Supply Management By Major Exporters Key To Market In Year's Second Half

Robert J. Beck
Associate Managing Editor-Economics

• U.S. oil demand and refinery runs increase [46,687 bytes]
• U.S. crude production slides, imports rise [49,138 bytes]
• Total industry stocks remain the same [52,410 bytes]
• U.S. gasoline demand continues up [38,688 bytes]
• U.S. refiners' crude costs drop [47,587 bytes]
• OGJ forcast of U.S. supply and demand [16,708 bytes]
• First half U.S. crude, condensate production [10,433 bytes]
• U.S. crude and products prices [13,932 bytes]
• U.S. energy consumption and efficiency [38,743 bytes]
• U.S. natural gas supply and demand [12,283 bytes]
• U.S. energy demand [7,186 bytes]
• U.S. refinery utilization [11,104 bytes]
• First quarter worldwide production [19,327 bytes]
• OPEC production [9,800 bytes]
• First half crude and products stocks [10,057 bytes]
• U.S. imports [23,130 bytes]
• World crude prices [18,954 bytes]
• Worldwide supply and demand [24,701 bytes]

The second half of 1998 will test the collective ability of leading oil exporters to manage supply.

Inventories rose toward capacity levels in the first half as worldwide production increased faster than demand, which was hobbled by economic troubles in Asia and a warm winter in the Northern Hemisphere. Crude oil prices sank.

To balance the market and strengthen crude prices, producers entered the second half of the year facing the need to reduce output. The Organization of Petroleum Exporting Countries in June announced its second production cut of the year, a 1.355 million b/d effort that brought total announced cuts for the year to 2.6 million b/d. Nonmembers pledged cuts totaling as much as 600,000 b/d.

At the start of the second half, doubt loomed that OPEC members would trim production sufficiently. They needed to offset expected increases in total supply from non-OPEC producers, especially in the North Sea, Latin America, and the Former Soviet Union (FSU). They also needed to accommodate an expected draw from inventories, which climbed in the first half to near-capacity levels.

Asia's economic crisis last year jolted the oil market. The region had been considered the major growth region for petroleum demand. Through the first half of 1998, however, most other economies remained strong. With Asia struggling, continued growth elsewhere will be critical to demand for oil.

Gross domestic product (GDP) for members of the European Union will be up an estimated 2.7% in 1998 after gains of 2.6% in 1997 and 1.7% in 1996. In the U.S., GDP will increase 2.8% after a 3.8% gain in 1997.

Total economic growth among the industrial countries that make up the Organisation for Economic Cooperation (OECD) and Development is projected at 2.4% in 1998, compared with 3.1% in 1997 and 2.8% in 1996. Slower growth in the U.S. and a recession in Japan are checking the growth rate this year.

Real GDP in the Asian developing countries is projected to increase by 4.4% in 1998, compared with 6.7% in 1997 and 8.3% in 1996.

Drilling activity worldwide held up during the first half despite slumping crude prices. Weakness, however, has begun to show.

The international rig count, which excluding the U.S. and Canada, averaged 807 for the first 5 months of 1998, compared with 806 a year earlier. But in May this year the count slipped to 798 from to 811 in the same month of 1997.

The Canadian rig count averaged 333 vs. 326 for the first 5 months last year. In May the rig count in Canada was 157 vs. 234 in May 1997. That decline might be related more to weather problems than a decline in investment.

The U.S. rig count averaged 928 for the first 5 months of 1998, compared with 879 a year earlier. But the May average dropped to 855 from 993 in January.

International oil market

With Asian consumption slowing because of the region's economic problems, first-half demand growth outside the OECD came mainly in Latin America, the Middle East, Africa, China, and the former Soviet Union (FSU). Demand in non-OECD Asia fell. Among OECD countries, demand grew modestly.

According to the International Energy Agency, total worldwide demand averaged 74 million b/d during the first half of 1998, up from 73 million b/d for the same period a year earlier. OECD demand averaged 41.65 million b/d for the first half, compared with 41.45 million b/d last year.

In China, first-half demand increased to 4.2 million b/d from 3.9 million b/d a year earlier. Latin American demand averaged 6.75 million b/d, up from 6.5 million b/d in first half 1997.

FSU consumption, which had been falling in recent years, climbed to 4.5 million b/d in the first half from 4.35 million b/d in 1997. FSU demand is projected to increase to 4.7 million b/d in the fourth quarter.

Whie demand growth slowed in the first half, output from both OPEC and non-OPEC producers moved up. Non-OPEC supply averaged 44.9 million b/d vs. 44.1 million b/d last year. Increased North Sea output helped boost first-half OECD production to 18.75 million b/d from 18.5 million b/d. In non-OECD developing countries, production increased to 24.55 million b/d from 24 million b/d in the first half of 1997. There were marked increases in output in Latin America and FSU.

OPEC delivered an average of 31 million b/d of liquids to market in the first half, compared with 29.6 million b/d in the first half a year earlier. Output included 28.1 million b/d of crude oil and 2.9 million b/d of natural gas liquids and condensate.

Stocks absorbed almost 2 million b/d of worldwide production in the first half. A year earlier, the net addition to stocks was 700,000 b/d, and in first-half 1996 there was no increase in inventories.

The stock gain in this year's first half followed an average increase of 700,000 b/d for all of 1997. Last year stocks did not decline in the fourth quarter, as they usually do.

The stock build increased to 1.6 million b/d in this year's first quarter and to 2.3 million b/d in the second quarter.

Part of 1997's stock build had been to restore inventories that had fallen close to minimum operating levels in previous years. Stocks now exceed levels needed to support demand. Later this year, withdrawals will help satisfy demand and reduce the need for production.

OPEC's first-half production of crude oil exceeded the group's quota of 27.5 million b/d, set last November in anticipation of rapidly rising demand. The group quota includes 1.3 million for Iraq, which produced 2 million b/d in the second quarter under United Nations sanction exemptions designed to raise revenues for humanitarian purposes and war reparations from the 1990 invasion of Kuwait.

Worldwide outlook

IEA projects total worldwide demand at 75 million b/d for 1998, up 1.2 million b/d from 1997. Demand will reach 77.4 million b/d in the fourth quarter.

Late last year IEA was projecting the demand increase for 1998 at close to 1.8 million b/d but has had to moderate its projection because of the slowdown in Asia.

For the industrial countries of the OECD, IEA sees an oil demand gain of 400,000 b/d in 1998 to an average of 42.3 million b/d. Outside OECD, average demand for the year is projected at 32.7 million b/d, up 800,000 b/d from 1997.

For non-OECD Asia, the IEA expects demand to drop 100,000 b/d to an average 9 million b/d in 1998. Earlier forecasts for the region were for a demand gain of 400,000 b/d.

IEA expects total non-OPEC liquids supply to move up 800,000 b/d to average 45.2 million b/d for 1998. OECD crude oil supply will average 18.9 million b/d, up 200,00 b/d. By the fourth quarter, OECD supply will be 19.5 million b/d.

Liquids output from the FSU will also boost non-OPEC supply. After falling from more than 12 million b/d in 1988 to 7.1 million b/d in 1996, FSU production moved up to an estimated 7.2 million b/d in 1997 and is expected to climb to 7.3 million b/d this year.

Other non-OPEC gains projected by IEA include 400,000 b/d from Latin America to an average of 7.2 million b/d for the year and 100,000 b/d from Africa to 2.8 million b/d. Total non-OPEC supply for the fourth quarter is estimated at 45.2 million b/d, up 800,000 b/d from the fourth quarter of 1997.

With supplies from inventory and non-OPEC producers increasing in the second half, demand for OPEC liquids will fall to an average of 30.1 million b/d. If net additions to stocks for 1998 average 700,000 b/d, demand for OPEC for all of 1998 will be 30.5 million b/d vs. 30 million b/d in 1997.

Prices

World export crude oil prices for the first half of 1998 fell to an estimated average of $12.44/bbl from $19.09/bbl in the first half of 1997. The average price for June this year was $11.50/bbl vs. $17.07/bbl in June last year.

The world export price started the year low, averaging only $14.10/bbl in January and slumped further to $11.56/bbl in March. The price climbed to $12.56/bbl in May but fell again in June as demand expectations worsened and stocks remained high.

The average price for OPEC export crude oil was $11.95/bbl for the first half of 1998, compared with $18.78/bbl for the same period of 1997. The price for non-OPEC crude oil averaged $13.14/bbl during the first half this year, down from $19.48/bbl for the same period a year earlier.

The price weakness that marked the first half of the year is expected to continue, and it is expected that on average crude oil prices for the year will finish much lower than the year before.

On the New York Mercantile Exchange (Nymex) the near-month futures price for light sweet crude oil averaged $16.84/bbl in January and slipped to an estimated $12.75/bbl in June. For the first half of the year the Nymex price averaged $15.20/bbl, compared with $21.34/bbl for first-half 1997.

The average posted price for West Texas Intermediate (WTI) crude oil followed a similar pattern, averaging an estimated $14.50/bbl for the first half this year vs. $20.47/bbl for the same period last year.

The U.S. wellhead price of crude oil averaged $12.82/bbl for January and February this year, the latest data available, down from $20.57/bbl for the same period a year earlier.

OGJ projects an average annual U.S. wellhead price of $13/bbl for 1998, down from the $17.24/bbl in 1997 and $18.46/bbl in 1996.

Product prices

Product prices followed crude values downward during the first half in a trend likely to stimulate consumption.

According to the OGJ survey of self-service unleaded motor gasoline pump prices, the average price for the first half of 1998 was $1.080/gal, down from $1.235/gal over the same period last year. Excluding excluding all federal, state, and local taxes, the price was 68.1¢/gal, down from 83.9¢/gal a year earlier.

The OGJ survey showed the pump price averaging $1.125/gal in January, compared with $1.255/gal a year earlier. The price to $1.047/gal in March and moved up marginally as the driving season started. The average pump price was $1.084/gal in May and $1.089/gal in June.

Federal, state, and local gasoline taxes averaged 39.9¢/gal for the first half vs. 39.7¢/gal over the same period a year ago.

OGJ is projecting the pump price for all types of motor gasoline, including premium grades, to average $1.12/gal for 1998, down from $1.291/gal for 1997. The peak annual-average pump price for motor gasoline was $1.353/gal in 1981.

Residential heating oil prices for the first 2 months of 1998 averaged 91.8¢/gal, compared with $1.065/gal in the same period a year earlier. OGJ expects heating oil prices will slip to an average 85¢/gal for the year from 98.4¢/gal last year.

Natural gas prices

Although natural gas prices are down from last year, the average decline has been less than that of crude prices. The main reason for the price decline is a abnormally warm heating season.

Spot gas prices started the year at $2.19/MMBTU in January, down from $3.96/MMBTU a year earlier. Gas prices started to weaken in late 1997, averaging $3.19/MMBTU in November and $2.38/MMBTU in December.

With demand steady, gas prices remained close to the January level through the first half of 1998, averaging $2.11/MMBTU. That is down from $2.38/MMBTU for first half 1997. The spot price was as high as $2.22/MMBTU in April but slipped to $1.95/MMBTU in June. Spot prices have shown some seasonal pattern and may move up if the weather is closer to normal during the heating season.

Following the same pattern, the Nymex futures gas price started weak in January, strengthened in April, then slumped slightly in June, averaging $2.27/MMBTU for the first half, compared with $2.23/MMBTU last year.

The average U.S. wellhead price for natural gas averaged $1.79/Mcf in January this year, the only data available. This was down from $3.42/Mcf in January a year earlier and $2.05/Mcf in January 1996.

Natural gas wellhead prices peaked in 1984 at an annual average of $2.66/Mcf then fell to $1.67/Mcf in 1987. During 1987-91, the average annual wellhead price fluctuated in a range of $1.64-1.71/Mcf. The price then rose to $1.74/Mcf in 1992 and $2.04/Mcf in 1993 before falling to $1.85/Mcf in 1994 and $1.55/Mcf in 1995 as natural gas responded to both the price of competing fuels and increased supply. A demand rebound pushed the wellhead gas price to $2.17/Mcf in 1996 and $2.23/Mcf in 1997. Utilities turned to natural gas in 1997 to fill a void left when nuclear power output dropped.

Natural gas demand for the first 4 months of this year, the latest data available, was down 1.3% from the same period of 1997.

Gas prices are expected to remain relatively steady in the second half, particularly in the utility and industrial markets where natural gas competes with heavy fuel oil and coal. OGJ projects an average U.S. wellhead price of $2.05/Mcf for 1998, based on an expected 1.2% increase in U.S. natural gas consumption this year.

U.S. demand

Despite the expected slowing of GDP growth, the economic outlook for the U.S. remains good. Inflation is still under control and there is no immediate danger of the Federal Reserve Bank raising interest rates. The unemployment rate is at the lowest level in over a decade but has shown no sign of driving up prices.

The U.S. economy has been growing slowly but steadily since a mild recession in late 1990 and early 1991.

The 2.8% growth projected for this year is based on the federal government's new method of calculating real GDP, which produces growth rates slightly lower than under the older method. The new chain-weighted system does a better job of adjusting for large price swings, such as the sharp drop in the cost of computing power, and therefore of measuring the true growth in goods and services.

U.S. GDP in 1997 was up 18.2% from the level in 1991-an average growth rate of 2.8%/year.

This year industrial production is expected to increase an estimated 3.6% following an increase of 5% in 1997. New-car sales are expected to be 8.2 million in 1998, compared with 8.3 million last year. Housing starts are projected to increase to 1.5 million units from 1.48 million in 1997.

U.S. energy demand

OGJ projects an increase in U.S. energy consumption in 1998 mainly due to the sustained increase in economic activity. Improvement in energy efficiency and conservation will keep the energy growth rate lower than the growth rate for the overall economy.

Total U.S. energy consumption will move up 1.4% this year following an increase of 0.6% in 1997-to 91.81 quadrillion BTU (quads) from 90.549 quads in 1997.

Energy consumption declined in the early 1980s but started increasing when the economy started to grow steadily. During 1982-90, energy consumption grew at an average rate of 1.7%/year. GDP in that period increased at an average rate of 3.6%/year.

Energy consumption declined 0.1% in 1990 and 0.2% in 1991. Since then it has risen at an average rate of 1.9%/year. This compares to average economic growth of 2.8%/year.

Since 1970 improvements in energy efficiency have kept energy consumption growth rates below those of the economy.

Energy consumption per unit of GDP was 37.4% lower in 1997 than in 1970, falling from 19,800 BTU/$ in 1970 to 12,600 BTU/$ in 1997. OGJ expects the trend to continue, with energy consumption in 1998 averaging 12,400 BTU/$ of GDP.

The rate of growth in energy consumption tracks closer to GDP growth during periods of rapid economic expansion and low energy costs.

Energy sources

Oil energy demand is projected to move up 1.2% in 1998 to 36.76 quads as economic strength and low prices offset the effects of the warm winter. Energy from oil increased 1.3% in 1996.

Oil's share of total energy demand will slip to 40% from 40.1% in 1997. The oil share was 39.8% in 1996. In 1978, the year of peak oil consumption, the market share was 48.6%.

Demand for energy from natural gas will also increase 1.2% in 1998 to 22.76 quads. This compares to a decline of 0.3% last year. Relatively high natural gas prices have slowed the growth rate the past 2 years.

The natural gas market share will remain at last year's level of 24.8%, compared with 25.1% in 1996. Together, oil and natural gas will provide 64.8% of the energy consumed in the U.S. during 1998, down from 64.9% last year.

Increased electric power consumption will boost demand for coal energy by 1.3% in 1998 to 21.29 quads. This follows an increase of 2.5% in 1997. Coal's market share will remain at 23.2% in 1998; it was 22.8% in 1996.

Energy from hydroelectric and other energy sources is expected to fall 2.5% in 1998 to 3.95 quads after an increase of 2.8% last year. The market share will slip to 4.3% from 4.5% in 1997. Other energy sources such as geothermal, wind, wood, and solar provided only 0.2% of total energy consumed in the U.S. in 1997.

Nuclear energy output is expected to increase 5.6% this year to 7.05 quads. This follows a sharp decline of 6.8% last year, when major maintenance projects reduced output at several nuclear facilities. Nuclear's market share is expected to increase to 7.7% in 1998 from 7.4% in 1997. It was 8% in 1996.

Any increase in nuclear energy output is dependent upon an increase in the capacity utilization rate. The rate hit a record high 77.4% in 1995 then slipped to 76.4% in 1996 and 71.3% last year. There are no plans to add new nuclear units, and total industry capacity is starting to slide.

This slowing of growth in nuclear power generation will force the electric power industry to turn to other fuel sources in the future, probably coal and natural gas.

U.S. natural gas

U.S. consumption of natural gas is expected to increase 1.2% in 1998 to a record 22.165 tcf. This follows gains of 0.3% in 1997 and 1.8% in 1996.

The recent low in gas consumption was 16.221 tcf in 1986. The record high for gas consumption was set in 1972-22.101 tcf.

Natural gas consumption in 1997 was up 5.682 tcf from the level in 1986. The industrial sector accounted for much of the increase. Industrial demand increased from 5.579 tcf in 1986 to 8.76 tcf in 1997. In 1997, however, it slipped by 110 bcf.

A major reason for gains in this sector is that gas used in nonutility electricity generation is counted as industrial consumption.

During 1986-97 period, commercial demand for gas increased 38.8% to 3.217 tcf in 1997. Consumption in this sector in 1997 was up 1.9% from a year earlier.

Residential demand moved up 16% during 1986-97 to 5.004 tcf in 1997. Residential demand slipped 4.5% in 1997 due to the warm winter.

Demand for natural gas as a pipeline fuel and a lease and plant fuel increased 38.6% over the longer period to 1.951 tcf in 1997.

Utility demand has been very volatile. This is the sector where natural gas has the most intense competition from other fuels. Utility demand reached a recent high of 3.197 tcf in 1995 then fell to 2.732 tcf in 1996. Demand increased 8.7% in 1997 to 2.969 tcf, when it was up 14.1% from the level in 1986.

A sharp increase in gas prices was the major reason for the drop in utility demand in 1996. Prices were even higher in 1997, but strong economic growth and reduced output at nuclear plants helped to boost utility demand for gas.

In 1998 gas demand is expected to increase in the utility and industrial sectors due to prices lower than a year ago and strong economic growth. The warm winter will slow demand growth in the commercial sector and push demand down in the residential sector.

According to the Energy Information Administration (EIA), the cost of coal for steam electric utilities dropped steadily from $1.455/MMBTU in 1990 to $1.273/MMBTU in 1997. The cost of natural gas for these utilities was $2.321/MMBTU in 1990, moved up to $2.56/MMBTU in 1993, slipped to $1.984/MMBTU in 1995, then jumped to $2.641/MMBTU in 1996 and $2.76/MMBTU in 1997. This improved the competitive advantages of coal and even heavy fuel oil.

Electric utility consumption of natural gas moved up last year despite the price increase. Strong demand for electric power and the decline in nuclear output more than offset the impact of the higher prices.

Natural gas prices during the first 5 months of this year have averaged 12% lower than a year earlier. That should help boost demand for gas by the utility sector, although slumping oil prices will keep heavy fuel oil competitive.

U.S. marketed production of natural gas is expected to increase by 1.1% to 20.07 tcf in 1998. This follows an increase of 0.5% in 1996.

In recent years domestic production has risen in response to increases in both demand and average wellhead price.

Domestic output hit a peak of 22.648 tcf in 1972 and slipped to a recent low of 16.859 tcf in 1986. Since then, output has moved up at an average rate of 1.5%/year to 19.846 tcf in 1997. This compares to an average increase in natural gas consumption of 2.9%/year over the same period.

Additional imports have been providing a large share of the increase in consumption. Imports of natural gas, mainly from Canada, moved up from 750 bcf in 1986 to 2.99 tcf last year. Imports of natural gas are projected to increase 1.3% in 1998 to 3.03 tcf. Last year imports increased 1.8%.

Imports from Canada will total 2.934 tcf this year. Canadian imports were up only 0.5% in 1997 at 2.896 tcf, from 2.883 tcf in 1996. This year there will also be a small supply of LNG, 80 bcf, from Algeria, the United Arab Emirates, and Australia. This compares with LNG imports of 78 bcf in 1997, 40 bcf in 1996, and 18 bcf in 1995. There will also be a modest level of gas from Mexico, 16 bcf in 1998, compared with 16 bcf in 1997 and 14 bcf in 1996.

Since the recent low in 1986, U.S. gas consumption has moved up 5.682 tcf, domestic dry gas production is up 2.862 tcf, and total imports have increased 2.24 tcf.

Petroleum demand

U.S. demand for petroleum products in the first half of this year moved up 1% from the same period last year, averaging 18.56 million b/d. Economic growth and falling prices more than offset weather effects.

Increases occurred in all major product categories except residual fuel oil. The sharpest first half increases were posted by jet fuel, 1.5%, and motor gasoline, 1.3%.

Resid demand was down 1.3% in the first half from the comparable period of 1997.

First half increases in demand for the other major product groups were distillate 0.9%, LPG and ethane 1.1%, and all other petroleum products 0.5%.

OGJ expects second-half demand for all petroleum products to average 19.12 million b/d.

For the entire year, U.S. demand for petroleum products will average 18.84 million b/d, up 1.2% from the level in 1997. Demand moved up 1.7% in 1997, 2.9% in 1996, 0.04% in 1995, 2.8% in 1994, 1.2% in 1993, and 1.9% in 1992.

U.S. demand hit the all time high of 18.847 million b/d in 1978, then fell to 15.231 million b/d in 1983 due to rapid gains in crude oil and product prices.

Motor gasoline demand

Demand for motor gasoline in the first half rose an estimated 1.3% from a year earlier, averaging 7.98 million b/d.

Pump prices are not expected to move up significantly in the second half of the year. Although crude prices might firm late in the year as inventories decline, which would put cost pressure on gasoline, demand for the product will be in a seasonal decline.

For the year average motor gasoline demand is projected to rise 1.2% from 1997 to a record 8.115 million b/d. Motor gasoline demand has set records in each of the past 5 years. The 1998 level will be will be up 12.9% from 1991 demand.

Motor gasoline consumption fell from a then-record 7.412 million b/d 1978 to a low of 6.539 million b/d in 1983 in response to sharp price increases.

Latest data from the EIA show that vehicle efficiency reached 21.3 mpg in 1996 after slipping from 21.2 mpg in 1991 to 20.6 mpg in 1993. In 1973 the average was only 13.4 mpg.

The average total miles driven per car moved up steadily from 8,813 in 1980 to 11,314 in 1996.

Distillate

Distillate fuel oil demand during the first half of 1998 was up an estimated 0.9% over demand in the same period last year, averaging 3.48 million b/d.

For the year OGJ projects distillate demand of 3.47 million b/d, up 1% from 1997.

Increases in demand are expected in all economic sectors, led by transportation.

Closer-to-normal winter weather will also boost demand in the home heating sector.

Residual fuel oil

Demand for residual fuel oil fell 1.3% to 820,000 b/d in the first half from the same period in 1997.

Annual demand for resid has fallen for 9 consecutive years and has been on a downward trend since peaking at 3.071 million b/d in 1977.

Extremely low resid prices will hold resid demand for the full year at the first-half average of 820,000 b/d, up 2.9% from all of 1997. Demand will fall to 800,000 b/d in the third quarter but rise to 840,000 b/d in the fourth.

Industries with fuel-switching capability, primarily electric utility and heavy manufacturing, will switch to resid from natural gas to take advantage of price differences.

LPG and other products

Demand for LPG and ethane is projected to average 2.055 million b/d in 1998, up 0.8% from 1997.

Demand during the first half of this year was an estimated 2.02 million b/d, up 1.1% from the same period in 1997. Increased chemical industry consumption associated with the growing economy has helped to boost demand.

Demand for all of the other petroleum products is also expected to increase this year-by 0.8% to 2.755 million b/d. During the first half of 1998 demand averaged 2.67 million b/d, up 0.5% from 1997.

This product category includes petrochemical feedstocks, special naphthas, lubricants, waxes, petroleum coke, asphalt and road oil, still gas, and other miscellaneous products. It represents more than 14% of total domestic demand.

U.S. petroleum supply

U.S. production of crude and condensate, once declining steeply in a trend thought to be unalterable, has nearly leveled.

Output slipped last year to 6.452 million b/d from 6.465 million b/d in 1996 and will fall only modestly again this year, although low oil prices will take a toll.

Production during first-half 1998 averaged an estimated 6.425 million b/d, down only 0.4% from the first half of 1997. During the second half, Lower 48 producers will probably reduce output in response to low prices.

For the year, crude and condensate output is expected to average 6.36 million b/d, down 1.4% from 1997.

The steady decline in Alaskan North Slope production is the main reason for the U.S. slide. Lower-48 production has been stabilized by discoveries and improved production techniques.

During the first half, Alaskan output averaged 1.23 million b/d, compared with 1.331 million b/d in the first half of 1997. Alaskan production peaked at 2.031 million b/d during first-half 1988 and averaged 2.017 million b/d that year.

Lower-48 production increased 1.4% in the first half this year to average 5.195 million b/d. Lower-48 crude and condensate production had fallen from 9.01 million b/d in 1973 to an average 5.072 million b/d in 1996. It increased to 5.156 million b/d in 1997.

The decline in total U.S. output is expected to continue in the second half, when it will average 6.295 million b/d.

Total U.S. crude and condensate output this year will be the lowest since 1954 and will be down 29.1% from the recent high of 8.971 million b/d in 1985.

U.S. crude oil production hit a peak in 1970 at 9.637 million b/d. Production then slipped to 8.132 million b/d in 1976, just prior to the addition of North Slope output. Increases in Alaska coupled with a boom in Lower-48 drilling activity pushed production to 8.971 million b/d in 1985.

Production of natural gas liquids (NGL) plus other hydrocarbon liquids averaged 2.2 million b/d for the first half of 1998, up 2% from the same period the year before. Production of NGL and other liquids is projected to average 2.2 million b/d for the full year, up 1.9% from 1997. Since 1993 this production category has included oxygenate production from MTBE plants and fuel ethanol. Therefore, output is tied to motor gasoline demand.

U.S. total liquids production is projected to average 8.56 million b/d in 1998, down from 8.611 million b/d in 1997. Total liquids production this year will be down 19.5% from the recent high of 10.636 million b/d in 1985.

Refining

Over the past few years U.S. operable refining capacity has moved up steadily but modestly after falling through the 1980s and early 1990s.

Operable capacity averaged 15.7 million b/d during the first half of 1998. It is expected to move up to 15.8 million b/d by year-end. For the year operable refinery crude capacity thus will average 15.75 million b/d vs. 15.594 million b/d in 1997. That 1% gain compares with a 2.3% increase in 1997. Increases in product demand have encouraged refiners to add capacity at existing facilities. Grassroots construction remains difficult due to costs and permitting problems related primarily to environmental regulations.

During 1984-92, refining capacity fluctuated in the range of 15.5-15.9 million b/d. Product demand was rising during this period, and utilization rates moved up. Capacity was reduced further to 15.143 million b/d in 1993 and 15.15 million b/d in 1994. The refinery utilization rate climbed to 92.6% in 1994.

The high utilization rate and strengthening margins triggered an increase of capacity in 1995, to 15.346 million b/d. Capacity slipped to 15.239 million b/d in 1996.

Total input to distillation units continued to climb along with crude runs and demand. The utilization rate rose to 94.1% in 1996 and 95.2% in 1997. That is close to full sustainable capacity, since some capacity is required for maintenance downtime and contingencies.

Crude input to refineries is projected to be up 0.9% this year to 14.8 million b/d. Total input to distillation units will move up 1% to 14.99 million b/d. The increase in capacity will be about the same as the increase in throughput, so the average utilization rate is projected to remain at 95.2%. The utilization rate in the third quarter is expected to rise an average 98% of crude capacity.

Imports

In 1998 crude and product imports will set their third straight yearly record high.

In the first half total industry imports were down 0.4% at 10.095 million b/d. This was primarily due to a sharp decline in product imports, which fell 10.8% from year ago levels. The high product stock levels at year-end 1997 lowered the need for product imports during the first half.

Industry imports are expected to increase during the latter half of the year to help support increased product demand and to fill some of the gap left by sliding domestic crude production. The import requirements will be partially offset by withdrawals from stocks.

Imports are projected to surge to 10.57 million b/d for the third quarter then slip to 10.28 million b/d in the last quarter as stocks are reduced. For the year total imports are forecast at 10.26 million b/d, up 1% from last year.

Last year imports increased 7.2% to 10.161 million b/d, from 9.478 million b/d in 1996.

This far surpasses levels of the late 1970s, when a surge in demand pushed imports to an average of 8.786 million b/d in 1977. Imports then dipped to a recent low of 4.949 million b/d in 1985, due to increased domestic production coupled with a decline in product demand, both related to the sharp rise in crude oil prices in the early 1980s.

Dependence on petroleum imports hit a record high last year: 54.6% of domestic demand, up from 51.7% the year before. The import dependency level is projected at 54.5% for 1998.

Crude imports are projected to increase 1.4% in 1998 to a record 8.34 million b/d. Crude imports increased 9.5% last year. During the first half of this year crude oil imports averaged 8.2 million b/d, up 2.3% from first half 1997.

There have been no crude imports for the Strategic Petroleum Reserve (SPR) since June of 1994 because of lack of funding. The size of the reserve peaked at 592 million bbl in 1994 and 1995. SPR withdrawals in 1996 raised federal funds for operations and maintenance, pulling the volume in storage to 566 million bbl at year-end.

There was a further reduction in January 1997 to 563 million bbl, the current level. Subsequently the Department of Energy (DOE) announced that there would be no further sales of SPR crude.

Petroleum product imports are expected to fall in 1998 to 1.92 million b/d from 1.936 million b/d. Product imports in 1996 jumped by 22.8% to 1.971 million b/d.

During the first half of this year product imports were down 10.8% from the level a year ago, at 1.895 million b/d. The high product stock levels at year-end 1997 reduced the need for refiners to import product to meet demand during the first half.

Strong demand in the second half will increase product imports to an average of 1.945 million b/d. This will be in addition to a decline in product stocks, the rate of which will influence imports.

Over the longer run, with little excess refining capacity, increases in product demand will probably be reflected in increased product imports.

The leading source of U.S. crude imports during the first quarter of this year was Saudi Arabia, which supplied 1.364 million b/d, 17.1% of the total. Next was Venezuela at 1.326 million b/d, 16.6% of the total; then Mexico, 1.288 million b/d; and Canada, 1.272 million b/d.

Other countries supplying large volumes of crude to the U.S. during the first quarter were Nigeria 658,000 b/d and Angola 381,000 b/d. Total crude imports from the OPEC countries averaged 3.72 million b/d for the first quarter, 46.6% of total crude imports. Crude imports from OPEC averaged 3.775 million b/d during all of 1997.

Canada was the leading source of U.S. product imports for the first quarter this year at 343,000 b/d. Venezuela was next at 325,000 b/d, followed by the Virgin Island refineries, 305,000 b/d, and Algeria, 272,000 b/d. Product imports from OPEC countries averaged 713,000 b/d, 41% of the first-quarter total.

Total imports from OPEC during the first quarter of this year averaged 4.433 million b/d, 45.6% of total. Last year OPEC provided 45% of total imports for the full year.

Stocks

Stocks play a growing role in U.S. total supply and demand and have become a key indicator of pressure on oil prices.

Total industry stocks finished 1997 at 1,036 million bbl, compared with 942 million bbl at year-end 1996, 971 million bbl at year-end 1995, and 1,061 million bbl at year-end 1994. The 1995 and 1996 totals were close to minimum operating levels.

Refiners appeared to have adopted a stock management system that minimized the level and cost of carrying large inventories of crude and products. But stocks may have been drawn down to levels that came close to creating delivery problems and that subsequently encouraged refiners to add some contingency inventories.

The reduced demand of late 1997 and early 1998 and falling prices also encouraged refiners to add to crude stocks. Stocks moved up from 942 million bbl at year-end 1996 to 1,036 million bbl at year-end 1997.

And rather then falling during the first quarter of the year due to high winter demand, stocks remained high and finished April at 1,036 million bbl. Stocks are usually drawn down in the first quarter and replenished later in the year. The stock build appears to have continued in the second quarter. Preliminary EIA estimates put end-May total industry stocks at 1,068 million bbl.

The high stock level has diminished the refiners' demand for additional crude during the second quarter of this year and suppressed oil prices. Refiners do not want to add to the current stock level and probably are attempting to work off stocks to reduce carrying costs.

In 1997 the increase in stocks added 260,000 b/d to overall demand. That helped to support prices through most of the year. This is in contrast to 1996 when the reduction in stocks added 63,000 b/d to supply.

A withdrawal able to reduce stocks to 1,000 million bbl by year-end would contribute 370,000 b/d to supply.

The EIA has listed 892.6 million bbl as the observed minimum for total industry stocks. The EIA no longer defines this as a minimum operating level, but it does represent the lowest stock level registered over the last 36 months. It was in fact the lowest industry stock level in decades.

At year-end total industry stocks are projected to be at the same level as a year earlier, 1,036 million bbl. Crude oil stocks are expected to finish the year at 315 million bbl, up 3.3% from year-end 1997.

Product stocks are expected to be reduced slightly to 721 million bbl from the 731 million bbl at year-end 1997. Product stocks were only 658 million bbl at year-end 1996.

At the end of the first half crude oil stocks were increased to an estimated 345 million bbl. The EIA has listed 283.9 million bbl as the observed minimum level for crude stocks, reached in December 1996.

At the end of the first half product stocks were estimated at 730 million bbl, up 5.6% from a year earlier and down slightly from the 731 million bbl at yearend 1997.

Refiners have generally been more willing to deplete product stocks than crude oil stocks. Crude stocks provide refiners with the flexibility to meet changes in demand for any product. However, with distillation capacity being used at close to maximum rates refiners have little room to step up throughput to meet unanticipated surges in demand.

At year-end 1997 total industry stocks represented 55.7 days of supply at the 1997 level of demand. That was up from year-end 1996, when total industry stocks represented 51.8 days of supply at 1996 demand levels. That was the lowest stock level, in terms of days' supply, on record. At year-end 1995 stocks represented 54.5 days of supply, and at year-end 1994 it was at 59.9 days of supply.

In the 1960s total stocks of crude oil and products represented 68-82 days of current demand. In the 1970s this dropped to a range that varied from 58 to 70 days. Government pressure boosted inventories as high as 78 days of supply in the early 1980s. But by the end of the 1980s refiners were managing stocks more efficiently and cutting inventory costs.

This year the increase in demand and constant stock level will reduce year-end 1998 stocks to 55 days of supply.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.