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:
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
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.
- ----------------------------
(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.
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.
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.
* 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.
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.
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
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.
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.
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
See accompanying notes.
MAGELLAN PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF INCOME
See accompanying notes.
MAGELLAN PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY Three years ended June 30, 1999
See accompanying notes.
MAGELLAN PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
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:
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:
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:
* Minority interests 49.1% in 1999, 49.3 % in 1998 and 1997
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
PART III
For information concerning Item 10
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)