TELLURIAN INC. /DE/ - Annual Report: 2007 (Form 10-K)

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

Commission file number 1-5507

 

Magellan Petroleum Corporation

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code

(860) 293-2006

 

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

 

 

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

 

Title of Class

 

                          None

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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. (Check one):

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

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant at the $1.32 closing price on December 29, 2006 (the last business day of the most recently completed second quarter) was $54,671,043.

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:

 

Common stock, par value $.01 per share, 41,500,325 shares outstanding as of October 2, 2007.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2007, are incorporated by reference in Part III of this Form 10-K to the extent stated herein.

 

 

TABLE OF CONTENTS

 

 

Unless otherwise indicated, all dollar figures set forth herein are in United States currency. Amounts expressed in Australian currency are indicated as “A.$00”. The exchange rate at October 2,, 2007 was approximately A.$1.00 equaled U.S. $.89.

 

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:

 

 

Future price declines may result in a write-down of our asset carrying values.

 

We follow the successful efforts method of accounting for our oil and gas operations. Under this method, the costs of successful wells, development dry holes and productive leases are capitalized and amortized on a units-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. Magellan records its proportionate share in its working interest agreements in the respective classifications of assets, liabilities, revenues and expenses. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any required impairment charged to expense. The successful efforts method also imposes limitations on the carrying or book value of proved oil and gas properties. Oil and gas properties, along with goodwill and exploration rights are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We estimate the future undiscounted cash flows from the affected properties to determine the recoverability of carrying amounts. In general, analyses are based on proved developed reserves, except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. For Mereenie and Palm Valley, proved developed natural gas reserves are limited to contracted quantities. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves or the contracted quantities. A significant decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings.

Oil and gas drilling and producing operations are hazardous and expose us to environmental liabilities.

 

Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these risks occur, we could sustain substantial losses as a result of:

 

 

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.

 

 

None

 

 

(a) MPC has interests in properties in Australia through its 100% equity interest in MPAL which holds interests in the Northern Territory, Queensland and South Australia. MPAL also has interests in the United Kingdom. In Canada, MPC has a direct interest in one lease. For additional information regarding the Company’s properties, See Item 1 — Business.

 

(b) (1) The information regarding reserves, costs of oil and gas activities, capitalized costs, discounted future net cash flows and results of operations is contained in Supplementary Oil & Gas Information under Item 8 — Financial Statements and Supplementary Data.

 

The following graphic presentation has been omitted, but the following is a description of the omitted material:

 

AUSTRALIAN MAP WITH MPAL PROJECTS SHOWN

 

The following graphic presentation has been omitted, but the following is a description of the omitted material:

 

AMADEUS BASIN PROJECTS MAP

 

The map indicates the location of the Amadeus Basin interests in the Northern Territory of Australia. The following items are identified:

 

Palm Valley Gas Field

Mereenie Oil & Gas Field

Dingo Gas Field

Palm Valley — Alice Springs Gas Pipeline

Palm Valley — Darwin Gas Pipeline

Mereenie Spur Gas Pipeline

Mereenie Oil Pipeline

 

The following graphic presentation has been omitted, but the following is a description of the omitted material:

 

CANADIAN PROPERTY INTERESTS MAP

 

The map indicates the location of the Kotaneelee Gas Field in the Yukon Territories of Canada. The map identifies the following items:

 

Kotaneelee Gas Field

Pointed Mountain Gas Field

Beaver River Gas Field

 

The following graphic presentation has been omitted, but the following is a description of the omitted material:

 

UNITED KINGDOM PROPERTY INTERESTS MAP

 

The map indicates the location of the MPAL property interests in the United Kingdom.

 

(2) Reserves Reported to Other Agencies.

 

None

 

(3) Production.

 

MPC’s net production volumes for gas and oil during the three years ended June 30, 2007 were as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material):

 

 

The average sales price per unit of production for Australia for the following fiscal years is as follows:

 

 

The average production cost per unit of production for Australia for the following fiscal years is as follows:

 

 

Amounts presented above are in Australian dollars to show a more meaningful trend of underlying operations. For the year ended June 30, 2007, 2006 and 2005 the average foreign exchange rates were .7860, .7477, and .7533, respectively.

 

(4) Productive Wells and Acreage.

 

Productive wells and acreage at June 30, 2007

 

 

(5) Undeveloped Acreage.

 

The Company’s undeveloped acreage (except as indicated below) is set forth in the table below:

 

GROSS AND NET ACREAGE AS OF JUNE 30, 2007

 

MPAL has interests in the following properties (before royalties). MPC has an interest in these properties through its 100% interest in MPAL.

 

 

 

 

 

(6) Drilling Activity.

 

Productive and dry net wells drilled during the following years (data concerning Canada and the United States is insignificant):

 

 

(7) Present Activities.

 

See Item 1 — Cooper Basin and United Kingdom for a discussion of the present activities of MPAL.

 

(8) Delivery Commitments.

 

See discussion under Item 1 concerning the Palm Valley and Mereenie fields.

 

Item 3.  Legal Proceedings.

 

MPAL, the Company’s wholly-owned Australian subsidiary, has been notified that the Australian Taxation Office (“ATO”) is conducting an audit of the Australian income tax returns of MPAL and its wholly owned subsidiaries for the years 1997- 2005. The ATO audit is focused on certain income tax deductions claimed by Paroo Petroleum Pty. Ltd. (“PPPL”), a wholly-owned 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. In the position papers, the ATO sets out the legal basis for its conclusions. 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. It is important to note that the position papers are not assessments of additional taxes.

 

In a comprehensive audit conducted by the ATO in the period 1992 – 94, the ATO concluded that PPPL was carrying on business as a money lender and accordingly, should, for taxation purposes, account for its interest income on an accrual basis rather than a cash basis. MPAL accepted this conclusion and from that point has been determining its annual Australian taxation liability on this basis (including claiming deductions for bad debts as a money lender).

 

Recently, the ATO appears to have taken a more aggressive approach with respect to its views regarding income tax deductions attributable to in-house finance companies. Since this change in approach, the ATO has commenced audits of a number of companies involving, among other issues, the appropriate treatment of bad debt deductions taken by in-house finance companies. Magellan understands that, at this time, while there have been negotiated settlements in relation to some of these audits, none of them has reached final resolution in court.

 

MPAL intends to refute the positions taken by the ATO and has retained the services of experienced Australian tax counsel, and will also be represented by its Australian tax advisors. For further information see Note 6 — “Income Taxes” under Item 8 — Financial Statements and Supplementary Data.

 

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

 

None.

 

PART II

 

Item 5.  Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Securities

 

(a) Principal Market

 

The principal market for MPC’s common stock is the NASDAQ Capital Market under the symbol MPET. The stock is also traded on the Australian Stock Exchange in the form of CHESS depository interests under the symbol MGN. The quarterly high and low prices on the most active market, NASDAQ, during the quarterly periods indicated were as follows:

 

 

 

(b) Approximate Number of Holders of Common Stock at October 2, 2007

 

 

(c) Frequency and Amount of Dividends

 

MPC has never paid a cash dividend on its common stock.

 

Recent Sales of Unregistered Securities

 

None

 

Issuer Purchases of Equity Securities

 

The following table sets forth the number of shares that the Company has repurchased under any of its repurchase plans for the stated periods, the cost per share of such repurchases and the number of shares that may yet be repurchased under the plans:

 

 

 

 

 

The following table sets forth selected data (in thousands except for exchange rates and per share data) and other operating information of the Company. The selected consolidated financial data in the table are derived from the consolidated financial statements of the Company. This data should be read in conjunction with the consolidated financial statements, related notes and other financial information included herein.

 

 

 

 

 

Forward Looking Statements

 

Statements included in Management’s Discussion and Analysis of Financial Condition and Results of Operations which are not historical in nature are intended to be, and are hereby identified as, forward looking statements for purposes of the “Safe Harbor” Statement under the Private Securities Litigation Reform Act of 1995. The Company cautions readers that forward looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those indicated in the forward looking statements. Among these risks and uncertainties are pricing and production levels from the properties in which the Company has interests, and the extent of the recoverable reserves at those properties. In addition, the Company has a large number of exploration permits and there is the risk that any wells drilled may fail to encounter hydrocarbons in commercial quantities. The Company undertakes no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

 

Executive Summary

 

MPC is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. MPC’s principal asset is a 100.00% equity interest in its subsidiary, MPAL. 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) and one petroleum production lease covering the Palm Valley gas field (52% working interest). Both fields are located in the Amadeus Basin in the Northern Territory of Australia. Santos Ltd., a publicly owned Australian company, owns a 48% interest in the Palm Valley field and a 65% interest in the Mereenie field.

 

MPAL is refocusing its exploration activities into two core areas, the Cooper Basin in onshore Australia and the Weald Basin in the onshore southern United Kingdom with an emphasis on developing a low to medium risk acreage portfolio.

 

MPC also has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. The Company recorded revenue of $130,000 from this investment during fiscal year 2007.

 

Critical Accounting Policies

 

Oil and Gas Properties

 

The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method, the costs of successful wells, development dry holes, productive leases, and permit and concession costs are capitalized and amortized on a units-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. The Company records its proportionate share in joint venture operations in the respective classifications of assets, liabilities and expenses. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any impairment charged to expense. The successful efforts method also imposes limitations on the carrying or book value of proved oil and gas properties. Oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The Company estimates the future undiscounted cash flows from the affected properties to determine the recoverability of carrying amounts. In general, analyses are based on proved developed reserves except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. For Mereenie and Palm Valley, proved developed reserves are limited to contracted quantities. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves or the contracted quantities.

Exploratory drilling costs are initially capitalized pending determination of proved reserves but are charged to expense if no proved reserves are found. Other exploration costs, including geological and geophysical expenses, leasehold expiration costs and delay rentals, are expensed as incurred. Because the Company follows the successful efforts method of accounting, the results of operations may vary materially from quarter to quarter. An active exploration program may result in greater exploration and dry hole costs.

 

Nondepletable assets

 

Oil and gas properties include $14.8 million of capitalized costs that are currently not being depleted. This amount consists of $10.4 million of costs capitalized as exploratory well costs pending the start of production, of which $1.6 million related to PEL 106 in the Cooper Basin has been capitalized in excess of one year. This remains capitalized because the related well has sufficient quantity of reserves to justify its completion as a producing well. In addition, capitalized costs not currently being depleted include $4.4 million associated with exploration permits and licenses in Australia and the U.K. The Company evaluates exploration permits and licenses annually or whenever events or changes in circumstances indicate that the carrying value may be impaired. An impairment loss of $892,000 was recorded for the year ended June 30, 2007.

 

Goodwill

 

Goodwill is not amortized. The Company evaluates goodwill for impairment annually or whenever events or changes in circumstances indicate that the carrying value may be impaired in accordance with methodologies prescribed in SFAS No. 142 “Goodwill and Other Intangible Assets.” There was no impairment of goodwill as of June 30, 2007.

 

Asset Retirement Obligations

 

SFAS 143, “Accounting for Asset Retirement Obligations” requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset (oil & gas properties) and amortized on a units-of-production basis over the life of the related reserves. Accretion expense in connection with the discounted liability is recognized over the remaining life of the related reserves.

 

The estimated liability is based on the future estimated cost of land reclamation, plugging the existing oil and gas wells and removing the surface facilities equipment in the Palm Valley, Mereenie, Kotaneelee, Nockatunga and the Cooper Basin fields. The liability is a discounted liability using a credit-adjusted risk-free rate on the date such liabilities are determined. A market risk premium was excluded from the estimate of asset retirement obligations because the amount was not capable of being estimated. Revisions to the liability could occur due to changes in the estimates of these costs, acquisition of additional properties and as new wells are drilled.

 

Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Judgments are based upon such things as field life and estimated costs. Such costs could differ significantly when they are incurred.

 

Revenue Recognition

 

The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Company’s share of production. Revenues from the purchase, sale and transportation of natural gas are recognized upon completion of the sale and when transported volumes are delivered. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which are recorded at the time of sale. The Company records pipeline tariff revenues on a gross basis with the revenue included in other production related revenues and the remittance of such tariffs are included in production costs. Shipping and handling costs in connection with such deliveries are included in production costs. Revenue under carried interest agreements is recorded in the period when the net proceeds become receivable, measurable and collection is reasonably assured. The time when the net revenues become receivable and collection is reasonably assured depends on the terms and conditions of the relevant agreements and the practices followed by the operator. As a result, net revenues from carried interests may lag the production month by one or more months.

Liquidity and Capital Resources

 

Consolidated

 

At June 30, 2007, the Company on a consolidated basis had approximately $28.5 million of cash and cash equivalents and $4.4 million in marketable securities.

 

Net cash provided by operations was $21,273,813 in 2007 compared to $11,765,925 in 2006. The increase is primarily related to a decrease of $301,935 in net income, an increase in non cash items of $4,090,143, mostly due to an increase in depletion, depreciation and amortization $4,379,366, an increase in exploration and dry hole costs ($1,874,839), and an impairment loss ($1,876,171) offset by a decrease in minority interests ($1,768,023) and an increase in deferred income taxes ($1,661,331), and a net increase in operating liabilities of $5,719,680, mostly due to an increase in the change to accounts receivable ($1,247,459), accounts payable ($2,842,830) and income taxes payable ($1,585,295). Cash flow from operations is primarily the result of MPAL’s oil and gas activities.

 

During 2007, the Company had a net increase in marketable securities of $3,838,592 compared to a net decrease in marketable securities of $2,676,867 in 2006. The increase in investments resulted from the investment of dividend income received from MPAL.

 

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 liquidity, financial condition, results of operations and cash flows.

 

As to MPC (Unconsolidated)

 

In August 2006, a dividend of approximately $5.9 million was received from MPAL. Also in August 2006, MPC loaned approximately $4.1 million to MPAL payable August, 2011. The loan along with interest was repaid in May of 2007. The tax effects of these transactions was recorded in fiscal year 2006.

 

At June 30, 2007, MPC, on an unconsolidated basis, had working capital of $3,519,233. Working capital is comprised of current assets less current liabilities. MPC’s current cash position and its annual MPAL dividend should be adequate to meet its current and future cash requirements. In fiscal 2006, MPC invested substantial portions of its cash to purchase the remaining minority shares of MPAL (See Note 2 to the financial statements).

 

MPC has a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2007, MPC purchased 680,850 of its shares at a cost of approximately $686,000. There were no shares purchased during fiscal years 2007, 2006 or 2005.

 

As to MPAL

 

At June 30, 2007, MPAL had working capital of $25,484,924 million. MPAL had budgeted approximately A$13.4 million for specific exploration projects in fiscal year 2007 as compared to the A$6.0 million expended during fiscal 2007. There was less money spent than budgeted in the Cooper Basin and United Kingdom. The current composition of MPAL’s oil and gas reserves are such that MPAL’s future revenues in the long-term are expected to be derived from the sale of gas in Australia. MPAL’s current contracts for the sale of Palm Valley and Mereenie gas will expire during fiscal year 2012 and 2009, respectively. Unless MPAL is able to obtain additional contracts for its remaining gas reserves or be successful in its current exploration program, its revenues will be materially reduced after 2009. 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. 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 Palm Valley producers will be able to contract for the sale of the remaining uncontracted reserves.

 

MPAL expects to fund its exploration costs through its cash and cash equivalents and cash flow from Australian operations. MPAL also expects that it will continue to seek partners to share its exploration costs. If MPAL’s efforts to find partners are unsuccessful, it may be unable or unwilling to complete the exploration program for some of its properties.

 

Off Balance Sheet Arrangements

 

The Company does not use off-balance sheet arrangements such as securitization of receivables with any unconsolidated entities or other parties. The Company is exposed to oil and gas market price volatility and uses fixed pricing contracts with inflation clauses to mitigate this exposure.

 

Contractual Obligations

 

The following is a summary of our consolidated contractual obligations as of June 30, 2007:

 

 

 

 

Recent Accounting Pronouncements

 

In June, 2006, the Emerging Issues Task Force (“EITF”) issued Abstract 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement.” The abstract concludes that an accounting policy decision regarding the presentation of taxes assessed by a government authority on either a gross basis (included in revenues and costs) or a net basis (excluded from revenues) should be disclosed. The Company records pipeline tariff revenues on a gross basis with the revenue included in other production related revenues and the remittance of such tariffs are included in production costs. Government sales taxes related to MPAL’s oil and gas production revenues are collected by MPAL and remitted to the Australian government. Such amounts are excluded from revenue and expenses.

 

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is an interpretation of FASB Statement No. 109 “Accounting for Income Taxes” and must be adopted by the Company no later than July 1, 2007. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the financial statements uncertain tax positions that the company has taken or expects to take in its tax returns. The Company is currently evaluating the impact of adopting FIN 48 (see Notes 6 and 12 to the Consolidated Financial Statements).

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. SFAS No. 157 is effective for the Company beginning July 1, 2008. The

Company is currently evaluating the impact, if any, the adoption of SFAS No. 157 will have on our combined financial position, results of operations and cash flows.

 

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities,” (“SFAS 159”). SFAS 159 provides companies with an option to report selected financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings at each subsequent reporting date. SFAS 159 is effective for the Company beginning July 1, 2008. The Company is currently in the process of evaluating the impact of adopting SFAS 159 on its financial statements.

 

Results of Operations

 

2007 vs. 2006

 

Revenues

 

Oil sales increased 12% in 2007 to $11,922,574 from $10,615,761 in 2006 because of a 16% increase in barrels sold due mostly to the Nockatunga Project and the 5% Australian foreign exchange rate increase discussed below, offset by a 6% decrease in the average sales price per barrel. Oil unit sales (net of royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:

 

 

Amounts presented above for oil prices and below for gas prices are in Australian dollars to show a more meaningful trend of underlying operations. For the fiscal years ended June 30, 2007 and 2006, the average foreign exchange rates were .7860 and .7477 respectively.

 

Gas sales increased 17% to $16,396,334 in 2007 from $14,060,968 in 2006. The increase was primarily the result of a 7% increase in price per mcf sold, a 5% increase in sales volume and the 5% Australian foreign exchange rate increase discussed below.

 

The volumes in billion cubic feet (bcf) (net of royalties) and the average price of gas per thousand cubic feet (mcf) sold during the periods indicated were as follows:

 

 

Other production related revenues increased 25% to $2,356,317 in 2007 from $1,885,706 in 2006. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which increased as a result of the higher volumes of gas sold at Mereenie and the 5% Australian foreign exchange rate increase discussed below.

Costs and Expenses

 

Production costs decreased 15% in 2007 to $6,965,641 from $8,220,013 in 2006. The decrease in 2007 was primarily the result of decreased expenditures of $1,106,555 in the Mereenie and Palm Valley fields due to the completion of the Mereenie workover program in 2006. The decrease was partially offset by the 5% Australian foreign exchange rate increase discussed below.

 

Exploration and dry hole costs increased 69% to $5,520,460 in 2007 from $3,264,837 in 2006. These costs related to the exploration work being performed on MPAL’s properties. The primary reasons for the increase in 2007 were the higher drilling costs related to the Cooper Basin drilling program ($2,393,853) and the 5% Australian foreign exchange rate increase discussed below.

 

Depletion, depreciation and amortization increased 70% to $10,693,415 in 2007 from $6,308,608 in 2006. This increase was mostly due to depletion of the higher book value of MPAL’s oil and gas properties acquired during fiscal 2006 ($1,962,784), increased depletion in the Nockatunga project due to increased production and capitalized costs ($1,027,556), increased depreciation on revised asset retirement obligations ($582,579) and the 5% Australian foreign exchange rate increase discussed below.

 

Auditing, accounting and legal expenses increased 58% to $628,114 in 2007 from $398,514 in 2006 primarily because of increased legal and accounting fees related to the ATO audit (see Note 12) and required filings with the Australian stock exchange. The Company will continue to incur significant administrative, auditing and legal expenses with respect to the Sarbanes-Oxley Act of 2002, particularly the requirements to document, test and audit the Company’s internal controls to comply with Section 404 of the Act and rules adopted thereunder. Management’s opinion on the internal controls of the Company is required for the fiscal year ending June 30, 2008. An audit opinion on the design and operating effectiveness of controls is expected to be required for the fiscal year ending June 30, 2009.

 

Accretion expense increased 22% to $517,856 in 2007 from $425,254 in 2006. Accretion expense represents the accretion on the asset retirement obligations (“ARO”) under SFAS 143. The increase was due mostly to accretion of the revised asset retirement obligations recorded in fiscal 2006.

 

Loss on asset retirement obligation settlement is the result of adjusting the estimated asset retirement cost to actual expenditures incurred for producing wells in the Mereenie field that were plugged and restored in accordance with environmental regulations. The loss recorded for 2006 was $444,566. No settlements occurred during fiscal 2007.

 

A non-cash impairment loss of $1,876,171 was recorded in 2007 relating to the decreased value of the Kiana field in the Cooper Basin ($984,171) and the decreased value of exploration permits and licenses included in oil and gas properties ($892,000). The net book value of the Kiana oil and gas property was written down to its future estimated discounted cash flow.

 

Income Taxes

 

Provision for income tax for the year ended June 30, 2007 was $998,565 compared to $1,678,980 for the year ended June 30, 2006. The decrease in the tax provision relates primarily to the decrease in income for the year ended June 30, 2007 (see Note 6.) The increase in the effective tax rate is due to the effect of permanent differences on the lower income.

 

Exchange Effect

 

The value of the Australian dollar relative to the U.S. dollar increased to $.8433 at June 30, 2007 compared to $.7301 at June 30, 2006. This resulted in a $7,401,076 credit to accumulated translation adjustments for fiscal 2007. The 15.5% increase in the value of the Australian dollar increased the reported asset and liability amounts in the balance sheet at June 30, 2007 from the June 30, 2006 amounts. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2007 was $.7860, which is a 5.1% increase compared to the $.7477 rate for fiscal 2006.

 

2006 vs. 2005

 

Revenues

 

Oil sales increased 40% in 2006 to $10,615,761 from $7,574,022 in 2005 because of a 37% increase in the average sales price per barrel and a 2% increase in barrels sold due mostly to Kiana-1 in the Cooper Basin. The increase was offset by the 1% Australian foreign exchange rate decrease discussed below. Oil unit sales (net of royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:

 

 

Amounts presented above for oil prices and below for gas prices are in Australian dollars to show a more meaningful trend of underlying operations. For the fiscal years ended June 30, 2006 and 2005, the average foreign exchange rates were .7477 and .7533 respectively.

 

Gas sales increased 13% to $14,060,968 in 2006 from $12,478,293 in 2005. The increase was primarily the result a 14% increase in price per mcf sold offset by decreased sales volume in 2006 and the 1% Australian foreign exchange rate decrease discussed below.

 

The volumes in billion cubic feet (bcf) (net of royalties) and the average price of gas per thousand cubic feet (mcf) sold during the periods indicated were as follows:

 

 

Other production related revenues increased 4% to $1,885,706 in 2006 from $1,818,471 in 2005. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which increased as a result of the higher volumes of gas sold at Mereenie, and offset by the 1% Australian foreign exchange rate decrease discussed below.

 

Costs and Expenses

 

Production costs increased 34% in 2006 to $8,220,013 from $6,144,339 in 2005. The increase in 2006 was primarily the result of increased expenditures of $1,600,000 in the Mereenie and Palm Valley fields mostly due to the Mereenie workover program, $102,000 in the Nockatunga project and $409,000 in the Cooper Basin. The increase was partially offset by the 1% Australian foreign exchange rate decrease discussed below.

 

Exploration and dry hole costs decreased 21% to $3,264,837 in 2006 from $4,157,344 in 2005. These costs related to the exploration work being performed on MPAL’s properties. The primary reasons for the decrease in 2006 were work performed on the Nockatunga project ($630,000), costs related to exploration activities in New Zealand ($1,141,000) and the 1% Australian foreign exchange rate decrease discussed below. The decrease in costs was partially offset by an increase in costs incurred in 2006 on properties in the Mereenie and Palm Valley fields ($880,000).

 

Depletion, depreciation and amortization decreased 10% to $6,308,608 in 2006 from $6,986,967 in 2005. Depletion expense for the Palm Valley and Mereenie fields decreased 20% during the 2006 period primarily because of a decrease in depletable costs of $4,740,000. This decrease was partially offset by an increase in depletion for the Nockatunga project ($378,000) and properties in the Cooper Basin ($198,000) primarily because

of a higher depletion rate for 2006 due to a change in reserve estimates. Depletion also decreased due to the 1% Australian foreign exchange rate decrease discussed below.

 

Auditing, accounting and legal expenses increased 5% to $398,514 in 2006 from $379,153 in 2005 primarily because of the administrative, auditing and legal expenses with respect to new SEC and accounting rules adopted pursuant to the Sarbanes-Oxley Act of 2002, offset by the 1% Australian foreign exchange rate decrease discussed below. The Company anticipates that it will be required in the future to incur significant administrative, auditing and legal expenses with respect to the Sarbanes-Oxley Act of 2002, particularly the requirements to document, test and audit the Company’s internal controls to comply with Section 404 of the Act and rules adopted thereunder. Management’s opinion on the internal controls of the Company is required for the fiscal year ending June 30, 2008. An audit opinion on the design and operating effectiveness of controls is expected to be required for the fiscal year ending June 30, 2009.

 

Accretion expense increased 4% to $425,254 in 2006 from $406,960 in 2005. Accretion expense represents the accretion on the asset retirement obligations (“ARO”) under SFAS 143. The increase in the 2006 period is partially offset by the 1% decrease in the Australian foreign exchange rate discussed below.

 

Shareholder communications costs increased 98% to $449,561 in 2006 from $227,032 in 2005 due to costs related to the exchange offer (see Note 2 to the Consolidated Financial Statements).

 

Loss on asset retirement obligation settlement is the result of adjusting the estimated asset retirement cost to actual expenditures incurred for producing wells in the Mereenie field that were plugged and restored in accordance with environmental regulations. The loss recorded for 2006 is $444,566.

 

Other administrative expenses increased 22.5% to $2,795,388 in 2006 from $2,281,523 in 2005 primarily due to a non-cash charge for directors’ stock option expense of $365,000, increased consulting costs of $191,000 relating to Mereenie contract negotiations and a charge to bad debts of $48,000, offset by the 1% decrease in the Australian foreign exchange rate discussed below.

 

Income Taxes

 

Provision for income tax for the year ended June 30, 2006 was $1,678,980 compared to an income tax benefit for the year ended June 30, 2005 of $82,152. The increase in the tax provision relates primarily to the increase in income for the year ended June 30, 2006, an increase in valuation reserve related to foreign exploration costs, and reduced benefits relating to New Zealand foreign losses (see Note 6 to the Consolidated Financial Statements).

 

Exchange Effect

 

The value of the Australian dollar relative to the U.S. dollar decreased to $.7301 at June 30, 2006 compared to $.7620 at June 30, 2005. This resulted in a $705,817 debit to accumulated translation adjustments for fiscal 2006. The 4% decrease in the value of the Australian dollar decreased the reported asset and liability amounts in the balance sheet at June 30, 2006 from the June 30, 2005 amounts. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2006 was $.7477, which is a 1% decrease compared to the $.7533 rate for fiscal 2005.

 

 

The Company does not have any significant exposure to market risk, other than as previously discussed regarding foreign currency risk and the risk of fluctuations in the world price of crude oil, as the only market risk sensitive instruments are its investments in marketable securities. At June 30, 2007, the carrying value of such investments including those classified as cash and cash equivalents was approximately $32.8 million, which approximates the fair value of the securities. Since the Company expects to hold the investments to maturity, the maturity value should be realized. A 10% change in the Australian foreign currency rate compared to the U.S. dollar would increase or decrease revenues and costs and expenses by $3.1 million and $3.1 million, respectively. For the twelve months ended June 30, 2007, oil sales represented approximately 42% of production revenues. Based on 2007 sales volume and revenue, a 10% change in oil price would increase or decrease oil revenues by $1.2 million. Gas sales, which represented approximately 58% of production revenues in 2007, are derived primarily from the Palm Valley and Mereenie fields in the Northern Territory of Australia and the gas prices are set according to long term contracts that are subject to changes in the Australian Consumer Price Index.

 

Item 8.  Financial Statements and Supplementary Data.

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of

Magellan Petroleum Corporation

Hartford, Connecticut

 

We have audited the accompanying consolidated balance sheets of Magellan Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2007. 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. The Company is not required to have, nor were we engaged to perform, an audit of its 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Magellan Petroleum Corporation and subsidiaries as of June 30, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2007, in conformity with accounting principles generally accepted in the United States of America.

 

 

 

October 5, 2007

Hartford, Connecticut

MAGELLAN PETROLEUM CORPORATION

 

CONSOLIDATED BALANCE SHEETS

 

 

See accompanying notes.

MAGELLAN PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF INCOME

 

 

See accompanying notes.

MAGELLAN PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF
STOCKHOLDERS’ EQUITY
Three Years Ended June 30, 2007