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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, 2011

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.)

7 Custom House Street, 3rd Floor, Portland ME   04101
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code

(207) 619-8500

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 þ    Non-accelerated filer ¨    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 $2.87 closing price on December 31, 2010 (the last business day of the most recently completed second quarter) was $120,355,442.

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, 52,552,852 shares outstanding as of September 1, 2011

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2011 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, 2   

Business and Properties

     3   
  

General Overview

     3   
  

Oil and Gas Properties and Activities

     4   
  

Reserves

     11   
  

Production Volumes, Prices, and Production Costs

     13   
  

Productive Wells

     14   
  

Acreage

     14   
  

Drilling Activity

     14   
  

Marketing Activities and Customers

     15   
  

Current Market Conditions and Competition

     15   
  

Segment Information

     16   
  

Employees

     16   
  

Regulatory Matters, Environmental and Additional Factors Affecting Business

     16   
  

Available Information

     17   
Item 1A.   

Risk Factors

     17   
Item 1B.   

Unresolved Staff Comments

     26   
Item 3.   

Legal Proceedings

     26   
Item 4.   

Removed and Reserved

     26   
   PART II   
Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      26   
Item 6.   

Selected Financial Data

     29   
Item 7.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     30   
Item 7A.   

Quantitative and Qualitative Disclosures about Market Risk

     47   
Item 8.   

Financial Statements and Supplementary Data

     49   
Item 9.   

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     96   
Item 9A.   

Controls and Procedures

     96   
Item 9B.   

Other Information

     98   
   PART III   
Item 10.   

Directors, Executive Officers and Corporate Governance

     100   
Item 11.   

Executive Compensation

     100   
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      100   
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

     100   
Item 14.   

Principal Accounting Fees and Services

     100   
   PART IV   
Item 15.   

Exhibits, Financial Statement Schedules

     101   

Unless otherwise indicated, all dollar figures set forth herein are in United States currency. Amounts expressed in Australian currency are indicated as (“AUD”, “AUS”, “A$”). The exchange rate at September 1, 2011 was approximately (AUD) $1.00 which equaled U.S. $1.07.


Table of Contents

PART I

Items 1 and 2: Business and Properties.

GENERAL OVERVIEW

Magellan Petroleum Corporation (the “Company” or “Magellan” or “MPC” or “we” or “us”) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. MPC was incorporated in 1957 under the laws of Panama and was reorganized under the laws of Delaware in 1967. At June 30, 2011, MPC has three reporting segments: (1) our 100.00% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”); (2) an 83.5% controlling member interest in Nautilus Poplar, LLC (“Nautilus”), based in Denver, Colorado and (3) MPC the parent company that owns directly a 28.3% working interest in the East Poplar Unit and Northwest Poplar Field (collectively, the “Poplar Field”) in Montana.

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), one retention license for the Dingo Field (34.3% working interest) and thirteen licenses in the United Kingdom, four of which are operated by MPAL. The Mereenie, Palm Valley, and Dingo fields are located in the Amadeus Basin in the Northern Territory of 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 65.7% interest in the Dingo field and is the operator of the Mereenie and Dingo fields. MPAL is operator of the Palm Valley field.

On December 4, 2009, the Company announced the sale of all its interests in the Cooper and Maryborough Basins in Australia. The Company subsequently entered into sales agreements to affect the sale of those interests including for the sale of its Authority to Prospect (“ATP”) 613P, ATPA 674P, ATP 732P and ATPA 733P interests which we completed during the year end June 30, 2011. These assets were disposed of because they are non-core to our strategies. See Note 10 for further discussion.

MPC acquired its 83.5% controlling interest in Nautilus in October 2009. Nautilus, based in Denver, Colorado, operates and holds a 68.75% interest in the East Poplar Unit and varied interests averaging 57% in the Northwest Poplar Field. MPC owns directly a 28.3% working interest in the Poplar Field. The Poplar Field is comprised of 23,000 combined licensed acres and has an estimated 700 to 800 million barrels of oil in place in the Charles Formation with 52 million barrels recovered to date. The Poplar Field is also being developed for Bakken shale as well as other shallow and deep oil and gas reservoirs. On a consolidated basis, MPC through Nautilus and directly owned an average 85.7% working interest in the Poplar Fields in Montana as of June 30, 2011. See Note 13 for further discussion.

MPC ORGANIZATION CHARTS

As of June 30, 2011:

LOGO

 

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OIL AND GAS PROPERTIES AND ACTIVITIES

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

LOGO

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. At June 30, 2011, MPAL’s share of the Mereenie field proved developed oil reserves was zero. Under the revised rules of the U.S. Securities and Exchange Commission (“SEC”), proved reserves of natural gas cannot be booked for Mereenie until a natural gas sales agreement is completed. Probable developed oil and gas reserves have been booked at Mereenie.

During fiscal 2011, MPAL’s share of oil and condensate sales was approximately 64 MBbls, which is subject to net overriding royalties aggregating 4.06% and the statutory government royalty of 10%.

Prior to June 2009, the oil was transported by means of a 167-mile eight-inch crude oil pipeline flowing eastbound from the field to Brewer Estate, southwest of Alice Springs. The oil was then shipped south approximately 950 miles by road to the Port Bonython Export Terminal at Whyalla, South Australia for sale. Beginning with June 2009, service on the pipeline was suspended and the line was idled pending future evaluation. Oil production began direct road transport from the field to the Port Bonython Export Terminal. The cost of transporting the oil to the terminal is borne by the Mereenie Producers. The petroleum leases covering the Mereenie field expire in November 2023.

The Mereenie Producers were contracted until September 5, 2010 to supply gas on a reasonable endeavors basis to the Power and Water Corporation (“PWC”) for use in the Northern Territory. After September 5, 2010, natural gas volumes continued to be produced, were processed for condensate and then cycled back for reinjection into the field. See “Gas Supply Contracts” below.

 

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On September 14, 2011, Magellan Petroleum (N.T.) Pty Ltd (“Magellan NT”), a wholly owned subsidiary of MPAL, entered into a Sale Agreement (“Santos SA”) with Santos QNT Pty Ltd (“Santos QNT”) and Santos Limited (“Santos Entities”). The Santos SA provides for the transfer of Magellan NT’s 35% interest in the Mereenie oil and gas field to the Santos Entities and the transfer of the Santos entities 47.977% interest in the Palm Valley gas field and the 65.6635% interest in the Dingo gas field to Magellan NT subject to the satisfaction of certain conditions.

The cash consideration payable to Magellan NT is A$25 million plus a bonus amount based on Mereenie future production levels.

Upon completion of the Santos SA, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”) with the Santos Entities on September 14, 2011, and provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65PJ over the anticipated 17 year term of the GSPA.

Palm Valley Gas Field

As of June 30, 2011, 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. MPAL and Santos (“Palm Valley Producers”) provide Palm Valley gas to meet a supply contract with PWC. See “Gas Supply Contracts” below. Pursuant to the same SEC rules noted for Mereenie above, basing proved developed bookings on gas sales agreement volumes, MPAL’s share of the Palm Valley proved developed reserves was .43 Bcf at June 30, 2011 and is based upon gas contract amounts. During fiscal 2011, MPAL’s share of gas sales was .86 Bcf which is subject to a 10% statutory government royalty and net overriding royalties aggregating 7.31%. Under the current gas sales agreement, 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.

Magellan NT has entered into the Santos SA to receive all of the Santos Entities’ interest in the Palm Valley and Dingo fields with effect July 1, 2011, as described above. Upon completion of the Santos Agreement MPAL will own 100% of the Palm Valley and Dingo gas fields and will have 25.65PJ of gas contracted under the GSPA with the Santos Entities. (See Note 20)

Dingo Gas Field

MPAL has a 34.34% interest in the Dingo gas field which is held under Retention License No. 2 in the Amadeus Basin in the Northern Territory. No market has emerged for 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 4.81%. The license was renewed for a further five year term and expires in February 2014.

Magellan NT has entered into the Santos SA to receive all of the Santos Entities’ interest in the Palm Valley and Dingo fields with effect July 1, 2011, as described above. Upon completion of the Santos Agreement MPAL will own 100% of the Palm Valley and Dingo gas fields and will have 25.65PJ of gas contracted under the GSPA with the Santos Entities. (See Note 20)

Gas Supply Contracts

In 1983, the 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 gas contract was adjusted quarterly to reflect changes in the Australian Consumer Price Index. The gas was delivered into the 922-mile Amadeus Basin gas pipeline which was built by an Australian consortium in 1987. Since 1985, there were several additional contracts for the sale of Mereenie gas, the latest being the Mereenie Sales Agreement No. 4 in June 2006 for the supply of an additional

 

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4.4 Bcf of gas to be supplied prior to December 31, 2008. The principal Mereenie contracts and supply obligations under the various agreements expired in January and June 2009, and September 2010. The Palm Valley gas contract expires in January 2012.

MPAL’s major customer, PWC, contracted with Eni Australia in 2006 for the supply of PWC’s Northern Territory gas demand requirement for twenty-five years, commencing January 2009. Eni Australia expected to commence sales from its Blacktip field offshore of the Northern Territory in January 2009; however, the Blacktip development encountered significant delays and only commenced partial production in September 2009 with full production not achieved until February 2010. The Mereenie Producers continued to supply PWC’s gas requirements on a reasonable endeavors basis to supplement Blacktip gas sales until early February 2010.

Upon completion of the Santos SA, as described above, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”) with the Santos Entities on September 14, 2011, and provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65PJ over the 17 year term of the GSPA.

The term of the GSPA shall commence on the later of Completion under the Sale Agreement, the first delivery of gas under a Concession GSPA or January 16, 2012 (when the existing gas sales agreement for the Palm Valley Gas Field expires) and will expire if the total contract quantity is reached before the expiry of 17 years.

As MPAL was not able to sell its uncontracted gas reserves for the fiscal year 2011, its revenues have declined in 2011. Palm Valley gas sales were approximately $1.8 million (net of royalties) or 100% of total gas sales for the year ended June 30, 2011, $2.1 million (net of royalties) or 15% of total gas sales for the year ended June 30, 2010, and $2.2 million (net of royalties) or 15% of total gas sales for the year ended June 30, 2009. There were no gas sales from Mereenie for the year ended June 30, 2011. There were $11.6 million of gas sales from Mereenie (net of royalties) or 85% of total sales for the year ended June 30, 2010, and $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009.

At June 30, 2011, MPAL’s commitment to supply gas under the Palm Valley contract was as follows:

 

Period

   Bcf  

Less than one year

     0.43   
  

 

 

 

Total

     0.43   
  

 

 

 

Evans Shoal Gas Field

Evans Shoal is a large, yet to be developed natural gas field with an estimated contingent gas resource in excess of 6.6 Tcf, including CO2 gas content, in the Bonaparte Basin, offshore Northern Australia. The field was discovered in 1988 and lies in a range of water depths from very shallow to more than 300 feet.

MPAL entered into an agreement with Santos on March 25, 2010 (“Asset Sales Deed”), to purchase Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48) (“Evans Shoal Transaction”). Under the Asset Sales Deed, the Company agreed to pay Santos a time-staged cash consideration equal to (AUD) $100 million for its interest in the Evans Shoal field which included a (AUD) $15 million deposit. The Company also agreed to pay additional contingent payments to Santos of (AUD) $50 million upon a favorable partner vote on any final investment decision to develop the Evans Shoal field and a further (AUD) $50 million upon first stabilized gas production from the field. Closing and completion of the purchase was subject to regulatory and other approvals. The Australian Foreign Investment Review Board indicated it had ‘no objection’ to the acquisition of Santos’ interest by MPAL.

The Asset Sales Deed was amended by the January 31, 2011 Deed of Variation (“Amended Asset Sales Deed”) which extended the closing date of the Evans Shoal Transaction through to May 31, 2011 in exchange for (1) MPAL’s release to Santos of the initial (AUD) $15 million escrow deposit payment made towards the closing

 

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price (“First Escrow Amount”) and (2) an additional (AUD) $10 million escrow account deposit towards the closing price (“Second Escrow Amount”). While the Amended Asset Sales Deed provided that the payment of the Second Escrow Amount would be made in accordance with the terms of the Amended Asset Sales Deed which provided certain defined circumstances under which MPAL was entitled to reimbursement of the deposit, the Amended Asset Sales Deed re-classified the First Escrow Amount as non-refundable.

On July 21, 2011, Santos and MPAL executed a Release Agreement to (1) terminate the Amended Asset Sales Deed and (2) resolve all outstanding issues relating to the Amended Asset Sales Deed. Under the Release Agreement, MPAL received back the Second Escrow Deposit, plus all interest accrued on that deposit from the date of deposit to the date of release and the parties agreed to mutually release each other from all claims arising out of the Asset Sales Deed and the Evans Shoal Transaction. As a result, the A$15 million deposit was written off.

In connection with the unwinding of the Evans Shoal Transaction, the Company and Santos executed agreements to transfer their interests in the Amadeus licenses with a resulting ownership interest by the Company of 100% of the Palm Valley and Dingo gas fields. (See Note 20)

LICENSES AND PERMITS

MPAL has interests directly and indirectly in the following permits. Permit holders are generally required to carry out agreed work and expenditure programs. (See Note 16)

 

Permit

   Ownership
Interest
  Expiration Date    Location

Petroleum Lease No. 4 and No. 5 (Mereenie) (Amadeus Basin)

   35%   November 17, 2023    Northern Territory, Australia

Petroleum Lease No. 3 (Palm Valley) (Amadeus Basin)

   52.023%   November 7, 2024    Northern Territory, Australia

Retention License No. 2 (Dingo) (Amadeus Basin)

   34.3365%   February 16, 2014    Northern Territory, Australia

NT/P82 (Bonaparte Basin)

   100%   May 12, 2016    Offshore Northern Territory, Australia

PEDL 125 (Weald Basin)

   40%   June 30, 2012    United Kingdom

PEDL 126 (Weald Basin)

   40%   June 30, 2014    United Kingdom

PEDL 135 (Weald Basin)

   100%   September 30, 2012    United Kingdom

PEDL 137 (Weald Basin)

   100%   September 30, 2012    United Kingdom

PEDL 155 (Weald Basin)

   40%   September 30, 2015    United Kingdom

PEDL 231 (Weald Basin)

   50%   June 30, 2014    United Kingdom

PEDL 232 (Weald Basin)

   50%   June 30, 2014    United Kingdom

PEDL 234 (Weald Basin)

   50%   June 30, 2014    United Kingdom

PEDL 240 (Wessex Basins)

   23%   June 30, 2014    United Kingdom

PEDL 242 (Weald Basin)

   100%   June 30, 2014    United Kingdom

PEDL 243 (Weald Basin)

   50%   June 30, 2014    United Kingdom

PEDL 246 (Weald Basin)

   100%   June 30, 2014    United Kingdom

PEDL 256 (Weald Basin)

   40%   April 30, 2015    United Kingdom

Petroleum permits issued by the Northern Territory of Australia are subject to the Petroleum (Prospecting and Mining) Act and the Petroleum Act of the Northern Territory. Lessees have the exclusive right to produce petroleum from the land subject to payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Rental payments may be offset against the royalty paid. The term of a lease is 21 years, and leases may be renewed for successive terms of 21 years each.

Petroleum 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.

 

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Bonaparte Basin

The Commonwealth – Northern Territory Offshore Petroleum Joint Authority granted Exploration Permit for Petroleum NT/P82 to the Company (100% interest) over Area NT09-1. Area NT09-1 was offered for competitive bid under the Australian Government 2009 Release of Offshore Petroleum Exploration Areas. The exploration permit was granted on May 13, 2010 for a six year term. The committed work program under the permit during the first three years of the term involves the reprocessing of existing seismic data, the acquisition of additional 2D and 3D seismic data and the interpretation of the combined seismic database. NT/P82 lies to the south and southeast of the Evans Shoal gas field within the Bonaparte Basin.

Magellan undertook the reprocessing of 2,061 miles of existing 2D seismic data during the first year of the permit and planning has commenced to undertake the acquisition of 62 miles of 2D and 46 square miles of 3D seismic data during the second permit year. Acquisition of the seismic surveys is planned for the first quarter of 2012. At June 30, 2011, MPAL’s share of the work obligations committed for the NT/P82 permit was $1,798,000.

Maryborough Basin

MPAL held 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. The Company was granted the previously excluded areas of ATP 613P in September 2010 and is waiting on the grant of ATP 674P and ATP 733P by the Queensland Government.

In May 2006, MPAL entered into a farm-out agreement in relation to ATP 613P, ATPA 674P and ATPA 733P with Eureka Petroleum, under which that company funded the drilling of two coal seam gas exploration wells in 2007 which intersected multiple thin coal seams. Eureka Petroleum has agreed to undertake a staged evaluation of the area to earn a 75% interest in any petroleum lease granted. MPAL retained a 25% interest and is carried by Eureka Petroleum through any development to the grant of a petroleum lease.

On January 16, 2010, the Company entered into an asset sale agreement with Adelaide Energy to sell all of its ownership interests in the three petroleum exploration permits ATP 613P, ATP 733P and ATP 674P. The transaction with Adelaide Energy closed on November 30, 2010 following the grant of the ATP 613P excluded areas. ATP 674P and ATP 733P will be transferred to Adelaide Energy following their grant.

UNITED KINGDOM

PEDL 125 & PEDL 126 (Markwells-1)

Effective July 1, 2003, MPAL acquired two Petroleum Exploration and Development Licenses (“PEDL”), PEDL 125 (40%) in Hampshire and PEDL 126 (40%) in West Sussex, in the Weald Basin of southern England; each granted for an initial exploration term of six years. The terms of both PEDL’s were extended by the Government; PEDL 126 will expire in June 2015 and PEDL 125 in June 2012. A PEDL will be extended past the end of its 11-year exploration term for a further 20-year production term if a development plan for production is approved by the Government.

The South Downs National Park was established by the Government in April 2011 over a 636 square mile area in southern England including parts of PEDL 125 and PEDL 126. Any petroleum development with the South Downs Nation Park must comply with the park’s Planning Policy. The Department of Energy supports the exploration and production of onshore oil and gas in line with its stated aim to maximize the economic recovery of UK’s oil and gas reserves, taking full account of environmental, social and economic objectives.

The Company participated in the Markwells Wood-1 exploration well in PEDL 126, which spudded in November 2010. Northern Petroleum is operator of the PEDL 126 joint venture. Markwells Wood-1 well

 

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targeted the eastward extension of the Horndean oil field which is currently producing from the Great Oolite Formation. Assessment of the well logs confirmed that the entire Great Oolite reservoir sequence in Markwells Wood-1 is oil-bearing above the Horndean field oil-water contact of 4,446 ft sub-sea level.

The presence of mobile (‘live’) oil was observed in 30 feet of core in the upper section of the Great Oolite. Analysis of the logs indicate the well, which was deviated at an inclination of approximately 56 degrees through the Great Oolite, penetrated a gross hydrocarbon bearing interval of 275 ft with a calculated net reservoir of 192 ft with an average porosity of 13-14%; a typical porosity value for this reservoir in the nearby fields in the same formation. Northern Petroleum started operations for an extended well test of the Markwells Wood oil discovery in West Sussex, with the arrival of a workover rig on September 6, 2011. The test will enable the joint venture partners to evaluate the potential and scheme for future development of the Markwells Wood oil accumulation.

At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL 125 and PEDL 126 licenses totaled $1,805,000.

PEDL 153, PEDL 154, PEDL 155 & PEDL 256

Effective October 1, 2004, MPAL acquired three licenses, PEDL 153 (33.3%), PEDL 154 (50%) and PEDL 155 (40%), in the Weald-Wessex Basins in southern England, each granted for an initial exploration term of six years. Each license has a drill or drop obligation at the end of its initial exploration term. The drilling plans for the Havant-1 well in PEDL 155 are under consideration. The initial exploration term of PEDL 155 was extended for a further four years and will expire on September 30, 2015. PEDL 153 and PEDL 154 terminated on September 30, 2010. The U.K. Company, Egdon Resources, will fund part of MPAL’s share of the PEDL 155 drilling and exploration costs to acquire a 10% interest in the license.

During fiscal year 2001, MPAL acquired an interest in exploration license PEDL 099 of the Portsdown area of Hampshire in southern England in the Weald Basin. The license (MPAL 40%) 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 venture partners for a period of six years with effect from May 2009 with a drill or drop obligation at the end of the initial exploration term. PEDL 256 expires in April 2015.

At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL 155 & PEDL 256 licenses was $1,429,000.

PEDL 231, PEDL 232, PEDL 234 & PEDL 243

Effective July 1, 2008, MPAL (50%) and its joint venture partner, Celtique Energie, were granted interests in PEDL 231, PEDL 232, PEDL 234 and PEDL 243 located in the central Weald Basin of southern England. Each license has a drill or drop obligation at the end of its initial exploration term and expires in June 2014. Celtique Energie, operator of the four joint ventures, will acquire 109 miles of 2D seismic data in PEDL 231, PEDL 234 and PEDL 243 during the fall of 2011 to more closely define drilling prospects identified from the existing seismic data, which will fulfill the firm work obligations under the licenses. At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL 231, PEDL 232, PEDL 234 & PEDL 243 licenses was $1,456,000.

PEDL 135, PEDL 137, PEDL 242 & PEDL 246

Effective October 1, 2004, MPAL was granted 100% interest in PEDL 135, and PEDL 137 in the Weald Basin in southern England for a term of six years. Effective July 1, 2008, MPAL was granted 100% interest in PEDL 242 and PEDL 246 located adjacent to the other licenses; each with a six year initial term. The initial exploration term of each of PEDL 135 and PEDL 137 has been extended to September 30, 2012. PEDL 136

 

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expired on September 30, 2010. Each license has a drill or drop obligation at the end of its initial term. MPAL has undertaken a program of seismic data purchase, reprocessing and interpretation and has identified three drilling prospects. At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL 135, PEDL 137, PEDL 242 and PEDL 246 licenses was $149,000.

PEDL 098 & PEDL 240

During fiscal year 2001, MPAL acquired an interest in an exploration license in southern England in the Weald-Wessex Basins. The license, PEDL 098 (22.5%), on the Isle of Wight was granted for a term of six years. The Sandhills-2 well, drilled in PEDL 098 during 2005, encountered a heavily biodegraded remnant oil column and was plugged and abandoned. PEDL 098 was surrendered in May 2011 towards the end of its 11-year term. Effective July 1, 2008, MPAL and its joint venture partners were granted PEDL 240 (22.5%) adjacent to PEDL 098 for an initial exploration term of six years. The license has a drill or drop obligation at the end of its initial exploration term. An exploration well has to be drilled within the first six years of the initial term in order for the license to be extended into the next five-year license term, as was the case for PEDL 098. At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL was $38,000.

UNITED STATES

East Poplar Unit and Northwest Poplar Oil Fields

On October 15, 2009, MPC completed the purchase of an 83.5% controlling interest in Nautilus. Nautilus, based in Denver, Colorado, owns a majority interest in and operates the Poplar Field in Roosevelt County, Montana. The controlling interest in Nautilus was purchased from White Bear, LLC and ECP Fund, SICAV-FIS (formerly, YEP I, SICAV- FIS) entities affiliated with Nikolay Bogachev and J. Thomas Wilson, two directors of the Company.

MPC also completed a consolidation of interests in the Poplar Field by purchasing a 25.05% average working interest from Hunter Energy, LLC and a 3.25% average working interest from Nautilus Technical Group, LLC in March 2010. On a consolidated basis, MPC, through Nautilus and directly, owned an average 85.7% working interest in the Poplar Fields in Montana as of June 30, 2011.

The Poplar Field was discovered and developed in 1954 by Murphy Oil Company. The Field, with 23,000 combined licensed acres, has an estimated 700-800 million barrels of original oil in-place with 52 million barrels recovered to-date (largely from just the Charles formation) or approximately 7% of in-place reserves. Typical recovery factors in other fields with like characteristics are 20% to 30%. Magellan (through Nautilus) has embarked on an active development program utilizing both infill and tertiary enhanced oil recovery programs shown to be successful and productive in adjacent, similar fields in both the U.S. and in nearby Canada. Although certain contingencies must materialize, attractive upside potential is seen in the three producing oil horizons in the Mississippian Charles formation, up to 23,000 acres of Bakken shale, and both shallow and deep gas plays.

For the year end June 30, 2011, the Poplar Field produced approximately 86 MBbls with approximately 35 active wells producing from the Charles Formation. During June 30, 2011, MPC’s share of oil sales was approximately 68 MBbls, which is net of royalties and overriding royalties averaging 21%. At June 30, 2011, MPC’s share of the Poplar Field proved oil reserves was approximately 9,190 MBbls.

The oil is transported by truck to a lease automatic custody transfer (“LACT”) facility in Reserve, MT where it enters the Enbridge Oil Pipeline to Clearbrook, MN. The East Poplar Unit and Northwest Poplar Field leases are held by production.

On September 2, 2011, the Company signed and closed a Purchase and Sale Agreement with the owners of Nautilus Technical Group LLC, (“Nautilus Technical”), and Eastern Rider LLC, (“Eastern Rider”), (collectively

 

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the “Sellers”), resulting in the Company owning 100% of Nautilus Poplar and, directly or indirectly through Nautilus, a 100% working interest in the Poplar Field, aside from certain working interest owners in the Northwest Poplar fields. (See Note 20)

On September 7, 2011 the Company and VAALCO Energy (USA) Inc. (“VAALCO”) signed a definitive Lease Purchase and Sale Agreement (the “VAALCO LPSA”). VAALCO also agreed to drill three wells, at its sole expense as operator, to the Bakken formation and to formations below the Bakken (the “Deep Intervals”) in Poplar Field. Upon completion of three (3) new wells in the Deep Intervals of the Poplar Field, VAALCO will earn a 65% working interest in the Deep Intervals within the Poplar Field. One well will be spud on or before June 1, 2012 and the second and third will be spud on or before December 31, 2012. One well will be drilled horizontally to test the Bakken Formation, one well will be drilled vertically to test the Red River Formation, and a third will be targeted at VAALCO’s discretion.

The Company will retain a 35% working interest in the Deep Intervals and will continue to hold its current interest in all formations above the Bakken formation, including the currently producing Charles and Tyler formations where all Poplar proved and probable reserves are located.

The Company has initiated a program in late summer 2011 to undertake seven recompletions along with the completion of the East Poplar Unit (“EPU”) 119 drilled last fall into the Charles Formation. Magellan also plans to drill one shallow natural gas well in fall of 2011 to evaluate significant reservoir pressure differentials seen in the shallow gas horizon during the drilling of the EPU119 well.

A second drilling program, including up to three new infill wells in the Charles Formation, is planned for the fall of 2011. Drilling will be based upon the results from the recompletion program with the objective of increased production resulting in increased cash generation amid high oil price netbacks.

Given the complexity of the Poplar reservoir, the Company has completed the first steps of a reservoir engineering study for the Charles Formation. Further work is being conducted to manage and monitor water influx, determine new high potential drilling sites, and to determine the merit of an infill program.

RESERVES

Detailed information regarding reserves, costs of oil and gas activities, capitalized costs, discounted future net cash flows and results of operations is disclosed in Note 19.

A summary of our estimated proved, probable and possible reserves as of June 30, 2011 are set forth in the table below. The table shows reserves on an Mboe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio.

Summary of Oil and Gas Reserves as of June 30, 2011 Fiscal Year End

Based on Average Fiscal-Year Prices

 

                                                      All other
Foreign
Geographic
 
     Total      Australia      United States      areas  

Proved Reserves:

   Oil
(MBbls)
     Gas
(Bcf)
     Mboe      Oil
(MBbls)
     Gas
(Bcf)
     Oil
(MBbls)
     Gas
(Bcf)
     Oil
(MBbls)
     Gas
(Bcf)
 

Proved Developed Producing (PDP)

     1,127         0.43         1,199         —           0.43         1,127         —           —           —     

Proved Developed Not Producing (PDNP)

     1,122         —           1,122         —           —           1,122         —           —           —     

Proved Undeveloped (PUD)

     6,941         —           6,941         —           —           6,941         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     9,190         0.43         9,262         —           0.43         9,190         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Probable undeveloped

     1,824         —           1,824         —           —           1,824         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total reserves

     11,014         0.43         11,086         —           0.43         11,014         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Information regarding changes in estimated reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 19.

Proved Undeveloped Reserves

MPC first recorded these Proved Undeveloped reserves related to the Poplar Field at June 30, 2010.

In the United States, Magellan commenced a drilling and development program in the Poplar Field with the EPU 119 that reached a depth of 7,137 feet on October 18, 2010. Well results to-date, while under further evaluation, yielded a broad stack of hydrocarbon-bearing formations from 692 feet all the way to total vertical depth of 7,137 feet. A Charles Formation core (the current producing formation) was completed and is currently under analysis. A Bakken and Three Forks core was also successfully obtained and analyzed, where it was found that the Bakken is over pressured and mature, with oil and gas saturation, and substantial fracturing and fair to good porosity. The EPU119 well was targeting possible reserve volumes in the Nisku Formation and failed to produce commercially viable quantities of oil. However, EPU 119 did encounter hydrocarbons up hole of the Nisku Formation in the Charles Formation as seen on the well logs and in the core. Completion work is currently planned for EPU 119 in the fall of 2011. Other than the EPU 119, the Company did not drill any new wells at the Poplar Field during this reporting period. The Company has a drilling program planned for the fall of 2011 to drill up to three new wells in the Charles Formation targeting proven undeveloped reserves. Since the program is relatively new to the Company, there is no recent experience of converting proved undeveloped reserves to proved developed reserves.

In Australia, the Company has no recent experience of converting possible reserves to probable reserves and probable reserves to proved reserves. In Australia, our possible and probable oil reserves relate to the Mereenie Field in Northern Territory, where there has not been any drilling since 2004.

Preparation of Oil and Gas Reserve Information

Proved reserves. Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Probable reserves. Estimates of probable developed and undeveloped reserves are inherently imprecise. When producing an estimate of the amount of oil and gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate that is as likely as not to be achieved. Estimates of probable reserves are also continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

We use deterministic methods to estimate probable reserve quantities, and when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible reserves. Estimates of possible developed and undeveloped reserves are also inherently imprecise. When producing an estimate of the amount of oil and gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

We use deterministic methods to estimate possible reserve quantities, and when deterministic methods are used to estimate possible reserve quantities, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. Possible reserves may be assigned to areas

 

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of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geo-science and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geo-science and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and we believe that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

PRODUCTION VOLUMES, PRICES AND COSTS

MPC’s production volumes, net of royalties, average sales prices and average production costs for oil and gas during the three years ended June 30, 2011, 2010, 2009 are as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material):

 

     Production Volumes      Average Sales Prices      Average Production Costs  
     Oil      Gas      Total(2)      Oil      Gas      Oil      Gas  
     (MBls)      Bcf      MBOE      (per bbl)      (per mcf)      (per bbl)      (per mcf)  

2011

                    

Australia (AUD)

     55         0.71         173       $ 99.67       $ 2.28       $ 93.40       $ 2.22   
  

 

 

    

 

 

    

 

 

             

United States (1) (3)

     68         —           68         77.96         —           34.58         —     
  

 

 

    

 

 

    

 

 

             

U.K.

     —           —           —           —           —           —           —     
  

 

 

    

 

 

    

 

 

             

Other

     —           —           —           —           —           —           —     
  

 

 

    

 

 

    

 

 

             

Total

     123         0.71         241               
  

 

 

    

 

 

    

 

 

             

2010

                    

Australia (AUD)

     97         3.43         669         82.19         5.07         30.92         1.86   
  

 

 

    

 

 

    

 

 

             

United States

     42         —           42         67.88         —           36.43         —     
  

 

 

    

 

 

    

 

 

             

U.K.

     —           —           —           —           —           —           —     
  

 

 

    

 

 

    

 

 

             

Other

     —           —           —           —           —           —           —     
  

 

 

    

 

 

    

 

 

             

Total

     139         3.43         711               
  

 

 

    

 

 

    

 

 

             

2009

                    

Australia (AUD)

     153         5.18         1,016         91.21         3.54         26.72         0.99   
  

 

 

    

 

 

    

 

 

    

 

 

          

U.K.

     —           —           —           —              —           —     
  

 

 

    

 

 

    

 

 

             

Other

     —           —           —           —           —           —           —     
  

 

 

    

 

 

    

 

 

             

Total

     153         5.18         1,016               
  

 

 

    

 

 

    

 

 

             

 

(1) Net Production by field was 51 MBbls for EPU and 17 MBbls for Northwest Poplar Field.
(2) Natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio.
(3) Includes 6 MBbls attributable to a consolidated subsidiary in which there was, as of June 30, 20111, an 16.5% non-controlling interest. (See Note 20)

 

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PRODUCTIVE WELLS

Productive wells at June 30, 2011 were as follows:

 

     Production Wells  
     Oil      Gas  
     Gross      Net      Gross      Net  

Australia

     16.0         5.6         10.0         4.2   

United States

     35.0         30.0         —           —     

Other Foreign Countries

     —           —           3.0         0.1   
  

 

 

    

 

 

    

 

 

    

 

 

 
     51.0         35.6         13.0         4.3   
  

 

 

    

 

 

    

 

 

    

 

 

 

ACREAGE

The following table summarizes gross and net developed and undeveloped acreage by geographic area at June 30, 2011. Net acreage is our percentage ownership of gross acreage. Acreage in which our interest is limited to royalty or overriding royalty is excluded.

 

     Developed Acreage      Undeveloped      Total Acreage  
     Gross      Net      Gross      Net      Gross      Net  

Australia

                 

Mereenie

     31,567         11,048         38,482         13,469         70,049         24,517   

Palm Valley

     41,644         21,664         116,288         60,497         157,932         82,161   

Dingo

     —           —           116,139         39,878         116,139         39,878   

Offshore

     —           —           1,556,647         1,556,647         1,556,647         1,556,647   

United States

                 

Poplar Field

     22,893         18,693         648         542         23,541         19,235   

All Other

                 

U.K — Weald / Wessex Basin

     —           —           449,737         270,253         449,737         270,253   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     96,104         51,405         2,277,941         1,941,286         2,374,045         1,992,691   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Of the total undeveloped acreage (2.3 million gross, 1.9 million net), as of June 30, 2011, the portion of our net undeveloped acres that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 4% in 2012, 0% in 2013 and 11% in 2014.

DRILLING ACTIVITY

There were two wells in process at June 30, 2011.

The Company has a 40% interest in the Markwells Wood-1 exploration well in PEDL 126, which spudded in November 2010. Northern Petroleum is operator of the PEDL 126 joint venture. Markwells Wood-1 well targeted the eastward extension of the Horndean oil field which is currently producing from the Great Oolite Formation. Assessment of the well logs confirmed that the entire Great Oolite reservoir sequence in Markwells Wood-1 is oil-bearing above the Horndean field oil-water contact of 4,446 ft sub-sea level. Northern Petroleum started operations for an extended well test of the Markwells Wood oil discovery, with the arrival of a workover rig on September 6, 2011. The test will enable the joint venture partners to evaluate the potential and scheme for future development of the Markwells Wood oil accumulation.

Magellan commenced a drilling and development program in the Poplar Field, with the EPU 119 that reached a depth of 7,137 feet on October 18, 2010. Well results to-date, while under further evaluation, yielded a broad stack of hydrocarbon-bearing formations from 692 feet all the way to current depth. The deepest target, the Nisku Formation, proved to be non-commercial and the well will be recompleted up hole in the Charles. Completion work is currently planned for EPU 119 in the fall of 2011.

 

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

 

                                                                            All Other Foreign  
    Total     Australia     United States     Geographic Areas  

Year ended
June 30

  Exploration     Development     Exploration     Development     Exploration     Development     Exploration     Development  
  Productive     Dry     Productive     Dry     Productive     Dry     Productive     Dry     Productive     Dry     Productive     Dry     Productive     Dry     Productive     Dry  

2011

    0.4        —          1.0        —          —          —          —          —          —          —          1.0        —          0.4        —          —          —     

2010

    —          —          —          —          —          —          —          —          —          —          —          —          —          —          —          —     

2009

    —          —          —          —          —          —          —          —          —          —          —          —          —          —          —          —     

MARKETING ACTIVITIES AND CUSTOMERS

Customers

Although MPAL’s producing oil and gas properties are located in a remote area in central Australia, 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 customer, PWC, contracted with Eni Australia in 2006 for the supply of PWC’s Northern Territory gas demand requirement for twenty five years, commencing January 2009. Eni Australia expected to commence sales from its Blacktip field offshore of the Northern Territory in January 2009; however, the Blacktip development encountered significant delays and only commenced partial production in September 2009 with full production not achieved until February 2010. The Mereenie Producers continued to supply PWC’s gas requirements on a reasonable endeavors basis to supplement Blacktip gas sales until early February, 2010. The last Mereenie gas sales contract terminated in September, 2010. As MPAL was not able to sell its uncontracted gas, its revenues have declined in 2011.

However, upon completion of the Santos SA, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”) with the Santos Entities on September 14, 2011, that provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65PJ over the anticipated 17 year term of the GSPA.

Oil Production

MPAL — 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. Oil sales during fiscal 2011 were 66.6% to the Santos group of companies, 20.2% to the Beach Petroleum group of companies and 13.2% to Origin Energy Resources.

Nautilus — Presently all of the oil production from the Poplar Field is being trucked to a terminal in Reserve, MT and sold to Plains Marketing, LP.

CURRENT MARKET CONDITIONS AND COMPETITION

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 and the availability of equipment. The success of exploitation is also the ability to avoid or minimize the effect of engineering and construction delays and difficulties. The Company also must compete with major oil and gas companies which have substantially greater resources.

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.

 

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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 weather.

SEGMENT INFORMATION

The Company is engaged in only one industry, namely, oil and gas exploration, development, production and sale. The Company conducts such business through its three operating segments: MPC, its 100% equity interest in its subsidiary, MPAL, and its 83.5% controlling member interest in Nautilus, as of June  30, 2011. See Note 15.

EMPLOYEES

Number of Persons Employed by Company.

As of fiscal year ended June 30, 2011 the Company had 42 total employees. MPC had 8 employees and Nautilus had 12 employees in the United States. At that date, MPAL had 22 employees in Australia.

REGULATORY MATTERS, ENVIRONMENTAL AND ADDITIONAL FACTORS AFFECTING BUSINESS

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. We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits and international environmental conventions, including those relating to the generation, storage, handling, use, disposal, movement and remediation of natural gas, natural gas liquids, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; the storage, use and treatment of water; and the placement, operation and reclamation of wells. These requirements are a significant consideration for us as our operations involve the generation, storage, handling, use, disposal, movement and remediation of natural gas, natural gas liquids, oil and other hazardous or regulated materials and the emission and discharge of such materials to the environment. If we violate these requirements, or fail to obtain and maintain the necessary permits, we could be fined or otherwise sanctioned, which sanctions could include the imposition of fines and penalties and orders enjoining future operations. Pursuant to such laws, regulations and permits, we have made and expect to continue to make capital and other compliance expenditures.

At fiscal year ended June 30, 2011, the Company had accrued approximately $11.4 million for asset retirement obligations for the Mereenie, Palm Valley, Dingo and Poplar Field (See Note 5).

Financial Information Relating to Foreign and Domestic Operations.

See Note 15 and Note 19.

Risks Attendant to Foreign Operations.

Many 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

 

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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.

AVAILABLE INFORMATION

Information regarding the Company, including corporate governance policies, code of ethics and charters for the committees of the board of directors can be found on our Internet website at http://www.magellanpetroleum.com and copies of these documents are available to stockholders, without charge, upon request to Jeffrey Tounge, Corporate Secretary, Magellan Petroleum Corporation, 7 Custom House Street, 3rd Floor, Portland, Maine 04101 (tel: (207) 619-8500). The information contained in our website is not intended to be incorporated into this Form 10-K. In addition, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are made available free of charge on our Internet website on the same day that we electronically file such material with, or furnish it to, the SEC. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. These filings are also available to the public from commercial document retrieval services and at the Internet website maintained by the SEC at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

 

Item 1A. Risk Factors

Set forth below and elsewhere in this Annual Report on Form 10-K are the risks and uncertainties that should be considered in evaluating the Company’s common stock and 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, MPC and Nautilus could stop producing oil and gas.

MPAL’s Palm Valley field and Nautilus’ Poplar Field could stop producing oil and gas or there could be a material decrease in production levels at the fields. Since these are the three principal revenue producing properties of Magellan, any decline in production levels at these properties could cause Magellan’s revenues to decline. Any such adverse impact on the revenues and cash flows being received by Magellan could restrict our ability to explore and develop oil and gas properties in the future and cause our stock price to decline.

MPAL’s production history depended upon long-term gas supply contracts, one of which was not renewed, and MPAL’s business has been adversely impacted.

MPAL’s financial performance and cash flows have historically been dependent upon its Palm Valley and Mereenie supply contracts to sell gas produced at these fields to MPAL’s former 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, commenced sales in

 

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September 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Mereenie Producers continued to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until September 5, 2010. The last Mereenie gas sales contract terminated in September, 2010. As MPAL was not able to sell its uncontracted gas, its revenues have declined in 2011.

In fiscal year 2010, we completed an acquisition of a 83.5% controlling member interest in Nautilus and may make acquisitions or investments in new oil and gas reserves, operating businesses or assets that involve additional risks, which could disrupt our business or harm our financial condition or results of operations.

As part of our business strategy, in October 2009, we acquired a controlling interest in Nautilus. We expect to continue to make acquisitions of companies that possess oil and gas reserves or other businesses or assets that are complementary to our growth strategy. Such acquisitions or investments involve a number of risks, including:

 

   

assimilating operations and new personnel may be unexpectedly difficult;

 

   

management’s attention may be diverted from other business concerns;

 

   

we may enter markets in which we have limited or no direct experience;

 

   

we may lose key employees of an acquired business;

 

   

we may not realize the value of the acquired assets relative to the price paid; and

 

   

despite our due diligence efforts, we may not succeed at quality control or other customer issues.

These factors could have a material adverse effect on our business, financial condition and operating results. Consideration paid for any future acquisitions could include our stock or require that we incur additional debt and contingent liabilities. As a result, future acquisitions could cause dilution of existing equity interests and earnings per share.

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

During fiscal year 2012, the Markwells Wood-1 well, in the Weald Basin United Kingdom in which we hold interests, is currently being production tested to recover oil and gas in commercially viable quantities. On October 18, 2010, Magellan commenced a drilling and development program in Poplar Field, with the EPU 119. Completion work is currently planned in the fall of 2011. If these drilling projects are not successful, no revenues will be achieved from the drilling projects and our results of operations would be adversely affected.

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 U.S. 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.

 

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

During the past few years, the equity trading markets in the United States have experienced price volatility that has often been unrelated to the operating performance of particular companies. These fluctuations may adversely affect the trading price of our common shares. From time to time, there may be significant volatility in the market price of our common shares. 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 shares.

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, Nautilus, and MPAL. The ability to retain 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.

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 MPC.

The properties in which Magellan has interests located outside the United States 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. 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 incentive plan and our outstanding warrants and shareholders may be adversely affected by the issuance of those shares.

As of June 30, 2011, there were 4,347,826 warrants outstanding and 5,200,000 stock options outstanding of which 3,258,332 are fully vested and exercisable. As of that date, there were also 1,270,000 options available for future grants under our 1998 Stock Incentive Plan as amended in December of 2010 (“Plan”). If all of these options and warrants, which total 10,817,826 in the aggregate, are awarded and exercised, shares received would represent approximately 21% of our outstanding common shares 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

 

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regain compliance with the rule. On September 1, 2011 the Company’s shares closed at $1.55 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.

We have limited management and staff and will be dependent upon partnering arrangements.

The Company and its affiliates had approximately 42 total employees as of June 30, 2011. Despite our increase in employment relative to prior years, we expect that we will continue to require the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers create a number of risks, including but not limited to:

 

   

the possibility that such third parties may not be available to us as and when needed; and

 

   

the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price will be materially adversely affected.

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 (i.e. hurricanes), including effects on prices and supplies in worldwide energy markets;

 

   

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

 

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caused by a recession would likely reduce worldwide demand for energy and result in lower oil and natural gas prices. Oil prices declined from previous years’ record levels to below $70 per barrel in August 2009, then up slightly to $76 per barrel in September 2010 and $82 per barrel in August 2011, while natural gas prices have declined from over $13 per mcf to approximately $4 per mcf over the same period.

Sustained declines in oil and gas prices would not only reduce our revenues, 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. 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.

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

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production and face intense competition from both major and other independent oil and natural gas companies. Many of our 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 potential impacts of climate change may negatively impact our business and results of operations.

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

 

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We depend on one purchaser for a substantial portion of our revenue in the United States. The inability of the purchaser to meet their payment obligations to us may adversely affect our financial results.

Currently, Nautilus relies on its contract with Plains Marketing, LP. as the sole customer for its oil produced in Montana. If Nautilus’ sole customer reduces or discontinues its business with us, or if we are not able to successfully negotiate a replacement contract with our sole customer after the expiration of such contract, or if the replacement contract is on less favorable terms, the effect on us could be adverse if we were not able to locate new customers to purchase the oil produced at the Poplar Field. In addition, if Nautilus’ sole customer was to experience financial difficulties or any deterioration in its ability to satisfy its obligations to us, our cash flow from the Poplar Field could be adversely affected.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

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. 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.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on the average, first-day-of-the-month price during the 12-month period preceding the measurement date. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

 

   

actual prices we receive for oil and natural gas;

 

   

actual cost of development and production expenditures;

 

   

the amount and timing of actual production;

 

   

supply of and demand for oil and natural gas; and

 

   

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows for financial statement disclosure, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Reserves as of June 30, 2011 have been reported under SEC rules. The estimates provided in accordance with the SEC rules may change materially as a result of interpretive guidance that may be subsequently released by the SEC.

We have included in this report estimates of our proved reserves at June 30, 2011 as prepared consistent with our independent reserve engineers’ interpretations of the SEC rules relating to disclosures of estimated natural gas and oil reserves. These rules require SEC reporting companies to prepare their reserve estimates using

 

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reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. While the estimates of our proved reserves at June 30, 2011 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could ultimately differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

We may be limited in our ability to book additional proved undeveloped reserves under the SEC rules.

Another impact of the SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program on our undeveloped properties.

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

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, farming-in other companies or investors to MPAL’s exploration and development projects in which we have an interest and/or equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flow from operations is not sufficient to fund the Company’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;

 

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adverse weather conditions;

 

   

compliance with environmental and other governmental requirements including the Bureau of Indian Affairs and the Bureau of Land Management; and

 

   

costs of, or shortages or delays in the availability of, drilling rigs, pressure pumping equipment and supplies, tubular materials, water resources, disposal facilities, other necessary equipment, supplies and services.

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

The Company follows 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. 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, but at least annually, 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 annually or whenever events or 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 Palm Valley, future undiscounted cash flows were based upon the quantities of gas currently committed to the current contract and estimated sales subsequent to the contract. If such new contracts are affected, the proved developed reserves will be increased to the lesser of the current risk adjusted probable and possible reserves or the newly contracted quantities. At June 30, 2011, Mereenie had no gas contracts, thus no gas reserves. The Mereenie discounted future net cash flows were negative due to the loss of the gas contract. According to the SEC definition of proved reserves, this results in zero proved oil reserves. 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;

 

   

suspension of operations;

 

   

and compliance with, or changes in, environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing , laws and regulations imposing conditions and restrictions on drilling and completion operations and other laws and regulations, such as tax laws and regulations.

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

 

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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. economy, may materially adversely affect our business and results of operations and we do not expect these conditions to improve in the near future.

Continual volatility and disruption, since 2008, 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.

We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.

We do not operate all of the properties in which we own an ownership interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these non-operated properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production, revenues and reserves. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

 

   

nature and timing of drilling and operational activities;

 

   

timing and amount of capital expenditures;

 

   

expertise and financial resources;

 

   

the approval of other participants in drilling wells; and

 

   

selection of suitable technology.

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 British pound, have changed in recent periods and may fluctuate substantially in the future. We expect that a majority of our revenue will be generated in the U.S. dollar in the future. However, at June 30, 2011, the U.S. dollar has weakened against the Australian dollar which has had, and may continue to have, a positive 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 gain for the year ended June 30, 2011 was $9.2 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 positive 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 British pounds. Accordingly, any material appreciation of the British pound against the Australian dollar could have a negative impact on our business, operating results and financial condition.

 

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Item 1B. Unresolved Staff Comments.

None

 

Item 3. Legal Proceedings

None

 

Item 4. Removed and Reserved.

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:

 

2011

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

High

     1.97         3.03         3.45         2.58   

Low

     1.49         1.78         2.27         1.38   

2010

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

High

     1.59         1.76         2.42         2.26   

Low

     0.91         1.30         1.53         1.54   

(b) Approximate Number of Holders of Common Stock at September 1, 2011

 

Title of Class

   Number of Record Holders  

Common stock, par value $.01 per share

     5,454   

(c) Frequency and Amount of Dividends

MPC has never paid a cash dividend on its common stock. The Company does not intend to pay cash dividends in the foreseeable future.

 

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(e) Performance Graph

The graph below compares the cumulative total returns, including reinvestment of dividends, if applicable, on the Company’s common stock with the returns on companies in the NASDAQ Composite Index, a broad equity market index, and Morningstar Oil and Gas E&P Industry Index Morningstar Industry Index (“Morningstar Industry Index”), an industry group index.

The chart displayed below is presented in accordance with SEC requirements. The graph assumes a $100 investment made on July 1, 2006 and the reinvestment of all dividends. Stockholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future performance.

LOGO

The Hemscott Oil & Gas Index, the industry group index formally used in the MPET graph is no longer available due to Morningstar’s acquisition of Hemscott, and it has been replaced in the performance graph with Morningstar’s Oil and Gas E&P Industry index, an index deemed to be the closest fit by composition and construction.

 

Company/Market/Peer Group

   6/30/2006      6/30/2007      6/30/2008      6/30/2009      6/30/2010      5/12/2011      6/30/2011  

Magellan Petroleum Corporation

   $ 100.00       $ 95.60       $ 101.89       $ 69.81       $ 115.09       $ 128.93       $ 105.66   

NASDAQ Composite Index

   $ 100.00       $ 119.88       $ 106.36       $ 85.99       $ 99.73       $ 136.44       $ 132.36   

Morningstar Industry Index

   $ 100.00       $ 116.77       $ 187.29       $ 101.82       $ 124.81       $ 175.35       $ 175.99   

Hemscott Industry Index

   $ 100.00       $ 126.95       $ 181.93       $ 104.27       $ 106.55       $ 139.05         n/a   

 

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Recent Sales of Unregistered Securities

As previously disclosed in the Company’s reports filed on May 14, 2010, 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 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 was used for acquisitions as well as, 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 are not registered under the Securities Act of 1933, as amended (“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 SEC or an available exemption from the applicable federal and state registration requirements. In the Purchase Agreement, YEP represents 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 will acquire 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 purposes of the YEP transaction.

On October 14, 2009, the Company entered into a Purchase and Sale Agreement (the “Nautilus Purchase Agreement”), dated October 15, 2009, with White Bear LLC, a Montana limited liability company (“White Bear”) and YEP I, SICAV-FIS, a Luxembourg entity (“the YEP I Fund”, and collectively with White Bear, the “Sellers”) and simultaneously closed the transactions described therein. Under the Nautilus Purchase Agreement, the Company acquired from the Sellers an 83.5% controlling ownership interest in Nautilus, a Montana limited liability company. The Company paid gross $10.9 million for the controlling interest in Nautilus, comprised of a cash payment totaling approximately $7.3 million and the issuance of 1.7 million new shares of Common Stock, valued by the parties at $2,380,000 (or $1.40 per share), with an adjustment for $1.2 million of net debt. All shares of Common Stock sold pursuant to the Nautilus Purchase Agreement were registered in the name of the YEP I Fund. The shares sold to YEP I Fund in the private placement 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 SEC or an available exemption from the applicable federal and state registration requirements. In the Nautilus Purchase Agreement, YEP I Fund represents 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 will acquire the shares for its own account for investment purposes only and not with a view to or for distributing or reselling the shares 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. The Company relied upon the exemption from the registration requirements of the Securities Act provided by Regulation S promulgated under the Securities Act.

On August 5, 2010, the Company entered into another Securities Purchase Agreement (the “Second Purchase Agreement”) with YEP, under which the Company agrees to sell, and YEP agrees that YEP and/or one or more of its affiliates (collectively, the “Investor”) will purchase 5,200,000 shares of Common Stock at a purchase price of $3.00 per share, for an aggregate purchase price of $15.6 million (such transaction referred to below as the “Investment Transaction”). Pursuant to the terms of the Second Purchase Agreement, the Company shall use the proceeds from the Investment Transactions to facilitate the closing of the Evans Shoal Transaction. The shares to be issued to the Investor in connection with the Investment Transaction have not been registered under the Securities Act, and may not be offered or sold in the United States in the absence of an effective registration statement or exemption from the registration requirements of the Securities Act. In the Second

 

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Purchase Agreement, the Investor 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 will acquire the shares for its own account for investment purposes only and not with a view to or for distributing or reselling the shares 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.

On February 11, 2011, the Company and YEP executed a First Amendment to Securities Purchase Agreement (“First Amendment”). The First Amendment provides for a final closing of the Investment Transaction on or before June 15, 2011 to the extent that: (i) the Evans Shoal Transaction does not close as contemplated by the Asset Sales Deed; and (ii) the failure to close the Evans Shoal Transaction results in the failure of the Company to recover an additional $10 million deposit made towards the purchase price set forth of the Asset Sales Deed (the “Deposit Back Stop”). On February 17, 2011, the Company and YEP executed a Second Amendment to Securities Purchase Agreement (“Second Amendment”) to clarify that the Deposit Back Stop set forth in the First Amendment and states that the funding contemplated by the First Amendment would not be withheld to the extent that the Company fails to satisfy any condition precedent set forth in the Second Purchase Agreement if such non-satisfaction is reasonably attributable to the failure to close the Evans Shoal Transaction. Since the Asset Sales Agreement has been terminated and MPAL did receive the $10 million deposit back in July 2011, the Investment Transaction has not closed. The Company and YEP are in the process of terminating the Securities Purchase Agreement as amended by the First and Second Amendments.

Please refer to Note 20 for details of all subsequent events.

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, 2010 – June 30, 2011

     —           —           —           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, 2011, the Company had purchased 680,850 of its shares at an average price of $1.01 per share, or a total cost of approximately $686,000, all of which shares have been cancelled. No shares were purchased during 2011, 2010, or 2009.

 

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, 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,  
     2011     2010     2009      2008     2007  

Financial Data

           

Total revenues

   $ 18,177      $ 28,525      $ 28,191       $ 40,895      $ 30,675   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Net (loss) income attributable to MPC

     (32,433     (1,447     665         (8,892     447   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Net (loss) income per share (basic and diluted) attributable to MPC

     (0.62     (0.03     0.02         (0.21     0.01   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Total assets

     71,575        90,706        71,704         85,295        85,616   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Long-term liabilities

     12,578        10,775        11,809         14,153        13,076   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Non-controlling interests

     1,989        1,914        —           —          —     
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Exchange rate A.$ = U.S. at September 1

     1.07        0.89        0.84         0.86        0.82   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

 

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

Forward Looking Statements

Our disclosure and analysis in this report contains forward-looking information that involves risks and uncertainties. Our forward-looking statements express our current expectations or forecasts of possible future results or events, including projections of future performance, statements of management’s plans and objectives, future contracts, and forecasts of trends and other matters. Forward-looking statements speak only as of the date of this filing, and we undertake no obligation to update or revise such statements to reflect new circumstances or unanticipated events as they occur. You can identify these statements by the fact that they do not relate strictly to historic or current facts and often use words such as “anticipate”, “estimate”, “expect”, “believe”, “will likely result”, “outlook”, “project” and other words and expressions of similar meaning. No assurance can be given that the results in any forward-looking statements will be achieved and actual results could be affected by one or more factors, which could cause them to differ materially. For these statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

Among these risks and uncertainties are the following: the ability of Magellan and Santos to complete and implement the terms of the Santos asset swap/sales agreement and gas sales contract, including securing the customary approvals necessary to complete the asset swap, the future outcome of the negotiations by Santos with its customers for gas sales contracts for the remaining uncontracted reserves in the Amadeus Basin, the production volume at Mereenie and whether it will be sufficient to trigger the bonus amounts provided for in the Santos asset swap/sales agreement, the ability of the Company to successfully develop its existing assets, the ability of the Company to secure gas sales contracts for the uncontracted reserves at Dingo, the ability of the Company to implement a successful exploration program, pricing and production levels from the properties in which Magellan and MPAL have interests, the extent of the recoverable reserves at those properties, the profitable integration of acquired businesses, including Nautilus Poplar LLC, the likelihood of success of the drilling program at the Poplar Fields by the Company’s new farm-in partner, VAALCO Energy, and the results of the ongoing production well tests in the U.K. 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. Any forward-looking information provided in this report should be considered with these factors in mind. Magellan assumes no obligation to update any forward-looking statements contained in this report, whether as a result of new information, future events or otherwise.

Executive Summary

Overview

Magellan is an oil and gas investment company, whose strategy is to create long-term value through the acquisition and redevelopment of “under-exploited” natural gas and oil reserves.

Although Magellan has been in existence for decades, particularly in Australia, the Company began the transformation to an active international E&P development platform only in the past two years. During this time, the Company has assembled a new management team with experience in oil and gas operations, project development, finance, and management. This team has worked to rationalize Magellan’s legacy assets, contracts, and holding structures, while positioning the Company to unlock the value of the most promising of these assets and expanding its scope to gain access to new growth opportunities.

In the past year, the Company dedicated significant time and resources to pursuing the acquisition of Santos’ 40% interest in a contingent 6.6 Tcf gas field in the Northern Territory, Australia, the Evans Shoal field. This transaction would likely have been transformational for Magellan. The development of the field using Methanol technology represented a creative solution to an otherwise long-term, stranded natural gas field. Despite spirited effort, due to factors outside of the Company’s control, Magellan and Santos agreed that the transaction would not be completed. The Company had committed A$25 million towards the acquisition of the Evans Shoal field through two deposits and was returned A$10 million on July 22, 2011.

 

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As a result, the Company continued with a review of its assets and developed a rationalization plan. On September 14, 2011, Magellan entered into an agreement with Santos to swap its interest in the Mereenie field for the purchase of the remaining interest in the producing Palm Valley gas field and exploration Dingo field, all three fields located in the Amadeus basin, onshore Australia. Upon completion of this transaction, which is subject to customary approvals and expected to close in the very near future, the Company will receive the new asset interests described above, a cash contribution of A$25 million, and further subsequent bonus payments contingent upon future production, with a cumulative possible value of A$17.5 million. In addition, the Company also entered into a long term gas supply agreement with Santos for its Palm Valley gas field, which will provide incremental revenue and cash flows to support the Company’s ongoing operations in Australia.

In parallel, the Company focused on its under-developed, multiple formation, producing oil field in Montana, the Poplar Field. Building from the acquisition of 3D seismic in 2010, and the acquisition of a set of cores and further data from a new well spud in 2010, the Company entered into a farm out agreement with VAALCO Energy for the Bakken and deep formations of the Poplar Field. VAALCO Energy committed to drill three new wells in the Poplar Field by December 2012 and paid $5 million on September 6, 2011 in consideration for a 65% working interest in these Deep Intervals. The Company will retain a 35% working interest in the Deep Intervals and will continue to hold its current interest in all formations above the Bakken formation, including the currently producing Charles and Tyler formations where all Poplar proved and probable reserves are located. This transaction will enable the Company to continue to focus on the development of the Charles formation while also testing the Bakken, Red River and other potential deep formations in the Poplar Field.

In the U.K., Magellan participated in the Markwells Wood-1 oil discovery. The well was spud, by Northern Petroleum in November 2010. A completion rig moved on site in September, 2011 to begin a series of incremental reservoir tests designed to measure oil flow response to several production strategies.

The financial results for fiscal year ending June 30, 2011 resulted in a consolidated loss of $32.4 million, or $0.62 per share. The net loss was largely the result of non-recurring charges of approximately $23.3 million, including $15.9 million relating to the Evans Shoal deposit and $7.0 million relating to the valuation allowance for deferred tax assets. In addition, the Company incurred materially higher consulting costs and expenses related to the transactions pursued during the fiscal year ending June 30, 2011. The financial results of the Company were particularly negatively impacted by the $10.3 million reduction in consolidated revenues from FY 2010 to FY 2011, which primarily resulted from the end of the gas sales contract at Mereenie and the reduction in gas sales volume from Palm Valley. The reduction in revenues from the Company’s Australian operations underpinned the completion of the rationalization plan described above.

The Company has now completed a series of key transactions that will enable (a) increased control over its asset portfolio, (b) several new, concurrent development programs for the Poplar Field, and (c) provide incremental resources to fund existing development plans and new opportunities.

Overview of our FY 2011 Financial Results

Magellan realized a 87% decrease in gas sales this fiscal year due to the term end of the Mereenie Sales Agreement and the volume decrease at Palm Valley which is according to the Palm Valley Contract, resulting in years ended June 30, 2011 gas sales of $1.8 million (net of royalties) or 10% of total revenues for the years ended June 30, 2011 and was offset by a 12.1% increase in the average exchange rate and a 1% increase in the average price per MCF received under the Palm Valley contract.

Oil sales increased by 20% this fiscal year due to oil sales related to the Poplar Field assets acquired in October 2009 and March 2010 and a 15% increase in the price per barrel in the United States resulting in years ended June 30, 2011 oil sales of $11.8 million (net of royalties) or 65% of total revenues for the years ended June 30, 2011.

 

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For the year ended June 30, 2011, Magellan recorded a consolidated net loss of $32.4 million, or $0.62 per share, on gross revenues of $18.2 million, as compared to a net loss of $1.5 million, or $0.03 per share, on gross revenues of $28.5 million in 2010. The following items impacted our 2011 earnings and cash flow as compared to 2010:

 

   

Gas sales decreased from $13.6 million in 2010 to $1.8 million in 2011 due to the term end of the Mereenie Sales Agreement (MSA4)

 

   

$15.9 million relates to a write off of the initial “deposit” contributed by Magellan Petroleum Australia Limited (“MPAL”), the Company’s wholly owned subsidiary, in connection with the March 25, 2010 Asset Sales Deed, as amended by the Deed of Variation, between MPAL and Santos Offshore Pty Ltd. (“Asset Sales Deed”) which outlined the terms of MPAL’s contemplated purchase of Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48) (“Evans Shoal Transaction”)

 

   

$7.0 million is attributable to a non-cash charge related to a valuation allowance recognized as a reserve against MPAL’s deferred tax balances

On August 30, 2011, the Company reported a preliminary unaudited consolidated net loss of $36.1 million, or $0.69 per share for the year ended June 30, 2011. The audited financial statements for the same period report a consolidated net loss of $32.4 million or $0.62 per share. The difference in the preliminary and audited consolidated net loss numbers results from the reversal of a $4 million impairment to MPAL’s Goodwill included in the unaudited results. At the time of the release of the Company’s preliminary unaudited financial statements, the Company had yet to complete its annual Goodwill impairment analysis, which upon finalization resulted in no impairment to MPAL’s Goodwill.

The net loss in the fiscal year ended June 30, 2011 income was largely the result of non-recurring charges.

The new commercial arrangements recently concluded are as follows:

On September 14, 2011, Magellan Petroleum (N.T.) Pty Ltd (“Magellan NT”), a wholly owned subsidiary of MPAL, entered into a Sale Agreement (“Santos SA”) with Santos QNT Pty Ltd (“Santos QNT”) and Santos Limited (“Santos Entities”). The Santos SA provides for the transfer of Magellan NT’s 35% interest in the Mereenie oil and gas field to the Santos Entities and the transfer of the Santos entities 47.977% interest in the Palm Valley gas field and the 65.6635% interest in the Dingo gas field to Magellan NT subject to the satisfaction of certain conditions.

The cash consideration payable to Magellan NT is A$25 million plus a bonus amount based on Mereenie future production levels.

Upon completion of the Santos SA, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”) with the Santos Entities on September 14, 2011, and provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65PJ over the anticipated 17 year term of the GSPA.

On September 2, 2011, the Company signed and closed a Purchase and Sale Agreement with the owners of Nautilus Technical Group LLC, (“Nautilus Technical”), and Eastern Rider LLC, (“Eastern Rider”), (collectively the “Sellers”), resulting in the Company owning 100% of Nautilus Poplar and, directly or indirectly through Nautilus, a 100% working interest in the Poplar Field, aside from certain working interest owners in the Northwest Poplar fields. The Company paid the Sellers total cash consideration of $4.0 million dollars.

On September 7, 2011, the Company and VAALCO Energy (USA) Inc. (“VAALCO”) signed a definitive Lease Purchase and Sale Agreement (the “VAALCO LPSA”). VAALCO also agreed to drill three wells, at its sole expense as operator, to the Bakken formation and to formations below the Bakken (the “Deep Intervals”) in Poplar Field. Upon completion of three (3) new wells in the Deep Intervals of the Poplar Field, VAALCO will earn a 65% working interest in the Deep Intervals within the Poplar Field. One well will be spud on or before June 1, 2012 and the second and third will be spud on or before December 31, 2012. One well will be drilled horizontally to test the Bakken Formation, one well will be drilled vertically to test the Red River Formation, and a third will be targeted at VAALCO’s discretion.

 

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The Company will retain a 35% working interest in the Deep Intervals and will continue to hold its current interest in all formations above the Bakken formation, including the currently producing Charles and Tyler formations where all Poplar proved and probable reserves are located.

Operational Results

Australia

MPC’s Australia sale volumes, net of royalties, were .71 BCF of gas and 55 MBbls of oil for the years ended June 30, 2011 or a 79% decrease in gas sales and 57% decrease in oil sales for the years ended June 30, 2010. The decrease in gas sales is due primarily to the term end of the MSA4 agreement and the decrease in oil sales is due primarily to the sale of the Cooper Basing and Nockatunga assets

Mereenie: There were no gas sales from Mereenie for the years ended June 30, 2011. The Mereenie Producers continued to supply PWC’s gas requirements on a reasonable endeavors basis to supplement Blacktip gas sales until early February 2010. The principal Mereenie contracts and supply obligations under the various agreements expired in January and June 2009, and September 2010.

Magellan NT has entered into the Santos SA to transfer all of the Company’s interest in the Mereenie field to the Santos Entities with effect July 1, 2011, as described above.

Palm Valley: The Palm Valley gas contract expires in January 2012.

Magellan NT has entered into the Santos SA to receive all of the Santos Entities’ interest in the Palm Valley and Dingo fields with effect July 1, 2011, as described above. Upon completion of the agreements, The Company will own 100% of the Palm Valley and Dingo gas fields and will have 25.65PJ of gas contracted under the GSPA with the Santos Entities.

Dingo: MPAL has a 34.34% interest in the Dingo gas field which is held under Retention License No. 2 in the Amadeus Basin in the Northern Territory. No market has emerged for 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 4.81%. The license was renewed for a further five year term and expires in February 2014

Evans Shoal (NT/P48): MPAL entered into an agreement with Santos Offshore Pty Ltd (“Santos”) on March 25, 2010 (“Asset Sales Deed”), to purchase Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48) (“Evans Shoal Transaction”).

On July 21, 2011, Santos and MPAL executed a Release Agreement to (1) terminate the Amended Asset Sales Deed and (2) resolve all outstanding issues relating to the Amended Asset Sales Deed. Under the Release Agreement, MPAL received back the Second Escrow Deposit, plus all interest accrued on that deposit from the date of deposit to the date of release and the parties agreed to mutually release each other from all claims arising out of the Asset Sales Deed and the Evans Shoal Transaction.

In connection with the unwinding of the Evans Shoal Transaction, the Company and Santos on September 14, 2011 executed agreements to transfer their interests in the Amadeus licenses with a resulting ownership interest by the Company of 100% of the Palm Valley and Dingo gas fields.

NT/P82: The Commonwealth — Northern Territory Offshore Petroleum Joint Authority granted Exploration Permit for Petroleum NT/P82 to the Company (100% interest) over Area NT09-1. Area NT09-1 was offered for competitive bid under the Australian Government 2009 Release of Offshore Petroleum Exploration Areas. The exploration permit was granted on May 13, 2010 for a six year term. The committed work program under the permit during the first three years of the term involves the reprocessing of existing seismic data, the acquisition of additional 2D and 3D seismic data and the interpretation of the combined seismic database. NT/P82 lies to the south and southeast of the Evans Shoal gas field within the Bonaparte Basin.

 

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Magellan undertook the reprocessing of 2,061 miles of existing 2D seismic data during the first year of the permit and planning has commenced to undertake the acquisition of 62 miles of 2D and 46 square miles of 3D seismic data during the second permit year. Acquisition of the seismic surveys is planned for the first quarter of 2012. At years ended June 30, 2011, MPAL’s share of the work obligations committed for the NT/P82 permit was $1,798,000.

Montana

MPC’s Poplar Field’s sale volumes, net of royalties, were 68 MBbls of oil for the years ended June 30, 2011 or 62% increase in oil sales for the years ended June 30, 2010. The increase is due primarily to the year over year effect of the oil sales related to the Poplar Field assets acquired in October 2009 and March 2010 and a 15% increase in the price per barrel in the United States.

Poplar Fields: On a consolidated basis, MPC, through Nautilus and directly, owned an average 85.7% working interest in the Poplar Fields in Montana as of June 30, 2011.

On September 2 and September 6, 2011, the Company completed transactions to consolidate its working interest in the Poplar Fields and sell 65% of its working interest in the Deep Intervals to VAALCO, respectively, as described above.

The Company has initiated a program in late summer 2011 to undertake seven recompletions along with the completion of the EPU119 drilled last fall into the Charles Formation. Magellan also plans to drill one shallow natural gas well in fall of 2011 to evaluate significant reservoir pressure differentials seen in the shallow gas horizon during the drilling of the EPU119 well.

A second drilling program, including up to three new infill wells in the Charles Formation, is planned for the fall of 2011. Drilling will be based upon the results from the recompletion program with the objective of increased production resulting in increased cash generation amid high oil price netbacks.

Given the complexity of the Poplar reservoir, the Company has completed the first steps of a reservoir engineering study for the Charles Formation. Further work is being conducted to manage and monitor water influx, determine new high potential drilling sites, and to determine the merit of an infill program.

United Kingdom

The Company participated in the Markwells Wood-1 exploration well in PEDL 126, which spud in November 2010. Northern Petroleum is operator of the PEDL 126 joint venture. Markwells Wood-1 well targeted the eastward extension of the Horndean oil field which is currently producing from the Great Oolite Formation. Assessment of the well logs confirmed that the entire Great Oolite reservoir sequence in Markwells Wood-1 is oil-bearing above the Horndean field oil-water contact of 4,446 ft sub-sea level. Northern Petroleum started operations for an extended well test of the Markwells Wood oil discovery in West Sussex, with the arrival of a workover rig on September 6, 2011. The test will enable the joint venture partners to evaluate the potential and scheme for future development of the Markwells Wood oil accumulation.

Magellan has a gross 240,000 acre Weald Basin position in Southern England, U.K., which is a newer, less mature shale play, where Magellan is a 50% partner with Celtique Energie. The Weald Basin shale play is unexplored and is based on the Lower Jurassic (Liassic) shale which lies in both the oil and gas window. There are currently no producing wells in the license area; however, with the recent developments in shale development technology, coupled with the Basin’s proximity to U.K. and NW European oil and gas markets and infrastructure, these licenses are an attractive opportunity for near term development. The Company’s goal is to establish near-term monetization and strategic drilling programs for U.K. shale acreage.

 

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Critical Accounting Estimates

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 Palm Valley, future undiscounted cash flows were based upon the quantities of gas currently committed to the contract and estimated sales subsequent to the contract. If such new contracts are effected, the proved developed reserves will be increased to the lesser of the risk adjusted probable and possible reserves or the newly 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.

Historically, we have adjusted our depletion rates during the year when new reserve information is available. For the year ended June 30, 2010, we adopted the current SEC accounting and disclosure regulations for oil and gas companies effective June 30, 2010. The change in price encompassed in the new SEC rules was a change in accounting principle inseparable from a change in estimate for 2009 and was accounted for prospectively. The price used under the current rules is a 12 month average price on the first day of the month for the 12 month reporting period. The price used in periods prior to fiscal year 2010 was the price on the last day of the reporting period. There was no measurable difference in the two prices and as such there was no material dollar impact caused by the change, for fiscal year 2010.

 

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Nondepletable assets

At June 30, 2011, 2010 and 2009 oil and gas properties include $8.1 million, $4.3 million and $6.6 million, respectively, of capitalized costs that are currently not being depleted pending the determination of proved reserves. Components of these costs are as follows:

 

Nondepletable capitalized costs

   2011     2010     2009  

United Kingdom (1)

      

Balance beginning of year

   $ 3,576,518      $ 3,154,266      $ 2,978,172   

Additions to capitalized costs

     1,703,285        608,479        485,725   

Charged to expense

     35,814        (231,798     (257,519

Exchange adjustment

     (55,892     45,571        (52,112
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 5,259,725      $ 3,576,518      $ 3,154,266   
  

 

 

   

 

 

   

 

 

 

United States (2)

      

Balance beginning of year

   $ 313,710      $ —        $ —     

Additions to capitalized costs

     2,406,210        313,710        —     

Reclassified to producing properties

     (277,417     —          —     

Charged to expense

     (31,934     —          —     
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 2,410,569      $ 313,710      $ —     
  

 

 

   

 

 

   

 

 

 

Australia (3)

      

Balance beginning of year

   $ 415,108      $ 3,486,611      $ 3,852,698   

Assets sold or held for sale

     —          (3,071,503     —     

Charged to expense

     —          —          (63,739

Exchange adjustment

     —          —          (302,348
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 415,108      $ 415,108      $ 3,486,611   
  

 

 

   

 

 

   

 

 

 

Total

      

Balance beginning of year

   $ 4,305,336      $ 6,640,877      $ 6,830,870   

Additions to capitalized costs

     4,109,495        922,189        485,725   

Assets sold or held for sale

     —          (3,071,503     —     

Reclassified to producing properties

     (277,417     —          —     

Charged to expense

     3,880        (231,798     (321,258

Exchange adjustment

     (55,892     45,571        (354,460
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 8,085,402      $ 4,305,336      $ 6,640,877   
  

 

 

   

 

 

   

 

 

 

 

(1) Of this amount, $1.9 million relates to the stepped up value of the U.K. exploration permits and licenses, which was recorded in the 2006 acquisition of the 44.87% remaining interest of MPAL. The step up value of these licenses and permits are evaluated for impairment annually. The balance represents capitalized exploratory well costs, initiated in 2007, pending discovery and production of reserves.
(2) U.S. capitalized exploratory well costs initiated in 2010, pending discovery and production of reserves.
(3) Australia exploration permits and licenses are evaluated annually or when events or changes in circumstances indicate that the carrying value, related to the step up to fair value for the 44.87% remaining interest of MPAL acquired in 2006, may be impaired. During the fiscal year ended June 30, 2010, Cooper Basin assets were sold. Prior costs were capitalized during the fiscal year ended June 30, 2006 and remained capitalized through the date of the sale as the related well had a sufficient quantity of reserves to justify its completion as a producing well.

Goodwill

The aggregate amount of goodwill is $4,695,204 at June 30, 2011 and 2010, of which $4,020,706 is related to the fiscal 2006 acquisition of the 44.87% of MPAL that we did not own at the time and $674,500 is attributable to the October 15, 2009 acquisition of Nautilus.

 

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Goodwill is not amortized but 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 for MPAL related goodwill is June 30 and is October 1 for Nautilus.

Goodwill is tested for impairment using a two-step process.

 

   

Step one — the fair value of each reporting unit is compared to its carrying value in order to identify potential impairment. If the fair value of a reporting unit exceeds the carrying value of its net assets, goodwill is not considered impaired and no further testing is required. If the carrying value of the net assets exceeds the fair value of a reporting unit, potential impairment is indicated and step two of the impairment test is performed in order to determine the implied fair value of the reporting unit’s goodwill and measure the potential impairment loss.

 

   

Step two — when potential impairment is indicated in step one, we compare the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. Determining the implied fair value of goodwill requires a valuation of the reporting unit’s tangible and intangible assets and liabilities in a manner similar to the allocation of the purchase price in a business combination. Any excess of the value of a reporting unit over the amounts assigned to its assets and liabilities is referred to as the implied fair value of goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. At June 30, 2011, Magellan passed step one and therefore the Company concluded step two was not necessary, as no impairment existed.

Determining the fair value of a reporting unit involves the use of significant estimates and assumptions.

We employed the adjusted net assets method to estimate the fair value of MPAL at June 30, 2011. This method entails estimating the fair value of all of MPAL’s balance sheet items as of the valuation date. The Company has utilized the Market Approach, specifically the Similar Transaction Method (“STM”) in order to estimate the fair value of MPAL’s acreage and oil and natural gas reserves (collectively, the “MPAL Reserves”) on the balance sheet. The MPAL Reserves are reflected on the balance sheet as Oil and Gas Properties. This line includes Exploration Phase petroleum properties (i.e. exploratory acreage) and Production Phase petroleum properties (i.e. proved and probable oil and natural gas reserves). In its application of the STM, the Company reviewed publicly available transaction data for the sale of comparable resources in the U.K. and Australia in order to estimate the fair value of MPAL Reserves. 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. No impairment existed as the adjusted fair value exceeded the carrying value by 25%, as of June 30, 2011.

The fair value of our oil properties are estimated using a form of the market approach, which consists of a review of similar transactions that have occurred in the marketplace for proved and risk adjusted probable and possible reserves. Accordingly, we have reviewed implied prices per thousand cubic feet equivalent associated with market-based transactions in similar geographic locations for each of our oil properties, and selected appropriate metrics based on a qualitative comparison between our oil properties and the relevant transactions.

The fair value of our non-depletable exploration permits and licenses is estimated based on a review of similar transactions that have occurred in the marketplace. Accordingly, we have reviewed implied prices per acre associated with market-based transactions in similar geographic locations for our non-depletable exploration permits and licenses, and selected appropriate metrics based on a qualitative comparison between our non-depletable exploration permits and the relevant transactions.

At October 1, 2010, we performed our annual impairment test of the Nautilus goodwill. We employed both the income approach (discounted cash flow method) and the market value approach in estimating the fair value of Nautilus. As of October 1, 2010, no impairment existed as the indicated fair value of Nautilus, based upon our estimate, exceeded its carrying value by 48% as of October 1, 2010.

 

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Asset Retirement Obligations

Legal obligations associated with the retirement of long-lived assets are recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, the 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 being drilled.

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

Income Taxes

The Company follows 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 management believes it is more likely than not that such assets will not be recovered. The current year increase in the valuation allowance is primarily due to a valuation allowance recorded against the Company’s Australian deferred tax assets. In evaluating the ability to recover these deferred tax assets, we considered all available positive and negative evidence, giving greater weight to the recent current loss, the absence of taxable income in the carryback period and the uncertainty regarding our ability to project financial results in future periods. Additionally, consistent with prior periods, the valuation allowance related to the Company’s U.S. and U.K. deferred tax assets increased due to the generation of U.S. net operating losses, U.S. foreign tax credits, tax benefits from U.K. exploration costs and U.K. net operating losses.

The Company evaluates uncertain tax positions, which requires significant judgments and 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 significant uncertain tax positions for fiscal 2011 and 2010.

Business combinations

The Company applies the acquisition method of recording business combinations. Under this method, the Company recognizes and measures the fair value of identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree. Any goodwill or gain is identified and recorded. We engage independent valuation consultants to assist us in determining the fair values of crude oil and natural gas properties acquired, and other third-party consultants as needed to assist us in assessing the fair value of other assets and liabilities assumed. Such valuations require management to make significant estimates and assumptions, especially with respect to the oil and gas properties.

Consolidated Liquidity and Capital Resources

Historically, we have funded our acquisition, exploration and development activities through cash from operations and debt facilities at Nautilus. Magellan’s corporate plan is to add long-term value and growth

 

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through the acquisition and redevelopment of “under-exploited” natural gas and oil reserves.

The Company estimates that its capital expenditures for the fiscal year ending June 30, 2012 to amount to approximately $33.6 million, arising from our operations in the U.S., Australia, and the U.K. of $29.4 million, $2.0 million and $2.2 million, respectively. The Company has complete discretion over the expenditures in the U.S. and will be able to adjust them in accordance with its funding priorities and strategy. The Company intends to fund these capital expenditures with cash on hand and cash flow from operations, including the proceeds received from transactions described in the subsequent events footnote (see Note 20).

Consolidated

The Company on a consolidated basis had approximately $20.4 million of cash and cash equivalents at June 30, 2011 and $33.6 million at June 30, 2010. 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 changes in interest rates. Cash balances were $14.0 million as of June 30, 2011 and the remaining $6.4 million was held in time deposit accounts in several Australian banks that have terms of 90 days or less.

When considering our liquidity and capital resources, we consider cash and cash equivalents since all of these amounts are available to fund operating, exploration and development activities.

The factors favorably impacting our liquidity and capital resources during the year ended June 30, 2011 included:

 

   

effect of exchange rate changes on cash and cash equivalents of $4.2 million.

Factors contributing to a decrease in our liquidity and capital resources during the year ended June 30, 2011 included:

 

   

$10.0 million escrow account deposit paid in February 2011, towards the Evans Shoal Purchase Price; which was refunded in full on July 22, 2011;

 

   

$4.6 million expended for property & equipment and exploration activities; and

 

   

$4.5 million expended for operating activities.

Cash provided by operating activities for the year ended June 30, 2011 decreased $8.4 million from the year ended June 30, 2010 as discussed below:

Cash from oil and gas revenues decreased approximately $12.5 million over the prior year due to the following:

Australian oil and gas sales volume decreased resulting from the sale of our Cooper Basin and Nockatunga assets, natural oil field declines of Mereenie and reduced sales due to the Blacktip Field coming online leading to the end of Mereenie MSA 4 contract in February 2010. This was offset by the receipts generated from MPAL’s portion of the Power and Water Corporation (“PWC”) contract settlement, increased U.S. oil sales and the 12.1% increase in the average foreign exchange rate, as well as a 15% oil price increase over the prior year at Poplar Field.

Operating cash outflows decreased approximately $5.2 million over the prior year due to the following:

 

   

$2.3 million decrease in our accounts payable pay down; and

 

   

$6.1 million decrease in taxes paid due to the expectation that MPAL would have a smaller tax liability.

 

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Offset by,

 

   

$0.9 million increase in salaries and benefits due to the severance payment made to a former officer and the year over year costs associated with the U.S. acquisition of Nautilus in October 2009;

 

   

$0.6 million increase in accounting and legal expense due to the Evans Shoal Transaction;

 

   

$1.6 million increase in exploration costs, primarily due to drilling in the United Kingdom.

The Company invested $4.6 million and $2.8 million in oil and gas exploration activities, which includes additions to property and equipment, during the fiscal years ended June 30, 2011 and 2010, respectively.

Effect of exchange rate changes

The value of the Australian dollar relative to the U.S. dollar increased 24% to $1.0591 at June 30, 2011 compared to a value of $0.8567 at June 30, 2010.

As to MPC

At June 30, 2011 MPC, on an unconsolidated basis, had working capital of $3.5 million. Working capital is comprised of current assets less current liabilities. On August 24, 2011, MPC borrowed $4.0 million from MPAL, this plus MPC’s current cash position will be adequate to meet MPC’s current obligations for the 2012 fiscal year.

As to MPAL

At June 30, 2011, MPAL had working capital of $27.0 million. Despite no SEC defined proved oil reserves, 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 contract for the sale of Palm Valley gas will expire during fiscal year 2012 as does Amadeus Gas Trust revenues ($4.6 million), at June 30, 2011. Future oil revenues will be impacted by any volatility in the world price for crude oil. MPAL will strive to align operating expenses with any reductions in revenues.

On July 21, 2011, Santos and MPAL executed a Release Agreement to (1) terminate the Amended Assets Sale Deed and (2) resolve all outstanding issues relating to the Amended Asset Sales Deed. Under the Release Agreement, MPAL received back the additional A$10.0 million escrow deposit made towards the purchase price stipulated in the Amended Asset Sales Deed plus all interest accrued on that amount from the date of deposit to the date of release and the parties agreed to mutually release each other from all claims arising out of the Amended Asset Sales Deed and the Evans Shoal Transaction. Pursuant to the terms of the Amended Asset Sales Deed, the initial A$15.0 million deposit made towards the purchase price set forth in the Amended Asset Sales Deed was re-classified as non-refundable, and written off at June 30, 2011.

The process of unwinding the Evans Shoal Transaction has allowed the Company and Santos to look at their joint operations in the Northern Territory, Australia. This has lead to productive discussions towards rationalizing and more efficiently exploiting their respective interests in the Amadeus Basin, and creating new commercial opportunities. The Company has concluded their discussions with Santos at the time of this filing. Please refer to Note 20.

As to Nautilus

At June 30, 2011, Nautilus had working capital of $0.3 million. At June 30, 2011, Nautilus has debt comprising a note payable of $1.4 million issued by a bank. In January 2011, Nautilus amended its existing long term debt agreement with the bank to increase its principal amount of indebtedness to $1,710,438 from $441,220. The term of the amended long term debt agreement runs through 2014. Proceeds from the increased debt will be used to finance capital activities. The variable rate of the note is based upon the Wall Street Journal Prime Rate (the index). The index was 3.25% at June 30, 2011, resulting in an interest rate of 6.25% per annum as of June 30, 2011. Under the note payable, Nautilus is subject to both financial and non-financial covenants. The

 

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financial covenant requires that Nautilus maintain a debt service coverage ratio, as defined, of 1.2 to 1.0, which is calculated based on Nautilus’ annual tax return. As of June 30, 2011, based upon its FY 2010 tax return, Nautilus was in compliance with the financial covenant.

The Nautilus’ demand note payable with the same bank is classified as short term debt, which consists of advances under a $1,000,000 business capital line, used by Nautilus, of credit of which there was $500 due on the line at June 30, 2011. This revolving line of credit secures a $25,000 credit card and a $25,000 letter of credit that is in favor of the Bureau of Land Management.

The Company has initiated a program in late summer 2011 to undertake seven recompletions along with the completion of the EPU119 drilled last fall through the Charles Formation. Magellan also plans to drill one shallow natural gas well in fall of 2011 to evaluate significant reservoir pressure differentials seen in the shallow gas horizon during the drilling of the EPU119 well.

A second drilling program, including up to three new infill wells in the Charles Formation, is planned for the fall of 2011. Drilling will be based upon the results from the recompletion program with the objective of increased production resulting in increased cash generation amid high oil price netbacks.

Off Balance Sheet Arrangements

None

Contractual Obligations

The following is a summary of our consolidated contractual obligations at June 30, 2011, in thousands:

 

     TOTAL      LESS THAN
1 YEAR
     1-3 YEARS      3-5 YEARS      MORE THAN
5 YEARS
 

Operating lease obligations

   $ 1,387       $ 514       $ 581       $ 193       $ 99   

Purchase obligations (1)

     4,516         3,056         1,460         —           —     

Asset retirement obligations-undiscounted

     31,934         —           288         —           31,646   

Note payable including interest (2)

     1,541         622         919         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 39,378       $ 4,192       $ 3,248       $ 193       $ 31,745   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Represents firm commitments for exploration and capital expenditures related to MPAL. Firm Commitments decreased $2.7 million offset by a $1.4 million increase caused by a 24% increase in exchange rates over June 30, 2010. The decrease was due to the delay of portions of the U.K. work program. Although the Company is committed to these expenditures, some may be farmed out to third parties. Additional contingent expenditures of $30,463,000 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), $3,621,000 (1-3 years), $26,842,000 (3-5 years), and $0 (greater than 5 years). Contingent expenditures increased $2.7 million over prior years reporting excluding the exchange rate effect.
(2) Includes interest at a 6.25% rate based on the rate at June 30, 2011.

 

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Results of Operations

2011 vs. 2010

REVENUES AND INVESTMENT INCOME

Changes in revenues and investment income are as follows:

 

     TWELVE MONTHS ENDED
June 30,
              
     2011      2010      $ Variance     % Variance  

Oil sales

   $ 11,815,231       $ 9,886,592       $ 1,928,639      $ 20

Gas sales

     1,796,405         13,615,755         (11,819,350     (87 %) 

Other production related revenues

     4,565,241         5,022,210         (456,969     (9 %) 

Investment and other income

     922,774         3,012,831         (2,090,057     (69 %) 

Significant changes are discussed below.

OIL SALES INCREASED — In the U.S., oil sales increased $2,789,000 due to the year over year effect of the sales related to the Poplar Field assets acquired in October 2009 and March 2010 and a 15% increase in the price per barrel in the United States. In Australia, sales decreased due to the sale of the Cooper Basin and Nockatunga Assets ($2,305,000) in fiscal 2010, increased sales in the prior year resulting from de-oiling the Mereenie pipeline, offset by the 12.1% increase in the average exchange rate discussed below and a 17% increase in the price per barrel at Mereenie.

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,               
     2011 SALES      2010 SALES               
     BBLS      AVERAGE PRICE
A.$ PER BBL
     BBLS      AVERAGE PRICE
A.$ PER BBL
     % Variance
BBLS
    % Variance
A.$ PER BBL
 

Australia:

                

Mereenie field

     55,043         99.67         68,344         85.50         (19 %)      17

Cooper Basin

     —           —           1,086         83.62         *        *   

Nockatunga project (1)

     —           —           27,962         73.92         *        *   
  

 

 

       

 

 

         

Total

     55,043            97,392            *        *   
  

 

 

       

 

 

         
     BBLS      AVERAGE PRICE
U.S.$ PER BBL
     BBLS      AVERAGE PRICE
U.S.$ PER BBL
     % Variance
BBLS
    % Variance
U.S.$ PER BBL
 

United States:

                

Poplar Field

     67,859       $ 77.96         42,017       $ 67.88         62     15
  

 

 

       

 

 

         

 

* Not meaningful
(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 in Australia are in Australian dollars to show a more meaningful trend of underlying operations. For the fiscal years ended June 30, 2011 and 2010, the average foreign exchange rates ($AUD to $USD) were .9893 and .8826 respectively.

 

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GAS SALES DECREASED primarily due to the end of Mereenie MSA4 contract in February 2010 ($14,200,000) and the volume decrease at Palm Valley which is according to the Palm Valley Contract, offset by the 12.1% increase in the average exchange rate discussed below and the 1% increase in the average price per MCF received under the Palm Valley contract.

 

     TWELVE MONTHS ENDED June 30,               
     2011 SALES      2010 SALES               
     BCF      AVERAGE PRICE
A.$ PER MCF
     BCF      AVERAGE PRICE
A.$ PER MCF
     % Variance
BCF
    % Variance
A.$ PER MCF
 

Australia: Palm Valley

     0.712         2.28         1.166         2.25         (39 %)      1

Australia: Mereenie

     —           —           2.264         6.53         *        *   
  

 

 

       

 

 

         

Total

     0.712         2.28         3.430         5.07         (79 %)      (55 %) 
  

 

 

       

 

 

         

 

* Not meaningful

OTHER PRODUCTION RELATED REVENUES are primarily MPAL’s share of gas pipeline tariff revenues which decreased as a result of an increase in Amadeus Gas Trust revenues on Blacktip Gas, MPAL’s portion of a PWC contract settlement, offset by the 12.1% increase in the average exchange rate. This revenue stream ended as of June 30, 2011.

INVESTMENT AND OTHER INCOME DECREASED primarily as a result of a $2,065,000 realized gain on the sale of available-for-sale securities in the twelve months ended June 30, 2010.

COSTS AND EXPENSES

Changes in costs and expenses were as follows:

 

     TWELVE MONTHS ENDED
June 30,
             
     2011     2010     $ Variance     % Variance  

Production costs

   $ 9,247,199      $ 10,116,320      $ (869,121     (9 %) 

Exploration and dry hole costs

     2,853,832        1,273,268        1,580,564        124

Salaries and employee benefits

     5,079,503        4,816,350        263,153        5

Depletion, depreciation and amortization

     2,326,817        4,680,240        (2,353,423     (50 %) 

Auditing, accounting and legal services

     2,595,465        1,947,901        647,564        33

Loss on Evans Shoal Deposit

     15,892,650        —          15,892,650        *   

(Gain) loss on sale of assets

     (968,644     (6,817,304     5,848,660        (86 %) 

Impairment loss

     173,401        2,049,616        (1,876,215     (92 %) 

Other administrative expenses

     7,285,549        6,030,583        1,254,966        21

Warrant Expense

     —          (4,276,471     4,276,471        (100 %) 

Income tax provision

     5,141,187        2,645,763        2,495,424        94

 

* Not meaningful

Significant changes are discussed below.

PRODUCTION COSTS DECREASED due to the result of cost reductions efforts (Mereenie & Palm Valley) ($2,840,000) including a new transportation contract at Mereenie, the elimination of prior year pipeline repair costs at Mereenie, and the elimination of production costs related to the Cooper Basin Assets sold in fiscal year 2010 offset by the year over year effect of production costs associated with the U.S. assets acquired in October 2009 and March 2010 ($1,446,000) and the 12.1% increase in the average foreign exchange rate discussed below.

 

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EXPLORATION AND DRY HOLE COSTS INCREASED at MPAL by $1,105,000, which was primarily due to drilling costs in the U.K. and 12.1% increase in the average foreign exchange rate discussed below. In the U.S., the $476,000 increase is associated with the U.S. assets acquired in October 2009 and March 2010.

SALARIES AND EMPLOYEE BENEFITS INCREASED due to current year severance payments in the U.S. to a former officer ($567,000) plus additional headcount, the year over year costs associated with the U.S. acquisition in October 2009 ($194,000), non-cash employee stock based compensation ($212,000) and the 12.1% increase in the average foreign exchange rate discussed below, offset by payment of employee termination costs in Australia in the prior year.

DEPLETION, DEPRECIATION AND AMORTIZATION DECREASED primarily because MPAL’s Australia oil and gas assets were fully depleted as of September 30, 2010, resulting in reduced depletion for MPAL activity in the current year, offset by the costs associated with the U.S. assets acquired in October 2009 and March 2010 not present in the first three months of the twelve months ended June 30, 2010, and the 12.1% increase in the average foreign exchange rate discussed below.

AUDITING, ACCOUNTING AND LEGAL COSTS INCREASED primarily due to costs associated with the Evans Shoal transaction.

LOSS ON EVANS SHOAL DEPOSIT relates to the non-refundable deposit paid by MPAL to Santos as part of the Evans Shoal Transaction (See Note 12).

GAIN ON SALE OF ASSETS is mostly due to the sale of non-core assets that occurred primarily in the prior fiscal year. For more information on these sales please refer to Note 10 of our Form 10-K, Sale of Cooper Basin Assets footnote for the period ended June 30, 2010.

IMPAIRMENT LOSS relates to MPAL’s loss on Udacha assets in the prior fiscal year and two remaining permits of the asset sale in the current year (See Notes 1 and 4).

OTHER ADMINISTRATIVE EXPENSES INCREASED primarily due to increased consulting fees at MPAL related to the Evans Shoal transaction, and 12.1% increase in the average foreign exchange rate discussed below.

WARRANT EXPENSE in the prior year relates entirely to the recording of the fair market value of certain warrants as discussed in our Form 10-K for the period ended June 30, 2010. The terms of the warrants were revised in March 2010 such that they are no longer carried at fair value.

INCOME TAX PROVISION INCREASED primarily due to net operating losses incurred in the current tax year that do not generate a corresponding tax benefit and the additional $7.0 million valuation allowance recorded against our Australian deferred tax assets. Deferred tax assets are recognized for the expected future tax consequences of temporary differences between the financial reporting and tax bases of assets and liabilities, and for operating losses and tax credit carryforwards. A valuation allowance reduces deferred tax assets to estimated realizable value, which assumes that it is more likely than not that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the net carrying value. We review our deferred tax assets and valuation allowance on a quarterly basis. As part of our review, we consider positive and negative evidence, including cumulative results in recent years. As a result of our review for the quarter ended June 30, 2011, we provided for a full valuation allowance against our Australian deferred tax assets, in addition to our $7.0 million valuation allowance previously recorded against our U.S. deferred tax assets. This resulted in a material income tax charge.

We anticipate we will continue to record a valuation allowance against the losses of these jurisdictions until such time as we are able to determine it is “more-likely-than-not” the deferred tax asset will be realized. Such

 

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position is dependent on whether there will be sufficient future taxable income to realize such deferred tax assets. (see Note 7)

EXCHANGE EFFECT — the value of the Australian dollar relative to the U.S. dollar increased to 1.0591 at June 30, 2011 compared to a value of .8567 at June 30, 2010. This resulted in an $9,307,710 debit to the foreign currency translation adjustments account for the twelve months ended June 30, 2011. The average exchange rate used to translate MPAL’s operations in Australia was .9893 for the the twelve months ended June 30, 2011, which was an 12.1% increase compared to the .8826 rate for the the twelve months ended June 30, 2010.

2010 vs. 2009

REVENUES AND INVESTMENT INCOME

Changes in revenues and investment income are as follows:

 

     TWELVE MONTHS ENDED
June 30,
              
     2010      2009      $ Variance     % Variance  

Oil sales

   $ 9,886,592       $ 11,479,660       $ (1,593,068   $ (14 %) 

Gas sales

     13,615,755         14,740,296         (1,124,541     (8 %) 

Other production related revenues

     5,022,210         1,970,621         3,051,589        155

Investment and other income

     3,012,831         1,583,065         1,429,766        90

Significant changes are discussed below.

OIL SALES DECREASED in Australia due to a 36% decrease in volume due to the sale of Cooper Basin assets and a 10% decrease in average price per barrel partially offset by the U.S. purchase of a controlling member interest in Nautilus Poplar, LLC and an 18% increase 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,               
     2010 SALES      2009 SALES               
     BBLS      AVERAGE PRICE
$ PER BBL
     BBLS      AVERAGE PRICE
$ PER BBL
     % Variance
BBLS
    % Variance
$ PER BBL
 

Australia (AUD):

                

Mereenie field

     68,344       $ 85.50         90,267       $ 94.20         (24 %)      (9 %) 

Cooper Basin

     1,086         83.62         2,362         101.42         (54 %)      (18 %) 

Nockatunga project (1)

     27,962         73.92         60,668         86.30         (54 %)      (14 %) 
  

 

 

       

 

 

         

Total

     97,392            153,297            (36 %)      (10 %) 
  

 

 

       

 

 

         
     BBLS      AVERAGE PRICE
$ PER BBL
     BBLS      AVERAGE PRICE
$ PER BBL
     % Variance
BBLS
    % Variance
$ PER BBL
 

United States:

                

Poplar Field (1)

     42,017         67.88         —           —           100     100
  

 

 

       

 

 

         

 

(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 in Australia are in Australian dollars to show a more meaningful trend of underlying operations. For the fiscal years ended June 30, 2010 and 2009, the average foreign exchange rates were .8826 and .7471 respectively.

 

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GAS SALES DECREASED due to a 34% decrease in volume resulting from natural field decline and significantly reduced sales to PWC. PWC’s most recent advisory to the Meerenie Producers (Magellan and Santos) states that Meerenie gas is no longer required, other than the reasonable endeavors obligation under the MSA No. 4 agreement to supply certain of PWC’s requirements on request through September 5, 2010. For further information, see “Gas Supply Contracts” in Item 1 — Business and Item 7 — Management’s Discussion and Analysis — Executive Summary, the decrease is partially offset by the 18% increase in the average exchange rate discussed below and by a 43% 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,               
     2010 SALES      2009 SALES               
     BCF      AVERAGE PRICE
AUD $ PER MCF
     BCF      AVERAGE PRICE
AUD $ PER MCF
     % Variance
BCF
    % Variance
AUD $ PER MCF
 

Australia: Palm Valley

     1.166         2.25         1.165         2.25         —       —  

Australia: Mereenie

     2.264         6.53         3.996         3.93         (43 %)      66
  

 

 

       

 

 

         

Total

     3.430         5.07         5.161         3.54         (34 %)      43
  

 

 

       

 

 

         

OTHER PRODUCTION RELATED REVENUES are primarily MPAL’s share of gas pipeline tariff revenues which increased as a result of an increase in Amadeus Gas Trust revenues on Blacktip Gas. MPAL’s portion of a PWC contract settlement, and the 18% increase in average exchange rate.

INVESTMENT AND OTHER INCOME increased primarily due to an investment gain.

COSTS AND EXPENSES

Changes in costs and expenses were as follows:

 

     TWELVE MONTHS ENDED
June 30,
              
           2010                 2009            $ Variance     % Variance  

Production costs

     10,116,320        8,153,263         1,963,057        24

Exploration and dry hole costs

     1,273,268        3,475,937         (2,202,669     (63 %) 

Salaries and employee benefits

     4,816,350        1,708,997         3,107,353        182

Depletion, depreciation and amortization

     4,680,240        6,785,952         (2,105,712     (31 %) 

Auditing, accounting and legal services

     1,947,901        1,576,509         371,392        24

Accretion expense

     748,209        531,405         216,804        41

(Gain) Loss on sale of assets

     (6,817,304     12,072         (6,829,376     (56,572 %) 

Impairment loss

     2,049,616        63,740         1,985,876        3,116

Other administrative expenses

     6,030,583        3,018,200         3,012,383        100

Foreign transaction (gain) loss

     676,601        951,458         (274,857     (29 %) 

Warrant Expense

     4,276,471        —           4,276,471        *   

Income tax provision

     2,645,763        2,198,422         447,341        20

 

* Not meaningful

Significant changes are discussed below.

PRODUCTION COSTS INCREASED due primarily to the acquisition of a controlling member interest in the Poplar Fields ($1,446,000) along with the 18% increase in the average exchange rate described below partially offset by the sale of the Cooper Basin assets (see Note 10).

EXPLORATION AND DRY HOLE COSTS DECREASED primarily due to prior year’s cost of ($300,000) related to the write down of the value of U.K. exploration licenses, seismic survey costs related to the Nockatunga fields ($1.6 million), and the sale of Cooper Basin assets (see Note 10). These costs are partially offset by the 18% increase in the average exchange rate described below.

 

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SALARIES AND EMPLOYEE BENEFITS INCREASED mostly due to the payment of employee termination costs ($883,000) at MPAL, non cash expense related to awarded of employee stock options ($1,400,000), the addition of new personnel at MPC ($338,000), the Nautilus acquisition ($331,000) and the 18% increase in the average exchange rate.

DEPLETION, DEPRECIATION AND AMORTIZATION DECREASED due to lower depletable costs related to the Cooper Basin assets sales (see Note 10), partially offset by the 18% increase in the average exchange rate described below and the acquisition of Nautilus ($448,000).

AUDITING, ACCOUNTING AND LEGAL SERVICES INCREASED due mostly to legal and accounting costs associated with the Nautilus acquisition, consulting fees related to the Evans Shoal transaction, and the 18% increase in the average exchange rate discussed below.

ACCRETION EXPENSE INCREASED due mostly to the controlling member interest in the Poplar Fields ($70,000) along with the 18% increase in the average exchange rate.

(GAIN) LOSS ON THE SALE OF ASSETS INCREASED due to the 2010 gain recorded on the sale of MPAL’S Cooper Basin assets ($6.8 million) (see Note 10).

IMPAIRMENT LOSS INCREASED due mostly to the impairment loss recorded on MPAL’s Udacha, Dingo and some UK assets (see Note 4).

OTHER ADMINISTRATIVE EXPENSES INCREASED due to costs relating to the July 2009 closing of the YEP equity-investment ($440,000), increased travel costs ($308,000), increased directors’ fees including the addition of three new directors ($250,000), Board of Director stock options ($103,000), Board of Directors Restricted Stock ($405,000), increased consulting costs ($725,000), closing costs for the Nautilus acquisition ($138,000) and the 18% increase in the average exchange rate described below.

FOREIGN TRANSACTION (GAIN) LOSS account represents transaction gains and losses that result from the translation of cash accounts held in foreign currencies.

WARRANT EXPENSE INCREASED (non-cash) due entirely to the increase in the fair value of the YEP warrants, which was driven by increases in the Company’s stock price. These warrants did not exist in 2009.

INCOME TAX PROVISION INCREASED due to the taxability in the U.S. of intercompany dividends which were not completely offset by available net operating loss carry forwards and nondeductible warrant and stock related compensation, offset by a decrease in Australian taxes due to the non-taxability of certain capital receipts (see Note 7). The effective tax rate of 223% results from the fact that MPC book losses do not generate a corresponding tax benefit because the taxable intercompany dividends and the nondeductible warrant and stock related compensation exceed book losses and thus create taxable income.

EXCHANGE EFFECT — the value of the Australian dollar relative to the U.S. dollar increased to $.8567 at June 30, 2010 compared to $.8048 at June 30, 2009. This resulted in a $1,358,464 credit to accumulated translation adjustments for fiscal 2010. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2010 was $.8826, which is an 18% increase compared to the $.7471 rate for fiscal 2009.

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

The Company’s exposure to market risk relates to fluctuations in foreign currency and world prices for crude oil, as well as market risk related to investment in marketable securities. The exchange rates between the Australian dollar and the U.S. dollar, as well as the exchange rates between the U.S. dollar and the British pound, have changed in recent periods and may fluctuate substantially in the future. Any appreciation of the U.S. dollar

 

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against the Australian dollar is likely to have a positive 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 British pound. Accordingly, any material appreciation of the British pound against the Australian and U.S. dollars could have a negative impact on our business, operating results and financial condition. 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 approximately $1.8 million and $3.6 million, respectively, for the twelve months ended June 30, 2011.

For the twelve months ended June 30, 2011, oil sales represented approximately 87% of total oil and gas revenues. Based on the current twelve month’s sales volume and revenues, a 10% change in oil price would increase or decrease oil revenues by $1.2 million. Gas sales, which represented approximately 13% of total oil and gas revenues in the current twelve months, are derived primarily from the Palm Valley Field 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 for the twelve months ended June 30, 2011.

At June 30, 2011, the carrying value of cash and cash equivalents was approximately $20.4 million, which approximates the fair value.

 

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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

Portland, Maine

We have audited the accompanying consolidated balance sheets of Magellan Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2011 and 2010, and the related consolidated statements of operations, changes in equity and comprehensive loss, and cash flows for each of the three years in the period ended June 30, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, on June 30, 2010, the Company adopted Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation and Disclosures”.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of June 30, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated September 20, 2011 expressed an adverse opinion on the Company’s internal control over financial reporting because of material weaknesses.

/s/ Deloitte & Touche LLP

Hartford, Connecticut

September 20, 2011

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

 

     June 30,
2011
    June 30,
2010
 
ASSETS     

Current assets:

    

Cash and cash equivalents

   $ 20,416,625      $ 33,591,534   

Accounts receivable — trade (net of allowance for doubtful accounts of $66,702 and $95,912 at June 30, 2011 and at June 30, 2010 respectively)

     4,356,621        4,427,245   

Accounts receivable — working interest partners

     453,843        204,630   

Deposit on Evans Shoal

     10,745,061        —     

Securities available-for-sale (at fair value)

     —          192,417   

Inventories

     731,672        815,179   

Deferred income taxes

     —          189,236   

Assets held for sale

     —          648,217   

Prepaid assets

     517,482        478,665   

Other assets

     61,934        1,223,426   
  

 

 

   

 

 

 

Total current assets

     37,283,238        41,770,549   
  

 

 

   

 

 

 

Deferred income taxes

     —          5,262,649   

Securities available-for-sale (at fair value)

     238,070        —     

Deposit on Evans Shoal

     —          12,850,500   

Property and equipment, net:

    

Oil and gas properties (successful efforts method)

     138,576,622        113,646,852   

Land, buildings and equipment

     4,088,759        3,328,670   

Field equipment

     6,390,383        5,843,939   
  

 

 

   

 

 

 
     149,055,764        122,819,461   

Less accumulated depletion, depreciation and amortization

     (119,901,581     (96,905,478
  

 

 

   

 

 

 

Net property and equipment

     29,154,183        25,913,983   

Goodwill

     4,695,204        4,695,204   

Other assets

     204,457        213,500   
  

 

 

   

 

 

 

Total assets

   $ 71,575,152      $ 90,706,385   
  

 

 

   

 

 

 
LIABILITIES AND EQUITY     

Current liabilities:

    

Accounts payable

   $ 3,860,919      $ 2,387,857   

Accrued liabilities

     2,056,717        2,064,979   

Demand notes payable

     500        470,000   

Current portion of note payable

     552,000        451,585   

Liability related to assets held for sale

     —          194,465   

Deferred income taxes

     —          83,400   

Income taxes payable

     —          460,617   
  

 

 

   

 

 

 

Total current liabilities

     6,470,136        6,112,903   
  

 

 

   

 

 

 

Long term liabilities:

    

Deferred income taxes

     —          1,157,735   

Note payable

     870,438        232,430   

Other long term liabilities

     309,758        92,577   

Asset retirement obligations

     11,397,410        9,292,556   
  

 

 

   

 

 

 

Total long term liabilities

     12,577,606        10,775,298   
  

 

 

   

 

 

 

Commitments and contingencies (Note 16)

     —          —     

Equity:

    

Common stock, par value $.01 per share: Authorized 300,000,000 shares, outstanding, 52,455,977 and 52,335,977 at June 30, 2011 and June 30, 2010 respectively

     524,558        523,358   

Capital in excess of par value

     93,617,424        91,905,062   

Preferred stock, par value $.01 per share: Authorized 50,000,000 and 0 shares, outstanding, none at June 30, 2011 and at June 30, 2010 respectively

     —          —     

Accumulated deficit

     (56,073,255     (23,640,191

Accumulated other comprehensive income

     12,469,626        3,116,263   
  

 

 

   

 

 

 

Total equity attributable to Magellan Petroleum Corporation

     50,538,353        71,904,492   

Non-controlling interest in subsidiaries

     1,989,057        1,913,692   
  

 

 

   

 

 

 

Total equity

     52,527,410        73,818,184   
  

 

 

   

 

 

 

Total liabilities and equity

   $ 71,575,152      $ 90,706,385   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

Three Years Ended June 30, 2011

 

     Years Ended June 30,  
     2011     2010     2009  

Revenues:

      

Oil sales

   $ 11,815,231      $ 9,886,592      $ 11,479,660   

Gas sales

     1,796,405        13,615,755        14,740,296   

Other production related revenues

     4,565,241        5,022,210        1,970,621   
  

 

 

   

 

 

   

 

 

 

Total revenues

     18,176,877        28,524,557        28,190,577   
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

      

Production costs

     9,247,199        10,116,320        8,153,263   

Exploration and dry hole costs

     2,853,832        1,273,268        3,475,937   

Salaries and employee benefits

     5,079,503        4,816,350        1,708,997   

Depletion, depreciation and amortization

     2,326,817        4,680,240        6,785,952   

Auditing, accounting and legal services

     2,595,465        1,947,901        1,576,509   

Accretion expense

     563,628        748,209        531,405   

Loss on Evans Shoal Deposit

     15,892,650        —          —     

Shareholder communications

     396,092        551,408        633,112   

(Gain) loss on sale of assets

     (968,644     (6,817,304     12,072   

Impairment loss

     173,401        2,049,616        63,740   

Other administrative expenses

     7,285,549        6,030,583        3,018,200   

Foreign transaction loss

     950,671        676,601        951,458   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

     46,396,163        26,073,192        26,910,645   
  

 

 

   

 

 

   

 

 

 

Operating (loss) income

     (28,219,286     2,451,365        1,279,932   

Warrant expense

     —          (4,276,471     —     

Investment and other income

     922,774        3,012,831        1,583,065   
  

 

 

   

 

 

   

 

 

 

(Loss) income before income taxes

     (27,296,512     1,187,725        2,862,997   

Income tax provision

     5,141,187        2,645,763        2,198,422   
  

 

 

   

 

 

   

 

 

 

Net (loss) income

     (32,437,699     (1,458,038     664,575   

Less net (loss) income attributable to non-controlling interest in subsidiaries

     (4,635     (10,766     —     
  

 

 

   

 

 

   

 

 

 

Net (loss) income attributable to Magellan Petroleum Corporation

   $ (32,433,064   $ (1,447,272   $ 664,575   
  

 

 

   

 

 

   

 

 

 

Average number of shares of common stock

      

Basic and Dilutive

     52,398,936        51,410,596        41,500,325   
  

 

 

   

 

 

   

 

 

 

Net (loss) income per basic and dilutive common shares attributable to Magellan Petroleum Corporation common shareholders

   $ (0.62   $ (0.03   $ 0.02   

The accompanying notes are an integral part of these consolidated financial statements

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY AND COMPREHENSIVE LOSS

Three Years Ended June 30, 2011

 

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

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 and stock based 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     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Net loss

    —          —          —          (1,447,272     —          (10,766     (1,458,038     (1,458,038

Foreign currency translation adjustments

    —          —          —          —          1,358,464        —          1,358,464        1,358,464   

Unrealized holding gains, net of taxes

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

Stock and stock based compensation

    440,000        4,400        2,301,352        —          —          —          2,305,752     

Equity investment YEP

    8,695,652        86,957        7,527,870        —          —          —          7,614,827     

Warrants issued

    —          —          6,401,765        —          —          —          6,401,765     

Nautilus acquisition

    1,700,000        17,000        2,363,000        —          —          1,924,458        4,304,458     

Total comprehensive loss

    —          —          —          —          —          —          —          (321,538
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

June 30, 2010

    52,335,977        523,358        91,905,062        (23,640,191     3,116,263        1,913,692        73,818,184     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Net loss

    —          —          —          (32,433,064     —          (4,635     (32,437,699     (32,437,699

Foreign currency translation adjustments

    —          —          —          —          9,307,710        —          9,307,710        9,307,710   

Unrealized holding gains, net of taxes

    —          —          —          —          45,653        —          45,653        45,653   

Stock and stock based compensation

    90,000        900        1,669,162        —          —          —          1,670,062     

Stock options exercised

    30,000        300        43,200        —          —          —          43,500     

Capital contribution

              80,000        80,000     

Total comprehensive loss

    —          —          —          —          —            —          (23,084,336
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

June 30, 2011

    52,455,977        524,558        93,617,424        (56,073,255     12,469,626        1,989,057        52,527,410     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

The accompanying notes are an integral part of these consolidated financial statements

 

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Years Ended June 30,  
     2011     2010     2009  

Operating Activities:

      

Net (loss) income

   $ (32,437,699   $ (1,458,038   $ 664,575   

Adjustments to reconcile net loss to net cash (used in) provided by operating activities:

      

Depletion, depreciation and amortization

     2,326,817        4,680,240        6,785,952   

Write off of Evans Shoal deposit

     15,892,650        —          —     

Interest earned on restricted deposits

     (149,961     —          —     

Accretion expense

     563,628        748,209        531,405   

Deferred income taxes

     5,354,748        921,934        (1,618,033

Foreign transaction loss (1)

     498,957        732,091        951,458   

(Gain) loss from disposal of assets

     (968,644     (6,817,304     12,072   

(Gain) from sale of investments

     —          (1,975,286     —     

Exploration and dry hole costs

     (123,970     —          5,765   

Write off of exploration permits

     66,098        —          359,471   

Impairment loss

     173,401        2,049,616        —     

Stock-based compensation and change in warrant valuation

     1,670,062        6,582,223        94,932   

Change in operating assets and liabilities:

      

Accounts receivable

     622,779        2,734,772        1,270,721   

Inventories

     142,745        646,986        203,312   

Other assets

     212,894        (105,952     65,531   

Accounts payable and accrued liabilities

     613,981        (1,689,063     1,793,486   

Income taxes payable (receivable)

     1,044,968        (3,097,915     (930,137
  

 

 

   

 

 

   

 

 

 

Net cash (used in) provided by operating activities (1)

     (4,496,546     3,952,513        10,190,510   
  

 

 

   

 

 

   

 

 

 

Investing Activities:

      

Additions to property and equipment

     (729,849     (2,276,128     (2,430,184

Oil and gas exploration activities

     (3,837,775     (567,343     (491,490

Proceeds from sale of assets

     1,481,172        7,280,402        27,728   

Purchase of working interest in Poplar Field

     (380,000     (4,090,170     —     

Deposit for purchase of Evans Shoal

     (10,013,500     (13,751,850     —     

Proceeds from sale of securities available for sale

     —          9,615,215        —     

Purchase of securities available for sale

     —          (7,259,082     (559,850

Proceeds from sale of securities

     —          465,004        —     

Marketable securities matured or sold

     6,999,735        7,194,090        3,109,611   

Marketable securities purchased

     (6,999,735     (6,196,784     (2,398,695

Purchase of controlling interest — Nautilus Poplar LLC

     —          (7,309,113     —     

Cash acquired-purchase of Nautilus Poplar LLC

     —          314,727        —     

Increase in restricted cash

     —          (75,444     —     
  

 

 

   

 

 

   

 

 

 

Net cash (used) in investing activities

     (13,479,952     (16,656,476     (2,742,880
  

 

 

   

 

 

   

 

 

 

Financing Activities:

      

Proceeds from issuance of stock

     43,500        10,000,000        —     

Proceeds from borrowings

     5,027,323        570,000        —     

Debt principal payments

     (4,589,053     (845,147     —     

Non-controlling Capital Contribution — Nautilus Poplar LLC

     80,000        —          —     

Equity issuance costs

     —          —          (259,879
  

 

 

   

 

 

   

 

 

 

Net cash by (used in) provided by financing activities

     561,770        9,724,853        (259,879
  

 

 

   

 

 

   

 

 

 

Effect of exchange rate changes on cash and cash equivalents (1)

     4,239,819        1,881,802        (7,114,137
  

 

 

   

 

 

   

 

 

 

Net increase in cash and cash equivalents

     (13,174,909     (1,097,308     73,614   

Cash and cash equivalents at beginning of period

     33,591,534        34,688,842        34,615,228   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of year

   $ 20,416,625      $ 33,591,534      $ 34,688,842   
  

 

 

   

 

 

   

 

 

 

Cash Payments:

      

Income taxes

     (1,258,529     4,821,744        4,746,589   

Interest Paid, net of amount capitalized

     140,656        62,300        —     

Supplemental Schedule of Noncash Investing and Financing Activities:

      

Unrealized holding gain (loss)

     45,652        —          344,074   

Revision to estimate of asset retirement obligations

     (128,805     (2,231,849     (625,962

Accounts payable related to property and equipment

     7,852        48,029        163,457   

 

(1) See Note 2 for explanation of Restatement of Prior Period Amount

The accompanying notes are an integral part of these consolidated financial statements

 

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1. Summary of Significant Accounting Policies

Principles of Consolidation

Magellan Petroleum Corporation (the “Company” or “Magellan” or “MPC” or “we” or “us”) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2011, MPC had three reporting segments: (1) the 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) and thirteen licenses in the United Kingdom, five of which are operating licenses. Both the Mereenie and Palm Valley fields are located in the Amadeus Basin in the Northern Territory of Australia; (2) an 83.5% controlling member interest in Nautilus Poplar, LLC (“Nautilus”), based in Denver, Colorado and (3) MPC the parent company, which owns directly a 28.3% working interest in the Poplar Fields in Montana. On a consolidated basis, MPC through Nautilus owned an average 85.7% working interest in the Poplar Fields in Montana as of June 30, 2011.

During the year ended June 30, 2010, MPC added to its holdings, its 83.5% controlling member interest in Nautilus and a 26.3% average working interest in the Poplar fields. During the year ended June 30, 2011, MPC added an additional 2% to its working interest giving MPC 85.7% of the total working interest of the consolidated group in the Poplar Field.

Nautilus, based in Denver, Colorado, operates and holds a 68.75% interest in the East Poplar Unit and varied interests averaging 57% in the Northwest Poplar Field in Montana, USA.

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 subsidiaries, MPAL and Nautilus, (collectively the “Company”). All intercompany transactions have been eliminated.

Reclassification

Certain reclassifications of prior period data included in the accompanying Consolidated Statement of Operations and Consolidated Balance Sheets have been made to conform to current financial statement presentation. Foreign currency exchange (gains) losses of $676,601 and $951,458 for the twelve months ended June 30, 2010 and June 30, 2009, respectively, were reclassified from other administrative expenses to foreign transaction losses on the consolidated statements of operations. This reclassification did not impact previously reported operating or net income. Prepaid assets of $478,665 at June 30, 2010 were reclassified from other current assets.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) 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.

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

 

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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 the MPAL deliveries are included in production costs. Revenue under carried interest agreements is recorded in the period when the net proceeds become receivable, measurable and collection is reasonably assured. The time when the net revenues become receivable and collection is reasonably assured depends on the terms and conditions of the relevant agreements and the practices followed by the operator. Other production revenues for the twelve months ended June 30, 2010 also included MPAL’s share of Power and Water Corporation (PWC) contract settlement for a breach in their gas contracts in the amount of $1.0 million.

Trade receivables

Collectability of trade receivables is reviewed on an ongoing basis. Receivables which are known to be uncollectible are written off by reducing the carrying amount directly. An allowance for doubtful accounts is used when there is objective evidence that the Company will not be able to collect all amounts due, according to the original terms of the related sales. Significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganization, and default or delinquency in payments are considered indicators that the trade receivable is not collectable. The amount of bad debt expense is recognized in the income statement within other administrative expenses. When a trade receivable, for which an allowance had been recognized, becomes uncollectible in a subsequent period, it is written off against the allowance account. Subsequent recoveries of amounts previously written off are credited against other administrative expenses in the consolidated statement of operations.

Preferred Stock

On December 8, 2010, shareholders approved an amendment to the Company’s Restated Certificate of Incorporation to authorize a class of 50,000,000 shares of preferred stock, par value of $0.01 per share (“Preferred Stock”). Pursuant to the amendment, shares of Preferred Stock may be issued in one or more series of any number of shares as determined by the Company’s Board of Directors (“Board”). The Board may fix the voting powers of such series and the designations, preferences, relative, participating, optional or other special rights, and the qualifications, limitations or restrictions thereof (including such series’ redemption rights, dividend rights, liquidation preferences, and conversion rights). As of June 30, 2011, no preferred shares have been issued.

Stock-Based Compensation

The Company has one stock incentive plan which was amended on December 8, 2010 to increase the aggregate number of shares issuable under the plan to 7,205,000. The costs resulting from all share-based payment transactions are recognized in the consolidated financial statements. GAAP establishes fair value as the measurement objective in accounting for share-based payments 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. 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 6 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 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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Concentration of Credit Risk

The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents. The Company places its cash and cash equivalents with reputable financial institutions. At times, balances deposited may exceed FDIC insured limits. The Company has not incurred any losses related to these deposits.

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 for gas, except in the case of Palm Valley proved gas, which is based in contracted volumes. At June 30, 2011, Mereenie had no gas contracts, thus no gas reserves. For Palm Valley, reserves were based upon the quantities of gas committed to the existing 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, 2011, 2010 and 2009 oil and gas properties include $8.1 million, $4.3 million and $6.6 million, respectively, of capitalized costs that are currently not being depleted pending the determination of proved reserves. Components of these costs are as follows:

 

Nondepletable capitalized assets

   2011     2010     2009  

United Kingdom (1)

      

Balance beginning of year

   $ 3,576,518      $ 3,154,266      $ 2,978,172   

Additions to capitalized costs

     1,703,285        608,479        485,725   

Assets sold or held for sale

     —          —          —     

Reclassified to producing properties

     —          —          —     

Charged to expense

     35,814        (231,798     (257,519

Exchange adjustment

     (55,892     45,571        (52,112
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 5,259,725      $ 3,576,518      $ 3,154,266   
  

 

 

   

 

 

   

 

 

 

United States (2)

      

Balance beginning of year

   $ 313,710      $ —        $ —     

Additions to capitalized costs

     2,406,210        313,710        —     

Assets sold or held for sale

     —          —          —     

Reclassified to producing properties

     (277,417     —          —     

Charged to expense

     (31,934     —          —     

Exchange adjustment

     —          —          —     
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 2,410,569      $ 313,710      $ —     
  

 

 

   

 

 

   

 

 

 

Australia (3)

      

Balance beginning of year

   $ 415,108      $ 3,486,611      $ 3,852,698   

Additions to capitalized costs

     —          —          —     

Assets sold or held for sale

     —          (3,071,503     —     

Reclassified to producing properties

     —          —          —     

Charged to expense

     —          —          (63,739

Exchange adjustment

     —          —          (302,348
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 415,108      $ 415,108      $ 3,486,611   
  

 

 

   

 

 

   

 

 

 

Total

      

Balance beginning of year

   $ 4,305,336      $ 6,640,877      $ 6,830,870   

Additions to capitalized costs

     4,109,495        922,189        485,725   

Assets sold or held for sale

     —          (3,071,503     —     

Reclassified to producing properties

     (277,417     —          —     

Charged to expense

     3,880        (231,798     (321,258

Exchange adjustment

     (55,892     45,571        (354,460
  

 

 

   

 

 

   

 

 

 

Balance end of year

   $ 8,085,402      $ 4,305,336      $ 6,640,877   
  

 

 

   

 

 

   

 

 

 

 

(1) Of this amount, $1.9 million relates to the stepped up value of the U.K exploration permits and licenses, which was recorded in the 2006 acquisition of the 44.87% remaining interest of MPAL. The step up value of these licenses and permits are evaluated annually. The balance represents capitalized exploratory well costs, initiated in 2007, pending discovery and production of reserves.
(2) U.S. capitalized exploratory well costs initiated in 2010, pending discovery and production of reserves.
(3) The balance at June 30, 2011 relates to an exploration permit held by MPAL related to step up to fair value for the 44.87% remaining interest of MPAL acquired in 2006, which is evaluated for impairment annually or when events or changes in circumstances indicate. During the fiscal year ended June 30, 2010, Cooper Basin assets were sold. Prior costs were capitalized during the fiscal year ended June 30, 2006 and remained capitalized through the date of the sale as the related well had a sufficient quantity of reserves to justify its completion as a producing well.

 

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Goodwill

The aggregate amount of goodwill is $4,695,204 at June 30, 2011 and 2010, of which $4,020,706 is related to the fiscal 2006 acquisition of the 44.87% of MPAL that we did not own at the time and $674,500 is attributable to the October 15, 2009 acquisition of Nautilus.

Goodwill is not amortized but 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 for MPAL related goodwill is June 30 and is October 1 for Nautilus.

Goodwill is tested for impairment using a two-step process.

 

   

Step one — the fair value of each reporting unit is compared to its carrying value in order to identify potential impairment. If the fair value of a reporting unit exceeds the carrying value of its net assets, goodwill is not considered impaired and no further testing is required. If the carrying value of the net assets exceeds the fair value of a reporting unit, potential impairment is indicated and step two of the impairment test is performed in order to determine the implied fair value of the reporting unit’s goodwill and measure the potential impairment loss.

 

   

Step two — when potential impairment is indicated in step one, we compare the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. Determining the implied fair value of goodwill requires a valuation of the reporting unit’s tangible and intangible assets and liabilities in a manner similar to the allocation of the purchase price in a business combination. Any excess of the value of a reporting unit over the amounts assigned to its assets and liabilities is referred to as the implied fair value of goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. At June 30, 2011, Magellan passed step one and therefore the Company concluded step two was not necessary, as no impairment existed.

Determining the fair value of a reporting unit involves the use of significant estimates and assumptions.

We employed the adjusted net assets method to estimate the fair value of MPAL at June 30, 2011. This method entails estimating the fair value of all of MPAL’s balance sheet items as of the valuation date. The Company has utilized the Market Approach, specifically the Similar Transaction Method (“STM”) in order to estimate the fair value of MPAL’s acreage and oil and natural gas reserves (collectively, the “MPAL Reserves”) on the balance sheet. The MPAL Reserves are reflected on the balance sheet as Oil and gas Properties. This line includes Exploration Phase petroleum properties (i.e. exploratory acreage) and Production Phase petroleum properties (i.e. proved and probable oil and natural gas reserves). In its application of the STM, the Company reviewed publicly available transaction data for the sale of comparable resources in the U.K. and Australia in order to estimate the fair value of MPAL Reserves. 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. No impairment existed as the adjusted fair value exceeded the carrying value as of June 30, 2011.

The fair value of our oil properties are estimated using a form of the market approach, which consists of a review of similar transactions that have occurred in the marketplace for proved and risk adjusted probable and possible reserves. Accordingly, we have reviewed implied prices per thousand cubic feet equivalent associated with market-based transactions in similar geographic locations for each of our oil properties, and selected appropriate metrics based on a qualitative comparison between our oil properties and the relevant transactions.

The fair value of our non-depletable exploration permits and licenses is estimated based on a review of similar transactions that have occurred in the marketplace. Accordingly, we have reviewed implied prices per

 

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acre associated with market-based transactions in similar geographic locations for our non-depletable exploration permits and licenses, and selected appropriate metrics based on a qualitative comparison between our non-depletable exploration permits and the relevant transactions.

At October 1, 2010, we performed our annual impairment test of the Nautilus goodwill. We employed both the income approach (discounted cash flow method) and the market value approach in estimating the fair value of Nautilus. As of October 1, 2010, no impairment existed as the indicated fair value of Nautilus, based upon our estimate, exceeded its carrying value as of October 1, 2010.

Asset Retirement Obligations

Obligations associated with the retirement of long-lived assets are 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 liability.

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 Australia and the U.S. 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 estimated life of the field, estimates of these costs, acquisition of additional properties and as new wells are drilled.

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. Inventories at Nautilus also include parts inventory using the first in-first out (FIFO) method.

Foreign Currency Translations

The accounts of MPAL, whose functional currency is the Australian dollar, are translated into U.S. dollars. The translation adjustment is included in accumulated other comprehensive income (loss), which is a component of equity, 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, 2011 and 2010, the Australian dollar was equivalent to U.S. 1.0595 and .8567, respectively. The annual weighted average exchange rates ($AUD to $USD) used to translate MPAL’s operations in Australia for the fiscal years 2011, 2010, and 2009 were .9893, .8826, and .7471, respectively.

The accounts of MPAL’s U.K. division, whose functional currency is the British pound, are translated into Australian dollars before MPAL consolidates. The translation adjustment is included in accumulated other 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.

 

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Accrued Liabilities

At June 30, 2011 and 2010, balances in accrued liabilities which exceeded 5% of current liabilities include $1,011,623 and $766,317 of employment benefits, respectively, and $-0- and $356,812 of withholding and sale taxes, respectively.

Accounting for Income Taxes

The Company follows 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.

GAAP 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 GAAP, the Company recognizes tax positions when 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 next step 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. A 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, the Company is required to make significant judgments and 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 significant uncertain tax positions for fiscal 2011 and 2010.

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, accounts payable and debt 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,  
     2011