Edgar Filing: ASPEN GROUP RESOURCES CORP

Aspen Group

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

[ ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF
THE SECURITIES EXCHANGE ACT OF 1934

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

For the fiscal year ended December 31, 2003

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

For the transition period from _______n/a__________ to ________________

ASPEN GROUP RESOURCES CORPORATION

(Exact name of Registrant as specified in its Charter)

Yukon, Canada
(State or other jurisdiction of incorporation or organization)

0-28814
(Commission File Number)

98-0164357
(I.R.S. Employer Identification No.)

One North Hudson, Suite 1000
Oklahoma City, Oklahoma 73102
(Address of principal executive offices)
Telephone Number (405) 278-8800
(Registrant's telephone number, including area code)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Class		Name on each exchange which registered
None		None

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

Title of Class

Common Stock, without par value

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

Title of Class

None

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the year ended December 31, 2003:

51,120,354 common shares

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 [ ]

Indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 [X] Item 18 [ ]

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TABLE OF CONTENTS

PART I

ITEM 1 IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

ITEM 2 OFFER STATISTICS AND EXPECTED TIMETABLE

ITEM 3 KEY INFORMATION

A) Selected Financial Data

B) Capitalization and Indebtedness

C) Reasons for the Offer and Use of Proceeds

D) Risk Factors

ITEM 4 INFORMATION ON THE COMPANY

A) History and Development of the Company

B) Business Overview

C) Organizational Structure

D) Property, Plant and Equipment Facilities

ITEM 5 OPERATING AND FINANCIAL REVIEW AND PROSPECTS

A) Operating Results

B) Liquidity and Capital Resources

C) Research and Development, Patents and Licenses, etc.

D) Trend Information

E) Off Balance Sheet Arrangements

F) Contractual Obligations

ITEM 6 Directors, Senior Management and Employees

A) Directors and Senior Management

B) Compensation

C) Board Practices

D) Employees

E) Share Ownership

ITEM 7 Major Shareholders and Related Party Transactions

A) Major Shareholders

B) Transactions with Affiliates

C) Interests of Experts and Counsel

ITEM 8 Financial Information

A) Consolidated Statements and Other Financial Information

B) Significant Changes

ITEM 9 Listing

A) Listing Details

B) Plan of Distribution

C) Markets

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D) Selling Shareholders

E) Dilution

F) Expenses of the Issue

ITEM 10 Additional Information

A) Share Capital

B) Articles of Incorporation and By-laws

C) Material Contracts

D) Exchange Controls

E) Taxation

F) Dividends and Paying Agents

G) Statement by Experts

H) Documents on Display

I) Subsidiary Information

ITEM 11 Quantitative and Qualitative Disclosures About Market Risk

ITEM 12 Description of Securities Other than Equity Securities

PART II

ITEM 13 Defaults, Dividend Arrearages and Delinquencies

ITEM 14 Material Modifications to the Rights of Security Holders and Use of Proceeds

ITEM 15 Controls and Procedures

ITEM 16A Audit Committee Financial Expert

ITEM 16B Code of Ethics

ITEM 16C Principle Accounting Fees and Services

ITEM 16D Exemption from the Listing Standards

ITEM 16E Purchase of Equity Securities

PART III

ITEM 17 Financial Statements

ITEM 18 Financial Statements

ITEM 19 Exhibits

GLOSSARY OF COMMON TERMS

"Aspen Endeavour" or "Aspen Canada" means Aspen Endeavour Resources Inc., a wholly owned subsidiary of the Company;

"Aspen Energy" or "Aspen US" means Aspen Energy Group, Inc., a wholly owned subsidiary of the Company;

"BBl or Barrel" means 42 U.S. gallons liquid volume of crude oil or natural gas liquids;

"Bcf" means billion cubic feet of gas. Usual expression of proved reserve gas volume;

"BOE" means barrels of Oil Equivalent. Generally one barrel of oil equals six mcf of gas. Allows reserves of oil and gas to be added together;

"BOE/d" means an expression of barrels of oil equivalent produced per day;

"BCAY" or "Act" means the Business Corporation Act of Yukon;

"Carbonates" means rocks composed predominantly of Calcium Carbonate (CaCO3);

"Common Share(s)" mean, respectively, one or more common shares in the capital of the Company;

"Company, Aspen or ASR" means Aspen Group Resources Corporation;

"Condensate" means a mixture comprising pentanes and heavier hydrocarbons recovered as a liquid from field separators, scrubbers or other gathering facilities or at the inlet of a processing plant before the gas is processed;

"Crown Royalty" means a amount payable to the government of the applicable Canadian province in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on Crown lands;

"Crude Oil" means a mixture, consisting mainly of pentanes and heavier hydrocarbons that may contain sulphur compounds, that is liquid at the conditions under which its volume is measured or estimated, but excluding such liquids obtained from the processing of natural gas;

"Depletion" means the reduction in petroleum reserves due to production;

"Development or developed" refers to the phase in which a proven oil or gas field is brought into production by drilling and completing production wells and the wells, in most cases, are connected to a petroleum gathering system;

"Exploration well" means a well drilled in a prospect without knowledge of the underlying sedimentary rock or the contents of the underlying rock;

"Farmin" means by way of agreement, a party earns (farmin) an interest in lands comprising petroleum and natural gas rights from another party by drilling a well or similar activity that evaluates, explores or develops the lands for the production of petroleum substances;

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"Farmout " means by way of agreement, a party gives up (farmout) an interest in lands comprising petroleum and natural gas rights to another party who earns the interest by drilling a well or similar activity that evaluates, explores or develops the lands for the production of petroleum substances;

"Field" means an area that is producing, or has been proven to be capable of producing, hydrocarbons;

"Formation" means a reference to a group of rocks of the same age extending over a substantial area of a basin;

"Freehold royalty" means an amount payable to a mineral rights holder in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on non-Crown lands;

"GAAP" means generally accepted accounting principles;

"Gross acres" means the total acreage in which the Company has an interest;

"Hectare" means a land measurement equalling 2.471 acres;

"Horizontal well" means a vertical well bore that is gradually deviated (usually horizontally to 90^o) in order to intersect the targeted formation;

"Hydrocarbon" means the general term for oil, gas, condensate, liquids and other petroleum products;

"Kilometre" means a measurement of distance equalling 0.621 miles or 3,281 feet;

"Meter" means a physical measurement equalling 3.281 feet;

"Freehold mineral tax" means an amount levied by the government of Alberta in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on non-government (freehold) lands in Alberta;

"Natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially a gas, but that may contain liquids;

"NGL’s" means Natural gas liquids. Hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butane and pentane plus, or combinations thereof;

"Net acres" means the percentage of gross acreage in which the Company has a working interest;

"Operator" means that party to a joint venture agreement whose responsibility it is to carry out all exploratory, development, maintenance and record-keeping duties on behalf of other joint venture partners in relation to hydrocarbon extraction on the joint-ventured lands;

"Overriding royalty" means an amount payable to a third party other than crown or freehold in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on lands in which the interest of the third party usually arises out of a separate agreement;

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"Reddy Report" means the independent reserve and economic evaluation of Aspen's interests in the USA dated April 3, 2003 prepared by Reddy Petroleum Company of Edmond, Oklahoma;

"Reliance Report" means the independent economic evaluation of certain petroleum and natural gas reserves owned by Aspen Endeavour dated April 8, 2003 prepared by Reliance Engineering Group Ltd. of Calgary, Alberta;

"Report" means this Form 20-F of the Company dated as of December 31, 2003;

"Probable reserves" means those reserves that analysis of drilling, geological, geophysical and engineering data do not demonstrate to be proved with current technology and under existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable reserves to be obtained will be the increased recovery beyond estimated proved reserves that can be realistically estimated for the pool through enhanced recovery processes that can reasonably be expected to be instituted in the future;

"Proved reserves" means those reserves estimated as recoverable with current technology and under existing economic conditions, from that portion of a reservoir that can be reasonably evaluated as economically productive through analysis of drilling, geological, geophysical and engineering data. This includes the reserves to be obtained by enhanced recovery processes demonstrated to be economically and technically successful in the subject reservoir;

"Royalty" means a stated or determinable percentage of the proceeds received from the sale of hydrocarbons calculated as prescribed in applicable legislation or in the agreement with the royalty holder;

"Seismic" means a geophysical technique using low frequency sound waves to determine the subsurface structure of sedimentary rocks;

"Sweet Gas" means Natural gas containing no hydrogen sulphide (H₂S) gas;

"Undeveloped" means prior to the time in which a proven oil or gas field is brought into production by drilling and completing production wells;

"Vertical Well" means a well bore that intersects the section(s) containing hydrocarbons at about 90^o; and

"Working Interest" means those lands in which the Company receives its share acreage net production revenues.

The following abbreviations are used in this REPORT to represent the following terms:

"bbl"	barrel	"bop/d"	barrels of oil per day
"bbls"	barrels	"mbbls"	thousand barrels
"boe"	barrels of oil equivalent	"ngl"	natural gas liquid
"boe/d"	barrels of oil equivalent per day
"bcf'"	billion cubic feet	"mmcf"	million cubic feet
"mcf"	thousand cubic feet	"mmcf/d"	million cubic feet per day
"mcf/d"	thousand cubic feet per day
"WI"	working interest	"WTI"	West Texas Intermediate

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The following sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units):

To Convert From	To	Multiply By
mcf	cubic metres	28.317
metres	cubic feet	35.494
bbls	cubic metres	0.159
cubic metres	bbls	6.289
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

Note: monetary value is US dollars unless otherwise stated

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Aspen Group Resources Corporation 2003 Form 20-F is being filed out of time, therefore all of the information contained in this Form 20-F is stated as of December 31, 2003, except as otherwise specifically indicated. Since December 31, 2003, there have been substantial changes at the Company and its assets, including without limitation the sale of substantially all of its US properties in 2004, the change of location of its principal executive offices to Calgary Alberta and the retirement of its US bank debt. All such material changes will be set forth in the Company's 2004 annual report on Form 20-F, which the Company anticipates filing with the SEC on or before May 30, 2005.

PART I

Forward-Looking Statements

Portions of this document include "forward-looking statements", which may be understood as any statement other than a statement of historical fact. Forward-looking statements contained in this document are made pursuant to the safe harbour provisions of the Private Securities Litigation Reform Act of 1995. These statements are based on management’s current expectations and are subject to uncertainty and changes in circumstances. Actual results may vary materially from management’s expectations and projections expressed in this document. Certain factors that can affect the Company’s ability to achieve projected results are described in the Company's Annual Report on Form 20-F and other reports filed with the Securities and Exchange Commission. Such factors include, among others, production variances from expectations, uncertainties about estimates of reserves, volatility of oil and gas prices, the need to develop and replace reserves, the substantial capital expenditures required to fund operations, environmental risks, drilling and operating risks, risks related to exploratory and developmental drilling, competition, government regulation, and the ability of the company to implement its business strategy.

ITEM 1 IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

Information on directors, senior management and advisors is contained in Section 6 of this report.

ITEM 2 OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 3 KEY INFORMATION

A) Selected Financial Data

In US dollars (except share data)	For the year ended
	Dec 31, 2003⁽²⁾	Dec 31, 2002⁽²⁾	Dec 31, 2001⁽¹⁾⁽³⁾	June 30, 2001⁽⁴⁾	June 30, 2000⁽⁵⁾	June 30, 1999⁽⁶⁾
Total Revenue	9,720,210	7,835, 634	4,235,081	10,549,274	3,481,718	908,966
Net Income (loss)	(2,717,662)	(17,009,828)	(869,198)	2,100,524	94,116	(11,479,086)
Net Income (loss) per share (basic)	(0.05)	(0.45)	(0.04)	0.11	0.01	(0.57)
Total Assets	45,623,578	52,536,324	56,067,031	54,852,919	42,774,666	11,341,651
Net Assets⁽⁷⁾	26,892,121	29,395,090	33,486,389	32,676,194	27,476,372	10,135,064
Capital Stock	25,910,230	27,798,607	34,280,942	34,856,740	29,034,659	9,078,955
Average Shares outstanding	50,030,092	37,420,390	19,582,323	18,825,709⁽⁸⁾	83,676,588	20,036,818

(1) Aspen changed its fiscal yearend from June 30 to December 31 in 2001.

(2) Additional data can be found in the audited financial statements contained in item 17 of this report.

(3) Additional data can be found in the Company's 10-KSB filed April 1, 2002

(4) Additional data can be found in the Company's 10-KSB filed September 28, 2001

(5) Additional data can be found in the Company's 10-KSB filed September 26, 2000

(6) Additional data can be found in the Company's 10-KSB filed October 4, 1999

(7) Calculation based on value of proved oil and gas properties discounted at 10 percent net of accumulated depreciation plus property and equipment net of accumulated depreciation less total bank debt.

(8) After effect of 1:7 share consolidation

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B) Capitalization and Indebtedness

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

C) Reasons for the Offer and Use of Proceeds

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

D) Risk Factors

Holders of the Common Stock and future investors in the Company should be aware of the following factors in evaluating their investment in Aspen.

Limited Operating History; Capital Intensive Business; Need For Additional Funds

From its inception in February 1995 through June 30, 1999, the Company was engaged principally in organization and capitalization activities and was not able to generate material net revenues from operations until the merger with East Wood and the change of management. The Company's business is highly capital-intensive requiring continuous development and acquisition of oil and gas reserves. In addition, capital is required to operate and expand the Company's oil field operations and purchase equipment. At December 31, 2003, the Company had a working capital deficit of $14,107,377 including bank debt. The Company anticipates, based on its currently proposed plans and assumptions relating to its operations, including borrowings from its line of credit, together with cash expected to be generated from operations, that it will be able to meet its cash requirements for at least the next 12 months. However, if such plans or assumptions change or prove to be inaccurate, the Company could be required to seek additional financing sooner than currently anticipated. The Company has no commitments to obtain any additional debt or equity financing and there can be no assurance that additional funds will be available, when required, on terms favourable to the Company. Any future issuances of equity securities would likely result in dilution to the Company's then existing Shareholders while the incurring of additional indebtedness would result in increased interest expense and debt service changes. See "Operating and Financial Review and Prospects."

History Of Losses

Although the Company's operations were profitable in fiscal years 2000 and 2001*, the Company had historically incurred losses. The Company has reported net losses of $2,717,662, $17,009,828 and $869,198 for the periods ended December 31, 2003, 2002, and 2001 respectively and has current liabilities in excess of current assets in the amount of $14,107,377. This includes $ $10,321,210 of long-term debt, which has been reclassified to current, because it is in default of certain covenants under its loan agreement. Aspen hopes to bring the US banking facility in full compliance and if it succeeds, it will reclassify $10,321,210 of the current loan back to long-term debt. These factors, among others, may indicate that the Company will be unable to continue as a going concern for a reasonable period of time. Since joining the Company in October of 2002, the new Chief Executive Officer, along with the rest of the Company's management team has been developing a broad operational financial restructuring plan. Despite its negative cash flow, the Company has been able to secure financing to support its operations to date. The Company's accumulated deficit as of December 31, 2003 was $33,480,888. The Company has historically funded its operating losses, acquisitions and expansion costs primarily through a combination of private offerings of debt and equity securities and proceeds from the exercise of options and warrants.

* Aspen changed its fiscal yearend from June 30 to December 31 in 2001.

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Legal Proceedings

The Company is a named defendant in a number of legal proceedings, which are described within the notes to the audited financial statements. The Company intends to defend its position in each such lawsuit vigorously, but if any such defence were found by a court hearing the matter to be ineffective, the Company could be assessed damages and other amounts in favour of the relevant plaintiff or other successful party. The amount of any such damages assessed against the Company, if any, are difficult to estimate given the uncertainty of litigation. Given the amounts being claimed against the Company, a successful action against the Company could have a material adverse effect on the Company. Refer to Notes to the Consolidated Financial Statements – Note 13 "Commitments and Contingencies" contained in Sections 8 and 17 of this report.

Significant Capital Expenditures Necessary For Undeveloped Properties

The Company has substantial oil and gas reserves, which are classified as Proved Undeveloped Reserves, meaning very little production currently exists. Recovery of the Company's Proved Undeveloped Reserves will require significant capital expenditures. No assurance can be given that the Company's estimates of capital expenditures will prove accurate, that its financing sources will be sufficient to fund fully its planned development activities or that development activities will be either successful or in accordance with the Company's schedule. Additionally, any significant decrease in oil and gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled and/or reworked. No assurance can be given that any wells will produce oil or gas in commercially profitable quantities.

Development Risks

The Company intends to continue its development activities and development drilling of oil and gas reserves. Even though development drilling carries less risk than exploration drilling, there is risk that production will not be obtained and/or that production will be insufficient to recover drilling and completion costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit on the investment or a recovery of drilling, completion and operating costs.

Volatility of Oil and Gas Prices

The Company's revenues, profitability and the carrying value of its oil and gas properties are substantially dependent upon prevailing prices of, and demand for, oil and gas and the costs of acquiring, finding, developing and producing reserves. The Company's ability to maintain or increase its borrowing capacity, to repay current or future indebtedness, and to obtain additional capital on favourable terms is also substantially dependent upon oil and gas prices. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations in response to: (i) relatively minor changes in the supply of, and demand for, oil and gas; (ii) market uncertainty; and (iii) a variety of additional factors such as the September 11, 2001 terrorist attacks on New York and Washington and the military action in Afghanistan and Iraq, all of which are beyond the Company's control. These factors include domestic and foreign political conditions, the price and availability of domestic and imported oil and gas, the level of consumer and industrial demand, weather, domestic and foreign government relations, the price and availability of alternative fuels and overall economic conditions. Furthermore, the marketability of the Company's production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Volatility in oil and gas prices could affect the Company's ability to market its production through such systems, pipelines or facilities. Substantially all of the Company's gas production is currently sold to gas marketing firms or end users either on the spot market on a month-to-month basis at prevailing spot market prices or under long-term contracts based on current spot market prices. The Company normally sells its oil under month-to-month contracts with a variety of purchasers. Accordingly, the Company's oil and gas sales expose it to the commodities risks associated with changes in market prices.

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Uncertainty of Estimates of Reserves and Future Net Cash Flows

This Report contains estimates of the Company's oil and gas reserves and the future net cash flows from those reserves, which have been prepared and audited by certain independent petroleum consultants. There are numerous uncertainties inherent in estimating quantities of reserves of oil and gas and in projecting future rates of production and the timing of development expenditures, including many factors beyond the Company's control. The reserve estimates in this report are based on various assumptions, including, for example, constant oil and gas prices, operating expenses, capital expenditures and the availability of funds and, therefore, are inherently imprecise indications of future net cash flows. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this report. Additionally, the Company's reserves may be subject to downward or upward revisions based upon actual production performance, results of future development and exploration, prevailing oil and gas prices and other factors, many of which are beyond the Company's control.

The present value of future net reserves discounted at 10 percent (the "PV-10") of Proved Reserves referred to in this report should not be construed as the current market value of the estimated Proved Reserves of oil and gas attributable to the Company's properties. In accordance with applicable requirements of the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), and Canadian National Instrument 51-101 guidelines, the estimated discounted future net cash flows from Proved Reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by: (i) the timing of both production and related expenses; (ii) changes in consumption levels; and (iii) governmental regulations or taxation. In addition, the calculation of the present value of the future net cash flows using a 10 percent discount as required by the FERC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company's reserves or the oil and gas industry in general. Furthermore, the Company's reserves may be subject to downward or upward revision based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors.

Under full cost accounting, the Company would be required to take a non-cash charge against earnings to the extent capitalized costs of acquisition, exploration and development (net of depletion and depreciation), less deferred income taxes, exceed the PV-10 of its Proved Reserves and the lower of cost or air value of unproved properties after income tax effects. See "Operating and Financial Review and Prospects."

Operating Hazards and Uninsured Risks; Production Curtailments

The Company's oil and gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although the Company carries insurance at levels, which it believes, are reasonable, it is not fully insured against all risks. The Company does not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on the financial condition and operations of the Company.

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From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which the Company owns an interest have been subject to production curtailments. The curtailments range from production being partially restricted to wells being completely shut-in. The duration of curtailments varies from a few days to several months. In most cases, the Company is provided only limited notice as to when production will be curtailed and the duration of such curtailments. The Company is not currently experiencing any material curtailment of its production.

Laws and Regulations

The Company's operations are affected by extensive regulation pursuant to various federal, state and local laws and regulations relating to the exploration for and development, production, gathering and marketing of oil and gas. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds or other financial responsibility requirements, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas.

Environmental Risks

Operations of the Company are also subject to numerous environmental laws, including but not limited to, those governing management of waste, protection of water, air quality, the discharge of materials into the environment and preservation of natural resources. Non-compliance with environmental laws and the discharge of oil, gas, or other materials into the air, soil or water may give rise to liabilities to the government and third parties, including civil and criminal penalties, and may require the Company to incur costs to remedy the discharge. Laws and regulations protecting the environment have become more stringent in recent years, and may in certain circumstances impose retroactive, strict, and joint and several liability rendering entities liable for environmental damage without regard to negligence or fault. From time to time the Company has agreed to indemnify sellers of producing properties from whom the Company has acquired reserves against certain liabilities for environmental claims associated with such properties. There can be no assurance that new laws or regulations, or modifications of or new interpretations of existing laws and regulations, will not increase substantially the cost of compliance or otherwise adversely affect the Company's oil and gas operations and financial condition or that material indemnity claims will not arise against the Company with respect to properties acquired by or from the Company. While the Company does not anticipate incurring material costs in connection with environmental compliance and remediation, it cannot guarantee that material costs will not be incurred.

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ITEM 4 INFORMATION ON THE COMPANY

A) History and Development of the Company

The Company was incorporated in the Province of Ontario, Canada, originally as Cotton Valley Energy Limited on February 15, 1995. On June 14, 1996, Cotton Valley amalgamated with Arjon Enterprises, Inc., and a name change occurred from Cotton Valley Energy Limited to Cotton Valley Resources Corporation. The Company continued from Ontario to the Yukon Territory pursuant to Articles of Continuance dated February 9, 1998 and changed its name to its current name "Aspen Group Resources Corporation" effective March 2, 2000. Under the applicable law and its organizational documents, the Company has unlimited life. The Company's principal place of business is at One North Hudson, Suite 1000, Oklahoma City, Oklahoma 73102 and the telephone number is (405) 278-8800.

The Company has completed several acquisitions of oil and gas properties or of companies primarily engaged in oil and gas exploration and development. The following is a summary of the acquisitions over the last three financial years.

On September 16, 1999 (but effective July 1, 1999), the Company acquired 50 percent of the outstanding common stock of East Wood Equity Venture, Inc. from Jack E. Wheeler, the past Chairman, Chief Executive Officer and Director of the Company and others in exchange for 6,604,414 restricted shares of common stock. On February 28, 2000, the Company purchased the remaining 50 percent of the outstanding capital stock of East Wood from Farrell Kahn and others in exchange for the issuance of 3,747,271 restricted shares of common stock and the Company's promissory note for $3,000,000. Effective December 31, 2001, the Company received a release and discharge of this promissory note in exchange for 3,857,143 shares of common stock. East Wood was principally engaged in the business of the acquisition, development, exploration and operation of producing oil and gas properties. At the time of the acquisition, the main concentration of East Wood's properties was in Oklahoma with 335 wells and Texas with 30 wells. Approximately 80 percent of these wells were gas wells.

Effective January 1, 2000, Aspen acquired 49 producing, operated wells in Oklahoma from EDB Oil Properties for $313,718, which was paid by the issuance of 260,714 Aspen Shares.

Effective the same date, Aspen closed smaller projects with Fer-Scher Exploration, L.L.C., Red Terra Resources Company, Sebenius & Associates 1982-1 Joint Venture and SGH, Inc. The total allocated cost of these four projects was $562,105 paid by a combination of cash and Aspen Shares.

Effective April 1, 2000, Aspen acquired certain oil and gas interests and all of the outstanding common stock of Mercer Oil and Gas Company from Ron Mercer, the current Vice President of Aspen, in exchange for cash of $100,000 and 142,857 Aspen Shares.

Effective May 1, 2000, Aspen acquired through a merger with Briscoe Oil Operating, Inc. a 52 percent undivided interest in 171 properties located in 21 counties in Oklahoma, Texas, and Kansas for $3,000,000. Effective May 1, 2000, Aspen also acquired 17 producing oil and gas properties, equipment, vehicles and a 10-year equipment facility yard lease from L.C.B. Resources, Inc., which was paid by the issuance of 571,429 Aspen Shares. This acquisition added 245 mbbls of oil reserves and 7,536 mmcf of net gas reserves for an acquisition cost of US$3.10/ net boe. Briscoe Oil Operating, Inc. and L.C.B. Resources, Inc. were both controlled by Lenard Briscoe, a past director of Aspen.

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Effective May 5, 2000, Aspen acquired an interest in approximately 3,775 gross acres and several producing oil and gas properties in the Tiger Hunton Unit Development Project in Seminole County, Oklahoma from Oak Tree Natural Resources, L.L.C. for $55,940 and a commitment to future development costs of approximately $500,000.

Aspen acquired a significant interest in the El Dorado field prior to June 30, 2000, through acquisitions from The Flowers Estate and MOG Oil and Gas Company. These acquisitions increased Aspen's proven oil reserves by over 1,600,000 bbls for an acquisition cost of $2.60/bbl, including future development costs expected to be $1.125 million.

Effective August 1, 2000, Aspen purchased interests in 158 oil and gas properties primarily located in the Arkoma and Anadarko Basins of Oklahoma, increasing its interest in 130 wells in inventory by an additional 5.88235 percent and royalty and overriding royalty interests in 28 wells from PGGB Oil and Gas Partnership for $131,164.

Effective August 1, 2000, Aspen purchased interests in approximately 400 oil and gas properties located in the Arkoma and Anadarko Basins of Oklahoma from Old Dominion Oil Corporation for $644,930.

Effective August 1, 2000, Aspen purchased interests in 41 producing wells, leases, property and equipment located in Butler County, Kansas from Crawford Oil Company and Leiker-Crawford Oil Company for a cash purchase price of $1,743,604.

Effective January 1, 2001, Aspen purchased from Muras Energy, Inc. working interests ranging up to 45 percent in 36 wells in 16 different counties in the Anadarko Basin of Western Oklahoma and certain other assets for a cash consideration of $475,250 and the issuance of 119,048 Aspen Shares.

Effective January 1, 2001, Aspen acquired United Cementing and Acid Co., Inc., a privately-held oilfield service company headquartered in El Dorado, Kansas for $1,040,000 in cash and 250,000 Aspen Shares. United Cementing operates a cementing and acidizing business providing oil field services integral to oil and gas operations.

Effective April 1, 2001, Aspen purchased from C.B. Oil Company working interests averaging 34 percent in 43 wells in 14 different counties in the Anadarko Basin of Western Oklahoma and certain other assets for $2,299,907.

Effective April 1, 2001, Aspen purchased from Saco Oil Company working interests in 44 producing wells and certain other assets for $1,125,000. The acquired properties comprise 39 leases and are primarily located in the El Dorado Field in Kansas.

Effective July 2, 2001, Aspen acquired 61,843 net acres of leasehold interest in the North East New Mexico Basin over an area of approximately 100,000 gross acres for $179,000. This resulted in Aspen owning an average 62 percent working interest with an estimated 53 percent net revenue interest. The area is prospective of coal-bed methane, shale gas, and Pennsylvanian ages gas reservoirs.

Effective January 2, 2002, by way of a Take-Over Circular, Aspen took up 39,314,048 common shares of Aspen Endeavour and 3,750,000 purchase warrants. The shares taken up by Aspen represented approximately 79.8 percent of the outstanding common shares of Aspen Endeavour. Aspen extended its bid for the remaining shares of Aspen Endeavour until January 31, 2002.

Effective March 21, 2002, Aspen completed the acquisition of all of the shares of Aspen Endeavour pursuant to a Notice of Compulsory Acquisition. In accordance with the take-over agreement, Aspen Endeavour was de-listed from the Canadian Venture Exchange effective February 15, 2002 and is now a wholly owned subsidiary of Aspen.

Effective December 1, 2002, Aspen sold its entire interest in the El Dorado Field in Kansas for approximately $2.85 million in cash. The majority of proceeds generated from this sale were utilized to further reduce the Company's US bank debt. In addition to the El Dorado assets, Aspen sold its entire interest in real properties located in Kerrville, Texas for net proceeds of $325,000.

Effective, December 10, 2002, Aspen sold its 25 percent interest in Wintering Hills, Alberta for Cdn $1.875 million ($1.22 million US) in cash. The majority of proceeds were used to reduce the Company's Canadian bank debt.

In 2003, the Company sold its entire interest in real properties located in Kerrville, Texas for net proceeds of $325,000. There was no oil and gas production on this property.

With effective dates of December 1, 2003 and December 31, 2003, Aspen sold 54 low value or uneconomic wells for $685,000, which was applied completely to debt.

At December 31, 2003, there were no other acquisitions or divestitures being investigated by the Company.

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B) Business Overview

Aspen is an independent energy company engaged in the acquisition, exploitation, development and operation of oil and gas properties with a geographic focus in major oil and gas producing regions in the United States and Canada. The Company's head office is based in Oklahoma City, Oklahoma and has an office in Calgary, Alberta. Aspen is listed for trading in Canada on The Toronto Stock Exchange ("TSX") and trades under the symbol ASR. In the US, Aspen is listed on the Pink Sheets and trades under the symbol ASPGF. Aspen currently owns interests in approximately 1000 wells in the United States, with a predominant focus in the Mid Continent region of the US and 138 wells located in the Alberta and Saskatchewan provinces in Canada. The Company estimates that 86 percent of its reserves and 81 percent of its current daily production are natural gas.

Of the approximate 1000 US wells the Company owns an interest in, 129 are operated by Aspen (operated properties) and 837 are operated by outside oil and gas companies (non-operated properties). The approximate working interests in the non-operated wells range between 2.74 percent and 50 percent.

In the non-operated properties, operations such as drilling, transportation, and marketing of the oil and natural gas produced, is carried out by outside companies. Aspen's obligation is to respond to requests by the operator for funds to drill additional wells, perform maintenance on existing wells, etc. and if those requests are determined to be appropriate, to contribute, on a timely basis, its pro rata share of the costs (working interest) associated with the aforementioned operations.

Aspen also owns significantly higher interests and acts as operator on approximately 129 US wells. Its average interest is 91 percent and the Company is responsible for the drilling, transportation and marketing of the oil and gas production. Where Aspen performs these functions, it subcontracts the drilling to independent drilling companies. Transportation is also contracted through local companies or through existing pipeline infrastructure. A third party marketing company performs sales of the Company's production.

In Canada, Aspen, through its wholly owned subsidiary Aspen Endeavour Resources Inc. operates 40 of the 138 wells it owns. The average working interests in the operated wells is approximately 47 percent and approximately 22 percent for the non-operated.

Readers should reference Item 3D “Risk factors”, particularly sections concerning “Laws and Regulations” and “Environmental Risks”.

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C) Organizational Structure

The following is a flow chart of the Company and its wholly owned subsidiaries as of the most recent financial year-end.

The Organization Chart was removed for EDGAR formatting. Please see the PDF exhibit.

D) Property, Plant and Equipment Facilities

Aspen occupies approximately 4,000 square feet of office space at Suite 1000, One North Hudson, Oklahoma City, Oklahoma 73102, under a two-year lease that expires on December 31, 2004. Monthly base rent is $3000.

Aspen obtained a lease of a 20-acre equipment yard for 10 years as part of the acquisition from L.C.B. Resources Inc. The property includes three freestanding pre-fab buildings, each approximately 25,000 square feet in size. The lease expires in May of 2010, and the lease payments of $140,000 have been prepaid.

Aspen obtained a 10-acre yard facility including an 1,800 sq. ft. office building, a shop building and warehouse as part of the United Cementing acquisition. There are no rent payments associated with this property.

Aspen's Canadian subsidiary, Aspen Endeavour Resources Inc., occupies approximately 6,831 square feet of office space at Suite 200, 630 – 4 Avenue S.W., Calgary, Alberta T2P 0J9, under a five year lease that expires on April 30, 2005. Monthly base rent is approximately $11,400.

Description of Properties

Mid-Continent

Aspen owns an interest in approximately 1000 well bores, of which 97 percent are in the Mid Continent area of the US, which encompasses the states of Oklahoma, Kansas, Texas, Arkansas, Louisiana, Mississippi, Alabama, and Michigan. The majority of the well bores are in the Anadarko Basin of western Oklahoma and the Texas Panhandle. The Company's value is mostly from the production of these well bores producing from the Atoka, Granite Wash, Morrow, Red Fork and other formations. There are several geologic provinces within the Mid-Continent area. Most of these provinces have established hydrocarbon production, i.e., the Arkoma Basin is predominately dry gas while the Anadarko has both oil and gas. The Nemaha Ridge Area and the Golden Trend are predominately oil, while recent activity in the northeastern part of the state has been in shale gas development.

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Geologically, the Anadarko Basin began as a rift in the North American plate. This rift valley was initially filled with volcanic material from vents on either side of the rift. During the Late Cambrian when rifting subsided, the sea invaded the rift valley from the southeast. The earliest sediments (known as the Arbuckle Group) were sandstones, limestones and dolomites; all deposited in a shallow sea environment. It is estimated that approximately 2,000 feet of the Arbuckle Group sediments were deposited. The true thickness of the Arbuckle Group in the "Deep Anadarko" is unknown; a deep test drilled in Washita County to a depth of more than 31,000 feet penetrated only 200 feet of the Arbuckle. The Arbuckle Group does produce throughout the State and production is usually associated with a structural component.

An additional 7,000 to 10,000 feet of limestones were deposited through the Mississippian Period. In many places the top of the Mississippian is an erosion surface with a "Chat" interval or with enhanced porosity due to exposure and/or structural movement. The open ocean was completely gone by the Triassic Age. Production from the Pennsylvanian is mainly stratigraphic, with multiple sandstones within each formation (the Morrow/Springer has multiple sandstones, 10 to 15 individual sandstones in one area is not unusual).

Anadarko Basin

The Anadarko Basin has been divided into the "Deep" and "Shelf" areas. The "Deep Anadarko" includes the counties of Beckham, Blaine, Caddo, Custer, Roger Mills, and Washita (the Central Western Oklahoma Counties). Drilling depths in these Counties are generally deeper than 10,000 feet; 17,000 feet is not uncommon for the Morrow/Springer Formation. In Beckham, Custer, Roger Mills and Washita Counties the "Granite Wash" is a prolific gas producer with several intervals (each of these zones can be several hundreds of feet thick) from Desmoisian to Atokan age. These zones are limestone, dolomite, shale mixtures that were washed in from the mountain front, with deposition primarily from the south.

The earlier Pennsylvanian (Morrow/Springer) sandstones were deposited in relatively deep water as long shore and near shore bars generally trending northwest southeast (parallel to the Basin). The eastern side of the "Deep Anadarko" includes Blaine, Canadian and Grady Counties. This area also included the Blaine County Embayment, an area known for overpressure Morrow/Springer sandstones (these sands were deposited in an embayment and range from fluvial to delta front sands instead of deep water sands and the depositional trend within the embayment is generally north-south). This area of the Basin is primarily productive from the Pennsylvanian sandstones.

Reserves can range from 1 to 30+ bcf per interval with many wells producing from the deepest interval first and then some years later will re-complete from the shallow zones. Spacing is typically based on 640 acres, but increased density drilling is common. For example, the "Granite Wash" is now being developed in many areas to 160 acre spacing (from one well per section to four wells per section).

Most of Aspen's operated wells are on the "Shelf Area" of the Anadarko Basin. These wells are generally 7,000-9,000 feet deep and produce with the aid artificial lift. The wells are characteristically low volume gas wells but have relative long lives.

The "Shelf" area of the Anadarko encompasses the northwestern part of the state as well as part of the Panhandles of Oklahoma and Texas. This area produces from zones ranging from the Arbuckle to the Permian. Most of the production is from multiple stratigraphic sandstones, 'reefal' limestones and massive limestone. The majority of the production is from the Pennsylvanian sandstones and limestones. The older and deeper limestone production is generally dependent of porosity development associated with structure. The majority of the production, however, is stratigraphically controlled. The major depositional trends for the sandstones are from north to south or northeast to southwest, depending on the geographic area.

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Drilling depths are generally less than 10,000 feet and do not usually require intermediate casing or special drilling programs. Spacing can range from 640 acres to 40 acres depending on the area, formation and well classification (oil or gas). Increased density drilling is as common on the "Shelf" area as it is in the "Deep" Anadarko. Reserves are from both oil and gas and can range from a few bcf's gas and a few thousand barrels of oil to 5+ bcf's and tens of thousands of barrels of oil.

The "Golden Trend" is an area in south-central Oklahoma, bounded by the Nemaha and Pauls Valley uplifts on the east and the southeastern embayment of the Anadarko. This area is known for prolific oil production from stratigraphic traps. The Upper Pennsylvanian sands are the best producers; these sands successively lap on to the Pauls Valley uplift. The overall Deese (the primary sequence of sands) interval is several thousand feet thick.

It is also known for the prolific oil production from the Simpson/Bromide (Ordovician) sands. Production from the Ordovician sands, however, is generally found associated with structures (the formations typically need a structure to trap hydrocarbons above water). Structure in this area is very complex and it is highly faulted with its major structural axis trending almost directly east west. This arch contains many known structural features that produce oil and gas (fields such as Cement, Lindsay and Maysville are along this arch). This area has had established production since the late 1940's and exploration/exploitation continues today with advances in seismic and drilling technology finding additional prospective formations and traps. Drilling depths can vary widely depending on the area and target formation. Oil is the major production – some formations such as the Bromide can flow up to 300 Bopd.

Hugoton Area

The "Hugoton" is an area encompassing far northern Oklahoma, the Oklahoma Panhandle and western Kansas. This was an embayment of the Anadarko with sediments being deposited predominately from the north and northwest. The area is dominated by natural gas production from shallow Permian sands (most wells are less than 3,000 feet). The area is also known for its large deposits of helium. For many years only the shallow Permian gas was exploited and deeper formations were not tested. During the past twenty years, this area has been slowly developed for the deeper producing formations. Pennsylvanian sandstones and the Mississippian limestones are favourite targets. These zones are generally stratigraphically controlled.

Drilling depths for the Mississippian are usually less than 6,000 feet in the Hugoton, making it an attractive area for drilling. The biggest problem here is getting an acreage position due to the spacing of the Permian and Kansas' rules for additional drilling.

Arkoma Basin

The Arkoma Basin lies in southeastern Oklahoma and central Arkansas. Geologically it is bounded by the Ozark Plateau to the north and the Quachita Overthrust Belt to the south. The Basin was separated from the Anadarko Basin by a series of volcanic islands and uplifts associated with the tectonics of the region. The Arkoma produces mainly dry gas from the Pennsylvanian age sandstones. Production is from stratigraphic traps, structural traps and combination of the two. There are some areas where the production is controlled by the faults (forming boundaries and stacking formations within blocks) and yet there are areas where faulting is not important at all to the production.

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Depending on the area of the Basin, drilling depths can range from a few thousand feet to 17,000+ feet and prospect definition can range from simple stratigraphic correlations and geologic mapping to state of the art 3D seismic. This area is currently enjoying increased activity as shale gas formations are now being exploited and seismic prospects have opened up new discoveries such as the Potato Hills Field.

New Mexico Acreage Acquisition

The Sierra Grande Uplift of NE New Mexico joins the Dalhart Basin of the Texas Panhandle in the north half of Union County, New Mexico. These features are tectonic of Mid Pennsylvanian to Wolfcampian (Permian) age. These strata consist of arkosic sandstone, conglomerate and shale. The arkosic sediments were derived from the granite core of these elements and were deposited as alluvial fans and fan deltas.

Structures of the Sierra Grande uplift appear to have been controlled primarily by high angle faulting (normal and reverse). In the southern parts of Union County and Northeastern part of Harding County commercial CO2 is being produced. The northern part of Union County has many hydrocarbon shows in past exploration efforts from 900 feet deep to 5,000 feet deep.

In 2001, Aspen acquired 61,843 net acres of leasehold interest in this area. Aspen owns 100 percent GWI with an estimated 85 percent average NRI. The area is prospective of coal-bed methane, shale gas, and Pennsylvanian aged gas reservoirs. Even though Aspen has not completed its Plan of Development, the Company is encouraged by the potential and the large position it now holds. According to one analysis by a geological engineer, the potential could be as great as 100 BCF from the coal beds alone. Due to financial constraints in 2002, Aspen released approximately 35,000 net acres.

Western Canadian Basin

The Company operates in Canada through its wholly owned subsidiary Aspen Endeavour Resources Inc. ("Aspen Endeavour"). Aspen Endeavour has properties throughout Alberta and southern Saskatchewan, both in an operator and non-operator position. The core areas are Sturgeon Lake, Namaka and Taber, Alberta.

Sturgeon Lake

Sturgeon Lake is situated approximately 80km east of Grande Prairie in north central Alberta. This is an operated property in which Aspen Endeavour holds an average working interest of 32.58 percent. In addition, Aspen Endeavour holds lease agreements covering lands within the Sturgeon Lake Indian Reserve #154. Aspen has spent considerable time and expense putting together this land block which will enable the Company to develop the extension of the D-3 zone, confirm the extensions of the Nisku D-2 Pool as well as to prove the shallow gas production viable over the field.

The shallow Cretaceous and Triassic gas reservoirs are formed by sands draped over the Devonian reef and exist between 1650m and 1000m in depth. The reservoirs are composed of, shoreface sands which prograded over the area forming thick sand deposits, and a wave dominated delta trending E-W through the area. These reservoirs are generally structural traps however there are stratigraphic components to the trapping mechanisms within some of these shallow sand reservoirs.

The majority of these reservoirs are sweet gas and as such require only minor processing, they do however require compression to produce into the major transition lines

The Sturgeon Lake Leduc complex, located in northwestern Alberta and centered over Twp 069- Rge 23-W5M, covers roughly 1000 square kilometres.

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The Leduc oil reserves on and adjacent to the Sturgeon Lake Indian Reservation are trapped on the updip edge of the dolomitized Leduc formation at a depth of approximately 2600m. The lands within the Sturgeon Lake Reserve are over a narrow section of the Leduc reef, where the reef has a relatively thin oil column with well-developed vertical fractures. Apparent lateral reservoir discontinuities have restricted development of the D-3 reserves, in the leasehold and adjacent areas. Successful wells produce only a small fraction of the oil in place. The Leduc reservoir has an active water drive and enjoys high primary recoveries due to this water drive.

After the end of Leduc deposition, a phase of marine regression resulted in the deposition of the basinal filling shales of the Ireton formation. During the next transgressive phase an isolated Nisku reef shelf was deposited over the Sturgeon Lake reef complex. Oil is also trapped on the updip edge of this complex. Both the Leduc and Nisku reef complexes were dolomitized. These two reservoirs are sour and produce gas with H2S content varying between 4-11 percent.

This reef complex was discovered in the early 1950's with single fold seismic data and continues to be developed with high resolution 3-D. Production occurs from localized highs on the updip peripheral of the complex.

As these reservoirs are sour the gas requires processing to meet pipeline specification as well as compression to produce into the major transition lines. The light crude oil production receives a deduction for it sulphur content at the point of sales.

Namaka

As of April 1, 2003 Aspen Endeavour took over operatorship in the Namaka area, located in southeastern Alberta approximately 35km east of Calgary. Aspen Endeavour holds between 50 percent and 78 percent working interest in the lands with 23 producing gas wells in the area. Gas production at Namaka is mainly from the sands of the Upper Cretaceous Belly River Formation at depths of 600m to 825m. The sands are fluvial to coastal plain deposits, with the reservoirs compartmentalized and very heterogeneous. The sands have varying reservoir quality from well to well. The most productive sand is the Basal Belly River. Porosity varies from 13 to 21 percent with reduced permeability due to cementation and clay content. Wells need to be stimulated with a frac program to produce.

Taber

At Taber, Alberta, Aspen Endeavour holds between 19 percent and 37.5 percent working interest in lands, which are operated by an outside oil and gas company. Aspen Endeavour also owns an interest in the Butte, Saskatchewan area, which is located approximately 55 km west of Swift Current. This area consists of 11 wells that are tied in and under a water flood program to increase reservoir performance with a working interest range from 10 percent to 35 percent. The Taber sands of the Cretaceous Manville Group produce heavy oil from a fine to medium grained quartz sandstone at 975m to 1000m depths. The reservoirs are stratigraphic traps within fluvial channel sands. The sands are up to 20m thick. The production comes from an oil leg overlying a thick water zone. The wells usually produce large volumes of water with the oil.

The following table summarizes, for the periods indicated, the number of wells that Aspen and Aspen Endeavour drilled or participated in drilling.

	Year Ended December 31
	2003 Gross/Net	2002 Gross/Net	2001 Gross/Net
Oil Wells Capable of Production	4/.025	3 / 1	5 / 1.15
Gas Wells Capable of Production	5/.0471	5 / 1.58	10 / 2.29
Dry Holes	0/0	1 / .088	7 / 1.61
Total	9/.072	9 / 2.668	22 / 5.05

Reserve and Production Information

	Year ended December 31, 2003 ⁽²⁾	Year ended December 31, 2002 ⁽²⁾	Six months ended December 31, 2001 ⁽¹⁾	Year ended June 30, 2001
Proved producing boe	3,305,885	4,475,088	5,099,927	4,022,657
Proved non-producing boe	216,175	250,766	315,729	383,408
Proved undeveloped boe	1,263,287	1,258,867	3,502,011	6,479,602
Total Proved boe	4,785,346	5,984,722	8,917,667	10,885.667

Note: Additional reserve information for December and June 2001 is available in the Company's 10-KSB's or 20-F's filed for those periods. Additional information on 2003 reserves can be found in the Reserve Reports attached as exhibits to this report.

Production	Year ended
	December 31, 2003	December 31, 2002	December 31, 2001⁽¹⁾	June 30, 2001
Oil Production (bbls/d)	198	458	348	274

Gas Production (mmcf/d)	5.1	6.4	4.1	4.0

Total Production (boe/d)	1,041	1517	1034	937

(1) Aspen changed its fiscal yearend from June 30 to December 31 in 2001.

(2) Combined US and Canadian reserves.

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ITEM 5 OPERATING AND FINANCIAL REVIEW AND PROSPECTS

A) Operating Results

Revenues

Aspen's gross revenues were $9,720,210 for the year ended December 31, 2003 compared to $7,834,634 in the same period last year. Oil and natural gas sales in 2003 were $8,667,363 compared to $6,969,309 in 2002. Service revenue from Aspen's subsidiary, United Cementing, was $1,052,847 compared to $865,325 for the same period in 2002.

Production

Net production in the twelve-month period ending December 31, 2003 averaged 1,041 boe/d as compared to 1,517 boe/d in the same period in 2002. The decline in production is primarily due to the sale of producing properties, which were monetized in order to reduce debt, and reduced cash flow in the first half of the year, which restricted investment into production.

Aspen reported proven reserves of approximately 4,785,346 million boe with an estimated present value of $43,008,763 discounted at 10 percent. (2002 – million boe with an estimated present value of $43,296,660 discounted at 10 percent) Aspen's production mix in 2003 was 81 percent gas and 19 percent oil and NGL's compared to 70 percent gas and 30 percent oil and NGL's in 2002.

Operating Costs

Operating costs in 2003 were $3,107,995 or $8.18 per boe compared to $7.61 per boe in 2002. The increase is attributable to lower production volumes.

General and Administrative

General and administrative costs incurred by Aspen decreased in fiscal 2003 to $2,252,112 or $5.93 per boe in 2003 compared to 4,937,057 or $8.91 per boe in 2002.

Depletion, Depreciation

Depreciation and depletion decreased in the twelve-month period from $11,304,036 in 2002 to $5,979,887 in 2003. In 2002, the Company reported a one-time ceiling test write-down on reserves of $6,997,182. Excluding the write-down, depletion and depreciation increased by $1,673,033 in 2003 primarily due to $1,574,980 ceiling test write down of the Company's Canadian reserves. On a per boe basis, excluding the 2002 and 2003 write-down, depletion and depreciation was $11.59 compared to $9.62 in 2002.

Interest Expense

Interest expense for the twelve months ended December 31, 2003 increased to $856,078 or $2.25 per boe compared to $901,738 or $1.63 per boe for the same period in 2002. The increase is due to several factors including lower production levels in 2003.

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Cash Flow

Cash flow from operations (before changes in working capital) improved to $3,177,033 or $0.06 per share in 2003 compared to negative cash flow of $4,259,819 or $0.11 per share deficiency for the year ended December 31, 2002. The $7.4 million improvement is mostly attributable to more efficient and cost effective operations.

Earnings/Loss Per Share

In 2003, Aspen recorded a net loss of $2,717,662, or $0.05 per share versus a net loss of $17,009,828 or $0.45 per share. The significant year over year reduction in net loss is due to several factors including more efficient operations due to company-wide cost reductions, higher commodity prices, and the impact of several write-downs and provisions taken in 2002 by the new management team in order to rationalize the Company's assets. In 2003, the net loss is primarily due to a $1,574,980 ceiling test write-down of its Canadian reserves.

Acquisitions

The Company made no material acquisitions in 2003.

Capital Expenditures

Capital additions, excluding acquisitions and divestitures for the year ended December 31, 2003 were $1,617,121 compared to $2,342,936 for the same period last year.

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B) Liquidity and Capital Resources

Although the Company's operations were profitable in fiscal years 2000 and 2001, the Company had historically incurred losses. The Company has reported net losses of $2,717,662, $17,009,828 and $869,198 for the periods ended December 31, 2003, 2002, and 2001 respectively and has current liabilities in excess of current assets in the amount of $14,107,377. This includes $ $10,321,210 of long-term debt, which has been reclassified to current, because it is in default of certain covenants under its loan agreement. Aspen hopes to bring the US banking facility in full compliance and if it succeeds, it will reclassify $10,321,210 of the current loan back to long-term debt. These factors, among others, may indicate that the Company will be unable to continue as a going concern for a reasonable period of time. Since joining the Company in October of 2002, the new Chief Executive Officer, along with the rest of the Company's management team has been developing a broad operational financial restructuring plan. Despite its history of losses, the Company has been able to secure financing to support its operations to date. The Company's accumulated deficit as of December 31, 2003 was $33,480,888. The Company has historically funded its operating losses, acquisitions and expansion costs primarily through a combination of private offerings of debt and equity securities and proceeds from the exercise of options and warrants.

Going forward, additional cash will be needed to implement the proposed business plan and to fund losses until the Company has returned to profitability. Where there is no assurance that funding will be available to execute the plan, the Company is continuing to seek financing to support its turnaround efforts and is exploring a number of alternatives in this regard. Management is exploring alternatives that include seeking strategic investors, selling Company assets and implementing cost reduction programs. There can be no assurance that management's efforts in this regard will be successful. The Company believes that the capital raised in fiscal 2003 and its current credit facility will be sufficient to support the Company's liquidity requirements through December 31, 2004, depending on operating results. Management believes that, despite the financial hurdles and funding uncertainties going forward, it has under development, a business plan that if successfully funded and executed as part of the financial restructuring, can significantly improve operating results.

On February 11, 2003, the Company completed a private placement of 12 million units at $0.14 each, for gross proceeds of $1.68 million Cdn. Each unit is comprised of one common share and one half of one common share purchase warrant with each whole common share purchase warrant exercisable for one common share at a price of $0.18 until August 10, 2004. The common shares and warrant issued will carry a four-month hold period under Canadian securities laws from the date of close.

On December 30, 2003, Aspen completed a Cdn$1,400,000 financing transaction (the "Loan") with Quest Capital Corp. ("Quest"). The Loan is due no later than December 30, 2004 and requires Aspen to make monthly interest only payments during the term. The Loan is secured by a guarantee and security interest over all of the assets of the Company's Canadian subsidiary, Aspen Endeavour Resources Inc. Pursuant to the Loan agreement, Aspen will utilize the funds to enhance its production levels through participation in several new drilling opportunities in its core areas in the United States, and for general working capital purposes of the Company.

C) Research and Development, Patents and Licenses, etc.

Aspen conducts no material research and development activities and has not dedicated any funds for this purpose.

D) Trend Information

An ongoing trend, which significantly affects the producers of oil and gas, is the continued volatility of commodity prices. In 2002 a number of factors caused huge fluctuations in the supply/demand expectations for oil and natural gas. Among these, were a colder than expected winter season and a slowdown in the world's economy. These factors have been offset by OPEC production cuts and the political instability in the Middle East.

There are a number of Canadian trends in the oil and gas industry that have been shaping the near term future of the business. The consolidation of the industry is affecting companies of all sizes. While consolidation is not new to the industry, the pace in which it has occurred recently and the nature of the companies are unique. Companies that have consolidated, include small emerging companies, medium companies and more recently large established companies. Royalty trust or large American companies have been the most active acquirers.

A direct result of this recent consolidation phase is the nationalization of assets. As a result, the Company believes that with time, this consolidation phase will provide opportunities for asset acquisitions and exploitation as the royalty trusts or established companies overlook or make available properties that are attractive to smaller companies.

Another result of this consolidation will be a tiering of exploration focus in the Western Canadian Basin with the majors and large independents focusing on impact reserves such as oil sands, foothills and northern areas. Smaller companies will be able to explore for smaller targets in mature areas utilizing innovative techniques of acquiring and interpreting data and accessing land.

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E) Off Balance Sheet Arrangements

As at December 31, 2003, the Company had no of balance sheet arrangements.

F) Contractual Obligations

Leases

The Company conducts its operations utilizing leased facilities under long-term lease agreements, classified as operating leases. The Company also leases certain equipment and vehicles under operating leases. Certain leases provide that the Company pay taxes, maintenance, insurance and certain other operating expenses and contain purchase options

Future minimum lease payments in the aggregate required by non-cancellable operating leases with initial or remaining terms in excess of one year are as follows:

Year Ending December 31,	Total
2004	$ 237,218
2005	97,909
2006	-
	$ 335,127

Total rent expense, all of which was minimum rentals, for the years ended December 31, 2003 and 2002 was approximately $223,000 and $696,000, respectively and is net of sublease rentals of $14,800 and $27,400, respectively.

Aspen Endeavour Resources, Inc. Notes Payable and Long-Term Debt:

		2003		2002
*CANADIAN WESTERN BANK*
Demand non-revolving $2,012,000 production loan, repayable in equal monthly installments of $96,725 commencing June 1, 2002 bearing interest at bank prime plus 0.75% which is secured by petroleum and natural gas properties	$	174,105	$	1,092,098
Demand revolving $1,780,000 production loan, repayable in equal monthly installments of $96,725 commencing January 1, 2004 bearing interest at bank prime plus 0.75% which is secured by petroleum and natural gas properties		1,470,220		443,170
		1,644,325		1,535,268

*OTHER NOTES PAYABLE AND LONG-TERM DEBT*
$205,000 loan, repayable in equal quarterly installments of $17,088 commencing March 31, 2002 bearing interest at 0% which is secured by petroleum and natural gas properties		68,352		111,848

Other		21,551		20,954

		1,734,228		1,668,070

Less - current portion		1,721,189		1,012,538
		13,039		655,532
Demand, revolving reducing loan in the principle amount of $1 million, bearing interest at bank prime plus 0.75%		-		-

	$	13,039	$	655,532

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The Aspen Endeavour loans bear interest at prime plus 0.75% and are secured by a $5 million fixed and floating charge debenture covering the various Canadian petroleum and natural gas leases. Aspen Endeavour is in compliance with all banking requirements.

Notes Payable and Long-Term Debt – U.S. Operations:

		2003		2002
*Aspen Energy Group Inc. Bank Loan*
Demand non-revolving production loan	$	10,321,210	$	14,844,002

*United Cementing and Acid Co., Inc.*
Equipment installment loans		403,579		508,184

*Aspen Group Resources Corporation*
Demand non-revolving production loan		1,083,320		-

Equipment and real estate installment loan		-		252,548

		11,808,109		15,604,734

Less – current portion		11,722,143		15,184,489

	$	85,966	$	420,245

Five-year maturity schedule:

Long-term debt is due as follows: 2004 - $13,443,332; 2005- $77,285; and 2006 - $21,720.

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ITEM 6 Directors, Senior Management and Employees

A) Directors and Senior Management

Name and Municipality of Residence	Position with Aspen	Principal Occupation	Age
Robert L. Calentine ⁽¹⁾ Santa Ynez, California	Director since May 31, 2002 and Chief Executive Officer	Businessman	62
Robert D. Cudney ^(1)(2)(3) Toronto, Ontario	Director since May 31, 2002 and Chairman of the Board	Businessman	45
Wayne T. Egan ⁽²⁾⁽³⁾ Toronto, Ontario	Director since June, 1996	Lawyer	41
James J. Unger ^(1)(2)(3) St. Charles, Missouri	Director since May 31, 2002	Businessman	54
Ron Mercer Norman, Oklahoma	VP Operations – United States	Petroleum Executive	55
Dennis P. Besler Calgary, Alberta	VP Operations – Calgary	Petroleum Executive	48
Allan C. Thorne Calgary, Alberta	Interim Chief Financial Officer	Manager of Finance & Taxation	49

Notes:

(1)

Denotes a member of the Executive Committee

(2)

Denotes a member of the Audit Committee

(3)

Denotes a member of the Compensation Committee

The following is a brief biographical description, including principal occupations of each of the officers and directors of the Company.

Directors

Robert L. Calentine

Mr. Robert Calentine currently holds the position of interim Chief Executive Officer. Mr. Calentine has been on the Board of Directors of Aspen since May 31, 2002, and was former CEO and founder of Custom Steel Inc., a leading supplier of custom fabricated steel products.

Robert C. Cudney

Mr. Robert D. Cudney was elected as a director of Aspen on May 31, 2002. Mr. Cudney is CEO, President and founder of Northfield Capital Corp. of Toronto, Ontario. Mr. Cudney is a former Director of Aspen Endeavour Resources Inc., which was acquired by Aspen effective December 31, 2001 and has served on the boards of several public companies in the manufacturing, mining, and technology industries

Wayne T. Egan

Mr. Wayne T. Egan has been a director of Aspen since June 17, 1996. Mr. Egan is a Partner of the law firm of WeirFoulds LLP and practices securities law and corporate finance. He is currently the head of the firm's Securities Law Practice Group. Mr. Egan received an LL.B. from Queen's University Law School in 1988 and a Bachelor of Commerce degree from the University of Toronto in 1985. Mr. Egan sits on the board of directors of numerous public companies. He is a Member of the Canadian Bar Association. WeirFoulds LLP serves as the Corporation's Corporate Counsel.

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James J. Unger

Mr. James J. Unger was elected as a director of Aspen on May 31, 2002. Mr. Unger is CEO of American Railcar Industries, Inc. of St. Charles, Missouri, a leading railcar manufacturer, and Vice-Chairman of ACF Industries, LLC.

The term of office of all of the above directors expires at the next annual meeting of shareholders of Aspen or until their successors are appointed, subject to the provisions of the Business Corporations Act (Yukon) and the by-laws of Aspen.

Officers

Ronald Mercer

Mr. Ron Mercer is Vice-President of Operations of Aspen. Mr. Mercer has been with Aspen since 1999 in various capacities. Mr. Mercer was appointed President of the Corporation effective December 1, 2000 and resigned his position as President in September 2002. Prior thereto he was Executive Vice-President and Chief Operating Officer of the Corporation effective from September 16, 1999. Prior thereto, Mr. Mercer has acted as President responsible for the daily operations of Mercer Oil and Gas Company and Armer LLC for the past 5 years. He is a Professional Engineer with over 30 years experience in oil and gas asset management. He is a Registered Professional Engineer in Texas and Oklahoma, and a Member of the Society of Professional Engineers and Society of Petroleum Engineers. Mr. Mercer received his B.Sc. in Petroleum Engineering from Texas Tech University.

Dennis Besler

Mr. Dennis Besler is Vice-President of Operations of Canadian Operations for Aspen. Mr. Besler is a director and Vice-President of Operations of Endeavour. Mr. Besler was a founder and was President of Lyse Petroleum Ltd., a private oil and gas corporation. Prior thereto, from 1994 to 1995, Mr. Besler was President of Ridgestarr Petroleum Management Ltd., an engineering and oil and gas management corporation. Mr. Besler was Operations Manager of ResoQuest Resources Ltd., a public oil and gas corporation. Prior to ResoQuest, Mr. Besler was employed with Ladd Exploration and Amoco Canada in various engineering operations capacities. Mr. Besler received his B.Sc. Mechanical Engineering in 1977 from the University of Saskatchewan, Saskatoon, Saskatchewan.

Allan Thorne

Mr. Allan Thorne, of Calgary, Alberta, is the interim Chief Financial Officer for Aspen. From 1998 until 2002, Mr. Thorne was the Manager of Finance and Taxation for Endeavour Resources Inc. Aspen acquired Endeavour in 2002. Prior thereto, Mr. Thorne was the owner of Sun West Ventures Ltd., a private management oil and gas consulting company that specializes in oil and gas accounting and taxation with small and medium sized exploration companies. Mr. Thorne has in excess of 20 years oil and gas experience specifically in the field of finance and taxation. From 1982 to 1996, Mr. Thorne was the Chief Financial Officer of Fossil Oil and Gas Limited, a TSE listed junior oil and gas Exploration Company.

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B) Compensation

Summary Compensation Table

Name and Position

Year

Annual Compensation

Long-term Compensation

All Other Compensation

($)

Awards

Salary

($)

Bonus

($)

Other Annual Compensation

($)

Securities Under Options/SAR’s Granted (#)

Robert Calentine

CEO

2003

2002⁽¹⁾

2001

250,000⁽²⁾

41,667

Ron Mercer ⁽³⁾

VP US Operations

2003

2002

2001 ⁽⁴⁾

2001 ⁽⁵⁾

150,000

162,375

72,167

128,667

100,000

107,143

Notes:

⁽¹⁾

Robert Calentine became CEO of the Corporation effective October 23, 2002.

⁽²⁾

Robert Calentine received total compensation of $250,000, $171,875 of which was paid by 1,937,624 common shares of the Corporation.

⁽³⁾

Ron Mercer resigned as President and COO of the Corporation in September of 2002. Mr. Mercer was appointed VP US Operations in October of 2002.

⁽⁴⁾

The Corporation switched from a June 30 year end to a December 31 year end in 2001, resulting in a 6 month fiscal period from July 1, 2001 to December 31, 2001, therefore the numbers reflected here are for the six month period only from July 1, 2001 to December 31, 2001.

⁽⁵⁾

Numbers reflected are for the twelve-month period from June 30, 2000 to June 30, 2001.

The Company maintains employment contracts with two officers, Mr. Robert Calentine and Mr. Ron Mercer through 2005 that provide for a minimum annual salary, benefits and incentives based on the Company's earnings. Mr. Calentine’s contract provides for lump sum severance payments, certain benefits and accelerated vesting of options upon termination of employment under certain circumstances or a change of control, as defined.

Legal expenses of approximately Cdn $87,718 were invoiced from a firm of which Wayne Egan, a director of the Corporation is a partner during the period January 1, 2003 to December 31, 2003. This amount is included in accounts payable in the Corporation's 2003 audited consolidated financial statements for the Corporation for the fiscal year ended December 31, 2003.

C) Board Practices

Directors are elected at each Annual General Meeting of Shareholders, each to hold office until the next Annual Meeting or until his/her successor is duly elected or appointed, unless his/her office is earlier vacated by death, removal or other cause in accordance with the Articles of the Company. The non-executive directors of the Company are not entitled to any benefits following termination of their service with the Company.

The board or directors has assigned specific governance responsibilities to three committees of the board, as follows:

Audit Committee

The Corporation has an Audit Committee which has the functions defined in the Business Corporations Act of Yukon. The Audit Committee is comprised of three non-management directors who are appointed by the Board. The committee reviews the Corporation's annual financial statements prior to their acceptance by the Board of Directors. The Committee is also responsible for reviewing the Corporation's financial reporting procedures and the adequacy of its internal controls. It considers the report of the external auditors and examines the fees and expenses for audit services and it recommends to the Board the independent auditors for appointment by the shareholders. It may undertake additional tasks at the request of the Board. The audit committee is composed of James Unger, Robert Cudney and Wayne Egan.

Compensation Committee

The Compensation Committee of the Board consists of Messrs. Cudney, Unger and Egan. The Compensation Committee exercises general responsibility regarding overall employee and executive compensation. The Compensation Committee sets the annual salary, bonus and other benefits of the President and the Chief Executive Officer and approves compensation for all other executive officers of the Corporation after considering the recommendations of the President and Chief Executive Officer.

Executive Committee

The Executive Committee consists of three directors. The Committee shall have and may exercise during the intervals between the meetings of the Board of Directors, all the powers vested in the board except the power to fill vacancies in the board, the power to change the membership of, or fill vacancies in, the said executive committee or any other committee of the board and such other powers, if any, as may be specified in a resolution of the board. The committee shall keep regular minutes or its transactions and shall cause them to be recorded in books kept for that purpose, and shall report the same to the board at such times as the board may from time to time require. The board shall have the power at any time to revoke or override the authority given to or acts done by the executive committee except as to acts done before such revocation or overriding and to terminate the appointment or change the membership of such executive committee and to fill vacancies in it. The executive committee may make rules for the conduct of its business and may appoint such assistants, as it may deem necessary. A majority of the members of the executive committee shall constitute a quorum thereof. The Committee is also responsible for assessing the effectiveness of the board as a whole, the committees of the board and the contribution of individual directors. The Executive Committee is composed of Robert Calentine, Robert Cudney and James Unger.

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D) Employees

The following chart outlines the number of Employees at the end of each of the past three years

	2003	2002	2001
United States:
Management	1	2	3
Professional	2	2	4
Administrative/support	1	12	20
Canada:
Management	2	3	n/a
Professional	0	3	n/a
Administrative/support	3	4	n/a

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E) Share Ownership

The Company is a publicly owned Yukon corporation, the shares of which are owned by U.S. residents, Canadian residents and other foreign residents.

The following table sets forth the Common Stock ownership of each of our directors and senior officers. All ownership shown is of record and reflects beneficial ownership and represents the number of shares of common stock beneficially owned, directly or indirectly, or controlled by the person listed but exclude stock options which are set forth in the following tables.

Name	Position	Number of shares beneficially owned, controlled or directed	Percentage of shares held
Robert Calentine	CEO	2,418,907	4.71
Robert Cudney	Chairman	5,564,438	9.27
Jim Unger	Director	75,000	less than 0.5
Wayne Egan	Director	30,000	less than 0.5

Ron Mercer	VP US Operations	142,857	less than 0.5
Dennis Besler	VP Cdn Operations	322,663	0.6
Allan Thorne	Interim CFO	22,533	less than 0.5
Total			14%

Options held by Aspen’s directors and officers expired on December 20, 2003.

ITEM 7 Major Shareholders and Related Party Transactions

A) Major Shareholders

Aspen's securities are recorded on the books of its transfer agent in registered form. A number of such shares are, however, registered in the name of intermediaries such as brokerage houses and clearinghouses on behalf of their respective clients. Aspen does not have any knowledge of the beneficial owners thereof. To the best of the Company's knowledge, the following is a summary of shareholders who own 5 percent or more of the Company's shares. The Company is not aware of any other shareholders with a 5 percent or greater share position in the Company.

Name	Number of Shares Held	Percentage of Shares
Robert Cudney	5,564,438	9.27

To the best of the Company's knowledge, the Company is not directly or indirectly owned or controlled by another corporation, by any foreign government, or by any other natural or legal persons severally or jointly.

B) Transactions with Affiliates

During the year ended June 30, 2001, the Company acquired ownership interests in 17 oil and gas producing properties, inventory and equipment from a company affiliated with Lenard Briscoe, who later became a director of the Company for 571,429 common shares of the Company. The common shares were recorded at $1,800,000.

- 28 -

Legal expenses of approximately, and $183,000 were attributable to a firm of which a director of the Company, during the periods ended December 31, 2003, December 31, 2002

In May 2002, the Company closed on an acquisition of real property and certain oil and gas properties in the United States. This transaction involved 2 former directors and the former CEO of the Company and is described as follows:

In July of 2000, the Company agreed to acquire real property from one of the former directors for 2 million unregistered shares of the Company. Upon closing in May 2002, the Company reflected the asset in the financial statements as Property and Equipment and assumed a mortgage payable by the former director on this property of $265,000 which has been reflected in the financial statements as part of the long-term debt. All operating expenses related to this property during the period prior to closing were the responsibility of the Company and were expensed in the current periods as operating and general and administrative expenses. In November of 2001 a cash payment of $100,000 was paid to the former director by a third party on behalf of the Company.

On December 31, 2001 the Company acquired through a third party, certain oil and gas assets owned by the former CEO of the Company. As the transaction had not closed, neither the asset nor the corresponding liability was reflected in the financial statements at December 31, 2001. The cost of the acquisition included a $500,000 promissory note bearing interest at 8% per annum payable in 60 installments commencing April 1, 2002 to a second former director. All revenue and expenses were recorded in the accounts of the Company commencing January 1, 2002.

On May 21, 2002, the transaction closed with the cancellation of a note receivable from a third party in the amount of $200,000 and the issuance of 2.825 million shares from treasury of the Company to the third party, which in turn forwarded 1.5 million of these shares to the former director.

On September 29, 2002, the former CEO returned the oil and gas properties to the second former director who held the promissory note on the transaction outlined in (b) above. This director assumed a $100,000 bank loan payable on behalf of the Company and forgave the $500,000 promissory note payable along with accrued interest.

In 2002, Endeavour contracted services from Prospect Oil & Gas Management Ltd., a company related by common management and controlled by a past director and officer of Endeavour for general and administrative, land, development and exploration services. The total amount charged for certain services during the year ended December 31, 2002 totalled $122,447. This contract expired on April 15, 2002.

At December 31, 2002, Prospect Oil & Gas Management Ltd. owed Endeavour $94,769 for oil and gas revenues in the normal course of operations, net of services rendered, which bear no interest and has been collected subsequent to December 31, 2003.

Endeavour is a shareholder of Cubacan exploration inc. (“Cubacan”) and at December 31, 2003 and 2002 owned 26,365,982 common shares or 32.5% of the outstanding capital. During 2002, the investment in these shares was written down to $1.00.

At December 31, 2003 and 2002, Cubacan owed endeavour $0 and $102,048, respectively as a result of cash advances and reimbursable costs which bear no interest and have no set terms of repayment. These transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

In November 2001, the Board of Directors approved a 2.5% and a 1.0% overriding royalty on all of the Company’s U.S. production as executive compensation for the Chief Executive Officer and President respectively. In 2002, 1.0% of these overriding royalties have been reassigned back to the Company. The 2.5% overriding royalty is currently in litigation. See footnote 13(m).

In 2002 Endeavour contracted Riechad, Inc. and APT, Inc., companies controlled by a past director and officer of Endeavour, for engineering and management services. The total contract fees charged and accrued during the year ended December 31, 2002 totalled $110,792. These transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

Evinco Exploration, Inc. is related by a common director. Evinco Exploration, Inc. f/k/a 988023 Alberta Ltd. is owed $228,202 and $101,916 at December 31, 2003 and 2002, respectively, for oil & gas revenues in the normal course of operations.

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C) Interests of Experts and Counsel

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 8 Financial Information

A) Consolidated Statements and Other Financial Information

The Company's audited financial statements, notes to the financial statements, independent auditors report, reserve reports, and other additional information are contained in Part III Item 17, 18, and 19 of this report.

Dividends

The Company has never paid or declared a dividend on its shares of common stock and does not intend to do so in the foreseeable future. The Company intends to use retained earnings to finance growth.

Exchange Rates

The financial statements, as provided under Items 8 and 17, are presented in US dollars.

B) Significant Changes

On February 11, 2003 the Corporation closed a private placement (the "Placement") brokered by Dundee Securities Corporation ("Dundee") of Toronto, Ontario of 12,000,000 units of the Corporation, each unit issued for Cdn.$0.14 a unit for gross proceeds of Cdn.$1,680,000 to the Corporation. Each unit was comprised of one common share and one-half common share purchase warrant exercisable at Cdn.$0.18 for a period of 18-months. Additionally, under the terms of the Corporation's engagement of Dundee as agent, Dundee received compensation options (the "Compensation Options") to purchase 1,200,000 units, being equal to 10 percent of the units placed by Dundee.

- 30 -

ITEM 9 Listing

A) Listing Details

The Common Shares of the Company are listed and posted for trading on The Toronto Stock Exchange (the "TSX"), under the symbol "ASR".

The Common Stock began trading through the Canadian Dealing Network ("CDN") on June 24, 1996, under the symbol "CVZC" and ceased trading on the CDN on October 2, 2000, when the shares commenced trading on the Canadian Venture Exchange ("CDNX"). The following table sets forth the high and low bid information for the Company's Common Stock in United States dollars as reported on the CDN or CDNX, as applicable, for the periods indicated reflecting the consolidation on a 1 for 7 basis effective February 12, 2001. The information in the table reflects inter-dealer prices, without retail mark-up, markdown or commission, and may not necessarily represent actual transactions. From December 31, 1997 to June 30, 1999, there were no significant trades on the CDN.

Period	High	Low
July 1 – September 30, 1999	2.59	0.70
October 1 – December 31, 1999	1.54	0.98
January 1 – March 31, 2000	0.98	0.84
April 1 – June 30, 2000	2.66	1.96
July 1 – September 30, 2000	1.925	1.40
October 1 – December 31, 2000	2.58	0.56
January 1 – February 26, 2001	2.25	0.98

The Common Stock began trading on the TSX on February 26, 2001, under the symbol "ASR." The following table sets forth the high and low sales prices for the Common Stock for the periods indicated, in Canadian dollars.

Period	High	Low
February 26 – March 31, 2001	1.95	1.60
April 1 – June 30, 2001	2.40	1.25
July 1, 2001 – September 30, 2001	1.50	1.15
October 1 – December 31, 2001	1.00	0.58
January 1 – March 31, 2002	0.67	0.42
April 1 – June 30, 2002	0.53	0.25
July 1 – September 30, 2002	0.30	0.10
October 1 – December 31, 2002	0.20	0.08
January 1 – March 31, 2003	0.235	0.14
April 1 – June 30, 2003	0.21	0.145
July 1 – September 30, 2003	0.21	0.155
October 1 – December 31, 2003	0.19	0.165

The Company's Common Stock began trading through the NASD Electronic Bulletin Board on January 14, 1997 under the symbol "CTVYF." On July 1, 1997, the Company's symbol was changed to "CTVY." The Company's Common Stock was not traded through the NASD Electronic Bulletin Board after October 17, 1997 until June 2, 1999 when the Common Stock returned to trading on the NASD Electronic Bulletin Board (OTCBB) under the symbol "KTNV." On April 12, 2000, Subsequent to the Company changing its name to Aspen Group Resources Corporation, the trading symbol was changed to "ASRG". On February 12, 2001 in accordance with a one for seven consolidation of Aspen's common shares, the symbol was changed by the OTCBB to "ASPG''. In 2002, the OTCBB again changed the trading symbol to "ASPGF" to indicate that the Company is a foreign issuer. In conjunction, The Company announced that due to its status as a "foreign private issuer" as defined in the Securities and Exchange Act of 1934, it elected to begin filing its financial reports and other applicable disclosure documents exclusively under Canadian securities guidelines effective January 1, 2003. Aspen is incorporated under the laws of the Yukon Territory, Canada and as of December 31, 2002, more than 50 percent of its outstanding common shares are held by non-U.S. residents thus causing it to become a "foreign private issuer" as defined in the Act. On August 20, 2003 Aspen shares were suspended from trading on the OTCBB pending the completion and filing of the Company's annual Form 20-F. The Company subsequently filed its 20-F but did not reapply for admission on the OTCBB and was relegated to the Pink Sheets under the symbol "ASPGF".

Period	High	Low
July 1 – December 31, 1999	1.95	0.58
January 1 – December 31, 2000	4.13	0.77
January 1 – March 31, 2001	1.69	0.63
April 1 – June 30, 2001	1.52	0.81
July 1 – September 30, 2001	1.10	0.60
October 1 – December 31, 2001	0.76	0.31
January 1 – March 31, 2002	0.35	0.26
April 1 – June 30, 2002	0.32	0.089
July 1 – September 30, 2002	0.17	0.07
October 1 – December 31, 2002	0.115	0.041
January 1 – March 31, 2003	.16	.10
April 1 – June 30, 2003	.15	.10
July 1 – September 30, 2003	.15	.11
October 1 – December 31, 2003	.13	.12

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B) Plan of Distribution

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

C) Markets

The Company's Common Shares are listed for trading on the Toronto Stock Exchange under the symbol "ASR" and on the Pink Sheets under the symbol “ASPGF”.

D) Selling Shareholders

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

E) Dilution

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

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F) Expenses of the Issue

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 10 Additional Information

A) Share Capital

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

B) Memorandum and Articles of Incorporation and By-laws

Aspen was incorporated in the Province of Ontario, originally as Cotton Valley Energy Limited, on February 15, 1995. On June 14, 1996, Aspen amalgamated with Arjon Enterprises, Inc., and Aspen's name was changed to Cotton Valley Resources Corporation. Aspen continued from Ontario to the Yukon Territory pursuant to Articles of Continuance dated February 9, 1998. Aspen changed its name to its current name "Aspen Group Resources Corporation" effective March 2, 2000. Aspen consolidated the Aspen Shares on a one for seven (1:7) basis by filing Articles of Amendment effective February 12, 2001.

A corporation subsisting under the Business Corporations Act (Yukon) ("YBCA") has the capacity and, subject to the YBCA, the rights, powers and privileges of a natural person. The Company's Articles and by-laws do not contain any restrictions on the business, which the Company may carry on or on the powers, which the Company may exercise.

The YBCA and the Company's by-laws provide that a director or officer who is a party to, or who is a director of officer of or has a material interest in any person who is a party to, a material contract or a proposed material contract with the Company shall disclose the nature and extent of his interest at the time and in the manner provided by the Act. Any such contract or proposed contract shall be referred to the board or shareholders for approval even if such contract is one that in the ordinary course of the Company's business would not require approval by the board or shareholders, and a director interested in a contract so referred to the board shall not vote on any resolution to approve the same except as provided by the Act. The directors shall manage the business and affairs of the Company. The powers of the board may be exercised by resolution passed at a meeting at which quorum is present or by resolution in writing, whether by document, telegram, telecopy or any method of transmitting legibly recorded messages or other means, signed by all the directors entitled to vote on that resolution at a meeting of the board and any resolution in writing so signed shall be as valid as if it had been passed at a meeting of directors or a committee of directors and shall be held to related to any date therein stated to be the effective date thereof, and a copy of every such resolution in writing shall be kept with the minutes of the proceedings of directors or committee of directors. Where there is a vacancy in the board, the remaining directors may exercise all the powers of the board so long as a quorum remains in office. Where the Company has only one director, that director may constitute a meeting. An action of a director is valid notwithstanding any irregularity in his election or appointment or a defect in his qualifications. The board shall be paid such remuneration for their services as the board may from time to time determine. The directors shall also be entitled to be reimbursed for traveling and other expenses properly incurred by them in attending meetings of the board or any committee thereof. Nothing shall preclude any director from serving the Company in any other capacity and receiving remuneration therefore.

- 33 -

The board of directors has unlimited authority to borrow money upon the credit of the Company in such amounts and on such terms as may be deemed expedient by obtaining loans or advances or by way of overdraft or otherwise, to issue, reissue, sell or pledge bonds, debentures, notes or other evidence of indebtedness or guarantees of the Company, whether secured or unsecured for such sums and at such prices as may be deemed expedient, to issue guarantees on behalf of the Company to secure the performance of the obligations of any person and to charge, mortgage, hypothecate, pledge or otherwise create a security interest in al or any currently owned or subsequently acquired real or personal, movable or immovable, property and undertaking of the Company, including book debts, rights, powers and franchises for the purpose of securing any such bonds, debentures, notes or other evidences of indebtedness or guarantee or any other present or future indebtedness or liability of the Company without the approval of the shareholders.

The Company's bylaws provide that no person shall be qualified for election as a director if he/she is less than nineteen (19) years of age. There is not, however, a bylaw which provides for a mandatory age of retirement. There is a requirement that the board of directors shall consist of not fewer than three (3) and not more than nine (9) directors, but there is no by-law stating that any director hold a specified number of shares in the Company.

The authorized capital of the Company consists of an unlimited number of common shares and an unlimited number of preference shares issuable in series ("preference shares").

Subject to the prior rights of the holders of the preference shares and to any other shares ranking senior to the common shares with respect to priority in the payment of dividends, the holders of the common shares shall be entitled to receive dividends and the Company shall pay dividends thereon, as an when declared by the board of directors of the Company, our of moneys properly applicable to the payment of dividends, in such amount and in such form as the board of directors may from time to time determine and all dividend which the directors may declare on the common shares shall be declared and paid in equal amounts per share on all common shares at the time outstanding.

In the event of dissolution, liquidation or winding-up of the Company, whether voluntary or involuntary, or any other distribution of the assets of the Company among its shareholders for the purpose of winding up its affairs, subject to the prior rights of the holders of the preference shares and to any other shares ranking senior to the common shares with respect to priority in the distribution of assets upon dissolution, liquidation or winding-up, the holders of the common shares shall be entitled to receive the remaining property and assets of the Company.

Except with the approval of all the holders of the preference shares, no dividends shall at any time be declared or paid or set apart for payment on the common shares or any other shares of the Company ranking junior to the preference shares unless all dividends up to and including the dividend payable for the last completed period for which such dividends shall be payable on each series of preference shares then issued and outstanding shall have been declared and paid or set apart for payment at the date of such declaration or payment or setting apart for payment on the common shares or such other shares of the Company ranking junior to the preference shares; nor shall the Company call for redemption, redeem, purchase for cancellation, acquire for value or reduce or otherwise pay off any of the preference shares (less than the total amount then outstanding) or any common shares or any other shares of the Company ranking junior to the preference shares unless and until all dividends up to and including the dividends payable for the last completed period for which such dividends shall be payable on each series of preference shares then issued an outstanding shall have been declared and paid or set apart for payment at the date of such call for redemption, purchase, acquisition, reduction or other payment.

The holders of the common shares shall be entitled to receive notice of and to attend all meetings of the shareholders of the Company and shall have one (1) vote for each common share held at all meetings of the shareholders of the Company, except for meeting at which only holders of another specified class or series of shares of the Company are entitled to vote separately as a class or series. Holders of the preference shares as a class shall not be entitled as such to receive notice of, to attend or to vote at any meeting of the shareholders of the Company.

The rights of holders of the common shares or preference shares may only be changed at a shareholders meeting were 662/3 percent of the shares being changed present at such meeting vote in favour, as required by the YBCA.

The time and place of the annual meeting is determined by the board of directors of the Company. A special meeting may be convened by the directors, the chairman of the board, or the president of the Company at any time. Notice of the time and place of each shareholders meeting shall be provided not less than 30 days and not more than 60 days before the date of the meeting to each director, to the auditor, and to each shareholder who at the close of business on the record date for such meeting is entered in the securities register as a holder of one or more shares carrying the right to vote at the meeting.

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C) Material Contracts

Except for contracts entered into in the ordinary course of business, the following sets forth the agreements entered into in the calendar years of 2002 and 2003, which may be considered presently material to Aspen:

The Company maintains employment contracts with two officers, Mr. Robert Calentine and Mr. Ron Mercer through 2005 that provide for a minimum annual salary, benefits and incentives based on the Company's earnings. One contract provides for lump sum severance payments, certain benefits and accelerated vesting of options upon termination of employment under certain circumstances or a change of control, as defined.

On February 11, 2003 the Corporation closed a private placement (the "Placement") brokered by Dundee Securities Corporation ("Dundee") of Toronto, Ontario of 12,000,000 units of the Corporation, each unit issued for Cdn.$0.14 a unit for gross proceeds of Cdn.$1,680,000 to the Corporation. Each unit was comprised of one common share and one-half common share purchase warrant exercisable at Cdn.$0.18 for a period of 18-months. Additionally, under the terms of the Corporation's contract with Dundee as agent, Dundee received compensation options (the "Compensation Options") to purchase 1,200,000 units, being equal to 10 percent of the units placed by Dundee.

As the Corporation received subscriptions for 12,000,000 units, the aggregate number of common shares issuable, including the Compensation Options, would be 19,800,000 common shares. This amounts to 2,085,005 shares in excess of the maximum approved by Shareholders at the last meeting of the Corporation. Accordingly and in order to accommodate the arm's length purchasers that wished to purchase the additional 2,085,005 units to complete the Placement and deliver funds to the Corporation, Robert Cudney, a director of the Corporation, agreed that under his subscription for 2,000,000 units he would receive the 1,000,000 warrants issuable thereunder subject to the condition that they are not exercisable until Shareholder approval for the issuance of these warrants is obtained. In addition, Dundee did also agree that 725,000 of the 1,200,000 units issued as the Compensation Options would not be exercisable until similar Shareholder approval is received. These 725,000 units, if fully exercised by Dundee, including the underlying warrants, represent 1,087,500 common shares. As a result, the securities represented by the 725,000 units to Dundee, when exercised, in addition to the 1,000,000 warrants issued Robert Cudney, equal an aggregate of 2,087,500 shares, which is in excess of the "shortfall" from the prior Shareholder approval.

On April 28, 2000, the Company entered into a credit agreement with a bank under which it may borrow up to $25,000,000 limited to the borrowing base as determined by the lender. The commitment amount was $14,844,002 at December 31, 2002. At December 31, 2003, there was $10,321,210 of outstanding borrowings under this agreement. The agreement also provides for a commitment fee of one-half percent per annum on the average unused portion of the commitment. A facility fee of one-half percent is assessed for increases in the commitment amount.

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The facility is collateralized by the Company's oil and gas properties. Under the terms of the credit agreement, the Company is required to maintain certain financial ratios and other financial conditions.

Interest is payable monthly and the credit agreement requires monthly commitment reductions as determined by lender. The credit agreement matures on April 10, 2004.

On October 4, 2002, Aspen Energy Group Inc. was notified that it was in default of the US Banking Credit Agreement for the quarterly period ending June 30, 2002. Management is currently in negotiations with the US banker to remedy these defaults. Due to the non-compliance of the US bank requirements, the Company has reclassified its $10,321,210 long-term debt to current.

D) Exchange Controls

U.S. shareholders may experience impediments to the enforcement of civil liabilities in the United States against foreign persons such as an officer, director or expert acting on our behalf in Canada. Such difficulty arises out of the uncertainty as to whether a court in the United States would have jurisdiction over a foreign person in the United States, whether a U.S. judgment is enforceable under Canadian law and whether suits under federal securities laws could initially be brought in Canada.

There are not any governmental laws, decrees or regulations in Canada relating to restrictions on the import/export of capital affecting the remittance of interest, dividends or other payments to non-residential holders of the Company's Common Shares. Any such remittances to United States residents, however, are subject to a 15 percent withholding tax pursuant to Article X of the reciprocal tax treaty between Canada and the United States.

Except as provided in the Investment Canada Act, which has provisions that govern the acquisition of a control block of voting shares by non-Canadians of a corporation carrying on a Canadian business, there are no limitations specific to the rights of non-Canadians to hold or vote the common shares of the Company under the laws of Canada or the Province of British Columbia or in the charter documents of the Company.

Management of the Company considers that the following general summary fairly describes those provisions of the Act pertinent to an investment in the Company by a person who is not a Canadian resident (a "non-Canadian").

The Act requires a non-Canadian making an investment which would result in the acquisition of control of the Canadian business to notify the Investment Review Division of Industry Canada, the federal agency created by the Act; or in the case of an acquisition of a Canadian business, the gross value of the assets of which exceeds certain threshold levels or the business activity of which is related to Canada's cultural heritage of national identity, to file an application for review with the Investment Review Division.

The notification procedure involves a brief statement of information about the investment on a prescribed form, which is required to be filed with Investment Canada by the investor at any time up to 30 days following implementation of the investment. Once the completed notice has been filed, a receipt bearing the certificate date will be issued to the non-Canadian investor. The receipt must advise the investor either that the investment proposal is unconditionally non-reviewable or that the proposal will not be reviewed as long as notice of review is not issued within 21 days of the date certified under the receipt. It is intended that investments requiring only notification will proceed without government intervention unless the investment is in a specific type of business activity related to Canada's cultural heritage and national identity.

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If an investment is reviewable under the Act, an order for review must be issued within 21 days after the certified date on which notice of investment was received. An application for review in the form prescribed is required to be filed with Investment Canada prior to the investment-taking place. Once the application has been filed, a receipt will be issued to the applicant, certifying the date on which the application was received. For incomplete applications, a deficiency notice will be sent to the applicant, and if not done within 15 days of receipt of application, the application will be deemed to be complete as of the date it was received. Within 45 days after the complete application has been received, the Minister responsible for the Investment Canada Act must notify the potential investor that the Minister is satisfied that the investment is likely to be of net benefit to Canada. If within such 45-day period the Minister is unable to complete the review, the Minister has an additional 30 days to complete the review, unless the applicant agrees to a longer period. Within such additional period, the Minister must advise either that he is satisfied or not satisfied that the investment is likely to be of net benefit to Canada. If the time limits have elapsed, the Minister will be deemed to be satisfied that the investment is likely to be of net benefit to Canada. The investment may not be implemented until the review has been completed and the Minister is satisfied that the investment is likely to be of net benefit to Canada.

If the Minister is not satisfied that the investment is likely to be of net benefit to Canada, the non-Canadian must not implement the investment or, if the investment has been implemented, could be penalized by being required to divest himself of control of the business that is the subject of the investment. To date, the only types of business activities which have been prescribed by regulation as related to Canada's cultural heritage or national identity deal largely with publication, film and music industries. Because the Company’s total assets are less than the $5 million notification threshold, and because the Company’s business activities would likely not be deemed related to Canada's cultural heritage or national identity, acquisition of a controlling interest in the Company by a non-Canadian investor would not be subject to even the notification requirements under the Investment Canada Act.

The following investments by non-Canadians are subject to notification under the Act:

an investment to establish a new Canadian business; and

an investment to acquire control of a Canadian business that is not reviewable pursuant to the Act.

The following investments by a non-Canadian are subject to review under the Act:

direct acquisition of control of Canadian businesses with assets of $5 million or more, unless the acquisition is being made by a World Trade Organization ("WTO") member country investor (the United States being a member of the WTO);

direct acquisition of control of Canadian businesses with assets of $172,000,000 or more by a WTO investor;

indirect acquisition of control of Canadian business with assets of $5 million or more if such assets represent more than 50 percent of the total value of the assets of the entities, the control of which is being acquired, unless the acquisition is being made by a WTO investor, in which case there is no review;

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indirect acquisition of control of Canadian businesses with assets of $50 million or more even if such assets represent less than 50 percent of the total value of the assets of the entities, the control of which is being acquired, unless the acquisition is being made by a WTO investor, in which case there is no review; and

an investment subject to notification that would not otherwise be reviewable if the Canadian business engages in the activity of publication, distribution or sale of books, magazines, periodicals, newspapers, film or video recordings, audio or video music recordings, or music in print or machine-readable form.

Generally speaking, an acquisition is direct if it involves the acquisition of control of the Canadian business or of its Canadian parent or grandparent and an acquisition is indirect if it involves the acquisition of control of a non-Canadian parent or grandparent of an entity carrying on the Canadian business. Control may be acquired through the acquisition of actual voting control by the acquisition of voting shares of a Canadian corporation or through the acquisition of substantially all of the assets of the Canadian business. No change of voting control will be deemed to have occurred if less than one-third of the voting control of a Canadian corporation is acquired by an investor.

A WTO investor, as defined in the Act, includes an individual who is a national of a member country of the World Trade Organization or who has the right of permanent residence in relation to that WTO member, a government or government agency of a WTO investor-controlled corporation, limited partnership, trust or joint venture and a corporation, limited partnership, trust or joint venture that is neither WTO-investor controlled or Canadian controlled of which two-thirds of its board of directors, general partners or trustees, as the case may be, or any combination of Canadians and WTO investors.

The higher thresholds for WTO investors do not apply if the Canadian business engages in activities in certain sectors such as uranium, financial services, transportation services or communications.

The Act specifically exempts certain transactions from either notification or review. Included among this category of transactions is the acquisition of voting shares or other voting interests by any person in the ordinary course of that person's business as a trader or dealer in securities.

E) Taxation

The discussion below is of a general nature only and is not intended to be, nor should it be construed to be, legal, business or tax advice to any particular holder or prospective holder of Common Shares. The tax considerations relative to ownership and disposition of the Common Shares may vary from taxpayer to taxpayer depending on the taxpayer's particular status. Accordingly, holders and prospective holders of Common Shares should consult their own tax advisors regarding any and all tax consequences of purchasing, owning and disposing of Common Shares.

Certain Canadian Federal Income Tax Consequences

The Company believes that the following is a summary of the principal Canadian federal income tax considerations generally applicable to holders of Common Shares who, for purposes of the Income Tax Act (Canada) (the "Canadian Tax Act"): (i) will hold Common Shares as capital property; (ii) deal at arm's length with the Company; (iii) do not and will not have a fixed base or permanent establishment in Canada; (iv) are not and will not be resident or deemed to be resident in Canada at any time while they hold Common Shares; (v) do not use or hold, and are not deemed to use or hold Common Shares in connection with carrying on a business in Canada; and (vi) in the case of a non-resident of Canada who carries on an insurance business in Canada and elsewhere, the Common Shares are not "designated insurance property" for purposes of the Canadian Tax Act and Regulations thereto and are not effectively connected with or used or held in the course of an insurance business carried on in Canada at any time a ("non-resident holder"). This summary does not apply to a non-resident holder with respect to whom the Company is a foreign affiliate within the meaning of the Canadian Tax Act.

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This summary is based on the current provisions of the Canadian Tax Act, the Regulations thereto, the current provisions of the Canada-United States Income Tax Convention of 1980 (the "Tax Treaty"), and the current published administrative practices of Canada Customs and Revenue Agency ("CCRA"). This summary takes into account the amendments to the Canadian Tax Acts and Regulations thereto, publicly announced by the Minister of Finance prior to the date hereof (the "Proposed Amendments"). Proposed Amendments and assumes that all the Proposed Amendments will be enacted in their present form. However, no assurance can be given that the Proposed Amendments will be enacted in the form proposed, or at all.

Except for the foregoing, this summary does not take into account or anticipate any changes in law, whether by legislative, administrative or judicial decision or action, nor does it take into account provincial, territorial or foreign income tax legislation or considerations, which may differ from the Canadian federal income tax considerations described herein.

Dividends

Dividends paid or credited to a non-resident holder on the Common Shares will be subject to a non-resident withholding tax under the Canadian Tax Act at the rate of 25 percent although such rate may be reduced under the provisions of an applicable income tax treaty.

Disposition of Company Common Shares

A non-resident holder will not be subject to tax under the Canadian Tax Act on any capital gain realized on a disposition or deemed disposition of Common Shares provided such shares are not "taxable Canadian property" to such holder at the time of disposition. Generally, the Common Shares will not be taxable Canadian property to a non-resident holder described above, provided that such shares are listed on a prescribed stock exchange (which currently includes the TSX and the NYSE), and the holder, persons with whom such holder does not deal at arm's length, or the holder and such persons, has not owned (or had under option) 25 percent or more of the issued shares of any class or series of the capital stock of the Company at any time within five years preceding the date in question.

Even if the Common Shares are taxable Canadian property to a non-resident holder, the Tax Treaty may generally exempt such a holder who is resident in the United States for purposes of the Tax Treaty from tax in respect of the disposition provided the value of the Common Shares is not derived principally from real property situated in Canada. The Company is of the view that the value of the Common Shares is not currently derived principally from real property situated in Canada.

Certain United States Federal Income Tax Consequences

The Company believes that the following is a summary of the principal United States Federal income tax consequences under current law which are generally applicable to a U.S. Holder (as defined below) of Common Shares. This discussion does not address all potentially relevant United States Federal income tax matters and it does not address consequences peculiar to persons subject to special provisions of United States Federal income tax law, such as those described below as excluded from the definition of a U.S. Holder. In addition, this discussion does not cover any state, local or foreign tax consequences.

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The following discussion is based upon the sections of the Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations, published Internal Revenue Service ("IRS") rulings, published administrative positions of the IRS and court decisions that are currently applicable, any or all of which could be materially and adversely changed possibly on a retroactive basis, at any time. The following discussion is for general information only and it is not intended to be, nor should it be construed to be, legal or tax advice to any holder or prospective holder of Common Shares and no opinion or representation with respect to the United States Federal income tax consequences to any such holder or prospective holders is made.

U.S. Holders

As used herein, a "U.S. Holder" includes a holder of Common Shares who is a citizen or resident of the United States, a corporation created or organized in or under the laws of the United States or of any political subdivision thereof, any entity which is taxable as a corporation for U.S. tax purposes and which is organized under the laws of the United States or any political subdivision thereof, and any other person or entity whose ownership of Common Shares is effectively connected with the conduct of a trade or business in the United States. A U.S. Holder does not include persons subject to special provisions of United States Federal income tax law.

Distributions on Common Shares

U.S. Holders receiving distributions (including constructive distributions) with respect to Common Shares are required to include in their gross income for United States Federal income tax purposes, the gross amount of such distributions to the extent that the Company has current or accumulated earnings and profits, without reduction for any Canadian income tax withheld from such distributions. Such Canadian tax withheld may be credited, subject to certain limitations, against the U.S. Holder's United States Federal income tax liability or, alternatively, may be deducted in computing the U.S. Holder's United States Federal taxable income by those who itemize deductions. (See more detailed discussion under the heading "Foreign Tax Credit" below). To the extent that such distributions exceed current or accumulated earnings and profits of the Company, they will be treated first as a tax-free return of capital up to the U.S. Holder's adjusted basis in the Common Shares and thereafter as gain from the sale or exchange of the Common Shares. Preferential tax rates for net capital gains are applicable to a U.S. Holder which is an individual, estate or trust. There are currently no preferential tax rates for long-term capital gains for a U.S. Holder which is a corporation or is an entity taxable as a corporation.

Foreign Tax Credit

A U.S. Holder who pays (or has withheld from distributions) Canadian income tax with respect to the ownership of Common Shares may be entitled, at the option of the U.S. Holder, to either a deduction or a tax credit for such foreign tax paid or withheld. This election is made on a year-by-year basis and applies to all foreign taxes paid by (or withheld from amounts paid to) the U.S. Holder during that year. There are significant and complex limitations which apply to the credit, among which is the general limitation that the credit cannot exceed the proportionate share of the U.S. Holder's United States income tax liability that the U.S. Holder's foreign source income bears to his or her worldwide taxable income.

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Disposition of Common Shares

A U.S. Holder will recognize a gain or loss upon the sale of Common Shares equal to the difference, if any, between (i) the amount of cash plus the fair market value of any property received, and (ii) and shareholder's tax basis in the Common Shares. This gain or loss will be a capital gain or loss if the Common Shares are a capital asset in the hands of the U.S. Holder, and will be either a short-term or long-term capital gain or loss depending upon the holding period of the U.S. Holder. Gains and losses are netted and combined according to special rules in arriving at the overall capital gain or loss for a particular tax year. Deductions for net capital losses are subject to significant limitations.

Other Considerations

In the following circumstances, the above sections of this discussion may not describe the United States Federal income tax consequences resulting from the holding and disposition of Common Shares.

Passive Foreign Investment Company

The Company may potentially be treated as a passive foreign investment company ("PFIC"), as defined in Section 1297 of the Internal Revenue Code of 1986, as amended, depending upon whether (i) 75 percent or more of its gross income is passive income; or (ii) 50 percent or more of the average amount of its assets produce (or are held for the production of) passive income.

For the years ended December 31, 2002, 2001 and 2000, the Company does believe that it is a PFIC as defined in Section 1297 of the Internal Revenue Code of 1986. The Company's determination in this respect has been made after reviewing the PFIC provisions and applying such provisions to its past and present situations. Although it is considered unlikely, there can be no assurance that the Company's determination concerning its PFIC status may not be challenged by the IRS, or that the Company will be able to satisfy record keeping requirements which are imposed on certain PFICs. The Company intends to make annual information available to each U.S. Holder as to its potential PFIC status and income to be reported.

If a U.S. Holder does not make an election with respect to a PFIC, such U.S. Holder may be subject to additional tax and to an interest charge upon receiving certain dividends from a PFIC, or upon the disposition of shares of a PFIC. The tax and interest charge are determined by allocating the distribution or gain over the U.S. Holder's holding period of the stock, imposing tax at the highest rate in effect for each tax year to which the excess distribution is allocated, and calculating interest on that unpaid tax.

If the U.S. Holder makes a timely election either to treat a PFIC as a qualified electing fund ("QEF") or to mark-to-market any publicly traded PFIC stock, the above-described rules generally will not apply. If a QEF election is made, a U.S. Holder would include annually in gross income his or her pro rata share of the PFIC's ordinary earnings and net capital gain, regardless of whether such income or gain was actually distributed.

The mark-to-market election would cause a PFIC shareholder to include in income each year an amount equal to the excess, if any, of the fair value of the PFIC stock as of the close of the taxable year over the shareholder's adjusted basis in such stock; or allow the shareholder a deduction for the excess, if any, of the adjusted basis of the PFIC stock over its fair market value as of the close of the taxable year. The shareholder's adjusted basis in the PFIC stock is increased by the amount included in income and decreased by any deductions allowed.

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The PFIC rules are exceedingly complex and, therefore, each U.S. Holder is encouraged and expected to consult his or her own tax advisor regarding the effect of the Company's potential PFIC status on such U.S. Holder.

F) Dividends and Paying Agents

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

G) Statement by Experts

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

H) Documents on Display

The documents and exhibits referred to in this document are available for inspection at the Head Office of the Company at One North Hudson, Suite 1000, Oklahoma City, OK, USA 73102 during normal business hours.

I) Subsidiary Information

The information referred to in this section is not required for reports filed in the United States.

ITEM 11 Quantitative and Qualitative Disclosures About Market Risk

The Company is a "Small Business Issuer" as such term is defined in Rule 12b-2 under the Exchange Act and, as such, there is no requirement to provide any information under this Item.

ITEM 12 Description of Securities Other than Equity Securities

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

PART II

ITEM 13 Defaults, Dividend Arrearages and Delinquencies

On April 28, 2000, the Company entered into a credit agreement with a bank under which it may borrow up to $25,000,000 limited to the borrowing base as determined by the lender. The commitment amount was $14,844,002 at December 31, 2002. At December 31, 2003, there was $10,321,210 of outstanding borrowings under this agreement. Interest on outstanding borrowings currently accrues at the bank's base rate of interest plus one-quarter percent. The agreement also provides for a commitment fee of one-half percent per annum on the average unused portion of the commitment. A facility fee of one-half percent is assessed for increases in the commitment amount.

Interest is payable monthly and the credit agreement requires monthly commitment reductions as determined by lender. The credit agreement matures on April 10, 2004.

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ITEM 14 Material Modifications to the Rights of Security Holders and Use of Proceeds

Neither the Company nor, to the best of its knowledge, anyone else has modified materially or qualified the rights evidenced by any class of registered securities.

ITEM 15 Controls and Procedures

Aspen maintains “disclosure controls and procedures”, as such term is defined under (Exchange Act Rule 13a-15(e) or OSC guidelines?), that are designed to ensure that information required to be disclosed in the Company’s reports is recorded, processed, summarized, and reported within the time periods specified by the SEC and the OSC and that such information is accumulated and communicated to Aspen’s management, including its Chief Executive Officer and Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the controls and procedures, Aspen’s management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In reviewing these controls and procedures, Aspen’s management has found deficiencies and is working to cure said deficiencies.

ITEM 16A Audit Committee Financial Expert

The Company's audit committee consists of James J. Unger, Wayne T. Egan, and Robert D. Cudney. The Company does not designate any one member of its audit committee as a financial expert. The members of the committee collectively possess the experience in accounting, auditing, and public disclosure to oversee and assess the performance and reporting requirements of a public company with respect to the preparation and evaluation of financial statements. Biographical information on each member of the audit committee is available in Item 6 of this report.

ITEM 16B Code of Ethics

The Company currently has a written code of ethics in place. The Company's new management team took over stewardship of the Company in late October of 2002 upon the resignation of the Company's former Chairman and CEO.

ITEM 16C Principle Accountant Fees and Services

Audit Fees

The Company paid $94,861 in audit fees in 2003 and $67,000 in 2002.

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Audit-related fees

The Company paid $30,700 in audit-related fees in 2003 and $26,500 in audit related fees in 2002.

Tax Fees

The Company paid $25,996 in tax fees in 2003 and $73,193 in tax fees in 2002.

All other fees

The Company paid $250 in other fees in 2003 and $10,750 in other fees in 2002.

Item 16D Exemption from the Listing Standards

The Company adheres to the guidelines for Audit Committee provides by the Ontario Securities Commission.

ITEM 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

*Period*	*Total Number of Shares Purchased*
*January 1 – 31, 2003*	-
*February 1- 28, 3003*	-
*March 1 – 31, 2003*	-
*April 1 – 30, 2003*	-
*May 1 – 31, 2003*	-
*June 1 – 30, 2003*	-
*July 1 – 31, 2003*	*61,500*
*August 1 – 31, 2003*	*40,000*
*September 1 – 31, 2003*	*397,500*
*October 1 – 31, 2003*	*130,000*
*November 1 –31, 2003*	*225,500*
*December 1 – 31, 2003*	*364,000*

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PART III

ITEM 17 Financial Statements

See the Financial Statements and Exhibits listed in Item 19 hereof and filed as part of this Annual Report.

The accompanying consolidated financial statements have been prepared by management and audited according to US generally accepted accounting principles, and the Company has been advised there are no material differences in the financial statements as a result of applying Canadian GAAP. Financial statements are not precise since they include certain amounts based on estimates and judgments. When alternative methods exist, management has chosen those it deems most appropriate in the circumstances in order to ensure that the consolidated financial statements are presented fairly, in all material respects, in accordance with accounting principles generally accepted in the United States of America and Canadian generally accepted accounting principles. The financial information presented elsewhere in the annual report is consistent with that in the consolidated financial statements.

The Board of Directors of the Company is responsible for ensuring that management fulfills its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements and the accompanying Management's Discussion and Analysis. The Board carries out this responsibility principally through its Audit Committee. The Audit Committee is appointed by the Board, and all of its members are non-executive directors. This Committee meets periodically with management and the external auditors to discuss internal controls, auditing matters and financial reporting issues, and to satisfy itself that each party is properly discharging its responsibilities. It also reviews the consolidated financial statements, Management's Discussion and Analysis and the external auditors' report, and examines the fees and expenses for audit services, and considers the engagement or reappointment of the external auditors. The Audit Committee reports its findings to the Board for its consideration when approving the consolidated financial statements for issuance to the shareholders. Lane Gorman LLP, Dallas, Texas, the external auditors, have full and free access to the Audit Committee.

ITEM 18 Financial Statements

See Item 17.

ITEM 19 Exhibits

The following exhibits are attached and incorporated herein:

Description of Document		Page
*A. Financial Statements*
Management’s Discussion and Analysis		M - 1
Cover Page		F-1
Auditors Report dated May 14, 2004		F-2
Consolidated Balance Sheets as at December 31, 2003 and 2002		F-3
Consolidated Statements of Operations and Deficit for the years ended December 31, 2003and 2002		F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2003and 2002		F-5
Notes to the Consolidated Financial Statements for the years ended December 31, 2003 and 2002		F-6
*B. Exhibits*
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		99-1
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		99-2
Reserve Report - US Properties		99-3

Reserve Report – Canadian Properties		99-4
Employment Agreements – Robert Calentine		99-5
Articles of Amalgamation		99-6
Organization Chart		99-7
Code of Ethics		99-8
Agency Agreement		99-9
Additional Certification		99-10

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.


	ASPEN GROUP RESOURCES CORPORATION.
	(Registrant)

Dated as of April 29, 2005.	By:	/s/ Robert L. Calentine
	Name:	Robert L. Calentine
	Title:	Chief Executive Officer

EXHIBITS

SECTION A – MANAGEMENT DICUSSION AND ANALYSIS

M-1

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following discussion should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2003 and the accompanying notes. Aspen Group Resource Corporation’s financial statements have been prepared using US GAAP. Aspen’s reserves have been reported in accordance with the respective SEC and National Instrument 51-101 guidelines.

This discussion contains certain forward-looking statements based on current expectations. These forward looking statements entail various risks and uncertainties that could cause actual results to differ materially from those reflected in these forward looking statements. Management has prepared this discussion to help investors understand the financial results of the Company in the broader context.

Aspen Group Resource Corporation (“Aspen” or the “Company”) is an independent energy company engaged in the acquisition, exploration, development and operation of oil and gas properties with a geographic focus in major oil and gas producing regions in the United States and Canada. The Company's head office is in Oklahoma City, Oklahoma. Its Canadian operations are run out of its office in Calgary, Alberta.

Aspen currently owns interests in approximately 1,000 wells located in U.S., with a predominant focus in the Mid Continent region of the U.S. and 138 wells located in two provinces within Canada. Approximately 65 percent of the Company’s daily production and 90 percent of its reserves are derived from its U.S. operations.

In the U.S., Aspen operates 129 wells with an average working interest of 91 percent and has an average working interest of 4 percent in 837 non-operated properties. 97 percent of Aspen’s U.S. properties are in the Mid Continent area with the majority of the well bores in the Anadarko and Arkoma Basins of western Oklahoma and the Texas Panhandle.

In Canada, Aspen operates through its wholly owned subsidiary Aspen Endeavour and has properties in Alberta and southern Saskatchewan, both in an operator and non-operator position. The primary areas of operation are Sturgeon Lake and Namaka, Alberta. The Company operates 40 wells with an average working interest of 47 percent and has an average working interest of 22 percent in 98 non-operated properties.

Aspen’s results are reported on a consolidated basis.

Revenues

Aspen’s gross revenues were $9,720,210 for the year ended December 31, 2003 compared to $7,834,634 for the same period in 2002. Oil and natural gas sales increased to $8,667,363 from $6,969,309 in 2002 primarily due to higher commodity prices. Oil field service revenue from Aspen’s wholly owned subsidiary, United Cementing and Acidizing Co. Inc. (“United”), increased to $1,052,847, up from $865,325 in 2002. The improved results at United were the result of actions taken by Aspen’s management to restructure the business.

Production

Gross production in the twelve-month period ending December 31, 2003 decreased to an average of 1,041boe/d as compared to 1,517 boe/d in 2002. The decline in production is primarily due to the sale of producing properties, which were monetized in order to reduce debt, and reduced cash flow in the first half of the year, which restricted investment into production. Aspen’s production mix in 2003 was 81 percent gas and 19 percent oil.

Oil and Gas Production Expense

Oil and gas production expense declined from $4,212,552 in 2002 to $3,107,995 in 2003. The decrease is directly attributable to the aforementioned decrease in production.

Operating Expenses

Operating expenses are costs associated with United operations, excluding G&A expense. For 2003 operating expenses declined to $674,320 from $908,973 for the same period in 2002. This was attributable to restructuring changes such as price increases and cost reductions.

General and Administrative Expense

General and administrative costs decreased from $4,937,057 in 2002 to $2,252,112 in 2003, representing a 54 percent year over year improvement. The significant decline in G&A is directly related to reductions in staff and related costs, as well as company-wide cost saving measures initiated by management in 2003.

Depletion, Depreciation and Amortization

Depletion, depreciation, and amortization decreased in the twelve-month period from $10,999,556 in 2002 to $5,926,563 in 2003. Of that, $1,574,980 is attributable to a ceiling test write–down of the Company’s Canadian reserves in 2003, and a write-down of the U.S. reserves of $6,997,182 in 2002.

Other Income

The Company recorded a one-time expense recovery of $337,158 this year from a legal settlement.

Interest Expense

Interest expense decreased slightly from $901,738 in 2002 to $856,078 in 2003 due to the reduction in long-term debt.

Income/Loss Per Share

In 2003, Aspen recorded a net loss of $2,717,662, or $0.05 per share versus a net loss of $17,009,828 or $0.45 per share. The significant year over year reduction in net loss is due to several factors including more efficient operations due to company-wide cost reductions, higher commodity prices, and the impact of several write-downs and provisions taken in 2002 by the new management team in order to rationalize the Company’s assets. In 2003, the net loss is primarily due to a $1,574,980 ceiling test write-down of its Canadian reserves.

Cash Flow

Capital Expenditures

Capital additions, excluding acquisitions and divestitures for the year ended December 31, 2003 were $1,617,121 compared to $2,342,936 for the same period in 2002.

Reserves

The independent reserve engineering reports for its U.S. and Canadian assets were prepared and are presented under the respective SEC and NI51-101 guidelines. The reserve data and future estimates presented in the following table are for Proved Reserves as at December 31, 2003 in US dollars on a constant price case basis.

Combined U.S. and Canadian Reserves

In US dollars at December 31, 2003
Reserve Category	Net Oil (Bbls)	Net Gas (Mcf)	Future Net Revenue ($)	Discounted Future Net Revenue ($) @ 10% Discount
Proved Developed Producing	576,686	16,375,193	58,043,706	27,397,534
Proved Developed Non-Producing	9,378	1,240,784	4,149,093	1,306,916
Proved Undeveloped	81,164	7,092,731	23,533,970	14,304,313
Total Proved	667,228	24,708,708	$85,726,769	$43,008,763

The 2003 reserve values are calculated using $29.30 per barrel for oil (Cdn.$35.78) and $4.56 per mcf for gas (Cdn.$5.59). On a PV-10 basis, reserve value declined by $288 thousand from 2002. The decline was due primarily to the sale of producing U.S. and Canadian assets and the annual re-evaluation of the Company’s reserves, which amounted to approximately 196 thousand barrels of oil and 4 million mcf of gas. In addition, Aspen’s decreased cash flow during the first half of 2003 reduced the Company’s drilling activities and hampered its ability to increase reserves. During the second half of 2003, Aspen’s cash flow improved significantly and the Company has begun investing in drilling in the U.S. and Canada in order to grow reserves and production. Based on Proved Developed Producing reserves only and current production levels, Aspen’s reserve life index is approximately 9 years.

On a Full Cost Method evaluation, net book value of reserves declined from $44,967,314 in 2002 to $39,487,383 in 2003. The decline in net book value is due to the impact of production and the Company’s inability to replace reserves in 2003 due to restricted cash flow in the first half of the year. Aspen began to re-invest capital into drilling programs in the fourth quarter of 2003, however no new reserves will be booked from these activities until 2004.

In US dollars	Cost	Accumulated Depletion and Depreciation	Net Book Value
2003 Petroleum & Natural Gas Properties	$66,760,889	($27,273,506)	$39,487,383

2002 Petroleum & Natural Gas Properties	$66,482,763	($21,515,449)	$44,967,314

Neither evaluation assigns any values for probable reserves.

Financial Results and Liquidity

The Company has incurred net losses of $2,717,662 and $17,009,828 for the period ended December 31, 2003 and 2002 respectively and has current liabilities of $19,296,497 versus current assets of $5,302,969. This includes $13,443,332 of long-term debt, which has been reclassified to current, due to the Company being in technical default on its U.S. lending facility. Aspen continues to work with its U.S. lender to bring the U.S. banking facility into full compliance and intends to reclassify $8,461,210 of the current loan back to long-term debt. The Company is in compliance with all its Canadian banking requirements.

Transactions with Related Parties

Legal expenses of approximately $87,718 and $183,000 were paid to firms of which an officer or director of the Company is a partner during the years ended December 31, 2003 and 2002, respectively.

The Corporation, through its subsidiary Aspen Endeavour Resources Inc., has conducted transactions with Evinco Exploration, Inc. a company that was related to a former officer of Aspen Endeavour Resources Inc. Evinco Exploration, Inc. f/k/a 988023 Alberta Ltd. owes $228,202 and $101,916 at December 31, 2003 and 2002, respectively, for oil & gas expenditures in the normal course of operations. As at May 31, 2004, Evinco Exploration Inc. owes Aspen Group Resources $392,00.

No other transactions with related parties occurred in 2003. Note 10 in the Notes to the Consolidated Financial Statements outlines Transactions with affiliates and related parties prior to 2003.

Equity

On February 11, 2003, the Company completed a private placement of 12 million units at Cdn $0.14 each, for gross proceeds of Cdn $1.68 million. Each unit was comprised of one common share and one half of one common share purchase warrant with each whole common share purchase warrant exercisable for one common share at a price of Cdn $0.18 until August 10, 2004. The common shares and warrant issued carried a four –month hold period under Canadian securities laws from the date of close. As of May 1, 2004, 1,470,833 of the 6 million warrants had been exercised for additional proceeds of Cdn $202,030.

On April 5, 2004, Aspen completed a private placement of 12 million special warrants at a price of Cdn $0.25 for total proceeds of Cdn $3,000,000. Each special warrant is convertible for no additional consideration into units, with each unit consisting of one share and one half-share purchase warrant. Each whole warrant is exercisable for 12 months at Cdn $0.35 to acquire one share. The shares and warrants carry a four-month hold period from the closing date. One-third of the gross proceeds from the sale of the special warrants will be deposited into escrow at closing pending shareholder approval of the financing at the Company’s annual general meeting.

Divestitures

In 2003, the Company closed the sale of the following non-core assets:

a) The Company sold its entire interest in real properties located in Kerrville, Texas for net proceeds of $325,000. There was no oil and gas production on this property.

b) With effective dates of December 1, 2003 and December 31, 2003, Aspen sold 54 low value or uneconomic wells for $685,000, which was applied completely to debt.

Legal Proceedings

The Company is a named defendant in a number of legal proceedings, which are described within the notes to the audited financial statements. Refer to Notes to the Consolidated Financial Statements - Note 13 “Commitments and Contingencies”.

Segmented Information

The Company’s operations for the twelve-month period ended December 31, 2003 were carried on in the following geographic locations:

	U.S.	Canada	Total
Total assets	$ 37,611,324	$ 8,012,254	$ 45,623,578
Gross revenue	$ 6,442,655	$ 3,277,555	$ 9,720,210
Net (loss) from operations	$ (272,437)	$ (2,540,587)	$ (2,813,024)
Net (loss)	$ (268,298)	$ (2,449,364)	$ (2,717,662)
Loss per share	$ (.00)	$ (.05)	$ (.05)

Outlook

The 2003 results reflect the impact of steps taken by Aspen’s management to return the Company to profitability. When the current team took control in October 2002, it inherited a Company overburdened with debt and unable to meet its obligations to its drilling programs. In addition, G&A and operating costs were out of control and many of the Company’s assets were under performing or economically unviable.

Aspen’s new management team quickly set about the task of evaluating all of Aspen’s assets and monetizing those which were deemed non-core or uneconomic. Concurrent with these actions, the team also took steps to reduce overhead, optimize operations, and inject new equity capital into the Company.

Although the 2003 results demonstrate significantly improved results and the success of the actions taken by management, there remain legacy issues from previous management. As noted in previous sections, Aspen remains in default with its U.S. lender. The new management has worked diligently with the lender to cure the conditions of default and expects to have the facility back in good standing. The other outstanding issue is the numerous lawsuits involving, or regarding the actions of, former management. Management intends to resolve these issues in order to focus all their resources towards Aspen’s future.

Going forward, Aspen will remain focused on natural gas as the fundamentals and forecasts for gas suggest increasing demand, long-term growth, and stability. The North American natural gas market is self-contained and according to the Energy Information Administration, natural gas demand will continue to increase 2 to 3 percent per year through 2020.

In 2004, Aspen will shift its focus from exploitation to an exploration and development strategy. The Company, through joint venture partnerships, like the one recently announced with Westchester Resources Limited, will drive its future growth through the drill bit. By acquiring and developing assets and acting as the operator, Aspen will be better able to control its destiny and create value for its shareholders.

Business Risks

Holders of the Common Stock and future investors in the Company should be aware of the following factors in evaluating their investment in Aspen.

The marketability and price of products owned or that may be acquired or discovered by Aspen will be affected by numerous factors beyond the Company’s control. Aspen must compete in all aspects of its operations with a number of other corporations that have equal or greater technical or financial resources. Aspen is also subject to market fluctuations in the prices of products, exchange rates, uncertainties related to the proximity of its reserves to pipelines and processing facilities and extensive governmental regulations.

Aspen will face different risks and uncertainties associated with oil and gas exploration and development, some of which are not always within the control of Aspen.

Operational risks include finding and developing oil and natural gas reserves on an economic basis, marketing production, hiring and retaining employees and conducting operations in a cost effective manner. Aspen mitigates these risks by concentrating in a limited number of areas with low cost exploration and development objectives, by ensuring that the Aspen employees are highly qualified and motivated to achieve success and to support long-term relationships with its service providers to ensure quality service is available through all business cycles. Insurance against well pollution, well blowouts and other forms of asset destruction will be employed as appropriate.

Financial risks include commodity prices, interest rates and the U.S./Canadian exchange rate, all of which are beyond the control of Aspen. Aspen will address these risks by employing price hedges as appropriate and minimizing interest rate risk through prudent management of cash flow, bank and equity financing.

The Company is a named defendant in a number of legal proceedings, which are described within the notes to the audited financial statements.

EXHIBITS

SECTION A – LETTER FROM AUDITORS,

FINANCIAL STATEMENTS AND NOTES TO THE FINANCIAL STATEMENTS

F-1

ASPEN GROUP RESOURCES CORPORATION

AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

AND REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

DECEMBER 31, 2003

ASPEN GROUP RESOURCES CORPORATION

AND SUBSIDIARIES

CONTENTS

Page

Report of Independent Registered Public Accounting Firm

Consolidated Financial Statements

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statement of Changes in Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

6-27

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Aspen Group Resources Corporation

We have audited the accompanying consolidated balance sheets of Aspen Group Resources Corporation and subsidiaries as of December 31, 2003 and 2002 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Aspen Group Resources Corporation and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 16 to the financial statements, the Company has suffered recurring losses from operations and current liabilities exceed current assets. This raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 16. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Dallas, Texas

May 2004

ASPEN GROUP RESOURCES CORP AND SUBSIDIARIES

F-3

CONSOLIDATED BALANCE SHEETS December 31,
(Expressed in US Dollars)
		2003		2002
ASSETS
Current Assets
Cash	$	627,291	$	50,016
Accounts receivable
Trade		3,833,812		1,432,920
Sale of assets		541,660		2,826,704
Due from affiliates		-		1,192,981
Other		40,552		27,071
Materials and supplies inventory		104,577		104,577
Prepaid expenses		41,228		123,802
Total current assets		5,189,120		5,758,071

Proved Oil & Gas Properties (full cost method)
net of accumulated depletion of $27,273,506 and $21,515,449		39,487,383		44,967,314

Property and Equipment
net of accumulated depreciation of $2,182,742 and $2,452,574		883,198		1,759,472

Other Assets
Notes receivable		40,685		42,587
Deposits and other assets		23,192		8,880

Total Assets	$	45,623,578	$	52,536,324

Liabilities and Stockholders’ Equity
Current Liabilities
Bank indebtedness	$	-	$	58,892
Accounts payable
Trade		4,910,152		3,860,856
Revenue distribution		763,664		924,652
Due to affiliates		-		1,132,943
Accrued expenses		134,287		1,099,300
Accrued interest		45,062		42,695
		5,853,165		7,119,338
Current maturities of long-term debt		13,443,332		16,197,027
Total current liabilities		19,296,497		23,316,365

*Long-Term Debt, less Current Maturities*		99,005		1,075,777

*Provision for Site Restoration*		317,846		264,522

*Deferred Income Taxes*		-		81,053

Stockholders’ Equity
Preferred stock, no par value, authorized-unlimited, issued – none		-		-
Common stock, no par value, authorized-unlimited, issued
51,378,037 in 2003 and 39,378,037 in 2002		58,895,708		57,952,574
Less subscriptions for 122,535 shares		(214,436)		(214,436)
Less 911,118 shares of treasury stock – at cost		(113,849)		-
Warrants and beneficial conversion feature		823,695		823,695
Accumulated deficit		(33,480,888)		(30,763,226) (13,753,399)
Total stockholders’ equity		25,910,230		27,798,607

Total Liabilities and Stockholders’ Equity	$	45,623,578	$	52,536,324

“signed Robert L. Calentine”

“signed Allan C. Thorne”

Robert L. Calentine, Director and CEO

Allan C. Thorne, CFO

ASPEN GROUP RESOURCES CORP AND SUBSIDIARIES

F-4

Consolidated Statements of OPERATIONS
Years ended December 31, 2003 and 2002 (Expressed in US Dollars)

		2003		2002

REVENUE
Oil and gas sales	$	8,667,363	$	6,969,309
Product and service revenues		1,052,847		865,325
Total revenues		9,720,210		7,834,634

EXPENSES
Oil and gas production		3,107,995		4,212,552
Operating expenses		674,320		908,973
General and administrative		2,252,112		4,937,057
Depreciation and depletion and site restoration		5,979,887		11,304,036
Impaired assets write-down		-		1,214,528
Total expenses		12,014,314		22,577,146

LOSS FROM OPERATIONS		(2,294,104)		(14,742,512)

OTHER INCOME (EXPENSE)
Interest and financing expense		(856,078)		(901,738)
Other income (expense)		337,158		(12,392)
Total other		(518,920)		(914,130)

LOSS BEFORE THE UNDERNOTED		(2,813,024)		(15,656,642)

PROVISION FOR WRITE DOWN OF INVESTMENT		-		(625,475)

*GAIN (LOSS) ON SALE OF ASSETS*		4,139		(920,258)

INCOME TAXES RECOVERY - CANADA		91,223		192,547

NET LOSS	$	(2,717,662)	$	(17,009,828)

BASIC NET LOSS PER SHARE	$	(.05)	$	(.45)

DILUTED NET LOSS PER SHARE	$	(.05)	$	(.45)

WEIGHTED AVERAGE SHARES		50,030,092		37,420,390

WEIGHTED AVERAGE SHARES – ASSUMING DILUTION		50,030,092		37,420,390

ASPEN GROUP RESOURCES CORP AND SUBSIDIARIES

F-4

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY Years ended December 31, 2003 and 2002 (Expressed in US Dollars)
	COMMON STOCK						WARRANTS AND BENEFICIAL CONVERSION FEATURE			ACCUMULATED DEFECIT			TOTAL
	SHARES		AMOUNT	COMMON STOCK SUBSCRIBED		TREASURY STOCK	WARRANTS AND BENEFICIAL CONVERSION FEATURE			ACCUMULATED DEFECIT			TOTAL

BALANCES, December 31, 2001	20,204,157	$	46,943,541	$ (214,436)	$	-	$		1,305,236	$	(13,753,399)	$	34,280,942

Shares issued on Endeavour take-over (January – October)	11,944,809		6,689,093	-		-			-		-		6,689,093
Conversion of shares in January for debt	2,857,143		3,000,000	-		-			-		-		3,000,000
Issuance of shares in February for interest on conversion of debt	1,000,000		90,000	-		-			-		-		90,000
Shares issued in February for services ($0.76 per share)	47,428		36,000	-		-			-		-		36,000
Conversion of Special Warrants in April	544,500		481,540	-		-			(481,541)		1		-
Shares issued in May for acquisition	2,825,000		741,800	-		-			-		-		741,800
Shares issued in July for services ($0.56 per share)	25,000		14,000	-		-			-		-		14,000
Retirement of shares ($0.62 per share)	(70,000)		(43,400)	-		-			-		-		(43,400)
Net loss	-		-	-		-			-		(17,009,828)		(17,009,828)

BALANCES, December 31, 2002	39,378,037		57,952,574	(214,436)		-			823,695		(30,763,226)		27,798,607

Issuance of shares in private offering which closed in February 2003	12,000,000		943,134	-		-		-			-		943,134
Acquisition of treasury stock						(113,849)							(113,849)
Net loss	-		-	-		-		-			(2,717,662)		(2,717,662)

BALANCES, December 31, 2003	51,378,037	$	58,895,708	$ (214,436)	$	(113,849)	$	823,695		$	(33,480,888)	$	25,910,230

ASPEN GROUP RESOURCES CORP AND SUBSIDIARIES

F-5

CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2003 and 2002
(Expressed in US Dollars)

		2003		2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(2,717,662)	$	(17,009,828)
Adjustments to reconcile net loss to net cash
provided (used) by operating activities:
Deferred income taxes recovery		(81,053)		(192,547)
Loss (gain) on sale of fixed assets		5,926,563		920,258
Depreciation and depletion		53,324		10,999,556
Amortization		-		-
Common stock issued for services		-		6,600
Provision for write-down of investments and other assets		-		1,016,142
Cash flow from operations		3,181,172		(4,259,819)
Change in assets and liabilities, net
Accounts receivable		1,063,651		1,108,852
Prepaid expenses		82,574		444,921
Accounts payable and accrued liabilities		(3,960,976)		1,680,793
Materials and supplies inventory		-		-
Other		(12,410)		-
Net cash provided (used) by operating activities		354,011		(1,025,253)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of other assets		655,117		-
Proceeds from sale of oil and gas properties		1,033,323		3,181,061
Proceeds from sale of fixed assets		58,922		84,213
Marketable securities		(113,849)		-
Exploration and development costs capitalized		(1,311,449)		(1,953,541)
Acquisition of property and equipment		(6,270)		(389,395)
Net cash provided by investing activities		315,794		922,338

CASH FLOWS FROM FINANCING ACTIVITIES
Cash acquired in acquisition		-		(8,540)
Bank overdraft		(58,892)		58,892
Sale of common stock and exercise of warrants		943,134		-
Issuance of notes payable and long-term debt		-		2,218,170
Issuance of related party note payable		-		-
Repayment of notes payable and long-term debt		(976,772)		(2,166,191)
Net cash provided by (used in) financing activities		(92,530)		102,331

NET INCREASE (DECREASE) IN CASH		577,275		(584)

CASH - Beginning of period		50,016		50,600

*CASH - End of period*	$	627,291	$	50,016

SUPPLEMENTAL INFORMATION
Cash paid for interest		853,711		904,784
Conversion of special warrants to common stock		-		481,541
Conversion of accounts payable to common stock		-		3,090,000
Issuance of common stock for acquisition consulting fees		-		36,000
Equipment and other assets acquired with common stock Extinguishment of convertible debentures		-		741,800
Non-cash collections on notes receivable		-		125,000
Cash income taxes paid		-		-
Issuance of common shares for Endeavour take-over		-		6,689,093

ASPEN GROUP RESOURCES CORP AND SUBSIDIARIES

F-6

Nature Of Business And Basis Of Preparation And Presentation

Nature of Business

The primary business focus of Aspen Group Resources Corporation (the “Company” or “Aspen”) is to build value through the development of its existing producing oil and gas properties by conducting an active exploitation program on these properties and pursuing the acquisition, development, and exploitation of oil and gas properties in both the United States and Canada that offer the potential for increased production while continuing to control costs.

The Company was incorporated under the laws of Ontario, Canada as Cotton Valley Energy Limited on February 15, 1995. On June 14, 1996, the Company merged with Arjon Enterprises, Inc., an Ontario corporation and reporting issuer in Ontario. As a result of that merger the Company’s name was changed to Cotton Valley Resources Corporation. The Company continued from Ontario to the Yukon Territory pursuant to Articles of Continuance dated February 9, 1998. On February 28, 2000 the Company’s name was changed to Aspen Group Resources Corporation.

Summary Of Significant Accounting Policies

Oil and Gas Properties

The Company follows the full-cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including directly related overhead costs, are capitalized into a “full-cost pool”. A separate full cost pool is established for U.S. and non-U.S. properties.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization base until the related properties are evaluated. Such unproved properties are assessed periodically and a provision for impairment is made to the full-cost amortization base when appropriate.

Sales of oil and gas properties are credited to the full-cost pool unless the sale would have a significant effect on the amortization rate. Abandonments of properties are accounted for as adjustments to capitalized costs with no loss recognized. Oil and gas drilling and workover equipment used primarily on the Company’s properties are included in the full cost pool.

The net capitalized costs are subject to a “ceiling test” which limits such costs to the aggregate of the estimated present value of future net revenues from proved reserves discounted at ten percent based on current economic and operating conditions.

The recoverability of amounts capitalized for oil and gas properties is dependent upon the identification of economically recoverable reserves, together with obtaining the necessary financing to exploit such reserves and the achievement of profitable operations.

Canadian Resource expenditure deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation.

Revenue Recognition

Revenue is accrued and recognized in the month the oil and gas is produced and sold. Reimbursement of costs from well operations is netted against the related oil and gas production expenses.

Inventories

Inventories, which consist primarily of oilfield equipment, acidizing and cementing products, and supplies held for resale, are stated at the lower of cost or market using the first-in, first-out (FIFO) method.

Debenture Financing Costs

Debenture financing costs are being amortized ratably over the life of the related debenture.

Property and Equipment

Property and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets.

Investments

Non-marketable securities are accounted for using the cost method of accounting and assessed for other-than-temporary impairments. If non-marketable securities have an other-than-temporary impairment, the cost of the security is written down to a new cost basis by a charge to operations. See Note 7.

Basis of Presentation

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States. The differences between accounting principles generally accepted in the United States and Canada would not have a material impact on the accompanying financial statements. The Company’s assets and principal activities are in the United States and its functional currency is the U.S. dollar; accordingly, the accompanying financial statements are presented in U.S. dollars. The effects of exchange rate changes on transactions denominated in Canadian dollars or other currencies are charged to operations. Foreign exchange gains or losses were insignificant for all periods presented.

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due, if any, plus net deferred taxes related primarily to differences between the bases of assets and liabilities for financial and income tax reporting. Deferred tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Deferred tax assets include recognition of operating losses that are available to offset future taxable income and tax credits that are available to offset future income taxes. Valuation allowances are recognized to limit recognition of deferred tax assets where appropriate. Such allowances may be reversed when circumstances provide evidence that the deferred tax assets will more likely than not be realized.

Net Earnings Per Share

Per share information is based on the weighted average number of common stock and common stock equivalent shares outstanding. As required by the Securities and Exchange Commission rules, all warrants, options, and shares issued within a year prior to the initial filing of a registration statement are assumed to be outstanding for each year presented for purposes of the earnings per share calculation.

Cash Flow Statement

For purposes of the statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Advertising Costs

The Company’s policy is to expense all advertising costs in the period in which they are incurred. Advertising and promotion expense was $2,933 and $36,248 for the 2003 and 2002, respectively.

Stock-Based Compensation

Statement of Financial Accounting Standards No. 123 - Accounting for Stock-Based Compensation (SFAS 123), requires recognition of compensation expense for grants of stock, stock options, and other equity instruments based on fair value. If the grants are to employees, companies may elect to disclose only the pro forma effect of such grants on net income and earnings per share in the notes to financial statements and continue to account for the grants pursuant to APB Opinion No. 25, Accounting for Stock Issued to Employees. The Company has elected the pro forma disclosure alternative for employee grants.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with generally accepted accounting principles requires the Company to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates. Significant assumptions are required in the valuation of proved oil and gas reserves, which as described above may affect the amount at which oil and gas properties are recorded. It is at least reasonably possible those estimates could be revised in the near term and those revisions could be material.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its majority-owned subsidiaries. All material intercompany accounts and transactions of consolidated subsidiaries have been eliminated in consolidation.

Joint Operations

Certain of the petroleum and natural gas activities are conducted jointly with others. These consolidated financial statements reflect only the Company's proportionate interest in such activities.

Cash and Cash equivalents

Cash and cash equivalents include cash on hand, balances with banks and short-term deposits with original maturities of three months or less. Bank borrowings are considered to be financing activities.

Financial Instruments

The Company has estimated the fair value of its financial instruments which include cash and cash equivalents, accounts receivable, advances to operators, due to and from related companies, contracts receivable and payable, investment, accounts payable, accrued liabilities, notes payable and long-term debt. The Company used valuation methodologies and market information available as at year-ends and unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from their financial instruments. It has been determined that the carrying amounts of such financial instruments approximate fair value in all cases, unless otherwise noted.

Future Site Restoration and Abandonment Costs - Canada

Estimated future costs relating to site restoration and abandonments are provided for over the life of proved reserves on a unit-of-production basis. Costs are estimated, net of expected recoveries, based upon current legislation, costs, technology and industry standards. The annual provision is recorded as additional depletion and depreciation. The accumulated provision is reflected as a non-current liability and actual expenditures are charged against the accumulated provision when incurred.

Recent Accounting Pronouncements

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 covers all legally enforceable obligations associated with the retirement of tangible long-lived assets and provides the accounting and reporting requirements for such obligations. SFAS No. 143 guidance covers (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS No. 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company adopted the statement as of January 1, 2003, and did not experience any material impact on the Company’s financial position or results of operations.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies financial accounting and reporting of derivatives, including derivative instruments embedded in other contracts, which are collectively referred to as derivatives, and for hedging activities under SFAS 133, Accounting for Derivative Instruments and Hedging Activities. SFAS 149 was effective for contracts entered into or modified after June 30, 2003. The adoption of SFAS 149 did not have a material impact on the Company’s financial position or results of operations.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which addresses how an issuer classifies and measures financial instruments with characteristics of both liabilities and equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 did not have a material impact on the Company’s financial position or results of operations.

Long-Lived Assets

Long-lived assets, other than oil and gas properties, are periodically reviewed for impairment based on an assessment of future operations. The Company records impairment losses on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Measurement of an impairment loss is based on the fair market value of the asset. Impairment for oil and gas properties is computed in the manner described above under “Oil and Gas Properties.”

Acquisitions

United Cementing & Acid Co., Inc.

Effective January 1, 2001, the Company entered into a share purchase agreement to acquire 100% of United Cementing & Acid Co., Inc. (United), a privately held oilfield service company. For financial statement purposes the acquisition was accounted for as a purchase. The aggregate purchase price was $1,250,000. On April 13, 2001, the Company entered into a share purchase agreement to sell 25% of United to a director of the Company. The aggregate sale price was $312,500. On January 1, 2002, the Company repurchased those 875 shares of United from that director of the Company for $312,500; making United a wholly owned subsidiary of the Company. For financial statement purposes, the acquisition was accounted for as a purchase and, accordingly United’s results are included in the consolidated financial statements since the date of acquisition. The net purchase price exceeded the net assets of United by approximately $691,000. The excess was allocated to property and equipment and is being depreciated.

Acquisition of Aspen Endeavour Resources Inc. (formerly Endeavour Resources Inc.)

On March 6, 2002 the Company completed the acquisition of 100% of Endeavour Resources Inc. ("Endeavour") in exchange for 11,944,809 common shares of the Company together with share purchase warrants to purchase an additional 5,972,403 common shares of the Company. Each whole share purchase warrant entitled the holder to purchase one common share of the Company at a price of $1.25 until September 30, 2002, or $1.75 thereafter until June 30, 2003. No share purchase warrants have been exercised at December 31, 2003. In addition, the Company acquired common share purchase warrants of Endeavour entitling the holder to acquire approximately 3,750,000 additional shares of Endeavour common stock. In exchange for these warrants, the Company issued 890,625 Class B common share purchase warrants (Class B Warrants), each whole Class B Warrant entitling the holder to purchase one share of the common stock of the Company at a price of $1.33 per share. No Class B Warrants were exercised and they expired on June 28, 2002.

On June 7, 2002, Endeavour received a Certificate of Amendment changing its name to Aspen Endeavour Resources Inc.

Acquisition of Lamb Creek Inn and 43 Producing wells

On April 1, 2002, The Company purchased the Lamb Creek Inn in Kerrville Texas from a past director of the Company along with a 50% interest in 43 oil wells in Oklahoma from a past officer and director of the Company. The Company issued 2,825,000 common shares from treasury and paid $750,000 in notes and cash.

Property and Equipment

Property and equipment consist of the following at December 31,

		2003		2002	Estimated Useful Lives

Office furniture and equipment	$	391,341	$	389,647	5 – 10 years
Equipment		361,573		378,006	5 – 10 years
Vehicles		1,406,595		1,531,044	5 years
Buildings and improvements		561,042		1,574,730	25 years
Land		239,548		239,548
Office furniture & fixtures (Canada)		105,841		99,071	20-30% declining
	$	3,065,940	$	4,212,046

Depreciation charged to expense amounted to $168,505 and $312,819 for 2003 and 2002, respectively.

Oil and Gas Properties


		Cost		Accumulated Depletion and Depreciation		2003 Net Book Value

*United States*
Petroleum and natural gas properties and equipment – Canadian subsidiary	$	947,673	$	(560,007)	$	387,666
Petroleum and natural gas properties and equipment – US operations		49,813,640		(15,758,999)		34,054,641

*Canada*
Petroleum and natural gas properties and equipment		15,999,576		(10,954,500)		5,045,076
	$	66,760,889	$	(27,273,506)	$	39,487,383


		Cost		Accumulated Depletion and Depreciation		2002 Net Book Value

*United States*
Petroleum and natural gas properties and equipment – Canadian subsidiary	$	915,961	$	(397,055)	$	518,906
Petroleum and natural gas properties and equipment – US operations		50,721,128		(13,750,838)		36,970,290

*Canada*
Petroleum and natural gas properties and Equipment		14,845,674		(7,367,556)		7,483,118
	$	66,482,763	$	(21,515,449)	$	44,967,314

Site restoration and abandonments - Canada

At December 31, 2003 and 2002 the costs, net of expected recoveries, relating to future site restoration and abandonments are estimated to be $437,934__ and $437,394 of which $317,846__ and $264,522 has been provided for in the consolidated financial statements.

Depletion and depreciation

At December 31, 2003 there were no costs (2002 $650,995) for unproven properties which have been excluded from the depletion calculation. The Company converted its gas to bbls using 6:1 conversion rate.

Ceiling test

The ceiling test for the year ended December 31, 2003 was completed resulting in a writedown of $1,574,980 for Canadian properties and $0 for U.S. properties in 2003 and $665,350 for Canadian properties and $6,331,832 for U.S. properties in 2002.

Notes Receivable

Notes receivable consist of the following at December 31,

		2003		2002

Note receivable	$	67,768	$	65,895
Less current maturities		(27,083)		(23,038)
	$	40,685	$	42,857

Notes Payable and Long-Term Debt

On April 28, 2000, the Company entered into a credit agreement with a bank under which it may borrow up to $25,000,000 limited to the borrowing base as determined by the lender. At December 31, 2003 and 2002, there were $10,321,210 and $14,844,002, respectively of outstanding borrowings under this agreement. Interest on outstanding borrowings currently accrues at the bank’s base rate of interest plus one percent (base rate is 4.0% and 5.0% at December 31, 2003 and December 31, 2002 respectively). The agreement also provides for a commitment fee of one-half percent per annum on the average unused portion of the commitment. A facility fee of one-half percent is assessed for increases in the commitment amount.

The facility is collateralized by the Company’s oil and gas properties. Under the terms of the credit agreement, the Company is required to maintain certain financial ratios and other financial conditions. On October 4, 2002, Aspen Energy Group Inc. was notified that it was in default of the credit agreement. At December 31, 2003, the Company is in default of the credit agreement, but is current on payment requirements. Management is currently in negotiations with the bank to remedy these defaults.

Interest is payable monthly and the credit agreement requires monthly commitment reductions as determined by lender. The monthly commitment reduction amount as of December 31, 2003 was $155,000. The credit agreement matures on July 10, 2004.

The Company has a note payable to a bank, dated June 26, 2001, in the original amount of $300,000; payable in monthly installments of $3,650, including interest at 7.50%, with all unpaid interest and principal due on June 26, 2004. The note payable is secured by real estate. At December 31, 2003 and 2002 the outstanding balance was $248,840 and $275,324, respectively.

The Company has a note payable to a bank, dated March 13, 2002, in the original amount of $272,419; payable in monthly installments of $6,654, including interest at the base rate plus one-half percent, with all unpaid interest and principal due on June 26, 2005. The note payable is secured by substantially all of United’s assets. At December 31, 2003 and 2002 the outstanding balance was $154,739 and $232,860, respectively.

On April 1, 2002, in connection with the purchase of certain assets from a past director of the Company, the Company assumed a note payable with an outstanding balance of $298,558 at the date of acquisition. The note was paid in full upon the sale of the assets during 2003. At December 31, 2003 and December 31, 2002 the outstanding balance was $0 and $252,548.

In 2001, in connection with the acquisition of certain oil and gas properties, the Company, on February 28, 2000, issued a $3,000,000 convertible 9% note payable. All unpaid principal and interest is due on or before December 31, 2002; provided that at any time the Company proposes to pay this note payable, the Company has the right, at their sole option, to pay all or any portion of the amount outstanding by the issuance to the payees of 2,857,143 shares of common stock of the Company. During 2002, this note and related unpaid accrued interest was exchanged for 3,857,143 shares of common stock.

The Company has a note payable to a merchant banking organization dated December 30, 2003, in the original amount of $1,083,320; interest at 24% is payable monthly, with all unpaid interest and principal due on December 30, 2004. The note payable is secured by substantially all assets of Aspen Endeavour Resources, Inc. At December 31, 2003 the outstanding balance was $1,083,320.

Aspen Endeavour Resources, Inc. Notes Payable and Long-Term Debt:

		2003		2002
*CANADIAN WESTERN BANK*
Demand non-revolving $2,012,000 production loan, repayable in equal monthly installments of $96,725 commencing June 1, 2002 bearing interest at bank prime plus 0.75% which is secured by petroleum and natural gas properties	$	174,105	$	1,092,098
Demand revolving $1,780,000 production loan, repayable in equal monthly installments of $96,725 commencing January 1, 2004 bearing interest at bank prime plus 0.75% which is secured by petroleum and natural gas properties		1,470,220		443,170
		1,644,325		1,535,268

*OTHER NOTES PAYABLE AND LONG-TERM DEBT*
$205,000 loan, repayable in equal quarterly installments of $17,088 commencing March 31, 2002 bearing interest at 0% which is secured by petroleum and natural gas properties		68,352		111,848

Other		21,551		20,954

		1,734,228		1,668,070

Less - current portion		1,721,189		1,012,538
		13,039		655,532
Demand, revolving reducing loan in the principle amount of $1 million, bearing interest at bank prime plus 0.75%		-		-

	$	13,039	$	655,532

Notes Payable and Long-Term Debt – U.S. Operations:

		2003		2002
*Aspen Energy Group Inc. Bank Loan*
Demand non-revolving production loan	$	10,321,210	$	14,844,002

*United Cementing and Acid Co., Inc.*
Equipment installment loans		403,579		508,184

*Aspen Group Resources Corporation*
Demand non-revolving production loan		1,083,320		-

Equipment and real estate installment loan		-		252,548

		11,808,109		15,604,734

Less – current portion		11,722,143		15,184,489

	$	85,966	$	420,245

Five-year maturity schedule:

Long-term debt is due as follows: 2004 - $13,443,332; 2005- $77,285; and 2006 - $21,720.

Investments

		2003		2002
*Cubacan Exploration Inc*

Common shares	$	1,016,560	$	1,016,560
Acquisition of shares		68,881		68,881
		1,085,441		1,085,441

Less provision for write down		(1,085,440)		(1,085,440)
	$	1	$	1

In the year 2002, Endeavour received 180,000 common shares of Cubacan at $0.38 per share as a settlement of debt of $68,881. At December 31, 2003 and 2002, the Company owned 26,365,982 common shares of Cubacan or 32.5% of the outstanding shares. On June 6, 2003, Cubacan was suspended from trading on the TSX Venture Exchange.

Income Taxes

Canadian Income Taxes

		2003		2002

Loss before income taxes	$	2,540,587	$	1,755,672

Expected tax expense (recovery) at combined federal and provincial rate of 41.12% for 2003 and 41.62% for 2002		(1,044,689)		(730,722)
Increase (decrease) resulting from;
Non deductible crown charges		91,650		54,720
Provincial royalty deduction		(134,752)		(21,561)
Resource allowance		39,112		(32,451)
Statutory rate reduction		14,294		(17,557)
Non-deductible DD&A		1,546,794		490,169
Other		97,589		64,855
Unrecognized future income tax recoveries		(518,775)		-

Provision for deferred income taxes	$	(91,223)	$	(192,547)

The temporary differences of the deferred income tax liability are as follows:


Deferred income tax assets
Non-capital loss carry forwards	$	(178,665)	$	(94,376)
Future site restoration		(149,239)		(106,459)
Share issue costs		(8,021)		(12,692)
Investments		(1,206,162)		(1,022,844)
Other		(171,970)		(53,598)
		(1,714,057)		(1,289,969)
Deferred income tax liabilities
Property and equipment		1,153,325		1,371,022
		560,732		81,053
Deferred income tax valuation allowance		(560,732)		-

	$	-	$	81,053

The Canadian subsidiary has $434,496 of available loss carry forwards for income tax purposes which may be used to reduce future taxable income, the benefit of which has been recognized in these consolidated financial statements. These losses expire in 2009.

The Canadian subsidiary has available the following approximate costs which may be deducted in the prescribed manner to determine future taxable income:

	Rate		2003		2002

Undepreciated capital costs	20%-30%	$	862,563	$	784,311
Canadian oil and gas property expense	10%	$	222,613	$	193,629
Canadian development expense	30%	$	1,194,886	$	1,521,233
Canadian exploration expense	100%	$	1,029,099	$	800,500
Foreign exploration and development expense	10%	$	540,542	$	867,068

United States Income Taxes

Aspen’s deferred tax assets (liabilities) consist of the following:

		2003		2002
Deferred tax liabilities:
Accumulated depreciation	$	(67,000)	$	(67,000)
Costs capitalized for books and deducted for tax		-		-
Total deferred tax liabilities		(67,000)		(67,000)

Deferred tax assets:
Net operating loss carryforwards		9,889,000		10,255,000
Costs expensed for books and capitalized for tax		1,639,000		1,185,000
Total deferred tax assets		11,528,000		11,440,000
Less valuation allowance		(11,458,000)		(11,373,000)
Net deferred tax liability	$	-	$	-

The difference from the expected income tax expense for the periods ended December 31, 2003 and 2002 at the statutory federal tax rate of 34% and the actual income tax expense is primarily the result of net operating loss carryforwards.

At December 31, 2003, the Company has available net operating loss carryforwards of approximately $29,051,000 to reduce future taxable income. These carryforwards expire from 2003 to 2023.

Stockholders’ Equity

On February 11, 2003, the Company completed a private placement of 12,000,000 Units at $.14 each (Canadian) for gross proceeds of $1,680,000 (Canadian). Each Unit is comprised of one common share and one-half of one common share purchase warrant with each whole common share purchase warrant exercisable for one common share at a price of $.18 (Canadian) until August 10, 2004. The common shares and warrants issued carry a four-month hold period under Canadian securities laws from the date of close.

During the year ended December 31, 2002, the Company completed the acquisition of 100% of Endeavour Resources Inc. (Endeavour), in exchange for 11,944,809 common shares of the Company together with share purchase warrants to purchase an additional 5,972,403 common shares of the Company. Each whole share purchase warrant entitled the holder to purchase one share of common stock of the Company at a price of $1.75 until June 30, 2003.

During the year ended December 31, 2002, warrants to acquire 272,250 shares for $1.80 per share through April 4, 2003 were granted in connection with the exercise of 495,000 special warrants.

At December 31, 2003, exercise prices of options and warrants range from $.12 to $1.00.

The following tables summarize the option and warrant activity for the periods ended December 31, 2003 and 2002:

	December 31, 2003		December 31, 2002
	Number Of Shares	Weighted Average Exercise Price	Number Of Shares	Weighted Average Exercise Price

Outstanding, beginning of period	8,818,371	$1.68	3,063,418	$2.12
Granted to:
Employees, officers, directors	2,000,000	.12	-	-
Others	4,000,000	.12	6,115,551	1.75
Expired/canceled	(8,032,659)	1.70	(860,598)	3.80
Exercised	-	-	-	-
Outstanding, end of period	6,285,712	$.16	8,318,371	$1.68

All outstanding warrants and options were exercisable at December 31, 2003. If not previously exercised, warrants and options outstanding at December 31, 2003 will expire as follows:

Year Ending December 31,	Number of Shares	Weighted Average Exercise Price

2004	6,271,428	$ .16
2005	10,713	.98
2006	3,571	.98
Total	6,285,712

Presented below is a comparison of the weighted average exercise prices and market price of the Company’s common stock on the measurement date for all warrants and stock options granted during the years ending December 31, 2003 and 2002:

December 31, 2003

December 31, 2002

Number

Shares

Exercise

Price

Market

Price

Number

Shares

Exercise

Price

Market

Price

Fair value equal to exercise price

$ -

Fair value greater than exercise price

$ -

Exercise price greater than fair value

6,000,000

$ .12

$ 0.11

6,115,551

$ 1.75

$ .56

Pro Forma Stock-Based Compensation Disclosures

The Company applies APB Opinion 25 and related interpretations in accounting for its stock options and warrants which are granted to employees. Accordingly, compensation cost has not been recognized for grants of options and warrants to employees and directors unless the exercise prices were less than the fair value of the Company’s common stock on the grant dates. Had compensation cost been determined based on the fair value at the grant dates for awards under those plans consistent with the method of FASB 123, the Company’s net earnings (loss) and earnings (loss) per share would have been changed to the pro forma amounts indicated below. The fair values generated by the Black-Scholes model may not be indicative of the future benefit, if any, that may be received by the option or warrant holder.

		2003		2002
Net loss applicable to common stockholders:
As reported	$	(2,717,662)	$	(17,009,828)
Pro forma		(2,717,662)		(17,009,828)
Basic earnings loss per common share:
As reported	$	(.05)	$	(0.45)
Pro forma		(.05)		(0.45)

The fair value of each option granted was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:

	2003	2001

Expected volatility	- %	- %
Risk-free interest rate	- %	- %
Expected dividends	-	-
Expected terms (in years)	-	-

Stock Based Compensation

The Company has two stock-based compensation plans. At December 31, 2003, 1,857,143 shares were reserved for issuance under these plans. Under the Non-Employee Directors Stock Option Plan, options are granted to certain non-employee directors at prices greater than or equal to the market price of the Company’s stock on the date of grant. The maximum term of the option is 10 years, and they vest according to the terms of the individual options granted. All options must be granted prior to February 26, 2011, the date the Plan will terminate. Options may be granted at any time prior to its termination. Any option outstanding under the plan at the time of its termination, remains in effect until the option is exercised or expires. Under the 2001 Stock Compensation Plan, options and stock appreciation rights are granted to certain officers, directors, employees and advisors at prices greater than or equal to the market price of the Company’s stock on the date of grant. The maximum term of the option is 10 years, and they vest according to the terms of the individual options granted. All options must be granted prior to February 26, 2011, the date the Plan will terminate. Options may be granted at any time prior to its termination. Any option outstanding under the plan at the time of its termination, remains in effect until the option is exercised or expires. Stock appreciation rights may be issued with stock options or separately, at the discretion of the Compensation Committee. At December 31, 2003, no stock appreciation rights had been granted.

10.

Transactions with affiliates

Legal expenses of approximately $88,000 and $183,000 were paid to firms of which an officer or director of the Company is a partner during the years ended December 31, 2003 and 2002, respectively.

In 2002, Endeavour contracted services from Prospect Oil & Gas Management Ltd., a company related by common management and controlled by a past director and officer of Endeavour for general and administrative, land, development and exploration services. The total amount charged for certain services during the year ended December 31, 2002 totaled $122,447. This contract expired on April 15, 2002.

ENDEAVOUR IS A SHAREHOLDER OF CUBACAN EXPLORATION INC. (“CUBACAN”) AND AT DECEMBER 31, 2003 AND 2002 OWNED 26,365,982 COMMON SHARES OR 32.5% OF THE OUTSTANDING CAPITAL. DURING 2002, THE INVESTMENT IN THESE SHARES WAS WRITTEN DOWN TO $1.00.

AT DECEMBER 31, 2003 AND 2002, CUBACAN OWED ENDEAVOUR $0 AND $102,048, RESPECTIVELY AS A RESULT OF CASH ADVANCES AND REIMBURSABLE COSTS WHICH BEAR NO INTEREST AND HAVE NO SET TERMS OF REPAYMENT. THESE TRANSACTIONS ARE IN THE NORMAL COURSE OF OPERATIONS AND ARE MEASURED AT THE EXCHANGE AMOUNT WHICH IS THE AMOUNT OF CONSIDERATION ESTABLISHED AND AGREED TO BY THE RELATED PARTIES.

In 2002 Endeavour contracted Riechad, Inc. and APT, Inc., companies controlled by a past director and officer of Endeavour, for engineering and management services. The total contract fees charged and accrued during the year ended December 31, 2002 totaled $110,792. These transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

11.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. The Company maintains its cash with banks primarily in Oklahoma City, Oklahoma and Calgary, Alberta. The terms of these deposits are on demand to minimize risk. The Company has not experienced any losses related to these cash deposits and believes it is not exposed to any significant credit risk.

Accounts receivable consist of uncollateralized receivables from domestic and international customers primarily in the oil and gas industry. To minimize risk associated with international transactions, all sales are denominated in U.S. currency. The Company routinely assesses the financial strength of it customers. The Company considers accounts receivable to be fully collectible; accordingly, no allowance for doubtful accounts is required. If amounts become uncollectible, they will be charged to operations when that determination is made.

12.

Employee Benefit Plan

The Company has established a salary deferral plan under Section 401(k) of the Internal Revenue Code. The plan allows eligible employees to defer a portion of their compensation. Such deferrals accumulate on a tax-deferred basis until the employee withdraws the funds. The plan provides for contributions by the Company in such amounts as the Board of Directors may determine annually. The Company contributed $0 and $40,500 for the years ended December 31, 2003 and 2002, respectively.

13.

Commitments and contingencies

Letters of Credit

At December 31, 2003 and 2002, the Company had $125,000 and $151,000 of outstanding letters of credit, respectively.

Leases

Future minimum lease payments in the aggregate required by noncancellable operating leases with initial or remaining terms in excess of one year are as follows:

Year Ending December 31,	Total
2004	$ 237,218
2005	97,909
2006	-
	$ 335,127

Environmental Matters

The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operation thereof. Although environmental assessments are conducted on all purchased properties, in the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon the Company. No claim has been made, nor is the Company aware of any liability, which it may have, as it relates to any environmental clean up, restoration or the violation of any rules or regulations relating thereto. Liabilities for expenditures are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

LITIGATION

THE COMPANY AND ITS SUBSIDIARIES, IN THE NORMAL COURSE OF OPERATIONS, ARE SOMETIMES NAMED AS DEFENDANTS IN LITIGATION. THE NATURE OF THESE CLAIMS IS RELATED TO DISPUTES ARISING FROM SERVICES PROVIDED BY OUTSIDE CONTRACTORS OR FOR DELINQUENT PAYMENTS. THE COMPANY DOES NOT EXPECT THAT THE RESULTS OF ANY OF THESE PROCEEDINGS WILL HAVE A MATERIAL ADVERSE EFFECT ON THE COMPANY’S FINANCIAL POSITION

Bruce J. Scambler and JMEKS, Inc. vs. Jack E. Wheeler, Crown Partners, LLC Minerals Division, Aspen Group Resources Corporation, Inc., and Cotton Valley Resources Corporation; Case No. CJ-2000-6912-62; D.C. Oklahoma County; Petition filed 9/20/00.

The Company was named as a defendant in an action filed in September 2000 whereby a former officer of the Company alleged a breach of a Settlement and Release Agreement. The Company was unsuccessful in defending this action and a judgment in the amount of $385,000 plus estimated interest and legal fees of $50,000 was granted against the Company and the former CEO. The Company is jointly and severally liable along with the CEO for this amount. Of this amount, the Company has made a provision for the total, which has been recorded as a liability at December 31, 2002 and charged to operations in 2002. Judgment was paid in full during 2003.

Duke Energy Trading and Marketing, LLC vs. Aspen Group Resources Corporation; Case No. 2002-02095; D.C. Harris County, Texas; Petition filed on 1/18/02.

The Company was named as a defendant in an action January 2002 whereby the Company allegedly executed a written Guaranty in October 2000, on behalf of a corporation that the Company was in the midst of merger negotiations, to a third party guaranteeing a potential liability up to $2,300,000. The Company claims that since the merger negotiations never came to fruition, that the Guaranty was cancelled and there is no liability to the Company. Outside council for the Company has advised at this stage of proceedings, they cannot offer an opinion as to the probable outcome. The Company’s management is vigorously defending the case.

615436 Alberta Ltd. vs. Aspen Endeavour Resources Inc.; Action No. 0201-17345; Court of Queen's Bench of Alberta, Judicial District of Calgary; Petition filed on 10/12/02.

A wholly owned subsidiary of the Company was named as a defendant in an action commenced October 2002 whereby a company controlled by a past director and officer of the subsidiary claims that it is owed for a promissory note signed by the Canadian subsidiary of the Company in October 1994 in the amount of Cdn $250,000 plus interest. The Company is defending this action as it believes it is not a liability of the Company and therefore, no liability has been accrued in these financial statements.

Jeffrey Chad and Riechad Incorporated vs. Aspen Endeavour Resources Inc.; Action No. 0201-17493; Court of Queen's Bench of Alberta, Judicial District of Calgary; Petition filed on 10/16/02.

A wholly owned subsidiary of the Company was named as a defendant in an action commenced October 2002, whereby a past director and officer of the subsidiary claims it is owed the sum of $440,000 (Canadian) pursuant to a suspension and redefinition of his consulting agreement. Jeffrey Chad and Riechad Incorporated received a judgment in their favor for $306,000 (Canadian) in December 2003. Judgment was paid in full in January 2004. This liability is accrued in these financial statements.

Jack Wheeler vs. Aspen Group Resources Corporation; Case No. CIV-03-0180W, filed in the United States District Court for the Western District of Oklahoma.

The past CEO alleges that the Company breached his employment contract by not paying sums due under the contract. Management intends to vigorously defend the case and has filed a counterclaim. See (f) below.

Aspen Group Resources Corporation and Aspen Energy Group, Inc. vs. Jack Wheeler and Wheeler & Sons Oil & Gas, LLC, Canadian County, Oklahoma Case No. CJ-2003-281. Petition filed on 05/15/03.

The Company alleges that the previous CEO committed fraud, embezzlement, breach of fiduciary duty, usurping of corporate opportunities and similar claims relating to his position as an officer and director of the Company. Management intends to vigorously pursue the claim and to defend the counterclaim.

Aspen Group Resources Corporation and Aspen Energy Group, Inc. vs. Lenard Briscoe and LCB Resources, Inc., Canadian County Oklahoma, Case no. CJ-2003-307. Petition filed on 05/27/03.

The Company has sued a past director and his private corporation, LCB Resources, Inc., alleging wide ranging fraud, breach of fiduciary duty, usurping corporate opportunities and misappropriation of corporate assets in connection with his service as an officer and director of the Company. See (h) below. Management intends to pursue the case vigorously.

LCB Resources and Lenard Briscoe vs. Aspen Energy Group, Inc., Kingfisher County, Oklahoma, Case No. CJ-2003-96. Petition filed on 05/27/03

The past director has counter sued alleging the Company’s subsidiary has failed to pay royalties owed on certain oil and gas properties, has mismanaged those properties and has sold oil wells in which the past director has an interest, but has not paid him. Management intends to vigorously defend the case. No liability has been accrued in these financial statements for this amount.

R. Charles Allen vs. Aspen Group Resources Corporation, Jack E. Wheeler, James E. Hogue, Wayne T. Egan, Anne Holland, Randall B. Kahn, Lenard Briscoe, Peter Lucas, Lane Gorman Trubitt L.L.P. and WierFoulds L.L.P.; Action #02-CV241587CP

The Company was named as a defendant, on a joint and several basis, along with the then directors, auditors and legal counsel of the Company in an Action dated December 30, 2002, whereby the plaintiff is seeking an order rescinding the take-over bid dated November 22, 2001 by the Company for the purchase of securities of Endeavour Resources Inc. along with damages in the amount of Cdn $10,000,000. The Company is defending this action as it believes it is not a liability of the Company, the outcome of which is undeterminable. Outside council for the Company has advised at this stage of proceedings, they cannot offer an opinion as to the probable outcome. The Company’s management is vigorously defending the case.

Riechad Incorporated vs. Aspen Endeavour Resources Inc.: Action No. 0201 – 17515; Court of Queens Bench of Alberta, Judicial District of Calgary; Counterclaim filed 07/07/03.

Aspen Endeavour Resources Inc. was named as a defendant in a counterclaim action commenced July 2003 whereby a company controlled by a past director and officer of Aspen Endeavour Resources Inc. claims that it is owned for related party transactions of Cdn $736,969. The Company has previously recorded Cdn $28,115 towards this claim. The Company is defending any amounts in excess of the Cdn $28,115.

615433 Alberta Ltd. vs. Aspen Endeavour Resources Inc.: Action No. 0401 – 06892 Court of Queen’s Bench of Alberta, Judicial District of Calgary, Petition filed on 04/29/04.

On April 29, 2004, Aspen Endeavour Resources Inc. was named as a defendant in an action commenced whereby a company (615433 Alberta Ltd.) controlled by a past officer/director of Aspen Endeavour Resources Inc. claimed that it is owed for an income tax notice of reassessment in amounts of Cdn $239,641 due to a 1999 flow through share transaction. The company is defending this action, as it believes it is not a liability of the company and therefore, no liability has been accrued in these financial statements.

114161 Resources Ltd. vs. Aspen Endeavour Resources Inc.: Action No. 0401 – 06893 Court of Queen’s Bench of Alberta, Judicial District of Calgary, Petition filed on 04/29/04.

On April 29, 2004, Aspen Endeavour Resources Inc. was named as a defendant in an action commenced whereby a company (114161 Resources Ltd.) controlled by a past officer/director of Aspen Endeavour Resources Inc. claimed that it is owed for an income tax notice of reassessment in amounts of Cdn $360,934 due to a 1999 flow through share transaction. The company is defending this action, as it believes it is not a liability of the company and therefore, no liability has been accrued in these financial statements.

Aspen Energy Group, Inc. vs. Jack Wheeler, Butler County, Kansas Case No. 03-C-189.

The lawsuit alleges that while serving as chairman of the board and chief executive officer, Jack Wheeler convinced the board of directors to grant him an overriding royalty interest in certain Aspen properties in lieu of a bonus. However, Wheeler failed to inform the board that such an overriding royalty interest would violate Aspen’s loan covenants with its bank. When the bank learned of the overrides it insisted that Wheeler return the overriding royalty interests to Aspen. Wheeler executed such reassignments. After his departure from Aspen, Wheeler began claiming that he did not fully reassign his overriding royalty interests to Aspen. Aspen filed an action in Butler County, Kansas to quiet title in these wells. Wheeler counterclaimed, asking that title be quieted in his favor. Management intends to vigorously pursue the claim and to defend the counterclaim.

14.

Earnings Per Share

The following data show the amounts used in computing earnings per share and the effect on income and the weighted average number of shares of dilutive potential common stock.

		2003		2002

Net loss	$	(2,717,662)	$	(17,009,828)
Effect of dilutive securities		-		-
Net loss after effect of dilutive securities	$	-	$	(17,009,828)
Weighted average number of common shares used in basic earnings per share		50,030,092		37,420,390
Special warrants		-		-
Convertible debt		-		-
Stock options and warrants		-		-
Weighted average number of common shares and dilutive potential common stock used in diluted earnings per share		50,030,092		37,420,390

Options and warrants to purchase approximately 6,285,712 shares of the Company’s common stock, with exercise prices ranging from $0.12 to $1.00, were excluded from the December 31, 2003 diluted earnings per share calculation because their effects were antidilutive. Options and warrants to purchase approximately 8,318,371 shares of the Company’s common stock, with exercise prices of ranging from $0.05 to $1.80, were excluded from the December 31, 2002 diluted earnings per share calculation because their effects were antidilutive.

15.

Acquisition of Endeavour Resources Inc.

On January 1, 2002, the Company acquired the outstanding common shares of Endeavour pursuant to a November 23, 2001 Offer to Purchase. On March 6, 2002, the Company completed the acquisition of 100% of Endeavour, in exchange for 11,944,809 common shares of the Company together with share purchase warrants to purchase an additional 5,972,403 common shares of the Company. Each whole share purchase warrant entitles the holder to purchase one share of common stock of the Company at a price of $1.25 until September 30, 2002, or $1.75 thereafter until June 30, 2003. In addition, the Company acquired common share purchase warrants of Endeavour entitling the holder to acquire approximately 3,750,000 additional shares of Endeavour common stock. In exchange for these warrants, the Company issued 890,625 Class B common share purchase warrants (Class B Warrants), each whole Class B Warrant entitling the holder to purchase one share of the common stock of the Company at a price of $1.33 per share until June 28, 2002. The Endeavour common stock and warrants are herein referred to as the “Endeavour Securities”. Endeavour is a Calgary based oil and gas company actively engaged in the exploration and development of oil and natural gas in Western Canada and Southern United States. Endeavour was listed on the Canadian Venture Exchange (CDNX) and traded under the symbol “ERU”.

Aspen acquired Endeavour in order to increase its oil and gas production, and to acquire the potential of the oil and gas production in Endeavour. Aspen’s management views the acquisition of Endeavour as an opportunity to acquire competent and experienced management personnel in Canada, along with access to the Canadian market place through increased market recognition from the Canadian oil and gas properties of Endeavour.

16.

Financial Results and Liquidity

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The Company has incurred net losses of $2,717,662 and $17,009,828 for the years ended December 31, 2003 and 2002 respectively and has current liabilities in excess of current assets. These factors, among others, may indicate that the Company will be unable to continue as a going concern for a reasonable period of time. Since joining the Company in October of 2002, the new Chief Executive Officer, along with the rest of the Company’s management team has been developing a broad operational financial restructuring plan. Despite its negative cash flow, the Company has been able to secure financing to support its operations to date. Going forward, additional cash will be needed to implement the proposed business plan and to fund losses until the Company has returned to profitability. Where there is no assurance that funding will be available to execute the plan, the Company is continuing to seek financing to support its turnaround efforts and is exploring a number of alternatives in this regard. Management is exploring alternatives that include seeking strategic investors, selling Company assets and implementing cost reduction programs. There can be no assurance that management’s efforts in this regard will be successful. The Company believes that the capital raised in fiscal 2003 and its current credit facility will be sufficient to support the Company’s liquidity requirements through December 31, 2004, depending on operating results. Management believes that, despite the financial hurdles and funding uncertainties going forward, it has under development, a business plan that if successfully funded and executed as part of the financial restructuring, can significantly improve operating results.

17.

Asset Impairment

During 2002, in connection with a change in management, the Company and its new management team evaluated the ongoing value of certain assets. Based on this evaluation, it was determined that certain assets were impaired and were written down by $1,214,528 to their estimated fair value. The estimated fair value was based on market and other information available to the Company.

18.

Subsequent Events

On April 5, 2004, the Company completed a private placement of 12 million special warrants at $0.25 each for gross proceeds of $3.0 million (Canadian). Each special warrant is comprised of one common share and one half of one common share purchase warrant with each whole common share purchase warrant exercisable for one common share at a price of $0.35 until April 5, 2005. The common shares and warrant issued will carry a four-month hold period under Canadian securities laws from the date of close.

The Company has also issued 2,570,833 shares at $0.18 (Canadian) per share for a total of $462,750 (Canadian). These shares are from the 6,000,000 outstanding purchase warrants, which were issued February 11, 2003.