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:

 

 

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.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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 $1.03 closing price on December 31, 2007 (the last business day of the most recently completed second quarter) was $42,659,981.

 

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 September 25, 2008.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2008, 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 September 25, 2008 was approximately A.$1.00 equaled U.S. $.84.

IMPORTANT INFORMATION REGARDING THIS FORM 10-K

 

Explanatory Note

 

As discussed in Note 12 to the accompanying consolidated financial statements in Item 8 of this Annual Report on Form 10-K, subsequent to the issuance of the Company’s Forms 10-Q for the quarterly periods ended September 30, 2007, December 31, 2007 and March 31, 2008, the Company’s management determined that depletion expense was miscalculated due to the misapplication of reserve information for a group of new wells which principally began production in fiscal 2008. Depletion expense for the three-month periods ended September 30, 2007, December 31, 2007 and March 31, 2008 was understated by $1,247,108, $1,569,467 and $1,075,003, respectively. Depletion expense was understated by $2,816,575 and $3,891,578 for the six months ended December 31, 2007 and the nine months ended March 31, 2008, respectively. This restatement has no impact on the consolidated balance sheets or consolidated cash flows from operations for any period presented in this Form 10-K. A summary of quarterly unaudited results as restated for the periods ended September 30, 2007, December 31, 2007 and March 31, 2008 is presented in Note 12.

 

In addition, as discussed in Note 13, the Company has restated the unaudited supplementary oil and gas disclosure that was presented in Note 14 of the consolidated financial statements included in Item 8 of the Company’s 2007 Form 10-K. This restatement was due to the misapplication of reserve information referred to above.

 

The Company intends to amend its previously issued Form 10Qs for the three periods ended September 30, 2007, December 31, 2007 and March 31, 2008 to adjust for the restatement discussed above.

 

 

Magellan Petroleum Corporation (the “Company” or “MPC” or “Magellan”) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2008, 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 MPC 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 consolidated 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 (41% 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 (“Santos”), 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 41% of the Nockatunga Fields, Australia.

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

SANTOS owns 65% of the Mereenie Field, Australia.

SANTOS owns 59% of the Nockatunga Fields, 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 and gas reserves based upon contracted amounts (net of royalties) was approximately 423,000 barrels and 3.3 billion cubic feet (Bcf) of gas at June 30, 2008. During fiscal 2008, MPAL’s share of oil sales was 111,000 barrels and 5.1 Bcf of gas, 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 borne by the Mereenie Producers. The petroleum leases covering the Mereenie field expire in November 2023.

The Mereenie Producers are contracted to provide 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 gas contract expires in June 2009.

 

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 the Palm Valley field 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 3.8 Bcf at June 30, 2008 and is based upon gas contract amounts. During fiscal 2008, MPAL’s share of gas sales was 1.6 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 Pty. Ltd., for use in PWC’s Darwin electricity generating station and at a number of other generating stations in the Northern Territory. 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 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 principal Mereenie contracts expire in June 2009. Supply obligations under the Mereenie contracts cease in May 2009.

 

MPAL’s major customer, Gasgo Pty. Ltd., a subsidiary of PWC of the Northern Territory, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years commencing at the beginning of 2009. Eni Australia is to supply the gas from its Blacktip field offshore the Northern Territory. The Mereenie Producers will continue to supply PWC’s gas demand until Blacktip gas is available. MPAL is actively pursuing gas sales contracts for the remaining reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2012 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. 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. Mereenie gas sales were approximately $15.5 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2008.

 

At June 30, 2008, 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 eleven producing oil fields (Currambar, Kamel, Dilkera, Dilkera North, Koora, Maxwell, Maxwell South, Muthero, Nockatunga, Thungo and Winna) in Petroleum Leases 33, 50 and 51 and Petroleum Lease Applications 244 and 245, together with exploration acreage in the adjacent Authority to Prospect for Petroleum (“ATP”) No. 267P. The fields are currently producing about 750 barrels of oil per day (MPAL share is approximately 290 BOPD). During fiscal 2008, MPAL’s share of oil sales was 124,000 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 oil reserves (net of royalties) was approximately 218,000 barrels at June 30, 2008. 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. ATP 267P was due to expire in November 2007 and an application has been made to renew the ATP for a further four year term. The ATP remains in effect until the renewal is determined by the Queensland Government.

 

The drilling of an appraisal well and an exploration well was undertaken late in calendar 2007. The appraisal well, Maxwell-5, has been completed as an oil producing well and tied in to the surface facilities at the Maxwell field. The exploration well, Burundi-1, was plugged and abandoned without encountering hydrocarbons. MPAL’s share of the cost was approximately $1,400,000. The drilling of additional appraisal and development wells is planned for 2009.

 

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 currently expires in February 2009 and is expected to be renewed.

 

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 farm-out 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 in 2007 to test the coal seam gas potential of the Burrum Coal Measures near the city of Maryborough. The Burrum-1 and Burrum-2 farm-out wells drilled in early 2007 intersected multiple thin coal seams and evaluation of the gas potential is continuing. The grant of ATPA 674P and ATP 733P is subject to agreement of the native title claimants to the area.

 

Eureka Petroleum has the option to undertake a staged evaluation of the farm-out 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. At June 30, 2008, the work obligations of the ATP 613P permit were fully committed by Eureka Petroleum under the farm-out arrangement. ATP 613P was renewed in March 2008 for a further 12-year term ending in 2019.

 

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, Petroleum Exploration License (“PEL”) 94 and PEL 95, in South Australia’s Cooper Basin. The

Aldinga-1 exploration well was drilled and completed in September 2002 and began producing in May 2003 at about 80 barrels of oil per day. Petroleum Production License (“PPL) 210 was granted over the Aldinga field in December 2004. By June 2008, production had declined to about 12 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. At June 30, 2008, MPAL’s share of the work obligations of PEL 94 totaled $554,000 of which $17,000 was committed and in PEL 95 totaled $1,104,000 of which $240,000 was committed. PEL 94 expires in May 2012 and PEL 95 expires in October 2011.

 

PEL 106, PEL 107 & PPL 212

 

During fiscal year 2005, MPAL entered into a farm-in arrangement with Great Artesian Oil and Gas to drill explorations wells in petroleum exploration permits PEL 106 and PEL 107 in the Cooper Basin of South Australia. The Kiana-1 well was drilled in PEL 107 in 2005 and was completed for production as an oil producer. PPL 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 2008, MPAL’s share of oil sales was approximately 5,000 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 4.0%. MPAL’s share of the Kiana field’s proved developed oil reserves was approximately 13,000 barrels at June 30, 2008. Beach Petroleum is operator of the joint venture.

 

MPAL exercised its option to participate in a further two wells in PEL 107 under the farm-in 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 farm-in wells were drilled in late 2006. Both wells were dry holes. At June 30, 2008, the work obligations of PEL 107 had been fulfilled.

 

The Udacha-1 gas discovery well was drilled in February 2006 in the farm-in area with Great Artesian Oil and Gas, 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 license 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 successful in bidding for 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 farm-out arrangement with Red Sky Energy. Red Sky undertook to fund the drilling of one exploration well to earn a 50% interest in PEL 110, but has subsequently declined to drill the well. At June 30, 2008, MPAL’s share of the work obligations of PEL 110 totaled $468,000 which was committed.

 

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, Petroleum Exploration and Development License (“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, drilled in the PEDL 098 permit during 2005, encountered a heavily biodegraded remnant oil column and was plugged and abandoned. At June 30, 2008, MPAL’s share of the work obligations of the PEDL 098 permit totaled $87,000 of which $22,000 was committed, and MPAL’s share of the work obligations of the PEDL 099 permit totaled $1,870,000 which was fully committed. PEDL 098 expires in September 2011. PEDL 099 expired in September 2008. Work obligations and the planned well under PEDL 099 will be transferred and drilled under PEDL 155.

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. PEDL 112 expired in January 2008 and PEDL 113 was surrendered in August 2007. No drilling was carried out in the licenses.

 

PEDL 125 & PEDL 126

 

Effective July 1, 2003, MPAL acquired two exploration licenses, PEDL 125 (40%) in Hampshire and PEDL 126 (40%) in West Sussex, in the Weald Basin of southern England; each granted for a period of six years. The drilling plans for the Markwells Wood-1 well in PEDL 126 are in progress and have received all necessary approvals. However, due to certain delays and the availability of suitable rigs to perform the drilling work, the spudding of this well is expected to take place in the first quarter of fiscal 2009. Plans for drilling Hedge End-2 later in 2009 are in progress. The UK company, Oil Quest Resources, will fund part of MPAL’s share of the cost of drilling the two wells to acquire a 10% interest in each of the permits. At June 30, 2008, MPAL’s share of the work obligations of the two permits totaled $4,980,000 which 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 has a drill or drop obligation at the end of the term. MPAL has undertaken a program of seismic data purchase, reprocessing and interpretation and has identified three drilling prospects. Drilling of two wells is planned for 2009. At June 30, 2008, MPAL’s work obligation for the three licenses totaled $16,900,000, of which $336,000 was committed.

 

PEDL 152, PEDL 153, PEDL 154 & PEDL 155

 

Effective October 1, 2004, MPAL acquired five licenses in the Weald Basin in southern England, each granted for a period of six years; 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 its term. 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 license term. The drilling plans for the Havant-1 well in PEDL 155 are in progress and spudding of this well is expected in 2009. The U.K. company, Oil Quest Resources, will fund part of MPAL’s share of the PEDL 155 drilling and exploration costs to acquire a 10% interest in the license. At June 30, 2008, MPAL’s work obligation for the five licenses totaled $8,100,000, of which $120,000 was committed.

 

PEDL 231, PEDL 232, PEDL 234, PEDL 240, PEDL 242, PEDL 243 & PEDL 246

 

Effective July 1, 2008, MPAL and its joint venture partners were granted interests in PEDL 231, PEDL 232, PEDL 234, PEDL 240, PEDL 242, PEDL 243 & PEDL 246 located in the Weald and Wessex Basins of southern England. Six of these PEDLs will be operated by MPAL.

 

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 $233,000 from this field in fiscal 2008.

 

(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 and the Petroleum Act of the Northern Territory and the Petroleum Act and the 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 Licenses 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. Petroleum Exploration and Development Licenses issued by the Government of the United Kingdom are subject to the Petroleum Act. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental. The term of the license is 31 years.

 

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 seasonal 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

 

MPAL’s major customer, Gasgo Pty. Ltd., is a subsidiary of PWC, a Northern Territory Government corporation. The Northern Territory Government also has regulatory authority over MPAL’s oil and gas operations in the Northern Territory. Gasgo Pty. Ltd. has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years commencing at the beginning of 2009. Eni Australia is to supply the gas from its Blacktip field offshore the Northern Territory. The Mereenie Producers will continue to supply PWC’s gas demand until Blacktip gas is available. MPAL is actively pursuing gas sales contracts for the remaining reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2012 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. 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. Mereenie gas sales were approximately $15.5 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2008.

 

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 fiscal 2008 were 32.5% to the Santos group of companies, 9.9% to Delhi Petroleum, 6.4% to Origin Energy Resources and 51.2% 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. MPAL’s major customer, Gasgo Pty. Ltd., a subsidiary of PWC of the Northern Territory, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years commencing at the beginning of 2009. Eni Australia is to supply the gas from its Blacktip field offshore the Northern Territory. The Mereenie Producers will continue to supply PWC’s gas demand until Blacktip gas is available. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2012 timeframe. When Blacktip gas becomes available there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. 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. Mereenie gas sales were approximately $15.5 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2008.

 

(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, 2008, the Company had accrued approximately $11.6 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, 2008, MPC had 3 employees in the United States and MPAL had 26 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 Annual 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 customer, Gasgo Pty. Ltd., a subsidiary of PWC of the Northern Territory. The Palm Valley Darwin contract expires in the year 2012 and the principal Mereenie contracts expire in 2009. The expiration of these contracts, if not replaced, will have an adverse effect on MPAL’s revenues and business outlook and possibly its share price. MPAL’s major customer, Gasgo Pty. Ltd., a subsidiary of PWC of the Northern Territory, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years commencing at the beginning of 2009. Eni Australia is to supply the gas from its Blacktip field offshore the Northern Territory. The Mereenie Producers will continue to supply PWC’s gas demand until Blacktip gas is available. MPAL is actively pursuing gas sales contracts for the remaining reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2012 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the

remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. 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. Mereenie gas sales were approximately $15.5 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2008.

 

Our plans to successfully drill for oil and gas on fields located in the U.K. may not result in successful discoveries of oil and gas.

 

During fiscal year 2009, we expect that at least two new wells, Markwell Woods-1 and Havant-1, in the Weald Basin in the United Kingdom in which we hold interests will be drilled in an attempt to recover oil and gas in recoverable quantities. If either or both of these drilling projects are not successful, no revenues will be achieved from the drilling projects and our results of operations would be adversely effected.

 

We may not be successful in sharing the exploration and development costs of the fields and permits in which we hold interests.

 

Our plans for drilling in the U.K. and other areas depend, in certain cases, on our ability to enter into farm-in, joint venture or other cost sharing arrangements with other oil and gas companies. If we are not able to secure such farm-in or other arrangements in a timely manner, or on terms which are economically attractive to the Company, we may be forced to bear higher exploration and development costs with respect to our fields and interests. We may also be unable to fully develop and/or explore certain fields if the costs to do so would exceed our available exploration budget and capital resources. In either case, our results of operations could be adversely affected and the market price of our common shares could decline.

 

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, 2008, there were 530,000 stock options outstanding all of which were fully vested and exercisable. There were also 295,000 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 September 24, 2008, the Company’s shares closed at $1.05 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, or OTC-BB. The delisting of the Company’s shares from NASDAQ could adversely impact the liquidity and value of the Company’s shares.

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. Approximately 62% of our proved reserves at June 30, 2008 were natural gas reserves. Existing gas sales contracts in Australia are long term contracts with the gas price movements related to the Australian Consumer Price Index. Future gas sales not governed by existing contracts would generate lower revenue if natural gas prices in Australia were to decline. Sales of our proved oil reserves are dependent on world oil prices. The volatility of these prices will affect future oil revenues. Based on 2008 gas and oil sales volumes and revenues, a 10% change in gas prices would increase or decrease gas revenues by approximately $1,850,000 and a 10% change in oil prices would increase or decrease oil revenue by approximately $1,979,000.

 

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 cash flows, 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 (including exploration rights), along with goodwill 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 or replaced, 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 write down 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 production volumes, net of royalties, for gas and oil during the three years ended June 30, 2008 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, 2008, 2007 and 2006 the average foreign exchange rates were .8965, .7860, and .7477, respectively.

(4) Productive Wells and Acreage.

 

Productive wells and acreage at June 30, 2008

 

(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, 2008

 

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.

 

 

As previously disclosed, the Australian Taxation Office (“ATO”) conducted an audit of the Australian income tax returns of MPAL and its wholly owned subsidiaries for the years 1997- 2005. The ATO audit 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 in August 2007 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 its legal basis for its conclusions. The ATO indicated in its 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.

 

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 has 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.

 

Based upon the advice of Australian tax counsel, the Company and the ATO held settlement discussions concerning this matter during the quarter ended December 31, 2007. In order to avoid a protracted and costly legal battle with the ATO, diversion of company management and resources away from Company business and the possibility of significantly higher payments with a loss in court, the Company decided to settle this matter. On December 19, 2007, MPAL reached a non-binding agreement in principle to settle this dispute for an aggregate settlement payment by MPAL to the ATO of (Aus) $14,641,994. The aggregate settlement payment was comprised

of (Aus) $10,340,796 in amended taxes and (Aus) $4,301,198 of interest on the amended taxes. No penalties were to be assessed as part of the terms of the settlement. The agreement in principle to settle the dispute was conditioned upon MPAL and the ATO agreeing on formal terms of settlement in a binding agreement (the Deed of Settlement) which the parties agreed to negotiate and sign promptly. As further agreed by the parties, the ATO issued assessments for the agreed upon amended tax liabilities in January 2008. Under the final terms of the Deed of Settlement signed by the parties on February 7, 2008, MPAL agreed not to object to or appeal the ATO’s amended assessments. The Deed of Settlement with the ATO constitutes a complete release and extinguishment of the tax liabilities of MPAL and its subsidiaries with respect to the amended assessments and the prior bad debt deductions.

 

On January 21, 2008, MPAL paid (Aus) $5,000,000 to the ATO as a deposit towards this settlement. The remaining (Aus) $9,641,994 was paid by MPAL on February 14, 2008. As agreed upon by the parties, the matter is now closed.

 

 

None.

 

 

(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 September 10, 2008

 

 

(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, except for the exchange rate and market value per share, 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.

 

 

 

 

 

Restatement

 

As discussed in Note 13 to the accompanying consolidated financial statements in Item 8 of this Annual Report on Form 10-K, we have restated the unaudited supplementary oil and gas disclosure that was presented in Note 14 to the consolidated financial statements included in Item 8 of the Company’s 2007 Form 10-K. This restatement was due to the misapplication of reserve information for a group of new wells which principally began production in fiscal 2008. This restatement has no effect on cash flow from operations.

 

In addition, previously issued condensed consolidated financial statements for the quarters ended September 30, 2007, December 31, 2007 and March 31, 2008 have been restated due to the misapplication of reserve information for a group of new wells which principally began production in fiscal 2008. A summary of quarterly unaudited results as restated for the periods ended September 30, 2007, December 31, 2007 and March 31, 2008 is presented in Note 12 to the accompanying consolidated financial statements in Item 8 of this Annual Report on Form 10-K.

 

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 owns a 48% interest in the Palm Valley field and a 65% interest in the Mereenie field. 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 Pty. Ltd., for use in PWC’s Darwin electricity generating station and at a number of other generating stations in the Northern Territory. 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 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 principal Mereenie contracts expire in June 2009. Supply obligations under the Mereenie contracts cease in May 2009. PWC has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years commencing at the beginning of 2009. Eni Australia is to supply the gas from its Blacktip field offshore the

Northern Territory. The Mereenie Producers will continue to supply PWC’s gas demand until Blacktip gas is available. MPAL is actively pursuing gas sales contracts for the remaining reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2012 timeframe. When Blacktip gas becomes available there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. 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. Mereenie gas sales were approximately $15.5 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2008.

 

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 $233,000 from this investment during fiscal year 2008.

 

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 reserves and risk adjusted probable and possible reserves. For Mereenie, natural gas reserves are limited to contracted quantities. If such contracts are extended, the reserves will be increased to the lesser of the actual proved reserves and risk adjusted probable and possible 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 $6.8 million of capitalized costs that are currently not being depleted. This amount consists of $2.4 million of costs capitalized as exploratory well costs pending the start of production, of which $1.9 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. at June 30, 2008 and 2007. The Company evaluates exploration permits and licenses annually or whenever events or changes in circumstances indicate that the carrying value may be impaired. There was no impairment recorded for the year ended June 30, 2008. 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 Statement of Financial Accounting Standards No. 142 “Goodwill and Other Intangible Assets.” There was no impairment of goodwill as of June 30, 2008 and 2007.

 

Asset Retirement Obligations

 

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) 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. 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, 2008, the Company on a consolidated basis had approximately $34.6 million of cash and cash equivalents and $1.7 million in marketable securities.

 

Net cash provided by operations was $4,211,265 in 2008 compared to $21,273,813 in 2007. The decrease is primarily related to a decrease of $9,338,484 in net income offset by an increase in the change in non-cash items of $1,313,022, an increase in accounts receivable of $3,113,078 and a decrease in accounts payable of $5,587,046.

 

During 2008, the Company had a net decrease in marketable securities of $2,670,045 compared to a net increase in marketable securities of $3,838,592 in 2007. The decrease in investments resulted from the use of investments to fund operations.

As previously disclosed, the ATO conducted an audit of the Australian income tax returns of MPAL and its wholly-owned subsidiaries for the years 1997-2005. As disclosed in Note 6 to the consolidated financial statements, the Company settled this matter and on January 21, 2008 MPAL paid (Aus) $5,000,000 to the ATO as a deposit towards this settlement. The remaining (Aus) $9,641,994 was paid by MPAL on February 14, 2008. By agreement of the parties, the matter is now closed.

 

MPAL’s current contracts for the sale of Palm Valley and Mereenie gas will expire during fiscal years 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 which could materially affect liquidity. For further information, see “Gas Supply Contracts” in Item 1-Business above. MPAL’s oil sales are dependent on world oil prices. The volatility of these prices will affect future oil revenues. The Company will align operating expenses with any reductions in revenues.

 

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 2007.

 

At June 30, 2008, MPC, on an unconsolidated basis, had working capital of $2,046,800. Working capital is comprised of current assets less current liabilities. MPC’s current cash position and its expected annual MPAL dividends should be adequate to meet its current and future cash requirements.

 

MPC has a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2008, MPC purchased 680,850 of its shares at a cost of approximately $686,000. There were no shares purchased during fiscal years 2008, 2007 or 2006.

 

As to MPAL

 

At June 30, 2008, MPAL had working capital of $35,732,764. MPAL had budgeted approximately (Aus) $7.2 million for specific exploration projects in fiscal year 2008 as compared to the (Aus) $3.0 million expended during fiscal 2008. During the year, there was less money spent than budgeted in the 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 oil and 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. MPAL’s major customer, Gasgo Pty. Ltd., a subsidiary of PWC of the Northern Territory, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years commencing at the beginning of 2009. Eni Australia is to supply the gas from its Blacktip field offshore the Northern Territory. The Mereenie Producers will continue to supply PWC’s gas demand until Blacktip gas is available. MPAL is actively pursuing gas sales contracts for the remaining reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2012 timeframe. When Blacktip gas becomes available there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. 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 which could materially affect liquidity. Mereenie gas sales were approximately $15.5 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2008.

 

Sales of MPAL’s proved oil reserves are dependent on world oil prices. The volatility of these prices will affect future oil revenues.

 

MPAL will fund its exploration costs through its cash and cash equivalents of $34.5 million at June 30, 2008 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, 2008:

 

 

 

 

Recent Accounting Pronouncements

 

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 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 157 is effective for the Company beginning July 1, 2008 for financial assets and liabilities and July 1, 2009 for nonfinancial assets and liabilities. The Company has concluded that the adoption of SFAS 157 will have no impact on its consolidated financial statements.

 

In February 2007, the FASB issued Statement of Financial Accounting Standards 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 has concluded that the adoption of SFAS 159 will have no impact on its consolidated financial statements.

 

Results of Operations

 

2008 vs. 2007

 

Revenues

 

Oil sales increased 66% in 2008 to $19,786,175 from $11,922,574 in 2007 because of a 17% increase in barrels sold due mostly to the Nockatunga Project, a 27% increase in the average sales price per barrel and the 14.1%

Australian foreign exchange rate increase 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, 2008 and 2007, the average foreign exchange rates were .8965 and .7860 respectively.

 

Gas sales increased 13% to $18,523,095 in 2008 from $16,396,334 in 2007. The increase was primarily the result of a 5% increase in price per mcf sold and the 14.1% Australian foreign exchange rate increase discussed below, offset by a 5% decrease in sales volume.

 

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:

 

 

MPAL’s current contracts for the sale of Palm Valley and Mereenie gas will expire during fiscal years 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. Mereenie gas sales were approximately $15.5 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2008. See discussion in “Gas Supply Contracts” under Item 1 and Executive Summary above.

 

Other production related revenues increased 10% to $2,585,540 in 2008 from $2,356,317 in 2007. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which increased as a result of the 14.1% Australian foreign exchange rate increase discussed below offset by a decrease in volumes of gas sold at Mereenie.

 

Costs and Expenses

 

Production costs increased 27% in 2008 to $8,865,663 from $6,965,641 in 2007. The increase in 2008 was primarily the result of increased expenditures in the Nockatunga project due to increased production, an increase in field equipment repairs in the Mereenie project and the 14.1% increase in the exchange rate described below.

 

Exploration and dry hole costs decreased 40% to $3,318,810 in 2008 from $5,520,460 in 2007. These costs related to the exploration work being performed on MPAL’s properties. The primary reason for the decrease in 2008 was the decreased drilling costs related to the Cooper Basin drilling program, partially offset by the 14.1% increase in the exchange rate described below.

 

Depletion, depreciation and amortization increased 69% to $18,021,236 in 2008 from $10,693,415 in 2007. This increase resulted from the higher book values of MPAL’s oil and gas properties acquired during fiscal 2006 resulting from an updated valuation at June 30, 2007, increased depletion in the Nockatunga project due to

increased production resulting from the 10 wells drilled in the fourth quarter of fiscal 2007, increased expenditures and the 14.1% increase in the exchange rate described below, partially offset by lower depletion in the Mereenie and Palm Valley and Cooper Basin projects due to lower depletable costs.

 

Auditing, accounting and legal expenses increased 75% to $1,102,115 in 2008 from $628,114 in 2007 due to higher auditing, accounting and legal costs incurred in connection with the ATO audit and settlement and tax planning.

 

Accretion expense increased 38% to $716,130 in 2008 from $517,856 in 2007. Accretion expense represents the accretion on the asset retirement obligations (“ARO”) under SFAS 143. The increase was due mostly to accretion of asset retirement obligations relating to the new wells drilled in fiscal 2007 in the Nockatunga project and the 14.1% increase in the exchange rate described below.

 

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. No impairment loss was recorded in fiscal 2008.

 

Other administrative expenses increased 33% to $3,591,856 in 2008 from $2,699,733 in 2007. This was due mostly to increased consulting costs related to the ATO audit and settlement, an increase due to the issuance of directors’ stock options in February, 2008, increased consulting fees relating to research and development in the U.K. and the 14.1% increase in the exchange rate described below.

 

Income Taxes

 

Provision for income tax for the year ended June 30, 2008 was $14,330,301 compared to $998,565 for the year ended June 30, 2007. The increase in the tax provision relates primarily to the payment of tax assessed by the Australian Taxation Office (see Note 6 to the Consolidated Financial Statements) upon settlement of an audit of the Australian income tax returns of MPAL and its wholly owned subsidiaries for the years 1997- 2005.

 

Exchange Effect

 

The value of the Australian dollar relative to the U.S. dollar increased to $.9615 at June 30, 2008 compared to $.8433 at June 30, 2007. This resulted in a $7,317,151 credit to accumulated translation adjustments for fiscal 2008. The 14% increase in the value of the Australian dollar increased the reported asset and liability amounts in the balance sheet at June 30, 2008 from the June 30, 2007 amounts. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2008 was $.8965, which is a 14.1% increase compared to the $.7860 rate for fiscal 2007.

 

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 6) 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 this annual report covering 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.

 

 

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, 2008, the carrying value of such investments and those classified as cash and cash equivalents was approximately $36.3 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. Marketable securities have not been impacted by the US credit crisis. 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 $4.1 million and $3.8 million, respectively. For the twelve months ended June 30, 2008, oil sales represented approximately 52% of production revenues. Based on 2008 sales volume and revenue, a 10% change in oil price would increase or decrease oil revenues by approximately $2.0 million. Gas sales, which represented approximately 48% of production revenues in 2008, 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.

 

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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2008. 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, 2008 and 2007, and the results of their operations and cash flows for each of the three years in the period ended June 30, 2008, in conformity with accounting principles generally accepted in the United States of America.

 

 

 

September 25, 2008

Hartford, Connecticut

MAGELLAN PETROLEUM CORPORATION

 

CONSOLIDATED BALANCE SHEETS

 

 

See accompanying notes.

MAGELLAN PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

See accompanying notes.

MAGELLAN PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF
STOCKHOLDERS’ EQUITY
Three Years Ended June 30, 2008