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