David H. KnappThe unexpected growth in oil supplies from outside the Organization of Petroleum Exporting Countries over the last few years and the likelihood of a continuation in this trend for the next several years have altered the standard view of the evolution of medium term oil supply-demand fundamentals. The traditional view was that near term peaks, particularly in the North Sea, and accelerating declines in mature areas, such as North America, would tilt the balance toward a rapid increase in the call on OPEC crude oil plus stock change.
International Energy Agency
Paris
During the first half of the 1990s, a precipitous decline in production from Russia effectively concealed the upward trends developing in many areas of the world as technological advances were allowing increased profits despite a relatively flat trajectory for world oil prices. With the bottoming out of the production decline in Russia in the mid-1990s, as can be seen from Fig. 1, (20211 bytes) the positive supply trends are becoming more prominent.
The impact of the expected non-OPEC supply growth and a projected 500,000 b/d increase in OPEC NGL production, from 2.6 million b/d in 1996 to 3.1 million b/d in 2000, implies a call on OPEC oil plus stock change on the order of 26-28 million b/d in 2000, well within the range of planned OPEC crude oil capacity. However, it is expected that, longer term, non-OPEC supply will not continue to increase and that the call on OPEC crude oil will increase significantly sometime after 2000.
Between 1990 and 1995, aggregate non-OPEC supply is estimated to have remained essentially unchanged, as a 4.3 million b/d decline in production from the Former Soviet Union (FSU), primarily Russia, was offset by increases of around 2.4 million b/d in member countries of the Organisation for Economic Cooperation and Development, 2 million b/d in non-OPEC developing countries outside of the FSU, and 250,000 b/d in refinery processing gains. Growth in the second half of the decade is expected to slow in the OECD due to accelerating declines in mature U.S. regions and a peak for the North Sea near the end of the decade, but production gains in the developing countries of Latin America, Asia, and Africa are projected to be even greater between 1995 and 2000 than between 1990 and 1995.
Most important, however, is the swing in FSU output, which is expected to increase by just over 1 million b/d in the next 5 years, with about half of the increase from Russia and half from the other republics, notably Kazakhstan. Aggregate non-OPEC supply is projected to increase from an estimated 42.3 million b/d in 1995 to 47.8 million b/d in 2000 (Table 1)(12568 bytes).
The projections for non-OPEC supply reflect a most-likely case; however, as demonstrated in the last 5 years, there is clearly considerable scope for error in predicting the next 5 years.
OECD outlook
The pattern of OECD production is characterized by conflicting trends among and within the key producing areas. U.S. production is expected to decline by more than 500,000 b/d over the next 5 years, while North Sea output is projected to be 1.4 million b/d higher in 2000 despite its peaking in 1998-99. Australias production is likewise seen rising in the near term and holding at a plateau level about 220,000 b/d above 1995 levels. Total Canadian production, which added 430,000 b/d in the first half of the decade is expected to hold relatively steady over the next 5 years (Tables 2(20732 bytes)- (26686 bytes)4)(25397 bytes).
In the U.S. and Australia, declines in older fields are partially offset in the first case and fully offset in the second case by increases in production from new offshore fields in the Gulf of Mexico and the Northwest Shelf/Timor Gap, respectively. New offshore production from the Canadian Atlantic Offshore is also seen contributing to the balancing of declines in mature conventional Western Canadian fields (Fig. 2)(30258 bytes).
U.S. patterns
Total U.S. oil production is expected to average 8.65 million b/d in 1995, about equal to 1994 but 345,000 b/d below 1990 production. Average annual declines on the order of 4% for onshore Texas and around 3% for Alaska and other Lower 48 states more than offset the 5%/year growth rates in the Gulf of Mexico and in NGL and other hydrocarbon output.
In the second half of the decade, decline rates in Texas and Alaska are expected to approach 10% and 5%, respectively, while other Lower 48 states are projected to decline by 5%. However, the overall decline rate in U.S. oil supply is only expected to be around 1% due to rapid development of deepwater Gulf of Mexico fields.
Over 800,000 b/d in new production is anticipated from nearly a dozen fields currently being developed. Total Gulf of Mexico crude oil supply is expected to reach 1.86 million b/d by 2000 and could be higher if the recent experiences in the North Sea are repeated there. With the addition of a small amount (about 90,000 b/d) of incremental NGL and other hydrocarbon supplies, total U.S. oil supply remains just over 8 million b/d in 2000.
Canadas growth
For Canada, a reversal in the growth shown in conventional crude oil over the last 5 years is anticipated, but growth in frontier areas, NGLs, and synthetics is projected to more than compensate for the declines.
Aggregate Canadian output is expected to increase marginally from 2.4 million b/d in 1995 to 2.45 million b/d in 2000. Conventional crude production, primarily from Alberta and Saskatchewan, is seen 235,000 b/d lower in 2000, a modest 3.7% annual decline rate. That decline is mostly offset by a 120,000 b/d gain in NGL production and 110,000 b/d more oil from frontier areas, predominantly due to the start-up of the Hibernia field in the Atlantic offshore in 1997-98.
Production from the two synthetic crude oil plants, Syncrude and Suncor, is expected to expand slowly from about 275,000 b/d in 1995 to 335,000 b/d in 2000 due to better operating efficiencies and development of small but increasingly remote deposits.
Mexican prospects
The third component of OECD North America oil production is Mexico, which joined the OECD in May 1994. Mexican oil production has increased relatively slowly despite a high level of reserves, with less than 130,000 b/d of crude oil production being added between 1990 and 1994. Growth in NGL production contributed another 35,000 b/d, bringing total 1994 oil production to 3.14 million b/d.
Due to the effects of damage from hurricanes in fourth quarter 1995 and an NGL pipeline explosion in February, Mexican output is expected to be depressed in 1995, averaging just under 3.1 million b/dor 50,000 b/d below 1994 levels. A recovery in offshore output in 1996 and development of new fields in the Gulf of Campeche are expected to add 340,000 b/d to offshore output by 2000.
Mature onshore production is projected to decline at an average annual rate of 0.7%, but NGL production is expected to grow by 5%/year, adding 135,000 b/d to Mexican oil output over the next 5 years.
North Sea gains
Non-OPEC oil supply growth in the mid-1990s is being dominated by the expansion in North Sea oil supplies. After growing by more than 900,000 b/d in 1994, increases of 415,000 b/d and 750,000 b/d are projected for 1995 and 1996, resulting in a total increment between 1993 and 1996 of over 2 million b/dand this from an area that had once been thought to be fully mature and in decline by the mid-1990s.
The use of existing infrastructure and improvements in exploration and production technologies have led to substantially lower costs, which have combined with more attractive tax regimes and leasing policies and a high level of familiarity with the regions geological and fiscal environments to generate a surprisingly successful record in developing oil supplies. The combined contributions of a large number of small satellite fields, primarily in the U.K. sector, and a few large fields off Norway are expected to maintain the upward track in North Sea oil supplies for 3 more years, with gains of 440,000 b/d in 1997, 475,000 b/d in 1998, and 80,000 b/d in 1999 before a decline of nearly 300,000 b/d in 2000.
The projected peak in North Sea crude oil output in 1999 exceeds 7.1 million b/d plus 520,000 b/d of NGL production. Subsequently, rapid declines in older oil fields, especially Norways three largest, and anticipated delays in the development of combination oil and gas fields due to an oversupplied European natural gas market are projected to cause a decline to 6.98 million b/d for 2000 North Sea crude oil production.
In the U.K. sector, the largest share of the incremental production has been associated with Forties system satellite fields, which accounted for virtually all of the 700,000 b/d increase in crude oil production between 1990 and 1995. In the second half of the decade, the gains will come from a number of new areas such as the West of Shetlands, Liverpool Bay, the J-Block, the Teal area, and Eastern Trough Area Project and more than a dozen individual fields developed with floating production systems.
Existing fields in the four major systems, Brent, Forties, Ninian, and Flotta, and the smaller Fulmar and Beryl offshore-loaded systems are expected to decline at rates of 5-10%/year, offsetting a combined 450,000 b/d of over 900,000 b/d in new field production. As opposed to the first half of the decade, only about 90,000 b/d of the 900,000 b/d is expected to be from satellite fields tied to the four major systems.
NGL production is projected rising from 275,000 b/d in 1995 to 375,000 b/d in 2000 as a substantial number of new natural gas and gas/condensate fields are brought on stream. The total 5 year increment to U.K. liquids production of 750,000 b/d is about 140,000 b/d lower in the second half of the 1990s than in the first half.
The outlook for Norway is characterized by both more rapid declines in the major fields and by a small number of large new fields, as opposed to the numerous relatively small fields being developed in the U.K. sector. The 730,000 b/d growth in Norwegian production between 1995 and 2000 is dominated by the Haltenbanken area, which is expected to add 685,000 b/d over the next 5 years from the 1993-vintage Draugen field, the recently started Heidrun field, the Norne field currently under development and scheduled for production in mid-1997, and the Aasgard area fields expected toward the end of the decade.
The decline rate for the existing Statfjord/Gullfaks area fields is expected to be much larger than for the older fields in the U.K. systems, averaging more than 18%/year for the 1995-2000 period, with very sharp decreases at the end of the period.
The Oseberg field should also be starting a rapid decline in oil production around the turn of the century. The field has been subjected to a very aggressive gas flood using gas from the Troll field TOGI project, and the gas is likely to begin reaching many of the well bores at that time. Oseberg liquids production will drop off very fast during the first few years of the next decade.
A small contribution is expected from the Danish sector, where increased water injection in the Gorm and Dan complexes and new satellite fields tied back to the Tyra platform are projected to raise Denmarks oil production from the current 185,000 b/d level to 200,000 b/d by 1999 and hold it there for the first few years of the next century. As with the Oseberg field, the resulting advancement of production through injection is expected to be reflected in precipitous declines by 2005.
Contrary to the Norwegian situation, however, there appear to be limited opportunities for new field discoveries in the Danish sector to offset the expected declines in known fields. No new oil field developments are currently proposed for the Dutch or German offshore sectors, and production is expected to decline steadily over the next 5 years.
Other OECD
Other OECD oil production is dominated by Australia, which produces more than half of the OECD oil outside of North America and the North Sea.
The oil production profile for Australia has been relatively flat during the first half of the 1990s, with declines in the mature Gippsland and Cooper basins balancing gains in Northwest Australia. In recent months, the Northwest Shelf area has passed the Gippsland basin as Australias largest producing area, and rapid growth in output from the Wanaea-Cossack floating production system and expansions at Wandoo, Goodwyn, Thevenard Island, and the Griffen fields is expected to add over 100,000 b/d to 1996 production levels.
Production increments from the Timor Gap area at the Laminaria, Elang, and other fields should keep Australian production above 800,000 b/d in 2000, despite declines of 5.5%/year in the Gippsland basin and about 2%/year in the Cooper-Eromanga basin.
Production from the other two Pacific region OECD members, New Zealand and Japan, is relatively small and is expected to remain relatively constant.
The two noticeable bright spots for onshore European oil development appear to be in south-central Italy and the U.K.s Wytch Farm onshore/offshore field in southern England. Total oil output from the continental Europe states has averaged around 400,000 b/d in the mid-1990s, plus about 100,000 b/d from the U.K. onshore. Output is expected to grow by about 55,000 b/d by 2000 as gains of 80,000 b/d and 20,000 b/d in Italy and onshore U.K. more than offset declines in most of the rest of continental Europe.
The Val dAgri area and surrounding prospective areas in the southern Apennines of Italy are sufficiently attractive to have generated a proposal for a 100,000 b/d pipeline from the region to the Taranto refinery.
Non-OPEC developing countries
The pattern of growth in the developing countries is expected to show accelerating gains in Latin America and Africa but a plateauing in Asia and non-OPEC Middle Eastern producers (Fig. 3)(24091 bytes). However, near-term increases are projected for all four regions at rates at least as great as in the early part of the 1990s. Production in central and eastern Europe (not shown in figure) is expected to remain below 300,000 b/d (Table 5).
Non-OPEC Latin America
Latin America is expected to contribute the largest share to non-OPEC developing-country oil, with production gains from Brazil, Colombia, and Ecuador dominating the increase. Total oil output (excluding Mexico) is projected to top 4 million b/d by 2000 vs. 2.86 million b/d in 1995.
Crude oil production rates from Brazil and Colombia are each seen exceeding 1 million b/d, with Brazils reaching nearly 1.5 million b/d. Prospects for Ecuador and Argentina are less encouraging, but the former is expected to eventually be able to complete a pipeline refurbishment and expansion project across the Andes that will permit a rise of about 100,000 b/d to 485,000 b/d over the next 5 years.
Argentine production is thought to have less potential given the relative maturity of the onshore production base and the early stage of exploration in the Malvinas Straits. With some growth in NGL production related to natural gas development, overall Argentine production is seen increasing only by 25,000 b/d between 1995 and 2000.
The expansion in Brazilian output is centered in the deepwater Campos basin area, especially in the Marlim field complex. When development plans for the field are completed in 1997-98, output from the Marlim field should exceed 500,000 b/d, higher than that of the largest North Sea fields.
Other developments in the Campos basin and in the Santos basin offshore Sao Paulo will bring total crude oil production to nearly 1.2 million b/d by 1998 and 1.5 million b/d by 2000. A small decline in the production of Brazilian alcohol fuels is expected to be offset by higher NGL production, with combined noncrude oil output remaining around 230,000 b/d.
The prospective Colombian production increases are from the current Cusiana-Cupiagua development in the Santa Atalayas area and exploitation later in the decade of the prodigious condensate reserves in the Pauto and Florena deposit overlying the giant Volcanero gas field. The full potential of the Cusiana field is awaiting construction of a major pipeline from east-central Colombia to the port of Covenas, expected to come into service in the 1997-98 time frame and to handle about 500,000 b/d of crude oil.
Production from the mature 200,000 b/d Cano Limon field appears to be in decline, as are many of the other older fields operated by national oil company Ecopetrol and by a number of foreign concessionaires. However, it is felt that there are highly prospective additional new areas along the same trend that yielded Cusiana and Volcanera.
Non-OPEC Africa
The second largest source of oil supply growth among the major developing country regions in the second half of the 1990s is Africa, which had made only a 200,000 b/d contribution to the growth in the first half of the 1990s. Incremental oil production between 1995 and 2000 is expected to be almost triple that amount, with total African oil production reaching 2.85 million b/d.
Production from the dominant producer, Egypt, is seen increasing marginally, as new Gulf of Suez and Western Desert fields offset declines in mature fields. Sizable increases are likely to continue in Angola, driven in the short term by restart of the onshore Soyo region fields and the expansion of shallower-water offshore fields. Over the medium term, development of deeper-water tracts is seen continuing the growth, with Angolan production gaining more than 100,000 b/d between 1995 and 2000.
Offshore developments in the Congo, around the NKossa platform to be put in service in mid-1996, are expected to add nearly 100,00 b/d as well. Another offshore West Africa development worth noting is Equatorial Guineas 40,000 b/d Zafiro field.
Besides the Zafiro development, several currently nonproducing or marginally producing, non-OPEC African states are expected to make significant contributions to Africas 2000 oil production. The two largest are Chad and the Sudan, each of which appear to have the potential to become 100,000+ b/d producers if pipeline construction hurdles are overcome. The Ivory Coast is returning as a moderate producer, and South Africa has a few offshore developments in process. The total contribution from the smaller African producers is projected to reach 550,000 b/d by 2000, nearly 300,000 b/d above current levels.
Non-OPEC Asia
Growth in non-OPEC Asian output is expected to be much lower in the next 5 years than in the first half of the decade, primarily because of the expected peaking and rapid decline of Papua New Guinea and slower growth in Viet Namese oil production. The increase between 1990 and 1995 exceeded 600,000 b/d, while the future gain is judged to be less than 400,000 b/d.
Relatively steady growth is projected for Asias largest oil producer, China, as developments in western China and the offshore areas more than compensate for small declines in some of the eastern onshore fields. Importantly, new drilling and injection technologies are allowing higher recovery rates from the thin oil-bearing sands that characterize the Daqing region, which produces nearly 40% of Chinas oil. Output from Daqing is expected to be held roughly constant over the next 5 years with increased water flooding and directional drilling projects.
Full development of the Tarim, Turpan-Hami, and Junggar basins in western Xinjiang Province depends on the construction of major long distance pipeline links to eastern consuming regions, which are not expected to be fully completed by 2000. But local use and expansion of current rail and pipeline capacity is seen allowing for moderate expansion over the next 5 years.
The recent turnaround in prospects for the Bohai Gulf and the ongoing development of the South China Sea suggest a growing contribution from the Chinese offshore as well.
The net increment between 1995 and 2000 of 220,000 b/d matches the expansion seen in the first half of the decade.
Malaysian and Viet Namese production are both likely to be higher in 2000, by 70,000 b/d and 75,000 b/d respectively, but production in India is expected to peak within the next few years and drop to about 650,000 b/d by 2000.
Other non-OPEC areas
The contribution to non-OPEC supply growth in the second half of the decade from the non-OPEC Middle East and Eastern Europe is expected to be less than 100,000 b/d, with most of that coming in Yemen. Omani and Syrian production appear to have reached plateaus after expanding by a combined 400,000 b/d between 1990 and 1995. Some recovery in Eastern European production is expected as small increases from Hungary and Poland and higher NGL output compensate for declining Romanian production.
The FSU turnaround
The turnaround in FSU production is expected to be relatively modest by the year 2000 compared to the sharp declines in the first half of the decade. Production will grow at an average rate of 3.3%/year after declining by more than 9%/year during the first half of the 1990s (Table 6)(11387 bytes).
The modest projection is primarily the result of lags in the development of a constructive legislative and business environment in Russia and political difficulties in developing pipeline links to Kazakh and Azerbaijani oil deposits in and around the Caspian Sea. Among the other republics, Uzbekistan appears to have the best growth prospects. A 40% increase in Uzbek crude oil production so far in 1995 to over 100,000 b/d has helped turn around production in the other republics.
Turkmenistan has also shown increasing crude oil production this year. The growth in these two republics is expected to continue at least for the next few years (Fig. 4)(25971 bytes).
Russias outlook
Russian production has declined by over 4 million b/d since 1990, but the declines have decelerated substantially in the last 2 years. Output is projected to decline by less than 2.5% in 1996 vs. average annual declines of nearly 12% between 1990 and 1994.
Production by joint ventures increased substantially in 1995, to an estimated 275,000 b/d from around 180,000 b/d in 1994, and a gain to 300,000 b/d is forecast for 1996. Major additional increases would appear to be conditional on the passage of a production sharing law that is consistent with the general fiscal regime.
The development of several megaprojects, such as the three Sakhalin Island projects, the Western Siberian Priobskoye field, and several projects in the Timan-Pechora area of northern Russia, are not expected to be fully developed until the business environment becomes more supportive. This entails not only the passage of legislation but also enough experience with the operation of the system to warrant confidence that there is a fair and functional legal system. For the projects in Western Siberia and in Central Asia, pipeline access is also a major issue.
As a result of these unresolved issues, the growth path of Russian production is projected to show only a mild recovery in the latter part of the decade. Total output for 2000 remains under 6.7 million b/d, an increase of only 520,000 b/d from 1995 and only a little more than half of the peak level reached in 1988. About half of the increase comes from expansion of joint venture production, some of which is associated with the beginnings of a few of the megaprojects.
Most of the new companies created out of the old Rosneft production association are expected to have difficulties turning around production because of high water cuts in their dominant fields. There is also a near-term difficulty in finding capital to invest in upstream activities due to repayment of tax arrears accumulated over the last few years.
Kazakhstan
The situation in Kazakhstan is generally better than in Russia, but the lack of pipeline access is limiting production, especially from the prolific Tengiz area on the northeast shore of the Caspian Sea. Kazakhstan produced about 375,000 b/d in 1994, including 55,000 b/d of condensates from the giant Karachaganak deposit on the Russia border in northern Kazakhstan.
The estimated 1995 production of 420,000 b/d is expected to more than double by 2000 to over 850,000 b/d. The largest share of the gain is expected to come from the Tengiz area, but substantial increases are also projected for the Mangistau and Aktyubinsk areas and for Karachaganak condensate.
Azerbaijan
Production in Azerbaijan is expected to continue to decline in 1996, as plans for a pipeline route to the Black Sea are seen only slowly being brought to fruition. The large Chirag, Guneshli, Azeri, and Karabakh fields offshore from Baku will not be developed until the pipeline situation is fully resolved. The geology of the fields and their seismic stability are also an issue, suggesting a conservative view of the near term supply outlook for Azerbaijan.
Production averaged 195,000 b/d in 1994 and is expected to decline slightly in 1995 and 1996 to 175,000 b/d before increasing to around 310,000 b/d in 2000. Better circumstances could allow for more aggressive development of the offshore Azerbaijani oil fields and production in 2000 of twice the current forecast.
The Author
David H. Knapp, who holds a PhD in economics from the University of California, joined International Energy Agency in November 1993. He is responsible for monitoring oil supply events affecting the near and medium term oil market.
Before joining IEA, Knapp was president of Knapp Energy Economics & Technical Services, a U.S. consulting firm specializing in energy market analysis, energy policy assessments, geopolitical analysis, and litigation support for trade actions. Earlier, he served for 11 years as energy economist for Brown Brothers Harriman & Co., New York, and also worked at Chase Manhattan Bank and the U.S. Department of Energy.
Knapp is a charter member of International Association for Energy Economics and has served as vice-president for finance and president of the New York chapter. He is currently an appointed member of council for the U.S. Association for Energy Economics. Copyright 1995 Oil & Gas Journal. All Rights Reserved.
