UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended June 30, 2005 |
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or |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period
from to |
Commission file number 1-5507
Magellan Petroleum Corporation
(Exact name of registrant as specified in its charter)
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Delaware
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06-0842255 |
State or other jurisdiction of
incorporation or organization |
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(I.R.S. Employer
Identification No.) |
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10 Columbus Boulevard, Hartford, CT
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06106 |
(Address of principal executive offices) |
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(Zip Code) |
Registrants telephone number, including area code
(860) 293-2006
Securities registered pursuant to Section 12(b) of the
Act:
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Name of Each Exchange on |
Title of Each Class |
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Which Registered |
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Common stock, par value $.01 per share
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Boston Stock Exchange |
Securities registered pursuant to Section 12(g) of the
Act
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Title of Class |
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Common stock, par value $.01 per share
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NASDAQ SmallCap Market |
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 registrants
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 an accelerated
filer (as defined in Rule 12b-2 of the Exchange
Act). Yes o No 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 $1.31
closing price on December 31, 2004 (the last business day
of the most recently completed second quarter) was $33,453,370.
Indicate the number of shares outstanding of each of the
registrants classes of common stock, as of the latest
practicable date:
Common stock, par value $.01 per share,
25,784,983 shares outstanding as of September 22, 2005.
DOCUMENTS INCORPORATED BY REFERENCE
None
TABLE OF CONTENTS
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Page | |
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PART I |
Item 1.
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Business |
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2 |
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Item 2.
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Properties |
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10 |
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Item 3.
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Legal Proceedings |
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13 |
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Item 4.
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Submission of Matters to a Vote of Security Holders |
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13 |
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PART II |
Item 5.
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Market for the Companys Common Stock, Related Stockholder
Matters and Issuer Purchase of Equity Securities |
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14 |
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Item 6.
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Selected Financial Data |
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15 |
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Item 7.
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Managements Discussion and Analysis of Financial Condition
and Results of Operations |
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16 |
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Item 7A.
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Quantitative and Qualitative Disclosures About Market Risk |
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25 |
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Item 8.
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Financial Statements and Supplementary Data |
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26 |
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Item 9.
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Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure |
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50 |
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Item 9A.
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Controls and Procedures |
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51 |
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Item 9B.
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Other Information |
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51 |
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PART III |
Item 10.
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Directors and Executive Officers of the Registrant |
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52 |
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Item 11.
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Executive Compensation |
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54 |
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Item 12.
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Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters |
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56 |
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Item 13.
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Certain Relationships and Related Transactions |
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56 |
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Item 14.
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Principal Accountant Fees and Services |
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57 |
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PART IV |
Item 15.
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Exhibits and Financial Statement Schedules |
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58 |
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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, 2005 was approximately A.$1.00 equaled
U.S.$.77.
1
PART I
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, 2005,
MPCs principal asset was a 55.125% equity interest of
stock that is publicly held in Australia and listed on the
Australian stock exchange under the trading symbol MAG.
MPALs 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. Santos Ltd owned 18.2% of MPALs
outstanding stock at June 30, 2003. It sold all of its
interest during 2004. Origin Energy Limited, a publicly owned
Australian company, owned 17.1% of MPALs outstanding stock
at June 30, 2003. On July 10, 2003, a subsidiary of
Origin Energy, Sagasco Amadeus Pty. Limited, agreed to
exchange 1.2 million shares of MPAL for
1.3 million shares of the Companys common stock.
After the exchange was completed on September 2, 2003,
MPCs interest in MPAL increased to 55% and Origin
Energys interest decreased to 14.5%. At June 30, 2005
Origin Energys interest in MPAL is 11%.
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 258 barrels of oil per day (MPAL share 100
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. During October 2003, the Company received
approximately $851,000, after Canadian withholding taxes and
reimbursement of certain past legal costs. The plaintiffs
terminated all litigation against the defendants related to the
field, including the claim that the defendants failed to fully
develop the field. Since each party agreed to bear its own legal
costs, there were no taxable costs assessed against any of the
parties. See Item 3 Legal Proceedings.
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 55.125% 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.
Origin Energy Limited owns 11% of MPAL.
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.
2
AUSTRALIA
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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. MPALs share
of the Mereenie field proved developed oil reserves (net of
royalties), based upon contract amounts, was approximately
262,000 barrels and 14.6 billion cubic feet
(bcf) of gas at June 30, 2005. 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 2005, MPALs share of oil sales was
136,000 barrels and 4.3 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 a 167-mile eight-inch oil pipeline from the field to an
industrial park near Alice Springs. The oil is then shipped
south approximately 950 miles by road to the Port Bonython
Export Terminal, Whyalla, South Australia for sale. The cost of
transporting the oil to the terminal is being borne by the
Mereenie Producers. The Mereenie Producers are providing
Mereenie gas in the Northern Territory to the Power and Water
Corporation (PAWC) and Gasgo Pty. Limited (Gasgo), a
company PAWC wholly owns, 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.
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 and Gasgo. See Gas Supply
Contracts below. MPALs share of the Palm Valley
proved developed reserves, net of royalities, was 10.7 bcf at
June 30, 2005 and is based upon contract amounts. During
fiscal 2005, MPALs share of gas sales was 2.4 bcf which is
subject to a 10% statutory government royalty and net overriding
royalties aggregating 7.3125%. MPAL drilled an additional
development well, Palm Valley-11, in 2004. The well was a dry
hole. Gasgo paid the cost of the well under the gas supply
agreement. The producers and Gasgo have agreed to install
additional compression equipment in the field that will assist
field deliverability during the remaining Darwin gas contract
period. Gasgo will pay for the cost of the additional
compression under the gas supply agreement, which is scheduled
to be commissioned in the field at the end of 2005. The
production lease covering the Palm Valley field expires in
November 2024.
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 the
PAWCs Darwin generating station and at a number of other
generating stations in the Northern Territory. The gas is being
delivered via the 922-mile Amadeus Basin gas pipeline which was
built by an Australian consortium. Since 1985, there have been
several additional contracts for the sale of Mereenie gas. The
Palm Valley Darwin contract expires in the year 2012 and the
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. As
indicated above, 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.
3
At June 30, 2005, MPALs commitment to supply gas
under the above agreements was as follows:
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Period |
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Bcf | |
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Less than one year
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6.21 |
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Between 1-5 years
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23.06 |
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Greater than 5 years
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.80 |
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Total
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30.07 |
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MPAL purchased its 40.936% working interest (38.703% net revenue
interest) in the Nockatunga oil fields in southwest Queensland
during 2004. Santos Ltd. 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 258 barrels of oil per day (MPAL share 100
bbls). During fiscal 2005, MPALs share of oil sales was
35,000 barrels which is subject to a 10% statutory
government royalty and net overriding royalties aggregating
3.0%. MPALs share of the Nockatunga fields proved
developed oil reserves was approximately 253,000 barrels at
June 30, 2005. Petroleum Lease 33 expires in April 2007 and
Petroleum Leases 50 and 51 expire in June 2011.
A 92 square mile 3D seismic survey was undertaken in late
2004 over PL51 and parts of PL33 and ATP 267P. The drilling of
four wells, development as well as exploration, is planned for
late 2005 at locations identified by the seismic data.
MPALs share of the cost is approximately $1,065,000. At
June 30, 2005, MPALs share of the work obligations of
ATP 267P totaled $312,000, of which none was committed.
MPAL has a 34.3% interest in the Dingo gas field which is held
under a retention license. No market has emerged for the gas
volumes that have been discovered in the Dingo gas field, which
is located in the Amadeus Basin in the Northern Territory.
MPALs 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.
During fiscal year 2001, MPAL acquired a 50% working interest in
each of exploration permits WA-306-P and WA-307-P in the Barcoo
Sub-basin of the southern Browse Basin, offshore Western
Australia. Antrim Energy, a Canadian company, is the operator of
the joint venture. During October 2004, Antrim Energy and ONGC
Videsh Limited, an Indian company, funded the drilling of the
South Galapagos-1 well in WA-306-P, including MPALs
estimated share of the well cost of $1,006,000. MPALs
interest in WA 306-P reduced to 12.5%. The well was a dry hole
and MPAL has withdrawn from both these permits.
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. At June 30, 2005, MPALs share
of the work obligations of permit ATP 613P totaled $1,067,000,
of which $114,000 is committed.
PEL 94, PEL 95 & PPL 210
During fiscal year 1999, MPAL (50%) and its partner Beach
Petroleum Ltd. were successful in bidding for two exploration
blocks (PEL 94 and PEL 95) in South Australias 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
4
2005, production had declined to about 25 barrels of oil
per day. Petroleum Production Licence 210 was granted over the
Aldinga field in December 2004. During July 2004, the
Waitpinga-1 well was drilled in PEL 95 and the
Almonta-1 well was drilled in PEL 95 during April 2005.
Both wells were dry holes. 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. MPALs interest
in PEL 94 was reduced to 35%. Black Rock Petroleum NL
subsequently assigned its interest in PEL 94 to Victoria
Petroleum NL. MPALs share of the cost of the two wells was
approximately $301,000. These have been reflected as exploration
and production costs in the consolidated financial statements.
At June 30, 2005, MPALs share of the work obligations
of the two permits totaled $513,000, of which $288,000 was
committed.
PEL 110 & PELA 116
During fiscal year 2001, MPAL and its partner Beach Petroleum
Ltd. were also successful in bidding for two additional
exploration blocks, PEL 110 (37.5%) and PELA 116 (50%) in the
Cooper Basin. PEL 110 was granted in February 2003. The
application for PEL 116 has been withdrawn. During July 2005,
the Yanerbie-1 well was drilled in PEL 110. 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.
MPAL has granted Enterprise Energy NL the option to earn a 6.25%
interest in the PEL 110 by funding further exploration in the
area. At June 30, 2005, MPALs share of the work
obligations of the PEL 110 permit totaled $601,000, of which
$143,000 was committed.
NEW ZEALAND
PEP 38222 & PEP 38225
During fiscal 2002, MPAL (100%) was granted exploration permit
PEP 38222, offshore south of the South Island of New Zealand.
Following a program of seismic reprocessing and interpretation,
the permit was surrendered during May 2005. In November 2003,
MPAL (100%) was granted permit PEP 38225, adjacent to PEP 38222.
At June 30, 2005, MPALs work obligations on the PEP
38225 permit totaled $12,725,000, of which none is committed.
PEP 38746, PEP 38748, PEP 38765 & PEP 38766
In August 2002, MPAL was granted a 25% interest in permits PEP
38746 and PEP 38748 in the Taranaki Basin in the North Island,
New Zealand. MPAL and its partners drilled the Hihi-1 well
in PEP 38748 during November 2004 and the Kakariki-1 well
during February 2005 at an approximate cost of $422,000 to MPAL.
Hihi located a sub-commercial gas pool and Kakariki-1 was a dry
hole. MPAL has withdrawn from the PEP 38746 and PEP 38748
permits.
MPAL was granted exploration permits PEP 38765 (12.5%) and PEP
38766 (25%) during 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 38766. At
June 30, 2005, MPALs share of the work obligations of
the PEP 38765 permit totaled $210,000, of which none was
committed.
UNITED KINGDOM
PEDL 098 & PEDL 099
During fiscal year 2001, MPAL acquired an interest in two
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 spudded in the
PEDL 098 permit during August 2005. At June 30, 2005,
MPALs share of the work obligations of the permits totaled
$1,112,000, of which $114,000 was committed. The UK companies,
Northern Petroleum and Montrose Industries, funded part of
MPALs share of the cost of the Sandhills-2 well.
5
PEDL 112 & PEDL 113
During fiscal year 2002, MPAL acquired two additional licenses
in southern England. The two licenses, PEDL 113 (22.5%) in the
Isle of Wight and PEDL 112 (33.3%) in the Kent area on the
margin of the Weald-Wessex basin, were each granted for a period
of six years. At June 30, 2005, MPALs share of the
work obligations of the permits totaled $1,458,000, of which
$60,000 was committed.
PEDL 125 & PEDL 126
Effective July 1, 2003, MPAL acquired two 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 well is expected in 2006. The UK company, Oil Quest
Resources Plc, will fund part of MPALs share of the cost
of the two wells to acquire a 10% interest in each of the
permits. At June 30, 2005, MPALs share of the work
obligations of the two permits totaled $1,759,000, of which
$1,686,000 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 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 and interpretation. At June 30,
2005, MPALs work obligation for the three licenses totaled
$8,573,000, of which none was committed.
PEDL 151, PEDL 152, PEDL 153, PEDL 154 & PEDL 155
Effective October 1, 2004, MPAL acquired an additional five
licenses 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 UK
company, Oil Quest Resources Plc, will fund part of MPALs
share of the PEDL 155 exploration costs to acquire a 10%
interest in the license. At June 30, 2005, MPALs work
obligation for the five licenses totaled $4,159,000, of which
none 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 $220,352 from this field in 2005.
During September 2003, MPC entered into a settlement agreement
with the litigants in the Kotaneelee litigation. In October
2003, the Company received approximately $851,000, after
Canadian withholding taxes and reimbursement of certain past
legal costs from the settlement. The plaintiffs, including MPC,
terminated all litigation against the defendants related to the
field, including the claim that the defendants failed to fully
develop the field. Since each party agreed to bear its own legal
costs, there were no taxable costs assessed against any of the
parties. See Item 3. Legal Proceedings.
(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 majority 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, New Zealand
and the United Kingdom.
6
(i) Principal Products.
MPAL has an interest in the Palm Valley gas field and in the
Mereenie oil and gas field as well as the Nockatunga and Aldinga
oil fields in South Australias Cooper Basin. See
Item 1(a) Australia for a
discussion of the oil and gas production from the Mereenie and
Palm Valley 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 and Palm Valley fields in Australia,
the Nockatunga fields in Australia and MPCs 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.
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Permit |
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Expiration Date |
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Location |
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Petroleum Lease No. 4 and No. 5 (Mereenie) (Amadeus
Basin)
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November 2023 |
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Northern Territory, Australia |
Petroleum Lease No. 3 (Palm Valley)
(Amadeus Basin)
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November 2024 |
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Northern Territory, Australia |
Retention License 2 (Dingo) (Amadeus Basin)
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October 2008 |
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Northern Territory, Australia |
Petroleum Lease No. 33 (Nockatunga)
(Cooper Basin)
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April 2007 |
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Queensland, Australia |
Petroleum Lease No. 50 and No. 51(Nockatunga) (Cooper
Basin)
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June 2011 |
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Queensland, Australia |
ATP 613P (Maryborough Basin)
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March 2007 |
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Queensland, Australia |
ATP 674P (Maryborough Basin)
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Application pending |
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Queensland, Australia |
ATP 733P (Maryborough Basin)
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Application pending |
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Queensland, Australia |
ATP 267P (Nockatunga) (Cooper Basin)
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November 2007 |
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Queensland, Australia |
ATP 732P (Cooper Basin)
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Application pending |
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Queensland, Australia |
WA-306-P (Browse Basin)
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July 2006 |
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Offshore Western Australia |
WA-307-P (Browse Basin)
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August 2006 |
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Offshore Western Australia |
PEL 94 (Cooper Basin)
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November 2006 |
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South Australia |
PEL 95 (Cooper Basin)
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October 2006 |
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South Australia |
PEL110 (Cooper Basin)
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February 2008 |
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South Australia |
PEP 38746 (Taranaki Basin)
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August 2007 |
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New Zealand |
PEP 38748 (Taranaki Basin)
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August 2007 |
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New Zealand |
PEP 38765 (Taranaki Basin)
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February 2009 |
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New Zealand |
PEP 38766 (Taranaki Basin)
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February 2009 |
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New Zealand |
PEP 38225 (Great South Basin)
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November 2009 |
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New Zealand |
PEDL 098 (Weald-Wessex Basins)
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September 2006 |
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United Kingdom |
PEDL 099 (Weald-Wessex Basins)
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September 2006 |
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United Kingdom |
PEDL 112 (Weald-Wessex Basins)
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January 2008 |
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United Kingdom |
PEDL 113 (Weald Basin)
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January 2008 |
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United Kingdom |
PEDL 125 (Weald-Wessex Basins)
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July 2009 |
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United Kingdom |
PEDL 126 (Weald-Wessex Basins))
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July 2009 |
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United Kingdom |
7
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Permit |
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Expiration Date |
|
Location |
|
|
|
|
|
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 |
Leases issued by the Northern Territory are subject to the
Petroleum (Prospecting and Mining) Act of the Northern
Territory. Lessees have the exclusive right to produce petroleum
from the land subject to a lease upon 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.
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 MPALs properties.
(v) Seasonality of Business.
Although the Companys 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 MPALs 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 MPALs gas
production.
MPALs principal customer and the most likely major
customer for future gas sales is PAWC, a governmental authority
of the Northern Territory Government, which also has substantial
regulatory authority over MPALs oil and gas operations.
The loss of PAWC as a customer would have a material adverse
effect on MPALs business.
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 Aldinga is shipped and sold through the Moomba processing
facility in northeastern South Australia, Nockatunga crude oil
is shipped and sold through the IOR refinery at Eromanga,
Southwest Queensland. Oil sales during 2005 were 66.6% to the
Santos group of companies, 20.2% to Delphi Petroleum P/L and
13.2% to Origin Energy Resources Ltd.
(viii) Backlog.
Not applicable.
(ix) Renegotiation of Profits or Termination of
Contracts or Subcontracts at the Election of the Government.
Not applicable.
8
(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 Companys principal income
producing operations are in Australia and for this reason,
current competitive conditions in Australia are material to the
Companys 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 its
respective share of 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
Companys operations or its financial resources.
At June 30, 2005, the Company had accrued approximately
$5.7 million for asset retirement obligations for the
Mereenie, Palm Valley, Kotaneelee, Nockatunga and Dingo fields.
See Note 2 of the Consolidated Financial Statements under
Item 8. Financial Statements and Supplementary Data.
(xiii) Number of Persons Employed by Company.
At June 30, 2005, MPC had two full-time employees in the
United States and MPAL had 31 employees in Australia. MPC relies
to a great extent on consultants for legal, accounting,
administrative and geological services.
(d)(2) Financial Information Relating to Foreign and Domestic
Operations.
See Note 10 to the Consolidated Financial Statements.
(3) Risks Attendant to Foreign Operations.
Most of the properties in which the Company has interests are
located outside the United States and are subject to certain
risks involved in the ownership and development of such foreign
property interests. These risks include but are not limited to
those of: nationalization; expropriation; confiscatory taxation;
changes in foreign exchange controls; currency revaluations;
price controls or excessive royalties; export sales
restrictions; limitations on the transfer of interests in
exploration licenses; and other laws and regulations which may
adversely affect the Companys 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.
9
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 MPALs properties.
(4) Data Which are Not Indicative of Current or Future
Operations.
None.
(a) MPC has interests in properties in Australia through
its 55% equity interest in MPAL which holds interests in the
Northern Territory, Queensland, South Australia and Western
Australia. MPAL also has interests in New Zealand and the United
Kingdom. In Canada, MPC has a direct interest in one lease. For
additional information regarding the Companys 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 |
10
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.
The following graphic presentation has been omitted, but the
following is a description of the omitted material:
NEW ZEALAND PROPERTY INTERESTS MAP
The map indicates the location of the MPAL property interests in
New Zealand.
(2) Reserves Reported to Other Agencies.
None
(3) Production.
MPCs net production volumes for gas and oil during the
three years ended June 30, 2005 were as follows (data for
Canada has not been included since MPC is in a carried interest
position and the data is not material)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (bcf)
|
|
|
5.7 |
|
|
|
5.7 |
|
|
|
6.0 |
|
Crude oil (bbl)
|
|
|
151,000 |
|
|
|
150,000 |
|
|
|
126,000 |
|
The average sales price per unit of production for Australia for
the following fiscal years is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (per mcf)
|
|
A.$ |
2.67 |
|
|
A.$ |
2.61 |
|
|
A.$ |
2.65 |
|
Crude oil (per bbl)
|
|
A.$ |
62.74 |
|
|
A.$ |
42.12 |
|
|
A.$ |
42.82 |
|
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 2005, 2004 and 2003,
the cost of remedial work on various wells in the Mereenie field
and lower production levels increased production costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (per mcf)
|
|
A.$ |
.49 |
|
|
A.$ |
.49 |
|
|
A.$ |
.48 |
|
Crude oil (per bbl)
|
|
A.$ |
21.20 |
|
|
A.$ |
25.68 |
|
|
A.$ |
29.15 |
|
Amounts presented above are in Australian dollars to show a more
meaningful trend of underlying operations. For the year ended
June 30, 2005, 2004 and 2003 the average foreign exchange
rates were .7533, .7179, and .5852, respectively.
(4) Productive Wells and Acreage.
Productive wells and acreage at June 30, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive Wells | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
Oil | |
|
Gas | |
|
Developed Acreage | |
|
|
| |
|
| |
|
| |
|
|
Gross | |
|
Net | |
|
Gross | |
|
Net | |
|
Gross Acres | |
|
Net Acres | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Australia
|
|
|
47.0 |
|
|
|
9.8 |
|
|
|
14.0 |
|
|
|
3.20 |
|
|
|
79,957 |
|
|
|
33,647 |
|
Canada
|
|
|
|
|
|
|
|
|
|
|
3.0 |
|
|
|
.08 |
|
|
|
3,350 |
|
|
|
89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47.0 |
|
|
|
9.8 |
|
|
|
17.0 |
|
|
|
3.28 |
|
|
|
83,307 |
|
|
|
33,736 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
(5) Undeveloped Acreage.
The Companys undeveloped acreage (except as indicated
below) is set forth in the table below:
GROSS AND NET ACREAGE AS OF JUNE 30, 2005
MPAL has interests in the following properties (before
royalties). MPC has an interest in these properties through its
55% interest in MPAL.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPAL | |
|
MPC | |
|
|
| |
|
| |
|
|
|
|
Interest | |
|
|
|
Interest | |
|
|
Gross Acres | |
|
Net Acres | |
|
% | |
|
Net Acres | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Territory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PL4/ PL5 Mereenie (Amadeus Basin)(1)
|
|
|
69,407 |
|
|
|
24,292 |
|
|
|
35.00 |
|
|
|
13,392 |
|
|
|
19.30 |
|
|
PL3 Palm Valley (Amadeus Basin)(2)
|
|
|
157,833 |
|
|
|
82,109 |
|
|
|
52.02 |
|
|
|
45,267 |
|
|
|
28.68 |
|
|
RL2 Dingo (Amadeus Basin)
|
|
|
115,596 |
|
|
|
39,696 |
|
|
|
34.34 |
|
|
|
21,882 |
|
|
|
18.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
342,836 |
|
|
|
146,097 |
|
|
|
|
|
|
|
80,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Queensland:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ATP 613P (Maryborough Basin)
|
|
|
230,352 |
|
|
|
230,352 |
|
|
|
100.00 |
|
|
|
126,993 |
|
|
|
55.13 |
|
|
ATP 267P (Cooper Basin)
|
|
|
177,445 |
|
|
|
72,605 |
|
|
|
40.94 |
|
|
|
40,046 |
|
|
|
22.57 |
|
|
PL33/ PL50/ PL51 Nockatunga (Cooper Basin)(3)
|
|
|
87,932 |
|
|
|
36,101 |
|
|
|
40.94 |
|
|
|
19,845 |
|
|
|
22.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
495,729 |
|
|
|
339,058 |
|
|
|
|
|
|
|
186,884 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PEL 94 (Cooper Basin)
|
|
|
669,296 |
|
|
|
234,254 |
|
|
|
35.00 |
|
|
|
129,144 |
|
|
|
19.30 |
|
|
PEL 95/ PPL 210 (Cooper Basin)(4)
|
|
|
960,805 |
|
|
|
480,403 |
|
|
|
50.00 |
|
|
|
264,846 |
|
|
|
27.57 |
|
|
PELA 110 (Cooper Basin)
|
|
|
361,188 |
|
|
|
135,446 |
|
|
|
37.50 |
|
|
|
74,671 |
|
|
|
20.67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,991,289 |
|
|
|
850,103 |
|
|
|
|
|
|
|
468,661 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WA-306-P (Browse Basin)
|
|
|
1,145,413 |
|
|
|
143,177 |
|
|
|
12.50 |
|
|
|
78,933 |
|
|
|
6.89 |
|
|
WA-307-P (Browse Basin)
|
|
|
856,769 |
|
|
|
428,384 |
|
|
|
50.00 |
|
|
|
236,168 |
|
|
|
27.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,002,182 |
|
|
|
571,561 |
|
|
|
|
|
|
|
315,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PEDL 098/113/152 (Weald-Wessex Basins)
|
|
|
82,407 |
|
|
|
18,542 |
|
|
|
22.50 |
|
|
|
10,222 |
|
|
|
12.40 |
|
|
PEDL 099/154 (Weald-Wessex Basins)
|
|
|
52,514 |
|
|
|
21,006 |
|
|
|
40.00 |
|
|
|
11,580 |
|
|
|
22.05 |
|
|
PEDL 112/153 (Weald Basin)
|
|
|
140,342 |
|
|
|
46,776 |
|
|
|
33.33 |
|
|
|
25,788 |
|
|
|
18.37 |
|
|
PEDL 125/126 (Weald-Wessex Basins)
|
|
|
111,975 |
|
|
|
44,790 |
|
|
|
40.00 |
|
|
|
24,693 |
|
|
|
22.05 |
|
|
PEDL 135/136/137 (Weald Basin)
|
|
|
123,152 |
|
|
|
123,152 |
|
|
|
100.00 |
|
|
|
67,894 |
|
|
|
55.13 |
|
|
PEDL 151 (Weald Basin)
|
|
|
23,540 |
|
|
|
2,648 |
|
|
|
11.25 |
|
|
|
1,460 |
|
|
|
6.20 |
|
|
PEDL 154 (Weald Basin)
|
|
|
84,834 |
|
|
|
42,417 |
|
|
|
50.00 |
|
|
|
23,385 |
|
|
|
27.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
618,764 |
|
|
|
299,331 |
|
|
|
|
|
|
|
165,022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Zealand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PEP 38225 (Great South Basin)
|
|
|
2,908,870 |
|
|
|
2,908,870 |
|
|
|
100.00 |
|
|
|
1,603,660 |
|
|
|
55.13 |
|
|
PEP 38746/38748/38766
|
|
|
36,037 |
|
|
|
9,009 |
|
|
|
25.00 |
|
|
|
4,967 |
|
|
|
13.78 |
|
|
PEP 38765
|
|
|
3,137 |
|
|
|
392 |
|
|
|
12.50 |
|
|
|
216 |
|
|
|
6.89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,948,044 |
|
|
|
2,918,271 |
|
|
|
|
|
|
|
1,608,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MPAL
|
|
|
8,398,844 |
|
|
|
5,124,421 |
|
|
|
|
|
|
|
2,825,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPAL | |
|
MPC | |
|
|
| |
|
| |
|
|
|
|
Interest | |
|
|
|
Interest | |
|
|
Gross Acres | |
|
Net Acres | |
|
% | |
|
Net Acres | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Properties held directly by MPC:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Yukon and Northwest Territories:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carried interest(5)
|
|
31,885 8,430,729 |
|
|
|
|
|
|
|
|
|
|
850 2,825,902 |
|
|
|
2.67 |
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Includes 41,644 gross developed acres and 14,575 net
acres. |
|
(2) |
Includes 31,567 gross developed acres and 16,422 net
acres. |
|
(3) |
Includes 6,400 gross developed acres and 2,477 net
acres. |
|
(4) |
Includes 346 gross developed acres and 173 net acres. |
|
(5) |
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 | |
|
|
| |
|
| |
|
| |
|
| |
2005
|
|
|
|
|
|
|
1.88 |
|
|
|
.70 |
|
|
|
|
|
2004
|
|
|
|
|
|
|
3.11 |
|
|
|
.41 |
|
|
|
.52 |
|
2003
|
|
|
.50 |
|
|
|
1.90 |
|
|
|
|
|
|
|
|
|
(7) Present Activities.
There was one well being drilled at June 30, 2005. During
July 2005, the Company decided to plug and abandon exploration
well Yanerbie-1. The Sandhills-2 and Kiana 1wells spudded during
August 2005. 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.
13
PART II
|
|
Item 5. |
Market for the Companys Common Stock and Related
Stockholder Matters and Issuer Purchases of Securities |
(a) Principal Market
The principal market for MPCs common stock is the NASDAQ
SmallCap market under the symbol MPET. The stock is also
traded on the Boston Stock Exchange under the symbol MPC.
The quarterly high and low prices on the most active market,
NASDAQ, during the quarterly periods indicated were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
1st Qtr. | |
|
2nd Qtr. | |
|
3rd Qtr. | |
|
4th Qtr. | |
|
|
| |
|
| |
|
| |
|
| |
High
|
|
|
1.37 |
|
|
|
1.57 |
|
|
|
2.32 |
|
|
|
1.80 |
|
Low
|
|
|
.98 |
|
|
|
1.00 |
|
|
|
1.36 |
|
|
|
1.02 |
|
(b) Approximate Number of Holders of Common Stock at
September 22, 2005
|
|
|
|
|
Title of Class |
|
Number of Record Holders | |
|
|
| |
Common stock, par value $.01 per share
|
|
|
6,752 |
|
(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, 2005
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
319,150 |
|
May 1-31, 2005
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
319,150 |
|
June 1-30, 2005
|
|
|
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, 2005, 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 2005 or 2004. |
14
|
|
Item 6. |
Selected Financial Data. |
The following table sets forth selected data (in thousands) 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, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
2002 | |
|
2001 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
21,871 |
|
|
$ |
19,424 |
|
|
$ |
14,736 |
|
|
$ |
13,700 |
|
|
$ |
14,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of accounting change
|
|
|
87 |
|
|
|
350 |
|
|
|
890 |
|
|
|
92 |
|
|
|
1,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
87 |
|
|
|
350 |
|
|
|
152 |
|
|
|
92 |
|
|
|
1,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share (basic and diluted)
|
|
|
|
|
|
|
.01 |
|
|
|
.01 |
|
|
|
|
|
|
|
.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital
|
|
|
26,208 |
|
|
|
21,696 |
|
|
|
21,798 |
|
|
|
17,862 |
|
|
|
15,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
8,527 |
|
|
|
10,781 |
|
|
|
7,109 |
|
|
|
8,157 |
|
|
|
4,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment (net)
|
|
|
24,265 |
|
|
|
24,421 |
|
|
|
21,592 |
|
|
|
17,046 |
|
|
|
16,482 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
56,424 |
|
|
|
52,894 |
|
|
|
50,741 |
|
|
|
40,166 |
|
|
|
37,498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities
|
|
|
5,729 |
|
|
|
5,256 |
|
|
|
5,629 |
|
|
|
3,974 |
|
|
|
3,982 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interests
|
|
|
18,583 |
|
|
|
16,533 |
|
|
|
16,931 |
|
|
|
13,933 |
|
|
|
12,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
|
|
|
44,660 |
|
|
|
44,660 |
|
|
|
43,152 |
|
|
|
43,332 |
|
|
|
43,426 |
|
|
Accumulated deficit
|
|
|
(15,161 |
) |
|
|
(15,248 |
) |
|
|
(15,598 |
) |
|
|
(15,751 |
) |
|
|
(15,843 |
) |
|
Accumulated other comprehensive loss
|
|
|
(2,323 |
) |
|
|
(4,491 |
) |
|
|
(5,407 |
) |
|
|
(8,965 |
) |
|
|
(10,410 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
27,176 |
|
|
|
24,920 |
|
|
|
22,147 |
|
|
|
18,616 |
|
|
|
17,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange rate A.$ = U.S. at end of period
|
|
|
.76 |
|
|
|
.70 |
|
|
|
.67 |
|
|
|
.56 |
|
|
|
.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock outstanding shares end of period
|
|
|
25,783 |
|
|
|
25,783 |
|
|
|
24,427 |
|
|
|
24,607 |
|
|
|
24,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Book value per share
|
|
|
1.05 |
|
|
|
.97 |
|
|
|
.91 |
|
|
|
.76 |
|
|
|
.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted market value
per share (NASDAQ)
|
|
|
2.40 |
|
|
|
1.31 |
|
|
|
1.20 |
|
|
|
.88 |
|
|
|
1.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flow relating to
proved oil and gas reserves (approximately 45% attributable to
minority interests) (See Note 13)
|
|
|
31,000 |
|
|
|
30,000 |
|
|
|
26,000 |
|
|
|
26,000 |
|
|
|
33,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual production (net of royalties)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (bcf)
|
|
|
5.7 |
|
|
|
5.7 |
|
|
|
6.0 |
|
|
|
6.0 |
|
|
|
5.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls) (In thousands)
|
|
|
151 |
|
|
|
150 |
|
|
|
126 |
|
|
|
141 |
|
|
|
148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
Item 7. |
Managements Discussion and Analysis of Financial
Condition and Results of Operations. |
Forward Looking Statements
Statements included in Managements 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
Magellan Petroleum Corporation (MPC) is engaged in the sale of
oil and gas and the exploration for and development of oil and
gas reserves. MPCs principal asset is a 55.125% equity
interest in its subsidiary, Magellan Petroleum Australia Limited
(MPAL).
MPALs 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
approximately $220,000 from this investment during fiscal 2005.
Critical Accounting Policies
The Company follows the successful efforts method of accounting
for its oil and gas operations. Under this method, the costs of
successful wells, development dry holes, productive leases, and
permit and concession costs are capitalized and amortized on a
units-of-production basis over the life of the related reserves.
Cost centers for amortization purposes are determined on a
field-by-field basis. The Company records its proportionate
share in joint venture operations in the respective
classifications of assets, liabilities and expenses. Unproved
properties with significant acquisition costs are periodically
assessed for impairment in value, with any impairment charged to
expense. The successful efforts method also imposes limitations
on the carrying or book value of proved oil and gas properties.
Oil and gas properties are reviewed for impairment whenever
events or changes in circumstances indicate that the carrying
amounts may not be recoverable. The Company estimates the future
undiscounted cash flows from the affected properties to
determine the recoverability of carrying amounts. In general,
analyses are based on proved developed reserves except in
circumstances where it is probable that additional resources
will be developed and contribute to cash flows in the future.
For Mereenie 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
16
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.
|
|
|
Asset Retirement Obligations |
Effective July 1, 2002, the Company adopted the provisions
of Statement of Financial Accounting Standards
(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 a
units-of-production basis over the life of the related reserves.
Accretion expense in connection with the discounted liability is
recognized over the remaining life of the related reserves. See
Note 3 to the consolidated financial statements regarding
the cumulative effect of the accounting change and its effect on
net income for the year ended June 30, 2003.
The estimated liability is based on the future estimated cost of
land reclamation, plugging the existing oil and gas wells and
removing the surface facilities equipment in the Palm Valley,
Mereenie, Kotaneelee, Nockatunga and Aldinga fields. The
liability is a discounted liability using a credit-adjusted
risk-free rate on the date such liabilities are determined. A
market risk premium was excluded from the estimate of asset
retirement obligations because the amount was not capable of
being estimated. Revisions to the liability could occur due to
changes in the estimates of these costs, acquisition of
additional properties and as new wells are drilled.
Estimates of future asset retirement obligations include
significant management judgment and are based on projected
future retirement costs. Judgments are based upon such things as
field life and estimated costs. Such costs could differ
significantly when they are incurred.
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
Companys 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.
Liquidity and Capital Resources
During September 2003, the litigants in the Kotaneelee
litigation entered into a settlement agreement. In October 2003,
the Company received approximately $851,000, after Canadian
withholding taxes and reimbursement of certain past legal costs.
The plaintiffs terminated all litigation against the defendants
related to the field, including the claim that the defendants
failed to fully develop the field. Since each party has agreed
to bear its own legal costs, there were no taxable costs
assessed against any of the parties. The settlement was recorded
during the quarter ending September 30, 2003. See
Note 11 to the consolidated financial statements.
At June 30, 2005, the Company on a consolidated basis had
approximately $21.7 million of cash and cash equivalents
and $3.2 million in marketable securities.
Net cash provided by operations was $8,776,195 in 2005 compared
to $10,717,936 in 2004. The decrease is primarily related to the
absence in 2005 of cash received from the Kotaneelee settlement
and decreased
17
collections from MPALs largest customer. Cash flow from
operations is primarily the result of MPALs oil and gas
activities.
During 2005, the Company had net investments in marketable
securities of $40,000 compared to $990,000 in 2004. The decrease
in investments was the result of MPC investing less due to the
absence of the Kotaneelee settlement in 2005.
The Company invested $8,335,370 and $8,937,923 in oil and gas
exploration activities during 2005 and 2004, respectively. The
net increase resulted from an increase in investment in the
Mereenie and Palm Valley fields and the acquisition of
Nockatunga. The Company continues to invest in exploratory
projects that result in exploratory and dry hole expenses in the
consolidated financial statements.
|
|
|
As to MPC (Unconsolidated) |
At June 30, 2005, MPC, on an unconsolidated basis, had
working capital of approximately $3.9 million. Working
capital is comprised of current assets less current liabilities.
MPCs current cash position, its annual MPAL dividend and
the anticipated revenue from the Kotaneelee field should be
adequate to meet its current cash requirements. MPC has in the
past invested and may in the future invest substantial portions
of its cash to maintain or increase its majority interest in its
subsidiary, MPAL. On July 10, 2003, a subsidiary of Origin
Energy, Sagasco Amadeus Pty. Limited, agreed to
exchange 1.2 million shares of MPAL for
1.3 million shares of the Companys common stock.
After the exchange was completed on September 2, 2003, the
Companys interest in MPAL increased to 55%.
In addition to the aforementioned stock exchange, during fiscal
2005, MPC purchased 31,605 shares of MPALs stock at a
cost of $29,466 and increased its interest in MPAL from 55.06%
to 55.125%.
During fiscal 2005, MPC received a dividend from MPAL of
approximately $975,000.
MPC has a stock repurchase plan to purchase up to one million
shares of its common stock in the open market. Through
June 30, 2005, MPC had purchased 680,850 of its shares at a
cost of approximately $686,000. There were no shares purchased
during fiscal 2005 or 2004.
At June 30, 2005, MPAL had working capital of approximately
$22.3 million. MPAL had budgeted approximately
$6.2 million for specific exploration projects in fiscal
year 2005 as compared to the $5.1 million expended during
fiscal 2005. However, the total amount to be expended may vary
depending on when various projects reach the drilling phase. The
current composition of MPALs oil and gas reserves are such
that MPALs future revenues in the long-term are expected
to be derived from the sale of gas in Australia. MPALs
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 MPALs efforts to find partners are
unsuccessful, it may be unable or unwilling to complete the
exploration program for some of its properties.
18
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
752,000 |
|
|
|
183,000 |
|
|
|
388,000 |
|
|
|
181,000 |
|
|
|
|
|
Purchase Obligations(1)
|
|
|
3,380,000 |
|
|
|
3,380,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
5,729,000 |
|
|
|
38,000 |
|
|
|
|
|
|
|
3,773,000 |
|
|
|
1,918,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
9,861,000 |
|
|
$ |
3,601,000 |
|
|
$ |
388,000 |
|
|
$ |
3,954,000 |
|
|
|
1,918,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 $30,083,000 which are not legally
binding have been excluded from the table above and based on
exploration decisions would be due as follows: $14,685, 000
(less than 1 year), $4,327,000 (1-3 years),
$11,071,000 (3-5 years). |
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board
(FASB) published Statement of Financial Accounting
Standards (SFAS) No. 123 (revised 2004),
(SFAS 123(R)) Share Based Payment.
SFAS 123(R) establishes standards for the accounting for
transactions in which an entity exchanges its equity instruments
for goods or services. SFAS 123(R) eliminates the ability
to account for share-based compensation transactions using APB
Opinion No. 25 (APB 25), Accounting for Stock
Issued to Employees, and generally requires that such
transactions be accounted for using a fair-value-based method.
SFAS 123(R) is effective as of the first annual reporting
period of a registrants fiscal year that begins on or
after June 15, 2005, therefore, the effective date for the
Company is July 1, 2005. SFAS 123(R) applies to all
awards granted after the required effective date and to awards
modified, repurchased, or cancelled after that date and as a
consequence future employee stock option grants and other stock
based compensation plans will be recorded as expense over the
vesting period of the award based on their fair values at the
date the stock based compensation is granted. The cumulative
effect of initially applying SFAS 123(R) is to be
recognized as of the required effective date using a modified
prospective method. Under the modified prospective method the
Company will recognize stock-based compensation expense from
July 1, 2005 as if the fair value based accounting method
had been used to account for all outstanding unvested employee
awards granted, modified or settled in prior years. The ultimate
impact on future years results of operation and financial
position will depend upon the level of stock based compensation
granted in future years.
For further information regarding equity- based compensation,
see Note 4 capital and stock options to the
consolidated financial statements
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 liabilitys
fair value can be reasonably estimated. FIN 47 is effective
for the fiscal year end June 30, 2005.
19
On April 4, 2005 the FASB adopted FASB Staff Position
(FSP) FSB 19-1 Accounting for Suspended Well
Costs that amends SFAS 19, Financial Accounting
and Reporting by Oil and Gas Producing Companies, to
permit the continued capitalization of exploratory well costs
beyond one year if the well found a sufficient quantity of
reserves to justify its completion as a producing well and the
entity is making sufficient progress assessing the reserves and
the economic and operating viability of the project. In
accordance with the guidance in the FSP, the Company applied the
requirements prospectively in its fourth quarter of fiscal 2005.
The adoption of FSP 19-1 by the Company during the
fourth quarter of 2005 did not have an immediate affect on
the consolidated financial statements. However, it could impact
the timing of the recognition of expenses for exploratory well
costs in future periods.
In November 2004, the FASB issued SFAS No. 151
Accounting for Inventory Costs that amends
Accounting Research Bulletin (ARB) No. 43,
Chapter 4, Inventory Pricing to clarify the
accounting for abnormal amounts of idle facility expense,
freight, handling costs, and wasted material (spoilage).
SFAS 151 requires that those items be recognized as
current-period charges regardless of whether they meet the
criterion of so abnormal and requires that
allocation of fixed production overheads to the costs of
conversion be based on the normal capacity of the production
facilities. SFAS 151 was effective for the Company for the
fiscal year ended June 30, 2005 and did not have an effect
on the financial statements.
In December 2004, the FASB issued SFAS No. 153
Exchanges of Nonmonetary Assets that amends
Accounting Principles Board (APB) Opinion No. 29,
Accounting for Nonmonetary Transactions. ARB No. 29
is based on the principle that exchanges of nonmonetary assets
should be measured based on the fair value of the assets
exchanged and SFAS 153 amended ABP 29 to eliminate the
exception for nonmonetary exchanges of similar productive assets
and replaced it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance.
SFAS No. 153 was effective for the Company for the
fiscal year ended June 30, 2005 and did not have an effect
on the financial statements.
In May 2005, the FASB issued SFAS No. 154
Accounting Changes and Error Corrections to replace
ABP No. 20 Accounting Changes and
SFAS No. 3 Reporting Accounting Changes in
Interim Financial Statements. Opinion 20 previously
required that most voluntary changes in accounting principle be
recognized by including in net income of the period of the
change the cumulative effect of changing to the new accounting
principle. SFAS 154 requires retrospective application to
prior periods financial statements of changes in
accounting principle, unless it is impracticable to determine
either the period-specific effects or the cumulative effect of
the change. When it is impracticable to determine the
period-specific effects of an accounting change on one or more
individual prior periods presented, SFAS 154 requires that
the new accounting principle be applied to the balances of
assets and liabilities as of the beginning of the earliest
period for which retrospective application is practicable and
that a corresponding adjustment be made to the opening balance
of retained earnings (or other appropriate components of equity
or net assets in the statement of financial position) for that
period rather than being reported in an income statement. When
it is impracticable to determine the cumulative effect of
applying a change in accounting principle to all prior periods,
SFAS 154 requires that the new accounting principle be
applied as if it were adopted prospectively from the earliest
date practicable. SFAS No. 154 is effective for the Company
in the second quarter of fiscal 2006. Management is currently
evaluating the impacts of SFAS 154 on the Company and
cannot yet reasonably estimate the impact of SFAS 154 on
the financial statements.
20
Results of Operations
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 MPALs 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.
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 MPALs 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
21
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 Companys internal controls to
comply with Section 404 of the Act and rules adopted
thereunder that is expected to apply to the Company for the
first time with respect to its annual report for the fiscal year
ending June 30, 2007.
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
MPALs 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 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 tax benefits for the years ended June 30, 2005 and
2004 were $82,153 and $775,085, 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 MPALs 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
MPALs operations in Australia for fiscal 2005 was $.7533,
which is a 5% increase compared to the $.7179 rate for fiscal
2004.
22
Oil sales increased 48% in 2004 to $4,923,000 from $3,329,000 in
2003 because of a 23% Australian foreign exchange rate increase
discussed below and new oil sales from the Cooper Basin and the
Nockatunga project. Oil unit sales are expected to continue to
decline in the Mereenie field unless additional development
wells are drilled to maintain production levels. MPAL is
dependent on the operator (65% control) of the Mereenie field to
maintain production. Oil unit sales (net of royalties) in
barrels (bbls) and the average price per barrel sold during
the periods indicated were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended June 30, | |
|
|
| |
|
|
2004 Sales | |
|
2003 Sales | |
|
|
| |
|
| |
|
|
|
|
Average Price | |
|
|
|
Average Price | |
|
|
Bbls | |
|
A.$ per bbl | |
|
Bbls | |
|
A.$ per bbl | |
|
|
| |
|
| |
|
| |
|
| |
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mereenie Field
|
|
|
110,955 |
|
|
|
43.44 |
|
|
|
124,553 |
|
|
|
42.87 |
|
|
Cooper Basin
|
|
|
6,522 |
|
|
|
37.29 |
|
|
|
800 |
|
|
|
34.41 |
|
|
Nockatunga Project
|
|
|
34,105 |
|
|
|
38.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
151,582 |
|
|
|
42.12 |
|
|
|
125,353 |
|
|
|
42.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2004
and 2003 the average foreign exchange rates were .7179 and .5852
and respectively.
Gas sales increased 26% to $12,870,000 in 2004 from $10,182,000
in 2003 because of the 23% Australian foreign exchange rate
increase discussed below and the $1,135,000 in gross proceeds
from the Canadian Kotaneelee gas field settlement. In addition,
the recurring portion of Kotaneelee revenues declined from
$536,000 in 2003 to $423,000 in 2004 due to reduced production.
This trend is likely to continue. These increases were partially
offset by a 2% decrease in volume and a 3% decrease in
Australian gas prices.
The volumes in billion cubic feet (bcf) (net of royalties) and
the average price of gas per thousand cubic feet (mcf) sold
during the periods indicated were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended June 30, | |
|
|
| |
|
|
2004 Sales | |
|
2003 Sales | |
|
|
| |
|
| |
|
|
|
|
A.$ Average | |
|
|
|
A.$ Average | |
|
|
Bcf | |
|
Price per mcf | |
|
Bcf | |
|
Price per mcf | |
|
|
| |
|
| |
|
| |
|
| |
Australia: Palm Valley
|
|
|
2.376 |
|
|
|
2.25 |
|
|
|
2.604 |
|
|
|
2.43 |
|
Australia: Mereenie
|
|
|
3.287 |
|
|
|
2.86 |
|
|
|
3.218 |
|
|
|
2.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
5.663 |
|
|
|
2.61 |
|
|
|
5.822 |
|
|
|
2.65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other production related revenues increased 33% to $1,632,000 in
2004 from $1,225,000 in 2003. Other production related revenues
are primarily MPALs share of gas pipeline tariff revenues
which increased as a result of the higher volumes of gas sold at
Mereenie, and because of the 23% Australian foreign exchange
rate increase discussed below.
Production costs increased 21% in 2004 to $5,416,000 from
$4,461,000 in 2003 in part because of the 23% Australian foreign
exchange rate increase discussed below. During 2004, production
costs also increased because of the new costs of $545,000 for
the Nockatunga project. These increases were partially offset by
a decrease in production costs applicable to two wells that were
plugged and abandoned in the Mereenie field in 2003. In
addition, a Mereenie two well workover program was completed
during the 2003 period.
23
Exploration and dry hole costs increased 10% to $3,225,000 in
2004 from $2,920,000 in 2003. The 2004 and 2003 costs related to
the exploration work being performed on MPALs properties.
The primary reason for the increase in 2004 is the 23%
Australian foreign exchange rate increase discussed below. For
the 2004 period, exploration costs totaled $1,509,000 and dry
hole costs totaled $1,716,000. For the 2003 period, exploration
costs totaled $2,043,000 and dry hole costs totaled $877,000.
The dry holes were drilled on MPAL properties in Australia and
New Zealand.
Salaries and employee benefits increased 95% to $3,812,000 in
2004 from $1,958,000 in 2003. During the 2004 period, there was
a 23% increase in the Australian foreign exchange rate discussed
below. In addition, MPAL curtailed its pension plan in 2004
which resulted in a $1,248,000 charge, of which $961,000 was non
cash.
Depletion, depreciation and amortization increased 71% from
$3,719,000 in 2003 to $6,342,000 in 2004. During the 2004
period, there was a 23% increase in the Australian foreign
exchange rate as discussed below. Depletion expense for the Palm
Valley and Mereenie fields increased 55% during the period
primarily because of the increase in oil and gas properties
related to MPCs increased interest in MPAL and the current
Mereenie development program. In addition, in 2004, $528,000 in
DD&A was also recorded for the Nockatunga project and the
Cooper Basin. The reserves in the Cooper Basin were reduced by
50% from 50,000 barrels to 25,000 barrels during the
current period because of lower oil production than estimated.
In the 2003 period the Palm Valley gas reserves were increased
by 35% and DD&A decreased by approximately $405,000 because
of this change in gas reserves.
Auditing, accounting and legal expenses increased 2% in 2004 to
$414,000 from $404,000 in 2003 primarily because of the 23%
Australian foreign exchange rate increase discussed below. The
increase was partially offset because the 2003 period included
higher audit fees in connection with the adoption of the new
accounting standard for asset retirement obligations.
Accretion expense increased 47% in the 2004 period from $243,000
in 2003 to $357,000 in 2004. 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 2004 period results from the 23% increase in the
Australian foreign exchange rate as discussed below and the
additions for the Nockatunga project and the Kotaneelee gas
field.
Shareholder communications costs increased 5% from $171,000 in
2003 to $180,000 in 2004 primarily because of MPC and
MPALs increased costs related to their status as public
companies.
Other administrative expenses increased 78% from $370,000 in
2003 to $660,000 in 2004. During the 2004 period, there was a
23% increase in the Australian foreign exchange rate as
discussed below. In addition, there were increases in
consultants fees ($134,000), directors fees and
expenses ($101,000), insurance costs ($120,000), rent ($72,000)
and travel expenses ($26,000) during the 2004 period that were
partially offset by an increase in the amount of overhead
charges that MPAL as operator was able to charge its partners.
Interest increased 28% to $1,099,000 in 2004 from $860,000 in
2003 primarily because of the $102,000 interest received from
the funds held in escrow from the Kotaneelee settlement and
because of the 23% Australian foreign exchange rate increase
discussed below.
Income tax benefits for the years ended June 30, 2004 and
2003 were $778,085 and $773,548, respectively. The income tax
benefits were reduced $362,000 in 2004 related to Canadian
withholding taxes as a result of increased revenues from the
Kotaneelee Settlement. Income tax benefits were further reduced
as a result of a decrease from $1,202,000 in 2003 to $929,000 in
2004 of financing related benefits received by MPAL. These
reductions were offset by an increase in income income tax
benefits of $639,000 resulting from pretax losses in Australia
during 2004. As a result of a change in Australian tax law
during 2004, MPAL does
24
not expect to receive similar financing benefits in the future.
These reductions were offset by tax benefits from MPALs
operating losses.
The value of the Australian dollar relative to the
U.S. dollar increased to $.6993 at June 30, 2004
compared to $.6737 at June 30, 2003. This resulted in a
$915,000 credit to accumulated translation adjustments for
fiscal 2004. The 4% increase in the value of the Australian
dollar increased the reported asset and liability amounts in the
balance sheet at June 30, 2004 from the June 30, 2003
amounts. The annual average exchange rate used to translate
MPALs operations in Australia for fiscal 2004 was $.7179,
which is a 23% increase compared to the $.5852 rate for fiscal
2003.
|
|
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, 2005, the
carrying value of such investments including those classified as
cash and cash equivalents was approximately $25 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 $2.2 million and $2.1 million,
respectively. For the twelve months ended June 30, 2005,
oil sales represented approximately 38% of production revenues.
Based on 2005 sales volume and revenue, a 10% change in oil
price would increase or decrease oil revenues by $757,000. Gas
sales, which represented approximately 62% of production
revenues in 2005, 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.
25
|
|
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
We have audited the accompanying consolidated balance sheets of
Magellan Petroleum Corporation (the Company) as of
June 30, 2005 and 2004, and the related consolidated
statements of income, stockholders equity, and cash flows
for the years then ended. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits. The financial statements of the
Company for the year ended June 30, 2003 were audited by
other auditors whose report, dated September 19, 2003,
expressed an unqualified opinion on those statements and
included an explanatory paragraph concerning a change in
accounting for asset retirement obligations.
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 Companys 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 2005 and 2004 consolidated financial
statements present fairly, in all material respects, the
financial position of Magellan Petroleum Corporation as of
June 30, 2005 and 2004, and the results of its operations
and its cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States of
America.
|
|
|
/s/ Deloitte &
Touche LLP
|
Hartford, Connecticut
September 26, 2005
26
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Magellan Petroleum Corporation
We have audited the accompanying consolidated statements of
income, changes in stockholders equity and cash flows of
Magellan Petroleum Corporation for the year ended June 30,
2003. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the
consolidated results of operations and cash flows of Magellan
Petroleum Corporation for the year ended June 30, 2003 in
conformity with U.S. generally accepted accounting
principles.
As discussed in Notes 1 and 3 to the consolidated financial
statements, in 2003 the Company changed its method of accounting
for asset retirement obligations.
Stamford, Connecticut
September 19, 2003
27
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
21,733,375 |
|
|
$ |
20,406,620 |
|
|
Accounts receivable Trade
|
|
|
4,210,174 |
|
|
|
2,931,609 |
|
|
Accounts receivable Working Interest Partners
|
|
|
864,922 |
|
|
|
1,044,619 |
|
|
Marketable securities
|
|
|
3,216,541 |
|
|
|
2,584,296 |
|
|
Inventories
|
|
|
591,997 |
|
|
|
595,948 |
|
|
Other assets
|
|
|
526,703 |
|
|
|
318,141 |
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
31,143,712 |
|
|
|
27,881,233 |
|
|
|
|
|
|
|
|
Marketable securities
|
|
|
|
|
|
|
592,138 |
|
Deferred income taxes
|
|
|
1,014,907 |
|
|
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
|
Oil and gas properties (successful efforts method)
|
|
|
80,765,911 |
|
|
|
69,970,134 |
|
|
Land, buildings and equipment
|
|
|
2,552,980 |
|
|
|
2,264,004 |
|
|
Field equipment
|
|
|
1,620,909 |
|
|
|
1,482,639 |
|
|
|
|
|
|
|
|
|
|
|
84,939,800 |
|
|
|
73,716,777 |
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(60,674,306 |
) |
|
|
(49,295,770 |
) |
|
|
|
|
|
|
|
|
|
Net property and equipment
|
|
|
24,265,494 |
|
|
|
24,421,007 |
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
56,424,113 |
|
|
$ |
52,894,378 |
|
|
|
|
|
|
|
|
|
LIABILITIES, MINORITY INTERESTS AND STOCKHOLDERS
EQUITY |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
3,602,085 |
|
|
$ |
4,367,305 |
|
|
Accrued liabilities
|
|
|
1,308,004 |
|
|
|
1,550,045 |
|
|
Income taxes payable
|
|
|
25,879 |
|
|
|
267,645 |
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
4,935,968 |
|
|
|
6,184,995 |
|
|
|
|
|
|
|
|
Long term liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
|
|
|
|
403,261 |
|
|
Asset retirement obligations
|
|
|
5,729,180 |
|
|
|
4,852,416 |
|
|
|
|
|
|
|
|
|
|
Total long term liabilities
|
|
|
5,729,180 |
|
|
|
5,255,677 |
|
|
|
|
|
|
|
|
Minority interests
|
|
|
18,583,046 |
|
|
|
16,533,491 |
|
Commitments (Note 11)
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
Common stock, par value $.01 per share:
|
|
|
|
|
|
|
|
|
|
|
Authorized 200,000,000 shares outstanding; 25,783,243
|
|
|
257,832 |
|
|
|
257,832 |
|
|
Capital in excess of par value
|
|
|
44,402,182 |
|
|
|
44,402,182 |
|
|
|
|
|
|
|
|
|
Total capital
|
|
|
44,660,014 |
|
|
|
44,660,014 |
|
|
Accumulated deficit
|
|
|
(15,161,462 |
) |
|
|
(15,248,422 |
) |
|
Accumulated other comprehensive loss
|
|
|
(2,322,633 |
) |
|
|
(4,491,377 |
) |
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
27,175,919 |
|
|
|
24,920,215 |
|
|
|
|
|
|
|
|
Total liabilities, minority interests and stockholders
equity
|
|
$ |
56,424,113 |
|
|
$ |
52,894,378 |
|
|
|
|
|
|
|
|
See accompanying notes.
28
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
7,574,022 |
|
|
$ |
4,922,585 |
|
|
$ |
3,329,243 |
|
|
Gas sales
|
|
|
12,478,293 |
|
|
|
12,870,065 |
|
|
|
10,182,104 |
|
|
Other production related revenues
|
|
|
1,818,471 |
|
|
|
1,631,613 |
|
|
|
1,224,729 |
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
21,870,786 |
|
|
|
19,424,263 |
|
|
|
14,736,076 |
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
6,144,339 |
|
|
|
5,416,465 |
|
|
|
4,461,365 |
|
|
Exploratory and dry hole costs
|
|
|
4,157,344 |
|
|
|
3,225,066 |
|
|
|
2,920,104 |
|
|
Salaries and employee benefits
|
|
|
2,726,341 |
|
|
|
3,812,012 |
|
|
|
1,958,371 |
|
|
Depletion, depreciation and amortization
|
|
|
6,994,253 |
|
|
|
6,341,998 |
|
|
|
3,718,660 |
|
|
Auditing, accounting and legal services
|
|
|
441,642 |
|
|
|
413,754 |
|
|
|
404,215 |
|
|
Accretion expense
|
|
|
406,960 |
|
|
|
356,981 |
|
|
|
242,854 |
|
|
Shareholder communications
|
|
|
227,032 |
|
|
|
179,840 |
|
|
|
171,385 |
|
|
Other administrative expenses
|
|
|
800,200 |
|
|
|
659,751 |
|
|
|
369,942 |
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
21,898,111 |
|
|
|
20,405,867 |
|
|
|
14,246,896 |
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(27,325 |
) |
|
|
(981,604 |
) |
|
|
489,180 |
|
Interest income
|
|
|
1,141,802 |
|
|
|
1,099,440 |
|
|
|
859,865 |
|
Income before income taxes, minority interests and cumulative
effect of accounting change
|
|
|
1,114,477 |
|
|
|
117,836 |
|
|
|
1,349,045 |
|
Income tax benefit
|
|
|
82,152 |
|
|
|
778,085 |
|
|
|
773,548 |
|
|
|
|
|
|
|
|
|
|
|
Income before minority interests and cumulative effect of
accounting change
|
|
|
1,196,629 |
|
|
|
895,921 |
|
|
|
2,122,593 |
|
Minority interests
|
|
|
(1,109,669 |
) |
|
|
(545,860 |
) |
|
|
(1,232,200 |
) |
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of accounting change
|
|
|
86,960 |
|
|
|
350,061 |
|
|
|
890,393 |
|
Cumulative effect of accounting change net
|
|
|
|
|
|
|
|
|
|
|
(737,941 |
) |
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
86,960 |
|
|
$ |
350,061 |
|
|
$ |
152,452 |
|
|
|
|
|
|
|
|
|
|
|
Average number of shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
25,783,243 |
|
|
|
25,644,566 |
|
|
|
24,560,068 |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
25,783,243 |
|
|
|
25,682,160 |
|
|
|
24,560,068 |
|
|
|
|
|
|
|
|
|
|
|
Per share (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of accounting change
|
|
$ |
|
|
|
$ |
.01 |
|
|
$ |
.04 |
|
|
Cumulative effect of accounting change net
|
|
|
|
|
|
|
|
|
|
|
(.03 |
) |
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
$ |
.01 |
|
|
$ |
.01 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
29
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF
CHANGES IN STOCKHOLDERS EQUITY
Three Years Ended June 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
|
|
|
|
Capital in | |
|
|
|
Other | |
|
|
|
Total | |
|
|
Number of | |
|
Common | |
|
Excess of | |
|
Accumulated | |
|
Comprehensive | |
|
|
|
Comprehensive | |
|
|
Shares | |
|
Stock | |
|
Par Value | |
|
Deficit | |
|
Loss | |
|
Total | |
|
Income | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
June 30, 2002
|
|
|
24,607,376 |
|
|
$ |
246,074 |
|
|
$ |
43,085,841 |
|
|
$ |
(15,750,935 |
) |
|
$ |
(8,964,524 |
) |
|
$ |
18,616,456 |
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
152,452 |
|
|
|
|
|
|
|
152,452 |
|
|
$ |
152,452 |
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,507,783 |
|
|
|
3,507,783 |
|
|
|
3,507,783 |
|
Reclassification adjustment on available-for-sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,214 |
|
|
|
50,214 |
|
|
|
50,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,710,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchases of common stock
|
|
|
(180,000 |
) |
|
|
(1,800 |
) |
|
|
(178,100 |
) |
|
|
|
|
|
|
|
|
|
|
(179,900 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
30
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
86,960 |
|
|
$ |
350,061 |
|
|
$ |
152,452 |
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting change
|
|
|
|
|
|
|
|
|
|
|
2,025,690 |
|
|
|
Depletion, depreciation and amortization
|
|
|
6,994,253 |
|
|
|
6,341,998 |
|
|
|
3,718,660 |
|
|
|
Accretion expense
|
|
|
406,960 |
|
|
|
356,981 |
|
|
|
242,854 |
|
|
|
Deferred income taxes
|
|
|
(1,454,544 |
) |
|
|
(1,445,241 |
) |
|
|
(1,494,621 |
) |
|
|
Minority interests
|
|
|
1,109,669 |
|
|
|
545,860 |
|
|
|
552,158 |
|
|
|
Exploration and dry hole costs
|
|
|
3,200,816 |
|
|
|
2,897,766 |
|
|
|
1,961,421 |
|
|
Increase (decrease) in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(978,727 |
) |
|
|
1,456,833 |
|
|
|
(951,967 |
) |
|
|
Other assets
|
|
|
(208,563 |
) |
|
|
905,146 |
|
|
|
(214,946 |
) |
|
|
Inventories
|
|
|
57,207 |
|
|
|
(142,397 |
) |
|
|
(69,275 |
) |
|
|
Accounts payable and accrued liabilities
|
|
|
(191,341 |
) |
|
|
(715,548 |
) |
|
|
1,368,413 |
|
|
|
Income taxes payable
|
|
|
(246,495 |
) |
|
|
166,477 |
|
|
|
(123,087 |
) |
|
|
Settlement of asset retirement obligation
|
|
|
|
|
|
|
|
|
|
|
(58,901 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
8,776,195 |
|
|
|
10,717,936 |
|
|
|
7,108,851 |
|
|
|
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
(5,154,554 |
) |
|
|
(6,040,157 |
) |
|
|
(2,438,829 |
) |
|
Oil and gas exploration activities
|
|
|
(3,200,816 |
) |
|
|
(2,897,766 |
) |
|
|
(1,961,421 |
) |
|
Sale of available-for-sale securities
|
|
|
|
|
|
|
|
|
|
|
93,334 |
|
|
Marketable securities matured
|
|
|
5,599,328 |
|
|
|
5,760,239 |
|
|
|
2,071,687 |
|
|
Marketable securities purchased
|
|
|
(5,639,435 |
) |
|
|
(6,750,171 |
) |
|
|
(2,564,501 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(8,395,477 |
) |
|
|
(9,927,855 |
) |
|
|
(4,799,730 |
) |
|
|
|
|
|
|
|
|
|
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends to MPAL minority shareholders
|
|
|
(821,732 |
) |
|
|
(744,971 |
) |
|
|
(628,209 |
) |
|
Repurchases of common stock
|
|
|
|
|
|
|
|
|
|
|
(179,900 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(821,732 |
) |
|
|
(744,971 |
) |
|
|
(808,109 |
) |
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
1,767,769 |
|
|
|
320,046 |
|
|
|
2,755,601 |
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
1,326,755 |
|
|
|
365,156 |
|
|
|
4,256,613 |
|
Cash and cash equivalents at beginning of year
|
|
|
20,406,620 |
|
|
|
20,041,464 |
|
|
|
15,784,851 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$ |
21,733,375 |
|
|
$ |
20,406,620 |
|
|
$ |
20,041,464 |
|
|
|
|
|
|
|
|
|
|
|
Cash Payments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes
|
|
|
13,000 |
|
|
|
12,000 |
|
|
|
173,000 |
|
|
Interest
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
31
|
|
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, 2005 and
2004, MPCs principal asset was a 55% equity interest in
its subsidiary, Magellan Petroleum Australia Limited (MPAL),
which has one class of stock that is publicly held and listed on
the Australian Stock Exchange under the trading symbol MAG.
MPALs 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 fields are located in the Amadeus Basin in the Northern
Territory of Australia. MPC has a direct 2.67% carried interest
in the Kotaneelee gas field in the Yukon Territory of Canada.
On July 10, 2003, a subsidiary of Origin Energy, Sagasco
Amadeus Pty. Limited, agreed to exchange 1.2 million
shares of MPAL for 1.3 million shares of the Companys
common stock. After the exchange was completed on
September 2, 2003, MPCs interest in MPAL increased to
55%. In fiscal 2005 and 2004, MPC purchased 32,000 (for $29,466)
and 24,000 shares (for $22,000), respectively of MPAL.
The accompanying consolidated financial statements include the
accounts of MPC and its majority owned subsidiary, MPAL,
collectively the Company. All intercompany transactions have
been eliminated.
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
Companys 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. 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.
Oil and gas properties are located in Australia, New Zealand,
Canada and the United Kingdom. The Company follows the
successful efforts method of accounting for its oil and gas
operations. Under this method, the costs of successful wells,
development dry holes, productive leases, and permitted
concession costs are capitalized and amortized on a
units-of-production basis over the life of the related reserves.
Cost centers for amortization purposes are determined on a
field-by-field basis. The Company records its proportionate
share in its working interest agreements in the respective
classifications of assets, liabilities and expenses. Unproved
properties with significant acquisition costs are periodically
assessed for impairment in value, with any impairment charged to
expense. The successful efforts method also imposes limitations
on the carrying or book value of proved oil and gas properties.
Oil and gas properties are reviewed for impairment whenever
events or changes in circumstances indicate that the carrying
amounts may not be recoverable. The Company estimates the future
undiscounted cash flows from the affected properties to
determine the recoverability of carrying amounts. In general,
analyses are based on proved developed reserves, except in
circumstances where it is probable that additional resources
will be developed and contribute to cash flows in the future.
For Mereenie 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.
Effective July 1, 2002, the Company adopted the provisions
of Statement of Financial Accounting Standard (SFAS)143,
Accounting for Asset Retirement Obligations.
SFAS 143 requires legal obligations
32
associated with the retirement of long-lived assets to be
recognized at their fair value at the time that the obligations
are incurred. Upon initial recognition of a liability, that cost
is capitalized as part of the related long-lived asset
(oil & gas properties) and amortized on a
units-of-production basis over the life of the related reserves.
Accretion expense in connection with the discounted liability is
recognized over the remaining life of the related reserves.
The estimated liability is based on the future estimated cost of
plugging the existing oil and gas wells and removing the surface
facilities equipment in the Palm Valley and Mereenie fields in
the Northern Territory of Australia, the Nockatunga fields in
Queensland, the Aldinga fields in South Australia, and the
Kotaneelee fields in Southeast Yukon Territory of Canada. The
liability is a discounted liability using a credit-adjusted
risk-free rate, based on the date the liability was recorded and
the geographic locations of the fields as follows: Mereenie and
Palm Valley, approximately 8%; Nockatunga, 6.25%; Aldinga, 6.3%;
and Kotaneelee, 4.5%. 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.
Effective July 1, 2002, the Company adopted the provisions
of SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. SFAS 144 supersedes
previous guidance related to the impairment or disposal of
long-lived assets. For long-lived assets to be held and used, it
resolves certain implementation issues of the former standards,
but retains the basic requirements of recognition and
measurement of impairment losses. For long-lived assets to be
disposed of by sale, it broadens the definition of those
disposals that should be reported separately as discontinued
operations. There was no impact on the Company in adopting
SFAS 144.
The Company performs an annual impairment test by performing a
discounted cash flow analysis.
The preparation of consolidated financial statements in
conformity with accounting principles generally accepted in the
United States requires management to make estimates and
assumptions that affect the amounts reported in the financial
statements and accompanying notes. Actual results could differ
from those estimates.
|
|
|
Land, Buildings and Equipment and Field Equipment |
Land, buildings and equipment and field equipment are carried at
cost. Depreciation and amortization are provided on a
straight-line basis over their estimated useful lives. The
estimated useful lives are: buildings 40 years,
equipment and field equipment 3 to 15 years.
The Company has determined that an allowance for doubtful
accounts was not necessary as all receivables were expected to
be realized in full.
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, 2005 and 2004, the Australian dollar was
equivalent to U.S. $.76 and $.70, respectively. The annual
average exchange rates used to translate MPALs operations
in Australia for the fiscal years 2005, 2004 and 2003 were $.75,
$.72 and $.59, respectively.
33
At June 30, 2005 and 2004, balances in accrued liabilities
which exceeded 5% of the total balance include $1,046,438 and
$1,221,446 of employment benefits, respectively and $226,578 and
$192,982 of payroll withholding taxes, 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.
The carrying value for cash and cash equivalents, accounts
receivable, marketable securities and accounts payable
approximates fair value based on anticipated cash flows and
current market conditions.
|
|
|
Cash and Cash Equivalents |
The Company considers all highly liquid short term investments
with maturities of three months or less at the date of
acquisition to be cash equivalents. Cash and cash equivalents
are carried at cost which approximates market value. The
components of cash and cash equivalents are as follows:
|
|
|
|
|
|
|
|
|
|
|
June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Cash
|
|
$ |
309,283 |
|
|
$ |
1,648,074 |
|
U.S. government obligations
|
|
|
|
|
|
|
398,852 |
|
Australian money market accounts and short-term commercial paper
|
|
|
21,424,092 |
|
|
|
18,359,694 |
|
|
|
|
|
|
|
|
|
|
$ |
21,733,375 |
|
|
$ |
20,406,620 |
|
|
|
|
|
|
|
|
At June 30, 2005 and 2004, MPC had the following marketable
securities which are expected to be held until maturity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2004 |
|
Par Value | |
|
Maturity Date | |
|
Amortized Cost | |
|
Fair Value | |
|
|
| |
|
| |
|
| |
|
| |
Short-term securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. government agency note
|
|
$ |
800,000 |
|
|
|
Jul. 7, 2004 |
|
|
$ |
796,896 |
|
|
$ |
799,840 |
|
U.S. government agency note
|
|
|
300,000 |
|
|
|
Aug. 24, 2004 |
|
|
|
298,785 |
|
|
|
299,430 |
|
U.S. government agency note
|
|
|
500,000 |
|
|
|
Sep. 15, 2004 |
|
|
|
497,813 |
|
|
|
498,600 |
|
U.S. government agency note
|
|
|
400,000 |
|
|
|
Oct. 7, 2004 |
|
|
|
398,104 |
|
|
|
398,360 |
|
State of Connecticut bond
|
|
|
200,000 |
|
|
|
Nov. 15, 2004 |
|
|
|
200,514 |
|
|
|
200,582 |
|
U.S. government agency note
|
|
|
100,000 |
|
|
|
Nov. 23, 2004 |
|
|
|
99,378 |
|
|
|
99,360 |
|
Lewiston, Maine Pension bond
|
|
|
290,000 |
|
|
|
Dec. 15, 2004 |
|
|
|
292,806 |
|
|
|
293,213 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total short-term
|
|
$ |
2,590,000 |
|
|
|
|
|
|
$ |
2,584,296 |
|
|
$ |
2,589,385 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State of Connecticut bond
|
|
$ |
200,000 |
|
|
|
Nov. 15, 2005 |
|
|
$ |
202,138 |
|
|
$ |
201,378 |
|
Lewiston, Maine Pension bond
|
|
|
390,000 |
|
|
|
Dec. 15, 2005 |
|
|
|
390,000 |
|
|
|
401,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term
|
|
$ |
590,000 |
|
|
|
|
|
|
$ |
592,138 |
|
|
$ |
602,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share are based upon the weighted average
number of common and common equivalent shares outstanding during
the period. The only reconciling item in the calculation of
diluted EPS is the dilutive effect of stock options which were
computed using the treasury stock method. In 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 were issued that had a strike price below the year end
stock price and resulted in 37,594 incremental diluted shares.
The exercise price of outstanding stock options exceeded the
average market price of the common stock during 2003. The
Companys basic and diluted calculations of EPS are the
same in 2005 and 2003 because the exercise of outstanding
options of 30,000 and 921,000 options is not assumed in
calculating diluted EPS, as the result would be anti-dilutive.
The Company has elected to follow Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to
Employees (APB No. 25) and related interpretations in
accounting for its stock options. Under APB No. 25, because
the exercise price of the Companys stock options equals
the market price of the underlying stock on the date of grant,
no compensation expense is recognized. See Note 4 Capital
and Stock Options for the pro forma impact of stock options on
net income and earnings per share.
For the purpose of pro forma disclosures required by
SFAS 123, Accounting for Stock Based
Compensation, as amended by SFAS 148 Accounting
for Stock-Based Compensation Transition and
Disclosure, the estimated fair value of the stock options
is expensed over the vesting period. See Note 4, Capital
and Stock Options for the pro forma impact of stock options on
net income and earnings per share.
|
|
|
Accumulated Other Comprehensive Loss |
Accumulated other comprehensive loss at June 30, 2005 and
2004 was as follows:
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Foreign currency translation adjustments
|
|
$ |
(2,322,633 |
) |
|
$ |
(4,491,377 |
) |
|
|
|
|
|
|
|
Government sales taxes related to MPALs oil and gas
production revenues are collected by MPAL and remitted to the
Australian government. Such amounts are excluded from revenue
and expenses.
35
Certain reclassifications of prior period data included in the
accompanying consolidated financial statements have been made to
conform with the current period presentation. Reclassifications
associated with the 2004 consolidated statement of cash flows
resulted in a decrease in net cash provided by operating
activities and a corresponding decrease in net cash used in
investing activities of $785,386 related to decreases in
exploration and dry hole costs, accounts receivable, and
accounts payable and accrued liabilities of $327,300, $96,277,
and $361,809, respectively. Reclassifications associated with
the 2003 consolidated statement of cash flows resulted in a
decrease in net cash provided by operating activities and a
corresponding decrease in net cash used in investing activities
of $1,965,013 related to changes in exploration and dry hole
costs, accounts receivable, and accounts payable and accrued
liabilities of $958,683, $(420,062) and $1,426,392, respectively.
|
|
2. |
Oil and Gas Properties |
MPC had the following amounts recorded in oil and gas properties
at June 30, 2005 and 2004.
|
|
|
|
|
|
|
|
|
Location |
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Mereenie and Palm Valley (Australia)
|
|
$ |
77,376,081 |
|
|
$ |
66,945,763 |
|
Nockatunga (Australia)
|
|
|
2,487,986 |
|
|
|
2,258,338 |
|
Aldinga (Australia)
|
|
|
779,871 |
|
|
|
604,747 |
|
Kotaneelee (Canada)
|
|
|
108,777 |
|
|
|
148,765 |
|
Other
|
|
|
13,196 |
|
|
|
12,521 |
|
|
|
|
|
|
|
|
|
|
$ |
80,765,911 |
|
|
$ |
69,970,134 |
|
|
|
|
|
|
|
|
Accumulated Depletion, Depreciation and Amortization
|
|
|
|
|
|
|
|
|
Location |
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Mereenie and Palm Valley (Australia)
|
|
$ |
56,083,919 |
|
|
$ |
45,644,688 |
|
Nockatunga (Australia)
|
|
|
464,523 |
|
|
|
218,594 |
|
Aldinga (Australia)
|
|
|
728,506 |
|
|
|
428,863 |
|
Kotaneelee (Canada)
|
|
|
53,492 |
|
|
|
30,059 |
|
|
|
|
|
|
|
|
|
|
$ |
57,330,440 |
|
|
$ |
46,322,204 |
|
|
|
|
|
|
|
|
|
|
|
Depletion, Depreciation and Amortization |
During the years ended June 30, 2005, 2004 and 2003, the
depletion rate by field was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Mereenie and Palm Valley (Australia)
|
|
|
25.6 |
|
|
|
20.9 |
|
|
|
17.6 |
|
Nockatunga (Australia)
|
|
|
12.1 |
|
|
|
9.5 |
|
|
|
|
|
Aldinga (Australia)
|
|
|
78.1 |
|
|
|
70.2 |
|
|
|
2.6 |
|
Kotaneelee (Canada)
|
|
|
8.3 |
|
|
|
25.0 |
|
|
|
25.0 |
|
During July 2003, 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 PLs 33, 50 and 51 together with exploration acreage in
ATP 267P at a purchase price of approximately
$1.4 million.
36
|
|
|
Exploratory and Dry Hole Costs |
The 2005, 2004 and 2003 costs relate primarily to the geological
and geophysical work and seismic acquisition on MPALs
exploration permits. The costs (in thousands) for MPAL by
location were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
U.S./ Belize
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(38 |
) |
Australia/ New Zealand
|
|
|
4,157 |
|
|
|
3,225 |
|
|
|
2,958 |
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
4,157 |
|
|
$ |
3,225 |
|
|
$ |
2,920 |
|
|
|
|
|
|
|
|
|
|
|
See Note 11 commitments for a summary of MPALs
required and contingent commitments for exploration expenditures
for the five year period beginning July 1, 2005.
|
|
3. |
Asset Retirement Obligations |
Upon the adoption of SFAS 143 on July 1, 2002, the
Company recorded a discounted liability (asset retirement
obligation) of $3,794,000, increased oil and gas properties by
$526,000 and recognized a one-time, cumulative effect after-tax
charge of $738,000 (net of $316,000 deferred tax benefit and
minority interest of $680,000) which has been reflected as a
cumulative effect of accounting change.
The adoption of SFAS 143 decreased net income before
cumulative effect of accounting change by approximately $76,000
for the fiscal year ended June 30, 2003.
A reconciliation of the Companys asset retirement
obligations for the years ended June 30, 2005 and 2004, is
as follows:
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Balance at beginning of year
|
|
$ |
4,852,000 |
|
|
$ |
3,858,000 |
|
Liabilities incurred
|
|
|
85,000 |
|
|
|
489,000 |
|
Liabilities settled
|
|
|
|
|
|
|
|
|
Accretion expense
|
|
|
407,000 |
|
|
|
357,000 |
|
Revisions to estimate
|
|
|
(40,000 |
) |
|
|
|
|
Exchange effect
|
|
|
425,000 |
|
|
|
148,000 |
|
|
|
|
|
|
|
|
Balance at end of year
|
|
$ |
5,729,000 |
|
|
$ |
4,852,000 |
|
|
|
|
|
|
|
|
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. During fiscal year 2003, two wells were plugged and
abandoned in the Mereenie field at a cost of approximately
$86,000. The $27,000 difference between the amount of the asset
retirement obligation of $59,000 and the abandonment costs of
$86,000 is included in production costs.
|
|
4. |
Capital and Stock Options |
MPCs 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, 2003, 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
2005 or 2004. During 2003, 180,000 shares were repurchased
at a cost of $179,900.
On July 10, 2003, a subsidiary of Origin Energy, Sagasco
Amadeus Pty. Limited, agreed to exchange 1.2 million
shares of MPAL for 1.3 million shares of the Companys
common stock. The exchange was
37
completed on September 2, 2003. The fair value of the
1,300,000 shares on July 10, 2003 was $1,508,000,
based on the closing price of the Companys common stock on
the Nasdaq SmallCap market on that date.
The Companys Stock Option Plan provides for options to be
granted at a price of not less than fair value on the date of
grant and for a term of not greater than ten years. As of
June 30, 2005, 795,000 options were available for future
issuance under the plan.
The following is a summary of option transactions for the three
years ended June 30, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration | |
|
Number of | |
|
|
Options Outstanding |
|
Dates | |
|
Shares | |
|
Exercise Prices ($) | |
|
|
| |
|
| |
|
| |
June 30, 2002
|
|
|
|
|
|
|
871,000 |
|
|
|
1.28-1.57 |
|
|
Granted
|
|
|
Jan. 2008 |
|
|
|
50,000 |
|
|
|
.85 |
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
Expired
|
|
|
|
|
|
|
(595,000 |
) |
|
|
1.28 |
|
|
|
|
|
|
|
|
|
|
|
June 30, 2005
|
|
|
|
|
|
|
30,000 |
|
|
|
1.45 |
|
|
|
|
|
|
|
|
|
|
|
Summary of Options Outstanding at June 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration | |
|
|
|
|
|
Exercise | |
|
|
Dates | |
|
Total | |
|
Vested | |
|
Prices ($) | |
|
|
| |
|
| |
|
| |
|
| |
Granted 2004
|
|
|
Jul. 2014 |
|
|
|
30,000 |
|
|
|
10,000 |
|
|
|
1.45 |
|
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. No charges have been made
against income in accounting for options during the three year
period ended June 30, 2005. Vested options are exercisable
during non black out periods.
The pro forma information regarding net income and earnings per
share as required by Statement 123, as amended, has been
determined as if the Company had accounted for its stock options
under the fair value method of that Statement. The fair value
for these options was estimated at the date of grant using a
Black-Scholes option pricing model. The weighted average grant
date fair value of the 30,000 options granted in 2005 was
$29,700.
Option valuation models require the input of highly subjective
assumptions including the expected stock price volatility. The
assumptions used in the 2003 valuation model were: risk free
interest rate 3.16%, expected life
5 years, expected volatility .439, expected
dividend 0. The assumptions used in the fiscal 2005
valuation model were: risk free interest rate 4.95%,
expected life 10 years, expected
volatility .518, expected dividend 0.
38
The Companys pro forma information follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per Share | |
|
|
|
|
| |
|
|
Net Income | |
|
Basic | |
|
Diluted | |
|
|
| |
|
| |
|
| |
Net income as reported June 30, 2003
|
|
$ |
152,000 |
|
|
$ |
.01 |
|
|
$ |
.01 |
|
Stock option expense (determined under fair value method)
|
|
|
(22,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income June 30, 2003
|
|
$ |
130,000 |
|
|
$ |
.01 |
|
|
$ |
.01 |
|
|
|
|
|
|
|
|
|
|
|
Net income as reported June 30, 2004
|
|
$ |
350,000 |
|
|
$ |
.01 |
|
|
$ |
.01 |
|
Stock option expense (determined under fair value method)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of income before income taxes, minority interests and
cumulative effect of accounting change by geographic area (in
thousands) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
United States
|
|
$ |
(1,004 |
) |
|
$ |
(548 |
) |
|
$ |
(329 |
) |
Foreign
|
|
|
2,118 |
|
|
|
666 |
|
|
|
1,678 |
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
1,114 |
|
|
$ |
118 |
|
|
$ |
1,349 |
|
|
|
|
|
|
|
|
|
|
|
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, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Tax provision computed at statutory rate (30%)
|
|
$ |
(334 |
) |
|
$ |
(35 |
) |
|
$ |
(405 |
) |
MPCs parent company (income) losses
|
|
|
(301 |
) |
|
|
165 |
|
|
|
(98 |
) |
Non-taxable revenue from Australian government sources
|
|
|
301 |
|
|
|
267 |
|
|
|
194 |
|
MPAL non-deductible foreign losses (New Zealand)
|
|
|
(513 |
) |
|
|
(337 |
) |
|
|
(197 |
) |
MPAL write off of foreign advances (New Zealand)
|
|
|
1,000 |
|
|
|
|
|
|
|
|
|
Reversal of prior year reserve on MPAL Deferred Tax Assets(a)
|
|
|
|
|
|
|
1,266 |
|
|
|
1,399 |
|
MPC income tax provision(b)
|
|
|
(71 |
) |
|
|
(492 |
) |
|
|
(130 |
) |
Other
|
|
|
|
|
|
|
(56 |
) |
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
Consolidated income tax (provision) benefit
|
|
$ |
82 |
|
|
$ |
778 |
|
|
$ |
774 |
|
|
|
|
|
|
|
|
|
|
|
Current income tax provision
|
|
$ |
(1,375 |
) |
|
$ |
(667 |
) |
|
$ |
(130 |
) |
Deferred income tax benefit
|
|
|
1,457 |
|
|
|
1,445 |
|
|
|
904 |
|
|
|
|
|
|
|
|
|
|
|
Consolidated income tax (provision) benefit
|
|
$ |
82 |
|
|
$ |
778 |
|
|
$ |
774 |
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
7 |
% |
|
|
|
|
|
|
(57 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
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. |
39
|
|
|
(b) |
|
MPCs income tax provisions represent the 25% Canadian
withholding tax on its Kotaneelee gas field carried interest net
proceeds. |
Significant components of the Companys deferred tax assets
and liabilities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
June 30, | |
|
June 30, | |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Deferred tax liabilities
|
|
|
|
|
|
|
|
|
|
Acquisition and development costs
|
|
$ |
(981,000 |
) |
|
$ |
(2,068,000 |
) |
Deferred tax assets
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
1,996,000 |
|
|
|
1,665,000 |
|
|
Net operating losses
|
|
|
2,749,000 |
|
|
|
2,633,000 |
|
|
Foreign tax credits
|
|
|
223,000 |
|
|
|
223,000 |
|
|
Interest
|
|
|
214,000 |
|
|
|
214,000 |
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
5,182,000 |
|
|
|
4,735,000 |
|
Valuation allowance
|
|
|
(3,186,000 |
) |
|
|
(3,070,000 |
) |
|
|
|
|
|
|
|
Net deferred tax (liabilities)/asset
|
|
$ |
1,015,000 |
|
|
$ |
(403,000 |
) |
|
|
|
|
|
|
|
The net deferred tax asset (liability) at June 30,
2005 and 2004, respectively, consist of deferred tax liabilities
of $981,000 and $2,068,000, primarily relating to the deduction
of acquisition and development costs which are capitalized for
financial statement purposes, offset by deferred tax assets of
$1,996,000 and $1,665,000, primarily relating to asset
retirement obligations which will result in tax deductions when
paid.
At June 30, 2005, the Company had approximately $12,250,000
and $2,237,000 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: $265,000 in 2007, $2,055,000 in 2008, $408,000 in 2020,
$52,000 in 2021, $110,000 in 2023, and $254,000 in 2025.
MPALs 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
$223,000 of foreign tax credit carryovers, which are scheduled
to expire by the year 2006. MPCs state loss carry forwards
expire periodically between the years 2006 and 2024. For
financial reporting purposes, a valuation allowance has been
recognized to offset the deferred tax assets related to those
carry forwards and other deductible temporary differences.
|
|
6. |
Related Party and Other Transactions |
G&OD INC, a firm that provided accounting and
administrative services, office facilities and support staff to
MPC, was paid $65,700, $24,723, and $20,830 in fees for fiscal
years 2005, 2004 and 2003 respectively. In addition, MPC
purchased $12,000 of office equipment from G&OD INC.
during 2005. James R. Joyce, the former President and Chief
Financial Officer of MPC, is the owner of G&OD 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 $144,596, $120,563, and $69,459 for fiscal years
2005, 2004 and 2003, respectively.
At June 30, 2005, future minimum rental payments applicable
to MPCs and MPALs non-cancelable operating
(office) lease were $183,000, $191,000, $197,000, $181,000
and $0 for the years 2006, 2007, 2008, 2009 and 2010,
respectively.
40
Operating lease rental expenses for each of the years ended
June 30, 2005, 2004 and 2003 were $214,661, $311,497 and
$239,026 respectively.
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.
The following table sets forth the actuarial present value of
benefit obligations and funded status for the MPAL pension plan
at June 30, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Change in Benefit Obligation
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$ |
2,145,394 |
|
|
$ |
1,980,930 |
|
|
Service cost
|
|
|
|
|
|
|
148,075 |
|
|
Interest cost
|
|
|
|
|
|
|
94,212 |
|
|
Actuarial gains and losses
|
|
|
|
|
|
|
(46,378 |
) |
|
Benefits paid
|
|
|
(2,145,394 |
) |
|
|
(447,277 |
) |
|
Settlement and curtailment
|
|
|
|
|
|
|
414,694 |
|
|
Expenses paid
|
|
|
|
|
|
|
(71,763 |
) |
|
Foreign currency effect
|
|
|
|
|
|
|
72,901 |
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
$ |
0 |
|
|
$ |
2,145,394 |
|
|
|
|
|
|
|
|
Change in Plan Assets
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
1,858,681 |
|
|
$ |
1,911,692 |
|
|
Actual return on plan assets
|
|
|
286,713 |
|
|
|
226,341 |
|
|
Contributions by employer
|
|
|
|
|
|
|
164,368 |
|
|
Benefits paid
|
|
|
(2,145,394 |
) |
|
|
(447,277 |
) |
|
Foreign currency effect
|
|
|
|
|
|
|
75,320 |
|
|
Other (expenses)
|
|
|
|
|
|
|
(71,763 |
) |
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
0 |
|
|
$ |
1,858,681 |
|
|
|
|
|
|
|
|
Reconciliation of Funded Status
|
|
|
|
|
|
|
|
|
Funded Status
|
|
|
0 |
|
|
$ |
(286,713 |
) |
|
Unamortized transition asset
|
|
|
|
|
|
|
|
|
|
Unamortized loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Accrued) Prepaid benefit costs
|
|
|
0 |
|
|
$ |
(286,713 |
) |
|
|
|
|
|
|
|
41
The net pension expense for the MPAL pension plan for 2004 and
2003 was as follows:
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
Settlement and curtailment
|
|
$ |
1,237,425 |
|
|
$ |
|
|
Service cost
|
|
|
148,075 |
|
|
|
144,216 |
|
Interest cost
|
|
|
94,212 |
|
|
|
96,803 |
|
Expected return on plan assets
|
|
|
(94,104 |
) |
|
|
(97,205 |
) |
Net amortization and deferred items
|
|
|
26,835 |
|
|
|
15,299 |
|
|
|
|
|
|
|
|
Net pension cost
|
|
$ |
1,412,443 |
|
|
$ |
159,113 |
|
|
|
|
|
|
|
|
Plan contributions by MPAL
|
|
$ |
228,958 |
|
|
$ |
156,247 |
|
|
|
|
|
|
|
|
Significant assumptions used in determining pension cost and the
related obligations were as follows:
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
Assumed discount rate
|
|
|
5.0 |
% |
|
|
5.5 |
% |
Rate of increase in future compensation levels
|
|
|
3.5 |
% |
|
|
3.5 |
% |
Expected long term rate of return on plan assets
|
|
|
5.0 |
% |
|
|
5.0 |
% |
Australian exchange rate
|
|
$ |
.70 |
|
|
$ |
.67 |
|
At June 30, 2004, Plan assets were held 98% in equity
mutual funds and 2% in cash. As a result of the Plans
termination, the Plans assets were distributed during 2005
with no additional pension plan expenditures required.
The Company has two reportable segments, MPC and its majority
owned subsidiary, MPAL. Although each company is in the same
business, MPAL is also a publicly held company with its shares
traded on the Australian Stock Exchange. MPAL issues separate
audited consolidated financial statements and operates
independently of MPC.
Segment information (in thousands) for the Companys two
operating segments is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
1,256 |
|
|
$ |
2,469 |
|
|
$ |
1,228 |
|
|
MPAL
|
|
|
21,590 |
|
|
|
17,866 |
|
|
|
14,194 |
|
|
Elimination of intersegment dividend
|
|
|
(975 |
) |
|
|
(911 |
) |
|
|
(686 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total consolidated revenues
|
|
$ |
21,871 |
|
|
$ |
19,424 |
|
|
$ |
14,736 |
|
|
|
|
|
|
|
|
|
|
|
Interest income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
89 |
|
|
$ |
160 |
|
|
$ |
85 |
|
|
MPAL
|
|
|
1,053 |
|
|
|
939 |
|
|
|
775 |
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated
|
|
$ |
1,142 |
|
|
$ |
1,099 |
|
|
$ |
860 |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before cumulative effect of accounting change:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
(101 |
) |
|
$ |
969 |
|
|
$ |
229 |
|
|
Equity in earnings of MPAL, net of related costs(1)
|
|
|
1,163 |
|
|
|
292 |
|
|
|
1,347 |
|
|
Elimination of intersegment dividend
|
|
|
(975 |
) |
|
|
(911 |
) |
|
|
(686 |
) |
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income before cumulative effect of accounting
change:
|
|
$ |
87 |
|
|
$ |
350 |
|
|
$ |
890 |
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
(101 |
) |
|
$ |
969 |
|
|
$ |
229 |
|
|
Equity in earnings of MPAL, net of related costs(1)
|
|
|
1,163 |
|
|
|
292 |
|
|
|
609 |
|
|
Elimination of intersegment dividend
|
|
|
(975 |
) |
|
|
(911 |
) |
|
|
(686 |
) |
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$ |
87 |
|
|
$ |
350 |
|
|
$ |
152 |
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
25,523 |
|
|
$ |
25,339 |
|
|
|
|
|
|
MPAL
|
|
|
50,659 |
|
|
|
47,884 |
|
|
|
|
|
|
Equity elimination
|
|
|
(19,758 |
) |
|
|
(20,329 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated assets
|
|
$ |
56,424 |
|
|
$ |
52,894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other significant items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
27 |
|
|
$ |
30 |
|
|
$ |
|
|
|
|
MPAL
|
|
|
6,967 |
|
|
|
6,312 |
|
|
|
3,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated
|
|
$ |
6,994 |
|
|
$ |
6,342 |
|
|
$ |
3,719 |
|
|
|
|
|
|
|
|
|
|
|
Exploratory and dry hole costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
MPAL
|
|
|
4,157 |
|
|
|
3,225 |
|
|
|
2,920 |
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated
|
|
$ |
4,157 |
|
|
$ |
3,225 |
|
|
$ |
2,920 |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MPC
|
|
$ |
71 |
|
|
$ |
492 |
|
|
$ |
130 |
|
|
MPAL
|
|
|
(153 |
) |
|
|
(1,270 |
) |
|
|
(904 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total consolidated
|
|
$ |
(82 |
) |
|
$ |
(778 |
) |
|
$ |
(774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Equity in earnings of MPAL for 2005 and 2004 of $1,363,000 and
$670,000, respectively is reported net of $195,000 and $378,000
for 2005 and 2004, 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 MPCs
investment in MPAL. |
|
|
10. |
Geographic Information |
As of each of the stated dates, the Companys revenue,
operating income, net income or loss and identifiable assets (in
thousands) were geographically attributable as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
$ |
21,590 |
|
|
$ |
17,866 |
|
|
$ |
14,194 |
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
281 |
|
|
|
1,558 |
|
|
|
542 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
21,871 |
|
|
$ |
19,424 |
|
|
$ |
14,736 |
|
|
|
|
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Operating income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
$ |
2,912 |
|
|
$ |
(103 |
) |
|
$ |
1,732 |
|
|
New Zealand
|
|
|
(1,441 |
) |
|
|
(909 |
) |
|
|
(628 |
) |
|
United States-Canada
|
|
|
258 |
|
|
|
1,525 |
|
|
|
569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,729 |
|
|
|
513 |
|
|
|
1,673 |
|
|
Corporate overhead and interest, net of other income (expense)
|
|
|
(615 |
) |
|
|
(395 |
) |
|
|
(324 |
) |
|
|
|
|
|
|
|
|
|
|
|
Consolidated operating income before income taxes, minority
interests and cumulative effect of accounting change
|
|
$ |
1,114 |
|
|
$ |
118 |
|
|
$ |
1,349 |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
$ |
1,831 |
|
|
$ |
718 |
|
|
$ |
835 |
|
|
New Zealand
|
|
|
(668 |
) |
|
|
(425 |
) |
|
|
(246 |
) |
|
United States
|
|
|
(1,076 |
) |
|
|
57 |
|
|
|
(437 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
87 |
|
|
$ |
350 |
|
|
$ |
152 |
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
$ |
52,264 |
|
|
$ |
48,652 |
|
|
|
|
|
|
Corporate assets
|
|
|
4,160 |
|
|
|
4,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
56,424 |
|
|
$ |
52,894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Substantially all of MPALs gas sales were to the Power and
Water Corporation (PAWC) of the Northern Territory of
Australia (NTA). All of MPALs crude oil production was
sold to the Mobil Port Stanvac Refinery near Adelaide during the
three years ended June 30, 2005.
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. The Company has firm commitments from
purchase obligations of $3,380,000. See Part II Contractual
Obligations.
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 PAWCs
Darwin generating station and at a number of other generating
stations in the Northern Territory. The gas is being delivered
via the 922-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
44
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, 2005, MPALs commitment to supply gas
under the above agreements was as follows:
|
|
|
|
|
Period |
|
Bcf | |
|
|
| |
Less than one year
|
|
|
6.21 |
|
Between 1-5 years
|
|
|
23.06 |
|
Greater than 5 years
|
|
|
.80 |
|
|
|
|
|
Total
|
|
|
30.07 |
|
|
|
|
|
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.
During September 2003, the litigants in the Kotaneelee
litigation entered into a settlement agreement. In October 2003
the Company received approximately $851,000, after Canadian
withholding taxes and reimbursement of certain past legal costs.
The plaintiffs terminated all litigation against the defendants
related to the field, including the claim that the defendants
failed to fully develop the field. Since each party agreed to
bear its own legal costs, there were no taxable costs assessed
against any of the parties.
The components of the settlement payment, which was recorded in
September 2003 are as follows:
|
|
|
|
|
Gas sales
|
|
$ |
1,135,000 |
|
Interest income
|
|
|
102,000 |
|
Canadian withholding taxes and legal expenses
|
|
|
(386,000 |
) |
|
|
|
|
Total
|
|
$ |
851,000 |
|
|
|
|
|
The Kotaneelee settlement agreement provides that the carried
interest partners will share in the abandonment of the
Kotaneelee field wells and facilities.
45
|
|
12. |
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, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
QTR 1 | |
|
QTR 2 | |
|
QTR 3 | |
|
QTR 4 | |
|
|
| |
|
| |
|
| |
|
| |
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
5,397 |
|
|
$ |
4,598 |
|
|
$ |
4,839 |
|
|
$ |
4,590 |
|
Costs and expenses
|
|
|
(3,900 |
) |
|
|
(5,634 |
) |
|
|
(4,599 |
) |
|
|
(6,273 |
) |
Interest income
|
|
|
335 |
|
|
|
243 |
|
|
|
271 |
|
|
|
251 |
|
Income tax (provision) benefit(b)
|
|
|
(411 |
) |
|
|
61 |
|
|
|
(115 |
) |
|
|
1,243 |
|
Minority interests
|
|
|
(354 |
) |
|
|
226 |
|
|
|
(254 |
) |
|
|
(164 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
1,067 |
|
|
|
(506 |
) |
|
|
142 |
|
|
|
(353 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share (basic & diluted)
|
|
|
.04 |
|
|
|
(.02 |
) |
|
|
.01 |
|
|
|
(.01 |
) |
Average number of shares outstanding
|
|
|
25,092 |
|
|
|
25,727 |
|
|
|
25,894 |
|
|
|
25,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
During the fourth quarter of 2005, MPALs 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. |
|
|
|
(b) |
|
During the fourth quarter of 2004, MPAL determined that prior
deferred tax benefits that had been reserved of $1,266 were
recoverable, resulting in lower income tax expense for the
fourth quarter of 2004. |
46
|
|
13. |
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.
|
|
|
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, 2002
|
|
|
40.780 |
|
|
|
.534 |
|
|
|
520 |
|
Extensions and discoveries
|
|
|
|
|
|
|
|
|
|
|
35 |
|
Revision of previous estimates
|
|
|
2.497 |
|
|
|
|
|
|
|
125 |
|
Production
|
|
|
(5.893 |
) |
|
|
(.107 |
) |
|
|
(126 |
) |
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2002
|
|
|
29.102 |
|
|
|
.534 |
|
|
|
520 |
|
|
|
|
|
|
|
|
|
|
|
June 30, 2003
|
|
|
28.855 |
|
|
|
.427 |
|
|
|
554 |
|
|
|
|
|
|
|
|
|
|
|
June 30, 2004
|
|
|
22.346 |
|
|
|
.170 |
|
|
|
616 |
|
|
|
|
|
|
|
|
|
|
|
June 30, 2005
|
|
|
25,284 |
|
|
|
.121 |
|
|
|
487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
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 royalities. Approximately
44.9% of reserves are attributable to minority interests at
June 30, 2005 (44.9% for 2004 and 47.6% for 2003). |
|
|
|
Costs of Oil and Gas Activities (In thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia/New Zealand | |
|
|
| |
|
|
Exploration | |
|
Development | |
|
Acquisition | |
Fiscal Year |
|
Costs | |
|
Costs | |
|
Costs | |
|
|
| |
|
| |
|
| |
2005
|
|
|
4,028 |
|
|
|
9,292 |
|
|
|
|
|
2004
|
|
|
3,741 |
|
|
|
3,926 |
|
|
|
2,086 |
|
2003
|
|
|
4,484 |
|
|
|
2,753 |
|
|
|
3 |
|
47
|
|
|
Capitalized Costs Subject to Depletion, Depreciation and
Amortization (DD&A) (In thousands): |
|
|
|
|
|
|
|
|
|
|
|
June 30, | |
|
|
| |
Australia/New Zealand |
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Costs subject to DD&A
|
|
$ |
80,766 |
|
|
$ |
69,970 |
|
Costs not subject to DD&A
|
|
|
|
|
|
|
|
|
Less accumulated DD&A
|
|
|
(57,330 |
) |
|
|
(46,322 |
) |
|
|
|
|
|
|
|
Net capitalized costs
|
|
$ |
23,436 |
|
|
$ |
23,648 |
|
|
|
|
|
|
|
|
|
|
|
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, 2005. At
June 30, 2005, approximately 44.9% (44.9% for 2004 and
47.6.% for 2003) of the reserves and the respective discounted
future net cash flows are attributable to minority interests.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Future cash inflows
|
|
$ |
81,688 |
|
|
$ |
82,449 |
|
|
$ |
78,192 |
|
Future production costs
|
|
|
(18,443 |
) |
|
|
(19,361 |
) |
|
|
(20,844 |
) |
Future development costs
|
|
|
(13,434 |
) |
|
|
(16,599 |
) |
|
|
(15,681 |
) |
Future income tax expense
|
|
|
(10,342 |
) |
|
|
(9,369 |
) |
|
|
(5,292 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
39,469 |
|
|
|
37,120 |
|
|
|
36,375 |
|
10% annual discount for estimating timing of cash flows
|
|
|
(8,157 |
) |
|
|
(7,639 |
) |
|
|
(10,675 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measures of discounted future net cash flows
|
|
$ |
31,312 |
|
|
$ |
29,481 |
|
|
$ |
25,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Future cash inflows
|
|
$ |
606 |
|
|
$ |
754 |
|
|
$ |
1,460 |
|
Future production costs
|
|
|
(60 |
) |
|
|
(125 |
) |
|
|
(213 |
) |
Future development costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Future income tax expense
|
|
|
(136 |
) |
|
|
(157 |
) |
|
|
(312 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
410 |
|
|
|
472 |
|
|
|
935 |
|
10% annual discount for estimating timing of cash flows
|
|
|
(89 |
) |
|
|
(72 |
) |
|
|
(149 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measures of discounted future net cash flows
|
|
$ |
321 |
|
|
$ |
400 |
|
|
$ |
786 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Future cash inflows
|
|
$ |
82,294 |
|
|
$ |
83,203 |
|
|
$ |
79,652 |
|
Future production costs
|
|
|
(18,503 |
) |
|
|
(19,486 |
) |
|
|
(21,057 |
) |
Future development costs
|
|
|
(13,434 |
) |
|
|
(16,599 |
) |
|
|
(15,681 |
) |
Future income tax expense
|
|
|
(10,478 |
) |
|
|
(9,526 |
) |
|
|
(5,604 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
39,879 |
|
|
|
37,592 |
|
|
|
37,310 |
|
10% annual discount for estimating timing of cash flows
|
|
|
(8,246 |
) |
|
|
(7,711 |
) |
|
|
(10,824 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measures of discounted future net cash flows
|
|
$ |
31,633 |
|
|
$ |
29,881 |
|
|
$ |
26,486 |
|
|
|
|
|
|
|
|
|
|
|
48
The following are the principal sources of changes in the above
standardized measure of discounted future net cash flows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Net change in prices and production costs
|
|
$ |
5,567 |
|
|
$ |
7,597 |
|
|
$ |
(5,020 |
) |
Extensions and discoveries
|
|
|
|
|
|
|
|
|
|
|
360 |
|
Revision of previous quantity estimates
|
|
|
281 |
|
|
|
981 |
|
|
|
1,059 |
|
Changes in estimated future development costs
|
|
|
443 |
|
|
|
(2,156 |
) |
|
|
(4,587 |
) |
Sales and transfers of oil and gas produced
|
|
|
(13,725 |
) |
|
|
(10,314 |
) |
|
|
(8,070 |
) |
Previously estimated development cost incurred during the period
|
|
|
3,827 |
|
|
|
3,110 |
|
|
|
3,110 |
|
Accretion of discount
|
|
|
2,337 |
|
|
|
2,344 |
|
|
|
2,992 |
|
Acquisitions
|
|
|
|
|
|
|
3,213 |
|
|
|
|
|
Net change in income taxes
|
|
|
410 |
|
|
|
(2,345 |
) |
|
|
6,100 |
|
Net change in exchange rate
|
|
|
2,612 |
|
|
|
965 |
|
|
|
4,231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,752 |
|
|
$ |
3,395 |
|
|
$ |
175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional Information Regarding Discounted Future Net
Cash Flows: |
Future net cash flows from net proved gas reserves in Australia
were based on MPALs 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, 2005.
At June 30, 2005, 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, 2005. 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.
Future Australian income tax expense applicable to the future
net cash flows has been reduced by the tax effect of
approximately A.$23,203,000, and A.$22,005,000 and A.$25,658,000
in unrecouped capital expenditures at June 30, 2005, 2004
and 2003, respectively. The tax rate in computing Australian
future income tax expense was 30%.
Future net cash flows from net proved gas reserves in Canada
were based on the Companys 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. $6.14 at June 30, 2005 (Can. $5.90
2004) and estimated future production and development costs at
June 30, 2005.
49
Results of Operations
The following are the Companys results of operations (in
thousands) for the oil and gas producing activities during the
three years ended June 30, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Americas | |
|
Australia/New Zealand | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
7,574 |
|
|
$ |
4,923 |
|
|
$ |
3,329 |
|
|
Gas sales
|
|
|
282 |
|
|
|
1,557 |
|
|
|
535 |
|
|
|
12,196 |
|
|
|
11,312 |
|
|
|
9,647 |
|
|
Other production income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,819 |
|
|
|
1,632 |
|
|
|
1,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
282 |
|
|
|
1,557 |
|
|
|
535 |
|
|
|
21,589 |
|
|
|
17,867 |
|
|
|
14,190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,144 |
|
|
|
5,416 |
|
|
|
4,424 |
|
|
Depletion, exploratory and dry hole costs
|
|
|
23 |
|
|
|
30 |
|
|
|
(38 |
) |
|
|
10,727 |
|
|
|
9,009 |
|
|
|
6,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
23 |
|
|
|
30 |
|
|
|
(38 |
) |
|
|
16,871 |
|
|
|
14,425 |
|
|
|
11,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes and minority interest
|
|
|
259 |
|
|
|
1,527 |
|
|
|
573 |
|
|
|
4,718 |
|
|
|
3,442 |
|
|
|
3,146 |
|
|
Income tax provision*
|
|
|
(65 |
) |
|
|
(382 |
) |
|
|
(134 |
) |
|
|
(1,415 |
) |
|
|
(1,027 |
) |
|
|
(944 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before minority interests
|
|
|
194 |
|
|
|
1,145 |
|
|
|
439 |
|
|
|
3,303 |
|
|
|
2,415 |
|
|
|
2,202 |
|
|
Minority interests**
|
|
|
|
|
|
|
|
|
|
|
(18 |
) |
|
|
(1,737 |
) |
|
|
(1,085 |
) |
|
|
(1,047 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from operations
|
|
$ |
194 |
|
|
$ |
1,145 |
|
|
$ |
421 |
|
|
$ |
1,566 |
|
|
$ |
1,330 |
|
|
$ |
1,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion per unit of production
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
A.$ |
7.40 |
|
|
A.$ |
7.25 |
|
|
A.$ |
5.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
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. |
|
|
** |
Minority interests 44.90% in 2005, 44.9% in 2004 and 47.6% in
2003. |
|
|
Item 9. |
Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure |
Previous Independent Accountants
On August 15, 2003, the Audit Committee of the Board of
Directors of the Company determined to dismiss Ernst &
Young LLP as the Companys independent auditors, effective
upon completion of the annual audit for the fiscal year ended
June 30, 2003. This decision was subject to the condition
that Magellan Petroleum Australia Limited (MPAL), the
Companys majority owned subsidiary, make a similar
determination to dismiss Ernst & Young as its
independent auditors. Ernst & Young had served as the
Companys independent auditors for many years. On
September 4, 2003, the audit committee of the Board of
Directors of MPAL made a similar determination to dismiss
Ernst & Young as its independent accountants, effective
upon the completion of the annual audit for the fiscal year
ended June 30, 2003.
The report of Ernst & Young on the Companys
financial statements for the fiscal year ended June 30,
2003 did not contain an adverse opinion or a disclaimer of
opinion, and was not qualified or modified as to audit scope or
accounting principles.
Ernst & Young LLP was dismissed on September 26,
2003, upon filing of the Companys annual report on
Form 10-K for the fiscal year ended June 30, 2003. The
report of Ernst & Young LLP was dated
September 19, 2003.
In connection with the audit of the Companys financial
statements for the fiscal year ended June 30, 2003 and
through September 19, 2003, there were no disagreements
with Ernst & Young on any matter of accounting
principles or practices, financial statement disclosure, or
auditing scope and procedures which, if
50
not resolved to Ernst & Youngs satisfaction,
would have caused Ernst & Young to make reference to
the matter in their report. In addition, there were no
reportable events as that term is described in
Item 304(a)(1)(v) of Regulation S-K.
New Independent Accountants
Effective October 30, 2003, the Audit Committee of the
Companys Board of Directors retained Deloitte &
Touche LLP as the Companys new independent auditors for
the fiscal year ended June 30, 2004.
During the Companys two most recent fiscal years and the
subsequent interim period(s) prior to engaging
Deloitte & Touche LLP, neither the Company nor anyone
acting on behalf of the Company consulted Deloitte &
Touche LLP regarding (i) either (a) the application of
accounting principles to a specified transaction, either
completed or proposed, or (b) the type of audit opinion
that might be rendered on the Companys financial
statements; or (ii) any matter that was either the subject
of a disagreement (as defined in paragraph 304(a)(1)(iv) of
Regulation S-K and the related instructions to
Item 304 of Regulation S-K) or a reportable event (as
described in paragraph 304(A)(1)(v) of
Regulation S-K). In addition, during the Companys two
most recent fiscal years and the subsequent interim period(s)
prior to engaging Deloitte & Touche LLP, no written
report was provided by Deloitte & Touche LLP to the
Company and no oral advice was provided that Deloitte &
Touche LLP concluded was an important factor considered by the
Company in reaching a decision as to any accounting, auditing,
or financial reporting issue.
|
|
Item 9A. |
Controls and Procedures |
Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the
participation of the Companys management, including Daniel
J. Samela, the Companys President, Chief Executive Officer
and Chief Financial and Accounting Officer, of the effectiveness
of the design and operation of the Companys 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, 2005. Based on this
evaluation, the Companys President concluded that the
Companys disclosure controls and procedures were effective
such that the material information required to be included in
the Companys 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 was made
known to him by others within those entities.
Internal Control Over Financial Reporting.
There have not been any changes in the Companys internal
control over financial reporting (as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act)
during the fourth fiscal quarter of the Companys fiscal
year ended June 30, 2005 that have materially affected, or
are reasonably likely to materially affect, the Companys
internal control over financial reporting.
|
|
Item 9B. |
Other Information |
None
51
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
corporation, 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 62. |
|
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 College, The American International
University, located in London, England from January 1993 until
his retirement in July 2002. Mr. McCann has been a director
of MPAL since 1997. From 1985 to 1992, he was President of
Athens College in Athens, Greece. He is a retired member of the
Bars of Massachusetts and the District of Columbia. Age 68. |
|
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 62. |
|
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 67. |
52
Executive Officers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Length of Service | |
|
Other Positions Held | |
Name |
|
Age | |
|
Office Held | |
|
as an Officer | |
|
with Company | |
|
|
| |
|
| |
|
| |
|
| |
Daniel J. Samela
|
|
|
57 |
|
|
President and Chief Financial Officer |
|
|
Since 2004 |
|
|
|
None |
|
T. Gwynn Davies
|
|
|
58 |
|
|
|
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 Companys executive officers, directors and
persons who beneficially own more than 10% of the Companys
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 5s were
required for those persons, the Company believes that during the
fiscal year ended June 30, 2005, its executive officers,
directors, and greater than 10% beneficial owners complied with
all applicable filing requirements.
Board Independence
The Companys Board of Directors has determined that
Messrs. Basso, Largay, Pettirossi 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 Companys 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 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 Companys 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. Under the Standards, all directors,
officers and employees (Employees) must demonstrate
a commitment to ethical business practices and behavior in all
business
53
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
Companys business. Any waivers of or changes to the
Standards must be approved by the Board and appropriately
disclosed under applicable law and regulation.
The Companys Standards are available on the Companys
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
$100,000 during fiscal year 2005 (collectively, the Named
Executive Officers).
Summary Compensation Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long Term | |
|
|
|
|
Annual | |
|
Compensation | |
|
|
|
|
Compensation | |
|
Awards | |
|
|
|
|
| |
|
| |
|
|
|
|
|
|
Securities | |
|
|
|
|
|
|
Underlying | |
|
All Other | |
|
|
Fiscal | |
|
Salary | |
|
Options/SARs | |
|
Compensation | |
Name and Principal Position |
|
Year | |
|
($) | |
|
(#) | |
|
($) | |
|
|
| |
|
| |
|
| |
|
| |
Daniel J. Samela
|
|
|
2005 |
|
|
|
175,000 |
|
|
|
|
|
|
|
26,250 |
(1) |
|
President, Chief Financial and |
|
|
2004 |
|
|
|
41,667 |
|
|
|
30,000 |
|
|
|
6,250 |
(1) |
|
Accounting Officer |
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
T. Gwynn Davies
|
|
|
2005 |
|
|
|
188,857 |
|
|
|
|
|
|
|
72,301 |
(2) |
|
General Manager MPAL |
|
|
2004 |
|
|
|
177,144 |
|
|
|
|
|
|
|
65,436 |
(2) |
|
(Effective Oct. 30, 2001) |
|
|
2003 |
|
|
|
138,000 |
|
|
|
|
|
|
|
51,000 |
(2) |
|
|
(1) |
Payment to a SEP-IRA pension plan. |
|
(2) |
Payment to pension plan similar to an individual retirement plan. |
Stock Options
The following tables provide information about stock options
granted and exercised during fiscal 2005 and unexercised stock
options held by the Named Executive Officers at the end of
fiscal year 2005.
Options/ SAR Grants in Fiscal Year 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potential Realized | |
|
|
Individual Grants | |
|
Value at Assumed | |
|
|
| |
|
Annual Rates of | |
|
|
|
|
% of Total | |
|
|
|
Stock Price | |
|
|
|
|
Options/SARs | |
|
|
|
Appreciation for | |
|
|
Options/ | |
|
Granted to | |
|
Exercise or | |
|
|
|
Option Terms | |
|
|
SARs Granted | |
|
Employees in | |
|
Base Price | |
|
Expiration | |
|
| |
Name |
|
(#) | |
|
Fiscal Year | |
|
($/Sh) | |
|
Date | |
|
5% ($) | |
|
10% ($) | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Daniel J. Samela
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
0 |
|
|
|
0 |
|
T. Gwynn Davies
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
0 |
|
|
|
0 |
|
54
Aggregated Option/ SAR Exercises in Fiscal 2005 and
June 30, 2005
Option/ SAR Values Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Unexercised | |
|
Value of Unexercised | |
|
|
Shares | |
|
|
|
Options/SARs at | |
|
In-the-Money Options/SARs | |
|
|
Acquired on | |
|
Value | |
|
2005 Year-End (#) | |
|
at 2005 Year-End ($) | |
|
|
Exercise | |
|
Realized | |
|
| |
|
| |
Name |
|
(#) | |
|
($) | |
|
Exercisable | |
|
Unexercisable | |
|
Exercisable | |
|
Unexercisable | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Daniel J. Samela
|
|
|
|
|
|
|
|
|
|
|
10,000 |
|
|
|
20,000 |
|
|
|
24,000 |
|
|
|
48,000 |
|
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 each 30-day
period during Mr. Samelas 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. Samelas benefit. The employment
agreement may be terminated for cause (as defined in the
agreement), on written notice by the Company without cause, by
Mr. Samelas 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 directors fees of $40,000 during
fiscal year 2005. 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 Companys 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 2005, the cost of this plan was approximately
$18,000.
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, 2005 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.
55
|
|
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 Companys Common Stock owned beneficially as
of September 22, 2005 (except as otherwise indicated) by
each director (or nominee director) and each Named Executive
Officer listed in the Summary Compensation Table and by all
directors and executive officers of the Company as a group:
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|
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|
Amount and Nature of | |
|
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|
Beneficial Ownership* | |
|
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| |
|
Percent of | |
Name of Individual or Group |
|
Shares | |
|
Options | |
|
Class | |
|
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| |
|
| |
|
| |
Donald Basso
|
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|
11,000 |
|
|
|
|
|
|
|
** |
|
T. Gwynn Davies
|
|
|
|
|
|
|
|
|
|
|
** |
|
Timothy L. Largay
|
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|
6,000 |
|
|
|
|
|
|
|
** |
|
Walter McCann
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59,368 |
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|
|
|
|
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** |
|
Ronald P. Pettirossi
|
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6,500 |
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|
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** |
|
Daniel J. Samela
|
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|
10,000 |
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** |
|
Directors and Executive Officers as a Group (a total of 6)
|
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109,453 |
|
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|
10,000 |
|
|
|
** |
|
|
|
* |
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%. |
Amount and Nature of Beneficial Ownership
|
|
|
|
|
Name of Individual or Group |
|
Percent of Class | |
|
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| |
Sagasco Amadeus Pty. Limited 1,300,000
|
|
|
5.05%* |
|
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|
* |
As reported in Schedule 13G filed with the SEC on
July 22, 2003. On July 10, 2003, a subsidiary of
Origin Energy Limited Sagasco Amadeus Pty. Limited, agreed to
exchange 1,200,000 shares of MPAL for
1,300,000 shares of the companys common stock, which
is 5.05% of the Companys outstanding shares. The exchange
was completed on September 2, 2003. The Company believes
that as of April 21, 2004, Origin Energy has resold all
shares of the Company held by it. |
Equity Compensation Plan Information
The following table provides information about the
Companys common stock that may be issued upon the exercise
of options and rights under the Companys existing equity
compensation plan as of June 30, 2005.
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|
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|
|
|
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|
|
Number of Securities | |
|
|
Number of Securities | |
|
|
|
Remaining Available for | |
|
|
to be Issued Upon | |
|
Weighted Average | |
|
Issuance Under Equity | |
|
|
Exercise of Outstanding | |
|
Exercise Price of | |
|
Compensation Plans | |
|
|
Options, Warrants | |
|
Outstanding Options, | |
|
(Excluding Securities | |
|
|
and Rights | |
|
Warrants and Rights | |
|
Reflected in Column (a)) | |
Plan Category |
|
(a) (#) | |
|
(b) ($) | |
|
(c) (#) | |
|
|
| |
|
| |
|
| |
Equity compensation plans approved by security holders
|
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|
30,000 |
|
|
$ |
1.45 |
|
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|
795,000 |
|
|
|
Item 13 |
Certain Business Relationships and Transactions |
During the year ended June 30, 2005, the Company paid
G&OD INC. $65,700 for providing accounting and
administrative services, a firm owned by Mr. James R.
Joyce, who served as the Companys President and Chief
Financial Officer until June 30, 2004. In addition, the
Company purchased $12,000 of office equipment from
G&OD INC.
56
Item 14 Principal Accountant Fees and
Services
During the fiscal years ended June 30, 2004 and
June 30, 2005, the Company retained its current principal
auditor, Deloitte & Touche LLP, to provide services in
the following categories and amounts.
Audit Fees
The aggregate fees paid or to be paid to Deloitte &
Touche LLP for the fiscal years ended June 30, 2004 and
June 30, 2005, for the review of the financial statements
included in the Companys 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, 2004 and June 30, 2005, respectively, were
$208,432 and $195,702.
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.
57
PART IV
|
|
Item 15. |
Exhibits and Financial Statement Schedules |
(a) (1) Financial Statements.
The financial statements listed below and included under
Item 8 are filed as part of this report.
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Page | |
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Reference | |
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| |
Reports of Independent Registered Public Accounting Firms
|
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26 |
|
Consolidated balance sheets as of June 30, 2005 and 2004
|
|
|
28 |
|
Consolidated statements of income for each of the three years in
the period ended June 30, 2005
|
|
|
29 |
|
Consolidated statements of changes in stockholders equity
for each of the three years in the period ended June 30,
2005
|
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|
30 |
|
Consolidated statements of cash flows for each of the three
years in the period ended June 30, 2005
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31 |
|
Notes to consolidated financial statements
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32 |
|
Supplementary oil and gas information (unaudited)
|
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|
47 |
|
(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
Companys quarterly report on Form 10-Q filed on
February 13, 2001 and incorporated herein by reference.
(b) By-Laws, as amended on July 22, 2004, is filed as
Exhibit 3(b) to Annual Report on Form 10-K for the
year ended June 30, 2004 (File No-001-5507) are
incorporated by reference.
4. Instruments defining the rights of security holders,
including indentures.
None.
9. Voting Trust Agreement.
None.
58
10. Material contracts.
(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.
59
(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 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 Companys Certificate of Incorporation and the
applicable By-Law to indemnify the Companys 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.
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.
16. Letter re change in certifying accountant.
60
Letter of Ernst & Young LLP dated August 27, 2003
filed as exhibit 16 to Current Report on Form 8-K
filed on August 27, 2003 (File No. 001-5507) is
incorporated herein by reference.
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 Ernst & Young LLP is filed herein.
3. 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.
61
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 26, 2005
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
Daniel
J. Samela |
|
President, Chief Executive Officer, Chief Financial and
Accounting Officer |
|
Dated: September 26, 2005 |
|
/s/ Donald V. Basso
Donald
V. Basso |
|
Director |
|
Dated: September 26, 2005 |
|
/s/ Timothy L. Largay
Timothy
L. Largay |
|
Director |
|
Dated: September 26, 2005 |
|
/s/ Walter McCann
Walter
McCann |
|
Director |
|
Dated: September 26, 2005 |
|
/s/ Ronald P.
Pettirossi
Ronald
P. Pettirossi |
|
Director |
|
Dated: September 26, 2005 |
62
INDEX TO EXHIBITS
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|
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|
|
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21 |
. |
|
Subsidiaries of the Registrant. |
|
23 |
. |
|
1. Consent of Deloitte & Touche LLP |
|
|
|
|
2. Consent of Ernst & Young LLP |
|
|
|
|
3. Consent of Paddock Lindstrom & Associates, Ltd. |
|
31 |
. |
|
Rule 13a-14(a) Certifications. |
|
32 |
. |
|
Section 1350 Certifications. |