Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended June 30, 2008
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number 1-5507
 
Magellan Petroleum Corporation
(Exact name of registrant as specified in its charter)
 
     
Delaware
State or other jurisdiction of
incorporation or organization
  06-0842255
(I.R.S. Employer
Identification No.)
10 Columbus Boulevard, Hartford, CT
(Address of principal executive offices)
  06106
(Zip Code)
 
Registrant’s telephone number, including area code
(860) 293-2006
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
    Name of Each Exchange on
Title of Each Class
 
Which Registered
 
Common stock, par value $.01 per share
  NASDAQ Capital Market
 
Securities registered pursuant to Section 12(g) of the Act
Title of Class
None
   
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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):
 
             
Large accelerated filer o
  Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
    (Do not check if a smaller reporting company)            
 
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
 
                 
        Page
 
      Business     3  
      Risk Factors     12  
      Unresolved Staff Comments     18  
      Properties     18  
      Legal Proceedings     22  
      Submission of Matters to a Vote of Security Holders     23  
 
      Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities     23  
      Selected Financial Data     25  
      Management’s Discussion and Analysis of Financial Condition and Results of Operation     26  
      Quantitative and Qualitative Disclosures About Market Risk     34  
      Financial Statements and Supplementary Data     35  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     64  
      Controls and Procedures     64  
      Other Information     65  
 
      Directors, Executive Officers and Corporate Governance     66  
      Executive Compensation     66  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     66  
      Certain Relationships and Related Transactions, and Director Independence     66  
      Principal Accounting Fees and Services     66  
 
      Exhibits and Financial Statement Schedules     67  
 EX-10.L: FORM OF INDEMNIFICATION AGREEMENT
 EX-10.N: FIRST AMENDMENT TO THE 1998 STOCK OPTION PLAN
 EX-10.P: AMENDED AND RESTATED EMPLOYMENT AGREEMENT
 EX-21: SUBSIDIARIES
 EX-23.1: CONSENT OF DELOITTE & TOUCHE LLP
 EX-23.2: CONSENT OF PADDOCK LINDSTROM & ASSOCIATES, LTD.
 EX-31: CERTIFICATIONS
 EX-32: CERTIFICATIONS
 
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.


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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.


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PART I
 
Item 1.   Business
 
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.


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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:
 
         
Period
  Bcf  
 
Less than one year
    5.23  
Between 1-5 years
    3.22  
Greater than 5 years
    0.00  
         
Total
    8.45  
         


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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


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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.


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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.


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(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.


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(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.
 
         
Permit
 
Expiration Date
 
Location
 
Petroleum Lease No. 4 and No. 5 (Mereenie) (Amadeus Basin)
  November 2023   Northern Territory, Australia
Petroleum Lease No. 3 (Palm Valley)
(Amadeus Basin)
  November 2024   Northern Territory, Australia
Retention License No. 2 (Dingo)
(Amadeus Basin)
  February 2009   Northern Territory, Australia
Petroleum Lease No. 33 (Nockatunga)
(Cooper Basin)
  April 2007
(Renewal application pending)
  Queensland, Australia
Petroleum Lease No. 50 and No. 51 (Nockatunga) (Cooper Basin)
  June 2011   Queensland, Australia
Petroleum Lease No. 244 (Currambar)
(Cooper Basin)
  Application pending   Queensland, Australia
Petroleum Lease No. 245 (Maxwell South)
(Cooper Basin)
  Application pending   Queensland, Australia
Petroleum Production License No. 210 (Aldinga) (Cooper Basin)
  Held by production   South Australia
Petroleum Production License No. 212 (Kiana) (Cooper Basin)
  Held by production   South Australia
ATP 267P (Nockatunga) (Cooper Basin)
  November 2007
(Renewal application pending)
  Queensland, Australia
ATP 613P (Maryborough Basin)
  March 2019   Queensland, Australia
ATP 674P (Maryborough Basin)
  Application pending   Queensland, Australia
ATP 733P (Maryborough Basin)
  Application pending   Queensland, Australia
ATP 732P (Cooper Basin)
  Application pending   Queensland, Australia
PEL 94 (Cooper Basin)
  May 2012   South Australia
PEL 95 (Cooper Basin)
  October 2011   South Australia
PEL 107 (Cooper Basin)
  December 2008   South Australia
PEL 110 (Cooper Basin)
  November 2008   South Australia
PEDL 098 (Weald-Wessex Basins)
  September 2011   United Kingdom
PEDL 099 (Weald-Wessex Basins)
  September 2008   United Kingdom
PEDL 125 (Weald-Wessex Basins)
  June 2009   United Kingdom
PEDL 126 (Weald-Wessex Basins))
  June 2009   United Kingdom
PEDL 135 (Weald Basin)
  September 2010   United Kingdom
PEDL 136 (Weald Basin)
  September 2010   United Kingdom
PEDL 137 (Weald Basin)
  September 2010   United Kingdom
PEDL 152 (Weald-Wessex Basin)
  September 2010   United Kingdom
PEDL 153 (Weald Basin)
  September 2010   United Kingdom
PEDL 154 (Weald Basin)
  September 2010   United Kingdom
PEDL 155 (Weald-Wessex Basins)
  September 2010   United Kingdom
 
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


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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.


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(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.


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(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.
 
Item 1A.   Risk Factors
 
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


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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.


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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.


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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:
 
  •  worldwide and domestic supplies of oil and gas;
 
  •  changes in the supply and demand for such fuels;
 
  •  political conditions in oil, natural gas, and other fuel-producing and fuel-consuming areas;
 
  •  the extent of Australian domestic oil and gas production and importation of such fuels and substitute fuels in Australian and other relevant markets;
 
  •  weather conditions, including effects on prices and supplies in worldwide energy markets because of recent hurricanes in the United States;
 
  •  the competitive position of each such fuel as a source of energy as compared to other energy sources; and
 
  •  the effect of governmental regulation on the production, transportation, and sale of oil, natural gas, and other fuels.
 
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.


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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.


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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:
 
  •  unexpected drilling conditions;
 
  •  title problems;
 
  •  pressure or irregularities in formations;
 
  •  equipment failures or accidents;
 
  •  adverse weather conditions;
 
  •  compliance with environmental and other governmental requirements; and
 
  •  increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.
 
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


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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:
 
  •  injury or loss of life;
 
  •  severe damage to or destruction of property, natural resources and equipment;
 
  •  pollution or other environmental damage;
 
  •  clean-up responsibilities;
 
  •  regulatory investigations and penalties;
 
  •  and suspension of operations.
 
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.
 
Item 1B.   Unresolved Staff Comments.
 
None
 
Item 2.   Properties.
 
(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


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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):
 
                         
    2008     2007     2006  
 
Australia:
                       
Gas (bcf)
    5.7       5.9       5.7  
Crude oil (bbl)
    211,000       179,000       155,000  
 
The average sales price per unit of production for Australia for the following fiscal years is as follows:
 
                         
    2008     2007     2006  
 
Australia:
                       
Gas (per mcf)
  A.$ 3.39     A.$ 3.24     A.$ 3.04  
Crude oil (per bbl)
  A.$ 102.35     A.$ 80.75     A.$ 86.17  
 
The average production cost per unit of production for Australia for the following fiscal years is as follows:
 
                         
    2008     2007     2006  
 
Australia:
                       
Gas (per mcf)
  A.$ .82     A.$ .71     A.$ .93  
Crude oil (per bbl)
  A.$ 17.98     A.$ 18.55     A.$ 26.59  
 
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.


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(4) Productive Wells and Acreage.
 
Productive wells and acreage at June 30, 2008
 
                                                 
    Productive Wells              
    Oil     Gas     Developed Acreage  
    Gross     Net     Gross     Net     Gross Acres     Net Acres  
 
Australia
    45.0       17.1       15.0       6.10       84,930       37,523  
Canada
                3.0       .08       3,350       89  
                                                 
      45.0       17.1       18.0       6.18       88,280       37,612  
                                                 


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(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.
 
                         
    MPC  
                Interest
 
    Gross Acres     Net Acres     %  
 
Australia
                       
Northern Territory
                       
PL 4/PL 5 Mereenie (Amadeus Basin)(1)
    70,049       24,517       35.0000  
PL 3 Palm Valley (Amadeus Basin)(2)
    157,932       82,161       52.0230  
RL 2 Dingo (Amadeus Basin)
    116,139       39,878       34.3365  
                         
      344,120       146,556          
                         
Queensland:
                       
PL 33/PL 50/PL 51 Nockatunga (Cooper Basin)(3)
    87,932       35,996       40.936  
ATP 267P (Cooper Basin)
    120,783       49,444       40.936  
ATP 613P (Maryborough Basin)
    153,387       153,387       100.000  
                         
      362,102       238,827          
                         
South Australia:
                       
PPL 210 Aldinga (Cooper Basin)(4)
    939       469       50.00  
PPL 212 Kiana (Cooper Basin)(5)
    395       119       30.00  
PEL 94 (Cooper Basin)
    445,588       155,956       35.00  
PEL 95 (Cooper Basin)
    637,507       318,754       50.00  
PEL 107 (Cooper Basin)
    201,058       40,212       20.00  
PEL 110 (Cooper Basin)
    361,114       135,418       37.50  
                         
      1,646,601       650,928          
                         
United Kingdom:
                       
PEDL 098/152 (Wessex Basin)
    29,467       6,630       22.50  
PEDL 099/125/126/155 (Weald Basin)
    137,602       55,041       40.00  
PEDL 135/136/137 (Weald Basin)
    123,152       123,152       100.00  
PEDL 153 (Weald Basin)
    66,242       22,078       33.33  
PEDL 154 (Weald Basin)
    84,834       42,417       50.00  
                         
      441,297       249,318          
                         
Total MPAL
    2,794,120       1,285,629          
                         
Properties held directly by MPC:
                       
Canada
                       
Yukon and Northwest Territories:
                       
Kotaneelee carried interest(6)
    31,885       850       2.67  
                         
Total
    2,826,005       1,286,479          
                         
 
 
(1) Includes 41,644 gross developed acres and 21,665 net acres.


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(2) Includes 31,567 gross developed acres and 11,048 net acres.
 
(3) Includes 11,200 gross developed acres and 4,585 net acres.
 
(4) Includes 346 gross developed acres and 173 net acres.
 
(5) Includes 173 gross developed acres and 52 net acres.
 
(6) Includes 3,350 gross developed acres and 89 net acres.
 
(6) Drilling Activity.
 
Productive and dry net wells drilled during the following years (data concerning Canada and the United States is insignificant):
 
                                 
    Australia/New Zealand  
Year Ended
  Exploration     Development  
June 30,
  Productive     Dry     Productive     Dry  
 
2008
    0.00       0.90       0.41        
2007
    0.82       1.55       3.27        
2006
    1.01       0.53       0.82        
 
(7) Present Activities.
 
See Item 1 — Cooper Basin and United Kingdom for a discussion of the present activities of MPAL.
 
(8) Delivery Commitments.
 
See discussion under Item 1 concerning the Palm Valley and Mereenie fields.
 
Item 3.   Legal Proceedings.
 
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


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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.
 
Item 4.   Submission of Matters to a Vote of Security Holders.
 
None.
 
PART II
 
Item 5.   Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Securities
 
(a) Principal Market
 
The principal market for MPC’s common stock is the NASDAQ Capital Market under the symbol MPET. The stock is also traded on the Australian Stock Exchange in the form of CHESS depository interests under the symbol MGN. The quarterly high and low prices on the most active market, NASDAQ, during the quarterly periods indicated were as follows:
 
                                 
2008
  1st Qtr.   2nd Qtr.   3rd Qtr.   4th Qtr.
 
High
    1.67       1.14       1.26       1.87  
Low
    1.01       0.89       0.87       1.16  
 
                                 
2007
  1st Qtr.   2nd Qtr.   3rd Qtr.   4th Qtr.
 
High
    1.65       1.47       1.49       1.74  
Low
    1.25       1.20       1.21       1.38  
 
(b) Approximate Number of Holders of Common Stock at September 10, 2008
 
         
Title of Class
  Number of Record Holders
 
Common stock, par value $.01 per share
    5,975  
 
(c) Frequency and Amount of Dividends
 
MPC has never paid a cash dividend on its common stock.
 
Recent Sales of Unregistered Securities
 
None


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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:
 
                                 
                      Maximum
 
                Total Number of
    Number of
 
    Total Number of
    Average Price
    Shares Purchased
    Shares that May
 
    Shares
    Paid
    as Part of Publicly
    Yet Be Purchased
 
Period
  Purchased     per Share     Announced Plan(1)     Under Plan  
 
April 1-30, 2008
    0       0       0       319,150  
May 1-31, 2008
    0       0       0       319,150  
June 1-30, 2008
    0       0       0       319,150  
 
 
(1) The Company through its stock repurchase plan may purchase up to one million shares of its common stock in the open market. Through June 30, 2008, the Company had purchased 680,850 of its shares at an average price of $1.01 per share, or a total cost of approximately $686,000, all of which shares have been cancelled. No shares were purchased during 2008, 2007 or 2006.


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Item 6.   Selected Financial Data.
 
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.
 
                                         
    Years Ended June 30,  
    2008     2007     2006     2005     2004  
 
Financial Data
                                       
Total revenues
  $ 40,895     $ 30,675     $ 26,562     $ 21,871     $ 19,424  
                                         
Net (loss) income
    (8,892 )     447       749       87       350  
                                         
Net (loss) income per share (basic and diluted)
    (.21 )     .01       . 03             .01  
                                         
Working capital
    37,780       29,004       24,820       26,208       21,696  
                                         
Cash provided by operating activities
    4,211       21,274       11,766       8,776       10,718  
                                         
Property and equipment (net)
    28,447       40,321       27,783       24,265       24,421  
                                         
Total assets
    85,295       85,616       68,580       56,424       52,894  
                                         
Long-term liabilities
    14,153       13,076       8,583       5,729       5,256  
                                         
Minority interests
                      18,583       16,533  
                                         
Stockholders’ equity:
                                       
Capital
    73,631       73,568       73,560       44,660       44,660  
Accumulated deficit
    (22,858 )     (13,966 )     (14,413 )     (15,161 )     (15,248 )
Accumulated other comprehensive income (loss)
    11,690       4,373       (3,028 )     (2,323 )     (4,491 )
                                         
Total stockholders’ equity
    62,463       63,975       56,119       27,176       24,920  
                                         
Exchange rate A.$ = U.S. at end of period
    .96       .84       .73       .76       .70  
                                         
Common stock outstanding shares end of period
    41,500       41,500       41,500       25,783       25,783  
                                         
Book value per share
    1.51       1.54       1.35       1.05       .97  
                                         
Quoted market value per share (NASDAQ)
    1.62       1.52       1.57       2.40       1.31  
                                         
Operating Data
                                       
Standardized measure of discounted future cash flow relating to proved oil and gas reserves (approximately 45% attributable to minority interest in 2005 and prior) (See Note 13)
    45,000       34,000 (1)     70,000       31,000       30,000  
                                         
Annual production (net of royalties) Gas (bcf)
    5.7       5.9       5.7       5.7       5.7  
                                         
Oil (bbls) (In thousands)
    211       179       155       151       150  
                                         
 
 
(1) Restated — see Note 13


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
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


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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.


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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.


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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.


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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:
 
                                         
    Payments Due by Period  
          Less Than
                More Than
 
Contractual Obligations
  Total     1 Year     1-3 Years     3-5 Years     5 Years  
 
Operating Lease Obligations
  $ 261,000     $ 256,000     $ 5,000     $     $  
Purchase Obligations(1)
    8,155,000       8,155,000                    
Asset Retirement Obligations
    11,596,000             7,412,000       2,009,000       2,175,000  
                                         
Total
  $ 20,012,000     $ 8,411,000     $ 7,417,000     $ 2,009,000     $ 2,175,000  
                                         
 
 
(1) Represents firm commitments for exploration and capital expenditures. The Company is committed to these expenditures, however some may be farmed out to third parties. Exploration contingent expenditures of $26,755,000 which are not legally binding have been excluded from the table above and based on exploration decisions would be due as follows: $0 (less than 1 year), $26,731,000 (1-3 years), $24,000 (3-5 years).
 
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%


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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:
 
                                 
    Twelve Months Ended June 30,  
    2008 Sales     2007 Sales  
          Average Price
          Average Price
 
    Bbls     A.$ per bbl     Bbls     A.$ per bbl  
 
Australia:
                               
Mereenie Field
    95,429       113.33       100,852       82.75  
Cooper Basin
    6,826       114.28       15,261       85.02  
Nockatunga Project
    108,311       91.82       63,252       76.50  
                                 
Total
    210,566       102.35       179,365       80.75  
                                 
 
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:
 
                                 
    Twelve Months Ended June 30,  
    2008 Sales     2007 Sales  
          A.$ Average
          A.$ Average
 
    Bcf     Price per mcf     Bcf     Price per mcf  
 
Australia: Palm Valley
    1.319       2.22       1.499       2.20  
Australia: Mereenie
    4.388       3.77       4.489       3.60  
                                 
Total
    5.707       3.39       5.988       3.24  
                                 
 
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


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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:
 
                                 
    Twelve Months Ended June 30,  
    2007 Sales     2006 Sales  
          Average Price
          Average Price
 
    Bbls     A.$ per bbl     Bbls     A.$ per bbl  
 
Australia:
                               
Mereenie Field
    100,852       82.75       99,838       86.23  
Cooper Basin
    15,261       85.02       20,700       94.91  
Nockatunga Project
    63,252       76.50       34,127       80.79  
                                 
Total
    179,365       80.75       154,665       86.17  
                                 


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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:
 
                                 
    Twelve Months Ended June 30,  
    2007 Sales     2006 Sales  
          A.$ Average
          A.$ Average
 
    Bcf     Price per mcf     Bcf     Price per mcf  
 
Australia: Palm Valley
    1.499       2.20       1.698       2.17  
Australia: Mereenie
    4.489       3.60       4.028       3.42  
                                 
Total
    5.988       3.24       5.726       3.04  
                                 
 
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


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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.
 
Item 7A.   Quantitative and Qualitative Disclosure About Market Risk.
 
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.


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Item 8.   Financial Statements and Supplementary Data.
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Stockholders of
Magellan Petroleum Corporation
Hartford, Connecticut
 
We have audited the accompanying consolidated balance sheets of Magellan Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 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.
 
 
/s/  Deloitte & Touche LLP
 
September 25, 2008
Hartford, Connecticut


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MAGELLAN PETROLEUM CORPORATION
 
CONSOLIDATED BALANCE SHEETS
 
                 
    June 30,  
    2008     2007  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 34,615,228     $ 28,470,448  
Accounts receivable — Trade (net of allowance for doubtful accounts of $99,344 and $69,658 at June 30, 2008 and 2007, respectively)
    8,357,839       5,044,258  
Accounts receivable — working interest partners
    112,330        
Marketable securities
    1,708,222       2,974,280  
Inventories
    1,260,189       702,356  
Other assets
    404,160       378,808  
                 
Total current assets
    46,457,968       37,570,150  
                 
Deferred income taxes
    6,368,665       2,300,830  
Marketable securities
          1,403,987  
Property and equipment, net:
               
Oil and gas properties (successful efforts method)
    138,556,513       120,734,449  
Land, buildings and equipment
    3,346,368       2,846,433  
Field equipment
    1,040,281       912,396  
                 
      142,943,162       124,493,278  
Less accumulated depletion, depreciation and amortization
    (114,495,875 )     (84,172,522 )
                 
Net property and equipment
    28,447,287       40,320,756  
Goodwill
    4,020,706       4,020,706  
                 
Total assets
  $ 85,294,626     $ 85,616,429  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 2,929,445     $ 5,313,653  
Accounts payable-working interest partners
          222,883  
Accrued liabilities
    1,891,194       1,382,320  
Income taxes payable
    3,857,766       1,647,137  
                 
Total current liabilities
    8,678,405       8,565,993  
                 
Long term liabilities:
               
Deferred income taxes
    2,507,712       3,518,990  
Other long term liabilities
    48,998       100,578  
Asset retirement obligations
    11,596,084       9,456,088  
                 
Total long term liabilities
    14,152,794       13,075,656  
                 
Commitments (Note 11)
           
Stockholders’ equity:
               
Common stock, par value $.01 per share: Authorized 200,000,000 shares outstanding 41,500,325
    415,001       415,001  
Capital in excess of par value
    73,216,143       73,153,002  
Accumulated deficit
    (22,857,494 )     (13,965,849 )
Accumulated other comprehensive income
    11,689,777       4,372,626  
                 
Total stockholders’ equity
    62,463,427       63,974,780  
                 
Total liabilities and stockholders’ equity
  $ 85,294,626     $ 85,616,429  
                 
 
See accompanying notes.


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MAGELLAN PETROLEUM CORPORATION
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
Revenues:
                       
Oil sales
  $ 19,786,175     $ 11,922,574     $ 10,615,761  
Gas sales
    18,523,095       16,396,334       14,060,968  
Other production related revenues
    2,585,540       2,356,317       1,885,706  
                         
Total revenues
    40,894,810       30,675,225       26,562,435  
                         
Costs and expenses:
                       
Production costs
    8,865,663       6,965,641       8,220,013  
Exploratory and dry hole costs
    3,318,810       5,520,460       3,264,837  
Salaries and employee benefits
    1,605,341       1,549,277       1,448,004  
Depletion, depreciation and amortization
    18,021,236       10,693,415       6,308,608  
Auditing, accounting and legal services
    1,102,115       628,114       398,514  
Accretion expense
    716,130       517,856       425,254  
Shareholder communications
    392,880       459,298       449,561  
Loss on settlement of asset retirement obligation
                444,566  
Gain on sale of field equipment
    (35,235 )     (10,346 )     (119,445 )
Impairment loss
          1,876,171        
Other administrative expenses
    3,591,856       2,699,733       2,795,387  
                         
Total costs and expenses
    37,578,796       30,899,619       23,635,299  
                         
Operating income (loss)
    3,316,014       (224,394 )     2,927,136  
Interest income
    2,122,642       1,669,798       1,268,641  
                         
Income before income taxes and minority interests
    5,438,656       1,445,404       4,195,777  
Income tax expense
    14,330,301       998,565       1,678,980  
                         
(Loss) income before minority interests
    (8,891,645 )     446,839       2,516,797  
Minority interests
                (1,768,023 )
                         
Net (loss) income
  $ (8,891,645 )   $ 446,839     $ 748,774  
                         
Average number of shares:
                       
Basic
    41,500,325       41,500,325       28,353,463  
                         
Diluted
    41,500,325       41,500,325       28,453,270  
                         
Per share (basic and diluted)
                       
Net (loss) income
  $ (.21 )   $ .01     $ .03  
                         
 
See accompanying notes.


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MAGELLAN PETROLEUM CORPORATION
 
CONSOLIDATED STATEMENTS OF
STOCKHOLDERS’ EQUITY
Three Years Ended June 30, 2008
 
                                                         
                            Accumulated
             
                Capital in
          Other
          Total
 
    Number of
    Common
    Excess of
    Accumulated
    Comprehensive
          Comprehensive
 
    Shares     Stock     Par Value     Deficit     Income (Loss)     Total     Income (Loss)  
 
June 30, 2005
    25,783,243     $ 257,832     $ 44,402,182     $ (15,161,462 )   $ (2,322,633 )   $ 27,175,919          
                                                         
Net income
                      748,774             748,774     $ 748,774  
Foreign currency translation adjustments
                            (705,817 )     (705,817 )     (705,817 )
                                                         
Stock exchange
    15,716,895       157,169       28,367,956                   28,525,125          
Stock option compensation
                375,439                   375,439          
Total comprehensive income
                                        42,957  
                                                         
June 30, 2006
    41,500,138       415,001       73,145,577       (14,412,688 )     (3,028,450 )     56,119,440          
                                                         
Net income
                      446,839             446,839       446,839  
Foreign currency translation adjustments
                            7,401,076       7,401,076       7,401,076  
                                                         
Stock exchange
    187                                          
Stock option compensation
                7,425                   7,425          
Total comprehensive income
                                        7,847,915  
                                                         
June 30, 2007
    41,500,325       415,001       73,153,002       (13,965,849 )     4,372,626       63,974,780          
                                                         
Net loss
                      (8,891,645 )           (8,891,645 )     (8,891,645 )
Foreign currency translation adjustments
                            7,317,151       7,317,151       7,317,151  
                                                         
Stock option compensation
                63,141                   63,141          
Total comprehensive loss
                                      $ (1,574,494 )
                                                         
June 30, 2008
    41,500,325     $ 415,001     $ 73,216,143     $ (22,857,494 )   $ 11,689,777     $ 62,463,427          
                                                         
 
See accompanying notes.


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MAGELLAN PETROLEUM CORPORATION
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
Operating Activities:
                       
Net (loss) income
  $ (8,891,645 )   $ 446,839     $ 748,774  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Gain from sale of field equipment
    (35,235 )     (10,346 )     (119,445 )
Depletion, depreciation and amortization
    18,021,236       10,693,415       6,314,049  
Accretion expense
    716,130       517,856       425,254  
Deferred income taxes
    (4,541,695 )     (1,818,631 )     (157,300 )
Director’s options expense
    63,141       7,425       375,439  
Minority interests
                1,768,023  
Exploration and dry hole costs
    3,227,200       4,871,865       2,997,026  
Loss on settlement of asset retirement obligation
                444,566  
Impairment loss
          1,876,171        
Increase (decrease) in operating assets and liabilities:
                       
Accounts receivable
    (2,640,315 )     472,763       (774,696 )
Other assets
    (26,946 )     (61,312 )     209,207  
Inventories
    (428,332 )     143,951       (170,664 )
Accounts payable and accrued liabilities
    (3,112,940 )     2,474,106       (368,724 )
Income taxes payable
    1,860,666       1,659,711       74,416  
                         
Net cash provided by operating activities
    4,211,265       21,273,813       11,765,925  
                         
Investing Activities:
                       
Additions to property and equipment(1)
    (1,628,476 )     (9,231,029 )     (5,700,232 )
Proceeds from sale of field equipment
    35,235       10,346       119,445  
Oil and gas exploration activities
    (3,227,200 )     (4,871,865 )     (2,997,026 )
Acquisition of minority interest in MPAL
          (88,432 )     (3,630,374 )
Marketable securities matured
    4,435,820       1,855,609       5,044,574  
Marketable securities purchased
    (1,765,775 )     (5,694,201 )     (2,367,707 )
                         
Net cash used in investing activities(1)
    (2,150,396 )     (18,019,572 )     (9,531,320 )
                         
Financing Activities:
                       
Dividends to MPAL minority shareholders
                (765,641 )
                         
Net cash used in financing activities
                (765,641 )
                         
Effect of exchange rate changes on cash and cash equivalents
    4,083,911       3,333,325       (1,319,457 )
                         
Net increase in cash and cash equivalents
    6,144,780       6,587,566       149,507  
Cash and cash equivalents at beginning of year
    28,470,448       21,882,882       21,733,375  
                         
Cash and cash equivalents at end of year
  $ 34,615,228     $ 28,470,448     $ 21,882,882  
                         
Cash Payments:
                       
Income taxes
    13,072,505       1,427,327       1,773,727  
Interest on tax settlement
    3,893,014              
Supplemental Schedule of Noncash Investing and Financing Activities:
                       
Revision to estimate of asset retirement obligations
    43,482       (54,765 )     1,667,877  
Asset retirement obligation liabilities incurred
          718,048        
Accounts payable related to property and equipment
    1,993,964       1,417,051       802,781  
 
The allocation of the purchase price to the assets acquired in the purchase of remaining minority interest in MPAL in 2006 was finalized in the fourth quarter of fiscal 2007. This resulted in a decrease in the amount of goodwill by $1,626,041 which was reallocated to oil and gas properties ($4,642,233) offset by an increase to deferred tax liabilities ($3,016,192). In fiscal year 2006, the Company purchased the remaining minority shares of MPAL for $32,155,498 which included cash consideration of $1,563,507, transaction costs of $2,078,804 and stock consideration of $28,601,581. Costs of registering securities in the amount of $76,457 were treated as a reduction to additional paid in capital (see Note 2 to the Consolidated Financial Statements).
 
         
Fair value of assets acquired
  $ 41,085,190  
Consideration paid for capital stock
    32,243,893  
         
Liabilities assumed
    8,841,297  
         
 
 
(1) Due to a typographical error, 2006 numbers are changed from previously reported.
 
See accompanying notes.


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1.   Summary of Significant Accounting Policies
 
Principles of Consolidation
 
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 and 2007, MPC’s principal asset was a 100% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”) (See Note 2). 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 field (41% working interest). Both the Mereenie and Palm Valley fields are located in the Amadeus Basin in the Northern Territory of Australia. The Nockatunga field is located in the Cooper Basin in South Australia. MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada.
 
The accompanying consolidated financial statements include the accounts of MPC and its subsidiary, MPAL, collectively the Company. All intercompany transactions have been eliminated.
 
Revenue Recognition
 
The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Company’s share of production. Revenues from the purchase, sale and transportation of natural gas are recognized upon completion of the sale and when transported volumes are delivered. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which are recorded at the time of sale. The Company records pipeline tariff revenues on a gross basis. The revenue is included in other production related revenues, while 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 at which 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.
 
Stock-Based Compensation
 
The Company has one stock option plan. Under FASB Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123(R)”) the costs resulting from all share-based payment transactions are recognized in the consolidated financial statements. This statement establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires the application of a fair-value measurement method of accounting for share-based payment transactions with employees and non-employees. The Company uses the Black-Scholes option valuation model to determine the fair value of its stock option share awards. The Black-Scholes model includes various assumptions, including the expected volatility and the expected life of the share awards. These assumptions reflect the Company’s best estimates, but they involve inherent uncertainties based on market conditions generally outside of the control of the Company. As a result, if other assumptions had been used, stock-based compensation expense, as calculated and recorded under SFAS 123(R) could have been significantly impacted. Furthermore, if the Company uses different assumptions in future periods, stock-based compensation expense could be significantly impacted in future periods. The Company’s policy for attributing the value of graded vested share-based payments is an accelerated multiple-option approach.
 
Oil and Gas Properties
 
Oil and gas properties are located in Australia, Canada and the United Kingdom. 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 permitted 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 its working interest agreements in the respective classifications of assets, liabilities and expenses. Unproved properties with significant acquisition costs


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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 at June 30, 2008 and 2007 associated with exploration permits and licenses in Australia and the U.K. The Company evaluates exploration permits and licenses annually or whenever events or changes in circumstances indicate that the carrying value may be impaired. 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.
 
Asset Retirement Obligations
 
Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset (oil & gas properties) and amortized on a units-of-production basis over the life of the related reserves. Accretion expense in connection with the discounted liability is recognized over the remaining life of the related reserves.
 
The estimated liability is based on the future estimated cost of land reclamation, plugging the existing oil and gas wells and removing the surface facilities equipment in the Palm Valley, Mereenie, and Nockatunga fields and the Cooper Basin. 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.


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Use of Estimates
 
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
 
Land, Buildings and Equipment and Field Equipment
 
Land, buildings and equipment and field equipment are carried at cost. Depreciation and amortization are provided on a straight-line basis over their estimated useful lives. The estimated useful lives are: buildings — 40 years, equipment and field equipment — 3 to 15 years.
 
Inventories
 
Inventories consist of crude oil in various stages of transit to the point of sale and are valued at the lower of cost (determined on an average cost basis) or market.
 
Foreign Currency Translations
 
The accounts of MPAL, whose functional currency is the Australian dollar, are translated into U.S. dollars in accordance with Statement of Financial Accounting Standards No. 52, “Foreign Currency Translation”. The translation adjustment is included as a component of stockholders’ equity and comprehensive income (loss), whereas gains or losses on foreign currency transactions are included in the determination of income. All assets and liabilities are translated at the rates in effect at the balance sheet dates. Revenues, expenses, gains and losses are translated using quarterly weighted average exchange rates during the period. At June 30, 2008 and 2007, the Australian dollar was equivalent to U.S. $.9615 and $.8433, respectively. The annual average exchange rates used to translate MPAL’s operations in Australia for the fiscal years 2008, 2007 and 2006 were $.8965, $.7860 and $.7477, respectively.
 
Accrued Liabilities
 
At June 30, 2008 and 2007, balances in accrued liabilities which exceeded 5% of current liabilities include $953,240 and $865,304 of employment benefits, respectively, and $596,975 and $358,589 of withholding and sale taxes, respectively.
 
Accounting for Income Taxes
 
The Company follows FASB Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”), the liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company records a valuation allowance for deferred tax assets when it is more likely than not that such assets will not be recovered.
 
FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) is an interpretation of SFAS 109 and was adopted by the Company on July 1, 2007. Under FIN 48, a company recognizes an uncertain tax position (“UTP”) based on whether it is more likely than not that the UTP will be sustained upon examination by the appropriate taxing authority, including resolution of any related appeals or litigation processes, based solely on the technical merits of the position. In evaluating whether a UTP has met the more-likely-than-not recognition threshold, a company must presume that its positions will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step of FIN 48 adoption is measurement. A UTP that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The UTP is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. A UTP is not recognized if it does not meet the more-likely-than-not threshold.


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The Company has adopted an accounting policy to record all tax related interest and penalties in its tax provision calculation.
 
Financial Instruments
 
The carrying value for cash and cash equivalents, accounts receivable, marketable securities and accounts payable approximates fair value based on anticipated cash flows and current market conditions.
 
Cash and Cash Equivalents
 
The Company considers all highly liquid short term investments with maturities of three months or less at the date of acquisition to be cash equivalents. Cash and cash equivalents are carried at cost which approximates market value. The components of cash and cash equivalents are as follows:
 
                 
    June 30,  
    2008     2007  
 
Cash
  $ 2,916,069     $ 3,421,271  
Australian money market accounts and short-term commercial paper
    31,699,159       25,049,177  
                 
    $ 34,615,228     $ 28,470,448  
                 
 
Marketable Securities
 
The Company has determined that declines in fair value below amortized costs are temporary and as management has the intent and ability to hold the securities to maturity, no impairment loss has been recognized. At June 30, 2008 and 2007, MPC had the following marketable securities which are expected to be held until maturity:
 
                                 
June 30, 2008
  Par Value     Maturity Date     Amortized Cost     Fair Value  
 
Short-term securities
                               
U.S. government agency note
  $ 200,000       Aug. 15, 2008     $ 200,152     $ 200,688  
U.S. government agency note
    250,000       Oct. 15, 2008       250,142       251,485  
U.S. government agency note
    250,000       Nov. 21, 2008       252,314       251,952  
U.S. government agency note
    255,000       Dec. 15, 2008       250,560       252,042  
U.S. government agency note
    250,000       Jan. 15, 2009       254,141       253,283  
U.S. government agency note
    250,000       Apr. 20, 2009       255,473       254,220  
U.S. government agency note
    250,000       Mar. 30, 2009       245,440       245,050  
                                 
Total short-term
  $ 1,705,000             $ 1,708,222     $ 1,708,720  
                                 
 


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June 30, 2007
  Par Value     Maturity Date     Amortized Cost     Fair Value  
 
Short-term securities
                               
Marketable securities
                               
U.S. government agency note
  $ 250,000       July 10, 2007     $ 246,291     $ 249,725  
U.S. government agency note
    250,000       Aug. 13, 2007       245,124       248,500  
U.S. government agency note
    250,000       Sept. 17, 2007       243,943       247,275  
U.S. government agency note
    250,000       Oct. 15, 2007       243,119       246,300  
U.S. government agency note
    250,000       Nov. 30, 2007       241,548       244,675  
U.S. government agency note
    250,000       Dec. 18, 2007       251,283       250,848  
U.S. government agency note
    250,000       Jan. 15, 2008       250,562       250,158  
U.S. government agency note
    250,000       Feb. 08, 2008       249,843       249,375  
U.S. government agency note
    250,000       Mar. 05, 2008       249,814       249,140  
U.S. government agency note
    250,000       Apr. 18, 2008       250,254       249,610  
U.S. government agency note
    250,000       May. 15, 2008       252,251       251,408  
U.S. government agency note
    250,000       Jun. 20, 2008       250,248       249,298  
                                 
Total short-term
    3,000,000               2,974,280       2,986,312  
                                 
Long-term securities
                               
U.S. government agency note
    200,000       Aug. 15, 2008       201,344       200,376  
U.S. government agency note(1)
    200,000       Sept. 12, 2008       200,052       199,074  
U.S. government agency note(2)
    500,000       Apr. 15, 2009       501,246       499,065  
U.S. government agency note(2)
    500,000       Feb. 08, 2010       501,345       499,020  
                                 
Total long-term
    1,400,000               1,403,987       1,397,535  
                                 
Total securities
  $ 4,400,000             $ 4,378,267     $ 4,383,847  
                                 
 
 
(1) This security was sold in June 2008
 
(2) These securities were called in February 2008
 
Earnings per Share
 
Earnings per common share are based upon the weighted average number of common and common equivalent shares outstanding during the period. The only reconciling item in the calculation of diluted EPS is the dilutive effect of stock options which were computed using the treasury stock method. In 2008, the Company had 100,000 outstanding options that were issued that had a strike price below the average stock price for the period and resulted in 8,661 incremental diluted shares for the respective period. However, since the Company incurred a loss from operations, the incremental shares are anti-dilutive. In 2007, the Company did not issue any stock options. At June 30, 2007, the Company had 430,000 stock options outstanding that were anti-dilutive. There were no other potentially dilutive items at June 30, 2007. At June 30, 2006, the Company had 430,000 stock options that were issued that had a strike price below the average stock price for the year and resulted in 99,807 incremental diluted shares. There were no other potentially dilutive items at June 30, 2006.
 
Stock Options
 
The Company’s 1998 Stock Option Plan (the “Plan”) provides for grants of non-qualified stock options principally at an option price per share of 100% of the fair value of the Company’s common stock on the date of the grant. The Plan originally had 1,000,000 shares authorized for awards of equity share options. Stock options are generally granted with a 3-year vesting period and a 10-year term. The stock options vest in equal annual installments over the vesting period, which is also the requisite service period. The 400,000 options granted to Directors on November 28, 2005 and 100,000 on February 18, 2008 each vested immediately.

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SFAS 123(R) requires recognition in the financial statements of the cost resulting from all share-based payment transactions by applying a fair-value-based measurement method to account for all share-based payment transactions with employees.
 
Accumulated Other Comprehensive Income
 
Accumulated other comprehensive income at June 30, 2008 and 2007 was as follows:
 
                 
    2008   2007
 
Foreign currency translation adjustments
  $ 11,689,777     $ 4,372,626  
                 
 
Sales Taxes
 
Government sales taxes related to MPAL’s oil and gas production revenues are collected by MPAL and remitted to the Australian government. Such amounts are recorded net in the consolidated statements of income.
 
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 asset 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.
 
2.   Acquisition of Minority Interest of 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 “Minority Shares”). 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 MPC registered 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.”
 
The purpose of the acquisition of the Minority Shares was to create a simpler, unified capital structure in which equity investors can participate at a single level. The Company believes that the unified capital structure provides the following benefits: 1) greater liquidity for investors due to a larger combined public float of MPC shares in the US and on the Australian Stock Exchange (“ASX”), 2) more efficient uses of consolidated financial resources through the facilitation of the investment and transfer of funds between Magellan and MPAL and its subsidiaries, 3) alignment of corporate strategies, 4) improved ability of Magellan to raise equity capital or debt financing for future strategic initiatives or exploration activities on potentially more favorable terms, and 5) opportunities for significant cost reductions and organizational efficiencies such as the reduction in costs related to ASX listing fees, regulatory filings and compliance related to MPAL shares that have now been delisted from the ASX. Effective July 1, 2006, 100% of MPAL’s operations are reflected in the consolidated statement of income.


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The Offer was accounted for using the purchase method of accounting. Under the purchase method of accounting, the total purchase price was allocated to the minority interests’ proportionate interest in MPAL’s identifiable assets and liabilities acquired by MPC based upon their estimated fair values. The fair value of the significant assets acquired (primarily oil and gas properties) and the liabilities assumed was determined by management. The purchase price allocation process was finalized in the fourth quarter of fiscal year 2007 after receipt of final appraisals.
 
The purchase price of the exchange offer was $32,243,893. This was based upon a value of $1.82 per share of MPC common stock for the 15,716,895 shares issued, cash consideration of $1,563,507 and transaction costs of $2,078,804. The value of the MPC common stock issued was determined based on the average market price of MPC’s common stock over the 3-day period before and 3-day period after the date that MPAL agreed to recommend the terms of the acquisition.
 
The following table summarizes the estimated fair values of the assets acquired and the liabilities assumed at June 30, 2006:
 
         
Current assets
  $ 12,153,855  
Property and equipment
    24,418,588  
Deferred income taxes
    492,041  
Goodwill
    4,020,706  
         
Total assets acquired
    41,085,190  
         
Current liabilities
    (1,396,332 )
Long term liabilities
    (7,444,965 )
         
Total liabilities assumed
    (8,841,297 )
         
Net assets acquired
  $ 32,243,893  
         
 
Pro Forma Condensed Consolidated Statements of Income
 
                         
    For the Year Ended June 30, 2006  
          Pro Forma
       
          Adjustments to
       
          Reflect
       
          Exchange
       
    Historical     Offer     Pro Forma  
 
Total revenues
  $ 26,562,435           $ 26,562,435  
Costs and expenses
    23,635,299       2,242,135 (1)     25,877,434  
                         
Operating income
    2,927,136       (2,242,135 )     685,001  
Other income
    1,268,641             1,268,641  
                         
Income before income taxes and minority interests
    4,195,777       (2,242,135 )     1,953,642  
Income tax (provision) benefit
    (1,678,980 )     672,640 (2)     (1,006,340 )
                         
Income before minority interests
    2,516,797       (1,569,495 )     947,302  
Minority interests
    (1,768,023 )     1,768,023 (3)      
                         
Net income
  $ 748,774     $ 198,528     $ 947,302  
                         
Average number of shares outstanding
                       
Basic
    25,783,243 (A)     15,716,895 (4)     41,500,138  
                         
Diluted
    25,783,243 (A)     15,716,895 (4)     41,500,138  
                         
Net income per share (basic and diluted)
  $ 0.03             $ 0.02  
                         
 
 
(A) Represents outstanding shares prior to the Offer.


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Pro Forma Adjustments
 
1. Represents the depletion on the excess of the purchase price over the identifiable assets and liabilities acquired which has been allocated to oil and gas properties of $2,242,135 for the fiscal years ended June 30, 2006.
 
2. Represents the income tax effect on the depletion and transaction costs calculated based on an Australian statutory rate of 30%.
 
3. Represents the reversal of the income allocated to the minority interest as 100% of MPAL subject to the Exchange Offer is assumed to be acquired by Magellan at the beginning of the period.
 
4. Represents the number of shares assumed to be issued by Magellan pursuant to the terms of the Exchange Offer calculated as follows:
 
         
Shares of MPAL not owned by Magellan
    20,952,916  
Exchange ratio
    .75  
         
Magellan shares issued pursuant to the Exchange Offer
    15,716,895  
         
 
3.   Oil and Gas Properties
 
MPC had the following amounts recorded in oil and gas properties at June 30, 2008 and 2007.
 
                 
Location
  2008     2007  
 
Mereenie and Palm Valley (Australia)(1)
  $ 109,674,080     $ 95,578,259  
Nockatunga (Australia)(2)
    20,301,033       17,126,416  
Cooper Basin (Australia)(3)
    5,604,219       5,046,996  
Other (Australia)(4)
    548,945       548,947  
Weald/Wessex Basin (U.K.)(4)
    2,428,236       2,433,831  
                 
    $ 138,556,513     $ 120,734,449  
                 
 
 
(1) At June 30, 2008, includes $549,935 costs capitalized as exploratory well costs pending the start of production.
 
(2) At June 30, 2007, includes $8,812,420 of costs capitalized as exploratory well costs pending the start of production.
 
(3) At June 30, 2008 and 2007, includes $1,855,186 and $1,615,943, respectively, of costs capitalized as exploratory well costs pending the start of production as well as $1,448,568 of nondepletable exploration permits and licenses at June 30, 2008 and 2007.
 
(4) Nondepletable exploration permits and licenses related to the Maryborough Basin and Amadeus Basin in Australia and the Weald/Wessex Basin in the U.K.
 
Accumulated Depletion, Depreciation and Amortization
 
                 
Location
  2008     2007  
 
Mereenie and Palm Valley (Australia)
  $ 94,218,078     $ 74,885,273  
Nockatunga (Australia)
    14,780,819       4,568,503  
Cooper Basin (Australia)
    2,132,354       1,787,837  
                 
    $ 111,131,251     $ 81,241,613  
                 


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Depletion, Depreciation and Amortization
 
During the years ended June 30, 2008, 2007 and 2006, the depletion rate by field was as follows:
 
                         
    2008     2007     2006  
 
Mereenie and Palm Valley (Australia)
    45.3       35.5       24.6  
Nockatunga (Australia)
    66.5       53.6       24.7  
Cooper Basin (Australia)
    35.9       32.3       42.2  
Kotaneelee (Canada)
                10.0  
 
Exploratory and Dry Hole Costs
 
The 2008, 2007 and 2006 costs relate primarily to the geological and geophysical work and seismic acquisition on MPAL’s exploration permits. The costs for MPAL were $3,318,810, $5,520,460 and $3,264,837 for 2008, 2007, and 2006, respectively.
 
See Note 11 — Commitments for a summary of MPAL’s required and contingent commitments for exploration expenditures for the five year period beginning July 1, 2008.
 
Impairment Loss
 
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 that were recognized in purchase accounting ($892,000). The net book value of the Kiana oil and gas property was written down to its future estimated discounted cash flow. As a result of declining production discounted cash flows were utilized to calculate the fair value of the Kiana field. The losses related to the exploration permits and licenses resulted from the ongoing exploration program which did not result in discovery of reserves. These losses related to the MPAL segment. There was no impairment loss recorded for fiscal 2008.
 
4.   Asset Retirement Obligations
 
A reconciliation of the Company’s asset retirement obligations for the years ended June 30, 2008 and 2007, is as follows:
 
                 
    2008     2007  
 
Balance at beginning of year
  $ 9,456,088     $ 7,147,261  
Liabilities incurred
          718,048  
Liabilities settled
           
Accretion expense
    716,130       517,856  
Revisions to estimate
    43,482       (54,765 )
Exchange effect
    1,380,384       1,127,688  
                 
Balance at end of year
  $ 11,596,084     $ 9,456,088  
                 
 
During 2007, the Company recorded liabilities of $718,048 for 11 new wells drilled in the Nockatunga field.
 
5.   Capital and Stock Options
 
The Company’s Stock Option Plan provides for options to be granted with an exercise price of not less than fair value of the stock price on the date of grant and for a term of not greater than ten years. As of June 30, 2008, 295,000 options were available for future issuance under the Plan.


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The following is a summary of option transactions for the three years ended June 30, 2008:
 
                             
    Expiration
    Number of
        Fair Value at
 
Options Outstanding
  Dates     Shares     Exercise Prices($)   Grant Date  
 
June 30, 2006 and 2007
            430,000     (1.59 weighted average price)        
Granted
    Feb. 2018       100,000     1.16   $ 63,141  
                             
June 30, 2008
            530,000     (1.51 weighted average price)        
                             
 
The weighted average remaining contractual term as of June 30, 2008 is 7.5 years.
 
Summary of Options Outstanding at June 30, 2008
 
                                 
    Expiration
                Exercise
 
    Dates     Total     Vested     Prices($)  
 
Granted fiscal year 2004
    Jul. 2014       30,000       30,000       1.45  
Granted fiscal year 2006
    Nov. 2015       400,000       400,000       1.60  
Granted fiscal year 2008
    Feb. 2018       100,000       100,000       1.16  
 
All of the options have been granted with an exercise price equal to the fair value of the Company’s stock at the date of grant. Upon exercise of options, the excess of the proceeds over the par value of the shares issued is credited to capital in excess of par value. For the years ended June 30, 2008, 2007 and 2006, the Company recorded stock-based compensation expense for the cost of stock options of $63,141, $7,425 and $375,439 both pre-tax and post-tax (or $.00, $.00 and $.01 per basic and diluted share), respectively. The grant date fair value of the options granted on February 18, 2008 and November 28, 2005 was $63,141 and $365,539, respectively. These expenses have no effect on cash flow. As of June 30, 2008, there was $0 of total unrecognized compensation costs related to stock options.
 
The Company determined the fair value of the options at the date of grant using the Black-Scholes option pricing model. Option valuation models require the input of highly subjective assumptions including the expected stock price volatility. The assumptions used to value the Company’s grants on July 1, 2004 and November 28, 2005, respectively were as follows:
 
             
    Feb. 18, 2008   Nov. 28, 2005   Jul. 1, 2004
 
Risk free interest rate
  3.20%   4.58%   4.95%
Expected life
  5 yrs   5 yrs   10 yrs
Expected volatility (based on historical price)
  .611   .627   .518
Expected dividend
  $0   $0   $0
 
The expected life of the options granted on November 28, 2005 and February 18, 2008 was determined under the “simplified” method described in SEC Staff Accounting Bulletin No. 107.
 
6.   Income Taxes
 
Components of income before income taxes and minority interests by geographic area (in thousands) are as follows:
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
United States
  $ (2,119 )   $ (1,386 )   $ (1,753 )
Foreign
    7,558       2,831       5,949  
                         
Total
  $ 5,439     $ 1,445     $ 4,196  
                         


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Reconciliation of the provision for income taxes (in thousands) computed at the Australian statutory rate to the reported provision for income taxes is as follows:
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
Tax provision computed at statutory rate (30)%
  $ (1,632 )   $ (434 )   $ (1,259 )
MPC (parent company) losses
    (636 )     (416 )     (526 )
Non-taxable Australian revenue
    443       404       311  
MPAL non-deductible foreign losses (New Zealand)
    (14 )     (10 )     (88 )
MPAL write off of foreign advances (New Zealand)
                218  
Increase in valuation reserve for foreign (UK) exploration expenditures
    (271 )     (374 )     (243 )
Australian Taxation Office settlement(c)
    (12,085 )            
Repatriation of foreign earnings(a)
                (1,964 )
Reversal of reserve on MPC deferred tax assets(a)
                879  
Benefit for previously taxed foreign earnings
                1,085  
MPC income tax provision(b)
    (58 )     (48 )     (13 )
Other
    (77 )     (121 )     (79 )
                         
Consolidated income tax provision
  $ (14,330 )   $ (999 )   $ (1,679 )
                         
Current income tax provision (foreign)
  $ (18,872 )   $ (2,817 )   $ (1,841 )
Deferred income tax benefit (foreign)
    4,542       1,818       162  
                         
Consolidated income tax provision
  $ (14,330 )   $ (999 )   $ (1,679 )
                         
Effective tax rate
    263 %     69 %     40 %
                         
 
 
(a) The Corporation has indefinitely reinvested undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.
 
(b) MPC’s income tax provisions represent the 25% Canadian withholding tax on its Kotaneelee gas field carried interest net proceeds and 10% Australian withholding tax on interest income from intercompany loans.
 
(c) See discussion below under Australia.


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Significant components of the Company’s deferred tax assets and liabilities (in thousands) were as follows:
 
                 
    June 30,
    June 30,
 
    2008     2007  
 
Deferred tax liabilities
               
Acquisition and development costs
  $     $ (425 )
Stepped up basis of oil and gas properties
    (2,508 )     (3,519 )
Other
    (8 )     (24 )
                 
Total deferred tax liabilities
    (2,516 )     (3,968 )
                 
Deferred tax assets
               
Acquisition and development costs
    2,486        
Asset retirement obligations
    3,883       3,100  
Net operating losses
    4,079       3,719  
United Kingdom exploration costs
    1,031        
Stock options
    174       149  
Interest
    539       422  
                 
Total deferred tax assets
    12,192       7,390  
                 
Valuation allowance
    (5,815 )     (4,640 )
                 
Net deferred tax asset/(liabilities)
  $ 3,861     $ (1,218 )
                 
 
The Company records a valuation allowance for deferred tax assets when it is more likely than not that such assets will not be recovered. The valuation allowance increased to $5,815,000 in 2008 from $4,640,000 in 2007. The change in the valuation allowance is due to an increase in net operating losses in the US netted against losses which expired on June 30, 2008, and an increase in the valuation allowance for the tax benefit of U.K. exploration costs.


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United States
 
At June 30, 2008, the Company had approximately $11,031,000 and $6,635,000 of net operating loss carry forwards for federal and state income tax purposes, respectively, which are scheduled to expire periodically as follows (in thousands):
 
                         
    Paroo USA
    MPC
    MPC
 
    Federal     Federal     State  
 
Expires:
                       
2010
  $ 1,669     $     $  
2011
    1,764              
2012
    2,856              
2013
    230              
2019
    96       408        
2020
          52        
2021
    25             56  
2022
    74       110       302  
2023
    3             359  
2024
    2              
2025
    1       296       1,058  
2026
          1,374       1,341  
2027
                1,462  
2028
          2,071       2,057  
                         
Total
  $ 6,720     $ 4,311     $ 6,635  
                         
 
For financial reporting purposes, a full valuation allowance has been recognized to offset the deferred tax assets related to the U.S. tax loss carry forwards and other deductible temporary differences as it is more likely than not that under current circumstances such assets will not be recovered.
 
Australia
 
The net deferred tax asset at June 30, 2008, consists of a deferred tax asset of $2,486,000, primarily relating to acquisition and development costs and $3,883,000 primarily relating to asset retirement obligations which will result in tax deductions when paid.
 
The net deferred tax liability at June 30, 2007 consists of deferred tax liabilities of $3,519,000 relating to a financial statement basis step up for oil and gas properties and $425,000, primarily relating to the deduction of acquisition and development costs which are capitalized for financial statement purposes, offset by deferred tax assets of $3,100,000 primarily relating to asset retirement obligations which will result in tax deductions when paid.
 
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 set 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 have exceeded 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


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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.
 
Both the amended taxes and interest in the amount of (US) $13,252,469 has been recorded as part of the income tax provision for the year ended June 30, 2008 ($.31 per share). During the current year the Company recorded (US) $2,725,110, of net interest related to tax matters.
 
FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) is an interpretation of SFAS 109 and was adopted by the Company on July 1, 2007. Under FIN 48, a company recognizes an uncertain tax position (“UTP”) based on whether it is more likely than not that the UTP will be sustained upon examination by the appropriate taxing authority, including resolution of any related appeals or litigation processes, based solely on the technical merits of the position. In evaluating whether a UTP has met the more-likely-than-not recognition threshold, a company must presume that its positions will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step of FIN 48 adoption is measurement. A UTP that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The UTP is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. A UTP is not recognized if it does not meet the more-likely-than-not threshold.
 
Upon the adoption of FIN 48, MPAL received a legal opinion from its Australian tax counsel that concluded that the Company would be more likely than not to sustain the Australian tax deductions under audit in court. Australian tax counsel also advised the Company that 100% of the tax benefit of these deductions is the largest amount of the benefit that would be more than 50% likely to be realized. As a result, the Company recorded no liability for this UTP prior to the settlement which was negotiated in December 2007.
 
The ATO matter was the only UTP identified upon adoption of FIN 48. No other UTPs have been identified for the year ended June 30, 2008.


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7.   Related Party and Other Transactions
 
Mr. Timothy L. Largay, a director of the Company, is a member of the law firm of Murtha Cullina LLP, which firm was paid fees of $264,170, $114,415 and $170,481 by the Company in fiscal years 2008, 2007 and 2006, respectively.
 
8.   Leases
 
At June 30, 2008, future minimum rental payments applicable to MPC’s and MPAL’s non-cancelable office operating leases were as follows:
 
         
    Future Minimum
Fiscal Year
  Rental Payments
 
2009
  $ 256,000  
2010
  $ 5,000  
 
Operating lease rental expenses for each of the years ended June 30, 2008, 2007 and 2006 were $473,944, $362,2005 and $303,536 respectively.
 
9.   Segment Information
 
The Company has two reportable segments, MPC and its wholly owned subsidiary, MPAL. The Company’s chief operating decision maker is Daniel J. Samela (President, Chief Executive Officer and Chief Accounting and Financial Officer) who reviews the results of the MPC and MPAL businesses on a regular basis. MPC and MPAL both engage in business activities from which it may earn revenues and incur expenses. MPAL and its subsidiaries are considered one segment. Although there is discreet information available below the MPAL level, their products and services, production processes, market distribution and customers are similar in nature. In addition, MPAL has a management team which focuses on drilling efforts, capital expenditures and other operational activities.


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Segment information (in thousands) for the Company’s two operating segments is as follows:
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
Revenues:
                       
MPC
  $ 233     $ 5,996     $ 973  
MPAL
    40,662       30,545       26,530  
Elimination of intersegment dividend
          (5,866 )     (941 )
                         
Total consolidated revenues
  $ 40,895     $ 30,675     $ 26,562  
                         
Interest income:
                       
MPC
  $ 159     $ 259     $ 100  
MPAL
    1,964       1,411       1,169  
                         
Total consolidated
  $ 2,123     $ 1,670     $ 1,269  
                         
Net (loss) income:
                       
MPC
  $ (2,177 )   $ 4,432     $ (826 )
Equity in earnings of MPAL, net of related costs(1)
    (6,715 )     1,881       2,516  
Elimination of intersegment dividend
          (5,866 )     (941 )
                         
Consolidated net (loss) income
  $ (8,892 )   $ 447     $ 749  
                         
Assets:
                       
MPC(2)
  $ 65,555     $ 61,810          
MPAL
    82,935       80,334          
Equity elimination
    (63,195 )     (56,528 )        
                         
Total consolidated assets
  $ 85,295     $ 85,616          
                         
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
Other significant items:
                       
Depletion, depreciation and amortization:
                       
MPC
  $ 6     $ 6     $ 10  
MPAL
    18,015       10,687       6,299  
                         
Total consolidated
  $ 18,021     $ 10,693     $ 6,309  
                         
Exploratory and dry hole costs:
                       
MPC
  $     $     $  
MPAL
    3,319       5,520       3,265  
                         
Total consolidated
  $ 3,319     $ 5,520     $ 3,265  
                         
Income tax expense (benefit):
                       
MPC
  $ 58     $ 48     $ 13  
MPAL
    14,272       951       1,666  
                         
Total consolidated
  $ 14,330     $ 999     $ 1,679  
                         
 
 
(1) Equity in earnings (losses) of MPAL for 2008, 2007 and 2006 of ($4,222,000), $3,408,000 and $2,665,000 respectively is reported net of $2,493,000, $1,527,000 and $149,000 for 2008, 2007 and 2006, respectively, of oil and gas property depletion, net of tax benefit, related to MPC’s stepped up book value of MPAL’s oil and gas


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properties which resulted from MPC’s acquisition of the remaining 45% interest in MPAL in 2006. As of June 30, 2006, MPC owned 100% of MPAL as a result of the Offer. See Note 2 to the Consolidated Financial Statements.
 
(2) Goodwill attributable to MPAL was $4,020,706 for 2008 and 2007, respectively
 
10.   Geographic Information
 
As of each of the stated dates, the Company’s revenue, operating income, net income or loss and identifiable assets (in thousands) were geographically attributable as follows:
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
Revenue:
                       
Australia
  $ 40,662     $ 30,545     $ 26,530  
Canada
    233       130       32  
                         
    $ 40,895     $ 30,675     $ 26,562  
                         
Income (loss) before income taxes and minority interests:
                       
Australia
  $ 7,257     $ 3,152     $ 6,103  
New Zealand
    (42 )     (25 )     (211 )
United Kingdom
    (904 )     (1,162 )     (812 )
United States-Canada
    233       161       27  
                         
      6,544       2,126       5,107  
Corporate overhead and interest, net of other income (expense)
    (1,105 )     (681 )     (911 )
                         
Consolidated income before income taxes and minority interests
  $ 5,439     $ 1,445     $ 4,196  
                         
 
                         
    Years Ended June 30,  
    2008     2007     2006  
 
Net income (loss):
                       
Australia
  $ (5,767 )   $ 3,074     $ 3,621  
New Zealand
    (44 )     (32 )     (293 )
United Kingdom
    (904 )     (1,162 )     (812 )
United States
    (2,177 )     (1,433 )     (1,767 )
                         
    $ (8,892 )   $ 447     $ 749  
                         
Identifiable assets:
                       
Australia
  $ 82,935     $ 80,334          
Corporate assets
    2,360       5,282          
                         
    $ 85,295     $ 85,616          
                         
 
Substantially all of MPAL’s gas sales were to the Power and Water Corporation (“PWC”) of the Northern Territory of Australia. Oil sales during 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.


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11.   Commitments
 
The Company is exposed to oil and gas market price volatility and for gas sales uses fixed pricing contracts with inflation clauses to mitigate this exposure.
 
The following is a summary of our consolidated contractual obligations as of June 30, 2008
 
                                         
    Payments Due by Period  
          Less Than
                More Than
 
Contractual Obligations
  Total     1 Year     1-3 Years     3-5 Years     5 Years  
 
Operating Lease Obligations
    261,000       256,000       5,000              
Purchase Obligations(1)
    8,155,000       8,155,000                    
Asset Retirement Obligations
    11,596,000             7,412,000       2,009,000       2,175,000  
                                         
Total
  $ 20,012,000     $ 8,411,000     $ 7,417,000     $ 2,009,000     $ 2,175,000  
                                         
 
 
(1) Represents firm commitments for exploration and capital expenditures. The Company is committed to these expenditures, however some may be farmed out to third parties. Exploration contingent expenditures of $26,755,000 which are not legally binding have been excluded from the table above and based on exploration decisions would be due as follows: $0 (less than 1 year), $26,731,000 (1-3 years), $24,000 (3-5 years).
 
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 expires in 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.
 
At June 30, 2008, MPAL’s commitment to supply gas under the above agreements was as follows:
 
         
Period
  Bcf  
 
Less than one year
    5.23  
Between 1-5 years
    3.22  
Greater than 5 years
    0.00  
         
Total
    8.45  
         
 
12.   Selected Quarterly Financial Data (Unaudited and Restated)
 
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 the 2008 fiscal year. Depletion expense for the three months 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


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months ended March 31, 2008, respectively. This correction has no impact on cash flow from operations for any period presented.
 
The following is a summary (in thousands, except for per share amounts) of the quarterly results of operations for the years ended June 30, 2008 and 2007:
 
                                 
    September 30,
    December 30,
    March 31,
    June 30,
 
    2007
    2007
    2008
    2008
 
    3 Months     3 Months     3 Months     3 Months  
 
AS PREVIOUSLY REPORTED:
                               
2008
                               
Total revenues
  $ 9,322     $ 10,374     $ 9,536     $ 11,663  
Costs and expenses
    (9,032 )     (7,827 )     (6,828 )     (10,000 )
Interest income
    490       570       500       563  
Income tax (provision) benefit
    (381 )     (12,798 )     (1,520 )     (799 )
                                 
Net income (loss)
  $ 399     $ (9,681 )   $ 1,688     $ 1,427  
                                 
Per share (basic & diluted)
  $ .01     $ (.23 )   $ .04     $ .03  
                                 
Average number of shares outstanding
    41,500       41,500       41,500       41,500  
                                 
 
                                 
    September 30,
    December 30,
    March 31,
    June 30,
 
    2007
    2007
    2008
    2008
 
    3 Months     3 Months     3 Months     3 Months  
 
RESTATEMENT ADJUSTMENT:
                               
2008
                               
Total revenues
  $     $     $     $  
Costs and expenses
    (1,247 )     (1,570 )     (1,075 )      
Interest income
                       
Income tax (provision) benefit
    375       471       322        
                                 
Net income (loss)
  $ (872 )   $ (1,099 )   $ (753 )   $  
                                 
Per share (basic & diluted)
  $ (.02 )   $ (.03 )   $ (.02 )   $  
                                 
Average number of shares outstanding
                       
                                 
 
                                 
    September 30,
    December 30,
    March 31,
    June 30,
 
    2007
    2007
    2008
    2008
 
    3 Months     3 Months     3 Months     3 Months  
 
AS RESTATED:
                               
2008
                               
Total revenues
  $ 9,322     $ 10,374     $ 9,536     $ 11,663  
Costs and expenses
    (10,279 )     (9,397 )     (7,903 )     (10,000 )
Interest income
    490       570       500       563  
Income tax (provision) benefit
    (6 )     (12,327 )     (1,198 )     (799 )
                                 
Net income (loss)
  $ (473 )   $ (10,780 )   $ 935     $ 1,427  
                                 
Per share (basic & diluted)
  $ (.01 )   $ (.26 )   $ .02     $ .03  
                                 
Average number of shares outstanding
    41,500       41,500       41,500       41,500  
                                 
 


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    September 30,
    December 30,
    March 31,
    June 30,
 
    2006
    2006
    2007
    2007
 
    3 Months     3 Months     3 Months     3 Months  
 
2007
                               
Total revenues
  $ 6,823     $ 8,414     $ 6,849     $ 8,589  
Costs and expenses
    (5,447 )     (8,592 )     (6,708 )     (10,153 )
Interest income
    345       426       438       461  
Income tax (provision) benefit
    (691 )     (255 )     (292 )     240  
                                 
Net income (loss)
  $ 1,030     $ (7 )   $ 287     $ (863 )
                                 
Per share (basic & diluted)
  $ .02     $     $ .01     $ (.02 )
                                 
Average number of shares outstanding
    41,500       41,500       41,500       41,500  
                                 
 
An impairment loss of $1,876,171 was recorded in the fourth quarter of 2007 relating to the decreased value of the Kiana field in the Cooper Basin ($984,171) and the decreased value of exploration rights ($892,000). See Note 3 for further discussion.
 
13.   Supplementary Oil and Gas Disclosure (Unaudited and Restated)
 
The consolidated data presented herein include estimates which should not be construed as being exact and verifiable quantities. The reserves may or may not be recovered, and if recovered, the cash flows there from, and the costs related thereto, could be more or less than the amounts used in estimating future net cash flows. Moreover, estimates of proved reserves may increase or decrease as a result of future operations and economic conditions, and any production from these properties may commence earlier or later than anticipated.

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Estimated Net Quantities of Proved and Proved Developed Oil and Gas Reserves:
 
                         
    Natural Gas     Oil  
    (Bcf)     (1,000 Bbls)  
Proved Reserves:
  Australia*     Canada     Australia  
 
June 30, 2005
    25.284       .121       487  
                         
Extensions and discoveries
          .035       71  
Revision of previous estimates
    (.142 )           406  
Purchase of reserves
                 
Production
    (5.706 )     (.070 )     (154 )
                         
June 30, 2006
    19.436       .086       810  
                         
Extensions and discoveries
          .067       218  
Revision of previous estimates
    .014             (127 )
Purchase of reserves
                 
Production
    (5.978 )     (.093 )     (179 )
                         
June 30, 2007
    13.472       .060       722  
                         
Extensions and discoveries
          .087       141  
Revision of previous estimates
    (.652 )           125  
Purchase of reserves
                 
Production
    (5.707 )     (.077 )     (210 )
                         
June 30, 2008
    7.113       .070       778  
                         
Proved Developed Reserves:
                       
June 30, 2005
    25.284       .121       487  
                         
June 30, 2006
    19.436       .086       327  
                         
June 30, 2007
    13.472       .060       347  
                         
June 30, 2008
    7.113       .070       520  
                         
 
 
* The amount of proved reserves applicable to the Palm Valley and Mereenie fields only reflects the amount of gas committed to specific contracts and are net of royalties. There were no minority interests at June 30, 2006, 2007 or 2008. Approximately 44.9% of reserves were attributable to minority interests at June 30, 2005.
 
Costs of Oil and Gas Activities (In thousands):
 
                         
    Australia  
    Exploration
    Development
    Acquisition
 
Fiscal Year
  Costs(1)     Costs(2)     Costs  
 
2008
    3,810       1,200        
2007
    5,250       20,067        
2006
    3,284       (2,842 )(3)      
 
 
(1) These costs have been expensed.
 
(2) These costs have been capitalized.
 
(3) Development costs include the net increase or decrease in development related assets. The decrease in the Australian exchange rate caused a foreign translation loss in excess of costs incurred.


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Capitalized Costs Subject to Depletion, Depreciation and Amortization (DD&A) (In thousands):
 
                 
    June 30,  
Australia
  2008     2007  
 
Costs subject to DD&A
  $ 131,726     $ 105,874  
Costs not subject to DD&A
    6,831       14,860  
Less accumulated DD&A
    (111,131 )     (81,242 )
                 
Net capitalized costs
  $ 27,426     $ 39,492  
                 
 
Discounted Future Net Cash Flows:
 
The misapplication of reserve information discussed in Note 12 for a group of new wells which principally began production in the current fiscal year also affected the unaudited Supplementary Oil and Gas Disclosure that was presented in Note 14 to the consolidated financial statements included in the Company’s 2007 Form 10-K. The restated discounted future net cash flows is presented below and includes the restatement reduction of $4,460,000.
 
The following is the standardized measure of discounted (at 10%) future net cash flows (in thousands) relating to proved oil and gas reserves during the three years ended June 30, 2008. There were no minority interests at June 30, 2006 or June 30, 2007.
 
                         
    Australia  
    2008     2007     2006  
    Restated  
 
Future cash inflows
  $ 147,581     $ 125,333     $ 161,788  
Future production costs
    (62,027 )     (52,994 )     (33,814 )
Future development costs
    (21,263 )     (14,036 )     (16,196 )
Future income tax expense
    (12,823 )     (14,018 )     (28,900 )
                         
Future net cash flows
    51,468       44,285       82,878  
10% annual discount for estimating timing of cash flows
    (6,532 )     (10,437 )     (12,680 )
                         
Standardized measures of discounted future net cash flows
  $ 44,936     $ 33,848     $ 70,198  
                         
 
                         
    Canada  
    2008     2007     2006  
 
Future cash inflows
  $ 380     $ 184     $ 332  
Future production costs
    (129 )     (88 )     (74 )
Future development costs
                 
Future income tax expense
    (63 )     (24 )     (65 )
                         
Future net cash flows
    188       72       193  
10% annual discount for estimating timing of cash flows
    (6 )     (7 )     (4 )
                         
Standardized measures of discounted future net cash flows
  $ 182     $ 65     $ 189  
                         
 


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    Total  
    2008     2007     2006  
    Restated  
 
Future cash inflows
  $ 147,961     $ 125,517     $ 162,120  
Future production costs
    (62,156 )     (53,082 )     (33,888 )
Future development costs
    (21,263 )     (14,036 )     (16,196 )
Future income tax expense
    (12,886 )     (14,042 )     (28,965 )
                         
Future net cash flows
    51,656       44,357       83,071  
10% annual discount for estimating timing of cash flows
    (6,538 )     (10,444 )     (12,684 )
                         
Standardized measures of discounted future net cash flows
  $ 45,118     $ 33,913     $ 70,387  
                         
 
The following are the principal sources of changes in the above standardized measure of discounted future net cash flows (in thousands):
 
                         
    2008     2007     2006  
    Restated  
 
Net change in prices and production costs
  $ 41,125     $ (66,738 )   $ 69,970  
Extensions and discoveries
                2,714  
Revision of previous quantity estimates
    (1,351 )     14,996       1,037  
Changes in estimated future development costs
    (5,015 )     7,144       (4,999 )
Sales and transfers of oil and gas produced
    (30,637 )     (20,660 )     (16,462 )
Previously estimated development cost incurred during the period
    (696 )     (179 )     (438 )
Accretion of discount
    1,917       8,838       7,017  
Net change in income taxes
    331       15,577       (17,025 )
Net change in exchange rate
    5,531       4,548       (3,060 )
                         
    $ 11,205     $ (36,474 )   $ 38,754  
                         
 
Additional Information Regarding Discounted Future Net Cash Flows:
 
Australia
 
Reserves — Natural Gas
 
Future net cash flows from net proved gas reserves in Australia were based on MPAL’s share of reserves in the Palm Valley and Mereenie fields. Reserves in the Mereenie field were limited to the quantities of gas committed to specific contract and the ability of the field to deliver the gas in the contract years. Reserves in the Palm valley field were based upon the quantities of gas committed to the contract and estimated sales subsequent to the contract date. Gas prices are computed on the prices set forth in the respective gas sales contracts at June 30, 2008 and estimated future prices for Palm Valley subsequent to the contract date.
 
Reserves and Costs — Oil
 
At June 30, 2008, future net cash flows from the net proved oil reserves in Australia were calculated by the Company. Estimated future production and development costs were based on current costs and rates for each of the three years ended at June 30, 2008. All of the crude oil reserves are developed reserves. Undeveloped proved reserves have not been estimated since there are only tentative plans to drill additional wells.
 
Income Taxes
 
Future Australian income tax expense applicable to the future net cash flows has been reduced by the tax effect on unrecouped capital expenditures of approximately A.$26,145,000, A.$29,167,000 and A.$23,976,000 at June 30, 2008, 2007 and 2006 respectively. The tax rate used in computing Australian future income tax expense was 30%.

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Canada
 
Reserves and Costs
 
Future net cash flows from net proved gas reserves in Canada were based on the Company’s share of reserves in the Kotaneelee gas field which was prepared by independent petroleum consultants, Paddock Lindstrom & Associates Ltd., Calgary, Canada. The estimates were based on the selling price of gas Can. $9.61 at June 30, 2008 (Can. $6.28 — 2007) and estimated future production and development costs at June 30, 2008.