Item 1.
ITEM 1. BUSINESS
Gulf Canada Resources Limited ("Gulf Canada" or the "Company") is a Company organized under the Canada Business Corporation Act ("CBCA"). Gulf Canada is one of Canada's largest independent producers of oil and natural gas, with operations in Western Canada, where the Company has over 80
years of experience in conventional oil and gas operations, and internationally with operations in Indonesia (through Gulf Indonesia Resources Limited ("GRL") of which Gulf Canada owns 72 per cent), the North Sea and Australia. Gulf Canada's head office is located at 401-9th Avenue S.W., Calgary, Alberta, Canada T2P 2H7.
In 1998, the Company completed the following significant transactions:
The sale of 50% of certain midstream assets to KeySpan Energy Development Corporation for $290 million.
The sale of $0.9 billion of assets of which over 60 per cent related to United Kingdom North Sea assets. Sales included proved reserves of 68 million gross barrels (63 million barrels net) of liquids and 294 gross bcf (253 bcf net) of natural gas. Proceeds were used to repay indebtedness and to fund capital expenditures.
The completion of the Gulf Indonesia Resources Limited operated Corridor Gas Project in Indonesia. The Corridor Gas Project commenced operations in October, 1998 and accounted for approximately 79 mmcf/d of sales gas net to GRL (76 mmcf/d after royalty) in the fourth quarter. Current production is 160 mmcf/d net to GRL.
After asset sales, Gulf Canada's estimated net proved oil and natural gas reserves excluding Syncrude oil decreased 10.4% per cent from 662 mmboe on December 31, 1997 to 593 mmboe on December 31, 1998, and average daily net production was virtually flat at 160 MBOE/d (natural gas converted to boes at 6:1) in 1997 and 1998.
In early 1999, the Company finalized an agreement with Ensyn Group, Inc. whereby, the Company will fund a Cdn$20 million bitumen and heavy oil upgrading test program. In connection with the transaction, the Company acquired a 28.5 per cent ownership interest in an Ensyn partnership that holds certain marketing and royalty rights associated with the technology.
Also, the Company entered into an agreement with Mobil Canada related to its 5.4 million-acre land holding near the French islands of St. Pierre and Miquelon. Under the agreement, the Company's share of costs for additional seismic and an initial exploration well will be paid for by Mobil Canada.
GENERAL.
Gulf Canada was founded in 1906, and operated as a fully integrated oil company until 1986 when the Company sold its refining and marketing assets. In 1988, the Company acquired Asamera, Inc., a predecessor to Gulf Indonesia Resources Limited, which has operations in Indonesia. During 1997, the Company further expanded its international operations primarily by acquiring Clyde Petroleum Plc, which had operations in the North Sea, Indonesia and Australia. As well, the Company expanded its Western Canadian position with the acquisition of Stampeder Exploration Limited in 1997. Gulf Canada is also a major producer of heavy oil and produces Syncrude Sweet Blend ("SSB") through its interest in Syncrude. SSB is a high quality, low sulphur, light crude oil.
The following table summarizes Gulf Canada's sales of production and estimated proved reserves net of royalties as of and for the year ended December 31, 1998:
[FN] (1) Excludes SSB production and reserves from oil sands.
(2) The reserves attributable to Indonesia are owned by GRL, a 72 per cent owned subsidiary of Gulf Canada. The amount of reserves represent 100 per cent of the estimated net proved reserves owned by GRL.
(3) Boe converts natural gas at an oil equivalent of 6 mcf: 1 barrel.
NORTH AMERICA
North American operations form the largest component of Gulf Canada's diversified portfolio. The vision for North America is to grow from a solid foundation of exploitation opportunities and expand through the development of natural gas from west central Alberta, up the western border and eventually to the MacKenzie Delta at Parsons Lake in the North.
During the year, property sales and acquisitions were used to balance the portfolio and have resulted in operations in four core regions: Southeast Alberta, Central Alberta, Red Earth and an emerging natural gas trend that stretches from west central Alberta to the Steen region in northern Alberta.
In addition to these core regions, Gulf Canada operates heavy oil interests in Saskatchewan and holds an interest in the Syncrude Joint Venture in northern Alberta.
In 1998, Gulf Canada entered into key partnerships that are expected to enable the Company to accelerate value growth in areas where it has strategic advantages. An alliance with Northrock Resources, a midsize producer, in west central Alberta provides a large, dominant land base in a competitive and prospective natural gas area. The sale of a 50 per cent interest in Gulf Canada's midstream natural gas assets to KeySpan Energy Corporation, a growth-oriented, U.S.-based utility, served to partially monetize assets undervalued in the market and bring greater focus to the midstream business as a profit center. Gulf Canada also established a partnership with Ensyn Energy Corporation to develop new upgrading technology for application to heavy oil.
Gulf Canada has 30 key properties in Western Canada that are predominantly Gulf Canada-operated. These properties as well as Gulf Canada's surrounding land positions encompass 4.1 million net acres of which 3.0 million acres are undeveloped. Average sales (before royalties) from Western Canada during 1998 were 52,400 barrels per day (b/d) of conventional light oil and natural gas liquids, 17,000 b/d heavy oil, 18,900 b/d from Syncrude and 369 million cubic feet per day (mmcf/d) of natural gas.
CONVENTIONAL LIGHT OIL AND NATURAL GAS.
Western Canada light oil and natural gas reserve additions for the year were 47 million (before royalties) barrels of oil equivalent (boe), replacing more than 100 per cent of production, two-thirds of which was natural gas.
Property sales in Western Canada in 1998 amounted to $136 million and were primarily completed in the second half of the year. During 1999, additional Western Canada asset sale transactions with associated production of approximately 7,800 boe/d (before royalties) are expected to close with proceeds in excess of $130 million.
Production (before royalties) from the four main regions in 1999 is expected to be approximately 85,000 boe/d after property sales, with approximately 40 per cent from Central Alberta, 20 per cent from Southeast Alberta, ten per cent from Red Earth and 30 per cent from the emerging natural gas corridor. Gulf Canada's actions in 1998 have increased its exposure to natural gas, which is anticipated to account for approximately 50 per cent of 1999 production. In each of these four regions, Gulf Canada maintains high working interests in large properties with substantial operating control.
CENTRAL ALBERTA. The Central Alberta region has historically been a core operating area for Gulf Canada. It is characterized by large, long-life, light oil reservoirs, substantial proven reserves and low-risk development opportunities. Gulf Canada's knowledge of the area and applicable technologies, such as infill and horizontal drilling, as well as enhanced oil recovery techniques, enable sustained exploitation, low cost operations and significant free cash flow.
During the year, Gulf Canada implemented a new technology, referred to as "geo-cellular", that creates a unified model from seismic, well log, production and reservoir data. Application of this technology to the Company's Central Alberta operations, as well as in other areas, will improve the process of identifying new, low risk exploitation prospects and create more efficient operating plans.
SOUTHEAST ALBERTA. Key properties in this area, Ghost Pine, Connorsville and Richdale, are characterized by both shallow and multi-zone natural gas plays. Gulf Canada expanded its position in this area in 1998 through an active drilling program and an alliance with a small, natural gas-oriented company. The alliance has control of production and processing facilities in the area and maintains an active exploitation program.
RED EARTH. Gulf Canada has built a dominant 700,000 net acre land position in the Red Earth area located in northern Alberta. The position was expanded through a major land acquisition and an early 1999 transaction in which the Company swapped shallow natural gas rights for the deeper oil and natural gas rights. Gulf Canada has significantly grown the reserve base, increased production and reduced costs through well-optimization plans, waterflood and recompletion work. Key fields in this area include House Creek, Panny and Senex fields with an average working interest of 84 per cent.
NATURAL GAS CORRIDOR. Gulf Canada has sizable natural gas holdings from west central Alberta up to the Steen area in the north that are expected to benefit from favourable changes in natural gas economics. The Company's plans for growth are focused on development in the Steen area, exploration in the Musreau Lake and Northwest Arch areas and through its partnership in west central Alberta.
In west central Alberta, 850,000 acres are held in an alliance with a mid-sized Canadian producer. This sizeable acreage position combined with an extensive seismic data base provides a base for rapid growth in this area.
The Company realized early success in the Musreau Lake and Northwest Arch areas, two new exploration areas for Gulf Canada. In the Musreau Lake area, an emerging natural gas region along the western border of Alberta, Gulf Canada holds an average 40 per cent working interest in 125,000 acres.
In the Steen area, in northwest Alberta, the Company added over 70 bcf to reserves and has extended its land position in the region. Gulf Canada is constructing a gas plant that is expected to add up to 30 mmcf/d of production to come on stream by mid-1999.
Additionally, Gulf Canada controls major infrastructure in the area through its ownership in Gulf Midstream Services. Ultimately, the Company expects this natural gas exploration corridor to extend to the MacKenzie Delta area where Gulf Canada already has significant gas reserves.
HEAVY OIL
Heavy oil production is mainly from the Plains, Senlac and Coleville areas of southwest Saskatchewan. The Company holds 700,000 net undeveloped acres in these areas. Gulf Canada is actively seeking to combine its assets with an industry partner to effect operating cost savings and synergies in future exploitation and development projects for this large, long-term resource base.
During the year, investment in heavy oil was predominantly facilities oriented. Additionally, increased efficiencies reduced operating costs by 20 per cent. The strategy for improved performance in 1999 will include reducing operating costs, increasing production from four waterflood facilities, continuing consolidation of assets to form core areas and implementing oil upgrading technology. These actions, combined with improved differentials between light and heavy oil prices, are expected to provide better economics for heavy oil production going forward.
OTHER ASSETS
THERMAL. Gulf Canada operates steam-enhanced oil recovery projects at Surmont, Alberta and Kerrobert, Saskatchewan. At the larger Surmont project, potential recoverable reserves of crude oil may be as high as 5 to 7 billion barrels. Pilot technology tests the viability of recovering heavy oil and bitumen using steam injection and horizontal wells.
Operations at the Surmont pilot project met Gulf Canada's expectations by showing consistent performance during the year with volumes averaging approximately 600 b/d in the second half. In 1999, the Company will proceed with the required regulatory applications to construct a 25,000 b/d commercial in-situ thermal recovery facility at Surmont. Current plans anticipate start-up and commissioning of that project during the second half of 2003. Due to the potential size of the project, Gulf Canada plans to continue to seek an industry partner to pursue development.
UPGRADING TECHNOLOGY. New technology is the key to unlocking the long-term potential of Gulf Canada's vast heavy oil and oil sands resources. Gulf Canada is working with its partner, Ensyn Energy Corporation, to develop a new upgrading technology for application to heavy oil and bitumen. Positive results from bench-scale tests conducted during 1998 indicate that this efficient upgrading process could be applied to larger volumes. In 1999, the Company is proceeding with the engineering and design of a $19 million field demonstration project expected to start-up by late 2000. In addition, subsequent to year-end Gulf Canada acquired a 28.5 per cent interest in a separate partnership formed with this company. The partnership will market the proprietary upgrading technology and own the associated royalty rights.
DEVELOPMENT - NORTHERN CANADA. Gulf Canada has 2.6 trillion (before royalties) cubic feet of probable natural gas reserves in the Beaufort Sea and MacKenzie Delta areas of Northern Canada. One-half of this gas, discovered by Gulf Canada more than 20 years ago, is in the Parson's Lake field located in the MacKenzie Delta. This field was delineated with 17 wells, which will allow a high percentage of these reserves to be reclassified as proved upon the start-up of a development project.
Gulf Canada is reviewing potential development of its Northern Canada prospects in light of changes in the Canadian natural gas industry that are expected to improve the economics of natural gas production. Substantial new pipeline export capacity was added in western Canada late in the year, with plans for additional capacity by the year 2000. Due to a trend in Canada towards increased production relative to a field's reserves, future supply growth will be dependent upon development of new reserves rather than acceleration of production. These factors, combined with new gas infrastructure in Alberta, more efficient development techniques and lower cost pipeline construction costs, make the concept of developing Gulf Canada's large, northern gas resources more attractive.
EXPLORATION - EAST COAST. Gulf Canada holds a sizable land position in a prospective area off the east coast of Canada between Hibernia and Sable Island. During the year, Gulf Canada completed a 7,300 kilometre, two-dimensional seismic program on its 5.4 million acre block.
Subsequent to year-end, Gulf Canada signed a letter of intent to enter into a joint operating agreement with Mobil Canada covering a combined 8.6 million acres. Subject to regulatory approval and execution of a joint operating agreement, Mobil will fund the initial exploration program on Gulf Canada's French permit acreage, including acquisition of additional seismic and drilling the initial well. Mobil will be assigned a 65 per cent interest in Gulf Canada's French permit and a 20 per cent interest in Gulf Canada's Canadian permits with an option to earn an additional 45 per cent in certain licenses after conducting additional exploration work. Gulf Canada will be assigned a ten per cent interest in Mobil's Canadian permits and have the option to earn an additional ten per cent interest in certain licenses after conducting additional exploration work.
SYNCRUDE
Gulf Canada holds a 9.03 per cent interest in the Syncrude Project Joint Venture. The Syncrude Project, located near Fort McMurray, Alberta, is the largest producer of crude oil from oil sands in the world. Bitumen is mined and oil is extracted and upgraded at the Project site into a high-quality, low-sulphur, light crude oil known as Syncrude Sweet Blend ("SSB"). The Syncrude Project is one of the largest mining operations in the world, with gross proved plus probable reserves of over 5 billion barrels and an ultimate predicted reserve life of 90 years at current production levels.
The Syncrude Project produced an average of 210,000 b/d of SSB in 1998, 18,900 b/d net to Gulf Canada's interest. Additionally, the Project celebrated the production of its one-billionth barrel in April. Two major capital expansion projects, approved in 1996 and 1998 totaling $1.4 billion, $126 million net to Gulf Canada, are expected to increase total daily production to 258,000 b/d by the year 2000, 23,000 b/d net to Gulf Canada. This expansion was approximately 45 per cent complete by year-end. Additional proposed capital spending by the joint venture over the next eight years of $4.2 billion, $380 million net to Gulf Canada, is expected to increase total daily production to 425,000 b/d or 38,000 b/d net to Gulf Canada.
Gulf Canada continues to provide administrative services to the Athabasca Oil Sands Trust, a publicly traded entity (AOS.un, Toronto) created in 1995 that holds an 11.74 per cent interest in the Syncrude Project. Gulf Canada also markets the Trust's share of Syncrude production through its ownership interest in Tidal Energy Marketing Inc.
GULF MIDSTREAM SERVICES
In mid-1998, Gulf Canada established the Gulf Midstream Services (GMS) division that focuses on the natural gas "midstream" business in western Canada. GMS manages all midstream functions from wellhead to customer, including gathering, processing, fractionation, storage, transportation and marketing of natural gas and natural gas liquids.
In December, KeySpan Energy Development Corporation, a wholly owned subsidiary of KeySpan Energy Corporation, finalized its purchase of 50 per cent of Gulf Midstream Services. Gulf Canada's partnership with KeySpan is a significant combination that will focus on aggressive growth in the midstream business.
To form GMS, substantially all of Gulf Canada's midstream facilities were combined with its natural gas and gas products marketing business. GMS holds interests in 14 raw gas processing plants and associated gathering systems, representing a network of facilities that is uniquely positioned to serve areas of growing exploration, development and production activity. GMS also controls strategic fractionation, storage and transportation facilities near Edmonton, Alberta, a major North American natural gas liquids hub. GMS employs an experienced team of marketing professionals that provides integrated marketing and risk management capabilities for Gulf Canada and other producers of natural gas, natural gas liquids, sulphur and other gas products.
INDONESIA
Gulf Indonesia Resources Limited (GRL), a 72 per cent owned subsidiary, completed another successful year and its first full year as a public company. GRL continued increasing its asset base in Indonesia by booking gross proved reserve additions of 52 million (before royalties) barrels of oil equivalent in 1998. Proved reserves have increased nearly 700 per cent since 1995. Finding and development costs over the same three-year period averaged US$2.63 per boe.
Completion of the Corridor Gas Project on time and on budget was the outstanding achievement of 1998. The Corridor Project created a completely new market for Indonesian natural gas, using it as a substitute for crude oil to fuel the large steamflood project operated by a third party at Duri, some 340 miles to the north. The initiation of gas deliveries from the Corridor Project to Duri in October was the culmination of a project that began with the discovery by Gulf Canada of significant natural gas reserves in Sumatra in the early 1990s.
Today, the Corridor Gas Project is fully operational and has more than doubled GRL's sales volumes. The Corridor Project is, however, only the first of many gas development opportunities. The pipeline and gas plant built at Corridor will support expansion projects in Sumatra. The Corridor Project is a model for developing more of GRL's abundant natural gas reserves for expansion to markets in Indonesia and Singapore.
Progress on other natural gas projects included:
- - Approval of a Plan of Development in October, 1998 for a 45 mmcf/d (net) expansion of the Corridor Gas Plant;
- - Execution of a Memorandum of Understanding in September, 1998 for the sale of gas from the Corridor and South Jambi B blocks to Singapore;
- - Negotiations to finalize agreements to supply 50 to 60 mmcf/d (net) of gas to international LNG markets and domestic fertilizer markets from the GRL-operated block A in northern Sumatra; and
- - Signing of a gas supply agreement in January, 1999 covering the sale of 20 mmcf/d (net) of gas from the GRL-operated Kakap block in the West Natuna Sea for power generation and petrochemical projects in Singapore.
To provide the natural gas reserves necessary to support these projects, GRL focuses much of its capital on natural gas exploration and delineation drilling.
NETHERLANDS
Operations in the Netherlands during the year focused on increasing Gulf Canada's working interests in existing operated assets, adding new operated assets and evaluating exploitation and exploration opportunities. These efforts resulted in production growth, better concentration in identified core areas and exploration success. Sales volumes before royalties from the Netherlands averaged 63 mmcf/d natural gas
and 2,600 b/d of oil from both the southern North Sea and onshore fields. Oil production was added in the second quarter with the acquisition of a 100 per cent owned and operated position in blocks K18b and L16a.
Gulf Canada operates 19 shallow water offshore and 4 onshore licenses that cover approximately 1.4 million acres. The Company owns strategic infrastructure and substantial three-dimensional seismic coverage in focus areas that include the K, L, P and Q offshore blocks and the onshore Waalwijk concession.
During the year, two of three Gulf Canada-operated exploration/appraisal wells were successful, with one immediately tied in to existing infrastructure. Gulf Canada intends to drill up to five exploration wells per year with a target to double production over four to five years. The combination of good regional natural gas prices, control of infrastructure and consolidated license positions provides strong fundamentals for growth and operating efficiencies going forward. Gulf Canada will seek growth through further exploitation of existing producing assets and exploring near existing infrastructure, including expansion into blocks adjacent to current operations. At the end of 1998, Gulf Canada expanded its position into the UK Sector of the southern North Sea through the acquisition of a 75 per cent working interest and operatorship of adjoining block 53/8.
AUSTRALIA
Australia represents the smallest of Gulf Canada's core operating areas, yet provides significant potential for growth. In 1998, the Company's focus in Australia shifted from onshore natural gas production from fields where Gulf Canada does not operate to offshore oil production in the Timor Sea. Gulf Canada established a base of operation in the Timor Sea with the mid-year acquisition of majority interests in the Jabiru and Challis fields.
Sales volumes before royalties from Australia averaged approximately 9,300 boe/d for the year. Non-core assets in South West Queensland were sold early in the year, followed by the acquisition of the Jabiru and Challis production and assets, including two floating production storage and offloading vessels (FPSOs). The acquisition added offshore oil production, and greatly extended Gulf Canada's control of infrastructure and undeveloped land in this area.
The Timor Sea has potential to be the key growth area within Australia. During the year, Gulf Canada extended its position here from five permits and approximately 440,000 net acres to ten permits and 1.2 million net acres. Gulf Canada now controls the largest position in the basin and in 1999 will acquire 3,800 kilometres of two-dimensional seismic data over the area. This data will be interpreted in 1999 in preparation for an extensive, three-year, multi-well exploration program scheduled to start in 2000.
The strategy for growth is to use the drill bit and to "quick connect" to Gulf Canada operated infrastructure. The Company is also pursuing the development of smaller, previously discovered fields in the Timor region to utilize spare processing capacity at its two FPSOs. Since taking over operations at Jabiru and Challis late in the year, Gulf Canada has identified opportunities in both these fields for exploitation and significant operating cost reductions. The combination of exploration, exploitation and cost reductions will set the foundation for continued growth in this area.
BUSINESS ENVIRONMENT
COMPETITIVE AND INDUSTRY CONDITIONS. There is strong competition relating to all aspects of the oil and gas industry, and in particular in the exploration and development of new oil and natural gas reserves.
The oil and natural gas business is subject to extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects. Gulf Canada's production is subject to deliverability uncertainties related to the proximity of its reserves to pipeline and processing facilities, and shipping restrictions on pipelines that deliver oil and natural gas to commercial markets. Future production from frontier lands will depend upon, among other factors, satisfactory fiscal and regulatory terms, oil prices, the establishment of sufficient reserves to justify the substantial capital costs of production facilities and the development of transportation systems to bring such reserves to market.
The business environment also exposes Gulf Canada to a number of risks, including those associated with fluctuations in oil prices and exchange rates, uncertainties in estimates of reserves, risks arising from active oil and gas exploration and development activities, and the potential for environmental
clean-up obligations and liabilities arising from its current or past operations. The Company endeavors to carry on its business in such a manner as to minimize such risks.
ENVIRONMENTAL PROTECTION. The operations of Gulf Canada are, and will continue to be, affected in varying degrees by laws and regulations regarding the protection of the environment. It is impossible to predict the full impact of these laws and regulations on Gulf Canada's operations. However, it is not anticipated that Gulf Canada's competitive position will be adversely affected by current or future environmental laws and regulations governing its current oil and gas operations. Since 1990, Gulf Canada has implemented a program of regular environmental audits to review operating practices and procedures at major plants and facilities in western Canada and to provide for compliance with regulatory requirements. In addition, acquisitions and divestitures are subject to environmental audits. Gulf Canada's accounting policy is to provide for future site restoration costs, including dismantling plants and abandoning properties, using the unit of production method or, where appropriate, the estimated remaining useful lives of the related assets. Gulf Canada has accrued $183 million for such future costs at December 31, 1998. Total anticipated future costs, given Gulf Canada's current inventory of wells and facilities, including those relating to Syncrude, is estimated to be approximately $602 million over the next 20 years. Gulf Canada also has environmental obligations related to certain mineral operations for which it has recorded a provision. In addition to its environmental responsibility for current operations, Gulf Canada is or may be responsible for future environmental costs related to certain past operations, mainly downstream in nature.
FOREIGN OPERATIONS. Some of Gulf Canada's reserves and operations outside North America are located in regions that may be considered politically and economically unstable. These reserves and the related operations are subject to certain risks, including increases in taxes and royalties, the establishment of production limits, export restrictions, the involuntary renegotiation of contracts, the nationalization of assets, other risks relating to changes in local government regimes and policies and resulting changes in business customs and practices, payment delays, currency exchange restrictions and losses and impairment of operations by actions of insurgent groups. Gulf Canada, like other international oil companies, attempts to conduct its business and financial affairs in such a manner as to protect against such political and economic risks. Gulf Canada reduces risk associated with foreign projects through farmouts, phased development programs and project financing. There can be no assurance, however, that Gulf Canada will be successful in protecting itself from the risks presented by foreign operations.
RISK FACTORS
VOLATILITY OF OIL AND NATURAL GAS PRICES
Gulf Canada's results of operations and financial condition are dependent on the prices received for its oil and natural gas production. The Company's ability to arrange financing and acquire the capital necessary to explore and develop its properties is also dependent on the price of oil and natural gas. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil producing regions, which are beyond the control of Gulf Canada. Any decline in oil or natural gas prices could have a material adverse effect on Gulf Canada's operations, financial condition, proved reserves and the level of expenditures for the development of its oil and natural gas reserves. No assurance can be given that oil and natural gas prices will be at levels which will generate profits for Gulf Canada.
In addition, Gulf Canada regularly assesses the carrying value of its assets in accordance with Canadian GAAP and U.S. GAAP under the successful efforts method. See the Consolidated Financial Statements included herein. If oil and natural gas prices become depressed or decline, the carrying value of Gulf Canada's assets could be subject to downward revision.
During 1998 and the first quarter of 1999, oil prices have been low compared to prices received in the last five years. Continued low oil prices could have a material adverse affect on Gulf Canada.
NEED TO REPLACE RESERVES
Gulf Canada's future oil and natural gas reserves and production, and therefore its cash flows, are highly dependent upon Gulf Canada's success in exploiting its current reserve base and acquiring or discovering additional reserves. Without reserve additions through exploration, acquisition or development activities, Gulf Canada's reserves and production will decline over time as reserves are produced. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flows from operations are insufficient and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital investments to maintain and expand its
oil and natural gas reserves will be impaired. In addition, there can be no assurance that Gulf Canada will be able to find and develop or acquire additional reserves to replace production at acceptable costs.
LEVERAGE
Gulf Canada's debt instruments impose restrictions on the operations and activities of Gulf Canada. Generally, the most significant restrictions relate to debt incurrence, investments, capital expenditures, asset sales and the use of proceeds therefrom and cash distributions by Gulf Canada. Additionally Gulf Canada is required to comply with certain financial covenants, including the maintenance of a debt to total capitalization ratio. The ability of Gulf Canada to comply with the foregoing restrictions and covenants will be dependent upon its future performance and various other factors, including factors beyond Gulf Canada's control. A failure to comply with these restrictions or covenants could result in an event of default under the applicable instrument, which could cause acceleration of the debt under such instrument and other instruments that contain cross-default provisions.
OPERATING HAZARDS AND OTHER UNCERTAINTIES
Acquiring, developing and exploring for oil and natural gas involves many risks. These risks include encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, craterings, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires and spills. Although Gulf Canada maintains insurance in accordance with customary industry practice, Gulf Canada is not fully insured against all of these risks. Losses resulting from the occurrence of these risks could have a material adverse impact on Gulf Canada. Gulf Canada, like other international oil companies, attempts to conduct its business and financial affairs so as to protect against political and economic risks applicable to operations in the various countries where it operates, but there can be no assurance that Gulf Canada will be successful in so protecting itself.
Gulf Canada is also subject to deliverability uncertainties related to the proximity of its reserves to pipeline and processing facilities and the inability to secure space on pipelines that deliver oil and natural gas to commercial markets.
UNCERTAINTY OF RESERVE ESTIMATES
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of Gulf Canada. The reserve data set forth herein represent estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Gulf Canada's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material.
Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves.
In accordance with applicable requirements of the U.S. Securities and Exchange Commission ("SEC"), the estimated discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.
The securities disclosure legislation and policies of Canada, as interpreted by the securities commissions in Canada, permit the use of escalated prices and costs in calculating reserve quantities, which is not permitted for disclosure of reserve quantities in financial statements filed with the SEC.
Reserves set forth in financial statements filed with the SEC must be based on period end prices and costs, without escalation, except where required by contract. Additionally, Canadian legislation and policies permit the disclosure of "probable" reserves and synthetic crude oil reserves from oil sands, such as SSB, which may not be disclosed in financial statements filed with the SEC. Probable reserves are generally believed to be less likely to be recovered than proved reserves.
The reserve estimates included in this Annual Report could be materially different from the quantities and values ultimately realized.
ENVIRONMENTAL RISKS
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and Canadian and U.S. federal, provincial, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with Gulf Canada's past and current operations. The legislation also requires that refineries, service stations, wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. In addition, certain types of operations require the submission and approval of environmental impact assessments. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Gulf Canada, either directly or through subsidiaries, owned numerous refineries, service stations and related operations in Canada and the United States prior to 1986, and continues to hold former sites, which have given rise to some claims and could give rise to additional claims in the future under laws that provide that responsible parties can include present and prior owners, operators and others, including claims for investigation, clean-up and restoration costs and damages for personal injury. Although Gulf Canada believes that it is currently in substantial compliance with all existing material environmental regulations, there can be no assurance that future environmental costs will not have a material adverse effect on Gulf Canada's financial condition or results of operations.
COMPETITION
There is strong competition relating to all aspects of the oil and gas industry, in particular the exploration for and development of new oil and natural gas reserves. Gulf Canada actively competes with a substantial number of other oil and gas companies for reserve acquisitions, exploration leases, licenses and concessions and skilled industry personnel. Gulf Canada's competitors include major integrated oil and gas companies and numerous other independent oil and gas companies and individual producers and operators, many of which have significantly greater financial resources than Gulf Canada.
GOVERNMENTAL REGULATION
The petroleum industry is particularly subject to regulation and intervention by governments in such matters as the awarding of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights, as well as with respect to prices, taxes, royalties and the exportation of oil and natural gas. Such regulation may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas and crude oil, increase Gulf Canada's costs and have a material adverse impact on Gulf Canada.
EXCHANGE RATE FLUCTUATIONS
Gulf Canada is exposed to foreign exchange risks since the majority of its revenue is received in or by reference to U.S. dollar denominated prices while the majority of its expenditures are in Canadian dollars. The exchange rate between Canadian dollars and U.S. dollars has varied substantially in the last five years. See "Currency and Exchange Rates."
ITEM 2.
ITEM 2. PROPERTIES
RESERVES
The following table describes the Company's estimated net proved reserves as of the end of each of the last three years:
[FN] * Excluding Syncrude oil from oilsands.
** Natural gas converted at 6:1.
The Company's internal staff of reservoir engineers prepared the estimates of proved reserves of the Company. Reserves were estimated using oil and gas prices and production and development costs in effect on December 31 of each year, without escalation, and were otherwise prepared in accordance with the Commission regulations regarding disclosure of oil and gas reserve information.
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company and the reservoir engineers. The reserve data set forth in this document represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates by different engineers often vary, sometimes materially. In addition, physical factors, such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors, such as an increase or decrease in product prices that renders production of such reserves more or less economic, may justify revision of such estimates. Accordingly, reserve estimates are different from the quantities of oil and gas that are ultimately recovered. See "Risk Factors -- Estimates of Oil and Gas Reserves."
OIL AND GAS DRILLING ACTIVITIES
During the five years ended December 31, 1998, approximately 92 per cent of the Company's net wells drilled were in Western Canada. In 1998, Gulf Canada had drilling success rates of 60 per cent for gross (61 per cent net) exploration wells and 92 per cent for gross (94 per cent net) development wells.
The following table sets forth the gross and net number of productive and dry exploratory and development oil and natural gas wells drilled from 1996 through 1998 for the Company as a whole. "Gross" means all wells in which Gulf Canada has an interest and "net" means gross wells after deducting interests of others.
PRODUCTIVE WELLS
The following table summarizes Gulf Canada's oil and natural gas wells that are capable of production as at December 31, 1998. "Gross" means all wells in which Gulf Canada has a working interest and "net" means gross wells after deducting working interests of others.
- ----------
ACREAGE
The following table summarizes Gulf Canada's conventional oil and natural gas land holdings as at December 31, 1998.
- ---------- [FN] (1) "Gross acres" means all acreage in which Gulf Canada has an interest and "net acres" means gross acres after deducting interests of others. "Developed acreage" refers to the acreage to which the Company has assigned proved reserves. "Undeveloped acreage" refers to the acreage to which the Company has not assigned any proved reserves. The table does not include approximately 325,000 gross acres in which royalty interests are held in Indonesia.
TITLE TO PROPERTIES
Oil and gas rights in Western Canada are held primarily by the provinces but may also be privately owned. On provincially owned lands, the two main types of rights agreements are licenses and leases. Licenses define the boundaries of an exploration area and the work required to maintain good standing. Satisfying the license requirements entitles the holder to convert all or a portion of the license rights to lease form. Leases accommodate exploration, development and production activities. The lessee of a lease is generally responsible for paying all development and operating costs and is entitled to the production subject to a rental and royalty payable to the lessor. Leases are also granted by private owners of mineral rights for varying terms. Both provincial and private leases are generally maintained by production or productive capability.
Most of Gulf Canada's interests in frontier lands are held under significant discovery licenses pursuant to the Petroleum Resources Act (Canada) ("CPRA"). In the Amauligak area of the Beaufort Sea, Gulf Canada's interest is held under a production license, subject to the CPRA.
Interests issued in the east coast offshore are adjacent to the Province of Newfoundland and are subject to the Canada-Newfoundland Atlantic Accord Implementation Act. The east coast offshore interests include a 100% Company interest in 5.4 million acres in the St. Pierre Bank and Banquereau areas that are presently under development moratorium. There is continuing negotiation over provincial jurisdiction between Newfoundland and Nova Scotia and the lands will remain in moratorium until this matter is settled.
The Company's land interests in Indonesia are owned by GRL. These interests are held subject to production sharing contracts, a technical assistance contract and an enhanced oil recovery contract, under which the GRL and the other contracting companies are eligible to recover their capital and operated costs from production if a commercial discovery is made. Any balance of production is divided in varying shares between the government of the producing country, or its state-owned oil Company, and the contracting companies.
Interests in the U.K. North Sea are held under licenses issued by the United Kingdom Department of Trade and Industry. The Netherlands North Sea licenses are issued by the Netherlands government.
In Australia, the Company's land interests (both onshore and offshore) consist of interests in production licenses, exploration permits and retention leases issued under the Petroleum Submerged Lands Act (Commonwealth or State, as appropriate). Interests held in the Zone of Cooperation, which is administered by the Joint Authority established by the Australian and Indonesian governments, consist of production sharing contracts approved by the Joint Authority. The relationships amongst the parties are governed through joint venture operating agreements, which are permit specific. Gulf Canada holds its interest in land through either a trust relationship with the Operator or by being a registered title holder on the relevant permit.
GAS PLANTS AND PIPELINES
Gulf Canada's business includes the acquisition, ownership and operation of assets that generate cash flow and are non-depleting, such as gas processing plants, pipelines and gathering systems. In mid-1998, Gulf Canada formed the Gulf Midstream Services (GMS) division to manage the Company's midstream assets. In December, 1998, Gulf Canada sold 50 per cent of its interest in GMS to KeySpan Energy Corporation. GMS holds interests in 14 raw gas processing plants and associated gathering systems. Gulf Canada maintains its interest in several other non-operated gas plants.
OTHER FACILITIES AND OPERATIONS
COAL. Although Gulf Canada is not currently engaged in commercial production of coal, it continues to hold some coal properties. The Company's most significant coal property is Mount Klappan in British Columbia where drilling has confirmed a substantial anthracite deposit. Gulf Canada is pursuing the sale of the Mount Klappan coal property.
MARKETING
The marketing of crude oil, natural gas liquids and natural gas is an integral part of Gulf Canada's business.
CRUDE OIL. Gulf Canada currently markets its crude oil through an arrangement effective January 1, 1998, with Tidal Energy Marketing Inc. ("Tidal"). Tidal is an entity formed in 1997 to carry on crude oil marketing and of which Gulf Canada is a 50 per cent shareholder. Tidal markets crude oil as agent for Gulf Canada, the Province of Alberta, Athabasca Oil Sands Trust and Gulf Canada's share of the Syncrude Joint Venture. In 1998, Tidal marketed a total of 198,000 b/d of crude oil.
In Indonesia, GRL's crude oil production is sold to Pertamina, the Indonesian state owned oil company and directly to offshore markets. The price received for the crude oil sold to Pertimina is determined monthly by the Indonesian government based on a weighted average of benchmark world crude oil prices. Further, GRL receives crude oil in kind for the delivery of natural gas to the Duri enhanced oil recovery project in Sumatra. This oil is sold through a long-term contract with ITOCHU Petroleum Co. and sold to offshore markets.
Crude oil from Gulf Canada's Netherlands and Australia operations is sold into world markets.
NATURAL GAS LIQUIDS. In 1998, Gulf Canada marketed approximately 21,000 b/d of natural gas liquids in western Canada, approximately 53 per cent of which represents third party volumes. Natural gas liquids (primarily ethane, propane and butane) are extracted from natural gas processed at various field plants. In December, 1998, Gulf Canada agreed to sell all of its natural gas liquids production to GMS at market rates.
NATURAL GAS. Sales of natural gas averaged 476 mmcf/d in 1998, 369 mmcf/d of which was from western Canada. Approximately 35 per cent of Gulf Canada's western Canada natural gas sales in 1998 were pursuant to long-term contracts with Alberta gas purchasers (known as "aggregators") who resell the gas in both domestic and export markets. The remaining natural gas sales were direct sales to local distribution companies, industrial customers and marketing companies. In December, 1998, Gulf Canada entered into an arrangement with GMS for the marketing of all of its natural gas production at market rates.
In the Netherlands, natural gas is sold under long-term contracts based on pricing for petroleum products. In Australia, natural gas production comes from onshore wells where the production is marketed by the operator of the properties, primarily under long-term, fixed-price contracts.
SEGMENT INFORMATION. Reference is made to Note 22 entitled "Segment information" under the heading "Notes to Consolidated Financial Statements" of the Consolidated Financial Statements of the Company for the year ended December 31, 1998.
GENERAL
EMPLOYEES. As of December 31, 1998, Gulf Canada employed 886 regular employees. As of March 26, 1999, Gulf Canada employed approximately 761 regular employees.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Gulf Canada is 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. However, no such matter can be predicted with certainty.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S ORDINARY SHARES AND RELATED STOCKHOLDER MATTERS
The Ordinary Shares are traded on the New York Stock Exchange ("NYSE"), the Toronto Stock Exchange ("TSE") and the Montreal Exchange under the symbol GOU. There were approximately 10,211 shareholders of record of the Ordinary Shares as of March 2, 1999. The Company has not paid dividends on its Ordinary Shares, and does not contemplate the payment of such dividends in the foreseeable future. In addition, restrictions in indentures relating to the Company's outstanding senior subordinated debentures and its credit facilities with commercial lenders restrict the payment of dividends. The high and low prices of the Ordinary Shares during 1997 and 1998 are set forth below:
On March 26, 1999, the high and low prices of the Ordinary Shares on the NYSE were US$2.94 and US$2.88, respectively. The high and low prices for the Ordinary Shares on the same date on the TSE were Cdn$4.45 and Cdn$4.35, respectively.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following information was prepared in accordance with Canadian generally accepted accounting principles. For information regarding variances between accounting principles generally accepted in Canada and the United States as they apply to the Company, reference is made to Note 23 to the Consolidated Financial Statements, which information is incorporated herein by reference.
FIVE-YEAR FINANCIAL SUMMARY
- ---------- [FN] (1) 1997 includes payment of regular and special dividends on preference shares.
(2) Includes Series 1 preference shares of $428 million and Series 2 Preference shares of $149 million in each of 1994 through 1998.
(3) Certain of the financial data for years prior to 1998 have been reclassified to conform with the presentation adopted for 1998.
Proved Reserves
CONTINUATION OF CHART FROM PREVIOUS PAGE
[FN]
(1) Under Statement of Financial Accounting Standards No. 69 (SFAS 69), these additions are considered part of revisions of previous estimates.
(2) Excludes Syncrude oil from oil sands.
(3) The above estimated reserve quantities are based upon year-end economic conditions as required under SAFS 69. Using management's estimate of costs and prices net proved reserves as at December 31, 1998 for oil and natural gas liquids would be 194 million barrels and for natural gas would be 978 billion cubic feet.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS
FINANCIAL REVIEW
Gulf Canada Resources Limited generated cash from continuing operations of $371 million in 1998, down from $592 million in 1997 and $440 million in 1996. The Company realized a loss of $562 million in 1998 versus earnings of $204 million in 1997 and $37 million in 1996. Although sales volumes remained relatively flat, lower oil prices, one-time charges and non-cash amortization of foreign exchange losses significantly reduced 1998 cash generation and earnings. In 1997, the earnings increase was mainly attributable to the gain on the sale of shares in Gulf's Indonesian subsidiary.
During 1998, Gulf received $1.2 billion in gross proceeds from asset sales, which included $110 million of debt assumed by a purchaser and is before selling costs and other adjustments. Asset sales included U.K. North Sea assets, 50 per cent of Gulf's Midstream Services business as well as various non-core North American properties. This compares with the $1.1 billion in proceeds received in 1997, the majority of which represents the public offering of 28 per cent of the shares of Gulf Indonesia Resources Limited.
Capital expenditures and exploration expenses were $850 million in 1998, down 25 per cent from 1997. North America accounted for $374 million or 44 per cent of the spending, and Indonesia accounted for $284 million or one-third of total spending. Additionally, Gulf spent $43 million on Syncrude, $142 million on other international projects and $7 million on corporate items. The 1998 capital program replaced 155 per cent of the Company's 1998 production at a cost of $7.58 per proved boe. Spending in 1997 of $1.1 billion was up 76 per cent over the 1996 capital and exploration activity of $644 million, mainly due to other international projects and spending on the Corridor Block Gas Project.
During 1998, cash flow from operations and asset sale proceeds were used to fund the Company's capital program, pay down debt by a net $399 million and increase year-end cash by $161 million. During 1997, financing activities provided a net $1.5 billion, that, together with cash from operations, was used to fund significant acquisitions and capital spending.
RESULTS FROM OPERATIONS
Gulf reports its year-to-year operations in four business segments: North America, Oil Sands, Indonesia and Other International.
NORTH AMERICA -- OIL & GAS
Cash generated from North America was $348 million in 1998, down $158 million from 1997. The decrease reflects the impact of significantly lower liquids prices. Lower sales volumes were also a factor as the full year benefit of the September 1997 Stampeder Exploration Ltd. ("Stampeder") acquisition and additions from capital spending were more than offset by the effect of natural reservoir declines and asset sales. In addition, other revenue net of other expenses declined by $11 million as 1998 included the net cost of thermal operations. Cash generated from operations in 1997 of $506 million was virtually unchanged from 1996 as acquisitions offset natural reservoir declines and asset divestitures. A net operating loss of $41 million in 1998 compares with earnings of $113 million in 1997, as cash generated was lower and non-cash items remained virtually unchanged. In 1997 net operating income declined to $113 million from $208 million in 1996, in spite of relatively flat cash generation, due to increased exploration activity and higher depreciation, depletion and amortization from acquisitions.
Net oil and gas revenues, excluding the effects of hedging, decreased by $130 million to $563 million in 1998. The decline in liquids prices and lower volumes were partially offset by lower royalties and an improvement in natural gas prices. Net oil and gas revenues in 1997 of $693 million increased from $669 million in 1996 due primarily to higher volumes from acquisitions.
Production operating expenses increased $17 million or $0.42 per boe as a $0.35 per boe decline in conventional light crude was more than offset by a full year of higher-cost conventional heavy oil operations. Production operating expenses in 1997 of $205 million increased $26 million from $179 million in 1996, which was also mainly attributable to the acquisition of higher-cost heavy oil properties.
Lower production volumes resulted in a slight decrease in depreciation, depletion and amortization to $286 million in 1998. Depreciation, depletion and amortization of $295 million in 1997 was $60 million higher than the $235 million charge in 1996 due to acquisitions and the write-down of certain unproductive properties.
Exploration expenses of $103 million in 1998 compared with $98 million in 1997 and $61 million in 1996. The increase in 1998 was due to additional seismic work more than offsetting a decrease in dry well expense, while 1997 was higher than 1996 largely as a result of dry well expense.
Conventional and heavy oil capital and exploration expenditures were $324 million in 1998 compared with $499 million in 1997 and $502 million in 1996. Proved reserve additions were 39 million barrels in 1998 compared with 84 million and 69 million for 1997 and 1996, respectively.
East Coast offshore expenditures were related to a 7,300-kilometre seismic program conducted during the year.
Expenditures on thermal pilot projects, comprising Gulf's activities in the development of steam-assisted oil recovery operations in the Surmont and Kerrobert areas, decreased to $21 million in 1998 from $48 million in 1997 and $7 million in 1996. Spending in 1998 included $17 million on the Surmont pilot project and $4 million on Kerrobert. Spending in 1997 included $31 million on the Surmont project and $17 million on Kerrobert for the completion of the main steam facilities.
Expenditures on infrastructure assets and injectants of $22 million in 1998 compared with $41 million in 1997 and $15 million in 1996.
NORTH AMERICA -- OIL & GAS
NORTH AMERICA -- OIL AND GAS*
[FN] * Excludes hedging ** Based on barrels of oil equivalents sold *** Includes USA spending of $14 million, $48 million and $55 million for the three years ended December 31,1998, 1997 and 1996, respectively
SYNCRUDE
Gulf owns a 9.03 per cent interest in the Syncrude Project. Net operating income from Syncrude decreased to $28 million in 1998 from $62 million in 1997 and $46 million in 1996. Cash generated from operations also decreased in 1998 to $45 million from $78 million in 1997 and $65 million in 1996.
Net revenues from Syncrude declined 19 per cent in 1998 to $139 million from $171 million in 1997. This decrease was the result of a $7.64 per barrel decline in the price of Syncrude oil, partially offset by an $18 million decrease in crown royalties, which are sensitive to prices and capital spending. Net revenues in 1997 of $171 million increased $14 million over 1996 net revenues of $157 million. This was due to significantly lower crown royalties as a result of the implementation of the new oil sands royalty regime effective January 1, 1997. Syncrude experienced another record production year, with Gulf's share of sales volumes increasing to 18,900 b/d in 1998 from 18,600 b/d in 1997. Sales volumes in 1997 increased from the 1996 average level of 18,200 b/d as a result of the opening of a new mining train in the North Mine and a higher bitumen conversion yield.
Gulf's share of capital expenditures at Syncrude increased to $43 million in 1998 from $32 million in 1997. The major project in 1998 was the Aurora mine, which is the next phase of expansion and is scheduled for start-up mid-2000. Capital expenditures in 1997 increased $13 million from $19 million in 1996 attributable to the new North Mine train, debottlenecking extraction and upgrading facilities and development work on the Aurora Mine.
SYNCRUDE
INDONESIA
Gulf owns 72 per cent of Gulf Indonesia Resources Limited and consolidates its results. The Indonesian segment consists of onshore operations, which are mainly focused on the island of Sumatra, and offshore operations located in the West Natuna Sea.
Cash generated from operations of $81 million decreased by $42 million from 1997, reflecting lower oil prices. Cash generated from operations in 1997 of $123 million increased $49 million from $74 million in 1996, reflecting in large part the impact of the Company's acquisition of Clyde Petroleum plc's Indonesian asset, the Kakap production sharing contract (PSC) in the West Natuna Sea.
The impact of lower oil prices combined with the increased cost of expensed exploration were the main contributors to a $34 million net operating loss in 1998. These factors were partially offset by the start-up of the Corridor Gas Project in the fourth quarter of 1998, which positively contributed to Gulf's financial results. Net operating income in 1997 of $42 million was $4 million higher than 1996. The Kakap PSC acquisition contributed $19 million in earnings in 1997, which was offset by higher dry hole write-offs associated with Indonesia's increased exploration program.
Net oil and gas revenue for 1998 was $124 million compared with $160 million for the same period last year. This reflects an $8.07 per barrel decline in the average liquids price year over year, partially offset by the addition of $11 million in net gas revenue from the Corridor Gas Project. Net oil revenues in 1997 were $61 million higher than 1996 net oil revenues of $99 million. The Kakap PSC accounted for the majority of the increase.
Operating expenses are based in US dollars and for 1998 increased to $4.89 per boe ($43 million) from $4.56 per boe ($37 million) in 1997, largely as a result of a weaker Canadian dollar. Operating expenses in 1997 fell from $4.86 per boe ($25 million) in 1996 due to the addition of lower-cost production from the Kakap PSC.
Exploration expenses increased by $24 million to $50 million for 1998 due to an increased level of activity. The Company drilled 24 exploration wells in 1998 compared with 12 in 1997. Of the total exploration wells drilled, ten, or approximately 40 per cent of the exploratory wells, were dry in 1998 and five were dry in 1997. Exploration expenses in 1997 increased by $19 million from $7 million in 1996 due to an increased level of activity.
Capital expenditures and exploration expenses decreased from $366 million in 1997 to $284 million in 1998. This decrease reflects a reduced level of spending related to the Corridor Gas Project (1998 -- $140 million; 1997 -- $255 million), where the major facilities for this project were completed in the third quarter of 1998. Expenditures in 1997 of $366 million increased from $78 million in 1996 due to the construction of the Corridor Block Gas Project and expenses related to the Kakap PSC.
Indonesia's economy continued to suffer severe setbacks into 1998 as a result of political and economic turmoil, with a further decline in the value of the Indonesian rupiah against the U.S. dollar. These currency fluctuations are not expected to have a material long-term impact on Gulf'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. The sale of natural gas from the Corridor Block Gas Project is exchanged for exportable Duri crude oil pursuant to a 15-year contract.
INDONESIA
OTHER INTERNATIONAL
The other international segment includes the North Sea in the United Kingdom and the Netherlands, Australia and various other exploration prospects.
UNITED KINGDOM
In May 1998, Gulf divested of its North Sea operations in the United Kingdom involving some 28 licenses, including interests in the Wytch Farm, Gryphon, Andrew and Ross fields. Oil production associated with these assets averaged 7,200 b/d in 1998 compared with 17,000 b/d in 1997. Cash generated from operations was $37 million, and netoperatingincome was $6 million in 1998, down from $118 million and $39 million, respectively, in 1997. Exploration write-offs and depreciation expense were $2 million and $29 million, respectively, compared with $11 million and $69 million, respectively, in 1997.
NETHERLANDS
Netherlands North Sea gas sales were 63 mmcf/d, virtually unchanged from a year ago, while the acquisition of two oil producing blocks during the year added 2,600 b/d of liquids sales. Netherlands operations generated cash of $73 million and net operating income of $10 million, which compares with $65 million and $12 million, respectively, in 1997.
During 1998, Gulf sold its 4.4 per cent interest in the K4/K5 non-operated production license located in the Dutch North Sea for cash plus interests in strategic, operated exploration properties.
Total capital and exploration expenditures were $51 million, up from $31 million in 1997. Exploration write-offs and depreciation expense were $9 million and $54 million, compared with $4 million and $49 million, respectively, for 1997.
AUSTRALIA
During 1998, Gulf Australia completed the acquisition of 50 per cent interests in the Jabiru and Challis production licences and a 43 per cent interest in the Skua production licence. These fields are located in the Timor Sea off the north coast of Western Australia. Gulf Australia also acquired a 70 per cent interest in the W97-2 block in the Timor Sea. This block is located in close proximity to the Jabiru and Challis production licences. Sales from Australia averaged 9,300 boe/d, with average oil and liquids sales of 5,600 b/d and natural gas of 23 mmcf/d. This resulted in cash generation of $32 million and net operating income of $1 million. In 1997, sales averaged 5,000 boe/d, with average oil and liquids sales of 1,600 b/d and natural gas of 21 mmcf/d. Cash generation and net operating income were $26 million and $8 million, respectively.
As part of Gulf's divestitures program, a 1.2 per cent interest in a South West Queensland Unit and associated natural gas production was sold for net proceeds of $33 million
Total capital and exploration expenditures were $28 million, up $6 million from a year ago. Exploration write-offs and depreciation expense were $7 million and $24 million, respectively, compared with $5 million and $14 million, respectively, for 1997.
OTHER INTERNATIONAL
Gulf's other international holdings had liquid sales of 500 b/d and natural gas sales of 1 mmcf/d, resulting in cash generation of $1 million and a net operating loss of $22 million. Capital and exploration expenditures in Mongolia, Algeria, Yemen, Argentina, Syria, Libya, Romania, the Falklands and the Ivory Coast amounted to $45 million. Exploration expense was $20 million, relating primarily to activity in Mongolia and Algeria, and depreciation expense was $3 million.
At the beginning of the year Gulf acquired a 75 per cent working interest in four production-sharing contracts in Mongolia. In an effort to focus on core areas, however, the Company made a decision to either sell or withdraw from the majority of its non-producing international holdings including Mongolia, Albania, Romania, Yemen, Argentina, Syria, Libya and the Falklands.
OTHER INTERNATIONAL*
CORPORATE
Gulf's consolidated net loss was $562 million, compared with earnings of $204 million and $37 million in 1997 and 1996, respectively. Total cash generated from operations was $371 million in 1998, down from $592 million in 1997 and $440 million in 1996. The 1998 discontinued operations gain of $24 million relates to the sale of an undeveloped tract of land in Reno, Nevada.
The Company's hedging program is designed to mitigate downside risk while providing Gulf with a reliable level of cash flow upon which to base capital expenditures. Gulf's hedging activity, which relates to commodity price and exchange rate contracts, increased pre-tax earnings and cash generation by $58 million in 1998; this compares with a net loss of $22 million in 1997 and a net loss of $69 million in 1996. Low market crude oil prices were the main reason for the gain in 1998.
During 1998, the Company incurred a net loss on asset disposals and net provision for other losses of $170 million, compared with $75 million in 1997 and a $5 million gain in 1996 (see note 2).
Additional one-time items during 1998 include a $212 million before-tax reduction in the carrying value of assets based on lower oil price assumptions. Heavy oil assets acquired in the purchase of Stampeder account for substantially all of this amount.
Other revenue net of other expenses provided earnings of $13 million in 1998, compared with $32 million in 1997 and $10 million in 1996. Results for 1997 benefited from foreign exchange gains.
During the year Gulf incurred restructuring and pension charges of $45 million, which compares with $67 million a year ago. Gulf's plan to annuitize its defined benefit pension plan resulted in a 1997 charge of $53 million relating to deferred pension expenses, compared with a charge of $6 million in 1998. Earnings in 1998 were also impacted by $39 million of restructuring charges relating to organizational changes, compared with $14 million in 1997.
General and administrative expenses for 1998 decreased $6 million to $62 million partially as a result of eliminating expenses related to the U.K. operations. On a unit-of-production basis, general and administrative costs were $0.94 per boe compared with $1.03 per boe for 1997. General and administrative costs in 1997 of $68 million increased from $49 million in 1996 due primarily to the addition of the Clyde and Stampeder operations.
Finance charges for 1998 were $278 million, up $56 million from 1997. Additional amortization of deferred foreign exchange on U.S. dollar-denominated debt accounted for $54 million of the net increase. In spite of using a net $399 million to pay down debt, cash finance charges were virtually unchanged from 1997 as the paydown was primarily in the fourth quarter and a weaker Canadian dollar increased the Company's Canadian dollar interest expense. Finance charges of $222 million in 1997 increased from $79 million in 1996. The change was primarily related to an increase of $79 million in interest expense on long-term debt and an increase in net short-term interest expense of $72 million due to the Clyde acquisition in 1997 and an income tax refund received in 1996.
Income tax was a recovery of $151 million in 1998, compared with an expense of $59 million in both 1997 and 1996. The effective tax rate in each of the years varies substantially from the statutory rate largely as a result of the amortization or sale of assets that do not have a tax basis.
CORPORATE AND OTHER
LIQUIDITY AND CAPITAL RESOURCES
Gulf's 1998 operating activities generated $353 million, investing activities provided an additional $219 million as asset sale proceeds exceeded capital spending, and a further $59 million was received from the issue of equity. These cash inflows totaled $631 million, of which $31 million was used to pay dividends. In addition, debt was reduced by a net $399 million, a rate swap was settled for $40 million, and cash increased by $161 million.
Long- and short-term debt decreased from $2,865 million at the end of 1997 to $2,593 million at December 31, 1998. In addition to the $399 million net debt reduction referred to above, an asset purchaser assumed $110 million of the Company's debt. However, a weaker Canadian dollar caused the Company's year-end debt to increase by $173 million, and a rate swap and other placement costs reduced proceeds from the issue of debt by $66 million.
During 1998, Gulf also made substantial progress to move from bank credit facilities to public debt. Outstanding bank facilities debt was reduced from $1,000 million at the end of 1997 to $143 million at the end of 1998. Going into 1999, the Company has a current portion of long-term debt totaling $215 million and cash on hand of $349 million. Looking beyond 1999, the Company has debt repayment obligations of $83 million per year for the period from 2000 to 2003. The Company also has uncommitted credit facilities of $767 million and uncommitted operating bank lines of $129 million.
Gulf's 1999 capital budget is currently $300 million, budgeting just under 50 per cent in Canada, 30 per cent in Indonesia and the remainder largely in the Netherlands and Australia. Gulf currently expects to finance this budget without increasing net debt.
RISK MANAGEMENT
Gulf is exposed to a variety of risks, including changes in commodity prices, foreign currency exchange rates and interest rates. Gulf's Board of Directors has authorized commodity trading activities, provided that the Company's total risk of loss shall not exceed $5 million at any time. The authorities include limits on both the number of uncovered cumulative positions and maximum dollar loss amounts. Control is maintained through the separation of trading and accounting functions, as well as through daily mark-to-market reporting. Gulf has not engaged in any significant speculative foreign exchange or commodity price transactions. For more information on these exposures, see Note 17.
COMMODITY PRICES
Gulf's results of operations are dependent upon the difference between prices received for its oil and natural gas production and the costs to find and produce such oil and natural gas. The Company's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing volatility is expected to continue.
The Company periodically enters into hedging activities with respect to a portion of its projected oil and natural gas production. Gulf may use futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. Gains or losses on natural gas derivative contracts are expected to offset variability in the spot market price or to preserve the margin on existing physical contracts. Realized gains or losses from the Company's hedging activities are recognized in oil and gas production revenues when the associated production occurs. Gulf does not hold or issue any significant amount of derivative instruments for trading purposes.
The maximum potential loss in the fair value of futures, options and financial forward contracts at December 31, 1998, is estimated to be $8 million with a 99.5 per cent confidence interval. This value at risk is based on a one-day holding period and is determined using a derivative of the Black-Scholes European option pricing model, which calculates a probability distribution of prices based on market-determined volatility.
The Company did not have any open market positions with respect to crude oil hedging at December 31, 1998.
FOREIGN CURRENCY EXCHANGE RATES
Gulf's reported results from operations are affected by the exchange rate between the Canadian dollar and other currencies, particularly the U.S. dollar. Prices for substantially all of Gulf's Western Canada oil production and approximately 23 per cent of its natural gas and other liquids production are U.S. dollar-denominated, while most of its expenses (with the exception of interest costs on U.S. dollar-denominated debt), are denominated in Canadian dollars. The Company's reported cash flows relating to international operations are based on the Canadian dollar equivalent of cash flows measured in foreign currencies. Australian crude oil revenue is received in U.S. dollars, while gas is sold under fixed-price Australian dollar contracts; substantially all capital expenditures and operating costs are paid in Australian dollars. Netherlands revenues are based in U.S. dollars, while costs are denominated in Dutch guilders. Substantially all of the Company's other international transactions are denominated in U.S. dollars. Transactions in foreign currencies are converted to Canadian dollar amounts based on the exchange rates prevailing on the dates of the transactions.
To mitigate the impact of exchange rate fluctuations on revenues, Gulf attempts to hedge its U.S. dollar exposure in two ways. First, it seeks to incur its debt in U.S. dollars. Based on Gulf's U.S. dollar-denominated debt at December 31, 1998,a 10 per cent ($0.153) change in the value of the U.S. dollar relative to the Canadian dollar would result in a $254 million unrealized gain or loss on the carrying amount of such debt and would affect annual interest expense by $20 million.
Second, Gulf undertakes forward sales of U.S. dollars into Canadian dollars. The Company monitors its foreign exchange exposures daily to ensure the overall effectiveness of its foreign currency hedge positions. However, there can be no assurance that the Company's foreign currency hedging activities will substantially offset the impact of fluctuations in currency exchange rates on its results of operations and financial position. Based on Gulf's forward contracts at December 31, 1998, a 10 per cent ($0.153) increase in the value of the U.S. dollar relative to the Canadian dollar would result in cumulative losses to 2001 on settlement of these contracts of $96 million. This sensitivity measure is the undiscounted before-tax cash flows realized on the contracts based on the foreign exchange forward curve.
Both of these strategies offer benefits to the Company in the event of a decline in the U.S. dollar relative to the Canadian dollar by decreasing its Canadian dollar equivalent cost of debt service obligations and by creating a gain on the forward sales of U.S. dollars.
INTEREST RATES
At December 31, 1998, about $564 million, or 22 per cent, of Gulf's total debt was variable rate. The impact on annual before-tax cash flow of a 10 per cent change in the floating rate (approximately 71 basis points) would be $4 million.
YEAR 2000
The Company is devoting significant resources throughout its business operations to the Year 2000 ("Y2K") issue. The Company's goal is business continuity and sustained operations beyond December 31, 1999, without significant disruption or material financial impact resulting from the Y2K issue. The Y2K issue is a result of computer programs tracking and storing dates represented by only two century digits (e.g., 98 rather than 1998) to define the applicable year. Without the century digits the last day of this millennium will be 99-12-31, and after midnight, any information technology ("IT") systems that have time-sensitive software may recognize the date using "00" as the year 1900 rather than the year 2000, which could result in miscalculations and systems failures. The problem also extends to many "non-IT"systems, that is, distributed control, scada and embedded chips used in its field operations both on and off shore. Like most other businesses, the Company is also at risk from Y2K failures in public and private infrastructure services, including power, water, transportation and telecommunications.
System failures resulting from the Y2K issue could adversely affect operations and financial results of the Company. The Company's primary risk lies in its internal date-dependent systems, including computer hardware, software and field control devices. The Company is also exposed to third-party risk through its financial institutions, joint interest partners, product transportation systems (pipelines, railcars and tankers), vendors and customers whose systems may be affected by the Y2K issue.
Addressing the Issue. In the fourth quarter of 1997, the Company organized a worldwide corporate task force to review Y2K issues, identify potential impacts, risks and preparations, and allocate appropriate resources. The task force developed a seven-phase approach to resolving the Y2K issues that are reasonably within its control. Since the initiation of this project, approximately 50 employees have devoted a significant portion of their time to Year 2000 efforts. In addition, the Company has retained several outside consultants to assist with specific phases of the plan. The task force reports regularly to the Audit Committee and the Board of Directors with respect to the Company's Y2K efforts.
The Company's approach to and the anticipated timing of each phase are described below:
Phase 1 -- Issue Identification. In the first quarter of 1998, the task force conducted an extensive inventory of the Company's software applications, operating systems, hardware, netware, control systems, key business partners and service providers to identify Y2K issues and compliance. During the inventory phase and throughout this project, the Company enlisted individual employees who have an intimate knowledge of their specific workplaces, tools and third-party relationships to identify items not captured in the initial inventory and ensure that such items were assessed and, if required, remediated.
Phase 2 -- Investigating Compliance. In the second quarter of 1998, the Company began to investigate the compliance of its inventoried items, ensuring those items that posed the greatest risk were dealt with first. The level of risk was established using the Company's corporate risk assessment model to rank items in terms of their safety and potential impact on its business. The task force focused on "high-risk" items and evaluated results with a view to upgrading, replacing, retiring or working around non-compliant items. Part of the investigation was the implementation of a testing program for critical systems.
As the inventory phase came to a close, the Company implemented a "Clean Management Date" to ensure further Y2K issues were minimized. That is, after June 15, 1998, the Company required that all acquisitions of software, hardware or other equipment with date-sensitive components be reported to the task force and be Year 2000-compliant.
Because the Y2K challenge is a global issue with a cross-industry focus, the Company closely reviewed its list of key business partners and service providers to assess their state of Y2K readiness through letter campaigns and interviews. The Company intends to continue its review of business partners and service providers throughout the remaining phases of the plan.
Phases 3 and 4 -- Corrective Measures and Sustainable Operations (Q3 and Q4, 1998). Phases 3 and 4 involved the correction of Y2K issues. During these phases the decisions from the compliance investigation phase relating to high- and selected moderate-risk items were implemented. For non-compliant items a decision was made to: upgrade, replace, retire, work around or ignore. During Phase 4, the task force followed up with interviews with partners and vendors deemed to have a potentially large impact on its business should such partners or vendors encounter Y2K issues. Because the Company recognizes that achieving total Y2K compliance is not realistic, during Phase 4 contingency and crisis management planning will be addressed. The Company expects to complete its contingency and crisis management plans by June 30, 1999.
Phase 5 -- Continuing Issue Management (Q1-Q3 1999).This phase involves addressing remaining less critical systems and continuing to assess the adequacy of measures taken by the Company's business partners and vendors to prepare for the Year 2000. The Company expects to be fully compliant from an internal standpoint by the end of this phase; however, due to the Company's reliance on third party vendors and customers, the Company cannot ensure complete Y2K compliance. The Company intends to discontinue business with any of its vendors who have not identified their compliance and are not willing or able to provide a positive statement of their Y2K readiness by June, 1999.
Phase 6 -- Y2K Readiness (Q4 1999). During this phase, the task force intends to focus on its Y2K response mechanisms and problem management, while continuing to deal with any remaining compliance issues and outstanding business partner and vendor concerns.
Phase 7 -- Y2K Response (January 1 - June 30, 2000). Although the task force will have marshaled every effort to limit Y2K problems, during this phase the planning and processes completed in Phase 5 will be implemented, remaining in place as long as there is a need. The task force has established a crisis communications team that will staff a communications center in Calgary beginning December 31, 1999. The team will chart Y2K events and issues, beginning with Australian and Indonesian operations mid-morning through to midnight and beyond in North America.
Costs. As at December 31, 1998, the Company had incurred costs of approximately $3.5 million related to its Y2K project. The estimated additional costs to complete the project are currently expected to be $6.5 million. A significant portion of these costs have been or will be incurred for the replacement of non-compliant equipment, with some of these costs being shared by the Company's partners. All of the Company's costs for the Y2K project are being paid out of operating expenses.
Based upon its efforts to date, the Company believes that it has addressed the majority of its critical IT and non-IT systems such that its critical systems will function properly into the Year 2000. Accordingly, the Company does not currently anticipate that internal systems failures will result in any material adverse effect to its operations or financial condition. During 1999, the Company will continue and expand its efforts to ensure that its key business partners, third-party vendors and customers will also be prepared for the Year 2000 and to develop contingency plans to address any failures on their part to become Y2K-compliant. At this time, the Company believes that the most likely "worst case" scenario involves potential disruptions worldwide in areas where the Company relies on third-party providers of power, telecommunications and transportation. As well, the Company's operations in Indonesia may be adversely affected by failures of third-party vendors, refiners and customers to take adequate steps to address the Y2K problem. In recognition of the potential impacts in Indonesia, the Company has taken steps to identify alternative providers of goods and services along with alternative markets to address concerns with refiners and other customers. While such failures could affect the operations of the Company and its subsidiaries, either directly or indirectly, in a significant manner, the Company cannot at present estimate either the likelihood or the potential cost of such failures. The Company is, however, currently developing contingency plans to mitigate any material impact on the Company's business.
The Company may revise the timing and focus of its efforts to address the Year 2000 problem from time to as new issues are identified. The description of the Company's efforts involves estimates and projections derived using numerous assumptions of future events including continued access to key resources. The Company cannot guarantee these estimates will be achieved, and actual results could differ materially from the plans, as it is impossible to predict the cost and availability of materials and resources as the year 2000 approaches.
SENSITIVITIES
Based on current production and price estimates and current hedge positions, the estimated effect on the Company's financial results for 1999 of a change in the following factors is set out below:
[FN] (1) The impact of hedging contracts in place at December 31, 1998, has been included.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - The information required by this Item 7A is provided in Item 7. Management's Discussion and Analysis of Financial Condition under the heading Risk Management.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Gulf Canada Resources Limited (Gulf) is responsible for preparing the accompanying consolidated financial statements. The consolidated 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 consolidated financial statements.
Gulf 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 Gulf'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 Gulf. 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.
[SIGNATURE] [SIGNATURE] R. H. Auchinleck G. S. Glick President and Chief Executive Officer Executive Vice-President and Chief Financial Officer
Calgary, Canada February 19, 1999
AUDITORS' REPORT
TO THE SHAREHOLDERS OF GULF CANADA RESOURCES LIMITED:
We have audited the consolidated statements of financial position of Gulf Canada Resources Limited as at December 31, 1998 and 1997 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, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform 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, 1998 and 1997 and the results of its operations and the cash flows for each of the years in the three-year period ended December 31, 1998, in accordance with accounting principles generally accepted in Canada.
[SIGNATURE] Ernst & Young LLP Chartered Accountants
Calgary, Canada February 18, 1999
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGS (DEFICIT)
(See summary of significant accounting policies and notes to consolidated financial statements.)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(See summary of significant accounting policies and notes to consolidated financial statements.)
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(See summary of significant accounting policies and notes to consolidated financial statements.)
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of Gulf Canada Resources Limited ("Gulf" or "the Company") include the accounts of all subsidiary companies. Substantially all of the activities of Gulf are conducted jointly with others, and these financial statements reflect the proportionate interest in such activities. Investments in companies in which Gulf exercises significant influence are accounted for on the equity basis.
PROPERTY, PLANT AND EQUIPMENT
The successful efforts method of accounting is followed for oil and gas exploration and development costs. The initial acquisition costs of oil and gas properties and the costs of drilling and equipping successful exploratory 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, including the cost of liquid injectants used in enhanced oil recovery projects, 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 proved oil and gas reserves. Depreciation of plant and equipment is based on estimated remaining useful lives of the assets using either the straight-line method or the unit-of-production method. Individually insignificant unproved properties are amortized on a group basis at rates determined after considering past experience and lease terms. Certain costs relating to significant acquisitions and major projects remain undepreciated pending evaluation or completion of development.
As changes in circumstances warrant, the net carrying values of proved properties, plant and equipment, and significant unproved properties are assessed to ensure that they do not exceed future cash flows from use or disposal. The estimated future costs to dispose of an asset or to exit an activity are recognized at the time that a commitment to such action is made.
ENVIRONMENTAL AND SITE RESTORATION LIABILITIES
Future obligations for site-restoration costs, including dismantling plants and abandoning properties, are provided for using the unit-of-production method or, where appropriate, the estimated remaining useful lives of the related assets. Accruals for other potential environmental remediation obligations, such as those related to discontinued downstream operations, are made when management believes that Gulf has an obligation for remediation and the anticipated costs can be estimated within a reasonable range.
FOREIGN CURRENCY TRANSLATION
Assets and liabilities of self-sustaining foreign subsidiaries are translated into Canadian dollars at year-end exchange rates. The resulting unrealized exchange gains or losses are reflected in shareholders' equity. Revenues and expenses are translated using the average rates of exchange during the year.
Assets and liabilities of all other foreign subsidiaries and all other transactions in foreign currencies are translated into Canadian dollars at the exchange rates prevailing at the transaction dates. Monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars at year-end exchange rates. Exchange gains or 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.
PENSIONS AND OTHER POST-RETIREMENT BENEFITS
The pension plans, which cover Canadian and U.S. employees, have both defined benefit and defined contribution options, which are company funded. The cost of the defined benefit option reflects management's best estimates of the pension plan's expected investment yields, salary escalation, mortality of members, terminations and the ages at which members will retire. Defined benefit pension plan assets are reported at market values. Adjustments arising from plan amendments, transitional surplus, experience gains and losses and changes in assumptions are amortized on a straight-line basis over the estimated average remaining service lives of the employees. The unamortized balance of such costs has been charged to earnings upon Gulf's decision to annuitize the defined benefit plan. The cost of the defined contribution option reflects specific amounts contributed on behalf of participating employees during the year. The costs of post-retirement benefits other than pensions, including dental, medical and life insurance, are accounted for on a cash basis.
FINANCIAL INSTRUMENTS
A financial instrument is recognized when a contractual benefit or obligation exists for the future receipt or payment of monetary amounts and is recorded at inception at the fair value of consideration paid or received, along with the costs of acquisition or issuance. A financial instrument held for disposal or settlement is carried thereafter at the lower of original cost or market value. One held over the long term or to maturity is carried at original cost and is assessed as circumstances warrant to ensure that its carrying value does not exceed its recoverable amount. Income or expense on a financial instrument is recognized in each period on an accrual basis. A premium or discount on debt bearing an interest rate different from the prevailing market rate and its costs of issuance are deferred and amortized over the life of the debt.
DERIVATIVE INSTRUMENTS
Gulf enters into physical and financial forward sales contracts, options and swap agreements to manage its exposure to changes in commodity prices, exchange rates and interest rates. Gains and losses on the contracts that are used to hedge such exposures on future transactions are recognized in the financial statements when the hedged transactions occur and are included in the measurement of such transactions. Changes in the market values of derivatives that are not hedges, or that arise subsequent to when they cease to be effective hedges, are recognized as gains and losses in the earnings of each period. Such gains or losses are recorded in other revenues.
A derivative is treated as a hedge when all of the following criteria are met:
- - Gulf has an identified risk exposure to commodity prices, exchange rates, interest rates or some other risk factor related to an asset or a liability, a contractual commitment or a planned future transaction.
- - There is an offsetting relationship between the cash flows of the derivative and those of the identified risk to be hedged.
- - Management intends to use the derivative to hedge the exposure. The derivative is therefore designated as a hedge at its inception.
If a hedge is terminated early, or if the designation of a derivative as a hedge is discontinued, any accumulated gain or loss up to that time continues to be deferred until the hedged transaction occurs. If the term of a derivative used as a hedge extends beyond the date of the hedged transaction, any deferred gain or loss at that date is included in the measurement of the hedged transaction; gains and losses thereafter are recognized in earnings on an accrual basis. If the occurrence of a hedged transaction ceases to be likely, any deferred gain or loss on the hedge is recognized in income immediately. An individually significant loss is included in the 1998 provision for other losses in Gulf's Consolidated Statements of Earnings (Loss).
INCOME TAXES
Gulf follows the deferred method of tax allocation for income taxes. Under this method, deferred income taxes are recorded to the extent that income taxes otherwise payable are reduced by capital cost allowances and exploration and development costs in excess of the depletion and depreciation provisions recorded in the accounts.
MEASUREMENT UNCERTAINTY
Certain items recognized in the financial statements are subject to measurement uncertainty. The recognized amounts of such items are based on Gulf's best information and judgment. Such amounts are not expected to change materially in the near term. These include:
- - The amounts recorded for depletion, depreciation, amortization and impairment of property, plant and equipment and future site restoration costs depend on estimates of oil and gas reserves or the economic lives and future cash flows from related assets. The provision for future site-restoration costs also depends on estimates of such costs based on current legislation.
- - The recognized amounts of other potential environmental claims and liabilities depend on estimates of the magnitude and probability of future costs.
- - The values of pension obligations and assets and the amount of pension costs charged to earnings depend on certain actuarial and economic assumptions.
- - The amounts recorded for assets and liabilities of acquired companies depend on estimates of their fair values on the acquisition date and are subject to subsequent adjustment over a one-year period.
- - The recognized future costs of exiting activities and disposing of assets depend on estimates of such amounts.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (tabular amounts expressed in millions of dollars except where otherwise noted)
1. GAIN ON SALE OF SHARES BY SUBSIDIARY
On September 29, 1997, Gulf completed a public offering of 28 per cent of the shares of Gulf Indonesia Resources Limited (Gulf Indonesia), the Indonesian arm of its oil and gas exploration and development activities. The Company sold 24,150,000 shares of Gulf Indonesia at US$19.50 per share for cash proceeds of $602 million, net of $44 million of costs. A gain of $417 million ($384 million after tax) associated with this transaction was recognized during the third quarter of 1997. Prior to the public offering, Gulf Indonesia was a wholly owned subsidiary of the Company.
2. UNUSUAL ITEMS
NET LOSS (GAIN) ON ASSET DISPOSALS AND PROVISION FOR OTHER LOSSES
[FN] (a) In 1998, the Company sold 50 per cent of its Western Canadian natural gas gathering and processing facilities, pipelines and gas products facilities, as well as its natural gas and gas products marketing business for total cash consideration of $290 million. Gulf's retained interest was combined with that of the purchaser in the jointly controlled Gulf Midstream Services business (GMS). Gulf also received $100 million subject to a future obligation (see Note 21).
(b) In 1998, the net loss on other asset disposals includes the divestment of various Western Canadian and international conventional, oil sands, and offshore oil and natural gas properties, and an interest in a pipeline project. In 1997 the net gain on other asset disposals consisted of a $27 million gain on the sale of the remaining portions of Gulf's northern drilling system and a $15 million net gain on the sale of Western Canadian oil and gas assets.
(c) The provision for expected losses on future asset disposals is the reduction to estimated realizable value in the carrying amounts of assets of which the Company expects to divest, along with estimated associated employee severance costs. The 1998 provision relates to the planned sale of non-core Western Canadian and international conventional oil and gas properties. The 1997 provision consists of write-downs of an undeveloped coal property of $67 million, North American oil and gas assets of $47 million and other assets of $3 million.
(d) Other provisions consist largely of impairments of investments and future obligations.
REDUCTION IN CARRYING VALUE OF ASSETS
As a result of a decline in oil prices in 1998, the Company recorded a provision of $212 million for the write-down of certain Western Canadian oil and natural gas assets. The write-down reflects the excess of net carrying amounts over recoverable amounts as measured by undiscounted estimated future net cash flows.
PENSION SETTLEMENT AND RESTRUCTURING CHARGES
[FN] (a) Restructuring charges pertain to costs and write-offs resulting from organizational changes. (b)In 1997 deferred pension costs were written off to reflect the Company's decision to commence a program
(b) In 1997 deferred pension costs were written off to reflect the Company's decision to commence a program to annuitize the obligations of the defined benefit pension plan (see Note 20). The charge in 1998 relates to the performance of the pension assets.
3. FINANCE CHARGES, NET
[FN] (a) Net debt comprises long-term debt and short-term loans less cash and short-term investments.
4. INCOME TAX EXPENSE (RECOVERY)
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:
Foreign taxes account for $21 million, $34 million and $13 million of the current taxes and $(12) million (recovery), $18 million and $9 million of the deferred taxes in 1998, 1997 and 1996, respectively.
5. DISCONTINUED OPERATIONS
Discontinued operations related to Asamera Minerals Inc. and environmental costs for Gulf's former downstream operations. In 1998, a gain of $24 million was realized on the sale of non-producing land in the United States. There were no income taxes applicable to this transaction.
6. EARNINGS (LOSS) PER ORDINARY SHARE
Earnings (loss) per ordinary share was calculated after deduction of cumulative preference share dividend requirements of $31 million, $23 million and $29 million for 1998, 1997 and 1996, respectively. The weighted average number of ordinary shares outstanding was 348,399,257 for 1998, 290,873,726 for 1997 and 238,156,206 for 1996. Earnings per share on a fully diluted basis was $0.58 in 1997, assuming all outstanding stock options at December 31, 1997, had been exercised in 1997.
7. CHANGES IN NON-CASH WORKING CAPITAL
8. ACQUISITIONS
(a) ACQUISITION OF CLYDE PETROLEUM PLC
Effective February 18, 1997, Gulf purchased all of the issued and outstanding common shares of Clyde Petroleum plc for 120 UK pence per share. The acquisition was accounted for using the purchase method. Gulf's consolidated financial statements include the operating results of the acquired business from February 18, 1997. The purchase price has been allocated as follows:
(b) ACQUISITION OF STAMPEDER EXPLORATION LTD.
Effective August 28, 1997, Gulf acquired all of the issued and outstanding common shares of Stampeder Exploration Ltd. ("Stampeder") for total consideration of $798 million (including $27 million of acquisition costs) with consideration consisting of 0.69124 of a Gulf ordinary share for each Stampeder common share (Note 15) and $69 million in cash on exercise of Stampeder's option to acquire a major heavy oil property. This acquisition was accounted for using the purchase method. Gulf's consolidated financial statements include the operating results of the acquired business from August 28, 1997. The purchase price has been allocated as follows:
(c) ACQUISITION OF PENNZOIL CANADA INC
Effective July 1, 1996, Gulf purchased all of the issued and outstanding common shares of Pennzoil Canada Inc. for a net cash consideration of $273 million. The acquisition was accounted for using the purchase method. Gulf's consolidated financial statements include the operating results of the acquired business from July 1, 1996. The purchase price has been allocated as follows:
9. OTHER CURRENT ASSETS
10. INVESTMENTS, DEFERRED CHARGES AND OTHER ASSETS
11. PROPERTY, PLANT AND EQUIPMENT
12. OTHER CURRENT LIABILITIES
13. SHORT-TERM LOANS AND LONG-TERM DEBT
[FN] (1) Rates reflect the weighted average rate on instruments outstanding at December 31. Rates vary with changes in short-term market interest rates.
BANK CREDIT FACILITIES
As of December 31, 1998, the Company had $767 million available under committed credit facilities, of which $143 million had been drawn. Gulf also had available uncommitted operating bank lines totaling approximately $129 million, of which $47 million had been drawn. Interest rates on the committed and uncommitted facilities are based on the bankers' acceptance rate plus a spread that varies between institutions and is based on certain financial tests. The average effective rate on the balances outstanding during 1998 was approximately 6.2 per cent on committed facilities and 5.7 per cent on uncommitted facilities. The average effective rate on all balances outstanding during 1997 was approximately 6.1 per cent.
DEBENTURES AND NOTES
US dollar debentures and notes are unsecured with interest paid semiannually.
LONG TERM SECURED LOAN
In February 1997, the Company, along with its partner in the Corridor Block Gas Project (the Project), entered into a Credit Agreement (Corridor Loan) with various lending institutions. The Corridor Loan will provide up to US$450 million of financing to fund the development of the Project of which Gulf's share is US$270 million. The borrowings are based on the London Interbank Offered Rate. Interest and commitment fees related to the Corridor Loan are capitalized until project completion (1998 -- $22 million, 1997 -- $7 million. After completion of the project, the lender's recourse under the Corridor Loan is limited to the Corridor production sharing contract asset pledged as collateral.
The expected minimum repayments on the Corridor loan are equal semiannual installments beginning in August 1999 and ending in February 2007. Mandatory and optional prepayments may also occur, depending on the cash flow generated by the Project. The Project completion date is expected to occur during the first half of 1999.
OTHER SECURED LOAN
The other secured loan represents senior notes issued by a wholly owned subsidiary that are exchangeable at the option of the holder into shares of Triton Energy Limited (currently held by the subsidiary) at a conversion price of US$36.75. The Notes have a fixed rate of interest of 6% and are due February 14, 2004.
INTEREST RATE SWAPS
In 1997, Gulf entered into a transaction to lock in a yield of 6.71% on US$250 million thirty-year bonds in connection with a planned issue of debt securities under a Shelf Registration Statement. In October 1998, Gulf changed its plans and consequently recognized $40 million of the cumulative loss on the interest rate contract, recorded in provision for other losses. The remaining loss of $54 million was included in the placement costs of debt issued on November 16, 1998.
DEBT REPAYMENTS
The Company's contractual minimum repayment requirements in respect of long-term debt for the five years following December 31, 1998, are expected to be 1999 -- $215 million, 2000 -- $83 million, 2001 -- $83 million, 2002 -- $83 million and 2003 -- $83 million.
14. OTHER LONG-TERM LIABILITIES
[FN] (a) $31 million of environmental and site restoration costs were charged to earnings in 1998 ($28 million in 1997).
15. SHARE CAPITAL
AUTHORIZED:
Senior preference shares -- unlimited number. These preference shares rank in priority to the ordinary shares and may be issued from time to time in series with the consideration per share, designation, attributes, including any preemptive, redemption or conversion rights, and the number of each series to be fixed by the directors prior to its issue.
Junior preference shares -- unlimited number. The attributes associated with these shares are substantially the same as the senior preference shares except that they rank junior to the senior preference shares.
Ordinary shares -- voting, unlimited number without nominal or par value.
(a) SERIES 1
Cumulative dividends accumulate monthly at a floating rate based on the average prime rate of interest charged by specified Canadian banks, adjusted for a factor based on the market price of the Series 1 shares. These shares are non-voting and are redeemable, in whole or in part, at the option of Gulf at a price of $5.00 per share.
On March 17, 1993, payment of dividends on the Series 1 shares was suspended. Payment of dividends was reinstated on February 9, 1995. At December 31, 1998 and December 31, 1997, Gulf had no dividends in arrears (1996 -- $33 million or $0.39 per share). Dividends in arrears paid during 1997 were charged to contributed surplus.
(b) SERIES 2
Cumulative dividends are payable at rates determined by Gulf based on negotiations with holders of the shares, or by a dealer bid or by auction procedures. The shares are non-voting and are redeemable, in whole or in part, at the option of Gulf at the end of any dividend period upon written notice at an amount equal to $0.5 million per share.
On March 17, 1993, payment of dividends on the Series 2 shares was suspended. Payment of dividends was reinstated on February 9, 1995. At December 31, 1998, and December 31, 1997, Gulf had no dividends in arrears (1996 -- $12 million or $40,000 per share). Dividends in arrears paid during 1997 were charged to contributed surplus.
(c) At December 31, 1998, pursuant to the terms of Gulf's Incentive Stock Option Plan (1994), options are outstanding to all employees to purchase an aggregate 20,701,831 ordinary shares. Under the plan, 955,670 shares are reserved but unallocated (1997 -- 4,741,281).
A summary of the status of the Company's stock options as of December 31, 1998 and 1997 and changes during the years ended on those dates is presented below:
The following table summarizes information about stock options outstanding at December 31, 1998:
(d) In 1995 the Company issued 13.75 million warrants to purchase one ordinary share each for $5.75 per share, originally expiring on January 25, 1998. By resolution of Gulf's Board of Directors, each warrant holder was given the option to extend the expiry of the warrants to December 15, 1998, in consideration for a strike price of $6.50 and subject to a hold period ending July 27, 1998. There were 11.9 million ordinary share warrants outstanding on December 31, 1997. During 1998, 9.9 million warrants were exercised, and the balance expired on December 31, 1998.
(e) At the May 3, 1995, annual meeting, shareholders approved a resolution to eliminate the $1,186 million deficit accumulated to the end of the first quarter of 1995 by applying it to the Company's share capital and contributed surplus.
The aggregate stated capital at December 31, 1998, for purposes of the Canada Business Corporations Act, of the senior preference shares and ordinary shares is $184 million and $1,730 million, respectively.
16. FOREIGN CURRENCY TRANSLATION ADJUSTMENT
17. FINANCIAL INSTRUMENTS
(a) RISK MANAGEMENT
Gulf is exposed to fluctuations in oil and gas prices, exchange rates and interest rates and periodically enters into contracts to hedge or manage these exposures. Current exposure to credit losses on these instruments approximates their fair values as disclosed below.
Gulf is also exposed to credit risk on the oil and gas price, exchange rate and interest rate instruments to the extent of non-performance by counterparties. For the oil and gas price instruments, credit risk is controlled through credit controls, limits, margin deposits and monitoring procedures. All exchange rate contracts are with major financial institutions, and non-performance is not expected.
(i) OIL AND GAS PRICES
To reduce its price risk on future gas production, at December 31, 1998, Gulf forward sold approximately 160 million cubic feet per day of 1999 gas production at an average plant gate price of approximately $2.48 per thousand cubic feet (assuming a foreign exchange rate of US$0.66 to Cdn$1.00). This price was achieved through a combination of physical sales contracts and financial forward sales and options. In addition, Gulf has fixed the basis differential through gas aggregator sales, direct physical sales and the use of financial transactions between Henry Hub, Louisiana (the pricing location used by the New York Mercantile Exchange) and Alberta on approximately 85 million cubic feet per day at an average level of approximately US$0.54 discount per million British thermal units.
Gulf held no hedging instruments for liquids production at December 31, 1998.
(ii) EXCHANGE RATES
As a large portion of Gulf's sales are based on U.S. dollar pricing, Gulf sells U.S. dollars forward to reduce its foreign exchange risk. At December 31, 1998, Gulf had entered into the following U.S. dollar forward sale contracts and options:
(b) SALES OF ACCOUNTS RECEIVABLE
In November 1994 Gulf entered into an agreement giving it the right, on a continuing basis for extendible three-year terms, to sell certain accounts receivable to a third party to a maximum amount of $100 million. The amount sold at December 31, 1998, was $81 million (1997 -- $91 million). The agreement calls for purchase discounts, based on Canadian Bankers Acceptance rates, to be paid on an ongoing basis. Gulf has potential exposure to an immaterial amount of credit loss.
(c) OIL-INDEXED FINANCIAL INSTRUMENT
A special purpose entity has $200 million 11 per cent public debentures issued and outstanding that mature on October 31, 2000, and assets consisting of a $200 million 5 per cent fixed plus variable rate oil indexed debenture maturing on October 31, 2000, and an interest rate swap agreement for the same amount and term of the debentures that converts the variable rate on the debenture into a 6 per cent fixed rate. These are not included in Gulf's statement of financial position because Gulf does not have the right and ability to obtain future economic benefits from the resources of the entity and is not exposed to the related risks, nor does Gulf have the continuing power to determine the strategic operating, investing and financing policies of the entity without the cooperation of others.
Gulf has an interest rate conversion agreement to October 31, 2000, whereby Gulf pays to an intermediary the fixed rate of 6 per cent and is eligible to receive a variable rate ranging from nil to 16.8 per cent, depending on the average quarterly West Texas Intermediate oil price. In 1993 and 1992, Gulf recorded provisions totaling $67 million to recognize the present value of Gulf's exposure. The unamortized balance of the provision at December 31, 1998, is $24 million (1997 -- $33 million). Gulf paid out the fixed-rate obligation for the remaining life of the swap on January 6, 1999, at a cost of $24 million.
CARRYING AMOUNTS AND ESTIMATED FAIR VALUES OF FINANCIAL INSTRUMENTS:
The following methods and assumptions were used in estimating the fair values of financial instruments:
Cash and short-term investments, accounts receivable, bank credit facilities, accounts payable and long-term secured loans: Terms are such that their carrying amounts approximate fair values.
Equity investments: Fair value of market-traded securities is based on quoted market prices. Other investments are relatively insignificant, and their carrying amounts are assumed to approximate fair values.
Oil indexed rate conversion agreement: The fair value at December 31, 1998, is established by the agreement to settle the obligation. Fair value in prior periods was estimated using discounted cash flow analysis based on the applicable incremental swap rate. Income on the variable-rate portion of interest was estimated based on a forecast of the average quarterly price of West Texas Intermediate crude oil.
Other long-term obligation: Fair values are estimated using discounted cash flow analysis based on current incremental borrowing rates for similar borrowing arrangements.
Notes and debentures: Fair values are based on quoted market prices.
Commodity price and foreign exchange contracts: Fair values are estimated based on the present value of quoted market prices of comparable contracts. The differences between the fair values and carrying amounts are equal to the cumulative unrecognized gains or losses on these contracts. Commodity price contracts include those that may be settled by the delivery of product.
18. COMMITMENTS AND CONTINGENT LIABILITIES
Gulf has lease commitments relating to office buildings. The estimated annual minimum operating lease rental payments for the buildings, before deducting sublease income, will be $35 million in 1999, $35 million in 2000, $34 million in 2001, $33 million in 2002, $17 million in 2003, and $20 million in 2004 - 2007, the remaining term of the leases. Lease rentals payable in foreign currencies have been converted to Canadian dollars using December 31, 1998, rates.
As part of Gulf's upstream operations and as a result of certain discontinued downstream operations, Gulf has ongoing site restoration and remediation responsibilities. Site restoration costs within upstream operations involve the surface clean-up and reclamation of wellsites and field production facilities to ensure that they can be safely returned to appropriate alternative land uses. In addition, over the long term, certain plant facilities will require decommissioning, which will involve dismantling of facilities as well as the decontamination and reclamation of these lands. Total anticipated future costs (including plugging and abandoning of wells), given Gulf's current inventory of wells and facilities including Syncrude, is in the order of $602 million over the next twenty years. Gulf has accrued $162 million ($11 million as current) for future upstream site restoration costs and continues to accrue these costs on the basis described in the summary of significant accounting policies.
Environmental liabilities relating to discontinued downstream operations generally involve the decontamination and/or remediation of formerly owned service stations, bulk fuel facilities and refinery sites. These future obligations are difficult to estimate as the number of sites that will need reclaiming, their degree of contamination, the cleanup standards, future regulatory requirements and other potentially responsible parties are all unknown. Gulf has accrued approximately $9 million ($3 million as current) for future downstream remediation costs. On the basis of current information it is not possible to reasonably estimate Gulf's total potential future liability for discontinued downstream operations.
Gulf is 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.
In connection with the Corridor Block Gas Project, a local court has ruled against the Corridor Block PSC Partners concerning a property claim. The Corridor Block PSC Partners, including Pertamina, believe that the claim is without merit and have filed an appeal to reverse the lower court decision based on advice received from counsel.
19. YEAR 2000 ISSUE
The year 2000 (Y2K) issue is a result of computer programs tracking and storing dates represented by only two century digits (e.g., 98 rather than 1998) to define the applicable year. Without the century digits information technology (IT) and non-IT systems that have time-sensitive software may recognize the date denoted by "00" as the year 1900 or some other date rather than the year 2000, which could result in miscalculations and systems failures. System failures resulting from the Y2K issue could adversely affect operations and financial results. Gulf's primary risk lies in its internal date-dependent systems, including computer hardware, software and field control devices. The Company is also exposed to third-party risk through its financial institutions, joint interest partners, public and private infrastructure services, including power, water, product transportation systems (pipelines, railcars and tankers), and telecommunications, and other vendors and customers whose systems may be affected by the Y2K issue.
Gulf is devoting significant resources to the Y2K issue. The Company's goal is business continuity and sustained operations beyond December 31, 1999, without significant disruption or material financial impact resulting from the Y2K issue. Gulf has organized a worldwide task force, which reports regularly to the Audit Committee and the Board of Directors, to identify potential impacts and risks, make appropriate preparations and allocate resources.
The Company believes that its greatest risk involves potential disruptions internationally where Gulf relies on vendors and customers who may fail to take adequate steps to address the Y2K issue. During 1999, the Company will continue to expand its efforts to ensure that its key business partners, vendors and customers are prepared for the year 2000, and to develop contingency plans to address any failures on their part to become Y2K compliant. Such failures could affect the operations of Gulf and its subsidiaries, either directly or indirectly, in a significant manner. Gulf cannot at present estimate either the likelihood or the potential cost of such failures.
20. PENSION PLANS
Defined benefit pensions at retirement are related to years of service and remuneration during the last years of employment. Funds are deposited with a trustee over periods permitted by regulatory authorities. These funds are invested primarily in publicly traded fixed-income and equity securities. Actuarial reports are prepared annually by independent actuaries for accounting and funding purposes.
For the years 1996 to 1998, assumed future rates of return on assets (net of administrative expenses), discount rates used to estimate projected benefit obligations of the plan and long-term average salary and wage escalation rates were as follows:
At December 31, 1998, the assumed future rate of return on assets of the plan, net of administration expenses, was reduced to 5.75 per cent. Estimated projected benefit obligations of the plans were determined using a discount rate of 5.75 per cent and a long-term salary and wage escalation rate averaging 2.5 per cent.
The actuarial fair values of pension assets and benefit obligations are as follows:
[FN] (a) Gulf uses the market value method of asset valuation.
(b) At December 31, 1998, the plan held 1,744,000 ordinary shares of Gulf valued at $7.8 million. Also, 1,000,000 Gulf ordinary stock warrants expired at December 31, 1998, at no value, previously valued at $4.4 million.
In December 1997, the Company started a program of annuitizing the plan's pension obligations with major life insurance companies. The program is being implemented on a phased basis and is anticipated to be completed over the next two years. The first phase, implemented in December 1997, involved annuity purchases settling pension obligations of $48 million, and the second phase, implemented in December 1998, settled pension obligations of $52 million. The amounts and timing of phases are at the Company's discretion and will depend on market conditions.
Both the rate of return on a portion of plan assets and the discount rate for plan obligations are related to market interest rates, and therefore both the value of assets and benefit obligations are affected by changes in such rates. At December 31, 1998, approximately 75 per cent of the plan's assets consisted of fixed-income securities with an average maturity of about 16 years, which approximates the term and interest rate exposure of the obligations.
In 1993, the Company's pension plan was amended to give Gulf's active Canadian employees the option to accrue future benefits under a defined contribution alternative. All new employees accrue future benefits on a defined contribution basis. At December 31, 1998, 93 per cent of employees were members within the defined contribution option.
The Company's pension expense for both the defined benefit and the defined contribution components of the plan was $6 million, $6 million and $8 million for the years ended December 31, 1998, 1997 and 1996, respectively. In addition, deferred pension costs of $6 million ($53 million in 1997) were charged to earnings relating to the annuitization of the plan's pension obligations.
The Company also administers a defined benefit pension plan for employees of Clyde Petroleum plc. The market value of assets and projected benefit obligations of that plan were L.13 million and L.9 million, respectively, at December 31, 1998. Estimated projected benefit obligations of the plans were determined using a discount rate of 5.25 per cent and a long-term salary and wage escalation rate of 3.25 per cent.
Additionally, the Company has a 9.03% interest in the defined benefit pension plan of the Syncrude joint venture. Gulf's proportionate share of the market value of assets and projected benefit obligations of that plan were $58 million and $53 million, respectively, at December 31, 1998, ($53 million and $48 million, respectively, at December 31, 1997).
21. RELATED PARTY TRANSACTIONS
Gulf holds all of the Preferred Shares of Athabasca Oil Sands Investments Inc. ("Athabasca"), entitling Gulf to elect two of the directors of Athabasca. Gulf also has agreements with Athabasca for the provision of administrative and marketing services. Revenue from such services was $2 million in 1998, $3 million in 1997 and $2 million in 1996.
Effective January 1, 1998, Gulf acquired a 50 per cent interest and joint control of Tidal Energy Marketing Inc. ("Tidal"). Gulf has an $11 million receivable from the other investor in Tidal as at December 31, 1998.
On December 18, 1998, Gulf acquired approximately 50 per cent interest and joint control of Gulf Midstream Services Partnership and GMS Facilities Ltd. (collectively "GMS"). GMS then paid Gulf $100 million subject to which Gulf has an obligation either to reinvest this amount in GMS by December 5, 2001, or to surrender an additional 19.7 per cent ownership interest to the unrelated investor in GMS. This obligation is classified in other long-term liabilities.
22. SEGMENT INFORMATION
[FN] (a) Included in the North America oil and gas segment is the following information pertaining to the United States
[FN] (b) Other North America includes frontiers, pipelines, contract drilling and other.
(c) Approximately $193 million of revenues was derived from sales to two customers in the year ended December 31, 1998, (1997 -- $309 million and 1996 -- $237 million).
There were no intersegment transfers of product.
Included in earnings (loss) from continuing operations are export sales of $168 million, $213 million and $315 million in 1998, 1997 and 1996, respectively.
23. UNITED STATES ACCOUNTING PRINCIPLES AND U.S. DOLLAR SUMMARY INFORMATION
If United States generally accepted accounting principles (U.S. GAAP) had been followed, the earnings (loss) and earnings (loss) per ordinary share would have been as follows:
STATEMENT OF COMPREHENSIVE INCOME
If U.S. GAAP had been followed, cash generated from continuing operations would have been as follows:
The Consolidated Statements of Cash Flows presented under Canadian GAAP comply with International Accounting Standard 7, except as noted in (d) below and that the $702 million of equity issued in 1997 in connection with the acquisition of Stampeder would not have been reflected.
If U.S. GAAP were followed, amounts on the Consolidated Statements of Financial Position would be adjusted as follows:
The financial statements have been prepared in accordance with accounting principles generally accepted in Canada (Canadian GAAP), which, in the case of Gulf, conform in all material respects with those in the United States except that:
(a) The financial statements would reflect the following effects of adopting Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes.
1. SFAS 109 requires a restatement, to pre-tax amounts, of the new asset values reflected in the accounts in connection with the change of control in 1986 of Gulf Canada Limited and the acquisition of new subsidiaries. This restatement, along with differences between the tax bases and recorded amounts of other asset transfers, would result in property, plant and equipment (PP&E) and deferred income taxes both being $1,074 million higher than under Canadian GAAP at December 31, 1998, (1997 -- $1,313 million). These differences are amortized to earnings over the lives of the related assets. The application of previous accounting standards at the time of the change in control results in ordinary share capital being lower by $89 million (1997 -- $89 million).
2. Measurement and presentation of deferred income taxes according to SFAS 109 would result in recording current and non-current deferred tax assets and liabilities, for a net increase in the deferred tax liability of $77 million at December 31, 1998, (1997 -- a net increase of $94 million).
(b) A special purpose entity has $200 million 11 per cent public debentures issued and outstanding that mature on October 31, 2000, and assets consisting of a $200 million oil-indexed debenture maturing on October 31, 2000 and an interest rate swap. These are not included in Gulf's statement of financial position, but under U.S. GAAP would have been included in long-term debt and investments and other assets, respectively. Amortization of a provision for losses on a related swap agreement of $9 million in 1998, $9 million in 1997 and $8 million in 1996 would not have been recorded under U.S. GAAP.
(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 under U.S. GAAP. The balances of such deferred losses were $206 million at December 31, 1998, $139 million at December 31, 1997, and $72 million at December 31, 1996.
(d) Under U.S. GAAP a liability for non-contractual involuntary employee termination benefits is not incurred until their terms are communicated to the affected employees. Under Canadian GAAP, the liability is recorded when the company makes the termination decision. As such, under U.S. GAAP, the liability recorded prior to employees being notified is reversed and recognized in the year of notification.
(e) Under U.S. GAAP the costs of providing all forms of post-retirement benefits to employees are recognized over the active service life of the employees rather than as incurred. The accrued cost of such benefits other than pensions at December 31, 1998, is estimated to be $43 million using a discount rate of 6.0%. The difference between the net periodic service cost under U.S. GAAP and the cash basis amount under Canadian GAAP is $1 million for the year ended December 31, 1998, and $1 million for the year ended December 31, 1997.
(f) U.S. GAAP requires that impaired assets be written down to fair value, rather than undiscounted future cash flows from use. Accordingly, Gulf would have recognized an additional write-down of $123 million.
(g) Under U.S. GAAP an unrealized holding loss on equity securities of $19 million recognized in 1998 would be reported in other comprehensive income rather than earnings.
(h) Under U.S. GAAP, as at December 31, 1998, an additional minimum pension liability of $16 million must be accrued for the deficit between the market value of the Company's pension plan assets and its accumulated benefit obligations. The charge to equity is reflected in other comprehensive income.
(i) For U.S. GAAP the Company has adopted SFAS 130, "Reporting Comprehensive Income," which establishes standards for reporting and display of certain components of changes in equity that arise from non-owner sources. The 1997 statement of financial position has been restated to reflect the new presentation.
SUMMARY FINANCIAL INFORMATION IN U.S. DOLLARS
The following information is based on U.S. GAAP and translated from Canadian into U.S. dollars at the average exchange rates for each of the years presented.
INTEREST AND INCOME TAXES PAID
INCOME TAXES
COMPONENTS OF DEFERRED INCOME TAXES: The net deferred tax liability (current and non-current) comprises:
(a) The expiration dates of tax credit carry forwards as at December 31, 1998 are:
The Company will utilize $26 million of tax credit carry forwards in the 1997-98 tax returns.
COMPONENTS OF INCOME TAX EXPENSE (RECOVERY): Income tax expense (recovery) attributable to continuing operations comprises:
Income tax expense (benefit) attributable to other comprehensive income is related to the following components:
For the year ended December 31, 1998, there was a $62 million reduction in the deferred tax liability related to the disposal of a subsidiary.
STOCK-BASED COMPENSATION PLANS
Pro forma disclosures of earnings and earnings per share are presented below as if the Company had adopted the cost recognition requirements under SFAS No. 123, Accounting for Stock Based Compensation. The compensation expense for the stock-based compensation was $33 million for 1998, $25 million for 1997 and $8 million for 1996. Pro forma disclosures are not likely to be representative of the effects on reported earnings for future years.
The Company has a fixed-option plan. Pursuant to the terms of the Incentive Stock Option Plan (1994), the Company may grant options to its employees for up to 21 million shares of common stock. Options outstanding are granted at prices equal to the market value of the stock on the date of grant, and an option's maximum term is 10 years. Options are granted during the year, and they vest from one to three years after issue.
The fair value of each option granted during 1998, 1997 and 1996 is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: expected volatility of 42 per cent; risk-free interest rate of 5 per cent; no payment of common share dividends; and expected life of 4.07 years.
PENSION PLANS
[FN] (a) The prescribed year-end settlement rate for discounting purposes was 6.0% in 1998 (6.4% in 1997 and 7.5% in 1996).The assumptions for rate of return on assets, and wage and salary escalation were the same as those used for Canadian GAAP purposes.
(b) Includes $6 million of settlement costs related to the 1998 annuity purchase, which settled a portion of the retiree pension obligation.
POST RETIREMENT BENEFITS OTHER THAN PENSIONS
The company is obligated to provide post-retirement benefits other than pensions to all regular employees who have retired on or before April 1, 1996. The cost of this plan is funded annually out of general revenues and includes such benefits as life insurance, dental coverage, supplementary health benefits and the subsidy of certain provincial health care premiums.
[FN] (a) The health care cost trend rate is estimated to decrease from 8.5% in 1998 to 6.5% for the years 2002 and thereafter. The discount rates used to value post-retirement benefits other than pensions are the same as those used to value Gulf's pension obligations.
A 1% charge in the assumed health care cost trend rate would have the following effects on 1998 service and interest cost, and the benefit obligation at December 31, 1998:
FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK
The Canadian GAAP financial statements do not include the assets and liabilities of a special purpose entity. The carrying amount and fair value of these financial instruments are as follows:
The following methods and assumptions were used in estimating the fair values of these financial instruments:
Oil-indexed debenture: Fair values are estimated using discounted cash flow analysis based on the applicable current incremental borrowing rate. Income on the variable-rate portion of interest is estimated based on a forecast of the average quarterly price of West Texas Intermediate crude oil.
11 per cent debentures: Fair values are estimated using discounted cash flow analysis based on current incremental borrowing rates for similar borrowing arrangements.
Interest rate swap: Fair values are estimated based on quoted market prices of comparable contracts.
FOREIGN CURRENCY TRANSACTIONS
The aggregate foreign currency transaction loss included in net income for the year ended December 31, 1998, is $164 million (1997 -- $75 million; 1996 -- $5 million).
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
NEW STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS
In June 1998, SFAS 133, Accounting for Derivative Instruments and Hedging Activities, was issued. Adoption of this standard is required in the first quarter of 2000. SFAS 133 requires that all derivatives be recognized as either assets or liabilities and measured at fair value. If certain conditions are met, a derivative may be specifically designated as a hedge of risk exposure. Gulf is currently reviewing the expected impact of SFAS 133, which will depend on the derivatives outstanding when it is adopted and is not expected to be significant.
24. RECLASSIFICATIONS
To conform with the presentation adopted in 1998, certain amounts have been reclassified in 1997 and 1996 as follows:
SUPPLEMENTAL INFORMATION FIVE-YEAR FINANCIAL SUMMARY
[FN] (1) 1997 includes payment of regular and special dividends on preference shares.
(2) Includes Series 1 preference shares of $428 million and Series 2 preference shares of $149 million in each of 1994 through 1998.
(3) Certain of the financial data for years prior to 1998 have been reclassified to conform with the presentation adopted for 1998.
SUPPLEMENTAL INFORMATION FIVE-YEAR OPERATING SUMMARY
[FN] (1) "Gross" sales include royalties; "net" sales are after royalties. Volumes are adjusted for:
SUPPLEMENTAL INFORMATION QUARTERLY SUMMARIES
[FN] (1) Ordinary share dividends were discontinued in 1992. Preference share dividends, suspended in 1993, were reinstated in February 1995. By November 1997, all dividend arrears had been paid off.
(2) Dividends paid on shares owned by non-residents of Canada are generally subject to 25 per cent withholding tax. However, for recipients to whom the existing tax treaty between the United States and Canada is applicable, the rate is 15 per cent.
SUPPLEMENTAL INFORMATION QUARTERLY SUMMARIES
[FN] (1) Ordinary share dividends were discontinued in 1992. Preference share dividends, suspended in 1993, were reinstated in February 1995. By November 1997, all dividend arrears had been paid off.
(2) Dividends paid on shares owned by non-residents of Canada are generally subject to 25 per cent withholding tax. However, for recipients to whom the existing tax treaty between the United States and Canada is applicable, the rate is 15 per cent.
SUPPLEMENTAL INFORMATION LAND INVENTORY
[FN] * Includes oil sand leases and other designated heavy oil properties in Alberta and Saskatchewan.
"Gross" refers to land or wells in which Gulf owns an interest; "net" is the sum of the fractional interests owned by Gulf in gross lands or wells.
SUPPLEMENTAL INFORMATION WELLS DRILLED
[FN] "Gross" refers to land or wells in which Gulf owns an interest; "net" is the sum of the fractional interests owned by Gulf in gross lands or wells.
SUPPLEMENTAL INFORMATION
[FN] (1) Does not include reduction in carrying value of assets
[FN] (1) Includes amounts for capitalized injection of $15 million, $18 million and $10 million for 1998, 1997 and 1996, respectively
[FN] (1) Unproved properties includes $329 million for frontier areas.
SUPPLEMENTAL INFORMATION STANDARDIZED MEASURE
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES.(1) 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 FASB.
Accordingly, the estimated future net cash inflows were computed by applying selling prices prevailing at December 31 for crude oil and during the month of December 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 year 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, there are numerous other equally valid assumptions under which these estimates could be made that would produce significantly different results.
[FN] (1) PROVED RESERVES AND, THEREFORE, RELATED NET CASH FLOWS FROM GULF'S 9.03 PER CENT INTEREST IN THE SYNCRUDE PROJECT ARE NOT INCLUDED IN THE STANDARDIZED MEASURE CALCULATION.
CHANGES IN THE STANDARDIZED MEASURE DURING THE YEAR
[FN] (1) Under SFAS 69, additions due to "Other" would be considered part of revisions of previous quantity and timing estimates.
SUPPLEMENTAL INFORMATION RESERVES
[FN] (1) "Gross" reserves are before deduction of royalties. "Net" reserves are after deduction of royalties, which vary depending on prices, production rates and legislative changes. "Proved" reserves are those that appear with reasonable certainty to be recoverable under existing economic and operating conditions.
(2) "Proved plus probable" reserves are those that appear with reasonable certainty to be recoverable under existing and anticipated economic conditions plus that judgment portion of contiguous reserves that are interpreted to exist, from geological, engineering or similar information, with reasonable certainty.
GULF CANADA RESOURCES LIMITED EMPLOYEES
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Information required by this item will be included in the Company's proxy statement for its 1999 Annual and Special Meeting which will be filed with the SEC within 120 days after December 31, 1998, and is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item will be included in the Company's proxy statement for its 1999 Annual and Special Meeting, and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item will be included in the Company's proxy statement for its 1999 Annual and Special Meeting, and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item will be included in the Company's proxy statement for its 1999 Annual and Special Meeting, and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
GULF CANADA RESOURCES LIMITED
By: /s/ RICHARD H. AUCHINLECK -------------------------------- Name: Richard H. Auchinleck Title: Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
EXHIBIT INDEX