EX-99.A.1.K 13 h97563exv99waw1wk.txt ANNUAL REPORT ON FORM 40-F Exhibit (a)(1)(K) 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, 2001 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 62 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. 87,927,853 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 dining 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, 2002, the Audited Consolidated Financial Statements of the Registrant and the Auditors' Report thereon for the fiscal year ended December 31, 2001, and Management's Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2001 and additional disclosures required by U.S. GAAP are incorporated by reference herein from Exhibits 1, 2, 3, 5, 6, 7 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/ Robert H. Allen ----------------------------------------- Robert H. Allen, Chairman of the Board and Director By: /s/ Alan P. Scott ----------------------------------------- Alan P. Scott, Corporate Secretary Page 2 of 62 EXHIBITS
PAGE Exhibit 1 Annual Information Form of the Registrant dated March 19, 2002 4 Exhibit 2 Audited Consolidated Financial Statements and the Auditors' Report thereon for the fiscal year ended December 31, 2001 29 Exhibit 3 Management's Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2001 45 Exhibit 4 Consent of Independent Chartered Accountants 55 Exhibit 5 Supplementary Oil and Gas Information 56 Exhibit 6 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves 57 Exhibit 7 Three Year Reserve Reconciliation 58 Exhibit 8 Note 15 to Financial Statements - U.S. GAAP Reconciliation and Additional Disclosure 59 Exhibit 9 Five-Year Financial Summary 61 Exhibit 10 Quarterly Summaries 62
Page 3 of 62 GULF INDONESIA RESOURCES LIMITED ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2001 MARCH 19, 2002 GULF INDONESIA RESOURCES LIMITED ANNUAL INFORMATION FORM INDEX THE CORPORATION ......................................................... 1 GENERAL DEVELOPMENT OF THE BUSINESS ..................................... 2 NARRATIVE DESCRIPTION OF THE BUSINESS ................................... 4 SELECTED CONSOLIDATED FINANCIAL INFORMATION ............................. 19 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ..................................... 19 MARKET FOR SECURITIES ................................................... 19 DIRECTORS AND OFFICERS .................................................. 19 ADDITIONAL INFORMATION .................................................. 21 MISCELLANEOUS ........................................................... 22
-1- THE CORPORATION INCORPORATION OF THE ISSUER AND SUBSIDIARIES Gulf Indonesia Resources Limited 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. References in this document to the "Corporation" refer to Gulf Indonesia Resources Limited and references to "Gulf Indonesia" or "the Company" include the Corporation and its direct or indirect subsidiaries. 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. 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 Resources Limited ("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 that same date, the Corporation also acquired from Gulf Canada all of the shares of Gulf Resources (Kakap) Ltd., formerly known as Clyde Petroleum Indonesia Ltd., and this subsidiary was subsequently continued in 1998 under the laws of Barbados. On September 29, 1997, the Corporation completed a public offering of approximately 28 percent of its shares, which are now publicly traded on the New York Stock Exchange. Following the successful completion of a take-over bid on July 13, 2001, Conoco Inc., a major integrated energy company active in more than 40 countries, acquired indirect control of Gulf Canada which held and continues to hold approximately 72 percent of the shares of the Corporation, and shortly thereafter the name of Gulf Canada was changed to Conoco Canada Resources Limited ("Conoco Canada"). The Corporation has three material direct or indirect 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 these subsidiaries. The following diagram illustrates the intercorporate relationships between the Corporation and its subsidiaries, all of which are 100 percent owned, directly or indirectly. [FLOW CHART] -2- GENERAL DEVELOPMENT OF THE BUSINESS THREE YEAR HISTORY In 1999, Gulf Indonesia, 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. Commercial gas sales commenced in the first quarter of 2001. This continued the Company's development as a natural gas producer which had achieved a major step forward in 1998 with the start-up of the Corridor Block Gas Project. The Corridor Gas Project supplies natural gas to the Duri Steamflood under a long-term agreement (the "Caltex I Agreement") in exchange for crude oil delivered to the Company by PT Caltex Pacific Indonesia ("Caltex") at the export terminal at Dumai on a British thermal unit ("Btu") equivalent basis, subject to certain thermal efficiency and cost adjustments. In December 2000, Gulf Indonesia 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 (0.6 Tcf net to Gulf Indonesia) to be delivered over 19 years. Gas for the agreements is to be supplied from the Suban field where, in 2000, Gulf Indonesia 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, Gulf Indonesia and Pertamina entered into an agreement with a subsidiary of Singapore Power Limited for the supply of natural gas from Sumatra to Singapore, (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 Gulf Indonesia) to be delivered over a 20 year period, currently scheduled to commence in August 2003. The Caltex II and Sumatra Gas to Singapore Agreements are the third and fourth substantial long-term U.S. dollar gas sales agreements for Gulf Indonesia. Including the Caltex I and West Natuna Agreements, the combined cumulative contract quantity of the four agreements to which Gulf Indonesia is a party is approximately 7 Tcf (2 Tcf net to Gulf Indonesia). In August 2001, Gulf Indonesia accelerated the repayment of the loan facility ("Corridor Loan") originally entered into to provide financing for the Corridor Gas Project and repaid the entire $142 million of the Corridor Loan that was outstanding at December 31, 2000, five and one-half years ahead of the originally scheduled repayment date of February 2007 and less than three years after the October 1998 start-up of the Project. In 2001, Gulf Indonesia celebrated its 40th anniversary of operations in Indonesia. As at December 31, 2001, Gulf Indonesia had interests in 13 contract areas in Indonesia, covering a total gross acreage of approximately ten million gross acres (6.3 million net acres) of which four have commercial production, six contain oil and gas fields that are currently under development or could potentially be developed or are under appraisal, two are new areas acquired in 2001 for future exploration and one was submitted for relinquishment in January 2002. A seven-well offshore exploration program that began in 2000 was completed in 2001, of which four wells were discoveries and a fifth contained untested gas. Three additional delineation wells were drilled in the Suban field where Gulf Indonesia has identified substantial gas reserves beyond current contracted amounts. The Company is currently negotiating with energy consumers to seek additional gas sales. -3- Gulf Indonesia produced 15 mmboe (41,300 boe/d) of gross oil and gas production (35,800 boe/d net) in 2001. Approximately 60 percent of this production came from onshore gas operations, 30 percent from onshore oil operations on the island of Sumatra, and the balance from offshore oil and gas operations in the Natuna Sea. TRENDS Over the past five years, Gulf Indonesia has moved from being a small oil producer on the island of Sumatra to becoming a significant player in Indonesia's oil and gas industry. The Caltex I Agreement and the successful completion of the Grissik Gas Plant in South Sumatra in 1998 were major milestones in that transition. Since that time, Gulf Indonesia has signed three additional major long-term U.S. dollar based gas contracts, resulting in an anticipated doubling of its share of contracted daily quantities of natural gas to over 320 mmcf/d by 2008. In total, these contracts cover approximately 7 Tcf (2 Tcf Gulf Indonesia share) of cumulative contract quantities over 15 to 23 year terms. Deliveries for the Caltex I contract from the Corridor Gas Project began in October 1998 and in 2001, first gas sales commenced from the Kakap PSC for the West Natuna gas contract. The Company is actively developing gas fields for the Caltex II and Sumatra Gas to Singapore contracts that are expected to commence in late 2002 and 2003, respectively. Further increases in gas sales for these contracts over the following years are expected to offset natural declines in oil production from existing fields in Sumatra and the Natuna Sea, providing a sustainable base level of production until 2009. Beyond the gas currently under contract, the Company also has significant additional gas reserve potential in its portfolio and is actively seeking to market this gas to domestic energy consumers on the islands of Sumatra, Batam and Java as well as to international buyers in Malaysia and Singapore. Based on the identified markets and identified gas prospects, the Company is targeting to double its gas under contract over the next few years to achieve its goal of becoming the pre-eminent supplier of the pipeline gas in Indonesia. Crude oil sales volumes from the Company's mature oil fields (both onshore and offshore) are dependent primarily on reservoir performance and, to a lesser extent, on the results of planned development activities in the year. Condensate sales volumes are dependent primarily on the related natural gas production. The Company anticipates that crude oil and condensate sales volumes from existing producing fields will decline by 15 to 20 percent per year in 2002 and 2003. The Company's exploration team has made a number of oil and gas discoveries in the last few years. The Company's success in delineating and developing these oil and gas discoveries and in finding and developing new oil and gas fields could have a significant effect on sales volumes in 2004 and beyond. The Company is also actively looking at opportunities to strengthen its asset portfolio through asset purchases, trades, and/or divestitures. These efforts could have a significant impact on the Company's sales volumes in the future. The Corporation recognizes the challenge arising from the uncertainties regarding international energy pricing and the Indonesian economic and political environment. Gulf Indonesia intends to seek growth through the application of strong core values to its business, taking pride in the safety of its people and operations, environmental stewardship, valuing all people and maintaining high standards of operation. -4- NARRATIVE DESCRIPTION OF THE BUSINESS PRINCIPAL BUSINESS The Company is an oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas onshore and offshore Indonesia. All of Gulf Indonesia'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, 2001, Gulf Indonesia had gross and net proved reserves of 323 MMBOE and 244 MMBOE, respectively, of which approximately 90 percent are natural gas. The Company's principal products are natural gas and crude oil. The Company's current onshore gas production from the Corridor PSC is exchanged for crude oil on an energy equivalent basis, subject to certain thermal efficiency and cost adjustments. This crude oil is marketed through a marketing agreement with Itochu Petroleum Co. (Hong Kong) Ltd. which expires in 2007. The price of the crude oil is determined based on the Indonesian Crude Price or ICP of the underlying crude oil, which in most cases is Duri crude. The ICP is set monthly by Pertamina, the Indonesian state owned gas and oil company, based on spot prices of internationally traded Indonesian crude oils, adjusted for quality. Offshore natural gas production is sold to SembCorp Gas, a consortium of SemCorp Industries (Singapore's leading engineering and technology services group), Temasek Holdings (a Singapore government holding company), and Tractebel (a power utility company from Belgium). This gas is priced based on a premium to the price of fuel oil in Singapore. Currently, Gulf Indonesia sells its oil production in two markets. Approximately 79 percent of its oil production is sold to Pertamina at the Indonesian Crude Price. Approximately 21 percent of oil production, representing offshore production from the 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 small balance of the Company's oil production is received through an overriding royalty payment on Block B in north Sumatra. As of December 31, 2001, the Company had 1,557 permanent employees, 570 of whom were located at the Company's offices in Jakarta, Indonesia, and the remainder of whom were located at field offices. In addition to its permanent employees, the Company also engaged approximately 1,350 daily contract labourers as of such date. PRINCIPAL PROPERTIES Gulf Indonesia's operations are conducted through contractual arrangements with Pertamina in the form of PSCs, one technical assistance contract ("TAC") and one enhanced oil recovery contract ("EOR") pursuant to which Gulf Indonesia and its associated participants provide financing and technical expertise to conduct exploration, development and production operations in a specified geographic area (each, a "contract area"). Two of these contract areas are currently producing natural gas and crude oil (Corridor Block PSC and Kakap PSC), while two more (Corridor Block TAC and Jambi EOR) are currently producing crude oil. Each of these producing contract areas is operated by Gulf Indonesia, as are most of the non-producing PSCs. The Pangkah PSC is operated by an affiliate of Amerada Hess and the operatorship of the Northwest Natuna Block I PSC is awaiting determination by Pertamina. In 2001, Gulf Indonesia acquired interests in two new onshore non-producing blocks, a 50 percent interest in the non-operated Banyumas PSC in south-central Java and a 70 percent interest in the Company-operated Sakakemang PSC in South Sumatra and relinquished its interests in two non-producing blocks, the onshore Calik PSC and offshore Sakala Timur PSC. In January -5- 2002, the Company requested relinquishment of its interest in the Sebuku PSC. It also increased its interest in the Pangkah PSC from a 12 percent to a 22 percent interest at a cost of approximately $8 million as a result of a contractual right to share in another party's acquisition. In addition to its interest in these contract areas, the Company 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 Company has often farmed out a working interest in the contract area to one or more parties. Operations among the Company and other participants with respect to a given contract area are generally governed by a joint operating agreement which varies from block to block. The following table lists, as of December 31, 2001, the Company's working interest, participants, term and acreage for each of the Company's production sharing arrangements.
Effective Post-Tax Working and Post-Cost Name, Type of Agreement Interest Recovery Share to Expiration and Location (%) Participants Contractor(3) 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 Exxon Mobil (50%) 15% 30% 2011 445,476/222,738 Northern Sumatra Tungkal PSC 100(1) -- 15% 30% 2022 l,130,862/l,130,862 South Sumatra South Jambi B PSC 45(2) Devon(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 Pangkah PSC 22(2) Amerada Hess(66%) 15% 35% 2026 723,435/159,156 East Java Sea Dana(12%) Ketapang PSC 50(1) Petronas Carigali(50%) 15% 35% 2028 820,783/410,391 East Java Sea Sebuku PSC(4) 100(1) -- 15% 35% 2027 2,167,467/2,167,467 Offshore Kalimantan Northwest Natuna Block 1 30(1) Premier(50%) 15% 35% 2027 1,068,352/320,505 PSC(5) Dana(20%) West Natuna Sea Banyumas PSC 50(1) Coparex(50%) 15% 35% 2031 1,325,804/662,902 South-Central Java Sakakemang PSC 70(1) Pertamina(30%) 15% 35% 2031 662,852/463,997 South Sumatra
(1) Pertamina has the right to direct that 10 percent of each participant's working interest under the PSC be sold to an Indonesian Participant. (2) The Company agreed to increase its interest in the Pangkah PSC to 22 percent in 2001 and this increase was approved by Pertamina in February 2002. -6- (3) 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. (4) The Company decided in early 2002 to relinquish its interest in the Sebuku PSC. (5) The status of this Northwest Natuna Block 1 PSC remains uncertain, pending Pertamina's consideration of a request to rescind an earlier relinquishment request in order to enable a possible farmout of a portion of the Company's interest. The following table lists the Company's production sharing arrangements that are currently in commercial production, and reflects reserves data as at December 31, 2001 and production data for the years ended December 31, 2001, 2000 and 1999.
Company's Gross/Net Company's Gross/Net Company's Gross/Net Production for Year Production for Year Production for Year Company's Gross/Net Proved Reserves Ended December 31, Ended December 31, Ended December 31, as at December 31, 2001(1) 2001(1) 2000(1) 1999(1) ----------------------------------------- ------------------- ------------------- ------------------- Oil & Natural Gas Liquids Sales Gas Total Total Total Total Property (MMBbls) (Bcf) (MMBOE) (MMBOEs) (MMBOEs) (MMBOEs) -------- ------------- ----------- ----------- ------------------- ------------------- ------------------- Corridor PSC 9.7/3.3 1,615/1,243 278.8/210.5 9.65/9.15 11.45/10.86 11.30/10.69 Corridor TAC 13.6/8.4 -/- 13.6/8.4 2.94/1.83 2.95/1.83 2.64/1.64 Kakap PSC 4.8/3.6 88/67 19.5/14.8 1.61/1.47 1.58/1.19 2.27/1.85 Jambi EOR 1.5/1.0 -/- 1.5/1.0 0.78/0.52 0.95/0.56 0.84/0.74 Other(2) 0.2/0.2 -/- 0.2/0.2 .04/04 0.12/0.11 0.31/0.30 --------- ----------- ----------- --------- ----------- ----------- Total(3) 30.1/16.7 1,758/1,362 323.0/243.8 15.02/13.01 17.05/14.55 17.36/15.22 ========= =========== =========== =========== =========== ===========
(1) Gross reserves and production volumes reflect the Company's interest prior to, and net reserves and production volumes reflect the Company'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 B overriding production payment. Crude oil reserves attributable to the Block A PSC were written off at year end. (3) Numbers may not add due to rounding. Corridor Block PSC, Southern Sumatra Gulf Indonesia is operator of the Corridor Block PSC with a 54 percent working interest. The original PSC was executed in 1983 and, in 1996, the PSC was amended and an extension was executed which extended the term until 2023. Natural Gas. Natural gas operations in the Corridor Block PSC contract area consist of 20 commercially producing wells in the Dayung, Gelam, Letang, Tengah and Sumpal fields. Gas operations commenced in October 1998 with production in 2001 averaging 140 MMcf/d (134 MMcf/d net) compared to 166 MMcf/d (159 MMcf/d net) in 2000. The "Corridor Block Gas Project" consists of (i) production from gas wells in the Dayung, Gelam, Letang and Tengah fields; (ii) field separation and gathering facilities, including three field stations to dehydrate gas; and (iii) a central gas processing plant to process 440 MMcf/d of raw gas from the three field -7- stations, with an output design capacity of 310 MMcf/d of sales gas. The Corridor Block Gas Project commenced operations in October 1998 and, in 2002, the operating capacity was increased to approximately 350 Mmcf/d. On October 13, 2001, the Corridor Gas Project achieved a new single-day gross gas sales record of 318 mmcf/d (Company share 166 mmcf/d), approximately three percent above the original design capacity. Gas produced in the Corridor Block PSC contract area is used primarily 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). Gas takes by Caltex were about five percent lower on an energy basis in 2001 than in 2000. In 2000, the Company 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. In 2001, Gulf Indonesia drilled three successful delineation wells at Suban, expanding the extent of the area and confirming deliverability from all sectors of the gas field. Extended production tests were conducted on the Suban-5 and Suban-6 wells and test information along with data from the wells drilled in 2001 led to an increase in the proved reserves booked for the field by the Company by over 25 percent in 2001. Further delineation activity is planned for 2002. In December 2000, the Company 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 (Gulf Indonesia'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 Company's 65 Mmcf/d share of contract quantities will supplement the 160 Mmcf/d of gas (net to the Company) that is contracted under the original agreement with Caltex, for a total combined quantity of 225 Mmcf/d. On February 12, 2001, Gulf Indonesia 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 PSC, the South Jambi B PSC (discussed below) and a third party operation. The agreement provides for a contract quantity of 2.27 Tcf (the Company's share being 0.7 Tcf) of sales gas to be delivered over a term of 20 years beginning in 2003. The Company'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 with a premium. 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. During 2001, the Company completed two onshore gas development projects in the Corridor PSC, being installation of compression facilities at the Gelam field to maintain gas production volumes and the completion of the first stage of the Sumpal field development to provide an additional source of gas for contracted gas demand. Ultimately, the Sumpal field is targeted to be the anchor supply field for the Corridor PSC's share of the Sumatra Gas to Singapore sales contract, commencing in 2003. The Company also began construction of phase 1 of the Suban field development in 2001. The Suban field is scheduled to be on-stream in late 2002 to be available to supply gas for the Caltex II sales contract. The Company also deferred the installation of compression facilities at the Dayung field by about one year in order to optimize the timing and amount of capital spending in relation to gas demand requirements. -8- Crude Oil. Crude oil operations in the Corridor Block PSC contract area consist of 54 commercially producing wells in 11 fields. Production in 2001 averaged 3,200 Bbls/d (2,700 Bbls/d net) compared to 3,600 Bbls/d (3,100 Bbls/d net) in 2000. At Suban Baru, a two-well delineation program early in 2001 tested shallow oil deposits above the Suban gas field. The quantities of oil discovered were insufficient to justify a full-scale development program and the Company now plans to place a single Suban Baru well on production in 2002. Corridor TAC, Southern Sumatra Gulf Indonesia operates several small non-contiguous areas located onshore in southern Sumatra with producing oil fields in the Corridor Block under a TAC between the Company 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 Company is operator of the block with a 60 percent working interest The TAC currently has 172 commercially producing wells in six fields. Production in 2001 averaged 8,000 Bbls/d (5,000 Bbls/d net) compared to 8,100 Bbls/d (5,000 Bbls/d net) in 2000. During 2001, the Corporation drilled 27 development wells in the Ramba and Bentayan fields, which contributed 1,100 Bbls/d (the Company's share being 660 Bbls/d) to the Company's total production from this area. Kakap PSC, West Natuna Sea Gulf Indonesia operates the Kakap PSC in the West Natuna Sea, offshore Kalimantan, with a 3l.25 percent 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 Company 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 Company's share of oil production in 2001 from the Kakap fields was 3,500 Bbls/d (3,100 Bbls/d net) compared to 4,300 Bbls/d (3,300 Bbls/d net) in 2000. The participants in the Kakap, Natuna Sea Block A and South Natuna Sea Block B PSCs 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 Gulf Indonesia share of gas volumes over the life of this contract is expected to be approximately 0.5 tcf. 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. West Natuna gas sales averaged 6 mmcf/d for the year and, by the fourth quarter of 2001, had increased to an average of 9 mmcf/d. -9- Block A PSC, Northern Sumatra The Company's interest in the Block A area located in the Aceh Province in northern Sumatra goes back to 1961. In July 1989, Gulf Indonesia entered into the current Block A production sharing contract, effective for 20 years beginning in September 1991. The Company is operator of the block with a 50 percent working interest. In 2001, the Company shut-in its remaining oil production due to sub-economic performance. Civil unrest in the Aceh Province is one of the factors impacting the Company's ability to develop its probable gas and condensate reserves in the area. South Jambi B PSC, Southern Sumatra Gulf Indonesia 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 and holds a 45 percent 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, previously noted in discussion of the Corridor Block PSC, has been approved by Pertamina. The Teluk Rendah and Geger Kalong fields are currently targeted to commence production in 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 30 Mmcf/d. The development of the shallow gas fields in the South Jambi B PSC has been deferred until the drilling of the wells in the Teluk Rendah and Geger Kalong fields in early 2002. The results of these wells will help determine the appropriate size of facilities required to provide the South Jambi B PSC's contribution to the Sumatra Gas to Singapore sales contract. Jambi EOR, Southern Sumatra In January 1990, Gulf Indonesia 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 Company 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 percent. Profit oil (the portion remaining of the contractor's equity share, less contractor's allowed operating costs and investment credits) is split 71.1538 percent with Pertamina and 38.8462 percent with the contractor. The Company has a 60 percent working interest. The Jambi EOR has 191 commercial wells in three fields that produced 2,100 Bbls/d (1,400 Bbls/d net) compared to 2,600 Bbls/d (1,500 Bbls/d net) in 2000. During 2001, the Company drilled 10 wells. Tungkal PSC, Southern Sumatra Gulf Indonesia 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 Company is operator of the block with a 100 percent working interest. In early 1997, the Company 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. The Company drilled the successful Mengoepeh-7 oil delineation well in December 2001, helping to define additional oil potential. The results of this well will be used in the -10- preparation of a plan of development that the Company expects to submit in 2002 for the Mengoepeh Field. The Company also drilled a successful gas discovery at SE Mengoepeh late in 2001. The Mengoepeh-6 delineation well drilled in early 2001 which was targeted to define the gas potential of the Mengoepeh field was unsuccessful. Pangkah PSC, East Java Sea In 1997, Gulf Indonesia 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. The Company agreed to increase its working interest in the PSC in 2001 to 22 percent, through acquisition of a 10 percent additional interest for approximately $8 million as a result of a contractual right to share in another party's acquisition, and Pertamina approved this increase in February 2002. There has been no commercial production of hydrocarbons in this contract area to date. The Ujung Pangkah-l well drilled in late 1998 tested at rates of 20 Mmcf/d of gas and 1,000 Bbls/d of oil and condensate. Five wells drilled during the fourth quarter of 2000 and first quarter of 2001 yielded one offshore oil discovery and three delineation success. The Sidayu-l oil well flowed 1,450 Bbls/d during testing and two new vertical wells, Ujung Pangkah-2 and Ujung Pangkah-3 as well as a planned sidetrack of the Ujung Pangkah-2 well confirmed reservoir continuity and the gas and oil columns seen in the Ujung Pangkah-l discovery well. The successful appraisal program resulted in the certification of significant gas reserves for the Ujung Pangkah field. The new operator of the block is finalizing a plan of development for the gas reserves in the field and has initiated discussions with customers for potential gas sales. The appraisal program also confirmed the presence of a significant oil accumulation underlying the gas and a 2D seismic program is planned for 2002 to determine locations for a two-well drilling program expected to commence in late 2002. The 3D seismic data acquired in conjunction with the Ketapang block will be used to define additional exploration prospects in the eastern portion of the Pangkah block. Ketapang PSC, East Java Sea In June 1998, Gulf Indonesia signed a 30-year PSC with Pertamina for a 100 percent working interest in the 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 Company farmed out 50 percent of its working interest in the Ketapang PSC to Petronas Carigali, with the Company holding the remaining 50 percent working interest. In 2001, the Company drilled three successful exploration wells in the Ketapang PSC, two that discovered oil and gas, and one that discovered gas, confirming the potential of the offshore East Java plays that the Company has been pursuing. The Bukit Tua-l well flowed at a combined rate of 7,250 bbls/d of oil from two tests of the Kujung III formation and the Jenggolo-l well, drilled 19 kilometres to the west, flowed 3,600 bbls/d of oil from the same formation. Post-drilling seismic mapping suggests that these two wells have penetrated different positions on the same structure. Tests for natural gas from shallower zones in these wells also yielded successful results. On the Payang-l well, a test of the Kujung I formation flowed 17 mmcf/d of natural gas, adding to gas discovered in this drilling program (including gas identified but not tested in the Bukit Panjang-1 well drilled in late 2000). To evaluate the extent and magnitude of these discoveries, the Company conducted what it believes to be the largest offshore 3D seismic survey ever undertaken in Indonesia. The 2,523 square kilometre survey over most of the Ketapang block and a portion of the adjacent Pangkah block was completed in early 2002 and the Company is now in the process of evaluating the seismic information acquired. The Company plans to use -11- the seismic information to select locations in late 2002 for appraisal drilling on the Bukit Tua/Jenggolo structure. The 3D seismic and oil delineation drilling program will also support efforts to determine the gas reserve potential of the block, helping the Company to position itself to compete for the growing East Java gas markets which are located within 100 kilometres of the Ketapang PSC. Northwest Natuna Block I PSC Gulf Indonesia entered into a farm-in agreement in 1997 with Dana Petroleum (NW Natuna) LLC to acquire a 30 percent interest in the undeveloped Northwest Natuna Block I PSC, just north of the Kakap PSC. 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 non-operated Northwest Natuna block. In April 2000, the Ande Ande Lumut-l well was drilled. The well logged oil pay and oil samples were recovered 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 were deferred and the Company is evaluating future options for this block. Banyumas Block, South-Central Java In May 2001, Gulf Indonesia acquired a 50 percent non-operated interest in the Banyumas PSC. The PSC has a term of 30 years and the remaining interest is held by Coparex, which is the operator of the PSC. The Banyumas Block covers over 1.3 million gross acres in onshore south-central Java, providing the Company with an opportunity to expand outside its existing core areas. The operator has commenced reprocessing of existing seismic data and a 2D seismic acquisition program is targeted for late 2002. Sakakemang PSC, South Sumatra In November 2001, Gulf Indonesia acquired new exploration acreage in South Sumatra through the signing of the Sakakemang PSC. Gulf Indonesia holds a 70 percent interest and Pertamina holds the remaining 30 percent in this PSC which has a term of 30 years. The PSC will be jointly operated by Gulf Indonesia and Pertamina. The acreage is adjacent to the Corridor PSC and the Company hopes that it will provide future opportunities to add to its natural gas reserves in south Sumatra to meet potential future gas sales demand. Block B, Northern Sumatra Gulf Indonesia receives an overriding production payment of $0.04 per BOE on 60 percent 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 $0.9 million in 2001 compared to $1.6 million in 2000. Unrest in the Aceh area in 2001 curtailed the production from Block B in the early part of the year but production has resumed and has increased to near normal levels. Sakala Timur PSC, Offshore Bali After receiving Pertamina's approval in early 1999, Gulf Indonesia held a 100 percent 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. An unsuccessful exploration well was drilled in 2000 and effective January 10, 2001, the Company relinquished its interest in the Sakala Timur Block. -12- Calik PSC, Southern Sumatra In June 1995, Gulf Indonesia entered into a 30 year PSC for the exploration of the Calik Block located onshore in southern Sumatra, northeast of the Corridor Block. Following the drilling of an unsuccessful well in each of 2000 and 2001, the Company initiated the relinquishment process for the block in November 2001. Sebuku PSC, Offshore Kalimantan In September 1997, Gulf Indonesia entered into a 30-year PSC for the exploration of the Sebuku Block, located in the Makassar Strait, offshore Kalimantan. The Company was operator of the block with a 100 percent working interest. Following the drilling of an unsuccessful exploration well in early 2001 and evaluation of the remaining potential in the Sebuku Block, the Company decided in early 2002 to request relinquishment of its interest in this PSC. RESERVES The following table summarizes the estimates of the Company's historical gross and net proved developed and proved undeveloped natural gas, oil and natural gas liquids reserves as of the dates indicated and the present value attributable to the net proved reserves at such dates. Gulf Indonesia, for all years presented, has prepared the reserves and present value data.
2001 2000 1999 ---------- ---------- ---------- Gulf Indonesia's gross and net proved, developed reserves: Natural gas (Bcf) 718/552 499/374 481/376 Crude Oil (MMBbls) 19/12 22/13 24/13 Natural Gas Liquids (MMBbls) 4/2 4/2 5/3 Total (MMBOE) 143/106 109/77 108/79 Present value of future net revenues $ 1,029 $1,513 $ 1,361 before income taxes (in millions of $)(5) Standardized measure of discounted $ 606 $ 836 $ 826 future net cash flows (in millions of $) Gulf indonesia's gross and net proved, undeveloped reserves: Natural gas (Bcf) 1,040/811 1,169/874 782/620 Crude Oil (MMBbls) 2/1 4/2 4/2 Natural Gas Liquids (MMBbls) 5/2 4/2 2/1 Total (MMBOE) 180/138 203/150 136/106
Notes: (1) "Gross" reserves are reserves attributable to the Company'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 Company'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. -13- (4) Proved developed reserves are reserves which can be expected to be recovered through existing equipment and operating methods. (5) The present value of future net revenues before income taxes attributable to the Company's net proved reserves was prepared using prices and costs in effect as of the end of the respective periods presented, discounted at 10 percent. Estimates of the Company's reserves and future net revenues are made using sales prices estimated by the Company 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 gas reserves and future net revenues therefrom have been calculated on a Btu equivalent basis based on crude oil prices. There are numerous uncertainties inherent in estimating natural gas, condensate 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 Gulf Indonesia's reserves that occurred in the most recent fiscal year on a gross/net basis.
Proven Probable Total ------ ------------- ------------- Developed Undeveloped --------- ----------- NATURAL GAS (Bcf) AS AT JANUARY 1, 2001 499/374 1,169/874 1,616/1,176 3,284/2,424 Additions(1) 283/217 (130)/(99) (152)/(117) 1/1 Purchases of Reserves 0/0 0/0 0/0 0/0 Revisions to Previous Estimates (11)/12 1/36 (358)/(172) (368)/(124) Production (53)/(51) 0/0 0/0 (53)/(51) AS AT DECEMBER 31, 2001 718/552 1,040/811 1,106/887 2,864/2,250 CRUDE OIL (MMBbls) AS AT JANUARY 1, 2001 21.7/12.7 3.7/2.0 13.8/7.8 39.3/22.6 Additions(1) 3.0/1.7 (1.6)/(0.9) (0.9)/(0.5) 0.5/0.4 Purchases of Reserves 0/0 0/0 0/0 0/0 Revisions 00 Previous Estimates 0.4/1.6 (0.2)/0 (4.4)/(2.1) (4.2)/(0.5) Production (5.7)/(4.1) 0/0 0/0 (5.7)/(4.1) AS AT DECEMBER 31, 2001 19.5/12.0 1.9/1.1 8.5/5.2 29.9/18.4 NATURAL GAS LIQUIDS (MMBbls) AS AT JANUARY 1, 2001 3.8/1.9 3.8/1.8 14.1/7.3 21.8/11.1 Additions(1) 0.6/0.5 0.9/0.3 (1.5)/(0.8) 0/0 Purchases of Reserves 0/0 0/0 0/0 0/0 Revisions to Previous Estimates 0/(0.2) 0/(0.4) (1.8)/0.3 (1.8)/(0.3) Production (0.4)/(0.4) 0/0 0/0 0.4/0.4 AS AT DECEMBER 31, 2001 4.0/1.9 4.7/1.7 10.8/6.8 19.6/10.4
(1) Includes discovery and extension, infill, improved recovery and other. (2) Columns and rows may not add due to rounding. -14- DRILLING HISTORY The following table sets forth the number of wells on Gulf Indonesia's properties for the years ended December 31, 2001, 2000 and 1999. Year Ended December 31 (Gross/Net)
2001 2000 1999 ------------ ------------ ------------ EXPLORATORY WELLS Oil 6/2.8 3/0.7 -/- Gas 5/3.1 1/0.5 4/2.3 Dry 7/4.9 6/3.3 1/0.3 ------------ ------------ ------------ Total Exploratory 18/10.8 10/4.5 5/2.6 DEVELOPMENT WELLS Oil 40/23.7 40/24.0 14/8.4 Gas 0/0 1/0.5 -/- Dry 5/2.7 -/- 1/0.6 ------------ ------------ ------------ Total Development 45/26.4 41/24.5 15/9.0 ------------ ------------ ------------ Total Wells 63/37.2 51/29.0 20/11.6
PRODUCTIVE WELLS The following table sets forth the number of productive wells in which Gulf Indonesia owned an interest as of December 31, 2001.
Company Operated Wells Non-Operated Wells Total Productive Wells Gross Net Gross Net Gross Net ---------- ---------- ---------- ---------- ---------- ---------- Oil 453 258 0 0 453 258 Gas 26 13 0 0 26 13 Total 479 271 0 0 479 271
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. EXPENDITURES In 2001, the Company's exploration/delineation expenditures were $49 million compared to $29 million in 2000. Additionally, the Company's development expenditures in 2001 were $55 million compared to $57 million in 2000. In 2001, the Company also agreed to spend $8 million for the acquisition of an additional interest in the Pangkah PSC. ACREAGE DATA The following table sets forth the approximate developed and undeveloped acreage in which the Company held a contract interest as of December 31, 2001. Undeveloped acreage includes acres on which the Company 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, 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 -15- 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 4,340 2,875 Offshore 36 11 5,238 3,201 Total 424 218 9,578 6,076
Note: The totals above do not include interests in the Calik or Sakala Tumir PSC's on which relinquishment requests were submitted in 2001 and are awaiting approval. The totals do include the 10 percent increase in the Company's interest in the Pangkah PSC which was not approved until February 2002 and the Sebuku PSC which was submitted for relinquishment in early 2002. The Northwest Natuna Block 1 PSC is assumed to be retained with an 30 percent interest. For further information, please refer to the earlier table describing the Company's working interests in production sharing contracts. 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 Company'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 Gulf Indonesia's oil and gas assets and operations are located in Indonesia, and substantially all of the Company's crude oil production in Sumatra is sold at a price which is calculated on the basis of a formula 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 Gulf Indonesia. 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 Company's financial position, results of operations or prospects. The Company'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. Gulf Indonesia 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 Company 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. During 2001, the Company did not experience, nor has it historically experienced, problems from civil unrest or disputes with the Indonesian government However, Indonesia's political and economic environment could impact the Company's financial position, results of operations or potential for growth in the future. -16- While civil unrest exists in the Aceh Province, planning and negotiations related to the Company's development of its probable gas reserves in the Block A PSC are ongoing. Gulf Indonesia continues to monitor the situation and could be required to re-evaluate its development plans if the situation warrants. If in the future the Company decides not to proceed with its development plans or decides to dispose of its interest in this PSC, a material change to earnings could result. Concentration of Assets and Operations. In 2001, 64 percent of the Company's total production on a barrel of oil equivalent ("boe") basis and 96 percent of the Company's natural gas production was attributable to fields in the Corridor Block PSC contract area. As of December 31, 2001, 86 percent of the Company's total gross proved crude oil and natural gas reserves on a boe basis and 92 percent of the Company's total proved natural gas reserves were located in the Corridor Block PSC contract area. The concentration of Gulf Indonesia's crude oil and natural gas reserves in the Corridor Block PSC contract area increases the Company'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 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 Company's financial condition, results of operations or prospects. In addition, 68 percent of the Company's total crude oil and condensate production for 2001, and 61 percent of the Company's total proved crude oil and condensate reserves as of December 31, 2001 were attributable to fields located in the Corridor Block TAC and Kakap PSC contract areas. Adverse developments with respect to one or both of these contract areas could also have a material adverse effect on the Company'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 Gulf Indonesia, and significant complex negotiations among multiple parties remain with respect to the development of certain gas projects. There is no assurance that the Company 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 Company or other parties involved to complete and operate any of these natural gas projects successfully could have a material adverse effect on the Company's financial condition, results of operations or prospects. Limited Markets for Indonesian Natural Gas. The absence 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 Company'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 Indonesian law existing for many years, Pertamina was the sole entity authorized to manage Indonesia's petroleum resources on behalf of the Indonesian government. In November 2001, the President signed the bill establishing a new body that is to take over Pertamina's current right to sign contracts with oil and gas companies for the development of the country's hydrocarbon resources. The full application of this new law is uncertain as the implementing regulations are currently being prepared. 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 Company'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 -17- a material adverse effect on the Company's financial condition, results of operations or prospects. In addition, Gulf Indonesian 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 Gulf Indonesia and used in a contract area become the property of Pertamina, although the Company may recover such costs through the cost recovery provisions of the applicable production sharing arrangements. Substantial Capital Requirements; Liquidity. Gulf Indonesia makes, and will continue to make, substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves. On February 26, 1997, Gulf Indonesia and the other private PSC participants entered into a credit agreement (the "Corridor Loan") with various lending institutions to provide up to $450 million of financing to fund the development of the Corridor Gas Project. Repayments on the Corridor Loan were scheduled to end February 2007. In August 2001, Gulf Indonesia elected to accelerate the repayment of the Corridor Loan and the entire remaining amount was repaid. In connection with that repayment, the Company entered into an agreement with Conoco Canada whereby Conoco Canada provides a $65 million committed three-year senior revolving term credit facility on commercial terms and conditions. While Gulf Indonesia 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 Company 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 Company. There is also no assurance that Conoco Canada or Conoco Inc. will choose to provide or continue financial support for Gulf Indonesia. Moreover, future activities may require Gulf Indonesia to alter its capitalization significantly. The inability of Gulf Indonesia to access sufficient capital for its operations could have a material adverse effect on the Company's financial condition, results of operations or prospects. Uncertainty of Reserves Estimates. This Annual Information Form includes estimates made by the Company of its 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 Gull Indonesia. The reserves data set forth in this Annual Information Form represent estimates only. Reliance on Development of Additional Reserves. Gulf Indonesia continually seeks to acquire, explore for and develop new hydrocarbon reserves to replace those produced and sold. Although the Company 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. Gulf Indonesia'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 Company'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, -18- 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 Company'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, 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 Company'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 Gulf Indonesia'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 Company's reserves and the Company's revenues, profitability, cash flow and credit availability. Competition. The oil and gas industry is highly competitive. Gulf Indonesia'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 Company. Certain of the Company's customers and potential customers are themselves exploring for oil and natural gas in Indonesia, and the results of such exploration efforts could affect Gulf Indonesia's ability to sell or supply oil or gas to these customers in the future. The Company'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 project participants and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. Environmental Risks. Gulf Indonesia'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 Company 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 Company's financial condition, results of operations or prospects. Control by, and Arrangements with, Conoco Potential Conflicts of Interest. At present, Conoco Canada owns approximately 72 percent of the outstanding Common Shares and Conoco Canada is itself a subsidiary of Conoco Inc. which has other subsidiaries active in Indonesia. Accordingly, Conoco Inc. and Conoco Canada each will be in a position to control the policies, management and affairs of Gulf Indonesia, to effectively prevent or cause a change in control of the Company 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 had entered into a series of agreements in 1997 relating to their ongoing intercompany arrangements and, in 2001 and early 2002, the Corporation entered into new agreements to provide for technical, administrative and information services between the Corporation and Conoco Inc., superceding the previous services agreement with Conoco Canada. Although these service agreements provide for payment on a cost recovery basis, 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 -19- least as favorable to Gulf Indonesia as could have been obtained from unaffiliated third parties. In addition, although the Company, Conoco Canada and Conoco Inc. have attempted to address potential future conflicts of interest through a series of agreements, in light of the significant past and ongoing relationships among the Company, Conoco Canada and Conoco Inc., the nature of their respective businesses and Conoco Inc.'s interests in Indonesia and Asia, there may be conflicts of interest that arise in the future between the Company and Conoco Canada or Conoco Inc. SELECTED CONSOLIDATED FINANCIAL INFORMATION SELECTED CONSOLIDATED FINANCIAL INFORMATION Selected consolidated financial information is contained under the heading "Five-Year Financial Summary" on page 59 of the Corporation's 2001 Annual Report filed with securities commissions in Canada. This information is incorporated herein by reference as the Selected Consolidated Financial Information. A summary of quarterly financial information is included in page 57 of the Annual Report under the caption "Quarterly Summaries", which summary is incorporated herein by reference. 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 31 to 40 of the Corporation's 2001 Annual Report and is 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. -20- DIRECTORS Reference is made to information contained under the heading "Election of Directors" on pages 3 to 5 of the Corporation's Management Proxy Circular dated March 18, 2002 (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, 2001 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 16,323 Common Shares or approximately 0.019 percent of the Common Shares of the Corporation. 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 588,816 Common Shares, or approximately 0.67 percent, of the Common Shares of the Corporation. The Audit Committee of the Board of Directors is described under the heading "Election of Directors" on page 5 of the Circular and the Compensation Committee is described under the heading "Composition of the Compensation and Pension Committee" on page 9 of the Circular. The Corporation does not have an executive committee. OFFICERS
NAME AND MUNICIPALITY OF RESIDENCE POSITION WITH THE CORPORATION Robert H. Allen Chairman of the Board of Directors Houston, Texas Paul C. Warwick President, Chief Executive Officer and Director Jakarta, Indonesia Taufik Ahmad Vice President, Administration Jakarta, Indonesia Andrew Hastings Vice President, Gas Marketing and Business Development Jakarta, Indonesia Donald D. MeKechnie Vice President, Finance Jakarta, Indonesia Supramu Santosa Vice President, Corporate Strategy and Government Relations Jakarta, Indonesia John K. Wearing Vice President, Operations Jakarta, Indonesia Cliff W. Zeliff Vice President, Exploration Jakarta, Indonesia Alan P. Scott Corporate Secretary Calgary, Alberta
-21- Mr. Allen has been Chairman of the Board of the Corporation since February 18, 1998. Paul C. Warwick was appointed President and Chief Executive Officer of the Corporation on July 24, 2001, succeeding William T. Fanagan who resigned from that position on that same date. Prior to assuming his position with the Corporation, Mr. Warwick had served since 1999 as President and Managing Director of Conoco Energy Nigeria Limited, Nigeria. Immediately prior to that appointment in 1999, Mr. Warwick was President and Chief Executive Officer of Gulfstream Resources (Canada) Limited and, from 1997 to 1999, he was Managing Director, Phoenix Park Gas Processors Limited in Trinidad. Taufik Ahmad was appointed Vice President, Administration of the Corporation on February 15, 2001. Prior to such appointment, Mr. Ahmad was employed by the Company. Andrew Hastings assumed his position as an officer of the Corporation on January 1, 2002. Prior to assuming this position, Mr. Hastings was Business Development Manager for Conoco Global Power in London for four years and, prior thereto, was Business Development Manager for Conoco European Gas Limited in London. Donald D. McKechnie was appointed Vice President, Finance in June 2001 succeeding Murray E. Hesje who had moved to Calgary in February 2001 to assume a position with Gulf Canada. Prior to joining the Corporation at the time of his appointment, Mr. McKechnie was Vice President, Finance and Corporate Secretary for Momentum Energy International Inc. from September 1997 and, prior thereto, was Vice President, Finance of Transwest Energy Inc. Prior to assuming his current position, Supramu Santosa was the Vice President, Administration of the Corporation's operating subsidiaries and held such position since 1989. John K. Wearing was appointed Vice President, Operations of the Corporation effective July 1, 2001, replacing Robert W. Klassen who left the Corporation and returned to Canada. Prior to his appointment Mr. Wearing was Coordinator, Asset Management for Gulf Canada in Calgary. Prior thereto, Mr. Wearing was President of Wearing Petroleum Management Ltd. in Calgary from 1999 through 2000 and, prior thereto, was Vice President Operations of Maxx Petroleum Ltd. in Calgary where he had served since 1996. Cliff W. Zeliff has been Vice President, Exploration of the Corporation's operating subsidiaries since 1990. Mr. Zeliff has been employed by the Company 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 Conoco 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 the Circular provided to holders of common shares of Gulf Indonesia in connection with the Annual General Meeting of Shareholders to be held on May 6, 2002. Additional financial information is provided in the Corporation's consolidated financial statements for the year ended December 31, 2001 filed with securities commissions in Canada and the Securities and Exchange Commission in the United States. -22- 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 ALP; (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. 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 Company'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 Company's reserves information presented in this Annual Information Form is based on estimates of reserves underlying the properties in which Gulf Indonesia 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 -23- otherwise indicated, gross to Gulf Indonesia 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. 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 Canadian generally accepted accounting principles 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. /s/ PAUL C. WARWICK /s/ DONALD D. MCKECHNIE PAUL C. WARWICK DONALD D. MCKECHNIE President and Chief Executive Officer Vice-President, Finance February 19, 2002 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, 2001 and 2000 and the consolidated statements of earnings and retained earnings (deficit) and cash flows for each of the years in the three year period ended December 31, 2001. 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 Canadian generally accepted auditing standards. 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, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in accordance with Canadian generally accepted accounting principles. /s/ ERNST & YOUNG LLP ERNST & YOUNG LLP Calgary, Canada Chartered Accountants February 19, 2002 56 GULF INDONESIA RESOURCES LIMITED CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT) (millions of United States dollars, except per share amounts)
YEAR ENDED DECEMBER 31 ---------------------- 2001 2000 1999 ---- ---- ---- EARNINGS Revenues Gross oil and gas revenue (Note 1) $ 308 $ 421 $ 246 Government take 54 76 42 ----- ----- ----- Net oil and gas revenue 254 345 204 Other 4 4 2 ----- ----- ----- 258 349 206 ----- ----- ----- Expenses Operating 33 33 35 Exploration 24 18 11 General and administrative 13 5 6 Depreciation, depletion and amortization 66 69 70 Finance charges, net (Note 2) 10 19 21 ----- ----- ----- 146 144 143 ----- ----- ----- Earnings before tax 112 205 63 Income tax expense (Note 3) 80 121 30 ----- ----- ----- Earnings for the year $ 32 $ 84 $ 33 ----- ----- ----- Earnings per common share, basic and diluted (Note 4) $0.36 $0.96 $0.37 ----- ----- ----- RETAINED EARNINGS (DEFICIT) Balance, beginning of year $ 81 $ (3) $ (36) Earnings for the year 32 84 33 ----- ----- ----- Balance, end of year $ 113 $ 81 $ (3) ----- ----- -----
(See summary of significant accounting policies and notes to consolidated financial statements) 2001 ANNUAL REPORT 41 CONSOLIDATED STATEMENTS OF CASH FLOWS (millions of United States dollars)
YEAR ENDED DECEMBER 31 ----------------------- 2001 2000 1999 ----- ----- ----- OPERATING ACTIVITIES Earnings for the year $ 32 $ 84 $ 33 Non-cash items included in earnings Depreciation, depletion and amortization 66 69 70 Exploration expense 24 18 11 Future tax expense (Note 3) (2) 96 21 Other 6 4 2 ----- ----- ----- Cash generated from operations 126 271 137 Changes in non-cash working capital (Note 5) 15 19 (4) ----- ----- ----- 141 290 133 ----- ----- ----- INVESTING ACTIVITIES Capital expenditures and exploration expenses (104) (86) (66) Acquisitions (8) -- -- Decrease (increase) in cash restricted in use (Note 10) 96 (21) (73) Changes in non-cash working capital (Note 5) 1 -- (35) ----- ----- ----- (15) (107) (174) ----- ----- ----- FINANCING ACTIVITIES Long-term debt repayments (Note 10) (142) (103) (16) Proceeds from issue of long-term debt (Note 10) -- -- 18 ----- ----- ----- (142) (103) 2 ----- ----- ----- Increase (decrease) in cash and short-term investments (16) 80 (39) Cash and short-term investments, beginning of year 107 27 66 ----- ----- ----- Cash and short-term investments, end of year (Note 12) $ 91 $ 107 $ 27 ----- ----- -----
(See summary of significant accounting policies and notes to consolidated financial statements) 42 GULF INDONESIA RESOURCES LIMITED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (millions of United States dollars)
DECEMBER 31 --------------- 2001 2000 ------ ------ ASSETS Current Cash and short-term investments (Note 12) $ 91 $ 107 Cash restricted in use (Note 10) 1 97 Accounts receivable (Note 12) 39 56 Other current assets (Note 6) 39 38 ------ ------ 170 298 Deferred charges -- 6 Property, plant and equipment (Note 7) 778 756 ------ ------ $ 948 $1,060 ------ ------ LIABILITIES AND SHAREHOLDERS' EQUITY Current Accounts payable $ 58 $ 53 Accounts payable - parent/affiliate (Note 8) 10 9 Current portion of long-term debt (Note 10) -- 31 Other current liabilities (Note 9) 13 19 ------ ------ 81 112 Long-term debt (Note 10) -- 111 Future income taxes (Note 3) 255 257 ------ ------ 336 480 ------ ------ Commitments and contingent liabilities (Note 13) Shareholders' equity Share capital (Note 11) 499 499 Retained earnings 113 81 ------ ------ 612 580 ------ ------ $ 948 $1,060 ------ ------
(See summary of significant accounting policies and notes to consolidated financial statements) Approved by the Board /s/ ROBERT H. ALLEN /s/ DONALD F. MAZANKOWSKI ROBERT H. ALLEN THE RIGHT HONOURABLE DONALD F. MAZANKOWSKI Chairman Director 2001 ANNUAL REPORT 43 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, 2001, the company is a 72 per cent owned subsidiary of Conoco Canada Resources Limited (formerly Gulf Canada Resources Limited), an indirect subsidiary of Conoco Inc. 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 significant 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 over 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. Under the terms of each contract, the company and its co-participants (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 approximately 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 generally will provide an after-tax rate of return 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. 44 GULF INDONESIA RESOURCES LIMITED 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 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 were recorded as deferred charges and, upon completion of the Project construction period in 1999, amortized over the remaining term of the loan. All such deferred charges were fully amortized by December 31, 2001. 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. 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. 2001 ANNUAL REPORT 45 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 ----------------------- 2001 2000 1999 ----- ----- ----- Pipeline tariffs - gas $ 32 $ 38 $ 37 Pipeline tariffs - oil 1 1 1 ----- ----- ----- $ 33 $ 39 $ 38 ===== ===== =====
2. FINANCE CHARGES, NET
YEAR ENDED DECEMBER 31 ----------------------- 2001 2000 1999 ----- ----- ----- Interest expense on Corridor Loan $ 5 $ 18 $ 19 Other finance charges(a) 1 2 2 Less: interest income on restricted cash related to the Corridor Loan (2) (5) (1) ----- ----- ----- Cash finance charges, net 4 15 20 Amortization of debt placement costs 6 4 1 ----- ----- ----- $ 10 $ 19 $ 21 ===== ===== =====
(a) In 2001, pursuant to the Senior Revolving Term Credit Facility (see note 10) between the company and its parent, Conoco Canada Resources Limited, the company incurred a standby fee of 1.5 per cent on the undrawn amount of the facility. In 1999 and 2000 as required under the terms of the Corridor Loan, the company's parent made available to the company a letter of credit totaling $42 million. During 2000, the letter of credit was replaced with cash. (b) Cash interest paid (including other finance charges) and included in the determination of earnings was $7 million for 2001 (2000 - $26 million; 1999 - $14 million). 3. INCOME TAX Effective tax rate reconciliation: The income tax expense 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 ----------------------- 2001 2000 1999 ----- ----- ----- Earnings before income taxes $ 112 $ 205 $ 63 ----- ----- ----- Computed income tax expense at the statutory rate 49 90 28 Difference between statutory tax rate and PSC tax rates 16 27 11 Other revenues taxed at non-statutory rates (3) (5) (3) Non-deductible costs related to amortization of assets with no tax basis 1 1 1 Petroleum revenue tax 1 2 1 Unrecorded income tax benefit arising from losses of non-producing subsidiaries(a) 11 9 5 Recognition of previously unrecognized temporary differences(b) -- -- (10) Other 5 (3) (3) ----- ----- ----- Income tax expense $ 80 $ 121 $ 30 ===== ===== ===== Current tax expense $ 82 $ 25 $ 9 Future tax expense (recovery) (2) 96 21 ----- ----- ----- Income tax expense $ 80 $ 121 $ 30 ===== ===== =====
46 GULF INDONESIA LIMITED (a) At December 31, 2001, certain non-producing subsidiaries of the company have accumulated losses for tax purposes of approximately $89 million which may be carried forward and used to reduce taxable income in these companies in future years. These losses, which relate primarily to exploration expenditures in pre-commercial production sharing contracts, may be utilized if and when development occurs in these production sharing contract areas. 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 incurred to date 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 was $92 million for 2001 (2000 - $15 million; 1999 - $6 million). Component of the company's future tax liability: The future tax liability comprises:
DECEMBER 31 -------------- 2001 2000 ----- ----- Differences between tax bases and reported amounts of depreciable assets $ 248 $ 250 Income tax benefit arising from losses of non-producing subsidiaries(a) 39 28 Valuation allowance(a) (32) (21) ----- ----- $ 255 $ 257 ===== =====
(a) 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. 4. EARNINGS PER COMMON SHARE The weighted average number of common shares outstanding was 87,920,321 for 2001, 87,901,350 for 2000 and 87,905,320 for 1999. Stock options outstanding for all periods presented do not have a dilutive effect on earnings per common share. 5. CHANGES IN NON-CASH WORKING CAPITAL
YEAR ENDED DECEMBER 31 ---------------------- 2001 2000 1999 ----- ----- ----- (Increase) decrease in non-cash working capital Accounts receivable $ 17 $ 13 $ (29) Other current assets (1) (2) (6) Accounts payable 5 1 (9) Accounts payable - parent/affiliate 1 1 2 Other current liabilities (6) 6 3 ----- ----- ----- $ 16 $ 19 (39) ===== ===== ===== The change relates to the following activities: Operating $ 15 $ 19 $ (4) Investing 1 -- (35) ----- ----- ----- $ 16 $ 19 $ (39) ===== ===== =====
2001 ANNUAL REPORT 47 6. OTHER CURRENT ASSETS
DECEMBER 31 -------------------- 2001 2000 ------ ------ Materials and supplies $ 32 $ 35 Product inventory 3 2 Prepaid expenses 4 1 ------ ------ $ 39 $ 38 ====== ======
7. PROPERTY, PLANT AND EQUIPMENT
Accumulated Gross depreciation, investment depletion and Net at cost amortization investment ---------- ------------- ---------- DECEMBER 31, 2001 $1,319 $ 541 $ 778 ====== ====== ===== December 31, 2000 $1,231 $ 475 $ 756 ====== ====== =====
Property, plant and equipment not being amortized at December 31, 2001 was $220 million (December 31, 2000 - $238 million). 8. ACCOUNTS PAYABLE-PARENT/AFFILIATE Amounts due to the company's parent and affiliate are interest free, unsecured, and callable on demand and are as follows:
DECEMBER 31 -------------------- 2001 2000 ----- ----- Accounts payable-parent/affiliate Conoco Canada Resources Limited $ 8 $ 7 GCRL International Limited 2 2 ----- ----- $ 10 $ 9 ===== =====
Pursuant to inter-company agreements, the company's parent and its affiliate provide certain technical, financial and accounting and administrative services to the company (2001 - $1 million; 2000 - $1 million; 1999 - nil). 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 -------------------- 2001 2000 ----- ----- Income taxes payable $ 4 $ 14 Deferred take-or-pay revenue(a) 8 -- Interest payable on long-term debt (Note 10) -- 2 Withholding tax payable -- 3 Other 1 -- ----- ----- $ 13 $ 19 ===== =====
(a) Pursuant to the terms of certain gas sales contracts, should gas sales fall below prescribed minimum levels, the customer is required to compensate the company relative to the deficiencies. Amounts received are recorded as deferred revenue and are recognized as income when the gas is eventually delivered. During 2001, the company received $10 million of such payments, of which $2 million was recognized as income in the fourth quarter. 48 GULF INDONESIA RESOURCES LIMITED 10. LONG-TERM DEBT On February 26, 1997, the company, along with its co-participant 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 Lenders recourse under the Corridor Loan was limited to the Corridor PSC asset that was pledged as collateral. The interest rate on the Corridor Loan wan 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. The effective interest rate on the balance outstanding during 2001 was approximately 6.96 per cent (2000 - 8.42 per cent; 1999 - 7.68 per cent). On August 8, 2001, the company used its existing cash balances to completely repay the Corridor Loan. At December 31, 2000, the outstanding balance of the Corridor Loan was $142 million and the company had $97 million of restricted cash in offshore trust accounts to satisfy the requirement to fund the next scheduled interest and principal payments and accumulated reserve requirements. Repayments of the Corridor Loan were quarterly installments that were scheduled to end in February 2007. The company has executed a committed Senior Revolving Term Credit Facility with its parent company, Conoco Canada Resources Limited, for $65 million for a three-year period at commercial terms and conditions. As at December 31, 2001, no funds had been drawn under this facility. 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 Issued pursuant to exercise of stock options (b) 64,419 -- Cancelled pursuant to exercise of stock options (b) (37,916) -- ---------- ------ AT DECEMBER 31, 2001 87,927,853 $ 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, the company may grant options to its employees at anytime prior to December 31, 2007. 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, 3,421,584 (2000 - 2,688,510 shares, 1999 - 3,009,219) are reserved but unallocated. 2001 ANNUAL REPORT 49 A summary of the status of the company's stock options as at December 31, 2001 and 2000 and changes during the years then ended are presented below:
2001 2000 --------------------------------------------------------------------------------------------- Weighted Weighted Average Average Exercise Exercise Options Price Options Price ---------- --------- --------- -------- Outstanding, beginning of year 6,097,625 $ 17.04 5,776,916 $ 18.29 Granted 774,875 8.84 738,125 8.16 Forfeited (1,569,718) (18.77) (417,416) (18.55) Exercised (64,419) (8.17) -- -- ---------- --------- --------- -------- Outstanding, end of year 5,238,363 $ 15.42 6,097,625 $ 17.04 ---------- --------- --------- -------- Options exercisable at year-end 4,113,540 4,737,375 Weighted average fair value of options granted during the year $ 3.00 $ 3.15
The following table summarizes information about stock options outstanding at December 31, 2001:
Options Outstanding Options Exercisable ------------------------------------- ----------------------- Average Number Remaining Average Number Average Outstanding Contractual Exercise Outstanding Exercise Range of Exercise Prices at 12/31/01 Life Price at 12/31/01 Price ------------------------ ----------- ----------- -------- ----------- --------- $ 8.06 - 9.06 1,179,613 8.9 years $ 8.17 378,790 $ 8.21 $10.70 - 15.38 1,053,750 7.4 years $11.94 729,750 $12.29 $19.31 - 20.06 3,005,000 5.9 years $19.48 3,005,000 $19.48 --------- --------- ------- --------- ------ 5,238,363 6.9 years $15.42 4,113,540 $17.17 --------- --------- ------- --------- ------
The company's aggregate stated capital at December 31, 2001 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. Except as referred to below, short-term investments are comprised of commercial paper with a maturity period no greater than 90 days. The average interest rate earned in 2001 from the short-term investments was 3.33 per cent (2000 - 6.26 per cent; 1999 - 5.15 per cent). Cash and short-term investments at December 31, 2001 included promissory notes of $52 million due from the company's parent and affiliate. Such promissory notes were in line with current commercial terms and were repaid in full in January 2002. The fair value of all 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 (2001 - $114 million; 2000 - $149 million: 1999 - $89 million). Offshore crude oil production from the Kakap PSC is marketed to customers throughout Asia. Accounts receivable at December 31, 2001, included $17 million from Pertamina, $6 million from Itochu and $16 million from other sources, the latter of which is subject to normal industry credit risks and routinely assessed for financial strength. 50 GULF INDONESIA RESOURCES LIMITED 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 that was amended and extended in October 1996, and the Kakap PSC that 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 agreements were signed. Total anticipated future costs (including plugging and abandoning wells), given the company's current inventory of wells and facilities, is approximately $6 million. 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, 2001. 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. Penalties by the Indonesian tax authorities amounting to $4 million have been assessed on the company for late payment of withholding tax on hypothetical interest cost recoverable in the Corridor PSC. The current Indonesian tax code does not address the issue of hypothetical interest. The company has entered into discussions with the local tax authorities and believe that such penalties will ultimately be waived. In accordance with the Ministry of Finance, production sharing contractors were permitted to defer payments of value added tax (VAT) related to specific exploration projects until commercial production. The company currently has approximately $3 million of deferred VAT recorded in accounts payable and accounts receivable. However, commencing January 1, 2000, the deferral of payments of VAT is no longer permitted and the company is likely to be assessed for the VAT payable as well as penalties amounting to approximately $2 million. The VAT payable will be reimbursed at some future time if and when commercial production commences. The industry has been lobbying government to reinstate the previous arrangement and many cases are pending trial in regard to this issue. Management considers such penalties unreasonable and awaits further clarification from the government. The company has been advised by Canadian tax authorities that they are proposing to issue a notice of assessment related to a dividend paid between two of the company's subsidiaries in 1994. The income tax in question for 1994 amounts to $16 million. The company made similar dividend payments in subsequent years and the comparable tax for those years would be $31 million. The company is of the view that the dividend qualifies for a tax exemption in Canada since it represents a repatriation of profits from Indonesian operations on which Indonesian taxes have already been paid. The position taken by the Canadian tax authorities is that in this particular circumstance the amounts paid to Indonesian authorities do not qualify as foreign taxes paid and therefore no exemption is available on the repatriation of the profits to Canada. The company does not agree with this interpretation and intends to challenge any assessment that may be received. 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. 2001 ANNUAL REPORT 51 14. SEGMENT INFORMATION
ONSHORE - GAS ONSHORE - OIL OFFSHORE - OIL AND GAS --------------------- --------------------- ---------------------- 2001 2000 1999 2001 2000 1999 2001 2000 1999 ----- ----- ----- ----- ----- ----- ----- ----- ----- Revenues Gross oil and gas revenue $ 152 $ 228 $ 118 $ 114 $ 151 $ 91 $ 42 $ 45 $ 40 Government take 9 13 7 39 52 25 6 11 10 ----- ----- ----- ----- ----- ----- ----- ----- ----- Net oil and gas revenue 143 215 111 75 99 66 36 34 30 Other -- -- -- -- -- -- -- -- -- ----- ----- ----- ----- ----- ----- ----- ----- ----- 143 215 111 75 99 66 36 34 30 ----- ----- ----- ----- ----- ----- ----- ----- ----- Expenses Operating 8 9 9 16 15 18 9 9 8 Exploration -- -- -- -- -- -- -- -- -- General and administrative -- -- -- -- -- -- -- -- -- Depreciation, depletion and amortization 21 29 29 22 30 26 20 10 15 Finance charges, net 10 19 21 -- -- -- -- -- -- ----- ----- ----- ----- ----- ----- ----- ----- ----- 39 57 59 38 45 44 29 19 23 ----- ----- ----- ----- ----- ----- ----- ----- ----- Earnings (loss) before tax 104 158 52 37 54 22 7 15 7 Income tax expense (recovery) Current 58 11 -- 15 12 7 8 1 2 Future 3 77 30 8 17 3 (4) 6 2 ----- ----- ----- ----- ----- ----- ----- ----- ----- 61 88 30 23 29 10 4 7 4 ----- ----- ----- ----- ----- ----- ----- ----- ----- Earnings (loss) for the year $ 43 $ 70 $ 22 $ 14 $ 25 $ 12 $ 3 $ 8 $ 3 ----- ----- ----- ----- ----- ----- ----- ----- ----- Total assets $ 419 $ 466 $ 438 $ 199 $ 234 $ 272 $ 199 $ 211 $ 180 ----- ----- ----- ----- ----- ----- ----- ----- ----- Capital expenditures and exploration expenses $ 29 $ 10 $ 9 $ 20 $ 15 $ 14 $ 6 $ 32 $ 11 ----- ----- ----- ----- ----- ----- ----- ----- -----
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 located 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. 52 GULF INDONESIA RESOURCES LIMITED 14. SEGMENT INFORMATION (continued)
EXPLORATION CORPORATE TOTAL -------------------------- -------------------------- ------------------------- 2001 2000 1999 2001 2000 1999 2001 2000 1999 ------ ------ ------ ------ ------ ------ ------ ------ ------ Revenues Gross oil and gas revenue $ -- -- -- $ -- $ (3) $ (3) $ 308 $ 421 $ 246 Government take -- -- -- -- -- -- 54 76 42 ------ ------ ------ ------ ------ ------ ------ ------ ------ Net oil and gas revenue -- -- -- 4 (3) (3) 254 345 204 Other -- -- -- 4 4 2 4 4 2 ------ ------ ------ ------ ------ ------ ------ ------ ------ -- -- -- 4 1 (1) 258 349 206 ------ ------ ------ ------ ------ ------ ------ ------ ------ Expenses Operating -- -- -- -- -- -- 33 33 35 Exploration 24 18 11 -- -- -- 24 18 11 General and administrative -- -- -- 13 5 6 13 5 6 Depreciation, depletion and amortization 3 -- -- -- -- -- 66 69 70 Finance charges, net -- -- -- -- -- -- 10 19 21 ------ ------ ------ ------ ------ ------ ------ ------ ------ 27 18 11 13 5 6 146 144 143 ------ ------ ------ ------ ------ ------ ------ ------ ------ Earnings (loss) before tax (27) (18) (11) (9) (4) (7) 112 205 63 Income tax expense (recovery) Current -- -- -- 1 1 -- 82 25 9 Future (4) (2) (12) (5) (2) (2) (2) 96 21 ------ ------ ------ ------ ------ ------ ------ ------ ------ (4) (2) (12) (4) (1) (2) 80 121 30 ------ ------ ------ ------ ------ ------ ------ ------ ------ Earnings (loss) for the year $ (23) $ (16) $ 1 $ (5) $ (3) $ (5) $ 32 $ 84 $ 33 ------ ------ ------ ------ ------ ------ ------ ------ ------ Total assets $ 89 $ 72 $ 68 $ 42 $ 77 $ 17 $ 948 $1,060 $ 975 ------ ------ ------ ------ ------ ------ ------ ------ ------ Capital expenditures and exploration expenses $ 49 $ 29 $ 32 $ -- $ -- $ -- $ 104 $ 86 $ 66 ------ ------ ------ ------ ------ ------ ------ ------ ------
2001 ANNUAL REPORT 53 15. UNITED STATES ACCOUNTING PRINCIPLES If United States generally accepted accounting principles (U.S. GAAP) had been followed, amounts on the Consolidated Statements of Cash Flow would be presented as follows:
YEAR ENDED DECEMBER 31 ----------------------- 2001 2000 1999 ----- ----- ----- OPERATING ACTIVITIES Cash generated from operations, as reported (a) $ 126 $ 271 $ 137 Changes in non-cash working capital, as reported 15 19 (4) Adjustments: Geological and geophysical expenditures (b) (13) (8) (10) ----- ----- ----- Operating activities, as adjusted $ 128 $ 282 $ 123 ----- ----- ----- INVESTING ACTIVITIES, as reported $ (15) $(107) $(174) Adjustments: Geological and geophysical expenditures (b) 13 8 10 ----- ----- ----- Investing activities, as adjusted $ (2) $ (99) $(164) ----- ----- -----
If U.S. GAAP had been followed, amounts on the Consolidated Statements of Financial Position would be adjusted as follows:
DECEMBER 31 ------------------- 2001 2000 ----- ----- Increase (decrease) ASSETS $ -- $ -- ----- ----- LIABILITIES AND SHAREHOLDERS' EQUITY Contributed surplus (c) $ 11 $ 11 Retained earnings (c) (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) 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. (b) Under U.S. GAAP, geological and geophysical expenditures would be classified as operating activities. (c) Prior to the company going public in 1997, certain costs related to 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. 54 GULF INDONESIA RESOURCES LIMITED (d) Statement of Financial Accounting Standards 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. FAS 143, "Accounting for Asset Retirement Obligations" is effective January 1, 2003. This standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it has incurred and a corresponding increase in the carrying amount of the related long-lived asset. FAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" is effective January 1, 2002. This standard clarifies certain implementation issues arising from an earlier standard, FAS 121. At this time, management does not believe that FAS 143 and FAS 144 will have a material effect on the company's consolidated financial statements. Comprehensive income, as defined by Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income", is equivalent to earnings as presented. 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 an 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 and earnings 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 2001 was $2 million (2000 - $2 million; 1999 - $3 million). Pro forma disclosures are not likely to be representative of the effects on reported earnings for future years.
YEAR ENDED DECEMBER 31 ------------------------- 2001 2000 1999 ----- ----- ----- Earnings As reported $ 32 $ 84 $ 33 Pro forma $ 30 $ 82 $ 30 Earnings per common share ($/share) As reported $0.36 $0.96 $0.37 Pro forma $0.34 $0.94 $0.33
The fair value of the options granted during 2001 is estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions: expected volatility of 50 per cent (2000 - 50 per cent; 1999 - 55 per cent), risk-free interest rate of 4.5 per cent (2000 - 5.1 per cent; 1999 - 6.5 per cent) and expected life of 3 years (2000 - 3 years; 1999 - 3 years). 16. RECLASSIFICATIONS Certain amounts for 2000 and 1999 have been reclassified to conform to the presentation adopted for 2001. 2001 ANNUAL REPORT 55 FINANCIAL HIGHLIGHTS o Cash generated from operations of $126 million ($1.43 per share) o Earnings of $32 million ($0.36 per share) o Operating costs of $2.19 per boe o F&D costs of $3.65 per boe of gross proved reserves added, with 188 per cent of 2001 production replaced o Payout of the company's original investment in the Corridor Gas Project after only three years of operation o Repayment of the entire balance of the Corridor Loan facility five and a half years ahead of schedule, resulting in a debt-free balance sheet o Increase in the net cash surplus to $92 million at year-end 2001 [PICTURE OF DON MCKECHNIE] MANAGEMENT'S DISCUSSION AND ANALYSIS RESULTS FROM OPERATIONS
CONSOLIDATED RESULTS 2001 2000 1999 US$ US$/ US$ US$/ US$ US$/ million boe million boe million boe ------- ----- ------- ----- ------- ----- Gross oil and gas revenue 308 20.46 421 24.69 246 14.18 Government take (54) (3.57) (76) (4.44) (42) (2.45) ----- ----- ----- ----- ----- ----- Net oil and gas revenue 254 16.89 345 20.25 204 11.73 Other revenue 4 0.24 4 0.23 2 0.14 Operating expense (33) (2.19) (33) (1.95) (35) (2.05) Exploration expense (24) (1.56) (18) (1.07) (11) (0.64) General and administrative expense (13) (0.85) (5) (0.33) (6) (0.34) DD&A expense (66) (4.43) (69) (4.06) (70) (4.02) Finance charges, net Cash interest charges, net (4) (0.30) (15) (0.86) (20) (1.13) Amortization of debt placement costs (6) (0.40) (4) (0.24) (1) (0.08) Income tax expense Current (82) (5.42) (25) (1.47) (9) (0.49) Future 2 0.11 (96) (5.56) (21) (1.24) ----- ----- ----- ----- ----- ----- Earnings 32 2.09 84 4.94 33 1.88 Add back non-cash items 94 6.28 187 10.93 104 6.02 ----- ----- ----- ----- ----- ----- Cash generated from operations 126 8.37 271 15.87 137 7.90 ----- ----- ----- ----- ----- ----- Volumes sold (mboe/d)(gross/net) 41.3/35.8 46.6/39.7 47.6/41.7 WTI (US$/bbl) $25.90 $30.20 $19.24 Per share (dollars) Cash generated from operations $ 1.43 $ 3.08 $ 1.56 Earnings $ 0.36 $ 0.96 $ 0.37
2001 ANNUAL REPORT 31 The company's 2001 results varied from the 2000 results due to the following: o A reduction in the reported share of Corridor Gas Project results from 60 per cent to 54 percent. During the development of the Project, the company incurred certain costs on behalf of Pertamina's working interest share of the Corridor PSC. As reimbursement of these costs, the company was entitled to an increased share of production until full repayment occurred in December 2000. o A reduction in sales volumes, primarily due to lower gas deliveries to Caltex in the first three quarters of the year and reservoir declines in its mature onshore and offshore oil fields. These effects were partially offset by the positive impact of gas sales from the West Natuna Gas Project. o A seventeen per cent reduction in realized prices for the year that was comprised of a fourteen per cent fall in world oil prices and a further three per cent fall due to weaker relative demand for Indonesian crude types. o An increase in exploration expense due to higher level of exploration activity. o An increase in general and administrative expense due to lower overhead recoveries from partners, one-time costs related to the third quarter acquisition of the company's parent by Conoco Inc., and an increase in community relations activities. o An improvement in net cash finance charges due to lower average outstanding net debt balances and lower interest rates. o An increase in non-cash finance charges due to the repayment of the Corridor Loan that accelerated the amortization of the remaining deferred debt placement costs. o An increase in current taxes for the Corridor PSC in 2001 as available tax deductions resulting from the Corridor Gas Project were fully utilized by the fourth quarter of 2000. o An adjustment relating to withholding taxes paid on interest costs recoverable in the Corridor PSC. The following table summarizes the impacts of the above items on the company's year-over-year results. RECONCILIATION OF SALES VOLUMES, CASH GENERATED FROM OPERATIONS AND EARNINGS
2001 VERSUS 2000 Sales Cash Generated Volumes From Operations Earnings ------- --------------- ------------ (mboe/d) (US$millions) (US$millions) Year ended December 31, 2000 46.6 271 84 Reconciling Items: Reduction in reported share of Corridor Gas Project results from 60 per cent to 54 per cent (2.9) (21) (8) Lower gas deliveries to Caltex (1.6) (12) (5) Lower onshore oil sales volumes (1.1) (8) (3) Lower offshore oil sales volumes (0.8) (6) (2) New gas sales volumes from the West Natuna Gas Project 1.1 10 2 Lower realized oil and gas prices (54) (25) Increase in exploration expense (4) Increase in general and administrative expense (8) (5) Write-off of costs related to relinquished blocks (3) Improvement in net cash finance charges 11 5 Increase in non-cash finance charges (1) Increase in current taxes for the Corridor PSC (41) Withholding tax adjustment for the Corridor PSC (11) (5) Other (5) 2 ---- ---- ---- YEAR ENDED DECEMBER 31, 2001 41.3 126 32
32 GULF INDONESIA RESOURCES LIMITED CAPITAL AND EXPLORATION EXPENDITURES AND ACQUISITIONS
(millions of US dollars) 2001 2000 1999 ---- ---- ---- Exploration/Delineation Onshore gas 16 6 11 Onshore oil 6 7 14 Offshore oil and gas 21 15 6 New ventures 6 1 1 --- --- --- 49 29 32 --- --- --- Development Onshore gas 29 10 9 Onshore oil 20 15 14 Offshore oil and gas 6 32 11 --- --- --- 55 57 34 --- --- --- Total capital and exploration expenditures 104 86 66 Acquisitions 8 -- -- --- --- --- 112 86 66
Capital and exploration expenditures and acquisitions totaled $112 million in 2001 compared to $86 million in 2000, reflecting an increase in exploration and delineation activities and the acquisition of an increased interest in the Pangkah PSC (see below). Development expenditures for the West Natuna Gas Project were the main reason for the increase in capital spending in 2000 compared to 1999. Exploration spending in 2001 of $49 million increased significantly compared to both 2000 and 1999 reflecting the drilling of eighteen exploration/delineation wells of which eleven were successful -- five offshore oil and gas, four onshore gas, and two onshore oil. The company drilled ten exploration/delineation wells in 2000 and five in 1999. As well, the company acquired interests in two new exploration blocks in 2001. Total development spending in 2001 of $55 million remained relatively flat year-over-year with higher levels of spending to develop the company's onshore gas fields being offset by lower offshore development spending (due to the completion of construction of the West Natuna Gas Project in 2000). The company also acquired an additional ten per cent working interest in the Pangkah PSC for approximately $8 million, increasing its working interest in this block to 22 per cent. PROVED RESERVES
2001 2000 1999 ----- ----- ----- Proved reserve additions (gross mmboe) 28.4 74.5 42.1 Finding and development costs (US$ per gross proved boe added) $3.65 $1.15 $1.57 Gross proved reserve replacement ratio (per cent of production) 188% 437% 242%
During 2001, the company booked 28.4 million boe of gross proved reserve additions, replacing 188 per cent of the oil and gas produced in the year at an average cost of $3.65 per boe. Over the past three years, the company has added 145 million boe of gross proved reserves, replacing nearly 300 per cent of the oil and gas produced over the three-year period at an average finding and development cost of $1.76 per boe. 2001 ANNUAL REPORT 33 SEGMENTS Gulf Indonesia reports its year-to-year operations in five business segments: onshore gas, onshore oil, offshore oil and gas, exploration and corporate. Each of the segments is detailed in this report. See Note 14 to the consolidated financial statements for additional segment information. ONSHORE GAS OPERATIONS
SEGMENT RESULTS 2001 2000 1999 US$ US$/ US$ US$/ US$ US$/ million boe million boe million boe ------- ----- ------- ----- ------- ----- Gross gas revenue Before pipeline tariff 184 21.62 266 26.22 155 15.83 Pipeline tariff (32) (3.72) (38) (3.72) (37) (3.72) Government take (9) (1.11) (13) (1.29) (7) (0.75) ----- ----- ----- ----- ----- ----- Net gas revenue 143 16.79 215 21.21 111 11.36 Operating expense (8) (0.93) (9) (0.94) (9) (0.99) DD&A expense (21) (2.53) (29) (2.87) (29) (3.00) Finance charges, net Cash interest charges net (4) (0.49) (15) (1.46) (20) (2.00) Amortization of debt placement costs (6) (0.70) (4) (0.39) (1) (0.15) Income tax expense Current (58) (6.85) (11) (1.07) -- -- Future (3) (0.36) (77) (7.63) (30) (3.08) ----- ----- ----- ----- ----- ----- Earnings 43 4.93 70 6.85 22 2.14 Add back non-cash items 30 3.59 110 10.89 60 6.23 ----- ----- ----- ----- ----- ----- Cash generated from operations 73 8.52 180 17.74 82 8.37 ----- ----- ----- ----- ----- ----- Volumes sold (gross/net) mmcf/d 140 / 134 166 / 159 161 / 154 mboe/d 23.3 / 22.4 27.7 / 26.5 26.8 / 25.7
The onshore gas segment consists of gas operations in the Corridor PSC. Related condensate production from this block is reported under the onshore oil segment, while exploration activity related to this block is reported under the exploration segment. The 2001 results for the onshore gas segment reflect the reduction in the reported share of Corridor Gas Project results from 60 per cent to 54 per cent. The impact of this reduction in reported share on sales volumes, cash generated from operations, and earnings for the onshore gas segment in 2001 was 2,800 boe/d, $21 million and $8 million, respectively. Cash generated from onshore gas operations was $73 million in 2001 compared to $180 million in 2000, primarily reflecting lower realized prices, lower reported sales volumes and higher current taxes, partially offset by lower cash finance charges. Cash generated from operations in 2000 benefited from higher realized prices, higher sales volumes and the improvement in cash finance charges compared to 1999. Gross revenue before pipeline tariff in 2001 was $184 million, 31 per cent lower than 2000 reflecting lower realized prices and lower reported sales volumes. Gross revenue before pipeline tariff in 2000 was higher than 1999 due to higher realized prices and higher reported sales volumes. Onshore gas prices are dependent on crude oil prices as the gas is exchanged for Duri crude oil on an energy equivalent basis. The 18 per cent decline in realized prices compared to 2000 reflects the 14 per cent decline in the WTI price and a six percent decrease resulting from lower demand for Duri crude relative to WTI, partially offset by a two per cent increase in price due to the higher energy content of the gas. The 66 per cent increase in realized price between 2000 and 1999 includes the impact of the 57 per cent improvement in the WTI price and higher demand for Duri crude relative to WTI. 34 GULF INDONESIA LIMITED The sales volume decrease of 26 mmcf/d between 2001 and 2000 reflects the following: o A reduction of approximately 17 mmcf/d reflecting the change in the company's reported share of Corridor Gas Project results from 60 per cent to 54 per cent. o A reduction of approximately 6 mmcf/d related to lower gas takes by Caltex during the first three quarters of 2001 to levels below the contracted take or pay amounts. During periods where gas takes fall below take or pay levels, Gulf Indonesia receives oil volumes equivalent to the contracted take or pay quantities of gas, thereby maintaining a minimum level of Duri crude oil liftings. In the fourth quarter of 2001, gas takes by Caltex increased to above take or pay levels, resulting in the delivery of make-up gas and the recognition of revenue at prices realized at the time the oil was received. o A reduction of approximately 3 mmcf/d in the volume required to meet the energy demand of Caltex. An increase in the carbon dioxide removal capacity at the Grissik gas plant during the latter part of 2000 helped to improve the energy content of the sales gas stream by two percent in 2001. Since the amount of Duri crude oil received in exchange for the gas deliveries is calculated based on energy and the pipeline tariff is calculated based on volume, the higher energy content of the gas improves overall netbacks by reducing the pipeline tariff per unit of energy sold. The year-over-year volume increase in 2000 compared to 1999 reflects lower volumes during the startup phase of the Project (January 1999) when gas production was constrained by restricted pipeline capacity. Government take in all three years was approximately five per cent of gross revenue before pipeline tariff. The low rate reflects utilization of substantial gas deductions (including hypothetical interest cost recovery and non-tax deductible investment credits). The company has claimed an investment credit related to the development of pre-tertiary gas reserves in the Dayung field that currently supplies gas to the Grissik gas plant for the Corridor Gas Project. This investment credit is equal to 130 per cent of the applicable costs of the related facilities and is claimed as a component of the costs recoverable from production in the Corridor PSC. This incentive reduces government take, but is taxable when claimed. The net cash flow benefit is approximately 9 percent of the amount claimed. The company's claim is subject to Pertamina approval. Operating expense per boe remained relatively flat from 2000 to 2001 as a decrease in costs related primarily to the installation of pre-treatment facilities at the Grissik gas plant in the second quarter of 2000 was virtually offset by lower volumes in 2001. Excluding a $0.29 per boa benefit from an insurance recovery in 1999, operating expenses per boa in 2000 were 27 percent lower than in 1999. Depreciation, depletion and amortization expense declined in 2001 due to lower volumes and a lower rate per boe. The depreciation, depletion and amortization rate per boe was lower in both 2001 and 2000, primarily as a result of significant low-cost reserve additions in 2000 and 1999, respectively. 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 $4 million in 2001 were $11 million below 2000 levels, due primarily to repayment of the Corridor Loan in August 2001, as discussed more fully in the "Liquidity and Capital Resources" section. The amortization of debt placement costs of $6 million in 2001 compared to $4 million in 2000 and $1 million in 1999 reflects the level of loan repayments in each of those years. Total income tax expense was $61 million in 2001, $88 million in 2000 and $30 million in 1999. The effective rate was approximately 59 per cent, 56 per cent and 59 per cent, respectively. While there were no current or cash income taxes in 1999, the Corridor PSC's available tax pools were fully utilized by the fourth quarter of 2000 resulting in the recognition of current taxes of $11 million in 2000 and $58 million in 2001 (including taxes owed related to investment credits claimed in the year). The extent of cash taxes in future periods will depend on revenues and the availability of tax-deductible costs, including the remaining tax depreciation on the Project facilities. Future costs in the Corridor PSC will generally be immediately available for tax deduction with the exception of the costs of production facilities and other tangible equipment that are to be depreciated over a specified period beginning in the year the particular asset is placed into service. In 2001, the Sumpal field facilities were placed into service, reducing the company's tax liability in the year by $2 million. 2001 ANNUAL REPORT 35 ONSHORE OIL OPERATIONS
SEGMENT RESULTS 2001 2000 1999 US$ US$/ US$ US$/ US$ US$/ million bbl million bbl million bbl ------- ----- ------- ----- ------- ----- Gross liquids revenue 114 23.35 151 28.18 91 17.14 Government take (39) (7.92) (52) (9.67) (25) (4.66) ----- ----- ----- ----- ----- ----- Net liquids revenue 75 15.43 99 18.51 66 12.48 Operating expense (16) (3.28) (15) (2.81) (18) (3.36) DD&A expense (22) (4.45) (30) (5.58) (26) (4.89) Income tax expense Current (15) (3.21) (12) (2.32) (7) (1.25) Future (8) (1.55) (17) (3.08) (3) (0.71) ----- ----- ----- ----- ----- ----- Earnings 14 2.94 25 4.72 12 2.27 Add back non-cash items 30 6.00 47 8.66 29 5.60 ----- ----- ----- ----- ----- ----- Cash generated from operations 44 8.94 72 13.38 41 7.87 ----- ----- ----- ----- ----- ----- Volumes sold (mb/d)(gross/net) Corridor TAC 8.0/5.0 8.1/5.0 7.2/ 4.6 Corridor PSC 3.2/2.7 3.6/3.1 4.2/ 3.5 Jambi EOR 2.1/1.4 2.6/1.5 2.3/ 2.0 -------- -------- --------- 13.3/9.1 14.3/9.6 13.7/10.1 Other 0.1/0.1 0.3/0.3 0.9/ 0.8 -------- -------- --------- 13.4/9.2 14.6/9.9 14.6/10.9
The onshore oil segment consists of crude oil and condensate operations in the Corridor TAC, Corridor PSC, Jambi EOR and "other" which includes the Block A PSC and an overriding royalty on the gas and condensate production from the Block B PSC. Exploration activity related to these blocks is reported under the exploration segment. Cash generated from onshore oil operations was $44 million in 2001, down 39 per cent from 2000, primarily as a result of lower realized prices and lower sales volumes. Cash generated from operations in 2000 benefited from higher realized prices and reduced operating expenses compared to 1999. Onshore oil sales volumes were 13,400 b/d in 2001 compared to 14,600 b/d in 2000 and 1999. Sales volumes before "other" were 13,300 b/d in 2001, down seven per cent from 2000 as natural reservoir declines more than offset the impact of development activities during 2001. In 2000, volumes before "other' increased by four per cent as successful development activities in the Corridor TAC and Jambi EOR more than offset natural reservoir declines. "Other" volumes include an overriding royalty production payment which declined in 2001 and 2000 due to lower production from the gas fields in the Block B PSC in the province of Aceh. Government take averaged approximately 34 per cent of gross revenue during 2001 compared to 34 per cent in 2000 and 27 per cent in 1999. The government take rate for 200l and 2000 was higher than 1999 due to the full utilization in early 2000 of certain previously unrecovered costs for the Jambi EOR contract area. Operating expenses of $16 million in 2001 were 7 per cent above 2000 levels due primarily to increased costs in the Jambi EOR contract area. On a per barrel basis the operating cost increased to $3.28 per bbl due to higher costs and lower production. Costs in 2000 benefited from the impact of cost cutting initiatives. Depreciation, depletion and amortization expense was $22 million or $4.45 per bbl in 2001 compared to $30 million or $5.58 per bbl in 2000. This expense is based on net volumes and decreased on a per bbl basis in 2001 as a result of lower-cost reserve additions in the Corridor TAC at year-end 2000 In 2000, the depreciation, depletion and amortization expense per bbl increased as a result of negative reserve revisions at year-end 1999. Income tax expense was approximately 62 per cent of pre-tax earnings in 2001 compared to approximately 53 per cent in 2000. The increase in the effective tax rate in 2001 was due to the reduction in the proportionate share of taxable income arising from overriding royalties, which have a lower tax rate of 20 per cent. Current taxes increased in 2001 due to the recognition of current taxes for the Corridor PSC for the full year 2001. 36 GULF INDONESIA LIMITED OFFSHORE OIL AND GAS OPERATIONS
SEGMENT RESULTS 2001 2000 1999 US$ US$/ US$ US$/ US$ US$/ million boe million boe million boe ------- ------ ------- ----- ------- ----- Gross oil and gas revenue 42 25.09 45 28.61 40 17.65 Government take (6) (3.42) (11) (7.09) (10) (4.63) --- ------ --- ----- --- ----- Net oil and gas revenue 36 21.67 34 21.52 30 13.02 Operating expense (9) (5.37) (9) (5.55) (8) (3.50) DD&A expense (20) (12.22) (10) (6.58) (15) (6.35) Income tax (expense) recovery Current (8) (4.39) (1) (0.77) (2) (0.65) Future 4 2.22 (6) (3.40) (2) (1.14) --- ------ --- ----- --- ----- Earnings 3 1.91 8 5.22 3 1.38 Add back non-cash items 16 10.00 16 9.98 17 7.49 --- ------ --- ----- --- ----- Cash generated from operations 19 11.91 24 15.20 20 8.87 --- ------ --- ----- --- ----- Volumes sold (gross/net) Gas (mmcf/d) 6/ 6 --/ -- --/ -- Crude oil and condensate 3.5/3.1 4.3/3.3 6.2/5.1 ------- ------- ------- 4.6/4.2 4.3/3.3 6.2/5.1
The offshore oil and gas segment consists of operations related to the Kakap PSC, located in the West Natuna Sea. The 2001 results reflect the startup of gas sales from this PSC as part of the West Natuna Gas Project. Exploration activity related to this block is reported under the exploration segment. Cash generated from offshore operations was $19 million, compared to $24 million in 2000 and $20 million in 1999. The startup of gas sales from the Kakap PSC in 2001 generated $10 million in cash, while lower realized prices and lower sales volumes in 2001 decreased the cash generated by oil sales from this PSC. Gross oil and gas revenue was $42 million in 2001, lower than 2000 as lower prices more than offset higher volumes sold on a boe basis. The gross revenue in 2000 was higher than 1999 reflecting the impact of higher realized prices offset by lower crude oil and condensate sales volumes. Offshore volumes sold on a boe basis increased to 4,600 boe/d in 2001 from 4,300 b/d in 2000. Offshore oil sales volumes declined to 3,500 b/d in 2001 from 4,300 b/d in 2000 and 6,200 b/d in 1999 due to reservoir declines. West Natuna gas sales commenced in early 2001 and averaged 6 mmcf/d for the year. By the fourth quarter of 2001, West Natuna gas sales had increased to an average of 9 mmcf/d, with December 2001 volumes averaging 11 mmcf/d. Government take was $6 million in 2001 compared to $11 million in 2000 and $10 million in 1999, as lower revenues and higher deductions arising from the West Natuna Gas Project (including a non-tax deductible investment credit) reduced the Indonesian government's before-tax share of gross revenues. The company has claimed an investment credit equal to 55 per cent of the applicable costs of the West Natuna Gas Project. This incentive reduces government take, but is taxable when claimed. The net cash flow benefit over time is approximately 16.5 per cent of the amount claimed. The company's claim is subject to Pertamina approval. The operating expenses per barrel of oil equivalent in 2001 declined slightly from 2000 as the relatively fixed expenses in the Kakap PSC supported the increase in production related to the startup of gas sales. Operating costs per boe 1999 benefited from higher oil sales volumes. Depreciation, depletion and amortization expense increased in 20Ol due to higher depreciation, depletion and amortization rates and higher net volumes sold. Rates in 2001 reflect the transfer of $37 million of unproved property value to the proved (depreciable) category. Net volumes sold in 2001 increased due to the impact of higher deductions on the calculation of the company's share of production after government take (see above). Income tax effective rates were relatively comparable in each of the three years. Current income taxes increased to $8 million in 2001 from $1 million in 2000 primarily due to taxes owed on investment credits claimed in the year. 2001 ANNUAL REPORT 37 EXPLORATION
SEGMENT RESULTS (millions of US dollars) 2001 2000 1999 ---- ---- ---- Exploration expense Producing blocks (7) (3) (4) Non-producing blocks (17) (15) (7) --- --- --- (24) (18) (11) DD&A expense (3) -- -- Income tax recovery Future 4 2 12 --- --- --- Earnings (loss) (23) (16) 1
The exploration segment includes exploration activity related to the onshore producing Corridor PSC and non-producing South Jambi B and Tungkal PSCs, and the offshore producing Kakap PSC and non-producing Pangkah, Ketapang, Northwest Natuna Block I and Sebuku PSCs. The 2001 results also include the exploration activities in two new onshore non-producing blocks acquired in 2001 - the Banyumas and Sakakemang PSCs and in two non-producing blocks that were relinquished in 2001 - the onshore Calik PSC and offshore Sakala Timur PSC. The 1999 results include activities in the Halmahera, West Natuna and Merangin PSCs that were relinquished in that year. Exploration expense was $24 million for 2001 compared to $18 million in 2000 and $11 million in 1999. The company drilled eighteen exploration wells in 2001 compared to ten wells in 2000 and five wells in 1999. The success factor during each of these periods was 61 per cent, 40 per cent and 80 per cent, respectively. Depreciation, depletion and amortization expense of $3 million in 2001 reflects the write-off of costs related to exploration blocks that were relinquished. Income tax recoveries in the exploration segment reflect the company's ability to immediately recognize a tax recovery on exploration expense related to producing PSCs. As well, a tax recovery may be recognized for non-producing PSCs if it becomes likely at a particular time that these PSCs will be able to use the available tax pools. The tax recovery in 1999 includes $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
SEGMENT RESULTS (millions of US dollars) 2001 2000 1999 ---- ---- ---- Gross oil and gas revenue -- (3) (3) Other revenue 4 4 2 General and administrative expense (13) (5) (6) Income tax (expense) recovery Current (1) (1) -- Future 5 2 2 --- --- --- Earnings (loss) (5) (3) (5) Add back non-cash items (5) (2) (1) --- --- --- Cash generated from operations (10) (5) (6)
The corporate segment includes general and administrative expenses for the entire company and other revenue related to interest income on unrestricted cash and short-term investments. The 2000 and 1999 results also include the impact of the company's hedging program in those years. General and administrative expense increased to $13 million in 2001 compared to $5 million in 2000 and $6 million in 1999, reflecting lower overhead recoveries from partners, one-time severance costs related to the third quarter acquisition of the company's parent by Conoco Inc., and an increase in community relations activities. Interest income was $4 million in 2001 compared to $4 million in 2000 and $2 million in 1999, reflecting changes in cash and short-term investment balances and interest rates over these periods. During 2000 and 1999, the company utilized a limited crude oil hedging program to increase the likelihood that its annual capital programs could be funded from internally generated unrestricted cash flows. As actual prices were higher than the prices in the hedge contracts, the program resulted in a reduction in net oil and gas revenues of $3 million in both 2000 and 1999. A more detailed discussion of the company's use of crude oil hedging is included under "Risks and Uncertainties - Commodity Prices." 38 GULF INDONESIA RESOURCES LIMITED LIQUIDITY AND CAPITAL RESOURCES
DECEMBER 31 ------------ (millions of US dollars) 2001 2000 ------------------------ ---- ---- Cash and short-term investments 91 107 Cash restricted in use 1 97 Less: Long-term debt (including current portion) -- (142) ---- ---- Net cash position 92 62
During 2001, the company increased its net cash surplus by $30 million to $92 million from $62 million at year-end 2000. Cash generated from operations of $126 million exceeded the $112 million required for capital and exploration expenditures and acquisitions by $14 million while the receipt of deferred revenue in 2001 related to take or pay deficiencies for the Caltex I gas contract and other changes in non-cash working capital provided the remaining $16 million. In 2001, the company elected to accelerate the repayment of the Corridor Loan. As a result, the entire $142 million of the Corridor Loan facility that was outstanding at December 31, 2000 was repaid, five and a half years ahead of the originally scheduled final repayment date of February 2007 and less than three years after the startup of the Corridor Gas Project. In connection with the Corridor Loan repayment, the company entered into an agreement with its parent company, Conoco Canada Resources Limited (formerly Gulf Canada Resources Limited), for a $65 million committed Senior Revolving Term Credit Facility for a three-year period at commercial terms and conditions. Looking forward, the company expects to be able to fund its 2002 capital program of $120 million with internally generated cash and existing cash balances. Actual capital spending in 2002 will depend partially on the timing of expenditures related to capital projects and on whether development and/or delineation wells are drilled in the year. The company is actively evaluating business opportunities outside of its current asset portfolio. Funding for these opportunities could be provided by the company's existing cash balances and the credit facility from Conoco Canada. Opportunities requiring funding in excess of the company's current sources of funds may require external forms of financing. The company's ability to raise external funds 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, except for cash and short-term investments, are located in Indonesia. During 2001, the company did not experience, nor has it historically experienced, problems from civil unrest or disputes with the Indonesian government. However, Indonesia's political and economic environment could impact the company's financial position, results of operations or potential for growth in the future. The company expects that, should the need arise, its ability to borrow additional funds at a reasonable rate could be negatively impacted by the Indonesian environment. 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 continues to monitor the situation and may be required to re-evaluate its development plans as the situation warrants. If in the future the company decides not to proceed with its development plans or decides to dispose of its interest in this PSC, a material charge to earnings may result. The Indonesian government has exercised and continues to exercise significant influence over many aspects of the Indonesian economy, including the oil and gas industry, as demonstrated by the introduction of the new oil and gas law in 2001 and new laws on revenue sharing and autonomy in 2000. The company is attempting to mitigate its risk through building strong relationships with the local, regional, provincial and central governments and their agencies as well as with the communities in which it operates. However, 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 potential for growth in the future. An additional consequence of Indonesia's political and economic uncertainty is possible fluctuation in the Rupiah/US dollar exchange rate. However, this currency volatility is not expected to have a material long-term impact on the company's financial position, as all current revenues are US dollar-denominated, all major contracts entered into are in US dollars and Rupiah-denominated expenses are limited to approximately 10-15 per cent of the company's overall expenditure profile. 2001 ANNUAL REPORT 39 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 US 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. Onshore gas production from the Corridor Gas Project is exchanged for Duri crude oil that is exported at a price based on a formula tied to the Duri ICP. Offshore gas production is sold at prices linked to the price of fuel oil in Singapore. 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 seek to fund exploration, maintenance and current development capital programs with internally generated cash flows. When necessary, the company may use crude oil price hedging to help enhance the predictability of internal cash flows. Although the company does not have any outstanding oil price hedge positions, it will continue to assess its capital requirements and the need for price security in the future. INVESTMENT INCENTIVES Production sharing contracts in Indonesia contain incentives including interest cost recovery and investment credits that can be used to improve the economic viability of development projects. The company has applied for incentives related to its development projects and the company's financial results assume that the incentives will be granted. The incentives are subject to Pertamina approval and as such, if Pertamina does not approve these incentives, the company's current and future results could be materially impacted. SENSITIVITIES Based on current production and price assumptions, the estimated effect of a change in the following factors on the company's 2002 cash generated from operations and earnings is set out in the table below.
CASH GENERATED (MILLIONS OF US DOLLARS) FROM OPERATIONS EARNINGS ------------------------ --------------- -------- Prices: US$1.00/bbl change in WTI oil price 5 4 Sales: 1,000 b/d change in crude oil and condensate volumes 3 2 10 mmcf/d change in gas volumes 5 4
Cash generated from operations and earnings can also be influenced by the level of capital spending in the Corridor and Kakap PSCs, as available deductions for the government take and current income tax calculations are impacted by the amount of spending in a particular year. 40 GULF INDONESIA RESOURCES LIMITED [ERNST & YOUNG LETTERHEAD] CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS We consent to the use of our report dated February 19, 2002 with respect to the consolidated financial statements of Gulf Indonesia Resources Limited filed under cover of the Annual Report for the year ended December 31, 2001 (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 19, 2002 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 2001. /s/ ERNST & YOUNG LLP Calgary, Canada March 19, 2002 Chartered Accountants SUPPLEMENTARY OIL AND GAS INFORMATION (millions of United States dollars) (unaudited)
2001 2000 1999 ------ ------ ------ RESULTS OF OIL AND GAS OPERATIONS Gross revenue derived from proved oil and gas reserves $ 341 $ 460 $ 284 Less: Pipeline tariffs 33 39 38 Government take 54 76 42 ------ ------ ------ Net revenue derived from proved oil and gas reserves 254 345 204 Less: Production costs 33 33 35 Exploration expense 24 18 11 Depreciation, depletion and amortization 66 69 70 Income tax expense 80 121 30 ------ ------ ------ Results of operations from producing activities $ 51 $ 104 $ 58 ------ ------ ------ COSTS INCURRED Costs incurred (capitalized and expensed) for: Property acquisitions: Proved $ -- $ -- $ -- Unproved 9 -- -- Exploration 48 29 32 Development 55 57 34 ------ ------ ------ $ 112 $ 86 $ 66 ------ ------ ------ CAPITALIZED COSTS Proved properties $1,120 $1,012 $ 949 Unproved properties 153 180 179 Incomplete wells and facilities 46 39 35 ------ ------ ------ 1,319 1,231 1,163 Less related accumulated depreciation, depletion, and amortization 541 475 406 ------ ------ ------ Net capitalized costs $ 778 $ 756 $ 757 ------ ------ ------
60 GULF INDONESIA RESOURCES LIMITED STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (unaudited) 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
(millions of United States dollars) AS AT DECEMBER 31 ----------------------------- 2001 2000 1999 ------- ------- ------- Future cash inflows $ 2,693 $ 3,639 $ 3,072 Future development costs (203) (278) (309) Future production costs (388) (447) (364) Future income taxes (862) (1,238) (924) ------- ------- ------- Future net cash flows 1,240 1,676 1,475 10 per cent annual discount for estimated timing of cash flows (634) (840) (649) ------- ------- ------- Standardized measure of discounted future net cash flows $ 606 $ 836 $ 826 ======= ======= =======
CHANGES IN THE STANDARDIZED MEASURE DURING THE YEAR
(millions of United States dollars) YEAR ENDED DECEMBER 31 ----------------------------------- ----------------------------- 2001 2000 1999 ------- ------- ------- Sales of oil and gas produced net of production costs $ (221) $ (315) $ (173) Development costs incurred during the year 55 57 34 Extensions, discoveries and improved recovery, less related costs 62 254 158 Revisions of previous quantity and timing estimates 10 (5) 43 Price and cost changes - selling prices (510) 10 1,032 - production costs (2) (18) 5 - development costs 5 41 19 Accretion of discount 151 136 22 Change in income taxes 220 (150) (517) ------- ------- ------- Net change (230) 10 623 Balance at beginning of year 836 826 203 ------- ------- ------- Balance at end of year $ 606 $ 836 $ 826 ======= ======= =======
2001 ANNUAL REPORT 61
NET VOLUMES ---------------------------- OIL NGL GAS (MMBBLS) (MMBBLS) (BCF) -------- -------- ----- PROVED DEVELOPED At December 31, 1998 23 3 436 Additions from discoveries and extensions 0 0 0 Additions from improved recovery 0 0 0 Additions from development (1) 1 0 0 Purchases of Reserves in place 0 0 0 Revisions of previous estimates (5) (0) (4) Sales of reserves in place 0 0 0 Production (6) (0) (56) ---- ---- ---- At December 31, 1999 13 3 376 Additions from discoveries and extensions 0 0 0 Additions from improved recovery 0 0 0 Additions from development (1) 2 0 4 Purchases of Reserves in place 0 0 0 Revisions of previous estimates 2 (1) 52 Sales of reserves in place 0 0 0 Production (4) 0 (58) ---- ---- ---- At December 31, 2000 13 2 374 Additions from discoveries and extensions 0 0 0 Additions from improved recovery 0 0 0 Additions from development (1) 1 0 217 Purchases of Reserves in place 0 0 0 Revisions of previous estimates 2 (0) 12 Sales of reserves in place 0 0 0 Production (4) (0) (51) ---- ---- ---- At December 31, 2001 12 2 552 PROVED UNDEVELOPED At December 31, 1998 3 0 483 Additions from discoveries and extensions 0 1 100 Additions from improved recovery 0 0 0 Additions from development (1) 0 0 94 Purchases of Reserves in place 0 0 0 Revisions of previous estimates (0) 0 (56) Sales of reserves in place 0 0 0 Production 0 0 (1) ---- ---- ---- At December 31, 1999 3 1 620 Additions from discoveries and extensions 0 1 215 Additions from improved recovery 0 0 0 Additions from development (1) 0 0 87 Purchases of Reserves in place 0 0 0 Revisions of previous estimates (1) (0) (48) Sales of reserves in place 0 0 0 Production 0 0 0 ---- ---- ---- At December 31, 2000 2 2 874 Additions from discoveries and extensions (0) 0 117 Additions from improved recovery 0 0 0 Additions from development (1) (1) 0 (216) Purchases of Reserves in place 0 0 0 Revisions of previous estimates 0 (0) 36 Sales of reserves in place 0 0 0 Production 0 0 0 ---- ---- ---- At December 31, 2001 1 2 811
Note 1 - Under Financial Accounting Standards No. 69, these additions are considered part of revisions of previous estimates. 15. UNITED STATES ACCOUNTING PRINCIPLES If United States generally accepted accounting principles (U.S. GAAP) had been followed, amounts on the Consolidated Statements of Cash Flow would be presented as follows:
YEAR ENDED DECEMBER 31 ----------------------- 2001 2000 1999 ----- ----- ----- OPERATING ACTIVITIES Cash generated from operations, as reported (a) $ 126 $ 271 $ 137 Changes in non-cash working capital, as reported 15 19 (4) Adjustments: Geological and geophysical expenditures (b) (13) (8) (10) ----- ----- ----- Operating activities, as adjusted $ 128 $ 282 $ 123 ===== ===== ===== INVESTING ACTIVITIES, as reported $ (15) $(107) $(174) Adjustments: Geological and geophysical expenditures (b) 13 8 10 ----- ----- ----- Investing activities, as adjusted $ (2) $ (99) $(164) ===== ===== =====
If U.S. GAAP had been followed, amounts on the Consolidated Statements of Financial Position would be adjusted as follows:
DECEMBER 31 ------------------- 2001 2000 ---- ---- Increase (decrease) ASSETS $ -- $ -- ---- ---- LIABILITIES AND SHAREHOLDERS' EQUITY Contributed surplus (c) $ 11 $ 11 Retained earnings (c) (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) 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. (b) Under U.S. GAAP, geological and geophysical expenditures would be classified as operating activities. (c) Prior to the company going public in 1997, certain costs related to 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. 54 GULF INDONESIA RESOURCES LIMITED (d) Statement of Financial Accounting Standards 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. FAS 143, "Accounting for Asset Retirement Obligations" is effective January 1, 2003. This standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it has incurred and a corresponding increase in the carrying amount of the related long-lived asset. FAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" is effective January 1, 2002. This standard clarifies certain implementation issues arising from an earlier standard, FAS 121. At this time, management does not believe that FAS 143 and FAS 144 will have a material effect on the company's consolidated financial statements. Comprehensive income, as defined by Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income", is equivalent to earnings as presented. 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 and earnings 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 2001 was $2 million (2000 - $2 million; 1999 - $3 million). Pro forma disclosures are not likely to be representative of the effects on reported earnings for future years.
YEAR ENDED DECEMBER 31 ------------------------- 2001 2000 1999 ------ ------ ------ Earnings As reported $ 32 $ 84 $ 33 Pro forma $ 30 $ 82 $ 30 Earnings per common share ($/share) As reported $ 0.36 $ 0.96 $ 0.37 Pro forma $ 0.34 $ 0.94 $ 0.33
The fair value of the options granted during 2001 is estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions: expected volatility of 50 per cent (2000 - 50 per cent; 1999 - 55 per cent), risk-free interest rate of 4.5 per cent (2000 - 5.1 per cent; 1999 - 6.5 per cent) and expected life of 3 years (2000 - 3 years; 1999 - 3 years). 16. RECLASSIFICATIONS Certain amounts for 2000 and 1999 have been reclassified to conform to the presentation adopted for 2001. 2001 ANNUAL REPORT 55 FIVE-YEAR FINANCIAL SUMMARY (millions of United States dollars, except per share amounts)
YEAR ENDED DECEMBER 31 --------------------------------------------------- 2001 2000 1999 1998 1997 ------- ------- ------- ------- ------- STATEMENTS OF EARNINGS (LOSS) Revenues Net oil and gas revenue $ 254 $ 345 $ 204 $ 81 $ 113 Other 4 4 2 5 3 ------- ------- ------- ------- ------- $ 258 $ 349 $ 206 $ 86 $ 116 ------- ------- ------- ------- ------- Earnings (loss) $ 32 $ 84 $ 33 $ (30) $ 8 ------- ------- ------- ------- ------- Earnings (loss) per common share $ 0.36 $ 0.96 $ 0.37 $ (0.34) 0.11 ------- ------- ------- ------- ------- Dividends declared per common share $ -- $ -- -- -- 0.88 ======= ======= ======= ======= ======= STATEMENTS OF CASH FLOWS Operating activities Cash generated from operations $ 126 $ 271 $ 137 $ 44 $ 74 Other operating activities, net 15 19 (4) 16 (1) ------- ------- ------- ------- ------- 141 290 133 60 73 Investing activities (15) (107) (174) (194) (363) Financing activities (142) (103) 2 93 387 ------- ------- ------- ------- ------- Increase (decrease) in cash $ (16) $ 80 $ (39) $ (41) 97 ======= ======= ======= ======= ======= Cash generated from operations per common share $ 1.43 $ 3.08 $ 1.56 $ 0.51 $ 0.96 ======= ======= ======= ======= =======
DECEMBER 31 --------------------------------------------------- 2001 2000 1999 1998 1997 ------- ------- ------- ------- ------- STATEMENTS OF FINANCIAL POSITION Total assets $ 948 $ 1,060 $ 975 $ 932 $ 859 Current liabilities (81) (112) (112) (92) (57) ------- ------- ------- ------- ------- Capital employed 867 948 863 840 802 Long-term debt -- 111 206 228 150 Future income taxes 255 257 161 149 158 ------- ------- ------- ------- ------- Shareholders' equity $ 612 $ 580 $ 496 $ 463 $ 494 ======= ======= ======= ======= ======= NET CASH (DEBT) POSITION Cash and short-term investments $ 91 $ 107 $ 27 $ 66 $ 107 Cash restricted in use 1 97 76 3 -- Less: Long-term debt (including current portion) -- (142) (245) (243) (150) ------- ------- ------- ------- ------- $ 92 $ 62 $ (142) $ (174) $ (43) ======= ======= ======= ======= =======
2001 ANNUAL REPORT 59 QUARTERLY SUMMARIES (unaudited)
2001 2000 --------------------------------- --------------------------------- 1 2 3 4 1 2 3 4 ------ ------ ------ ------ ------ ------ ------ ------ FINANCIAL (millions of United States dollars) Gross oil and gas revenue 80 86 82 60 95 103 113 110 Total revenue 65 71 68 53 80 84 92 93 Earnings (Loss) 9 18 9 (4) 20 20 17 27 per common share (dollars) 0.10 0.21 0.10 (0.04) 0.23 0.22 0.20 0.31 Cash generated from operations 37 38 34 17 63 66 76 66 per common share (dollars) 0.42 0.44 0.38 0.20 0.71 0.75 0.86 0.75 EBITDAX(1) 56 60 55 38 70 74 82 81 ------ ------ ------ ------ ------ ------ ------ ------ OPERATING Volumes sold (gross) Onshore gas (mmcf/d) 144 134 133 149 171 162 165 167 Barrels of oil equivalent(mboe/d)(2) 24.0 22.3 22.1 24.8 28.5 27.0 27.5 27.8 Onshore crude oil and condensate (mb/d) 13.7 12.9 13.6 13.2 14.5 14.5 14.3 14.9 Offshore oil and gas Natural gas (mmcf/d) -- 9 6 9 -- -- -- -- Crude oil and condensate (mb/d) 0.2 2.6 4.9 2.9 4.1 5.8 3.8 3.6 Barrels of oil equivalent (mboe/d)(2) 0.2 4.1 6.0 4.4 4.1 5.8 3.8 3.6 Total (mboe/d)(2) 37.9 39.3 41.7 42.4 47.1 47.3 45.6 46.3 Gross average prices Onshore gas ($/mcf) 3.12 3.64 3.12 2.15 3.28 3.73 4.02 3.98 Oil equivalent ($/boe)(2) 18.71 21.85 18.73 12.89 19.66 22.35 24.13 23.90 Onshore oil ($/bbl) 24.41 27.04 24.23 17.81 25.80 27.15 30.76 29.00 Offshore oil and gas Natural gas ($/mcf) -- 4.35 4.81 3.72 -- -- -- -- Crude oil and condensate ($/bbl) 26.31 27.09 24.22 22.84 25.74 26.72 35.72 27.29 Oil equivalent($/boe)(2) 26.31 26.74 25.05 22.65 25.74 26.72 35.72 27.29 Combined ($/boe)(2) 21.30 24.05 21.43 15.44 22.09 23.95 27.00 25.80 WTI ($/bbl) 28.73 27.96 26.49 20.43 28.73 28.63 31.58 31.86 Operating expense ($/boe)(2) Onshore gas 0.60 0.93 0.95 1.24 0.97 1.00 0.76 1.02 Onshore oil 3.16 3.93 2.89 3.69 2.85 2.47 3.24 2.67 Offshore oil and gas 5.18 4.81 6.17 4.96 3.95 4.76 6.10 8.05 Total 1.87 2.14 2.33 2.39 1.81 1.91 1.99 2.10 ------ ------ ------ ------ ------ ------ ------ ------ MARKET VALUE PER SHARE (DOLLARS) New York Stock Exchange high 10.15 11.50 11.89 9.10 9 7/16 9 3/8 12 3/4 12 1/2 low 8.37 7.48 8.69 7.89 6 15/16 6 9/16 7 3/8 8 1/8 close 8.88 10.16 8.70 9.00 7 15/16 8 10 7/8 9 5/16 ------ ------ ------ ------ ------- ------ ------- -------
(1) EBITDAX: earnings before interest, taxes, depletion, depreciation and amortization, exploration expense and other non-cash charges (2) Natural gas converted at 6:1 2001 ANNUAL REPORT 57