PART I

 

 

Magellan Petroleum Corporation (the “Company” or “MPC”) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2007, MPC’s principal asset was a 100.00% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”). At June 30, 2005, MPC’s equity interest in MPAL was 55.13%. During the fourth quarter of fiscal 2006, MPC completed an exchange offer (the “Offer”) to acquire all of the 44.87% of ordinary shares of MPAL that it did not own. The Offer consideration was .75 newly-issued shares of MPC common stock and A$0.10 in cash consideration for each of the 20,952,916 MPAL shares that it did not own. New MPC shares were issued to MPAL’s Australian shareholders either as registered MPC shares or in the form of CDIs (CHESS Depository Interests), which have been listed on the Australian Stock Exchange (“ASX”), effective April 26, 2006, under the symbol “MGN”(see Note 2 to the financial statements).

 

MPAL’s major assets are two petroleum production leases covering the Mereenie oil and gas field (35% working interest), one petroleum production lease covering the Palm Valley gas field (52% working interest) and three petroleum production leases covering the Nockatunga oil fields (40.94% working interest). Both the Mereenie and Palm Valley fields are located in the Amadeus Basin in the Northern Territory of Australia and the Nockatunga fields are located in the Cooper Basin in Queensland, Australia. Santos Ltd, a publicly owned Australian company, owns a 65% interest in the Mereenie field, a 48% interest in the Palm Valley field and a 59% interest in the Nockatunga fields.

 

MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. The following chart illustrates the various relationships between MPC and the various companies discussed above.

 

The following is a tabular presentation of the omitted material:

 

MPC — MPAL RELATIONSHIPS CHART

 

MPC owns 100% of MPAL.

MPC owns 2.67% of the Kotaneelee Field, Canada.

MPAL owns 52% of the Palm Valley Field, Australia.

MPAL owns 35% of the Mereenie Field, Australia.

MPAL owns 40.94% of the Nockatunga Field, Australia.

SANTOS owns 48% of the Palm Valley Field, Australia.

SANTOS owns 65% of the Mereenie Field, Australia.

SANTOS owns 59.06% of the Nockatunga Field, Australia.

 

(a) General Development of Business.

 

Operational Developments Since the Beginning of the Last Fiscal Year:

 

The following is a summary of oil and gas properties that the Company has an interest in. The Company is committed to certain exploration and development expenditures, some of which may be farmed out to third parties.

 

AUSTRALIA

 

Mereenie Oil and Gas Field

 

MPAL (35%) and Santos (65%), the operator (together known as the Mereenie Producers) own the Mereenie field which is located in the Amadeus Basin of the Northern Territory. MPAL’s share of the Mereenie field proved developed oil reserves (net of royalties), based upon contract amounts, was approximately 278,000 barrels and 7.6 billion cubic feet (Bcf) of gas at June 30, 2007. Two gas development wells were drilled in late 2004 to increase gas deliverability in order to meet the gas contractual requirements until June 2009.

During fiscal 2007, MPAL’s share of oil sales was 117,000 barrels and 5.2 Bcf of gas sold, which is subject to net overriding royalties aggregating 4.0625% and the statutory government royalty of 10%. The oil is transported by means of a 167-mile eight-inch oil pipeline from the field to an industrial park near Alice Springs. The oil is then shipped south approximately 950 miles by road to the Port Bonython Export Terminal, Whyalla, South Australia for sale. The cost of transporting the oil to the terminal is being borne by the Mereenie Producers. The Mereenie Producers are providing Mereenie gas in the Northern Territory to the Power and Water Corporation (PWC) for use in Darwin and other Northern Territory centers. See “Gas Supply Contracts” below. The petroleum leases covering the Mereenie field expire in November 2023.

 

Palm Valley Gas Field

 

MPAL has a 52.023% interest in, and is the operator of, the Palm Valley gas field which is also located in the Amadeus Basin of the Northern Territory. Santos, the operator of the Mereenie field, owns the remaining 47.977% interest in Palm Valley which provides gas to meet the Alice Springs and Darwin supply contracts with PWC. See “Gas Supply Contracts” below. MPAL’s share of the Palm Valley proved developed reserves, net of royalties, was 5.9 Bcf at June 30, 2007 and is based upon contract amounts. During fiscal 2007, MPAL’s share of gas sales was 1.8 bcf which is subject to a 10% statutory government royalty and net overriding royalties aggregating 7.3125%. The producers and PWC installed additional compression equipment in the field in early 2006 that will assist field deliverability during the remaining Darwin gas contract period. PWC funds the cost of additions and modifications to the gas delivery system under the gas supply agreement. The petroleum lease covering the Palm Valley field expires in November 2024.

 

Gas Supply Contracts

 

In 1983, the Palm Valley Producers (MPAL and Santos) commenced the sale of gas to Alice Springs under a 1981 agreement. In 1985, the Palm Valley Producers and Mereenie Producers signed agreements for the sale of gas to PWC, through its wholly-owned company Gasgo, for use in PWC’s Darwin electricity generating station and at a number of other generating stations in the Northern Territory. The gas is being delivered via the 922-mile Amadeus Basin gas pipeline which was built by an Australian consortium. Since 1985, there have been several additional contracts for the sale of Mereenie gas, the latest being in June 2006 for the supply of an additional 4.4 bcf of gas to be supplied prior to December 31, 2008. The Palm Valley Darwin contract expires in the year 2012 and the Mereenie contracts expire in the year 2009. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index.

 

The Mereenie and Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields. As indicated above, gas production from both fields is substantially contracted through to 2009 and 2012, respectively. While opportunities exist to contract additional gas sales in the Northern Territory market after these dates, there is strong competition within the market and there are no assurances that the Mereenie and Palm Valley producers will be able to contract for the sale of the remaining uncontracted reserves.

 

At June 30, 2007, MPAL’s commitment to supply gas under the above agreements was as follows:

 

Nockatunga Oil Fields

 

MPAL purchased its 40.936% working interest (38.703% net revenue interest) in the Nockatunga oil fields in the Cooper Basin in southwest Queensland effective from July 2003. Santos is operator of the fields and holds the remaining interest. The assets comprise eight producing oil fields (Dilkera, Koora, Maxwell, Maxwell South, Muthero, Nockatunga, Thungo and Winna) in Petroleum Leases 33, 50 and 51 together with exploration acreage in the adjacent ATP 267P. The fields are currently producing about 1,000 barrels of oil per day (MPAL share is approximately 400 bbls). During fiscal 2007, MPAL’s share of oil sales was 73,000 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 3.0%. MPAL’s share of the Nockatunga fields’ proved developed oil reserves was approximately 22,000 barrels at June 30, 2007. Petroleum Lease 33 was due to expire in April 2007 and an application has been made to renew the lease for a further 21 years. The lease remains in effect until the renewal is determined by the Queensland Government and is awaiting finalization of the term of a new Environmental Authority by the Environment Protection Agency(“EPA”). Petroleum Leases 50 and 51 expire in June 2011.

 

The drilling of three development wells, five appraisal wells and two exploration wells was undertaken in early 2007. All ten wells have been completed as oil producing wells and the surface facilities at the Thungo and Muthero fields have been upgraded to accommodate the anticipated increased production. MPAL’s share of the cost is approximately $8,200,000. Nine of the ten wells have been brought on production and the last is scheduled to be brought on production later in 2007. The drilling of additional appraisal, development and exploration wells, is planned for late 2007. At June 30, 2007, the work obligations of ATP 267P had been fulfilled.

 

Dingo Gas Field

 

MPAL has a 34.3365% interest in the Dingo gas field which is held under Retention License 2 in the Amadeus Basin in the Northern Territory. No market has emerged for the gas volumes that have been discovered in the Dingo gas field. MPAL’s share of potential production from this permit area is subject to a 10% statutory government royalty and overriding royalties aggregating 4.8125%. The license expires in October 2008.

 

Maryborough Basin

 

MPAL holds a 100% interest in exploration permit ATP 613P in the Maryborough Basin in Queensland, Australia. MPAL (100%) also has applications pending for permits ATP 674P and ATP 733P which are adjacent to ATP 613P. In May 2006, MPAL entered into a farmout agreement in relation to a portion of ATP 613P, ATPA 674P and ATPA 733P with Eureka Petroleum under which that company funded the drilling of two exploration wells to test the coal seam gas potential of the Burrum Coal Measures near the city of Maryborough. The Burrum-1 and Burrum-2 farmout wells drilled in early 2007 intersected multiple thin coal seams and evaluation of the gas potential is continuing.

 

Eureka Petroleum has the option to undertake a staged evaluation of the area to earn a 90% interest in any petroleum lease granted in the area. MPAL has the option to retain a 50% interest in any petroleum lease by carrying Eureka Petroleum through any development to the extent of Eureka Petroleum’s prior exploration and evaluation expenditures. MPAL operates the joint venture. Exploration permit ATP 613P was due to expire in March 2007 and an application was made to renew the permit for a further 12 year term. The lease remains in effect until the renewal is determined by the Queensland Government and is awaiting finalization of the term of a new Environmental Authority by the Environment Protection Agency. At June 30, 2007, the work obligations of the ATP 613P permit were fully committed by Eureka Petroleum under the farmout arrangement.

Cooper/Eromanga Basin

 

PEL 94, PEL 95 & PPL 210

 

During fiscal year 1999, MPAL (50%) and its partner Beach Petroleum were successful in bidding for two exploration blocks (PEL 94 and PEL 95) in South Australia’s Cooper Basin. Aldinga-1 was completed in September 2002 and began producing in May 2003 at about 80 barrels of oil per day. Petroleum Production Licence 210 was granted over the Aldinga field in December 2004. By June 2007, production had declined to about 13 barrels of oil per day. No further development is planned for the field. Black Rock Petroleum contributed to the cost of drilling the Myponga-1 well in June 2004 to earn a 15% interest in the PEL 94 permit. MPAL’s interest in PEL 94 was reduced to 35%. Black Rock Petroleum subsequently assigned its interest in PEL 94 to Victoria Petroleum. The 104-mile 2D Scutus seismic survey was acquired in PEL 95 in January 2007. MPAL’s share of the cost of the survey was approximately $270,000. At June 30, 2007, MPAL’s share of the work obligations of PEL 94 totaled $476,000 of which $14,000 was committed and PEL 95 totaled $940,000 of which $20,000 was committed. PEL 94 was renewed for a further five year term in May 2007 and PEL 95 was renewed for a further five year term in October 2006.

 

PEL 106, PEL 107 & PPL 212

 

During fiscal year 2005, MPAL entered into a farmin arrangement with Great Artesian Oil and Gas to drill explorations wells in exploration permits PEL 106 and PEL 107 in the Cooper Basin of South Australia. The Kiana-1 well was drilled in PEL 107 during August-September 2005 and was completed for production as an oil producer. Petroleum Production Licence 212 was granted over the Kiana field in January 2006. MPAL earned a 30% interest in PPL 212 by contributing to the drilling cost of the Kiana-1 well. During fiscal 2007, MPAL’s share of oil sales was 15,000 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 3.0%. MPAL’s share of the Kiana field’s proved developed oil reserves was approximately 16,000 barrels at June 30, 2007. Beach Petroleum is operator of the joint venture. The joint venture drilled an appraisal well, Kiana-2, in the licence area in October 2006. The well did not encounter hydrocarbons and was plugged and abandoned. MPAL’s share of the cost was approximately $400,000.

 

MPAL exercised its option to participate in a further two wells in PEL 107 under the farmin arrangement with Great Artesian Oil and Gas to earn a 30% interest in any discoveries and a 20% interest in the PEL 107 permit. The Keeley-1 and Cabbots-1 farmin wells were drilled in late 2006. Both wells were dry holes. MPAL’s share of the cost of the two wells was approximately $1,456,000. The PEL 107 joint venture, including MPAL, also drilled the Talia-1 well in PEL 107 in late 2006, which was a dry hole. MPAL’s 20% share of the cost of the Talia-1 well was approximately $217,000. MPAL’s share of the work obligations of PEL 107 totaled $40,000 of which $20,000 was committed.

 

The Udacha-1 gas discovery well was drilled in February 2006 in a farmin area covering portion of PEL 106 and the adjacent PEL 91 permit. A production test was carried out in late 2006 which indicated that the discovery is potentially commercially viable. If the discovery is commercial, MPC will earn a 30% interest in any petroleum production licence granted over the Udacha field. Beach Petroleum is operator of the joint venture and the participants are seeking a gas sales arrangement for the Udacha gas.

 

PEL 110

 

During fiscal year 2001, MPAL (50%) and its partner Beach Petroleum were also successful in bidding for an additional exploration block PEL 110 in the Cooper Basin. PEL 110 was granted in February 2003. During July 2005, Cooper Energy contributed to the cost of the Yanerbie-1 well to earn a 25% interest in PEL 110 which reduced MPAL’s interest in PEL 110 to 37.5%. During fiscal year 2007, MPAL, Beach Petroleum and Cooper Energy entered into a farmout arrangement with Red Sky Energy. Red Sky will fund the drilling of one exploration well to earn a 50% interest in exploration permit PEL 110. At June 30, 2007, MPAL’s share of the work obligations of the PEL 110 permit were fully committed by Red Sky under the farmout arrangement.

UNITED KINGDOM

 

PEDL 098 & PEDL 099

 

During fiscal year 2001, MPAL acquired an interest in two exploration licenses in southern England in the Weald-Wessex basin. The two licenses, PEDL 098 (22.5%) in the Isle of Wight and PEDL 099 (40%) in the Portsdown area of Hampshire, were each granted for a period of six years. The Sandhills-2 well was drilled in the PEDL 098 permit during August-September 2005 encountered a heavily biodegraded remnant oil column and was plugged and abandoned. At June 30, 2007, MPAL’s share of the work obligations of the PEDL 098 permit totaled $99,000 of which $27,000 was committed, and MPAL’s share of the work obligations of the PEDL 099 permit totaled $960,000 which was fully committed.

 

PEDL 112 & PEDL 113

 

During fiscal year 2002, MPAL acquired two additional exploration licenses in southern England. The two licenses, PEDL 113 (22.5%) in the Isle of Wight in the Wessex Basin and PEDL 112 (33.3%) in the Kent area on the north-eastern margin of the Weald Basin, were each granted for a period of six years. At June 30, 2007, MPAL’s share of the work obligations of the permits totaled $1,786,000, of which none was committed. PEDL 113 and the associated $720,000 in work obligations were relinquished in August of 2007.

 

PEDL 125 & PEDL 126

 

Effective July 1, 2003, MPAL acquired two exploration licenses each granted for a period of six years in southern England; PEDL 125 (40%) in Hampshire and PEDL 126 (40%) in West Sussex. The drilling plans for the Hedge End-2 well in PEDL 125 and Markwells Wood-1 in PEDL 126 are in progress and spudding of these wells is expected in late 2007-early 2008. The UK company, Oil Quest Resources, will fund part of MPAL’s share of the cost of the two wells to acquire a 10% interest in each of the permits. At June 30, 2007, MPAL’s share of the work obligations of the two permits totaled $1,946,000, of which $1,920,000 was committed.

 

PEDL 135, PEDL 136 & PEDL 137

 

Effective October 1, 2004, MPAL was granted 100% interest in PEDL 135, PEDL 136 and PEDL 137 in the Weald Basin in southern England for a term of six years, each with a drill or drop obligation at the end of the third year of the term. MPAL has undertaken a program of seismic data purchase, reprocessing and interpretation and has identified three drilling prospects. Drilling is planned for late 2008. At June 30, 2007, MPAL’s work obligation for the three licenses totaled $11,040,000, of which $960,000 was committed.

 

PEDL 151, PEDL 152, PEDL 153, PEDL 154 & PEDL 155

 

Effective October 1, 2004, MPAL acquired five licenses in the Weald Basin each granted for a period of six years in southern England, PEDL 151 (11.25%), PEDL 152 (22.5%), PEDL 153 (33.3%), PEDL 154 (50%) and PEDL 155 (40%). PEDL 151 was surrendered during fiscal 2007. Each remaining license has a drill or drop obligation at the end of the third year of the term. Northern Petroleum, operator of the licenses, applied to have the drill or drop obligation varied and the UK Department has agreed to vary the terms of each of PEDL 152, 153,154 and 155 such that the license terms require that the well has to be drilled within the first six years of the initial term in order for the license to extend into the next five-year term. The drilling plans for the Leigh Park-1 well in PEDL 155 are in progress and spudding of this well is expected in 2008. The UK company, Oil Quest Resources, will fund part of MPAL’s share of the PEDL 155 exploration costs to acquire a 10% interest in the license. At June 30, 2007, MPAL’s work obligation for the five licenses totaled $4,480,000, of which $161,000 was committed.

 

CANADA

 

MPC owns a 2.67% carried interest in a lease (31,885 gross acres, 850 net acres) in the southeast Yukon Territory, Canada, which includes the Kotaneelee gas field. Devon Canada Corporation is the operator of this partially developed field which is connected to a major pipeline system. Production at Kotaneelee commenced in February 1991. The Company recorded revenue of $130,000 from this field in fiscal 2007.

(b) Financial Information About Industry Segments.

 

The Company is engaged in only one industry, namely, oil and gas exploration, development, production and sale. The Company conducts such business through its two operating segments; MPC and its wholly owned subsidiary MPAL.

 

(c) (1) Narrative Description of the Business.

 

MPC was incorporated in 1957 under the laws of Panama and was reorganized under the laws of Delaware in 1967. MPC is directly engaged in the exploration for, and the development and production and sale of oil and gas reserves in Canada, and indirectly through its subsidiary MPAL in Australia and the United Kingdom.

 

(i) Principal Products.

 

MPAL has an interest in the Palm Valley gas field and in the Mereenie oil and gas field in the Amadeus Basin of the Northern Territory and in the Nockatunga, Kiana and Aldinga oil fields in the Cooper Basin of South Australia and Queensland. See Item 1(a) — Australia — for a discussion of the oil and gas production from these fields. MPC has a direct 2.67% carried interest in the Kotaneelee gas field in Canada.

 

(ii) Status of Product or Segment.

 

See Item 1(a) and (b) — Australia and Canada — for a discussion of the current and future operations of the Mereenie, Palm Valley, Nockatunga, Kiana and Aldinga fields in Australia and MPC’s interest in the Kotaneelee field in Canada.

 

(iii) Raw Materials.

 

Not applicable.

(iv) Patents, Licenses, Franchises and Concessions Held.

 

MPAL has interests directly and indirectly in the following permits. Permit holders are generally required to carry out agreed work and expenditure programs.

 

 

Petroleum Leases issued by the Northern Territory and Queensland Governments are subject to the Petroleum (Prospecting and Mining) Act of the Northern Territory and the Petroleum Act and Petroleum and Gas (Production & Safety) Act of Queensland. Lessees have the exclusive right to produce petroleum from the land subject to

payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Rental payments may be offset against the royalty paid. The term of a lease is 21 years, and leases may be renewed for successive terms of 21 years each. Petroleum Production Licences issued by the South Australian Government are subject to the Petroleum Act of South Australia. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Licenses terminate two years after production ceases.

 

Since 1992, there has been an ongoing controversy regarding the Aborigines and the ownership of their traditional lands. There has been legislation aimed at resolving this controversy. The Company does not believe that this issue will have a material adverse impact on MPAL’s properties.

 

(v) Seasonality of Business.

 

Although the Company’s business is not seasonal, the demand for oil and especially gas is subject to fluctuations in the Australian weather.

 

(vi) Working Capital Items.

 

See Item 7 — Liquidity and Capital Resources for a discussion of this information.

 

(vii) Customers.

 

Although the majority of MPAL’s producing oil and gas properties are located in a relatively remote area in central Australia (See Item 1 — Business and Item 2 — Properties), the completion in January 1987 of the Amadeus Basin to Darwin gas pipeline has provided access to and expanded the potential market for MPAL’s gas production.

 

     Natural Gas Production

 

Substantially all of MPAL’s gas sales were to the PAWC, a Northern Territory Government corporation. The Northern Territory Government also has regulatory authority over MPAL’s oil and gas operations in the Northern Territory. The loss of PAWC as a customer would have a material adverse affect on MPAL’s business.

 

     Oil Production

 

Presently all of the crude oil and condensate production from Mereenie is being shipped and sold through the Port Bonython Export Terminal, Whyalla, South Australia. Crude oil production from Kiana and Aldinga is shipped through the Moomba processing facility in northeastern South Australia and piped from there to the Port Bonython Export Terminal where it is sold. Nockatunga crude oil is shipped and sold through the IOR Energy refinery at Eromanga, Southwest Queensland. Oil sales during 2007 were 44.9% to the Santos group of companies, 13.6% to Delhi Petroleum, 8.9% to Origin Energy Resources and 32.6% to IOR Energy.

 

(viii) Backlog.

 

Not applicable.

 

(ix) Renegotiation of Profits or Termination of Contracts or Subcontracts at the Election of the Government.

 

Not applicable.

 

(x) Competitive Conditions in the Business.

 

The exploration for and production of oil and gas are highly competitive operations. The ability to exploit a discovery of oil or gas is dependent upon such considerations as the ability to finance development costs, the availability of equipment, and the possibility of engineering and construction delays and difficulties. The Company also must compete with major oil and gas companies which have substantially greater resources than the Company.

 

Furthermore, various forms of energy legislation which have been or may be proposed in the countries in which the Company holds interests may substantially affect competitive conditions. However, it is not possible to predict the nature of any such legislation which may ultimately be adopted or its effects upon the future operations of the Company.

At the present time, the Company’s principal income producing operations are in Australia and for this reason, current competitive conditions in Australia are material to the Company’s future. Currently, most indigenous crude oil is consumed within Australia. In addition, refiners and others import crude oil to meet the overall demand in Australia. The Palm Valley Producers and the Mereenie Producers are developing and separately marketing the production from each field. Because of the relatively remote location of the Amadeus Basin and the inherent nature of the market for gas, it would be impractical for each working interest partner to attempt to market separately its respective share of gas production from each field. The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. There is strong competition within the market and the Palm Valley producers may not be able to contract for the sale of the remaining uncontracted reserves.

 

(xi) Research and Development.

 

Not applicable.

 

(xii) Environmental Regulation.

 

The Company is subject to the environmental laws and regulations of the jurisdictions in which it carries on its business, and existing or future laws and regulations could have a significant impact on the exploration for and development of natural resources by the Company. However, to date, the Company has not been required to spend any material amounts for environmental control facilities. The federal and state governments in Australia strictly monitor compliance with these laws but compliance therewith has not had any adverse impact on the Company’s operations or its financial resources.

 

At June 30, 2007, the Company had accrued approximately $9.5 million for asset retirement obligations for the Mereenie, Palm Valley, Nockatunga, Kiana, Aldinga and Dingo fields. See Note 4 of the Consolidated Financial Statements under Item 8. Financial Statements and Supplementary Data.

 

(xiii) Number of Persons Employed by Company.

 

At June 30, 2007, MPC had 3 employees in the United States and MPAL had 28 employees in Australia.

 

(d) (2) Financial Information Relating to Foreign and Domestic Operations.

 

See Note 10 to the Consolidated Financial Statements.

 

(3) Risks Attendant to Foreign Operations.

 

Most of the properties in which the Company has interests are located outside the United States and are subject to certain risks involved in the ownership and development of such foreign property interests. These risks include but are not limited to those of: nationalization; expropriation; confiscatory taxation; changes in foreign exchange controls; currency revaluations; price controls or excessive royalties; export sales restrictions; limitations on the transfer of interests in exploration licenses; and other laws and regulations which may adversely affect the Company’s properties, such as those providing for conservation, proration, curtailment, cessation, or other limitations of controls on the production of or exploration for hydrocarbons. Thus, an investment in the Company represents a speculation with risks in addition to those inherent in domestic petroleum exploratory ventures.

 

Since 1992, there has been an ongoing controversy regarding the Aborigines and the ownership of their traditional lands. There has been legislation aimed at resolving this controversy. The Company does not believe that this issue will have a material adverse impact on MPAL’s properties.

 

(4) Data Which are Not Indicative of Current or Future Operations.

 

None.

 

 

Set forth below and elsewhere in this Annual Report on Form 10-K are risks that should be considered in evaluating the Company’s common stock, as well as risks and uncertainties that could cause the actual future results of the Company to differ from those expressed or implied in the forward-looking statements contained in this Report

and in other public statements the Company makes. Additionally, because of the following risks and uncertainties, as well as other variables affecting the Company’s operating results, the Company’s past financial performance should not be considered an indicator of future performance.

 

The principal oil and gas properties owned by MPAL could stop producing oil and gas.

 

MPAL’s Palm Valley, Mereenie and Nockatunga fields could stop producing oil and gas or there could be a material decrease in production levels at the fields. Since these are the three principal revenue producing properties of MPAL, any decline in production levels at these properties could cause MPAL’s revenues to decline, thus reducing the amount of dividends paid by MPAL to Magellan. Any such adverse impact on the revenues being received by Magellan from MPAL could restrict our ability to explore and develop oil and gas properties in the future.

 

In addition, the Kotaneelee gas field, which has in recent years provided Magellan with an additional source of revenue, could stop producing natural gas, produce gas in decreased amounts, or be shut-in completely (so that production would cease). In this event, Magellan may experience a decline in revenues and would be forced to rely completely on our receipt of dividends from MPAL.

 

If MPAL’s existing long-term gas supply contracts are terminated or not renewed, MPAL’s business could be adversely affected.

 

MPAL’s financial performance and cash flows are substantially dependent upon its Palm Valley and Mereenie existing supply contracts to sell gas produced at these fields to MPAL’s major customers, the Power and Water Corporation of the Northern Territory and its subsidiary, Gasgo Pty Ltd. The Palm Valley Darwin contract expires in the year 2012 and the Mereenie contracts expire in the year 2009. If these gas supply contracts were to be terminated or not renewed when they become due, MPAL’s revenues, share price and business outlook could be adversely affected. The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. There is strong competition within the market and the Palm Valley producers may not be able to contract for the sale of the remaining uncontracted reserves.

 

If the Australian Taxation Office issues tax assessments against MPAL as described in the position papers recently received by MPAL (including possible interests and penalties), and such assessments are upheld by the Australian courts, our business and share price could be adversely affected.

 

As previously disclosed, the ATO has conducted an audit of the Australian income tax returns of MPAL and its wholly-owned subsidiaries for the years 1997- 2005. The audit focused on certain income tax deductions claimed by Paroo Petroleum Pty. Ltd. (“PPPL”), a wholly-owned finance subsidiary of MPAL, related to the write-off of outstanding loans made by PPPL to other entities within the MPAL group of companies. As a result of this audit, the ATO has issued “position papers” which set forth its opinions that these previous deductions should be disallowed, resulting in additional income taxes being payable by MPAL and its subsidiaries. The ATO has indicated in the position papers that the increase in taxes arising from its proposed positions would be (Aus.) $13,392,460, plus possible interest and penalties, which could be substantial and exceed the amount of the increased taxes asserted by the ATO. If assessments of this amount are issued by the ATO, and upheld by the Australian courts, such assessments would have a material adverse impact on the Company’s financial condition, results of operations and cash flows.

 

Fluctuations in our operating results and other factors may depress our stock price.

 

During the past few years, the equity trading markets in the United States have experienced price volatility that has often been unrelated to the operating performance of particular companies. These fluctuations may adversely affect the trading price of our common stock. From time to time, there may be significant volatility in the market price of our common stock. Investors could sell shares of our common stock at or after the time that it becomes apparent that the expectations of the market may not be realized, resulting in a decrease in the market price of our common stock.

The loss of key MPAL personnel could adversely affect our ability to operate.

 

We depend, and will continue to depend in the foreseeable future, on the services of the officers and key employees of MPAL. The ability to retain its officers and key employees is important to MPAL’s and our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on MPAL’s and our business. We do not maintain key person life insurance on any of our personnel.

 

There are risks inherent in foreign operations such as adverse changes in currency values and foreign regulations relating to MPAL’s exploration and development operations and to MPAL’s payment of dividends to us.

 

The properties in which Magellan has interests are located outside the United States and are subject to certain risks related to the indirect ownership and development of foreign properties, including government expropriation, adverse changes in currency values and foreign exchange controls, foreign taxes, nationalization and other laws and regulations, any of which may adversely affect the Company’s properties. In addition, MPAL’s principal present customer for gas in Australia is the Northern Territory Government, which also has substantial regulatory authority over MPAL’s oil and gas operations. Although there are currently no exchange controls on the payment of dividends to the Company by MPAL, such payments could be restricted by Australian foreign exchange controls, if implemented.

 

Our Restated Certificate of Incorporation includes provisions that could delay or prevent a change in control of our Company that some of our shareholders may consider favorable.

 

Our Restated Certificate of Incorporation provides that any matter to be voted upon at any meeting of shareholders must be approved not only by a simple majority of the shares voted at such meeting, but also by a majority of the shareholders present in person or by proxy and entitled to vote at the meeting. This provision may have the effect of making it more difficult to take corporate action than customary “one share one vote” provisions, because it may not be possible to obtain the necessary majority of both votes.

 

As a consequence, our Restated Certificate of Incorporation may make it more difficult that a takeover of Magellan will be consummated, which could prevent the Company’s shareholders from receiving a premium for their shares. In addition, an owner of a substantial number of shares of our common stock may be unable to influence our policies and operations through the shareholder voting process (e.g., to elect directors).

 

In addition, our Restated Certificate of Incorporation requires the approval of 66.67% of the voting shareholders and of the voting shares for the consummation of any business combination (such as a merger, consolidation, other acquisition proposal or sale, transfer or other disposition of $5 million or more of Magellan’s assets) involving our company and certain related persons (generally, any 10% or greater shareholders and their affiliates and associates). This higher vote requirement may deter business combination proposals which shareholders may consider favorable.

 

Our dividend policy could depress our stock price.

 

We have never declared or paid dividends on our common stock and have no current intention to change this policy. We plan to retain any future earnings to reduce our accumulated deficit and finance growth. As a result, our dividend policy could depress the market price for our common stock and cause investors to lose some or all of their investment.

 

We may issue a substantial number of shares of our common stock under our stock option plans and shareholders may be adversely affected by the issuance of those shares.

 

As of June 30, 2007, there were 430,000 stock options outstanding all of which were fully vested and exercisable. There were also 395,000 options available for future grants under our Stock Option Plan. If all of these options, which total 825,000 in the aggregate, were awarded and exercised these shares would represent approximately 2% of our outstanding common stock and would, upon their exercise and the payment of the exercise prices, dilute the interests of other shareholders and could adversely affect the market price of our common stock.

If our shares are delisted from trading on the Nasdaq Capital Market, their liquidity and value could be reduced.

 

In order for us to maintain the listing of our shares of common stock on the Nasdaq Capital Market, the Company’s shares must maintain a minimum bid price of $1.00 as set forth in Marketplace Rule 4310(c)(4). If the bid price of the Company’s shares trade below $1.00 for 30 consecutive trading days, then the bid price of the Company’s shares must trade at $1.00 or more for 10 consecutive trading days during a 180 day grace period to regain compliance with the rule. On October 2, 2007, the Company’s shares closed at $1.11 per share. If the Company shares were to be delisted from trading on the Nasdaq Capital Market, then most likely the shares would be traded on the Electronic Bulletin Board. The delisting of the Company’s shares could adversely impact the liquidity and value of the Company’s shares of common stock.

 

RISKS RELATED TO THE OIL AND GAS INDUSTRY

 

Oil and gas prices are volatile. A decline in prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

 

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend primarily upon the prices we receive for the oil and gas we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The prices of oil, natural gas, methane gas and other fuels have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to numerous factors, including the following:

 

 

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. Declines in oil and gas prices would not only reduce revenue, but could reduce the amount of oil and gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and gas prices do not necessarily move in tandem. Because more than 80% of our proved reserves at June 30, 2007 were natural gas reserves, we are more affected by movements in natural gas prices and would receive lower revenues if natural gas prices in Australian and Canada were to decline. Based on 2007 gas sales volumes and revenues, a 10% change in gas prices would increase or decrease gas revenues by approximately $1,640,000. Existing gas sales contracts in Australia are long term contracts with the gas price movements related to the Australian Consumer Price Index.

 

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.

 

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production and face intense competition from both major and other independent oil and natural gas companies. Many of our Australian competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a

greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may not be able to compete with, or enter into cooperative relationships with, any such firms.

 

Our oil and gas exploration and production operations are subject to numerous environmental laws, compliance with which may be extremely costly.

 

Our operations are subject to environmental laws and regulations in the various countries in which they are conducted. Such laws and regulations frequently require completion of a costly environmental impact assessment and government review process prior to commencing exploratory and/or development activities. In addition, such environmental laws and regulations may restrict, prohibit, or impose significant liability in connection with spills, releases, or emissions of various substances produced in association with fuel exploration and development.

 

We can provide no assurance that we will be able to comply with applicable environmental laws and regulations or that those laws, regulations or administrative policies or practices will not be changed by the various governmental entities. The cost of compliance with current laws and regulations or changes in environmental laws and regulations could require significant expenditures. Moreover, if we breach any governing laws or regulations, we may be compelled to pay significant fines, penalties, or other payments. Costs associated with environmental compliance or noncompliance may have a material adverse impact on our financial condition or results of operations in the future.

 

The actual quantities and present value of our proved reserves may prove to be lower than we have estimated.

 

This annual report and the documents incorporated by reference in this annual report contain estimates of our proved reserves and the estimated future net revenues from our proved reserves as well as estimates relating to recent acquisitions. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

 

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

 

There are many uncertainties in estimating quantities of oil and gas reserves. In addition, the estimates of future net cash flows from our proved developed reserves and their present value are based upon assumptions about future production levels, prices and costs that may prove to be inaccurate. Our estimated reserves may be subject to upward or downward revision based upon our production, results of future exploration and development, prevailing oil and gas prices, operating and development costs and other factors.

 

We may not have funds sufficient to make the significant capital expenditures required to replace our reserves.

 

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, farming-in other companies or investors to MPAL’s exploration and development projects in which we have an interest and/or equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a

reduced ability to replace our reserves. If our cash flow from operations is not sufficient to fund MPAL’s capital expenditure budget, we may not be able to rely upon additional farm-in opportunities, debt or equity offerings or other methods of financing to meet these cash flow requirements.

 

If we are not able to replace reserves, we may not be able to sustain production.

 

Our future success depends largely upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. Recovery of any additional reserves will require significant capital expenditures and successful drilling operations. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.

 

Exploration and development drilling may not result in commercially productive reserves.

 

We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: