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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, 2009

or

 

¨ 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   06-0842255

State or other jurisdiction of

incorporation or organization

 

(I.R.S. Employer

Identification No.)

10 Columbus Boulevard, Hartford, CT   06106
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code

(860) 293-2006

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

 

Title of Each Class

 

Name of Each Exchange on

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  ¨    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  ¨    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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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.    ¨

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 ¨   Accelerated filer ¨    Non-accelerated filer þ   Smaller reporting company ¨
  (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  ¨    No  þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant at the $0.65 closing price on December 31, 2008 (the last business day of the most recently completed second quarter) was $26,803,787.

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, 50,210,977 shares outstanding as of September 1, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2009, are incorporated by reference in Part III of this Form 10-K to the extent stated herein.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

          Page
PART I

Item 1.

   Business    3

Item 1A.

   Risk Factors    12

Item 1B.

   Unresolved Staff Comments    19

Item 2.

   Properties    19

Item 3.

   Legal Proceedings    23

Item 4.

   Submission of Matters to a Vote of Security Holders    23
PART II

Item 5.

   Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities    24

Item 6.

   Selected Financial Data    26

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operation    27

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk    40

Item 8.

   Financial Statements and Supplementary Data    41

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    70

Item 9A.

   Controls and Procedures    70

Item 9B.

   Other Information    71
PART III

Item 10.

   Directors, Executive Officers and Corporate Governance    72

Item 11.

   Executive Compensation    72

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    72

Item 13.

   Certain Relationships and Related Transactions, and Director Independence    73

Item 14.

   Principal Accounting Fees and Services    73
PART IV

Item 15.

   Exhibits, Financial Statement Schedules    73

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 1, 2009 was approximately A.$1.00 equaled U.S. $.84.

 

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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, 2009, MPC’s principal asset was a 100.00% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”).

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), five petroleum production leases covering the Nockatunga oil fields (41% working interest) and eighteen licenses in the United Kingdom, five of which are operated by MPAL. Both the Mereenie and Palm Valley fields are located in the Amadeus Basin in the Northern Territory of Australia. The Nockatunga fields are located in the Cooper Basin in South West 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. Santos is the operator of the Mereenie and 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 685,000 barrels and 0.8 billion cubic feet (Bcf) of gas at June 30, 2009. During fiscal 2009, MPAL’s share of oil sales was 105,000 barrels and 4.6 Bcf of gas, which is subject to net overriding royalties aggregating 4.0625% and the statutory government royalty of 10%. Prior to early June 2009, the oil was transported by means of a 167-mile eight-inch oil pipeline from the field to an industrial park near Alice Springs.

 

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The oil was then shipped south approximately 950 miles by road to the Port Bonython Export Terminal at Whyalla, South Australia for sale. Since early June 2009, the oil is transported by road directly from the field to Port Bonython Export Terminal. The cost of transporting the oil to the terminal is borne by the Mereenie Producers. The oil pipeline has been placed in care and maintenance because of environmental concerns by the operator over its integrity. The petroleum leases covering the Mereenie field expire in November 2023.

The Mereenie Producers are contracted to provide Mereenie gas in the Northern Territory to the Power and Water Corporation (“PWC”) for use in Darwin and other Northern Territory centers. See “Gas Supply Contracts” below.

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 2.5 Bcf at June 30, 2009 and is based upon gas contract amounts. During fiscal 2009, MPAL’s share of gas sales was 1.4 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 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 MPAL and Santos (“Palm Valley Producers”) commenced the sale of gas to Alice Springs under a 1981 agreement. That agreement terminated in June 2008. 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. (“Gasgo”), 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 expired in January and June 2009. Supply obligations under the Mereenie contracts ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended.

MPAL’s major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the higher-priced Mereenie Sales Agreement 4 (“Backstop Agreement”). MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 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 sell uncontracted gas, including reasonable

 

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endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

At June 30, 2009, MPAL’s commitment to supply gas under the above agreements was as follows:

 

Period

   Bcf

Less than one year

   2.22

Between 1-5 years

   1.77

Greater than 5 years

   0.00
    

Total

   3.99
    

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 are comprised of eleven producing oil fields (Currambar, Kamel, Dilkera, Dilkera North, Koora, Maxwell, Maxwell South, Muthero, Nockatunga, Thungo and Winna) in Petroleum Leases 33, 50, 51, 244 and 245, together with exploration acreage in the adjacent Authority to Prospect for Petroleum (“ATP”) No. 267P. The fields are currently producing about 425 barrels of oil per day (MPAL’s share is approximately 165 barrels of oil per day). During fiscal 2009, MPAL’s share of oil sales was 70,000 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 3.0%. MPAL’s share of the Nockatunga fields’ proved developed oil reserves (net of royalties) was approximately 92,000 barrels at June 30, 2009. Petroleum Lease 33 was renewed for a further 21 years and will expire in April 2028. Petroleum Leases 50 and 51 expire in June 2011. Petroleum Leases 244 and 245 were granted with effect on December 1, 2008 and will expire in November 2029. ATP 267P was renewed for a further four year term and will expire in November 2011. A 99 square mile 3D seismic survey was conducted over Petroleum Leases 51 and 245 and parts of ATP 267P in early 2009. No drilling was undertaken during fiscal 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 was renewed for a further five year term and expires in February 2014.

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 agreed to undertake a staged evaluation of the farm-out area to earn a 75% interest in any petroleum lease granted in the area. MPAL retains a 25% interest and is carried by Eureka Petroleum through any development to the grant of a petroleum lease. Eureka Petroleum operates the joint venture. At June 30,

 

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2009, 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 March 2019.

Cooper/Eromanga Basin (See Executive Summary in Part II, Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operation for discussion of potential sale of Cooper Basin assets.)

PEL 94, PEL 95 & PPL 210

During fiscal year 1999, MPAL (50%) and its partner Beach Petroleum were successful in bidding for two exploration blocks, Petroleum Exploration License (“PEL”) 94 and PEL 95, in South Australia’s Cooper Basin. The Aldinga-1 exploration well was drilled and completed in September 2002 and began producing in May 2003 at about 80 barrels of oil per day. Petroleum Production License (“PPL”) 210 was granted over the Aldinga field in December 2004. By June 2009, production had declined to about 10 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, 2009, MPAL’s share of the work obligations of PEL 94 totaled $622,000 of which $28,000 was committed and in PEL 95 totaled $929,000 of which $81,000 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 2009, MPAL’s share of oil sales was approximately 1,900 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 11,000 barrels at June 30, 2009. 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. PEL 107 was renewed for a further five year term and expires in December 2013. At June 30, 2009, the work obligations of PEL 107 totaled $525,000, of which $40,000 was committed.

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. The operator has recommenced applying for a retention license with the view to moving to a petroleum production license by the end of 2009. The intention is to commence gas production and sales in January 2010.

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%. PEL 110 was renewed for a further five year term and expires in

 

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November 2013. Beach Petroleum withdrew from the license and joint venture with effect at the end of the first five year term, and MPAL’s interest increased proportionally to 60%. At June 30, 2009, MPAL’s share of the work obligations of PEL 110 totaled $1,231,000, of which $68,000 was committed.

UNITED KINGDOM

PEDL 098, PEDL 099 & PEDL 256

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, 2009, MPAL’s share of the work obligations of the PEDL 098 license totaled $55,000 of which $18,000 was committed. PEDL 098 expires in September 2011. PEDL 099 expired in September 2008.

The former PEDL 099 licensees made an out-of-round application for a license over the northeast portion of the former PEDL 099 area which is adjacent to the Havant Prospect in PEDL 155. PEDL 256 was granted to MPAL (40% interest) and its joint venturers for a period of six years with effect from May 2009 with a drill or drop obligation at the end of the term. PEDL 256 expires in May 2015. At June 30, 2009, MPAL’s share of the work obligations of the PEDL 256 license totaled $2,180,000, of which $40,000 was committed.

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 in the early part of the first quarter of 2010. Plans for drilling Hedge End-2 later in 2010 are in progress. The U.K, company Encore Oil (formerly known as 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 licenses. Both PEDLs were extended by the Government for a further one year term and the licenses expire in June 2010. At June 30, 2009, MPAL’s share of the work obligations of the two licenses totaled $3,150,000 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 being planned and government drilling approvals sought. At June 30, 2009, MPAL’s work obligation for the three licenses totaled $13,930,000, of which $282,000 was committed.

PEDL 152, PEDL 153, PEDL 154 & PEDL 155

Effective October 1, 2004, MPAL acquired four licenses in the Weald Basin in southern England, each granted for a period of six years; PEDL 152 (22.5%), PEDL 153 (33.3%), PEDL 154 (50%) and PEDL 155 (40%). Each 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 2010. The U.K. company Encore Oil 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, 2009, MPAL’s work obligation for the four licenses totaled $5,500,000, of which $1,588,000 was committed.

 

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

Effective July 1, 2008, MPAL and its joint venture partner were granted interests in PEDL 231 (MPAL 50%), PEDL 232 (50%), PEDL 234(50%), PEDL 240 (22.5%), PEDL 242 (100%), PEDL 243 (50%) & PEDL 246 (100%) located in the Weald and Wessex Basins of southern England. Two of these PEDLs are operated by MPAL. Each license has a drill or drop obligation at the end of its term and expires in July 2014. At June 30, 2009, MPAL’s share of the work obligations of: the PEDL 231, PEDL 232, PEDL 234 & PEDL 243 licenses totaled $7,500,000 of which $1,000,000 was committed; the PEDL 240 license was $1,328,000, of which $40,000 was committed; and the PEDL 242 & PEDL 246 licenses totaled $10,515,000, of which $56,000 was committed.

CANADA

MPC owns a 2.67% carried interest in a lease (31,885 gross acres, 850 net acres) in the southeast Yukon Territory, Canada, which includes the Kotaneelee gas field. Devon Canada Corporation is the operator of this partially developed field which is connected to a major pipeline system. Production at Kotaneelee commenced in February 1991. The Company recorded revenue of $164,000 from this field in fiscal 2009.

(b) Financial Information About Industry Segments.

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

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

MPC was incorporated in 1957 under the laws of Panama and was reorganized under the laws of Delaware in 1967. MPC is directly engaged in the exploration for, and the development, 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 2014   Northern Territory, Australia

Petroleum Lease No. 33 (Nockatunga) (Cooper Basin)

  April 2028   Queensland, Australia

Petroleum Lease No. 50 and No. 51 (Nockatunga) (Cooper Basin)

  June 2011   Queensland, Australia

Petroleum Lease No. 244 (Currambar) (Cooper Basin)

  November 2029   Queensland, Australia

Petroleum Lease No. 245 (Maxwell South) (Cooper Basin)

  November 2029   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 2011   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 2013   South Australia

PEL 110 (Cooper Basin)

  November 2013   South Australia

PEDL 098 (Weald-Wessex Basins)

  September 2011   United Kingdom

PEDL 125 (Weald-Wessex Basins)

  June 2010   United Kingdom

PEDL 126 (Weald-Wessex Basins))

  June 2010   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 Basin)

  September 2010   United Kingdom

PEDL 231 (Weald Basin)

  June 2014   United Kingdom

PEDL 232 (Weald Basin)

  June 2014   United Kingdom

PEDL 234 (Weald Basin)

  June 2014   United Kingdom

PEDL 240 (Weald-Wessex Basins)

  June 2014   United Kingdom

PEDL 242 (Weald Basin)

  June 2014   United Kingdom

PEDL 243 (Weald Basin)

  June 2014   United Kingdom

PEDL 246 (Weald Basin)

  June 2014   United Kingdom

PEDL 256 (Weald Basin)

  April 2015   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

 

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21 years, and leases may be renewed for successive terms of 21 years each. Petroleum Production Licenses issued by the South Australian Government are subject to the Petroleum Act of South Australia. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Licenses terminate two years after production ceases. Petroleum Exploration and Development Licenses issued by the Government of the United Kingdom are subject to the Petroleum Act. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental. The term of the license is 31 years.

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

(v) Seasonality of Business.

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

(vi) Working Capital Items.

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

(vii) Customers.

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

Natural Gas Production

MPAL’s major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 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 sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total 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

 

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generally 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 2009 were 40.2% to the Santos group of companies, 13.1% to the Beach Petroleum group of companies, 8.0% to Origin Energy Resources and 39.2% to IOR Energy.

(viii) Backlog.

Not applicable.

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

Not applicable.

(x) Competitive Conditions in the Business.

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

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

At the present time, the Company’s principal income producing operations are in Australia and for this reason, current competitive conditions in Australia are material to the Company’s future. Currently, most indigenous crude oil is consumed within Australia. In addition, refiners and others import crude oil to meet the overall demand in Australia. The Palm Valley Producers and the Mereenie Producers are developing and separately marketing the production from each field. Because of the relatively remote location of the Amadeus Basin and the inherent nature of the market for gas, it would be impractical for each working interest partner to attempt to market separately its respective share of gas production from each field. MPAL’s major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 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 sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

(xi) Research and Development.

Not applicable.

 

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(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, 2009, the Company had accrued approximately $9.8 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, 2009, MPC had 5 employees in the United States and MPAL had 25 employees in Australia.

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

See Note 10 to the Consolidated Financial Statements.

(3) Risks Attendant to Foreign Operations.

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

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

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

None.

 

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

 

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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 MPC. 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.

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, a subsidiary of PWC of the Northern Territory. Gasgo has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 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 sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

The Palm Valley Darwin contract expires in the year 2012 and the principal Mereenie contracts expired in January and June 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.

Our plans to 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 2010, we expect that at least three new wells, Markwells Wood-1, Havant-1 and Hedge End-2, 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 commercially viable quantities. If 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

 

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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 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 MPC and MPAL. The ability to retain its officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. We maintain $2 million of key person life insurance on our Chief Executive Officer, William Hastings.

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

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

Our 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, 2009, there were 3,242,500 stock options outstanding of which 530,000 were fully vested and exercisable. There were also 1,787,500 options available for future grants under our 1998 Stock Incentive Plan. If all of these options, which total 5,030,00 in the aggregate, were awarded and exercised these shares would represent approximately 11% 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 5550(a)(2). 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 16, 2009, the Company’s shares closed at $1.40 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. Furthermore, the ongoing worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A slowdown in economic activity caused by a recession would likely reduce worldwide demand for energy and result in lower oil and natural gas prices. Oil prices declined from record levels in early July 2008 of over $140 per barrel to below $70 per barrel in August 2009, while natural gas prices have declined from over $13 per mcf to approximately $3 per mcf over the same period.

Sustained declines in oil and gas prices (such as those experienced in the second half of 2008) 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 44% of our proved reserves at June 30, 2009 were natural gas reserves. Gas sales contracts in Australia are adjusted to 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 2009 sales volume and revenue, a 10% change in oil price would increase or decrease oil revenues by approximately $1.1 million. Gas sales, which represented approximately 56% of production revenues in 2009, 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.

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

 

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gas companies. Many of our Australian competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may not be able to compete with, or enter into cooperative relationships with, any such firms.

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

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

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

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

This annual report and the documents incorporated by reference in this annual report contain estimates of our proved reserves and the estimated future net revenues from our proved reserves. 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,

 

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farming-in other companies or investors to MPAL’s exploration and development projects in which we have an interest and/or equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flow from operations is not sufficient to fund MPAL’s capital expenditure budget, we may not be able to rely upon additional farm-in opportunities, debt or equity offerings or other methods of financing to meet these cash flow requirements.

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

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

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

We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment. 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

 

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circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. For Mereenie, proved developed natural gas reserves are limited to contracted quantities. For Palm Valley, reserves were based upon the quantities of gas committed to the contract and estimated sales subsequent to the contract date. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves and risk adjusted probable and possible reserves or the contracted quantities. A significant decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future write down of capitalized costs and a non-cash charge against future earnings.

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

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

 

   

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.

Difficult conditions resulting from the ongoing U.S. and worldwide financial and credit crisis, and significant concerns over the continuing recessions in the U.S. and Australian economies, may materially adversely affect our business and results of operations and we do not expect these conditions to improve in the near future.

Since 2008, the United States and many other nations (including Australia) around the world have been experiencing a financial and credit crisis. Concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. and elsewhere have contributed to increased market volatility and disruptions and diminished expectations for the U.S. and world economies and markets going forward. These factors, combined with volatile oil and gas prices, declining business and consumer confidence and increased unemployment, have precipitated a worldwide economic slowdown.

In addition, the U.S. and worldwide capital and credit markets have been experiencing extreme volatility and disruption for more than twelve months. Initially, the concerns on the part of market participants were focused on the subprime segment of the mortgage-backed securities market. However, these concerns have since expanded to include a broad range of mortgage and asset-backed and other fixed income securities, including those rated investment grade, the U.S. and international credit and interbank money markets generally, and a wide range of financial institutions and markets, asset classes and sectors. Since September 2008, market volatility and disruptions have reached unprecedented levels, leading in many cases to unprecedented

 

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government legislation and other actions to stabilize world markets and financial institutions and promote consumer and investor confidence.

Continuing volatility and disruption in worldwide capital and credit markets and further deteriorating conditions in the U.S. and Australian economies could affect our revenues and earnings negatively and could have a material adverse effect on our business, results of operations and financial condition. For example, purchasers of our oil and gas production may reduce the amounts of oil and gas they purchase from us and/or delay or be unable to make timely payments to us.

Further, a number of our oil and gas properties are operated by third parties whom we depend upon for timely performance of drilling and other contractual obligations and, in some cases, for distribution to us of our proportionate share of revenues from sales of oil and gas we produce. If current economic conditions adversely impact our third party operators, we are exposed to the risk that drilling operations or revenue disbursements to us could be delayed. This “trickle down” effect could significantly harm our business, financial condition and results of operation.

Currency exchange rate fluctuations may negatively affect our operating results.

The exchange rates among the Australian dollar and the U.S. dollar, as well as the exchange rates between the Australian dollar and the U.K. pound sterling, have changed in recent periods and may fluctuate substantially in the future. We expect that a majority of our revenue will continue to be generated in the Australian dollar in the future. Since June 30, 2008, the U.S. dollar has strengthened materially against the Australian dollar which has had, and may continue to have, a materially negative impact on our revenues generated in the Australian dollar, as well as our operating income and net income, as considered on a consolidated basis. The foreign exchange loss for the year ended June 30, 2009 was $9.9 million and is included in accumulated other comprehensive income on the balance sheet. Any continued appreciation of the U.S. dollar against the Australian dollar is likely to have a negative impact on our revenue, operating income and net income. Because of our U.K. development program, a portion of our expenses, including exploration costs and capital and operating expenditures, will continue to be denominated in U.K. pound sterling. Accordingly, any material appreciation of the U.K. pound sterling against the Australian dollar could have a negative impact on our business, operating results and financial condition.

 

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

 

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

AMADEUS BASIN PROJECTS MAP

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

Palm Valley Gas Field

Mereenie Oil & Gas Field

Dingo Gas Field

Palm Valley — Alice Springs Gas Pipeline

Palm Valley — Darwin Gas Pipeline

Mereenie Spur Gas Pipeline

Mereenie Oil Pipeline

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

CANADIAN PROPERTY INTERESTS MAP

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

Kotaneelee Gas Field

Pointed Mountain Gas Field

Beaver River Gas Field

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

UNITED KINGDOM PROPERTY INTERESTS MAP

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

(2) Reserves Reported to Other Agencies.

None

(3) Production.

MPC’s production volumes, net of royalties, for gas and oil during the three years ended June 30, 2009 were as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material):

 

     2009    2008    2007

Australia:

        

Gas (bcf)

   5.2    5.7    5.9

Crude oil (bbl)

   153,000    211,000    179,000

 

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

 

     2009    2008    2007

Australia:

        

Gas (per mcf)

   A.$ 3.54    A.$ 3.39    A.$ 3.24

Crude oil (per bbl)

   A.$ 91.21    A.$ 102.35    A.$ 80.75

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

 

     2009    2008    2007

Australia:

        

Gas (per mcf)

   A.$ .99    A.$ .82    A.$ .71

Crude oil (per bbl)

   A.$ 26.72    A.$ 17.98    A.$ 18.55

Amounts presented above are in Australian dollars to show a more meaningful trend of underlying operations. For the years ended June 30, 2009, 2008 and 2007 the average foreign exchange rates were .7471, .8965, and .7860, respectively.

(4) Productive Wells and Acreage.

Productive wells and acreage at June 30, 2009

 

     Productive Wells     
     Oil    Gas    Developed Acreage
     Gross    Net    Gross    Net    Gross Acres    Net Acres

Australia

   37.0    13.8    15.0    6.10    84,930    37,523

Canada

   —      —      3.0    .08    3,350    89
                             
   37.0    13.8    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, 2009

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

 

     MPC
     Gross Acres    Net Acres    Interest
%

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/PL 244/PL 245 Nockatunga (Cooper Basin) (3)

   102,233    41,850    40.936

ATP 267P (Cooper Basin)

   106,704    43,680    40.936

ATP 613P (Maryborough Basin)

   153,387    153,387    100.000
            
   362,324    238,917   
            

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)

   100,529    20,106    20.00

PEL 110 (Cooper Basin)

   180,310    108,186    60.00
            
   1,365,268    603,590   
            

United Kingdom:

        

PEDL 098/152/240 (Wessex Basin)

   31,245    7,030    22.50

PEDL 125/126/155/256 (Weald Basin)

   136,120    54,448    40.00

PEDL 135/136/137/242/246 (Weald Basin)

   155,459    155,459    100.00

PEDL 153 (Weald Basin)

   66,242    22,078    33.33

PEDL 154 (Weald Basin)

   84,834    42,417    50.00

PEDL 231/232/234/243 (Weald Basin)

   270,342    135,171    50.00
            
   744,242    416,603   
            

Total MPAL

   2,815,954    1,405,666   
            

Properties held directly by MPC:

        

Canada

        

Yukon and Northwest Territories:

        

Kotaneelee carried interest (6)

   31,885    850    2.67
            

Total

   2,847,839    1,406,516   
            

 

(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 is insignificant):

 

     Australia/United Kingdom

Year Ended

June 30,

   Exploration    Development
   Productive    Dry    Productive    Dry

2009

   0.00    0.00    0.00    —  

2008

   0.00    0.90    0.41    —  

2007

   0.82    1.55    3.27    —  

(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.

None

 

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

(a) On May 27, 2009, the Company held its 2008 Annual General Meeting of Stockholders.

(b) The following director was elected as a director of the Company. The vote was as follows:

 

     Shares    Stockholders
     For    Withheld    For    Withheld

William H. Hastings

   27,852,601    6,822,991    1,078    89

(c) Authorization to amend the Company’s Restated Certificate of Incorporation to repeal, effective December 31, 2009, the “per capita” voting requirements of Articles 12th and 14th thereof, which will have the effect of adopting one share, one vote for all matters for which shareholders are required to vote under the Delaware General Corporation Law. The vote was as follows:

 

     Shares    Stockholders

For

   31,607,833    1,018

Against

   1,814,198    89

Abstain

   1,326,667    60

 

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(d) Authorization to amend the Company’s Restated Certificate of Incorporation to repeal, effective December 31, 2009, Article 13th, the “super majority” voting provision of the Restated Certificate. The vote was as follows:

 

     Shares    Stockholders

For

   30,784,474    987

Against

   2,533,857    112

Abstain

   1,430,367    68

(e) Approval of a $10 million equity investment in the Company through the issuance (A) 8,695,652 shares of the Company’s common stock and (B) warrants to acquire 4,347,826 shares of common stock to Young Energy Prize S.A. or its affiliate. The vote was as follows:

 

     Shares    Stockholders

For

   14,736,131    934

Against

   2,341,364    141

Abstain

   1,330,801    74

(f) Approval of an amendment and restatement of the Company’s 1998 Stock Option Plan to: (A) increase the authorized shares of common stock reserved for awards under the Plan to 5,205,000 shares; (B) authorize the Compensation Committee to award shares of restricted stock, make annual awards of stock to non-employee directors and make performance-based awards; and (C) rename the Plan the “1998 Stock Incentive Plan.” The vote was as follows:

 

     Shares    Stockholders

For

   12,309,652    851

Against

   4,820,814    225

Abstain

   1,303,737    73

(g) The firm of Deloitte & Touche LLP was appointed as the Company’s independent auditors for the year ending June 30, 2009. The vote was as follows:

 

     Shares    Stockholders

For

   31,019,215    1,068

Against

   1,439,273    43

Abstain

   2,290,210    56

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:

 

2009

   1st Qtr.    2nd Qtr.    3rd Qtr.    4th Qtr.

High

   1.64    1.10    0.78    1.35

Low

   1.02    0.48    0.58    0.61

 

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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

(b) Approximate Number of Holders of Common Stock at September 1, 2009

 

Title of Class

   Number of Record Holders

Common stock, par value $.01 per share

   5,886

(c) Frequency and Amount of Dividends

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

Recent Sales of Unregistered Securities

During the fiscal year ended June 30, 2009, there were no equity securities of the Company sold that were not registered under the Securities Act of 1933, as amended (the “Securities Act”).

As previously disclosed in the Company’s current reports filed on February 10, 2009, April 8, 2009, June 2, 2009 and July 14, 2009, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”), dated February 9, 2009, with Young Energy Prize S.A. (“YEP”) under which the Company agreed to sell, and YEP agreed to purchase, 8,695,652 shares (the “Shares”) of the Company’s common stock, par value $0.01 per share (the “Common Stock”) at a purchase price of $1.15 per share, or an aggregate of $10,000,000. The Purchase Agreement was amended on April 3, 2009 and June 30, 2009. On July 9, 2009, the Company and YEP completed the issuance and sale of the Shares to YEP. The Company received gross proceeds of $10 million, which will be used for general corporate and working capital purposes. On July 9, 2009, the Company also executed and delivered to YEP a Warrant Agreement entitling YEP to purchase an additional 4,347,826 shares of the Company’s Common Stock (the “Warrant Shares”) at an exercise price of $1.20 per Warrant Share, subsequently reduced to $1.15 per share on July 30, 2009.

The shares sold to YEP in the private placement and the Warrant Shares were not registered under the Securities Act or state securities laws, and may not be resold in the United States in the absence of an effective registration statement filed with the U.S. Securities and Exchange Commission (“SEC”) or an available exemption from the applicable federal and state registration requirements. In the Purchase Agreement, YEP represented to the Company that: (a) it is an accredited investor, as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act; (b) it acquired the Shares and the Warrant as principal for its own account for investment purposes only and not with a view to or for distributing or reselling the Shares and the Warrant or any part thereof, and (c) it is knowledgeable, sophisticated, and experienced in making, and qualified to make, decisions with respect to investments in securities representing an investment decision similar to that involved in the purchase of the Shares and the Warrant. The Company has relied on the exemption from the registration requirements of the Securities Act set forth in Regulation S promulgated thereunder for the purposes of the YEP transaction.

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:

 

Period

   Total Number of
Shares
Purchased
   Average Price
Paid
per Share
   Total Number of
Shares Purchased
as Part of Publicly
Announced Plan(1)
   Maximum
Number of
Shares that May
Yet Be Purchased
Under Plan

July 1, 2008 – June 30, 2009

   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, 2009, the Company had purchased 680,850 of its shares at an average

 

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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 2009, 2008 or 2007.

 

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,  
     2009     2008     2007     2006     2005  

Financial Data

          

Total revenues

   $ 28,191      $ 40,895      $ 30,675      $ 26,562      $ 21,871   
                                        

Net income (loss)

     665        (8,892     447        749        87   
                                        

Net income (loss) per share (basic and diluted)

     .02        (.21     .01        .03        —     
                                        

Working capital

     37,161        37,780        29,004        24,820        26,208   
                                        

Cash provided by operating activities

     9,239        5,496 (1)      15,936 (1)      9,875 (1)      7,022 (1) 
                                        

Property and equipment (net)

     17,529        28,447        40,321        27,783        24,265   
                                        

Total assets

     71,704        85,295        85,616        68,580        56,424   
                                        

Long-term liabilities

     11,809        14,153        13,076        8,583        5,729   
                                        

Minority interests

     —          —          —          —          18,583   
                                        

Stockholders’ equity:

          

Capital

     73,726        73,631        73,568        73,560        44,660   

Accumulated deficit

     (22,193     (22,858     (13,966     (14,413     (15,161

Accumulated other comprehensive income (loss)

     1,980        11,690        4,373        (3,028     (2,323
                                        

Total stockholders’ equity

     53,513        62,463        63,975        56,119        27,176   
                                        

Exchange rate A.$ = U.S. at end of period

     .80        .96        .84        .73        .76   
                                        

Common stock outstanding shares end of period

     41,500        41,500        41,500        41,500        25,783   
                                        

Book value per share

     1.29        1.51        1.54        1.35        1.05   
                                        

Quoted market value per share (NASDAQ)

     1.11        1.62        1.52        1.57        2.40   
                                        

Operating Data

          

Annual production (net of royalties) Gas (bcf)

     5.2        5.7        5.9        5.7        5.7   
                                        

Oil (bbls) (In thousands)

     153        211        179        155        151   
                                        

 

(1) Restated — see Note 12 of Item 8, Financial Statements and Supplementary Data

 

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

Restatement

As discussed in Note 12 to accompanying consolidated financial statements in Item 8 of this Annual Report on Form 10-K, we have restated the Consolidated Statement of Cash Flows for the years ended June 30, 2008 and 2007 that were presented in Item 8 of the Company’s Form 10-K. All affected amounts contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations have been adjusted to reflect the restatement.

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. The results reflect fully the consolidated financial statements of MPC. Among these risks and uncertainties are pricing and production levels from the properties in which Magellan and MPAL have interests, the extent of the recoverable reserves at those properties and the future outcome of the negotiations for gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin, including the likelihood of success of other potential suppliers of gas to the current customers of Mereenie and Palm Valley production. In addition, MPAL has a large number of exploration permits and faces the risk that any wells drilled may fail to encounter hydrocarbons in commercially recoverable quantities. Magellan assumes no obligation to update any forward-looking statements contained in this release, whether as a result of new information, future events, or otherwise.

Executive Summary

MPC is engaged in the exploration, development, production, and sale of natural gas and oil reserves. Magellan has maintained a conservative financial philosophy and is now well-positioned with cash and no debt to gain value through acquisition of distressed, debt-laden small-cap companies with substantive discovered reserves.

MPAL has begun refocusing its activities toward long-term development of and sale of reserves from the Amadeus Basin, gaining ownership/control of existing reserves offshore in the Bonaparte and Browse Basin, Australia and toward entry into major oil/gas basins in North America and Europe beginning with the Weald Basin, onshore southern United Kingdom. In addition, a number of other recent initiatives are active as described below:

 

   

We completed our first Private Investment transaction with Young Energy Prize S. A. (YEP) and signed a significant Heads of Agreement and Exclusivity Agreement with a major Methanol producer that will lead to the start of a feasibility study and commercial negotiations which may result in the construction of a methanol plant in or around the Darwin, NT, Australia area.

 

   

We have started work with an independent advisor to sell all of our assets in the Cooper Basin, Australia. Initial indications are that there will be considerable interest in bidding on the package(s). These assets are non-core to our strategies and are better suited to being consolidated into other portfolios.

 

   

Discussions are ongoing regarding consolidation of operations/ownership of our Palm Valley and Mereenie fields. We believe that success in these programs will result in material long-term expense reduction.

 

   

Gas sales discussions for near and longer term Mereenie volumes remain very active and promising. We are working to supplement delayed Blacktip volumes and are endeavoring to resolve the situation

 

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on a longer-term basis as well. In the interim, full gas flow to PWC continues and all prices for those sales now fall under the higher-priced Mereenie Sales Agreement 4, which runs on a best endeavors basis through December 31, 2010, unless amended or extended.

 

   

With the removal of land ownership and royalty issues in the United Kingdom, we are now in a position to initiate drilling at our first United Kingdom onshore location, Markwells Wood. We have ongoing discussions with the Operator, Northern Petroleum. From both an environmental and economic standpoint it is prudent to select a drilling rig that fits the requirements of the area and minimizes local impact. The Operator believes it will be in a position to do that with a target spud date in the first quarter of 2010.

 

   

We are exploring asset acquisition opportunities in North America with the idea of adding production and value while monetizing our tax loss carryforward position.

 

   

We are actively discussing property transactions and capital infusions so as to take positions in gas supply toward the Methanol feasibility and commercial process mentioned above.

The Palm Valley Darwin contract expires in the year 2012 and the principal Mereenie contracts expired in January and June 2009. Supply obligations under the Mereenie contracts ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010. The Palm Valley local sales contract expires in January 2012 and the Mereenie contracts continue on a month-to-month basis into 2010 under an evergreen term. The Company is making strong efforts to dedicate remaining natural gas to area buyers under “life of remaining reserves” agreement(s).

MPAL’s major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 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 sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

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 $164,000 from this investment during fiscal year 2009.

On July 9, 2009, the Company completed, pursuant to the terms of a definitive purchase agreement and related amendments an equity investment in the Company by the Company’s strategic investor, Young Energy Prize S.A. (“YEP”), through the issuance to YEP of 8,695,652 shares of the Company’s common stock, $0.01 par value per share (the “Common Stock”) and warrants to acquire an additional 4,347,826 shares of Common Stock. The Company received gross proceeds of $10 million, which will be used for working capital and general corporate purposes.

On July 9, 2009, the Company entered into a Warrant Agreement which entitles YEP to purchase 4,347,826 shares of the Company’s Common Stock (the “Warrant Shares”) at an exercise price of $1.20 per Warrant Share.

 

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The Warrant has a term of five years and contains certain provisions which would reduce the exercise price. Furthermore The First Amendment to the Purchase Agreement provides that, if YEP completes the purchase of the ANS Shares from the ANS Parties under the ANS-YEP Purchase Agreement, (more fully described in Item 8.01 of the Company’s Form 8-K filed on April 8, 2009,) then the exercise price payable by YEP for the Warrant Shares shall be reduced from $1.20 to $1.15 per share. This transaction was completed on July 30, 2009 reducing the exercise price to $1.15 per share.

In connection with the YEP Purchase Agreement, at a Board meeting held on May 27, 2009, the Company’s Board adopted resolutions: (a) conditionally amending the Company’s Bylaws to expand the size of the Board; and (b) conditionally electing Messrs. Nikolay Bogachev and J. Thomas Wilson to the Board as Class II directors, each to serve a term of office expiring at the Company’s 2011 Annual Meeting of Shareholders. On July 9, 2009, upon completion of the YEP equity investment transaction, the elections to the Board of Messrs. Bogachev and Wilson became effective.

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. 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, proved developed natural gas reserves were limited to contracted quantities. For Palm Valley, reserves were based upon the quantities of gas committed to the contract and estimated sales subsequent to the contract date. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed 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.

 

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Nondepletable assets

At June 30, 2009 and 2008, oil and gas properties include $6.6 million and $6.8 million, respectively, of capitalized costs that are currently not being depleted. Components of these costs are as follows:

 

     For the year ended June 30,  

Nondepletable capitalized costs

   2009     2008     2007  

PEL 106 – Cooper Basin (1)

      

Balance beginning of year

   $ 1,855,186      $ 1,615,943      $ 1,170,040   

Additions to capitalized costs

     —          12,746        264,492   

Exchange adjustment

     (302,348     226,497        181,411   
                        

Balance end of year

   $ 1,552,838      $ 1,855,186      $ 1,615,943   
                        

Weald/Wessex Basin U.K. (2)

      

Balance beginning of year

   $ 549,935      $ —        $ —     

Additions to capitalized costs

     485,725        549,935        —     

Exchange adjustment

     (52,112     —          —     
                        

Balance end of year

   $ 983,548      $ 549,935      $ —     
                        

Nockatunga

      

Balance beginning of year

   $ —        $ 7,431,514      $ —     

Additions to capitalized costs

     —          —          7,431,514   

Reclassified to producing properties

     —          (7,431,514     —     

Exchange adjustment

     —          —          —     
                        

Balance end of year

   $ —        $ —        $ 7,431,514   
                        

Exploration permits and licenses – Australia and U.K. (3)

      

Balance beginning of year

   $ 4,425,749      $ 4,431,347      $ 5,323,347   

Charged to expense

     (321,258     (5,598     (892,000
                        

Balance end of year

   $ 4,104,491      $ 4,425,749      $ 4,431,347   
                        

Total

      

Balance beginning of year

   $ 6,830,870      $ 13,478,804      $ 6,493,387   

Additions to capitalized costs

     485,725        562,681        7,696,006   

Reclassified to producing properties

     —          (7,431,514     —     

Charged to expense (3)

     (321,258     (5,598     (892,000

Exchange adjustment

     (354,460     226,497        181,411   
                        

Balance end of year

   $ 6,640,877      $ 6,830,870      $ 13,478,804   
                        

 

(1) These costs were capitalized during the year ended June 30, 2006 and remain capitalized because the related well has sufficient quantity of reserves to justify its completion as a producing well. Efforts are currently being made to market the gas from this well. The operator intends to apply for a petroleum retention license with the objective of obtaining a petroleum production license by the end of calendar year 2009. The intention is to commence gas production and sales in January 2010.
(2) Capitalized exploratory well costs pending the start of production.
(3) The Company evaluates exploration permits and licenses annually or whenever events or changes in circumstances indicate that the carrying value, related to step up to fair value for the 44.87% remaining interest acquired in 2006, may be impaired. See discussion under Goodwill below for valuation methodology of the exploration permits and licenses. An impairment loss of $63,740 was recorded during the fiscal year. In addition, the Company did not renew certain permits resulting in a write off of $257,518. These amounts are recorded in exploration and dry hole costs.

 

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Goodwill

All of our goodwill is related to the fiscal 2006 acquisition of the 44.87% of MPAL that we did not own at the time. In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, goodwill is not amortized and is tested for impairment annually or whenever events or changes in circumstances indicate that the carrying value may be impaired. We performed our annual impairment testing as of June 30, 2009 and determined that no impairment existed as of that date.

We employ the adjusted balance sheet method to estimate the fair value of MPAL. This method entails estimating the fair value of all of MPAL’s balance sheet items as of the valuation date. If the adjusted equity value, after considering the fair values of the assets and liabilities, is greater than the carrying value of MPAL, then no impairment is indicated. Management believes that this methodology is most meaningful since the highest and best use of these assets would be to continue to hold and exploit the assets over time.

The fair value of our oil and gas properties are estimated based on the discounted cash flows of our proved and risk adjusted probable and possible reserves.

The significant assumptions used in estimating the fair values of the oil and gas properties are oil and gas selling prices for non-contracted volumes, oil and gas sales volumes, discount rates, and production trends. The fair value of MPAL is most susceptible to changes in selling prices of oil and gas and changes in estimated sales volume. As an example, a 10% decrease in the selling price or sales volume of oil and gas for the non-contracted volumes would reduce the estimated fair value of MPAL by approximately $3.3 million.

The fair value of our nondepletable exploration permits and licenses is estimated separately using one of four methods – discounted cash flows, discounted cash flows adjusted for chances of success, recent farmin costs and premiums, and estimated costs of committed work programs. The majority of the permits and licenses are valued based on the estimated cost of agreed work program commitments, which is a methodology that is not dependent on significant assumptions.

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 our operating fields. The liability is a discounted liability using a credit-adjusted risk-free rate on the date such liabilities are determined. Revisions to the liability could occur due to changes in the estimates or timing 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 (net of royalties) 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

 

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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. Government sales taxes related to MPAL’s oil and gas production revenues are collected by MPAL and remitted to the Australian government. Such amounts are excluded from revenue and expenses. Shipping and handling costs in connection with such deliveries are included in production costs except for Nockatunga crude oil transportation costs which are deducted from gross sales. 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 may lag the production month by one or more months.

Liquidity and Capital Resources

At June 30, 2009, the Company on a consolidated basis had approximately $34.7 million of cash and cash equivalents and $1.0 million in marketable securities. The Company considers cash equivalents to be short term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of change in interest rates. Cash balances were $13.3 million as of June 30, 2009 and the remaining $21.4 million was held in time deposit accounts in several Australian banks that have terms of 90 days or less. National Australia Bank, Ltd. (“NAB”) holds 55% of the cash and cash equivalent balance. Although the funds are uninsured, Standard and Poor’s credit rating of NAB is AA Stable long-term and A-1+ short-term.

Consolidated

When considering our liquidity and capital resources, we consider cash and cash equivalents and marketable securities together since all of these amounts are available to fund operating, exploration and development activities. The balance of cash and cash equivalents and marketable securities decreased $637,000 during the year ended June 30, 2009 compared to a $3.5 million increase in those balances during the year ended June 30, 2008. The factors favorably impacting our liquidity and capital resources during the year ended June 30, 2009 included a decrease in tax payments of $12.2 million offset by a net decrease in collections of $8.8 million. We also experienced a $1.4 million decrease in cash expenditures on exploration and development and a $1.8 million decrease in property and equipment expenditures offset by a $0.6 million investment in securities available for sale. Our cash position was also unfavorably affected by a $10.2 million decrease in foreign exchange transaction gains resulting from a weakened Australian dollar.

The decrease in cash from the sales of oil and gas was due to decreased sales of $12.7 million offset by a decrease in accounts receivable of $3.9 million. Sales decreases were mostly due to a 27% decrease in barrels sold, attributable essentially to a 48,000 barrel decrease in the Nockatunga project resulting from a downward production trend. The decrease in accounts receivable resulted from the collection in 2009 of 2008 revenues for which the due date had been extended.

The Company invested $2.9 million and $6.1 million in oil and gas exploration activities, which includes additions to property and equipment, during the fiscal years ended June 30, 2009 and 2008, respectively. The decrease was due to reduced drilling activities in 2009.

MPAL’s current contracts for the sale of Palm Valley gas will expire during fiscal years 2012. Mereenie contracts expired in January and June 2009. Supply obligations ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC or be successful in its current exploration program, its revenues will begin to decline substantially

 

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in 2010 which would materially affect liquidity. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index. 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 December, 2008, a dividend of $3.0 million was received from MPAL to fund operating costs. Also in June, 2009, MPAL loaned approximately $1.9 million to MPC.

On July 9, 2009, the Company completed, pursuant to the terms of a definitive purchase agreement and related amendments an equity investment in the Company by the Company’s strategic investor, Young Energy Prize S.A. through the issuance to YEP of 8,695,652 shares of the Company’s common stock, $0.01 par value per share and warrants to acquire an additional 4,347,826 shares of Common Stock. The Company received gross proceeds of $10 million, which will be used for working capital and general corporate purposes.

At June 30, 2009, MPC, on an unconsolidated basis, had working capital of $800,054. Working capital is comprised of current assets less current liabilities. MPC’s current cash position and any future MPAL dividends should be adequate to meet MPC’s 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, 2009, MPC purchased 680,850 of its shares at a cost of approximately $686,000. There were no shares purchased during fiscal years 2009, 2008 or 2007.

As to MPAL

At June 30, 2009, MPAL had working capital of $36,360,451. MPAL had budgeted approximately (Aus) $6.0 million for specific exploration projects in fiscal year 2009 as compared to the (Aus) $4.7 million expensed during fiscal 2009. 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 gas will expire during fiscal years 2012. Mereenie contracts expired in January and June 2009. Supply obligations ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC or be successful in its current exploration program, its revenues will begin to decline substantially in 2010 which could materially affect liquidity. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index. 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 in the past, MPAL expects to fund its exploration costs through its cash and cash equivalents and cash flow from Australian operations. MPAL also expects that it will continue to seek partners to share its exploration costs. If MPAL’s efforts to find partners are unsuccessful, it may be unable or unwilling to complete the exploration program for some of its properties.

Off Balance Sheet Arrangements

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

 

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Contractual Obligations

The following is a summary of our consolidated contractual obligations as of June 30, 2009, in thousands:

 

     Payments Due by Period

Contractual Obligations

   Total    Less Than
1 Year
   1-3 Years    3-5 Years    More Than
5 Years

Operating Lease Obligations

   $ 821    $ 263    $ 558    $ —      $ —  

Purchase Obligations (1)

     6,469      6,469      —        —        —  

Asset Retirement Obligations – Undiscounted (2)

     14,470      202      2,446      8,397      3,425
                                  

Total

   $ 21,760    $ 6,934    $ 3,004    $ 8,397    $ 3,425
                                  

 

(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 $41,541,000 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), $20,971,000 (1-3 years), $18,409,000 (3-5 years) and $2,161,000 (greater than 5 years).
(2) During the year ended June 30, 2009, the Company decreased total asset retirement obligations by $626,000 due to changes in cost estimates and expected restoration dates (see Note 4 to the Financial Statements).

Recent Accounting Pronouncements

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for annual reports for fiscal years ending on or after December 15, 2009. This guidance is effective for the Company for the fiscal year ended June 30, 2010. The SEC will also require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.

In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157”. This FSP delays the effective date of FASB Statement No. 157, “Fair Value Measurements”, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), including asset retirement obligations and goodwill and other impairment analyses. This guidance is effective for the Company for the fiscal year ended June 30, 2010. The Company is currently evaluating the impact of adoption of this FSP.

 

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Results of Operations

2009 vs. 2008

REVENUES

Changes in revenues are as follows:

 

     Twelve Months ended
June 30,
            
     2009    2008    $ Variance     % Variance  

Oil sales

   $ 11,479,660    $ 19,786,175    $ (8,306,515   (42 %) 

Gas sales

     14,740,296      18,523,095      (3,782,799   (20 %) 

Other production related revenues

     1,970,621      2,585,540      (614,919   (24 %) 

Interest income

     1,583,065      2,122,642      (539,577   (25 %) 

Significant changes are discussed below.

OIL SALES DECREASED due to a 27% decrease in production, an 11% decrease in average price per barrel and the 17% decrease in the average exchange rate discussed below. Oil unit sales (after deducting royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:

 

    TWELVE MONTHS ENDED JUNE 30,            
    2009 SALES   2008 SALES            
    BBLS   AVERAGE PRICE
A.$ PER BBL
  BBLS   AVERAGE PRICE
A.$ PER BBL
  % Variance
BBLS
    % Variance
A.$ PER BBL
 

Australia:

           

Mereenie field

  90,267   94.20   95,429   113.33   (5 %)    (17 %) 

Cooper Basin

  2,362   101.42   6,826   114.28   (65 %)    (11 %) 

Nockatunga project (1)

  60,668   86.30   108,311   91.82   (44 %)    (6 %) 
               

Total

  153,297   91.21   210,566   102.35   (27 %)    (11 %) 
               

 

(1) Nockatunga average price per bbl is net of crude oil transportation costs which are deducted from the gross sales price.

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, 2009 and 2008, the average foreign exchange rates were .7471 and .8965 respectively.

GAS SALES DECREASED due to a 10% decrease in volume resulting from natural field decline and the 17% decrease in the average exchange rate discussed below partially offset by a 4% increase in the average price per mcf. The volumes in billion cubic feet (bcf) (after deducting 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,             
     2009 SALES    2008 SALES             
     BCF    AVERAGE PRICE
A.$ PER MCF
   BCF    AVERAGE PRICE
A.$ PER MCF
   % Variance
BCF
    % Variance
A.$ PER MCF
 

Australia: Palm Valley

   1.165    2.25    1.319    2.22    (12 %)    1

Australia: Mereenie

   3.996    3.93    4.388    3.77    (9 %)    4
                    

Total

   5.161    3.54    5.707    3.39    (10 %)    4
                    

 

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MPAL’s current contracts for the sale of Palm Valley gas will expire during fiscal years 2012. Mereenie contracts expired in January and June 2009. Supply obligations ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. For further information, see “Gas Supply Contracts” in Item 1-Business and Item 7-Executive Summary above.

OTHER PRODUCTION RELATED REVENUES are primarily MPAL’s share of gas pipeline tariff revenues which decreased as a result of a decrease in volumes of gas sold at Mereenie and the 17% Australian foreign exchange rate decrease discussed below.

INTEREST INCOME DECREASED due to a decrease in market interest rates and the 17% decrease in the average exchange rate discussed below.

COSTS AND EXPENSES

Changes in costs and expenses are as follows:

 

     Twelve Months Ended
June 30,
             
     2009    2008     $ Variance     % Variance  

Production cost

   8,153,263    8,865,663      (712,400   (8 %) 

Exploration and dry hole costs

   3,475,937    3,318,810      157,127      5

Salaries and employee benefits

   1,708,997    1,605,341      103,656      6

Depletion, depreciation and amortization

   6,785,952    18,021,236      (11,235,284   (62 %) 

Auditing, accounting and legal services

   1,576,509    1,102,115      474,394      43

Accretion expense

   531,405    716,130      (184,725   (26 %) 

Shareholder communications

   633,112    392,880      240,232      61

Loss (gain) on sale of field equipment

   12,072    (35,235   47,307      (134 %) 

Impairment loss

   63,740    —        63,740      —     

Other administrative expenses

   3,969,658    3,591,856      377,802      11

Income tax provision

   2,198,422    14,330,301      (12,131,879   (85 %) 

Significant changes are discussed below.

PRODUCTION COSTS DECREASED due to the 17% decrease in the average exchange rate described below offset by increased labor and rental costs in the Nockatunga project ($438,000).

EXPLORATION AND DRY HOLE COSTS INCREASED due to seismic survey costs related to the Nockatunga fields ($1.4 million) and the write off of certain U.K. permits in 2009 ($296,000) offset by Cooper Basin drilling costs incurred in 2008 but not in 2009 ($1.3 million) and the 17% decrease in the average exchange rate described below.

DEPLETION, DEPRECIATION AND AMORTIZATION DECREASED due to lower depletable costs and the 17% decrease in the average exchange rate described below. Lower depletable costs result from recent depletion charges in excess of recent capital spending.

AUDITING, ACCOUNTING AND LEGAL SERVICES INCREASED due mostly to legal fees related to the YEP investment transaction and the shareholder agreement of approximately $574,000 (See Note 15 to the Financial Statements) partially offset by the 17% decrease in the average exchange rate described below.

ACCRETION EXPENSE DECREASED due mostly because of a reduction of the Mereenie asset retirement obligations (“ARO”) in the first quarter of fiscal 2009 ($995,000) and the 17% decrease in the exchange rate described below.

 

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SHAREHOLDER COMMUNICATION COSTS INCREASED due to an increase in proxy and regulatory filing activity. The increased proxy activity was due to a threatened director election and additional voting matters which required stockholder approval, including the YEP investment transaction.

OTHER ADMINISTRATIVE EXPENSES INCREASED due to net exchange rate losses ($461,000), increased travel costs ($125,000), increased repair and maintenance costs ($138,000) and increased due diligences costs related to the YEP investment transaction ($393,000—see Note 15 to the Financial Statements) offset by a decrease in costs related to the ATO settlement ($597,000) that were incurred in 2008 but not in 2009, decrease in insurance expense in 2009 ($247,000) and the 17% decrease in the average exchange rate described below.

INCOME TAXES

INCOME TAX PROVISION DECREASED due to the decrease in income before taxes as well as the provision of the ATO settlement in the prior fiscal period (see Note 6 to the Financial Statements for a discussion of effective tax rates used and the ATO settlement).

EXCHANGE EFFECT

The value of the Australian dollar relative to the U.S. dollar decreased to $.8048 at June 30, 2009 compared to $.9615 at June 30, 2008. This resulted in a $9,931,978 debit to accumulated translation adjustments for fiscal 2009. The 16% decrease in the value of the Australian dollar decreased the reported asset and liability amounts in the balance sheet at June 30, 2009 from the June 30, 2008 amounts. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2009 was $.7471, which is a 17% decrease compared to the $.8965 rate for fiscal 2008.

2008 vs. 2007

REVENUES

Changes in revenues are as follows:

 

     Twelve Months ended
June 30,
           
     2008    2007    $ Variance    % Variance  

Oil sales

   $ 19,786,175    $ 11,922,574    $ 7,863,601    66

Gas sales

     18,523,095      16,396,334      2,126,761    13

Other production related revenues

     2,585,540      2,356,317      229,223    10

Interest income

     2,122,642      1,669,798      452,844    27

Significant changes are discussed below.

 

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OIL SALES INCREASED 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% 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            
    BBLS   AVERAGE PRICE
A.$ PER BBL
  BBLS   AVERAGE PRICE
A.$ PER BBL
  % Variance
BBLS
    % Variance
A.$ PER BBL
 

Australia:

           

Mereenie field

  95,429   113.33   100,852   82.75   (5 %)    37

Cooper Basin

  6,826   114.28   15,261   85.02   (55 %)    34

Nockatunga project (1)

  108,311   91.82   63,252   76.50   71   20
               

Total

  210,566   102.35   179,365   80.75   17   27
               

 

(1) Nockatunga average price per bbl is net of crude oil transportation costs which are deducted from the gross sales price.

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 primarily as the result of a 5% increase in price per mcf sold and the 14% 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             
     BCF    AVERAGE PRICE
A.$ PER MCF
   BCF    AVERAGE PRICE
A.$ PER MCF
   % Variance
BCF
    % Variance
A.$ PER MCF
 

Australia: Palm Valley

   1.319    2.22    1.499    2.20    (12 %)    1

Australia: Mereenie

   4.388    3.77    4.489    3.60    (2 %)    5
                    

Total

   5.707    3.39    5.988    3.24    (5 %)    5
                    

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 are primarily MPAL’s share of gas pipeline tariff revenues which increased as a result of the 14% Australian foreign exchange rate increase discussed below offset by a decrease in volumes of gas sold at Mereenie.

 

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COSTS AND EXPENSES

Changes in costs and expenses are as follows:

 

     Twelve Months Ended
June 30,
             
     2008     2007     $ Variance     % Variance  

Production cost

   8,865,663      6,965,641      1,900,022      27

Exploration and dry hole costs

   3,318,810      5,520,460      (2,201,650   (40 %) 

Salaries and employee benefits

   1,605,341      1,549,277      56,064      4

Depletion, depreciation and amortization

   18,021,236      10,693,415      7,327,821      69

Auditing, accounting and legal services

   1,102,115      628,114      474,001      75

Accretion expense

   716,130      517,856      198,274      38

Shareholder communications

   392,880      459,298      (66,418   (14 %) 

Gain on sale of field equipment

   (35,235   (10,346   (24,889   241

Impairment loss

   —        1,876,171      (1,876,171   (100 %) 

Other administrative expenses

   3,591,856      2,699,733      892,123      33

Income tax provision

   14,330,301      998,565      13,331,736      1335

Significant changes are discussed below.

PRODUCTION COSTS INCREASED primarily as 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% increase in the exchange rate described below.

EXPLORATION AND DRY HOLE COSTS DECREASED due primarily to decreased drilling costs related to the Cooper Basin drilling program, partially offset by the 14% increase in the exchange rate described below.

DEPLETION, DEPRECIATION AND AMORTIZATION INCREASED as a result of the higher book values of MPAL’s oil and gas properties acquired during fiscal 2006 resulting from an updated valuation at June 30, 2007, increased depletion in the Nockatunga project due to increased production resulting from the 10 wells drilled in the fourth quarter of fiscal 2007, increased expenditures and the 14% 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 SERVICES INCREASED due to higher auditing, accounting and legal costs incurred in connection with the ATO audit and settlement and tax planning.

ACCRETION EXPENSE INCREASED due mostly to accretion of asset retirement obligations relating to the new wells drilled in fiscal 2007 in the Nockatunga project and the 14% increase in the exchange rate described below. Accretion expense represents the accretion on the asset retirement obligations (“ARO”) under SFAS 143.

IMPAIRMENT LOSS DECREASED because 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 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% increase in the exchange rate described below.

 

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INCOME TAXES

INCOME TAX PROVISION INCREASED primarily due 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% increase compared to the $.7860 rate for fiscal 2007.

 

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 in Item 1A-Risk Factors 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 (including held-to-maturity and available-for-sale securities). At June 30, 2009, the carrying value of such investments and those classified as cash and cash equivalents was approximately $36.6 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 U.S. 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 $2.8 million and $2.7 million, respectively. For the twelve months ended June 30, 2009, oil sales represented approximately 44% of oil and gas sales. Based on 2009 sales volume and revenue, a 10% change in oil price would increase or decrease oil revenues by approximately $1.1 million. Gas sales, which represented approximately 56% of production revenues in 2009, 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, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2009. 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, 2009 and 2008, and the results of their operations and cash flows for each of the three years in the period ended June 30, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

October 2, 2009

Hartford, Connecticut

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

 

     June 30,  
     2009     2008  
ASSETS     

Current assets:

    

Cash and cash equivalents

   $ 34,688,842      $ 34,615,228   

Accounts receivable — Trade (net of allowance for doubtful accounts of $90,102 and $99,344 at June 30, 2009 and 2008, respectively)

     5,346,111        8,357,839   

Accounts receivable — working interest partners

     500,404        112,330   

Marketable securities

     997,306        1,708,222   

Inventories

     847,159        1,260,189   

Deferred income taxes

     563,853        —     

Other assets

     598,509        404,160   
                

Total current assets

     43,542,184        46,457,968   
                

Deferred income taxes

     5,708,448        6,368,665   

Securities available-for-sale (at fair value)

     903,924        —     

Property and equipment, net:

    

Oil and gas properties (successful efforts method)

     117,617,555        138,556,513   

Land, buildings and equipment

     2,962,649        3,346,368   

Field equipment

     868,504        1,040,281   
                
     121,448,708        142,943,162   

Less accumulated depletion, depreciation and amortization

     (103,919,971     (114,495,875
                

Net property and equipment

     17,528,737        28,447,287   

Goodwill

     4,020,706        4,020,706   
                

Total assets

   $ 71,703,999      $ 85,294,626   
                
LIABILITIES AND STOCKHOLDERS’ EQUITY     

Current liabilities:

    

Accounts payable

   $ 2,688,342      $ 2,929,445   

Accrued liabilities

     1,639,284        1,891,194   

Income taxes payable

     2,054,052        3,857,766   
                

Total current liabilities

     6,381,678        8,678,405   
                

Long term liabilities:

    

Deferred income taxes

     1,923,907        2,507,712   

Other long term liabilities

     70,232        48,998   

Asset retirement obligations

     9,815,262        11,596,084   
                

Total long term liabilities

     11,809,401        14,152,794   
                

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

     73,311,075        73,216,143   

Accumulated deficit

     (22,192,919     (22,857,494

Accumulated other comprehensive income

     1,979,763        11,689,777   
                

Total stockholders’ equity

     53,512,920        62,463,427   
                

Total liabilities and stockholders’ equity

   $ 71,703,999      $ 85,294,626   
                

See accompanying notes.

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Years Ended June 30,  
     2009    2008     2007  

Revenues:

       

Oil sales

   $ 11,479,660    $ 19,786,175      $ 11,922,574   

Gas sales

     14,740,296      18,523,095        16,396,334   

Other production related revenues

     1,970,621      2,585,540        2,356,317   
                       

Total revenues

     28,190,577      40,894,810        30,675,225   
                       

Costs and expenses:

       

Production costs

     8,153,263      8,865,663        6,965,641   

Exploratory and dry hole costs

     3,475,937      3,318,810        5,520,460   

Salaries and employee benefits

     1,708,997      1,605,341        1,549,277   

Depletion, depreciation and amortization

     6,785,952      18,021,236        10,693,415   

Auditing, accounting and legal services

     1,576,509      1,102,115        628,114   

Accretion expense

     531,405      716,130        517,856   

Shareholder communications

     633,112      392,880        459,298   

Loss (gain) on sale of field equipment

     12,072      (35,235     (10,346

Impairment loss

     63,740      —          1,876,171   

Other administrative expenses

     3,969,658      3,591,856        2,699,733   
                       

Total costs and expenses

     26,910,645      37,578,796        30,899,619   
                       

Operating income (loss)

     1,279,932      3,316,014        (224,394

Interest income

     1,583,065      2,122,642        1,669,798   
                       

Income before income taxes

     2,862,997      5,438,656        1,445,404   

Income tax expense

     2,198,422      14,330,301        998,565   
                       

Net income (loss)

   $ 664,575    $ (8,891,645   $ 446,839   
                       

Average number of shares:

       

Basic

     41,500,325      41,500,325        41,500,325   
                       

Diluted

     41,500,325      41,500,325        41,500,325   
                       

Per share (basic and diluted)

       

Net income (loss)

   $ 0.02    $ (0.21   $ 0.01   
                       

 

See accompanying notes.

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF

STOCKHOLDERS’ EQUITY

Three Years Ended June 30, 2009

 

    Number of
Shares
  Common
Stock
  Capital in
Excess of
Par Value
  Accumulated
Deficit
    Accumulated
Other
Comprehensive
Income (Loss)
    Total     Total
Comprehensive
Income (Loss)
 

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     
                                         

Net income

  —       —       —       664,575        —          664,575        664,575   

Foreign currency translation adjustments

  —       —       —       —          (9,931,978     (9,931,978     (9,931,978

Unrealized holding gains, net of taxes

  —       —       —       —          221,964        221,964        221,964   
                   

Stock option compensation

  —       —       94,932     —          —          94,932     

Total comprehensive loss

  —       —       —       —          —          —        $ (9,045,439
                                               

June 30, 2009

  41,500,325   $ 415,001   $ 73,311,075   $ (22,192,919   $ 1,979,763      $ 53,512,920     
                                         

See accompanying notes.

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Years Ended June 30,  
     2009     2008     2007  

Operating Activities:

      

Net income (loss)

   $ 664,575      $ (8,891,645   $ 446,839   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Loss (gain) from sale of field equipment

     12,072        (35,235     (10,346

Depletion, depreciation and amortization

     6,785,952        18,021,236        10,693,415   

Accretion expense

     531,405        716,130        517,856   

Deferred income taxes

     (1,618,033     (4,541,695     (1,818,631

Stock option compensation

     94,932        63,141        7,425   

Exploration and dry hole costs

     5,765        1,328,114        2,717,546   

Write off of exploration permits

     359,471        —          1,876,171   

Changes in operating assets and liabilities:

      

Accounts receivable

     1,270,721        (2,640,315     472,763   

Other assets

     65,531        (26,946     (61,312

Inventories

     203,312        (428,332     143,951   

Accounts payable and accrued liabilities

     1,793,486        70,480        (709,314

Income taxes payable

     (930,137     1,860,666        1,659,711   
                        

Net cash provided by operating activities

     9,239,052        5,495,599        15,936,074   
                        

Investing Activities:

      

Additions to property and equipment

     (2,430,184     (4,249,215     (5,783,117

Proceeds from sale of field equipment

     27,728        35,235        10,346   

Oil and gas exploration activities

     (491,490     (1,890,795     (2,982,038

Acquisition of minority interest in MPAL

     —          —          (88,432

Investment in securities available for sale

     (559,850     —          —     

Marketable securities matured or sold

     3,109,611        4,435,820        1,855,609   

Marketable securities purchased

     (2,398,695     (1,765,775     (5,694,201
                        

Net cash used in investing activities

     (2,742,880     (3,434,730     (12,681,833
                        

Financing Activities:

      

Equity issuance costs

     (259,879     —          —     
                        

Net cash used in financing activities

     (259,879     —          —     
                        

Effect of exchange rate changes on cash and cash equivalents

     (6,162,679     4,083,911        3,333,325   
                        

Net increase in cash and cash equivalents

     73,614        6,144,780        6,587,566   

Cash and cash equivalents at beginning of year

     34,615,228        28,470,448        21,882,882   
                        

Cash and cash equivalents at end of year

   $ 34,688,842      $ 34,615,228      $ 28,470,448   
                        

Cash payments:

      

Income taxes

     4,746,589        13,072,505        1,427,327   

Interest on tax settlement

     —          3,893,014        —     

Supplemental Schedule of Noncash Investing and Financing Activities:

      

Unrealized holding gains

     344,074        —          —     

Revision to estimate of asset retirement obligations

     (625,962     43,482        (54,765

Asset retirement obligation liabilities incurred

     —          —          718,048   

Accounts payable related to property and equipment

     163,457        1,993,964        3,195,633   

The allocation of the purchase price to the assets acquired in the purchase of the 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).

See accompanying notes.

 

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1. Summary of Significant Accounting Policies

Principles of Consolidation

Magellan Petroleum Corporation (“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, 2009 and 2008, MPC’s principal asset was a 100% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”). 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 five 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 (net of royalties) from its interests in producing wells as oil and gas is produced and sold from those wells. Revenues from the 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. Government sales taxes related to MPAL’s oil and gas production revenues are collected by MPAL and remitted to the Australian government. Such amounts are excluded from revenue and expenses. Shipping and handling costs in connection with such deliveries are included in production costs except for Nockatunga crude oil transportation costs which are deducted from gross sales. 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 may lag the production month by one or more months.

Stock-Based Compensation

The Company has one stock option plan which was amended on May 27, 2009 to, among other things, increase the aggregate number of shares issuable under the plan to 5,205,000. 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 time based stock option share awards and the Monte Carlo model for performance based options share awards that include a market condition as described in SFAS 123(R). These models include various assumptions, including the expected volatility and the expected life of the share awards as well as significant assumptions for performance based awards that include probabilities of certain vesting conditions and behaviors impacting exercise. These assumptions, as detailed in Note 5-Capital and Stock Options, 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.

 

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Oil and Gas Properties

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

 

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Nondepletable assets

At June 30, 2009 and 2008, oil and gas properties include $6.6 million and $6.8 million, respectively, of capitalized costs that are currently not being depleted. Components of these costs are as follows:

 

     For the year ended June 30,  

Nondepletable capitalized costs

   2009     2008     2007  

PEL 106 – Cooper Basin (1)

      

Balance beginning of year

   $ 1,855,186      $ 1,615,943      $ 1,170,040   

Additions to capitalized costs

     —          12,746        264,492   

Exchange adjustment

     (302,348     226,497        181,411   
                        

Balance end of year

   $ 1,552,838      $ 1,855,186      $ 1,615,943   
                        

Weald/Wessex Basin U.K. (2)

      

Balance beginning of year

   $ 549,935      $ —        $ —     

Additions to capitalized costs

     485,725        549,935        —     

Exchange adjustment

     (52,112     —          —     
                        

Balance end of year

   $ 983,548      $ 549,935      $ —     
                        

Nockatunga

      

Balance beginning of year

   $ —        $ 7,431,514      $ —     

Additions to capitalized costs

     —          —          7,431,514   

Reclassified to producing properties

     —          (7,431,514     —     

Exchange adjustment

     —          —          —     
                        

Balance end of year

   $ —        $ —        $ 7,431,514   
                        

Exploration permits and licenses – Australia and U.K. (3)

      

Balance beginning of year

   $ 4,425,749      $ 4,431,347      $ 5,323,347   

Charged to expense

     (321,258     (5,598     (892,000
                        

Balance end of year

   $ 4,104,491      $ 4,425,749      $ 4,431,347   
                        

Total

      

Balance beginning of year

   $ 6,830,870      $ 13,478,804      $ 6,493,387   

Additions to capitalized costs

     485,725        562,681        7,696,006   

Reclassified to producing properties

     —          (7,431,514     —     

Charged to expense (3)

     (321,258     (5,598     (892,000

Exchange adjustment

     (354,460     226,497        181,411   
                        

Balance end of year

   $ 6,640,877      $ 6,830,870      $ 13,478,804   
                        

 

(1) These costs were capitalized during the year ended June 30, 2006 and remain capitalized because the related well has sufficient quantity of reserves to justify its completion as a producing well.
(2) Capitalized exploratory well costs pending the start of production.
(3) The Company evaluates exploration permits and licenses annually or whenever events or changes in circumstances indicate that the carrying value, related to step up to fair value for the 44.87% remaining interest acquired in 2006, may be impaired. See discussion under Goodwill below for valuation methodology of the exploration permits and licenses. An impairment loss of $63,740 was recorded during the fiscal year. In addition, the Company did not renew certain permits resulting in a write off of $257,518. These amounts are recorded in exploration and dry hole costs.

Goodwill

The aggregate amount of goodwill at June 30, 2009 and 2008 is $4,020,706. All of our goodwill is related to the fiscal 2006 acquisition of the 44.87% of MPAL that we did not own at the time. In accordance with

 

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Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, goodwill is not amortized and is tested for impairment annually or whenever events or changes in circumstances indicate that the carrying value may be impaired. Our annual impairment testing date is June 30. An impairment test was performed as of December 31, 2008 due to the significant decrease in world oil prices and the fact that our stock was trading significantly below our tangible book value. We also performed our annual impairment testing as of June 30, 2009. We determined that no impairment existed at either of those dates.

We employ the adjusted balance sheet method to estimate the fair value of MPAL. This method entails estimating the fair value of all of MPAL’s balance sheet items as of the valuation date. If the adjusted equity value, after considering the fair values of the assets and liabilities, is greater than the carrying value of MPAL, then no impairment is indicated. Management believes that this methodology is most meaningful since the highest and best use of these assets would be to continue to hold and exploit the assets over time.

The fair value of our oil and gas properties are estimated based on the discounted cash flows of our proved and risk adjusted probable and possible reserves. The significant assumptions used in estimating the fair values of the oil and gas properties are oil and gas selling prices for non-contracted volumes, oil and gas sales volumes, discount rates, and production trends. The fair value of MPAL is most susceptible to changes in selling prices of oil and gas and changes in estimated sales volume.

The fair value of our nondepletable exploration permits and licenses is estimated separately using one of four methods – discounted cash flows, discounted cash flows adjusted for chances of success, recent farmin costs and premiums, and estimated costs of committed work programs. The majority of the permits and licenses are valued based on the estimated cost of agreed work program commitments, which is a methodology that is not dependent on significant assumptions.

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 and 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 estimated life of the field, 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.

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.

 

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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, 2009 and 2008, the Australian dollar was equivalent to U.S. $.8048 and $.9615, respectively. The annual average exchange rates used to translate MPAL’s operations in Australia for the fiscal years 2009, 2008 and 2007 were $.7471, $.8965 and $.7860, respectively.

Accrued Liabilities

At June 30, 2009 and 2008, balances in accrued liabilities which exceeded 5% of current liabilities include $770,024 and $953,240 of employment benefits, respectively, and $350,886 and $596,975 of withholding and sale taxes, respectively.

Accounting for Income Taxes

The Company follows 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.

Financial Accounting Standards Board 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. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the financial statements uncertain tax positions that the company has taken or expects to take in its tax returns. Under FIN 48, the Company is able to recognize a tax position based on whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company has presumed 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 tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. An uncertain income tax position will not be recognized if it does not meet the more-likely-than-not threshold. To appropriately account for income tax matters in accordance with SFAS 109 and FIN 48, the Company is required to make significant judgments and

 

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estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. There are no uncertain tax positions for fiscal 2009.

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 the timing of the 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. The components of cash and cash equivalents are as follows:

 

     June 30,
     2009    2008

Cash

   $ 13,294,642    $ 2,916,069

Australian money market accounts

     21,394,200      31,699,159
             
   $ 34,688,842    $ 34,615,228
             

National Australia Bank, Ltd. (“NAB”) holds 55% of the cash and cash equivalent balance. Although the funds are uninsured, Standard and Poor’s credit rating of NAB is AA Stable long-term and A-1+ short-term.

Marketable Securities

The Company has determined that declines in fair value below amortized costs are temporary as management does not have the intent to sell the securities before maturity nor does it believe that it is more likely than not that the securities will be required to be sold before anticipated recovery. Therefore, no impairment loss has been recognized. At June 30, 2009 and 2008, MPC had the following marketable securities which are expected to be held until maturity:

 

June 30, 2009

   Par Value    Maturity Date    Amortized Cost    Fair Value

Short-term securities

           

U.S. government agency note

   $ 250,000    Jul. 15, 2009    $ 249,690    $ 250,000

U.S. government agency note

     250,000    Aug. 14, 2009      249,449      249,975

U.S. government agency note

     250,000    Sep. 21, 2009      249,179      249,925

U.S. government agency note

     250,000    Oct. 15, 2009      248,988      249,875
                       

Total short-term

   $ 1,000,000       $ 997,306    $ 999,775
                       

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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Securities Available-for-Sale

The Company classifies securities that have a readily determinable fair value and are not bought and not held principally for the purpose of selling them in the near term as securities available-for-sale, pursuant to FAS 115 Accounting for Certain Investment in Debt & Equity Securities. Under FAS 115, unrealized holding gains and losses for available-for-sale securities shall be excluded from earnings and reported in other comprehensive income until realized. The Company currently has one foreign equity security classified as available for sale.

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 2009, the Company issued approximately 2.7 million stock options. These options have been issued under the Company’s 1998 Stock Incentive Plan, which was approved at the annual shareholders’ meeting held on May 27, 2009. At June 30, 2009, the Company had 3,242,500 stock options outstanding all of which were anti-dilutive.

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.

Stock Options

The Company’s 1998 Stock Incentive Plan (the “Plan”) provides for grants of shares of stock, stock appreciation rights (“SARs”), restricted shares and 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 awarded. The Plan was amended on May 27, 2009. The amended Plan has 5,205,000 shares authorized for awards. See Note 5-Capital and Stock Options.

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, 2009 and 2008 was as follows:

 

     2009    2008

Foreign currency translation adjustments

   $ 1,757,799    $ 11,689,777

Unrealized holding gains, net of deferred tax

     221,964      —  
             

Accumulated other comprehensive income

   $ 1,979,763    $ 11,689,777
             

Recent Accounting Pronouncements

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the

 

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management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for annual reports for fiscal years ending on or after December 15, 2009. This guidance is effective for the Company for the fiscal year ended June 30, 2010. The SEC will also require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.

In April 2009, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”, which is effective as of June 30, 2009 with early adoption permitted. The Company adopted the FSP as of June 30, 2009. The FSP changes the indicators for determining whether an other-than-temporary impairment on a debt security should be recorded in earnings. Under the new accounting guidance, the primary indicators that an unrealized loss should be recognized in earnings are whether the Company intends to sell the debt security or whether it is more likely than not that it will be required to sell the debt security prior to recovery of its cost basis. For other-than-temporarily impaired debt securities that the Company intends to sell or is more likely than not going to be required to sell before recovery, unrealized losses must be recorded in earnings. The adoption did not have a material impact on the financial statements as the Company did not have unrealized losses as of June 30, 2009.

In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157”. This FSP delays the effective date of FASB Statement No. 157, “Fair Value Measurements”, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), including asset retirement obligations and goodwill and other impairment analyses. This guidance is effective for the Company for the fiscal year ended June 30, 2010. The Company is evaluating the impact of adoption of this FSP.

2. Fair Value Measurements

On July 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which establishes a framework for defining and measuring fair value and requires expanded disclosures about fair value measurements. The Company’s only items to which SFAS 157 applies are cash equivalents, securities available-for-sale and fixed maturity securities. Cash equivalents and securities available for sale are classified as Level 1 in the fair value hierarchy. These investments are traded in active markets and quoted prices are available for identical investments. Fixed maturity securities classified as Level 2 within the fair value hierarch include U.S. Treasury securities. The fair value of these instruments is estimated using pricing models which utilize inputs such as recent trades for the same or similar instrument, yield curves, discount margin and bond structures.

The following table presents the amounts of assets carried at fair value at June 30, 2009 by the level in which they are classified within the SFAS No. 157 valuation hierarchy:

 

     Fair Value Measurements at Reporting Date Using

Description

   Quoted Prices in Active
Markets for Identical Assets

Level 1
   Significant Other
Observable Inputs

Level 2

Cash Equivalents

   $ 21,394,200      —  

Securities available for sale

     903,924      —  

Marketable securities

     —      $ 999,775

 

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3. Oil and Gas Properties

MPC had the following amounts recorded in oil and gas properties at June 30, 2009 and 2008.

 

Location

   2009    2008

Mereenie and Palm Valley (Australia)

   $ 91,851,863    $ 109,124,145

Nockatunga (Australia)

     17,212,729      20,301,033

Cooper Basin (Australia) (1)

     4,849,588      5,604,219

Other (Australia) nondepletable exploration permits and licenses (2)

     549,109      548,945

Weald/Wessex Basin (U.K.) nondepletable exploration permits and licenses

     2,170,718      2,428,236

Weald/Wessex Basin (U.K.) capitalized exploratory drilling costs

     983,548      549,935
             
   $ 117,617,555    $ 138,556,513
             

 

(1) At June 30, 2009 and 2008, includes $1,552,838 and $1,855,186, respectively, of costs capitalized as exploratory well costs pending the start of production as well as $1,384,664 and $1,448,568, respectively, of nondepletable exploration permits and licenses.
(2) Maryborough Basin and Amadeus Basin in Australia.

Accumulated Depletion, Depreciation and Amortization

 

Location

   2009    2008

Mereenie and Palm Valley (Australia)

   $ 83,937,714    $ 94,218,078

Nockatunga (Australia)

     15,280,813      14,780,819

Cooper Basin (Australia)

     1,808,664      2,132,354
             
   $ 101,027,191    $ 111,131,251
             

Depletion, Depreciation and Amortization

During the years ended June 30, 2009, 2008 and 2007, the depletion rate by field was as follows:

 

     2009    2008    2007
     Percent

Mereenie and Palm Valley (Australia)

   63.8    45.3    35.5

Nockatunga (Australia)

   64.6    66.5    53.6

Cooper Basin (Australia)

   13.3    35.9    32.3

Exploratory and Dry Hole Costs

Exploration and dry hole costs relate to the exploration work performed on MPAL’s properties. Components of these costs are as follows:

 

     Year ended June 30

Exploration and Dry Hole Costs

   2009    2008    2007

Farmout, Field Monitoring and Technical Costs

   $ 1,807,129    $ 1,892,528    $ 2,662,014

Seismic Data and Acquisition Costs (1)

     1,367,312      98,168      140,900

Dry Hole Drilling (2)

     5,765      1,328,114      2,717,546

Write off expired permits – U.K.

     295,731      —        —  
                    

Total

   $ 3,475,937    $ 3,318,810    $ 5,520,460
                    

 

(1) Seismic data costs related to the Nockatunga fields in 2009, Cooper Basin and U.K. permits in 2008, and Nockatunga and U.K. permits in 2007.
(2) Dry hole costs related mostly to the Cooper Basin in 2008 and 2007.

 

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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, 2009.

Impairment Loss

A non-cash impairment loss of $63,740 was recorded in 2009 relating to the decreased value of U.K. exploration permits and licenses that were recognized under purchase accounting. 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.

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 under 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.

4. Asset Retirement Obligations

A reconciliation of the Company’s asset retirement obligations for the years ended June 30, 2009 and 2008, is as follows:

 

     2009     2008

Balance at beginning of year

   $ 11,596,084      $ 9,456,088

Liabilities incurred

     —          —  

Liabilities settled

     —          —  

Accretion expense

     531,405        716,130

Revisions to estimate (1)

     (625,962     43,482

Exchange effect

     (1,686,265     1,380,384
              

Balance at end of year

   $ 9,815,262      $ 11,596,084
              

 

(1) During the year ended June 30, 2009, changes in cost estimates and expected restoration dates resulted in decreases in total asset retirement obligations.

5. Capital and Stock Options

On May 27, 2009, shareholders approved an amendment to the 1998 Stock Incentive Plan (the “Plan”) which reserved for issuance an aggregate of 5,205,000 shares of the Company’s common stock in the form of non-qualified stock options, SARs, restricted share awards, annual awards of stock to non-employee directors and performance based awards.

The Plan provides for options to be issued with an exercise price of not less than fair value of the stock price on the date of the award and for a term of not greater than ten years. As of June 30, 2009, 1,787,500 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, 2009:

 

Options Outstanding

   Expiration
Dates
   Number of
Shares
  

Exercise Prices ($)

   Fair Value at
Grant Date

June 30, 2007

      430,000    (1.59 weighted average price)   

Awarded

   Feb. 2018    100,000     1.16    $ 63,141
             

June 30, 2008

      530,000    (1.51 weighted average price)   

Awarded

   Dec. 2018    2,712,500     1.20    $ 1,881,362
             

June 30, 2009

      3,242,500    (1.25 weighted average price)   
             

The weighted average remaining contractual term as of June 30, 2009 is 9 years.

Summary of Options Outstanding at June 30, 2009

 

     Expiration
Dates
   Total    Vested    Exercise
Prices ($)

Awarded fiscal year 2004

   Jul. 2014    30,000    30,000    1.45

Awarded fiscal year 2006

   Nov. 2015    400,000    400,000    1.60

Awarded fiscal year 2008

   Feb. 2018    100,000    100,000    1.16

Awarded fiscal year 2009

   Dec. 2018    2,712,500    —      1.20
               
      3,242,500    530,000   
               

All of the options have been issued with an exercise price equal to or greater than the fair value of the Company’s stock at the date of the award, which may differ from the grant date used for accounting purposes.

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, 2009, 2008 and 2007, the Company recorded stock-based compensation expense for the cost of stock options of $83,560, $63,141, and $7,425 both pre-tax and post-tax, which has no impact on basic or diluted earnings per share. The grant date fair values of the options granted on May 27, 2009 and February 18, 2008 were $1,881,362 and $63,141, respectively. These expenses have no effect on cash flow. As of June 30, 2009 and 2008, there was $1,797,802 and $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 for the time based options. Option valuation models require the input of certain assumptions including the expected stock price volatility. The assumptions used to value the Company’s time based grants were as follows:

 

     May 27, 2009     Feb. 18, 2008     Nov. 28, 2005     Jul. 1, 2004  

Risk free interest rate

     2.82     3.20     4.58     4.95

Expected life

     6 yrs        5 yrs        5 yrs        10 yrs   

Expected volatility (based on historical price)

     .650        .611        .627        .518   

Expected dividend

   $ 0      $ 0      $ 0      $ 0   

The expected life of the time based options granted on May 27, 2009 and February 18, 2008 was determined under the “simplified” method described in SEC Staff Accounting Bulletin No. 110.

The time based stock options vest in equal annual installments over the vesting period, which is also the requisite service period. Time based stock options are generally granted with a 3-year vesting period and a 10-year term. The 400,000 options granted to Directors on November 28, 2005 and 100,000 on February 18,

 

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2008 each vested immediately. Vesting criteria of performance based/market based options (“PBO”s) are determined by the Company’s compensation committee. PBOs issued during fiscal 2009 will vest in full upon attainment of either of the following investment goals; monetizing the uncontracted gas reserves held by MPAL at the Amadeus Basin field, or upon the closing price of the Company’s stock being at or above $1.50 per share for sixty consecutive trading days. All options vest in the event of change of control of the Company.

The Monte Carlo model was used to value the PBOs. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows:

 

     May 27, 2009  

Risk free interest rate

   3.71

Expected volatility (based on historical price)

   .70   

Expected dividend

   $     0   

Closing stock price as of May 27, 2009

   $1.23   

Term

   10 years   

Days until expiration (per annum)

   252 days   

Steps until expiration

   2,520   

Probability of performance criteria occurring over term of options:

  

Monetization of uncontracted reserves

   25% – 60

Change of control

   10% – 50

As of June 30, 2009 there were 1,837,500 nonvested option shares outstanding under the Plan with a weighted average fair value at date of award of $0.75 per share and 875,000 nonvested option shares in the Plan with a weighted average fair value at date of award of $0.57 per share.

6. Income Taxes

Components of income (loss) before income taxes by geographic area (in thousands) are as follows:

 

     Years Ended June 30,  
     2009     2008     2007  

United States

   $ (3,845   $ (2,119   $ (1,386

Foreign

     6,708        7,558        2,831   
                        

Total

   $ 2,863      $ 5,439      $ 1,445   
                        

 

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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,  
     2009     2008     2007  

Tax provision computed at statutory rate (30)%

   $ 859      $ 1,632      $ 434   

MPC (parent company) losses

     1,154        636        416   

Non-taxable Australian revenue

     (342     (443     (404

Increase in valuation reserve for foreign (UK) exploration expenditures

     382        271        374   

Australian Taxation Office settlement (a)

     —          12,085        —     

MPC capitalized facilitation costs

     268        —          —     

Rate differential on MPC book income

     (154     —          —     

MPC income tax provision (b)

     41        72        58   

Other

     (10     77        121   
                        

Consolidated income tax provision

   $ 2,198      $ 14,330      $ 999   
                        

Current income tax provision (foreign)

   $ 3,816      $ 18,872      $ 2,817   

Deferred income tax benefit (foreign)

     (1,618     (4,542     (1,818
                        

Consolidated income tax provision

   $ 2,198      $ 14,330      $ 999   
                        

Effective tax rate

     77     263     69
                        

 

(a) See discussion below under Australia.
(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.

Significant components of the Company’s deferred tax assets and liabilities (in thousands) were as follows:

 

     June 30,
2009
    June 30,
2008
 

Deferred tax liabilities

    

Stepped up basis of oil and gas properties

     (1,842     (2,508

Other

     (82     (8
                

Total deferred tax liabilities

     (1,924     (2,516
                

Deferred tax assets

    

Acquisition and development costs

     2,752        2,486   

Asset retirement obligations

     2,945        3,883   

Net operating losses

     3,562        4,079   

United Kingdom exploration costs

     1,274        1,031   

Stock options

     211        174   

Interest

     539        539   

Other

     575        —     
                

Total deferred tax assets

     11,858        12,192   
                

Valuation allowance

     (5,586     (5,815
                

Net deferred tax asset/(liabilities)

   $ 4,348      $ 3,861   
                

The Company records a valuation allowance for deferred tax assets when management believes it is more likely than not that such assets will not be recovered. The valuation allowance decreased to $5,586,000 in 2009 from $5,815,000 in 2008. The change in the valuation allowance is due to utilization of net operating losses in the US offset by an increase in the valuation allowance for the tax benefit of U.K. exploration costs

 

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United States

At June 30, 2009, the Company had approximately $9,078,000 and $9,609,000 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
Federal
   MPC
Federal
   MPC
State

Expires:

        

2010

   $ 1,669    $ —      $ —  

2011

     1,764      —        —  

2012

     2,856      —        —  

2013

     230      —        —  

2019

     96      —        —  

2021

     25      —        56

2022

     74      —        302

2023

     3      —        359

2024

     2      —        —  

2025

     1      —        1,058

2026

     —        287      1,341

2027

     —        —        1,462

2028

     —        2,071      2,057

2029

     —        —        2,974
                    

Total

   $ 6,720    $ 2,358    $ 9,609
                    

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, 2009, consists of a deferred tax asset of $2,752,000, primarily relating to acquisition and development costs and $2,945,000 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 the settlement reached with the ATO, the Company recorded taxes and interest in the amount of (US) $13,252,469 ($0.31 per share) as part of the income tax provision for the year ended June 30, 2008 which included (US) $2,725,110 of interest net of the tax benefit related to the interest deduction. No additional interest related to tax matters was recorded for the year ended June 30, 2009.

There are no uncertain tax positions for fiscal 2009.

7. Related Party and Other Transactions

Mr. Timothy L. Largay, a director of the Company through December 2008, is a partner of the law firm of Murtha Cullina, LLP, which firm was paid fees of $689,652, $264,170 and $114,415 by the Company in fiscal years 2009, 2008 and 2007, respectively. At June 30, 2009, 2008 and 2007, the Company’s payables included $50,812, $22,196 and $25,402, respectively, owed Murtha Cullina, LLP.

 

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8. Leases

At June 30, 2009, future minimum rental payments applicable to MPC’s and MPAL’s non-cancelable office operating leases were as follows:

 

Fiscal Year

   Future Minimum
Rental Payments

2010

   $ 263,000

2011

   $ 272,000

2012

   $ 286,000

Operating lease rental expenses for each of the years ended June 30, 2009, 2008 and 2007 were $415,760, $473,944 and $362,005 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 William H. Hastings (President and Chief Executive 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 they 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,  
     2009     2008     2007  

Revenues:

      

MPC

   $ 164      $ 233      $ 130   

MPAL

     28,027        40,662        30,545   
                        

Total consolidated revenues

   $ 28,191      $ 40,895      $ 30,675   
                        

Interest income:

      

MPC

   $ 24      $ 159      $ 259   

MPAL

     1,559        1,964        1,411   
                        

Total consolidated

   $ 1,583      $ 2,123      $ 1,670   
                        

Net (loss) income:

      

MPC

   $ (885   $ (2,177   $ 4,432   

MPAL, net of related costs

     4,550        (6,715     1,881   

Elimination of intersegment dividend

     (3,000     —          (5,866
                        

Consolidated net income (loss)

   $ 665      $ (8,892   $ 447   
                        

Assets:

      

MPC (1)

   $ 68,349      $ 65,555     

MPAL

     69,711        82,935     

Equity elimination

     (66,356     (63,195  
                  

Total consolidated assets

   $ 71,704      $ 85,295     
                  

Expenditures for additions to long-lived assets:

      

MPC

   $ —        $ —        $ —     

MPAL

     2,430        4,249        5,783   
                        

Total expenditures for additions to long-lived assets

   $ 2,430      $ 4,249      $ 5,783   
                        
     Years Ended June 30,  
     2009     2008     2007  

Other significant items:

      

Depletion, depreciation and amortization:

      

MPC

   $ 5      $ 6      $ 6   

MPAL

     6,781        18,015        10,687   
                        

Total consolidated

   $ 6,786      $ 18,021      $ 10,693   
                        

Production costs:

      

MPC

   $ —        $ —        $ —     

MPAL

     8,153        8,866        6,966   
                        

Total consolidated

   $ 8,153      $ 8,866      $ 6,966   
                        

Exploratory and dry hole costs:

      

MPC

   $ —        $ —        $ —     

MPAL

     3,476        3,319        5,520   
                        

Total consolidated

   $ 3,476      $ 3,319      $ 5,520   
                        

Income tax expense:

      

MPC

   $ 41      $ 58      $ 48   

MPAL

     2,157        14,272        951   
                        

Total consolidated

   $ 2,198      $ 14,330      $ 999   
                        

 

(1) Goodwill attributable to MPAL was $4,020,706 for 2009 and 2008, respectively.

 

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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,  
     2009     2008     2007  

Revenue:

      

Australia

   $ 28,027      $ 40,662      $ 30,545   

Canada

     164        233        130   
                        
   $ 28,191      $ 40,895      $ 30,675   
                        

Income (loss) before income taxes:

      

Australia

   $ 6,952      $ 7,257      $ 3,152   

New Zealand

     —          (42     (25

United Kingdom

     (1,272     (904     (1,162

United States and Canada

     164        233        161   
                        
     5,844        6,544        2,126   

Corporate overhead and interest, net of other income (expense)

     (2,981     (1,105     (681
                        

Consolidated income before income taxes

   $ 2,863      $ 5,439      $ 1,445   
                        
     Years Ended June 30,  
     2009     2008     2007  

Net income (loss):

      

Australia

   $ 5,822      $ (5,767   $ 3,074   

New Zealand

     —          (44     (32

United Kingdom

     (1,272     (904     (1,162

United States

     (3,885     (2,177     (1,433
                        
   $ 665      $ (8,892   $ 447   
                        

Identifiable assets:

      

Australia

   $ 69,711      $ 82,935     

Corporate assets

     1,993        2,360     
                  
   $ 71,704      $ 85,295     
                  

Substantially all of MPAL’s gas sales were to the Power and Water Corporation of the Northern Territory of Australia. Oil sales during 2009 were 40% to the Santos group of companies, 13% to Beach Petroleum, 8% to Origin Energy Resources and 39% 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, 2009, in thousands:

 

     Payments Due by Period

Contractual Obligations

   Total    Less Than
1 Year
   1-3 Years    3-5 Years    More Than
5 Years

Operating Lease Obligations

   $ 821    $ 263    $ 558    $ —      $ —  

Purchase Obligations (1)

     6,469      6,469      —        —        —  

Asset Retirement Obligations-Undiscounted (2)

     14,470      202      2,446      8,397      3,425
                                  

Total

   $ 21,760    $ 6,934    $ 3,004    $ 8,397    $ 3,425
                                  

 

(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 which are not legally binding have been excluded from the table above.
(2) During the year ended June 30, 2009, the Company decreased total asset retirement obligations by $626,000 due to changes in cost estimates and expected restoration dates (see Note 4 to the Financial Statements).

Gas Supply Contracts

In 1983, the MPAL and Santos (“Palm Valley Producers”) commenced the sale of gas to Alice Springs under a 1981 agreement. That agreement terminated in June 2008. In 1985, the Palm Valley Producers and Mereenie Producers (MPAL and Santos) signed agreements for the sale of gas to PWC, through its wholly-owned company Gasgo Pty. Ltd. (“Gasgo”), 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 expired in January and June 2009. Supply obligations under the Mereenie contracts ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010.

At June 30, 2009, MPAL’s commitment to supply gas under the above agreements was as follows:

 

Period

   Bcf

Less than one year

   2.22

Between 1-5 years

   1.77

Greater than 5 years

   0.00
    

Total

   3.99
    

12. Restatement of Financial Information

Subsequent to the issuance of our 2008 annual report on Form 10-K we determined that in our consolidated statement of cash flows for the year ended June 30, 2007, we inappropriately added back to cash flows from operating activities $3.2 million of accounts payable related to property and equipment additions. This increase in accounts payable should have been reflected as a reduction of cash outflows from investing activities rather than an increase in cash flows from operating activities. This error also affected our consolidated statement of

 

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cash flows for the year ended June 30, 2008 as these amounts should have increased cash flows from operating activities through the adjustment for the change in accounts payable and should have been reflected as an increase to reported cash outflows for additions to property and equipment in the investing activities section for that year. The statement of cash flows for the years ended June 30, 2008 and 2007 as contained herein have been adjusted for the restatement discussed above. This restatement has no impact on the change in cash and cash equivalents, the balance sheet or the statement of operations.

Additionally, we also determined that the amounts we have previously reported in our consolidated statements of cash flows as investing outflows for exploration and dry hole costs have included certain engineering and other costs that do not result in the acquisition of an asset and should, therefore, be classified as operating cash outflows rather than investing outflows. The amounts of exploration and dry hole costs inappropriately included as investing outflows in previously issued consolidated statements of cash flows were: $1.9 million and $2.1 million for the years ended June 30, 2008 and 2007, respectively as contained herein. The statement of cash flows for the years ended June 30, 2008 and 2007 as contained herein have been adjusted for the restatement discussed above. This restatement has no impact on the change in cash and cash equivalents, the balance sheet or the statement of operations.

The following is a summary of the restatement on the originally issued Consolidated Statement of Cash Flows for the years ended June 30, 2009 and 2008:

CONSOLIDATED STATEMENT OF CASH FLOWS

 

     June 30, 2008  
     As Previously
Reported
    Adjustments     As Restated  

Adjustments to reconcile net loss to net cash provided by operating activities: Exploration and dry hole costs

   $ 3,227,200      $ (1,899,086   $ 1,328,114   

Changes in operating assets and liabilities:

      

Accounts payable and accrued liabilities

     (3,112,940     3,183,420        70,480   

Net cash provided by operating activities

     4,211,265        1,284,334        5,495,599   

Additions to property and equipment

     (1,628,476     (2,620,739     (4,249,215

Oil and gas exploration activities

     (3,227,200     1,336,405        (1,890,795

Net cash used in investing activities

     (2,150,396     (1,284,334     (3,434,730

 

     June 30, 2007  
     As Previously
Reported
    Adjustments     As Restated  

Adjustments to reconcile net loss to net cash provided by operating activities: Exploration and dry hole costs

   $ 4,871,865      $ (2,154,319   $ 2,717,546   

Changes in operating assets and liabilities:

      

Accounts payable and accrued liabilities

     2,474,106        (3,183,420     (709,314

Net cash provided by operating activities

     21,273,813        (5,337,739     15,936,074   

Additions to property and equipment

     (9,231,029     3,447,912        (5,783,117

Oil and gas exploration activities

     (4,871,865     1,889,827        (2,982,038

Net cash used in investing activities

     (18,019,572     5,337,739        (12,681,833

Accounts payable related to property and equipment

     1,417,051        1,778,582        3,195,633   

 

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13. Selected Quarterly Financial Data (Unaudited)

The following is a summary (in thousands, except for per share amounts) of the quarterly results of operations for the years ended June 30, 2009 and 2008:

 

     September 30,
2008
3 Months
    December 31,
2008
3 Months
    March 31,
2009
3 Months
    June 30,
2009
3 Months
 

2009

        

Total revenues

   $ 10,439      $ 5,172      $ 5,523      $ 7,057   

Costs and expenses

     (7,959     (5,436     (6,489     (7,027

Interest income

     628        460        274        221   

Income tax (provision) benefit

     (1,600     (721     1,083        (960
                                

Net income (loss)

   $ 1,508      $ (525   $ 391      $ (709
                                

Per share (basic & diluted)

   $ 0.04      $ (0.01   $ 0.01      $ (0.02
                                

Average number of shares outstanding

     41,500        41,500        41,500        41,500   
                                

 

     September 30,
2007
3 Months
    December 31,
2007
3 Months
    March 31,
2008
3 Months
    June 30,
2008
3 Months
 

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)

   $ (0.01   $ (0.26   $ 0.02      $ 0.03   
                                

Average number of shares outstanding

     41,500        41,500        41,500        41,500