UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended June 30, 1999
---------------------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 1-5507
MAGELLAN PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 06-0842255
State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
149 Durham Road, Madison, Connecticut 06443
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (203) 245-7664
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Common stock, par value $.01 per share Boston Stock Exchange
Pacific Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
(Title of Class)
Common stock, par value $.01 per share 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.
|X| Yes |_| No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (ss.229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. |X|
The aggregate market value of the voting and non-voting common equity
held by non-affiliates of the registrant was $45,074,000 at September 15, 1999
(based on the last sale price of such stock as quoted on the Pacific Stock
Exchange).
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date:
Common stock, par value $.01 per share, 25,108,226 shares outstanding
as of September 15, 1999.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement related to the Annual Meeting of
Stockholders for the fiscal year ended June 30, 1999, are incorporated by
reference in Part III of this Form 10-K to the extent stated herein.
TABLE OF CONTENTS
Page
PART I
Item 1. Business 6
Item 2. Properties 18
Item 3. Legal Proceedings 23
Item 4. Submission of Matters to a Vote of Security Holders 27
PART II
Item 5. Market for the Company's Common Stock and Related
Stockholder Matters 28
Item 6. Selected Consolidated Financial Information 29
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 37
Item 8. Financial Statements and Supplementary Data 38
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 74
PART III
Item 10. Directors and Executive Officers of the Company 74
Item 11. Executive Compensation 74
Item 12. Security Ownership of Certain Beneficial Owners and Management 74
Item 13. Certain Relationships and Related Transactions 74
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 75
--------------------
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 15, 1999 was approximately A.$1.00
equaled U.S.$.6491.
PART I
Item 1. Business
Magellan Petroleum Corporation (the "Company" or "MPC") is engaged,
directly and through its majority-owned subsidiary, in the sale of oil and gas
and the exploration for and development of oil and gas reserves. At June 30,
1999, the Company's principal asset was a 50.9% equity interest in its
subsidiary, Magellan Petroleum Australia Limited ("MPAL"), which has one class
of stock that is publicly held and traded in Australia.
MPAL owns interests in various oil and gas properties in Australia, the
United States and Belize, Central America. MPAL's major Australian 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 (50.8% working interest). Both fields are located in the Amadeus Basin
in the Northern Territory of Australia ("Northern Territory"). Santos Ltd.
("Santos"), a publicly owned Australian company, owns a 48% interest in the Palm
Valley field, a 65% interest in the Mereenie field and 18.2% of MPAL's
outstanding stock. Boral Limited, a publicly owned Australian company, owned a
17.1% interest in MPAL's outstanding stock at June 30, 1999.
The Company has a direct 2.67% carried interest in the Kotaneelee gas
field in the Yukon Territory of Canada. The Company has not received any
revenues from this field to date. See Item 3 - Legal Proceedings. In addition,
the Company has a 3% working interest in a Belize project (in which MPAL has a
20% working interest) and a 20% working interest in two wells in Texas.
The following chart illustrates the various relationships between the
Company and the various companies discussed above.
The following is a tabular presentation of the omitted material:
MPC - MPAL RELATIONSHIPS CHART
MPC owns 50.9% of MPAL.
MPAL owns 50.8% of the Palm Valley Field, Australia.
MPAL owns 35% of the Mereenie Field, Australia.
BORAL owns 17.1% of MPAL.
SANTOS owns 18.2% of MPAL.
SANTOS owns 48% of the Palm Valley Field, Australia.
SANTOS owns 65% of the Mereenie Field, Australia.
(a) General Development of Business.
Operational Developments Since the Beginning of the Last
Fiscal Year.
AUSTRALIA
Mereenie
MPAL (35%) and Santos (65%), the operator, (together known as the
Mereenie Participants) own the Mereenie field which is located in the Amadeus
Basin of the Northern Territory. MPAL's share of production from the field is
subject to net overriding royalties aggregating 3.0625% and the statutory
government royalty of 10%. MPAL's share of the Mereenie field proved developed
oil reserves was approximately 730,000 barrels at June 30, 1999.
The field was producing about 1,700 (MPAL share - 595) barrels of crude
oil per day ("bpd") at June 30, 1999. During 1999, MPAL's share of oil sales was
236,000 barrels and 3.4 billion cubic feet ("bcf") of gas sold from 41 oil and
gas wells. The oil is transported by means of a 167 mile eight-inch oil pipeline
from the field to the Brewer Estate industrial park near Alice Springs. Most of
the oil is then shipped south approximately 950 miles by rail and road to a
refinery in the Adelaide area. The cost of transporting the oil to the refinery
is being borne by the producers. The Mereenie Participants are also providing
Mereenie gas in the Northern Territory to the Power and Water Authority ("PAWA")
and Gasgo Pty. Ltd., a company it wholly owns, for use in Darwin and other
Northern Territory centers. See "Gas Supply Contracts".
During 1999, the Mereenie Participants had been negotiating for the
sale of Liquid Petroleum Gas from the field to a purchaser but the project was
terminated after it was determined that it was uneconomic.
Palm Valley
MPAL has a 50.8% interest in and is the operator of the Palm Valley gas
field which is located in the Northern Territory. Santos, the operator of the
Mereenie field, owns a 48% interest in Palm Valley. Ten wells have been drilled
in the field, five of which are currently connected to the gas treatment plant
and are flowed at maximum deliverability levels to meet the Alice Springs and
Darwin supply contracts with PAWA. See "Gas Supply Contracts". During fiscal
1999, MPAL's share of gas sales was 3.7 bcf. In order to increase
deliverability, field compression began in November 1996 with two 400 HP
compressors. A third 800 HP compressor was installed during fiscal 1999. MPAL
has recommended that four additional wells be drilled at Palm Valley to improve
the field's production capacity. Under the gas supply agreement with PAWA, the
costs of these wells are reimbursed by PAWA and, consequently, the
recommendation is under review by PAWA's consultants.
MPAL's share of Palm Valley production revenues is subject to a 10%
statutory government royalty and net overriding royalties aggregating 4.2548%.
Gas Supply Contracts
In 1983, the Palm Valley Participants commenced the sale of gas to
Alice Springs under a 1981 agreement. In 1985, the Palm Valley Participants and
Mereenie Participants signed agreements for the sale of gas to PAWA for use in
PAWA's 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 following is a summary of MPAL's interest in the Palm Valley and the
Mereenie gas supply contracts:
Maximum contract
(balance/after royalties) Percentage of
contract completed Contract Period
(bcf)
Palm Valley:
Alice Springs (1981) 9.6 54 25 years (1983-2008)
Darwin (1985) 43.8 43 25 years (1987-2012)
----
53.4
Mereenie:
Darwin (1985) 8.6 43 25 years (1987-2012)
Darwin (1995) - 100 10 years (1995-2005)
Darwin (1997) 18.4 - 10 years (1999-2009)
Other .7 - Various
----
27.7
Total 81.1
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.
In consideration for the Palm Valley Participants forgoing 20% of the
Amadeus Basin to Darwin gas supply contract during the first 20 contract years,
Mereenie Participants made a payment to the Palm Valley Participants to
partially compensate the Palm Valley Participants for the reduced net present
value of the future gas sales revenues which were postponed from contract years
1 to 20 to contract years 21 to 26. The agreement also provides that when the
Mereenie Participants sell any additional gas from the Mereenie field, the Palm
Valley Participants are entitled, as additional consideration, to 35% of the
revenues from the first 38 bcf (MPAL share - 19.5 bcf) of gas sold. At June 30,
1999, the balance of the Mereenie Participants gas subject to this entitlement
was 9.7 bcf (MPAL share - 4.8 bcf).
Dingo Gas Field
MPAL has a 34.3% interest in the Dingo gas field which is held under
Retention License 2 and is subject to renewal in 2003. The Dingo gas field,
which is located in the Amadeus Basin in the Northern Territory, has
approximately 25 bcf of presently proved and recoverable reserves based on four
delineation wells. Dingo 2 and Dingo 3 wells are estimated to have the capacity
of producing a combined rate of 5 million cubic feet ("mmcf") per day. MPAL's
share of potential production from these permit areas is subject to a 10%
statutory government royalty and overriding royalties aggregating 2.5043%.
Ngalia Basin
MPAL had a 40% interest in permit EP-15 in the Ngalia basin in the
Northern Territory which expired during May 1999. During July 1998, the Newhaven
well was plugged and abandoned. MPAL's share of the drilling costs incurred
through June 30, 1998 were included in exploratory and dry hole costs for the
1998 fiscal year. The costs to drill the well subsequent to June 30, 1998 in the
amount of $316,000 are included in exploratory and dry hole costs for fiscal
1999.
Northern Surat Basin
During fiscal 1998, MPAL sold its 15.625% interest in ATP 378P
Queensland, Australia to its partner, Santos. The $636,000 difference between
the carrying cost and the sale price was included in loss on the sale of assets
for the 1998 fiscal year.
Surat Basin
During the 1998 fiscal year, MPAL earned a 17% interest in Block D of
ATP 244P in Queensland by completing a pilot seismic reprocessing program.
During the 1999 fiscal year, MPAL abandoned its interest in the permit.
During fiscal 1998, MPAL earned a 15% interest in ATP 626P in
Queensland. During fiscal 1999, MPAL relinquished its interest in the permit.
Timor Sea
During April 1998, MPAL acquired a 5% interest in Exploration Permit
WA-199-P in the Bonaparte Basin in the Timor Sea offshore Western Australia.
MPAL earned its interest in the permit by funding 10% of the cost of drilling
the Kittiwake-1 well which was a dry hole. MPAL's cost of the well was written
off in the fourth quarter of fiscal 1998 and was included in exploratory and dry
hole costs. MPAL relinquished its interest in the permit during the 1999 fiscal
year.
Browse Basin
During the 1999 fiscal year, MPAL was granted a 17.5% interest in
exploration permits WA-281-P, WA-282-P and WA-283-P in the Browse Basin offshore
Western Australia. During the 1999 fiscal year, MPAL spent approximately $67,000
toward the Year 1 work obligations. MPAL's share of the work obligations for the
three permits is as follows:
WA-281-P WA-282-P WA-283-P Total
Year 1 $ 368,000 $ 286,000 $ 286,000 $ 940,000
Year 2 713,000 111,000 111,000 935,000
Year 3 1,320,000 23,000 1,203,000 2,546,000
---------- ---------- ---------- ----------
Total Years 1-3 $2,401,000 $ 420,000 $1,600,000 $4,421,000
---------- ---------- ---------- ----------
Year 4 187,000 23,000 187,000 397,000
Year 5 1,437,000 1,308,000 1,437,000 4,182,000
Year 6 35,000 23,000 35,000 93,000
---------- ---------- ---------- ----------
Total Year 4-6 $1,659,000 $1,354,000 $1,659,000 $4,672,000
---------- ---------- ---------- ----------
Total All Years $4,060,000 $1,774,000 $3,259,000 $9,093,000
========== ========== ========== ==========
During January 1999, MPAL was granted exploration blocks WA-287-P and
WA-288-P in the Eastern Browse Basin offshore Western Australia. During the 1999
fiscal year, MPAL spent approximately $54,000 toward the Year 1 work
obligations. The following exploration program was submitted to obtain the
blocks with the exploration expenditures in Years 1-3 obligatory and Years 4-6
discretionary:
Year WA-287-P WA-288-P Total
---- -------- -------- -----
1 $ 67,000 $ 120,000 $ 187,000
2 134,000 334,000 468,000
3 134,000 134,000 268,000
---------- ---------- -----------
Total Years 1-3 335,000 588,000 923,000
---------- ---------- -----------
4 2,336,000 2,336,000 4,672,000
5 167,000 167,000 334,000
6 2,336,000 2,336,000 4,672,000
---------- ---------- -----------
Total Years 4-6 4,839,000 4,839,000 9,678,000
---------- ---------- -----------
Total All Years $5,174,000 $5,427,000 $10,601,000
========== ========== ===========
Carnarvon Basin
MPAL earned a 15% interest in exploration permits TP/12 and EP398 in
the Carnarvon Basin offshore Western Australia by funding 30% of the cost of
drilling the Springbok-1 well. The Springbok-1 well was plugged and abandoned
during August 1998. MPAL's cost of drilling the well was written off during the
first quarter of fiscal 1999.
During April 1999, MPAL was awarded permit WA-291-P, offshore Western
Australia in the Carnarvon Basin. The minimum expenditure obligations for the
first three year period totals $347,000. The discretionary commitment for years
4-6 totals approximately $4.8 million.
Maryborough Basin
MPAL holds a 98% interest in exploration permit ATP 613P, a 670,000
acre block, in the Maryborough Basin in Queensland, Australia. A third party has
agreed to drill an exploration well in exchange for an approximate 50% interest
in the permit. The well will be drilled during the 2000 fiscal year.
Cooper Basin
During April 1999, MPAL (50%) and its partner Beach Petroleum NL were
successful in bidding for two exploration blocks in South Australia's Cooper
Basin. The formal grant of the permit is pending. MPAL's share of the work
obligations during the five year period of the permit are as follows:
Year CO98I CO98J Total
---- ----- ----- -----
1 $ 534,000 $ 668,000 $1,202,000
2 334,000 401,000 735,000
3 234,000 300,000 534,000
---------- ---------- ----------
Total Years 1-3 1,102,000 1,369,000 2,471,000
---------- ---------- ----------
4 67,000 367,000 434,000
5 234,000 300,000 534,000
---------- ---------- ----------
Total Years 4-5 301,000 667,000 968,000
---------- ---------- ----------
Total All Years $1,403,000 $2,036,000 $3,439,000
========== ========== ==========
UNITED STATES
Baca County, Colorado
MPC (10%) and MPAL (90%) participated in an exploration program in
Colorado. During 1995, MPAL commenced a three well drilling program. All three
wells were dry holes. During fiscal 1995 and 1996, the Company wrote off
$809,000 and $1,691,000 in costs, respectively. During fiscal 1997, the Company
drilled a fourth well which was a dry hole and all of the remaining costs of the
project, which totaled $3,008,000, were written off. During fiscal 1999, MPAL
spent approximately $16,000 on the project and it is allowing most of the leases
to expire.
Tapia Canyon, California
Effective December 1, 1997, MPC acquired an 18% interest in a heavy oil
recovery project in Tapia Canyon, California. Because the Company was
dissatisfied with the program to develop the field reserves, the Company has
sold its interest for its approximate cost of $101,000 effective August 31,
1999.
Stephens County, Texas
During fiscal 1999, MPC participated (20%) in the drilling of the
Puckett No. 1 well which is presently suspended. There are indications of oil
and additional work will be performed during September 1999. During late June
1999, MPC also participated (21.4%) in the drilling of the Smith No. 1 well
which also has indications of oil. MPC's capitalized costs at June 30, 1999
totaled $71,000.
BELIZE
Southern Offshore Block PSA
During March 1998, MPC (3%), MPAL (20%) and the other joint venture
participants entered into a new Production Sharing Agreement ("PSA") with the
Government of Belize. The new Southern Offshore Block PSA ("SOB PSA") combines
most of the blocks previously included in the Gladden PSA and the Block 13 PSA,
and totals approximately 893,000 acres. The work obligations of the new PSA are
as follows: Year 1 - $100,000, Year 2 - $300,000, Year 3 - $3,000,000 and Year 4
- - $150,000. The participants in the PSA have been seeking partners in the
venture. The first year obligations have been completed and the participants are
negotiating with the Government of Belize to reduce the Year 2 obligations.
Gladden Basin PSA/Block 13 PSA
During 1997, the Gladden No. 1 well was plugged and abandoned and the
Company's cost of the well was written off. During March 1998, this block was
consolidated into the SOB PSA.
MPC and MPAL were also participants in a Production Sharing Agreement
("Block 13 PSA") offshore Belize adjoining the western and southern boundaries
of the Gladden PSA. The Block 13 PSA covered approximately 788,000 acres. During
March 1998, this block was consolidated into the SOB PSA.
CANADA
The Company 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. Anderson Oil & Gas, Inc., ("Anderson") is the operator
of this partially developed field which is connected to a major pipeline system.
Two wells are currently producing gas from the field approximately 60-65 mmcfd.
Although production at the Kotaneelee field commenced in 1979,
sustained production from the field did not begin until February 1991. Total
production from the field, according to government reports, has been as follows:
Calendar Year Production (bcf)
1979-1980 1.6
1991 8.1
1992 18.0
1993 17.5
1994 16.7
1995 15.7
1996 15.2
1997 14.4
1998 16.0
1999 (6 mos.) 10.6
-----
Total through June 30, 1999 133.8
=====
In a 1989 application to the National Energy Board, a reserve study by
the then operator estimated gas in place at 1.6 trillion cubic feet with proved
and probable recoverable reserves of 781 bcf.
The operator has not permitted the Company access to detailed pricing
and volume information, citing the litigation regarding the field. See Item 3 -
Legal Proceedings for a discussion of litigation relating to the Kotaneelee
field which may affect the status of the carried interest and the amount of the
carried interest account.
The Company is not entitled to any revenue from the field until the
working interest owners recover their costs. The operator last reported to the
Company unrecovered development costs totaling approximately Cdn.$8,873,000
(Company share - U.S.$159,000) at May 31, 1999. The amount of remaining
recoverable costs is one of the issues being contested in the Kotaneelee
litigation. The Company claims, and the defendants deny, that the defendants
have made improper charges to the carried interest account and one defendant
(Amoco Canada Oil and Gas) maintains that the carried interest account should be
charged additional amounts for gas processing fees. Amoco claims that the
remaining costs to be recovered at February 28, 1999 were Cdn.$77,983,000.
Projections by the operator indicate that the carried interest account
may reach payout status prior to December 1999. However, there can be no
assurances that payout will occur within that time frame, inasmuch as there are
uncertainties as to production levels, gas pricing, field operating expenses,
additional capital expenditures and the impact of the Kotaneelee litigation.
For financial statement purposes in fiscal 1987 and 1988, the Company
wrote down its Canada cost center which included 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.
Although the field is now producing and payout may occur by December 1999, the
Company has not yet classified its share of the Kotaneelee gas reserves as
proved because the gas field is still the subject of litigation. The Company
will reclassify the reserves at the Kotaneelee field as proved when there is
greater assurance as to the timing and assumptions regarding the investment.
(b) Financial Information about Industry Segments.
Since the Company is engaged in only one industry, namely, oil
and gas exploration, development, production and sale, this item is not
applicable to the Company.
(c) (1) Narrative Description of the Business.
The Company was incorporated in 1957 under the laws of Panama
and was reorganized under the laws of Delaware in 1967. The Company is engaged
in the exploration for, and the development and production and sale of oil and
gas reserves in the United States, Canada, and Belize and, through its
subsidiary MPAL, in Australia, the United States and Belize.
(i) Principal Products.
MPAL has an interest in the Palm Valley gas field and in the
Mereenie oil and gas field. See Item 1(a) - Australia - for a discussion of the
oil and gas production from the Mereenie and Palm Valley fields. The Company has
a direct 2.67% carried interest in the Kotaneelee gas field in Canada.
(ii) Status of Product or Segment.
See Item 1(a) - Australia - for a discussion of the current
and future operations of the Mereenie and Palm Valley fields in Australia.
(iii) Raw Materials.
Not applicable.
(iv) Patents, Licenses, Franchises and Concessions
Held.
In Australia, the Company has interests directly and
indirectly through its subsidiaries in the following permits. Permittees are
required to carry out agreed work and expenditure programs.
Permit Expiration Date Location
Retention License 2 (Dingo) October 2003 Northern Territory
ATP 613P (Maryborough) Renewal pending Queensland
WA-291-P (Carnarvon Basin) August 2005 Offshore Western Australia
WA-281-P (Browse Basin) August 2004 Offshore Western Australia
WA-282-P (Browse Basin) August 2004 Offshore Western Australia
WA-283-P (Browse Basin) August 2004 Offshore Western Australia
TP12 & EP398 (Carnarvon Basin) January 2002 Offshore Western Australia
WA-287-P (Browse Basin) February 2005 Offshore Western Australia
WA-288-P (Browse Basin) February 2005 Offshore Western Australia
CO98I (Cooper Basin) Pending South Australia
CO98J (Cooper Basin) Pending South Australia
In 1981, the Northern Territory issued Petroleum Leases No. 4
and No. 5 which cover the Mereenie oil and gas field to MPAL's subsidiaries. As
part of the lease conditions, MPAL and its Mereenie partners agreed to construct
an oil refinery near Alice Springs, if it were determined that such a refinery
is economically feasible. MPAL believes that the oil refinery would not be
economically viable under current market conditions, and the Northern Territory
has not raised any current objection to this conclusion. In the event that a
refinery becomes economically viable and the MJV does not construct the
refinery, MPAL and its partners will be required to pay the Northern Territory
liquidated damages based on the value of the crude oil produced from the lands
under lease. The amount to be paid to the Territory is an amount per barrel
which is the greater of (a) A.$3.00 per barrel or (b) A.$2.00 per barrel plus
10% of the amount by which the market price of Mereenie crude oil exceeds
A.$27.50. Production is subject to a statutory 10 percent royalty payable to the
Northern Territory.
In 1982 the Northern Territory granted Petroleum Lease No. 3
for the Palm Valley gas field to a MPAL subsidiary. Production is subject to a
statutory 10 percent royalty payable to the Northern Territory.
The above leases 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 25 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 consider
that this issue will have a material adverse impact on MPAL's properties.
In Belize, Central America, the Company has interests directly
and indirectly through a subsidiary in the following PSA is which issued for
eight years but work and expenditure obligations are calculated in two year
blocks. Application is made ninety days prior to the two year block expiration.
PSA Expiration Date
Southern Offshore Block March 2002
(v) Seasonality of Business.
Although the Company's business is not seasonal, the demand
for oil and especially gas is subject to fluctuations in the Australian weather.
(vi) Working Capital Items.
See Item 7 - Liquidity and Capital Resources for a discussion
of this information.
(vii) Customers.
Although the majority of the Company's producing oil and gas
properties are located in a relatively remote area in central Australia (See
Item 1 - Business and Item 2 - Properties), the completion in January 1987 of
the Amadeus Basin to Darwin gas pipeline has provided access to and expanded the
potential market for the Company's gas production.
Natural Gas Production
MPAL's principal customer and the most likely major customer
for future gas sales is PAWA, a governmental authority of the Northern Territory
Government, which also has substantial regulatory authority over MPAL's oil and
gas operations. The loss of PAWA as a customer would have a material adverse
effect on MPAL's business.
Oil Production
There is presently a small local market for the Mereenie crude
oil in the Alice Springs area. Most of the crude oil production is being shipped
and sold to a refinery in Adelaide.
(viii) Backlog.
Not applicable.
(ix) Renegotiation of Profits or Termination of
Contracts or Subcontracts at the Election
of the Government.
Not applicable.
(x) Competitive Conditions in the Business.
The exploration for and production of oil and gas are highly
competitive operations. The ability to exploit a discovery of oil or gas is
dependent upon such considerations as the ability to finance development costs,
the availability of equipment, and engineering and construction delays and
difficulties. The Company also must compete with major companies which have
substantially greater resources than the Company.
Furthermore, competitive conditions may be substantially
affected by various forms of energy legislation which have been or may be
proposed in Australia, Canada, the United States and Belize; however, it is not
possible to predict the nature of any such legislation which may ultimately be
adopted or its effects upon the future operations of the Company.
At the present time, the Company's principal income producing
operations are in Australia and for this reason, current competitive conditions
in Australia are material to the Company's future. Currently, most indigenous
crude oil is consumed within Australia. In addition, imports of crude oil are
made by refiners and others to meet the overall demand in Australia. The Palm
Valley Participants and the Mereenie Participants 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 unusual material amounts
for environmental control facilities. The federal and state governments in
Australia strictly monitor compliance with these laws but compliance therewith
has not had any adverse impact on the Company's operations or its financial
resources.
(xiii) Number of Persons Employed by Company.
At June 30, 1999, the Company had no full time employees in
the United States and MPAL had 33 employees in Australia. The Company relies to
a great extent on consultants for legal, accounting and administrative services.
(d) Financial Information About Foreign and Domestic
Operations and Export Sales.
(1) Financial Information Relating to Foreign and
Domestic Operations.
See Note 12 to the Consolidated Financial Statements.
(2) Risks Attendant to Foreign Operations.
Most of the properties in which the Company has
interests are located outside the United States and are subject to certain risks
involved in the ownership and development of such foreign property interests.
These risks include but are not limited to those of: nationalization;
expropriation; confiscatory taxation; changes in foreign exchange controls;
currency revaluations; price controls or excessive royalties; export sales
restrictions; limitations on the transfer of interests in exploration licenses;
and other laws and regulations which may adversely affect the Company's
properties, such as those providing for conservation, proration, curtailment,
cessation, or other limitations of controls on the production of or exploration
for hydrocarbons. Thus, an investment in the Company represents a speculation
with risks in addition to those inherent in domestic petroleum exploratory
ventures.
(3) Data Which are Not Indicative of Current or Future
Operations.
MPAL and its co-venturer in the Mereenie field have
been negotiating with PAWA and other parties to sell production out of the
field's uncommitted gas reserves. A new gas supply contract for the uncommitted
reserves in the Mereenie field could increase revenue from gas sales in the
future.
Item 2. Properties.
(a) The Company has interests in properties in Australia, United
States, Canada and Belize. In Australia, it has interests through its 50.9%
equity interest in MPAL which holds interests in the Northern Territory,
Queensland, South Australia and Western Australia. In Canada, the Company has a
direct interest in one lease. The Company also has direct interests in
properties in the United States and Belize and indirectly through MPAL's
interests in these areas. For additional information regarding the Company's
properties, See Item 1 - Business.
(b) (1) The information regarding reserves, costs of oil and gas
activities, capitalized costs, discounted future net cash flows and results of
operations is contained in Item 8 - Financial Statements and Supplementary Data.
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
Wells drilled on the permit
Pointed Mountain Gas Field
Beaver River Gas Field
Westcoast Transmission Pipeline
(2) Reserves reported to other agencies.
None
(3) Production
The average sales price per unit of production for
the following fiscal years are as follows:
June 30,
1999 1998 1997
Australia:
Gas (per mcf) A.$ 2.32 A.$ 2.32 A.$ 2.30
Crude oil (per bbl) A.$20.20 A.$24.55 A.$27.71
The average production cost per unit of production
for the following fiscal years has been impacted by transportation costs on
Mereenie oil in Australia. During 1999, the cost of remedial work on various
wells in the Mereenie field and lower production increased production costs.
June 30,
1999 1998 1997
Australia:
Gas (per mcf) A.$ .33 A.$ .26 A.$ .28
Crude oil (per bbl) A.$19.35 A.$12.28 A.$8.20
(4) Productive Wells and Acreage.
Productive wells and acreage at June 30, 1999:
Productive Wells
Oil Gas Developed Acreage
--- --- -----------------
Gross Net Gross Net Gross Acres Net Acres
----- --- ----- --- ----------- ---------
Australia 40.0 14.0 27.0 10.5 72,025 30,001
Americas 2.0 .4 2.0 .1 3,350 89
---- ---- ---- ---- ------ ------
42.0 14.4 29.0 10.6 75,375 30,090
==== ==== ==== ==== ====== ======
(5) Undeveloped Acreage.
The Company's undeveloped acreage (except as
indicated below) is set forth in the table below:
GROSS AND NET ACREAGE AS OF JUNE 30, 1999
(i) MPAL has interests in the following properties (before royalties).
The Company has an interest in these properties through its 50.9% interest in
MPAL.
Properties held by MPAL: MPAL The Company
------------------------------------------ -------------------------
Net Interest Net Interest
Gross Acres Acres % Acres %
----------- --------- -------- --------- --------
Australia
Northern Territory:
Amadeus Basin:
Mereenie (OL4&5)(1) 69,407 24,292 35.00 12,364 17.81
Palm Valley (OL3)(2) 151,905 77,130 50.78 39,259 25.84
Dingo (RL2) 115,596 39,696 34.34 20,205 17.48
---------- --------- ---------
Total Amadeus Basin 336,908 141,023 71,828
---------- --------- ---------
Queensland:
Maryborough Basin (ATP 613P) 344,318 337,432 98.00 171,753 49.88
---------- --------- ---------
South Australia:
Cooper Basin (CO98I&J) 1,621,802 810,902 50.00 412,750 25.45
---------- --------- ---------
Western Australia:
Browse WA-281-P 1,147,315 200,780 17.50 102,197 8.91
Browse WA-282-P 1,468,662 257,016 17.50 130,821 8.91
Browse WA-283-P 1,060,618 185,608 17.50 94,474 8.91
Carnarvon TP12 & EP398 146,224 21,934 15.00 11,164 7.64
Carnarvon WA-291-P 2,205,710 2,205,710 100.00 1,122,706 50.90
Browse WA-287-P 515,736 515,736 100.00 262,510 50.90
Browse WA-288-P 513,266 513,266 100.00 261,252 50.90
---------- --------- ---------
Total Western Australia 7,057,531 3,900,050 1,985,124
---------- --------- ---------
Total Australia 9,360,559 5,189,502 2,641,455
---------- --------- ---------
Belize, C.A.
Southern Offshore Block 892,543 178,509 20.00 90,861 10.18
---------- --------- ---------
Total MPAL 10,253,102 5,368,011 2,732,316
---------- --------- ---------
Properties held directly by MPC:
United States
Texas 160 32 20.00
---------- ---------
Belize, C.A.
Southern Offshore Block(3) - 26,776 3.00
---------- ---------
Canada
Yukon and Northwest Territories:
Carried interest(4) 35,076 935 2.67
---------- ---------
Total 10,288,338 2,760,059
========== =========
- ----------------------------
(1) Includes 41,644 gross developed acres and 14,575 net acres.
(2) Includes 30,381 gross developed acres and 15,426 net acres.
(3) Gross acres shown above.
(4) Includes 3,350 gross developed acres and 89 net acres.
(6) Drilling activity.
Productive and dry net wells drilled during the
following years (data concerning Canada is insignificant):
Australia
Exploration Development
Year ended ----------------------- ------------------------
June 30, Productive Dry Productive Dry
1999 - .15 .70 -
1998 - .55 .70 .35
1997 - - - -
Americas
Exploration Development
Year ended ----------------------- ------------------------
June 30, Productive Dry Productive Dry
1999 .20 .19 - -
1998 - - - -
1997 - 1.23 - -
(7) Present Activities.
There are no wells being drilled at the present time.
(8) Delivery Commitments.
See discussion under Item 1 concerning the Palm
Valley and Mereenie fields.
Item 3. Legal Proceedings.
Kotaneelee Gas Field
The Company's 2.67% carried interest in the Kotaneelee gas field is
held in trust by Canada Southern Petroleum Ltd. ("Canada Southern") which has a
30% carried interest in the field. Canada Southern and the Company (the
"Plaintiffs") believe that the working interest owners in the Kotaneelee gas
field have not adequately pursued the attainment of contracts for the sale of
Kotaneelee gas; accordingly, legal action in the United States was commenced by
Canada Southern in 1987 against AlliedSignal Inc. and Allied Corporation
(collectively, Allied Signal). This suit was ultimately dismissed in December
1988.
In October 1989 and in March 1990, Canada Southern filed statements of
claim in the Court of Queens Bench of Alberta, Judicial District of Calgary,
Canada, against the working interest partners in the Kotaneelee gas field. The
named defendants were Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum
Limited (now Amoco Canada Resources Ltd.), and Amoco Production Company
(collectively the "Amoco Dome Group"), Columbia Gas Development of Canada Ltd.
("Columbia"), Mobil Oil Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd.
("Esso") (collectively the "Defendants").
The Plaintiffs claim that the Defendants breached either a contract
obligation or a fiduciary duty owed to the Plaintiffs to market gas from the
Kotaneelee gas field when it was possible to so do. The Plaintiffs assert that
marketing the Kotaneelee gas was possible in 1984 and that the Defendants
deliberately failed to do so. The Company seeks monetary damages and the
forfeiture of the Kotaneelee gas field. The Plaintiffs presented evidence at
trial that the monetary damages sustained by the Plaintiffs were approximately
Cdn.$110 million (Company share-U.S.$5.8 million).
In addition, the Plaintiffs have claimed that the Plaintiff's carried
interest account should be reduced because of the negligent operation of the
field and improper charges to the carried interest account by the Defendants.
The Plaintiffs claim that when the Defendants in 1980 suspended production from
the field's gas wells, they failed to take precautionary measures necessary to
protect and maintain the wells in good operating condition. The wells thereafter
deteriorated, which caused unnecessary expenditures to be incurred, including
expenditures to redrill one well. In addition, the Plaintiffs claim that
expenditures made to repair and rebuild the field's dehydration plant would not
have been necessary had the facilities been properly constructed and maintained
by the Defendants. The expenditures, the Plaintiffs claim, were inappropriately
charged to the field's carried interest account. The effect of an increased
carried interest account is to extend the period before payout begins to the
carried interest account owners.
The Plaintiffs claim that production from the field should have
commenced in 1984. At that time the field's carried interest account was
approximately Cdn.$63 million. The Company claims that by 1993 at least Cdn.$34
million of unnecessary expenses had been wrongfully charged to the carried
interest account. The Company's 2.6% share of these expenses would be
approximately Cdn.$.9 million. The Plaintiffs further claim that, if production
had commenced in 1984, the carried interest account would have been paid off in
approximately two years and the Company would have begun to receive revenues
from the field in 1986. Projections by the operator indicate that the carried
interest account may reach payout status prior to the end of 1999. However,
there can be no assurances that payout will occur within that timeframe,
inasmuch as there are uncertainties as to production levels, gas pricing, field
operating expenses, additional capital expenditures and the impact of the
Kotaneelee litigation.
Columbia has filed a counterclaim against the Plaintiffs seeking, if
the Plaintiffs are successful in its claim for the forfeiture of the field,
repayment from the Plaintiffs of all sums Columbia has expended on the
Kotaneelee lands before the Plaintiffs are entitled to their interest.
The parties to the litigation have conducted extensive discovery since
the filing of the claims. The trial, which started on September 3, 1996, is
still in progress. The trial was adjourned during the period December 1996-April
1997, July-August 1997, and July-August 1998. The trial resumed on September 8,
1998 and the Plaintiff's case was completed on September 16, 1998. The
Defendants began their case on September 16, 1998 and the trial was adjourned
for the July-August 1999 period and resumed on September 7, 1999.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Plaintiffs sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Plaintiff will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Plaintiffs maintain that no
interest should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Plaintiffs maintain that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position while the Amoco Dome
Group continues to contest this issue and claims that the remaining costs to be
recovered at February 28, 1999 were Cdn.$78 million (U.S.$52 million) as
compared to the other party's amount of Cdn.$13.5 million (U.S.$9 million) at
such date.
On January 22, 1996, the Plaintiffs settled two claims outstanding
against the Company in the Court of Queens Bench, Calgary, Alberta, which
related to a suit brought against AlliedSignal in Florida which was dismissed on
the basis that Canada was the appropriate forum for the litigation. AlliedSignal
had sought additional relief against the Company in Canada to preclude other
types of suits by the Company and to recover the costs of the defense of the
initial action. The settlement bars AlliedSignal from making a claim against the
Plaintiffs for any costs in connection with the Kotaneelee Litigation. The
Plaintiffs agreed not to bring any action against AlliedSignal in connection
with the Kotaneelee gas field. Neither party made any monetary payment to the
other party.
In 1991, Anderson Exploration Ltd. acquired Columbia and changed its
name to Anderson Oil & Gas Inc. ("Anderson"). Anderson is now the sole operator
of the field and is a direct defendant in the Canada Court lawsuits. Columbia's
previous parent, The Columbia Gas System, Inc., which was reorganized in a
bankruptcy proceeding in the United States, is contractually liable to Anderson
in the legal proceeding described above.
The working interest owners have reported that they have been selling
Kotaneelee gas since February 1991. The Company is uncertain as to what impact,
if any, these sales may have on the status of the litigation.
Under Canadian law, certain costs (known as "taxable costs") of the
litigation may be assessed against the non-prevailing party. Previously, the
Company had reported that while such costs were not determinable, Canada
Southern had estimated that taxable costs, assuming a twelve month trial, could
be approximately Cdn.$1.5 million and noted that the judge in complex and length
trials has the discretion to increase an award. MPC has not agreed to share any
costs that might be assessed against Canada Southern, however, MPC's potential
share would not have exceeded U.S.$80,000.
Effective September 1, 1998, the Alberta Rules of Court were amended to
provide for a material increase in the costs which may be awarded to the
prevailing party in matter before the Court. In addition, the trial has extended
well beyond its original time estimates and, therefore, potential assessable
costs would increase accordingly.
The trial has been lengthy, complicated and costly to all parties and
the Company believes that the prevailing party or parties in the litigation will
argue for a substantial assessment of costs against the non-prevailing party or
parties. The Court has very broad discretion as to whether to award costs and
disbursements and as to the calculation of the amount to be awarded.
Accordingly, the Company is unable to determine whether, in the event that
Canada Southern does not prevail on its claims in the litigation, costs will be
assessed against it or in what amount. However, since the costs incurred by the
Defendants have been substantial, and since the Court has broad discretion in
the awarding of costs, an award to the Defendants potentially could be material,
if such costs were to be directly assessed against the Company.
There is no assurance whatever that Canada Southern and the Company
will be successful on the merits of their claims, which have been vigorously
defended by the Defendants. There is also no assurance that Canada Southern or
the Company will be awarded any damages, or that, if damages are awarded, the
Court will apply the measure of damages that Canada Southern and the Company
claim should be applied.
Canada Southern has been advancing and paying all the legal and other
expenses of the Kotaneelee litigation. The Company has not received an
accounting of the amounts spent to date and understands that Canada Southern
expects to recover its costs only from any judgment in favor of the Plaintiffs.
The Company believes that the outcome of the Kotaneelee litigation is not
reasonably likely to have a material adverse effect on the Company's future
consolidated financial condition or results of operations.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Executive Officers of the Registrant
The following information with respect to the executive officers of the
Company is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
Length of Service Other Positions Held
Name Age Office Held as an Officer with Company
James R. Joyce 58 President and Chief Financial President since Director
Officer July 1, 1993
Dennis D. Benbow* 60 General Manager - MPAL Since 1993 Director
* Effective August 13, 1999, Mr. Benbow retired as an officer and director of
MPAL, and as a director of MPC.
All officers of MPC are elected annually by the Board of Directors and
serve at the pleasure of the Board of Directors.
The Company is not aware of any arrangements or understandings between
any of the individuals named above and any other person pursuant to which any
individual named above was selected as an officer.
PART II
Item 5. Market for the Company's Common Stock and Related Stockholder
Matters.
(a) Principal Market
The principal markets for the Company's common stock is the Pacific
Exchange, Inc. [MPC] and the NASDAQ SmallCap market [MPET]. The stock is also
traded on the Boston Stock Exchange. The quarterly high and low prices on the
most active market, NASDAQ, during the calendar quarterly periods indicated were
as follows:
1999 1st quarter 2nd quarter 3rd quarter*
- ---- ----------- ----------- ------------
High......... 1.81 2.50 2.81
Low.......... 1.27 1.19 1.63
1998 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High......... 3.16 3.00 2.44 2.00
Low.......... 2.50 2.19 1.13 1.13
1997 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High......... 4.13 2.81 4.00 3.81
Low.......... 2.38 2.09 2.25 2.50
- ---------------------------------
* Through September 15, 1999, on which date the closing price was $1.81.
(b) Approximate Number of Holders of Common Stock at
September 15, 1999
Title of Class Number of Record Holders
Common stock, par
value $.01 per share 9,100
(c) Frequency and Amount of Dividends
The Company has never paid a cash dividend on its common stock. The
Company will consider the payment of dividends when it has the ability to make
such payments.
(d) Recent Sales of Unregistered Securities
None.
Item 6. Selected Consolidated Financial Information.
The following table sets forth selected data (in thousands) of the
Company insofar as it relates to each of the five fiscal years in the period
ended June 30, 1999. This data should be read in conjunction with Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations and Item 8 - Financial Statements and Supplementary Data.
Year ended June 30,
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
Financial Data $ $ $ $ $
Operating revenues 13,398 15,235 19,936 17,027 14,154
====== ====== ====== ====== ======
Total revenues 14,115 15,340 20,758 18,073 15,424
====== ====== ====== ====== ======
Net income 945 1,037 694 1,411 684
====== ====== ====== ====== ======
Net income per share (Basic and Diluted) .04 .04 .03 .06 .03
====== ====== ====== ====== ======
Working capital 12,772 13,452 14,219 9,858 8,806
====== ====== ====== ====== ======
Cash provided by operating activities 4,993 6,737 11,181 9,185 8,587
====== ====== ====== ====== ======
Property and equipment (net) 26,725 23,019 28,623 32,912 37,361
====== ====== ====== ====== ======
Total assets 44,234 39,779 46,230 47,816 39,575
====== ====== ====== ====== ======
Long-term liabilities 6,910 6,512 7,738 6,981 6,312
====== ====== ====== ====== ======
Minority interests 15,318 13,123 16,147 16,682 14,366
====== ====== ====== ====== ======
Stockholders' equity:
Capital 43,838 43,782 43,659 43,492 43,358
Accumulated deficit (18,405) (19,350) (20,387) (21,080) (22,491)
Accumulated other comprehensive loss (5,699) (7,013) (3,729) (2,785) (4,833)
-------- -------- -------- -------- --------
Total stockholders' equity 19,734 17,419 19,543 19,627 16,034
====== ====== ====== ====== ======
Exchange rate A.$=U.S. at end of period .6675 .6194 .7538 .7875 .7097
====== ====== ====== ====== ======
Common stock outstanding shares 25,108 24,982 24,851 24,691 24,544
====== ====== ====== ====== ======
Book value per share .79 .70 .78 .79 .65
====== ====== ====== ====== ======
Quoted market value per share 2.50 2.28 2.38 2.50 1.94
====== ====== ====== ====== ======
Operating Data
Annual production (Net of royalties)
Gas (BCF) 5.898 5.844 5.673 5.422 5.066
====== ====== ====== ====== ======
Oil (BBLS) (In thousands) (net of royalties 205 248 307 318 369
====== ====== ====== ====== ======
Standard measure of discounted future cash
flow relating to proved oil and gas reserves.
(approximately 49% attributable to minority interests) 53,000 48,000 68,000 44,000 38,000
====== ====== ====== ====== ======
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
(1) Liquidity and Capital Resources - June 30, 1999
Consolidated
At June 30, 1999, the Company on a consolidated basis had approximately
$15.5 million of cash and securities.
A summary of the major changes in cash and cash equivalents during the
period is as follows:
Cash and cash equivalents at beginning of period $12,436,000
Cash provided by operations 4,993,000
Dividends to MPAL minority shareholders (687,000)
Additions to property and equipment (4,679,000)
Effect of exchange rate changes 897,000
Other 421,000
-----------
Cash and cash equivalents at end of period $13,381,000
===========
As to the Company (unconsolidated)
At June 30, 1999, Magellan Petroleum Corporation ("MPC"), on an
unconsolidated basis, had working capital of approximately $3.6 million. MPC's
annual operating budget is approximately $700,000 and its current cash position
and annual MPAL dividend should be adequate to meet its current cash
requirements. During the fiscal year 2000, MPC has budgeted approximately
$200,000 for oil and gas exploration compared to the $92,000 expended during
1999. MPC has in the past invested and may in the future invest substantial
portions of its cash to maintain its majority interest in its subsidiary
company, MPAL. During fiscal 1999, MPC purchased 113,000 shares of MPAL at a
cost of approximately $112,000.
During December 1998, MPC received a dividend from MPAL of $599,000
(after the $106,000 Australian withholding tax) which was added to MPC's working
capital.
As to MPAL
At June 30, 1999, MPAL had working capital of approximately $11
million. MPAL has budgeted approximately $2.5 million for specific exploration
projects in the fiscal year 2000 and allocated $1.3 million for potential new
projects as compared to the $2 million expended during fiscal 1999. The current
composition of MPAL's oil and gas reserves are such that MPAL's future revenues
in the long term are expected to be derived from the sale of gas in Australia.
The following is a summary of MPAL's required and contingent
commitments for exploration expenditures for the five year period ended June 30,
2004. The contingent amounts will be dependent on such factors as the results of
the current program to evaluate the exploration permits, drilling results and
the Company's financial position.
Fiscal Year Expenditures Required Contingent Expenditures Total
2000 $2,557,000 $ 214,000 $ 2,771,000
2001 4,495,000 521,000 5,016,000
2002 1,035,000 1,025,000 2,060,000
2003 584,000 14,003,000 14,587,000
2004 - 1,705,000 1,705,000
---------- ----------- -----------
$8,671,000 $17,468,000 $26,139,000
========== =========== ===========
MPAL expects to fund its exploration costs through its cash flow from
Australian operations and any balance from its A.$10 million bank line of
credit.
The Company has assessed that its Year 2000 readiness is compliant at
June 30, 1999. The Year 2000 change had no material impact on the Company's
internal operations or financial results. The Company will be dependent on its
suppliers, partners and customers to make their systems year 2000 compliant, but
this reliance should not have a material effect on the Company's financial
results.
(2) Results of Operations
1999 vs. 1998
The Company had consolidated net income of $945,212 for fiscal 1999
compared to net income of $1,036,513 for fiscal 1998. The components of
consolidated net income for the comparable periods were as follows:
Year ended June 30,
------------------------------
1999 1998
MPC unconsolidated pretax loss $ (688,814) $ (688,596)
MPC income tax expense (105,370) (1,000)
Share of MPAL pretax income 1,659,185 1,798,595
Share of MPAL income (tax) benefit 80,211 (72,486)
---------- -----------
Consolidated net income $ 945,212 $1,036,513
========== ==========
Net income per share (basic & diluted) $.04 $.04
==== ====
Revenues
Oil sales decreased 37% in fiscal 1999. Oil sales in Australia
decreased in 1999 to $2,573,000 from $4,098,000 in 1998 because of an 18%
decrease in oil prices, the 8% Australian foreign exchange rate decrease
discussed below and a 17% decrease in the number of units produced. Because of
low oil prices, it has not been economic to drill additional wells to increase
production. Oil unit sales (before deducting royalties) in barrels ("bbls") and
the average price per barrel sold during the periods indicated were as follows:
Fiscal 1999 Sales Fiscal 1998 Sales
----------------------- -------------------------
Average Price Average Price
bbls per bbl bbls per bbl
------- ------------- ------- -------------
Australia - Mereenie 235,806 A.$20.20 284,757 A.$24.55
Gas sales in Australia decreased 8% in fiscal 1999. Gas sales decreased from
$10,485,000 in 1998 to $9,640,000 in 1999 because of the 8% Australian foreign
exchange rate decrease discussed below. The volumes in billion cubic feet
("bcf") (before deducting royalties) and the average price of gas per thousand
cubic feet ("mcf") sold during the periods indicated were as follows:
Fiscal 1999 Sales Fiscal 1998 Sales
--------------------- ---------------------
Average Price Average Price
bcf per mcf bcf per mcf
----- ------------- ----- -------------
Australia: (A.$) (A.$)
Palm Valley
Alice Springs contract 1.232 2.95 1.147 2.96
Darwin contract 2.507 2.02 2.395 2.02
Mereenie
Darwin contract 2.289 2.08 2.171 2.02
Other 1.138 2.77 1.416 2.74
----- -----
Total 7.166 7.129
===== =====
Other production income increased 82% to $1,185,000 in 1999 compared to
$652,000 in 1998. The primary reason for this increase was that MPAL's share of
gas pipeline tariffs increased to $1,061,000 in 1999 compared to $531,000 in
1998. In the 4th quarter of fiscal 1999 the amount increased because of an
anticipated resolution of a dispute regarding the producers' share of the
tariffs.
Interest income decreased 3% to $717,000 in 1999 from $741,000 in 1998.
Although additional funds were available for investment, substantially lower
interest rates and the 8% Australian foreign exchange rate decrease discussed
below offset the increase.
Costs and Expenses
Production costs increased 20% to $4,372,000 in 1999 from $3,647,000 in
1998. The increase relates to the costs at Mereenie where substantial remedial
work was performed on 8 wells and the costs associated with the proposed LPG
plant. During the 4th quarter of fiscal year 1999, the loss attributable to the
LPG plant was reduced by $300,000 to $190,000.
Salaries and employee benefits decreased 10% from $1,435,000 in 1998 to
$1,297,000 in 1999. Compensation costs decreased in Australia together with the
8% Australian foreign exchange rate decrease discussed below.
Depreciation, depletion and amortization increased 7% in 1999 to
$2,357,000 from $2,205,000 in 1998. The increase was the result of the
additional costs from the Mereenie Central Treatment Plant upgrade added to the
depletion calculation which was partially offset by the 8% Australian foreign
exchange rate decrease discussed below.
Exploratory and dry hole costs totaled $2,059,000 during 1999 compared
to $3,346,000 in 1998. The costs in 1999 related primarily to the Springbok-1
well offshore Western Australia which was plugged and abandoned during the first
quarter and the Belize project which was written off in the third quarter of the
fiscal year. In 1998, the Schilling-1 well and the Kittiwake-1 well which were
drilled offshore Western Australia were also abandoned. The costs (in thousands)
in fiscal 1999 and fiscal 1998 for MPC and MPAL were as follows:
1999 1998
------------------------- -------------------------
Location MPAL MPC Total MPAL MPC Total
- -------------------- ------ --- ------ ------ --- ------
United States/Belize $ 361 $50 $ 411 $ 118 $32 $ 150
Australia 1,648 - 1,648 3,196 - 3,196
------ --- ------ ------ --- ------
$2,009 $50 $2,059 $3,314 $32 $3,346
====== === ====== ====== === ======
Auditing, accounting and legal expenses increased 6% from $480,000 in
1998 to $510,000 in 1999. The increase in the 1999 period relates to the legal
and tax advice sought in connection with an unsuccessful bid to acquire certain
oil and gas properties in Australia.
Shareholder communications increased 9% to $185,000 in 1999 compared to
$169,000 in 1998 because of increased exchange listing fees.
Other administrative expenses decreased 20% from $957,000 in 1998 to
$765,000 in 1999. Rent and travel expenses decreased and there was an 8%
Australian foreign exchange rate decrease as discussed below.
Income Taxes
Income tax expense decreased from $144,000 in 1998 to a credit of
$52,000 in 1999. The effective income tax rate for 1999 was -2% compared to 5%
in 1998. The components of income tax expense between MPC and MPAL were as
follows:
1999 1998
MPC $105,000 $ 1,000
MPAL (157,000) 143,000
--------- --------
Consolidated tax (credit) $(52,000) $144,000
========= ========
In 1998, there was no 15% Australian withholding tax on the dividend
paid by MPAL to MPC compared to a withholding tax of $105,000 in 1999. In
addition, MPAL's income tax expense in 1999 (recognized during the 4th quarter)
and 1998 was lower due to the effect of permanent tax benefits under Australian
tax law and the utilization of prior year losses not previously taken into
account.
Exchange Effect
The value of the Australian dollar relative to the U.S. dollar
increased to $.6675 at June 30, 1999 compared to the value of $.6194 at June 30,
1998. This resulted in a $1,314,000 credit to accumulated translation
adjustments for fiscal 1999. The 8% increase in the value of the Australian
dollar increased the reported asset and liability amounts in the balance sheet
at June 30, 1999 from the June 30, 1998 amounts. The annual average exchange
rate used to translate MPAL's operations in Australia for fiscal 1999 was
$.6281, which is a 8% decrease compared to a $.6810 rate for the comparable 1998
period.
1998 vs. 1997
The Company had consolidated net income of $1,036,513 for fiscal 1998
compared to net income of $693,987 for fiscal 1997. The components of
consolidated net income for the comparable periods were as follows:
Year ended June 30,
------------------------------
1998 1997
MPC unconsolidated pretax loss $ (688,596) $(1,254,223)
MPC income tax expense (1,000) (276,117)
Share of MPAL pretax income 1,798,595 2,815,193
Share of MPAL income tax (72,486) (590,866)
----------- ------------
Consolidated net income $1,036,513 $ 693,987
========== ===========
Net income per share (basic & diluted) $.04 $.03
==== ====
Revenues
Oil sales decreased 39% in fiscal 1998. Oil sales in Australia
decreased in 1998 to $4,098,000 from $6,740,000 in 1997 because of a 11%
decrease in oil prices, the 13% Australian foreign exchange rate decrease
discussed below and a 19% decrease in the number of units produced. Oil unit
sales (before deducting royalties) in barrels ("bbls") and the average price per
barrel sold during the periods indicated were as follows:
Fiscal 1998 Sales Fiscal 1997 Sales
------------------------ ------------------------
Average Price Average Price
bbls per bbl bbls per bbl
------- ------------- ------- -------------
Australia - Mereenie 284,757 A.$24.55 352,783 A.$27.71
Gas sales in Australia decreased 9% in fiscal 1998. Gas sales
decreased from $11,552,000 in 1997 to $10,485,000 in 1998 because of the 13%
Australian foreign exchange rate decrease discussed below which was partially
offset by a 3% increase in the volume of gas sold. The volumes in billion cubic
feet ("bcf") (before deducting royalties) and the average price of gas per
thousand cubic feet ("mcf") sold during the periods indicated were as follows:
Fiscal 1998 Sales Fiscal 1997 Sales
--------------------- ---------------------
Average Price Average Price
bcf per mcf bcf per mcf
----- ------------- ----- -------------
Australia: (A.$) (A.$)
Palm Valley
Alice Springs contract 1.147 2.96 1.072 2.95
Darwin contract 2.395 2.02 2.496 2.02
Mereenie
Darwin contract 2.171 2.02 1.963 1.99
Other 1.416 2.74 1.373 2.76
----- -----
Total 7.129 6.904
===== =====
Other production income decreased 60% to $652,000 in 1998 compared to
$1,644,000 in 1997. The primary reason for this decrease was that MPAL's share
of gas pipeline tariffs decreased to $531,000 in 1998 compared to $1,498,000 in
1997. The 1998 amount decreased because of a dispute regarding the producers'
share of the tariffs.
Interest income decreased 10% to $741,000 in 1998 from $822,000 in
1997. Although additional funds were available for investment, substantially
lower interest rates and the 13% Australian foreign exchange rate decrease
discussed below offset the increase.
Loss on sale of assets. During March 1998, MPAL agreed to sell its
15.625% interest in ATP 378P Queensland, Australia to its partner, Santos,
Limited. The $636,000 difference between the carrying cost and the sale price is
included in loss on the sale of assets.
Costs and Expenses
Production costs decreased 24% to $3,647,000 in 1998 from $4,811,000 in
1997. The decrease relates to a decrease in costs at Mereenie and Palm Valley
and the 13% Australian foreign exchange rate decrease discussed below.
Depreciation, depletion and amortization increased 3% in 1998 to
$2,205,000 from $2,140,000 in 1997. The increase was the result of the
additional costs added to the depletion calculation which was partially offset
by the 13% Australian foreign exchange rate decrease discussed below.
Exploratory and dry hole costs totaled $3,346,000 during 1998 compared
to $6,243,000 in 1997. In 1998, the Schilling-1 and the Kittiwake-1 well which
were drilled offshore Western Australia were abandoned. In 1997, the Baca
County, Colorado project was abandoned. In Belize, the Gladden No. 1 well was
also plugged and abandoned in 1997. The costs (in thousands) in 1998 and 1997
for MPC and MPAL are as follows:
1998 1997
------------------------- -------------------------
Location MPAL MPC Total MPAL MPC Total
- -------------------- ------ --- ------ ------ --- ------
Baca County, Colorado $ 46 $ - $ 46 $2,693 $315 $3,008
Belize, C.A. 72 32 104 2,372 283 2,655
Australia 3,196 - 3,196 580 - 580
------ --- ------ ------ ---- ------
$3,314 $32 $3,346 $5,645 $598 $6,243
====== === ====== ====== ==== ======
Bad debts increased to $239,000 during the 1998 period. MPAL
established a reserve for the amount due from Pegasus Gold Australian Pty. Ltd.
because of its bankruptcy filing.
Income Taxes
Income tax expense decreased from $1,442,000 in 1997 to $144,000 in
1998. The effective income tax rate for 1998 was 5% compared to 34% in 1997. The
components of income tax expense between MPC and MPAL were as follows:
1998 1997
MPC $ 1,000 $ 276,000
MPAL 143,000 1,166,000
-------- ----------
Consolidated $144,000 $1,442,000
======== ==========
In 1998, there was no 15% Australian withholding tax on the dividend
paid by MPAL to MPC. In addition, MPAL's income tax expense in 1998 was lower
due to the effect of permanent tax benefits under Australian tax law.
Exchange Effect
The value of the Australian dollar relative to the U.S. dollar
decreased to $.6194 at June 30, 1998 compared to the value of $.7538 at June 30,
1997. This resulted in a $3,284,000 charge to accumulated translation
adjustments for fiscal 1998. The 18% decrease in the value of the Australian
dollar decreased the reported asset and liability amounts in the balance sheet
at June 30, 1998 from the June 30, 1997 amounts. The annual average exchange
rate used to translate MPAL's operations in Australia for fiscal 1998 was
$.6810, which is a 13% decrease compared to a $.7830 rate for the comparable
1997 period.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk.
The Company does not have any significant exposure to market risk as
the only market risk sensitive instruments are its investments in marketable
securities. At June 30, 1999, the carrying value of such investments was
approximately $2.10 million, the fair value was $2.06 million and the face value
was $2.09 million. Since the Company expects to hold the investment to maturity,
the maturity value should be realized. During the year 1999, the value of the
Australian dollar relative to the U.S. dollar increased 8% and increased the
reported asset amounts at June 30, 1999 from the June 30, 1998 amounts.
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Magellan Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Magellan
Petroleum Corporation as of June 30, 1999 and 1998 and the related consolidated
statements of income, changes in stockholders' equity and cash flows for each of
the three years in the period ended June 30, 1999. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Magellan Petroleum Corporation at June 30, 1999 and 1998, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended June 30, 1999, in conformity with generally accepted accounting
principles.
/s/ Ernst & Young LLP
Stamford, Connecticut
September 15, 1999
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
June 30,
-----------------------------------
1999 1998
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents $13,380,699 $12,436,297
Accounts receivable 676,710 567,175
Marketable securities 392,973 1,265,495
Reimbursable development costs 95,743 191,266
Inventories 215,953 218,359
Other assets 282,900 296,933
----------- -----------
Total current assets 15,044,978 14,975,525
----------- -----------
Marketable securities 1,709,455 1,201,890
----------- -----------
Property and equipment:
Oil and gas properties (successful efforts method) 46,430,741 39,196,101
Land, buildings and equipment 1,822,094 1,510,666
Field equipment 1,373,326 1,262,464
----------- -----------
49,626,161 41,969,231
Less accumulated depletion, depreciation and amortization (22,901,263) (18,949,917)
----------- -----------
Total property and equipment 26,724,898 23,019,314
----------- -----------
Other assets 754,639 582,251
----------- -----------
$44,233,970 $39,778,980
=========== ===========
LIABILITIES, MINORITY INTERESTS
AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 1,372,043 $ 1,918,880
Accrued liabilities 780,570 806,150
Income taxes payable 120,150 -
----------- -----------
Total current liabilities 2,272,763 2,725,030
----------- -----------
Long term liabilities:
Deferred income taxes 6,060,402 5,854,261
Reserve for future site restoration costs 849,311 657,288
----------- -----------
Total long term liabilities 6,909,713 6,511,549
----------- -----------
Minority interests 15,317,698 13,123,313
----------- -----------
Commitments (Note 2) - -
Stockholders' equity:
Common stock, par value $.01 per share:
Authorized 50,000,000 shares
Outstanding 25,108,226 (1999), 24,982,495 (1998) shares 251,082 249,825
Capital in excess of par value 43,586,606 43,532,238
----------- -----------
Total capital 43,837,688 43,782,063
Accumulated deficit (18,404,824) (19,350,036)
Accumulated other comprehensive loss (5,699,068) (7,012,939)
----------- -----------
Total Stockholders' equity 19,733,796 17,419,088
----------- -----------
$44,233,970 $39,778,980
=========== ===========
See accompanying notes.
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Year ended June 30,
1999 1998 1997
----------- ----------- -----------
Revenues:
Oil sales $ 2,572,966 $ 4,097,570 $ 6,739,663
Gas sales 9,639,657 10,485,380 11,551,546
Other production related revenues 1,185,020 651,706 1,644,457
Interest income 717,118 741,011 821,941
Gain (loss) on sale of assets - (635,882) -
----------- ----------- -----------
14,114,761 15,339,785 20,757,607
----------- ----------- -----------
Costs and expenses:
Production costs 4,372,253 3,647,135 4,810,931
Exploratory and dry hole costs 2,058,977 3,346,329 6,243,211
Salaries and employee benefits 1,297,036 1,434,868 1,667,678
Depletion, depreciation and amortization 2,356,582 2,205,127 2,140,066
Auditing, accounting and legal services 509,891 479,623 446,336
Bad debts - 239,201 -
Shareholder communications 184,721 168,715 179,111
Other administrative expenses 764,503 956,932 967,267
----------- ----------- -----------
11,543,963 12,477,930 16,454,600
----------- ----------- -----------
Income before income taxes and minority interests 2,570,798 2,861,855 4,303,007
Income taxes provision (benefit) (52,211) 144,087 1,442,495
----------- ----------- -----------
Income before minority interests 2,623,009 2,717,768 2,860,512
Minority interests 1,677,797 1,681,255 2,166,525
----------- ----------- -----------
Net income $ 945,212 $ 1,036,513 $ 693,987
=========== =========== ===========
Average number of shares
Basic 25,040,300 24,949,322 24,782,360
========== ========== ==========
Diluted 25,040,300 25,126,523 25,029,561
========== ========== ==========
Per share, based on average number of shares
outstanding during the period:
Net income (Basic and Diluted) $.04 $.04 $.03
==== ==== ====
See accompanying notes.
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF
CHANGES IN STOCKHOLDERS' EQUITY
Three years ended June 30, 1999
Accumulated
Capital in other Comprehensive
Number Common excess of Accumulated comprehensive income
of shares stock par value deficit loss Total (loss)
---------- -------- ----------- ------------ ------------- ----------- -------------
July 1, 1996 24,691,245 $246,912 $43,244,901 $(21,080,536) $(2,784,596) $19,626,681
Net income - - - 693,987 - 693,987 693,987
Currency translation
adjustments - - - - (944,609) (944,609) (944,609)
Exercise of stock
options 160,000 1,600 165,275 - - 166,875 -
---------- -------- ----------- ------------ ----------- ----------- ----------
Comprehensive loss (250,622)
==========
June 30, 1997 24,851,245 248,512 43,410,176 (20,386,549) (3,729,205) 19,542,934
Net income - - - 1,036,513 - 1,036,513 1,036,513
Currency translation
Adjustments - - - - (3,283,734) (3,283,734) (3,283,734)
Exercise of stock
Options 131,250 1,313 122,062 - - 123,375 -
---------- -------- ----------- ------------ ----------- ----------- ----------
Comprehensive loss (2,247,221)
==========
June 30, 1998 24,982,495 249,825 43,532,238 (19,350,036) (7,012,939) 17,419,088
Net income - - - 945,212 - 945,212 945,212
Currency translation
Adjustments - - - - 1,313,871 1,313,871 1,313,871
Exercise of stock
Options 125,731 1,257 54,368 - - 55,625 -
---------- -------- ----------- ------------ ----------- ----------- ----------
Comprehensive income 2,259,083
==========
June 30, 1999 25,108,226 $251,082 $43,586,606 $(18,404,824) $(5,699,068) $19,733,796
========== ======== =========== ============= ============ ===========
See accompanying notes.
MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended June 30,
1999 1998 1997
----------- ----------- -----------
Operating Activities:
Net income $ 945,212 $ 1,036,513 $ 693,987
Adjustments to reconcile net income to
net cash provided by operating activities:
Exploratory and dry hole costs 420,748 775,150 6,243,211
Depletion, depreciation and amortization 2,356,582 2,205,127 2,140,066
Deferred income taxes 206,141 (1,232,963) 637,130
Minority interests 1,677,797 1,681,255 2,166,525
Increase (decrease) in operating assets
and liabilities:
Accounts receivable (78,785) 1,058,967 1,082,939
Reimbursable development costs 103,461 145,024 (31,784)
Other assets (330,742) (97,483) (84,665)
Inventories 14,367 109,923 111,429
Accounts payable and accrued liabilities (442,159) 829,314 169,687
Income taxes payable 120,150 - (1,947,610)
----------- ----------- -----------
Net cash provided by operating activities 4,992,772 6,510,827 11,180,915
----------- ----------- -----------
Investing Activities:
Additions to property and equipment (4,679,109) (2,997,791) (5,305,699)
Marketable securities purchased (sold) 364,957 (256,180) (2,211,205)
----------- ----------- -----------
Net cash used in investing activities (4,314,152) (3,253,971) (7,516,904)
----------- ----------- -----------
Financing Activities:
Dividends to MPAL minority shareholders (686,567) (1,506,103) (1,778,622)
Exercise of stock options 55,625 123,375 166,875
----------- ----------- -----------
Net cash used in financing activities (630,942) (1,382,728) (1,611,747)
----------- ----------- -----------
Effect of exchange rate changes on cash
and cash equivalents 896,724 (2,380,693) (388,359)
----------- ----------- -----------
Net increase (decrease) in cash and cash
equivalents 944,402 (506,565) 1,663,905
Cash and cash equivalents at beginning of year 12,436,297 12,942,862 11,278,957
----------- ----------- -----------
Cash and cash equivalents at end of year $13,380,699 $12,436,297 $12,942,862
=========== =========== ===========
See accompanying notes.
MAGELLAN PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
1. Summary of significant accounting policies
Principles of consolidation
The accompanying consolidated financial statements include the accounts
of Magellan Petroleum Corporation ("MPC") and its subsidiaries, hereafter
referred to collectively as the "Company". All intercompany transactions have
been eliminated. At June 30, 1999 and 1998, MPC owned a 50.9% and 50.7%
interest, respectively, in Magellan Petroleum Australia Limited ("MPAL"). During
fiscal 1999, MPC increased its interest in MPAL by purchasing additional MPAL
shares for $112,000.
Revenue Recognition
The Company recognizes oil and gas revenue from its interests in
producing wells as oil and gas is produced and sold from those wells. Oil and
gas sold is not significantly different from the Company's share of production.
Revenues from the purchase, sale and transportation of natural gas are
recognized upon completion of the sale and when transported volumes are
delivered.
Oil and Gas Properties
Oil and gas properties are located in Australia, Canada, Belize and the
United States. 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 and productive leases are capitalized and amortized
on a unit-of-production basis over the life of the related reserves. Cost
centers for amortization purposes are determined on a field-by-field basis.
Estimated future abandonment and site restoration costs, net of anticipated
salvage values, are accrued based on units of production. 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 and requires an impairment provision or noncash charge against
earnings for any quarter in which their carrying value exceeds the standardized
measure of undiscounted future net cash flows from proved oil and gas reserves
based on prices received for oil and gas production as of the end of that
quarter or a subsequent date prior to publication of financial results for the
quarter.
MAGELLAN PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
1. Summary of significant accounting policies (Cont'd)
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.
Use of Estimates
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the amounts reported in the financial statements and
accompanying notes. Actual results could differ from those estimates.
Land, buildings and equipment and field equipment
Land, buildings and equipment and field equipment are carried at cost.
Depreciation and amortization are provided on a straight-line basis over their
estimated useful lives. The estimated useful lives are: buildings - 40 years,
equipment and field equipment - 3 to 15 years.
Inventories
Inventories consist of crude oil in various stages of transit to the
point of sale and are valued at the lower of cost (determined on an average cost
basis) or market.
Foreign currency translations
The accounts of the Company's Australian subsidiaries are translated
into U.S. dollars in accordance with Statement of Financial Accounting Standards
No. 52. The translation adjustment is included as a component of stockholders'
equity and comprehensive income (loss), whereas gain or loss on foreign currency
transactions is 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 a quarterly weighted
average exchange rate for the period. At June 30, 1999 and 1998, the Australian
dollar was equivalent to U.S.$.6675, and $.6194, respectively.
1. Summary of significant accounting policies (Cont'd)
Recently issued accounting standards
As of July 1, 1998, the Company adopted Statement 130, Reporting
Comprehensive Income. Statement 130 establishes new rules for the reporting and
display of comprehensive income and its components; however, the adoption of
this Statement had no impact on the Company's net income or shareholders'
equity. Statement 130 requires unrealized gains or losses on the Company's
available-for-sale securities and foreign currency translation adjustments to be
included in other comprehensive income. Prior to the adoption of Statement 130,
these items were reported separately in stockholders' equity. Prior year
financial statements have been reclassified to confirm to the requirements of
Statement 130.
For the year ended June 30, 1999, the Company adopted SFAS No. 132,
Employers' Disclosures about Pension and Other Postretirement Benefits. This
Statement revises employers' disclosures about pension plans, but does not
result in any financial impact. SFAS No. 132 standardizes the disclosure
requirements for pensions benefits to the extent practicable, requires
additional information on changes in the benefits obligations and fair values of
plan assets that will facilitate financial analysis, and eliminates certain
disclosures (see Note 10 of Notes to Financial Statements).
In June 1998, FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS No. 133"). SFAS No. 133 provides a
comprehensive and consistent standard for the recognition and measurement of
derivatives and hedging activities. The statement requires all derivatives to be
recognized on the balance sheet at fair value and establishes standards for the
recognition of changes in such fair value. SFAS No. 133 is effective for the
Company's 2001 fiscal year. Because the Company does not currently use
derivatives, the adoption of SFAS No. 133 will not have a significant effect on
earnings or the financial condition of the Company.
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.
1. Summary of significant accounting policies (Cont'd)
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,
-----------------------------
1999 1998
----------- -----------
Cash $ 132,589 $ 23,460
U.S. marketable securities 1,087,601 1,085,137
Australian money market accounts and short
term commercial paper 12,160,509 11,327,700
----------- -----------
$13,380,699 $12,436,297
=========== ===========
Marketable securities
At June 30, 1999 and 1998, the Company has the following marketable
securities which are expected to be held until maturity:
Amortized
June 30, 1999 Par value Maturity Date Cost Fair value
Short-term securities
Federal National Mortgage Association $ 400,000 Jul. 15, 1999 $ 392,973 $ 399,258
========== ========== ==========
Long-term securities
Federal National Mortgage Association $ 400,000 Feb. 16, 2001 $ 400,000 $ 395,560
New Britain Connecticut Bond 335,000 May 1, 2001 335,417 330,578
State of Connecticut Bond 550,000 Jan. 15, 2003 557,747 540,337
State of Connecticut Bond 400,000 Jul.1, 2003 416,291 396,224
---------- ---------- ----------
$1,685,000 $1,709,455 $1,662,699
========== ========== ==========
June 30, 1998
Short-term securities
Federal Home Loan Bank $1,300,000 Nov. 10, 1998 $1,265,495 $1,265,496
========== ========== ==========
Long-term securities
Federal National Mortgage Association $ 375,000 May 3, 2000 $ 375,000 $ 374,063
Federal National Mortgage Association 465,000 Aug. 25, 2000 465,000 463,256
Federal Home Loan Mortgage Corporation 360,000 Apr. 2, 2001 361,890 361,688
---------- ---------- ----------
$1,200,000 $1,201,890 $1,199,007
========== ========== ==========
1. Summary of significant accounting policies (Cont'd)
Earnings per share
Earnings per common share is 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 was computed using the treasury stock method. The Company's
basic and diluted calculations of EPS are the same.
Financial instruments
The carrying value for cash and cash equivalents, accounts receivable,
marketable securities and accounts payable approximates fair value based on
anticipated cash flows and current market conditions.
Segment Disclosure
FASB Statement No. 131 requires the disclosure of certain financial
data based on an entity's operating segments. The Company's two operating
segments are MPC and MPAL. Condensed financial statements of these segments are
included in Notes 3 and 4 and additional segment data are included in Note 11.
2. Oil and gas properties
(a) Australia
Mereenie
MPAL (35%) and Santos (65%), the operator, (together known as the
Mereenie Participants) own the Mereenie field which is located in the Amadeus
Basin of the Northern Territory. MPAL's share of production from the field is
subject to net overriding royalties aggregating 3.0625% and the statutory
government royalty of 10%. MPAL's share of the Mereenie field proved developed
oil reserves was approximately 730,000 barrels at June 30, 1999.
2. Oil and gas properties (Cont'd)
The field was producing about 1,700 (MPAL share - 595) barrels of crude
oil per day ("bpd") at June 30, 1999. During 1999, MPAL's share of oil sales was
236,000 barrels and 3.4 billion cubic feet ("bcf") of gas sold from 41 oil and
gas wells. The oil is transported by means of a 167 mile eight-inch oil pipeline
from the field to the Brewer Estate industrial park near Alice Springs. Most of
the oil is then shipped south approximately 950 miles by rail and road to a
refinery in the Adelaide area. The cost of transporting the oil to the refinery
is being borne by the producers. The Mereenie Participants are also providing
Mereenie gas in the Northern Territory to the Power and Water Authority ("PAWA")
and Gasgo Pty. Ltd., a company it wholly owns, for use in Darwin and other
Northern Territory centers. See "Gas Supply Contracts".
During 1999, the Mereenie Participants had been negotiating for the
sale of Liquid Petroleum Gas from the field to a purchaser but the project was
terminated after it was determined that it was uneconomic.
Palm Valley
MPAL has a 50.8% interest in and is the operator of the Palm Valley gas
field which is located in the Northern Territory. Santos, the operator of the
Mereenie field, owns a 48% interest in Palm Valley. Ten wells have been drilled
in the field, five of which are currently connected to the gas treatment plant
and are flowed at maximum deliverability levels to meet the Alice Springs and
Darwin supply contracts with PAWA. See "Gas Supply Contracts". During fiscal
1999, MPAL's share of gas sales was 3.7 bcf. In order to increase
deliverability, field compression began in November 1996 with two 400 HP
compressors. A third 800 HP compressor was installed during fiscal 1999. MPAL
has recommended that four additional wells be drilled at Palm Valley to improve
the field's production capacity. Under the gas supply agreement with PAWA, the
costs of these wells are reimbursed by PAWA and, consequently, the
recommendation is under review by PAWA's consultants.
MPAL's share of Palm Valley production revenues is subject to a 10%
statutory government royalty and net overriding royalties aggregating 4.2548%.
2. Oil and gas properties (Cont'd)
Gas Supply Contracts
In 1983, the Palm Valley Participants commenced the sale of gas to
Alice Springs under a 1981 agreement. In 1985, the Palm Valley Participants and
Mereenie Participants signed agreements for the sale of gas to PAWA for use in
PAWA's 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 following is a summary of MPAL's interest in the Palm Valley and the
Mereenie gas supply contracts:
Maximum contract
(balance/after royalties) Percentage of
contract completed Contract Period
(bcf)
Palm Valley:
Alice Springs (1981) 9.6 54 25 years (1983-2008)
Darwin (1985) 43.8 43 25 years (1987-2012)
----
53.4
Mereenie:
Darwin (1985) 8.6 43 25 years (1987-2012)
Darwin (1995) - 100 10 years (1995-2005)
Darwin (1997) 18.4 - 10 years (1999-2009)
Other .7 - Various
------
27.7
Total 81.1
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.
In consideration for the Palm Valley Participants forgoing 20% of the
Amadeus Basin to Darwin gas supply contract during the first 20 contract years,
Mereenie Participants made a payment to the Palm Valley Participants to
partially compensate the Palm Valley Participants for the reduced net present
value of the future gas sales revenues which were postponed from contract years
1 to 20 to contract years 21 to 26. The agreement also provides that when the
Mereenie Participants sell any additional gas from the Mereenie field, the Palm
Valley Participants are entitled, as additional consideration, to 35% of the
revenues from the first 38 bcf (MPAL share - 19.5 bcf) of gas sold. At June 30,
1999, the balance of the Mereenie Participants gas subject to this entitlement
was 9.7 bcf (MPAL share - 4.8 bcf).
2. Oil and gas properties (Cont'd)
At June 30, 1999, the Company had accrued $849,000 for future site
restoration costs for the Mereenie and Palm Valley fields. The balance of the
estimated liability is $3,246,000 at June 30, 1999 which will be accrued over
the remaining life of the related reserves based on units of production.
Dingo Gas Field
MPAL has a 34.3% interest in the Dingo gas field which is held under
Retention License 2 and is subject to renewal in 2003. The Dingo gas field,
which is located in the Amadeus Basin in the Northern Territory, has
approximately 25 bcf of presently proved and recoverable reserves based on four
delineation wells. Dingo 2 and Dingo 3 wells are estimated to have the capacity
of producing a combined rate of 5 million cubic feet ("mmcf") per day. MPAL's
share of potential production from these permit areas is subject to a 10%
statutory government royalty and overriding royalties aggregating 2.5043%.
Ngalia Basin
MPAL had a 40% interest in permit EP-15 in the Ngalia basin in the
Northern Territory which expired during May 1999. During July 1998, the Newhaven
well was plugged and abandoned. MPAL's share of the drilling costs incurred
through June 30, 1998 were included in exploratory and dry hole costs for the
1998 fiscal year. The costs to drill the well subsequent to June 30, 1998 in the
amount of $316,000 are included in exploratory and dry hole costs for fiscal
1999.
Northern Surat Basin
During fiscal 1998, MPAL sold its 15.625% interest in ATP 378P
Queensland, Australia to its partner, Santos. The $636,000 difference between
the carrying cost and the sale price was included in loss on the sale of assets
for the 1998 fiscal year.
Surat Basin
During the 1998 fiscal year, MPAL earned a 17% interest in Block D of
ATP 244P in Queensland by completing a pilot seismic reprocessing program.
During the 1999 fiscal year, MPAL abandoned its interest in the permit.
During fiscal 1998, MPAL earned a 15% interest in ATP 626P in
Queensland. During fiscal 1999, MPAL relinquished its interest in the permit.
2. Oil and gas properties (Cont'd)
Timor Sea
During April 1998, MPAL acquired a 5% interest in Exploration Permit
WA-199-P in the Bonaparte Basin in the Timor Sea offshore Western Australia.
MPAL earned its interest in the permit by funding 10% of the cost of drilling
the Kittiwake-1 well which was a dry hole. MPAL's cost of the well was written
off in the fourth quarter of fiscal 1998 and was included in exploratory and dry
hole costs. MPAL relinquished its interest in the permit during the 1999 fiscal
year.
Browse Basin
During the 1999 fiscal year, MPAL was granted a 17.5% interest in
exploration permits WA-281-P, WA-282-P and WA-283-P in the Browse Basin offshore
Western Australia. During the 1999 fiscal year, MPAL spent approximately $67,000
toward the Year 1 work obligations. MPAL's share of the work obligations for the
three permits is as follows:
WA-281-P WA-282-P WA-283-P Total
Year 1 $ 368,000 $ 286,000 $ 286,000 $ 940,000
Year 2 713,000 111,000 111,000 935,000
Year 3 1,320,000 23,000 1,203,000 2,546,000
---------- ---------- ---------- ----------
Total Years 1-3 $2,401,000 $ 420,000 $1,600,000 $4,421,000
========== ========== ========== ==========
Year 4 187,000 23,000 187,000 397,000
======= ====== ======= =======
Year 5 1,437,000 1,308,000 1,437,000 4,182,000
========= ========= ========= =========
Year 6 35,000 23,000 35,000 93,000
========== ========== ========== ==========
Total Year 4-6 $1,659,000 $1,354,000 $1,659,000 $4,672,000
========== ========== ========== ==========
Total All Years $4,060,000 $1,774,000 $3,259,000 $9,093,000
========== ========== ========== ==========
During January 1999, MPAL was granted exploration blocks WA-287-P and
WA-288-P in the Eastern Browse Basin offshore Western Australia. During the 1999
fiscal year, MPAL spent approximately $54,000 toward the Year 1 work
obligations. The following exploration program was submitted to obtain the
blocks with the exploration expenditures in Years 1-3 obligatory and Years 4-6
discretionary:
Year WA-287-P WA-288-P Total
---- -------- -------- -----
1 $ 67,000 $ 120,000 $ 187,000
2 134,000 334,000 468,000
3 134,000 134,000 268,000
---------- ---------- -----------
Total Years 1-3 335,000 588,000 923,000
---------- ---------- -----------
4 2,336,000 2,336,000 4,672,000
5 167,000 167,000 334,000
6 2,336,000 2,336,000 4,672,000
---------- ---------- -----------
Total Years 4-6 4,839,000 4,839,000 9,678,000
---------- ---------- -----------
Total All Years $5,174,000 $5,427,000 $10,601,000
========== ========== ===========
2. Oil and gas properties (Cont'd)
Carnarvon Basin
MPAL earned a 15% interest in exploration permits TP/12 and EP398 in
the Carnarvon Basin offshore Western Australia by funding 30% of the cost of
drilling the Springbok-1 well. The Springbok-1 well was plugged and abandoned
during August 1998. MPAL's cost of drilling the well was written off during the
first quarter of fiscal 1999.
During April 1999, MPAL was awarded permit WA-291-P, offshore Western
Australia in the Carnarvon Basin. The minimum expenditure obligations for the
first three year period totals $347,000. The discretionary commitment for years
4-6 totals approximately $4.8 million.
Maryborough Basin
MPAL holds a 98% interest in exploration permit ATP 613P, a 670,000
acre block, in the Maryborough Basin in Queensland, Australia.
Cooper Basin
During April 1999, MPAL (50%) and its partner Beach Petroleum NL were
successful in bidding for two exploration blocks in South Australia's Cooper
Basin. The formal grant of the permit is pending. MPAL's share of the work
obligations during the five year period of the permit are as follows:
Year CO98I CO98J Total
---- ----- ----- -----
1 $ 534,000 $ 668,000 $1,202,000
2 334,000 401,000 735,000
3 234,000 300,000 534,000
---------- ---------- ----------
Total Years 1-3 1,102,000 1,369,000 2,471,000
---------- ---------- ----------
4 67,000 367,000 434,000
5 234,000 300,000 534,000
---------- ---------- ----------
Total Years 4-5 301,000 667,000 968,000
---------- ---------- ----------
Total All Years $1,403,000 $2,036,000 $3,439,000
========== ========== ==========
2. Oil and gas properties (Cont'd)
(b) Canada
The Company has a 2.67% carried interest in the Kotaneelee gas field
in the Yukon Territory which has been on production since February 1991. There
are two wells capable of production in the field which is part of a permit
covering 31,885 gross acres. For financial statement purposes in fiscal 1987 and
1988, the Company wrote down its Canada cost center, which included 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. Although the field is now producing, the Company has
not yet classified its share of the Kotaneelee gas reserves as proved because
the gas field is still the subject of litigation. The Company will reclassify
the reserves at the Kotaneelee field as proved when there is greater assurance
as to the timing and assumptions regarding the investment. Projections by the
operator of the field, indicate that the carried interest account may reach
payout status prior to December 1999.
(c) United States
Baca County, Colorado
MPC (10%) and MPAL (90%) participated in an exploration program in
Colorado. During 1995, MPAL commenced a three well drilling program. All three
wells were dry holes. During fiscal 1995 and 1996, the Company wrote off
$809,000 and $1,691,000 in costs, respectively. During fiscal 1997, the Company
drilled a fourth well which was a dry hole and all of the remaining costs of the
project, which totaled $3,008,000, were written off. During fiscal 1999, MPAL
spent approximately $16,000 on the project and it is allowing most of the leases
to expire.
Tapia Canyon, California
Effective December 1, 1997, MPC acquired a 20% interest in a heavy oil
recovery project in Tapia Canyon, California. Because the Company was
dissatisfied with the program to develop the field reserves, the Company has
sold its interest for its approximate cost of $101,000 effective August 31,
1999.
2. Oil and gas properties (Cont'd)
Stephens County, Texas
During fiscal 1999, MPC participated (20%) in the drilling of the
Puckett No. 1 well which is presently suspended. There are indications of oil
and additional work will be performed during September 1999. During late June
1999, MPC also participated (21.4%) in the drilling of the Smith No. 1 well
which also has indications of oil. MPC's capitalized costs at June 30, 1999
totaled $71,000.
(d) Belize
Southern Offshore Block PSA
During March 1998, MPC (3%), MPAL (20%) and the other joint venture
participants entered into a new Production Sharing Agreement ("PSA") with the
Government of Belize. The new Southern Offshore Block PSA ("SOB PSA") combines
most of the blocks previously included in the Gladden PSA and the Block 13 PSA,
and totals approximately 893,000 acres. The work obligations of the new PSA are
as follows: Year 1 - $100,000, Year 2 - $300,000, Year 3 - $3,000,000 and Year 4
- - $150,000. The participants in the PSA have been seeking partners in the
venture. The first year obligations have been completed and the participants are
negotiating with the Government of Belize to reduce the Year 2 obligations.
Gladden Basin PSA/Block 13 PSA
During 1997, the Gladden No. 1 well was plugged and abandoned and the
Company's cost of the well was written off. During March 1998, this block was
consolidated into the SOB PSA.
MPC and MPAL were also participants in a Production Sharing Agreement
("Block 13 PSA") offshore Belize adjoining the western and southern boundaries
of the Gladden PSA. The Block 13 PSA covered approximately 788,000 acres. During
March 1998, this block was consolidated into the SOB PSA.
3. MPC condensed financial statements
The following are unconsolidated condensed balance sheets and
statements of income and cash flows of MPC (in thousands).
MAGELLAN PETROLEUM CORPORATION
BALANCE SHEETS
June 30,
1999 1998
-------- --------
ASSETS
Current assets $ 1,684 $ 2,691
Other assets 1,992 1,202
Oil and gas properties - net 171 126
Investment in MPAL 15,957 13,497
------- -------
Total assets $19,804 $17,516
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ 70 $ 97
------- -------
Stockholders' equity:
Capital 43,838 43,782
Accumulated deficit (18,405) (19,350)
Accumulated other comprehensive loss (5,699) (7,013)
-------- --------
Total stockholders' equity 19,734 17,419
------- -------
Total liabilities and stockholders' equity $19,804 $17,516
======= =======
MAGELLAN PETROLEUM CORPORATION
STATEMENTS OF INCOME
Year ended June 30,
------------------------------------
1999 1998 1997
------- ------- --------
Revenues $ 190 $ 175 $ 122
Costs and expenses (879) (863) (1,376)
------- ------- --------
Loss before income taxes (689) (688) (1,254)
Income tax provision 105 1 276
------ ------ -------
Loss before equity in MPAL (794) (689) (1,530)
Equity in MPAL net income 1,739 1,726 2,224
------ ------ -------
Net income $ 945 $1,037 $ 694
====== ====== =======
3. MPC condensed financial statements (Cont'd)
MAGELLAN PETROLEUM CORPORATION
STATEMENTS OF CASH FLOWS
Year ended June 30,
----------------------------
1999 1998 1997
------ ------ ------
Operating Activities:
Net income $ 945 $1,037 $ 694
Adjustments to reconcile net income
to net cash used in operating activities:
Abandonments 47 - 598
Equity in MPAL income (1,739) (1,726) (2,224)
Change in operating assets and liabilities:
Accounts receivable (37) (59) (57)
Accounts payable and accrued liabilities (27) 79 (73)
------ ------ ------
Net cash used in operating activities (811) (669) (1,062)
------ ------ ------
Investing Activities:
Additions to property and equipment (92) (79) (363)
Marketable securities purchased (sold) 365 (256) (2,211)
Purchase of MPAL shares (112) - -
------ ------ ------
161 (335) (2,574)
------ ------ ------
Financing Activities:
Dividends from MPAL 705 1,546 1,826
Exercise of stock options 56 122 167
------ ------ ------
761 1,668 1,993
------ ------ ------
Net increase (decrease) in cash and
cash equivalents 111 664 (1,643)
Cash and cash equivalents at beginning of year 1,088 424 2,067
------ ------ ------
Cash and cash equivalents at end of year $1,199 $1,088 $ 424
====== ====== ======
4. MPAL transactions and condensed financial statements
The following are the condensed consolidated balance sheets and
consolidated statements of income of MPAL (in thousands). At June 30, 1999,
Santos Ltd. held 18.2% of MPAL and Boral Limited held 17.1% with the balance of
13.8% held by approximately 2,000 shareholders in Australia.
4. MPAL transactions and condensed financial statements (Cont'd)
The condensed consolidated financial statements have been prepared in
accordance with U.S. generally accepted accounting principles and include all of
MPAL's subsidiaries.
Magellan Petroleum Australia Limited
Consolidated Balance Sheets
June 30,
------------------------
1999 1998
------- -------
ASSETS
Current assets $13,832 $12,866
Oil and gas properties - net 25,313 21,887
Land, building and equipment - net 1,073 885
------- -------
Total $40,218 $35,638
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ 2,202 $ 2,628
------- -------
Long term liabilities 7,005 6,606
------- -------
Stockholders' equity:
Capital 34,408 34,408
Retained earnings 6,890 4,865
Accumulated other comprehensive loss (10,287) (12,869)
------- -------
31,011 26,404
------- -------
Total $40,218 $35,638
======= =======
4. MPAL transactions and condensed financial statements (Cont'd)
Magellan Petroleum Australia Limited
Consolidated Statements of Income
Year ended June 30,
--------------------------------
1999 1998 1997
-------- -------- --------
Revenues $13,925 $15,165 $20,636
Costs and expenses 10,666 11,615 15,079
-------- -------- --------
Income before income taxes 3,259 3,550 5,557
Income tax provision (benefit) (158) 143 1,166
-------- -------- --------
Net income $ 3,417 $ 3,407 $ 4,391
======== ======== ========
Magellan and Minority Equity in MPAL
Magellan equity interest in MPAL:
Magellan equity in net income $ 1,739 $ 1,726 $ 2,224
======== ======== ========
Minority equity interest in MPAL:
Minority interest in net income $ 1,678 $ 1,681 $ 2,166
Other comprehensive income (loss) 1,203 (3,198) (922)
Dividends paid (687) (1,506) (1,779)
-------- -------- --------
Total minority interest increase (decrease) $ 2,194 $ (3,023) $ (535)
======== ========= =========
5. Capital and stock options
The Company's Certificate of Incorporation provides that any matter to
be voted upon must be approved not only by a majority of the shares voted, but
also by a majority of the stockholders casting votes present in person or by
proxy and entitled to vote thereon.
On October 5, 1989, the Company adopted a Stock Option Plan covering
one million shares of the Company's common stock. The 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. On December 3, 1997, the Board of
Directors approved a new stock option plan for an additional one million shares
which was approved at the 1998 Annual Meeting of Stockholders.
At June 30, 1999, all of the stock options outstanding were vested and
exercisable. Options to purchase 146,000 shares expire on October 20, 2003 and
options to purchase 50,000 (which were repriced from $2.75 to $1.57, the fair
value on the date of repricing) shares expire on September 25, 2001. During
fiscal 1999, options to purchase 175,000 shares of common stock were exercised
in a cashless exchange which resulted in the issuance of 75,731 shares.
Following is a summary of option transactions for the three years ended June 30,
1999:
Options outstanding Number of shares Exercise Prices ($)
July 1, 1996 516,250 .75 - 1.0625
Granted 50,000 2.75
Exercised (150,000) 1.0625
Exercised (10,000) .75
----------
June 30, 1997 406,250 .8125-2.75
Exercised (131,250) .94
June 30, 1998 275,000 .8125 - 2.75
--------
Granted 146,000 1.57
Exercised (225,000) .8125
---------
June 30, 1999 196,000 1.57
========
($1.57 weighted average)
Options reserved for future grants 1,000,000
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 because the alternative fair
value accounting provided under FASB Statement No. 123, "Accounting for Stock
Based Compensation," requires use of option valuation models that were not
developed for use in valuing stock options. Under APB No. 25, because the
exercise price of the Company's stock options equals the market price of the
underlying stock on the date of grant, no compensation expense is recognized.
5. Capital and stock options (Cont'd)
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, 1999.
Pro forma information regarding net income and earnings per share is
required by Statement 123, and 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.
Option valuation models require the input of highly subjective
assumptions including the expected stock price volatility. The assumptions used
in the 1997 valuation model were: risk free interest rate - 6.55%, expected life
- - 5 years, expected volatility - .579, expected dividend - 0. The assumptions
used in the 1999 valuation model were: risk free interest rate - 4.45%, expected
life - 5 years, expected volatility - 1.0, expected dividend - 0. Because the
Company's stock options have characteristics significantly different from those
of traded options, and because changes in the subjective input assumptions can
materially affect the fair value estimate, in management's opinion, the existing
models do not necessarily provide a reliable single measure of the fair value of
its stock options.
For the purpose of pro forma disclosures, the estimated fair value of
the stock options is expensed in the year of grant since the options are
immediately exercisable. The Company's pro forma information follows:
Amount Per Share
Net income as reported - June 30, 1997 $ 694,000 $ .03
Stock option expense (78,000) -
---------- ------
Pro forma net income - June 30, 1997 $ 616,000 $ .03
========= ======
Net income as reported - June 30, 1999 $ 945,000 $ .04
Stock option expense (200,000) (.01)
---------- -------
Pro forma net income - June 30, 1999 $ 745,000 $ .03
========= ======
6. Income taxes
(a) Components of pretax income (loss) by geographic area (in thousands)
are as follows:
Year ended June 30,
-------------------------------
1999 1998 1997
------- ------- --------
United States $ (743) $ (850) $(4,547)
Foreign 3,314 3,712 8,850
------ ------ -------
Total $2,571 $2,862 $ 4,303
====== ====== =======
(b) 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:
Year ended June 30,
----------------------------
1999 1998 1997
------- ------- -------
Pretax consolidated income $2,571 $2,862 $4,303
Losses not recognized:
MPC's operations 689 689 1,254
MPAL's nonAustralian operations - - (145)
Permanent differences (1,231) (2,443) (2,040)
------- ------- -------
Book taxable income - Australia $2,029 $1,108 $3,372
====== ====== ======
Australian tax rate 36% 36% 36%
=== === ===
Australian income tax $ 722 $ 399 $1,214
Tax (benefit) attributable to reconciliation of
Year end deferred tax liability (879) (256) (48)
------- ------- -------
MPAL Australian tax (benefit) $ (157) $ 143 $1,166
MPC income tax 105 1 276
------- ------ ------
Consolidated income tax (benefit) $ (52) $ 144 $1,442
======= ====== ======
Current income tax $ 225 $ 1 $ 276
Deferred income tax (277) 143 1,166
------- ------ ------
Consolidated income tax (benefit) $ (52) $ 144 $1,442
======= ====== ======
Effective tax rate (2%) 5% 34%
==== == ===
The amount of $6,060,000 and $5,854,000 in deferred income tax
liability at June 30, 1999 and June 30, 1998, respectively, relates primarily to
the deduction of acquisition and development costs which are capitalized for
financial statement purposes. The 1999 and 1998 credits of $879,000 and $255,000
represent the tax benefit of prior years' losses previously not taken into
account.
6. Income taxes (Cont'd)
(c) United States
On June 30, 1999, the Company had approximately $16,408,000 and
$3,538,000 of net operating loss carryforwards for federal and state income tax
purposes, respectively, which are scheduled to expire periodically between the
years 2000 and 2019. The Company also has approximately $887,000 of foreign tax
credit carryovers, which are scheduled to expire periodically between the years
2000 and 2004. For financial reporting purposes, a valuation allowance has been
recognized to offset the deferred tax assets related to those carryforwards and
other temporary differences. Significant components of the Company's deferred
tax assets were as follows:
June 30, June 30,
1999 1998
------------ ------------
Net operating losses $ 4,223,000 $ 4,075,000
Foreign tax credits 887,000 1,004,000
Interest 214,000 214,000
Intangible drilling costs - 7,000
------------ ------------
Total deferred tax assets 5,324,000 5,300,000
Valuation allowance (5,324,000) (5,300,000)
------------ ------------
Net deferred tax assets $ - $ -
============ ============
7. Bank loan
MPAL has a $6.7 million line of credit with an Australian bank at the
bank's prime rate of interest (4.9% at June 30, 1999, and 5.2% at June 30, 1998)
plus .5%. This line of credit is unsecured and expires December 31, 1999. In
addition, there is an annual fee of A.$30,000 payable with respect to the line
of credit. At June 30, 1999 and 1998, the line of credit was not being utilized.
8. Related party and other transactions
G&O'D INC, a firm that provides accounting and administrative services,
office facilities and support staff to the Company, was paid $235,028, $248,174
and $211,088 in fees for fiscal years 1999, 1998 and 1997, respectively. James
R. Joyce, the President and Chief Financial Officer, is the owner of G&O'D INC.
Mr. Timothy L. Largay, a director of the Company since February 1996, is a
member of the law firm of Murtha, Cullina, Richter and Pinney LLP, which firm
was paid fees of $44,860, $36,366 and $29,004 for fiscal years 1999, 1998 and
1997, respectively. In addition, Mr. Heath, a director, has overriding royalty
interests which were granted between 1957 and 1968 on certain of the Company's
oil and gas properties prior to any discoveries. The following gross royalty
amounts represent payments by all of the owners of the fields, not just the
Company's share. The payments to Mr. Heath with respect to these royalties in
fiscal 1999 were $44,469, in fiscal 1998 were $46,044 and in fiscal 1997 were
$54,252.
9. Leases
At June 30, 1999, future minimum rental payments applicable to MPAL's
noncancelable operating (office) lease were as follows:
Fiscal Year Amount
2000 $100,000
2001 105,000
2002 110,000
2003 130,000
2004 136,000
--------
Total $581,000
The information regarding the rental expense for all operating leases
is included in Note 13.
10. Pension Plan
MPAL maintains a defined benefit pension plan and contributes to the
plan at rates which (based on actuarial determination) are sufficient to meet
the cost of employees' retirement benefits. No employee contributions are
required. MPAL is committed to make up any shortfall in the plan's assets to
meet payments to employees as they become due. Plan participants are entitled to
defined benefits on normal retirement, death or disability.
The following table sets forth the actuarial present value of benefit
obligations and funded status for the MPAL pension plan:
June 30,
1999 1998
---------- ----------
Change in Benefit Obligation
Benefit obligation at beginning of year $2,412,353 $2,639,716
Service cost 207,386 186,819
Interest cost 137,739 135,945
Actuarial gains and losses 61,692 124,542
Benefits paid (87,691) (142,208)
Taxes on contributions (43,022) (27,566)
Expenses (41,707) (34,242)
Foreign currency effect 187,334 (470,653)
---------- ----------
Benefit obligation at end of year $2,834,084 $2,412,353
========== ==========
Change in Plan Assets
Fair value of plan assets at beginning of year $2,974,283 $3,311,309
Actual return on plan assets 232,262 253,429
Contributions by employer 233,566 203,956
Benefits paid (87,691) (142,208)
Foreign currency effect 230,970 (590,395)
Other (expenses) (84,729) (61,808)
---------- ----------
Fair value of plan assets at end of year $3,498,661 $2,974,283
========== ==========
Reconciliation of Funded Status
Funded Status $ 664,577 $ 561,930
Unrecognized actuarial loss (gain) (148,469) (165,324)
Unrecognized prior service cost 238,530 185,646
---------- ----------
Prepaid benefit costs $ 754,638 $ 582,252
========== ==========
10. Pension Plan (Cont'd)
The net pension expense for the MPAL pension plan was as follows:
Year ended June 30,
-------------------------------------
1999 1998 1997
--------- --------- ---------
Service cost $217,154 $186,819 $242,014
Interest cost 140,517 135,945 200,995
Actual return on plan assets (186,932) (192,079) (246,904)
Net amortization and deferred items (29,694) (27,554) (18,472)
--------- --------- ---------
Net pension cost $141,045 $103,131 $177,633
======== ======== ========
Plan contributions by MPAL $220,000 $224,000 $275,000
======== ======== ========
Significant assumptions used in determining pension cost and the
related obligations were as follows:
1999 1998 1997
------ ------ ------
Assumed discount rate 6.0% 5.5% 6.5%
Rate of increase in future compensation levels 4.5% 4.0% 5.0%
Expected long term rate of return on plan assets 6.0% 6.5% 7.0%
Australian exchange rate $.6675 $.6194 $.7538
11. Segment information
The Company has two reportable segments, MPC and its 50.9% 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 Company's two operating
segments is as follows:
Year ended June 30,
----------------------------------
1999 1998 1997
-------- -------- --------
Revenues:
MPC $ 895 $ 1,721 $ 1,948
MPAL 13,925 15,165 20,636
Elimination of intersegment dividend (705) (1,546) (1,826)
-------- -------- --------
Total consolidated revenues $14,115 $15,340 $20,758
======= ======= =======
11. Segment information (Cont'd)
Year ended June 30,
------------------------------
1999 1998 1997
-------- -------- --------
Interest income:
MPC $ 183 $ 171 $ 122
MPAL 534 570 700
-------- -------- --------
Total consolidated $ 717 $ 741 $ 822
======== ======== ========
Net income:
MPC $ (89) $ 857 $ 296
MPAL 1,739 1,726 2,224
Elimination of intersegment dividend (705) (1,546) (1,826)
-------- -------- --------
Consolidated income $ 945 $ 1,037 $ 694
======== ======== ========
Assets:
MPC $ 19,804 $ 17,516 $ 19,561
MPAL 40,218 35,638 43,149
Equity elimination (15,788) (13,375) (16,480)
-------- -------- --------
Total consolidated assets $ 44,234 $ 39,779 $ 46,230
======== ======== ========
Other significant items:
Depletion, depreciation and amortization:
MPC $ - $ - $ -
MPAL 2,357 2,205 2,140
-------- -------- --------
Total consolidated $ 2,357 $ 2,205 $ 2,140
======== ======== ========
Exploratory and dry hole costs:
MPC 50 $ 32 $ 598
MPAL 2,009 3,314 5,645
-------- -------- --------
Total consolidated $ 2,059 $ 3,346 $ 6,243
======== ======== ========
Income tax expense (credit):
MPC $ 105 $ 1 $ 276
MPAL 157 143 1,166
-------- -------- --------
Total consolidated $ (52) $ 144 $ 1,442
========= ======== ========
12. Geographic information
As of each of the stated dates, the Company's revenue, operating
income, net income or loss and identifiable assets (in thousands) were
geographically attributable as follows:
Year ended June 30,
---------------------------------
1999 1998 1997
------- ------- -------
Revenue:
Australia $13,924 $15,148 $20,618
United States 191 192 140
------- ------- -------
$14,115 $15,340 $20,758
======= ======= =======
Operating income (loss):
Australia $ 3,144 $ 3,979 $10,195
Belize (351) (195) (2,584)
United States (46) (163) (2,862)
------- ------- -------
2,747 3,621 4,749
Corporate overhead and interest
net of other income (176) (759) (446)
------- ------- -------
Consolidated operating income before
income taxes and minority interests $ 2,571 $ 2,862 $ 4,303
======= ======= =======
Net income (loss):
Australia $ 1,945 $ 1,911 $ 5,212
Belize (178) (103) (1,320)
United States (822) (771) (3,198)
------- ------- -------
945 $ 1,037 $ 694
======= ======= =======
Identifiable assets:
Australia $40,218 $35,236 $42,516
Belize - 433 563
United States 169 17 70
------- ------- -------
40,387 35,686 43,149
Corporate assets 3,847 4,093 3,081
------- ------- -------
$44,234 $39,779 $46,230
======= ======= =======
Substantially all of MPAL's gas sales were to the Power and Water
Authority ("PAWA") of the Northern Territory of Australia ("NTA"). Most of
MPAL's crude oil production was sold to the Mobil Port Stanvac Refinery near
Adelaide.
13. Other financial information
Year ended June 30,
------------------------------------
1999 1998 1997
---------- ---------- ----------
Costs and expenses - Other
Consultants $ 160,684 $ 52,741 $ 108,552
Directors' fees and expense 200,373 181,466 173,832
Insurance 189,765 217,503 284,532
Interest expense 19,259 24,468 32,005
Rent 167,947 271,241 326,665
Taxes 158,925 218,467 234,960
Travel 145,046 219,172 233,044
Other (net of overhead reimbursements) (277,496) (228,126) (426,323)
---------- ---------- ----------
$ 764,503 $ 956,932 $ 967,267
========== ========== ==========
Royalty payments $1,224,149 $1,464,478 $1,930,011
========== ========== ==========
Interest payments $ 19,259 $ 24,468 $ 32,005
========== ========== ==========
Income tax payments $ 105,370 $ 1,000 $2,256,934
========== ========== ==========
14. Selected quarterly financial data (unaudited)
The following is a summary (in thousands) of the quarterly results of
operations for the years ended June 30, 1999 and 1998:
1999 QTR 1 QTR 2 QTR 3 QTR 4*
------- ------- ------- -------
($) ($) ($) ($)
Total revenues 3,200 3,570 3,319 4,026
Costs and expenses (3,398) (2,781) (3,332) (2,033)
Income tax (provision) benefit 53 (372) (98) 469
Minority interests (28) (358) (38) (1,254)
------- ------- ------- -------
Net income (loss) (173) 59 (149) 1,208
======= ======= ======= =======
Per share (basic & diluted) .01 - (.01) .05
=== === ===== ===
1998 QTR 1 QTR 2 QTR 3 QTR 4
------- ------- ------- -------
($) ($) ($) ($)
Total revenues 4,552 4,497 3,184 3,107
Costs and expenses (3,943) (2,858) (2,442) (3,235)
Income tax (provision) benefit (251) (520) (246) 873
Minority interests (288) (653) (324) (417)
------- ------- ------- -------
Net income 70 466 172 328
======= ======= ======= =======
Per share (basic & diluted) - .02 .01 .01
=== === === ===
*See Management's Discussion and Analysis of Financial Condition and Results of
Operations.
MAGELLAN PETROLEUM CORPORATION
SUPPLEMENTARY OIL AND GAS INFORMATION
(unaudited)
June 30, 1999
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 developed and proved oil and gas reserves:
Natural Gas Oil
(Bcf) (Thousand Bbls)
Proved Reserves: Australia Australia
(*)
June 30, 1996 79.670 1,201
Revision of previous estimates (.861) 65
Extensions and discoveries 22.946 -
Production (5.673) (307)
-------- -----
June 30, 1997 96.082 959
Revision of previous estimates (5.071) 204
Extensions and discoveries - -
Production (5.844) (248)
-------- -----
June 30, 1998 85.167 915
Revision of previous estimates .011 20
Extensions and discoveries 1.258 -
Production (5.898) (205)
------- -----
June 30, 1999 80.538 730
====== ===
Proved Developed Reserves:
June 30, 1996 79.670 1,201
====== =====
June 30, 1997 96.082 959
====== ===
June 30, 1998 85.167 915
====== ===
June 30, 1999 80.538 730
====== ===
- -------------------
(*) The amount of proved reserves applicable to the Palm Valley and Mereenie
fields only reflects the amount of gas committed to specific contracts.
Approximately 49.1% of reserves are attributable to minority interests at June
30, 1999 (49.3% for 1998 and 1997).
Costs of oil and gas activities (in thousands):
Australia
Exploration Development
Fiscal Year Costs Costs
1999 $1,648 $3,757
1998 3,196 3,474
1997 580 678
Americas
Exploration Acquisition
Fiscal Year Costs Costs
1999 $ 81 $ --
1998 150 79
1997 3,138 47
Capitalized costs subject to depletion, depreciation and amortization ("DD&A")
(in thousands):
June 30, 1999
Australia Americas Total
Costs subject to DD&A $49,456 $ - $49,456
Costs not subject to DD&A - 171 171
Less accumulated DD&A (22,902) - (22,902)
-------- ---- --------
Net capitalized costs $26,554 $171 $26,725
======= ==== =======
June 30, 1998
Australia Americas Total
Costs subject to DD&A $41,470 $ - $41,470
Costs not subject to DD&A - 499 499
Less accumulated DD&A (18,950) - (18,950)
-------- ---- --------
Net capitalized costs $22,520 $499 $23,019
======= ==== =======
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, 1999. Australia was the only cost center with proved
reserves. At June 30, 1999, approximately 49.1% (49.3% for 1998 and 1997) of the
reserves and the respective discounted future net cash flows are attributable to
minority interests.
Total
---------------------------------
1999 1998 1997
--------- --------- ---------
Future cash inflows $144,116 $136,828 $198,406
Future production costs (17,917) (17,441) (22,204)
Future development costs - (893) -
Future income tax expense (42,288) (40,429) (60,926)
--------- --------- ---------
Future net cash flows 83,911 78,065 115,276
10% annual discount for estimating timing
of cash flows (30,590) (29,813) (46,963)
--------- --------- ---------
Standardized measures of discounted future
net cash flows $ 53,321 $ 48,252 $ 68,313
======== ======== ========
The following are the principal sources of changes in the above
standardized measure of discounted future net cash flows (in thousands):
1999 1998 1997
-------- --------- --------
Net change in prices and production costs $ 952 $ (4,318) $18,300
Extensions and discoveries 1,123 - 29,530
Revision of previous quantity estimates (62) (6,675) (341)
Changes in estimated future development costs - (1,087) -
Sales and transfers of oil and gas produced (6,033) (8,849) (11,264)
Previously estimated development cost
incurred during the period 893 - -
Accretion of discount 3,966 5,623 3,535
Net change in income taxes 386 5,716 (12,604)
Net change in exchange rate 3,844 (10,471) (3,056)
------- --------- --------
$ 5,069 $(20,061) $24,100
======= ========= =======
Additional information regarding discounted future net cash flows:
Australia
Reserves - Natural Gas
Future net cash flows from net proved gas reserves in Australia were
based on MPAL's share of reserves in the Palm Valley and Mereenie fields which
have been limited to the quantities of gas committed to specific contracts.
Reserves and Costs - Oil
At June 30, 1999, 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, 1999. All of the crude oil reserves are
developed reserves. Undeveloped proved reserves have not been estimated since
there are only tentative plans to drill additional wells.
Income taxes
Future Australian income tax expense applicable to the future net cash
flows has been reduced by the tax effect of approximately A.$13,081,000,
A.$9,995,000 and A.$9,236,000 in unrecouped capital expenditures at 1999, 1998
and 1997, respectively. The tax rate in computing Australian future income tax
expense was 36%.
For financial statements purposes in fiscal 1987 and 1988, MPC wrote
down its Canada cost center which included the Kotaneelee gas 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.
Although the field is now producing, the Company has not yet classified its
share of the Kotaneelee gas reserves as proved because the gas field is still
the subject of litigation. The Company will reclassify the reserves at the
Kotaneelee field as proved when there is greater assurance as to the timing and
assumptions of the investment.
Results of Operations
The following are the Company's results of operations (in thousands)
for the oil and gas producing activities during the three years ended June 30,
1999:
Americas Australia
------------------------------------ ------------------------------------
1999 1998 1997 1999 1998 1997
-------- -------- -------- -------- -------- --------
Revenues:
Oil sales $ 7 $ 3 $ - $ 2,566 $ 4,095 $ 6,740
Gas sales - - - 9,640 10,485 11,552
Other production income - - - 1,180 632 1,512
-------- -------- -------- -------- -------- --------
Total revenues 7 3 - 13,386 15,212 19,804
-------- -------- -------- -------- -------- --------
Costs:
Production costs 14 5 - 4,358 3,642 4,811
Depletion, exploratory
and dry hole costs 410 151 3,008 3,905 5,937 2,605
-------- -------- -------- -------- -------- --------
Total costs 424 156 3,008 8,263 9,579 7,416
-------- -------- -------- -------- -------- --------
Income (loss) before taxes and
minority interest (417) (153) (3,008) 5,123 5,633 12,388
Income tax provision (36%) - - - (1,844) (2,028) (4,460)
-------- -------- -------- -------- -------- --------
Income before minority interests (417) (153) (3,008) 3,279 3,605 7,928
Minority interests* 177 74 1,327 (1,610) (1,779) (3,909)
-------- -------- -------- -------- -------- --------
Net income (loss) from
Operations $ 240 $ (79) $(1,681) $ 1,669 $ 1,826 $ 4,019
======== ======== ======== ======= ======= =======
Depletion per unit of
Production - - - A.$2.73 A.$2.30 A.$1.86
======== ======== ======== ======= ======= =======
* Minority interests 49.1% in 1999, 49.3 % in 1998 and 1997
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
None.
PART III
For information concerning Item 10 - Directors and Executive Officers
of the Company, Item 11 Executive Compensation, Item 12 - Security Ownership of
Certain Beneficial Owners and Management and Item 13 Certain Relationships and
Related Transactions, see the Proxy Statement of Magellan Petroleum Corporation
relative to the Annual Meeting of Stockholders for the fiscal year ended June
30, 1999, which will be filed with the Securities and Exchange Commission, which
information is incorporated herein by reference. For information concerning Item
10 - Executive Officers of the Company, see Part I.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a) (1) Financial Statements.
The financial statements listed below and included
under Item 8 are filed as part of this report. Page
reference
Report of Independent Auditors 38
Consolidated balance sheets as of June 30, 1999 and 1998 39
Consolidated statements of income for each of the three years
in the period ended June 30, 1999 40
Consolidated statements of changes in stockholders' equity for each
of the three years in the period ended June 30, 1999 41
Consolidated statements of cash flows for each of the three years
in the period ended June 30, 1999 42
Notes to consolidated financial statements 43-68
Supplementary oil and gas information (unaudited) 69-73
(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.
(3) Exhibits.
List of each management contract or compensatory or
arrangement required to be filed as an exhibit pursuant to Item 14(c).
(b) Reports on Form 8-K.
None.
(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.
(b) Copy of the By-Laws, as amended filed as exhibit
4(c) to Form S-8 Registration Statement, filed on
January 14, 1999 is incorporated herein by reference.
4. Instruments defining the rights of security holders,
including indentures.
None.
9. Voting Trust Agreement.
None.
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. is filed
herein.
(b) Petroleum Lease No. 5 dated November 18, 1981
granted by the Northern Territory of Australia to
Magellan Petroleum (N.T.) Pty. Ltd. is filed herein.
(c) Gas Sales Agreement between The Palm Valley
Producers and The Northern Territory Electricity
Commission dated November 11, 1981 is filed herein.
(d) Palm Valley Petroleum Lease (OL3) dated November
9, 1982 is filed herein.
(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 is filed herein.
(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 is filed herein.
(3) Copy of Modification to Agreement dated
May 28, 1959 (see (e)(1) above), made as of
January 31, 1961, is filed herein.
(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 is filed herein.
(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. is filed herein.
(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 are filed herein.
(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 are filed herein.
(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 are filed
herein.
(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. are filed herein.
(k) Agreement between the Mereenie Producers and the
Palm Valley Producers dated June 28, 1985 is filed
herein.
(l) Form of Agreement pursuant to Article SIXTEENTH
of the Company's Certificate of Incorporation and the
applicable By-Law to indemnify the Company's
directors and officers is filed herein.
(m) 1998 Stock Option Plan, filed as exhibit 4(a) to
Form S-8 Registration Statement on January 14, 1999,
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.
None.
18. Letter re change in accounting principles.
None.
21. Subsidiaries of the registrant.
Filed herein.
22. Published report regarding matters submitted to vote
of security holders.
Not applicable.
23. Consent of experts and counsel.
Consent of Ernst & Young LLP filed herein.
24. Power of attorney.
None.
27. Financial Data Schedule.
Filed herein (EDGAR filing only).
99. Additional Exhibits.
None.
(d) Financial Statement Schedules.
None.
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
/s/ James R. Joyce
James R. Joyce, President
Dated: September 15, 1999
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/ Benjamin W. Heath /s/ James R. Joyce
Benjamin W. Heath James R. Joyce
Director Director, President and Chief Executive
Officer, Chief Financial and Accounting
Officer
Dated: September 15, 1999 Dated: September 15, 1999
------------------------- ------------------------
/s/ Hedley Howard /s/ Walter McCann
Hedley Howard Walter McCann
Director Director
Dated: September 15, 1999 Dated: September 15, 1999
------------------------- ------------------------
/s/ Timothy L. Largay /s/ Ronald P. Pettirossi
Timothy L. Largay Ronald P. Pettirossi
Director Director
Dated: September 15, 1999 Dated: September 15, 1999
------------------------- ------------------------
INDEX TO EXHIBITS
Exhibit No.
10. (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.
(b) Petroleum Lease No. 5 dated November 18, 1981 granted
by the Northern Territory of Australia to Magellan
Petroleum (N.T.) Pty. Ltd.
(c) Gas Sales Agreement between The Palm Valley Producers and
The Northern Territory Electricity Commission dated
November 11, 1981
(d) Palm Valley Petroleum Lease (OL3) dated November 9, 1982
(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
(2) Copies of Supplementary Documents to May 28, 1959
Agreement (see (1) above), dated June 24, 1959,
consisting of Guarantee by Home Oil Company
Limited and Pipeline Promotion Agreement
(3) Copy of Modification to Agreement dated May 28,
1959 (see (1) above), made as of January 31, 1961
(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
(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.
INDEX TO EXHIBITS (Cont'd)
Exhibit No.
(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
(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.
(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.
(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.
(k) Agreement between the Mereenie Producers and the Palm
Valley Producers dated June 28, 1985
(l) Form of Agreement pursuant to Article SIXTEENTH of the
Company's Certificate of Incorporation and the applicable
By-Law to indemnify the Company's directors and officers
21. Subsidiaries of the Registrant
23. Consent of Independent Auditors
27. Financial Data Schedule (EDGAR filing only)