WORLDWIDE PRODUCTION FALLS AS MARKET PLAYS ITS WILD CARDS

Worldwide production of crude oil and condensate fell slightly this year as the oil market began playing its wild cards.

Stagnant economies in Europe and Japan kept demand from rising despite a slow but steady recovery in the U.S. and solid growth elsewhere in the Asia-Pacific region.

Average oil production for the year slipped by 0.6% from 1992's average to 59.6 million b/d. Crude oil reserves increased. fractionally to 999.1 billion bbl, natural gas reserves by 2.7% to 5 quadrillion cu ft.

As expected, reemergence of surplus production capacity created tension among the world's major oil exporters and edginess among traders (OGJ, Dec. 28, 1992, p. 39) And the market's wild cards complicated the always rough efforts by the Organization of Petroleum Exporting Countries to balance supply and demand.

One of those Uncertainties was the former Soviet Union (FSU). Although production there continued to slide, exports remained strong because economic troubles depressed local demand. This unpredictable interplay of demand and exports will be a crucial factor in the market until economies and production--especially Russia's--stabilize.

In the third quarter, net FSU oil exports averaged 2.4 million b/d, according to estimates by the International Energy Agency. This is significant competition for OPEC from a source that might have exported much less if economies and demand had been more robust.

Meanwhile, production surged during the second half of the year in the North Sea, which meant even more oil in international trade. And it all happened while demand was sputtering.

At midyear, IEA was projecting, worldwide oil demand of 66.2 million b/d in the third quarter, 68.9 million b/d in the fourth quarter, and an average of 67.2 million b/d for the year.

The year's average at that level would have been 200,000 b/d more than the average for 1992.

But IEA had to reduce its second half 1993 projections as the industrialized world's economic problems held product consumption in check.

In its December Oil Market Report, IEA estimated demand at 65.9 million b/d in the third quarter, 68.2 million b/d in the fourth quarter, and 66.9 million b/d for the year--a 200,000 b/d decline from 1992's level contrasting with the gain of the same size it had expected just months earlier.

OPEC'S STRUGGLES

The world's most influential group of producers thus was squeezed from two directions in the second half of the year as markets shrunk and competition increased from non-OPEC sources.

The squeeze added to the difficulties OPEC was destined to face in 1993 since the end late in 1992 of a period of unusual balance in the market.

Iraq's invasion of Kuwait in August 1990 took 4.6 million b/d of oil out of international trade and allowed OPEC's other members to produce at nearly capacity rates. By late 1992, however, Kuwait had all , but restored its production to preinvasion levels, and OPEC was once more faced with the task of assigning production limits to its members to support the price of crude.

The challenge--a normal one for OPEC since its members control nearly all the world's discretionary production capacity--has intensified during the course of a politically complex year.

Through most of 1993, OPEC aligned its group quotas fairly accurately with outside estimates' of the call on its crude: 24.4 million b/d in the first quarter and 23.6 million b/d in the second and third quarters.

There were two problems. One was the lax demand and amount of non-OPEC oil in the market, which together kept the call on OPEC crude below projected levels and meant that any quota cheating by members simply aggravated a structural surplus.

The other problem was Kuwait, which needed oil revenues for war reconstruction, exempted itself from an implicit third quarter quota of 1.6 million b/d, and produced 2.16 million b/d instead. The action had the effect of pushing OPEC's third quarter quota to 24.1 million b/d. Even that level fell within the range of expectations for demand for OPEC crude in the third quarter--as they stood in June.

But it left no room for cheating by other members, and demand at any rate didn't match forecasts. By the time OPEC ministers met in September to discuss a fourth quarter quota, crude prices had declined by nearly $3/bbl since May.

The September meeting at first seemed like a triumph for OPEC. The group set a new production ceiling of 24.5 million b/d--a quota increase but a production cut if members complied, And compliance looked possible. For the first time in the year, Kuwait accepted the quota OPEC assigned it: 2 million b/d.

Impressive OPEC political maneuvering had little effect on the market, however. Prices continued to fall.

In an emergency meeting late in November, OPEC members looked again at production cuts but decided to leave the fourth quarter quota intact rather than jeopardize the delicate September accord. The decision meant that OPEC was favoring a minimum production level over a minimum which sent prices skid-ding again. During the first week of December, the spot price of Brent crude fell below $14.50/bbl.

REMAINING WILD CARD

A sustained price slump would jeopardize marginally economic production and perhaps delay start-up of new production in view at the end of 1993.

And a sustained slump isn't out of the question. Technological advances in the past few years have reduced costs of exploration, development, and production. Cost competition may be suppressing crude values.

Furthermore, noncrude inputs represent a growing share of internal refinery streams. Last winter in the U.S., refiners added an estimated 400,000 b/d of methyl tertiary butyl ether equivalent oxygenates to gasoline to meet Clean Air Act requirements. This year's amount will be greater. The volumes, net of processing changes, represent crude no longer needed at a given level of product demand. And the numbers will grow as oxygenate requirements spread in the U.S. and elsewhere.

But there's a remaining wild card that influenced oil trading psychology more than those structural changes did during 1993: Iraq.

Subject to an export embargo imposed by the United Nations since its invasion of Kuwait, Iraq has rebuilt and maintained production facilities but was able to produce only 436,000 b/d this year, up 11,000 b/d from its level of 1992. It was exporting some of the oil by truck.

A key question in the market--and a crucial factor for production elsewhere in the next few years--is when Iraqi oil will return to the market in significant amounts.

President Saddam Hussein recently has been more accommodating than at any time since the war to U.N. conditions for relaxation of the embargo. Thus, resurgent Iraqi production this year has come to be viewed as an imminent development rather than a distant prospect and played some role in the price slide of 1993's second half,

One question is whether Iraq will be allowed to ratchet up flow for 6 months to raise $1.6 billion for human needs or whether it will receive the go-ahead to resume normal market operations.

Under the limited option, it would produce about 740,000 b/d.

Without any U.N. limit, it probably could boost production to 2 million b/d fairly quickly, of which 1.5 million b/d would be exported. Beyond that, exportable production will be limited not just by field capacities but by capacities of available export outlets: the 1.2 million b/d pipeline through Turkey if Iraq can satisfy tariff demands and the 600,000 b/d Mina al-Bakr terminal. Saudi Arabia probably won't reopen the 1.5 million b/d pipeline through its territory.

The key question for worldwide production in 1994, therefore, is whether and when the Iraqi return comes about.

PRODUCTION LEADERS

Outside of OPEC, oil production fell by 1 million b/d from the 1992 average to 34.6 million b/d.

Production by the biggest non-OPEC producer dropped even more than that. Flow from the Commonwealth of Independent States--which in this report includes non-C.I.S. Georgia and Azerbaijan--sank by 1.1 million b/d to an estimated 7.8 million b/d.

And production from another major non-OPEC producer, the U.S., fell by 275,000 b/d to 6.9 million b/d.

The combined 1.4 million b/d production drop by the U.S. and C.I.S. follows a 1.8 million b/d decline in 1992.

And for all its late-year problems, OPEC managed to raise production this year by 636,000 b/d as a group following a 1 million b/d increase in 1992.

OPEC's share of total worldwide production thus gained a percentage point to 42% in 1992.

RESERVES CHANGES

As always, OPEC's domination of estimated worldwide reserves is even more pronounced.

Group members account for 77% of the world total for oil and 40% for natural gas.

Worldwide, reserves changes were scattered. Big volumetric gains from 1992 oil reserves estimates came in Saudi Arabia 861 million bbl, Venezuela 680 million bbl, Malaysia 600 million bbl, Brazil 570 million bbl, Norway 478 million bbl, Ecuador 414 million bbl, and the U.K. 411 million bbl.

The largest oil reserves decline came in the U.S.--937 million bbl. Mexico's reserves fell by 373 million bbl, Pakistan's by 209 million bbl. Other declines were less than 200 million bbl.

Estimated worldwide natural gas reserves rose by 131 tcf in 1993--a gain of nearly 3% and a reflection of rising exploratory interest in gas.

The mayor volumetric gains in gas reserves came in the C.I.S. 54.7 tcf, Iran 30.8 tcf, and Qatar 23 tcf. Individual country declines weren't nearly as large.

Oil reserves lives, as usual, were largest in the Middle East. The region's reserves/production ratio is an estimated 99 years.

Other regional oil reserves/production ratios, expressed in years, are Asia-Pacific 19, Western Europe 10, Eastern Europe and the C.I.S. 20, Africa 28, and Western Hemisphere 27.

The world's reserves/production ratio amounts to 46 years.

ASIA-PACIFIC

Upstart producers in the Asia-Pacific region scored big gains this year, offsetting declines in most of the traditional producing countries.

Among the latter group, China was the exception, managing a 2% production gain to 2.9 million b/d.

Further Chinese gains are in prospect. Following 14 years of disappointing offshore exploration by non-Chinese companies, the country this year opened onshore exploration to outsiders and opened bidding for the first time on acreage in the East China Sea. The onshore acreage includes the promising Tarim basin,

In addition, Amoco Orient Petroleum Co. and China Offshore Oil Nanhai East plan to develop the South China Sea's Liuhua 11-1 field with a floating production system that will be able to handle 300,600 b/d of fluids, including 65,000 b/d of oil.

Among the upstarts, Papua New Guinea raised production from 52,000 b/d to an estimated 125,000 b/d this year as Chevron Niugini Pty. Ltd. and partners brought the Kutubu export project on stream. The Kutubu complex is expected eventually to produce as much as 140,000 b/d.

Viet Nam's production rose to 123,000 b/d from 105,000 b/d, all from Bach Ho field.

Viet Nam is expected to produce more than 400,000 b/d by 2000 following development of Dai Hung field by a group led by BHP Petroleum Pty. Ltd.

Production in the Philippines averaged 10,000 b/d this year, nearly all of it from West Linapakan field. Vaalco Energy Inc., the operator, initially targeted production of 15,000-20,000 b/d from the field, which it brought on stream at 18,700 b/d, but had to limit output for reservoir management. It expects to increase flow in 1994 after reworking wells in which water production has begun to rise.

Most of Asia-Pacific's major producers have taken steps to reverse production declines evident this year.

Indonesia's oil production has slipped, but the country has made exploratory acreage available and tried to improve terms of its production sharing contracts.

Conoco Indonesia Ltd. and partners in October reported start of second phase production from Belida field in the South Natuna Sea. Output from the field is to peak next year at 100,000 b/d.

Among recent Indonesian discoveries that might yield significant future production are PT Caltex Pacific Indonesia 1 Asih, which flowed 2,353 b/d of oil in Sumatra south of Minas oil field, and Total 1 Nubi, which late in 1992 gauged a total of 2,850 b/d of liquids from four zones off eastern Kalimantan's Mahakam Delta.

In Malaysia, Occidental Petroleum (Malaysia) Ltd. has made four large gas discoveries on Block SK-8 off Sarawak and signed a production sharing contract with Petronas for an adjacent block.

Australia's production will receive a boost next year when BHP starts up giant Griffin oil field in the Carnarvon basin off Western Australia. Production will rise to 80,000 b/d of crude and 40 MMcfd of gas.

Western Australia, which has been encouraging oil and gas operations, soon will replace the Bass Strait as Australia's leading producing region. The government expects the region's crude and condensate production to triple to 350,000 b/d by 1996.

Brunei intentionally, capped oil production at 150,000 in 1988 but let it rise after the Persian Gulf conflict. Brunei Shell Petroleum Co. Sdn. Bhd. plans to raise production at offshore Champion field to 80,000 b/d from 70,000 b/d.

WESTERN EUROPE

The North Sea scored strong production gains in 1993, with Norway, as it did last year, leading the way.

The region is on track to increase output by 41% to 5.5 million b/d during 1991-95. In September, average North Sea production was 4.36 million b/d. Of that, 2.24 million b/d came from the Norwegian sector and 1.93 million b/d came from the U.K.

Production from the Danish North Sea set a record during the month at 120,000 b/d, the result of redevelopment of old fields. At the end of September, Dansk Undergrunds Consortium brought two small producers, Regnar and Valdemar, on stream.

Development activity in the North Sea has been brisk, with investment having peaked in 1992. In the U.K. sector, development projects will benefit from recent tax law changes.

Operators brought more than two dozen fields on stream this year in the British, Norwegian, Dutch, and Danish sectors (OGJ, Nov. 1, p. 24).

The list includes Scott oil field, where operator Amerada Hess Ltd. expects flow to peak at 200,000 b/d and make the field the largest to come on stream in the U.K. sector this decade.

In the Norwegian sector, Norske Shell AS started flow from Draugen oil field, the first commercial field on stream off central Norway. Plateau production of 95,000 b/d is expected by mid-1994.

Next year, Shell U.K. Exploration & Production and partners will start flow from Nelson oil field, one of the U.K. sector's largest discoveries in recent years. Flow is to start in March, rising to 135,000 b/d. Facilities can handle as much as 160,000 b/d of oil and 65 MMcfd Of gas.

In addition, redevelopment is scheduled for venerable Brent and Forties oil fields, which will boost reserves and extend production. The work at Brent will add 34 million bbl to oil reserves in the U.K.'s most prolific oil field and turn it into a major gas producer.

Off Norway, Phillips Petroleum Co. plans to redevelop Ekofisk field.

Statoil brought gas production on line this year from East Sleipner field to satisfy requirements under the Troll gas contract. Groups operated by Norsk Hydro AS and Norske Shell are developing Troll oil, gas, and condensate reserves.

EASTERN EUROPE, C.I.S.

Hope emerged for oil producing states of the FSU this year.

A study by Troika Energy Service, Dallas, predicted an easing of the production slide that began in the region after 1988. Troika expects the current crisis production decline, caused largely by equipment failures and the economic problems that prevent repairs, to ease about 1995-96.

The study expects the problem of idle wells to be resolved by the end of 1994. And it says wellhead prices within the FSU will align with world prices soon and provide an incentive for production gains.

In addition, the study says, new production from joint ventures involving non-FSU companies will be,in offsetting declines from old fields in 1995-96. And small companies forming in the region will begin adding production from the small fields they target (OGJ, Nov. 8, p. 30)

Russia, formerly the world's largest producer, and other FSU states continued signing joint ventures with international companies during 1993. Tax charges aggravated uncertainties in Russia, although work progressed under several joint ventures in the country.

Work in Russia has received a lift from international financial groups, with entities such as World Bank, Overseas Private Investment Corp., and European Bank for Reconstruction & Development becoming involved in several projects. Access to international capital has been cited as a key ingredient to success of restoration of production in Russia and other FSU states.

Azerbaijan, where civil unrest confounded the outlook for much of the year, combined three separate project proposals into one production sharing contract involving eight foreign companies to develop Chirag and Azeri fields.

Turkmenistan also has ambitious production plans, envisioning 560,000 b/d of oil and 12.57 bcfd of gas in 2000 vs. 100,000 b/d and 7.74 bcfd in 1994, according to a government report. joint ventures involving companies from Argentina, the United Arab Emirates, and the Netherlands have formed to operate in the former Soviet state.

Uzbekistan, Ukraine, and Kazakhstan were among other FSU states advancing licensing programs in their territory.

In Eastern Europe, Poland this year prepared to open its second bidding round, which will cover 27 blocks in the Lublin area of the Polish Lowlands. And work is beginning in Romania under agreements the government signed recently with international companies for onshore and offshore exploration.

MIDDLE EAST

The OPEC quotas that shaped production from the Middle East this year don't tell all of the region's story.

Big producers are still adding production capacity. And non-OPEC producers in the region are gaining ground.

Saudi Arabia, now the world's No. 1 oil producer, is making progress in its capacity boost to 10 million b/d. Because the country holds one fourth of the world's oil reserves, its capacity is always a function of investment in producing and exporting facilities rather than of geology. But progress toward the capacity goal can be slowed in light of market conditions.

This year, the kingdom expanded capacity of the 1,200 km Petroline pipeline from Abqaiq and Ghawar fields to Yanbu to 5 million b/d from 3.2 million b/d.

In the Northern Area of Saudi Arabian Oil Co. (Saudi Aramco), work is under way to upgrade the offshore Safaniyah, Marjan, and Berri oil fields and onshore Zuluf field. The project includes addition of two gas-oil separation plants (GOSPs) the one GOSP at Marjan.

Marjan production capacity will increase to 600,000 b/d of Arab Medium crude from 100,000 b/d. Associated gas production capacity increases to more than 600 MMscfd.

At Zuluf field, Aramco is converting two GOSPs from Arab Heavy to Arab Medium production to increase sustainable capacity for Arab Medium by 300,000 b/d. New wet crude handling facilities will raise total Arab Medium capacity from Zuluf to 1.2 million b/d.

Aramco is adding two offshore platforms at Safaniya field to handle 250,000 b/d.

In its Southern Area, the state owned company is building and expanding GOSPs in a project that might add as much as 450,000 b/d to capacity of supergiant Gahwar field.

Aramco plans to develop Hawtah field in its Central Region, building a GOSP, blending station, and link to the Petroline pipeline. Flow of 150,000 of Arab Super-Light crude could start in 1994.

Plans are uncertain for development of 7 billion bbl Shaybah field, which extends into Abu Dhabi as Zarar field, and the Empty Quarter. Development probably will be necessary if the kingdom sticks by its earlier schedule of having 10 million b/d of production capacity by 1995.

Abu Dhabi and Iran are among other OPEC members building production capacity in the Middle East. Abu Dhabi aims to have 3 million b/d of production capacity by 1995. Iran targets 4 million b/d and says it has achieved that level of production intermittently. This year it disclosed a discovery in southern Khuzestan province that it said added 7 billion bbl of light oil to reserves.

Among the Middle East's non-OPEC producers, Yemen boosted flow to 208,000 b/d from 182,000 b/d in 1992 as foreign operators reported more discoveries despite a number of dry holes in the complex Shabwa area.

Canadian Occidental Petroleum Ltd. started production at the rate of 40,000 b/d from its Masila block at midyear and expected it to rise to 120,000 b/d within months, pushing Yemeni flow to 300,000 b/d in the latter part of the year.

Oman's production increased to 775,000 b/d this year from 742,000 b/d in 1992. Occidental of Oman Inc. late in the year said it had tested 2,439 b/d of light oil in a discoverer on its Suneinah block in the northwestern part of the country.

AFRICA

Africa's production declined to 6.2 million b/d this year, but several countries plan licensing rounds.

Nigeria's production slipped to just below 1.9 million b/d. Foreign companies remained active in the country despite political unrest and strikes that followed a voided presidential election in June, resignation of military President Ibrahim Babangida, and his appointment of a political crony as a replacement.

Nigerian National Petroleum Co. signed several production sharing contracts during the year.

Libya wants to increase its production capacity to 2 million b/d from 1.7 million b/d but treaded lightly during 1993. It is subject to United Nations sanctions imposed in 1992 when it refused to extradite two suspects in a 1988 bombing of an airliner over Scotland.

Algeria's production fell to 750,000 b/d this year. The country continues to offer acreage to foreign companies as the government concentrates on expanding capacity to export natural gas by pipeline and as LNG.

Production fell to less than 500,000 b/d this year in Angola, where civil war hampered oil and gas operations. The government nevertheless was reported to be negotiating exploration licenses with several foreign companies.

Egypt, which experienced a degree of civil unrest unusual for the country, increased production as foreign companies continued to report discoveries in the Western Desert and Gulf of Suez.

Congo's production increased this year, and prospects remain bright. Elf Congo is developing offshore N'Kossa oil field with facilities capable of processing 120,000 b/d of crude and 455 MMcfd of gas for reinjection with 9,500 b/d of NGL recovery.

Several minor African producers hope to boost activity.

Equatorial Guinea held its first licensing round during the year covering all unlicensed prospective area in the country. Its only field, Alba operated by Walter International Inc. of Houston, flows 4,000-5,000 b/d of condensate.

Ivory Coast, where production has ceased , opened an international bidding round for production sharing contracts mostly in the Gulf of Guinea near idle Belier and Espoir oil fields.

In Namibia, exploration got under way in acreage licensed under the country's first bidding round 2 years ago. Another licensing round is planned in 1994.

Sudan, impoverished and hampered by war, may have its first commercial production in the next few years. Arakis Energy Corp. of Vancouver, B.C., and State Petroleum Corp., a private Sudanese company, filed a development plan to produce 40,000 b/d from Heglig and Unity oil fields.

Chevron Corp. discovered the fields in the 1980s but couldn't come to terms with the government over a plan to export the production.

Exploration and development activity increased this year in Tunisia, with British Gas plc starting development of Miskar gas field and production of 4,000 b/d from Cercina oil field and several other international operators receiving exploration and production permits.

Uganda this year made 22,000 sq km of exploration acreage available for exploration.

WESTERN HEMISPHERE

Canadian oil production increased 5% to 1.7 million b/d this year--a noteworthy gain for a country with such a mature resource base.

Contributing to the gain was a 1 year royalty holiday for oil development wells, which ended after several extensions at the end of July and applied to more than 1,900 wells.

Production also is increasing from the heavy oil deposits of northern Alberta, light synthetic oil from which accounted for 12% of Canada's production in 1992.

Increasingly, however, exploration and development work in Canada, as in the U.S., is oriented to natural gas.

Elsewhere in the Western Hemisphere, production gains tended to result from work stimulated by privatization of formerly state-owned oil companies.

An exception is Brazil, which raised production by nearly a percentage point to 631,000 b/d and where Petroleo Brasileiro SA remains firmly in the hands of government. Production is rising from fields in the offshore Campos basin, where Albacora is to become the country's largest producer at 60,000 b/d.

Production declined slightly in Mexico, which is privatizing downstream sections of Petroleos Mexicanos but continuing to exclude direct outside participation in exploration and production.

Activity remains brisk in Colombia, where production slipped to 450,000 b/d but where development is under way for giant Cusiana and Cupiagua fields.

Ecuador is developing a new hydrocarbon law and privatizing its state oil company. Exploration and development by Petroecuador and foreign contractors boosted production by 6% to 341,000 b/d this year.

Peru reversed a production slide of several years in 1993 with an average of 126,000 b/d, up 8% from 1992 flow. The country is selling state holdings to private concerns and encouraging activity by foreign operators.

Petroleos del Peru expects output to climb to 133,200 b/d in 1994.

Venezuela remained on its tentative privatization course this year with a second bidding round for rights to produce oil and gas from old and marginal fields. It received bids from 44 companies for 74 fields that Petroleos de Venezuela SA says might yield 300,000 b/d by 2000.

It also approved two major projects involving foreign investors for development and upgrade of extra heavy crude from the huge Orinoco oil belt.