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For The Fiscal Year Ended October 31, 2003
Colorado 84-0772991 (State of incorporation) (I.R.S. employer identification number) |
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
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.
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.
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.
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.
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. 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.
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. 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.
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. 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.
No matters were submitted to a vote of security holders during the fourth
quarter of 2003.
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.
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.
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.
2003 2002 2001
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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
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
================================================================
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
====================================================================
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. 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.
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.
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.
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.
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.
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.
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.
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.
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
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.
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.
In December 2002, the Financial Accounting Standards Board issued 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.
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.
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.
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.
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.
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
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.
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
The Board of Directors and Stockholders 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.
Denver, Colorado None.
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.
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
Product Prices and Production
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%
Oil and Gas Activities
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.
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.
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
Natural Gas and Crude Oil Price Hedging
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
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
========================================================================
(2) COMMON STOCK AND PREFERRED STOCK
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
=======================================================================
(3) COMMITMENTS
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
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
=======================================================================
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
Denver, Colorado
December 22, 2003
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.
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.
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.
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.
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.
(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.
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.
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
|
AS AMENDED AS ADOPTED PURSUANT TO
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 |
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 |
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
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 |
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
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 |
End of Filing
|
©2000-2003 CREDO Petroleum Corporation. All rights
reserved. |
