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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, 2006 | ||
or | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
Commission file number 1-5507
Magellan Petroleum Corporation
(Exact name of registrant as specified in its charter)
Delaware | 06-0842255 | |
State or other jurisdiction of incorporation or organization | (I.R.S. Employer Identification No.) | |
10 Columbus Boulevard, Hartford, CT | 06106 | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code
(860) 293-2006
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on | ||
Title of Each Class | Which Registered | |
Common stock, par value $.01 per share | Boston Stock Exchange NASDAQ Capital Market |
Securities registered pursuant to Section 12(g) of the Act
Title of Class | ||
None |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filero Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant at the $1.75 closing price on December 30, 2005 (the last business day of the most recently completed second quarter) was $44,975,656.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:
Common stock, par value $.01 per share, 41,500,138 shares outstanding as of September 22, 2006.
DOCUMENTS INCORPORATED BY REFERENCE
None
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Unless otherwise indicated, all dollar figures set forth herein are in United States currency. Amounts expressed in Australian currency are indicated as “A.$00”. The exchange rate at September 22, 2006 was approximately A.$1.00 equaled U.S. $.76.
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PART I
Item 1. | Business |
Magellan Petroleum Corporation (the Company or MPC) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2006, MPC’s principal asset was a 100.00% equity interest in its subsidiary, Magellan Petroleum Australia Limited (MPAL). At June 30, 2005, MPC’s equity interest in MPAL was 55.13%. During the fourth quarter of fiscal 2006, MPC completed an exchange offer (the Offer) to acquire all of the 44.87% of ordinary shares of MPAL that it did not own. The Offer consideration was .75 newly-issued shares of MPC common stock and A$0.10 in cash consideration for each of the 20,952,916 MPAL shares that it did not own. New MPC shares were issued to MPAL’s Australian shareholders either as registered MPC shares or in the form of CDIs (CHESS Depository Interests), which have been listed on the Australian Stock Exchange (“ASX”), effective April 26, 2006, under the symbol “MGN”(see Note 2 to the financial statements).
MPAL’s major assets are two petroleum production leases covering the Mereenie oil and gas field (35% working interest) and one petroleum production lease covering the Palm Valley gas field (52% working interest). Both fields are located in the Amadeus Basin in the Northern Territory of Australia. Santos Ltd., a publicly owned Australian company, owns a 48% interest in the Palm Valley field and a 65% interest in the Mereenie field.
During July 2004, MPAL reached an agreement with Voyager Energy Limited for the purchase of its 40.936% working interest (38.703% net revenue interest) in its Nockatunga assets in southwest Queensland. The assets comprise several producing oil fields in Petroleum Leases 33, 50 and 51 together with exploration acreage in ATP 267P at a purchase price of approximately $1.4 million. The project is currently producing about 320 barrels of oil per day (MPAL share 125 bbls).
MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. During September 2003, the litigants in the Kotaneelee litigation entered into a settlement agreement. The following chart illustrates the various relationships between MPC and the various companies discussed above.
The following is a tabular presentation of the omitted material:
MPC — MPAL RELATIONSHIPS CHART
MPC owns 100% of MPAL.
MPC owns 2.67% of the Kotaneelee Field, Canada.
MPAL owns 52% of the Palm Valley Field, Australia.
MPAL owns 35% of the Mereenie Field, Australia.
MPAL owns 40.94% of the Nockatunga Field, Australia.
SANTOS owns 48% of the Palm Valley Field, Australia.
SANTOS owns 65% of the Mereenie Field, Australia.
SANTOS owns 59.06% of the Nockatunga Field, Australia.
(a) General Development of Business.
Operational Developments Since the Beginning of the Last Fiscal Year:
The following is a summary of oil and gas properties that the Company has an interest in. The Company is committed to certain exploration and development expenditures, some of which may be farmed out to third parties.
AUSTRALIA
Mereenie Oil and Gas Field |
MPAL (35%) and Santos (65%), the operator (together known as the Mereenie Producers) own the Mereenie field which is located in the Amadeus Basin of the Northern Territory. MPAL’s share of the
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Mereenie field proved developed oil reserves (net of royalties), based upon contract amounts, was approximately 161,000 barrels and 11.5 billion cubic feet (bcf) of gas at June 30, 2006. Two gas development wells were drilled in late 2004 to increase gas deliverability in order to meet the gas contractual requirements until June 2009.
During fiscal 2006, MPAL’s share of oil sales was 116,000 barrels and 4.7 bcf of gas sold, which is subject to net overriding royalties aggregating 4.0625% and the statutory government royalty of 10%. The oil is transported by means of a167-mile eight-inch oil pipeline from the field to an industrial park near Alice Springs. The oil is then shipped south approximately 950 miles by road to the Port Bonython Export Terminal, Whyalla, South Australia for sale. The cost of transporting the oil to the terminal is being borne by the Mereenie Producers. The Mereenie Producers are providing Mereenie gas in the Northern Territory to the Power and Water Corporation (PAWC) for use in Darwin and other Northern Territory centers. See “Gas Supply Contracts” below. The petroleum lease covering the Mereenie field expires in November 2023.
Palm Valley Gas Field |
MPAL has a 52.023% interest in, and is the operator of, the Palm Valley gas field which is also located in the Amadeus Basin of the Northern Territory. Santos, the operator of the Mereenie field, owns the remaining 47.977% interest in Palm Valley which provides gas to meet the Alice Springs and Darwin supply contracts with PAWC. See “Gas Supply Contracts” below. MPAL’s share of the Palm Valley proved developed reserves, net of royalities, was 7.8 bcf at June 30, 2006 and is based upon contract amounts. During fiscal 2006, MPAL’s share of gas sales was 2.1 bcf which is subject to a 10% statutory government royalty and net overriding royalties aggregating 7.3125%. The producers and PAWC installed additional compression equipment in the field in early 2006 that will assist field deliverability during the remaining Darwin gas contract period. PAWC funds the cost of the additional compression under the gas supply agreement. The petroleum lease covering the Palm Valley field expires in November 2024.
Gas Supply Contracts |
In 1983, the Palm Valley Producers (MPAL and Santos) commenced the sale of gas to Alice Springs under a 1981 agreement. In 1985, the Palm Valley Producers and Mereenie Producers signed agreements for the sale of gas to PAWC, through its wholly-owned company Gasgo, for use in the PAWC’s Darwin electricity generating station and at a number of other generating stations in the Northern Territory. The gas is being delivered via the922-mile Amadeus Basin gas pipeline which was built by an Australian consortium. Since 1985, there have been several additional contracts for the sale of Mereenie gas, the latest being in June 2006 for the supply of an additional 4.4 bcf of gas to be supplied prior to December 31, 2008. The Palm Valley Darwin contract expires in the year 2012 and the Mereenie contracts expire in the year 2009. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index.
The Mereenie and Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields. As indicated above, gas production from both fields is substantially contracted through to 2009 and 2012, respectively. While opportunities exist to contract additional gas sales in the Northern Territory market after these dates, there is strong competition within the market and there are no assurances that the Mereenie and Palm Valley producers will be able to contract for the sale of the remaining uncontracted reserves.
At June 30, 2006, MPAL’s commitment to supply gas under the above agreements was as follows:
Period | Bcf | |||
Less than one year | 7.64 | |||
Between 1-5 years | 18.12 | |||
Greater than 5 years | 0.98 | |||
Total | 26.74 | |||
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Nockatunga Oil Fields |
MPAL purchased its 40.936% working interest (38.703% net revenue interest) in the Nockatunga oil fields in the Cooper Basin in southwest Queensland with effect from July 2003. Santos is operator of the fields and holds the remaining interest. The assets comprise eight producing oil fields in Petroleum Leases 33, 50 and 51 together with exploration acreage in ATP 267P. The fields are currently producing about 320 barrels of oil per day (MPAL share 125 bbls). During fiscal 2006, MPAL’s share of oil sales was 39,000 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 3.0%. MPAL’s share of the Nockatunga fields’ proved developed oil reserves was approximately 114,000 barrels at June 30, 2006. Petroleum Lease 33 expires in April 2007 and Petroleum Leases 50 and 51 expire in June 2011.
The drilling of two appraisal wells and one exploration well was undertaken in late 2005-early 2006. All three wells have been completed as oil producing wells. The drilling of an additional ten wells, appraisal, development as well as exploration, is planned for late 2006. MPAL’s share of the cost is approximately $2,750,000. At June 30, 2006, the work obligations of ATP 267P had been fulfilled.
Dingo Gas Field |
MPAL has a 34.3365% interest in the Dingo gas field which is held under Retention License 2 in the Amadeus Basin in the Northern Territory. No market has emerged for the gas volumes that have been discovered in the Dingo gas field. MPAL’s share of potential production from this permit area is subject to a 10% statutory government royalty and overriding royalties aggregating 4.8125%. The license expires in October 2008.
Maryborough Basin |
MPAL holds a 100% interest in exploration permit ATP 613P in the Maryborough Basin in Queensland, Australia. MPAL (100%) also has applications pending for permits ATP 674P and ATP 733P which are adjacent to ATP 613P. In May 2006, MPAL entered into a farmout agreement in relation to a portion of ATP 613P, ATPA 674P and ATPA 733P with Eureka Petroleum under which that company will fund the drilling of two exploration wells to test the coal seam gas potential of the Burrum Coal Measures near the city of Maryborough. Eureka Petroleum has the option to undertake a staged evaluation of the area to earn a 90% interest in any petroleum lease granted in the area. MPAL has the option to retain a 50% interest in any petroleum lease by carrying Eureka Petroleum through any development to the extent of Eureka Petroleum’s prior exploration and evaluation expenditures. MPAL will operate the joint venture. At June 30, 2006, MPAL’s share of the work obligations of permit ATP 613P totaled $38,000 which is fully committed. Exploration Permit ATP 613P is due for renewal in March 2007 for a further four year term.
Cooper/ Eromanga Basin |
PEL 94, PEL 95 &PPL 210
During fiscal year 1999, MPAL (50%) and its partner Beach Petroleum were successful in bidding for two exploration blocks (PEL 94 and PEL 95) in South Australia’s Cooper Basin. Aldinga-1 was completed in September 2002 and began producing in May 2003 at about 80 barrels of oil per day. By June 2006, production had declined to about 15 barrels of oil per day. Petroleum Production Licence 210 was granted over the Aldinga field in December 2004. No further development is planned for the field. Black Rock Petroleum NL contributed to the cost of drilling the Myponga-1 well in June 2004 to earn a 15% interest in the PEL 94 permit. MPAL’s interest in PEL 94 was reduced to 35%. Black Rock Petroleum NL subsequently assigned its interest in PEL 94 to Victoria Petroleum NL. The41-mile 2D Discuss seismic survey was acquired in PEL 95 in October 2005. MPAL’s share of the cost of the survey was approximately $130,000. At June 30, 2006, MPAL’s share of the work obligations of PEL 94 totaled $263,000 which is fully committed. The work obligations of PEL 95 have been fulfilled. PEL 94 is due for renewal for a further five year term in May 2007 and PEL 95 is due for renewal in October 2006.
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PEL 106, PEL 107 & PPL 212
During fiscal year 2005, MPAL entered into a farmin arrangement with Great Artesian Oil and Gas to drill explorations wells in exploration permits PEL 106 and PEL 107 in the Cooper Basin of South Australia. The Tyringa-1 and Kiana-1 wells were drilled in PEL 107 during August-September 2005. Tyringa-1 was a dry hole and Kiana-1 was completed for production as an oil producer. MPAL’s share of the cost of the two wells was approximately $1,353,000. Petroleum Production Licence 212 was granted over the Kiana field in January 2006. MPAL earned a 30% interest in PPL 212 by contributing to the drilling cost of theKiana-1 well. It earned no interest in the Tyringa area as the well was a dry hole. Beach Petroleum is operator of the joint venture which is planning to drill an appraisal well, Kiana-2, in the licence area later in 2006. MPAL has the option to participate in a further two wells in PEL 107 under the farmin arrangement with Great Artesian Oil and Gas to earn a 30% interest in any discoveries and a 20% interest in the PEL 107 permit. The PEL 107 joint venture is planning to drill the two wells later in 2006.
The Udacha-1 well was drilled in a farmin area covering portion of PEL 106 and the adjacent PEL 91 permit. Udacha-1 was completed for production as a gas discovery. MPAL’s share of the cost of theUdacha-1 well was approximately $1,110,000. A production test is planned to establish whether the discovery is commercially viable. If the discovery is commercial, MPC will earn a 30% interest in any petroleum production licence granted over the Udacha field.
PEL 110
During fiscal year 2001, MPAL and its partner Beach Petroleum were also successful in bidding for an additional exploration block PEL 110 (37.5%) in the Cooper Basin. PEL 110 was granted in February 2003. During July 2005, theYanerbie-1 well was drilled in PEL 110 at an approximate cost of $156,000 to MPAL. Cooper Energy NL contributed to the cost of the well to earn a 25% interest in PEL 110, and Enterprise Energy NL contributed to the cost of the well to earn 12.5% in any discovery. The well was a dry hole. Enterprise Energy NL elected not to exercise its option to earn a 6.25% interest in the PEL 110 by funding further exploration in the area and has withdrawn from the venture. At June 30, 2006, MPAL’s share of the work obligations of the PEL 110 permit totaled $493,000, of which $127,000 was committed.
NEW ZEALAND
PEP 38225
In November 2003, MPAL (100%) was granted exploration permit PEP 38225 in the Great South Basin, offshore south of the South Island of New Zealand. Following a program of seismic reprocessing and interpretation, the permit was surrendered during May 2006.
PEP 38765
MPAL was granted exploration permit PEP 38765 (12.5%) in February 2004. The Miromiro-1 well was drilled in PEP 38765 during December 2004. The well was a dry hole. MPAL has elected to withdraw from PEP 38765.
UNITED KINGDOM
PEDL 098 & PEDL 099
During fiscal year 2001, MPAL acquired an interest in two exploration licenses in southern England in the Weald-Wessex basin. The two licenses, PEDL 098 (22.5%) in the Isle of Wight and PEDL 099 (40%) in the Portsdown area of Hampshire, were each granted for a period of six years. The Sandhills-2 well was drilled in the PEDL 098 permit during August-September 2005. Sandhills-2 intersected oil shows in the objective but was low to prognosis. A sidetrack Sandills-2, drilled to intersect the reservoir up-dip, encountered a heavily biodegraded remnant oil column. The well was plugged and abandoned. The UK companies, Northern Petroleum and Montrose Industries, funded part of MPAL’s share of the cost of the Sandhills-2 well. MPAL’s
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share of the cost of Sandhills-2Z was approximately $400,000. At June 30, 2006, MPAL’s share of the work obligations of the permits totaled $81,000, which is fully committed.
PEDL 112 & PEDL 113
During fiscal year 2002, MPAL acquired two additional exploration licenses in southern England. The two licenses, PEDL 113 (22.5%) in the Isle of Wight in the Wessex Basin and PEDL 112 (33.3%) in the Kent area on the north-eastern margin of the Weald Basin, were each granted for a period of six years. At June 30, 2006, MPAL’s share of the work obligations of the permits totaled $1,521,000, of which $34,000 was committed.
PEDL 125 & PEDL 126
Effective July 1, 2003, MPAL acquired two exploration licenses each granted for a period of six years in southern England, PEDL 125 (40%) in Hampshire and PEDL 126 (40%) in West Sussex. The drilling plans for the Hedge End-2 well in PEDL 125 and Horndean Extension-1 in PEDL 126 are in progress and spudding of these wells is expected in late 2006-early 2007. The UK company, Oil Quest Resources Plc, will fund part of MPAL’s share of the cost of the two wells to acquire a 10% interest in each of the permits. At June 30, 2006, MPAL’s share of the work obligations of the two permits totaled $1,848,000, of which $1,800,000 was committed.
PEDL 135, PEDL 136 & PEDL 137
Effective October 1, 2004, MPAL was granted 100% interest in PEDL 135, PEDL 136 and PEDL 137 in the Weald Basin in southern England for a term of six years, each with a drill or drop obligation at the end of the third year of the term. MPAL is undertaking a program of seismic data purchase, reprocessing and interpretation. At June 30, 2006, MPAL’s work obligation for the three licenses totaled $10,890,000, of which $675,000 was committed.
PEDL 151, PEDL 152, PEDL 153, PEDL 154 & PEDL 155
Effective October 1, 2004, MPAL acquired five licenses in the Weald Basin each granted for a period of six years in southern England, PEDL 151 (11.25%), PEDL 152 (22.5%), PEDL 153 (33.3%), PEDL 154 (50%) and PEDL 155 (40%). Each licence has a drill or drop obligation at the end of the third year of the term. The drilling plans for the Leigh Park-1 well in PEDL 155 are in progress and spudding of this well is expected in 2007. The UK company, Oil Quest Resources Plc, will fund part of MPAL’s share of the PEDL 155 exploration costs to acquire a 10% interest in the license. At June 30, 2006, MPAL’s work obligation for the five licenses totaled $4,334,000, of which $1,022,000 was committed.
CANADA
MPC owns a 2.67% carried interest in a lease (31,885 gross acres, 850 net acres) in the southeast Yukon Territory, Canada, which includes the Kotaneelee gas field. Devon Canada Corporation is the operator of this partially developed field which is connected to a major pipeline system. Production at Kotaneelee commenced in February 1991. The Company received cash of $60,083 from this field in 2006. Due to the completion of well L-38 drilled in fiscal 2006 in the Kotaneelee gas field in which MPC has a carried interest, MPC will not receive any revenue from the operator of this field until its share of the drilling costs are absorbed. Based upon average field production and costs for the last seven months provided to us by the operator, we currently estimate that it will take until the third or fourth calendar quarter of 2007 for the operator to recover the Company’s share of the wells’ costs from the Company’s carried interest account. This estimate could change based upon future production and expenses related to this well.
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(b) Financial Information About Industry Segments.
The Company is engaged in only one industry, namely, oil and gas exploration, development, production and sale. The Company conducts such business through its two operating segments; MPC and its wholly owned subsidiary MPAL.
(c) (1)Narrative Description of the Business.
MPC was incorporated in 1957 under the laws of Panama and was reorganized under the laws of Delaware in 1967. MPC is directly engaged in the exploration for, and the development and production and sale of oil and gas reserves in Canada, and indirectly through its subsidiary MPAL in Australia and the United Kingdom.
(i) Principal Products.
MPAL has an interest in the Palm Valley gas field and in the Mereenie oil and gas field in the Amadeus Basin of the Northern Territory as well as the Nockatunga, Kiana and Aldinga oil fields in the Cooper Basin of South Australia and Queensland. See Item 1(a) — Australia — for a discussion of the oil and gas production from these fields. MPC has a direct 2.67% carried interest in the Kotaneelee gas field in Canada.
(ii) Status of Product or Segment.
See Item 1(a) and (b) — Australia and Canada — for a discussion of the current and future operations of the Mereenie, Palm Valley, Nockatunga, Kiana and Aldinga fields in Australia and MPC’s interest in the Kotaneelee field in Canada.
(iii) Raw Materials.
Not applicable.
(iv) Patents, Licenses, Franchises and Concessions Held.
MPAL has interests directly and indirectly in the following permits. Permit holders are generally required to carry out agreed work and expenditure programs.
Permit | Expiration Date | Location | ||
Petroleum Lease No. 4 and No. 5 (Mereenie) (Amadeus Basin) | November 2023 | Northern Territory, Australia | ||
Petroleum Lease No. 3 (Palm Valley) (Amadeus Basin) | November 2024 | Northern Territory, Australia | ||
Retention License No. 2 (Dingo) (Amadeus Basin) | October 2008 | Northern Territory, Australia | ||
Petroleum Lease No. 33 (Nockatunga) (Cooper Basin) | April 2007 | Queensland, Australia | ||
Petroleum Lease No. 50 and No. 51(Nockatunga) (Cooper Basin) | June 2011 | Queensland, Australia | ||
Petroleum Production Licence No. 210 (Aldinga) (Cooper Basin) | Held by production | South Australia | ||
Petroleum Production Licence No. 212 (Kiana) (Cooper Basin) | Held by production | South Australia | ||
ATP 267P (Nockatunga) (Cooper Basin) | November 2007 | Queensland, Australia | ||
ATP 613P (Maryborough Basin) | March 2007 | Queensland, Australia | ||
ATP 674P (Maryborough Basin) | Application pending | Queensland, Australia | ||
ATP 733P (Maryborough Basin) | Application pending | Queensland, Australia | ||
ATP 732P (Cooper Basin) | Application pending | Queensland, Australia | ||
PEL 94 (Cooper Basin) | May 2007 | South Australia | ||
PEL 95 (Cooper Basin) | October 2006 | South Australia | ||
PEL110 (Cooper Basin) | February 2008 | South Australia |
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Permit | Expiration Date | Location | ||
PEDL 098 (Weald-Wessex Basins) | September 2011 | United Kingdom | ||
PEDL 099 (Weald-Wessex Basins) | September 2007 | United Kingdom | ||
PEDL 112 (Weald-Wessex Basins) | January 2008 | United Kingdom | ||
PEDL 113 (Weald Basin) | January 2008 | United Kingdom | ||
PEDL 125 (Weald-Wessex Basins) | June 2009 | United Kingdom | ||
PEDL 126 (Weald-Wessex Basins)) | June 2009 | United Kingdom | ||
PEDL 135 (Weald Basin) | September 2010 | United Kingdom | ||
PEDL 136 (Weald Basin) | September 2010 | United Kingdom | ||
PEDL 137 (Weald Basin) | September 2010 | United Kingdom | ||
PEDL 151 (Weald-Wessex Basins) | September 2010 | United Kingdom | ||
PEDL 152 (Weald-Wessex Basin) | September 2010 | United Kingdom | ||
PEDL 153 (Weald Basin) | September 2010 | United Kingdom | ||
PEDL 154 (Weald Basin) | September 2010 | United Kingdom | ||
PEDL 155 (Weald-Wessex Basins) | September 2010 | United Kingdom |
Petroleum Leases issued by the Northern Territory and Queensland Governments are subject to the Petroleum (Prospecting and Mining) Act of the Northern Territory and the Petroleum Act and Petroleum and Gas (Production & Safety) Act of Queensland. Lessees have the exclusive right to produce petroleum from the land subject to payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Rental payments may be offset against the royalty paid. The term of a lease is 21 years, and leases may be renewed for successive terms of 21 years each. Petroleum Production Licences issued by the South Australian Government are subject to the Petroleum Act of South Australia. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Licenses terminate two years after production ceases.
Since 1992, there has been an ongoing controversy regarding the Aborigines and the ownership of their traditional lands. There has been legislation aimed at resolving this controversy. The Company does not believe that this issue will have a material adverse impact on MPAL’s properties.
(v) Seasonality of Business.
Although the Company’s business is not seasonal, the demand for oil and especially gas is subject to fluctuations in the Australian weather.
(vi) Working Capital Items.
See Item 7 — Liquidity and Capital Resources for a discussion of this information.
(vii) Customers.
Although the majority of MPAL’s producing oil and gas properties are located in a relatively remote area in central Australia (See Item 1 — Business and Item 2 — Properties), the completion in January 1987 of the Amadeus Basin to Darwin gas pipeline has provided access to and expanded the potential market for MPAL’s gas production.
Natural Gas Production |
Substantially all of MPAL’s gas sales were to the Power and Water Corporation (PAWC), a Northern Territory Government corporation. The Northern Territory Government also has regulatory authority over MPAL’s oil and gas operations in the Northern Territory. The loss of PAWC as a customer would have a material adverse affect on MPAL’s business.
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Oil Production |
Presently all of the crude oil and condensate production from Mereenie is being shipped and sold through the Port Bonython Export Terminal, Whyalla, South Australia. Crude oil production from Kiana and Aldinga is shipped through the Moomba processing facility in northeastern South Australia and piped from there to the Port Bonython Export Terminal where it is sold. Nockatunga crude oil is shipped and sold through the IOR Energy refinery at Eromanga, Southwest Queensland. Oil sales during 2006 were 53.3% to the Santos group of companies, 16.2% to Delhi Petroleum, 10.5% to Origin Energy Resources and 20.0% to IOR Energy.
(viii) Backlog.
Not applicable.
(ix) Renegotiation of Profits or Termination of Contracts or Subcontracts at the Election of the Government.
Not applicable.
(x) Competitive Conditions in the Business.
The exploration for and production of oil and gas are highly competitive operations. The ability to exploit a discovery of oil or gas is dependent upon such considerations as the ability to finance development costs, the availability of equipment, and the possibility of engineering and construction delays and difficulties. The Company also must compete with major oil and gas companies which have substantially greater resources than the Company.
Furthermore, various forms of energy legislation which have been or may be proposed in the countries in which the Company holds interests may substantially affect competitive conditions. However, it is not possible to predict the nature of any such legislation which may ultimately be adopted or its effects upon the future operations of the Company.
At the present time, the Company’s principal income producing operations are in Australia and for this reason, current competitive conditions in Australia are material to the Company’s future. Currently, most indigenous crude oil is consumed within Australia. In addition, refiners and others import crude oil to meet the overall demand in Australia. The Palm Valley Producers and the Mereenie Producers are developing and separately marketing the production from each field. Because of the relatively remote location of the Amadeus Basin and the inherent nature of the market for gas, it would be impractical for each working interest partner to attempt to market separately its respective share of gas production from each field.
(xi) Research and Development.
Not applicable.
(xii) Environmental Regulation.
The Company is subject to the environmental laws and regulations of the jurisdictions in which it carries on its business, and existing or future laws and regulations could have a significant impact on the exploration for and development of natural resources by the Company. However, to date, the Company has not been required to spend any material amounts for environmental control facilities. The federal and state governments in Australia strictly monitor compliance with these laws but compliance therewith has not had any adverse impact on the Company’s operations or its financial resources.
At June 30, 2006, the Company had accrued approximately $7.1 million for asset retirement obligations for the Mereenie, Palm Valley, Kotaneelee, Nockatunga, Kiana, Aldinga and Dingo fields. See Note 4 of the Consolidated Financial Statements under Item 8. Financial Statements and Supplementary Data.
(xiii) Number of Persons Employed by Company.
At June 30, 2006, MPC had two full-time employees in the United States and MPAL had 27 employees in Australia. MPC relies to a great extent on consultants for legal, accounting, administrative and geotechnical services.
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(d)(2)Financial Information Relating to Foreign and Domestic Operations.
See Note 11 to the Consolidated Financial Statements.
(3) Risks Attendant to Foreign Operations.
Most of the properties in which the Company has interests are located outside the United States and are subject to certain risks involved in the ownership and development of such foreign property interests. These risks include but are not limited to those of: nationalization; expropriation; confiscatory taxation; changes in foreign exchange controls; currency revaluations; price controls or excessive royalties; export sales restrictions; limitations on the transfer of interests in exploration licenses; and other laws and regulations which may adversely affect the Company’s properties, such as those providing for conservation, proration, curtailment, cessation, or other limitations of controls on the production of or exploration for hydrocarbons. Thus, an investment in the Company represents a speculation with risks in addition to those inherent in domestic petroleum exploratory ventures.
Since 1992, there has been an ongoing controversy regarding the Aborigines and the ownership of their traditional lands. There has been legislation aimed at resolving this controversy. The Company does not believe that this issue will have a material adverse impact on MPAL’s properties.
(4) Data Which are Not Indicative of Current or Future Operations.
None.
Item 1A. Risk Factors
Set forth below and elsewhere in this Annual Report on Form 10-K are risks that should be considered in evaluating the Company’s Common Stock, as well as risks and uncertainties that could cause the actual future results of the Company to differ from those expressed or implied in the forward-looking statements contained in this Report and in other public statements the Company makes. Additionally, because of the following risks and uncertainties, as well as other variables affecting the Company’s operating results, the Company’s past financial performance should not be considered an indicator of future performance.
The principal oil and gas properties owned by MPAL could stop producing oil and gas. |
MPAL’s Palm Valley and Mereenie fields could stop producing oil and gas or there could be a material decrease in production levels at the fields. Since these are the two principal revenue producing properties of MPAL, any decline in production levels at these properties could cause MPAL’s revenues to decline, thus reducing the amount of dividends paid by MPAL to Magellan. Any such adverse impact on the revenues being received by Magellan from MPAL could restrict our ability to explore and develop oil and gas properties in the future.
In addition, the Kotaneelee gas field, which has in recent years provided Magellan with an additional source of revenue, could stop producing natural gas, produce gas in decreased amounts, or be shut-in completely (so that production would cease). In this event, Magellan may experience a decline in revenues and would be forced to rely completely on our receipt of dividends from MPAL.
If MPAL’s existing long-term gas supply contracts are terminated or not renewed, MPAL’s share price and business could be adversely affected. |
MPAL’s financial performance and cash flows are substantially dependent upon its Palm Valley and Mereenie existing supply contracts to sell gas produced at these fields to MPAL’s major customers, The Power and Water Corporation of the Northern Territories and its subsidiary, Gasgo Pty Ltd. The Palm Valley Darwin contract expires in the year 2012 and the Mereenie contracts expire in the year 2009. If these gas supply contracts were to be terminated or not renewed when they become due, MPAL’s revenues, share price and business outlook could be adversely affected. The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the
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Amadeus Basin. There is strong competition within the market and the Palm Valley producers may not be able to contract for the sale of the remaining uncontracted reserves.
Fluctuations in our operating results and other factors may depress our stock price. |
During the past few years, the equity trading markets in the United States have experienced price volatility that has often been unrelated to the operating performance of particular companies. These fluctuations may adversely affect the trading price of our common stock. From time to time, there may be significant volatility in the market price of our common stock. Investors could sell shares of our common stock at or after the time that it becomes apparent that the expectations of the market may not be realized, resulting in a decrease in the market price of our common stock.
We only have two full time employees, including our Chief Executive Officer, and our operations could be disrupted if he was unable or unwilling to perform his duties. |
We only have two full time employees, including Daniel J. Samela, our President, Chief Executive Officer, and Chief Financial Officer. Mr. Samela has an employment agreement with an automatically renewing three-year and three-month term. Mr. Samela may terminate his employment relationship with us at any time with no penalty other than the loss of future compensation. If Mr. Samela resigned or were unable or unwilling to perform the duties of President, Chief Executive Officer and Chief Financial Officer, our operations could face significant delay and disruption until a suitable replacement could be found to succeed Mr. Samela. Any such delay or disruption could also prevent the achievement of our business objectives. In order to minimize any delay or disruption, we have retained a consultant to assist Mr. Samela in the performance of his duties.
The loss of key MPAL personnel could adversely affect our ability to operate. |
We depend, and will continue to depend in the foreseeable future, on the services of the officers and key employees of MPAL. The ability to retain its officers and key employees is important to MPAL’s and our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on MPAL’s and our business. We do not maintain key person life insurance on any of our personnel.
There are risks inherent in foreign operations such as adverse changes in currency values and foreign regulations relating to MPAL’s exploration and development operations and to MPAL’s payment of dividends to us. |
The properties in which Magellan has interests are located outside the United States and are subject to certain risks related to the indirect ownership and development of foreign properties, including government expropriation, adverse changes in currency values and foreign exchange controls, foreign taxes, nationalization and other laws and regulations, any of which may adversely affect the Company’s properties. In addition, MPAL’s principal present customer for gas in Australia is the Northern Territory Government, which also has substantial regulatory authority over MPAL’s oil and gas operations. Although there are currently no exchange controls on the payment of dividends to the Company by MPAL, such payments could be restricted by Australian foreign exchange controls, if implemented.
Our Restated Certificate of Incorporation includes provisions that could delay or prevent a change in control of our Company that some of our shareholders may consider favorable. |
Our Restated Certificate of Incorporation provides that any matter to be voted upon at any meeting of shareholders must be approved not only by a simple majority of the shares voted at such meeting, but also by a majority of the shareholders present in person or by proxy and entitled to vote at the meeting. This provision may have the effect of making it more difficult to take corporate action than customary “one share one vote” provisions, because it may not be possible to obtain the necessary majority of both votes.
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As a consequence, our Restated Certificate of Incorporation may make it more difficult that a takeover of Magellan will be consummated, which could prevent the Company’s shareholders from receiving a premium for their shares. In addition, an owner of a substantial number of shares of our common stock may be unable to influence our policies and operations through the shareholder voting process (e.g., to elect directors).
In addition, our Restated Certificate of Incorporation requires the approval of 66.67% of the voting shareholders and of the voting shares for the consummation of any business combination (such as a merger, consolidation, other acquisition proposal or sale, transfer or other disposition of $5 million or more of Magellan’s assets) involving our company and certain related persons (generally, any 10% or greater shareholders and their affiliates and associates). This higher vote requirement may deter business combination proposals which shareholders may consider favorable.
Our dividend policy could depress our stock price. |
We have never declared or paid dividends on our common stock and have no current intention to change this policy. We plan to retain any future earnings to reduce our accumulated deficit and finance growth. As a result, our dividend policy could depress the market price for our common stock and cause investors to lose some or all of their investment.
We may issue a substantial number of shares of our common stock under our stock option plans and shareholders may be adversely affected by the issuance of those shares. |
As of June 30, 2006, there were 430,000 stock options outstanding, of which 420,000 were fully vested and exercisable and 10,000 were not vested. There were also 395,000 options available for future grants under our Stock Option Plan. If all of these options, which total 825,000 in the aggregate, were awarded and exercised these shares would represent approximately 2% of our outstanding common stock and would, upon their exercise and the payment of the exercise prices, dilute the interests of other shareholders and could adversely affect the market price of our common stock.
If our shares are delisted from trading on the Nasdaq Capital Market, their liquidity and value could be reduced. |
In order for us to maintain the listing of our shares of common stock on the Nasdaq Capital Market, the Company’s shares must maintain a minimum bid price of $1.00 as set forth in Marketplace Rule 4310(c)(4). If the bid price of the Company’s shares trade below $1.00 for 30 consecutive trading days, then the bid price of the Company’s shares must trade at $1.00 or more for 10 consecutive trading days during a 180 day grace period to regain compliance with the rule. On September 22, 2006, the Company’s shares closed at $1.28 per share. If the Company shares were to be delisted from trading on the Nasdaq Capital Market, then most likely the shares would be traded on the Electronic Bulletin Board. The delisting of the Company’s shares could adversely impact the liquidity and value of the Company’s shares of common stock.
RISKS RELATED TO THE OIL AND GAS INDUSTRY
Oil and gas prices are volatile. A decline in prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow. |
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend primarily upon the prices we receive for the oil and gas we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The prices of oil, natural gas, methane gas and other fuels have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to numerous factors, including the following:
• | worldwide and domestic supplies of oil and gas; | |
• | changes in the supply and demand for such fuels; |
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• | political conditions in oil, natural gas, and other fuel-producing and fuel-consuming areas; | |
• | the extent of Australian domestic oil and gas production and importation of such fuels and substitute fuels in Australian and other relevant markets; | |
• | weather conditions, including effects on prices and supplies in worldwide energy markets because of recent hurricanes in the United States; | |
• | the competitive position of each such fuel as a source of energy as compared to other energy sources; and | |
• | the effect of governmental regulation on the production, transportation, and sale of oil, natural gas, and other fuels. |
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. Declines in oil and gas prices would not only reduce revenue, but could reduce the amount of oil and gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and gas prices do not necessarily move in tandem. Because more than 80% of our proved reserves at June 30, 2006 were natural gas reserves, we are more affected by movements in natural gas prices and would receive lower revenues if natural gas prices in Australian and Canada were to decline. Based on 2006 gas sales volumes and revenues, a 10% change in gas prices would increase or decrease gas revenues by approximately $1,406,000.
Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do. |
We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production and face intense competition from both major and other independent oil and natural gas companies. Many of our Australian competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may not be able to compete with, or enter into cooperative relationships with, any such firms.
Our oil and gas exploration and production operations are subject to numerous environmental laws, compliance with which may be extremely costly. |
Our operations are subject to environmental laws and regulations in the various countries in which they are conducted. Such laws and regulations frequently require completion of a costly environmental impact assessment and government review process prior to commencing exploratory and/or development activities. In addition, such environmental laws and regulations may restrict, prohibit, or impose significant liability in connection with spills, releases, or emissions of various substances produced in association with fuel exploration and development.
We can provide no assurance that we will be able to comply with applicable environmental laws and regulations or that those laws, regulations or administrative policies or practices will not be changed by the various governmental entities. The cost of compliance with current laws and regulations or changes in environmental laws and regulations could require significant expenditures. Moreover, if we breach any governing laws or regulations, we may be compelled to pay significant fines, penalties, or other payments. Costs associated with environmental compliance or noncompliance may have a material adverse impact on our financial condition or results of operations in the future.
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The actual quantities and present value of our proved reserves may prove to be lower than we have estimated. |
This annual report and the documents incorporated by reference in this annual report contain estimates of our proved reserves and the estimated future net revenues from our proved reserves as well as estimates relating to recent and pending acquisitions. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.
There are many uncertainties in estimating quantities of oil and gas reserves. In addition, the estimates of future net cash flows from our proved developed reserves and their present value are based upon assumptions about future production levels, prices and costs that may prove to be inaccurate. Our estimated reserves may be subject to upward or downward revision based upon our production, results of future exploration and development, prevailing oil and gas prices, operating and development costs and other factors.
We may not have funds sufficient to make the significant capital expenditures required to replace our reserves. |
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, farming-in other companies or investors to MPAL’s exploration and development projects in which we have an interest and/or equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flow from operations is not sufficient to fund MPAL’s capital expenditure budget, we may not be able to rely upon additional farm-in opportunities, debt or equity offerings or other methods of financing to meet these cash flow requirements.
If we are not able to replace reserves, we may not be able to sustain production. |
Our future success depends largely upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. Recovery of any additional reserves will require significant capital expenditures and successful drilling operations. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.
Exploration and development drilling may not result in commercially productive reserves. |
We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do
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not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
• | unexpected drilling conditions; | |
• | title problems; | |
• | pressure or irregularities in formations; | |
• | equipment failures or accidents; | |
• | adverse weather conditions; | |
• | compliance with environmental and other governmental requirements; and | |
• | increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment. |
Future price declines may result in a write-down of our asset carrying values.
We follow the successful efforts method of accounting for our oil and gas operations. Under this method, the costs of successful wells, development dry holes and productive leases are capitalized and amortized on aunits-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. Magellan records its proportionate share in its working interest agreements in the respective classifications of assets, liabilities, revenues and expenses. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any required impairment charged to expense. The successful efforts method also imposes limitations on the carrying or book value of proved oil and gas properties. Oil and gas properties, along with goodwill and other intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We estimate the future undiscounted cash flows from the affected properties to determine the recoverability of carrying amounts. In general, analyses are based on proved developed reserves, except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. For Mereenie and Palm Valley, proved developed natural gas reserves are limited to contracted quantities. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves or the contracted quantities. A significant decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings.
Oil and gas drilling and producing operations are hazardous and expose us to environmental liabilities. |
Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these risks occur, we could sustain substantial losses as a result of:
• | injury or loss of life; | |
• | severe damage to or destruction of property, natural resources and equipment; | |
• | pollution or other environmental damage; | |
• | clean-up responsibilities; | |
• | regulatory investigations and penalties; | |
• | and suspension of operations. |
Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.
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Item 1B. | Unresolved SEC Staff Comments |
None
Item 2. | Properties. |
(a) MPC has interests in properties in Australia through its 100% equity interest in MPAL which holds interests in the Northern Territory, Queensland and South Australia. MPAL also has interests in the United Kingdom. In Canada, MPC has a direct interest in one lease. For additional information regarding the Company’s properties, See Item 1 — Business.
(b) (1) The information regarding reserves, costs of oil and gas activities, capitalized costs, discounted future net cash flows and results of operations is contained in Supplementary Oil & Gas Information under Item 8 — Financial Statements and Supplementary Data.
The following graphic presentation has been omitted, but the following is a description of the omitted material:
AUSTRALIAN MAP WITH MPAL PROJECTS SHOWN
The following graphic presentation has been omitted, but the following is a description of the omitted material:
AMADEUS BASIN PROJECTS MAP
The map indicates the location of the Amadeus Basin interests in the Northern Territory of Australia. The following items are identified:
Palm Valley Gas Field | |
Mereenie Oil & Gas Field | |
Dingo Gas Field | |
Palm Valley — Alice Springs Gas Pipeline | |
Palm Valley — Darwin Gas Pipeline | |
Mereenie Spur Gas Pipeline |
The following graphic presentation has been omitted, but the following is a description of the omitted material:
CANADIAN PROPERTY INTERESTS MAP
The map indicates the location of the Kotaneelee Gas Field in the Yukon Territories of Canada. The map identifies the following items:
Kotaneelee Gas Field | |
Pointed Mountain Gas Field | |
Beaver River Gas Field |
The following graphic presentation has been omitted, but the following is a description of the omitted material:
UNITED KINGDOM PROPERTY INTERESTS MAP
The map indicates the location of the MPAL property interests in the United Kingdom.
(2) Reserves Reported to Other Agencies.
None
(3) Production.
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MPC’s net production volumes for gas and oil during the three years ended June 30, 2006 were as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material)
2006 | 2005 | 2004 | ||||||||||
Australia: | ||||||||||||
Gas (bcf) | 5.7 | 5.7 | 5.7 | |||||||||
Crude oil (bbl) | 155,000 | 151,000 | 150,000 |
The average sales price per unit of production for Australia for the following fiscal years is as follows:
2006 | 2005 | 2004 | ||||||||||
Australia: | ||||||||||||
Gas (per mcf) | A.$ | 3.04 | A.$ | 2.67 | A.$ | 2.61 | ||||||
Crude oil (per bbl) | A.$ | 86.17 | A.$ | 62.74 | A.$ | 42.12 |
The average production cost per unit of production for the following fiscal years has been impacted by transportation costs on Mereenie oil in Australia. During fiscal 2006, 2005 and 2004, the cost of remedial work on various wells in the Mereenie field and lower production levels increased production costs.
2006 | 2005 | 2004 | ||||||||||
Australia: | ||||||||||||
Gas (per mcf) | A.$ | .93 | A.$ | .49 | A.$ | .49 | ||||||
Crude oil (per bbl) | A.$ | 26.59 | A.$ | 21.20 | A.$ | 25.68 |
Amounts presented above are in Australian dollars to show a more meaningful trend of underlying operations. For the year ended June 30, 2006, 2005 and 2004 the average foreign exchange rates were .7477, .7533, and .7179, respectively.
(4) Productive Wells and Acreage.
Productive wells and acreage at June 30, 2006
Productive Wells | ||||||||||||||||||||||||
Oil | Gas | Developed Acreage | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross Acres | Net Acres | |||||||||||||||||||
Australia | 39.0 | 14.9 | 13.0 | 5.40 | 80,770 | 35,663 | ||||||||||||||||||
Canada | — | — | 3.0 | .08 | 3,350 | 89 | ||||||||||||||||||
39.0 | 14.9 | 16.0 | 5.48 | 84,120 | 35,752 | |||||||||||||||||||
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(5) Undeveloped Acreage.
The Company’s undeveloped acreage (except as indicated below) is set forth in the table below:
GROSS AND NET ACREAGE AS OF JUNE 30, 2006
MPAL has interests in the following properties (before royalties). MPC has an interest in these properties through its 100% interest in MPAL.
MPC | ||||||||||||||
Interest | ||||||||||||||
Gross Acres | Net Acres | % | ||||||||||||
Australia | ||||||||||||||
Northern Territory | ||||||||||||||
PL 4/ PL 5 Mereenie (Amadeus Basin)(1) | 70,049 | 24,517 | 35.0000 | |||||||||||
PL 3 Palm Valley (Amadeus Basin)(2) | 157,932 | 82,161 | 52.0230 | |||||||||||
RL 2 Dingo (Amadeus Basin) | 116,139 | 39,878 | 34.3365 | |||||||||||
344,120 | 146,556 | |||||||||||||
Queensland: | ||||||||||||||
PL 33/ PL 50/ PL 51 Nockatunga (Cooper Basin)(3) | 87,932 | 35,996 | 40.936 | |||||||||||
ATP 267P (Cooper Basin) | 120,783 | 49,444 | 40.936 | |||||||||||
ATP 613P (Maryborough Basin) | 153,568 | 153,568 | 100.000 | |||||||||||
362,283 | 239,008 | |||||||||||||
South Australia: | ||||||||||||||
PPL 210 Aldinga (Cooper Basin)(4) | 939 | 469 | 50.00 | |||||||||||
PPL 212 Kiana (Cooper Basin)(5) | 395 | 119 | 30.00 | |||||||||||
PEL 94 (Cooper Basin) | 669,296 | 234,254 | 35.00 | |||||||||||
PEL 95 (Cooper Basin) | 958,928 | 479,464 | 50.00 | |||||||||||
PELA 110 (Cooper Basin) | 361,188 | 135,446 | 37.50 | |||||||||||
1,990,746 | 849,752 | |||||||||||||
United Kingdom | ||||||||||||||
PEDL 098/113/152 (Wessex Basin) | 82,407 | 18,542 | 22.50 | |||||||||||
PEDL 099/154 (Weald Basin) | 52,514 | 21,006 | 40.00 | |||||||||||
PEDL 112/153 (Weald Basin) | 140,342 | 46,776 | 33.33 | |||||||||||
PEDL 125/126 (Weald Basin) | 111,975 | 44,790 | 40.00 | |||||||||||
PEDL 135/136/137 (Weald Basin) | 123,152 | 123,152 | 100.00 | |||||||||||
PEDL 151 (Weald Basin) | 23,540 | 2,648 | 11.25 | |||||||||||
PEDL 154 (Weald Basin) | 84,834 | 42,417 | 50.00 | |||||||||||
618,764 | 299,331 | |||||||||||||
Total MPAL | 3,315,913 | 1,534,647 | ||||||||||||
Properties held directly by MPC: | ||||||||||||||
Canada | ||||||||||||||
Yukon and Northwest Territories: | ||||||||||||||
Kotaneelee Carried interest(6) | 31,885 | 850 | 2.67 | |||||||||||
Total | 3,347,798 | 1,535,497 | ||||||||||||
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(1) | Includes 41,644 gross developed acres and 21,664 net acres. |
(2) | Includes 31,567 gross developed acres and 11,048 net acres. |
(3) | Includes 7,040 gross developed acres and 2,725 net acres. |
(4) | Includes 364 gross developed acres and 173 net acres. |
(5) | Includes 173 gross developed acres and 52 net acres. |
(6) | Includes 3,350 gross developed acres and 89 net acres. |
(6) Drilling Activity.
Productive and dry net wells drilled during the following years (data concerning Canada and the United States is insignificant):
Australia/New Zealand | ||||||||||||||||
Exploration | Development | |||||||||||||||
Year Ended | ||||||||||||||||
June 30, | Productive | Dry | Productive | Dry | ||||||||||||
2006 | 1.01 | 0.53 | 0.82 | — | ||||||||||||
2005 | — | 1.88 | 0.70 | — | ||||||||||||
2004 | — | 3.11 | 0.41 | 0.52 |
(7) Present Activities.
See Item 1 — Cooper Basin and United Kingdom for a discussion of the present activities of MPAL.
(8) Delivery Commitments.
See discussion under Item 1 concerning the Palm Valley and Mereenie fields.
Item 3. | Legal Proceedings. |
None.
Item 4. | Submission of Matters to a Vote of Security Holders. |
None.
PART II
Item 5. | Market for the Company’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 symbolMPET. The stock is also traded on the Boston Stock Exchange under the symbolMPCand on the Australian Stock Exchange in the form of CHESS depository interests under the symbolMGN. The quarterly high and low prices on the most active market, NASDAQ, during the quarterly periods indicated were as follows:
2006 | 1st Qtr. | 2nd Qtr. | 3rd Qtr. | 4th Qtr. | ||||||||||||
High | 3.77 | 2.59 | 2.23 | 2.63 | ||||||||||||
Low | 2.31 | 1.51 | 1.64 | 1.33 |
2005 | 1st Qtr. | 2nd Qtr. | 3rd Qtr. | 4th Qtr. | ||||||||||||
High | 1.59 | 1.65 | 1.97 | 3.60 | ||||||||||||
Low | 1.19 | 1.22 | 1.23 | 1.05 |
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(b) Approximate Number of Holders of Common Stock at September 22, 2006
Title of Class | Number of Record Holders | |||
Common stock, par value $.01 per share | 6,350 |
(c) Frequency and Amount of Dividends
MPC has never paid a cash dividend on its common stock.
Recent Sales of Unregistered Securities |
None
Issuer Purchases of Equity Securities |
The following table sets forth the number of shares that the Company has repurchased under any of its repurchase plans for the stated periods, the cost per share of such repurchases and the number of shares that may yet be repurchased under the plans:
Maximum | ||||||||||||||||
Total Number of | Number of | |||||||||||||||
Total Number of | Average Price | Shares Purchased | Shares that May | |||||||||||||
Shares | Paid | as Part of Publicly | Yet Be Purchased | |||||||||||||
Period | Purchased | per Share | Announced Plan(1) | Under Plan | ||||||||||||
April 1-30, 2006 | 0 | 0 | 0 | 319,150 | ||||||||||||
May 1-31, 2006 | 0 | 0 | 0 | 319,150 | ||||||||||||
June 1-30, 2006 | 0 | 0 | 0 | 319,150 |
(1) | The Company through its stock repurchase plan may purchase up to one million shares of its common stock in the open market. Through June 30, 2006, 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 2006, 2005 or 2004. |
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Item 6. | Selected Financial Data. |
The following table sets forth selected data (in thousands except for exchange rates and per share data) and other operating information of the Company. The selected consolidated financial data in the table 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, | |||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||||||||
Financial Data | |||||||||||||||||||||
Total revenues | $ | 26,562 | $ | 21,871 | $ | 19,424 | $ | 14,736 | $ | 13,700 | |||||||||||
Income before cumulative effect of accounting change | 749 | 87 | 350 | 890 | 92 | ||||||||||||||||
Net income | 749 | 87 | 350 | 152 | 92 | ||||||||||||||||
Net income per share (basic and diluted) | .03 | — | .01 | .01 | — | ||||||||||||||||
Working capital | 24,820 | 26,208 | 21,696 | 21,798 | 17,862 | ||||||||||||||||
Cash provided by operating activities | 11,766 | 8,776 | 10,718 | 7,109 | 8,157 | ||||||||||||||||
Property and equipment (net) | 27,783 | 24,265 | 24,421 | 21,592 | 17,046 | ||||||||||||||||
Total assets | 68,580 | 56,424 | 52,894 | 50,741 | 40,166 | ||||||||||||||||
Long-term liabilities | 8,583 | 5,729 | 5,256 | 5,629 | 3,974 | ||||||||||||||||
Minority interests | — | 18,583 | 16,533 | 16,931 | 13,933 | ||||||||||||||||
Stockholders’ equity: | |||||||||||||||||||||
Capital | 73,560 | 44,660 | 44,660 | 43,152 | 43,332 | ||||||||||||||||
Accumulated deficit | (14,413 | ) | (15,161 | ) | (15,248 | ) | (15,598 | ) | (15,751 | ) | |||||||||||
Accumulated other comprehensive loss | (3,028 | ) | (2,323 | ) | (4,491 | ) | (5,407 | ) | (8,965 | ) | |||||||||||
Total stockholders’ equity | 56,119 | 27,176 | 24,920 | 22,147 | 18,616 | ||||||||||||||||
Exchange rate A.$ = U.S. at end of period | .73 | .76 | .70 | .67 | .56 | ||||||||||||||||
Common stock outstanding shares end of period | 41,500 | 25,783 | 25,783 | 24,427 | 24,607 | ||||||||||||||||
Book value per share | 1.35 | 1.05 | .97 | .91 | .76 | ||||||||||||||||
Quoted market value per share (NASDAQ) | 1.57 | 2.40 | 1.31 | 1.20 | .88 | ||||||||||||||||
Operating Data | |||||||||||||||||||||
Standardized measure of discounted future cash flow relating to proved oil and gas reserves (approximately 45% attributable to minority interest in 2005 and prior) (See Note 14) | 70,000 | 31,000 | 30,000 | 26,000 | 26,000 | ||||||||||||||||
Annual production (net of royalties) Gas (bcf) | 5.7 | 5.7 | 5.7 | 6.0 | 6.0 | ||||||||||||||||
Oil (bbls) (In thousands) | 155 | 151 | 150 | 126 | 141 | ||||||||||||||||
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Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
Forward Looking Statements
Statements included in Management’s Discussion and Analysis of Financial Condition and Results of Operations which are not historical in nature are intended to be, and are hereby identified as, forward looking statements for purposes of the “Safe Harbor” Statement under the Private Securities Litigation Reform Act of 1995. The Company cautions readers that forward looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those indicated in the forward looking statements. Among these risks and uncertainties are pricing and production levels from the properties in which the Company has interests, and the extent of the recoverable reserves at those properties. In addition, the Company has a large number of exploration permits and there is the risk that any wells drilled may fail to encounter hydrocarbons in commercial quantities. The Company undertakes no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.
Executive Summary
MPC is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. MPC’s principal asset is a 100.00% equity interest in its subsidiary, Magellan Petroleum Australia Limited (MPAL). During the fourth quarter of fiscal 2006, MPC completed an exchange offer (the Offer) to acquire all of the 44.87% of ordinary shares of MPAL that it did not own. The Offer consideration was .75 newly-issued shares of MPC common stock and A$0.10 in cash consideration for each of the 20,952,916 MPAL shares that it did not own. New MPC shares were issued to MPAL’s Australian shareholders either as registered MPC shares or in the form of CDIs (CHESS Depository Interests), which have been listed on the Australian Stock Exchange (“ASX”), effective April 26, 2006, under the symbol “MGN”(see Note 2 to the financial statements).
MPAL’s major assets are two petroleum production leases covering the Mereenie oil and gas field (35% working interest) and one petroleum production lease covering the Palm Valley gas field (52% working interest). Both fields are located in the Amadeus Basin in the Northern Territory of Australia. Santos Ltd., a publicly owned Australian company, owns a 48% interest in the Palm Valley field and a 65% interest in the Mereenie field.
MPAL is refocusing its exploration activities into two core areas, the Cooper Basin in onshore Australia and the Weald Basin in the onshore southern United Kingdom with an emphasis on developing a low to medium risk acreage portfolio.
MPC also has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. The Company received cash of $60,083 from this investment during fiscal 2006. Due to the completion of well L-38 drilled in fiscal 2006 in the Kotaneelee gas field in which MPC has a carried interest, MPC will not receive any revenue from the operator of this field until its share of the drilling costs are absorbed. Based upon average field production and costs for the last seven months provided to us by the operator, we currently estimate that it will take until the third or fourth calendar quarter of 2007 for the operator to recover the Company’s share of the wells’ costs from the Company’s carried interest account. This estimate could change based upon future production and expenses related to this well.
Critical Accounting Policies
Oil and Gas Properties |
The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method, the costs of successful wells, development dry holes, productive leases, and permit and concession costs are capitalized and amortized on aunits-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
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carrying or book value of proved oil and gas properties. Oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The Company estimates the future undiscounted cash flows from the affected properties to determine the recoverability of carrying amounts. In general, analyses are based on proved developed reserves except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. For Mereenie and Palm Valley, proved developed reserves are limited to contracted quantities. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves or the contracted quantities.
Exploratory drilling costs are initially capitalized pending determination of proved reserves but are charged to expense if no proved reserves are found. Other exploration costs, including geological and geophysical expenses, leasehold expiration costs and delay rentals, are expensed as incurred. Because the Company follows the successful efforts method of accounting, the results of operations may vary materially from quarter to quarter. An active exploration program may result in greater exploration and dry hole costs.
Goodwill and Intangibles |
Goodwill and intangible exploration rights are not amortized. The Company evaluates goodwill and intangible exploration rights for impairment annually or whenever events or changes in circumstances indicate that the carrying value may be impaired in accordance with methodologies prescribed in Statement of Financial Accounting Standards (“SFAS”) SFAS No. 142 “Goodwill and Other Intangible Assets.” There was no impairment of goodwill or intangible exploration rights as of June 30, 2006.
Asset Retirement Obligations |
Effective July 1, 2002, the Company adopted the provisions of SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset (oil & gas properties) and amortized on aunits-of-production basis over the life of the related reserves. Accretion expense in connection with the discounted liability is recognized over the remaining life of the related reserves.
The estimated liability is based on the future estimated cost of land reclamation, plugging the existing oil and gas wells and removing the surface facilities equipment in the Palm Valley, Mereenie, Kotaneelee, Nockatunga fields and the Cooper Basin. The liability is a discounted liability using a credit-adjusted risk-free rate on the date such liabilities are determined. A market risk premium was excluded from the estimate of asset retirement obligations because the amount was not capable of being estimated. Revisions to the liability could occur due to changes in the estimates of these costs, acquisition of additional properties and as new wells are drilled.
Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Judgments are based upon such things as field life and estimated costs. Such costs could differ significantly when they are incurred.
Revenue Recognition |
The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Company’s share of production. Revenues from the purchase, sale and transportation of natural gas are recognized upon completion of the sale and when transported volumes are delivered. Shipping and handling costs in connection with such deliveries are included in production costs (cost of goods sold). Revenue under carried interest agreements is recorded in the period when the net proceeds become receivable, measurable and collection is reasonably assured. The time when the net revenues become receivable and collection is reasonably assured depends on the terms and conditions of the relevant agreements and the practices followed by the operator. As a result, net revenues from carried interests may lag the production month by one or more months.
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Liquidity and Capital Resources
Consolidated |
At June 30, 2006, the Company on a consolidated basis had approximately $21.9 million of cash and cash equivalents and $540,000 in marketable securities.
Net cash provided by operations was $11,766,000 in 2006 compared to $8,776,000 in 2005. The increase is primarily related to an increase of approximately $662,000 in net income, an increase in non cash items of $1,790,000 and an increase in current payables of approximately $144,000. Cash flow from operations is primarily the result of MPAL’s oil and gas activities.
During 2006, the Company had a net decrease in marketable securities of $2,677,000 compared to a net investment of $40,000 in 2005. The decrease in investments resulted from the use of investments to fund MPC’s purchase of MPAL’s minority shares during 2006 (See Note 2 to the Consolidated Financial Statements).
As to MPC (Unconsolidated) |
During fiscal 2006, MPC received a dividend from MPAL of approximately $941,000. In August 2006, a dividend of approximately $5.9 million was received from MPAL. Also in August 2006, MPC loaned approximately $4.1 million to MPAL payable August, 2011. Interest on the loan will be paid annually. The tax effects of these transactions was recorded in fiscal year 2006.
At June 30, 2006, MPC, on an unconsolidated basis, had working capital of approximately $480,000. Working capital is comprised of current assets less current liabilities. MPC’s current cash position and its annual MPAL dividend should be adequate to meet its current and future cash requirements. In fiscal 2006, MPC invested substantial portions of its cash to purchase the remaining minority shares of MPAL (See Note 2 to the financial statements.)
MPC has a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2006, MPC purchased 680,850 of its shares at a cost of approximately $686,000. There were no shares purchased during fiscal 2006 or 2005.
As to MPAL |
At June 30, 2006, MPAL had working capital of approximately $24.3 million. MPAL had budgeted approximately A$15.5 million for specific exploration projects in fiscal year 2006 as compared to the A$5.8 million expended during fiscal 2006. The current composition of MPAL’s oil and gas reserves are such that MPAL’s future revenues in the long-term are expected to be derived from the sale of gas in Australia. MPAL’s current contracts for the sale of Palm Valley and Mereenie gas will expire during fiscal year 2012 and 2009, respectively. Unless MPAL is able to obtain additional contracts for its remaining gas reserves or be successful in its current exploration program, its revenues will be materially reduced after 2009. The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. While opportunities exist to contract additional gas sales in the Northern Territory market after these dates, there is strong competition within the market and there are no assurances that the Palm Valley producers will be able to contract for the sale of the remaining uncontracted reserves.
MPAL expects to fund its exploration costs through its cash and cash equivalents and cash flow from Australian operations. MPAL also expects that it will continue to seek partners to share its exploration costs. If MPAL’s efforts to find partners are unsuccessful, it may be unable or unwilling to complete the exploration program for some of its properties.
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Off Balance Sheet Arrangements
We do not use off-balance sheet arrangements such as securitization of receivables with any unconsolidated entities or other parties. The Company does not engage in trading or risk management activities and does not have material transactions involving related parties.
Contractual Obligations
The following is a summary of our consolidated contractual obligations as of June 30, 2006:
Payments Due by Period | |||||||||||||||||||||
Less Than | More Than | ||||||||||||||||||||
Contractual Obligations | Total | 1 Year | 1-3 Years | 3-5 Years | 5 Years | ||||||||||||||||
Long-Term Debt Obligations | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
Capital Lease Obligations | — | — | — | — | — | ||||||||||||||||
Operating Lease Obligations | 555,000 | 184,000 | 371,000 | — | — | ||||||||||||||||
Purchase Obligations(1) | 3,380,000 | 3,380,000 | — | — | — | ||||||||||||||||
Asset Retirement Obligations | 7,147,000 | 169,000 | 4,677,000 | — | 2,301,000 | ||||||||||||||||
Total | $ | 11,082,000 | $ | 3,733,000 | $ | 5,048,000 | $ | — | $ | 2,301,000 | |||||||||||
(1) | Represents firm commitments for exploration and capital expenditures. The Company is committed to these expenditures, however some may be farmed out to third parties. Exploration contingent expenditures of $15,284,000 which are not legally binding have been excluded from the table above and based on exploration decisions would be due as follows: $1,158,000 (less than 1 year), $14,126,000 (1-3 years), $0 (3-5 years). |
Recent Accounting Pronouncements
On March 30, 2005, the FASB issued FASB Interpretation No. (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. FIN 47 is effective for the fiscal year ended June 30, 2006.
Management has determined that the Company currently does not have any conditional asset retirement obligations, but may incur such in the future at which time they will be recorded.
On February 3, 2006, the FASB issued FASB Staff Position (“FSP”) 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation that Allow for Cash Settlement upon the Occurrence of a Contingent Event.” FSP 123(R)-4 requires that an option or similar instrument that is classified as equity, but subsequently becomes a liability because a contingent cash settlement event is probable of occurring, shall be accounted for similar to a modification from equity to liability award. FSP 123(R)-4 was effective for the Company for the quarter ended March 31, 2006. There was no impact on the Company’s financial statements upon adoption of this FSP since the terms of the Company’s Stock Option Plan do not provide for cash settlements as contemplated by the FSP.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109 “Accounting for Income Taxes” and must be adopted by the Company no later than July 1, 2007. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the financial statements uncertain tax positions that the company has taken or expects to take in its tax returns. The Company is evaluating the impact of adopting FIN 48.
On September 13, 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108 which is effective for the fiscal year ended June, 2007. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements. The Company believes that SAB 108 will not have a material impact on the consolidated financial statements.
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Results of Operations
2006 vs. 2005 |
Revenues |
Oil sales increased 40% in 2006 to $10,616,000 from $7,574,000 in 2005 because of a 37% increase in the average sales price per barrel and a 2% increase in barrels sold due mostly toKiana-1 in the Cooper Basin. The increase was offset by the 1% Australian foreign exchange rate decrease discussed below. Oil unit sales (net of royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:
Twelve Months Ended June 30, | |||||||||||||||||
2006 Sales | 2005 Sales | ||||||||||||||||
Average Price | Average Price | ||||||||||||||||
Bbls | A.$ per bbl | Bbls | A.$ per bbl | ||||||||||||||
Australia: | |||||||||||||||||
Mereenie Field | 99,838 | 86.23 | 116,920 | 64.15 | |||||||||||||
Cooper Basin | 20,700 | 94.91 | 4,002 | 62.65 | |||||||||||||
Nockatunga Project | 34,127 | 80.79 | 30,567 | 57.28 | |||||||||||||
Total | 154,665 | 86.17 | 151,489 | 62.74 | |||||||||||||
Amounts presented above for oil prices and below for gas prices are in Australian dollars to show a more meaningful trend of underlying operations. For the years ended June 30, 2006 and 2005, the average foreign exchange rates were .7477 and ..7533 respectively.
Gas sales increased 13% to $14,061,000 in 2006 from $12,478,000 in 2005. The increase was primarily the result a 14% increase in price per mcf sold offset by decreased sales volume in 2006 and the 1% Australian foreign exchange rate decrease discussed below.
The volumes in billion cubic feet (bcf) (net of royalties) and the average price of gas per thousand cubic feet (mcf) sold during the periods indicated were as follows:
Twelve Months Ended June 30, | |||||||||||||||||
2006 Sales | 2005 Sales | ||||||||||||||||
A.$ Average | A.$ Average | ||||||||||||||||
Bcf | Price per mcf | Bcf | Price per mcf | ||||||||||||||
Australia: Palm Valley | 1.698 | 2.17 | 2.017 | 2.14 | |||||||||||||
Australia: Mereenie | 4.028 | 3.42 | 3.724 | 2.97 | |||||||||||||
Total | 5.726 | 3.04 | 5.741 | 2.67 | |||||||||||||
Other production related revenues increased 4% to $1,886,000 in 2006 from $1,818,000 in 2005. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which increased as a result of the higher volumes of gas sold at Mereenie, and offset by the 1% Australian foreign exchange rate decrease discussed below.
Costs and Expenses |
Production costs increased 34% in 2006 to $8,220,000 from $6,144,000 in 2005. The increase in 2006 was primarily the result of increased expenditures of $1,600,000 in the Mereenie and Palm Valley fields mostly due to the Mereenie workover program, $102,000 in the Nockatunga project and $409,000 in the Cooper Basin. The increase was partially offset by the 1% Australian foreign exchange rate decrease discussed below.
Exploration and dry hole costs decreased 21% to $3,265,000 in 2006 from $4,157,000 in 2005. These costs related to the exploration work being performed on MPAL’s properties. The primary reasons for the decrease in 2006 were work performed on the Nockatunga project ($630,000), costs related to exploration activities in New Zealand ($1,141,000) and the 1% Australian foreign exchange rate decrease discussed below. The
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decrease in costs was partially offset by an increase in costs incurred in 2006 on properties in the Mereenie and Palm Valley fields ($880,000).
Depletion, depreciation and amortization decreased 10% to $6,314,000 in 2006 from $6,994,000 in 2005. Depletion expense for the Palm Valley and Mereenie fields decreased 20% during the 2006 period primarily because of a decrease in depletable costs of $4,740,000. This decrease was partially offset by an increase in depletion for the Nockatunga project ($378,000) and properties in the Cooper Basin ($198,000) primarily because of a higher depletion rate for 2006 due to a change in reserve estimates. Depletion also decreased due to the 1% Australian foreign exchange rate decrease discussed below.
Auditing, accounting and legal expenses increased 7% to $472,000 in 2006 from $442,000 in 2005 primarily because of the administrative, auditing and legal expenses with respect to new SEC and accounting rules adopted pursuant to the Sarbanes-Oxley Act of 2002, offset by the 1% Australian foreign exchange rate decrease discussed below. The Company anticipates that it will be required in the future to incur significant administrative, auditing and legal expenses with respect to the Sarbanes-Oxley Act of 2002, particularly the requirements to document, test and audit the Company’s internal controls to comply with Section 404 of the Act and rules adopted thereunder. Management’s opinion on the internal controls of the Company is required for the fiscal year ending June 30, 2008. An audit opinion on the design and operating effectiveness of controls is expected to be required for the fiscal year ending June 30, 2009.
Accretion expense increased 4% to $425,000 in 2006 from $407,000 in 2005. Accretion expense represents the accretion on the asset retirement obligations (ARO) under SFAS 143. The increase in the 2006 period is partially offset by the 1% decrease in the Australian foreign exchange rate discussed below.
Loss on asset retirement obligation settlement is the result of adjusting the estimated asset retirement cost to actual expenditures incurred for producing wells in the Mereenie field that were plugged and restored in accordance with environmental regulations. The loss recorded for 2006 is $445,000.
Shareholder communications costs increased 98% to $450,000 from $227,000 in 2006 due to costs related to the exchange offer (see Note 2 to the Consolidated Financial Statements).
Other administrative expenses increased 82% to $1,456,000 from $800,000 in 2006 primarily due to a non-cash charge for directors’ stock option expense of $365,000, increased consulting costs of $191,000 relating to Mereenie contract negotiations and a charge to bad debts of $48,000, offset by the 1% decrease in the Australian foreign exchange rate discussed below.
Income Taxes |
Provision for income tax for the year ended June 30, 2006 was $1,679,000 compared to an income tax benefit for the year ended June 30, 2005 of $82,152. The increase in the tax provision relates primarily to the increase in income for the year ended June 30, 2006, an adjustment to prior year deferred taxes, and reduced benefits relating to New Zealand foreign losses (see Note 6 to the Consolidated Financial Statements).
Exchange Effect
The value of the Australian dollar relative to the U.S. dollar decreased to $.7301 at June 30, 2006 compared to $.7620 at June 30, 2005. This resulted in a $705,817 debit to accumulated translation adjustments for fiscal 2006. The 4% decrease in the value of the Australian dollar decreased the reported asset and liability amounts in the balance sheet at June 30, 2006 from the June 30, 2005 amounts. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2006 was $.7477, which is a 1% decrease compared to the $.7533 rate for fiscal 2005.
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2005 vs. 2004 |
Revenues |
Oil sales increased 54% in 2005 to $7,574,000 from $4,923,000 in 2004 because of the 5% Australian foreign exchange rate increase discussed below and a 49% increase in the average sales price per barrel. Oil unit sales (net of royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:
Twelve Months Ended June 30, | |||||||||||||||||
2005 Sales | 2004 Sales | ||||||||||||||||
Average Price | Average Price | ||||||||||||||||
Bbls | A.$ per bbl | Bbls | A.$ per bbl | ||||||||||||||
Australia: | |||||||||||||||||
Mereenie Field | 116,920 | 64.15 | 110,955 | 43.44 | |||||||||||||
Cooper Basin | 4,002 | 62.65 | 6,522 | 37.29 | |||||||||||||
Nockatunga Project | 30,567 | 57.28 | 34,105 | 38.73 | |||||||||||||
Total | 151,489 | 62.74 | 151,582 | 42.12 | |||||||||||||
Amounts presented above for oil prices and below for gas prices are in Australian dollars to show a more meaningful trend of underlying operations. For the years ended June 30, 2005 and 2004, the average foreign exchange rates were .7533 and ..7179, respectively.
Gas sales decreased 3% to $12,478,000 in 2005 from $12,870,000 in 2004. The decrease was primarily the result of the one time proceeds of $1,135,000 from the Kotaneelee gas field settlement recorded in 2004. This was partially offset by the 5% Australian foreign exchange rate increase discussed below, an increase in price per mcf sold and increased sales volume in 2005.
The volumes in billion cubic feet (bcf) (net of royalties) and the average price of gas per thousand cubic feet (mcf) sold during the periods indicated were as follows:
Twelve Months Ended June 30, | |||||||||||||||||
2005 Sales | 2004 Sales | ||||||||||||||||
A.$ Average | A.$ Average | ||||||||||||||||
Bcf | Price per mcf | Bcf | Price per mcf | ||||||||||||||
Australia: Palm Valley | 2.017 | 2.14 | 2.376 | 2.25 | |||||||||||||
Australia: Mereenie | 3.724 | 2.97 | 3.287 | 2.86 | |||||||||||||
Total | 5.741 | 2.67 | 5.663 | 2.61 | |||||||||||||
Other production related revenues increased 11% to $1,818,000 in 2005 from $1,632,000 in 2004. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which increased as a result of the higher volumes of gas sold at Mereenie, and because of the 5% Australian foreign exchange rate increase discussed below.
Costs and Expenses |
Production costs increased 13% in 2005 to $6,144,000 from $5,416,000 in 2004. The increase in 2005 was primarily the result of increased expenditures in the Mereenie and Palm Valley fields ($789,000) and the 5% Australian foreign exchange rate increase discussed below, partially offset by lower expenditures for the Nockatunga project and the Cooper Basin.
Exploration and dry hole costs increased 29% to $4,157,000 in 2005 from $3,225,000 in 2004. The 2005 and 2004 costs related to the exploration work being performed on MPAL’s properties. The primary reasons for the increase in 2005 were work performed on the Nockatunga project ($893,000), costs related to exploration activities in New Zealand ($567,000) and the 5% Australian foreign exchange rate increase
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discussed below. These costs were partially offset by lower costs incurred in 2005 on properties in Southern Australia ($476,000).
Salaries and employee benefits decreased 28% to $2,726,000 in 2005 from $3,812,000 in 2004. During the 2004 period, MPAL curtailed its pension plan, which resulted in a $1,248,000 charge, of which $961,000 was non cash. This reduction was partially offset by the 5% Australian foreign exchange rate increase discussed below.
Depletion, depreciation and amortization increased 10% from $6,342,000 in 2004 to $6,994,000 in 2005. Depletion expense for the Palm Valley and Mereenie fields increased 16% during the 2005 period primarily because of a higher depletion rate for 2005 due to a change in reserve estimates. Depletion also increased due to the 5% Australian foreign exchange rate increase discussed below.
Auditing, accounting and legal expenses increased 7% in 2005 to $442,000 from $414,000 in 2004 primarily because of the 5% Australian foreign exchange rate increase discussed below. The Company anticipates that it will be required in the future to incur significant administrative, auditing and legal expenses with respect to new SEC and accounting rules adopted pursuant to the Sarbanes-Oxley Act of 2002, particularly the requirements to document, test and audit the Company’s internal controls to comply with Section 404 of the Act and rules adopted thereunder. Management’s opinion on the internal controls of the Company is required for the fiscal year ending June 30, 2008. An audit opinion on the design and operating effectiveness of controls is expected to be required for the fiscal year ending June 30, 2009.
Accretion expense increased 14% in the 2005 period from $357,000 in 2004 to $407,000 in 2005. Accretion expense represents the accretion on the asset retirement obligations (ARO) under SFAS 143 that was adopted effective July 1, 2002. The increase in the 2005 period is primarily the 5% increase in the Australian foreign exchange rate discussed below.
Shareholder communications costs increased 26% from $180,000 in 2004 to $227,000 in 2005 primarily because of MPC and MPAL’s increased costs related to preparing public filings for distribution and the 5% increase in the Australian foreign exchange rate discussed below.
Other administrative expenses increased 21% from $660,000 in 2004 to $800,000 in 2005 primarily due to increased consulting costs and the 5% increase in the Australian foreign exchange rate discussed below.
Interest Income |
Interest income increased 4% to $1,142,000 in 2005 from $1,099,000 in 2004 primarily because of the 5% Australian foreign exchange rate increase discussed below.
Income Taxes |
Income tax benefits for the years ended June 30, 2005 and 2004 were $82,152 and $778,085, respectively. Income tax benefits were reduced in 2005 as a result of the lack of the reversal of the reserve of $1,266,000 recognized in 2004 on MPAL deferred tax assets generated from MPAL’s financing subsidiary. This was offset by a reduction in Canadian income tax expense of $421,000 in 2005, as a result of reduced Canadian revenues. As a result of a change in Australian tax law during 2004, MPAL docs not expect to receive similar financing benefits in the future.
Exchange Effect |
The value of the Australian dollar relative to the U.S. dollar increased to $.7620 at June 30, 2005 compared to $.6993 at June 30, 2004. This resulted in a $2,169,000 credit to accumulated translation adjustments for fiscal 2005. The 9% increase in the value of the Australian dollar increased the reported asset and liability amounts in the balance sheet at June 30, 2005 from the June 30, 2004 amounts. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2005 was $.7533, which is a 5% increase compared to the $.7179 rate for fiscal 2004.
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Item 7A. | Quantitative and Qualitative Disclosure About Market Risk. |
The Company does not have any significant exposure to market risk, other than as previously discussed regarding foreign currency risk and the risk of fluctuations in the world price of crude oil, as the only market risk sensitive instruments are its investments in marketable securities. At June 30, 2006, the carrying value of such investments including those classified as cash and cash equivalents was approximately $22.4 million, which approximates the fair value of the securities. Since the Company expects to hold the investments to maturity, the maturity value should be realized. A 10% change in the Australian foreign currency rate compared to the U.S. dollar would increase or decrease revenues and costs and expenses by $2.7 million and $2.4 million, respectively. For the twelve months ended June 30, 2006, oil sales represented approximately 43% of production revenues. Based on 2006 sales volume and revenue, a 10% change in oil price would increase or decrease oil revenues by $1,062,000. Gas sales, which represented approximately 57% of production revenues in 2006, are derived primarily from the Palm Valley and Mereenie fields in the Northern Territory of Australia and the gas prices are set according to long term contracts that are subject to changes in the Australian Consumer Price Index.
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Item 8. | Financial Statements and Supplementary Data. |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Magellan Petroleum Corporation
Hartford, Connecticut
We have audited the accompanying consolidated balance sheets of Magellan Petroleum Corporation (the “Company”) as of June 30, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Magellan Petroleum Corporation as of June 30, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP |
September 27, 2006
Hartford, Connecticut
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MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
June 30, | ||||||||||
2006 | 2005 | |||||||||
ASSETS | ||||||||||
Current assets: | ||||||||||
Cash and cash equivalents | $ | 21,882,882 | $ | 21,733,375 | ||||||
Accounts receivable — Trade | 4,809,051 | 4,210,174 | ||||||||
Accounts receivable — Working Interest Partners | 413,786 | 864,922 | ||||||||
Marketable securities | 539,675 | 3,216,541 | ||||||||
Inventories | 734,887 | 591,997 | ||||||||
Other assets | 317,496 | 526,703 | ||||||||
Total current assets | 28,697,777 | 31,143,712 | ||||||||
Deferred income taxes | 1,129,719 | 1,014,907 | ||||||||
Property and equipment, net: | ||||||||||
Oil and gas properties (successful efforts method) | 87,831,709 | 80,765,911 | ||||||||
Land, buildings and equipment | 2,448,790 | 2,552,980 | ||||||||
Field equipment | 789,921 | 1,620,909 | ||||||||
91,070,420 | 84,939,800 | |||||||||
Less accumulated depletion, depreciation and amortization | (63,287,726 | ) | (60,674,306 | ) | ||||||
Net property and equipment | 27,782,694 | 24,265,494 | ||||||||
Intangible exploration rights | 5,323,347 | — | ||||||||
Goodwill | 5,646,747 | — | ||||||||
Total assets | $ | 68,580,284 | $ | 56,424,113 | ||||||
LIABILITIES, MINORITY INTERESTS AND STOCKHOLDERS’ EQUITY | ||||||||||
Current liabilities: | ||||||||||
Accounts payable | $ | 1,856,515 | $ | 3,602,085 | ||||||
Accrued liabilities | 1,919,739 | 1,308,004 | ||||||||
Income taxes payable | 101,746 | 25,879 | ||||||||
Total current liabilities | 3,878,000 | 4,935,968 | ||||||||
Long term liabilities: | ||||||||||
Deferred income taxes | 1,435,583 | — | ||||||||
Asset retirement obligations | 7,147,261 | 5,729,180 | ||||||||
Total long term liabilities | 8,582,844 | 5,729,180 | ||||||||
Minority interests | — | 18,583,046 | ||||||||
Commitments (Note 11) | — | — | ||||||||
Stockholders’ equity: | ||||||||||
Common stock, par value $.01 per share: | ||||||||||
Authorized 200,000,000 shares Outstanding 41,500,138 and 25,783,243 | 415,001 | 257,832 | ||||||||
Capital in excess of par value | 73,145,577 | 44,402,182 | ||||||||
Total capital | 73,560,578 | 44,660,014 | ||||||||
Accumulated deficit | (14,412,688 | ) | (15,161,462 | ) | ||||||
Accumulated other comprehensive loss | (3,028,450 | ) | �� | (2,322,633 | ) | |||||
Total stockholders’ equity | 56,119,440 | 27,175,919 | ||||||||
Total liabilities, minority interests and stockholders’ equity | $ | 68,580,284 | $ | 56,424,113 | ||||||
See accompanying notes.
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MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended June 30, | |||||||||||||
2006 | 2005 | 2004 | |||||||||||
Revenues: | |||||||||||||
Oil sales | $ | 10,615,761 | $ | 7,574,022 | $ | 4,922,585 | |||||||
Gas sales | 14,060,968 | 12,478,293 | 12,870,065 | ||||||||||
Other production related revenues | 1,885,706 | 1,818,471 | 1,631,613 | ||||||||||
Total revenues | 26,562,435 | 21,870,786 | 19,424,263 | ||||||||||
Costs and expenses: | |||||||||||||
Production costs | 8,220,013 | 6,144,339 | 5,416,465 | ||||||||||
Exploratory and dry hole costs | 3,264,837 | 4,157,344 | 3,225,066 | ||||||||||
Salaries and employee benefits | 2,709,172 | 2,726,341 | 3,812,012 | ||||||||||
Depletion, depreciation and amortization | 6,314,049 | 6,994,253 | 6,341,998 | ||||||||||
Auditing, accounting and legal services | 471,596 | 441,642 | 413,754 | ||||||||||
Accretion expense | 425,254 | 406,960 | 356,981 | ||||||||||
Shareholder communications | 449,561 | 227,032 | 179,840 | ||||||||||
Loss on settlement of asset retirement obligation | 444,566 | — | — | ||||||||||
Gain on sale of field equipment | (119,445 | ) | — | — | |||||||||
Other administrative expenses | 1,455,696 | 800,200 | 659,751 | ||||||||||
Total costs and expenses | 23,635,299 | 21,898,111 | 20,405,867 | ||||||||||
Operating income (loss) | 2,927,136 | (27,325 | ) | (981,604 | ) | ||||||||
Interest income | 1,268,641 | 1,141,802 | 1,099,440 | ||||||||||
Income before income taxes and minority interests | 4,195,777 | 1,114,477 | 117,836 | ||||||||||
Income tax expense (benefit) | 1,678,980 | (82,152 | ) | (778,085 | ) | ||||||||
Income before minority interests | 2,516,797 | 1,196,629 | 895,921 | ||||||||||
Minority interests | (1,768,023 | ) | (1,109,669 | ) | (545,860 | ) | |||||||
Net income | $ | 748,774 | $ | 86,960 | $ | 350,061 | |||||||
Average number of shares: | |||||||||||||
Basic | 28,353,463 | 25,783,243 | 25,644,566 | ||||||||||
Diluted | 28,453,270 | 25,783,243 | 25,682,160 | ||||||||||
Per share (basic and diluted) | |||||||||||||
Net income | $ | .03 | — | $ | .01 | ||||||||
See accompanying notes.
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MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF
STOCKHOLDERS’ EQUITY
Three Years Ended June 30, 2006
Accumulated | ||||||||||||||||||||||||||||
Capital in | Other | Total | ||||||||||||||||||||||||||
Number of | Common | Excess of | Accumulated | Comprehensive | Comprehensive | |||||||||||||||||||||||
Shares | Stock | Par Value | Deficit | Loss | Total | Income | ||||||||||||||||||||||
June 30, 2003 | 24,427,376 | $ | 244,274 | $ | 42,907,741 | $ | (15,598,483 | ) | $ | (5,406,527 | ) | $ | 22,147,005 | |||||||||||||||
Net income | — | — | — | 350,061 | — | 350,061 | 350,061 | |||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | — | 915,150 | 915,150 | 915,150 | |||||||||||||||||||||
Total comprehensive income | — | — | — | — | — | — | 1,265,211 | |||||||||||||||||||||
Stock exchange | 1,300,000 | 13,000 | 1,495,000 | 1,508,000 | ||||||||||||||||||||||||
Issuance of common stock | 55,867 | 558 | (559 | ) | — | — | (1 | ) | ||||||||||||||||||||
June 30, 2004 | 25,783,243 | $ | 257,832 | $ | 44,402,182 | $ | (15,248,422 | ) | $ | (4,491,377 | ) | $ | 24,920,215 | |||||||||||||||
Net income | — | — | — | 86,960 | — | 86,960 | 86,960 | |||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | — | 2,168,744 | 2,168,744 | 2,168,744 | |||||||||||||||||||||
Total comprehensive income | — | — | — | — | — | — | 2,255,704 | |||||||||||||||||||||
June 30, 2005 | 25,783,243 | $ | 257,832 | $ | 44,402,182 | $ | (15,161,462 | ) | $ | (2,322,633 | ) | $ | 27,175,919 | |||||||||||||||
Net income | — | — | — | 748,774 | — | 748,774 | 748,774 | |||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | — | (705,817 | ) | (705,817 | ) | (705,817 | ) | ||||||||||||||||||
Stock exchange | 15,716,895 | 157,169 | 28,367,956 | — | — | 28,525,125 | ||||||||||||||||||||||
Stock option compensation | — | — | 375,439 | — | — | 375,439 | ||||||||||||||||||||||
Total comprehensive income | — | — | — | — | — | — | 42,957 | |||||||||||||||||||||
June 30, 2006 | 41,500,138 | $ | 415,001 | $ | 73,145,577 | $ | (14,412,688 | ) | $ | (3,028,450 | ) | $ | 56,119,440 | |||||||||||||||
See accompanying notes.
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MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended June 30, | ||||||||||||||
2006 | 2005 | 2004 | ||||||||||||
Operating Activities: | ||||||||||||||
Net income | $ | 748,774 | $ | 86,960 | $ | 350,061 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||
Gain from sale of field equipment | (119,445 | ) | — | — | ||||||||||
Depletion, depreciation and amortization | 6,314,049 | 6,994,253 | 6,341,998 | |||||||||||
Accretion expense | 425,254 | 406,960 | 356,981 | |||||||||||
Deferred income taxes | (157,300 | ) | (1,454,544 | ) | (1,445,241 | ) | ||||||||
Director’s options expense | 375,439 | — | — | |||||||||||
Minority interests | 1,768,023 | 1,109,669 | 545,860 | |||||||||||
Exploration and dry hole costs | 2,997,026 | 3,200,816 | 2,897,766 | |||||||||||
Loss on settlement of asset retirement obligation | 444,566 | — | — | |||||||||||
Increase (decrease) in operating assets and liabilities: | ||||||||||||||
Accounts receivable | (774,696 | ) | (978,727 | ) | 1,456,833 | |||||||||
Other assets | 209,207 | (208,563 | ) | 905,146 | ||||||||||
Inventories | (170,664 | ) | 57,207 | (142,397 | ) | |||||||||
Accounts payable and accrued liabilities | (368,724 | ) | (191,341 | ) | (715,548 | ) | ||||||||
Income taxes payable | 74,416 | (246,495 | ) | 166,477 | ||||||||||
Net cash provided by operating activities | 11,765,925 | 8,776,195 | 10,717,936 | |||||||||||
Investing Activities: | ||||||||||||||
Additions to property and equipment | (5,072,500 | ) | (4,132,434 | ) | (5,254,771 | ) | ||||||||
Proceeds from sale of field equipment | 119,445 | — | — | |||||||||||
Oil and gas exploration activities | (2,997,026 | ) | (3,200,816 | ) | (2,897,766 | ) | ||||||||
Decrease in construction payables | (627,732 | ) | (1,022,120 | ) | (785,386 | ) | ||||||||
Acquisition of minority interest in MPAL | (3,630,374 | ) | — | — | ||||||||||
Marketable securities matured | 5,044,574 | 5,599,328 | 5,760,239 | |||||||||||
Marketable securities purchased | (2,367,707 | ) | (5,639,435 | ) | (6,750,171 | ) | ||||||||
Net cash used in investing activities | (9,531,320 | ) | (8,395,477 | ) | (9,927,855 | ) | ||||||||
Financing Activities: | ||||||||||||||
Dividends to MPAL minority shareholders | (765,641 | ) | (821,732 | ) | (744,971 | ) | ||||||||
Net cash used in financing activities | (765,641 | ) | (821,732 | ) | (744,971 | ) | ||||||||
Effect of exchange rate changes on cash and cash equivalents | (1,319,457 | ) | 1,767,769 | 320,046 | ||||||||||
Net increase in cash and cash equivalents | 149,507 | 1,326,755 | 365,156 | |||||||||||
Cash and cash equivalents at beginning of year | 21,733,375 | 20,406,620 | 20,041,464 | |||||||||||
Cash and cash equivalents at end of year | $ | 21,882,882 | $ | 21,733,375 | $ | 20,406,620 | ||||||||
Cash Payments: | ||||||||||||||
Income taxes | 1,773,727 | 13,000 | 12,000 | |||||||||||
Interest | — | — | — |
Supplemental Schedule of Noncash Investing and Financing Activities:
The Company purchased the remaining minority shares of MPAL for $32,155,498 which includes cash consideration of $1,563,507, transaction costs of $1,990,410 and stock consideration of $28,601,581. Costs of registering securities in the amount of $76,457 were treated as a reduction to additional paid in capital.
Fair value of assets acquired | $ | 37,980,603 | |||
Consideration paid for capital stock | 32,155,498 | ||||
Liabilities assumed | 5,825,105 | ||||
See Note 2 to the Consolidated Financial Statements.
In addition, non-cash asset retirement obligations increased as a result of a revision in estimates by $1,667,877.
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1. | Summary of Significant Accounting Policies |
Principles of Consolidation |
Magellan Petroleum Corporation (the Company or MPC) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2006 and 2005, MPC’s principal asset was a 100% and 55%, respectively, equity interest in its subsidiary, Magellan Petroleum Australia Limited (MPAL) (See Note 2.). MPAL’s major assets are two petroleum production leases covering the Mereenie oil and gas field (35% working interest), one petroleum production lease covering the Palm Valley gas field (52% working interest), and three petroleum production leases covering the Nockatunga oil field (41% working interest). Both the Mereenie and Palm Valley fields are located in the Amadeus Basin in the Northern Territory of Australia. The Nockatunga filed is located in the Cooper Basin in South Australia. MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada.
The accompanying consolidated financial statements include the accounts of MPC and its subsidiary, MPAL, collectively the Company. All intercompany transactions have been eliminated.
Revenue Recognition |
The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Company’s share of production. Revenues from the purchase, sale and transportation of natural gas are recognized upon completion of the sale and when transported volumes are delivered. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which are recorded at the time of sale. Shipping and handling costs in connection with such deliveries are included in production costs. Revenue under carried interest agreements is recorded in the period when the net proceeds become receivable, measurable and collection is reasonably assured. The time the net revenues become receivable and collection is reasonably assured depends on the terms and conditions of the relevant agreements and the practices followed by the operator. As a result, net revenues from carried interests may lag the production month by one or more months.
Stock-Based Compensation |
The Company has one Stock Option Plan. Under SFAS No. 123(R) “Share-Based Payment,” the costs resulting from all share-based payment transactions are recognized in the consolidated financial statements. This statement establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires the application of a fair-value measurement method of accounting for share-based payment transactions with employees and non-employees. The Company uses the Black-Scholes option valuation model to determine the fair value of its Stock Option share awards. The Black-Scholes model includes various assumptions, including the expected volatility and the expected life of the share awards. These assumptions reflect the Company’s best estimates, but they involve inherent uncertainties based on market conditions generally outside of the control of the Company. As a result, if other assumptions had been used, stock-based compensation expense, as calculated and recorded under SFAS 123(R) could have been materially impacted. Furthermore, if the Company uses different assumptions in future periods, stock-based compensation expense could be materially impacted in future periods. The Company’s policy for attributing the value of graded vest share-based payments is an accelerated multiple-option approach.
Oil and Gas Properties |
Oil and gas properties are located in Australia, Canada and the United Kingdom. The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method, the costs of successful wells, development dry holes, productive leases, and permitted concession costs are capitalized and amortized on aunits-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. The Company records its proportionate share in its working interest agreements in the respective classifications of assets, liabilities and expenses. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any impairment
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charged to expense. The successful efforts method also imposes limitations on the carrying or book value of proved oil and gas properties. Oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The Company estimates the future undiscounted cash flows from the affected properties to determine the recoverability of carrying amounts. In general, analyses are based on proved developed reserves, except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. For Mereenie and Palm Valley, proved developed natural gas reserves are limited to contracted quantities. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves or the contracted quantities.
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.
Goodwill and Intangibles |
Goodwill and intangible exploration rights are not amortized. The Company evaluates goodwill and intangible exploration rights for impairment annually or whenever events or changes in circumstances indicate that the carrying value may be impaired in accordance with methodologies prescribed in Statement of Financial Accounting Standards (“SFAS”) SFAS No. 142 “Goodwill and Other Intangible Assets.” There was no impairment of goodwill or intangible exploration rights as of June 30, 2006.
Asset Retirement Obligations |
SFAS No. 143, “Accounting for Asset Retirement Obligations” requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset (oil & gas properties) and amortized on aunits-of-production basis over the life of the related reserves. Accretion expense in connection with the discounted liability is recognized over the remaining life of the related reserves.
The estimated liability is based on the future estimated cost of land reclamation, plugging the existing oil and gas wells and removing the surface facilities equipment in the Palm Valley, Mereenie, Kotaneelee, and Nockatunga fields and the Cooper Basin. The liability is a discounted liability using a credit-adjusted risk-free rate on the date such liabilities are determined. A market risk premium was excluded from the estimate of asset retirement obligations because the amount was not capable of being estimated. Revisions to the liability could occur due to changes in the estimates of these costs, acquisition of additional properties and as new wells are drilled.
Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Such costs could differ significantly when they are incurred.
Use of Estimates |
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
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Land, Buildings and Equipment and Field Equipment |
Land, buildings and equipment and field equipment are carried at cost. Depreciation and amortization are provided on a straight-line basis over their estimated useful lives. The estimated useful lives are: buildings — 40 years, equipment and field equipment — 3 to 15 years.
Accounts Receivable |
The Company has determined that an allowance for doubtful accounts was not necessary as all receivables were expected to be realized in full.
Inventories |
Inventories consist of crude oil in various stages of transit to the point of sale and are valued at the lower of cost (determined on an average cost basis) or market.
Foreign Currency Translations |
The accounts of MPAL, whose functional currency is the Australian dollar, are translated into U.S. dollars in accordance with SFAS No. 52. The translation adjustment is included as a component of stockholders’ equity and comprehensive income (loss), whereas gains or losses on foreign currency transactions are included in the determination of income. All assets and liabilities are translated at the rates in effect at the balance sheet dates. Revenues, expenses, gains and losses are translated using quarterly weighted average exchange rates during the period. At June 30, 2006 and 2005, the Australian dollar was equivalent to U.S. $.73 and $.76, respectively. The annual average exchange rates used to translate MPAL’s operations in Australia for the fiscal years 2006, 2005 and 2004 were $.75, $.75 and $.72, respectively.
Accrued Liabilities |
At June 30, 2006 and 2005, balances in accrued liabilities which exceeded 5% of the total balance include $1,032,037 and $1,046,438 of employment benefits, respectively, $321,145 and $226,578 of payroll withholding taxes, respectively, and $457,635 and $11,963 of MPAL exchange offer costs, respectively.
Accounting for Income Taxes |
The Company follows FASB Statement 109, the liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company records a valuation allowance for deferred tax assets when it is more likely than not that such assets will not be recovered.
Financial Instruments |
The carrying value for cash and cash equivalents, accounts receivable, marketable securities and accounts payable approximates fair value based on anticipated cash flows and current market conditions.
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Cash and Cash Equivalents |
The Company considers all highly liquid short term investments with maturities of three months or less at the date of acquisition to be cash equivalents. Cash and cash equivalents are carried at cost which approximates market value. The components of cash and cash equivalents are as follows:
June 30, | ||||||||
2006 | 2005 | |||||||
Cash | $ | 1,925,923 | $ | 309,283 | ||||
Australian money market accounts and short-term commercial paper | 19,956,959 | 21,424,092 | ||||||
$ | 21,882,882 | $ | 21,733,375 | |||||
Marketable Securities |
At June 30, 2006 and 2005, MPC had the following marketable securities which are expected to be held until maturity:
June 30, 2006 | Par Value | Maturity Date | Amortized Cost | Fair Value | ||||||||||||
Short-term securities | ||||||||||||||||
U.S. government agency note | $ | 150,000 | Sept. 12, 2006 | $ | 149,991 | $ | 149,671 | |||||||||
U.S. government agency note | 240,000 | Nov. 15, 2006 | 239,288 | 238,874 | ||||||||||||
U.S. government agency note | 150,000 | Dec. 20, 2006 | 150,396 | 149,250 | ||||||||||||
Total short-term | $ | 540,000 | $ | 539,675 | $ | 537,795 | ||||||||||
June 30, 2005 | Par Value | Maturity Date | Amortized Cost | Fair Value | ||||||||||||
Short-term securities | ||||||||||||||||
U.S. government agency note | $ | 300,000 | Jul. 21, 2005 | $ | 295,437 | $ | 299,460 | |||||||||
U.S. government agency note | 575,000 | Aug. 23, 2005 | 565,532 | 572,240 | ||||||||||||
U.S. government agency note | 210,000 | Sep. 16, 2005 | 206,920 | 208,488 | ||||||||||||
U.S. government agency note | 100,000 | Sep. 16, 2005 | 98,380 | 99,280 | ||||||||||||
U.S. government agency note | 200,000 | Oct. 24, 2005 | 196,611 | 197,840 | ||||||||||||
State of Connecticut bond | 200,000 | Nov. 15, 2005 | 200,585 | 199,852 | ||||||||||||
Lewiston, Maine Pension bond | 390,000 | Dec. 15, 2005 | 390,000 | 392,336 | ||||||||||||
U.S. government agency note | 310,000 | Jan. 10, 2006 | 302,863 | 304,141 | ||||||||||||
U.S. government agency note | 300,000 | Feb. 24, 2006 | 291,980 | 292,950 | ||||||||||||
U.S. government agency note | 300,000 | Mar. 28, 2006 | 300,000 | 298,500 | ||||||||||||
U.S. government agency note | 230,000 | Apr. 28, 2006 | 223,035 | 223,008 | ||||||||||||
U.S. government agency note | 150,000 | May 02, 2006 | 145,198 | 145,350 | ||||||||||||
Total short-term | $ | 3,265,000 | $ | 3,216,541 | $ | 3,233,445 | ||||||||||
Earnings per Share |
Earnings per common share are based upon the weighted average number of common and common equivalent shares outstanding during the period. The only reconciling item in the calculation of diluted EPS is the dilutive effect of stock options which were computed using the treasury stock method. At June 30, 2006, the Company had 430,000 stock options that were issued that had a strike price below the average stock price for the year and resulted in 99,807 incremental diluted shares. In 2005, the Company did not have any stock options that were issued that had a strike price below the average stock price for the year. There were no other potentially dilutive items at June 30, 2005. At June 30, 2004, the Company had 595,000 stock options that
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were issued that had a strike price below the average stock price for the year and resulted in 37,594 incremental diluted shares.
Stock Options |
The Company’s 1998 Stock Option Plan (the “Plan”) provides for grants of non-qualified stock options principally at an option price per share of 100% of the fair value of the Company’s common stock on the date of the grant. The Plan has 1,000,000 shares authorized for awards of equity share options. Stock options are generally granted with a3-year vesting period and a10-year term. The stock options vest in equal annual installments over the vesting period, which is also the requisite service period. The 400,000 options granted to Directors on November 28, 2005 had an immediate vesting period.
In December 2004, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment.” SFAS 123(R) is effective for the first interim or annual reporting period beginning after June 15, 2005 and is a revision of SFAS No. 123, “Accounting for Stock Based Compensation” and supersedes Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees”. SFAS 123(R) eliminates the alternative to use the intrinsic value method of accounting provided by SFAS 123, which generally resulted in no compensation expense recorded in the financial statements related to the issuance of equity awards to employees. SFAS 123(R) requires recognition in the financial statements of the cost resulting from all share-based payment transactions by applying a fair-value-based measurement method to account for all share-based payment transactions with employees.
On July 1, 2005, the Company adopted SFAS 123(R) and elected the modified prospective application permitted under SFAS 123(R). Under this application, the Company is required to record compensation expense for all awards granted after the date of adoption and for the unvested portion of previously granted awards that remain outstanding at the date of adoption. Compensation expense has been and will continue to be recorded for the unvested portion of previously issued awards that were outstanding at July 1, 2005 using the same estimate of the grant date fair value and the same attribution method used to determine the pro forma disclosure under SFAS No. 123. Prior to the adoption of SFAS 123(R), the Company applied the requirements of APB 25 to account for its stock-based awards. Under APB 25, because the exercise price of the Company’s stock option equaled the market price of the underlying stock on the date of grant, no compensation expense was recognized.
The Company determined the fair value of the options at the date of grant using the Black-Scholes option pricing model. Option valuation models require the input of highly subjective assumptions including the expected stock price volatility. The assumptions used to value the Company’s grants on July 1, 2004 and November 28, 2005, respectively were: risk free interest rate -4.95% and 4.58%, expected life - -10 years and 5 years, expected volatility -.518 and ..627, expected dividend -0. The expected life of the options granted on November 28, 2005 was determined under the “simplified” method described in SAB No. 107.
Accumulated Other Comprehensive Loss |
Accumulated other comprehensive loss at June 30, 2006 and 2005 was as follows:
2006 | 2005 | |||||||
Foreign currency translation adjustments | $ | (3,028,450 | ) | $ | (2,322,633 | ) | ||
Sales Taxes |
Government sales taxes related to MPAL’s oil and gas production revenues are collected by MPAL and remitted to the Australian government. Such amounts are excluded from revenue and expenses.
Reclassifications |
Certain reclassifications of prior period data included in the accompanying consolidated financial statements have been made to conform with the current period presentation.
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Recent Accounting Pronouncements |
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109 “Accounting for Income Taxes” and must be adopted by the Company no later than July 1, 2007. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the financial statements uncertain tax positions that the company has taken or expects to take in its tax returns. The Company is evaluating the impact of adopting FIN 48.
On September 13, 2006, the SEC issued SAB No. 108 which is effective for the fiscal year ended June, 2007. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements. The Company believes that SAB 108 will not have a material impact on the consolidated financial statements.
2. | Acquisition of Minority Interest of MPAL |
During the fourth quarter of fiscal 2006, MPC completed an exchange offer (the Offer) to acquire all of the 44.87% of ordinary shares of MPAL that it did not own. Reasons for the Offer included: (1) simplification of Magellan’s corporate structure, (2) greater liquidity for investors, (3) access to capital on potentially more favorable terms for future strategic initiatives or exploration activities, (4) opportunities for cost reductions leading to organizational efficiencies and (5) the potential improvements in cash flow and tangible asset value per share for Magellan The Offer consideration was .75 newly-issued shares of MPC common stock and A$0.10 in cash consideration for each of the 20,952,916 MPAL shares that it did not own. New MPC shares were issued to MPAL’s Australian shareholders either as MPC registered shares or in the form of CDIs (CHESS Depository Interests), which have been listed on the Australian Stock Exchange (“ASX”), effective April 26, 2006, under the symbol “MGN.”
The Offer was accounted for using the purchase method of accounting. Under the purchase method of accounting, the total purchase price was allocated to the minority interests’ proportionate interest in MPAL’s identifiable assets and liabilities acquired by MPC based upon their estimated fair values. The fair value of the significant assets acquired (primarily oil and gas properties and intangible exploration rights) and the liabilities assumed was determined by management with the assistance of third party valuation experts. This process is not complete, thus the purchase price allocation is subject to refinement.
The purchase price of the exchange offer was $32,155,498. This was based upon a value of $1.82 per share of MPC common stock for the 15,716,895 shares issued, cash consideration of $1,563,507 and transaction costs of $1,990,410. The value of the MPC common stock issued was determined based on the average market price of MPC’s common stock over the3-day period before and3-day period after the date that MPAL agreed to recommend the terms of the acquisition.
The following table summarizes the estimated fair values of the assets acquired and the liabilities assumed at June 30, 2006:
Current assets | $ | 12,153,855 | |||
Property and equipment | 14,364,613 | ||||
Deferred income taxes | 492,041 | ||||
Intangible exploration rights | 5,323,347 | ||||
Goodwill | 5,646,747 | ||||
Total assets acquired | 37,980,603 | ||||
Current liabilities | (1,396,332 | ) | |||
Long term liabilities | (4,428,773 | ) | |||
Total liabilities assumed | (5,825,105 | ) | |||
Net assets acquired | $ | 32,155,498 | |||
Goodwill and intangible exploration rights are not subject to amortization.
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The following pro forma condensed income statement for the fiscal years ended June 30, 2006 and 2005 is presented as if the Offer had been completed as of July 1, 2005 and July 1, 2004, respectively.
Pro Forma Condensed Consolidated Statements of Income
For the Year Ended June 30, 2006 | |||||||||||||
Pro Forma | |||||||||||||
Adjustments to | |||||||||||||
Reflect | |||||||||||||
Exchange | |||||||||||||
Historical | Offer | Pro Forma | |||||||||||
Total revenues | $ | 26,562,435 | — | $ | 26,562,435 | ||||||||
Costs and expenses | 23,635,299 | 1,072,388 | (1) | 24,707,687 | |||||||||
Operating income | 2,927,136 | (1,072,388 | ) | 1,854,748 | |||||||||
Other income | 1,268,641 | — | 1,268,641 | ||||||||||
Income before income taxes and minority interests | 4,195,777 | (1,072,388 | ) | 3,123,389 | |||||||||
Income tax provision | (1,678,980 | ) | 321,716 | (2) | (1,357,264 | ) | |||||||
Income before minority interests | 2,516,797 | (750,672 | ) | 1,766,125 | |||||||||
Minority interests | (1,768,023 | ) | 1,768,023 | (3) | — | ||||||||
Net income | $ | 748,774 | $ | 1,017,351 | $ | 1,766,125 | |||||||
Average number of shares outstanding | |||||||||||||
Basic | 25,783,243 | (A) | 15,716,895 | (4) | 41,500,138 | ||||||||
Diluted | 25,783,243 | (A) | 15,716,895 | (4) | 41,500,138 | ||||||||
Net income per share (basic and diluted) | $ | 0.03 | $ | 0.04 | |||||||||
For the Year Ended June 30, 2005 | |||||||||||||
Pro Forma | |||||||||||||
Adjustments to | |||||||||||||
Reflect | |||||||||||||
Exchange | |||||||||||||
Historical | Offer | Pro Forma | |||||||||||
Total revenues | $ | 21,870,786 | — | $ | 21,870,786 | ||||||||
Costs and expenses | 21,898,111 | 1,053,704 | (1) | 22,951,815 | |||||||||
Operating income | (27,325 | ) | (1,053,704 | ) | (1,081,029 | ) | |||||||
Other income | 1,141,802 | — | 1,141,802 | ||||||||||
Income before income taxes and minority interests | 1,114,477 | (1,053,704 | ) | 60,773 | |||||||||
Income tax provision | 82,152 | 316,111 | (2) | 398,263 | |||||||||
Income before minority interests | 1,196,629 | (737,593 | ) | 459,036 | |||||||||
Minority interests | (1,109,669 | ) | 1,109,669 | (3) | — | ||||||||
Net income | $ | 86,960 | $ | 372,076 | $ | 459,036 | |||||||
Average number of shares outstanding | |||||||||||||
Basic | 25,783,243 | (A) | 15,716,895 | (4) | 41,500,138 | ||||||||
Diluted | 25,783,243 | (A) | 15,716,895 | (4) | 41,500,138 | ||||||||
Net income per share (basic and diluted) | $ | 0.00 | $ | 0.01 | |||||||||
(A) | Represents outstanding shares prior to the Offer. |
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Pro Forma Adjustments
1. | Represents the depletion on the excess of the purchase price over the identifiable assets and liabilities acquired which has been allocated to oil and gas properties of $1,072,388 and $1,053,704 for the fiscal years ended June 30, 2006 and 2005, respectively. |
2. | Represents the income tax effect on the depletion and transaction costs calculated based on an Australian statutory rate of 30%. |
3. | Represents the reversal of the income allocated to the minority interest as 100% of MPAL subject to the Exchange Offer is assumed to be acquired by Magellan at the beginning of the period. |
4. | Represents the number of shares assumed to be issued by Magellan pursuant to the terms of the Exchange Offer calculated as follows: |
Shares of MPAL not owned by Magellan | 20,952,916 | |||
Exchange ratio | .75 | |||
Magellan shares issued pursuant to the Exchange Offer | 15,716,895 | |||
3. | Oil and Gas Properties |
MPC had the following amounts recorded in oil and gas properties at June 30, 2006 and 2005.
Location | 2006 | 2005 | ||||||
Mereenie and Palm Valley (Australia) | $ | 78,878,810 | $ | 77,376,081 | ||||
Nockatunga (Australia)(1) | 5,716,444 | 2,487,986 | ||||||
Cooper Basin (Australia)(1) | 3,127,678 | 779,871 | ||||||
Kotaneelee (Canada) | 108,777 | 108,777 | ||||||
Other | — | 13,196 | ||||||
$ | 87,831,709 | $ | 80,765,911 | |||||
(1) | Includes costs of $434,122 in Nockatunga and $1,602,575 in Cooper Basin which are currently capitalized as exploratory well costs pending the determination of proved reserve. |
Accumulated Depletion, Depreciation and Amortization
Location | 2006 | 2005 | ||||||
Mereenie and Palm Valley (Australia) | $ | 57,850,806 | $ | 56,083,919 | ||||
Nockatunga (Australia) | 1,793,413 | 464,523 | ||||||
Cooper Basin (Australia) | 1,141,757 | 728,506 | ||||||
Kotaneelee (Canada) | 58,349 | 53,492 | ||||||
Other | — | — | ||||||
$ | 60,844,325 | $ | 57,330,440 | |||||
Depletion, Depreciation and Amortization |
During the years ended June 30, 2006, 2005 and 2004, the depletion rate by field was as follows:
2006 | 2005 | 2004 | ||||||||||
Mereenie and Palm Valley (Australia) | 24.6 | 25.6 | 20.9 | |||||||||
Nockatunga (Australia) | 24.7 | 12.1 | 9.5 | |||||||||
Cooper Basin (Australia) | 42.2 | 78.1 | 70.2 | |||||||||
Kotaneelee (Canada) | 10.0 | 8.3 | 25.0 |
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Exploratory and Dry Hole Costs |
The 2006, 2005 and 2004 costs relate primarily to the geological and geophysical work and seismic acquisition on MPAL’s exploration permits. The costs (in thousands) for MPAL were $3,265, $4,157 and $3,225 for 2006, 2005, and 2004, respectively.
See Note 12 commitments for a summary of MPAL’s required and contingent commitments for exploration expenditures for the five year period beginning July 1, 2006.
4. | Asset Retirement Obligations |
A reconciliation of the Company’s asset retirement obligations for the years ended June 30, 2006 and 2005, is as follows:
2006 | 2005 | |||||||
Balance at beginning of year | $ | 5,729,180 | $ | 4,852,416 | ||||
Liabilities incurred | — | 85,124 | ||||||
Liabilities settled | (442,469 | ) | — | |||||
Accretion expense | 425,254 | 406,960 | ||||||
Revisions to estimate | 1,667,877 | (40,000 | ) | |||||
Exchange effect | (232,581 | ) | 424,680 | |||||
Balance at end of year | $ | 7,147,261 | $ | 5,729,180 | ||||
During fiscal 2006, the Company plugged and restored 8 wells in the Mereenie field at a cost of $887,035 which resulted in a settlement loss of $444,566. In addition, based upon revised estimates for all fields, an increase of $1,667,877 was made to the total restoration liability.
During 2005, an $85,000 liability was incurred for two wells drilled in the Mereenie field. In addition, revised estimates were established for restoration costs for the Kotaneelee field in Canada.
5. | Capital and Stock Options |
MPC’s certificate of incorporation provides that any matter to be voted upon must be approved not only by a majority of the shares voted, but also by a majority of the stockholders casting votes present in person or by proxy and entitled to vote thereon.
On December 8, 2000, MPC announced a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2006, MPC had purchased 680,850 of its shares at a cost of approximately $686,000, all of which were cancelled. No shares have been repurchased during 2006, 2005 or 2004.
The Company’s Stock Option Plan provides for options to be granted at a price of not less than fair value on the date of grant and for a term of not greater than ten years. As of June 30, 2006, 395,000 options were available for future issuance under the Plan.
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The following is a summary of option transactions for the three years ended June 30, 2006:
Fair Market | |||||||||||||||||
Expiration | Number of | Value at | |||||||||||||||
Options Outstanding | Dates | Shares | Exercise Prices($) | Grant Date | |||||||||||||
June 30, 2003 | 921,000 | .85-1.57 | |||||||||||||||
Expired | (126,000 | ) | 1.57 | ||||||||||||||
Cancelled | (25,000 | ) | .85 | ||||||||||||||
Exercised | (175,000 | ) | .85-1.28 | ||||||||||||||
June 30, 2004 | 595,000 | (1.28 weighted average price | ) | ||||||||||||||
Granted | Jul. 2014 | 30,000 | 1.45 | $ | 43,500 | ||||||||||||
Expired | (595,000 | ) | 1.28 | ||||||||||||||
June 30, 2005 | 30,000 | 1.45 | |||||||||||||||
Granted | Nov. 2015 | 400,000 | 1.60 | $ | 640,000 | ||||||||||||
June 30, 2006 | 430,000 | (1.59 weighted average price | ) | ||||||||||||||
The weighted average remaining contractual term as of June 30, 2006 is 8.8 years.
Summary of Options Outstanding at June 30, 2006
Expiration | Exercise | |||||||||||||||
Dates | Total | Vested | Prices($) | |||||||||||||
Granted 2004 | Jul. 2014 | 30,000 | 20,000 | 1.45 | ||||||||||||
Granted 2006 | Nov. 2015 | 400,000 | 400,000 | 1.60 |
All of the options have been granted at the fair value at the date of grant. Upon exercise of options, the excess of the proceeds over the par value of the shares issued is credited to capital in excess of par value. For the year ended June 30, 2006, the Company recorded stock-based compensation expense for the cost of stock options of $375,439 both pre-tax and post-tax (or $.01 per basic and diluted share), respectively. The grant date fair value of the 400,000 options granted on November 28, 2005 was $365,539. Vested options are exercisable during non black out periods. This expense has no effect on cash flow.
The Company determined the fair value of the options at the date of grant using the Black-Scholes option pricing model. Option valuation models require the input of highly subjective assumptions including the expected stock price volatility. The assumptions used to value the Company’s grants on July 1, 2004 and November 28, 2005, respectively were: risk free interest rate -4.95% and 4.58%, expected life - -10 years and 5 years, expected volatility -.518 and ..627 based on historical stock price expected dividend -0. The expected life of the options granted on November 28, 2005 was determined under the “simplified” method described in SEC Staff Accounting Bulletin (“SAB”) No. 107.
For the years ended June 30, 2005 and 2004, pro forma information regarding net income and earnings per share was required by SFAS 148, and was determined as if the Company had accounted for its stock options under the fair value method of SFAS 123. The fair value for these options was estimated at the date of grant using the Black-Scholes option pricing model. The Company’s pro forma information follows:
As of June 30, 2006, there was $3,300 of total unrecognized compensation costs related to stock options, which is expected to be recognized in fiscal 2007.
On October 20, 2003, options to purchase 126,000 shares of the Company’s common stock expired without being exercised. On December 31, 2003, unvested options to purchase 25,000 shares of the Company’s common stock were cancelled when the terms of the grant were not satisfied. On March 8, 2004, 175,000 options to purchase shares of common stock were exercised in a cashless exercise that resulted in 55,867 shares being issued. The Company has a policy of repurchasing shares on the open market to satisfy
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options exercised. On February 23, 2005 options to purchase 595,000 shares of the Company’s common stock expired without being exercised.
Earnings per Share | ||||||||||||
Net Income | Basic | Diluted | ||||||||||
Net income as reported — June 30, 2004 | $ | 350,000 | $ | .01 | $ | .01 | ||||||
Stock option expense (determined under fair value method)(1) | — | — | — | |||||||||
Pro forma net income — June 30, 2004 | $ | 350,000 | $ | .01 | $ | .01 | ||||||
Net income as reported — June 30, 2005 | $ | 87,000 | $ | — | $ | — | ||||||
Stock option expense (determined under fair value method) | (18,000 | ) | — | — | ||||||||
Pro forma net income — June 30, 2005 | $ | 69,000 | $ | — | — | |||||||
(1) | There was no expense because there were no options issued or outstanding. |
6. | Income Taxes |
Components of income before income taxes and minority interests by geographic area (in thousands) are as follows:
Years Ended June 30, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
United States | $ | (1,753 | ) | $ | (1,004 | ) | $ | (548 | ) | |||
Foreign | 5,949 | 2,118 | 666 | |||||||||
Total | $ | 4,196 | $ | 1,114 | $ | 118 | ||||||
Reconciliation of the provision for income taxes (in thousands) computed at the Australian statutory rate to the reported provision for income taxes is as follows:
Years Ended June 30, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Tax provision computed at statutory rate (30%) | $ | (1,259 | ) | $ | (334 | ) | $ | (35 | ) | |||
MPC’s parent company (income) losses | (526 | ) | (301 | ) | 165 | |||||||
Non-taxable revenue from Australian government sources | 311 | 301 | 267 | |||||||||
MPAL non-deductible foreign losses (New Zealand) | (88 | ) | (513 | ) | (337 | ) | ||||||
MPAL write off of foreign advances (New Zealand) | 218 | 1,000 | — | |||||||||
Increase in MPAL deferred tax assets(a) | (243 | ) | — | — | ||||||||
Repatriation of foreign earnings(b) | (1,964 | ) | — | — | ||||||||
Reversal of prior year reserve on MPAL deferred tax assets(c) | — | — | 1,266 | |||||||||
Reversal of prior year reserve on MPC deferred tax assets(d) | 879 | — | — | |||||||||
Benefit for previously taxed foreign earnings | 1,085 | — | — | |||||||||
MPC income tax provision(d) | (13 | ) | (71 | ) | (492 | ) | ||||||
Other | (79 | ) | — | (56 | ) | |||||||
Consolidated income tax (provision) benefit | $ | (1,679 | ) | $ | 82 | $ | 778 | |||||
Current income tax provision | $ | (1,841 | ) | $ | (1,375 | ) | $ | (667 | ) | |||
Deferred income tax benefit | 162 | 1,457 | 1,445 | |||||||||
Consolidated income tax (provision) benefit | $ | (1,679 | ) | $ | 82 | $ | 778 | |||||
Effective tax rate | 40 | % | 7 | % | — | |||||||
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(a) | Adjustment to deferred taxes due to MPAL’s recognition of asset retirement obligations. |
(b) | The Corporation has indefinitely reinvested undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material. | |
(c) | Tax benefits relate primarily to additional tax benefits taken in connection with financing prior year exploration activities in Australia. These benefits were reserved in prior years and as a result of the benefits becoming recoverable during the current year, such reserves were reversed. | |
(d) | MPC’s income tax provisions represent the 25% Canadian withholding tax on its Kotaneelee gas field carried interest net proceeds and a decrease in valuation allowance due to the expected utilization of net operating losses in future years. |
Significant components of the Company’s deferred tax assets and liabilities were as follows:
June 30, | June 30, | ||||||||
2006 | 2005 | ||||||||
Deferred tax liabilities | |||||||||
Acquisition and development costs | $ | (1,321,000 | ) | $ | (981,000 | ) | |||
Stepped up basis of oil and gas properties | (1,436,000 | ) | — | ||||||
Repatriated foreign earnings | (1,964,000 | ) | — | ||||||
Deferred tax assets | |||||||||
Asset retirement obligations | 2,453,000 | 1,996,000 | |||||||
Net operating losses | 4,804,000 | 2,749,000 | |||||||
Previously taxed foreign earnings | 1,085,000 | — | |||||||
Stock options | 128,000 | — | |||||||
Foreign tax credits | 109,000 | 223,000 | |||||||
Interest | 422,000 | 214,000 | |||||||
Total deferred tax assets | 9,001,000 | 5,182,000 | |||||||
Valuation allowance | (4,586,000 | ) | (3,186,000 | ) | |||||
Net deferred tax (liabilities)/asset | $ | (306,000 | ) | $ | 1,015,000 | ||||
Australia |
The net deferred tax asset (liability) at June 30, 2006 and 2005, respectively, consist of deferred tax liabilities of $1,321,000 and $981,000, primarily relating to the deduction of acquisition and development costs which are capitalized for financial statement purposes, offset by deferred tax assets of $2,453,000 and $1,996,000, primarily relating to asset retirement obligations which will result in tax deductions when paid.
United States |
At June 30, 2006, the Company had approximately $13,675,000 and $3,121,000 of net operating loss carry forwards for federal and state income tax purposes, respectively, which are scheduled to expire periodically between the years 2007 and 2025. Of this amount, MPC has federal loss carry forwards that expire as follows: $267,000 in 2007, $2,055,000 in 2008, $408,000 in 2020, $52,000 in 2021, $110,000 in 2023, $296,000 in 2025 and $1,381,000 in 2026. MPAL’s U.S. subsidiary has federal loss carry forwards that expire as follows: $2,392,000 in 2006, $1,669,000 in 2010, $1,764,000 in 2011, $2,855,000 in 2012, $229,000 in 2013, and $197,000 between 2019 and 2025. MPC also has approximately $109,000 of foreign tax credit carryovers, which are scheduled to expire by the year 2007. MPC’s state loss carry forwards expire periodically between the years 2007 and 2011. For financial reporting purposes, a valuation allowance has been recognized to partially offset the deferred tax assets related to those carry forwards and other deductible temporary differences. The deferred tax asset also includes a benefit of $1,085,000 recognized for previously taxed foreign earnings under Subpart F of the Internal Revenue Code.
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7. | Related Party and Other Transactions |
G&O’D INC, a firm that provided accounting and administrative services, office facilities and support staff to MPC, was paid $65,700 and $24,723 in fees for fiscal years 2005 and 2004 respectively. In addition, MPC purchased $12,000 of office equipment from G&O’D INC. during 2005. James R. Joyce, the former President and Chief Financial Officer of MPC, is the owner of G&O’D INC. Mr. Joyce retired from his position effective June 30, 2004. Mr. Timothy L. Largay, a director of the Company is a member of the law firm of Murtha Cullina LLP, which firm was paid fees of $170,481, $144,596 and $120,563, in fiscal years 2006, 2005 and 2004, respectively.
8. | Leases |
At June 30, 2006, future minimum rental payments applicable to MPC’s and MPAL’s non-cancelable operating (office) lease were $184,000, $190,000, $181,000, $0 and $0 for the years 2007, 2008, 2009, 2010 and 2011, respectively.
Operating lease rental expenses for each of the years ended June 30, 2006, 2005 and 2004 were $303,536, $214,661 and $311,497 respectively.
9. | Pension Plan |
Prior to August 31, 2004, MPAL maintained a defined benefit pension plan and contributed to the plan at rates which (based on actuarial determination) were sufficient to meet the cost of employees’ retirement benefits. No employee contributions were required. On August 31, 2004, the MPAL Board formally terminated the Plan. The termination was effective as of June 30, 2004 and a settlement and curtailment loss of $1,237,425 was recognized for the year ended June 30, 2004. Therefore, there were no pension costs during fiscal 2005 or 2006.
The following table sets forth the actuarial present value of benefit obligations and funded status for the MPAL pension plan at June 30, 2005:
2005 | |||||
Change in Benefit Obligation | |||||
Benefit obligation at beginning of year | $ | 2,145,394 | |||
Benefits paid | (2,145,394 | ) | |||
Benefit obligation at end of year | $ | 0 | |||
Change in Plan Assets | |||||
Fair value of plan assets at beginning of year | 1,858,681 | ||||
Actual return on plan assets | 286,713 | ||||
Benefits paid | (2,145,394 | ) | |||
Fair value of plan assets at end of year | 0 | ||||
Reconciliation of Funded Status | |||||
Funded Status | 0 | ||||
(Accrued) Prepaid benefit costs | 0 | ||||
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The net pension expense for the MPAL pension plan for 2004 was as follows:
2004 | ||||
Settlement and curtailment | $ | 1,237,425 | ||
Service cost | 148,075 | |||
Interest cost | 94,212 | |||
Expected return on plan assets | (94,104 | ) | ||
Net amortization and deferred items | 26,835 | |||
Net pension cost | $ | 1,412,443 | ||
Plan contributions by MPAL | $ | 228,958 | ||
Significant assumptions used in determining pension cost and the related obligations were as follows:
2004 | ||||
Assumed discount rate | 5.0 | % | ||
Rate of increase in future compensation levels | 3.5 | % | ||
Expected long term rate of return on plan assets | 5.0 | % | ||
Australian exchange rate | $ | .70 |
At June 30, 2004, Plan assets were held 98% in equity mutual funds and 2% in cash. As a result of the Plan’s termination, the Plan’s assets were distributed during 2005 with no additional pension plan expenditures required.
10. | Segment Information |
The Company has two reportable segments, MPC and its wholly owned subsidiary, MPAL.
Segment information (in thousands) for the Company’s two operating segments is as follows:
Years Ended June 30, | |||||||||||||
2006 | 2005 | 2004 | |||||||||||
Revenues: | |||||||||||||
MPC | $ | 973 | $ | 1,256 | $ | 2,469 | |||||||
MPAL | 26,530 | 21,590 | 17,866 | ||||||||||
Elimination of intersegment dividend | (941 | ) | (975 | ) | (911 | ) | |||||||
Total consolidated revenues | $ | 26,562 | $ | 21,871 | $ | 19,424 | |||||||
Interest income: | |||||||||||||
MPC | $ | 100 | $ | 89 | $ | 160 | |||||||
MPAL | 1,169 | 1,053 | 939 | ||||||||||
Total consolidated | $ | 1,269 | $ | 1,142 | $ | 1,099 | |||||||
Net income: | |||||||||||||
MPC | $ | (826 | ) | $ | (101 | ) | $ | 969 | |||||
Equity in earnings of MPAL, net of related costs(1) | 2,516 | 1,163 | 292 | ||||||||||
Elimination of intersegment dividend | (941 | ) | (975 | ) | (911 | ) | |||||||
Consolidated net income | $ | 749 | $ | 87 | $ | 350 | |||||||
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Years Ended June 30, | ||||||||||||||
2006 | 2005 | 2004 | ||||||||||||
Assets: | ||||||||||||||
MPC(2) | $ | 62,248 | $ | 25,523 | ||||||||||
MPAL | 61,811 | 50,659 | ||||||||||||
Equity elimination | (55,479 | ) | (19,758 | ) | ||||||||||
Total consolidated assets | $ | 68,580 | $ | 56,424 | ||||||||||
Other significant items: | ||||||||||||||
Depletion, depreciation and amortization: | ||||||||||||||
MPC | $ | 10 | $ | 27 | $ | 30 | ||||||||
MPAL | 6,304 | 6,967 | 6,312 | |||||||||||
Total consolidated | $ | 6,314 | $ | 6,994 | $ | 6,342 | ||||||||
Exploratory and dry hole costs: | ||||||||||||||
MPC | $ | — | $ | — | $ | — | ||||||||
MPAL | 3,265 | 4,157 | 3,225 | |||||||||||
Total consolidated | $ | 3,265 | $ | 4,157 | $ | 3,225 | ||||||||
Income tax expense (benefit): | ||||||||||||||
MPC | $ | 13 | $ | 71 | $ | 492 | ||||||||
MPAL | 1,666 | (153 | ) | (1,270 | ) | |||||||||
Total consolidated | $ | 1,679 | $ | (82 | ) | $ | (778 | ) | ||||||
(1) | Equity in earnings of MPAL for 2006 and 2005 of $2,665,000 and $1,358,000, respectively is reported net of $149,000 and $195,000 for 2006 and 2005, respectively of oil and gas property depletion related to MPC book value of oil and gas property and resulting from its step acquisition reporting of MPC’s investment in MPAL. As of June 30, 2006, MPC owned 100% of MPAL as a result of the Offer. See Note 2 to the Consolidated Financial Statements. |
(2) | Goodwill of $5,646,000 is attributable to MPC. |
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11. | Geographic Information |
As of each of the stated dates, the Company’s revenue, operating income, net income or loss and identifiable assets (in thousands) were geographically attributable as follows:
Years Ended June 30, | |||||||||||||
2006 | 2005 | 2004 | |||||||||||
Revenue: | |||||||||||||
Australia | $ | 26,530 | $ | 21,590 | $ | 17,866 | |||||||
United States | — | — | — | ||||||||||
Canada | 32 | 281 | 1,558 | ||||||||||
$ | 26,562 | $ | 21,871 | $ | 19,424 | ||||||||
Operating income (loss): | |||||||||||||
Australia | $ | 5,291 | $ | 2,912 | $ | (103 | ) | ||||||
New Zealand | (211 | ) | (1,441 | ) | (909 | ) | |||||||
United States-Canada | 27 | 258 | 1,525 | ||||||||||
5,107 | 1,729 | 513 | |||||||||||
Corporate overhead and interest, net of other income (expense) | (911 | ) | (615 | ) | (395 | ) | |||||||
Consolidated operating income before income taxes and minority interests | $ | 4,196 | $ | 1,114 | $ | 118 | |||||||
Net income (loss): | |||||||||||||
Australia | $ | 2,809 | $ | 1,831 | $ | 718 | |||||||
New Zealand | (293 | ) | (668 | ) | (425 | ) | |||||||
United States | (1,767 | ) | (1,076 | ) | 57 | ||||||||
$ | 749 | $ | 87 | $ | 350 | ||||||||
Identifiable assets: | |||||||||||||
Australia | $ | 61,811 | $ | 52,264 | |||||||||
Corporate assets | 6,769 | 4,160 | |||||||||||
$ | 68,580 | $ | 56,424 | ||||||||||
Substantially all of MPAL’s gas sales were to the Power and Water Corporation (PAWC) of the Northern Territory of Australia (NTA). All of MPAL’s crude oil production was sold to the Mobil Port Stanvac Refinery near Adelaide during the three years ended June 30, 2006. Oil sales during 2006 were 53.3% to the Santos group of companies, 16.2% to Delhi Petroleum, 10.5% to Origin Energy Resources and 20.0% to IOR Energy.
12. | Commitments |
The Company does not use off-balance sheet arrangements such as securitization of receivables with any unconsolidated entities or other parties. The Company does not engage in trading or risk management activities and does not have material transactions involving related parties.
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The following is a summary of our consolidated contractual obligations as of June 30, 2006:
Payments Due by Period | |||||||||||||||||||||
Less Than | More Than | ||||||||||||||||||||
Contractual Obligations | Total | 1 Year | 1-3 Years | 3-5 Years | 5 Years | ||||||||||||||||
Long-Term Debt Obligations | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
Capital Lease Obligations | — | — | — | — | — | ||||||||||||||||
Operating Lease Obligations | 555,000 | 184,000 | 371,000 | — | — | ||||||||||||||||
Purchase Obligations(1) | 3,380,000 | 3,380,000 | — | — | — | ||||||||||||||||
Asset Retirement Obligations | 7,147,000 | 169,000 | 4,677,000 | — | 2,301,000 | ||||||||||||||||
Total | $ | 11,082,000 | $ | 3,733,000 | $ | 5,048,000 | $ | — | $ | 2,301,000 | |||||||||||
(1) | Represents firm commitments for exploration and capital expenditures. The Company is committed to these expenditures, however some may be farmed out to third parties. Exploration contingent expenditures of $15,284,000 which are not legally binding have been excluded from the table above and based on exploration decisions would be due as follows: $1,158,000 (less than 1 year), $14,126,000 (1-3 years), $0 (3-5 years). |
Gas Supply Contracts |
In 1983, the Palm Valley Producers (MPAL and Santos) commenced the sale of gas to Alice Springs under a 1981 agreement. In 1985, the Palm Valley Producers and Mereenie Producers signed agreements for the sale of gas to PAWC for use in PAWC’s Darwin generating station and at a number of other generating stations in the Northern Territory. The gas is being delivered via the922-mile Amadeus Basin to Darwin gas pipeline which was built by an Australian consortium. Since 1985, there have been several additional contracts for the sale of Mereenie gas. The Palm Valley Darwin contract expires in the year 2012 and Mereenie contracts expire in the year 2009. Under the 1985 contracts, there is a difference in price between Palm Valley gas and most of the Mereenie gas for the first 20 years of the 25 year contracts which takes into account the additional cost to the pipeline consortium to build a spur line to the Mereenie field and increase the size of the pipeline from Palm Valley to Mataranka. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index.
The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. Gas production from both fields is fully contracted through to 2009 and 2012, respectively. While opportunities exist to contract additional gas sales in the Northern Territory market after these dates, there is strong competition within the market and there are no assurances that the Palm Valley Producers will be able to contract for the sale of the remaining uncontracted reserves.
At June 30, 2006, MPAL’s commitment to supply gas under the above agreements was as follows:
Period | Bcf | |||
Less than one year | 7.64 | |||
Between 1-5 years | 18.12 | |||
Greater than 5 years | 0.98 | |||
Total | 26.74 | |||
MPC owns a 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory which has been in production since February 1991 with two producing wells. For financial statement purposes in fiscal 1987 and 1988, MPC wrote down its costs relating to the Kotaneelee field to a nominal value because of the uncertainty as to the date when sales of Kotaneelee gas might begin and the immateriality of the carrying value of the investment.
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The Kotaneelee settlement agreement provides that the carried interest partners will share in the abandonment of the Kotaneelee field wells and facilities.
13. | Selected Quarterly Financial Data (Unaudited) |
The following is a summary (in thousands, except for per share amounts) of the quarterly results of operations for the years ended June 30, 2006 and 2005:
QTR 1 | QTR 2 | QTR 3 | QTR 4 | |||||||||||||
2006 | ||||||||||||||||
Total revenues | $ | 6,095 | $ | 6,459 | $ | 7,358 | $ | 6,650 | ||||||||
Costs and expenses | (6,020 | ) | (6,020 | ) | (5,354 | ) | (6,241 | ) | ||||||||
Interest income | 340 | 321 | 290 | 317 | ||||||||||||
Income tax provision | (190 | ) | (425 | ) | (717 | ) | (347 | ) | ||||||||
Minority interests | (253 | ) | (561 | ) | (877 | ) | (76 | ) | ||||||||
Net income (loss) | (28 | ) | (226 | ) | 700 | 303 | ||||||||||
Per share (basic & diluted) | — | (.01 | ) | .03 | .01 | |||||||||||
Average number of shares outstanding | 25,783 | 25,783 | 25,783 | 36,087 | ||||||||||||
2005 | ||||||||||||||||
Total revenues | $ | 4,577 | $ | 5,454 | $ | 5,996 | $ | 5,844 | ||||||||
Costs and expenses | (5,137 | ) | (5,500 | ) | (5,599 | ) | (5,662 | ) | ||||||||
Interest income | 356 | 377 | 104 | 305 | ||||||||||||
Income tax (provision) benefit(a) | (5 | ) | (153 | ) | (102 | ) | 342 | |||||||||
Minority interests | (86 | ) | (254 | ) | (294 | ) | (476 | ) | ||||||||
Net income (loss) | (295 | ) | (76 | ) | 105 | 353 | ||||||||||
Per share (basic & diluted) | (.01 | ) | — | — | .01 | |||||||||||
Average number of shares outstanding | 25,783 | 25,783 | 25,783 | 25,783 | ||||||||||||
(a) | During the fourth quarter of 2005, MPAL’s financing subsidiary determined that its loans to the New Zealand subsidiary were no longer collectible and this resulted in a permanent benefit in Australia of $1,000. This amount was offset by tax benefits from New Zealand losses that are not deductible in Australia of $513. |
14. | Supplementary Oil and Gas Disclosure (Unaudited) |
The consolidated data presented herein include estimates which should not be construed as being exact and verifiable quantities. The reserves may or may not be recovered, and if recovered, the cash flows therefrom, and the costs related thereto, could be more or less than the amounts used in estimating future net cash flows. Moreover, estimates of proved reserves may increase or decrease as a result of future operations and economic conditions, and any production from these properties may commence earlier or later than anticipated.
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Estimated Net Quantities of Proved and Proved Developed Oil and Gas Reserves: |
Natural Gas | Oil | |||||||||||
(Bcf) | (1,000 Bbls) | |||||||||||
Proved Reserves: | Australia* | Canada | Australia | |||||||||
June 30, 2003 | 37.384 | .427 | 554 | |||||||||
Extensions and discoveries | — | — | — | |||||||||
Revision of previous estimates | (.631 | ) | (.180 | ) | (110 | ) | ||||||
Purchase of reserves | — | — | 322 | |||||||||
Production | (5.728 | ) | (.077 | ) | (150 | ) | ||||||
June 30, 2004 | 31.025 | .170 | 616 | |||||||||
Extensions and discoveries | — | .012 | — | |||||||||
Revision of previous estimates | (.024 | ) | — | 22 | ||||||||
Purchase of reserves | — | — | — | |||||||||
Production | (5.717 | ) | (.061 | ) | (151 | ) | ||||||
June 30, 2005 | 25.284 | .121 | 487 | |||||||||
Extensions and discoveries | — | .035 | 71 | |||||||||
Revision of previous estimates | (.142 | ) | — | 406 | ||||||||
Purchase of reserves | — | — | — | |||||||||
Production | (5.706 | ) | (.070 | ) | (154 | ) | ||||||
June 30, 2006 | 19.436 | .086 | 810 | |||||||||
Proved Developed Reserves: | ||||||||||||
June 30, 2003 | 28.855 | .427 | 554 | |||||||||
June 30, 2004 | 22.346 | .170 | 616 | |||||||||
June 30, 2005 | 25,284 | .121 | 487 | |||||||||
June 30, 2006 | 19.436 | .086 | 327 | |||||||||
* | The amount of proved reserves applicable to the Palm Valley and Mereenie fields only reflects the amount of gas committed to specific contracts and are net of royalties. There are no minority interests at June 30, 2006. Approximately 44.9% of reserves are attributable to minority interests at June 30,2005 and June 30, 2004. |
Costs of Oil and Gas Activities (In thousands): |
Australia/New Zealand | ||||||||||||
Exploration | Development | Acquisition | ||||||||||
Fiscal Year | Costs | Costs | Costs | |||||||||
2006 | 3,284 | (2,842 | )(1) | — | ||||||||
2005 | 4,028 | 9,292 | — | |||||||||
2004 | 3,741 | 3,926 | 2,086 |
(1) | Development costs include the net increase or decrease in development related assets. The decrease in the Australian exchange rate discussed in Note 1 caused a foreign translation loss in excess of costs incurred. |
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Capitalized Costs Subject to Depletion, Depreciation and Amortization (DD&A) (In thousands): |
June 30, | ||||||||
Australia/New Zealand | 2006 | 2005 | ||||||
Costs subject to DD&A | $ | 85,795 | $ | 80,766 | ||||
Costs not subject to DD&A | 2,037 | — | ||||||
Less accumulated DD&A | (60,844 | ) | (57,330 | ) | ||||
Net capitalized costs | $ | 26,988 | $ | 23,436 | ||||
Discounted Future Net Cash Flows: |
The following is the standardized measure of discounted (at 10%) future net cash flows (in thousands) relating to proved oil and gas reserves during the three years ended June 30, 2006. There were no minority interests at June 30, 2006. Approximately 44.9% of the reserves and the respective discounted future net cash flows are attributable to minority interests at June 30, 2005 and June 30, 2004.
Australia | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Future cash inflows | $ | 161,788 | $ | 81,688 | $ | 82,449 | ||||||
Future production costs | (33,814 | ) | (18,443 | ) | (19,361 | ) | ||||||
Future development costs | (16,196 | ) | (13,434 | ) | (16,599 | ) | ||||||
Future income tax expense | (28,900 | ) | (10,342 | ) | (9,369 | ) | ||||||
Future net cash flows | 82,878 | 39,469 | 37,120 | |||||||||
10% annual discount for estimating timing of cash flows | (12,680 | ) | (8,157 | ) | (7,639 | ) | ||||||
Standardized measures of discounted future net cash flows | $ | 70,198 | $ | 31,312 | $ | 29,481 | ||||||
Canada | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Future cash inflows | $ | 332 | $ | 606 | $ | 754 | ||||||
Future production costs | (74 | ) | (60 | ) | (125 | ) | ||||||
Future development costs | — | — | — | |||||||||
Future income tax expense | (65 | ) | (136 | ) | (157 | ) | ||||||
Future net cash flows | 193 | 410 | 472 | |||||||||
10% annual discount for estimating timing of cash flows | (4 | ) | (89 | ) | (72 | ) | ||||||
Standardized measures of discounted future net cash flows | $ | 189 | $ | 321 | $ | 400 | ||||||
Total | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Future cash inflows | $ | 162,120 | $ | 82,294 | $ | 83,203 | ||||||
Future production costs | (33,888 | ) | (18,503 | ) | (19,486 | ) | ||||||
Future development costs | (16,196 | ) | (13,434 | ) | (16,599 | ) | ||||||
Future income tax expense | (28,965 | ) | (10,478 | ) | (9,526 | ) | ||||||
Future net cash flows | 83,071 | 39,879 | 37,592 | |||||||||
10% annual discount for estimating timing of cash flows | (12,684 | ) | (8,246 | ) | (7,711 | ) | ||||||
Standardized measures of discounted future net cash flows | $ | 70,387 | $ | 31,633 | $ | 29,881 | ||||||
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The following are the principal sources of changes in the above standardized measure of discounted future net cash flows (in thousands):
2006 | 2005 | 2004 | ||||||||||
Net change in prices and production costs | $ | 69,970 | $ | 5,567 | $ | 7,597 | ||||||
Extensions and discoveries | 2,714 | — | — | |||||||||
Revision of previous quantity estimates | 1,037 | 281 | 981 | |||||||||
Changes in estimated future development costs | (4,999 | ) | 443 | (2,156 | ) | |||||||
Sales and transfers of oil and gas produced | (16,462 | ) | (13,725 | ) | (10,314 | ) | ||||||
Previously estimated development cost incurred during the period | (438 | ) | 3,827 | 3,110 | ||||||||
Accretion of discount | 7,017 | 2,337 | 2,344 | |||||||||
Acquisitions | — | — | 3,213 | |||||||||
Net change in income taxes | (17,025 | ) | 410 | (2,345 | ) | |||||||
Net change in exchange rate | (3,060 | ) | 2,612 | 965 | ||||||||
$ | 38,754 | $ | 1,752 | $ | 3,395 | |||||||
Additional Information Regarding Discounted Future Net Cash Flows: |
Australia |
Reserves — Natural Gas |
Future net cash flows from net proved gas reserves in Australia were based on MPAL’s share of reserves in the Palm Valley and Mereenie fields which has been limited to the quantities of gas committed to specific contracts and the ability of the fields to deliver the gas in the contract years. Gas prices are computed on the prices set forth in the respective gas sales contracts at June 30, 2006.
Reserves and Costs — Oil |
At June 30, 2006, future net cash flows from the net proved oil reserves in Australia were calculated by the Company. Estimated future production and development costs were based on current costs and rates for each of the three years ended at June 30, 2006. All of the crude oil reserves are developed reserves. Undeveloped proved reserves have not been estimated since there are only tentative plans to drill additional wells.
Income Taxes |
Future Australian income tax expense applicable to the future net cash flows has been reduced by the tax effect of approximately A.$23,976,000, and A.$23,203,000 and A.$22,005,000 in unrecouped capital expenditures at June 30, 2006, 2005 and 2004, respectively. The tax rate in computing Australian future income tax expense was 30%.
Canada |
Reserves and Costs |
Future net cash flows from net proved gas reserves in Canada were based on the Company’s share of reserves in the Kotaneelee gas field which was prepared by independent petroleum consultants, Paddock Lindstrom & Associates Ltd., Calgary, Canada. The estimates were based on the selling price of gas Can. $4.55 at June 30, 2006 (Can. $6.14 — 2005) and estimated future production and development costs at June 30, 2006.
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Results of Operations
The following are the Company’s results of operations (in thousands) for the oil and gas producing activities during the three years ended June 30, 2006:
Americas | Australia/New Zealand/United Kingdom | ||||||||||||||||||||||||
2006 | 2005 | 2004 | 2006 | 2005 | 2004 | ||||||||||||||||||||
Revenues: | |||||||||||||||||||||||||
Oil sales | $ | — | $ | — | $ | — | $ | 10,616 | $ | 7,574 | $ | 4,923 | |||||||||||||
Gas sales | 32 | 282 | 1,557 | 14,028 | 12,196 | 11,312 | |||||||||||||||||||
Other production income | — | — | — | 1,886 | 1,819 | 1,632 | |||||||||||||||||||
Total revenues | 32 | 282 | 1,557 | 26,530 | 21,589 | 17,867 | |||||||||||||||||||
Costs: | |||||||||||||||||||||||||
Production costs | — | — | — | 8,220 | 6,144 | 5,416 | |||||||||||||||||||
Depletion, exploratory and dry hole costs | 5 | 23 | 30 | 9,391 | 10,727 | 9,009 | |||||||||||||||||||
Total costs | 5 | 23 | 30 | 17,611 | 16,871 | 14,425 | |||||||||||||||||||
Income before taxes and minority interest | 27 | 259 | 1,527 | 8,919 | 4,718 | 3,442 | |||||||||||||||||||
Income tax provision* | (7 | ) | (65 | ) | (382 | ) | (2,676 | ) | (1,415 | ) | (1,027 | ) | |||||||||||||
Income before minority interests | 20 | 194 | 1,145 | 6,243 | 3,303 | 2,415 | |||||||||||||||||||
Minority interests** | — | — | — | (2,491 | ) | (1,737 | ) | (1,085 | ) | ||||||||||||||||
Net income from operations | $ | 20 | $ | 194 | $ | 1,145 | $ | 3,752 | $ | 1,566 | $ | 1,330 | |||||||||||||
Depletion per unit of production | $ | — | $ | — | — | A.$ | 6.71 | A.$ | 7.40 | A.$ | 7.25 | ||||||||||||||
* | Income tax provision used for Australia is based on a rate of 30%. Americas 25% is due to a 25% Canadian withholding tax on Kotaneelee gas sales. |
** | Effective minority interest for 2006 was 39.9%. Minority interests were 44.9% in 2005 and 44.9% in 2004. |
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Item 9. — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A. | Controls and Procedures |
Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Company’s management, including Daniel J. Samela, the Company’s President, Chief Executive Officer and Chief Financial and Accounting Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities and Exchange Act of 1934) as of June 30, 2006. Based on this evaluation, the Company’s President concluded that the Company’s disclosure controls and procedures were effective such that the material information required to be included in the Company’s Securities and Exchange Commission reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms relating to the Company, including its consolidated subsidiaries, and the information required to be disclosed was accumulated and communicated to management as appropriate to allow timely decisions for disclosure.
Internal Control Over Financial Reporting.
There have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and15d-15(f) under the Exchange Act) during the fourth fiscal quarter of the Company’s fiscal year ended June 30, 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. | Other Information |
None
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PART III
Item 10. | Directors and Executive Officers of the Registrant |
Following is information concerning each Director and executive officer of the Company including name, age, position with the Company, and business experience during the last five years:
Directors
Director | Position Held with | |||||||||||
Name | Since | Company | Age and Business Experience | |||||||||
Timothy L. Largay | 1996 | Director; member of Nominating Committee Chairman, Compensation Committee, Assistant Secretary | Mr. Timothy L. Largay has been a partner in the law firm of Murtha Cullina LLP, Hartford, Connecticut since 1974. Mr. Largay has been a director of MPAL since August 2001. He is also Assistant Secretary of Canada Southern Petroleum Ltd., Calgary, Alberta, Canada. Murtha Cullina has been retained by the Company for more than five years and is being retained during the current year. Age 63. | |||||||||
Walter McCann | 1983 | Director, Chairman of the Board, Chairman of Compensation Committee, member of Audit Committee and Nominating Committee | Mr. Walter McCann, a former business school dean, was the President of Richmond, The American International University, located in London, England, from January 1993 until September 2002. From 1985 to 1992, he was President of Athens College in Athens, Greece. Mr. McCann has been a director of MPAL since 1997. He is a retired member of the Bar in Massachusetts. Age 69. | |||||||||
Ronald P. Pettirossi | 1997 | Director; Chairman of the Audit Committee, member of Nominating Committee and Compensation Committee | Mr. Ronald P. Pettirossi has been President of ER Ltd., a consulting company since 1995. Mr. Pettirossi is a former audit partner of Ernst & Young LLP, who worked with public and privately held companies for 31 years. Age 63. | |||||||||
Donald V. Basso | 2000 | Director; member of Audit Committee | Mr. Donald V. Basso was elected a director of the Company in 2000. Mr. Basso served as a consultant and Exploration Manager for Canada Southern Petroleum Ltd. from October 1997 to May 2000. He also served as a consultant to Ranger Oil & Gas Ltd. during 1997. From 1995 to 1997, Mr. Basso served as Exploration Manager for Guard Resources Ltd. Mr. Basso has over 40 years experience in the oil and gas business in the United States, Canada and the Middle East. Age 68. |
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Director | Position Held with | |||||||||||
Name | Since | Company | Age and Business Experience | |||||||||
Robert Mollah | 2006 | Director | Mr. Robert Mollah was elected a director of the Company on September 5, 2006. Mr. Mollah has been a director of MPAL since 2003 and was recently elected to serve as Chairman of the MPAL Board of Directors. Mr. Mollah is a geophysicist with broad petroleum exploration experience, both within Australia and internationally. From 1995 until 2003, Mr. Mollah was the Australian Executive Director of the Timor Gap Joint Authority which covered the administration of petroleum exploration and production activities in the Timor Sea Joint Development Zone between Australia and Indonesia/East Timor. Prior to 1995, he served as a Petroleum Explorationist and Manager with broad experience in the oil and gas business in Australia and Asia. Age 64. |
Executive Officers
Length of Service | Other Positions Held | |||||||||||||||
Name | Age | Office Held | as an Officer | with Company | ||||||||||||
Daniel J. Samela | 58 | President and Chief Financial Officer | Since 2004 | None | ||||||||||||
T. Gwynn Davies. | 60 | General Manager — MPAL | Since 2001 | None |
* | All of the named companies are engaged in oil, gas or mineral exploration and/or development, except where noted. |
All officers are elected annually and serve at the pleasure of the Board of Directors. No family relationships exist between any of the directors or officers.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers, directors and persons who beneficially own more than 10% of the Company’s Common Stock to file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission. Such persons are required by the SEC regulations to furnish the Company with copies of all Section 16(a) forms filed by such persons. Based solely on copies of forms received by it, or written representations from certain reporting persons that no Form 5’s were required for those persons, the Company believes that during the fiscal year ended June 30, 2006, its executive officers, directors, and greater than 10% beneficial owners complied with all applicable filing requirements.
Board Independence
The Company’s Board of Directors has determined that Messrs. Basso, Largay, Pettirossi, Mollah and McCann are independent directors under the listing standards of the Nasdaq Stock Market, Inc. and rules adopted by the Securities and Exchange Commission (“SEC”).
Audit Committee Financial Expert(s)
The Company’s Board of Directors maintains an Audit Committee which is currently composed of the following directors: Messrs. Basso, McCann and Pettirossi (Chairman). The Board of Directors has determined that each of the members of the Audit Committee is financially literate and that Mr. Pettirossi is
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an audit committee financial expert, as such term is defined under SEC regulations, by virtue of having the following attributes through relevant education and/or experience:
(1) an understanding of generally accepted accounting principles and financial statements; | |
(2) the ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves; | |
(3) experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Company’s financial statements, or experience actively supervising one or more persons engaged in such activities; | |
(4) an understanding of internal controls and procedures for financial reporting; and | |
(5) an understanding of audit committee functions. |
Standards Of Conduct And Business Ethics
The Company has previously adopted Standards of Conduct for the Company (the “Standards”). The Board amended the Standards in August 2004. A copy of the Standards is filed herewith as Exhibit 14. Under the Standards, all directors, officers and employees (“Employees”) must demonstrate a commitment to ethical business practices and behavior in all business relationships, both within and outside of the Company. All Employees who have access to confidential information are not permitted to use or share that information for stock trading purposes or for any other purpose except the conduct of the Company’s business. Any waivers of or changes to the Standards must be approved by the Board and appropriately disclosed under applicable law and regulation.
The Company’s Standards will be made available on the Company’s website at www.magpet.com and it is our intention to provide disclosure regarding waivers of or amendments to the policy by posting such waivers or amendments to the website in the manner provided by applicable law.
Item 11 — | Executive Compensation |
The following table sets forth certain summary information concerning the compensation of Mr. Daniel J. Samela, who is President, Chief Executive Officer and Chief Financial Officer of the Company, and each of the most highly compensated executive officers of the Company who earned in excess of $100,000 during fiscal year 2006 (collectively, the “Named Executive Officers”).
Summary Compensation Table
Long Term | |||||||||||||||||
Compensation | |||||||||||||||||
Awards | |||||||||||||||||
Annual | |||||||||||||||||
Compensation | Securities | ||||||||||||||||
Underlying | All Other | ||||||||||||||||
Fiscal | Salary | Options/SARs | Compensation | ||||||||||||||
Name and Principal Position | Year | ($) | (#) | ($) | |||||||||||||
Daniel J. Samela | 2006 | 175,000 | — | 26,250 | (1) | ||||||||||||
President, Chief Financial and | 2005 | 175,000 | — | 26,250 | (1) | ||||||||||||
Accounting Officer | 2004 | 41,667 | 30,000 | 6,250 | (1) | ||||||||||||
T. Gwynn Davies | 2006 | 190,663 | — | 92,417 | (2) | ||||||||||||
General Manager — MPAL | 2005 | 188,857 | — | 72,301 | (2) | ||||||||||||
(Effective Oct. 30, 2001) | 2004 | 177,144 | — | 65,436 | (2) |
(1) | Payment to a SEP-IRA pension plan. |
(2) | Payment to pension plan similar to an individual retirement plan. |
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Stock Options
The following tables provide information about stock options granted and exercised during fiscal 2006 and unexercised stock options held by the Named Executive Officers at the end of fiscal year 2006.
Options/ SAR Grants in Fiscal Year 2006
Potential Realized | ||||||||||||||||||||||||
Individual Grants | Value at Assumed | |||||||||||||||||||||||
Annual Rates of | ||||||||||||||||||||||||
% of Total | Stock Price | |||||||||||||||||||||||
Options/SARs | Appreciation for | |||||||||||||||||||||||
Options/ | Granted to | Exercise or | Option Terms | |||||||||||||||||||||
SARs Granted | Employees in | Base Price | Expiration | |||||||||||||||||||||
Name | (#) | Fiscal Year | ($/Sh) | Date | 5% ($) | 10% ($) | ||||||||||||||||||
Daniel J. Samela | 0 | 0 | 0 | — | 0 | 0 | ||||||||||||||||||
T. Gwynn Davies | 0 | 0 | 0 | — | 0 | 0 |
Aggregated Option/ SAR Exercises in Fiscal 2006 and June 30, 2006
Option/ SAR Values Table
Number of Unexercised | Value of Unexercised | |||||||||||||||||||||||
Shares | Options/SARs at | In-the-Money Options/SARs | ||||||||||||||||||||||
Acquired on | Value | 2006 Year-End (#) | at 2006 Year-End ($) | |||||||||||||||||||||
Exercise | Realized | |||||||||||||||||||||||
Name | (#) | ($) | Exercisable | Unexercisable | Exercisable | Unexercisable | ||||||||||||||||||
Daniel J. Samela | — | — | 20,000 | 10,000 | 31,400 | 15,700 | ||||||||||||||||||
T. Gwynn Davies | — | — | — | — | — | — |
Employment Agreement
On March 1, 2004, the Company entered into a thirty-six month employment agreement with Mr. Daniel J. Samela. The thirty-six month term automatically renews each30-day period during Mr. Samela’s term of employment, unless he elects to retire or the agreement is terminated according to its terms. The agreement provides for him to be employed as the President and Chief Executive Officer of the Company, effective as of July 1, 2004, at a salary of $175,000 per annum, and an annual contribution of 15% of the salary to a SEP/ IRA pension plan for Mr. Samela’s benefit. The employment agreement may be terminated for cause (as defined in the agreement), on written notice by the Company without cause, by Mr. Samela’s resignation or upon a change in control of the Company (as defined in the agreement). Upon a termination without cause, Mr. Samela will be entitled to payment of the balance of salary and average bonus payments due for the term of the agreement. If, during the two-year period following a change in control, Mr. Samela terminates his employment for good reason (as defined in the agreement) or the Company terminates his employment other than for cause of disability (as defined in the agreement), then Mr. Samela will be paid an amount equal to three times his annual base salary and three-year average bonus payment, plus any previously deferred compensation, accrued vacation pay, and three years of reimbursements for medical coverage and insurance benefits. In addition, any then-unvested options will be accelerated so as to become fully exercisable. If, at any time after the two-year period following a change in control, Mr. Samela terminates his employment for good reason or the Company terminates his employment other than for cause of disability, then he will be paid an amount equal to his then current annual salary and a three-year average bonus payment. In addition, any then-unvested options will be accelerated so as to become fully exercisable.
Compensation of Directors
Messrs. Donald V. Basso, Timothy L. Largay, and Ronald P. Pettirossi were each paid director’s fees of $40,000 during fiscal year 2006. Mr. Walter McCann was paid $65,000 as Chairman of the Board. In addition, Mr. Pettirossi was paid $7,500 as Chairman of the Audit Committee.
Under the Company’s medical reimbursement plan for all outside directors, the Company reimburses certain directors the cost of their medical premiums, up to $500 per month. During fiscal 2006, the cost of this plan was approximately $18,000.
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Compensation Committee Interlocks and Insider Participation
The only officers or employees of the Company or any of its subsidiaries, or former officers or employees of the Company or any of its subsidiaries, who participated in the deliberations of the Board concerning executive officer compensation during the fiscal year ended June 30, 2006 were Messrs. Daniel T. Samela and Timothy L. Largay. At the time of such deliberations, Mr. Largay was a director of the Company. Because he does not serve on the Board, Mr. Samela did not participate in any discussions or deliberations regarding his own compensation. Mr. Largay does not receive any compensation for his services as Assistant Secretary.
Item 12 — | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The following table sets forth information as to the number of shares of the Company’s Common Stock owned beneficially as of September 22, 2006 (except as otherwise indicated) by each director of the Company and each Named Executive Officer listed in the Summary Compensation Table and by all directors and executive officers of the Company as a group:
Amount and Nature of | ||||||||||||
Beneficial Ownership* | ||||||||||||
Name of Individual or Group | Shares | Options | Percent of Class | |||||||||
Donald Basso | 11,000 | 100,000 | ** | |||||||||
T. Gwynn Davies | — | — | ** | |||||||||
Timothy L. Largay | 6,000 | 100,000 | ** | |||||||||
Walter McCann | 59,368 | 100,000 | ** | |||||||||
Robert Mollah | — | — | ** | |||||||||
Ronald P. Pettirossi | 6,500 | 100,000 | ** | |||||||||
Daniel J. Samela | — | 20,000 | ** | |||||||||
Directors and Executive Officers as a Group (a total of 7) | 82,868 | 420,000 | ** |
* | Unless otherwise indicated, each person listed has the sole power to vote and dispose of the shares listed. |
** | The percent of class owned is less than 1%. |
Equity Compensation Plan Information
The following table provides information about the Company’s common stock that may be issued upon the exercise of options and rights under the Company’s existing equity compensation plan as of June 30, 2006.
Number of Securities | ||||||||||||
Remaining Available for | ||||||||||||
Number of Securities | Weighted Average | Issuance Under Equity | ||||||||||
to be Issued Upon | Exercise Price of | Compensation Plans | ||||||||||
Exercise of Outstanding | Outstanding Options, | (Excluding Securities | ||||||||||
Options, Warrants and | Warrants and Rights | Reflected in Column (a)) | ||||||||||
Plan Category | Rights (a) (#) | (b)($) | (c) (#) | |||||||||
Equity compensation plans approved by security holders | 430,000 | $ | 1.59 | 395,000 |
Item 13 — | Certain Business Relationships and Transactions |
None.
Item 14 — | Principal Accountant Fees and Services |
During the fiscal years ended June 30, 2006 and June 30, 2005, the Company retained its current principal auditor, Deloitte & Touche LLP, to provide services in the following categories and amounts.
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Audit Fees
The aggregate fees paid or to be paid to Deloitte & Touche, LLP for the review of the financial statements included in the Company’s Quarterly Reports on Form 10-Q and the audit of financial statements included in the Annual Report on Form 10-K for the fiscal years ended June 30, 2006 and June 30, 2005 were $295,096 and $195,702, respectively.
Audit-Related Fees
The aggregate fees paid or to be paid to Deloitte & Touche, LLP in connection with the Company’s filing of a registration statement on Form S-4 for the fiscal year ended June 30, 2006 and June 30, 2005 were $131,500 and $0, respectively.
Tax Fees
The aggregate fees paid or to be paid to Deloitte & Touche, LLP for tax services was $0 for both the fiscal years ended June 30, 2006 and June 30, 2005.
All Other Fees
The aggregate fees paid or to be paid to Deloitte & Touche, LLP for other services for the fiscal years ended June 30, 2006 and June 30, 2005 were $3,701 and $0, respectively
Pre-Approval Policies
Under the terms of its Charter, the Audit Committee is required to pre-approve all the services provided by, and fees and compensation paid to, the independent auditors for both audit and permitted non-audit services. When it is proposed that the independent auditors provide additional services for which advance approval is required, the Audit Committee may form and delegate authority to a subcommittee consisting of one or more members, when appropriate, with the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are to be presented to the Committee at its next scheduled meeting.
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PART IV
Item 15. | Exhibits, Financial Statement Schedules |
(a) (1)Financial Statements.
The financial statements listed below and included under Item 8 are filed as part of this report.
Page | ||||
Reference | ||||
31 | ||||
32 | ||||
33 | ||||
34 | ||||
35 | ||||
Notes to consolidated financial statements | 36 | |||
53 |
(2) Financial Statement Schedules.
All schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and the notes thereto.
(c) Exhibits.
The following exhibits are filed as part of this report:
Item Number
2. Plan of acquisition, reorganization, arrangement, liquidation or succession.
None.
3. Articles of Incorporation and By-Laws.
(a) Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware and Amendment of Article Twelfth as filed on February 12, 1988 with the State of Delaware filed as exhibit 4(b) to Form S-8 Registration Statement, filed on January 14, 1999, are incorporated herein by reference. Certificate of Amendment to Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware, filed as Exhibit 3(a) to the Company’s quarterly report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference.
(b) By-Laws, as amended on September 5, 2006, as filed as Exhibit 3.1 to current Report on Form 8-K filed on September 8, 2006 are incorporated by reference.
4. Instruments defining the rights of security holders, including indentures.
None.
9. Voting Trust Agreement.
None.
10. Material contracts.
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(a) Petroleum Lease No. 4 dated November 18, 1981 granted by the Northern Territory of Australia to United Canso Oil & Gas Co. (N.T.) Pty Ltd. filed as Exhibit 10(a) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(b) Petroleum Lease No. 5 dated November 18, 1981 granted by the Northern Territory of Australia to Magellan Petroleum (N.T.) Pty. Ltd. filed as Exhibit 10(b) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(c) Gas Sales Agreement between The Palm Valley Producers and The Northern Territory Electricity Commission dated November 11, 1981 filed as Exhibit 10(c) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(d) Palm Valley Petroleum Lease (OL3) dated November 9, 1982 filed as Exhibit 10(d) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(e) Agreements relating to Kotaneelee.
(1) Copy of Agreement dated May 28, 1959 between the Company et al and Home Oil Company Limited et al and Signal Oil and Gas Company filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. | |
(2) Copies of Supplementary Documents to May 28, 1959 Agreement (see (e)(1) above), dated June 24, 1959, consisting of Guarantee by Home Oil Company Limited and Pipeline Promotion Agreement filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. | |
(3) Copy of Modification to Agreement dated May 28, 1959 (see (e)(1) above), made as of January 31, 1961. Filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. | |
(4) Copy of Letter Agreement dated February 1, 1977 between the Company and Columbia Gas Development of Canada, Ltd. for operation of the Kotaneelee gas field filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. |
(f) Palm Valley Operating Agreement dated April 2, 1985 between Magellan Petroleum (N.T.) Pty. Ltd., C. D. Resources Pty. Ltd., Farmout Drillers N.L., Canso Resources Limited, International Oil Proprietary, Pancontinental Petroleum Limited, I.E.D.C. Australia Pty. Ltd., Southern Alloys Ventures Pty. Limited and Amadeus Oil N.L. filed as Exhibit 10(f) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(g) Mereenie Operating Agreement dated April 27, 1984 between Magellan Petroleum (N.T.) Pty., United Oil & Gas Co. (N.T.) Pty. Ltd., Canso Resources Limited, Oilmin (N.T.) Pty. Ltd., Krewliff Investments Pty. Ltd., Transoil (N.T.) Pty. Ltd. and Farmout Drillers NL and Amendment of October 3, 1984 to the above agreement filed as Exhibit 10(g) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(h) Palm Valley Gas Purchase Agreement dated June 28, 1985 between Magellan Petroleum (N.T.) Pty. Ltd., C. D. Resources Pty. Ltd., Farmout Drillers N.L., Canso Resources Limited, International Oil Proprietary, Pancontinental Petroleum Limited, IEDC Australia Pty Limited, Amadeus Oil N.L., Southern Alloy Venture Pty. Limited and Gasgo Pty. Limited. Also included are the Guarantee of the Northern Territory of Australia dated June 28, 1985 and Certification letter dated June 28, 1985 that the Guarantee is binding. All of the above were filed as Exhibit 10(h) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) and are incorporated herein by reference.
(i) Mereenie Gas Purchase Agreement dated June 28, 1985 between Magellan Petroleum (N.T.) Pty. Ltd., United Oil & Gas Co. (N.T.) Pty. Ltd., Canso Resources Limited, Moonie Oil N.L., Petromin No Liability, Transoil No Liability, Farmout Drillers N.L., Gasgo Pty. Limited, The Moonie Oil Company
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Limited, Magellan Petroleum Australia Limited and Flinders Petroleum N.L. Also included is the Guarantee of the Northern Territory of Australia dated June 28, 1985. All of the above were filed as Exhibit 10(i) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) and are incorporated herein by reference.
(j) Agreements dated June 28, 1985 relating to Amadeus Basin -Darwin Pipeline which include Deed of Trust Amadeus Gas Trust, Undertaking by the Northern Territory Electric Commission and Undertaking from the Northern Territory Gas Pty Ltd. filed as Exhibit 10(j) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(k) Agreement between the Mereenie Producers and the Palm Valley Producers dated June 28, 1985 filed as Exhibit 10(k) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(l) Form of Agreement pursuant to Article SIXTEENTH of the Company’s Certificate of Incorporation and the applicable By-Law to indemnify the Company’s directors and officers filed as Exhibit 10(l) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(m) 1998 Stock Option Plan, filed as Exhibit 4(a) to Form S-8 Registration Statement on January 14, 1999, filed as Exhibit 10(m) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference.
(n) 1989 Stock Option Plan filed as Exhibit O to Annual Report on Form 10-K for the year ended June 30, 2002 (File No. 001-5507) is incorporated herein by reference.
(o) Palm Valley Gas Purchase Agreement Deed of Amendment dated January 17, 2003 filed as Exhibit 10(p) to Annual Report on Form 10-K for the year ended June 30, 2003 (file No. 001-5507) is incorporated herein by reference.
(p) Share sale agreement dated July 10, 2003 between Sagasco Amadeus Pty. Limited and Magellan Petroleum Corporation filed as Exhibit 10(p) to Annual Report on Form 10-K for the year ended June 30, 2003 (File No. 001-5507) is incorporated herein by reference.
(q) Registration Rights Agreement date September 2, 2003 between 2003 between Sagasco Amadeus Pty. Limited and Magellan Petroleum Corporation filed as Exhibit 10(p) to Annual Report on Form 10-K for the year ended June 30, 2003 (File No. 001-5507) is incorporated herein by reference.
(r) Employment Agreement between Daniel J. Samela and Magellan Petroleum Corporation effective March 1, 2004, filed as Exhibit 10(1) to Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 (File No. 001-5507) is incorporated herein by reference.
(s) Palm Valley Renewal of Petroleum Lease dated November 6, 2003, is filed as Exhibit 10 (s) to Annual Report on Form 10K for the year ended June 30, 2005, is incorporated herein by reference.
(t) Loan Agreement between Magellan Petroleum Corporation and Magellan Petroleum Australia Limited, dated as of July 31, 2006, is filed herein.
11. Statement re computation of per share earnings.
Not applicable.
12. Statement re computation of ratios.
None.
13. Annual report to security holders, Form 10-Q or quarterly report to security holders.
Not applicable.
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14. Code of Ethics
Magellan Petroleum Corporation Standards of Conduct is filed herein.
16. Letter re change in certifying accountant.
None
18. Letter re change in accounting principles.
None.
21. Subsidiaries of the registrant.
Filed herein.
22. Published report regarding matters submitted to vote of security holders.
Not applicable.
23. Consent of experts and counsel.
1. Consent of Deloitte & Touche LLP is filed herein.
2. Consent of Paddock Lindstrom & Associates, Ltd. is filed herein.
24. Power of attorney.
None.
31. Rule 13a-14(a) Certifications.
Certification of Daniel J. Samela, Chief Executive Officer and Chief Financial and Accounting Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, is filed herein.
32. Section 1350 Certifications.
Certification of Daniel J. Samela, President, Chief Executive Officer and Chief Financial and Accounting Officer, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, is filed herein.
(d) Financial Statement Schedules.
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MAGELLAN PETROLEUM CORPORATION | |
(Registrant) | |
/s/Daniel J. Samela | |
Daniel J. Samela | |
President, Chief Executive Officer, Chief | |
Financial and Accounting Officer |
Dated: September 27, 2006
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/Daniel J. Samela | President, Chief Executive Officer, Chief Financial and Accounting Officer | Dated: September 27, 2006 | ||||
/s/Donald V. Basso | Director | Dated: September 27, 2006 | ||||
/s/Timothy L. Largay | Director | Dated: September 27, 2006 | ||||
/s/Robert Mollah | Director | Dated: September 27, 2006 | ||||
/s/Walter Mccann | Director | Dated: September 27, 2006 | ||||
/s/Ronald P. Pettirossi | Director | Dated: September 27, 2006 |
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INDEX TO EXHIBITS
10(t) | Loan Agreement between Magellan Petroleum Corporation and Magellan Petroleum Australia Limited, dated as of July 31, 2006. | |||
14 | . | Magellan Petroleum Corporation Standards of Conduct. | ||
21 | . | Subsidiaries of the Registrant. | ||
23 | . | 1. Consent of Deloitte & Touche LLP | ||
2. Consent of Paddock Lindstrom & Associates, Ltd. | ||||
31 | . | Rule 13a-14(a) Certifications. | ||
32 | . | Section 1350 Certifications. |