Mediashift 10K 2005 Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended December 31, 2005


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

For the transition period from to .

Commission file number 001-32438

JMG Exploration, Inc.

(Exact name of registrant as specified in its charter)


Nevada (Jurisdiction of incorporation)		20-1373949 (I.R.S. Employer Identification No.)

Suite 2600, 500 4^th Avenue S.W.
Calgary Alberta, Canada
T2P 2V6
(Address of principal executive offices)

Registrant’s telephone number: (403) 537-3250

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


Title of each class		Name of each exchange on which registered

Common Stock		Pacific Stock Exchange

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

Not applicable
(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yeso Noþ

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. Yesþ Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.o

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

Large accelerated filero Accelerated filero Non-accelerated filerþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

As of the last business day of the registrant’s most recently completed second fiscal quarter, which was June 30, 2005, there was no public market for the issuer’s securities. All of the voting and non-voting equity was held by an affiliate, so the aggregate market value held by non-affiliates was $nil.

The number of shares of the registrant’s Common Stock outstanding as of March 24, 2006 was 5,086,832.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders are incorporated by reference into Part III.

FORWARD LOOKING STATEMENTS

Certain statements in this Annual Report constitute forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements can often be identified by terminology such as may, will, should, expect, plan, intend, expect, anticipate, believe, estimate, predict, potential or continue, the negative of such terms or other comparable terminology. Such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of JMG Exploration Inc. (“JMG”, “we”, “us” or the “Company”), or developments in the Company’s industry, to differ materially from the anticipated results, performance or achievements expressed or implied by such forward-looking statements. Important factors currently known to management that could cause actual results to differ materially from those in forward-looking statements include, without limitation, fluctuation of the Company’s operating results, the ability of the Company to compete successfully, the ability of the Company to maintain current client and publisher relationships and attract new ones, the sufficiency of remaining cash and short-term investments to fund ongoing operations and the ability to integrate acquired companies. For additional factors that may cause actual results to differ materially from those contemplated by such forward-looking statements, please see the risks and uncertainties described under “Business — Risk Factors” in Part I of this Annual Report. Certain of the forward-looking statements contained in this Report are identified with cross-references to this section and/or to specific risks identified under “Business — Risk Factors.” We undertake no obligation to update any forward-looking statements after the date of this Annual Report, whether as a result of new information, future events or otherwise.

PART I

Item 1:Business

Overview

JMG Exploration, Inc. was incorporated under the laws of the State of Nevada on July 16, 2004. We explore for oil and natural gas in the United States and Canada. In August 2004, we completed two private placements totaling $8.8 million and we have commenced exploration activities. We have made direct property acquisitions and will be developing the oil and natural gas properties of others under arrangements in which we will finance the cost of exploration drilling in exchange for interests in the oil or natural gas revenue generated by the properties. Such arrangements are commonly referred to as farm-ins to us, or farm-outs by the lessees of the mineral interests to us.

JMG has the following active projects

	•		A large farm-in agreement and direct purchase of acreage for several Williston Basin prospects in Divide and Burke Counties, northern North Dakota. To date JMG has participated in 4 Upper Devonian Bakken sandstone horizontal oil wells (results being reviewed) and 4 Mississippian Midale carbonate oil wells. For 2006 the Midale is targeted for up to 16 horizontal oil wells with other deeper potential zones being evaluated. These prospect areas are referred to as Candak (approx. 35,000 gross acres), Myrtle (approx. 5,000 gross acres), Bluffton (approx. 5,000 gross acres), and Crosby (approx. 60,000 gross acres).

	•		A farm-in agreement on the Cheyenne River Project (Powder River Basin) in Niobrara County (eastern Wyoming) with 2 existing oil wells and approximately 30,000 gross acres. The Timber Draw well was drilled in early 2001 and the Hooligan Draw well was

			drilled in 2004. Both wells targeted the Lower Cretaceous Newcastle sands. The well performance and the exploration potential of the acreage are both being re-evaluated.

	•		A joint venture on the Pinedale anticline in the Jonah field (Green River Basin) of western Wyoming targeting gas in the Upper Cretaceous Lance sandstone. 2 vertical wells are planned for drilling before year-end 2006.

	•		A joint area of interest in the Fellows Prospects in Weston County in eastern Wyoming on the eastern edge of the Powder River Basin. Targets are the Lower Cretaceous Dakota channel sands and the Permian/Pennsylvanian Minnelusa sands. Approximately 20,000 acres have been acquired with no wells drilled to date. Also included in the Fellows deal is over 5,000 acres in the Gordon Creek project in Carbon County, Utah with no wells drilled to date.

Company History

JMG Exploration, Inc. was incorporated under the laws of the State of Nevada on July 16, 2004. We explore for oil and natural gas in the United States and Canada. In August 2004, we completed two private placements totaling $8.8 million, issuing 250,000 shares of common stock and 1,950,000 shares of convertible preferred stock, and have commenced exploration activities. We have made direct property acquisitions primarily in North Dakota and Wyoming and will be developing the oil and natural gas properties of others under arrangements in which we will finance the cost of exploration drilling in exchange for interests in the oil or natural gas revenue generated by the properties. (See Item 2- Properties)

Upon the closing of the initial public offering on August 3, 2005, the Company issued 2,185,000 shares of common stock at a price of $5.00 and 2,185,000 warrants at a price of $0.10 for gross proceeds of $11,143,500. The Company completed its initial public offering and commenced trading on the Archipelago Exchange under the symbols JMG (common stock) and JMG+ (stock warrants). Simultaneously with our initial public offering, the 1,950,000 preferred shares were converted to 1,950,000 shares of our common stock.

Strategy

Our business strategy is based on drilling oil and natural gas exploratory projects and the initial start-up strategy includes synergistic business relationships with JED Oil Inc. (“JED”) and Enterra Energy Trust (“Enterra”).

Business Relationships with JED and Enterra

Agreement of Business Principles: We entered into the 2^nd Amended and Restated Agreement of Business Principles with JED and Enterra Energy Trust, effective August 1, 2004. Under the agreement, JED and Enterra shall offer farm-outs to us of exploratory drilling prospects, and we shall offer farm-outs to JED of developed drilling prospects from Enterra and us. The agreement contemplates that we will pursue exploratory drilling, JED will pursue development drilling, and Enterra will pursue developed and producing assets. Under the agreement, if we accept a farm-in, we will pay all of the exploration drilling costs and will earn 70%, or a mutually agreeable percentage, of the interest in the producing zones of the wells we drill. This agreement may provide us with exploration projects developed by JED and Enterra and not just those we identify independently. Under our farm-outs to JED, JED will pay all of the drilling costs and will earn 70%, or a mutually agreeable percentage, of our interest in the producing zones of the

wells drilled under the farm-out. This arrangement provides us with the potential for a carried working interest in new wells for which we will have no costs.

We have also agreed that Enterra has the right of first refusal to purchase our interests when we determine that we wish to sell. The agreement provides that the price for our interest is to be the same consideration as offered under abona fidethird party offer, or if there is no such offer, as determined by an independent engineering report prepared by a mutually agreeable independent engineering firm. We believe these arrangements will permit us to concentrate on our business plan of exploratory drilling, possibly provide a buyer for our interests as they are developed and possibly further development drilling in which we may be able to retain a reduced interest at no additional cost to us.

We believe the terms of the 2^nd Amended and Restated Agreement of Business Principles are equivalent to those we could obtain from unaffiliated third parties. The agreement requires independent engineering evaluations as a basis for the valuation of any purchase of a prospect. Nevertheless, under the business principles agreement we may receive proceeds from the sale of our exploration prospects that are less than we might have obtained from unaffiliated third parties.

Services Agreements: We entered into a Technical Services Agreement with JED effective January 1, 2004 under which JED provided us with all personnel, office space and equipment on an as needed basis. The agreement provided that JED will bill us at its cost, including overhead allocation, for all management, operating, administrative and support services. These services include engineering, geological and geophysical analysis, joint venture land activities, drilling operations, well and facility operations, marketing, corporate and business management, planning and budgeting, finance and treasury functions, accounting functions (including general, production and revenue and joint venture accounting, financial reporting, regulatory filing and reporting, corporate and commodity tax, and internal and joint venture audit), payroll, purchasing, human resources, legal services, insurance and risk management, government and regulatory affairs, computer services and information management, administrative services and record keeping, office services and leasing. The Technical Services Agreement was terminated and replaced by a Joint Services Agreement at January 1, 2006 and JED continues to provide these services to us. The Joint Services Agreement may be terminated by either party with 30 days notice.

Total expenses incurred under this agreement during 2005 was $442,667.

Interpersonal Relationships with JED and Enterra: The senior officers and some of the directors of JED, Enterra and JMG have equity ownership in all three entities and hold the following executive positions and/or directorships:

	•		H. S. (Scobey) Hartley is our Chief Executive Officer, President, and is a director of Enterra. Mr. Hartley has announced that he will not stand for re-election to the Board of Enterra at the 2006 annual general meeting.

	•		Thomas J. Jacobsen is a director of JMG, and is Chief Executive Officer and a director of JED.

	•		Reg J. Greenslade is Chairman of the JMG board, and is Chairman of Enterra and JED boards. Mr. Greenslade is resigning as Chairman and a director of Enterra at March 31, 2006.

Proposed Merger with JED: JMG and JED announced in January, 2006 that they are pursuing a possible merger in which JMG would merge with a wholly-owned subsidiary of JED in the U.S., and

JMG’s securities would be exchanged for securities of JED on the basis of two-thirds of a JED common share for each JMG common share.

JED: JED was formed as an Alberta, Canada corporation in September 2003. JED is a publicly traded American Stock Exchange listed company that develops and operates oil and natural gas properties primarily in western Canada.

Enterra: Enterra Energy Trust is an open-ended income trust formed under the laws of Alberta, Canada in October 2003. Trust units of Enterra publicly trade on the New York Stock Exchange and Toronto Stock Exchange. It is administered by Enterra Energy Corp. and “Enterra” as used herein may refer to Enterra Energy Trust or Enterra Energy Corp.

Our oil and natural gas exploration prospects will generally be required to meet the following criteria.

Exploratory projects

We intend to concentrate our efforts on oil and natural gas projects that carry a relatively high risk of failure but offer relatively high rewards in terms of a larger potential for significant oil or natural gas reserves. Our management believes that the potential rewards of a significant discovery of oil or natural gas reserves in the current robust commodity price environment adequately compensates for this risk.

Consolidation of adjacent assets

We seek exploration opportunities on lands that are in close proximity to producing fields. These close-in opportunities create the ability to reduce capital program costs by consolidating drilling and gathering facilities. Moreover, drilling costs are lower when wells are drilled as part of a multi-well program, due to reduced rig moving costs and other efficiencies.

Use of seismic and other data in site selection

We intend to generate and analyze seismic data, including three-dimensional seismic information, whenever its use is appropriate for the geology and is cost effective, to further minimize drilling risk. We also intend to use information from adjacent wells, including petrophysical data, production records and completion data to help reduce our risk and costs. The use of seismic data and other technologies, and the study of producing fields in the same area, provides information that is useful in evaluating a prospect’s potential. This information will not however enable us to know conclusively prior to drilling and testing whether oil or natural gas will be present or, if present, if it will be in sufficient quantities to recover drilling and completion costs or to be economically viable.

Selection of prospects

We intend to select prospects for exploration which we believe offer us the opportunity to reduce operating costs and maximize economies of scale, thereby improving operating profitability. Considerations include identifying areas of moderate drilling costs, multi-zone potential, year round accessibility and good oil and natural gas plant and pipeline infrastructure.

We expect that many of our prospects will be properties identified by JED and Enterra, and determined to be exploratory in nature, and therefore not the type of drilling prospect that JED or Enterra

is seeking. Any prospects that JED or Enterra believes have merit but that fit our exploratory criteria will be presented to our management for approval.

Sales and Marketing

During 2005, we sold all of our oil and gas production through Murphy Oil, who also handled the production accounting and sent us are percentage interest in the revenues, net of royalties and production and sales costs. Murphy Oil is an independent third party who trucks the oil from our wellhead to their production facility.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, local and tribal laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our business strategy discussed above identifies the areas we believe are key in effectively competing in this marketplace in conjunction with our strategic business principles agreement with JED and Enterra.

Geographic Segments

The majority of our assets and revenue are in North Dakota. Wyoming and Utah only accounts for a very small percentage, less than 5%, of our assets and less than 10% of our revenue for the period ended December 31, 2005.

Employees

As of February 28, 2006, we had a total of two employees being our senior officers: our President and Chief Executive Officer and our Chief Financial Officer. As discussed above in the description of our business strategy as it relates to a business relationship with JED, JED provides all of our staff, office space and equipment. Unions do not represent either our employees or any employees of JED.

Government regulation

Our operations are subject to government controls and regulations in the United States and Canada:

United States regulation

In the United States, legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas drilling, pipelines, gas processing plants and production activities, increase the cost of doing business and, consequently, affect profitability. As new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. We consider the cost of environmental protection a necessary and manageable part of our business. We expect to be able to plan for and comply with new environmental initiatives without materially altering our operating strategies.

Exploration and production.Our United States operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes:

	•		requiring permits for the drilling of wells;

	•		maintaining bonding requirements in order to drill or operate wells;

	•		implementing spill prevention plans;

	•		submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; regulating the location of wells;

	•		regulating the method of drilling and casing wells;

	•		regulating the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities;

	•		regulating surface usage and the restoration of properties upon which wells have been drilled;

	•		regulating the plugging and abandoning of wells; and

	•		regulating the transporting of production.

Our operations are also subject to various land conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from wells and limit the number of wells or the locations at which we can drill.

Environmental and occupational regulations.We are subject to various federal, state and local laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of contaminants or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect exploration, development, processing, and production operations and the costs attendant thereto. These laws and regulations increase

overall operating expenses. We maintain levels of insurance customary in the industry to limit financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil or other substances. However, 100% coverage is not maintained concerning any environmental claim, and no coverage is maintained with respect to any penalty or fine required to be paid because of violation of any federal, state or local law. We are committed to meeting our responsibilities to protect the environment wherever we operate.

We are also subject to laws and regulations concerning occupational safety and health. Due to the continued changes in these laws and regulations we are unable to predict our future costs of complying with these laws and regulations. We consider the cost of safety and health compliance a necessary and manageable part of our business. We expect to be able to plan for and comply with any new initiatives without materially altering our operating strategy. We contract with JED for assistance with environmental and occupational regulations and utilize their Environmental, Health and Safety Department personnel for this purpose. This department is responsible for instituting and maintaining an environmental and safety compliance program for us. The program includes field inspections of properties and internal assessments of compliance procedures.

Canadian regulation

The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect any future Canadian operations in a manner materially different than they would affect other oil and gas companies of similar size. The following are the most important areas of control and regulation.

The North American Free Trade Agreement.The North American Free Trade Agreement, or NAFTA, which became effective on January 1, 1994, carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not:

	•		reduce the proportion of energy exported relative to the supply of the energy resource;

	•		impose an export price higher than the domestic price; or

	•		disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements.

Exploration and production.Canadian operations are subject to federal and provincial governmental regulation. Such regulation includes requiring licenses for the drilling of wells, regulating the location of wells and the method and ability to produce wells, surface usage and the restoration of land upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production from wells. Canadian operations are also subject to various conservation regulations, including the regulation of the size of spacing units, the number of wells which may be drilled in a unit, the unitization or pooling of oil and gas properties, the rate of production allowable from oil and gas wells, and the ability to produce oil and gas. In Canada, the effect of such regulation is to limit the amounts of oil and gas that can be produced and to limit the number of wells or the locations at which wells can be drilled.

Royalties and incentives.Each province and the federal government of Canada have legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime is a significant factor in the

profitability of oil and natural gas production. Royalties payable on production from lands other than Provincial or Federal Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the governments of Canada, Alberta, British Columbia and Saskatchewan have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing the cash flow to the producer.

Pricing and marketing.The price of oil and natural gas sold is determined by negotiation between buyers and sellers. An order from the National Energy Board, or NEB, is required for oil exports from Canada. Any oil export to be made pursuant to an export contract of longer than one year, in the case of light crude, and two years, in the case of heavy crude, duration (up to a maximum of 25 years) requires an exporter to obtain an export license from the NEB. The issue of such a license requires the approval of the Government of Canada. Natural gas exported from Canada is also subject to similar regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB. The governments of Alberta and British Columbia also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Land tenure.Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms from two years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental regulation.The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. We are committed to meeting our responsibilities to protect the environment wherever we operate.

In Alberta, environmental compliance has been governed pursuant to the Alberta Environmental Protection and Enhancement Act, or AEPEA, since September 1, 1993. In addition to replacing a variety of older statutes which related to environmental matters, AEPEA also imposes certain new environmental responsibilities on oil and natural gas operators in Alberta and in certain instances also imposes greater penalties for violations.

Kyoto protocol.In December 2002, the Government of Canada ratified the Kyoto Protocol. This protocol calls for Canada to reduce its greenhouse gas emissions to six percent below 1990 levels during the period between 2008 and 2012. The protocol will only become legally binding when it is ratified by at least 55 countries, covering at least 55 percent of the emissions addressed by the protocol. At this time, it is uncertain if the protocol will in fact be ratified. If the protocol becomes legally binding, it is expected to affect the operation of all industries in Canada, including the oil and gas industry. As details of the

implementation of emissions reduction initiatives related to this protocol have yet to be announced, the effect on any future operations in Canada cannot be determined at this time.

Investment Canada Act.The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval.

The following are our executive officers:

H. S. (Scobey) Hartley.Mr. Hartley has been our Chief Executive Officer, President and a director from August 2004 through July 2005. His activities as our Chief Executive Officer and President are on a part-time basis and he has an ongoing consulting practice with other oil and gas companies, including Enterra and JED. He has been a director of Enterra Energy Trust and its predecessors since May 2000. Mr. Hartley has been the Chairman and Chief Executive Officer of Welwyn Resources Ltd., a junior oil and gas company listed on the Toronto Stock Exchange Venture Exchange since August 26, 1997. Mr. Hartley has been a director of Cathedral Energy Services Ltd. since June 2001 and is co-owner of Linvest Resources Corp., a family consulting business. Mr. Hartley is Co-Chair of Alberta’s Promise, an Alberta government initiative that promotes partnerships between businesses, clubs, communities, foundations and agencies to direct resources to children and youth. Mr. Hartley was the President of Prism Petroleum Ltd. and a predecessor company from December 1990 through December 1996. Mr. Hartley has been the Chairman of Prism Petroleum Ltd. since January 1997. He served as the President of Faster Oilfield Services since June 1995, and was the President of Cayenne Energy Corp. from 1990 to 1996. Mr. Hartley was the President and a director of Scaffold Connection Corporation from February 2000 to November 2001. He has a Bachelor of Science degree in Geology from Texas Tech University.

Joanne Finnerty.Ms. Finnerty joined our company as Chief Financial Officer in July 2005. Ms. Finnerty was previously employed as the Controller of Divestco Inc, a publicly traded company on the Toronto Stock Exchange — Venture Exchange, from September 2002 to July 2005. Ms. Finnerty was the Controller of Sigma Explorations Inc., a private seismic data brokerage company, from 1995 until 2002. From 1992 until 1995 Ms. Finnerty was Manager of Financial Planning for TriWaste Reduction Services Inc. (a division of Trimac Ltd.). Ms. Finnerty Received her Certified General Accountant designation in 1991.

Item 1A:Risk Factors

Risks related to our company and the oil and natural gas industry

Other than our executive officers, we have no operating personnel and are dependent upon JED for drilling, field operations and related administrative services. The loss of JED’s services could substantially increase our costs.

We have entered into a Joint Services Agreement with JED which provides us with all additional personnel required, office space and equipment. If JED terminates the agreement for any reason, we will be required to find another company willing to provide us with these services or hire personnel, find office space and purchase or lease equipment ourselves. Retaining another company to provide these services or doing so ourselves could substantially increase our costs. See “Business” — “Strategy” —“Relationships with JED and Enterra”– “Services Agreements”.

We depend on our executive officers for critical management decisions and industry contacts. We have no key person insurance with these individuals and therefore the loss of their services would be costly to us.

We are dependent upon the continued services of our chairman of the board, chief executive officer and chief financial officer. We do not carry key person insurance on their lives. The loss of the services of either of our executive officers, through incapacity or otherwise, would be costly to us and would require us to seek and retain other qualified personnel. See Item 1 “Business” — “Employees”.

Potential conflicts of interest in our relationship with JED and Enterra may cause us to receive proceeds from the sale of our exploration prospects that are less favorable than we might have obtained from third parties.

Several of the senior officers and directors of JED, Enterra and JMG have equity ownership in all three companies and hold the following executive positions and/or board memberships:

	•		H. S. (Scobey) Hartley is our Chief Executive Officer, President, and is a director of Enterra. He has announced that he will not stand for re-election at Enterra’s 2006 annual general meeting.

	•		Thomas J. Jacobsen is a director of JMG, and is Chief Executive Officer and a director of JED.

	•		Reg J. Greenslade is Chairman of the JMG board, and is Chairman of the Enterra and JED boards. He is resigning as Chairman and a director of Enterra at March 31, 2006.

We also have a business principles agreement with JED and Enterra, which gives each of them certain rights to develop our exploration prospects. As a result of these relationships and the business principles agreement, we may receive proceeds from the sale of our exploration prospects that are less than we might have obtained from unaffiliated third parties. See Item 1 “Business” — “Strategy” —Relationships with JED and Enterra”— “Agreement of Business Principles”.

We have a limited operating history, which makes it difficult to predict our future performance.

We were formed in July 2004. Our limited operating history makes predicting our future performance difficult and does not provide investors with a meaningful basis for evaluating an investment in our common stock.

A substantial or extended decline in oil and natural gas prices could reduce our future revenue and earnings.

The price we receive for future oil and natural gas production will heavily influence our revenue, profitability, access to capital and rate of growth. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and currently oil and natural gas prices are significantly above historic levels. These markets will likely continue to be volatile in the future and current record prices for oil and natural gas are expected by many to decline in the future. The prices we may receive for any future production, and the levels of this production, depend on numerous factors beyond our control. These factors include the following:

	•		changes in global supply and demand for oil and natural gas;

	•		actions by the Organization of Petroleum Exporting Countries, or OPEC;

	•		priced and quantities of imports of foreign oil and natural gas in Canada and the U.S.;

	•		political conditions, including embargoes, which affect other oil-producing activities;

	•		levels of global oil and natural gas exploration and production activity;

	•		levels of global oil and natural gas inventories;

	•		weather conditions affecting energy consumption;

	•		technological advances affecting energy consumption; and

	•		prices and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our future revenues but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may reduce our earnings, cash flow and working capital.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could substantially increase our costs and reduce our profitability.

Oil and natural gas exploration is subject to numerous risks beyond our control; including the risk that drilling will not result in any commercially viable oil or natural gas reserves. Our decisions to develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Failure to successfully discover oil or natural gas resources will increase our costs, decrease our revenue and decrease our profitability.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Our cost of drilling, completing and operating wells will be uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

	•		delays imposed by or resulting from compliance with regulatory requirements;

	•		pressure or irregularities in geological formations;

	•		shortages of or delays in obtaining equipment and qualified personnel;

	•		equipment failures or accidents;

	•		adverse weather conditions;

	•		reductions in oil and natural gas prices;

	•		land title problems; and

	•		limitations in the market for oil and natural gas.

Our insurance coverage does not cover all risks and we may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

	•		environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

	•		abnormally pressured formations;

	•		mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

	•		fires and explosions;

	•		personal injuries and death; and

	•		natural disasters.

Any of these risks could adversely affect our ability to operate or result in substantial losses to our company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event that is not fully covered by insurance occurs, it could adversely affect us.

We currently have the following insurance coverage in place:


General liability	$	1,000,000
Pollution liability	$	1,000,000
Umbrella legal liability	$	14,000,000
Operators extra expense	$	20,000,000

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our future oil and natural gas production will depend on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production will depend in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut-in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. We presently have no contracts with operators of gathering systems, pipelines or processing facilities with respect to our exploration prospects.

We are subject to complex laws that can affect the cost, manner and feasibility of doing business thereby increasing our costs and reducing our profitability.

Development, production and sale of oil and natural gas are subject to extensive federal, state, provincial, local and international laws and regulations. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

	•		discharge permits for drilling operations;

	•		drilling bonds;

	•		reports concerning operations;

	•		spacing of wells;

	•		unitization and pooling of properties; and

	•		taxation.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our financial condition and results of operations. See Item 1 “Business” — “Government Regulation”.

We may incur substantial liabilities to comply with environmental laws and regulations.

Oil and natural gas operations are subject to stringent federal, state, provincial, local and international laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

	•		require acquisition of a permit before drilling commences;

	•		restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

	•		limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

	•		impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, incurrence of investigatory or remedial obligations, or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position, or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release of such materials or if our operations were standard in the industry at the time they were performed. See “Business” — “Government Regulation”.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our plans on a timely basis and within our budget.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development operations, which could have a material adverse effect on our business, financial condition or results of operations.

Competition in the oil and natural gas industry is intense, which may increase our costs and otherwise adversely affect our ability to compete.

We operate in a highly competitive environment for prospects suitable for exploration, marketing of oil and natural gas and securing the services of trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for prospective oil and natural gas properties and prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In order for us to compete with these companies, we may have to increase the amounts we pay for prospects, thereby reducing our profitability. See Item 1 “Business” — “Competition”.

We may not be able to compete successfully in acquiring prospective reserves, developing reserves, marketing oil and natural gas, attracting and retaining quality personnel and raising additional capital.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. Our inability to compete successfully in these areas could have a material adverse effect on our business, financial condition or results of operations. See “Business — Competition.”

Item 1B.Unresolved Staff Comments

Not applicable

Item 2:Properties

Divide and Burke Counties, North Dakota

JMG has various working interests ranging from 65% to 98% in approximately 100,000 gross acres in Divide and Burke Counties in northern North Dakota near the Canada / US border (162N-164N, 94W-97W. Targeted thus far for direct acreage purchase and exploratory drilling have been the Upper Devonian / Lower Mississippian Bakken sandstone and the Middle Mississippian Midale carbonates. The Bakken Formation averages 10’ in thickness, 40⁰ API oil in this area and is a major established producing horizon in many parts of the Williston Basin. The Bakken requires large fracture stimulations to open up small-scale fractures present in the reservoir. The Midale Formation averages 5’ in thickness, 30⁰ API oil in the area and is an emerging play to the north in the Tableland area of southern Saskatchewan. JMG’s development drilling activity in the area has been in partnership with JED Oil whereby JED farms-in on JMG and pays 100% of the drilling cost to earn a 70% working interest in each spacing unit to depth drilled. To date 4 Bakken horizontal oil wells have been drilled and placed on production (Burau 4-22H in Burke County and Rindel 3-9H, Points 2-11H, and Buck 3-8H in Divide County) and the reservoir performance is currently being reviewed. Typical drill depths for these Bakken horizontals is 13,000’. Also to date 3 Midale horizontal oil wells have been drilled and placed on production plus the Burau horizontal Bakken oil well has been recompleted in the uphole, vertical portion of the wellbore and placed on production. The 3 Midale horizontal oil wells are Schutz 5-26H, Erickson1-27H and Kearney 4-25H with all production having come on-stream in early 2006. Typical drill depths are approx. 10,500’ for these Midale horizontals. Up to 16 horizontal Midale wells are projected to be drilled in 2006 with other deeper potential zones being evaluated. Current Midale spacing is 2 horizontals per section with potential for 4 wells per section as warranted. Active prospect areas in this region include Candak (approx. 35,000 gross acres), Myrtle Beach (approx. 5,000 gross acres), Bluffton (approx. 5,000 gross acres), and Crosby (approx. 60,000 gross acres). This area has year-round drilling access. Reserves have been assigned for our Bakken, Midale wells in these areas.

Pinedale Anticline

JMG has a joint venture on one section of land with a 77.5% working interest on the Pinedale anticline in the Jonah field of the Green River Basin in west central Wyoming. The drilling target is the Lower Cretaceous Lance sandstone at approx. 15,000’ vertical drill depth and 2 wells are planned for drilling before year-end 2006. The tight gas in the Lance Formation typically demonstrates poor reservoir connectivity to offsetting wells thereby necessitating down spacing to 40 acres with large multiple fracture stimulations. Extensive gas gathering infrastructure is present in the immediate area. No reserves have been assigned to this area at this time. No reserves have been assigned to this area for 2005.

Cheyenne River Project

JMG entered into a large farm-in agreement in August 2004 on approximately 30,000 gross acres and 1 pre-existing well (Timber Draw) in Niobrara County (eastern Wyoming). The exploration target is the Lower Cretaceous Newcastle sand of the Dakota Group. In 2004 an assignment was made to JED Oil whereby it operated the drilling of the horizontal Hooligan Draw exploratory test well to 9,332’. This Hooligan Draw well has a surface location approximately¹/2 mile east of the Timber Draw well. The interest in the 2 wells has been pooled and JMG now holds 40.16% working interest. To date, both wells

produce oil intermittently. The well performance and the exploration potential of the acreage are both being re-evaluated currently. Limited reserves have been assigned to the wells in this area.

Weston County, Wyoming

JMG entered into a joint area of interest with Fellows Energy Ltd in November 2004 to evaluate acreage in Weston County (eastern Wyoming) on the eastern edge of the Powder River Basin. Targets are light oil prospects in the Lower Cretaceous Dakota channel sands and the Permian/Pennsylvanian Minnelusa sands. There is potential for structural and stratigraphic traps against channel edges and up-dip shale pinch-outs imaged on seismic. There are similar developed fields in the area with an infrastructure of oil and gas gathering and processing facilities. Approximately 20,000 acres have been acquired with no wells drilled and no reserves assigned to date.

Carbon County, Utah

JMG also entered into a joint area of interest with Fellows Energy Ltd in November 2004 to evaluate the Gordon Creek project in Carbon County, eastern Utah. The targets are coal bed methane and tight gas sands within the Cretaceous Ferron Formation nearby the established coal bed methane fields in Drunkard’s Wash, Utah. Approximately 5,000 gross acres of land have been acquired with no wells drilled and no reserves assigned to date.

Item 3:Legal Proceedings

There are no material outstanding or threatened legal claims by or against us.

Item 4:Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of our security holders during the fourth quarter of 2005.

PART II

Item 5:Market For Our Common Equity And Related Stockholder Matters

Price Range of Common Stock

Our common stock is quoted on the Pacific Stock Exchange under the symbol “JMG” since our initial public offering on August 5, 2005. Prior to our initial public offering, there was no public market for our common stock. The following table shows the high and low closing sale prices for our common stock as reported on the Pacific Stock Exchange for the periods indicated:


Period	High		Low
August 5 – 31, 2005		18.75		12.01
September, 2005		18.00		13.25
October, 2005		15.60		10.00
November, 2005		12.50		8.50
December, 2005		9.25		6.00
January, 2006		11.75		6.75
February, 2006		11.30		7.50
March 1 – 24, 2006		11.00		7.50

As of March 24, 2006,there were approximately 31 holders of record of the Common Stock and 5,086,832 shares of the Common Stock outstanding. The number of holders of record is calculated excluding individual participants in securities positions listings. The closing price of our shares on March 24, 2006, was $9.75.

We have never paid cash dividends on the Common Stock and do not intend to pay cash dividends on the Common Stock in the foreseeable future. Our board of directors intends to retain any earnings to provide funds for the operation and expansion of our business.

Recent Sales of Unregistered Securities

None.

Item 6: Selected Financial Data

The following selected financial data are qualified in their entirety by reference to, and you should read them in conjunction with, our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” appearing elsewhere in this annual report. The statement of operations data presented below for the periods ending December 31, 2005 and the period from incorporation July 16, 2004 to December 31, 2004, and the selected balance sheet data at December 31, 2004 and 2005, are derived from JMG’s consolidated financial statements that have been audited by Ernst & Young LLP, independent registered public accounting firm.


	Twelve month			Period from the date of
	period ended			incorporation on July 16,
	December 31			2004 to December 31
	$			$			$
	2005			2004			2003
Statement of Operations Data:
Revenues		854,864			—			n/a
Operating expenses:
Less royalties		(227,404	)		—			n/a

Production		189,598			—			n/a
General and administrative		1,768,712			286,060			n/a
Stock-based compensation		78,589
Geophysical and Geological		256,484
Depreciation and amortization		4,265,162			479,702			n/a

Accretion		3,385

Total operating expenses		6,561,930			765,762			n/a
Operating income (loss)		(5,934,470	)		(765,762	)		n/a
Interest expense		—			—			n/a
Interest income		120,461			64,630			n/a
Gain on warrant liability		—			—			n/a
Net income (loss)		(5,814,009	)		(701,132	)		n/a
Less cumulative preferred dividends		(458,342	)		(323,157	)
Net loss applicable to common shareholders		(6,272,351	)		(1,024,289	)
Earnings (loss) per share:
Basic		(2.97	)		(4.10	)		n/a
Diluted		(2.97	)		(4.10	)		n/a
Weighted average shares outstanding:
Basic		2,111,351			250,000			n/a
Diluted Diluted		2,111,351			250,000			n/a

Twelve month

Period from the date of

period ended

incorporation on July 16,

December 31

2004 to December 31

2005

2004

2003

Total assets

17,773,179

8,429,049

n/a

Current Liabilities

2,793,111

656,238

n/a

Long-term obligations, less current portion

78,642

—

n/a

Total shareholders’ equity

14,901,426

7,772,811

n/a

Item 7:Management’s Discussion And Analysis Of Financial Conditions And Results Of Operations

The following Management’s Discussion and Analysis (“MD&A”) of financial results as provided by the management of JMG Exploration, Inc. (“JMG”) should be read in conjunction with the audited consolidated financial statements and notes for the year ended December 31, 2005. This commentary is based upon information available to March 31, 2006.

FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements. All statements other than statements of historical facts contained herein, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of risks, uncertainties and assumptions described in “Risk Factors” of the Company’s Registration Statement dated August 3, 2005.

Other sections of this report may include additional factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. Readers arecautionedthat the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this MD&A are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except in accordance with applicable securities laws. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

Finally, in the presentation of the MD&A, JMG uses two terms that are universally applied in analyzing corporate performance within the oil and gas industry for which regulators require that we provide disclaimers.

Barrel of Oil Equivalent (BOE) —The oil and gas industry commonly expresses production volumes and reserves on a “barrel of oil equivalent” basis (“BOE”) whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. Throughout this MD&A, JMG has used the 6:1 BOE measure which is the approximate energy equivalency of the two commodities at the burner tip. BOE does not represent a value equivalency at the plant gate, which is where JMG sells its production volumes, and therefore may be a misleading measure if used in isolation.

Funds Flow from Operations (funds flow) —This measure is considered critical within the oil and gas industry both in terms of measuring success in our historical operations and being an indicator of funding sources for on-going efforts to replace production volumes and increase reserve volumes. United States GAAP requires that “funds flow from operating activities” be the measurement focus. Funds flow is derived from “cash flow” as defined by JMG adjusted for non-cash working capital. JMG believes “funds flow” and “funds flow per share” to be more meaningful measures of our performance and therefore have used these terms throughout this MD&A. Accordingly, we are required to advise the reader that: (a) these are non-GAAP measure for purposes the United States accounting standards and (b) our determinations may not be comparable to those reported by other companies. (See” Funds flow from operations” section of this management discussion and analysis.)

Overview

JMG was incorporated under the laws of the State of Nevada on July 16, 2004. We explore for oil and natural gas in the United States and Canada.

In 2005, we made direct property acquisitions and will be developing the oil and natural gas properties of others under arrangements in which we will finance the cost of exploration drilling in exchange for interests in the oil or natural gas revenue generated by the properties. Such arrangements are commonly referred to as farm-ins to us, or farm-outs by the property owners to us.

Upon the closing of the initial public offering on August 3, 2005, the Company issued 2,185,000 shares of common stock at a price of $5.00 and 2,185,000 warrants at a price of $0.10 for gross proceeds of $11,143,500. The warrants associated with the initial public offering are exercisable at $5.00, until one year from the statement of registration. The Company completed its initial public offering and commenced trading on the Archipelago Exchange under the symbols JMG (common stock) and JMG+ (stock warrants).

Other than our executive officers, we have no operating personnel and have entered into a technical services agreement with JED Oil Inc. (“JED”) to provide us office space, equipment and all required personnel, including drilling, field operations and related administrative services on an as needed basis. These services are billed to JMG on a quarterly basis at standard industry rates for similar services. JED is considered an affiliate of ours because of its ownership interest in JMG and because two of our directors are directors of JED. (See “ Related Party Transactions” of this management discussion and analysis”)

We entered into the 2^nd Amended and Restated Agreement of Business Principles with JED and Enterra Energy Trust, effective August 1, 2004. Under the agreement, JED and Enterra shall offer farm-outs to us of exploratory drilling prospects, and we shall offer farm-outs to JED of developed drilling prospects from Enterra and us. The agreement contemplates that we will pursue exploratory drilling, JED will pursue development drilling, and Enterra will pursue developed and producing assets. Under the agreement, if we accept a farm-in, we will pay all of the exploration drilling costs and will earn 70%, or a mutually agreeable percentage, of the interest in the producing zones of the wells we drill. This arrangement provides us with exploration projects developed by JED and Enterra and not just those we identify independently. Under our farm-outs to JED, JED will pay all of the drilling costs and will earn 70%, or a mutually agreeable percentage, of our interest in the producing zones of the wells drilled under the farm-out. This arrangement provides us with the potential for a carried working interest in new wells for which we will have no costs.

This agreement also provides that Enterra has the right of first refusal to purchase our interests when we determine that we wish to sell. The agreement provides that the price for our interest is to be the same consideration as offered under abona fidethird party offer, or if there is no such offer, as determined by an independent engineering report prepared by a mutually agreeable independent engineering firm. We believe these arrangements will permit us to concentrate on our business plan of exploratory drilling, possibly provide a buyer for our interests as they are developed and permit further development drilling in which we may be able to retain a reduced interest at no additional cost to us.

To date, JMG has assembled substantial land positions in North Dakota and Wyoming and participated in the drilling of seven gross (3.2 net) wells with 100% success rate proving up significant future development. Two of the seven wells drilled to date were on production in late 2005 with the other four wells coming on production in 2006. Current net production to JMG is approximately 150-175 BOE/d.

JMG currently has over 115,000 gross (over 80,000 net) acres of land in northern North Dakota. In addition, JMG owns a 77.5% working interest in a section of land in the Pinedale area of Wyoming. These lands offset the prolific Jona/Pinedale producing fields. As previously announced, JMG was involved in a significant oil discovery in the Midale formation in the northern part of North Dakota. Three wells have been drilled into this formation to date and 16 development locations have been identified as a result of this initial drilling.

We are pursing a merger with JED, which was announced in January 2006. (See Outlook and Proposed Transaction’s section of this management discussion and analysis)

Financial operations overview


Summarized Financial and Operational Data(In US$ thousands, except per share data)
													Period from
													incorporation
										Year ended			July 16, 2004
	Q4			Q4						December 31,			to December
	2005			2004			*Change*			2005			31, 2004			*Change*

Petroleum and natural gas revenue		398			—			398			855			—			855
Net loss		(4,435	)		(627	)		(3,808	)		(5,814	)		(701	)		(5,113	)
Per share basic and diluted		(0.91	)		(3.29	)		2.38			(2.97	)		(4.10	)		1.13
Exit production rate (BOE/d)		129			—			129			129			—			129
Funds flow from operations⁽¹⁾		(462	)		(147	)		(315	)		(1,210	)		(221	)		(989	)
Per share – basic and diluted		(0.09	)		(0.59	)		0.50			(0.57	)		(0.88	)		0.31
Weighted average number of shares outstanding — basic		4,897			250			4,647			2,111			250			1,861

⁽¹⁾

Funds flow from operations and earnings from operations are non-GAAP measure. It is management’s view that this information is relevant for investors. Funds flow from operations is reconciled to GAAP in the funds flow from operations section of the management discussion and analysis.

Quarterly Information


*Quarterly information(In US$ thousands, except per share data)***
	Q1			Q2			Q3			Q4			Q1		Q2		Q3			Q4
	2005			2005			2005			2005			2004		2004		2004			2004

Revenue		—			8			449			398			—		—		—			—

Loss from operations⁽¹⁾		(217	)		(467	)		(695	)		(4,435	)		—		—		(74	)		(627	)
Per share, basic and diluted		(1.64	)		(2.65	)		(0.26	)		(0.91	)		—		—		(0.80	)		(3.29	)

Net loss		(217	)		(467	)		(695	)		(4,435	)		—		—		(74	)		(627	)
Per share, basic and diluted		(1.64	)		(2.65	)		(0.26	)		(0.91	)		—		—		(0.80	)		(3.29	)

2 Year Summary


Summarized financial and operational data
*(In US$ thousands except for volumes and per share amounts)*

				Period from
				incorporation
	Year ended			July 16, 2004
	December			to December
	31, 2005			31, 2004

Revenue		855			—

Funds flow from operations		(1,210	)		(221	)
Funds flow from operations per share — basic and diluted		(0.57	)		(0.88	)

Loss from operations⁽¹⁾		(5,814	)		(701	)
Loss from operations per share — basic and diluted⁽¹⁾		(2.97	)		(4.10	)

Net loss		(5,814	)		(701	)
Net loss per share — basic and diluted		(2.97	)		(4.10	)

Weighted average number of shares — basic and diluted		2,111			250

Total assets		17,773			8,429
Total long-term debt		—			—

(1)

Funds flow, funds flow from operations and loss from operations are non-GAAP measures. Funds flow, funds flow from operations and loss from operations are reconciled to GAAP loss in funds flow from operation section of the management discussion and analysis.

Results of operations

Revenue.Our revenue is dependent upon success in finding and developing oil and natural gas reserves. Our ownership interest in the production from these properties is measured in BOE per day, a term that encompasses both oil and natural gas production. Revenues were $854,864 for the year ended December 31, 2005. This revenue related to production sales from two Bakken exploratory wells and one Midale exploratory well in North Dakota together with revenue from two non-operated wells in Wyoming. There was no revenue for the period ended December 31, 2004. Total revenue from incorporation July 16, 2004 to December 31, 2005 was $854,864.


*Year ended to December 31, 2005 Compared to Year Ended December 31, 2004*
					Percentage
Year ended December 31,	2005		2004		Increase

Production (BOE)		15,449		—		N/a

Average Price	$	55.33		—

Revenues	$	854,864		—		N/a


*Period from incorporation on July 16, 2004 to December 31, 2005*
Incorporation July 16, 2004 to December 31, 2005.

Production (BOE)		15,449

Average Price	$	55.33

Revenues	$	854,864

Critical to our revenue stream from any production activities is the market price for crude oil and natural gas. Commodity benchmark prices for crude oil and natural gas were as follows:


December 31,	2005		2004

West Texas Intermediate grade crude oil, per barrel	$	59.78	$	41.10

Our realized price for any oil and natural gas production will be dependent upon the actual quality of the commodity which could result in a premium or discount to the above indices. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. If oil and natural gas prices decrease this movement could affect the overall valuation of our petroleum and natural gas reserves and we may be required to take a write-down of the carrying value.

We may use derivative financial instruments when we deem them appropriate to hedge exposure to changes in the price of crude oil and natural gas, fluctuations in interest rates and foreign currency exchange rates. JMG currently does not have any financial derivative contracts or fixed price contracts in place.

Royalty expense.Royalty expense is based on the percentage royalties calculated by applying the applicable royalty rate or formula. The royalties for the period ended December 31, 2005 were $227,404 there were no revenues or related royalties for the period ended December 31, 2004. Total royalties from incorporation July 16, 2004 to December 31, 2005 were $227,404.


*Year ended to December 31, 2005 Compared to Year Ended December 31, 2004*
			% of					% of		Percentage
Year Ended December 31,	2005		revenue			2004		revenue		Increase

Royalty expense	$	227,404		26.6	%		—		—		100	%

Royalty expense per BOE:	$	14.72		—			—		—


*Period from incorporation on July 16, 2004 to December 31, 2005*
			% of
Incorporation July 16, 2004 to December 31, 2005.			revenue

Royalty expense	$	227,404		26.6	%

Royalty expense per BOE:	$	14.72		—

Interest income. Interest for the year ending December 31, 2005 and the period from incorporation to December 31, 2004 respectively are $120,461 and $64,630. Interest was due a promissory note to unrelated industry partner, which was repaid on June 28, 2005. Total interest from incorporation July 16, 2004 to December 31, 2005 was $185,091.

Production expense.Production costs include operating costs associated with field activities. Production expenses for the year ended December 31,2005 were $189,598; there was no production for the period from

incorporation to December 31, 2004. Initially these costs as a percentage of revenue will be higher than desired due to recently commencing operations, but as production and revenue increase these costs should fall within industry ranges. Total production expenses from incorporation July 16, 2004 to December 31, 2005 were $189,598.


*Year ended to December 31, 2005 Compared to Year Ended December 31, 2004*
			% of					% of		Percentage
Year Ended December 31,	2005		revenue			2004		revenue		Increase

Production expense	$	189,598		22.1	%		—		—		100	%

Production expense per BOE:	$	12.27		—			—		—


*Period from incorporation on July 16, 2004 to December 31, 2005*
			% of
Incorporation July 16, 2004 to December 31, 2005.			revenue

Production expense	$	189,598		22.1	%

Production expense per BOE:	$	12.27		—

General and administrative expense.General and administrative expense relates to compensation and overhead for executive officers and fees for general operational and administrative services. We have contracted out all field personnel and equipment necessary for exploration activities, and for related administrative functions. During the period ending December 31, 2005 the amount for general and administrative expense were $1,768,712 compared with $286,060 for the period ending December 31, 2004. This increase related to percentage of total general and administrative costs allocated to the Company relating to the technical service agreement, which are based on production and capital acquired in the current quarter. Both JED and Enterra provide services on our behalf. Expenses consist principally of salaries, consulting fees and office costs relating to the preparation and planning of our exploratory wells that commenced drilling this year, and planning for future drilling activities. Total general and administrative expenses from incorporation July 16, 2004 to December 31, 2005 were $2,054,772.


*Year ended to December 31, 2005 Compared to Year Ended December 31, 2004*
					Percentage
Year ended December 31,	2005		2004		Increase

General and administrative expense	$	1,768,712	$	286,060		518	%

Period from incorporation on July 16, 2004 to December 31, 2005


Incorporation July 16, 2004 to December 31, 2005.

General and administrative expense	$	2,054,772

Stock–based Compensation.The Company has a stock option plan under which employees; directors and consultants are eligible to receive grants. The Corporation accounts for the stock option granted to consultants using the fair value recognition provisions of SFAS No. 123. Stock compensation expense for the year ended December 31, 2005 was as $78,589. There was no stock based compensation for the period ended December 31, 2004. The stock based compensation expense for 2005 resulted from the expensing of the stock options for consultants on straight-line bases using the Black-Scholes option-pricing model. A total stock-base compensation expense from incorporation July 16, 2004 to December 31, 2005 was $78,589.

Employee and director stock options are accounted for using the intrinsic value method in accordance with Accounting Principles Board Opinion No. 25, “Accountingfor Stock Issued to Employees,” and related interpretations, and provide only a pro forma disclosures of net income (loss) as if a fair value based method had been applied in measuring compensation expense.

Geophysical and geological expense.Geophysical and geological expense for the year ended December 31, 2005 were $256,484 and nil for the period ended December 31, 2004. Under the successful-efforts method, costs such as geological and geophysical, exploratory dry holes and delay rentals are expensed as incurred. The costs in 2005 related to the expensing of acquisition costs of seismic data as well as the expensing of land deposits, which had expired. Total geophysical and geological expenses from incorporation July 16, 2004 to December 31, 2005 were $256,484.

Depletion, depreciation expense.Depletion and depreciation expense was $4,265,162 for the twelve months ending December 31, 2005 and $479,702 for the period ending December 31, 2004. This increase was due to the depletion recorded in the current year and the impairment charge. Depletion was recorded in the third and fourth quarters of 2005 due commencement of production. In 2005 the company’s impairment charge related to properties located in Wyoming and North Dakota. This impairment is a result of unsuccessful work programs and production evaluation work performed during 2005. The impairment equals the excess of the aggregate carrying value of PP&E over the discounted (10%) cash flows, which are expected to result from the Company’s proved plus probable reserves from these fields. The company also recorded impairment in 2005 when it terminated operations in the Fiddler Creek area and abandoned any further plans for development in the area. Impairment ($472,172) was a recorded for 2004 for the work programs and production evaluation work performed on the Cut Bank property that resulted in no commercial quantities of oil. We have abandoned all planned activities in this prospect. Total depletion and depreciation expenses from incorporation July 16, 2004 to December 31, 2005 were $4,744,864.


*Year ended to December 31, 2005 Compared to Year Ended December 31, 2004*
			% of					% of		Percentage
Year Ended December 31,	2005		revenue			2004		revenue		Increase

Depletion, depreciation expense	$	4,265,162		498.9	%	$	479,702		—		100	%

Depletion, depreciation expense per BOE:	$	276.08					—		—

Period from incorporation on July 16, 2004 to December 31, 2005


			% of
Incorporation July 16, 2004 to December 31, 2005.			revenue

Depletion, depreciation expense	$	4,744,864		555.0	%

Depletion, depreciation expense per BOE:	$	307.13

Accretion expense.As at December 31, 2005, the estimated present value of the Company’s asset retirement obligation was $78,642 based on estimated future cash requirements of $216,000, determined using a credit adjusted risk free interest rate of 8.5% over the economic life of the properties, an inflation rate of 2.0%, and an estimated life until repayment of 5-10 years. Accretion of $3,385 was recorded for the twelve months ending December 31, 2005. There was no accretion expense for the period ending December 31, 2004. Total accretion expense from incorporation July 16, 2004 to December 31, 2005 was $3,385.

Preferred dividend.In August 2004, we issued 1,950,000 shares of preferred stock, which pay a 10% annual dividend on a quarterly basis. In August 2005, all holders of our preferred stock converted to common stock following the effectiveness of our registration statement. Dividends have been paid up to the date of conversion. The cumulated preferred dividends for the year ended December 31, 2005 was $458,342 compared with $323,157 for the period ended December 31, 2004. Total preferred dividends paid from incorporation July 16, 2004 to December 31, 2005 were $781,499.

Income taxes.Due to the loss, the company did not pay any income taxes in the period ended December 31, 2004 and December 31, 2005.


	2004			2005			Cumulative
	$			$			$

Loss for the period before income taxes		(701,132	)		(5,814,009	)		(6,515,141	)
Effective tax rate		39	%		39	%		39	%

Expected income tax recovery		(273,442	)		(2,424,463	)		(2,540,905	)
Deferred tax asset valuation allowance		273,442			2,424,463			2,540,905

Income tax benefit		—			—			—

Earnings (Loss).Both the loss from operations and the net loss are presented below.


*Year ended to December 31, 2005 Compared to Year Ended December 31, 2004*
				% of						% of			Percentage
Year Ended December 31,	2005			revenue			2004			revenue			Increase
	$						$

Loss from operations		(5,814,009	)		(680.1	%)		(701,132	)		100	%		(129.2	%)
Income taxes		—			—			—			—			—

Net loss		(5,814,009	)		(680.1	%)		(701,132	)		100	%		(129.2	%)

Loss from operations per BOE		(376.33	)		—			—			—			—

Per share information

Loss from operations per Share
Net loss per share		(2.97	)					(4.10	)
Average number of shares outstanding		2,111,351			—			250,000			—

Period from incorporation on July 16, 2004 to December 31, 2005


				% of
Incorporation July 16, 2004 to December 31, 2005.				revenue
	$

Loss from operations		(6,515,141	)		(762.1	%)
Income taxes		—			—

Net loss		(6,515,141	)		(762.1	%)

Loss from operations per BOE		(421.71	)		—

Per share information

Loss from operations per Share
Net loss per share		(4.88	)
Average number of shares outstanding		1,494,620			—

Funds flow from operations.It is management’s view that funds flow from operations is a useful measure of performance and a good benchmark when comparing results from year to year or quarter to quarter. Funds flow from operations is a non-GAAP measure, reconciled with GAAP net earnings in the table below.


*Year ended to December 31, 2005 Compared to Year Ended December 31, 2004*
Year ended December 31,				2004

Net loss	($	5,814,009	)	($	701,132	)
Add back Stock based compensation	$	78,589			—
Geophysical and geological	$	256,484			—
Depletion and deprecation	$	4,265,162		$	479,702
Accretion	$	3,385			—


Funds flow from Operations	($	1,210,389	)	($	221,430	)

Funds flow from operations as a percentage of production revenue		(141.5	%)		—
Funds flow from operations per BOE	($	78.34	)		—

Per share information
Funds flow from operations per share	($	0.57	)		—
Average number of shares outstanding		2,111,351			250,000

Period from incorporation on July 16, 2004 to December 31, 2005


Incorporation July 16, 2004 to December 31, 2005.

Net loss	($	6,515,141	)
Add back
Stock based compensation	$	78,589
Geophysical and geological	$	256,484
Depletion and deprecation	$	4,744,864
Accretion	$	3,385


Funds flow from Operations	($	1,431,819	)

Funds flow from operations as a percentage of production revenue		(167.5	%)
Funds flow from operations per BOE	($	92.68	)

Per share information
Funds flow from operations per share	($	0.96	)
Average number of shares outstanding		1,494,620

Reserves

JMG had its reserves evaluated by independent engineers. JMG’s 2005 reserves were independently evaluated, as at December 31, 2005 by DeGolyer and Mac Naughton Canada Limited.

All of the Corporation’s properties, reserves and production are located in the United States in North Dakota and Wyoming. All dollar amounts in this Statement are in the currency of the United States. The Corporation’s reserves consist of light crude oil only.

Constant Prices and Costs

The following tables detail the aggregate gross and net reserves of the Corporation as at December 31, 2005 using constant prices and costs, and the aggregate net present value of future net revenue attributable to the reserves estimated using constant prices and costs, calculated without discount and using discount rates of 5%, 10%, 15% and 20%.


	Light Crude Oil
	Gross		Net
Reserves Category	(bbl)		(bbl)

PROVED
Developed Producing		62,216		53,907
Developed Non-Producing		9,153		7,749
Undeveloped		—		—


TOTAL PROVED		71,369		61,656

PROBABLE		590,030		515,369


TOTAL PROVED PLUS PROBABLE		661,339		577,025

Net Present Values of Future Net Revenues
Constant Prices and Costs
as at December 31, 2005


	Before and After Income Taxes Discounted at (% / year)
	0%		5%		10%		15%		20%
Reserves Category	(US$thousands)		(US$thousands)		(US$thousands)		(US$thousands)		(US$thousands)

PROVED
Developed Producing		1,548		1,416		1,307		1,216		1,139
Developed Non-Producing		172		156		142		131		120
Undeveloped		—		—		—		—		—


TOTAL PROVED		1,720		1,572		1,449		1,347		1,259

PROBABLE		9,256		6,625		4,870		3,622		2,697


TOTAL PROVED PLUS PROBABLE		10,976		8,197		6,319		4,969		3,956

The following table summarizes the Corporation’s interests in oil wells as at December 31, 2005:

Producing and Non-producing Wells
as at December 31, 2005


	North Dakota				Wyoming				Total
	Gross		Net		Gross		Net		Gross		Net

Oil Wells
Producing		3		2.04		2		.8		5		2.84
Non-Producing		1		.12		—		—		1		1.2

Capital Expenditures

Capital expenditures for the year ended December 31, 2005 were $15,918,765, net of capital accrual and $1,971,199 for the period ended December 31, 2004. For period from incorporation July 16, 2004 to December 31, 2005, the capital expenditures net of the capital accrual were $17,889,964. The expenditures were as follows:


				Period from the			Period from the
				date of			date of
	For the twelve month			incorporation			incorporation
	period ended			July 16, 2004 to			July 16, 2004 to
	December 31, 2005			December 31, 2004			December 31, 2005

Property Acquisitions	$	5,719,929		$	136,760		$	5,856,689
Drilling Exploration	$	11,302,720		$	1,916,617		$	13,219,339
Other Assets	$	106,835		$	120,482		$	227,317
Reclassification of capital accrual	($	1,210,809	)	($	202,660	)	($	1,413,469	)

	$	15,918,765		$	1,971,199		$	17,889,874

Liquidity and capital resources

Cash flows and capital expenditures

At December 31, 2005, we had $1,150,965 in cash and cash equivalents. Since our incorporation, we have financed our operating cash flow needs through private and public offerings of equity securities.

Upon the closing of our initial public offering on August 3, 2005, the Company issued 2,185,000 shares of common stock at a price of $5.00 and 2,185,000 warrants at a price of $0.10 for gross proceeds of $11,143,500.

We have no plans for any future issues of equity securities other than in conjunction with the exercise of outstanding warrants, and pursuant to our employee equity compensation plan. Any additional exploration activities are dependent upon the exercise of our outstanding warrants, which are summarized in the table below. In the event funds from the exercise of warrants are unavailable, we will delay our exploration activities until alternative sources of capital such as production revenue and farm out agreements on our properties or sale of our properties. The 2,185,000 warrants from the initial public offering are trading on the Archipelago Exchange under the symbol (JMG+). The warrants issued with the preferred shares 1,950,000 at $4.25 and 487,500 at $6.00 are not trading and were outstanding upon the closing of our initial public offering on August 3, 2005.


	Number
	of warrants		Exercise		Maximum
Warrant summary as of December 31, 2005.	outstanding		price		proceeds

Warrants issued in the preferred stock private placement		378,187	$	6.00	$	2,269,122
Warrants issued upon conversion of preferred stock		1,777,500		4.25	$	7,554,375
Warrants issued our initial public offering		1,854,235		5.00	$	9,271,175

		4,009,922	$	4.25-$6.00	$	19,094,672

Cash flow used in operations.Cash utilized by operating activities was $1,5,99,751 for the twelve months ended December 31, 2005. The use of cash was principally attributable to the net losses for the twelve-month period ending December 31, 2005 of $5,814,009. The cash flow was further reduced by the increase in accounts receivable of $508,601 offset by the reduction in prepaid expenses and deposits of $70,186. In addition, an increase in accounts payable of $382,917 for the twelve month period ending December 31,2005 resulted in a positive impact in cash flow used in operations. The depreciation and depletion and accretion were $4,268,547 for the twelve-month period ending December 31, 2005. The stock-based compensation was $78,589 for the period ending December 31, 2005.

Cash flow decreased due to the reduction in Due to Related Party by $4,164 for the twelve-month period ended December 31, 2005 and in “Due to JED Oil” by $89,899 for twelve-month period ending December 31, 2005.

Cash utilized by operating activities was $1,780,298 for the period from incorporation on July 16, 2004 to December 31, 2005. The use of cash was principally attributable to the net loss for the period of $6,515,141 decreased by the change in accounts receivable of $508,601 and prepaid expenses of $34,701. This is offset by the increase in accounts payable of $252,166 and due to JED Oil Inc of $286,956.

Cash flow used in investing activitiesCash utilized for the twelve-month period ended December 31, 2005 it was $14,957,516. Cash utilized in investing activities was $18,478,715 for the period from incorporation on July 16, 2004 to December 31, 2005 and was principally attributable to $17,889,964 in property and equipment purchased for our exploration prospects which included the following: the Hooligan Draw prospect of $1,517,679, the Cut Bank prospect of $416,299, the Fiddler Creek prospect of $163,800, the Bakken prospect $3,071,996 the Rindal prospect $3,508,562, the two Candak prospects $4,696,907, and $5,229,159 invested in connection with a farm-in agreement and direct purchase of acreage for several prospects in the Bakken Zone of North Dakota which comprised our Candak prospect, Myrtle Beach prospect and Bluffton prospects. In November 2004, we loaned Fellows Energy $1,500,000, with interest at a rate of 18% per annum and a fixed and specific charge on all the assets provided as collateral. The promissory note was due and payable in two installments: the first installment of $750,000 plus accrued interest was received February 2005, and the second, for the remaining balance and all accrued and unpaid interest thereon, was due April 30, 2005. The first installment has been paid, including accrued interest to date. In May 2005, we accepted the remaining 50% working interest in the contracted lands we did not already own as payment in full on the final installment of the note due from Fellows Energy, including accrued interest to date. We granted Fellows an option through June 30, 2005 to reacquire an undivided 50% interest in the exploration and development lands for $391,249. The option was exercised on June 28, 2005.

Cash flow used in financing activities.Cash provided by financing activities was $ $12,670,129 for the twelve-month period ended December 31, 2005 this was attributable to the initial public offering and the payment of preferred dividends during the period. We realized net proceeds of $10,282,246 from the initial public offering. Further warrants were exercised during the period for $3,042,828 and share issue costs were $861,254. Cash flow for financing was further offset by $654,945 in preferred dividend payments for the twelve-month period ended December 31, 2005.

Cash provided by financing activities was $21,340,675 for the period from incorporation on July 16, 2004 to December 31, 2005 and was attributable to two private placements completed in 2004 and the initial public offering on August 3, 2005. We realized $1,000,000 from the sale of common stock to JED. We realized $7,797,100 from the sale of 1,950,000 units consisting of preferred stock and warrants. Upon the closing of our initial public offering on August 3, 2005, the Company issued 2,185,000 shares of common stock at a price of $5.00 and 2,185,000 warrants at a price of $0.10 for net proceeds of $10,282,246. We have warrants outstanding exercisable into shares of our common stock at prices ranging from $4.25 to $6.00 per share, which expire in one to one and a half years from the date of our initial offering. These sources of financing were offset by $781,499 in preferred dividends paid during the period. All holders of preferred stock converted their preferred stock in common stock following the effectiveness of our registration statement. Dividends have been paid up to the date of conversion.

Critical accounting estimates

In the preparation of the financial statements, it was necessary for JMG to make certain estimates that were critical to determining our assets, liabilities and net income. None of these estimates affect the determination of cash flow but do have a significant impact in the determination of net income. The most critical of these estimates is the reserves estimations and the resulting effect on various income statement and balance sheet measures.

JMG engaged an independent engineering firm to evaluate 100% of our oil and natural gas reserves and prepare a report thereon. Their report was utilized in the calculations of depletion and depreciation expense. The estimation of the reserve volumes and future net revenues set out in the report is complex and subject to uncertainties and interpretations. Judgments are based upon engineering data, projected future rates of production,

forecasts of commodity prices, and the timing of future expenditures. Inevitably the estimates of reserve volumes and future net revenues will vary over time as new data becomes available and estimates of future net revenues do not represent fair market value.

The following significant accounting policies outline the major policies involving critical estimates.

Successful-efforts method of accounting

Our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful-efforts method and the full-cost method. Under the successful-efforts method, costs such as geological and geophysical, exploratory dry holes and delay rentals are expensed as incurred whereas under the full-cost method these types of charges are capitalized.

We retroactively adopted the successful-efforts method of accounting for our oil and natural gas properties. Previously, we followed the full-cost method of accounting. As no depletion was previously recorded under the full-cost method, no adjustments to our financial statements are required to reflect the change.

Under the successful-efforts method of accounting, all costs of property acquisitions and drilling of exploratory wells are initially capitalized. If a well is unsuccessful, the capitalized costs of drilling the well, net of any salvage value, are charged to expense. If a well finds oil and natural gas reserves that cannot be classified as proved within a year after discovery, the well is assumed to be impaired and the capitalized costs of drilling the well, net of any salvage value, are charged to expense. The capitalized costs of unproven properties are periodically assessed to determine whether their value has been impaired below the capitalized cost, and if such impairment is indicated, a loss is recognized. We consider such factors as exploratory results, future drilling plans and lease expiration terms when assessing unproved properties for impairment. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable from estimated future net revenues. The impairment provision is measured as the excess of carrying value over the fair value. Fair value is defined as the present value of the estimated future net revenue from total proved and risked-adjusted probable reserves over the economic life of the reserves, based on year end oil and gas prices, consistent with price and cost assumptions used for acquisition evaluations.

Geological and geophysical costs and costs of retaining undeveloped properties are expensed as incurred. Expenditures for maintenance and repairs are charged to expense, and renewals and betterments are capitalized. Upon disposal, the asset and related accumulated depreciation and depletion are removed from the accounts, and any resulting gain or loss is reflected currently in income or loss.

Costs of development dry holes and proved leaseholds are depleted on the unit-of-production method using proved developed reserves on a field basis. The depreciation of capitalized production equipment, drilling costs and asset retirement obligations is based on the unit-of-production method using proved developed reserves on a field basis.

To economically evaluate our future proved oil and natural gas reserves, if any, independent engineers must make a number of assumptions, estimates and judgments that they believe to be reasonable based upon their expertise and professional guidelines. Were the independent engineers to use differing assumptions, estimates and judgments, then our financial condition and results of operations could be affected. We would have lower revenues in the event revised assumptions, estimates and judgments resulted in lower reserve estimates, since the depletion and depreciation rate would then be higher. A write-down of excess carrying value also might be required. Similarly, we would have higher revenues and net profits in the event the revised assumptions, estimates and judgments resulted in higher reserve estimates, since the depletion and depreciation rate would then be lower.

Proved Oil and Gas Reserves

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. The estimated

quantities of proved crude oil, natural gas liquids and natural gas are derived from geological and engineering data that demonstrate with reasonable certainty the amounts that can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserves are considered proved if they can be produced economically as demonstrated by either actual production or conclusive formation tests. The oil and gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the Company’s plans.

Long-lived assets

When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and depletion. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.

Asset Retirement Obligations

We have adopted SFAS No. 143,“Accounting for Asset Retirement Obligations”from inception. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the properties. These costs are capitalized as part of the cost of the related asset and amortized. The associated liability is classified as a long-term liability and is adjusted when circumstances change and for the accretion of expense which is recorded as a component of depreciation and depletion.

Stock-based compensation

We account for employee and director stock options using the intrinsic value method in accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, and provide pro forma disclosures of net income (loss) as if a fair value based method had been applied in measuring compensation expense. Under the intrinsic value method, no stock-based compensation expense for stock options issued is reflected in the statement of operations as all grants under our stock option plan have an exercise price equal to the fair market value of the underlying common stock on the date of grant.

The Corporation accounts for the stock option granted to consultants using SFAS No. 123. Under these provisions, the cost of options granted consultants are charged to net loss with a corresponding increase in additional paid-in capital, based on an estimate of the fair value determined using the Black-Scholes option-pricing model.

We determine the fair value of our common stock by evaluating a number of factors, including our financial condition and business prospects, our stage of development and achievement of key technical and business milestones, private and public market conditions, the terms of our private financings and the valuations of similar companies in our industry.

Contingencies

In the future, we may be subject to adverse proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We will be required to assess the likelihood of any adverse judgments or outcomes of these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters

Contractual obligations and commitments

Our exploration prospects have several phases of possible development. Costs cannot be estimated at this time, as they are dependent upon the results of the exploration activities. In the event the results of the initial exploration are positive, our investment in subsequent exploration phases could be substantial. In the event the results of the initial exploration are not positive, there may be no further expenditures on the prospect.

Related Party Transactions

On August 1, 2004 the Company entered into a technical services agreement with JED Oil Inc. (“JED”). Under the Agreement, JED provides all required personnel, office space and equipment, at standard industry rates for similar services. Transactions during the twelve-month period ending December 31, 2005 were as follows:

JED paid on behalf of the Company a total of $442,667, $139,838 and $582,505 respectively for the twelve month periods ending December 31, 2005, the period from incorporation July 16, 2004 to December 31, 2004 and for the period from incorporation to December 31, 2005, for general and administrative services and capital related expenditures, and

In consideration for the assignment of JED’s interests in certain oil and gas properties, JED charged the Company for drilling and other costs related to those properties in the amount of $85,085, $1,467,012 and $1,552,097 respectively for the twelve month periods ending December 31, 2005, the period from incorporation July 16, 2004 to December 31, 2004 and for the period from incorporation to December 31, 2005.

All amounts are due and payable on receipt, as at December 31, 2005, $286,956 (2004 - $376,855) was due and payable. The amount was paid in full in early 2006.

General and administrative expenses for the twelve months ended December 31, 2005 include $46,180 paid to the previous Chief Financial Officer of the Company for consulting services related to the preparation of the Company’s registration statement.

Recent accounting pronouncements

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 123 (revised 2004), “Share-Based Payment,” which is a revision of FASB Statement No. 123, “Accounting for Stock-Based Compensation.” Statement 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends FASB Statement No. 95, “Statement of Cash Flows.” Generally, the approach in Statement 123(R) is similar to the approach described in Statement 123. However, Statement 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

Statement 123(R) must be adopted by small-business issuers at the beginning of the first interim or annual period beginning after December 15, 2005. Early adoption will be permitted in periods in which financial statements have not yet been issued. We expect to adopt Statement 123(R) on January 1, 2006.

Statement 123(R) permits public companies to adopt its requirements using one of two methods:

	•		A modified prospective method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of Statement 123 for all awards granted to employees prior to the effective date of Statement 123(R) that remain unvested on the effective date; or

	•		A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under Statement 123 for purposes of pro forma disclosures either for (a) all periods presented or (b) prior interim periods of the year of adoption.

We plan to adopt Statement 123 using the modified-prospective method.

As permitted by Statement 123, we currently account for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognize no compensation cost for employee stock options. Accordingly, the adoption of Statement 123(R)’s fair value method will have a significant impact on our results of operations, although it will have no impact on our overall financial position. The impact of adoption of Statement 123(R) cannot be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had we adopted Statement 123(R) in prior periods, the impact of that standard would have approximated the impact of Statement 123 as described in note 4(c) to our financial statements.

Outlook and Proposed Transactions

The year ended December 31, 2005 was the start up period for JMG and should be viewed as such. The focus in 2005 was to assemble a significant land position with initial drilling to commencing in the latter part of 2005 carrying into 2006. The majority of JMG’s drilling has taken place in early 2006 or the latter part of the fourth quarter of 2005. The Company has begun generating production volumes starting in the third quarter of 2005.

JMG and JED announced in January 2006 that they are pursuing a possible merger in which JMG would merge with a wholly owned subsidiary of JED in the U.S., and JMG’s securities would be exchanged for securities of JED on the basis of two-thirds of a JED common share for each JMG common share.

Item 7A:Quantitative And Qualitative Disclosures About Market Risk

We are exposed to all of the normal market risks inherent within the oil and natural gas industry, including commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We plan to manage our operations in a manner intended to minimize our exposure to such market risks.

Credit Risk.Credit risk is the risk of loss resulting from non-performance of contractual obligations by a customer or joint venture partner. A substantial portion of our accounts receivable are expected to be with customers in the energy industry and are subject to normal industry credit risk. We intend to assess the financial strength of our customers and joint venture partners through regular credit reviews in order to minimize the risk of non-payment.

Market Risk.We are exposed to market risk from changes in currency exchange rates. As JED and Enterra are based in Canada, we may be adversely affected by changes in the exchange rate between U.S. and Canadian dollars as most of our operating expenses, drilling expenses and general overhead expenses will be billed by JED and Enterra in Canadian dollars. The price we will receive for oil and natural gas production from operations in Canada, if any, will be based on a benchmark expressed in U.S. dollars, which is the standard for the oil and natural gas industry worldwide. Changes to the exchange rate between U.S. and Canadian dollars can adversely affect us. When the value of the U.S. dollar increases, we will receive higher revenue from any Canadian prospects and when the value of the U.S. dollar declines, we will receive lower revenue from any Canadian prospects on the same amount of production sold at the same prices.

Interest Rate Risk.Interest rate risk will exist principally with respect to any future indebtedness that bears interest at floating rates. At September 30, 2005, we had no indebtedness and do not contemplate utilizing indebtedness as a means of financing our exploration activities.

Item 8: Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

JMG Exploration Inc.
Financial Statements


	Page
Reports of Ernst & Young, LLP, , Independent Registered Public Accounting Firm		36
Consolidated Balance Sheets as of December 31, 2005 and 2004		38
Consolidated Statements of Operations for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		39
Consolidated Statements of Cash Flows for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		40
Consolidated Statements of Shareholders’ Equity for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		41
Consolidated Statements of Comprehensive Loss for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		42
Notes to Consolidated Financial Statements		43- 53

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of JMG Exploration, Inc.

We have audited the accompanying consolidated balance sheets of JMG Exploration, Inc., a development stage enterprise (the “Company”) as of December 31, 2005 and 2004 and the related consolidated statements of operations and deficit, comprehensive income, changes in stockholders’ equity and cash flows for the year ended December 31, 2005 and for the period from inception on July 16, 2004 to December 31, 2004. 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of JMG Exploration, Inc. and subsidiary at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for the year ended December 31, 2005 and for the period from inception on July 16, 2004 to December 31, 2004, in conformity with U.S. generally accepted accounting principles.


Calgary, Canada
March 23, 2006		/s/ “Ernst & Young LLP”

Consolidated Financial Statements

JMG Exploration, Inc. (a development stage enterprise)
December 31, 2005

JMG Exploration, Inc.
A Development Stage Enterprise

CONSOLIDATED BALANCE SHEETS

(In United States Dollars)


	2005			2004
As at December 31	$			$

ASSETS
Current
Cash and cash equivalents		1,150,965			5,040,800
Accounts receivable		1,284,474			—
Loan receivable[note 3]		—			1,179,205
Prepaid expenses and deposits		34,701			104,887

		2,470,140			6,324,892

Other assets[note 5]		230,000			50,000
Property and equipment[notes 4 and 8]		15,073,039			2,054,157

		17,773,179			8,429,049


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current
Accounts payable		845,507			58,616
Accrued liabilities		1,660,648			20,000
Dividends payable		—			196,603
Due to JED Oil Inc.[note 8]		286,956			376,855
Due to related party		—			4,164

		2,793,111			656,238

Asset retirement obligations[note 9]		78,642			—

		2,871,753			656,238

Stockholders’ equity
Share capital[note 6]
Common stock — $.001 par value; 25,000,000 shares authorized; 4,997,578 shares issued and outstanding at December 31, 2005.		4,997			250
Preferred stock — $.001 par value; 10,000,000 shares authorized; 0 shares issued and outstanding at December 31, 2005 and 1,950,000 outstanding December 31, 2004.		—			1,950
Additional paid-in capital		20,044,296			8,790,025
Share purchase warrants		2,151,470			4,875
Deficit accumulated during the development stage		(7,296,640	)		(1,024,289	)
Accumulated other comprehensive earnings		(2,697	)		—

		14,901,426			7,772,811

		17,773,179			8,429,049

The accompanying notes are an integral part of these audited consolidated financial statements.

JMG Exploration, Inc.
A Development Stage Enterprise

CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
(In United States Dollars)


				Period from the date			Period from the date
	Twelve month			of incorporation on			of incorporation on
	period ended			July 16, 2004 to			July 16, 2004 to
For the	December 31,			December 31,			December 31,
	2005			2004			2005
	$			$			$

Revenue
Petroleum and natural gas revenue		854,864			—			854,864
Royalties		(227,404	)		—			(227,404	)

		627,460						627,460

Interest		120,461			64,630			185,091

		747,921			64,630			812,551


Expenses
Production		189,598			—			189,598
General and administrative[note 8]		1,768,712			286,060			2,054,772
Stock-based compensation[note 6]		78,589			—			78,589
Geophysical and Geological		256,484			—			256,484
Depletion, depreciation[note 4]		4,265,162			479,702			4,744,864
Accretion on asset retirement obligation[note 9]		3,385			—			3,385

		6,561,930			765,762			7,327,692


Net loss for the period[note 7]		(5,814,009	)		(701,132	)		(6,515,141	)
Less: cumulative preferred dividends		(458,342	)		(323,157	)		(781,499	)

Net loss applicable to common shareholders		(6,272,351	)		(1,024,289	)		(7,296,640	)

Deficit, beginning of period		(1,024,289	)		—			—


Deficit, end of period		(7,296,640	)		(1,024,289	)		(7,296,640	)


Basic weighted average shares outstanding[note 6]		2,111,351			250,000			1,494,620


Net loss for the period per share, basic and diluted[note 6]		(2.97	)		(4.10	)		(4.88	)

The accompanying notes are an integral part of these audited consolidated financial statements.

JMG Exploration, Inc.
A Development Stage Enterprise

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In United States Dollars)


				Period from the
	Twelve			date of			Period from the
	month			incorporation			date of
	period ended			on July 16,			incorporation on
	December			2004 to			July 16, 2004 to
For the	31,			December 31,			December 31,
	2005			2004			2005
	$			$			$

OPERATIONS
Net loss for the period		(5,814,009	)		(701,132	)		(6,515,141	)
Adjustments to reconcile net loss to cash flows from operating activities:
Stock-based compensation		78,589			—			78,589
Depletion and depreciation and accretion		4,268,547			479,702			4,748,249
Other changes:
Increase in accounts receivable		(508,601	)		—			(508,601	)
Decrease( Increase) in prepaid expenses and deposits		70,186			(104,887	)		(34,701	)
Increase in accounts payable and accrued liabilities		382,917			82,780			252,166
Decrease (increase) in due to JED Oil Inc.		(89,899	)		170,031			286,956
Decrease in due to related party		(4,164	)		4,164			—
Decrease (increase) in accrued interest on Loan receivable		16,683			(39,205	)		(15,815	)

Cash used in operating activities		(1,599,751	)		(108,547	)		(1,708,298	)

INVESTING
Repayment (advance) of loan receivable		750,000			(1,500,000	)		(750,000	)
Proceeds on disposition of property		391,249			—			391,249
Purchase of property and equipment		(15,918,765	)		(1,971,199	)		(17,889,964	)
Increase in other assets		(180,000	)		(50,000	)		(230,000	)

Cash used in investing activities		(14,957,516	)		(3,521,199	)		(18,478,715	)

FINANCING
Issue of common shares, net of issue costs		11,178,479			1,000,000			19,970,704
Issue of preferred shares		—			7,797,100			—
Issue of share purchase warrants		2,146,595						2,151,470
Preferred share dividends		(654,945	)		(126,554	)		(781,499	)

Cash provided by financing activities		12,670,129			8,670,546			21,340,675

Effect of foreign exchange on cash and cash equivalents		(2,697	)		—			(2,697	)


Net (decrease) increase in cash and cash equivalents		(3,889,835	)		5,040,800			1,150,965

Cash and cash equivalents, beginning of period		5,040,800			—			—


Cash and cash equivalents, end of period		1,150,965			5,040,800			1,150,965

The accompanying notes are an integral part of these audited consolidated financial statements.

JMG Exploration, Inc.
A Development Stage Enterprise

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

(In United States Dollars)


	Shares			Total
	#			$

Common stock, $.001 par value:
Balance at July 16, 2004 and December 31, 2004		250,000			1,000,000
Preferred shares converted to common stock		1,950,000			7,792,225
Issuance of common stock, stock issued for cash pursuant to initial public offering		2,185,000			11,143,500
Warrants exercised for common stock		612,578			3,042,828
Share issue costs		—			(861,254	)
Portion of proceeds attributed to share purchase warrants		—			(2,146,595	)

Balance at December 31, 2005		4,997,578			19,970,704


Additional paid in capital
Balance, July 16, 2004 (inception) and December 31, 2004					—
Stock-based compensation					78,589

Balance at December 31, 2005		—			78,589


Preferred stock, $.001 par value:
Balance at December 31, 2004		1,950,000			7,792,225
Preferred shares converted to common stock		(1,950,000	)		(7,792,225	)

Balance at December 31, 2005		—			—


Share purchase warrants:
Balance at December 31, 2004		487,500			4,875
Share purchase warrants: issued pursuant to initial public offering $5.00		2,185,000			693,866
Share purchase warrants: issued pursuant conversion preferred shares $4.25		1,950,000			1,816,766
Warrants exercised for common stock		(612,578	)		(364,037	)

Balance at December 31, 2005		4,009,922			2,151,470

Deficit:
Balance at beginning of period July 16, 2004		—			—
Net loss for the period to December 31, 2004		—			(701,132	)
Preferred share dividends		—			(323,157	)

Balance at December 31, 2004		—			(1,024,289	)
Net loss for the twelve-month period ended December 31, 2005		—			(5,814,009	)
Preferred share dividends		—			(458,342	)

Balance at December 31, 2005		—			(7,296,640	)


Accumulated other comprehensive income
Balance at beginning of period July 16, 2004		—			—
Balance December 31, 2004		—			—
Foreign exchange translation adjustment		—			(2,697	)

Balance at December 31, 2004		—			(2,697	)

Total stockholders equity at December 31, 2005		—			(14,901,426	)

The accompanying notes are an integral part of these audited consolidated financial statements.

JMG Exploration, Inc.
A Development Stage Enterprise

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In United States Dollars)


				For the period			For the period
	For the twelve			from the date of			from the date of
	month period			incorporation on			incorporation on
	ended			July 16, 2004 to			July 16, 2004 to
	December 31,			December 31,			December 31,
	2005			2004			2005
	$			$			$

Net loss for the period		(5,814,009	)		(701,132	)		(6,515,141	)

Other comprehensive income:
Foreign exchange translation adjustment		(2,697	)		—			(2,697	)

Comprehensive loss for the period		(5,816,706	)		(701,132	)		(6,517,838	)

The accompanying notes are an integral part of these audited consolidated financial statements.

1. INCORPORATION AND NATURE OF OPERATIONS

JMG Exploration, Inc. (“JMG” or the “Company”) is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids in Canada and the United States. Currently, all of the Company’s proved reserves are located in the United States.

The Company’s future financial condition and results of operations will depend upon prices received for its oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to change in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.

JMG was incorporated with nominal share capital under the laws of the State of Nevada on July 16, 2004 and commenced operations in August 2004.

2. SIGNIFICANT ACCOUNTING POLICIES

These financial statements have been prepared by management in accordance with accounting principles generally accepted in the United States.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

a) Principles of consolidation

These consolidated financial statements include the accounts of the Company’s wholly owned legal subsidiary, JMG Canada Ltd., incorporated under the laws of Alberta on August 20, 2004. All inter-company accounts and transactions have been eliminated.

b) Cash and cash equivalents

Cash and cash equivalents consist of cash on hand and balances invested in short-term securities with original maturities of less than 90 days. For the period ended December 31, 2005, the average effective interest rate earned on cash equivalent balances was 0.4%. As at December 31, 2005, the Company had $1,043,331 in cash and $107,634 in short-term securities .

c) Foreign currency translation

As the majority of the Company’s operating activities are in the United States, the Company uses the United States dollar as its functional currency. The Company’s Canadian subsidiary is translated for financial statement reporting purposes into United States dollars using the current rate method. Under this method, assets and liabilities are translated at the period-end rate of exchange and all revenue and expense items are translated at the average rate of exchange for the period. Exchange differences arising on translation are classified in a separate component of stockholders equity.

d) Revenue recognition

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and if the collection of the revenue is probable.

e) Joint operations

Substantially all of the Company’s petroleum and natural gas development activities are conducted jointly with others. These financial statements reflect only the Company’s proportionate interest in such activities.

f) Property and equipment

The Company is engaged in the exploration for and development of oil and natural gas in the United States and Canada. The Company has adopted the successful efforts method of accounting for its oil and natural gas activities.

Under the successful efforts method of accounting, all costs of property acquisitions and drilling of exploratory wells are initially capitalized. If a well is unsuccessful, the capitalized costs of drilling the well, net of any salvage value, are charged to expense. If a well finds oil and natural gas reserves that cannot be classified as proved within a year after discovery, the well is assumed to be impaired and the capitalized costs of drilling the well, net of any salvage value, are charged to expense. The capitalized costs of unproven properties are periodically assessed to determine whether their value has been impaired below the capitalized cost, and if such impairment is indicated, a loss is recognized. The Company considers such factors as exploratory results, future drilling plans and lease expiration terms when assessing unproved properties for impairment. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable from estimated future net revenues. The impairment provision is measured as the excess of carrying value over the fair value. Fair value is defined as the present value of the estimated future net revenue from total proved and risked-adjusted probable oil and gas reserves over the economic life of the reserves, based on the Company’s expectations of future oil and gas prices and costs, consistent with price and cost assumptions used for acquisition evaluations.

Other property and equipment are recorded at cost. Depreciation is provided using the straight-line method based over the estimated useful lives at a rate of 25 percent per annum.

g) Asset retirement obligations

The Company follows SFAS No 143. “Accounting for Asset Retirement Obligations”, which requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable, with a corresponding increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depreciated such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The Company’s asset retirement obligations are expected to relate primarily to the plugging and abandonment of petroleum and natural gas properties.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the petroleum and natural gas properties balance.

h) Measurement uncertainty

The amount recorded for depletion and depreciation of oil and gas properties, the provision for asset retirement obligations and the impairment calculation are based on estimates of gross proved reserves, production rates, commodity prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be significant.

i) Income taxes

The Company accounts for income taxes using the liability method, whereby deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities measured using enacted income tax rates and laws that are in effect when the differences are expected to reverse. Income tax expense for the period is the tax payable for the period and any change during the period in deferred tax assets and liabilities. A valuation allowance is provided to the extent that it is more likely than not that deferred tax assets will not be realized.

j) Other comprehensive income (loss)

Comprehensive income (loss) includes net loss and other comprehensive income (loss), which includes foreign currency translation gains or losses.

k) Stock-based compensation

The Company has a stock option plan under which employees; directors and consultants are eligible to receive grants. Consideration received on the exercise of stock options under the stock option plan is recorded as capital stock.

The Company accounts for the stock options granted to employees and qualifying non-employee directors under the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees”,and related interpretations. Under this method, no compensation expense is recorded for stock options granted when the exercise price is equal to or greater than the estimated market value of the common shares at the date of grant, unless the awards are subsequently modified. The Company also provides disclosure of the effect on net loss for the period and net loss per common share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-based Compensation”, as amended, to stock-based

The Company accounts for the stock option granted to consultants who do not qualify as employees using SFAS No. 123. Under these provisions, the cost of options granted to consultants is charged to net loss with a corresponding increase in additional paid-in capital, based on an estimate of the fair value determined using the Black-Scholes option-pricing model. For purposes of these awards, the grant date is the measurement date.

l) Net loss per share

The Company accounts for earnings/loss per share (“EPS”) in accordance with SFAS No. 128, “Earnings per Share.” Under SFAS No. 128, basic EPS is computed by dividing net loss attributable to common stockholders by the weighted average number of common shares outstanding without including any potentially dilutive securities. Diluted EPS is computed by dividing net loss by the weighted average number of common shares outstanding plus, when their effect is dilutive, common stock equivalents. The treasury stock method is used to determine the dilutive effect of the stock options and warrants. The treasury stock method assumes any proceeds obtained upon exercise of options would be used to purchase common shares at the average market price during the period. The effect of the exercise of warrants and stock options has been excluded since their effect is anti-dilutive.

m) Allowance for doubtful accounts

The Company considers amounts receivable to be fully collectible as recorded as of December 31, 2004 and 2005. Accordingly no allowance for doubtful accounts is required.

3. LOAN RECEIVABLE

On November 8, 2004, the Company entered into a Promissory Note with an unrelated industry partner (the “Borrower”), whereby the Company loaned the Borrower a total of $1,500,000. The terms of the loan agreement called for interest calculated at a rate of 18% per annum, and a fixed and specific charge on all the assets of the Borrower was provided as collateral. The Promissory Note was repayable in two installments; the first for $750,000 plus accrued interest of $81,750 was paid on February 22, 2005 and the second, for the entire remaining balance and all accrued and unpaid interest thereon, was due on April 30, 2005.

Effective May 1, 2005 the outstanding principal amount of the loan plus accrued interest was settled by the Company in exchange for the Borrower’s interest in certain exploration and development lands in Wyoming and Utah. In connection with the settlement agreement, the Company also granted the borrower an option to reacquire an undivided 50% interest in these lands for a payment of $391,249. The option was exercised on June 28, 2005. In conjunction with the settlement agreement, the Company’s previous commitment to spend $2,000,000 on drilling and completion of wells on these lands by November 7, 2005 was eliminated.

4. PROPERTY AND EQUIPMENT

During the twelve month period ended December 31, 2005, the Company recorded a total impairment provisions related to its oil properties of $3,773,062, as described below.

In May 2005, the Company terminated operations in the Fiddler Creek area and abandoned any further plans for development in the area. Accordingly, the Company recorded an impairment charge in the amount of $163,800 in the second quarter of 2005.

In June 2005, the Company sold equipment to a third party. This equipment had been previously written off as an impairment charge. The year-to-date net recovery was $54,413.

In December 31, 2005, the Company recorded an impairment provision of $3,663,675 related to properties located in Wyoming and North Dakota. This impairment is a result of unsuccessful work programs and production evaluation work performed during 2005. The impairment equals the excess of the aggregate carrying value of PP&E over its fair value.

The impairment charges have been included in depletion and depreciation expense in the accompanying statements of operations. Undeveloped land and other assets not related to petroleum and natural gas properties were excluded from the depletion calculation.


December 31, 2005
			Accumulated
			depletion,
	Cost		depreciation		Net book value
	$		$		$

Petroleum and natural gas properties		13,720,365		4,706,137		9,014,228

Undeveloped Land		5,868,691		—		5,868,691

Other assets		227,317		37,197		190,120

		19,816,373		4,743,334		15,073,039


December 31, 2004
			Accumulated
			depletion,
			depreciation and
	Cost		accretion		Net book value
	$		$		$

Petroleum and natural gas properties		2,053,378		472,172		1,941,206

Other assets		120,481		7,530		112,951

		2,173,859		479,702		2,054,157

5. OTHER ASSETS

The majority of other assets are bonds for oil and gas bond deposits in the states of North Dakota and Wyoming. These bonds provide coverage for operations conducted by or on behalf of the company. The bonds will be retained until all conditions of the bond have been fulfill or until a satisfactory replacement bond has been accepted.

6. SHARE CAPITAL

a) Authorized

The Company has authorized 25,000,000 common shares, par value $.001, and 10,000,000 preferred shares, par value $.001. As of December 31, 2005 there were 4,997,578 common shares issued and outstanding. Preferred shares were converted into common shares of the Company subsequent to Company’s initial public offering on August 3, 2005. No preferred shares are currently outstanding.

b) Issued and outstanding


							Additional
				Capital			Paid-in
				Stock			Capital			Total
	#			$			$			$

Common Stock, $.001 par value:
Balance, at July 16, 2004 and December 31, 2004		250,000			250			999,750			1,000,000
Preferred shares converted to common stock		1,950,000			1,950			7,790,275			7,792,225
Issued for cash, pursuant to initial public offering		2,185,000			2,185			11,141,315			11,143,500
Warrants exercised for common stock		612,578			612			3,042,216			3,042,828
Share Issue Costs								(861,254	)		(861,254	)
Portion of proceeds attributed to share purchase warrants								(2,146,595	)		(2,146,595	)

Balance at December 31, 2005		4,997,578			4,997			19,965,707			19,970,704


Preferred Stock
Balance, at July 16, 2004 and December 31, 2004		1,950,000			1,950			7,798,050			7,800,000
Preferred shares converted to common stock		(1,950,000	)		(1,950	)		(7,790,275	)		(7,792,225	)
Share issue costs, net of tax		—			—			(2,900	)		(2,900	)
Portion of proceeds attributed to share purchase warrants		—			—			(4,875	)		(4,875	)

Balance at December 31, 2005		—			—			—			—


Share Purchase Warrants
Balance, at July 16, 2004 and December 31, 2004		487,500			—			—			4,875
Issued pursuant to initial public offering		2,185,000			—			—			693,866
Issued pursuant to conversion of preferred shares		1,950,000			—			—			1,816,766
Warrants exercised for common stock		(612,578	)		—			—			(364,037	)

Balance at December 31, 2005		4,009,922			—			—			2,151,470


Additional paid in capital
Balance, July 16, 2004 (inception) and December 31, 2004								—
Stock-based compensation								78,589

Total December 31, 2005					4,997			20,044,296			22,122,174

c) Initial Public Offering

On August 3, 2005, the Company’s registration statement was declared effective by the Securities and Exchange Commission to register 2,185,000 units offered at $5.10 per unit to the stockholders of record of JED Oil Inc. as of February 1, 2005, and thereafter, to the extent not fully subscribed by the shareholders of JED, to the public. Each unit consisted of one share of common stock and one common stock purchase warrant to acquire one share of common stock

for $5.00 per share for a period of one year from the date of the prospectus. The units did not trade separately. Accordingly, the Company registered 4,370,000 shares of common stock underlying the 2,185,000 units of common stock, including 570,000 shares of common stock underlying the 285,000 units subject to the underwriter’s over allotment. The Company also registered 2,185,000 warrants underlying the units. Upon the closing of the initial public offering on August 3, 2005, the Company issued 2,185,000 shares of common stock at a price of $5.00 and 2,185,000 warrants at a price of $0.10 for gross proceeds of $11,143,500. The common stock and warrants underlying the units were listed and are trading separately.

The registration statement also registered the resale by the preferred stockholders of 1,950,000 shares of common stock. In August 2005 all holders of preferred stock converted their preferred stock into common stock and warrants to acquire common stock. The Company has also registered these 1,950,000 warrants to acquire common stock at $4.25 per share; and 487,500 warrants to acquire common stock for $6 per share.

d) Stock options

The Company has a stock option plan under which employees; directors and consultants are eligible to receive grants. As of December 31, 2005 479,250 shares were reserved for issuance under the plan. Options granted under the plan generally have a term of five years to expiry and vest immediately when issued to directors and generally vest as to one-third on each of the first, second and third anniversaries of the grant date for employees and consultants. The exercise price of each option equals the market value of the Company’s common stock on the date of grant. The following summarizes information concerning outstanding and exercisable stock options as of December 31, 2005:


				Weighted
				average exercise
	Number of			price
	options			$

Outstanding as at December 31, 2004		260,000			4.00
Granted — April 5, 2005		387,750			5.00
Granted — July 21, 2005		79,500			5.00
Granted — August 19, 2005		1,500			15.25
Granted — August 29, 2005		5,000			14.74
Granted — November 1, 2005		10,000			12.25
Cancelled		(260,000	)		4.00
Cancelled		(4,500	)		5.00

Options outstanding as at December 31, 2005		479,250

Exercisable as at December 31, 2005		250,000			5.00

Pro forma disclosure

The Company does not record compensation expense when stock options are issued to employees. Had compensation expense been determined based on the fair value of the options granted, net loss and net loss per share would have been increased to the pro forma amounts indicated below:


Twelve months ended
	As reported			Pro Forma
December 31, 2005	$			$

Net loss		(6,272,351	)		(6,485,985	)
Net loss per share, basic and diluted		(2.97	)		(3.07	)

The weighted average fair value of stock option grants in the period in the amount of $5.00 was estimated using the Black-Scholes option-pricing model with the following assumptions:


Risk-free interest rate (%)		4.3
Expected life (years)		5.0
Expected volatility (%)		10 to 50
Expected dividend yield (%)		Nil
Vesting period (years)		0 to 3

Prior to August 3, 2005 the Company was private. Accordingly the expected volatility of the Company’s stock options granted during the period prior to August 3, 2005 had been set at a rate of 10%. The 13,000 stock options granted after the Company became public were set with an expected volatility of 50%.

d) Loss per share

For the twelve-month period ended December 31, 2005 the weighted average number of common shares outstanding were 2,111,351. (2004 – December 31, 2004 weighted average number of common shares outstanding were 250,000). All of the Company’s outstanding stock options and warrants currently have an antidilutive effect on per common share amounts. These stock options and warrants could be dilutive in future periods.

7. INCOME TAXES

The Company provides deferred income taxes for differences between the tax reporting bases and the financial reporting bases of assets and liabilities. The Company follows the accounting procedures established by SFAS No. 109, “Accounting for Income Taxes.” The Company did not pay any income taxes in the period ended December 31, 2004 and December 31, 2005.

(a) Income tax expense (recovery)

The provision for income taxes recorded in the financial statements differs from the amount which would be obtained by applying the statutory income tax rate to the loss before tax as follows:


	2004			2005			Cumulative
	$			$			$

Loss for the period before income taxes		(701,132	)		(5,814,009	)		(6,515,141	)
Effective tax rate		39	%		39	%		39	%

Expected income tax recovery		(273,442	)		(2,267,463	)		(2,540,905	)
Deferred tax asset valuation allowance		273,442			2,267,463			2,540,905

Income tax benefit		—			—			—

(b) Deferred income taxes

The Company does not recognize the deferred income tax asset at this time because the realization of the asset is less likely than not. The components of the Company’s deferred income tax asset are as follows:

Deferred Tax Assets


	2004			2005
	$			$			Cumulative

Non-capital loss carry forward		340,805			1,303,797			1,644,602
Property Impairments		—			963,666			963,666

Total		340,805			2,267,463			2,608,268


Expense of Intangibles		(67,363	)		—			(67,363	)

Impairment		(273,442	)		(2,267,463	)		(2,540,905	)

The Company has non-capital losses for income tax purposes of approximately $4,216,927 which are available for application against future taxable income and which expire in 20 years. The non-capital loss carry forward was generated by intangible drilling costs that are deductible for U.S. income tax purposes creating a temporary difference for financial reporting purposes. The benefit associated with the non-capital loss carry forward will more likely than not go unrealized unless future exploration in the U.S. is successful. The deferred tax assets were generated by asset impairments, which will be realized, when the property is sold of otherwise disposed. Since the success of future exploration is indeterminable, the potential benefits resulting from these non-capital losses have not been recorded in the financial statements.

8. RELATED PARTY TRANSACTIONS

On August 1, 2004 the Company entered into a technical services agreement with JED Oil Inc. (“JED”). Under the Agreement, JED provides all required personnel, office space and equipment, at standard industry rates for similar services. JED is considered an affiliate of ours because of its ownership interest in us and because two of our directors are directors of JED. All transactions are recorded at the exchange amount. Transactions during the twelve month period ending December 31, 2005 were as follows:

All amounts are due and payable on receipt, and do not earn interest. At December 31, 2005, $286,956 (2004 — $376,855) was outstanding. The amount was paid in full in early 2006.

General and administrative expenses for the twelve months ended December 31, 2005 include $46,180 paid to the Chief Financial Officer of the Company for consulting services related to the preparation of the Company’s registration statement.

9. ASSET RETIREMENT OBLIGATIONS

As at December 31, 2005, the estimated present value of the Company’s asset retirement obligation was $78,642 based on estimated future cash requirements of $216,000, determined using a credit adjusted risk free interest rate of 8.5% over the economic life of the properties, an inflation rate of 2.0%, and an estimated life until repayment of 5-10 years. Accretion of $3,385 was recorded for the twelve months ending December 31, 2005.


Asset retirement obligation at December 31, 2004		—
Liabilities incurred	$	75,257
Liabilities settled		—
Accretion expense	$	3,385

Asset retirement obligations at December 31, 2005	$	78,642

10. FINANCIAL INSTRUMENTS

a) Fair value of financial assets and liabilities

The company’s financial instruments consist of cash and cash equivalents, accounts receivable, due from related parties, loan receivable and accounts payable. As at December 31, 2005 and 2004 there were no significant difference between the carrying amounts of these financial instruments and their estimated fair value.

b) Concentration of credit risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of cash and cash equivalents, accounts receivable, and loan receivable. At December 31, 2005, the Company had all of its cash and cash equivalents with three banking institutions. The company mitigates the concentration risk associated with cash deposits by only depositing material amounts of funds with major banking institutions. Concentrations of credit risk with respect to accounts receivables are the result of joint venture operations with industry partners and are subject to normal industry credit risks. The Company routinely assesses the credit of joint venture partners to minimize the risk of non-payment.

c) Interest rate risk

At December 31, 2005 and 2004, the Company had no outstanding indebtedness, that bears interest.

d) Foreign currency risk

Foreign currency risk is the risk that a variation in exchange rates between the United States dollar and the foreign currencies will affect the Company’s operating and financial results. The Company is exposed to foreign currency risk as the Company holds cash and cash equivalents on hand that are denominated in Canadian currency.

11. RECENT PRONOUNCEMENTS

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 123 (revised 2004),Share-Based Payment, which is a revision of FASB Statement No. 123,Accounting for Stock-Based Compensation. Statement 123(R) supersedes APB Opinion No. 25,Accounting for Stock Issued to Employees, and amends FASB Statement No. 95,Statement of Cash Flows. Generally, the approach in Statement 123(R) is similar to the approach described in Statement 123. However, Statement 123(R)requiresall share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

Statement 123(R) permits public companies to adopt its requirements using one of two methods:

1. A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of Statement 123 for all awards granted to employees prior to the effective date of Statement 123(R) that remain unvested on the effective date.

2. A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under Statement 123 for purposes of pro forma disclosures either (a) for all periods presented or (b) prior interim periods of the year of adoption.

The Company plans to adopt Statement 123 using the modified-prospective method.

As permitted by Statement 123, the Company currently accounts for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. However, accordingly, the adoption of Statement 123(R)’s fair value method will have a significant impact on our results of operations

12. SUBSEQUENT EVENTS

JED Oil Inc. (Amex: JDO) (“JED”) and JMG on February 27, 2006 announced they have signed a letter of intent to pursue a possible acquisition of JMG by JED. The proposal would offer two-thirds of a share of common stock of JED for each share of common stock of JMG. This exchange ratio is based on the “market to market” recent trading prices

of JED and JMG stock and the transaction is subject to the receipt of independent third party opinions that the transaction is fair to both the shareholders of JMG and shareholders of JED. Completion of the transaction is also subject to receipt of all required regulatory and stock exchange approvals in both the United States and Canada, and to the approval of the shareholders of both JMG and JED. It is anticipated that all of the outstanding common shares, warrants and options of JMG will be converted at the above-mentioned exchange rate. The JMG Board of Directors has extended the JMG warrants that were to expire in August and December of 2006 to January 15, 2007.

13. COMPARATIVE FIGURES

“Certain comparative figures have been reclassified to conform to the current period presentation.”

Item 9:Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A:Controls And Procedures

Evaluation of Disclosure Controls and Procedures

Our accounting services are provided by JED Oil Inc. which maintains disclosure controls and procedures designed to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the specified time periods. Disclosure controls are also designed to reasonably assure that such information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. As of the end of the Company’s 2005 fiscal year, management conducted an assessment of the effectiveness of the design and operation of the Company’s disclosure controls. Based on this assessment, management has determined that the Company’s disclosure controls as of December 31, 2005 have weaknesses arising from the situation of not having internal staff. This is one of the reasons for the proposed merger with JED. If this merger does not occur, we will address the weaknesses by retaining our own accounting staff.

Changes in Internal Controls

During the fourth quarter ended December 31, 2005, there have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Effectiveness of Controls

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent or detect all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Further, because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Projections of any evaluation of controls effectiveness to future periods are subject to risks. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.

Item 9B:Other Information

None.

PART III

Item 10:Directors and Executive Officers of the Registrant

The information for this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by JMG pursuant to Regulations 14A of the General Rules and Regulations under theSecurities Exchange Act of 1934not later than April 30, 2006.

We have adopted a Code of Conduct effective January 1, 2005, which applies to all of our employees, consultants, officers and directors. It establishes standards of conduct for individuals and also individual standards of business conduct and ethics. In addition it sets out our policies in relation to our employees on such issues as discrimination, harassment, privacy, drugs, alcohol, tobacco and weapons. The Code of Conduct is attached as an Exhibit hereto and will be placed on our website — www.jmgexploration.com — when its construction is completed.

Item 11: Executive Compensation

The information for this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by JMG pursuant to Regulations 14A of the General Rules and Regulations under theSecurities Exchange Act of 1934not later than April 30, 2006.

Item 12: Security Ownership of Certain Beneficial Owners and Management and related Stockholder Matters

The information for this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by JMG pursuant to Regulations 14A of the General Rules and Regulations under theSecurities Exchange Act of 1934not later than April 30, 2006.

[


	Number of securities		Weighted average
	to be issued upon		exercise price of
	exercise of		outstanding
	outstanding options,		options, warrants		Number of available
Plan category	warrants and rights		and rights		for future issuance

Equity compensation plans approved by security holders		479,250	$	5.28		20,507

Equity compensation plans not approved by security holders		—		—		—

Total		479,250	$	5.28		20,507

Item 13: Certain Relationships and Related Transactions

Item 14: Principle Accountant Fees and Services

It is the policy of the Company for the Audit Committee to pre-approve all audit, tax and financial advisory services. All services rendered by Ernst & Young LLP were pre-approved by the audit committee in the years ended December 31, 2005 and 2004. The aggregate fees billed by Ernst & Young

LLP for professional services rendered for the audit of the Company’s financial statements and other services were as follows:


	Year ended December 31,
	2005		2004
Audit fees	$	171,500	$	10,000
Audit related fees	$	30,000		—
Tax fees		—		—
All other fees		—		—

PART IV

Item 15.Exhibits and Financial Statement Schedules

(a)1.Financial Statements

The following financial statements of the registrant and the Reports of our Independent Registered Public Accounting Firm thereon are included herewith in Item 8 above.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

JMG Exploration Inc.
Financial Statements


	Page
Reports of Ernst & Young, LLP, , Independent Registered Public Accounting Firm		36
Consolidated Balance Sheets as of December 31, 2005 and 2004		38
Consolidated Statements of Operations for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		39
Consolidated Statements of Cash Flows for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		40
Consolidated Statements of Shareholders’ Equity for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		41
Consolidated Statements of Comprehensive Loss for the year ended December 31, 2005, the period from the date of incorporation on July 16, 2004 to December 31, 2004 and to December 31, 2005		42
Notes to Consolidated Financial Statements		43- 53

(a)2.Financial Statement Schedules

(a)3 Exhibits:


Number		Exhibit
3.1(1)		Amended and Restated Articles of Incorporation of the registrant *

3.2(1)		By-laws of the registrant *

3.3(1)		Certificate of Designation of the Rights and Preferences of the Series A Convertible Preferred Stock

4.1(1)		Specimen of Common stock Certificate *

4.1(1)		Form of Lockup Agreement – Officers and Directors *

4.3(1)		Form of $4.25 Warrant *

4.4(1)		Form of $6.00 Warrant *


Number		Exhibit
4.5(1)		Form of $5.00 Warrant *

4.6(1)		Form of Underwriter’s Warrant Agreement

10.1(1)*		Equity compensation plan *

10.2(1)		Hooligan Draw Farm-in Agreement*

10.3(1)		Cut Bank Farm-in Agreement*

10.4(1)		Fiddler Creek Farm-in Agreement *

10.5(1)		JED Oil Technical Services Agreement, as amended *

10.6(1)		2^nd Amended and Restated Agreement of Business Principles with Enterra Energy Trust, JED Oil Inc. and JMG Exploration, Inc. *

10.7(1)		Fellows Energy Ltd. Exploration and Development and Conveyance Agreement *

10.8(1)		Fellows Energy Ltd. Promissory Note *

10.9(1)		Fellows Energy Ltd. General Security Agreement *

10.10(1)		Candak Farm-in Agreement *

10.11(1)		Myrtle Beach Farm-in Agreement *

10.12(1)		Bluffton Farm-in Agreement *

10.13(1)		Pinedale – Jonah Farm-in Agreement *

10.14(1)		Pinedale – Desert Mining, Inc. Agreement *

10.15		Termination Agreement dated January 1, 2006 relating to JED Oil Technical Services Agreement, as amended

10.16		Joint Services Agreement between JMG Exploration Inc. and JED Oil Inc. dated January 1, 2006

14.1		Code of Business Conduct*

23.1(1)		Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm

23.2		Consent of DeGolyer and Mac Naughton Canada Limited, Independent Engineers

31.1		Certificate of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certificate of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*		Management contract

(1)		Incorporated by reference to the Company’s registration statement on Form SB-2 (333-120082)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of theSecurities Exchange Act of 1934, JMG Exploration Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


April 5, 2006	JMG Exploration Inc.
	By:	/s/ Herman S. Hartley
		Herman S. Hartley
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report to be signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.


Signature	Title	Date
By: /s/ Herman S. Hartley	President, Chief Executive	April 5, 2006
	Officer and Director

By: /s/ Joanne R. Finnerty	Chief Financial Officer and	April 5, 2006
	Chief Accounting Officer

By: /s/ Reg Greenslade	Director	April 5, 2006

By: /s/ Thomas J. Jacobsen	Director	April 5, 2006

By: /s/ Reuben Sandler	Director	April 5, 2006

By: /s/ Joseph W. Skeehan	Director	April 5, 2006

By: /s/ Donald P. Wells	Director	April 5, 2006

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Mediashift (MSHFQ) Inactive 10-K2005 FY Annual report

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