Colorado                             84-0772991
(State of incorporation)                  (I.R.S. employer
                                       identification number)

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: $5,358,000

As of December 31, 2002, the aggregate market value of common stock held by non-affiliates of the registrant was approximately $24,757,000.

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.

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 in oil and gas acquisition, exploration, development and production activities mostly in the Mid-Continent and Rocky Mountain regions of the United States. The company operates in eight states and has ten employees. CREDO is an active operator in Kansas and the Rocky Mountain Region. United is an active operator doing business exclusively in Oklahoma, and SECO owns royalty interests primarily in the Rocky Mountain region. References to years as used in this report indicate fiscal years ended October 31.

Business Activities

The company's primary business activities consist of (i) exploration for and development of oil and gas reserves, (ii) application of its patented Calliope^TM Gas Recovery System ("Calliope") to low pressure gas wells, (iii) oil and gas production, (iv) purchasing producing oil and gas properties, and (v) operation of oil and gas properties for the company's interest and for the interests of third parties.

Except for development, testing and application of Calliope, 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. Applications of Calliope are concentrated below 10,000 feet and, to date, have not required external sources of capital.

The company acts as "operator" of 89 wells pursuant to standard industry Operating Agreements, and it owns working and royalty interests in approximately 822 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. The technology is designed to efficiently lift fluids from wellbores using pressure differentials, and is primarily applicable to mature natural gas wells in low pressure reservoirs at depths below 8,000 feet. 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 fiscal year end, Calliope was installed on eight wells ranging in depth from 6,500 feet to 18,600 feet. Of the eight applications, three rank as the company's first, second and fourth largest producing wells in terms of reserve quantities. Two Calliope applications were not economic due to wellbore problems (scaling and a casing leak) unrelated to the technology. The company believes it has proven Calliope's breadth and economic viability on actual field applications of wells it owns and operates.

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. The fall in oil prices to below $10.00 per barrel in 1999 and the subsequent recovery to over $30.00 in 2000 and 2002 demonstrates oil's extreme price volatility.

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 ("netted") by certain pipelines charges.

Natural gas prices were very volatile during calendar 2001 and 2002. Henry Hub monthly Index prices averaged $4.26 per MBtu (thousand Btus) in 2001 compared to $3.22 in 2002. During 2001, daily spot gas prices rose to historic highs of over $10.00 per MBtu. However, as the year progressed, demand was lost due to a combination of high prices forcing demand out of the market and the warmest U.S. winter on record. That caused the supply of gas left in storage at the end of the 2001-2002 heating season to be abnormally high and resulted in a significant price reversal late in 2001 and in 2002. However, during the summer of 2002 gas storage refill data indicated a bullish imbalance between North American supply and demand. That caused prices to strengthen throughout the 2002 storage refill season and is bullish for 2003 prices. Management 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.

Information concerning the company's major customers is included in Note (6) to the Consolidated Financial Statements. The company's ability to market its oil and gas is generally not dependent on a single purchaser.

Refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information regarding oil and gas markets and prices.

Competition and Regulation

The oil and gas industry is highly competitive. As a small independent oil and gas company, 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 increase the company's cost of doing business and which carry penalties, often substantial, for failure to comply. It is anticipated that the aggregate burden on the company of Federal, state and local regulation will continue to increase particularly in the area of rapidly changing environmental laws and regulations. The company 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 fiscal 2003. The company cannot predict what subsequent legislation or regulations may be enacted or what effect it will have on the company's business.

General

In fiscal 2002, capital spending totaled $2,464,000, the second highest level in the company's history. The company's business focused on two core projects--natural gas drilling along the Anadarko Shelf of Oklahoma and application of its patented Calliope Gas Recovery System. During the year, the company drilled thirteen wells in Oklahoma with interests ranging from 7% to 40%. Eleven of the wells were successful, one was a dry hole and one is undergoing extended evaluation. In addition, 281 coal bed methane wells were drilled on acreage in Wyoming where the company owns small royalty interests. Oklahoma drilling was concentrated in Ellis and Harper Counties on the company's 11,000 gross acre Sand Creek Prospect and its 3,000 gross acre Two Springs Prospect where eight wells were drilled. The wells targeted the Morrow and Chester formations between 7,500 and 9,000 feet. Calliope operations were focused on production of a multimedia presentation for use in introducing Calliope to other companies and on acquiring wells for new Calliope installations. Near the end of the year, the company purchased nine wells intended for new Calliope installations.

In fiscal 2001, capital expenditures totaled $2,688,000, the highest level in company history. CREDO's business focused on two core projects--natural gas drilling along the Anadarko Shelf of Oklahoma and application of Calliope. During the year, the company participated in drilling 11 gas wells in Oklahoma and Wyoming which were successfully completed as commercial gas wells. The company's interest in the wells ranged from 5% to 60%. Oklahoma drilling was concentrated in Ellis and Harper Counties on the company's Sand Creek and Two Springs Prospects with encouraging results. In Wyoming, electrical, gathering and water disposal infrastructures were installed for the 22 coal bed methane wells drilled last year on the company's 10% owned Recluse property. The company also significantly refined and extended the limits of its Calliope technology. The company believes that it has proved the economic viability and breadth of the Calliope system.

For more complete information regarding these activities, refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations--Oil and Gas Activities".

The company's reserves, and the value of those reserves, are concentrated in relatively few properties. At October 31, 2002, approximately 70% of the gross value of the company's estimated proved reserves is concentrated in 20% of its properties (in most cases individual wells). The company's two most valuable producing properties are Calliope wells (the Bradford and Carroll wells) which represent 13% the company's gross reserve value. The two original wells drilled in late 2001 and early 2002 on the company's Sand Creek Prospect in Oklahoma (the Glendena and Redfearn wells) and a well drilled in 2002 on the company's Two Springs Prospect (Emet well) represent 12% of such value. Approximately 600 coal bed methane royalty interest wells located on one property in Sheridan County, Wyoming and a waterflood project in southern Oklahoma account for 6% of such value.

All of these properties, or wells, have limited production histories. In the case of the Calliope wells the limited history is based on the application of Calliope. Accordingly, estimates of reserve quantities and values 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 old down-hole equipment, like tubulars, 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 significant properties which represented 62% in 2002, 62% in 2001 and 63% in 2000 of the total estimated future value of estimated reserves. Remaining reserves were estimated by the company in all years. At October 31, 2002, natural gas represented 82% and crude oil represented 18% 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 $26.76, $20.61 and $31.82 per barrel for oil and $3.74, $2.87 and $4.33 per Mcf for gas as of October 31, 2002, 2001 and 2000, respectively. Amounts do not include estimates of future Federal and state income taxes.

Productive Wells and Developed Acreage

Developed acreage at October 31, 2002 totaled 23,200 net and 120,500 gross acres. At October 31, 2002, the company owned working interests in 58.30 net (196 gross) wells consisting of 19.02 net (46 gross) oil wells and 39.28 net (150 gross) gas wells. In addition, the company owned royalty and production payment interests in approximately 715 oil and gas wells. In 2002, the company sold 3.55 net (9 gross) wells. In the same period, the company drilled and acquired interests in 8.17 net (20 gross) wells in which it did not previously own an interest.

The following table sets forth the number of undeveloped acres (90% located in the Mid-Continent and Rocky Mountain Regions) which will expire during the next five fiscal 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.

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 fiscal 2002.

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.

                              2002                   2001
----------------------------------------------------------------
Fiscal Quarter Ended     High      Low          High      Low
----------------------------------------------------------------
January 31             $ 6.75    $ 5.10       $ 7.69    $ 4.75
April 30                 7.70      5.76         7.50      6.31
July 31                  9.85      7.50        10.30      6.29
October 31               8.82      6.55         7.75      4.87

At December 31, 2002, the company had 3,758 shareholders of record. The company has never paid a dividend and does not expect to pay any dividends in the foreseeable future. Earnings are reinvested in business activities.

ITEM 6.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
                 AND RESULTS OF OPERATIONS

Liquidity and Capital Resources

At fiscal year-end October 31, 2002, working capital was $6,630,000. Cash generated by operating activities (before working capital changes) totaled $2,870,000 in 2002. Cash flow was used primarily to fund oil and gas exploration and development expenditures totaling $2,464,000 and to increase working capital.

Existing working capital and anticipated cash flow are expected to be sufficient to fund fiscal 2003 operations. At fiscal 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 fiscal year-end. The company has no defined benefit plans and no obligations for post retirement employee benefits.

Product Prices, Production and Investments

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 ("netted") by certain pipelines charges.

Significant world events and OPEC's production and pricing policies influence worldwide supply and demand and prices for crude oil and petroleum products. Since 1998, crude oil prices have ranged widely from approximately $10.00 to $30.00 per barrel.

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.

                  2002              2001              2000
-----------------------------------------------------------------
Product      Volume    Price   Volume    Price   Volume    Price
-----------------------------------------------------------------
Gas (Mcf)  1,298,000  $ 3.00   800,000  $ 5.00   668,000  $ 2.84
% change        +62%    -40%      +20%    +76%      -22%    +33%
Oil (bbls)    37,000  $22.01    44,000  $26.45    39,000  $27.88
% change        -16%    -17%      +14%     -5%      -       +78%

The 2002 and 2001 increases in natural gas volumes resulted primarily from successful drilling in Oklahoma. Oil production increased in 2001 as production from a waterflood project peaked and then fell in 2002 as the project began a normal decline. Most other 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.

Surplus cash is invested with professional money managers. The average return on CREDO's investments was three percent in 2002, four percent in 2001, and 14 percent in 2000. At year-end approximately 70% of the investments were with managers who specialize in market timing using U.S. mutual funds. 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 management believes they represent a responsible approach to cash management. In management's opinion, the greatest risk to our investments is the potential for negative market impact from unexpected, major adverse news, like the September 11th terrorist attacks.

Fiscal 2002 capital spending totaled $2,464,000, the second 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 Anadarko Shelf of Oklahoma and application of its patented Calliope Gas Recovery System.

Drilling Activities. In fiscal 2002, the company drilled thirteen wells in Oklahoma with interests ranging from 7% to 40%. Eleven of the wells were successful and one was a dry hole and one is undergoing extended evaluation. In addition, 281 coal bed methane wells were drilled on acreage in Wyoming where the company owns small royalty interests. Oklahoma drilling was concentrated in Ellis and Harper Counties on the company's 11,000 gross acre Sand Creek Prospect and its 3,000 gross acre Two Springs Prospect where eight wells were drilled. The wells targeted the Morrow and Chester formations between 7,500 and 9,000 feet.

To date, 14 wells have been drilled on the two prospects of which 11 were successful, two were dry holes, and one is undergoing extended evaluation. Two of the wells are exceptional for the area. The Glendena well was completed in October 2001 and the Redfearn in April 2002, both from the same Morrow reservoir. The wells each commenced production at 3.0 MMcfg (million cubic feet of gas) per day and are still producing between 1.7 and 1.9 MMcfg per day. To date, they have produced 1.10 and .64 Bcfg (billion cubic feet of gas), respectively. The two wells accounted for 38% of the company's 2002 production and were primarily responsible for the increase in the company's 2002 production. The wells accounted for only 8% of the company's estimated proved reserves values at year-end because their exceptionally high production rates have resulted in rapid depletion of reserves.

Both the Sand Creek and the Two Springs Prospects have ample room for additional wells to be drilled, and the company believes that more exceptional wells are likely. The recently drilled Hudson Trust well, located about one mile east of the Redfearn well, has tested 2.5 MMcfgd from a "natural" (no acid or fracture stimulation) completion with good pressures. Logs and other data look very similar to the Redfearn well. The Hudson Trust well is waiting pipeline connection and the company owns a 32% working interest. The company also owns 45% of the section to the south. That section is bounded on the north by the Hudson Trust well and on the west by the Glendena well and looks very promising for drilling.

Drilling is not restricted to the Sand Creek and Two Springs Prospects. The company has drilled wells and is generating prospects elsewhere on the Northern Anadarko Shelf, in the Oklahoma Panhandle, and north-central Oklahoma. Except for royalty interests, the company currently has no significant interests in the Wyoming coal bed methane play.

The company replaced 122% of the reserves produced in 2002 and its reserve replacement cost was $6.58 per barrel of oil-equivalent (BOE). According to John S. Herold, Inc.'s Global Upstream Performance Review--2002 Final Report, the company's historic three and five-year average reserve replacement costs have been in the top quartile of its peer group.

The company believes that it has proven Calliope will add 0.5 to 2.0 Bcfg to many dead and uneconomic wells and that Calliope is a new generation of gas recovery technology for many low pressure gas wells. Calliope systems are currently installed on six company-owned wells. In terms of undiscounted reserve values at fiscal year-end 2002, Calliope wells rank first, second, ninth and tenth among the company's most valuable producing wells. The six producing Calliope wells account for 19% of the company's reserve value. 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 and the well is still producing about 410 Mcfg per day. Calliope has already recovered over 0.5 Bcfg from the Carroll well and the company estimates it will recover an additional 1.2 Bcfg.

Late in fiscal 2002, the company purchased nine wells intended for new Calliope installations. Each well has substantial Calliope reserve potential ranging from several hundred million to 2.0 billion cubic feet of gas. Installations are expected to be completed on three of the wells in the first calendar quarter of 2003. The remaining wells are in various stages of evaluation. It should be expected that some of the wells will not prove suitable for a Calliope installation.

The company's objective is to install Calliope on more wells. To that end, the company is preparing a multimedia presentation about Calliope to be used to introduce Calliope to certain companies with the objective of joint venturing, licensing, or providing Calliope for a fee. Management expects the final presentation to be complete in March 2003.

Reserves. At fiscal year-end, approximately 70% of the gross value of the company's estimated proved reserves is concentrated in 20% of its properties (in most cases individual wells). The company's two most valuable producing properties are Calliope wells (the Bradford and Carroll wells) which represent 13% of the company's gross reserve value. The Glendena and Redfearn wells (discussed above) and the Emet well drilled in 2002 on the company's Two Springs Prospect (Emet well) represent 12% of such value. Approximately 600 coal bed methane royalty interest wells located on one property in Sheridan County, Wyoming and a waterflood project in southern Oklahoma account for 6% of such value.

All of these properties, or wells, have limited production histories. In the case of the Calliope wells the limited history is based on the application of Calliope. Accordingly, estimates of reserve quantities and values 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 old down-hole equipment, like tubulars, that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well.

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 fiscal 2002 that limited investment opportunities for the market timers that manage the bulk of the company's investments.

In 2001, total revenues rose 38% to $5,807,000 compared to $4,204,000 in 2000. As the oil and gas price/volume table on page 8 shows, total gas price realizations, which reflect hedging transactions, rose 76% to $5.00 per Mcf and oil price realizations fell 5% to $26.45 per barrel. The net effect of these price changes was to increase oil and gas sales by $1,388,000. Hedging gains were $663,000 in 2001 compared to hedging losses of $141,000 in 2000. Gas volumes and oil volumes produced rose 20% and 14%, respectively. The net effect of these volume changes was to increase oil and gas sales by $804,000. The increase in gas production resulted from new wells added during the year. Operating income rose 9% due to drilling supervision income and additional operated properties. Investment income and other declined 60% due primarily to a volatile and down trending stock market during fiscal 2001 which 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.

In 2001, total costs and expenses rose 30% to $2,987,000 compared to $2,307,000 in 2000. The 22% increase in oil and gas production expenses primarily reflects increased production taxes on higher oil and gas sales revenue. DD&A increased 58% due to increases in oil and gas production and amortization of the cost of an exclusive license agreement which was not effective in the prior year. General and administrative expenses rose 14% due to inflationary pressures and additional staffing. Interest expense relates to the exclusive license agreement note payment that was not effective in the prior year. The effective tax rate was 29% in 2001 and 2000.

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, 2002 and 2001

Consolidated Statements of Operations for the Three Years Ended October 31, 2002

Consolidated Statements of Stockholders' Equity for the Three Years Ended October 31, 2002

Consolidated Statements of Cash Flows for the Three Years Ended October 31, 2002

Notes to Consolidated Financial Statements

Independent Auditors' Report

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, 2002, short-term investments are approximately 70% allocated to professional money managers who specialize in market timing using U.S. mutual fund groups. These managers generally enter and exit stock fund trades on a frequent and short-term basis and use mutual fund money market accounts when not invested in stock funds. Other short-term investments consist primarily of professionally managed limited partnerships which provide readily determinable market values. The partnerships are invested primarily in financial instruments. Unrealized gains on limited partnerships total $28,000 and $97,000 at October 31, 2002 and 2001, respectively. 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 2002, 2001 and 2000. 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. Estimated dismantlement, restoration, and abandonment costs are approximately offset by estimated residual values of lease and well equipment. Accordingly, no accrual for such costs has been recorded.

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. Cost 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 $4.27 in 2002, $4.06 in 2001, and $3.21 in 2000.

Unevaluated properties consist primarily of lease acquisition and maintenance costs. Evaluation normally takes three to five years. Of the unevaluated property costs, $98,000 and $121,000 were incurred in 2002 and 2001, 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. All other futures transactions are accounted for as speculative transactions and gains and losses are immediately recognized in other income.

Hedging gains and losses are recognized as adjustments to oil and gas sales as the hedged product is produced. The company had hedging gains of $505,000 and $663,000 in 2002 and 2001, respectively, and hedging losses of $141,000 in 2000. Gains and losses on speculative transactions were immaterial in all years. The company has recorded in other comprehensive income net deferred gains of approximately $53,000 ($37,000 net of tax) related to natural gas hedging transactions of which gains of $72,000 were realized and losses of $19,000 were unrealized. Any hedge ineffectiveness, which is currently immaterial, is immediately recognized in other income. At October 31, 2002, the company's open hedge position totaled 450,000 Mcf covering the months of December 2002 through March 2003 at an average price of $4.12 per Mcf. The hedge represented approximately 100% of the company's estimated gas production for those months. Subsequently, hedges for all months except March 2003 (110,000 Mcf at $4.07) were closed and a $129,000 gain was realized.

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.

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. The assumed exercise of stock options would increase the weighted average shares outstanding from 3,245,000 to 3,316,000 in 2002, 3,110,000 to 3,271,000 in 2001, and from 2,981,000 to 3,175,000 in 2000.

Impact of New Accounting Pronouncement

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards 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. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. This statement is effective for fiscal years beginning after June 15, 2002. The effect of this standard on the company's results of operations and financial position is not expected to be material.

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.

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.

Years Ended October 31  2002              2001                2000
--------------------------------------------------------------------------
                           Weighted           Weighted           Weighted
                 Number    Average   Number   Average    Number  Average
                   of      Exercise    of     Exercise    of     Exercise
                 Options    Price    Options   Price    Options    Price
--------------------------------------------------------------------------
Outstanding at   295,000   $ 3.66     366,667   $ 2.33   361,667   $ 2.10
 beginning
 of year
  Granted         15,000     8.35     125,000     4.90    45,000     4.55
  Exercised     (114,100)    2.01    (196,667)    1.97   (20,000)    1.94
  Cancelled
   or forfeited (100,000)    4.88        -         -     (20,000)    1.63
-------------------------------------------------------------------------
Outstanding
 at end of year   95,900   $ 5.07     295,000   $ 3.66   366,667   $ 2.33
=========================================================================

Options are exercisable at weighted average exercise prices as follows: 57,566 in 2002 at $4.56; 22,084 in 2003 at $4.95; 8,750 in 2004 at $5.90; 3,750 in 2005 at $8.35; and 3,750 in 2006 at $8.35. Options expire with weighted average exercise prices as follows: 13,000 in 2004 at $3.19, 42,900 in 2005 at $4.53, 25,000 in 2006 at $5.00, and 15,000 in 2007 at $8.35. The weighted average remaining contractual life of options outstanding at October 31, 2002 is 3.0 years.

Under current accounting rules the company has elected to follow APB 25 for recognizing the costs associated with employee stock options, and is only subject to the disclosure items of FASB 123. Had compensation cost been recorded under FASB 123, net income and per share amounts for 2002 would have been $1,179,000, or $.36 per share basic and $.36 per share diluted, for 2001 would have been $1,872,000, or $.60 per share basic and $.57 per share diluted, and for 2000 would have been $1,257,000, or $.42 per share basic and $.40 per share diluted. For the purpose of this disclosure, the fair value of each option granted was $3.75 in 2002, $2.41 in 2001 and $2.26 in 2000. 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 volatility of 53% in 2002, 58% in 2001 and 48% in 2000, a risk-free interest rate of 4% in 2002 and 6% for 2001 and 2000, no expected dividends, and an expected term of 5 years.

The company leases office facilities under a five year lease agreement which was amended to extend the lease term for an additional five years effective May 1, 2001. The lease agreement requires payments of $42,000 in 2003 through 2005 and $21,000 in 2006. Total rental expense in fiscal 2002 was $42,000, $43,000 in 2001 and $46,000 in 2000. 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, 2002, the company had $363,000 of statutory depletion carry forward for tax return purposes and $70,000 for financial statement purposes.

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 annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures 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 annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: January 23, 2003

/s/ James T. Huffman
-----------------------------
    James T. Huffman
    Chief Executive Officer

I, John A. Alsko, 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 annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures 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 annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: January 23, 2003

/s/ John A. Alsko
-----------------------------
    John A. Alsko
    Vice President and
    Chief Financial Officer

Exhibit No.     Description


99.1            Certification by Chief Executive Officer under
                Section 906 of the Sarbanes-Oxley Act
                (18 U.S.C. Section 1350)

99.2            Certification by Chief Financial Officer under
                Section 906 of the Sarbanes-Oxley Act
                (18 U.S.C. Section 1350)

The undersigned, James T. Huffman, 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 fiscal year ended October 31, 2002 (the "Report").

The undersigned hereby certifies that:

1. The Report fully complies with the requirements ofSection 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 23rd day of January, 2003.

/s/ James T. Huffman
-----------------------------
James T. Huffman
Chief Executive Officer

The undersigned, John A. Alsko, 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 fiscal year ended October 31, 2002 (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 23rd day of January, 2003.

/s/John A. Alsko
-----------------------------
John A. Alsko
Vice President
and Chief Financial Officer

Home  News  Calliope Technology  Report to Shareholders  Fiscal Year-End Highlights  SEC Filings  Corporate Information
  Corporate Governance  CREDO Stock Quote-NASDAQ Search this Site

©2000-2004 CREDO Petroleum Corporation. All rights reserved.