UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________________________________________
FORM 10-KSB
_______________________________________________________________
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
--- SECURITIES ACT OF 1934
For The Fiscal Year Ended October 31, 2003
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF SECURITIES EXCHANGE ACT OF 1934
For the transition period ____________ to _____________
Commission File Number 0-8877
_______________________________________________________________
CREDO PETROLEUM CORPORATION
_______________________________________________________________
(Exact name of registrant as specified in charter)
Colorado 84-0772991
(State of incorporation) (I.R.S. employer identification number)
1801 Broadway, Suite 900, Denver, Colorado 80202-3837
(Address of principal executive offices and zip code)
Registrant's telephone number, including area code:
(303) 297-2200
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.10 Par Value
4,014,000 Shares Outstanding, Net of Treasury Stock,
at the Close of Business on December 31, 2003
(Title of class and shares outstanding)
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-B is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB. X
-----
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports) and (2) has been subject to such filing
requirements for the past 90 days. Yes X No _____
----- -----
Issuer's revenues for its most recent fiscal year: $8,491,000
As of December 31, 2003, the aggregate market value of common
stock held by non-affiliates of the registrant was approximately
$57,334,000.
DOCUMENTS INCORPORATED BY REFERENCE into Part III hereof - Proxy
Statement to be filed with the Commission in connection with the
company's 2003 Annual Meeting.
Transitional Small Business Format (Check One): Yes No X
--- ---
PART I.
ITEM 1. BUSINESS
General
CREDO Petroleum Corporation ("CREDO") was incorporated in
Colorado in 1978. CREDO and its wholly owned subsidiaries, SECO
Energy Corporation and United Oil Corporation ("SECO", "United"
and collectively "the company"), are Denver, Colorado based
independent oil and gas companies which engage primarily in oil
and gas exploration, development and production activities in the
Mid-Continent region of the United States. The company operates
in eight states and has ten employees. CREDO is an active
operator in Kansas, Wyoming, Colorado and Utah. United is an
active operator doing business exclusively in Oklahoma, and SECO
primarily owns royalty interests in the Rocky Mountain region.
References to years as used in this report indicate fiscal years
ended October 31.
Business Activities
The company focuses on two core projects--natural gas drilling in
the Northern Anadarko Basin of Oklahoma and recovering standard
gas from low-pressure reservoirs using its patented Calliope Gas
Recovery System ("Calliope").
Drilling operations are concentrated on medium depth properties
generally ranging from 7,000 to 10,000 feet. The company enters
into various types of cost sharing arrangements with industry
participants on most of its operating activities.
The company acts as "operator" of approximately 94 wells pursuant
to standard industry Operating Agreements, and it owns working
and royalty interests in approximately 122 wells which are
operated by outside parties. In addition, the company is general
partner of three private limited partnerships. The Partnerships
are in the production stage of operations and their results are
proportionately consolidated in the company's financial
statements.
Over the past five years, the company has participated in
developing, testing, refining, and patenting Calliope. Calliope
efficiently lifts fluids from wellbores using pressure
differentials, thus allowing gas previously trapped by fluid
build-up in the wellbore to flow to the surface. The company
believes Calliope is clearly different from all other fluid lift
technologies because it does not rely on bottom-hole pressure and
has only one down-hole moving part. Calliope is primarily
applicable to mature natural gas wells in low pressure, gas
expansion reservoirs at depths below 8,000 feet. To date,
Calliope has not required external capital. During 2000, the
company purchased an unrestricted, exclusive license to the
technology. The term of the license is 10 years, and it can be
extended an additional five years to cover the entire 15 year
term of the patent. At year end, Calliope was installed on
13 wells ranging at depth from 6,500 feet to 18,400 feet. The
company believes it has proven Calliope's economic viability and
flexibility over a wide range of applications.
Markets and Customers
Marketing of the company's oil and gas production is influenced
by many factors which are beyond the company's control and the
exact effect of which cannot be accurately predicted. These
factors include changes in supply and demand, market prices,
regulation, and actions of major foreign producers. Oil price
fluctuations can be extremely volatile as was demonstrated during
1999 when the posted price for West Texas intermediate fell below
$10.00 per barrel and then rose to over $30.00 per barrel in
2000.
Gas price decontrol, the advent of an active spot market for
natural gas, changes in supply and demand for natural gas, and
weather patterns cause natural gas prices to be subject to
significant fluctuations. The company presently sells virtually
all of its gas under one to five year contracts with major
pipeline companies. The sales price is typically based on
monthly "spot" (Index) prices for the applicable production
region. Title to the gas normally passes to the pipeline at
meters located near the wells. The Index prices are reduced by
certain pipeline charges.
Most of the company's natural gas production is located in
northwestern Oklahoma. There has been significant consolidation
among gas pipelines in this area, thereby reducing the number of
available purchasers. In many instances, there may be only one
viable pipeline option, which enables the pipeline to charge
higher rates.
Over the past few years a supply/demand imbalance has developed
in domestic natural gas as demand has increased and
deliverability has fallen. This, together with active fund
speculation in the natural gas derivatives market, has caused
natural gas prices to become increasing volatile. It has also
resulted in higher domestic natural gas prices beginning in 2000
compared to the previous 10 years. The company expects these
historically strong natural gas prices to continue for several
years but cannot reasonably predict the extent or timing of
natural gas price fluctuations.
As discussed elsewhere in this Form 10-KSB, the company
periodically hedges the price of a portion of its natural gas
production by forward selling on the NYMEX futures market.
Oil production is sold to crude oil purchasing companies at
competitive spot field prices. Crude oil and condensate
production are readily marketable, and the company is generally
not dependent on a single purchaser. Crude oil prices are
subject to world-wide supply and demand, and are primarily
dependent upon available supplies which can vary significantly
depending on production and pricing policies of OPEC and other
major producing countries and on significant events in major
producing regions. Unrest in the Middle East and OPEC's renewed
cooperation in managing the price of its produced oil have
resulted in higher world-wide oil prices during the past two
years.
Information concerning the company's major customers is included
in Note (6) to the Consolidated Financial Statements.
Competition and Regulation
The oil and gas industry is highly competitive. As a small
independent, the company must compete against companies with
substantially larger financial and other resources in all aspects
of its business.
Oil and gas drilling and production operations are regulated by
various Federal, state and local agencies. These agencies issue
binding rules and regulations which carry penalties, often
substantial, for failure to comply. The company anticipates its
aggregate burden of Federal, state and local regulation will
continue to increase particularly in the area of rapidly changing
environmental laws and regulations. The company also believes
that its present operations substantially comply with applicable
regulations. To date, such regulations have not had a material
effect on the company's operations, or the costs thereof. There
are no known environmental or other regulatory matters related to
the company's operations which are reasonably expected to result
in material liability to the company. The company does not
believe that capital expenditures related to environmental
control facilities or other regulatory matters will be material
in 2004. The company cannot predict what subsequent legislation
or regulations may be enacted or what effect it will have on the
company's business.
ITEM 2. PROPERTIES
General
The company's drilling activities are primarily located along the
shelf of the Northern Anadarko Basin of Oklahoma and in the
Oklahoma Panhandle. Specifically, drilling is focused on the
company's 17,000 gross acre Sand Creek and its 6,000 gross acre
Two Springs Prospects, both located in Harper and Ellis Counties,
Oklahoma and the Traxler Prospect located in Beaver County,
Oklahoma. Wells target the Morrow and Chester formations between
7,000 and 9,000 feet. Since 2001, the company has participated
in drilling 32 wells on the three properties with interests
ranging up to 60%. Of those wells, 27 were completed as
producers and five were dry holes. Several of the wells are
exceptional for the area, and 11 of the wells are included in the
company's Significant Properties (see definition below). The
Sand Creek and Two Springs Prospects have ample room for
additional drilling and the company believes that more good wells
will be drilled.
The company owns the exclusive right to a patented technology
known as the Calliope Gas Recovery System. Calliope is a new
generation of fluid lift technology that is applicable to gas
wells that meet certain criteria. Calliope achieves
substantially lower flowing bottom hole pressure than
conventional production methods because it does not rely on
reservoir pressure to lift liquids. The company believes it has
proven that Calliope will add 0.5 to 2.0 Bcf of proved gas
reserves to many dead and uneconomic wells. The company also
believes there are presently more than 1,000 wells that meet its
general criteria for Calliope candidate wells and thousands more
that will meet its general Calliope criteria in the future.
Calliope operations are currently focused in Oklahoma where the
company has a significant field operations infrastructure. Most
Calliope wells are located in the Northern Anadarko Basin of
Oklahoma. To date, Calliope has been installed on 15 wells
ranging in depth from 6,500 feet to 18,400 feet. All of the
wells were either dead or uneconomic at the time Calliope was
installed. Two Calliope wells were unsuccessful due to wellbore
problems (scaling and a casing leak) which were unrelated to the
technology. Nine Calliope wells are included in the company's
Significant Properties.
For more complete information regarding current year activities,
including oil and gas production, refer to "Management's
Discussion and Analysis of Financial Condition and Results of
Operations".
Significant Properties, Estimated Proved Oil and Gas Reserves,
and Future Net Revenues
The company's reserves, and reserve values, are concentrated in
36 properties ("Significant Properties"). Some of the
Significant Properties are individual wells and others are
multi-well properties. At year-end, the Significant Properties
represent 21% of the company's total properties but a
disproportionate 75% of the discounted value (at 10%) of the
company's reserves. Individual Calliope wells comprise 25% of the
Significant Properties and represent 37% of the discounted
reserve value of such properties. Wells drilled on the Sand
Creek, Two Springs and Traxler Prospects comprise 31% of the
Significant Properties and represent 42% of the discounted value
of such properties.
Seven of the non-Calliope properties included in Significant
Properties are relatively new wells with limited production
histories. In addition, six of the Calliope wells have a limited
production history based on post-Calliope installation
operations. Estimates of reserve quantities and values for these
Significant Properties must be viewed as being subject to
significant change as more data about the properties becomes
available. In addition, Calliope wells are generally 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.
McCartney Engineering, Inc., an independent petroleum engineering
firm, estimated proved reserves for the company's properties
which represented 64% in 2003, 62% in 2002 and 62% in 2001 of the
total estimated future value of estimated reserves. Remaining
reserves were estimated by the company in all years. At
October 31, 2003, natural gas represented 86% and crude oil
represented 14% of total reserves denominated in equivalent
barrels using a six Mcf of gas to one barrel of oil conversion
ratio.
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 (6) to the
Consolidated Financial Statements where additional reserve
information is provided. The average price used to calculate
estimated future net revenues was $28.64, $26.76 and $20.61 per
barrel of oil and $3.99, $3.74 and $2.87 per Mcf of gas as of
October 31, 2003, 2002 and 2001, respectively. Amounts do not
include estimates of future Federal and state income taxes.
Estimated Future
Oil Gas Estimated Future Net Revenues
Year (bbls) (Mcf) Net Revenues Discounted at 10%
--------------------------------------------------------------------------
2003 385,000* 13,786,000* $ 45,165,000 $ 28,024,000
2002 337,000 9,415,000 $ 29,774,000 $ 18,035,000
2001 330,000 9,121,000 $ 21,843,000 $ 13,874,000
* Substantially all of the company's reserves are classified as proved
developed.
Production, Average Sales Prices and Average Production Costs
The company's net production quantities and average price
realizations per unit for the indicated years are set forth
below. Price realizations include the sales price and hedging
gains or losses.
2003 2002 2001
--------------------------------------------------------------------
Product Volume Price Volume Price Volume Price
--------------------------------------------------------------------
Gas (Mcf) 1,449,000 $ 4.50 1,298,000 $ 3.00 800,000 $ 5.00
Oil (bbls) 35,000 $27.68 37,000 $22.01 44,000 $26.45
Average production costs, including production taxes, per unit of
production (using a six to one conversion ratio of Mcfs to
barrels) were $5.82, $5.10 and $6.40 per barrel in 2003, 2002 and
2001, respectively.
Productive Wells and Developed Acreage
Developed acreage at October 31, 2003 totaled 24,400 net and
135,600 gross acres. At October 31, 2003, the company owned
working interests in 64.48 net (216 gross) wells consisting of
15.73 net (41 gross) oil wells and 48.75 net (175 gross) gas
wells. In addition, the company owned royalty and production
payment interests in approximately 819 wells, primarily coal bed
methane located in Wyoming. In 2003, the company sold or
abandoned 5.52 net (7 gross) wells. In the same period, the
company drilled and acquired interests in 11.49 net (29 gross)
wells in which it did not previously own an interest.
Undeveloped Acreage
The following table sets forth the number of undeveloped acres
(primarily located in the Mid-Continent and Rocky Mountain
Regions) which will expire during the next five years (and
thereafter) unless production is established in the interim.
Undeveloped acres "held-by-production" represent the undeveloped
portions of producing leases which will not expire until
commercial production ceases.
Royalty Working
Interest Acreage Interest Acreage
------------------------------------------------------------------
Expiration
Year Ending
October 31 Gross Net Gross Net
------------------------------------------------------------------
2004 12,400 200 17,300 4,000
2005 1,700 500 16,700 5,700
2006 500 - 17,800 7,800
2007 - - 4,800 1,600
2008 3,300 100 4,200 600
Thereafter - - 3,800 900
Held-By-Production 145,200 8,000 11,200 2,300
----------------------------------------------------------------
163,100 8,800 75,800 22,900
================================================================
In general, "royalty" and "production payment" interests are
non-operated interests which are not burdened by costs of
exploration or lease operations, while "working interests" have
operating rights and participate in such costs.
Drilling
The following tables set forth the number of gross and net oil
and gas wells in which the company has participated and the
results thereof for the periods indicated.
Gross Wells
--------------------------------------------------------------------
Year Ended Total Gross Exploratory Development
----------------- -------------------
October 31 Wells Oil Gas Dry Oil Gas Dry
--------------------------------------------------------------------
2003 21 - 12 3 - 6 -
2002 13 - 6 2 - 5 -
2001 11 - 9 - - 2 -
1978-2000 210 12 86 76 15 16 5
--------------------------------------------------------------------
255 12 113 81 15 29 5
====================================================================
Net Wells
--------------------------------------------------------------------
Year Ended Total Net Exploratory Development
----------------- -------------------
October 31 Wells Oil Gas Dry Oil Gas Dry
--------------------------------------------------------------------
2003 4.906 - 2.564 0.762 - 1.580 -
2002 3.212 - 2.032 0.925 - 0.255 -
2001 2.236 - 2.097 - - 0.139 -
1978-2000 33.479 1.557 11.933 11.493 4.350 2.161 1.985
--------------------------------------------------------------------
43.833 1.557 18.626 13.180 4.350 4.135 1.985
====================================================================
ITEM 3. LEGAL PROCEEDINGS
The company is not a party to any material pending legal
proceedings. No such proceedings have been threatened and none
are contemplated by the company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during
the fourth quarter of 2003.
PART II.
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
The company's common stock is traded on the National Association
of Securities Dealers Automated Quotation System under the symbol
"CRED". Market quotations shown below were reported by the
National Association of Securities Dealers, Inc. and represent
prices between dealers excluding retail mark-up or commissions.
2003 2002
--------------------------------------------------------------
Quarter Ended High Low High Low
--------------------------------------------------------------
January 31 $ 9.46 $ 6.20 $ 5.63 $ 4.25
April 30 14.80 9.50 6.38 4.80
July 31 16.00 10.69 8.21 5.78
October 31 17.80 12.60 7.35 5.46
At December 31, 2003, the company had 3,617 shareholders of
record. The company has never paid a cash dividend and does not
expect to pay any cash dividends in the foreseeable future.
Earnings are reinvested in business activities. The company
issued a 20% stock dividend during 2003.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Liquidity and Capital Resources
References to years as used in this Item indicate fiscal years
ended October 31.
At October 31, 2003, working capital was $6,577,000. Net cash
provided by operating activities for 2003, 2002, and 2001 was
$5,891,000, $2,555,000, and $2,813,000, respectively, and
comprises primarily net income, depreciation, depletion and
amortization, and deferred income taxes for each of the three
years. For 2003, such amounts are $3,130,000, $1,333,000, and
$1,016,000. For 2002, such amounts are $1,282,000, $1,202,000,
and $379,000. For 2001, such amounts are $2,002,000, $842,000,
and $527,000. In 2003, 2002, and 2001, cash used in investing
activities was $5,332,000, $2,165,000 and $2,696,000,
respectively, and was used primarily to fund oil and gas
exploration and development expenditures totaling $5,520,000,
$2,464,000, and $2,688,000, respectively.
The average return on CREDO's investments was 10% in 2003, three
percent in 2002, and four percent in 2001. At year-end
approximately 43% 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. During 2003, the company suspended what are
generally characterized as mutual fund timing investments pending
the outcome of regulatory inquiries and investigations concerning
whether mutual funds allowed timing and other activities in
violation of their representations to investors. In the company's
opinion, the greatest investment risk is the potential for
negative market impact from unexpected, major adverse news, such
as the September 11th terrorist attacks.
Existing working capital and anticipated cash flow are expected
to be sufficient to fund 2004 operations. At year-end, the
company had no lines of credit or other bank financing
arrangements. Because earnings are anticipated to be reinvested
in operations, cash dividends are not expected to be paid in the
foreseeable future. Commitments for future capital expenditures
were not material at year-end. The company has no defined
benefit plans and no obligations for post retirement employee
benefits.
Product Prices and Production
Refer to Item 1., "Markets and Customers", for discussion of oil
and gas prices and marketing.
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 natural gas prices by
forward selling a portion of its estimated production in the
NYMEX futures market. This is generally done when (i) the price
relationship (the "basis") between the futures markets and the
cash markets where the company sells its gas is stable within
historical ranges, and (ii) in the company's opinion, the current
price is adequate to insure reasonable returns at a time when
downside price risks appear to be substantial. The company closes
its hedges by purchasing offsetting "long" positions in the
futures market at then prevailing prices. Accordingly, the gain
or loss on the hedge position will depend on futures prices at
the time offsetting "long" positions are purchased. Hedging gains
and losses are included in revenues from oil and gas sales. The
company believes its most significant hedging risk is that
expected correlations in price movements as discussed above do
not occur, and thus, that gains or losses in one market are not
fully offset by opposite moves in the other market.
Hedging transactions resulted in a loss of $92,000 in 2003 and
gains of $505,000 in 2002 and $663,000 in 2001. At
October 31, 2003, the company's open hedge positions totaled
560,000 Mcf covering the production months of December 2003
through March 2004. Hedges for the months of November 2003
through January 2004 were closed at a $83,000 gain. At
December 31, 2003, the company had open hedge positions totaling
100,000 Mcf covering the months of February through October 2004
at an average NYMEX price of $4.92 per Mcf. This hedge
represents approximately 85% of the company's estimated
production for the months of February and March and 55% to 60% of
such production for April through October 2004.
Gas and oil sales volume and price realization comparisons for
the indicated years ended October 31 are set forth below. Price
realizations include the sales price and hedging gains and
losses.
2003 2002 2001
-----------------------------------------------------------------------
Product Volume Price Volume Price Volume Price
-----------------------------------------------------------------------
Gas (Mcf) 1,449,000 $ 4.50 1,298,000 $ 3.00 800,000 $ 5.00
% change +12% +50% +62% -40% +20% +76%
Oil (bbls) 35,000 $27.68 37,000 $22.01 44,000 $26.45
% change -5% +26% -16% -17% +14% -5%
The 2003 and 2002 increases in natural gas volumes resulted
primarily from successful drilling in Oklahoma. Most oil and
condensate volumes are associated with gas production and,
therefore, vary from well to well depending on the volume and
"richness" of gas produced. Significant Properties (see
definition on page 4), contributed 60% of 2003 production on a
gas-equivalent basis.
As to Significant Properties, wells drilled since 2001 contributed
33% of 2003 production while Calliope wells installed during the
same period contributed 13% of such production. Refer to Item 2,
"Properties", for disclosures regarding reserve values on
Significant Properties.
Oil and Gas Activities
General. Capital spending in 2003 totaled $5,520,000, by far the
highest level in the company's history. During the year the
company continued to focus on its two core projects--natural gas
drilling along the shelf of the Northern Anadarko Basin of
Oklahoma and application of its patented Calliope Gas Recovery
System.
The company believes that, in combination, these two core projects
provide an excellent (and possibly unique) balance for achieving
the company's goal of adding high quality gas reserves and
production at reasonable costs and risks. In general, Calliope is
reserve driven while new drilling is production rate driven.
Calliope adds long-lived reserves at moderate costs and low risks.
In most of the applications to date, Calliope has developed more
reserves than the average new well drilled by the company at about
one-half the cost and a small fraction of the risk. However,
because Calliope is applied to mature, low pressure gas
reservoirs, its initial production rates are generally
significantly lower than initial rates for the successful new well
drilled by the company. In contrast, drilling new wells is much
higher risk and higher cost than Calliope (particularly for
comparable reserves) but, when successful, provides higher initial
production rates and cash flow. However, production decline rates
on new wells are generally much steeper than on Calliope wells.
In a business that is generally driven by production rates and
cash flow, Calliope provides excellent balance by adding
long-lived reserves at moderate costs and low risks. In 2003, the
company had significant success with both new drilling and
Calliope. However, the company generally expects its success with
these two core projects to occur unevenly and, therefore, believes
they must be evaluated over a three to five year period.
Drilling Activities. During 2003, the company drilled 21 wells in
Oklahoma with working interests ranging up to 60%. Eighteen (18)
of the wells were completed as producers and three were dry holes.
Drilling was concentrated in Ellis and Harper Counties on the
company's 17,000 gross acre Sand Creek Prospect and its
6,000 gross acre Two Springs Prospect where 18 wells were drilled.
The wells targeted the Morrow and Chester formations between 7,000
and 9,000 feet. A promising well was also drilled on the Traxler
Prospect located in Beaver County, Oklahoma. Both the Sand Creek
and Two Springs properties have ample room for additional wells to
be drilled and the company believes that more excellent wells are
likely.
Drilling is not restricted to the Sand Creek, Two Springs and
Traxler Prospects. The company has drilled wells and is generating
prospects elsewhere in the Northern Anadarko Basin, in the
Oklahoma Panhandle, and north-central Oklahoma. In addition, 98
coal bed methane wells were drilled on acreage in Wyoming where
the company owns primarily small royalty interests.
Several of the more promising wells drilled in 2003 commenced
production in the fourth quarter of 2003. That resulted in fourth
quarter production increasing 48% over the same quarter last year
and 27% over the immediately preceding quarter. The well recently
drilled on the Traxler Prospect commenced production shortly after
year end.
The company replaced 337% of the reserves produced in 2003 and its
reserve replacement cost was $5.15 per barrel of
oil-equivalent, or $0.86 per Mcf of gas-equivalent. According to
John S. Herold, Inc.'s Global Upstream Performance Review, the
company's historic three and five-year average reserve replacement
costs have been in the best quartile of its peer group.
Calliope Gas Recovery System. Calliope systems are currently
installed on 13 wells, all company-operated. Nine of these wells
are included in the company's Significant Properties (see Item 1,
"Properties-General"). The 11,800-foot J. C. Carroll well
provides an excellent example of Calliope's potential. When the
well was purchased for salvage value in 1999, it had not produced
commercially in five years. Calliope immediately restored
production to 660 Mcfg (thousand cubic feet of gas) per day.
Calliope has already recovered about 0.7 Bcfg from the Carroll
well and the company estimates it will recover an additional
1.1 Bcfg.
During 2003, the company installed Calliope on six dead or
uneconomic wells with 100% success. Included in those wells was
an 18,400-foot well that had been dead for three years. This well
extended Calliope's depth record by 5,600 feet, or 43%, and has
recently produced over 600 Mcf of gas per day. The company is in
various stages of preparing to install new Calliope systems on
four additional wells in Oklahoma.
The company's primary challenge presently, is obtaining candidate
wells on the needed scale. In addition, wells that are available
for purchase often have mechanical problems or problems caused by
the seller's "parting shots" which preclude successful Calliope
installations. The company is considering a number of strategies
to realize the value of Calliope. In an effort to install
Calliope on more wells, the company intends to offer joint
ventures or other sharing arrangements to selected companies that
have access to Calliope candidate wells. To that end, during 2003,
the company concluded a Calliope marketing study and fortified
Calliope's track record in anticipation of completing a multimedia
presentation to introduce Calliope to selected companies. The
presentation is now expected to be completed in March 2004. The
company presently intends to use the multimedia presentation only
for the purpose described above.
Reserves. Refer to Item 2, "Properties, General, Estimated Proved
Oil and Gas Reserves and Future Net Reserves", for information
regarding oil and gas reserves.
Results of Operations
In 2003, total revenues rose 58% to $8,491,000 compared to
$5,358,000 in 2002. As the oil and gas price/volume table on page
8 shows, total gas price realizations, which reflect hedging
transactions, rose 50% to $4.50 per Mcf and oil price realizations
rose 26% to $27.68 per barrel. The net effect of these price
changes was to increase oil and gas sales by $2,760,000. Hedging
losses were $92,000 in 2003 compared with gains of $505,000 in
2002. Gas production rose 12% and oil production declined 5%.
The net effect of these volume changes was to increase oil and gas
sales by $633,000. The increase in gas volumes resulted primarily
from successful drilling in 2003 and 2002. Operating income rose
10% due to drilling supervision income and additional operated
wells. Investment income and other increased 168% due primarily
to improved market conditions.
In 2003, total costs and expenses rose 18% to $4,244,000 compared
to $3,602,000 in 2002. Oil and gas production expenses rose
25% due primarily to increased production taxes on higher
revenues and new wells added during the year. Depreciation,
depletion and amortization ("DD&A") increased 11% primarily due to
an increase in production volume. General and administrative
expenses rose 19% due to expenses related to installation of, and
conversion to updated accounting software, and increased salary
costs. Interest expense relates to the exclusive license
agreement note payment. The effective tax rate was 28% in 2003
and 27% in 2002.
In 2002, total revenues fell 8% to $5,358,000 compared to
$5,807,000 in 2001. As the oil and gas price/volume table on page
8 shows, total gas price realizations, which reflect hedging
transactions, fell 40% to $3.00 per Mcf and oil price realizations
fell 17% to $22.01 per barrel. The net effect of these price
changes was to decrease oil and gas sales by $1,604,000. Hedging
gains were $505,000 in 2002 compared to $663,000 in 2001. Gas
volumes produced rose 62% and oil volumes produced declined 16%.
The net effect of these volume changes was to increase oil and gas
sales by $1,139,000. The increase in gas volumes resulted
primarily from successful drilling in 2002 and 2001. The decline
in oil volumes produced was primarily due to a waterflood project
that peaked in 2001 and started a normal decline in 2002.
Operating income rose 7% due to drilling supervision income and
additional operated wells. Investment income and other declined
9% due primarily to market conditions during 2002 that limited
investment opportunities for the market timers that manage the
bulk of the company's investments.
In 2002, total costs and expenses rose 21% to $3,602,000 compared
to $2,987,000 in 2001. Oil and gas production expenses rose
14% due to three major well workovers that cost approximately
$106,000. Depreciation, depletion and amortization ("DD&A")
increased 43% primarily due to a net increase in production
volume. Two wells that accounted for 38% of the company's 2002
production delivered gas at much higher than normal rates for area
wells. This resulted in a higher than normal depletion rate.
General and administrative expenses rose 11% due to inflationary
pressures. Interest expense relates to the exclusive license
agreement note payment. The effective tax rate was 27% in 2002
and 29% in 2001.
Critical Accounting Policies and Estimates
Accounting for Oil and Gas Property Costs. As more fully
discussed in Note 1 to the consolidated financial statements, the
company (i) follows the full cost method of accounting for the
costs of its oil and gas properties, (ii) amortizes such costs
using the units of production method, and (iii) applies a
quarterly full cost ceiling test. Adverse changes in conditions
(primarily gas price declines) could result in permanent
write-downs in the carrying value of oil and gas properties as
well as non-cash charges to operations, but would not affect cash
flows.
Estimates of Proved Oil and Gas Reserves. An independent
petroleum engineer annually estimates approximately 60% of the
company's proved reserves. The company estimates the remainder.
Reserve engineering is a subjective process that is dependent upon
the quality of available data and the interpretation thereof. In
addition, subsequent physical and economic factors such as the
results of drilling, testing, production and product prices may
justify revision of such estimates. Therefore, actual quantities,
production timing, and the value of reserves may differ
substantially from estimates. A reduction in proved reserves
would result in an increase in depreciation, depletion and
amortization ("DD&A") expense.
Estimates of Asset Retirement Obligations. In accordance with
SFAS No 143, the company makes estimates of future costs and the
timing thereof in connection with recording its future obligations
to plug and abandon wells. Estimated abandonment dates will be
revised in the future based on changes to related economic lives,
which vary with product prices and production costs. Estimated
plugging costs may also be adjusted to reflect changing industry
experience. Increases in operating costs and decreases in product
prices would increase the estimated amount of the obligation and
increase DD&A expense. Cash flows would not be affected until
costs to plug and abandon were actually incurred.
Cautionary Statement Pursuant to Safe Harbor Provisions of the
Private Securities Litigation Reform Act of 1995
This Form 10-KSB 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 Form 10-KSB, other than statements of historical
facts, address matters that the company reasonably expects,
believes or anticipates will or may occur in the future. Such
statements are subject to various assumptions, risks and
uncertainties, many of which are beyond the control of the
company. Investors are cautioned that any such statements are not
guarantees of future performance and that actual results or
developments may differ materially from those described in the
forward-looking statements.
ITEM 7. FINANCIAL STATEMENTS
Index to Consolidated Financial Statements
Consolidated Balance Sheets, October 31, 2003 and 2002
Consolidated Statements of Operations for the Three Years Ended
October 31, 2003
Consolidated Statements of Stockholders' Equity for
the Three Years Ended October 31, 2003
Consolidated Statements of Cash Flows for the Three Years
Ended October 31, 2003
Notes to Consolidated Financial Statements
Independent Auditors' Report
CONSOLIDATED BALANCE SHEETS
October 31, 2003 and 2002
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
----------------------------------------------------------------------
Assets 2003 2002
----------------------------------------------------------------------
Current assets:
Cash and cash equivalents $ 1,885,000 $ 1,324,000
Short-term investments 4,778,000 5,586,000
Receivables:
Trade 410,000 577,000
Accrued oil and gas sales 1,256,000 535,000
Other 234,000 390,000
----------------------------------------------------------------------
Total current assets 8,563,000 8,412,000
----------------------------------------------------------------------
Oil and gas properties, net, at cost,
using full cost method:
Unevaluated 2,075,000 1,690,000
Evaluated 11,986,000 7,987,000
----------------------------------------------------------------------
Net oil and gas properties 14,061,000 9,677,000
----------------------------------------------------------------------
Exclusive license agreement, net of
amortization of $221,000 and $152,000 478,000 548,000
----------------------------------------------------------------------
Other, net 470,000 174,000
----------------------------------------------------------------------
$23,572,000 $18,811,000
======================================================================
Liabilities and Stockholders' Equity
----------------------------------------------------------------------
Current liabilities:
Accounts payable and accrued liabilities $ 1,776,000 $ 1,733,000
Income taxes payable 210,000 49,000
----------------------------------------------------------------------
Total current liabilities 1,986,000 1,782,000
Deferred income taxes, net 3,358,000 2,314,000
----------------------------------------------------------------------
Exclusive license obligation, less current
obligations of $53,000 and $48,000 355,000 408,000
----------------------------------------------------------------------
Asset retirement obligation 238,000 -
----------------------------------------------------------------------
Commitments
----------------------------------------------------------------------
Stockholders' equity:
Preferred stock, without par value,
5,000,000 shares authorized,
none issued - -
Common stock, $.10 par value,
20,000,000 shares authorized,
4,334,000 shares issued in 2003
and 3,678,000 issued in 2002 433,000 368,000
Capital in excess of par value 12,664,000 6,452,000
Retained earnings net of $6,272,000
related to 20% stock dividend in 2003 5,062,000 8,209,000
Accumulated other comprehensive income 180,000 37,000
Treasury stock, at cost, 378,000 shares
in 2003, and 398,000 shares in 2002 (704,000) (759,000)
----------------------------------------------------------------------
Total stockholders' equity 17,635,000 14,307,000
----------------------------------------------------------------------
$23,572,000 $18,811,000
======================================================================
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended October 31, 2003
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
---------------------------------------------------------------------------
2003 2002 2001
---------------------------------------------------------------------------
Revenues:
Oil and gas sales $ 7,494,000 $ 4,698,000 $ 5,163,000
Operating 536,000 488,000 456,000
Investment income and other 461,000 172,000 188,000
---------------------------------------------------------------------------
8,491,000 5,358,000 5,807,000
---------------------------------------------------------------------------
Costs and expenses:
Oil and gas production 1,608,000 1,291,000 1,135,000
Depreciation, depletion and
amortization 1,333,000 1,202,000 842,000
General and administrative 1,257,000 1,060,000 957,000
Interest 46,000 49,000 53,000
---------------------------------------------------------------------------
4,244,000 3,602,000 2,987,000
---------------------------------------------------------------------------
Income before income taxes and
cumulative effect of
accounting change 4,247,000 1,756,000 2,820,000
Income taxes (1,189,000) (474,000) (818,000)
---------------------------------------------------------------------------
Income before cumulative
effect of accounting change 3,058,000 1,282,000 2,002,000
Cumulative effect of change
in accounting principle 72,000 - -
---------------------------------------------------------------------------
Net income $ 3,130,000 $ 1,282,000 $ 2,002,000
===========================================================================
Basic income per share before
accounting change $ .77 $ .33 $ .53
Cumulative effect of change in
accounting principle .02 - -
---------------------------------------------------------------------------
Basic income per share $ .79 $ .33 $ .53
===========================================================================
Diluted income per share before
accounting change $ .76 $ .32 $ .51
Cumulative effect of change in
accounting principle .02 - -
---------------------------------------------------------------------------
Diluted income per share $ .78 $ .32 $ .51
===========================================================================
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended October 31, 2003
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
----------------------------------------------------------------------------------------------------------------------------
Accumulated
Capital In Other Total
Common Stock Excess Of Retained Comprehensive Treasury Stockholders'
--------------------
Shares Amount Par Value Earnings Income Stock Equity
----------------------------------------------------------------------------------------------------------------------------
Balances, October 31, 2000 3,678,000 $ 368,000 $ 6,270,000 $4,925,000 - $(1,176,000) $10,387,000
Comprehensive income:
Net income - - - 2,002,000 - - 2,002,000
Other comprehensive income,
net of tax: Change in fair
value of derivatives - - - - $ 14,000 - 14,000
-----------
Comprehensive income - - - - - - 2,016,000
Stock options issued
to consultant - - 12,000 - - - 12,000
Income tax benefit from
exercise of nonqualified
stock options and
premature dispositions - - 170,000 - - - 170,000
Purchase of treasury stock - - - - - (129,000) (129,000)
Exercise of stock options - - - - - 387,000 387,000
----------------------------------------------------------------------------------------------------------------------------
Balances, October 31, 2001 3,678,000 368,000 6,452,000 6,927,000 14,000 (918,000) 12,843,000
Comprehensive income:
Net income - - - 1,282,000 - - 1,282,000
Other comprehensive income,
net of tax: Change in fair
value of derivatives - - - - 23,000 - 23,000
-----------
Comprehensive income - - - - - - 1,305,000
Purchase of treasury stock - - - - - (71,000) (71,000)
Exercise of stock options - - - - - 230,000 230,000
----------------------------------------------------------------------------------------------------------------------------
Balances, October 31, 2002 3,678,000 368,000 6,452,000 8,209,000 37,000 (759,000) 14,307,000
Comprehensive income:
Net income - - - 3,130,000 - - 3,130,000
Other comprehensive income,
net of tax: Change in fair
value of derivatives - - - - 143,000 - 143,000
-----------
Comprehensive income - - - - - - 3,273,000
20% stock dividend 656,000 65,000 6,212,000 (6,277,000) - - -
Purchase of treasury stock - - - - - (1,000) (1,000)
Exercise of stock options - - - - - 56,000 56,000
----------------------------------------------------------------------------------------------------------------------------
Balances, October 31, 2003 4,334,000 $ 433,000 $12,664,000 $5,062,000 $ 180,000 $ (704,000) $17,635,000
============================================================================================================================
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended October 31, 2003
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
----------------------------------------------------------------------------
2003 2002 2001
----------------------------------------------------------------------------
Cash flows from operating activities:
Net income $3,130,000 $1,282,000 $2,002,000
Non-cash expenses included in
net income:
Depreciation, depletion and
amortization 1,333,000 1,202,000 842,000
Deferred income taxes 1,016,000 379,000 527,000
Cumulative effect of change in
accounting principle (72,000) - -
Other 6,000 7,000 21,000
Changes in operating assets
and liabilities:
Proceeds from
short-term investments 5,261,000 4,836,000 3,209,000
Purchase of
short-term investments (4,453,000) (5,139,000) (3,866,000)
Trade receivables 167,000 (260,000) (90,000)
Accrued oil and gas sales (721,000) (168,000) 105,000
Other current assets 299,000 (126,000) 12,000
Accounts payable
and accrued costs and expenses (236,000) 603,000 191,000
Income taxes payable 161,000 (61,000) (140,000)
----------------------------------------------------------------------------
Net cash provided
by operating activities 5,891,000 2,555,000 2,813,000
----------------------------------------------------------------------------
Cash flows from investing activities:
Additions to oil and gas properties
(net of $446,000 in 2003 included
primarily in Accounts Payable) (5,520,000) (2,464,000) (2,688,000)
Proceeds from sale of oil and gas
properties 526,000 376,000 34,000
Other (338,000) (77,000) (42,000)
----------------------------------------------------------------------------
Net cash used in investing activities (5,332,000) (2,165,000) (2,696,000)
----------------------------------------------------------------------------
Cash flows from financing activities:
Proceeds from exercise
of stock options 56,000 230,000 387,000
Purchase of treasury stock (1,000) (71,000) (129,000)
Principal payment on exclusive
license obligation (53,000) (44,000) (40,000)
----------------------------------------------------------------------------
Net cash provided
by financing activities 2,000 115,000 218,000
----------------------------------------------------------------------------
Increase in cash and cash equivalents 561,000 505,000 335,000
Cash and cash equivalents:
Beginning of year 1,324,000 819,000 484,000
----------------------------------------------------------------------------
End of year $1,885,000 $1,324,000 $ 819,000
============================================================================
See accompanying notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
October 31, 2003
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
---------------------------------------------------------------
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations and Basis of Presentation
The consolidated financial statements include the accounts of
CREDO Petroleum Corporation and its wholly owned subsidiaries
(the "company"). The company engages in oil and gas acquisition,
exploration, development and production activities in the United
States. Certain operations are conducted through three private
limited partnerships (the "Partnerships") which, as general
partner, the company manages and controls. The company's general
and limited partner interests in the Partnerships are combined on
the proportionate share basis in accordance with accepted
industry practice. All significant intercompany transactions
have been eliminated. Certain reclassifications have been made
to prior year amounts with no effect on net income. All
references to years in these Notes refer to the company's fiscal
October 31 year.
Cash, Cash Equivalents, and Short-Term Investments
Cash equivalents consist of highly liquid investments with
original maturities of three months or less. At
October 31, 2003, approximately 43% of short-term investments are
mutual funds. Other short-term investments consist primarily of
professionally managed limited partnerships which provide readily
determinable market values and short-term liquidity. The
partnerships are invested primarily in financial instruments.
Unrealized gains on limited partnerships are not significant.
Short-term investments are classified as "trading" and are stated
at fair value with realized and unrealized gains and losses
immediately recognized.
Oil and Gas Properties
The company follows the full cost method of accounting for its
oil and gas operations. Under this method all costs incurred in
the acquisition, exploration, and development of oil and gas
properties are capitalized in one cost center, including certain
internal costs directly associated with such activities which
totaled $200,000 in 2003, 2002 and 2001. Proceeds from sales of
oil and gas properties are credited to the cost center with no
gain or loss recognized unless such adjustments would
significantly alter the relationship between capitalized costs
and proved oil and gas reserves.
If capitalized costs, less related accumulated amortization and
deferred income taxes, exceed the "full cost ceiling," the excess
is expensed in the period such excess occurs. The full cost
ceiling includes an estimated discounted value of future net
revenues attributable to proved reserves using current product
prices and operating costs, and an estimate of the value of
unproved properties which are included in the cost center. Costs
of oil and gas properties are amortized using the units of
production method. The company's composite depreciation,
depletion and amortization ("DD&A") rate per equivalent barrel
produced was $4.41 in 2003, $4.27 in 2002 and $4.06 in 2001.
Unevaluated properties consist primarily of lease acquisition and
maintenance costs. Evaluation normally takes three to five
years. Of the unevaluated property costs, $829,000 and $98,000
were incurred in 2003 and 2002, respectively.
Natural Gas and Crude Oil Price Hedging
The company periodically hedges the price of its oil and gas
production when the potential for significant downward price
movement is anticipated. Hedging transactions take the form of
forward, or "short," selling in the NYMEX futures market, and are
closed by purchasing offsetting "long" positions. Such hedges,
which are accounted for as cash flow hedges, do not exceed
anticipated 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.
Hedging gains and losses are recognized as adjustments to oil and
gas sales as the hedged product is produced. The company had
hedging losses of $92,000 in 2003 , and hedging gains of $505,000
in 2002, and $663,000 in 2001. The company has recorded in other
comprehensive income net deferred gains of approximately $248,000
($180,000 net of tax) related to natural gas hedging transactions
of which gains of $161,000 were realized and $87,000 were
unrealized. Any hedge ineffectiveness, which is currently
immaterial, is immediately recognized in other income. At
October 31, 2003, the company's open hedge position totaled
560,000 Mcf covering the months of December 2003 through March
2004 at an average price of $5.19 per Mcf. The hedge represented
approximately 85% of the company's estimated gas production for
those months.
Accounting Estimates
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 and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Significant estimates with regard to these financial statements
include the estimate of proved oil and gas reserve quantities and
the related present value of estimated future net cash flows
therefrom.
Stock-Based Compensation
In December 2002, the Financial Accounting Standards Board issued
SFAS No. 148, "Accounting for Stock-Based Compensation --
Transition and Disclosure, an amendment of SFAS No. 123." Among
other provisions, the statement amends the disclosure
requirements of SFAS No. 123, "Accounting for Stock-Based
Compensation." Under current accounting rules the company
elected to account for its stock-based employee compensation
under the intrinsic value method established by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees."
For purposes of this disclosure, the fair value of each option
granted was $5.66 in 2003, $3.75 in 2002 and $2.41 in 2001. All
options were granted with an exercise price equal to the market
price on the date of grant. The fair value was estimated on the
date of grant using the Black-Scholes option-pricing model with
an expected average volatility of 52% in 2003, 53% in 2002 and
58% in 2001, a risk-free interest rate of 3% in 2003, 4% in 2002
and 6% in 2001, no expected dividends, and average expected terms
of five years.
If compensation expense had been determined in accordance with
the provisions of SFAS No. 123, the company's net income and per
share amounts would have been reported as follows:
Years Ended October 31 2003 2002 2001
------------------------------------------------------------------------
Net Income as reported $3,130,000 $1,282,000 $2,002,000
Pro forma stock compensation
expense, net of tax (428,000) (103,000) (130,000)
------------------------------------------------------------------------
Pro forma net income $2,702,000 $1,179,000 $1,872,000
========================================================================
Basic net income per share:
As reported $ 0.79 $ 0.33 $ 0.53
========================================================================
Pro forma $ 0.69 $ 0.30 $ 0.50
========================================================================
Diluted net income per share:
As reported $ 0.78 $ 0.32 $ 0.51
========================================================================
Pro forma $ 0.68 $ 0.30 $ 0.48
========================================================================
Per Share Amounts
Basic income per share is computed using the weighted average
number of shares outstanding. Diluted income per share reflects
the potential dilution that would occur if stock options were
exercised using the average market price for the company's stock
for the period. Total potential dilutive shares based on options
outstanding at October 31, 2003 was 322,980. The assumed exercise
of stock options would increase the weighted average shares
outstanding from 3,942,000 to 4,019,000 in 2003, 3,894,000 to
3,979,000 in 2002 and from 3,732,000 to 3,925,000 in 2001. Shares
outstanding for 2002 and 2001 have been adjusted to reflect a 20%
stock dividend effective April 2, 2003.
Change in Accounting Principle
In June 2001, the Financial Accounting Standards Board issued
SFAS No. 143, "Accounting for Asset Retirement Obligations" that
requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred
and a corresponding increase in the carrying amount of the related
long-lived asset. This statement is effective for fiscal years
beginning after June 15, 2002. The company adopted SFAS No. 143
on November 1, 2002 and recorded an asset and related liability of
$179,000 (using a 5% discount rate) and a cumulative effect on
change in accounting principle on prior years of $72,000 (net of
taxes of $28,000). During 2003, the company recognized $7,000 of
accretion expenses on the liability and a decrease of $45,000 in
depletion expense as a result of adopting SFAS No. 143.
Recently Issued Accounting Standards
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141, "Business Combinations", to oil and
gas companies. The issue is whether SFAS No. 141 requires oil and
gas companies to classify the costs of mineral rights held under
lease or contracts as intangible assets in the balance sheet,
apart from other capitalized oil and gas property costs.
Historically the company and other oil and gas companies have
included such costs as part of oil and gas properties. If it is
ultimately determined that SFAS No. 141 requires such
reclassifications, the company estimates amounts to be
reclassified from Oil and Gas Properties to Intangible Assets at
October 31, 2003 and 2002 would be $5,600,000 and $4,300,000,
respectively. These potential balance sheet reclassifications
would have no effect on results of operations or cash flow.
(2) COMMON STOCK AND PREFERRED STOCK
The company has authorized 5,000,000 shares of preferred stock
which may be issued in series and with preferences as determined
by the company's Board of Directors. Approximately 100,000 shares
of the company's authorized but unissued preferred stock have been
reserved for issuance pursuant to the provisions of the company's
Shareholders' Rights Plan.
On March 19, 2003, the company declared a 20% stock dividend to
shareholders of record on April 2, 2003. On April 23, 2003, the
company issued 656,000 shares of common stock in conjunction with
this dividend. Accordingly, the fair value based on the quoted
market price of the additional shares issued of $6,277,000 was
charged to retained earnings and credited to common stock and
capital in excess of par value. Cash payments were made to
shareholders in lieu of fractional shares. The basic and diluted
weighted average number of shares outstanding and net income per
share information for all prior reporting periods have been
adjusted to reflect the effects of the stock dividend.
The company's 1997 Stock Option Plan (the "Plan"), as amended and
restated effective October 25, 2001, authorizes the granting of
incentive and nonqualified options to purchase shares of the
company's common stock. The Plan is administered by the Board of
Directors which determines the terms pursuant to which any option
is granted. The Plan provides that upon a change in control of
the company, options then outstanding will immediately vest and
the company will take such actions as are necessary to make all
shares subject to options immediately salable and transferable.
Plan activity is set forth below and has been adjusted for the 20%
stock dividend.
Years Ended October 31 2003 2002 Adjusted 2001 Adjusted
-----------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Number Exercise Number Exercise Number Exercise
of of of
Options Price Options Price Options Price
-----------------------------------------------------------------------
Outstanding at
beginning
of year 115,080 $ 4.22 354,000 $ 3.05 440,000 $ 1.94
Granted 246,500 13.00 18,000 6.96 150,000 4.08
Exercised (20,100) 2.82 (136,920) 1.68 (236,000) 1.64
Cancelled
or forfeited (18,500) 10.24 (120,000) 4.07 - -
-----------------------------------------------------------------------
Outstanding
at end of year 322,980 $10.67 115,080 $ 4.22 354,000 $ 3.05
=======================================================================
Options are exercisable at weighted average exercise prices as
follows: 113,228 in 2003 at $7.23; 72,435 in 2004 at $12.65;
72,442 in 2005 at $12.65; 34,687 in 2006 at $11.91; and 30,188 in
2007 at $12.65. Options expire with weighted average exercise
prices as follows: 13,500 in 2004 at $3.39, 27,480 in 2005 at
$4.11, 30,000 in 2006 at $4.17, 18,000 in 2007 at $6.96, 18,000 in
2008 at $8.38, 216,000 in 2013 at $13.37. The weighted average
remaining contractual life of options outstanding at October 31,
2003 is 7.2 years.
(3) COMMITMENTS
The company leases office facilities under an operating lease
agreement which expires May 1, 2006. The lease agreement requires
payments of $42,000 in 2004 and 2005 and $21,000 in 2006. Total
rental expense in 2003 was $73,000, 2002 was $73,000, and $68,000
in 2001. The company has no capital leases and no other operating
lease commitments.
(4) INCOME TAXES
The company follows 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. At
October 31, 2003, the company had $613,000 of statutory depletion
carry forward for tax return purposes and $177,000 for financial
statement purposes.
The income tax expense recorded in the Consolidated Statements of
Operations consists of the following:
Years Ended October 31 2003 2002 2001
------------------------------------------------------------------------
Current $ 173,000 $ 95,000 $ 291,000
Deferred 1,016,000 379,000 527,000
------------------------------------------------------------------------
$1,189,000 $ 474,000 $ 818,000
========================================================================
The effective income tax rate differs from the U.S. Federal statutory
income tax rate due to the following:
Years Ended October 31 2003 2002 2001
------------------------------------------------------------------------
Federal statutory income tax rate 34% 34% 34%
State income taxes 2 2 2
Percentage depletion (8) (9) (7)
-----------------------------------------------------------------------
28% 27% 29%
=======================================================================
The principal sources of temporary differences resulting in deferred tax
assets and tax liabilities at October 31, 2003 and 2002 are as follows:
October 31 2003 2002
-----------------------------------------------------------------------
Deferred tax assets:
Gain on property sales $ 452,000 $ 334,000
-----------------------------------------------------------------------
Total deferred tax assets 452,000 334,000
-----------------------------------------------------------------------
Deferred tax liabilities:
Intangible drilling, leasehold and
other exploration costs capitalized
for financial reporting purposes but
deducted for tax purposes (3,438,000) (2,436,000)
State taxes and other (372,000) (212,000)
-----------------------------------------------------------------------
Total deferred tax liabilities (3,810,000) (2,648,000)
-----------------------------------------------------------------------
Net deferred tax liability $(3,358,000) $(2,314,000)
=======================================================================
(5) EXCLUSIVE LICENSE AGREEMENT OBLIGATION
On September 1, 2000, the company acquired an unrestricted,
exclusive license for patented technology. The initial
license term is ten years and includes an option to extend the
term to the remaining life of the patents. The licensor will
receive a net 8.3% carried interest in any installation of the
technology. The license purchase price is $1,115,000, of which
$485,000 has been paid. The balance, which is due in six
remaining annual increments of $105,000, is recorded at 10%
present value. The related assets are being amortized over 10
years on a straight-line basis. If the option to extend the
license after the initial ten-year term is exercised, the cost
will be $94,000 per year to the expiration of the last patent.
(6) SUPPLEMENTARY OIL AND GAS INFORMATION
Capitalized Costs
October 31 2003 2002 2001
-----------------------------------------------------------------------
Unproved properties not being
amortized $ 2,075,000 $ 1,690,000 $ 1,549,000
Properties being amortized 23,082,000 18,027,000 16,080,000
Accumulated depreciation,
depletion and amortization (11,096,000) (10,040,000) (8,960,000)
-----------------------------------------------------------------------
Total capitalized costs $14,061,000 $ 9,677,000 $ 8,669,000
=======================================================================
Acquisition, Exploration and Development Costs Incurred
Years Ended October 31 2003 2002 2001
-----------------------------------------------------------------------
Property acquisition costs net
of divestiture proceeds:
Proved $ - $ - $ -
Unproved 385,000 14,000 87,000
Exploration costs 4,233,000 2,007,000 2,481,000
Development costs 822,000 67,000 86,000
-----------------------------------------------------------------------
Net costs incurred $ 5,440,000 $ 2,088,000 $ 2,654,000
=======================================================================
Major Customers and Operating Region
The company operates exclusively within the United States. Except
for cash investments, all of the company's assets are employed in,
and all its revenues are derived from, the oil and gas industry.
The company had sales in excess of 10% of total revenues to oil
and gas purchasers as follows: Duke Energy 49% in 2003, 40% in
2002, and 30% in 2001; Enogex, Inc. 10% in 2003 and 15% in 2001.
Oil and Gas Reserve Data (Unaudited)
Independent petroleum engineers estimated proved reserves for the
company's properties which represented approximately 64% in 2003,
62% in 2002 and 62% in 2001 of total estimated future net
revenues. The remaining reserves were estimated by the company.
Reserve definitions and pricing requirements prescribed by the
Securities and Exchange Commission were used. The determination
of oil and gas reserve quantities involves numerous estimates
which are highly complex and interpretive. The estimates are
subject to continuing re-evaluation and reserve quantities may
change as additional information becomes available. Estimated
values of proved reserves were computed by applying prices in
effect at October 31 of the indicated year. The average price
used was $28.64, $26.76, and $20.61 per barrel for oil and $3.99,
$3.74, and $2.87 per Mcf for gas in 2003, 2002, and 2001,
respectively. Estimated future costs were calculated assuming
continuation of costs and economic conditions at the reporting
date.
Total estimated proved reserves and the changes therein are set forth below
for the indicated year.
2003 2002 2001
------------------------------------------------------------------------------
Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls)
------------------------------------------------------------------------------
Proved reserves:
Balance,
November 1 9,415,000 337,000 9,121,000 330,000 7,413,000 373,000
Revisions of
previous estimates (220,000) 35,000 (239,000) 20,000 82,000 (9,000)
Extensions and
discoveries 5,867,000 51,000 1,715,000 28,000 2,404,000 5,000
Purchases of
reserves in place 178,000 - 141,000 - 22,000 5,000
Sales of reserves
in place (5,000) (3,000) (25,000) (4,000) - -
Production (1,449,000) (35,000)(1,298,000)(37,000) (800,000)(44,000)
------------------------------------------------------------------------------
Balance,
October 31 13,786,000 385,000 9,415,000 337,000 9,121,000 330,000
==============================================================================
Proved developed reserves:
Beginning of period 8,459,000 298,000 8,249,000 296,000 6,511,000 340,000
==============================================================================
End of period 13,786,000 385,000 8,459,000 298,000 8,249,000 296,000
==============================================================================
The standardized measure of discounted future net cash flows from reserves is
set forth below as of October 31 of the indicated year.
2003 2002 2001
------------------------------------------------------------------------------
Future cash inflows $ 66,043,000 $ 44,244,000 $ 32,952,000
Future production and
development costs (20,878,000) (14,469,000) (11,109,000)
Future income tax expense (11,094,000) (6,552,000 ) (4,589,000)
------------------------------------------------------------------------------
Future net cash flows 34,071,000 23,223,000 17,254,000
10% discount factor (12,930,000) (9,157,000) (6,294,000)
------------------------------------------------------------------------------
Standardized measure of
discounted future net cash flows $ 21,141,000 $ 14,066,000 $ 10,960,000
==============================================================================
The principal sources of change in the standardized measure of discounted future
cash flows from reserves are set forth below for the indicated year.
2003 2002 2001
------------------------------------------------------------------------------
Balance, November 1 $ 14,066,000 $ 10,960,000 $ 14,456,000
Sales of oil and gas produced,
net of production costs (5,886,000) (3,407,000) (4,028,000)
Net changes in prices, production
and development costs 2,484,000 3,587,000 (8,661,000)
Extensions and discoveries, net of
future development and production
costs 11,436,000 3,039,000 4,132,000
Revisions of quantity
estimates, timing, and other 77,000 (218,000) 1,883,000
Purchases of reserves in place 441,000 320,000 110,000
Sales of reserves in place (66,000) (122,000) -
Accretion of discount 1,407,000 1,096,000 1,446,000
Net change in income taxes (2,818,000) (1,189,000) 1,622,000
------------------------------------------------------------------------------
Balance, October 31 $ 21,141,000 $ 14,066,000 $ 10,960,000
==============================================================================
INDEPENDENT AUDITORS' REPORT
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
The Board of Directors and Stockholders
CREDO Petroleum Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheets of
CREDO Petroleum Corporation and subsidiaries as of
October 31, 2003 and 2002, and the related consolidated statements
of operations, stockholders' equity, and cash flows for each of
the years in the three year period ended October 31, 2003. These
consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion
on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of CREDO Petroleum Corporation and subsidiaries as of
October 31, 2003 and 2002, and the results of their operations and
their cash flows for each of the years in the three year period
ended October 31, 2003, in conformity with accounting principles
generally accepted in the United States of America.
HEIN + ASSOCIATES LLP
Denver, Colorado
December 22, 2003
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 8A. CONTROLS AND PROCEDURES
Within 90 days prior to the filing date of this report, the
company carried out an evaluation, under the supervision and with
the participation of the company's Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and
operation of its disclosure controls and procedures pursuant to
Securities Exchange Act Rule 13a-14(c). "Disclosure controls and
procedures" are controls and procedures that are designed to
ensure that information required to be disclosed by the company in
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. Based upon that evaluation, the company's Chief Executive
Officer and Chief Financial Officer concluded that the company's
disclosure controls and procedures are effective for these
purposes as of the date of the evaluation.
There have been no significant changes in the company's internal
controls or in other factors that could significantly affect these
controls subsequent to the date of their evaluation, including any
corrective actions with regard to significant deficiencies and
material weaknesses.
PART III.
ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's year 2003.
ITEM 10. EXECUTIVE COMPENSATION
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's year 2003.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's year 2003.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's year 2003.
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
3(a)(i) Articles of Incorporation of CREDO Petroleum
& 4(a) Corporation (incorporated by reference to
Form 10-K dated October 31, 1982).
3(a)(ii) Articles of Amendment of Articles of Incorporation,
dated March 9, 1982 (incorporated by reference to
Form 10-K dated October 31, 1982).
3(a)(iii) Articles of Amendment of Articles of Incorporation,
dated October 28, 1982 (incorporated by reference to
Form 10-K dated October 31, 1982).
3(a)(iv) Articles of Amendment of Articles of Incorporation
dated April 18, 1984 (incorporated by reference to
Form 10-K dated October 31, 1984).
3(a)(v) Articles of Amendment of Articles of Incorporation
dated April 18, 1984 (incorporated by reference to
Form 10-K dated October 31, 1984).
3(a)(vi) Articles of Amendment of Articles of Incorporation
dated April 2,1985 (incorporated by reference to
Form 10-K dated October 31, 1985).
3(a)(vii) Articles of Amendment of Articles of Incorporation
dated March 25, 1986 (incorporated by reference to
Form 10-K dated October 31, 1986).
3(a)(viii) Articles of Amendment of Articles of Incorporation
dated March 24, 1988 (incorporated by reference to
Form 10-K dated October 31, 1989).
3(a)(ix) Articles of Amendment to Articles of Incorporation
dated May 11, 1990.
3(b)(i) By-Laws of CREDO Petroleum Corporation, as amended
October 30, 1986 (incorporated by reference to
Form 10-K dated October 31, 1986).
3(b)(ii) Amendment to Article X of CREDO Petroleum
Corporation's By-Laws dated March 24, 1988
(incorporated by reference to the company's definitive
proxy dated February 5, 1988).
4(i) Shareholders' Rights Plan, dated April 11, 1989.
4(ii) Amendment to Shareholders' Rights Plan, dated
February 24, 1999 (incorporated into Part II of the
company's Form 10-QSB dated January 31, 1999).
10(a) CREDO Petroleum Corporation Non-qualified Stock Option
Plan, dated January 13, 1981 (incorporated by
reference to Amendment No. 1 to Form S-1 dated
February 2, 1981).
10(b) CREDO Petroleum Corporation Incentive Stock Option
Plan, dated October 2, 1981 (incorporated by reference
to the company's definitive proxy statement, dated
January 22, 1982).
10(c) Model of Director and Officer Indemnification
Agreement provided for by Article X of CREDO Petroleum
Corporation's By-Laws (incorporated by reference to
Form 10-K dated October 31, 1987).
10(d) CPC Exclusive License Agreement, dated
September 1, 2000 (incorporated by reference to
Form 10-KSB dated October 31, 2000).
10(e) CREDO Petroleum Corporation 1997 Stock Option Plan, as
amended and restated effective October 25, 2001
(incorporated by reference to Form 10-KSB dated
October 31, 2001).
21 CREDO Petroleum Corporation (a Colorado corporation)
and its subsidiaries SECO Energy Corporation (a Nevada
corporation) and United Oil Corporation (an Oklahoma
corporation) are located at 1801 Broadway, Suite 900,
Denver, CO 80202-3837.
31.1 Certification by Chief Executive Officer under
Section 302 of the Sarbanes-Oxley Act of 2002 (filed
herewith).
31.2 Certification by Chief Financial Officer under
Section 302 of the Sarbanes-Oxley Act of 2002 (filed
herewith).
32.1 Certification by Chief Executive Officer under
Section 906 of the Sarbanes-Oxley Act
(18 U.S.C. Section 1350) (Filed herewith)
32.2 Certification by Chief Financial Officer under
Section 906 of the Sarbanes-Oxley Act
(18 U.S.C. Section 1350) (Filed herewith)
(b) Reports on Form 8-K
On September 16, 2003, CREDO Petroleum Corporation
filed a current report on Form 8-K reporting under
Item 9 Pursuant to Item 12 that it had issued a press
release announcing its third quarter 2003 financial
results and updated drilling results.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's year 2003.
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CREDO PETROLEUM CORPORATION
By:/s/ James T. Huffman
----------------------------
James T. Huffman,
Chief Executive Officer
(Principal Executive Officer)
By:/s/ James P. Garrett, Jr.
----------------------------
James P. Garrett, Jr.
Vice President and
Chief Financial Officer
(Principal Financial and
Accounting Officer)
Date: January 14, 2004
In accordance with the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of
the registrant and in the capacities and on the dates indicated.
Date Signature Title
January 29, 2004 /s/ William N. Beach Director
-------------------------
William N. Beach
January 29, 2004 /s/ Clarence H. Brown Director
-------------------------
Clarence H. Brown
January 29, 2004 /s/ Oakley Hall Director
-------------------------
Oakley Hall
January 14, 2004 /s/ James T. Huffman Chairman of the
------------------------- Board, President,
James T. Huffman Treasurer
January 29, 2004 /s/ William F. Skewes Director,
------------------------- Corporate
William F. Skewes Secretary,
General
Counsel
January 29, 2004 /s/ Richard B. Stevens Director
-------------------------
Richard B. Stevens
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:
1. I have reviewed this annual report on Form 10-KSB 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 report;
3. Based on my knowledge, the financial statements, and other
financial information included in this 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 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)) 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) Designed such internal control over financial reporting, or
caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting
and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c) 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
d) 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 auditors
and the audit committee of Registrant's Board of Directors:
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: January 14, 2004
/s/ James T. Huffman
------------------------------
James T. Huffman
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
I, James P. Garrett, Jr., Vice President and Chief Financial
Officer of CREDO Petroleum Corporation, certify that:
1. I have reviewed this annual report on Form 10-KSB 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 report;
3. Based on my knowledge, the financial statements, and other
financial information included in this 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 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)) 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) Designed such internal control over financial reporting, or
caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting
and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c) 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
d) 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 auditors
and the audit committee of Registrant's Board of Directors:
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: January 14, 2004
/s/ James P. Garrett, Jr.
------------------------------
James P. Garrett, Jr.
Vice President and Chief Financial Officer
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
18 U.S.C. 1350)
The undersigned, James T. Huffman, President and Chief Executive
Officer of CREDO Petroleum Corporation (the "Company"), has
executed this certification in connection with the filing with
the Securities and Exchange Commission of the Company's Annual
Report on Form 10-KSB for the year ended October 31, 2003 (the
"Report").
The undersigned hereby certifies that:
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.
IN WITNESS WHEREOF, the undersigned has executed this
certification as of the 14th day of January, 2004.
/s/ James T. Huffman
------------------------------
James T. Huffman
Chief Executive Officer
Exhibit 32.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. 1350)
The undersigned, James P. Garrett, Jr., Vice President and Chief
Financial Officer of CREDO Petroleum Corporation (the "Company"),
has executed this certification in connection with the filing
with the Securities and Exchange Commission of the Company's
Annual Report on Form 10-KSB for the year ended October 31, 2003
(the "Report").
The undersigned hereby certifies that:
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.
IN WITNESS WHEREOF, the undersigned has executed this
certification as of the 14th day of January, 2004.
/s/ James P. Garrett, Jr.
------------------------------
James P. Garrett, Jr.
Vice President and Chief Financial Officer