EX-99.A.1.L 14 h97563e3exv99waw1wl.txt ANNUAL REPORT ON FORM 40-F Exhibit (a)(1)(l) U.S. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 40-F ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 COMMISSION FILE NUMBER 1-14698 GULF INDONESIA RESOURCES LIMITED (Exact name of Registrant as specified in its charter) NEW BRUNSWICK (Province or other jurisdiction of incorporation or organization) Wisma 46 - Kota BNI, Jalan Jenderal Sudirman Kavling 1, Jakarta 10220, Indonesia (Address of Registrant's principal executive office) Registrant's telephone number, including area code: 403-233-4000 CT CORPORATION SYSTEM, 111-8TH AVENUE, NEW YORK N.Y. 10011, (212) 590-9009 (Name, address (including zip code) and telephone number (including area code) of agent for service in the United States) Securities registered or to be registered pursuant to Section 12(b) of the Act. Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Shares New York Stock Exchange Securities registered or to be registered pursuant to Section 12(g) of the Act. None ------------------------------ (Title of Class) Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. None ------------------------------ (Title of Class) For annual reports, indicate by check mark the information filed with this Form: [X] Annual information form [X] Audited annual financial statements Page 1 of 55 Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report. 87,901350 Common Shares Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "YES" is marked, indicate the filing number assigned to the Registrant in connection with such Rule. Yes [ ] No [X] Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] The Annual Information Form of the Registrant dated March 19, 2001, the Audited Consolidated Financial Statements of the Registrant and the Auditors' Report thereon for the fiscal year ended December 31, 2000, and Management's Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2000 and additional disclosures required by U.S. GAAP are incorporated by reference herein from Exhibits 1,2,3 and 8 respectively, to this Annual Report on Form 40-F. UNDERTAKING AND CONSENT TO SERVICE OF PROCESS A. Undertaking Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities. SIGNATURES Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized. Registrant: GULF INDONESIA RESOURCES LIMITED By: /s/ Henry W. Sykes ------------------------------------- Henry W. Sykes, Director By: /s/ Alan P. Scott ------------------------------------- Alan P. Scott, Corporate Secretary Page 2 of 55 EXHIBITS
PAGE Exhibit l Annual Information Form of the Registrant dated March 19,2001 4 Exhibit 2 Audited Consolidated Financial Statements and the Auditors' 26 report thereon for the fiscal year ended December 31, 2000 Exhibit 3 Management's Discussion and Analysis of Financial Condition and 41 Results of Operations for the fiscal year ended December 31,2000 Exhibit 4 Consent of Independent Chartered Accountants 50 Exhibit 5 Supplementary Oil and Gas Information 51 Exhibit 6 Standardized Measure of Discounted Future Net Cash flows Relating 52 to Proved Reserves Exhibit 7 Three Year Reserve Reconciliation 53 Exhibit 8 Note 15 to Financial Statements - U.S. GAAP Reconciliation and 54 Additional Disclosure
Page 3 of 55 GULF INDONESIA RESOURCES LIMITED ANNUAL INFORMATION FORM For the year ended December 31, 2000 March 19, 2001 GULF INDONESIA RESOURCES LIMITED ANNUAL INFORMATION FORM INDEX THE CORPORATION .......................................................... 2 GENERAL DEVELOPMENT OF THE BUSINESS ...................................... 2 NARRATIVE DESCRIPTION OF THE BUSINESS .................................... 4 SELECTED CONSOLIDATED FINANCIAL INFORMATION .............................. 18 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ...................................... 18 MARKET FOR SECURITIES .................................................... 18 DIRECTORS AND OFFICERS ................................................... 18 ADDITIONAL INFORMATION ................................................... 20 MISCELLANEOUS ............................................................ 21
-2- THE CORPORATION INCORPORATION OF THE ISSUER AND SUBSIDIARIES Gulf Indonesia Resources Limited ("Gulf Indonesia" or the "Corporation") was incorporated pursuant to Articles of Incorporation under the Canada Business Corporations Act as Asamera Canada Limited and continued under the Business Corporations Act (New Brunswick) on August 27, 1997. The Corporation's principal executive offices are located at 21st floor, Wisma 46, Kota BNI, Jalan Jenderal Sudirman Kavling 1, Jakarta 10220, Indonesia, and its telephone number is (6221) 574- 2120. The Corporation's registered office is 10th Floor Brunswick House, 44 Chipman Hill, Suite 1000, Saint John, New Brunswick, Canada E2L 2A9. Effective February 18, 1997, Gulf Canada Resources Limited ("Gulf Canada") acquired control of Clyde Petroleum Plc, of which Clyde Petroleum Indonesia Ltd. ("Clyde Indonesia") was a wholly owned subsidiary. Clyde Indonesia's name was changed to Gulf Resources (Kakap) Ltd., and on August 19, 1997, the Corporation acquired all of the shares of Gulf Resources (Kakap) Ltd. On August 19, 1997, the Corporation was involved in a corporate reorganization in which it acquired all of the shares of Gulf Resources (Tungkal) Ltd., Gulf Resources (Calik) Ltd., Gulf Resources (Merangin) Ltd., Gulf Resources (Sakala Timur) Ltd. and Gulf Resources (Pangkah) Ltd. from Gulf Canada in exchange for common shares of the Corporation. These wholly owned subsidiaries are all incorporated pursuant to Articles of Incorporation under the Business Corporations Act (Alberta). On September 29, 1997, the Corporation completed a public offering of approximately 28 per cent of its shares, which are now publicly traded on the New York Stock Exchange. The offering netted approximately U.S. $100 million to the Corporation (after payment of a dividend to Gulf Canada and repayment of inter-company amounts). The Corporation has three material subsidiaries: Gulf Resources (Ramba) Ltd., Gulf Resources (Grissik) Ltd. and Gulf Resources (Kakap) Ltd., all of which are incorporated under the laws of Barbados. The Corporation either owns or exercises control over all the voting shares of the three subsidiaries; no non-voting securities have been issued by the subsidiaries. GENERAL DEVELOPMENT OF THE BUSINESS THREE YEAR HISTORY In 1998, construction of the Corridor Block Gas Project was essentially completed, doubling the Corporation's overall production. Natural gas production from the Corridor Block Gas Project is dedicated to the Duri Steamflood under a long-term agreement (the "Caltex I Agreement"). In exchange, PT Caltex Pacific Indonesia ("Caltex") delivers designated crude oil to the Corporation at the export terminal at Dumai on a British thermal unit ("Btu") equivalent basis, subject to certain thermal efficiency and cost adjustments. During the first nine years of the contract, the crude oil received from Caltex is sold under an offtake agreement to Itochu Petroleum Co. (Hong Kong) Ltd. ("Itochu"), a subsidiary of Itochu Corporation. The Corridor Block Gas Project was financed through a credit agreement with a consortium of lenders. Gulf's share of the loan facility was drawn to U.S. $261 MM, of which U.S. $119MM was repaid by year-end 2000, with a further $15 million repaid on February 8, 2001. -3- In 1999, the Corporation, along with other participants in the Kakap production sharing contract ("PSC") and two other third party PSCs, signed an agreement with Pertamina, the Indonesian state oil and gas company, for the sale of natural gas to be used for power generation and petrochemical projects in Singapore (the "West Natuna Agreement"). The construction of the upstream facilities and 650-kilometre pipeline system required to supply the gas under this agreement was completed in December, 2000. Sustained gas sales are expected to commence in the first quarter of 2001. In December, 2000, the Corporation and Pertamina signed agreements for additional gas deliveries from the Corridor Block PSC to the Caltex operated Duri Steamflood (the "Caltex II Agreement"). The agreements provide for a contract quantity of 1.1 Tcf of gas (0.06 Tcf net to the Corporation) to be delivered over 19 years. Gas for the agreements is to be supplied from the Suban field where, in 2000, the Corporation drilled the Suban-4 delineation well which tested at a flow rate of 80 Mmcf/d. Gas deliveries under this agreement are expected to commence in late 2002. In February 2001, the Corporation and Pertamina entered into an agreement with a subsidiary of Singapore Power Limited for the supply of natural gas from Sumatra to Singapore beginning in mid-2003 (the "Sumatra Gas to Singapore Agreement"). The agreement provides for a contract quantity of 2.27 Tcf of sales gas (0.7 Tcf net to the Corporation) to be delivered over a 20 year period. The Caltex II and Sumatra Gas to Singapore Agreements are the third and fourth substantial long-term US dollar gas sales agreements for the Corporation. Including the Caltex I and West Natuna Agreements, the combined cumulative contract quantity of the four agreements that the Corporation is a party to is approximately 7 Tcf (2 Tcf net to the Corporation). TRENDS The Corporation has developed a three-part exploration strategy. The first part of this strategy is an onshore oil exploration program that targets prospects in the five to ten million barrel range. The second part is an offshore program that targets large oil prospects with unrisked potential in excess of 100 million barrels. Three of the seven wells in the current offshore program were drilled in 2000, including the successful Ande Ande Lumut-1 well in the Northwest Natuna Block I PSC and two dry holes in the Sakala Timur and Ketapang Blocks. The third part of the exploration strategy is onshore gas exploration where the Corporation presently has a large number of prospects. This three- part exploration strategy is designed to balance the higher risk, but high return, offshore oil exploration with lower risk, but lower return, onshore oil exploration. The Corporation will continue to explore for gas to the extent that it perceives that additional reserves are required to meet market opportunities. The Corporation recognizes the challenge arising from the need to coordinate its obligations under the Caltex II and Sumatra Gas to Singapore Agreements with the addition of compression to the existing pipeline to the Caltex facility and the construction of a new pipeline from Sumatra by third parties, as well as the usual uncertainties regarding international energy pricing and the political and economic environment in Indonesia. -4- NARRATIVE DESCRIPTION OF THE BUSINESS PRINCIPAL BUSINESS The Corporation is an independent oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas onshore and offshore Indonesia. All of the Corporation's oil and gas producing properties are located in Indonesia. The Company currently produces crude oil and natural gas from established fields onshore on the island of Sumatra and from established fields offshore in the West Natuna Sea. As of December 31, 2000, the Corporation had gross and net proved reserves of 311 MMBOE and 227 MMBOE, respectively, of which approximately 90 per cent were natural gas. The Corporation's principal products are crude oil and natural gas. Currently, the Corporation sells all of its oil production in two markets. Approximately 76 per cent of its oil production is sold to Pertamina, the Indonesian state owned oil and gas company, at the Indonesian Crude Price, being prices set monthly by Pertamina based on spot prices of internationally traded Indonesian crude oils, adjusted for quality. Approximately 23 per cent of oil production, representing offshore production from Kakap fields, is sold under a marketing agreement with BP Oil International Limited. The crude oil from all the Kakap fields is commingled and sold as the Kerapu blend. The Kerapu blend is sold into regional markets at prices reflecting market values at the time of sale. The balance of the Corporation's oil production is received through an overriding royalty payment on Block B in north Sumatra. As of December 31, 2000, the Corporation had approximately 1600 permanent employees, approximately 500 of whom were located at the Corporation's offices in Jakarta, Indonesia, and the remainder of whom were located at field offices. In addition to its permanent employees, the Corporation also engaged over 1,400 daily contract labourers as of such date. PRINCIPAL PROPERTIES The Corporation's operations are conducted through contractual arrangements with Pertamina in the form of eleven PSCs, one technical assistance contract ("TAC") and one enhanced oil recovery contract ("EOR") pursuant to which the Corporation and its partners provide financing and technical expertise to conduct exploration, development and production operations in a specified geographic area (each, a "contract area"). Five of these contract areas are currently producing crude oil: the Corridor Block PSC, Corridor Block TAC, Block A PSC, Kakap PSC and Jambi EOR. Each of these producing contract areas is operated by the Corporation, as are six non-producing PSCs. The remaining two non-producing PSC, are operated by affiliates of Premier Oil Plc. (the Pangkah and Northwest Natuna Block I PSCs). In addition to its interest in these thirteen contract areas, the Corporation also receives an overriding production payment on all production from Block B, northern Sumatra. Upon commercial production, the production revenue from each contract area is divided between the Indonesian government and the participants according to percentages that vary with each production sharing arrangement, subject to cost recovery provisions. After entering into a production sharing arrangement with Pertamina, the Corporation has often farmed out a working interest in the contract area to one or more parties. Operations among the Corporation and other participants with respect to a given contract area are generally governed by a joint operating agreement which varies from block to block. -5- The following table lists, as of December 31, 2000, the Corporation's working interest, participants, term and acreage for each of the Corporation's production sharing arrangements.
Effective Post-Tax Working and Post-Cost Name, Type of Agreement Interest Recovery Share to Expiration and Location (%) Participants Contractor(6) of Term Gross/Net Acreage ----------------------- -------- ------------ ------------------ ---------- ----------------- Oil Gas Corridor (PSC) 54 Talisman(36%) 15% 35% 2023 647,830/349,828 South Sumatra Pertamina(10%) Corridor (TAC) 60 Talisman(40%) 27% 30% 2010 118,843/71,306 South Sumatra Kakap PSC 31.25 Premier(18.75%) 15% 27.5% 2028 494,150/154,422 West Natuna Sea Novus(25%) Singapore Petroleum(15%) Pertamina(10%) Block A PSC 50 Mobil Oil(50%) 15% 30% 2011 445,476/222,738 Northern Sumatra Tungkal PSC 100(1) -- 15% 30% 2022 1,130,862/1,130,862 South Sumatra South Jambi B PSC 45(2) Santa Fe(30%) 15% 30% 2020 380,100/171,045 South Sumatra Pertamina(25%) Jambi EOR 60 Talisman(40%) 7.5% N/A 2005 15,146/9,087 South Sumatra Calik PSC 100(1)(3) 15% 35% 2025 88,846/88,846 South Sumatra Sakala Timur PSC 100(1)(4) -- 35% 40% 2021 1,249,211/1,249,211 Offshore Bali Pangkah PSC 12(1) Premier(40%) 15% 35% 2026 723,435/86,812 East Java Sea Amerada Hess(36%) Dana (12%) Ketapang PSC 50(1)(5) Petronas Carigali(50%) 15% 35% 2028 1,095,283/547,641 East Java Sea Sebuku PSC 100(1) -- 15% 35% 2027 2,160,176/2,160,176 Offshore Kalimantan Northwest Natuna PSC 30(1) Premier(50%) 15% 35% 2027 1,068,352/320,506 West Natuna Sea Dana(20%)
(1) Pertamina has the right to direct that a 10 per cent working interest under the PSC be sold to an Indonesian Participant. (2) Approval of the change in working interest holder was received from Pertamina in early 2000. (3) The change in working interest from 40 per cent to 100 per cent was approved by Pertamina in 2000. (4) In early 2001, the Corporation filed a letter with Pertamina to relinquish this block effective January 10, 2001. (5) Awaiting approval from Pertamina for the December 2000 Farm-in Agreement with Petronas Carigali whereunder Petronas will acquire a 50 per cent working interest from the Corporation. (6) These percentages reflect approximate post-tax and post-cost recovery share for typical fields but are prior to the effects of any domestic market obligations on crude oil production. The effective post-tax and post-cost recovery rate is based on the revenue sharing rate stated in the PSC and the Indonesian tax rate applicable to the specific PSC. In the case of the Corridor Block TAC, the effective post-tax and post-cost recovery share is calculated after payment of the petroleum revenue tax and accordingly, may vary depending on the applicable petroleum revenue tax. To encourage drilling and exploration in new geological horizons and frontier areas as well as enhanced recovery projects with respect to mature fields, PSCs typically contain provisions increasing the contractor's pre-tax share of production under certain circumstances such as production from pre-Tertiary reservoirs, wells drilled in water depths in excess of designated levels and fields with low rates of production. -6- The following table lists the Corporation's production sharing arrangements that are currently in commercial production, and reflects reserves data as at December 31, 2000 and production data for the years ended December 31, 2000, 1999 and 1998.
Corporation's Gross/Net Corporation's Gross/Net Corporation's Gross/Net Production for Year Production for Year Production for Year Corporation's Gross/Net Proved Reserves Ended December 31, Ended December 31, Ended December 31, as at December 31, 2000(1) 2000(1) 1999(1) 1998(1) --------------------------------------- ----------------------- ----------------------- ----------------------- Oil & Natural Gas Liquids Sales Gas Total Total Total Total Property (MMBbls) (Bcf) (MMBOE) (MMBOEs) (MMBOEs) (MMBbls) -------- ------------- --------- ------- ----------------------- ----------------------- ----------------------- Corridor PSC 9.9/4.6 1,523/1,142 263.7/194.9 11.45/10.86 11.30/10.69 2.62/2.39 Corridor TAC 15.4/8.6 -/- 15.4/8.6 2.95/1.83 2.64/1.64 2.72/1.69 Kakap PSC 4.7/3.4 90/64 19.7/14.1 1.58/1.19 2.27/1.85 2.25/2.25 Jambi EOR 2.5/1.4 -/- 2.5/1.4 0.95/0.56 0.84/0.74 0.72/0.64 9.2/7.0 South Jambi -/- 55/42 -/- -/- -/- -/- Other(2) 0.6/0.5 -/- 0.6/0.5 0.12/0.11 0.31/0.30 0.38/0.37 ----------- ----------- Total 33.1/18.5 1.668/1.248 311.1/226.5 17.05/14.55 17.36/15.22 8.69/7.34 =========== ===========
(1) Gross reserves and production volumes reflect the Corporation's interest prior to, and net reserves and production volumes reflect the Corporation's interest after, deduction of applicable government take payable to the Indonesian government under the applicable contractual arrangement. (2) Represents reserves attributable to the Block A PSC and the Block B overriding production payment. Corridor Block PSC, Southern Sumatra The Corporation operates in two contract areas in the Corridor Block, one of which is governed by a PSC executed in 1983 and one of which is governed by a TAC originally entered into in 1968. Pertamina amended the Corridor Block PSC in 1996 to extend its term until 2023. The Corporation is operator of the Corridor Block PSC with a 54 per cent working interest. Crude Oil. Crude oil operations in the Corridor Block PSC contract area consist of 47 commercially producing wells in 11 fields. Production in 2000 averaged 3,600 Bbls/d (3,100 Bbls/d net) compared to 4,200 Bbls/d (3,500 Bbls/d net) in 1999. Natural Gas. Natural gas operations in the Corridor Block PSC contract area consist of 15 commercially producing wells in the Dayung, Gelam, Letang, and Tengah fields. Gas operations commenced in October 1998 with production in 2000 averaging 166 MMcf/d (159 MMcf/d net) compared to 161 MMcf/d (154 MMcf/d net) in 1999. Corridor Block Gas Project. The "Corridor Block Gas Project" consists of (i) production from gas wells in the Dayung, Gelam, Letang and Tengah fields (collectively, the "Phase I Fields"); (ii) field separation and gathering facilities, including three field stations to dehydrate gas from the Phase I Fields; and (iii) a central gas processing plant to process 440 MMcf/d of Raw Gas from the three field stations, with an output design capacity of 310 MMcf/d of sales gas (the "Gas Processing Plant" and, together with the field separation and gathering facilities, the "Project Facilities") and an operating capacity increase in 2000 to approximately 350 Mmcf/d. The Corridor Block Gas Project commenced operations in October 1998. -7- Gas produced in the Corridor Block PSC contract area is used for steam generation at Caltex's enhanced oil recovery operations at Duri, in central Sumatra. The gas is transported from the gas processing plant to the Duri Steamflood through a 28-inch diameter onshore transmission pipeline, constructed by the Indonesian-owned gas transmission company P.T. Perusahaan Gas Negara (Persero) ("PGN"). In 2000, the Corporation drilled the Suban-4 delineation well which tested at a flow rate of 80 Mmcf/d with approximately 420 barrels of condensate per day. Extended testing of the Suban-4 well and the Durian Mabok-2 well, which was drilled in 1998, indicates that these two wells have penetrated the same structure. The Corporation believes that the Suban-4 well will be capable of a sustainable production of 100 Mmcf/d, similar to the Durian Mabok-2 well. The Corporation is currently drilling the Suban-5 delineation well and plans to drill three additional delineation wells in 2001 to further establish the size of the Suban field. Ongoing drilling success in the Corridor Block PSC resulted in the Corporation booking gross proved reserve additions of over 400 Bcf in 2000, with estimated remaining proved reserves at year- end 2000 of 1.5 Tcf. In December 2000, the Corporation and Pertamina signed agreements for additional gas deliveries from the Corridor Block PSC area to the Duri Steamflood in central Sumatra operated by Caltex. The agreements provide for a contract quantity of 1.1 Tcf (Corporation's share 0.6 Tcf) of sales gas to be delivered over a term of 19 years and exchanged for Duri crude oil at an approximate ratio of 8,000 cubic feet per barrel. Natural gas for the new contract will be supplied from the Suban field with gas deliveries expected to commence in late 2002. By early 2003, the Corporation's 65 Mmcf/d share of contract quantities will supplement the 160 Mmcf/d of gas (net to the Corporation) that is contracted under the original agreement with Caltex, for a total combined quantity of 225 Mmcf/d. On February 12, 2001, the Corporation and Pertamina entered into a gas sales and purchase agreement with Gas Supply Pte. Ltd. (a subsidiary of Singapore Power Limited) for the supply of natural gas from the Corridor and South Jambi B PSCs and a third party operation. The agreement provides for a contract quantity of 2.27 Tcf (the Corporation's share being 0.7 Tcf) of sales gas to be delivered over a term of 20 years beginning in mid-2003. The Corporation's share of daily contract quantities is initially 42 Mmcf/d, increasing over time to 110 Mmcf/ by 2009. Pricing for the gas sales will be indexed to the price of high sulphur fuel oil. Natural gas for this new agreement will be supplied from the Sumpal field in the Corridor Block PSC and three fields (Teluk Rendah, Geger Kalong and Bungin) in the South Jambi B PSC. Corridor TAC, Southern Sumatra The Corporation operates several small non-contiguous areas located onshore in southern Sumatra with producing oil fields in the Corridor Block under a TAC between the Corporation and Pertamina. The Corridor Block TAC was renewed in 1989 for a 20-year period beginning October 1990 to replace the original TAC entered into in 1968. The Corporation is operator of the block with a 60 per cent working interest. The TAC currently has 163 commercially producing wells in six fields. Production in 2000 averaged 8,100 Bbls/d (5,000 Bbls/d net) compared to 7,200 Bbls/d (4,600 Bbls/d net) in 1999. During 2000, the Corporation drilled 28 development wells in the Ramba and Bentayan fields, which contributed 2,500 Bbls/d (the Corporation's share being 1,500 Bbls/d) in production to the Corporation's total production from this area. In June 2000, the Corporation also acquired 73 -8- kilometres of 2D seismic data in the Bentayan field to investigate the possibility of a southeast extension to the field. Kakap PSC, West Natuna Sea The Corporation operates the Kakap PSC in the West Natuna Sea, offshore Kalimantan, with a 31.25 per cent working interest that currently consists of some 33 producing oil wells in 10 fields. In 1999, in connection with the West Natuna Gas Project described below, the Corporation signed a 23- year extension of the contract term of the Kakap PSC, which now expires in 2028. Each of the four main producing fields has its own dedicated platform with initial processing facilities that are linked by pipelines to a floating production storage and offloading vessel with a storage capacity of 650 MBbls. In addition, five subsea completions are currently tied back and produced to the main oil production platforms via subsea flowlines and umbilicals. The Corporation's share of production in 2000 from the Kakap fields was 4,300 Bbls/d (3,300 Bbls/d net) compared to 6,200 Bbls/d (5,100 Bbls/d net) in 1999. West Natuna Gas Project. The participants in the Kakap, Natuna Sea Block A and South Natuna Sea Block B PSCs have formed the West Natuna Gas Group (the "West Natuna Group") in order to jointly market gas from the West Natuna Area. In January 1999, the West Natuna Group concluded extensive negotiations and signed a supply agreement with Pertamina for natural gas to be used for power generation and petrochemical projects in Singapore. The construction of the Kakap upstream facilities and the West Natuna Transportation System was completed in December, 2000, approximately four months ahead of schedule and under budget. The upstream facilities required for the project were placed into service in early December, 2000 and the 650-kilometre West Natuna pipeline system was commissioned at the end of 2000. Actual gas sales began in January 2001, six months prior to the commencement of the full sales contract on July 15, 2001. Block A PSC, Northern Sumatra In July 1989, the Corporation entered into a production sharing contract (effective for 20 years beginning in September 1991) for exploration of the Block A PSC located in northern Sumatra. The Corporation is operator of the block with a 50 per cent working interest. The PSC consists of 12 commercially producing wells in three fields with production averaging 132 Bbls/d (113 Bbls/d net) in 2000 compared to 181 Bbls/d (155 Bbls/d net) in 1999. From a development perspective, civil unrest in the Aceh Province, where the Block A PSC is located, is one of the factors impacting the Corporation's ability to develop its probable reserves in the area. Tungkal PSC, Southern Sumatra The Corporation entered into a 30-year production sharing contract in 1992 for the exploration of the Tungkal PSC located onshore south Sumatra, northwest of the South Jambi B Block. The Corporation is operator of the block with a 100 per cent working interest. In early 1997, the Corporation discovered oil and gas at the Mengoepeh Field on the Tungkal PSC. Four appraisal wells following a 96 square kilometre 3D seismic survey completed in 1997 delineated a marginal oil and gas accumulation. An additional seismic program was completed in the third quarter of 2000 to provide drilling locations in the Mengoepeh Field and the Corporation drilled the unsuccessful Mengoepeh-6 well in January 2001. The Corporation continues to investigate the field for its oil potential and for development options to commercialize the field. -9- South Jambi B PSC, Southern Sumatra The Corporation operates the South Jambi B Block, located onshore in South Sumatra adjacent to the Corridor Block, under a 30-year PSC entered into in 1990. The Corporation holds a 45 per cent working interest in the block. A plan of development for the Teluk Rendah and Geger Kalong fields in the north end of the block, and the Bungin field in the southern area of the block in support of the South Jambi B PSC's share of the Sumatra Gas to Singapore sales contract has been approved by Pertamina. The Teluk Rendah and Geger Kalong fields are targeted to commence production in mid-2003 and the Bungin project is scheduled to commence production later in the contract term, with the combined developments expected to increase the total net sales from the block to approximately 40 Mmcf/d. Jambi EOR, Southern Sumatra In January, 1990, the Corporation and Pertamina entered into a 15-year EOR contract to perform secondary recovery operations in six fields in the Jambi area of southern Sumatra. Three of these six fields are under waterflood as the Corporation decided not to pursue development of the remaining three fields. Under the terms of the EOR, the contractor receives a share in, and can recover costs from, oil produced in excess of primary oil production. The contractor pays all the development costs but Pertamina repays past capital costs plus an uplift of 30 per cent. Profit oil (the portion remaining of the contractor's equity share, less contractor's allowed operating costs and investment credits) is split 71.1538 per cent with Pertamina and 38.8462 per cent with the contractor. The Corporation has a 60 per cent working interest. The Jambi EOR has 195 commercial wells in three fields that currently produce 2,600 Bbls/d (1,500 Bbls/d net) compared to 2,300 Bbls/d (2,000 Bbls/d net) in 1999. During 2000, the Corporation drilled 12 development wells. Calik PSC, Southern Sumatra In June, 1995, the Corporation entered into a 30 year PSC for the exploration of the Calik Block located onshore in southern Sumatra, northeast of the Corridor Block. The Corporation, which is operator of the block, received approval from Pertamina in 2000 for a change in working interest from 60 per cent to 100 per cent. Through 2000, the Company completed a work program commitment, which consisted of reprocessing seismic data, acquiring additional 2D seismic, conducting geological studies and drilling one exploratory well, which did not produce oil in commercial quantities. Recent seismic mapping has identified several potential oil prospects in the lower Talang Akar sandstone formation. In May 2000, the Corporation drilled the Cahaya-1 prospect well, which was plugged and abandoned. Sakala Timur PSC, Offshore Bali After receiving Pertamina's approval in early 1999, the Corporation held a 100 per cent working interest and operatorship in a 30-year PSC executed in January, 1991 for exploration of the Sakala Timur Block, located offshore Lombok, northeast of the island of Bali. There has been no commercial production of hydrocarbons in this contract area to date. In July, 2000, the Corporation drilled the Sawangan-1X well, which was plugged and abandoned. Effective January 10, 2001, the Corporation relinquished its interest in the Sakala Timur Block, as the remaining potential identified on the block was not sufficient to justify further expenditures. -10- Pangkah PSC, East Java Sea In 1997, the Corporation entered into a farm-in agreement with Dana Petroleum (Pangkah) LLC ("Dana") to acquire an interest in a 30-year PSC executed in May 1996 for exploration of the Pangkah Block, located offshore in the East Java Sea. Premier Oil Pangkah Ltd. is operator of the Pangkah Block contract area. The Corporation has a 12 per cent working interest. There has been no commercial production of hydrocarbons in this contract area to date. The Ujung Pangkah-1 well drilled in late 1998 tested gas and oil and condensate at rates of 20 Mmcf/d and 1,000 Bbls/d, respectively. Three wells drilled in the fourth quarter of 2000 yielded one offshore oil discovery and one delineation success. The Sidayu-1 oil well flowed 1,450 Bbls/d during testing and the Ujung Pangkah-2 delineation well confirmed reservoir continuity and the gas and oil columns seen in the Ujung Pangkah-1 discovery well. The results of these wells along with the results of the successful Ujung Pangkah-3 well drilled in early 2001 are being evaluated for the potential submission of a plan of development to the Indonesian government in late 2001 for both the Ujung Pangkah and Sidayu fields. Ketapang PSC, East Java Sea In June, 1998, the Corporation signed a 30-year PSC with Pertamina for a 100 per cent working interest in the 1.1 million acre offshore Ketapang Block. This block is east of and adjacent to the Pangkah Block, and the discovery at Ujung Pangkah confirmed the prospectivity of the main play type in the Ketapang Block. In December 2000, the Corporation farmed out 50 per cent of its working interest in the Ketapang PSC to Petronas Carigali, with the Corporation holding the remaining 50 per cent working interest. Several oil and gas prospects have been confirmed by the mapping of new and reprocessed seismic data and the discovery at Ujung. A seismic survey was conducted in early 1999, which further defined drilling prospects, and locations were selected for a four well drilling program. The first of these four wells, the Bukit Panjang-1 well was drilled in late 2000 and plugged and abandoned. The remaining three wells are scheduled to be drilled in the first half of 2001. Sebuku PSC, Offshore Kalimantan In September, 1997, the Corporation entered into a 30-year PSC for the exploration of the Sebuku Block, located in the Makassar Strait, offshore Kalimantan. The Corporation is operator of the block with a 100 per cent working interest. Although there is currently no commercial production of hydrocarbons in the contract area, the Corporation is evaluating a 1974 discovery, Makassar 1, and several prospects and leads were identified by the mapping of 2,633 kilometres of new 2D seismic data. In early 2001, the Corporation completed the drilling of the Pangkat-1 well, a large oil prospect. The well encountered oil shows during drilling and flowed a small amount of oil during testing, but has been plugged and abandoned as non-commercial. Northwest Natuna Block I PSC. The Corporation entered into a farm-in agreement in 1997 with Dana Petroleum (NW Natuna) LLC to acquire a 30 per cent interest in the undeveloped Northwest Natuna Block I PSC, just north of the Kakap PSC. The Corporation will earn its interest by funding 50 per cent of the next $6.5 -11- million spent on the block, including shooting and processing seismic and drilling one exploratory well. There has been no commercial production of hydrocarbons in this contract area to date. A high resolution 2D seismic survey conducted in 1998 further developed a large oil prospect on the Premier operated Northwest Natuna block. In April 2000, the Corporation drilled the Ande Ande Lumut-1 well. The well logged oil pay and the Corporation recovered oil samples from four sands of the Gabus Formations. Testing of the well was terminated without a sustained oil flow. Plans for appraisal drilling in 2001 to delineate the Ande Ande Lumut field are being considered. Block B, Northern Sumatra The Corporation receives an overriding production payment of $0.04 per BOE on 60 per cent of all crude oil, natural gas and natural gas liquids produced in the Block B contract area in Aceh, northern Sumatra. This payment amounted to approximately $1.6 million in 2000 compared to $3.5 million in 1999. NATURAL GAS AND OIL RESERVES The following table summarizes the estimates of the Corporation's historical gross and net proved natural gas and oil reserves as of the dates indicated and the present value attributable to the net proved reserves at such dates. The Corporation, for all years presented, has prepared the reserves and present value data.
2000 1999 1998 ------------ ------------ ------------ Corporation's gross and net proved reserves(1)(2)(3): Natural gas (Bcf) 1,668/1,248 1,263/996 1053/919 Oil and Condensate (MMBbls) 33/19 34/20 39/30 Total (MMBOE) 311/227 245/186 214/183 Corporation's gross and net proved developed reserves 109/77 108/79 116/99 (MMBOE) Present value of future net revenues $ 1,513 $ 1,361 $ 218 before income taxes (in millions of $)(4) Standardized measure of discounted $ 836 $ 826 $ 203 future net cash flows (in millions of $)
(1) "Gross" reserves are reserves attributable to the Corporation's interest but prior to deduction of applicable government take payable to the Indonesian government as owner of the reserves under the applicable contractual arrangement. (2) "Net" reserves are reserves attributable to the Corporation's interest after deduction of applicable government take payable to the Indonesian government as owner of the reserves under the applicable contractual arrangement, which government take may vary depending on prices, production rates, expenditure levels and legislative changes. (3) "Proved" reserves are those reserves estimated as recoverable under current technology and existing economic conditions, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir. All of the proved developed reserves were producing as of December 31, 2000. (4) The present value of future net revenues before income taxes attributable to the Corporation's net proved reserves was prepared using prices and costs in effect as of the end of the respective periods presented, discounted at 10 per cent. -12- Estimates of the Corporation's reserves and future net revenues are made using sales prices estimated by the Corporation to be in effect as of the date of such reserves estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of reserves and future net revenues therefrom have been gas calculated on a Btu equivalent basis based on crude oil prices. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond the control of the producer. THE FUTURE NET CASH FLOWS ARE NOT INDICATIVE OF THE CURRENT VALUE OR FUTURE EARNINGS THAT MAY BE REALIZED FROM THE PRODUCTION OF PROVED RESERVES NOR SHOULD IT BE ASSUMED THAT THEY REPRESENT THE FAIR MARKET VALUE OF THE RESERVES OR OF THE OIL AND GAS PROPERTIES. RESERVE RECONCILIATION The following table provides a summary of the changes in the Corporation's reserves which occurred in the most recent fiscal year on a gross/net basis.
Proven Probable Total --------------- --------------- --------------- NATURAL GAS (BCF) AS AT JANUARY 1, 2000 1,262.5/996.3 745.7/612.3 2,008.2/1,608.6 Additions(1) 407.9/218.8 924.9/647.4 1,332.8/866.2 Purchases of Reserves 0/87.1 0/0 0/87.1 Revisions to Previous Estimates 62.9/47.3 (54.3)/(38) 8.6/9.3 Production (60.7)/(58.2) 0/0 (60.7)/(58.2) Royalty Adjustment (4.8)/(43.4) 0/(46) (4.8)/(89.4) --------------- --------------- --------------- AS AT DECEMBER 31, 2000 1,667.9/1,247.9 1,616.3/1,175.7 3,284.2/2,423.6 OIL AND CONDENSATE (MMBbls) AS AT JANUARY 1, 2000 34.1/19.6 23.2/15.2 57.3/34.8 Additions(1) 6.5/2.1 8.5/2.7 15/4.8 Purchases of Reserves 0/1.4 0/0 0/1.4 Revisions to Previous Estimates (0.6)/(0.7) (3.8)/(2.1) (4.4)/(2.7) Production (6.9)/(4.8) 0/0 (6.9)/(4.8) Royalty Adjustment and Rounding 0/1.0 0/(0.8) 0/(0.2) --------------- --------------- --------------- AS AT DECEMBER 31, 2000 33.1/18.5 27.9/15.1 61.1/33.7
(1) Includes discovery and extension, infill, improved recovery and other (2) Columns may not add due to rounding. -13- DRILLING HISTORY The following table sets forth the number of wells completed by the Corporation on its properties for the years ended December 31, 2000, 1999 and 1998.
Year Ended December 31, (Gross/Net) 2000 1999 1998 ---------- ---------- ---------- EXPLORATORY WELLS Oil 3/0.7 -/- 4/1.8 Gas 1/0.5 4/2.3 10/5.6 Dry 6/3.3 1/0.3 10/5.6 ---------- ---------- ---------- Total Exploratory 10/4.5 5/2.6 24/13.0 DEVELOPMENT WELLS Oil 40/24.0 14/8.4 20/11.4 Gas 1/0.5 -/- 6/3.2 Dry -/- 1/0.6 -/- ---------- ---------- ---------- Total Development 41/24.5 15/9.0 26/14.6 ---------- ---------- ---------- Total Wells 51/29.0 20/11.6 50/27.6
PRODUCTIVE WELLS The following table sets forth the number of productive wells in which the Corporation owned an interest as of December 31, 2000.
Total Productive Corporation Operated Wells Non-Operated Wells Wells Gross Net Gross Net Gross Net ----------- ------------ ---------- ---------- ---------- ---------- Oil 40 251.5 4 1.1 444 252.6 Gas 15 8.1 -- -- 15 8.1 Total 455 259.6 4 1.1 459 260.7
Productive wells consist of producing wells capable of production, including wells awaiting connections. Wells that are completed in more than one producing horizon are counted as one well. The Corporation also owns an interest in four offshore platforms. EXPENDITURES In 2000, the Corporation's exploration/delineation expenditures were $29 million compared to $32 million in 1999. Additionally, the Corporation's development expenditures in 2000 were $57 million compared to $34 million in 1999. ACREAGE DATA The following table sets forth the approximate developed and undeveloped acreage in which the Corporation held a contract interest as of December 31, 2000. Undeveloped acreage includes acres on which the Corporation has a concession and on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, -14- regardless of whether such acreage contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres expressed as whole numbers and fractions thereof.
Thousands of Acres Developed Undeveloped ---------- ---------- ---------- ---------- Gross Net Gross Net Onshore 388 207 2,440 1,837 Offshore 36 11 6,754 4,507 Total 424 218 9,194 6,344
ENVIRONMENTAL MATTERS Indonesian laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, require remedial measures to prevent pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from the Corporation's operations. In addition, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist. RISK FACTORS Risk of Operations in Indonesia. Substantially all of the Corporation's assets and operations are located in Indonesia, and substantially all of the Corporation's crude oil production in Sumatra is sold at a price determined by the Indonesian government. The Indonesian government has exercised and continues to exercise significant influence over many aspects of the Indonesian economy, including the oil and gas industry, and any Indonesian government action concerning the economy could have a material impact on private sector entities, including the Corporation. There is no assurance that the Indonesian government will not postpone or review additional projects or will not make changes in government policies, which in each case could materially impact or adversely affect the Corporation's financial position, results of operations or prospects. The Corporation's business is regulated by the laws and regulations of Indonesia, including those relating to the development, production, marketing, pricing, transportation and storage of natural gas and crude oil, taxation and environmental and safety matters. The Corporation may be adversely affected by changes in governmental policies or social instability or other political, economic or diplomatic developments in or affecting Indonesia which are not within the control of the Corporation including, among other things, a change in crude oil or natural gas pricing policy, the risks of war, expropriation, nationalization, renegotiation or nullification of existing concessions and contracts, taxation policies, foreign exchange and repatriation restrictions, changing political conditions, international monetary fluctuations and currency controls. Concentration of Assets and Operations. As of December 31, 2000, 85 per cent of the Corporation's total gross proved crude oil and natural gas reserves on an energy equivalent basis and 91 per cent of the Corporation's total proved natural gas reserves were located in the Corridor Block PSC contract area. The concentration of the Corporation's crude oil and natural gas reserves in the Corridor Block PSC contract area increases the Corporation's exposure to an event that could adversely affect the development or production of crude oil and natural gas in a limited geographic area, such as catastrophic damage to pipelines, gas processing plants or reservoir structures or events -15- that could result in the loss, or material modification, of the Corridor Block PSC. Adverse developments with respect to the Corridor Block PSC could have a material adverse effect on the Corporation's financial condition, results of operations or prospects. In addition, 66 per cent of the Corporation's total crude oil and condensate production for 2000 was attributable to oil fields located in the Corridor Block TAC and the Kakap PSC contract areas, and 68 per cent of the Corporation's total proved crude oil and condensate reserves as of December 31, 2000 were located in the Kakap PSC, Corridor Block TAC and Jambi EOR contract areas. Adverse developments with respect to one or more of these contract areas could also have a material adverse effect on the Corporation's financial condition, results of operations or prospects. Natural Gas Projects Under Development. The factors upon which the success of natural gas projects are contingent are in large part beyond the control of the Corporation, and significant complex negotiations among multiple parties remain with respect to the development of certain gas projects. There is no assurance that the Corporation will be able to successfully develop any proposed project and, if completed, that such projects will be completed on a timely basis. The failure of the Corporation or other parties involved to complete and operate any of these natural gas projects successfully could have a material adverse effect on the Corporation's financial condition, results of operations or prospects. Limited Markets for Indonesian Natural Gas. The absence of, or limited development of a natural gas transmission and distribution infrastructure within Indonesia and between Indonesia and Singapore has restricted consumption of Indonesian natural gas. The Corporation's ability to market gas may be limited by the lack of infrastructure within Indonesia. Further, there is no assurance that long-term market demand will develop. Relationship with Pertamina. Under current Indonesian law, Pertamina is the sole entity authorized to manage Indonesia's petroleum resources on behalf of the Indonesian government. In September, 2000, the Indonesian government submitted a bill to the House of Representatives proposing to establish an "Executive Body" that would take over Pertamina's current right to sign contracts with oil and gas companies for the development of the country's hydrocarbon resources. The status of this bill is unclear at this time. Pertamina enters into production sharing arrangements with private energy companies whereby such companies explore, develop and market oil and gas in specified areas in exchange for a percentage interest in the production from the fields in the applicable production sharing area. All of the Corporation's reserves are attributable to such production sharing arrangements. Production sharing arrangements contain requirements regarding quality of service, capital expenditures, legal status of the concessionaires, restrictions on transfer and encumbrance of assets and other restrictions. Failure to comply with these arrangements could result, under certain circumstances, in the revocation of a production sharing arrangement. Such an action could have a material adverse effect on the Corporation's financial condition, results of operations or prospects. In addition, the Corporation must obtain approval from Pertamina for substantially all material activities undertaken with respect to the production sharing arrangements, including exploration, development, production, drilling and other operations, sale of oil or natural gas and the hiring or termination of personnel. Furthermore, all facilities and equipment purchased by the Corporation and used in a contract area become the property of Pertamina, although the Corporation may recover such costs through the cost recovery provisions of the applicable production sharing arrangements. Substantial Capital Requirements; Liquidity. The Corporation makes, and will continue to make, substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves. During 1996 and 1997, a portion of the Corporation's capital requirements were financed by loans from Gulf Canada. On February 26, 1997, the Corporation and -16- the other private PSC participants entered into a credit agreement (the "Corridor Loan") with various lending institutions (the "Lenders") to provide up to $450 million of financing to fund the development of the Corridor Gas Project (the "Project"). Repayments on the Corridor Loan are equal quarterly installments ending February, 2007. Under the terms of the Corridor Loan, the Project net cash flows contribute to certain cash reserve requirements that the Corporation reports as "cash restricted in use". Additionally a specified percentage of the surplus cash is used to fund mandatory early repayments with the remainder released to the Corporation. The mandatory early repayments were substantial in 2000 because of high prices and the Corporation not paying current taxes. Based on long-term debt outstanding at December 31, 2000, the Corporation's repayment requirements for the next five years are $25 million plus a $6 million mandatory early repayment in 2001, and $21 million (assuming no mandatory early repayments) for each of the years 2002 through 2005. Pursuant to certain financing agreements entered into in connection with the Corridor Facility, Gulf Canada is required for the term of the Corridor Facility to hold (directly or indirectly) at least 60 per cent of the outstanding voting shares of the Corporation and, in any event, to continue to control the Corporation. While the Corporation expects to be able to fund its current exploration and development plans with internally generated cash flow and current cash balances, if its pending gas projects are not completed on time or, if after production commences, revenues or reserves decline, the Corporation may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. Moreover, future activities may require the Corporation to alter its capitalization significantly. The inability of the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation's financial condition, results of operations or prospects. Uncertainty of Reserves Estimates. This Annual Information Form includes estimates made by the Corporation of the Corporation's gross and net proved oil and gas reserves and the present value of net proved reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the control of the Corporation. The reserves data set forth in this Annual Information Form represent estimates only. Reliance on Development of Additional Reserves. The Corporation must continually acquire, explore for and develop new hydrocarbon reserves to replace those produced and sold. Although the Corporation believes that the properties subject to its PSCs have potential for significant reserves additions from presently contemplated exploration and development activities, the success of such activities cannot be assured. Exploration, Development and Production Risks. The Corporation's oil and gas exploration, development and planned production operations involve risks normally inherent to such activities, including blowouts, oil spills and fires (each of which could result in damage to or destruction of wells, production facilities or other property, or injury to persons), geological uncertainties and unusual or unexpected formations and pressures, which may result in dry holes, failure to produce oil or gas in commercial quantities or inability to fully produce discovered reserves. The Corporation's offshore operations are also subject to hazards inherent in marine operations, such as capsizing, sinking, grounding, collision and damage from severe weather conditions. Oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field-operating conditions may adversely affect the Corporation's production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-in of connected wells resulting from extreme weather conditions, -17- insufficient storage or transportation capacity or other geological and mechanical conditions. While close well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Volatility of Oil and Gas Prices. The revenues expected to be generated by the Corporation's future operations will be highly dependent upon the prices of, and demand for, oil and natural gas. In addition, there is no assurance that the Indonesian government will not adopt a natural gas or oil pricing policy that would adversely affect the Corporation's future results of operations or prospects. Decreases in the prices of oil and gas could have an adverse effect on the carrying value of the Corporation's reserves and the Corporation's revenues, profitability, cash flow and credit availability. Competition. The oil and gas industry is highly competitive. The Corporation's competitors for the acquisition, exploration, production and development of oil and natural gas properties in Indonesia, and for capital to finance such activities, include companies that have greater financial and personnel resources available to them than the Corporation. Certain of the Corporation's customers and potential customers are themselves exploring for oil and natural gas in Indonesia, and the results of such exploration efforts could affect the Corporation's ability to sell or supply oil or gas to these customers in the future. The Corporation's ability to successfully bid on and enter into new PSCs or otherwise acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon a continuation of its close working relationships with its partners and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. Environmental Risks. The Corporation's business is subject to certain Indonesian laws and regulations relating to exploration for and development and production of oil and natural gas, and environmental and safety matters. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to the Indonesian government and third parties and may require the Corporation to incur costs to remedy such discharge. No assurance can be given that Indonesian environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect the Corporation's financial condition, results of operations or prospects. Control by, and Arrangements with, Gulf Canada; Potential Conflicts of Interest. At present, Gulf Canada owns approximately 72 per cent of the outstanding Common Shares. Additionally, pursuant to certain financing agreements entered into in connection with the Corridor Loan, Gulf Canada is required for the term of the Corridor Loan to hold (directly and indirectly) at least 60 per cent of the outstanding voting shares of the Corporation and to continue to control the Corporation. Accordingly, Gulf Canada will be in a position to control the policies, management and affairs of the Corporation, to effectively prevent or cause a change in control of the Corporation and to determine the outcome of corporate action requiring shareholder approval, including electing all, or substantially all, the members of the Board of Directors of the Corporation and adopting amendments to the Corporation's Articles of Continuance. The Corporation and Gulf Canada have also entered into a series of agreements relating to their ongoing intercompany arrangements. Because of the complexity of the various relationships between the Corporation and Gulf Canada, there can be no assurance that each of the agreements between them, or the transactions provided for therein, has been or will be effected on terms at least as favorable to the Corporation as could have been obtained from unaffiliated third parties. In addition, although the Corporation and Gulf Canada have attempted to address potential future conflicts of interest through a series of -18- agreements, in light of the significant past and ongoing relationships between the Corporation and Gulf Canada and the nature of their respective businesses, there may be conflicts of interest that arise in the future between the Corporation and Gulf Canada. SELECTED CONSOLIDATED FINANCIAL INFORMATION SELECTED CONSOLIDATED FINANCIAL INFORMATION Reference is made to the information under the heading "Consolidated Financial Statements" on pages 32 to 34 of the Corporation's 2000 Annual Report filed with securities commissions in Canada and with the Securities and Exchange Commission in the United States. This information is incorporated herein by reference as the Selected Consolidated Financial Information. DIVIDEND POLICY The Corporation's dividend policy has been to retain its available cash flow to support the continued development of its business. Accordingly, the Corporation does not plan to declare dividends on its common shares in the foreseeable future. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Reference is made to the information under the heading "Management Discussion and Analysis" which appears on pages 21 to 29 of the Corporation's 2000 Annual Report, filed with securities commissions in Canada and with the Securities and Exchange Commission in the United States. This information is incorporated herein by reference as the Management's Discussion and Analysis of Financial Condition and Results of Operations. MARKET FOR SECURITIES Gulf Indonesia's common shares are listed for trading on the New York Stock Exchange, and trade under the symbol "GRL". DIRECTORS AND OFFICERS The Board of Directors is currently composed of eleven members. Directors are elected for a term of office expiring at the next succeeding annual shareholders' meeting following their election to office or until a successor is duly elected and qualified. The Officers of the Corporation serve at the discretion of the Board of Directors. -19- DIRECTORS Reference is made to information contained under the heading "Election of Directors" on pages 3 to 5 of the Circular for the names of the directors of Gulf Indonesia as at the date of this AIF, their current offices, their principal occupations for the five years ended December 31, 2000 and their municipality of residence, which information is incorporated herein by reference. All directors and officers as a group beneficially own, directly or indirectly, or have control over or exercise direction in respect of 40,136 Common Shares or approximately 0.012 per cent of the Common Shares of the Company. Together with stock options that are exercisable within 60 days of the date hereof, all directors and officers as a group beneficially own, directly or indirectly, or have control over or exercise direction in respect of 1,491,294 Common Shares, or approximately 1.69 per cent, of the Common Shares of the Company. The Committees of the Board of Directors are described under the heading "Election of Directors" on page 5 of the Circular. OFFICERS
NAME AND MUNICIPALITY OF RESIDENCE POSITION WITH THE CORPORATION William T. Fanagan President, Chief Executive Officer and Jakarta, Indonesia Director Murray E. Hesje Vice President, Finance Calgary, Alberta Robert W. Klassen Vice President, Operations Jakarta, Indonesia Supramu Santosa Vice President, Business Planning and Jakarta, Indonesia Government Relations Cliff W. Zeliff Vice President, Exploration Jakarta, Indonesia Taufik Ahmad Vice President, Administration Jakarta, Indonesia Alan P. Scott Corporate Secretary Calgary, Alberta
William T. Fanagan has been President and Chief Executive Officer of the Corporation since May, 1998. Mr. Fanagan was Director-International of Gulf Canada from 1996 to May 1998. From 1992 to 1995, Mr. Fanagan was Finance Director of the KomiArcticOil joint venture. Mr. Fanagan has been employed by Gulf Canada in various capacities since 1977. Murray E. Hesje was appointed Vice President, Finance of each of the Corporation's operating subsidiaries in 1999. Mr. Hesje has been employed by Gulf Canada or its subsidiaries in various capacities since at least 1974. In February, 2001, Mr. Hesje moved to Calgary and assumed the position of Vice President and Controller of Gulf Canada. His responsibilities as Vice President, Finance of the Corporation are expected to be assumed by a new officer in the near future. -20- Robert W. Klassen has been Vice President, Operations of the Corporation since May 1998. Mr. Klassen was the Senior Development Engineer - International, from 1993 to May 1998. Mr. Klassen has been employed by Gulf Canada in various capacities since 1976. Prior to assuming his current position, Supramu Santosa was the Vice President, Administration of each of the Corporation's operating subsidiaries and held such position since 1989. Taufik Ahmad was appointed Vice President, Administration of the Corporation on February 15, 2001. Cliff W. Zeliff has been Vice President, Exploration of each of the Corporation's operating subsidiaries since 1990. Mr. Zeliff has been employed by the Corporation in various capacities since 1984. Alan Scott has been Secretary of the Corporation since November, 2000. Mr. Scott has been employed as legal counsel and in other capacities for Gulf Canada since 1978. ADDITIONAL INFORMATION Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities, options to purchase securities and interest of insiders in material transactions, where applicable, is contained in Gulf Indonesia's Management Proxy Circular dated March 19, 2001 provided to holders of common shares of Gulf Indonesia in connection with the Annual General Meeting of Shareholders to be held on May 7, 2001 the ("2001 Management Proxy Circular"). Additional financial information is provided in the Corporation's consolidated financial statements for the year ended December 31, 2000 filed with securities commissions in Canada and the Securities and Exchange Commission in the United States. Upon request to the Corporate Secretary, the Corporation will provide to any person or company: (i) one copy of the Corporation's AIF, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the AIF; (ii) one copy of the comparative consolidated financial statements of the Corporation for its most recently completed financial year for which financial statements have been filed together with the accompanying report of the auditor and one copy of the most recent interim financial statements of the issuer that have been filed, if any, for any period after the end of its most recently completed financial year; and (iii) one copy of the information circular of the Corporation in respect of its most recent annual meeting of the shareholders that involved the election of directors, or one copy of any annual filing prepared instead of that information circular, as appropriate. When the securities of the Corporation are in the course of a distribution pursuant to a short form prospectus, or a preliminary short form prospectus has been filed, copies of the foregoing documents and any other documents that are incorporated by reference into the short form prospectus or preliminary short form prospectus may also be obtained from the Secretary of the Corporation, upon request. -21- MISCELLANEOUS As used in this Annual Information Form, the following terms have the meanings indicated: "Bbls", "MBbls" and "MMBbls" mean barrels, thousand barrels and million barrels, respectively; "Mcf", "MMcf", "Bcf" and "Tcf" mean thousand cubic feet, million cubic feet, billion cubic and trillion cubic feet, respectively; "BOE", "MBOE" and "MMBOE" mean barrels of oil equivalent, thousand barrels of oil equivalent and million barrels of oil equivalent, respectively; "Bbls/d", "MBbls/d", "Mcf/d", "MMcf/d", "BOE/d" and "MBOE/d" mean barrels per day, thousand barrels per day, thousand cubic feet per day, million cubic feet per day, barrels of oil equivalent per day and thousand barrels of oil equivalent per day, respectively. Gross reserves or gross production are reserves or production attributable to the Corporation's interest prior to deduction of government take; net reserves or net production are reserves or production net of such government take. Natural gas volumes are converted to a BOE basis using the ratio of 6 Mcf of natural gas to one Bbl of oil and condensate. Unless otherwise indicated, per BOE calculations are on a per BOE sold basis. Natural gas volumes are stated at the official temperature and pressure bases of the area in which the reserves are located. Unless otherwise indicated, estimated reserves quantities as set forth in this Annual Information Form are based upon the Corporation's assumptions concerning future price and cost escalations. Additions to reserves are quoted in accordance with applicable Canadian industry standards. Under United States Statement of Accounting Standards No. 69, reserves additions from development would be considered part of revisions of previous estimates. Finding and development costs per BOE are calculated by dividing capital expenditures and exploration expenses by gross estimated proved reserves additions (excluding purchased reserves). Unless otherwise indicated, amounts expressed in dollars or $ are in United States dollars. The Indonesian government owns all of Indonesia's petroleum resources. The Indonesian state-owned oil and gas company, Perusahaan Pertambangan Minyak dan Gas Bumi Negara ("Pertamina"), manages all of Indonesia's petroleum resources on behalf of the Indonesian government and, in certain cases, enters into production sharing arrangements with private energy companies entitling such private energy companies to a portion of the production from the fields in the applicable production sharing area. The Corporation's reserves information presented in this Annual Information Form is based on estimates of reserves underlying the properties in which the Corporation has an interest under production sharing arrangements with Pertamina. All oil and natural gas reserves and production volumes presented in this Annual Information Form are, unless otherwise indicated, gross to the Corporation and reflect its interest prior to deduction of applicable government take payable to the Indonesian government as owner of the reserves under the applicable contractual arrangement. All Pertamina interests, other than working interests, and income and revenue taxes, are considered to be government take. Unless otherwise indicated, references to "crude oil" or "oil" include condensate. /s/ HENRY W. SYKES ---------------------------------- Henry W. Sykes Director /s/ MARCEL R. COUTU ---------------------------------- Marcel R. Coutu Director 31 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Gulf Indonesia Resources Limited (the company) is responsible for preparing the accompanying consolidated financial statements. The financial statements were prepared in accordance with accounting principles generally accepted in Canada and are necessarily based in part on management's best estimates and judgments. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. The financial information included elsewhere in the Annual Report is consistent with that contained in the financial statements. The company maintains a system of internal control including an internal audit function. Management believes that this system of internal control provides reasonable assurance that financial records are reliable and form a proper basis for preparation of financial statements. The internal control process includes communication to employees of the company's standards for ethical business conduct. The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board exercises this responsibility through its Audit Committee, none of whom are officers or employees of the company. The Committee meets with management, its internal auditors and the independent auditors to satisfy itself that each group is properly discharging its responsibilities and to review the consolidated financial statements and the independent auditors' report. The Audit Committee reports its findings to the Board of Directors for consideration in approving the consolidated financial statements for issuance to the shareholders. The Committee also considers, for review by the Board and approval by the Shareholders, the engagement or re-appointment of the external auditors. The consolidated financial statements have been examined by the independent auditors, Ernst & Young LLP, and their report follows. The independent auditors have full and free access to the Audit Committee. signed signature signed signature William T. Fanagan Murray E. Hesje William T. Fanagan Murray E. Hesje President and Chief Executive Officer Vice President, Finance February 12, 2001 AUDITORS' REPORT TO THE SHAREHOLDERS OF GULF INDONESIA RESOURCES LIMITED: We have audited the consolidated statements of financial position of Gulf Indonesia Resources Limited as at December 31, 2000 and 1999 and the consolidated statements of earnings (loss) and retained earnings (deficit) and cash flows for each of the years in the three year period ended December 31, 2000. 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 auditing standards generally accepted in Canada. Those standards require that we plan and perform an audit to obtain reasonable assurance 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. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2000 and 1999 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2000 in accordance with accounting principles generally accepted in Canada. signed signature Ernst & Young LLP Ernst & Young LLP Calgary, Canada Chartered Accountants February 12, 2001 32 CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGS (DEFICIT) (millions of United States dollars, except per share amounts)
YEAR ENDED DECEMBER 31 -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- EARNINGS (LOSS) REVENUES Gross oil and gas revenue (Note 1) $ 421 $ 246 $ 99 Government take 76 42 18 ---------- ---------- ---------- Net oil and gas revenue 345 204 81 Other 4 2 5 ---------- ---------- ---------- 349 206 86 ---------- ---------- ---------- EXPENSES Operating 33 35 27 Exploration 18 11 34 General and administrative 5 6 8 Depreciation, depletion and amortization 69 70 48 Finance charges, net (Note 2) 19 21 2 ---------- ---------- ---------- 144 143 119 ---------- ---------- ---------- Earnings (loss) before tax 205 63 (33) ---------- ---------- ---------- Income tax expense (recovery) (Note 3) 121 30 (3) ---------- ---------- ---------- Earnings (loss) for the year $ 84 $ 33 $ (30) ========== ========== ========== Earnings (loss) per common share (Note 4) $ 0.96 $ 0.37 $ (0.34) ========== ========== ========== RETAINED EARNINGS (DEFICIT) Balance, beginning of year $ (3) $ (36) $ (6) Earnings (loss) for the year 84 33 (30) ---------- ---------- ---------- Balance, end of year $ 81 $ (3) $ (36) ========== ========== ==========
(See summary of significant accounting policies and notes to consolidated financial statements) GULF INDONESIA RESOURCES LIMITED 33 CONSOLIDATED STATEMENTS OF CASH FLOWS (millions of United States dollars)
YEAR ENDED DECEMBER 31 -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- OPERATING ACTIVITIES Earnings (loss) for the year $ 84 $ 33 $ (30) Non-cash items included in earnings (loss) Depreciation, depletion and amortization 69 70 48 Exploration expense 18 11 34 Future tax expense (Note 3) 96 21 (9) Other 4 2 1 ---------- ---------- ---------- Cash generated from operations 271 137 44 Changes in non-cash working capital (Note 5) 19 (4) 16 ---------- ---------- ---------- 290 133 60 ---------- ---------- ---------- INVESTING ACTIVITIES Capital expenditures and exploration expenses (86) (66) (190) Increase in cash restricted in use (Note 10) (21) (73) (3) Changes in non-cash working capital (Note 5) -- (35) (1) ---------- ---------- ---------- (107) (174) (194) ---------- ---------- ---------- FINANCING ACTIVITIES Long-term debt repayments (Note 10) (103) (16) -- Proceeds from issue of long-term debt (Note 10) -- 18 93 ---------- ---------- ---------- (103) 2 93 ---------- ---------- ---------- Increase (decrease) in cash and short-term investments 80 (39) (41) Cash and short-term investments, beginning of year 27 66 107 ---------- ---------- ---------- Cash and short-term investments, end of year (Note 12) $ 107 $ 27 $ 66 ========== ========== ==========
(See summary of significant accounting policies and notes to consolidated financial statements) 34 CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (millions of United States dollars)
DECEMBER 31 --------------------------- 2000 1999 ------------ ------------ ASSETS CURRENT Cash and short-term investments (Note 12) $ 107 $ 27 Cash restricted in use (Note 10) 97 76 Accounts receivable (Note 12) 56 69 Other current assets (Note 6) 38 36 ------------ ------------ 298 208 Deferred charges 6 10 Property, plant and equipment (Notes 2 and 7) 756 757 ------------ ------------ $ 1,060 $ 975 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT Accounts payable $ 53 $ 52 Accounts payable - parent/affiliates (Note 8) 9 8 Current portion of long-term debt (Note 10) 31 39 Other current liabilities (Note 9) 19 13 ------------ ------------ 112 112 Long-term debt (Note 10) 111 206 Future income taxes (Note 3) 257 161 ------------ ------------ 480 479 ------------ ------------ Commitments and contingent liabilities (Note 13) SHAREHOLDERS' EQUITY Share capital (Note 11) 499 499 Retained earnings (deficit) 81 (3) ------------ ------------ 580 496 ------------ ------------ $ 1,060 $ 975 ============ ============
(See summary of significant accounting policies and notes to consolidated financial statements) Approved by the Board signed signature signed signature Robert H. Allen The Right Honourable Donald F. Mazankowski Robert H. Allen The Right Honourable Donald F. Mazankowski Director Director GULF INDONESIA RESOURCES LIMITED 35 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES OPERATIONS Gulf Indonesia Resources Limited (the company), formerly Asamera Canada Limited, was incorporated under the Canada Business Corporations Act and in August 1997 was continued under the Business Corporations Act, New Brunswick. At December 31, 2000, the company is a 72 per cent owned subsidiary of Gulf Canada Resources Limited. The company is involved in the exploration for, development and production of crude oil and natural gas in Indonesia. BASIS OF PRESENTATION The consolidated financial statements of the company include the accounts of all subsidiary companies. Substantially all of the activities of the company are conducted jointly with others and these activities are accounted for using the proportionate consolidation method. The financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada and conform in all material respects with International Accounting Standards. The impact of differences between accounting principles generally accepted in Canada and those in the United States are disclosed in Note 15. All amounts are reported in United States dollars unless otherwise indicated. PROPERTY, PLANT AND EQUIPMENT The successful efforts method of accounting is followed for oil and gas exploration and development costs. Initial acquisition costs of oil and gas properties and the costs of drilling and equipping successful exploration wells are capitalized. The costs of unsuccessful exploration wells are charged to earnings. All other exploration costs are charged to earnings as incurred. All development costs are capitalized. Maintenance and repairs are charged to earnings; renewals and betterments, which extend the economic life of the assets, are capitalized. Capitalized costs of proved oil and gas properties are amortized using the unit-of-production method based on estimated net proved oil and gas reserves (net reserves are after government take). As changes in circumstances warrant, the net carrying values of proved properties, plant and equipment are assessed to ensure that they do not exceed future cash flows from use. Capitalized costs of unproved properties are also assessed regularly to determine whether an impairment in value has occurred. The company has no ownership interest in the producing assets nor in the oil and gas reserves, but rather has the right to operate the assets and receive production and/or revenues from the sale of oil and gas in accordance with the production sharing agreements. Proved reserves have therefore been determined on a net entitlement basis, which takes into account projections of the government's share of production calculated with certain price and expenditure assumptions. SITE RESTORATION LIABILITIES Future obligations for site restoration costs, including dismantling plants and abandoning properties, are provided for using the estimated remaining lives of the related assets. INTEREST CAPITALIZATION Interest costs are capitalized on the net investments in major projects during their respective development stages. GOVERNMENT TAKE Operations conducted jointly with the Indonesian state oil and gas company (Pertamina) are reflected in these financial statements based on the company's proportionate interest in such activities. All Pertamina interests, other than working interests, and income and revenue taxes, are considered to be government take. Government take on production from Indonesian properties represents the entitlement of Pertamina to a portion of the company's share of crude oil, condensate and natural gas production and are recorded using rates in effect under the terms of contracts at the time of production. Certain of the company's withholding tax obligations are also classified as government take. Under the terms of each contract, the company and its joint venture partners (the Participants) are entitled to recover out of proceeds of production from such contract, substantially all of the non-capital costs incurred during each year as well as current year depreciation for capital costs and any costs unrecovered from prior years. Typically, the maximum cost recovery in any year is equal to 80 per cent of gross revenue. Pertamina and the Participants are entitled to share the remaining crude oil, condensate and natural gas profit based upon the terms contained in each contract. Post cost recovery, the Participant's pre-tax profit share is generally the rate that will provide an after-tax profit share of 15 per cent for crude oil and condensate production, prior to the domestic market obligations described below, and 27. 5 per cent to 35 per cent for gas production based on the corporate tax rate that applies to the specific contract. 36 After a period of five years starting the month of the first delivery of crude oil produced from each new field in the contract area, the Participant will typically have a domestic market obligation to sell a portion, not generally exceeding approximately 8 per cent to 9 per cent, of the crude oil produced from the contract area, at a specific price. This price varies from contract to contract, being $0.20 per barrel in older contracts and 10 per cent, 15 per cent or 25 per cent of market price in the more recent contracts, in each case calculated at the point of export. The domestic market obligation does not apply to natural gas production. The Indonesian government's share of revenue may vary considerably from one fiscal period to the next and also between contracts depending on the level of unrecovered prior period costs and current period exploration and development activity. FOREIGN CURRENCY TRANSLATION The accounting records of the company are maintained in United States dollars as substantially all of its operations are transacted in that currency. Monetary assets and liabilities denominated in foreign currencies are translated into United States dollars at year-end exchange rates. Non-monetary assets and liabilities denominated in foreign currencies are translated into United States dollars at historical rates. Revenues and expenses are translated at exchange rates prevailing at the transaction dates. Exchange gains and losses are included in earnings with the exception of the unrealized gains or losses on translation of long-term monetary liabilities, which are deferred and amortized over the remaining terms of such liabilities on a straight-line basis. PIPELINE TARIFFS Pipeline tariffs are charged against gross oil and gas revenue. INVENTORIES Materials and supplies inventories are valued at the lower of cost (determined on an average cost basis) and estimated net realizable value. DEFERRED CHARGES The company incurred certain costs in connection with the financing of the Corridor Gas Project (the Project). These costs have been recorded as deferred charges and, upon completion of the Project construction period in 1999, are being amortized over the remaining term of the loan. INCOME TAXES The company follows the liability method of tax allocation accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and measured using substantively enacted tax rates that will be in effect when the differences are expected to reverse. Prior to January 1, 1999, the company followed the deferral method of tax allocation accounting whereby deferred taxes are recorded based on differences in timing between the recognition of revenues and expenses for financial reporting and income tax purposes. STOCK OPTIONS The company has a fixed stock option plan which is described in Note 11. The company does not recognize any compensation expense when stock options are issued to employees. Any consideration paid by employees on exercise of stock options is credited to share capital. MEASUREMENT UNCERTAINTY Certain items recognized in the financial statements are subject to measurement uncertainty. The recognized amounts of such items are based on the company's best information and judgment. Such amounts are not expected to change materially in the near term. The amounts recorded for depletion and depreciation as well as the recovery of the carrying values of property, plant and equipment depend on estimates of oil and gas reserves and the economic lives and future cash flows from related assets. The primary factors affecting these estimates are technical engineering assessments of producible quantities of oil and gas reserves in place and economic constraints such as the availability of commercial markets for the company's gas production as well as assumptions related to anticipated commodity prices and the costs of development and production of the reserves. GULF INDONESIA RESOURCES LIMITED 37 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (amounts expressed in millions of United States dollars, except where otherwise noted) 1. GROSS OIL AND GAS REVENUE Included as a charge against gross oil and gas revenue are the following pipeline tariffs paid to third parties:
YEAR ENDED DECEMBER 31 -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Pipeline tariffs - gas $ 38 $ 37 $ 5 Pipeline tariffs - oil 1 1 1 ---------- ---------- ---------- $ 39 $ 38 $ 6 ========== ========== ==========
2. FINANCE CHARGES, NET
YEAR ENDED DECEMBER 31 -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Interest expense on Corridor Loan(a) $ 18 $ 19 $ 2 Letter of credit fees(b) 2 2 -- Less: interest income on restricted cash related to the Corridor Loan (5) (1) -- ---------- ---------- ---------- Cash finance charges, net 15 20 2 Amortization of debt placement costs 4 1 -- ---------- ---------- ---------- $ 19 $ 21 $ 2 ========== ========== ==========
(a) Interest and commitment fees related to the Corridor Loan were capitalized during the Project construction period (2000 - $nil; 1999 - $1 million; and 1998 - $15 million). (b) As required under the terms of the Corridor Loan, the company's parent, Gulf Canada Resources Limited, made available to the company a letter of credit totalling $42 million. During 2000, the letter of credit was replaced with cash. (c) Cash interest paid (including letter of credit fees) and included in the determination of earnings (loss) was $26 million for 2000 (1999 - $14 million; 1998 - $nil). 3. INCOME TAX Effective tax rate reconciliation: The income tax expense (recovery) reflects an effective tax rate that differs from the Canadian statutory rate of 44 per cent. This difference is mainly the result of the following:
YEAR ENDED DECEMBER 31 -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Earnings (loss) before income taxes $ 205 $ 63 $ (33) ---------- ---------- ---------- Computed income tax expense (recovery) at the statutory rate $ 90 $ 28 $ (14) Difference between statutory tax rate and PSC tax rate 27 11 (1) Non-deductible costs related to amortization of assets with no tax basis 1 1 1 Petroleum revenue tax 2 1 1 Non-taxable revenues (6) (3) (3) Unrecorded income tax benefit arising from losses of non-producing subsidiaries(a) 6 3 12 Recognition of previously unrecognized temporary differences(b) -- (10) -- Other 1 (1) 1 ---------- ---------- ---------- Income tax expense (recovery) $ 121 $ 30 $ (3) ========== ========== ========== Current tax expense $ 25 $ 9 $ 6 Future tax expense 96 21 (9) ---------- ---------- ---------- Income tax expense (recovery) $ 121 $ 30 $ (3) ========== ========== ==========
38 (a) At December 31, 2000, certain non-producing subsidiaries of the company have accumulated losses for tax purposes of approximately $55 million which may be carried forward and used to reduce taxable income in these companies in future years. The potential income tax benefits related to these items have not been reflected in the accounts. (b) During 1999, the company recognized $10 million of previously unrecognized income tax benefits related to the planned development of the non-producing South Jambi B PSC. The potential income tax benefits of exploration expenses had not previously been reflected due to insufficient likelihood of realization of these benefits. (c) Cash income tax paid and included in the determination of earnings (loss) was $15 million for 2000 (1999 - $6 million; 1998 - $6 million). Components of the company's future tax liability: The future tax liability comprises:
DECEMBER 31 ------------------------ 2000 1999 ---------- ---------- Differences between tax bases and reported amounts of depreciable assets(a) $ 250 $ 154 Income tax benefit arising from losses of non-producing subsidiaries(b) 31 25 Valuation allowance(b) (24) (18) ---------- ---------- $ 257 $ 161 ========== ==========
(a) During 1999, the company recognized $9 million of previously unrecognized temporary differences associated with one of its producing subsidiaries. This amount has been accounted for as a reduction of property, plant and equipment and future income taxes. (b) A valuation allowance has been provided against the future tax asset related to the losses of certain non-producing subsidiaries as the company is not permitted to file a consolidated income tax return and accordingly, the company does not have reasonable assurance of realizing the benefits of these losses. During 1999, the company recognized previously unrecognized income tax benefits related to the planned development of the non-producing South Jambi B PSC. The potential income tax benefits of exploration expenses had not previously been reflected due to insufficient likelihood of realization of these benefits. 4. EARNINGS (LOSS) PER COMMON SHARE The weighted average number of common shares outstanding was 87,901,350 for 2000; 87,905,320 for 1999 and 87,906,600 for 1998. Stock options outstanding for all periods presented do not have a dilutive effect on earnings (loss) per common share. 5. CHANGES IN NON-CASH WORKING CAPITAL
YEAR ENDED DECEMBER 31 -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (Increase) decrease in non-cash working capital Accounts receivable $ 13 $ (29) $ 1 Other current assets (2) (6) (5) Accounts payable 1 (9) 9 Accounts payable - parent/affiliates 1 2 6 Other current liabilities 6 3 4 ---------- ---------- ---------- $ 19 $ (39) $ 15 ========== ========== ========== The change relates to the following activities: Operating $ 19 $ (4) $ 16 Investing -- (35) (1) Financing -- -- -- ---------- ---------- ---------- $ 19 $ (39) $ 15 ========== ========== ==========
GULF INDONESIA RESOURCES LIMITED 39 6. OTHER CURRENT ASSETS
DECEMBER 31 ----------------------- 2000 1999 ---------- ---------- Materials and supplies $ 35 $ 33 Product inventory 2 1 Prepaid expenses 1 2 ---------- ---------- $ 38 $ 36 ========== ==========
7. PROPERTY, PLANT AND EQUIPMENT
Accumulated Gross depreciation, investment depletion and Net at cost amortization investment ------------ ------------ ------------ Oil and gas property and equipment DECEMBER 31, 2000 $ 1,231 $ 475 $ 756 ============ ============ ============ December 31, 1999 $ 1,163 $ 406 $ 757 ------------ ------------ ------------
Property, plant and equipment not being amortized at December 31, 2000 was $238 million (December 31, 1999 - $233 million). 8. ACCOUNTS PAYABLE - PARENT/AFFILIATES Amounts due to the company's parent and affiliates are interest free, unsecured, and callable on demand and are as follows:
DECEMBER 31 ----------------------- 2000 1999 ---------- ---------- Gulf Canada Resources Limited $ 7 $ 6 GCRL International Limited 2 2 ---------- ---------- $ 9 $ 8 ========== ==========
Pursuant to inter-company agreements, the company's parent and affiliates provide certain technical, financial and accounting and administrative services to the company (2000 - $1 million; 1999 - $nil; 1998 - $1 million). In addition the company's parent incurs charges on behalf of the company. All services rendered to the company and charges incurred on its behalf are billed back to the company at cost. 9. OTHER CURRENT LIABILITIES
DECEMBER 31 ----------------------- 2000 1999 ---------- ---------- Income taxes payable $ 14 $ 5 Interest payable on long-term debt (Note 10) 2 8 Withholding tax payable 3 -- ---------- ---------- $ 19 $ 13 ========== ==========
10. LONG-TERM DEBT On February 26, 1997, the company, along with its partner in the Corridor PSC, entered into a Credit Agreement (the Corridor Loan) with various lending institutions (the Lenders) to provide up to $450 million of financing to fund the development of the Corridor Gas Project (the Project). The Lender's recourse under the Corridor Loan is limited to the Corridor PSC asset which has been pledged as collateral. The interest rate on the Corridor Loan is based on LIBOR plus 2 per cent, up to the date of overall completion of the Project, which occurred June 9, 2000, and LIBOR plus 1.75 per cent - 1.875 per cent thereafter. Interest and commitment fees were compounded during the Project construction period. The effective interest rate on the balance outstanding during 2000 was approximately 8.42 per cent (December 31, 1999 - 7.68 per cent; December 31, 1998 - 7.97 per cent). 40 Funds required to satisfy the next scheduled interest and principal payments and accumulated reserve requirements are held in offshore trust accounts. At December 31, 2000, the amount of restricted cash was $97 million (December 31, 1999 - $76 million). Funds in these offshore trust accounts earned interest at a rate of 6.23 per cent (December 31, 1999 - 5.09 per cent). Repayments on the Corridor Loan are equal quarterly installments which are scheduled to end in February 2007. Additional mandatory early repayments and optional prepayments may also occur, depending on the cash flow generated by the Project. Based on long-term debt outstanding at December 31, 2000, the company's repayment requirements for the next five years are $31 million for 2001 and $21 million for each of the years 2002 through 2005. These repayments assume a $6 million mandatory early repayment in 2001 and $nil for each of the years 2002 through 2005. 11. SHARE CAPITAL AUTHORIZED: COMMON SHARES - voting, unlimited number with a par value of U. S. $0.01. PREFERRED SHARES - unlimited number. These preference shares rank in priority to the common shares and may be issued from time to time in series, and with the price, rights, preferences, privileges and restrictions, including voting and conversion rights, to be fixed by the directors prior to their issue.
ISSUED AND OUTSTANDING: Number Amount ----------- ----------- COMMON SHARES: AT DECEMBER 31, 1998 87,906,600 $ 499 Shares forfeited under restricted stock plan(a) (5,250) -- ----------- ----------- AT DECEMBER 31, 1999 AND 2000 87,901,350 $ 499 =========== ===========
(a) On October 3, 1999, pursuant to the terms of the company's 1997 Restricted Stock Plan, 97,350 common shares (net of forfeitures) were issued to certain individuals in exchange for performance of services. The restricted stock vested on October 3, 1999 and the benefit related to the performance of services in exchange for the restricted stock was recognized in income over the two year vesting period. (b) The company has a fixed option plan. Pursuant to the terms of the Gulf Indonesia Resources Limited 1997 Stock Option and Incentive Plan, implemented in August 1997, the company may grant options to its employees at any time prior to December 31, 2007. The maximum number of common shares which may be issuable at any particular time is 10 per cent of the outstanding common shares. Options outstanding are granted at prices determined at the time the option is granted, provided that the exercise price is not less than the fair market value of the common shares on the date of grant, and have a maximum term of 10 years. Under the plan, 2,688,510 shares (1999 - 3,009,219; 1998 - 3,324,960) are reserved but unallocated. A summary of the status of the company's stock options as at December 31, 2000 and 1999 and changes during the years then ended are presented below:
2000 1999 -------------------------------- -------------------------------- WEIGHTED Weighted AVERAGE Average EXERCISE Exercise SHARES PRICE Shares Price -------------- -------------- -------------- -------------- Outstanding, beginning of year 5,776,916 $ 18.29 5,461,700 $ 18.63 Granted 738,125 8.16 369,250 11.25 Forfeited (417,416) (18.55) (54,034) (4.46) -------------- -------------- -------------- -------------- Outstanding, end of year 6,097,625 $ 17.04 5,776,916 $ 18.29 ============== ============== ============== ============== Options exercisable at year-end 4,737,375 5,087,666 Weighted average fair value of options granted during the year $ 3.15 $ 4.13
GULF INDONESIA RESOURCES LIMITED 41 The following table summarizes information about stock options outstanding at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------------------------------------------------------------------------------ AVERAGE NUMBER REMAINING AVERAGE NUMBER AVERAGE OUTSTANDING CONTRACTUAL EXERCISE OUTSTANDING EXERCISE RANGE OF EXERCISE PRICES AT 12/31/00 LIFE PRICE AT 12/31/00 PRICE ------------------------ ----------- ----------- ---------- ------------ ----------- $ 8.06 - 9.06 736,125 9.4 years $ 8.16 3,125 $ 8.06 $11.19 - 15.38 895,500 7.9 years $ 12.15 268,250 $ 14.32 $19.31 - 20.06 4,466,000 6.4 years $ 19.49 4,466,000 $ 19.49 --------- --------- ---------- --------- ---------- 6,097,625 7.0 years $ 17.04 4,737,375 $ 19.19 ========= ========= ========== ========= ==========
The company's aggregate stated capital at December 31, 2000 for purposes of the Business Corporations Act, New Brunswick is $1 million. 12. FINANCIAL INSTRUMENTS The company's financial instruments recognized on the balance sheet consist of cash and short-term investments, cash restricted in use, accounts receivable, current liabilities and long-term debt. Short-term investments are comprised of commercial paper with a maturity period no greater than 90 days. The average interest rate earned in 2000 from the short-term investments was 6.26 per cent (1999 - 5.15 per cent; 1998 - 5.65 per cent). Borrowings under the Corridor Loan are market rate based, thus, carrying value approximates fair value. The fair value of all other financial instruments approximate their carrying value. All of the company's onshore natural gas production is delivered to the Duri Steamflood, exchanged for Duri crude and sold to Itochu Petroleum Co, (Hong Kong) Ltd. Substantially all of the company's onshore crude oil production is sold domestically to Pertamina (2000 - $149 million; 1999 - $89 million; 1998 - $60 million). Offshore crude oil production from the west Natuna Sea is marketed to customers throughout Asia. Accounts receivable at December 31, 2000, includes $20 million from Pertamina, $17 million from Itochu and $19 million from other sources, the latter of which is subject to normal industry credit risks and routinely assessed for financial strength. 13. COMMITMENTS AND CONTINGENT LIABILITIES Prior to 1994, the Production Sharing Contracts (PSCs) required environmentally responsible operating practices but there was no requirement for abandonment and site restoration. For PSCs and amendments and extensions thereto signed after January 1, 1994, the contractor is responsible for abandonment and site restoration costs. For the company these abandonment and site restoration obligations involve 5 non-producing PSCs, the Corridor PSC which was amended and extended in October 1996 and the Kakap PSC which was amended and extended in January 1999. Per the terms of the amendments and extensions the company is responsible for abandonment and site restoration of facilities installed after the agreement was signed. Total anticipated future costs (including plugging and abandoning wells), given the company's current inventory of wells and facilities, is approximately $6 million. Facilities subject to abandonment and site restoration costs have been provided for. The Indonesian tax authorities have contested tax paid by the company in regard to certain revenues received outside of Indonesia. The company has been paying tax on this revenue based on a directive issued by the Director General of Taxation in 1989. In 1996, the directive was retroactively challenged by a new Director General of Taxation. The estimated potential unrecorded liability to the company is approximately $7 million at December 31, 2000. The company believes that the position taken by the tax authorities is unreasonable, particularly the retroactive application of the position, and that the assumptions on which the claim is based are incomplete. The company is contesting the claim. The company is also involved in various litigation, regulatory and other environmental matters in the ordinary course of business. In management's opinion, an adverse resolution of these matters would not have a material impact on operations or financial position. 42 14. SEGMENT INFORMATION
Onshore - Gas Onshore - Oil Offshore ----------------------- ------------------------ ------------------------ 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ------ ------ ------ ------ REVENUES Gross oil and gas revenue $ 228 $ 118 $ 7 $ 151 $ 91 $ 62 $ 45 $ 40 $ 30 Government take 13 7 -- 52 25 18 11 10 -- ------ ------ ------ ------ ------ ------ ------ ------ ------ Net oil and gas revenue 215 111 7 99 66 44 34 30 30 Other -- -- -- -- -- -- -- -- -- ------ ------ ------ ------ ------ ------ ------ ------ ------ 215 111 7 99 66 44 34 30 30 ------ ------ ------ ------ ------ ------ ------ ------ ------ EXPENSES Operating 9 9 1 15 18 19 9 8 7 Exploration -- -- -- -- -- -- -- -- -- General and administrative -- -- -- -- -- -- -- -- -- Depreciation, depletion and amortization 29 29 4 30 26 28 10 15 16 Finance charges 19 21 2 -- -- -- -- -- -- ------ ------ ------ ------ ------ ------ ------ ------ ------ 57 59 7 45 44 47 19 23 23 ------ ------ ------ ------ ------ ------ ------ ------ ------ EARNINGS (LOSS) BEFORE TAX 158 52 -- 54 22 (3) 15 7 7 Income tax expense (recovery) Current 11 -- -- 12 7 5 1 2 -- Future 77 30 1 17 3 (7) 6 2 4 ------ ------ ------ ------ ------ ------ ------ ------ ------ 88 30 1 29 10 (2) 7 4 4 ------ ------ ------ ------ ------ ------ ------ ------ ------ EARNINGS (LOSS) FOR THE YEAR $ 70 $ 22 $ (1) $ 25 $ 12 $ (1) $ 8 $ 3 $ 3 ====== ====== ====== ====== ====== ====== ====== ====== ====== TOTAL ASSETS $ 466 $ 438 $ 391 $ 234 $ 272 $ 254 $ 211 $ 180 $ 187 ====== ====== ====== ====== ====== ====== ====== ====== ====== CAPITAL EXPENDITURES AND EXPLORATION EXPENSES $ 10 $ 9 $ 73 $ 15 $ 14 $ 19 $ 32 $ 11 $ 9 ====== ====== ====== ====== ====== ====== ====== ====== ======
Gulf Indonesia has four reportable segments:onshore gas operations, onshore oil operations, offshore oil and gas operations, and exploration. The operations segments are involved in the production and development of crude oil and natural gas in Indonesia. The onshore operations are focused on the island of Sumatra while the offshore operations are located in the west Natuna Sea. The exploration segment is involved in the exploration for crude oil and natural gas in Indonesia. Gulf Indonesia's reportable segments are strategic business units that are managed separately as each has different operational requirements and focuses. Due to the nature of the operations, there are no intersegment sales and transfers. The corporate segment is comprised principally of the impact of crude oil hedging, interest income from unrestricted cash on hand, miscellaneous other revenue and general corporate expenditures. GULF INDONESIA RESOURCES LIMITED 43 14. SEGMENT INFORMATION (continued)
Exploration Corporate Total -------------------------- -------------------------- ------------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ------ ------ ------ ------ REVENUES Gross oil and gas revenue $ -- $ -- $ -- $ (3) $ 3) $ -- $ 421 $ 246 $ 99 Government take -- -- -- -- -- -- 76 42 18 ------ ------ ------ ------ ------ ------ ------ ------ ------ Net oil and gas revenue -- -- -- (3) (3) -- 345 204 81 Other -- -- -- 4 2 5 4 2 5 ------ ------ ------ ------ ------ ------ ------ ------ ------ -- -- -- 1 (1) 5 349 206 86 ------ ------ ------ ------ ------ ------ ------ ------ ------ EXPENSES Operating -- -- -- -- -- -- 33 35 27 Exploration 18 11 34 -- -- -- 18 11 34 General and administrative -- -- -- 5 6 8 5 6 8 Depreciation, depletion and amortization -- -- -- -- -- -- 69 70 48 Finance charges -- -- -- -- -- -- 19 21 2 ------ ------ ------ ------ ------ ------ ------ ------ ------ 18 11 34 5 6 8 144 143 119 ------ ------ ------ ------ ------ ------ ------ ------ ------ EARNINGS (LOSS) BEFORE TAX (18) (11) (34) (4) (7) (3) 205 63 (33) Income tax expense (recovery) Current -- -- -- 1 -- 1 25 9 6 Future (2) (12) (4) (2) (2) (3) 96 21 (9) ------ ------ ------ ------ ------ ------ ------ ------ ------ (2) (12) (4) (1) (2) (2) 121 30 (3) ------ ------ ------ ------ ------ ------ ------ ------ ------ EARNINGS (LOSS) FOR THE YEAR $ (16) $ 1 $ (30) $ (3) $ (5) $ (1) $ 84 $ 33 $ (30) ====== ====== ====== ====== ====== ====== ====== ====== ====== TOTAL ASSETS $ 72 $ 68 $ 55 $ 77 $ 17 $ 45 $1,060 $ 975 $ 932 ====== ====== ====== ====== ====== ====== ====== ====== ====== CAPITAL EXPENDITURES AND EXPLORATION EXPENSES $ 29 $ 32 $ 89 $ -- $ -- $ -- $ 86 $ 66 $ 190 ====== ====== ====== ====== ====== ====== ====== ====== ======
44 15. UNITED STATES ACCOUNTING PRINCIPLES If United States generally accepted accounting principles (U.S. GAAP) had been followed, the earnings (loss) and earnings (loss) per common share would have been as follows:
YEAR ENDED DECEMBER 31 -------------------------------- 2000 1999 1998 -------- -------- -------- EARNINGS (LOSS) BEFORE TAX, as reported $ 205 $ 63 $ (33) Adjustments: New asset values (a) -- -- (4) EARNINGS (LOSS) BEFORE TAX, as adjusted 205 63 (37) -------- -------- -------- Income tax recovery (expense), as reported (121) (30) 3 Income tax recovery (a) -- -- 4 -------- -------- -------- (121) (30) 7 -------- -------- -------- EARNINGS (LOSS), as adjusted $ 84 $ 33 $ (30) ======== ======== ======== EARNINGS (LOSS) PER COMMON SHARE ($/SHARE) $ 0.96 $ 0.37 $ (0.34) ======== ======== ========
Comprehensive income, as defined by Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income", is equivalent to earnings (loss) as presented. If U. S. GAAP were followed, amounts on the Consolidated Statements of Cash Flow would be presented as follows:
YEAR ENDED DECEMBER 31 -------------------------------- 2000 1999 1998 -------- -------- -------- OPERATING ACTIVITIES CASH GENERATED FROM OPERATIONS, as reported (d) $ 271 $ 137 $ 44 Changes in non-cash working capital, as reported 19 (4) 16 Adjustments: Geological and geophysical expenditures (e) (8) (10) (13) -------- -------- -------- Operating activities, as adjusted $ 282 $ 123 $ 47 ======== ======== ======== INVESTING ACTIVITIES, as reported $ (107) $ (174) $ (194) Adjustments: Geological and geophysical expenditures (e) 8 10 13 -------- -------- -------- Investing activities, as adjusted $ (99) $ (164) $ (181) ======== ======== ========
If U. S. GAAP were followed, amounts on the Consolidated Statements of Financial Position would be adjusted as follows:
DECEMBER 31, -------------------- 2000 1999 -------- -------- Increase (decrease) ASSETS $ -- $ -- ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY Contributed surplus(b) $ 11 $ 11 Deficit(a)(b) (11) (11) -------- -------- $ -- $ -- ======== ========
The financial statements have been prepared in accordance with accounting principles generally accepted in Canada which, in the case of the company, conform in all material respects with those in the United States except that: (a) Prior to January 1, 1999, the financial statements would reflect the effect of adopting Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109). SFAS 109 requires a restatement, to pre-tax amounts, of the new asset values reflected in the accounts in connection with the parent company's GULF INDONESIA RESOURCES LIMITED acquisition of the company in 1988 and the acquisition of Gulf Resources (Kakap) Ltd. on February 18, 1997. These differences result in additional depreciation, depletion and amortization charges and related income tax recoveries over the lives of the related assets. Effective January 1, 1999 such differences have been eliminated as the company retroactively changed (with restatement of prior periods) its method of accounting for income taxes under Canadian GAAP. While the new Canadian standards are substantially identical to those of SFAS 109, the method and assumptions used to apply these new standards in the Canadian GAAP financial statements differ in some respects from those applied to SFAS 109. The U.S. GAAP financial statements shall reflect application of these standards consistent with the Canadian GAAP financial statements prospectively from January 1, 1999. (b) Prior to the company going public in 1997, the costs of certain of the company's technical, financial, accounting and administrative services were borne by the company's parent on the company's behalf. Under U.S. GAAP, these costs would be recognized as additional general and administrative expenses offset by contributions to capital. These adjustments have been calculated based on a specific allocation of salary costs of individuals providing technical services to the company and a general allocation of corporate overhead determined using comparative ratios of reserves, sales volumes and assets of the company and its parent. (c) Unrealized gains or losses arising on translation of long-term liabilities repayable in foreign funds would be included in earnings in the period in which they arise in the United States. At December 31, 2000 and December 31, 1999, no such liabilities existed. (d) Under U.S. GAAP, "cash generated from operations" as defined by the company would not be presented in the Consolidated Statement of Cash Flows as it excludes the effect of changes in non-cash working capital and therefore differs from the definition of operating cash flow under Statement of Financial Accounting Standards No. 95. The company has presented this item for Canadian GAAP as it is commonly used by oil and gas investors in Canada as a measure of performance and liquidity and is normally presented in Canadian financial statements. (e) Under U.S. GAAP, geological and geophysical expenditures would be classified as operating activities. (f) Statement of Financial Accounting Standards (FAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended by FAS 137 and 138) is effective for fiscal years beginning after June 15, 2000. These pronouncements have no impact on the company's consolidated financial statements. Additional disclosure STOCK-BASED COMPENSATION PLANS The Financial Accounting Standards Boards Statement No. 123, "Accounting for Stock-Based Compensation" (FAS 123) requires the fair value of stock-based compensation to be either recorded as compensation over the service period or the impact of the use of fair values are to be disclosed in the financial statements. The company applies Accounting Principles Board Opinion No. 25 (APB 25) and related Interpretations in accounting for its plans. As a result, no compensation cost has been recognized in income for its fixed stock option plan as under APB 25 the exercise price of the company's plans equal the market value of the underlying stock on the date of grant. Pro forma disclosures of earnings (loss) and earnings (loss) per common share are presented below as if the company had adopted the cost recognition requirements under FAS 123. The compensation cost for the stock-based compensation for 2000 was $2 million (1999 - $3 million; 1998 - $10 million). Pro forma disclosures are not likely to be representative of the effects on reported earnings for future years.
YEAR ENDED DECEMBER 31 ------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Earnings (loss) As reported $ 84 $ 33 $ (30) Pro forma $ 82 $ 30 $ (40) Earnings (loss) per common share ($/share) As reported $ 0.96 $ 0.37 $ (0.34) Pro forma $ 0.94 $ 0.33 $ (0.46) ========== ========== ==========
The fair value of the options granted during 2000 is estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions: expected volatility of 50 per cent (1999 - 55 per cent; 1998 - 42 per cent); risk-free interest rate of 5.1 per cent (1999 - 6.5 per cent; 1998 - 5.0 per cent); and expected life of 3 years (1999 - 3 years; 1998 - 3 years). 16. RECLASSIFICATIONS Certain amounts for 1999 and 1998 have been reclassified to conform with the presentation adopted for 2000. 21 MANAGEMENT'S DISCUSSION AND ANALYSIS OUTSTANDING FUNDAMENTALS YIELD RECORD RESULTS o Record cash generation of $271 million or $3.08 per share was nearly double 1999 levels and over six times that of 1998. o Record earnings of $84 million or $0.96 per share were nearly 160 per cent higher than in 1999. o Gulf Indonesia continues to be a low-cost producer. In 2000, we reduced operating costs to $1.95 per boe, down 5 per cent from 1999 and 38 per cent from 1998. o The company replaced 437 per cent of 2000 production at a finding and development cost of $1.15 per boe. Over the past three years, Gulf Indonesia has replaced 391 per cent of production at a finding and development cost of $2.03 per boe. o Gulf Indonesia became debt free on a net basis during the third quarter of 2000. At year end, the company had a net cash surplus of $62 million. o The company renegotiated the Corridor Loan facility to alter the terms such that disbursements occur quarterly rather than semi-annually, providing more timely access to restricted funds. RESULTS FROM OPERATIONS Cash generated from operations was $271 million in 2000, a 97 per cent improvement over 1999 and a 509 per cent improvement over 1998. Gross revenue in 2000 was $421 million, a 71 per cent improvement over 1999, primarily due to higher prices. The improvement over 1998 relates to increases in both realized price and volumes from the onshore natural gas segment that commenced production in October 1998. Government take ranged between 17 and 18 per cent of gross oil and gas revenue in each of the three years. However, rates vary significantly by segment, as discussed further in this document. Operating expenses were $1.95 per boe in 2000, representing a five per cent reduction from 1999 and a 38 per cent reduction when compared to 1998. The improvement over 1999 relates to operating efficiencies, while the reduction from 1998 primarily reflects the addition of low cost natural gas production since October 1998. Exploration expense has fluctuated significantly over the three year period. These fluctuations are explained in the exploration segment. Finance charges are reported net of interest income on cash which is restricted in use under the terms of the Corridor Loan. An explanation of year-over-year changes is included in the onshore natural gas segment. Current income tax expense was $25 million in 2000 compared to $9 million in 1999 and $6 million in 1998. The substantial increase in 2000 is detailed in the onshore natural gas segment. Overall income tax expense (current and future) reflects effective rates of 59 per cent in 2000, 48 per cent in 1999 and 9 per cent in 1998. The variability in effective rates results from the company's inability to recognize a tax recovery for exploration expense related to non-producing PSCs. This situation occurs because Indonesian income tax returns are not filed on a consolidated basis as each PSC is "ring fenced," which is discussed further in the exploration segment. 22 TOTAL COMPANY OPERATIONS
2000 1999 1998 US$ US$/ US$ US$/ US$ US$/ MILLION BOE million boe million boe --------- -------- --------- -------- --------- -------- Gross oil and gas revenue 421 24.69 246 14.18 99 11.46 Government take (76) (4.44) (42) (2.45) (18) (2.03) --------- -------- --------- -------- --------- -------- Net oil and gas revenue 345 20.25 204 11.73 81 9.43 Other revenue 4 0.23 2 0.14 5 0.58 Operating expense (33) (1.95) (35) (2.05) (27) (3.17) Exploration expense (18) (1.07) (11) (0.64) (34) (3.88) General and administration expense (5) (0.33) (6) (0.34) (8) (0.97) DD&A expense (69) (4.06) (70) (4.02) (48) (5.53) Finance charges, net Cash (15) (0.86) (20) (1.13) (2) (0.26) Amortization of debt placement costs (4) (0.24) (1) (0.08) -- -- Income tax expense Current (25) (1.47) (9) (0.49) (6) (0.61) Future (96) (5.56) (21) (1.24) 9 1.04 --------- -------- --------- -------- --------- -------- Earnings (loss) 84 4.94 33 1.88 (30) (3.37) Add back non cash items 187 10.93 104 6.02 74 8.48 --------- -------- --------- -------- --------- -------- Cash generated from operations 271 15.87 137 7.90 44 5.11 --------- -------- --------- -------- --------- -------- Volumes sold (mboe/d) (gross/net) 46.6/39.7 47.6/41.7 23.8/20.1 --------- -------- --------- -------- --------- -------- WTI (US$/bbl) 30.20 19.24 14.43 --------- -------- --------- -------- --------- --------
CAPITAL AND EXPLORATION EXPENDITURES During 2000, the company replaced 437 per cent of its production at a finding and development cost of $1.15 per boe. Over the three-year period, reserve additions replaced an average of 391 per cent of production at a finding and development cost of $2.03 per boe. Exploration/delineation spending for 2000 was $29 million compared to $32 million in 1999 and $89 million in 1998, reflecting changes in level and composition of exploration drilling activity over the three-year period. The company drilled ten exploration/delineation wells in 2000, compared to five wells in 1999 and 24 wells in 1998. CAPITAL AND EXPLORATION EXPENDITURES
(millions of dollars) 2000 1999 1998 -------- -------- -------- Exploration/Delineation Onshore natural gas 6 11 17 Onshore oil 7 14 42 Offshore oil/gas 15 6 29 New ventures 1 1 1 -------- -------- -------- 29 32 89 -------- -------- -------- Development Onshore natural gas 10 9 73 Onshore oil 15 14 19 Offshore oil/gas 32 11 9 -------- -------- -------- 57 34 101 -------- -------- -------- Total capital and exploration expenditures 86 66 190 -------- -------- -------- Proved reserve additions (gross mmboe) 74.5 42.1 51.8 -------- -------- -------- Finding and development costs (US$/gross proved boe added) $ 1.15 $ 1.57 $ 3.68 -------- -------- -------- Proved reserve replacement (per cent of production) 437% 242% 596% -------- -------- --------
GULF INDONESIA RESOURCES LIMITED 23 [BAR CHARTS] 24 Development drilling and project capital spending of $57 million increased by $23 million over 1999 levels and $44 million over 1998 levels. The main reason for the year-over-year increase is due to expenditures related to the West Natuna Gas Project (2000 - $30 million; 1999 - $13 million) which was completed in the fourth quarter of 2000. The 1998 expenditures included $73 million related to the development of the Corridor PSC reserves. SEGMENTS Gulf Indonesia reports its year-to-year operations in five business segments: onshore natural gas, onshore oil, offshore oil/gas, exploration and corporate. Each of the segments is detailed in this report. See Note 14 to the consolidated financial statements for additional segment information. ONSHORE NATURAL GAS OPERATIONS The onshore natural gas segment consists of operations in the Corridor PSC. Related condensate production from this block is reported under the onshore oil segment, while exploration activity related to this segment is reported under the exploration segment. Cash generated from onshore gas operations was $180 million in 2000, representing 66 per cent of the company's total cash generated from operations, as compared to 60 per cent in 1999 and 9 per cent in 1998. Gross revenue for 2000, before pipeline tariff, was $266 million, a 72 per cent increase over 1999 due to a 66 per cent improvement in realized price and a 3 per cent improvement in volumes sold. Natural gas prices are dependent on crude oil prices as the company's contracted natural gas volumes are exchanged for Duri crude oil production on an energy equivalent basis. The increase in price includes not only the 57 per cent improvement in the WTI price, but also the benefit of reduced differentials (discounts) between Duri crude and WTI, which were approximately 13 percent in 2000 versus 18 per cent in 1999. Over the last five years the differential has averaged 15 per cent The year-over-year volume increase in 2000 reflects lower volumes during the start-up period (January 1999) when gas production was constrained by restricted pipeline capacity. Volumes reported by the company for all years ONSHORE NATURAL GAS OPERATIONS
2000 1999 1998(1) US$ US$/ US$ US$/ US$ US$/ million boe(2) million boe(2) million boe(2) --------- --------- --------- --------- --------- --------- Gross gas revenue Before pipeline tariff 266 26.22 155 15.83 12 9.94 Pipeline tariff (38) (3.72) (37) (3.72) (5) (3.72) Government take (13) (1.29) (7) (0.75) -- (0.40) --------- --------- --------- --------- --------- --------- Net gas revenue 215 21.21 111 11.36 7 5.82 Operating expense Before one time insurance settlement (9) (0.94) (12) (1.28) (1) (1.04) One time insurance settlement -- -- 3 0.29 -- -- DD&A expense (29) (2.87) (29) (3.00) (4) (3.57) Finance charges, net Cash (15) (1.46) (20) (2.00) (2) (1.88) Amortization of debt placement costs (4) (0.39) (1) (0.15) -- -- Income tax expense Current (11) (1.07) -- -- -- -- Future (77) (7.63) (30) (3.08) (1) (0.78) --------- --------- --------- --------- --------- --------- Earnings (loss) 70 6.85 22 2.14 (1) (1.45) Add back non-cash items 110 10.89 60 6.23 5 4.35 --------- --------- --------- --------- --------- --------- Cash generated from operations 180 17.74 82 8.37 4 2.90 --------- --------- --------- --------- --------- --------- Volumes sold (gross/net) mmcf/d 166/159 161/154 20/19 mboe/d 27.7/26.5 26.8/25.7 3.3/3.2 --------- --------- --------- --------- --------- --------- Unrecovered cost pools - producing PSCs Costs immediately eligible for recovery 48 148 132 Costs subject to depreciation 88 128 158 --------- --------- --------- --------- --------- --------- 136 276 290 --------- --------- --------- --------- --------- ---------
(1) Gas deliveries commenced October 1998 (2) US$/boe based on natural gas boe volumes GULF INDONESIA RESOURCES LIMITED 25 presented represent 60 per cent of the total volumes from the Corridor Gas Project (Project). Government take in all three years was approximately six per cent of gross revenue. The low rate reflects substantial natural gas cost pools and a lower government take percentage for natural gas compared to liquids. Government take is expected to remain at these low levels throughout 2001. Operating expense per boe (before the benefit of a 1999 insurance recovery) dropped 27 per cent from $1.28 per boe in 1999 to $0.94 per boe in 2000 due to cost reduction initiatives, including the installation of pretreatment facilities at the Grissik gas plant in the second quarter of 2000. The depreciation, depletion and amortization rate per boe was lower in both 1999 and 2000, primarily as a result of significant reserve additions in 1998 and 1999. Finance charges include cash interest expense and amortization of debt placement costs and are net of interest income on cash restricted in use related to the Corridor Loan. Cash finance charges of $15 million were $5 million below 1999 levels, due largely to repayments of the Corridor Loan as more fully discussed in the "Liquidity and Capital Resources" section. During 1998, the majority of the finance costs incurred on the Corridor Loan were capitalized prior to the completion of construction of the Corridor gas plant and facilities in the fourth quarter of 1998. The amortization of debt placement costs was $4 million in 2000 compared to $1 million in 1999, due to acceleration of the provision resulting from mandatory early repayments of the Corridor Loan, as discussed in the "Liquidity and Capital Resources" section. Total income tax expense was $88 million in 2000, $30 million in 1999 and $1 million in 1998. The effective rate was approximately 56 percent, 59 per cent and (117) per cent, respectively. While there were no current or cash income taxes in either 1999 or 1998, high realized prices in 2000 served to increase the present value of the company's tax pools by accelerating their recovery. This acceleration resulted in full utilization of the Corridor PSC's available tax pools and $11 million of current taxes being recognized in the fourth quarter of 2000. The extent of cash taxes in future periods will depend on revenues and the availability of tax-deductible cost, including the remaining tax depreciation on the Project facilities. All future costs in the Corridor PSC will be immediately available for tax deduction with the exception of the cost of production facilities and other tangible equipment which are depreciated over a specified period beginning in the year the particular asset is placed into service. As part of the Project, the company incurred certain costs on behalf of Pertamina and consequently has been recording an increased share of production as repayment of these costs. Full repayment of these cost occurred in December 2000, resulting in the company's reported share of the Project's results decreasing from 60 per cent to 54 per cent effective January 2001. ONSHORE OIL OPERATIONS The onshore oil segment consists of crude oil and condensate operations in the Corridor PSC, Corridor TAC, Jambi EOR and "other" which includes Block A and an overriding royalty. Exploration activity related to these blocks is reported under the exploration segment. Cash generated from onshore oil operations was $72 million in 2000, up 76 per cent from 1999 and 260 per cent from 1998, primarily as a result of increased realized prices and reduced operating expenses. Sales volumes of 14,600 b/d in 2000 were unchanged from 1999 levels and two per cent higher than 1998. Sales volumes before "other" were 14,300 b/d in 2000, up four per cent over 1999 and eight per cent over 1998, as successful development drilling programs in the Corridor TAC and Jambi EOR more than offset natural reservoir declines. "Other" volumes include an overriding royalty production payment where volumes decline in periods of higher realized prices. ONSHORE OIL OPERATIONS
2000 1999 1998 ------------ ------------ ------------ Volumes sold (gross/net) Crude oil and condensate (mb/d) Corridor PSC 3.6 / 3.1 4.2 / 3.5 3.9 / 3.3 Corridor TAC 8.1 / 5.0 7.2 / 4.6 7.4 / 4.6 Jambi EOR 2.6 / 1.5 2.3 / 2.0 2.0 / 1.8 ------------ ------------ ------------ 14.3 / 9.6 13.7 / 10.1 13.3 / 9.7 Other 0.3 / 0.3 0.9 / 0.8 1.0 / 1.0 ------------ ------------ ------------ 14.6 / 9.9 14.6 / 10.9 14.3 / 10.7 ------------ ------------ ------------
26 ONSHORE OIL OPERATIONS
2000 1999 1998 US$ US$/ US$ US$/ US$ US$/ MILLION Bbl million Bbl million Bbl --------- --------- --------- --------- --------- --------- Gross liquids revenue 151 28.18 91 17.14 62 11.95 Government take (52) (9.67) (25) (4.66) (18) (3.30) --------- --------- --------- --------- --------- --------- Net liquids revenue 99 18.51 66 12.48 44 8.65 Operating expense (15) (2.81) (18) (3.36) (19) (3.63) DD&A expense (30) (5.58) (26) (4.89) (28) (5.38) Income tax recovery (expense) Current (12) (2.32) (7) (1.25) (5) (0.94) Future (17) (3.08) (3) (0.71) 7 1.32 --------- --------- --------- --------- --------- --------- Earnings (loss) 25 4.72 12 2.27 (1) 0.02 Add back DD&A and future income tax expense 47 8.66 29 5.60 21 4.06 --------- --------- --------- --------- --------- --------- Cash generated from operations 72 13.38 41 7.87 20 4.08 --------- --------- --------- --------- --------- --------- Unrecovered cost pools - producing PSCs Costs immediately eligible for recovery 77 92 99 Coats subject to depreciation 8 10 13 --------- --------- --------- --------- --------- --------- 85 102 112 --------- --------- --------- --------- --------- ---------
Government take averaged approximately 34 per cent of gross revenue during 2000 compared to 27 per cent of gross revenue in 1999 and 1998. The seven per cent increase in the government take rate in 2000 reflects the full utilization in 2000 of certain opening cost pools for the Jambi EOR contract area. Operating expenses of $2.81 per boe in 2000 were 16 per cent below 1999 levels and 23 per cent below 1998 due primarily to cost cutting initiatives. DD&A expense was $5.58 per boe in 2000 compared to $4.89 per boe in 1999 and $5.38 per boe in 1998. This expense is based on net volumes and increased on a per boe basis in 2000 as a result of reserve revisions in 1999. Income tax expense was approximately 53 per cent of pre-tax earnings in 2000 compared to approximately 46 per cent in 1999. The increase in 2000 was due to lower overriding royalties, which have a tax rate of 20 per cent. OFFSHORE OIL/GAS OPERATIONS The offshore oil/gas segment consist of operations related to the Kakap PSC, located in the West Natuna Sea. Exploration activity related to this PSC is reported under the exploration segment. Cash generated from offshore operations was $24 million, compared to $20 million in 1999 and $23 million in 1998. Gross revenue was $45 million in 2000, higher than either 1999 or 1998 as stronger prices more than offset volume declines. Sales volumes declined from 6,200 b/d in 1999 and 1998 to 4,300 b/d in 2000 due to reservoir declines. Volumes in 1999 and 2000 benefited from the Jangkar and KRA South field, which were brought on stream in late 1998. Government take was $11 million in 2000, virtually unchanged from 1999 levels despite a 62 per cent increase in realized prices. During 2000, the West Natuna Gas Project was placed in service, allowing the company to benefit from additional cost pools. The government take obligation in 1998 was $nil due to lower realized prices and the ability to utilize cost pools carried forward from prior years. The increase in operating expenses per barrel is due to declining production and relatively fixed expenses. Upon start-up of the West Natuna gas project, operating expense on a boe basis will decline as these fixed costs will also support natural gas sales. DD&A expense, which is sensitive to net volumes sold, declined over the three-year period. Income tax effective rates were comparable in each of the three years. EXPLORATION This segment includes exploration activity related to both the company's producing and non-producing blocks, including onshore blocks at the South Jambi B. Tungkal and Calik PSCs. Also included are non-producing offshore blocks at the Northwest Natuna Block I, Pangkah, Ketapang and Sebuku PSCs. In 1999, the company relinquished its interests in the Halmahera, West Natuna and Merangin PSCs. Exploration expense was $18 million for 2000 compared to $11 million in 1999 and $34 million in 1998. The $7 27 OFFSHORE OIL/GAS OPERATIONS
2000 1999 1998 US$ US$/ US$ US$/ US$ US$/ MILLION BBL million Bbl million Bbl --------- --------- --------- --------- --------- --------- Gross liquids revenue 45 28.61 40 17.65 30 13.17 Government take (11) (7.09) (10) (4.63) -- -- --------- --------- --------- --------- --------- --------- Net liquids revenue 34 21.52 30 13.02 30 13.17 Operating expense (9) (5.55) (8) (3.50) (7) (3.24) DD&A expense (10) (6.58) (15) (6.35) (16) (6.91) Income tax expense Current (1) (0.77) (2) (0.65) -- -- Future (6) (3.40) (2) (1.14) (4) (1.64) --------- --------- --------- --------- --------- --------- Earnings 8 5.22 3 1.38 3 1.38 Add back DD&A and future Income tax expense 16 9.98 17 7.49 20 8.55 --------- --------- --------- --------- --------- --------- Cash generated from operations 24 15.20 20 8.87 23 9.93 --------- --------- --------- --------- --------- --------- Volumes sold (mb/d) (gross/net) 4.3/3.3 6.2/5.1 6.2/6.2 --------- --------- --------- --------- --------- --------- Unrecovered cost pools - producing PSCs Costs immediately eligible for recovery -- -- 5 Costs subject to depreciation 32 6 20 --------- --------- --------- --------- --------- --------- 32 6 25 --------- --------- --------- --------- --------- ---------
million increase over 1999 was mostly due to an $8 million charge associated with the costs of the unsuccessful Sawangan-IX well drilled in the non-producing Sakala Timur PSC. The company also increased its exploration activity during the year, drilling ten exploration wells compared to five wells in 1999. During 1998, the company drilled 24 wells. The success factor during each of these periods was 40 per cent, 80 per cent and 58 per cent, respectively. Income tax expense reflects effective rates which varied significantly over the three-year period, due to the company's inability to recognize a tax recovery on exploration expense related to non-producing PSCs. A tax recovery may be recognized in future years if it becomes likely at that time that these PSCs will be able to use available cost pools. The 1999 tax recovery reflects $11 million of future income tax recoveries related to the planned development of the South Jambi B PSC. The potential income tax benefits of exploration expenses in the South Jambi B PSC had not previously been reflected due to insufficient likelihood of realization of these benefits. CORPORATE The corporate segment includes general and administration expenses for the entire company, the impact of the company's hedging program and interest income related to unrestricted cash and short-term investments. In the second quarter of 1999, the company's Board of Directors approved the implementation of a limited crude oil hedging program to help ensure that its capital program could be funded from internally generated unrestricted cash flows. This program impacted net oil and gas revenues in both 2000 and 1999. A more detailed discussion of the company's hedging program is included under "Risks and Uncertainties -- Commodity Prices." Other revenue relates to interest income on cash and short-term investments (excluding interest income on cash restricted in use). Year-over-year improvements in interest income are directly attributable to the $80 million increase in unrestricted cash balances during the year. EXPLORATION
(millions of dollars) 2000 1999 1998 -------- -------- -------- Exploration expense Producing (3) (4) (7) Non-producing (15) (7) (27) -------- -------- -------- (18) (11) (34) Income tax recovery - future 2 12 4 -------- -------- -------- Earnings (loss) (16) 1 (30) -------- -------- --------
28 CORPORATE
(millions of dollars) 2000 1999 1998 -------- -------- -------- Net oil and gas revenue (3) (3) -- Other revenue 4 2 5 G&A expense (5) (6) (8) Income tax (expense) recovery Current (1) -- (1) Future 2 2 3 -------- -------- -------- Earnings (loss) (3) (5) (1) Add back non-cash items (2) (1) (2) -------- -------- -------- Cash generated from operations (5) (6) (3) -------- -------- --------
G&A expense has been reduced significantly over the three-year period, falling from $8 million in 1998 to $5 million in 2000. LIQUIDITY AND CAPITAL RESOURCES During 2000, the company moved to a cash surplus of $62 million from a net debt position of $142 million. Approximately $185 million of the $204 million improvement was the result of cash generated from operations exceeding capital and exploration expenditures. The remaining $19 million resulted from a decrease in non-cash working capital, of which a significant component was related to a $9 million increase in income tax payable for the Corridor PSC and to collection of outstanding value added tax receivables. Long-term debt was reduced by $103 million during 2000. Approximately $39 million was related to scheduled repayments, while $64 million was related to mandatory early repayments. Under the terms of the Corridor Loan, net cash flows from the Corridor PSC contribute to certain cash reserve requirements which the company reports as "cash restricted in use." Additionally, a specified percentage of the surplus cash is used to fund mandatory early repayments with the remainder released to the company. The mandatory early repayments were substantial in 2000 due to the increase in cash generation from the Corridor PSC, as discussed in the onshore natural gas segment The company has taken action to reduce cash restricted in use by altering the terms of the Corridor Loan such that disbursements occur quarterly rather than semiannually. On November 8, 2000 the first quarterly disbursement occurred resulting in $30 million, which would otherwise have been held until the first quarter of 2001, being released to the unrestricted category. Looking forward to 2001, the company expects to be able to fund approximately $150 million of capital spending with internally generated cash. Actual capital spending will depend partially on the timing of expenditures on capital projects, whether delineation wells are drilled and the results of the company's farmout activities. The company is actively looking at potential uses for its surplus cash. The cash may be used in whole or in part for funding of development following potential exploration successes, acquisitions, or debt repayments. The eventual use of the company's surplus cash may be influenced by certain risk factors in Indonesia, which are more fully described under "Risks and Uncertainties". RISKS AND UNCERTAINTIES INDONESIAN POLITICAL AND ECONOMIC ENVIRONMENT Substantially all of the company's assets are located in Indonesia. Although Gulf Indonesia has not historically experienced problems from civil unrest or disputes with the Indonesian government, Indonesia's current political and economic environment could impact the company's financial position, results of operations or prospects. The company expects that, should the need LIQUIDITY AND CAPITAL RESOURCES
DECEMBER 31 ----------------------------- (millions of dollars) 2000 1999 ------------ ------------ Cash and short-term investments $ 107 $ 27 Cash restricted in use 97 76 Less: Long-term debt (including current portion) (142) (245) ------------ ------------ Net cash (debt) position $ 62 $ (142) ------------ ------------
GULF INDONESIA RESOURCES LIMITED 29 arise, its ability to borrow additional funds at a reasonable rate could be negatively impacted by the current situation in Indonesia. While civil unrest exists in the Aceh Province, planning and negotiations related to the company's development of its gas reserves in the Block A PSC are ongoing. The company will continue to monitor the situation and re-evaluate its development plans if the situation warrants. The Indonesian government has exercised and continues to exercise significant influence over many aspects of the Indonesian economy, including the oil and gas industry. The Indonesian government recently undertook the following actions: o During 1999, two new laws (on revenue sharing and regional autonomy, respectively) were passed which will see a transfer of some of the economic and political power from the central government to the regions, effective January 1, 2001. o During 2000, a new oil and gas law was drafted and is under consideration by the Indonesian parliament. Under current Indonesian law, Pertamina is the sole entity authorized to manage Indonesia's petroleum resources on behalf of the Indonesian government. The proposed oil and gas law would see the management of petroleum resources transferred from Pertamina to an Executive Body that reports directly to the President of Indonesia. Pertamina itself would become an independent oil and gas company and, along with other oil and gas companies, would report to the Executive Body. It is unclear at the present time what impact, if any, the above will have on the company's financial position, results of operations or prospects. Further, an additional consequence of Indonesia's political and economic uncertainty is fluctuation in the Rupiah/U.S. dollar exchange rate. However, the currency volatility is not expected to have a material long-term impact on the company's financial position, as all current revenues are U.S. dollar-denominated, all major contracts entered into are in U.S. dollars and Rupiah-denominated expenses are limited to approximately 10-15 per cent of the company's overall expenditure profile. COMMODITY PRICES The company's financial results are substantially dependent upon the price of, and demand for, crude oil. Onshore oil production is sold to Pertamina in U.S. dollars at the Indonesian Crude Price (ICP), a price based on spot prices of internationally traded Indonesian crude oils, adjusted for quality. Offshore oil production is sold in the spot market. Natural gas production contracted from the Project is exchanged for Duni crude oil and is exported at a price based on a formula that yields not less than the Duri ICR. Crude oil prices have been volatile in the past and are expected to continue to be volatile in the near future, due to a number of economic factors beyond the company's control. Part of Gulf Indonesia's financial strategy is to fund exploration, maintenance and current development capital programs with internally generated cash flows. When necessary, the company will use hedging to help ensure the predictability of internal cash flows and help implement this strategy. Although the company does not have any outstanding hedge positions it will continue to assess its capital requirements and the need for price security in the future. SENSITIVITIES Based on current production and price assumptions, the estimated effect of a change in the following factors on the company's 2001 cash generated from operations and earnings, is set out in the table below. During 2000, the impact of changes in prices on the company's cash generated from operations was dramatically reduced from prior years (1999 - $12 million) as a result of the Corridor PSC becoming taxable. Cash generation is also influenced by the level of capital spending in the Corridor PSC as available tax pools (and hence current taxability) are impacted by the amount of spending in a particular year. SENSITIVITIES
millions of dollars) Cash Generation Earnings --------------- --------------- Prices: US$1.00/Bbl change in WTI oil price 6 6 Production: 1 mb/d change in crude oil and condensate 3 2 10 mmcf/d change in natural gas 5 4
[ERNST & YOUNG LLP LETTERHEAD] CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS We consent to the use of our report dated February 12, 2001 with respect to the consolidated financial statements of Gulf Indonesia Resources Limited included in the Annual Information Form, filed under cover of the Annual Report for the year ended December 31, 2000 (Form 40-F) with the United States Securities and Exchange Commission. We also consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-07886) pertaining to the Incentive Stock Option Plan of Gulf Indonesia Resources Limited of our report dated February 12, 2001 with respect to the consolidated financial statements of Gulf Indonesia Resources Limited included in the Annual Report (Form 40-F) for the year ended December 31, 2000. /s/ ERNST & YOUNG, LLP Calgary, Canada April 2, 2001 Chartered Accountants 43 SUPPLEMENTARY OIL AND GAS INFORMATION (millions of United States dollars) (unaudited)
2000 1999 1998 ------- ------- ------- RESULTS OF OIL AND GAS OPERATIONS Gross revenues derived from proved oil and gas reserves during the year $ 460 $ 284 $ 105 Less: Government take 76 42 18 Pipeline tariffs 39 38 6 ------- ------- ------- Net revenue derived from proved oil and gas reserves during the year 345 204 81 Less: Production costs 33 35 27 Exploration expense 18 11 34 Depreciation, depletion and amortization 69 70 48 Income tax expense (recovery) 121 30 (3) ------- ------- ------- Results of operations from producing activities $ 104 $ 58 $ (25) ======= ======= ======= COSTS INCURRED Costs incurred (capitalized and expensed during the year) for: Property acquisitions: Proved $ -- $ -- $ -- Unproved -- -- 1 Exploration 29 32 88 Development 57 34 101 ------- ------- ------- $ 86 $ 66 $ 190 ======= ======= ======= CAPITALIZED COSTS Proved properties $ 1,012 $ 949 $ 886 Unproved properties 180 179 179 Incomplete wells and facilities 39 35 52 ------- ------- ------- 1,231 1,163 1,117 Less related accumulated depreciation, depletion and amortization 475 406 336 ------- ------- ------- Net capitalized costs $ 756 $ 757 $ 781 ======= ======= =======
The standardized measure for calculating the present value of future net cash flows from proved oil and gas reserves is based on current costs and prices and a 10 per cent discount factor as prescribed by the Financial Accounting Standards Board (FASB). Accordingly, the estimated future net cash inflows were computed by applying selling prices prevailing at the end of the indicated period for crude oil and during the last month of the period indicated for other products to the estimated future production of proved reserves. Estimated future expenditures to be incurred in developing and producing proved reserves are based upon average costs incurred in each period presented and assume the continuation of economic conditions existing at the end of each year presented. Although these calculations have been prepared according to the standards described above, it should be emphasized that, due to the number of assumptions and estimates required in the calculations, the amounts are not indicative of the amount of net revenue that the company expects to receive in future years. They are also not indicative of the current value or future earnings that may be realized from the production of proved reserves nor should it be assumed that they represent the fair market value of the reserves or of the oil and gas properties. Although the calculations are based on existing economic conditions at each year end, such economic conditions have changed, and may continue to change significantly due to events such as the continuing changes in international crude oil availability and prices, and changes in government policies and regulations. While the calculations are based on the company's understanding of the established FASB guidelines, there are numerous other equally valid assumptions under which these assumptions could be made which would produce significantly different results. STANDARDIZED MEASURE
AS AT DECEMBER 31 --------------------------- 2000 1999 1998 ------- ------ ------ (millions of United States Dollars) Future cash inflows $ 3,639 $3,072 $1,009 Future development costs (278) (309) (254) Future production costs (447) (364) (324) Future income taxes (1,238) (924) (33) ------- ------ ------ Future net cash flows 1,676 1,475 398 10 per cent annual discount for estimated timing of cash flows (840) (649) (195) ------- ------ ------ Standardized measure of discounted future net cash flows $ 836 $ 826 $ 203 ======= ====== ======
CHANGES IN THE STANDARDIZED MEASURE DURING THE YEAR
YEAR ENDED DECEMBER 31 --------------------------- 2000 1999 1998 ------- ------ ------ (millions of United States Dollars) Sales of oil and gas produced net of production costs $ (315) $ (173) $ (55) Development costs incurred during the year 57 34 86 Extensions, discoveries and improved recovery, less related costs 254 158 36 Revisions of previous quantity and timing estimates (5) 43 47 Price and cost changes - selling prices 10 1,032 (507) - producing costs (18) 5 28 - development costs 41 19 2 Accretion of discount 136 22 53 Change in income taxes (150) (517) 136 ------- ------ ------ Net change 10 623 (174) Balance at beginning of year 826 203 377 ------- ------ ------ Balance at end of year(1) $ 836 $ 826 $ 203 ======= ====== ======
(1) 2000 reflects higher income taxes resulting from utilization of substantial tax pools during the year.
Net Volumes(2) ------------------ Liquids Gas (mmbbls) (Bcf) -------- ----- PROVED DEVELOPED AND UNDEVELOPED At December 31, 1997 28 652 Additions from discoveries and extensions 1 180 Additions from improved recovery 1 0 Additions from development(1) 1 75 Purchases of Reserves in place 0 0 Revisions of previous estimates 5 19 Sales of reserves in place 0 0 Production (6) (7) ----- ----- At December 31, 1998 30 919 Additions from discoveries and extensions 1 100 Additions from improved recovery 0 0 Additions from development(1) 1 93 Purchases of Reserves in place 0 0 Revisions of previous estimates (6) (59) Sales of reserves in place 0 0 Production (6) (57) ----- ----- At December 31, 1999 20 996 Additions from discoveries and extensions 1 215 Additions from improved recovery 0 0 Additions from development (1) 1 4 Purchases of Reserves in place 1 87 Revisions of previous estimates 0 4 Sales of reserves in place 0 0 Production (5) (58) ----- ----- At December 31, 2000 18 1248 ===== ===== PROVED DEVELOPED At December 31, 1998 26 436 At December 31, 1999 16 376 At December 31, 2000 15 374
(1) Under Statement of Financial Accounting Standards No. 69 (SFAS 69), these additions are considered past of revisions of previous estimates. (2) The above estimated reserve quantities are based upon year-end economic conditions as required under SFAS 69. Page 53 of 55 44 15. UNITED STATES ACCOUNTING PRINCIPLES If United States generally accepted accounting principles (U.S. GAAP) had been followed, the earnings (loss) and earnings (loss) per common share would have been as follows:
YEAR ENDED DECEMBER 31 ------------------------------ 2000 1999 1998 ------ ------ ------ Earnings (loss) before tax, as reported $ 205 $ 63 $ (33) Adjustments: New asset values (a) -- -- (4) ------ ------ ------ Earnings (loss) before tax, as adjusted 205 63 (37) ------ ------ ------ Income tax recovery (expense), as reported (121) (30) 3 Income tax recovery (a) -- -- 4 ------ ------ ------ (121) (30) 7 ------ ------ ------ Earnings (loss), as adjusted $ 84 $ 33 $ (30) ====== ====== ====== Earnings (loss) per common share ($/share) $ 0.96 $ 0.37 $(0.34) ====== ====== ======
Comprehensive income, as defined by Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income", is equivalent to earnings (loss) as presented. If U.S. GAAP were followed, amounts on the Consolidated Statements of Cash Flow would be presented as follows:
YEAR ENDED DECEMBER 31 ------------------------------ 2000 1999 1998 ------ ------ ------ OPERATING ACTIVITIES Cash generated from operations, as reported (d) $ 271 $ 137 $ 44 Changes in non-cash working capital, as reported 19 (4) 16 Adjustments: Geological and geophysical expenditures (e) (8) (10) (13) ------ ------ ------ Operating activities, as adjusted $ 282 $ 123 $ 47 ====== ====== ====== INVESTING ACTIVITIES, as reported $ (107) $ (174) $ (194) Adjustments: Geological and geophysical expenditures (e) 8 10 13 ------ ------ ------ Investing activities, as adjusted $ (99) $ (164) $ (181) ====== ====== ======
If U.S. GAAP were followed, amounts on the Consolidated Statements of Financial Position would be adjusted as follows:
DECEMBER 31, ---------------------- 2000 1999 -------- -------- Increase (decrease) ASSETS $ -- $ -- -------- -------- LIABILITIES AND SHAREHOLDERS' EQUITY Contributed surplus (b) $ 11 $ 11 Deficit (a)(b) (11) (11) -------- -------- $ -- $ -- ======== ========
The financial statements have been prepared in accordance with accounting principles generally accepted in Canada which, in the case of the company, conform in all material respects with those in the United States except that: (a) Prior to January 1, 1999, the financial statements would reflect the effect of adopting Statement of Financial Accounting Standards No. 109. "Accounting for Income Taxes" (SFAS 109). SFAS 109 requires a restatement, to pre-tax amounts, of the new asset values reflected in the accounts in connection with the parent company's 45 acquisition of the company in 1988 and the acquisition of Gulf Resources (Kakap) Ltd. on February 18, 1997. These differences result in additional depreciation, depletion and amortization charges and related income tax recoveries over the lives of the related assets. Effective January 1, 1999 such differences have been eliminated as the company retroactively changed (with restatement of prior periods) its method of accounting for income taxes under Canadian GAAP. While the new Canadian standards are substantially identical to those of SFAS 109, the method and assumptions used to apply these new standards in the Canadian GAAP financial statements differ in some respects from those applied to SFAS 109. The U.S. GAAP financial statements shall reflect application of these standards consistent with the Canadian GAAP financial statements prospectively from January 1, 1999. (b) Prior to the company going public in 1997, the costs of certain of the company's technical, financial, accounting and administrative services were borne by the company's parent on the company's behalf. Under U.S. GAAP, these costs would be recognized as additional general and administrative expenses offset by contributions to capital. These adjustments have been calculated based on a specific allocation of salary costs of individuals providing technical services to the company and a general allocation of corporate overhead determined using comparative ratios of reserves, sales volumes and assets of the company and its parent. (c) Unrealized gains or losses arising on translation of long-term liabilities repayable in foreign funds would be included in earnings in the period in which they arise in the United States. At December 31, 2000 and December 31, 1999, no such liabilities existed. (d) Under U.S. GAAP, "cash generated from operations" as defined by the company would not be presented in the Consolidated Statement of Cash Flows as it excludes the effect of changes in non-cash working capital and therefore differs from the definition of operating cash flow under Statement of Financial Accounting Standards No. 95. The company has presented this item for Canadian GAAP as it is commonly used by oil and gas investors in Canada as a measure of performance and liquidity and is normally presented in Canadian financial statements. (e) Under U.S. GAAP, geological and geophysical expenditures would be classified as operating activities. (f) Statement of Financial Accounting Standards (FAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended by FAS 137 and 138) is effective for fiscal years beginning after June 15, 2000. These pronouncements have no impact on the company's consolidated financial statements. Additional disclosure Stock-based compensation plans The Financial Accounting Standards Boards Statement No. 123, "Accounting for Stock-Based Compensation" (FAS 123) requires the fair value of stock-based compensation to be either recorded as compensation over the service period or the impact of the use of fair values are to be disclosed in the financial statements. The Company applies Accounting Principles Board Opinion No. 25 (APB 25) and related Interpretations in accounting for its plans. As a result, no compensation cost has been recognized in income for its fixed stock option plan as under APB 25 the exercise price of the company's plans equal the market value of the underlying stock on the date of grant. Pro forma disclosures of earnings (loss) and earnings (loss) per common share are presented below as if the company had adopted the cost recognition requirements under FAS 123. The compensation cost for the stock-based compensation for 2000 was $2 million (1999 - $3 million; 1998 - $10 million). Pro forma disclosures are not likely to be representative of the effects on reported earnings for future years.
YEAR ENDED DECEMBER 31 ---------------------------------- 2000 1999 1998 -------- -------- -------- Earnings (loss) As reported $ 84 $ 33 $ (30) Pro forma $ 82 $ 30 $ (40) Earnings (loss) per common share ($/share) As reported $ 0.96 $ 0.37 $ (0.34) Pro forma $ 0.94 $ 0.33 $ (0.46) ======== ======== ========
The fair value of the options granted during 2000 is estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions: expected volatility of 50 per cent (1999 - 55 per cent; 1998 - 42 per cent); risk-free interest rate of 5.1 per cent (1999 - 6.5 per cent; 1998 - 5.0 per cent); and expected life of 3 years (1999 - 3 years; 1998 - 3 years). Page 55 of 55