow hedges) on the 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 (Loss) on the Consolidated Balance Sheets and then are reclassified
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.
Hedging gains and losses are recognized as
adjustments to gas sales as the hedged product is produced. The company
had after tax hedging losses of $190,000 in the first nine months of 2006
and after tax hedging losses of $207,000 for the same period in 2005. Any
hedge ineffectiveness, which was not material for the first nine months of
2006 and 2005, is immediately recognized in gas sales. The company had no
open hedge positions at July 31, 2006.
Subsequent to third quarter end 2006, the company
entered into hedge transactions totaling 80,000 MMbtu for the quarter
ending January 31, 2007, 230,000 MMbtu for the quarter ending April 30,
2007 and 240,000 MMbtu for the quarter ending July 31, 2007. These
hedges are intended to cover between 20% and 50% of the company’s
current production base without taking into consideration production
additions during the interim periods. The hedges are indexed to PEPL with
a weighted average contract price of $9.59 for the quarter ending January 31,
2006, $8.25 for the quarter ending April 30, 2007 and $6.85 for the
quarter ending July 31, 2007. Individual month basis differentials to
the NYMEX and Henry Hub range from minus $.90 to minus $1.46.
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 $2,000,000 with interest calculated at the prime rate. The
facility is unsecured and has affirmative covenants which 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. The hedging line of credit expires on
October 31, 2006.
5. COMPREHENSIVE INCOME
Comprehensive income includes all changes in equity
during a period except those resulting from investments by owners and
distributions to owners. The components of comprehensive income for the
three and nine months ended July 31, 2006 and 2005 are as follows:
9
Table of Contents
6. EARNINGS PER SHARE
The company’s calculation of earnings per share of
common stock is as follows:
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. COMPRESSOR AND TUBULAR INVENTORY
Compressor and tubular inventory are finished goods,
recorded at cost, which are expected to be used in the future development
of certain of the company’s oil and gas properties. The company has
classified this amount as a long-term asset because the compressors and
tubulars are not held for re-sale and the cost, net of amounts billed to
joint interest owners in the normal course of business, will eventually be
included in evaluated properties.
10
Table of Contents
9. UNEVALUATED OIL AND GAS PROPERTIES
Costs directly associated with the acquisition and
evaluation of unproved properties are excluded from the amortization
computation until they are evaluated. The following table shows, by
category of cost and date incurred, the unevaluated oil and gas property
costs excluded from the amortization computation as of July 31, 2006:
10. COMMITMENTS
The company had no material outstanding commitments
at July 31, 2006.
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:
11
Table of Contents
LIQUIDITY AND CAPITAL RESOURCES
At July 31, 2006, working capital was
$8,920,000, compared to $7,697,000 at July 31, 2005. For the nine
months ended July 31, 2006, net cash provided by operating activities
increased $4,008,000, or 75%, to $9,349,000 when compared to net cash
provided by operating activities of $5,341,000 for the same period in
2005. This increase is primarily the result of increases in net income and
other non-cash items of $1,920,000; a net increase of $363,000 in short
term investments in 2006 versus a net decrease in short term investments
of $859,000 in 2005 which resulted in a net decrease in cash provided by
operating activities of $1,222,000 between the two periods; a net increase
in cash provided by operating activities as a result of changes in accrued
oil and gas sales, trade receivables and other current assets of
$2,105,000; and a net increase in cash provided by operating activities as
a result of changes in accounts payable and income taxes payable of
$1,347,000. For the nine months ended July 31, 2006 and 2005, net
cash used in investing activities was $8,256,000 and $5,144,000,
respectively. Investing activities primarily included oil and gas
exploration and development expenditures, including Calliope, totaling
$9,054,000 and $5,064,000, respectively.
The average return on the company’s investments
for the nine months ended July 31, 2006 and 2005 was 6.0% and 3.1%,
respectively. At July 31, 2006, approximately 55% 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 July 31, 2006, 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”) increased to
$8,711,000 for the nine months ended July 31, 2006 from $6,284,000
for the nine months ended July 31, 2005. 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:
12
Table of Contents
OFF-BALANCE SHEET FINANCING
The company has no off-balance sheet financing
arrangements at July 31, 2006.
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. 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 the effect of hedging
transactions.
OPERATIONS
During the third fiscal quarter the company
continued to focus on its two core projects — natural gas drilling and
application of its patented Calliope Gas Recovery System.
As discussed below, the company recently 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 and into north-central Kansas through an exploration
program using 3-D seismic to define Lansing-Kansas City oil prospects in
Graham and Sheridan counties.
Also as discussed below, the company recently
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.
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
13
Table of Contents
drilling success rate. Calliope results are
primarily dependent on the timing and volume of Calliope installations
available to the company.
The company will continue to actively pursue adding
reserves through its two core projects in fiscal 2006 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 liquid lift 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 Shelf —The company
currently drills primarily on its 60,000 gross acre inventory located
along the northern shelf of the Anadarko Basin where it has drilled about
70 wells. The wells targeted the Morrow, Oswego and Chester formations
between 7,000 and 10,000 feet. A substantial number of additional wells
are anticipated for the area.
Drilling is not restricted to the northern Anadarko
shelf acreage. The company is generating prospects elsewhere in the
Anadarko Basin, the Oklahoma Panhandle, north-central Oklahoma,
north-central Kansas and South Texas. For the nine months ended July 31,
2006, the company drilled 11 wells on its northern Anadarko Shelf acreage.
During fiscal 2006, 4 wells have been drilled on the
company’s 5,760 gross acre Glacier Prospect. The most important of these
wells are the Garnet State and Scarlet State drilled on the north portion
of the prospect. Both wells encountered excellent Morrow sands at about
7,500 feet, and are producing at high rates for the area. Combined
production for the wells has exceeded 1.1 Bcf since they were placed on
production in February and June 2006, respectively. The wells are
currently producing at a combined daily rate of approximately 7.4 MMcf.
Previously, the company drilled two other high rate wells on the Glacier
prospect, both of which had limited reservoir extent but proved the
presence of high quality sands on the prospect. A number of additional
wells are expected to be drilled on the prospect with two to three more
wells scheduled during calendar 2006. The company owns a 57% working
interest in the Garnet State and a 55% interest in the Scarlet State, and
is the operator of both wells and the prospect.
Drilling is also continuing on the company’s 2,560
gross acre Buffalo Creek Prospect. In February 2006 the company completed
the 6,900-foot Lauer #1-21 well as the third producing oil well on the
prospect. In anticipation of additional drilling, a 3-D seismic program is
currently underway on the Buffalo Creek Prospect to identify additional
drilling locations. The company owns a 31% working interest.
A second well has recently been drilled on the
company’s 1,280 gross acre Saddle Prospect which appears to be
productive and is awaiting pipeline connection. The company owns a 49%
working interest and is the operator. Additional wells are scheduled for
the prospect.
Drilling Program Expansion and Diversification —During
fiscal 2005, 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 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
14
Table of Contents
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 —During 2005, the company
commenced a new exploration project in South Texas. The project has far
greater per well production and reserve potential than the company’s
core drilling projects, and provides the opportunity to materially
increase the company’s reserves. However, it also carries a much higher
cost and greater risk.
In return for a 37.5% interest, the company
committed $1,500,000 for prospect generation and leasing costs. The
company has the option to participate in each prospect for all, or a
portion, of its interest. If the company does not participate for the full
interest, the remaining amount will be sold to industry participants on a
promoted basis.
The project is 3-D seismic driven and focuses on the
Vicksburg, Frio and Queen City sands in Hidalgo and Jim Hogg Counties
ranging in depth from 7,500 to 15,000 feet. Both the cost and the
potential of this project far exceed anything the company has done before.
Leasing is complete on four prospects. The first well drilled in the
project was the 10,500-foot Peery #1 located on the Robertson Prospect in
Hidalgo County. The well targeted the Frio sands. Multiple up-hole sands
are currently being tested for commercial production. The company owns a
37.5% interest in the well. The 8/8ths cost of the well is expected to
range between $3,500,000 and $4,000,000.
The next South Texas well scheduled for drilling is
the 12,500-foot Rosa Amarilla well on the Esparza Prospect. The Rosa
Amarilla well is a step-out from excellent production. The company
currently owns a 37.5% working interest. The estimated cost of field
services has almost doubled since the prospect was originated with the
completed well cost now estimated between $6,000,000 and $7,000,000.
Although the well has very high reserve potential, the company is
presently considering significantly reducing its interest in the well to
mitigate its risk exposure to high drilling costs and the availability of
quality field services.
The remaining two leased prospects consist of
development drilling on the Santa Ana Prospect and a wildcat test on the
West Mestena Prospect. The company currently owns a 37.5% working interest
in both prospects. The prospects will be drilled as rigs become available.
The company is considering the amount of interest to retain in the
prospects in view of rapidly escalating drilling costs and the
availability of quality field services.
North-Central Kansas —During 2005, the
company took another significant step to diversify its exploration by
acquiring a 30% interest in 20,000 gross acres along the Central Kansas
Uplift. Drilling targets the Lansing-Kansas City formation at 4,000 feet.
This project is expected to be an excellent supplement to the company’s
Oklahoma drilling. Together, the Oklahoma and Kansas drilling programs are
expected to replace the company’s production in each of the next three
to five years, and to provide moderate growth in both production and
reserves.
The company’s acreage is located in a prolific
producing area where 3-D seismic has recently proven to be an effective
exploration tool. Higher oil prices have justified using 3-D seismic
technology to locate undrilled structures that are very difficult to find
with old technology.
The Kansas 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.
In north-central Kansas, approximately 28 square
miles of 3-D seismic have been shot and evaluated. At least five
exploratory wells will be drilled. Completed costs for individual wells
are estimated to be approximately $300,000.
15
Table of Contents
The first two wells confirmed the seismic
interpretation and encountered multiple sands. However, the sands were
either tight or wet, resulting in dry holes. As with its other drilling
projects, the company expects successful results to occur unevenly over
time. Drilling is expected on approximately 30 prospects.
Calliope Drilling Project —See discussion
under Calliope Gas Recovery Technology below.
Calliope Gas Recovery Technology.
The company owns the exclusive right to a patented
technology known as the Calliope Gas Recovery System. Calliope can achieve
substantially lower flowing bottom hole pressure than conventional
production methods because it does not rely on reservoir pressure to lift
liquids. 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
has recently begun implementing strategies designed to expand the
population of wells on which Calliope should be installed.
Realizing Calliope’s value continues to be a top
priority of the company. 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.
Purchasing Calliope Candidate Wells —Calliope
systems are currently installed on 18 wells that are owned and operated by
CREDO. These wells 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.
Initial 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.
During 2005, the company successfully expanded its
Calliope operations into Texas 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 an office
in the region to focus exclusively on Calliope.
In southwest Texas, the company successfully
installed two 11,000-foot prototype Calliope installations which once
again broadened Calliope’s down-hole application, successfully lifting
several times more fluid volume than Calliope has previously lifted from
the company’s Oklahoma wells. Calliope immediately returned the wells to
economic production making up to 210 Mcfd. In central Louisiana, the
company recently installed Calliope on a 13,800-foot well. Calliope
immediately restored the well to economic production making 320 Mcfd. Each
of these Calliope installations have created wells that are once again
highly economic.
The company currently has two Calliope candidate
wells that are awaiting Calliope installations, both located in Oklahoma.
If the company experiences no significant procurement delays, it expects
that the installations will be completed in 2006.
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.
16
Table of Contents
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 believes that it
will achieve a breakthrough in the joint venture area.
Calliope Drilling Project —The company has
entered into a joint venture with Redman Energy Holdings II, L.P. to drill
wells for the purpose of using its patented Calliope Gas Recovery System
to develop stranded gas reserves. Redman Energy Holdings is an affiliate
of Redman Energy Corporation, a privately-held, Houston-based E&P
company. Redman is affiliated with Natural Gas Partners, a highly
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 fluid lift technologies 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. The company believes this project is
a target-rich opportunity for the company to expand its Calliope
operations. Wells are expected to range in depth from 8,000 to 12,000
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 1,000 Mcf per day. Average drilling economics are expected to
include payouts of less than two years and internal rates of return from
50% to 100%.
The company believes that the ability to configure
larger casing and tubular sizes in newly drilled wells will maximize
Calliope’s potential. This is expected to substantially improve reserve
recoveries and production rates compared to installing Calliope on
existing wells.
In this Quarterly Report on Form 10-Q, the company
is providing the following information to enhance and supplement the
disclosures regarding Reserve Replacement Percentage and Finding Cost per
Mcfe which are contained in its Annual Report on Form 10-K for the year
ended October 31, 2005. The company will eliminate disclosure of
Reserve Replacement Percentage and Finding Cost per Mcfe from its 1933 and
1934 Act filings, beginning with its Annual Report on Form 10-K for the
fiscal year ending October 31, 2006, because the information is
generally available from independent sources.
The company previously disclosed in its most recent
Annual Report on Form 10-K that, during the fiscal year ended October 31,
2005 the company replaced 106% of the reserves produced in fiscal 2005.
This reserve replacement percentage is derived directly from the line
items disclosed in the reconciliation of beginning and ending proved
reserve quantities contained in Footnote 8 to the Consolidated Financial
Statements, Supplementary Oil and Gas Information, page 42 of the
company’s Annual Report on Form 10-K. The table
17
Table of Contents
below shows the calculation used by the company at
October 31, 2005. Oil is converted to gas for the calculation of Mcfe
(thousand cubic feet equivalent) on the basis of one barrel of oil is
equal to six Mcf of gas.
The company previously disclosed in its Annual
Report on Form 10-K for the fiscal year ended October 31, 2005 that
its finding cost for the period was $2.73 per Mcfe excluding start-up
costs in South Texas and north-central Kansas. The company believes that
excluding these start-up costs provides a meaningful matching of current
costs with current reserve additions. Finding costs are derived from the
line item Total Including Asset Retirement Obligation disclosed in the
table identifying Acquisition, Exploration and Development Costs Incurred
contained in Footnote 8 to the Consolidated Financial Statements,
Supplementary Oil and Gas Information, page 41 of the company’s Annual
Report on Form 10-K and from the line items disclosed in the
reconciliation of beginning and ending proved reserve quantities contained
in Footnote 8 to the Consolidated Financial Statements, Supplementary Oil
and Gas Information, page 42 of the company’s Annual Report on Form
10-K. The table below shows the calculation used by the company at October 31,
2005.
Proved reserve additions, including the proved
developed and proved undeveloped portions can be calculated from the
information in Footnote 8 to the Consolidated Financial Statements,
Supplementary Oil and Gas Information, page 42 of the company’s Annual
Report on Form 10-K. As is stated in Management’s Discussion and
Analysis of Financial Condition and Results of Operations, Oil and Gas
Activities, Drilling Activities, and Calliope Gas Recovery System on pages
19 through 22 of the company’s Annual Report on Form 10-K, these proved
reserve additions for the fiscal year ended October 31, 2005 were
primarily the result of activity on the company’s two core projects,
drilling along the shelf of the Northern Anadarko Basin in northwest
Oklahoma and application of the company’s patented liquid lift system on
low pressure gas wells.
The company uses only proved reserves to calculate
the reserve replacement percentage and finding costs described above and
does not include any proved reserves attributable to consolidated entities
or investments accounted for using the equity method.
18
Table of Contents
The finding costs and production replacement
measures are used by the company as one way of measuring the company’s
performance and comparing it to that of its competitors and the industry.
The calculation of both of these performance measures is based, in part,
on estimated proved oil and gas reserve quantities. As is more fully
described under Item 2., Properties, Significant Properties,
Estimated Proved Oil and Gas reserves, and Future Net Revenues on pages 11
and 12 of the company’s Annual Report on Form 10-K for the fiscal year
ended October 31, 2005, estimates of reserve quantities must be
viewed as being subject to significant change as more data about the
company’s properties becomes available. Additionally, both of these
performance measures are historical in nature and are calculated as of a
specific date, and may not be indicative of the company’s future
performance.
The company’s success depends primarily on
locating and producing new reserves, the level of production from existing
wells, and prices of oil and natural gas. Production from the company’s
oil and gas properties declines over time. In order to maintain current
production rates the company must locate and develop or acquire new oil
and gas reserves to replace those being depleted by production. In
addition, competition for oil and gas leases, oil field services, and
producing oil and gas properties is intense and many of the company’s
competitors have financial and other resources substantially greater than
those available to it. Without success on its core projects, the
company’s reserves, production and revenues will decline rapidly.
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.
Results of Operations
Nine Months Ended July 31, 2006 Compared to
Nine Months Ended July 31, 2005
For the nine months ended July 31, 2006, total
revenues increased 36% to $12,255,000 compared to $8,986,000 last year. As
the oil and gas price/volume table on page 13 shows, total gas price
realizations, which reflect hedging transactions, increased 13% to $6.46
per Mcf and oil price realizations increased 30% to $61.74 per barrel. The
net effect of these price changes was to increase oil and gas sales by
$1,400,000. For the nine months ended July 31, 2006, the company’s
gas equivalent production increased 16%. The effect of the volume change
was to increase oil and gas sales by $1,624,000. Investment income and
other increased $245,000 primarily due to improved performance of the
company’s investments.
For the nine months ended July 31, 2006, total
costs and expenses rose 41% to $6,139,000 compared to $4,340,000 for the
comparable period in 2005. Oil and gas production expenses increased 36%
due primarily to an increase in production taxes and lease operating
expense. Production taxes increased during the current period primarily
due to increased production revenue and the company’s receipt of a
production tax rebate during the 2005 period. The increase in lease
operating expense is primarily due to an increase in the number of wells
owned by the company and from additional workover expenses incurred during
the 2006 period. Depreciation, depletion and amortization (“DD&A”)
increased primarily due to increased production and an increase in the
amortizable cost base. General and administrative expenses increased
primarily due to costs associated with compliance with Sarbanes-Oxley
regulations. Interest expense relates to the exclusive license agreement
note payment. The effective tax rate was 28.5% for the 2006 period and
28.0% for the 2005 period.
19
Table of Contents
Three Months Ended July 31, 2006 Compared to
Three Months Ended July 31, 2005
For the three months ended July 31, 2006, total
revenues increased 13% to $3,969,000 compared to $3,501,000 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 9% to $5.70 per Mcf and oil price realizations increased 17% to
$65.80 per barrel. The net effect of these price changes was to decrease
oil and gas sales by $183,000. For the three months ended July 31,
2006, the company’s gas equivalent production increased 22% resulting in
an oil and gas sales increase of $752,000. Investment and other income
declined $102,000 primarily due to poorer performance of the company’s
investments, compared to last year.
For the three months ended July 31, 2006, total
costs and expenses rose 35% to $2,170,000 compared to $1,609,000 for the
comparable period in 2005. Oil and gas production expenses increased due
primarily to an increase in production taxes and lease operating expense.
DD&A rose primarily due to increased production and an increase in the
amortizable cost base. General and administrative expenses increased
primarily due to costs associated with compliance with Sarbanes-Oxley
regulations. Interest expense relates to the exclusive license agreement
note payment. The effective tax rate was 28.5% for the 2006 period and
28.0% for the 2005 period.
SIGNIFICANT ACCOUNTING POLICIES
The company believes the following accounting
policies and estimates are critical in the preparation of its consolidated
financial statements: the carrying value of its oil and natural gas
properties, the accounting for oil and gas reserves, and the estimate of
its asset retirement obligations.
OIL AND GAS PROPERTIES. The company
uses the full cost method of accounting for costs related to its oil and
natural gas properties. Capitalized costs included in the full cost pool
are depleted on an aggregate basis using the units-of-production method.
Depreciation, depletion and amortization is a significant component of oil
and natural gas properties. A change in proved reserves without a
corresponding change in capitalized costs will cause the depletion rate to
increase or decrease.
Both the volume of proved reserves and any estimated
future expenditures used for the depletion calculation are based on
estimates such as those described under “Oil and Gas Reserves” below.
The capitalized costs in the full cost pool are
subject to a quarterly ceiling test that limits such pooled costs to the
aggregate of the present value of future net revenues attributable to
proved oil and natural gas reserves discounted at 10 percent plus the
lower of cost or market value of unproved properties less any associated
tax effects. If such capitalized costs exceed the ceiling, the company
will record a write-down to the extent of such excess as a non-cash charge
to earnings. Any such write-down will reduce earnings in the period of
occurrence and result in lower depreciation and depletion in future
periods. A write-down may not be reversed in future periods, even though
higher oil and natural gas prices may subsequently increase the ceiling.
The company has made only one ceiling write-down in
its 28-year history. That write down was made in 1986 after oil prices
fell 51% and natural gas prices fell 45% between fiscal year end 1985 and
1986.
Changes in oil and natural gas prices have
historically had the most significant impact on the 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.
20
Table of Contents
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.
At October 31, 2005, the date of the
company’s most recent reserve report, the company’s reserves, and
reserve values, were concentrated in 54 properties (“Significant
Properties”). Some of the Significant Properties were individual wells
and others were multi-well properties. The Significant Properties
represented 28% of the company’s total properties but a disproportionate
76% of the discounted value (at 10%) of the company’s reserves.
Individual wells on which the company’s patented liquid lift system is
installed comprise 22% of the Significant Properties and represented 32%
of the discounted reserve value of such properties. Relatively new wells
comprised 22% of the Significant Properties and represented 24% of the
discounted value of such properties.
Estimates of reserve quantities and values for
certain Significant Properties must be viewed as being subject to
significant change as more data about the properties becomes available.
Such properties include wells with limited production histories and
properties with proved undeveloped or proved non-producing reserves. In
addition, the company’s patented liquid lift system is generally
installed on mature wells. As such, they contain older down-hole equipment
that is more subject to failure than new equipment. The failure of such
equipment, particularly casing, can result in complete loss of a well.
Historically, performance of the company’s wells has not caused
significant revisions in its proved reserves.
The following table sets forth, as of October 31
of the indicated year, information regarding the company’s proved
reserves which is based on the assumptions set forth in Note (8) to
the company’s Consolidated Financial Statements on Form 10-K for the
year ended October 31, 2005 where additional reserve information is
provided. The average price used to calculate estimated future net
revenues was $55.59, $50.43 and $28.64 per barrel of oil and $10.26,
$5.84, and $3.99 per Mcf of gas as of October 31, 2005, 2004, and
2003, respectively. Amounts do not include estimates of future Federal and
state income taxes.
Estimated Future Net Revenues Discounted at 10% is
not a GAAP measure of operating performance. Because the company drills
new wells on an ongoing basis, and plans to continue to do so in the
future, it expects to continue to generate deferred income taxes which are
not reasonably expected to be paid in the near term. This pre-tax, non-GAAP
measure is used by the company in connection with estimating funds
expected to be available in the future for drilling and other operating
activities. The company believes that this performance measure may also be
useful to investors for the same purpose. The difference between this
measure and the Standardized Measure of Discounted Future Net Cash Flows
From Reserves is that this measure excludes future income tax expense and
the effect of the 10% discount factor on future income tax expense. In
this Form 10-Q, the company is providing the following information to
enhance and supplement
21
Table of Contents
the disclosures contained in it Form 10-K for the
year ended October 31, 2005. The following table provides a
reconciliation of Estimated Future Net Revenues Discounted at 10% to the
Standardized Measure of Discounted Future Net Cash Flows From Reserves as
shown in Note 8 to the company’s Consolidated Financial Statements on
Form 10-K for the year ended October 31, 2005.
Price changes will affect the economic lives of oil
and gas properties and, therefore, price changes may cause reserve
revisions. Price changes have not caused significant proved reserve
revisions by the company except in 1986 when a 51% decline in oil prices
and a 45% decline in natural gas prices resulted in an 8.7% reduction in
estimated proved reserves. Based upon this historical experience, the
company does not believe its reserve estimates are particularly sensitive
to prices changes within historical ranges.
One measure of the life of the company’s proved
reserves can be calculated by dividing proved reserves at a fiscal year
end by production for that fiscal year. This measure yields an average
reserve life of nine years at October 31, 2005. Since this measure is
an average, by definition, some of the company’s properties will have a
life shorter than the average and some will have a life longer than the
average. The expected economic lives of the company’s properties may
vary widely depending on, among other things, the size and quality,
natural gas and oil prices, possible curtailments in consumption by
purchasers, and changes in governmental regulations or taxation. As a
result, the company’s actual future net cash flows from proved reserves
could be materially different from its estimates.
The company is not aware of any material adverse
issues related to its reserves regarding regulatory approval, the
availability of additional development capital, or the installation of
additional infrastructure.
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 oil and gas production expenses. Revenue is recorded in
the month production is delivered to the purchaser at which time title
changes hands. The company makes estimates of the amount of production
delivered to purchasers and the prices it will receive. The company uses
its knowledge of its properties; their historical performance; the
anticipated effect of weather conditions during the month of production;
NYMEX and local spot market prices; and other factors as the basis for
these estimates. Variances between estimates and the actual amounts
received are recorded when payment is received.
22
Table of Contents
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.
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
The effectiveness of our or any system of disclosure
controls and procedures is subject to certain limitations, including the
exercise of judgment in designing, implementing and evaluating the
controls and procedures, the assumptions used in identifying the
likelihood of future events, and the inability to eliminate misconduct
completely. As a result, there can be no assurance that our disclosure
controls and procedures will detect all errors or fraud. By their nature,
our, or any, system of disclosure controls and procedures can provide only
reasonable assurance regarding management’s control objectives.
Under the supervision and with the participation of
our management, including our Chief Executive Officer and Chief Financial
Officer, we evaluated the design and operation of our disclosure controls
and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the
Securities Exchange Act of 1934, or the “Exchange Act”) as of July 31,
2006. On the basis of this review, our management, including our Chief
Executive Officer and Chief Financial Officer, concluded that our
disclosure controls and procedures are designed, and are effective, to
give reasonable assurance that the information required to be disclosed by
us in reports that we file under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the rules and
forms of the SEC and to ensure that information required to be disclosed
in the reports filed or submitted under the Exchange Act is accumulated
and communicated to our management, including our Chief Executive Officer
and Chief Financial Officer, in a manner that allows timely decisions
regarding required disclosure. There were no changes in the company’s
internal controls over financial reporting that occurred in the third
fiscal quarter of 2006 that materially affected or were reasonably likely
to materially affect, its 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, 2005.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES
AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
23
Table of Contents
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:
24
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.
25
Table of Contents
Exhibit Index
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
I, James T. Huffman, Chief Executive Officer of
CREDO Petroleum Corporation, certify that:
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
I, David E. Dennis, Chief Financial Officer of CREDO
Petroleum Corporation, certify that:
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)
In connection with this Quarterly Report of CREDO
Petroleum Corporation (the “company”) on Form 10-Q for the period
ending July 31, 2006 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:
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||