UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

                       For The Fiscal Year Ended October 31, 2005

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number 0-8877

CREDO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Colorado		84-0772991
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

1801 Broadway, Suite 900, Denver, Colorado 80202-3837
(Address of principal executive offices and zip code)

Registrant’s telephone number, including area code:		(303) 297-2200

Securities registered pursuant to Section 12(b) of the Act:		None

Securities registered pursuant to Section 12(g) of the Act:

          Common Stock, $.10 Par Value          

(Title of class and shares outstanding)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:    o    Yes      þ    No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:    o    Yes      þ    No

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.    þ    Yes      o    No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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-K or any amendment to this Form 10-K.    þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. (See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Act.)

Large accelerated filer    o      Accelerated filer    o      Non-accelerated filer    þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.    o    Yes      þ    No

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of April 30, 2005, the end of the registrant’s most recently completed second quarter was $68,204,000.

As of January 27, 2006, the registrant had 9,163,000 net shares of common stock outstanding.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

Pursuant to instruction G (3) to Form 10-K, Items 10, 11, 12, 13 and 14 are omitted because the company will file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such items will be included in the Proxy Statement to be so filed for the company’s annual meeting of shareholders to be held on or about March 23, 2006 and is hereby incorporated by reference.

NON-GAAP FINANCIAL MEASURES

In this Annual Report on Form 10-K, the company uses the term “cash flow from operating activities (before changes in operating assets and liabilities)” which is considered a non-GAAP financial measure as defined in SEC Regulation S-K Item 10 and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations for a definition of this measure as used in this Annual Report on Form 10-K.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K 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 Annual Report on Form 10-K, other than statements of historical facts, address matters that the company reasonably expects, believes or anticipates will or may occur in the future. Forward-looking statements may relate to, among other things:

	•		the company’s future financial position, including working capital and anticipated cash flow;
	•		amounts and nature of future capital expenditures;
	•		operating costs and other expenses;
	•		wells to be drilled or reworked;
	•		oil and natural gas prices and demand;
	•		existing fields, wells and prospects;
	•		diversification of exploration;
	•		estimates of proved oil and natural gas reserves;
	•		reserve potential;
	•		development and drilling potential;
	•		expansion and other development trends in the oil and natural gas industry;
	•		the company’s business strategy;
	•		production of oil and natural gas;
	•		matters related to the Calliope Gas Recovery System;
	•		effects of federal, state and local regulation;
	•		insurance coverage;
	•		employee relations;
	•		investment strategy and risk; and
	•		expansion and growth of the company’s business and operations.

Although the company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Disclosure of important factors that could cause actual results to differ materially from the company’s expectations, or cautionary statements, are included under “Risk Factors” and elsewhere in this Annual Report on 10-K, including, without limitation, in conjunction with the forward-looking statements. The following factors, among others that could cause actual results to differ materially from the company’s expectations, include:

	•		unexpected changes in business or economic conditions;
	•		significant changes in natural gas and oil prices;
	•		timing and amount of production;
	•		unanticipated down-hole mechanical problems in wells or problems related to producing reservoirs or infrastructure;
	•		changes in overhead costs;
	•		material events resulting in changes in estimates; and
	•		competitive factors.

All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to the company, or persons acting on the company’s behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, the company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

TABLE OF CONTENTS

ITEM				PAGE
PART I
Item 1.		Business			5
		General			5
		Business Activities			5
		Markets and Customers			6
		Competition and Regulation			7
Item 1A.		Risk Factors			7
Item 2.		Properties			11
		General			11
		Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net Revenues			11
		Production, Average Sales Prices and Average Production Costs			12
		Productive Wells and Developed Acreage			12
		Undeveloped Acreage			13
		Drilling			13
		Insurance			14
		Facilities and Employees			14
		Company Website			14
Item 3.		Legal Proceedings			14
Item 4.		Submission of Matters to a Vote of Security Holders			14
PART II
Item 5.		Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			14
Item 6.		Selected Financial Data			16
Item 7.		Management's Discussion and Analysis of Financial Condition and Results of Operations			17
Item 7A.		Quantitative and Qualitative Disclosures about Market Risk			25
Item 8.		Financial Statements and Supplementary Data			25
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			45
Item 9A.		Controls and Procedures			45
Item 9B.		Other Information			45
PART III
Item 10.		Directors and Executive Officers of the Registrant			45
Item 11.		Executive Compensation			45
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			45
Item 13.		Certain Relationships and Related Transactions			45
Item 14.		Principal Accounting Fees and Services			45
PART IV
Item 15.		Exhibits and Financial Statement Schedules			46
Signatures					48
Consent of Independent Registered Public Accounting Firm
Certification by CEO Under Section 302
Certification by CFO Under Section 302
Certification by CEO and CFO Under Section 906

PART I

development, refinement or installation of Calliope. At October 31, 2005, Calliope has been installed on 22 wells ranging in depth from 6,500 feet to 18,400 feet. The company has proven Calliope’s economic viability and flexibility over a wide range of applications.

The company significantly expanded its Calliope operations in 2005 by moving into Texas and Louisiana and has entered into discussions with other companies regarding the formation of joint venture arrangements that utilize Calliope. In addition, higher gas prices have facilitated a new Calliope project to drill wells into low-pressure reservoirs containing substantial stranded gas reserves. Calliope will then be used to recover those reserves. This is expected to enhance the company’s control over monetizing Calliope’s value while providing the opportunity to optimize Calliope’s performance and broaden the range of reservoirs for Calliope applications.

The company acts as “operator” of approximately 108 wells pursuant to standard industry operating agreements. The company owns interests in approximately 1,400 wells of which approximately 1,150 wells, represent small overriding royalty interests.

Markets and Customers

Marketing of the company’s oil and gas production is influenced by many factors which are beyond the company’s control, 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 when, during 2003, the posted price for West Texas intermediate fell below $25.00 per barrel and then rose to over $60.00 per barrel late in 2005.

Natural 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 natural gas under one to five year contracts with major pipeline companies. The sales price is typically based on monthly index prices for the applicable pipeline. Title to the natural gas normally passes to the pipeline at meters located near the wells. The index prices are reduced by certain pipeline charges.

Most of the company’s natural gas production is located in northwestern Oklahoma. There has been significant consolidation among natural 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 there has been increasing concern that a supply/demand imbalance has developed in domestic natural gas based on increasing demand and lower deliverability. This, together with rising oil prices, political unrest and uncertainty in certain major producing regions, supply vulnerability to natural disasters, such as hurricanes, and active speculation in the natural gas futures market has caused natural gas prices to become increasingly volatile. The company expects 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 Annual Report on Form 10-K, the company periodically hedges the price of a portion of its estimated natural gas production in the form of forward short positions and collars 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. Political unrest and market uncertainty in the Middle East, Africa, South America and former Soviet Union, OPEC’s renewed cooperation in managing the price of its produced oil, and increased demand from countries with developing economies, such as China and India, have resulted in higher world-wide oil prices during the past several years.

Information concerning the company’s major customers is included in Note (8) 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, human 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 2006. The company cannot predict what subsequent legislation or regulations may be enacted or what effect they might have on the company’s business.

ITEM 1A.		RISK FACTORS

In evaluating the company, careful consideration should be given to the following risk factors, in addition to the other information included or incorporated by reference in this Annual Report on Form 10-K. Each of these risk factors could adversely affect the company’s business, operating results and financial condition, as well as adversely affect the value of an investment in the company’s common stock.

Volatility of oil and natural gas prices could adversely affect the company’s profitability and financial condition.

The company’s performance in terms of revenues, operating results, profitability, future rate of growth and the carrying value of its oil and natural gas properties is significantly impacted by prevailing market prices for oil and natural gas. Any substantial or extended decline in the price of oil or natural gas could have a material adverse effect on the company. It could reduce the company’s operating cash flow as well as the value and, to a lesser degree, the quantity of its oil and natural gas reserves.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile. Relatively minor changes in supply or demand can have a significant effect on oil and natural gas prices. Some of the factors affecting oil and natural gas prices which are beyond the company’s control include:

	•		worldwide and domestic supplies of oil and natural gas;
	•		worldwide and domestic demand for oil and natural gas;
	•		the ability of the members of OPEC to agree to and maintain oil price and production controls;
	•		political instability or armed conflict in oil or natural gas producing regions;
	•		worldwide and domestic economic conditions;
	•		the availability of transportation facilities;
	•		weather patterns; and
	•		actions of governmental authorities.

Competition for opportunities to replace and increase production and reserves is intense and could adversely affect the company.

Properties produce at a declining rate over time. In order to maintain current production rates the company must add new oil and natural gas reserves to replace those being depleted by production. Competition within the oil and natural gas industry is intense and many of the company’s competitors have financial and other resources substantially greater than those available to the company. This could place the company at a disadvantage with respect to accessing opportunities to maintain, or increase, its oil and natural gas reserve base.

In the event that the company does not have adequate cash flow to fund operations, it may be required to use debt or equity financing.

The company makes, and will continue to make, significant expenditures to find, acquire, develop and produce oil and natural gas reserves. If oil and natural gas prices decrease, or if operating difficulties are encountered that result in cash flow from operations being less than expected, the company may have to reduce capital expenditures unless additional funds are raised through debt or equity financing. Debt or equity financing or cash generated by operations may not be available to the company in sufficient amounts or on acceptable terms to meet these requirements.

Future cash flows and the availability of financing will be subject to a number of variables, such as:

	•		the company’s success in locating and producing new reserves;
	•		the level of production from existing wells; and
	•		prices of oil and natural gas;

Issuing equity securities to satisfy the company’s financing requirements could cause substantial dilution to existing stockholders. Debt financing could make the company more vulnerable to competitive pressures and economic downturns.

Reserve quantities and values are subject to many variables and estimates and actual results may vary.

This Annual Report on Form 10-K contains estimates of the company’s proved oil and natural gas reserves and the estimated future net revenues from those reserves. Any significant negative variance in these estimates could have a material adverse effect on the company’s future performance.

Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data.

Reserve estimates are dependent on many variables, and therefore, as more information becomes available, it is reasonable to expect that there will be changes to the estimates. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by the company. In addition, estimates of proved reserves will be adjusted in the future to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond the company’s control.

As of October 31, 2005, approximately 11% of the company’s estimated proved reserves are classified as proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is generally based on volumetric calculations rather than the performance data used to estimate reserves for producing properties. Recovery of proved undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Revenues from proved developed non-producing and proved undeveloped reserves will not be realized until some time in the future. The reserve estimate includes an estimate of the capital expenditures required to develop these reserves as well as the

timing of such expenditures. Although the company has prepared estimates of its proved undeveloped reserves and the associated development costs in accordance with industry standards, they are based on estimates, and actual results may vary.

You should not interpret the present value of estimated reserves, or PV-10, as the current market value of reserves attributable to the company’s properties. The 10% discount factor, which we are required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which the company’s business or the oil and natural gas industry in general are subject. The company has based the PV-10 on prices and costs as of the date of the reserve estimate, in accordance with applicable regulations. Actual future prices and costs may be materially higher or lower. In addition to the price volatility factors discussed above, factors that will affect actual future net cash flows, include:

	•		the amount and timing of actual production;
	•		curtailments or increases in consumption by oil and natural gas purchasers; and
	•		changes in governmental regulations or taxation.

As a result, the company’s actual future net cash flows could be materially different from the estimates included in this Annual Report on Form 10-K.

The company’s reserve quantities and values are concentrated in a relative few properties and fields.

The company’s reserves, and reserve values, are concentrated in 54 properties which represent 28% of the company’s total properties but a disproportionate 76% of the discounted value (at 10%) of the company’s reserves. Individual wells on which Calliope is installed comprise 22% of these significant properties and 32% of the discounted reserve value of such properties. Relatively new wells comprise 22% of these significant properties and 24% of the discounted reserve value of such properties.

Estimates of reserve quantities and values for these properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, Calliope is generally installed on mature wells. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well.

Competition for materials and services is intense and could adversely affect the company.

Major oil companies, independent producers, and institutional and individual investors are actively seeking oil and gas properties throughout the world, along with the equipment, labor and materials required to develop and operate properties. Shortages for equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. Many of the company’s competitors have financial and technological resources which exceed those available to the company.

The company’s hedging arrangements involve credit risk and may limit future revenues from price increases.

To manage the company’s exposure to price risks associated with the sale of natural gas, the company periodically enters into hedging transactions for a portion of its estimated natural gas production. These transactions may limit the company’s potential gains if natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose the company to the risk of financial loss in certain circumstances, including instances in which:

	•		the company’s production is less than expected;
	•		the contractual counterparties fail to perform under the contracts; or

•

a sudden, unexpected event, materially impacts natural gas prices.

The terms of the company’s hedging agreements may also require that it furnish cash collateral, letters of credit or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by the company to the counterparties, which would encumber the company’s liquidity and capital resources.

In addition, hedging transactions using derivative instruments involve basis risk. Basis risk in a hedging contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective.

The marketability of the company’s natural gas production is dependent upon infrastructure, such as gathering systems, pipelines and processing facilities, that the company does not own or control.

The marketability of the company’s natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities necessary to move the company’s natural gas production to market. The company does not own this infrastructure and is dependent on other companies to provide it.

Oil and natural gas operations are inherently risky.

The oil and natural gas business involves a variety of risks, including the risks of operating hazards such as fires, explosions, cratering, blow-outs, and encountering formations with abnormal pressures. The occurrence of any of these risks could result in losses. We maintain insurance against some, but not all, of these risks. Management believes that the level of insurance against these risks is reasonable and is in accordance with industry practices. The occurrence of a significant event, however, that is not fully insured could have a material adverse effect on our financial position and results of operations.

The company’s operations are subject to a variety of contractual, regulatory and other constraints.

The production and sale of oil and natural gas are subject to a variety of federal, state and local government regulations. These include:

	•		the prevention of waste;
	•		the discharge of materials into the environment;
	•		the conservation of oil and natural gas;
	•		pollution;
	•		permits for drilling operations;
	•		drilling bonds;
	•		reports concerning operations;
	•		the spacing of wells; and
	•		the unitization and pooling of properties.

Because current regulations covering the company’s operations are subject to change at any time, and despite its belief that it is in substantial compliance with applicable environmental and other government laws and regulations, the company may incur significant costs for future compliance.

Increases in taxes on energy sources may adversely affect the company’s operations.

Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas products sold. Historically, there has been on-going consideration by federal, state and local officials concerning a variety of energy tax proposals. Such matters are beyond the company’s ability to accurately predict or control.

The company is highly dependent on the services of one of its officers.

The company is highly dependent on the services of James T. Huffman, our President and Chief Executive Officer. The loss of Mr. Huffman could have a material adverse effect on the company.

McCartney Engineering, Inc., an independent petroleum engineering firm, estimated proved reserves for the company’s properties which represented 63% in 2005, 61% in 2004, and 64% in 2003 of the total estimated future value of estimated reserves. Remaining reserves were estimated by the company in all years. At October 31, 2005, natural gas represented 87% and crude oil represented 13% of total reserves denominated in equivalent Mcf’s 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 (8) to the Consolidated Financial Statements where additional reserve information is provided. The average price used to calculate estimated future net revenues was $55.59, $50.43 and $28.64 per barrel of oil and $10.26, $5.84, and $3.99 per Mcf of gas as of October 31, 2005, 2004, and 2003, respectively. Amounts do not include estimates of future Federal and state income taxes.

Production, Average Sales Prices and Average Production Costs

The company’s net production quantities and average price realizations per unit for the indicated years are set forth below. Price realizations are net of any hedging gains or losses.

Average production costs, including production taxes, per equivalent Mcf of production (using a six Mcf of gas to one barrel of oil conversion ratio) were $1.35, $1.06, and $0.97 per Mcfe in 2005, 2004, and 2003, respectively.

Productive Wells and Developed Acreage

Developed acreage at October 31, 2005 totaled 26,000 net and 118,000 gross acres. At October 31, 2005, the company owned working interests in 75.45 net (257 gross) wells consisting of 16.23 net (43 gross) oil wells and 59.22 net (214 gross) natural gas wells. In addition, the company owned royalty and production payment interests in approximately 1,150 wells, primarily coal bed methane located in Wyoming. In 2005, the company sold or abandoned 1.30 net (4 gross) wells. In the same period, the company drilled and acquired interests in 7.22 net (31 gross) wells in which it did not previously own an interest.

Undeveloped Acreage

The following table sets forth the number of undeveloped acres (primarily located in the Mid-Continent and Rocky Mountain Regions) which will expire during the next five years (and thereafter) unless production is established in the interim. Undeveloped acres “held-by-production” represent the undeveloped portions of producing leases which will not expire until commercial production ceases.

In general, “royalty” interests are non-operated interests which are not burdened by costs of exploration or lease operations, while “working interests” have operating rights and participate in such costs.

Drilling

The following tables set forth the number of gross and net oil and gas wells in which the company has participated and the results thereof for the periods indicated.

Insurance

The company believes that its existing insurance coverage is adequate to protect it from the risks associated with the ongoing operation of its business. This coverage includes commercial property, liability and auto, workers compensation, inland marine and excess liability.

Facilities and Employees

The company’s corporate headquarters are located at 1801 Broadway, Suite 900, Denver, Colorado, in approximately 4,000 square feet occupied under a lease. The company believes

that this space is adequate for its current needs. The company’s current lease expires in April 2006. The company has finalized negotiations with its landlord and expects to renew its office lease in the second quarter of 2006.

As of October 31, 2005, the company had 12 employees. None of the company’s employees is subject to a collective bargaining agreement, and the company considers relations with its employees to be good.

Company Website

Information related to the following items, among other information, can be found on the company’s website at www.credopetroleum.com: (a) company filings with the Securities and Exchange Commission, (b) company press releases, (c) officers, directors and ten percent shareholders filings on Forms 3, 4 and 5, and (d) the company’s Code of Ethics and Audit Committee Charter. The company’s website is not a part of, or incorporated by reference in, this Annual Report on Form 10-K.

A description of the company’s equity compensation plan is contained in Note 2 to the Consolidated Financial Statements contained elsewhere in this document.

ITEM 6.		SELECTED FINANCIAL DATA

The following table sets forth certain financial information with respect to the company and is qualified in its entirety by reference to the historical financial statements and notes thereto of the company included in Item 8, “Financial Statements and Supplementary Data.” The statement of operations and balance sheet data included in this table for each of the five years in the period ended October 31, 2005 were derived from the audited financial statements and the accompanying notes to those financial statements.

ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

substitute for operating income, cash flows from operating activities or any other measure for determining the company’s operating performance or liquidity that is calculated in accordance with generally accepted accounting principles. In addition, because cash flow from operating activities (before changes in operating assets and liabilities) is not calculated in accordance with generally accepted accounting principles, it may not necessarily be comparable to similarly titled measures employed by other companies. A reconciliation of cash flow from operating activities (before changes in operating assets and liabilities) can be made by adding net income, depreciation, depletion and amortization expense, deferred income taxes, the cumulative effect of change in accounting principal and other as in the table below.

Off-Balance Sheet Financing

The company has no off-balance sheet financing arrangements at October 31, 2005.

Product Prices and Production

Refer to Item 1., “Markets and Customers”, for discussion of oil and gas prices and marketing.

Although product prices are key to the company’s ability to operate profitably and to budget capital expenditures, they are beyond the company’s control and are difficult to predict. Since 1991, the company has periodically hedged the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated. Hedging transactions typically take the form of forward short positions and collars on the NYMEX futures market, and are closed by purchasing offsetting positions. Such hedges, which are accounted for as cash flow hedges, do not exceed estimated production volumes, are expected to have reasonable correlation between price movements in the futures market and the cash markets where the company’s production is located, and are authorized by the company’s Board of Directors. Hedges are expected to be closed as related production occurs but may be closed earlier if the anticipated downward price movement occurs or if the company believes that the potential for such movement has abated.

The company recognizes all derivatives (consisting solely of cash flow hedges) on the balance sheet at fair value at the end of each period. Changes in the fair value of a cash flow hedge are recorded in Stockholders’ Equity as Accumulated Other Comprehensive Income(Loss) on the Consolidated Balance Sheets and then are reclassified into the Consolidated Statement of Operations as the underlying hedged item affects earnings. Amounts reclassified into earnings related to natural gas hedges are included in oil and gas sales.

Hedging gains and losses are recognized as adjustments to gas sales as the hedged product is produced. The company had after tax hedging losses of $518,000 in fiscal 2005 and after tax hedging losses of $516,000 in fiscal 2004. Any hedge ineffectiveness, which was not material for the three years ended October 31, 2005, is immediately recognized in gas sales. Subsequent to October 31, 2005, the company closed its December 2005 and January 2006 hedge contracts at expiration (120 MMbtu) with an after tax hedging loss of $227,000. The company currently has no open hedge positions.

The company has a hedging line of credit with its bank which is available, at the discretion of the company, to meet margin calls. To date, the company has not used this facility and maintains it only as a precaution related to possible margin calls. The maximum credit line is $2,000,000 with interest calculated at the prime rate. The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments and prohibits unfunded debt in excess of $500,000. It expires on October 31, 2006.

Oil and natural gas sales volume and price realization comparisons for the indicated years ended October 31 are set forth below. Price realizations include hedging gains and losses.

Increases in natural gas volumes resulted primarily from successful drilling in Oklahoma. Most oil and condensate volumes are associated with natural gas production and, therefore, vary from well to well depending on the volume and “richness” of the natural gas produced. Significant Properties (see definition on page 11) contributed 41% of 2005 production on a gas-equivalent basis.

As to Significant Properties, wells drilled since 2001 contributed 40% of 2005 production while Calliope wells installed during the same period contributed 17% of such production. Refer to Item 2, “Properties”, for disclosures regarding reserve values on Significant Properties.

Oil and Gas Activities

General. Capital spending in 2005 totaled $7,327,000, a 3% increase over last year. 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 has recently expanded into South Texas through an exploration program using 3-D seismic to define the Vicksburg, Frio, Queen and Wilcox prospects in Hidalgo and Jim Hogg counties and into north-central Kansas through an exploration program using 3-D seismic to define Lansing-Kansas City oil prospects in Graham and Sheridan counties. The company believes that, in combination, its drilling and Calliope projects provide an excellent (and possibly unique) balance for achieving its goal of adding long-lived natural gas reserves and production at reasonable costs and risks.

The company will continue to actively pursue adding reserves through its two core projects in fiscal 2006 and expects these activities to be a reliable source of reserve additions. However, the timing and extent of such activities can be dependent on many factors which are beyond the company’s control, including but not limited to, the availability of oil field services such as drilling rigs, production equipment and related services and access to wells for application of the company’s patented liquid lift system on low pressure gas wells. The prevailing price of oil and natural gas has a significant affect on demand and, thus, the related cost of such services and wells.

Drilling Activities. The company currently drills primarily on its 73,000 gross acre inventory located along the northern shelf of the Anadarko Basin. During 2005, the company drilled 12 wells in Oklahoma with working interests ranging up to 69%. Ten of these wells have been completed as producers. The wells, which ranged from development to rank wildcat, are located on five different prospects. Drilling expenditures were concentrated on the company’s acreage inventory located along the northern shelf of the Anadarko Basin of

Oklahoma. The wells targeted the Morrow, Oswego and Chester formations between 7,000 and 10,000 feet. A substantial number of additional wells are anticipated for the area.

Drilling is not restricted to the northern Anadarko shelf acreage. The company is generating prospects elsewhere in the Northern Anadarko Basin, in the Oklahoma Panhandle, north-central Oklahoma, north-central Kansas and South Texas. In addition, 14 coal bed methane wells were drilled on acreage in Wyoming where the company owns working interests of approximately 10%, and 160 coal bed methane wells were drilled on Wyoming acreage where the company owns small royalty interests.

This year the company significantly expanded both the volume and breadth of its exploration program with new projects in South Texas and north-central Kansas. It is the company’s intention to diversify its exploration geographically, scientifically, and in terms of capital, risk and reserve potential. Compared to drilling in Oklahoma, the South Texas project involves higher costs and greater risks but significantly higher per well reserve potential. The north-central Kansas project is geared to oil exploration and has excellent potential to add significant reserves at moderate costs and risks. Both projects are in areas where 3-D seismic is a proven exploration tool and where continuing refinements are providing excellent exploration success. Equally as important, both exploration teams specialize in their respective geographic areas and have been highly successful finding new reserves using 3-D seismic.

As previously discussed, drilling of generated South Texas prospects is not covered by the exploration agreement and, therefore, is not a capital requirement under the exploration agreement. Drilling is expected to commence in early 2006. The initial four well drilling program will be located in Hidalgo and Jim Hogg Counties and wells will range in depth from 10,200 to 15,500 feet with an estimated total cost (8\8ths basis) of approximately $14,000,000. Completed well costs are estimated to range from $1,500,000 at 10,000 feet to $6,500,000 at 15,500 feet. The company is currently evaluating what portion of its 37.5% after payout interest to retain for direct participation.

The north-central Kansas project agreement provides for approximately 28 square miles of 3-D seismic to be collected and evaluated and five exploratory wells to be drilled. Completed well costs are estimated to be approximately $280,000. Drilling will commence after new 3-D seismic shooting and interpretation is completed, which is expected in mid-2006.

The company replaced 106% of its 2005 production. Per unit finding costs were $2.73 per Mcf in gas equivalents excluding start-up costs in South Texas and north-central Kansas.

All of the company’s oil and natural gas properties are located on-shore in the continental United States. The company’s future drilling activities may not be successful, and its overall drilling success rate may change. Unsuccessful drilling activities could have a material adverse effect on the company’s results of operations and financial condition. Also, the company may not be able to obtain the right to drill in areas where it believes there is significant potential for the company.

Calliope Gas Recovery Technology. The company owns the exclusive right to a patented technology known as the Calliope Gas Recovery System. Calliope can achieve substantially lower flowing bottom hole pressure than conventional production methods because it does not rely on reservoir pressure to lift liquids. Lower bottom hole pressure can translate into recovery of substantial additional natural gas reserves.

Calliope has proven to be reliable and flexible over a wide range of applications on wells the company owns and operates. It has also proven to be consistently successful. Accordingly, the company has recently begun implementing strategies designed to widen the envelope of wells on which Calliope should be installed.

Realizing Calliope’s value continues to be a top priority of the company. The company is focused on three fronts to increase the number of Calliope installations: expanding the geographic region for purchasing Calliope candidate wells from third parties, joint ventures

with larger companies, and drilling wells into low-pressure gas reservoirs for the purpose of using Calliope to recover stranded natural gas reserves.

Higher natural gas prices have facilitated a new project to drill wells into low-pressure natural gas reservoirs. Many low-pressure reservoirs, including abandoned fields, contain substantial stranded natural gas that can be recovered by Calliope. This project is designed to ramp-up the number of Calliope installations, improve the company’s control over monetizing Calliope’s value, control configuration of wellbores for optimum Calliope performance, and broaden the range of reservoirs for Calliope applications. Completed well costs are estimated to be approximately $2,200,000 including installation of Calliope. The company expects to commence drilling wells for Calliope applications in mid-2006 and is considering bringing in industry participants for the project.

As previously reported, joint venture presentations have been made to a range of companies, including several of the major oil and gas companies as well as several large independents. All of these companies have expressed a keen interest in Calliope, and joint venture discussions are continuing with several of those companies, including evaluation of candidate wells.

In addition to joint ventures and the Calliope drilling project, the company has successfully expanded its Calliope operations into Texas and Louisiana. In southwest Texas, the company recently completed two prototype Calliope installations which once again broadened Calliope’s down-hole application, successfully lifting several times more fluid volume than Calliope has previously lifted from the company’s Oklahoma wells. Although this prototype Calliope configuration limits the amount of natural gas that can be produced during the start-up and dewatering phase, after initial dewatering and once liquid production stabilizes, the system can be optimized to allow greater natural gas flow. In Louisiana, the company recently completed the purchase of a Calliope candidate well in Acadia Parish. The well is currently dead and will be evaluated for a Calliope installation in the first quarter of 2006. These efforts are being spearheaded on a full-time basis by a highly qualified petroleum engineer based in Houston.

Reserves. Refer to Item 2, “Properties, General, Estimated Proved Oil and Gas Reserves and Future Net Reserves”, for information regarding oil and gas reserves.

Results of Operations

In 2005, total revenues increased 35% to $13,957,000 compared to $10,314,000 last year. As the oil and gas price/volume table on page 19 shows, total gas price realizations, which reflect hedging transactions, increased 34% to $6.16 per Mcf and oil price realizations increased 39% to $50.90 per barrel. The net effect of these price changes was to increase oil and gas sales by $3,253,000. Hedging losses were $719,000 in 2005 compared to $717,000 in 2004. During the same period, the company’s gas equivalent production increased 5% resulting in an increase to oil and gas sales of $523,000. Operating income increased 11% due to an increase in drilling and production supervision income related to operated wells. Investment and other income decreased 57% primarily due to a decrease in other income.

In 2005, total costs and expenses rose 28% to $6,695,000 compared to $5,244,000 for last year. Oil and gas production expenses increased 33% due primarily to new wells. Depreciation, depletion and amortization (“DD&A”) increased 37% primarily due to increased production volumes and an increase in the amortizable full cost pool. General and administrative expenses increased 8% primarily due to increases in professional fees and salaries and benefit costs related primarily to increased administration resulting from rapid growth, transition from small business SEC reporting status to full reporting status, compliance with Sarbanes-Oxley regulations and preparation for accelerated filing requirements related to the company’s quarterly and annual SEC reports. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28% for the 2005 and 2004 periods.

In 2004, total revenues rose 21% to $10,314,000 compared to $8,491,000 in 2003. As the oil and gas price/volume table on page 19 shows, total gas price realizations, which reflect hedging transactions, rose 2% to $4.60 per Mcf and oil price realizations rose 32% to $36.57 per barrel. The net effect of these price changes was to increase oil and gas sales by $448,000. Hedging losses were $717,000 in 2004 compared to $92,000 in 2003. Gas and oil production both rose 18%. The net effect of these volume changes was to increase oil and gas sales by $1,425,000. The increase in volumes resulted primarily from successful drilling in 2004 and 2003. Operating income rose 13% due to drilling supervision income and additional operated wells. Investment income and other fell 26% due primarily to market declines.

In 2004, total costs and expenses rose 24% to $5,244,000 compared to $4,244,000 in 2003. Oil and gas production expenses rose 29% due primarily to increased production taxes on higher revenues and new wells added during the year. DD&A increased 31% due primarily to increased production volume. General and administrative expenses rose 10% primarily due to increases in salaries and benefit costs. Interest expense relates to the exclusive license agreement note payment. The effective tax rate was 28% in 2004 and 2003.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires the company to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts. The company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and natural gas properties, the accounting for oil and natural gas reserves, and the estimate of its asset retirement obligations.

Oil and Gas Properties. The company uses the full cost method of accounting for costs related to its oil and natural gas properties. Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method. Depreciation, depletion and amortization is a significant component of oil and natural gas properties. A change in proved reserves without a corresponding change in capitalized costs will cause the depletion rate to increase or decrease.

Both the volume of proved reserves and any estimated future expenditures used for the depletion calculation are based on estimates such as those described under “Oil and Gas Reserves” below.

The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling.

The company has made only one ceiling write-down in its 27-year history. That write down was made in 1986 after oil prices fell 51% and natural gas prices fell 45% between fiscal year end 1985 and 1986.

Changes in oil and natural gas prices have historically had the most significant impact on the company’s ceiling test. In general, the ceiling is lower when prices are lower. Even though oil and natural gas prices can be highly volatile over weeks and even days, the ceiling calculation dictates that prices in effect as of the last day of the test period be

used and held constant. The resulting valuation is a snapshot as of that day and, thus, is generally not indicative of a true fair value that would be placed on the company’s reserves by the company or by an independent third party. Therefore, the future net revenues associated with the estimated proved reserves are not based on the company’s assessment of future prices or costs, but rather are based on prices and costs in effect as of the end the test period.

Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the company’s oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves. Oil and natural gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the company’s control. Accordingly, reserve estimates are often different from the quantities of oil and natural gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

The company’s reserves, and reserve values, are concentrated in 54 properties (“Significant Properties”). Some of the Significant Properties are individual wells and others are multi-well properties. At October 31, 2005, the Significant Properties represent 28% of the company’s total properties but a disproportionate 76% of the discounted value (at 10%) of the company’s reserves. Individual wells on which the company’s patented liquid lift system is installed comprise 22% of the Significant Properties and represent 32% of the discounted reserve value of such properties. Relatively new wells comprise 22% of the Significant Properties and represent 24% of the discounted value of such properties.

Estimates of reserve quantities and values for certain Significant Properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, the company’s patented liquid lift system is generally installed on mature wells. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well. Historically, performance of the company’s wells has not caused significant revisions in its proved reserves.

Price changes will affect the economic lives of oil and gas properties and, therefore, price changes may cause reserve revisions. Price changes have not caused significant proved reserve revisions by the company except in 1986 when a 51% decline in oil prices and a 45% decline in natural gas prices resulted in an 8.7% reduction in estimated proved reserves. Based upon this historical experience, the company does not believe its reserve estimates are particularly sensitive to prices changes within historical ranges.

One measure of the life of the company’s proved reserves can be calculated by dividing proved reserves at fiscal year end 2005 by production for fiscal year 2005. This measure yields an average reserve life of nine years. Since this measure is an average, by definition, some of the company’s properties will have a life shorter than the average and some will have a life longer than the average. The expected economic lives of the company’s properties may vary widely depending on, among other things, the size and quality, natural gas and oil prices, possible curtailments in consumption by purchasers, and changes in governmental regulations or taxation. As a result, the company’s actual future net cash flows from proved reserves could be materially different from its estimates.

Asset Retirement Obligations. Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” requires that the company estimate the future cost of asset retirement obligations, discount that cost to its present value, and record a corresponding asset and liability in its Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, market risk premiums, useful life, and cost of capital. The nature of these estimates requires the company to make judgments based on historical experience and future

expectations. Revisions to the estimates may be required based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis.

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 153, Exchange of Non-monetary Assets. This statement is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of the assets exchanges. SFAS 153 is effective for non monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The company does not expect that the adoption of SFAS No. 153 will have an impact on the company’s financial statements.

The Securities and Exchange Commission (“SEC”) recently issued guidance on the ways in which its full-cost rules interact with the accounting requirements that the FASB established for asset retirement obligations — specifically, how SFAS No. 143, Accounting for Asset Retirement Obligations, interacts with the full-cost requirements in Rule 4-10 of Regulation S-X (Rule 4-10). The SEC’s new guidance appears in Staff Accounting Bulletin (SAB) No. 106 issued in October 2004. The adoption of SAB No. 106 did not have an impact on the company’s financial statements.

In March 2005, the FASB issued Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations — An Interpretation of SFAS No. 143”, which clarifies the term “conditional asset retirement obligation” used in SFAS No. 143, “Accounting for Asset Retirement Obligations”, and specifically when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption did not have an impact on the company’s financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”, which replaces Accounting principles Board Opinion No. 20, Accounting Changes and SFAS No. 3. SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The company does not expect that the adoption of SFAS No. 154 will have an impact on the company’s financial statements.

In December 2004, the FASB issued SFAS No. 123 (Revised 2004), “Share-Based Payment”, that addresses the accounting for share-based payment transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R addresses all forms of share-based payment awards, including shares issued under employee stock purchase plans, stock options, restricted stock and stock appreciation rights. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25, “Accounting for Stock Issued to Employees”, that was provided in Statement 123 as originally issued. Under SFAS No. 123R companies are required to record compensation expense for all share based payment award transactions measured at fair value. This statement is effective for fiscal years beginning after June 15, 2005. The company will implement SFAS 123R in the first quarter of the company’s fiscal year beginning November 1, 2005. The company is currently evaluating the impact of this new standard, and estimates that the impact of applying the various provisions of SFAS No. 123R will result in an expense similar to the pro-forma effects reported elsewhere in this Annual Report on Form 10-K if all current unvested stock options vest on the scheduled dates and the assumptions in the Black-Scholes model remain the same.

CONSOLIDATED BALANCE SHEETS
October 31, 2005 and 2004

CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
ASSETS		2005				2004
Current assets:
Cash and cash equivalents		$	1,935,000			$	518,000
Short-term investments			5,495,000				6,371,000
Receivables:
Trade			1,003,000				1,019,000
Accrued oil and gas sales			2,776,000				2,051,000
Other current assets			245,000				58,000
Total current assets			11,454,000				10,017,000
Long-term assets:
Oil and gas properties, at cost, using full cost method:
Unevaluated oil and gas properties			3,452,000				2,174,000
Evaluated oil and gas properties			36,121,000				30,072,000
Less: accumulated depreciation, depletion and amortization of oil and gas properties			(15,022,000	)			(12,737,000	)
Net oil and gas properties, at cost, using full cost method			24,551,000				19,509,000
Exclusive license agreement, net of accumulated amortization of $361,000 in 2005 and $291,000 in 2004			338,000				408,000
Inventory			1,288,000				883,000
Other, net			213,000				159,000
Total assets		$	37,844,000			$	30,976,000
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	3,426,000			$	4,394,000
Income taxes payable			331,000				12,000
Total current liabilities			3,757,000				4,406,000
Long-term liabilities:
Deferred income taxes, net			5,978,000				4,605,000
Exclusive license obligation, less current obligations of $64,000 in 2005 and $58,000 in 2004			233,000				297,000
Asset retirement obligation			929,000				748,000
Total liabilities			10,897,000				10,056,000
Commitments:
Stockholders’ equity:
Preferred stock, no par value, 5,000,000 shares authorized, none issued			—				—
Common stock, $.10 par value, 20,000,000 shares authorized, 9,510,000 shares issued and outstanding in 2005 and 2004			951,000				951,000
Capital in excess of par value			12,486,000				12,146,000
Treasury stock, at cost, 393,000 shares in 2005, and 454,000 shares in 2004			(125,000	)			(452,000	)
Accumulated other comprehensive loss			(306,000	)			(437,000	)
Retained earnings net of $6,277,000 related to 20% stock dividend in 2003			13,941,000				8,712,000
Total stockholders’ equity			26,947,000				20,920,000
Total liabilities and stockholders’ equity		$	37,844,000			$	30,976,000

See accompanying notes to consolidated financial statements.

See accompanying notes to consolidated financial statements.