(Sanitized)

• Document Type: CREST
• Collection: General CIA Records
• Document Number (FOIA) /ESDN (CREST): CIA-RDP80T00702A001100040004-1
• Release Decision: RIPPUB
• Original Classification: S
• Document Page Count: 36
• Document Creation Date: December 12, 2016
• Document Release Date: January 2, 2002
• Sequence Number: 4
• Publication Date: August 26, 1978
• Content Type: CABLE

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9 q9rr
ER IEBB 78-017
23 August 1978
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Warning Notice
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(WNINTEL)
NATIONAL SECURITY INFORMATION
Unauthorized Disclosure Subject to Criminal Sanctions
DISSEMINATION CONTROL ABBREVIATIONS
NOFORN- Not Releasable to Foreign Nationals
NOCONTRACT- Not Releasable to Contractors or
Contractor/ Consultants
PROPIN- Caution-Proprietary Information Involved
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Controlled by Originator
REL... - This Information has been Authorized for
Release to ...
Classified by 015319
Exempt from General Declassification Schedule
of E.O. 11652, exemption category:
? 5B(1), (2), and (3)
Automatically declassified on:
date impossible to determine
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SECRET
NOFORN-NOCONTRACT-:ORCON
INTERNATIONAL ENERGY BIWEEKLY REVIEW
23 August 1978
Overview .............................................................................................
Some international companies plan to begin speculative buying of crude
oil earlier than in previous year, in anticipation of a price increase. Some
Increase by January 1979 appears inevitable; several companies expect it
to be on the order of 10 percent.
Saudi Arabian Oil Export Policy: Impact on the Oil Market ......................
The decision by Saudi Arabia to alter its oil output mix toward heavier
crudes should increase demand for light crudes from other sources and
tighten somewhat the current weak oil market.
OPEC Weighs Currency Basket Oil Pricing ............................................... 16
OPEC will likely consider indexing oil prices to the Geneva 11 basket of
currencies by yearend. The OPEC committee of financial experts that met
in July recommended indexing, with Saudi Arabia and the UAE standing
alone in opposition.
Saudi Arabia: Oil Reserves in the Untapped Oilfields .............................. 18
In recent press releases, Aramco has cited the existence of 37 oilfields in
Saudi Arabia, only 15 of which have ever produced oil. The impression
conveyed by these statements Is that the 22 unproduced fields contain
vast untapped oil deposits. In reality, the combined reserves in these
fields amount to only a fraction of the Saudi total.
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USSR: Development of the Gas Industry ................................................. 33
Soviet natural gas production will continue to increase rapidly and to
provide the USSR with a growing source of energy for domestic use.
Chartering Flurry Buoys Tanker Rates ..................................................... 36
Increased chartering activity has pushed rates to the highest level since
yearend 1977.
i
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SECRET
NOFORN-NOCONTRACT- ORCON
INTERNATIONAL ENERGY BIWEEKLY REVIEW
Some international oil companies plan to begin speculative buying of crude oil
earlier this year than in previous years. An oil price increase by January 1979 appears
inevitable; several companies expect it to be on the order of 10 percent. They are
concerned that some OPEC countries will restrict anticipatory company liftings of
crude. They are also aware that supplies in Saudi Arabia will be tighter than in the
past.
Saudi output is not expected to increase significantly for the remainder of the
year, mainly because of restrictive operating rules imposed earlier this year by the
Petroleum Ministry. The restriction called for the ratio of Arab Light to total Aramco
output to amount to 65 percent on an annual basis. Initial misunderstanding of how
this restriction was to be applied caused Aramco shareholders to overlift more than
300,000 b/d of this oil in the first half of 1978. The companies will have to compensate
for their overlift before yearend by holding down output of Arab Light.
Aramco already is producing close to capacity levels in other types of crude (Arab
Medium, Arab Heavy, and Berri) and does not have the flexibility for further shifts in
the immediate future. Only about 300,000 b/d in new capacity will be added later this
year when a new gas-oil separating plant begins operation at the Zuluf (medium
crude) field. This will be partially offset by reductions in sustainable capacity at other
fields, including Safaniya (heavy crude). Aramco's average production for second half
1978 is projected by two shareholder companies at 7.3 to 7.5 million b/d, with no
allowance for substantially higher production toward the end of the year. The
restrictions in Saudi Arabia are likely to shift demand elsewhere and could temporar-
ily tighten available crude supplies and strengthen OPEC price expectations.
The sentiment among a large majority of OPEC countries clearly favors some
form of compensation for import inflation and the declining dollar. Saudi Arabia
probably will be less disposed to argue for a continued price freeze than at any time in
the last three years. Oil Minister Yamani has reiterated his previously stated view that
the appropriate price path for oil is a series of gradual increases that should begin soon.
He indicated that market conditions were likely to tighten before the end of the year,
Note: Comments and queries regarding this publication are welcome. They may be
directed to-of the Office of Economic Research, telephone 25X1A
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making such an increase difficult to resist. Iran, which cooperated in holding the line
against a price rise in 1978, also clearly will favor an increase in 1979.
Officials of the OPEC Secretariat strongly deny rumors that an extraordinary
high-level meeting of the 13 member countries will be convened in September to
adopt some form of price revision. Several key OPEC states, including Saudi Arabia,
would prefer to defer any decision on prices until the December meeting of cartel oil
ministers in Caracas. (Secret Noforn-Nocontract)
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SECRET
SAUDI ARABIAN OIL EXPORT POLICY: IMPACT ON THE OIL MARKET
In February 1978, Saudi Arabia announced a policy of shifting its crude export
mix toward more heavy crudes. Aramco was ordered to reduce the share of its Arab
Light crude to 65 percent of the total oil flow. Saudi spokesmen have indicated that
the action is designed to bring the Saudi production mix more in line with the
proportion of crudes in its reserves. In addition, the resultant slowdown in light crude
output is consistent with the Petroleum Ministry's view that the giant Ghawar field
should be produced at a lower rate of production. This article will examine the impact
of this decision on Aramco liftings and the international oil market.
The decision by Saudi Arabia to alter its oil output mix toward heavier crudes
should increase demand for light crudes from other sources and tighten somewhat the
current weak market for OPEC oil. Under existing production rules imposed by the
Saudis, productive capacity in the Aramco area is insufficient to permit any wide
swings in overall output for the remainder of 1978. Moreover, the difficulty of selling
higher proportions of heavy crude in the current market is inhibiting demand for
Saudi oil. Light crude acquisitions from Saudi Arabia have fallen sharply; Aramco
shareholders and third party buyers have been forced to meet requirements from
alternative suppliers.
At least two of the Aramco shareholder companies forecast an OPEC price
increase on the order of 10 percent by yearend-an action that usually precipitates an
anticipatory surge in crude oil liftings. In past years, Saudi Arabia has been a key
supplier of advanced liftings. Advanced liftings from Saudi Arabia in fourth quarter
1976, for example, were about 1 million b/d. This year, however, will be an exception.
The consortium's average production for second half 1978 is projected at 7,3 - 7.5
million b/d with no allowance for substantially higher production toward the end of
the year. Customers reluctant to take 35 percent medium and. heavy crude are likely
to shift demand elsewhere. Although other countries may not be called upon to absorb
the entire volume of oil sales that otherwise would have been made by the Saudis, the
market could temporarily tighten before yearend.
The impact of reduced Saudi crude oil on the international refining industry in
the near term is manageable. Spare light crude capacity in several countries and the
additional supplies of light North Sea crude coming onstream will enable refiners to
satisfy product mix requirements. In the longer term, the Saudi action will encourage
long-delayed investments in secondary refining equipment needed to process larger
volumes of heavy, high-sulfur crudes.
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Saudi Production Rules
For several years, Saudi Arabia's petroleum ministry has talked of altering the
composition of crude output so that ratios would eventually approximate the
distribution of oil reserves. Saudi Arabia's most abundant crude is Arab Light, a 34
degree (API) gravity crude which comprises 43 percent of proved and probable oil
reserves but constituted 72 percent of Saudi output in 1977. Arab Light has been
disproportionately produced because of: (1) its desirability on the world oil market
relative to other Saudi crudes, (2) its ready accessibility from a couple of major
oilfields (Ghawar and Abgaiq), which historically had exceptionally low capital costs,
and (3) the discovery of these fields in the early period of Saudi oil development.
Saudi Arabia: Crude Oil Production by Type
Total
Aramco
Production
Arabian
Light
Percent
of
Arabian
Berri
Percent
of
Arabian
Medium
Percent
of
Arabian
Heavy
Percent
of
(Thousand b/d) (Thousand b/d) Total
(Thousand b/d)
Total
(Thousand b/d)
Total
(Thousand b/d)
Total
1966
2,390
1,575
65.9
0
0
220
9.2
595
24.9
1967
2,600
1,910
73.5
0
0
195
7.5
495
19.0
1968
2,835
2,250
79.4
0
0
130
4.6
455
16.0
1969
2,990
2,265
75.8
0
0
260
8.7
465
15.6
1970
3,550
2,485
70.0
20
0.6
255
7.2
790
22.3
1971
4,500
3,325
73.9
160
3.6
235
5.2
780
17.3
1972
5,735
4,025
70.2
420
7.3
285
5.0
1,005
17.5
1973
7,330
5,385
73.5
580
7.9
420
5.7
945
12.9
1974
8,210
6,000
73.1
625
7.6
545
6.6
1,040
12.7
1975
6,825
5,515
80.8
415
6.1
220
3.2
675
9.9
1976
8,340
6,500
77.9
750
9.0
245
2.9
845
10.2
1977
9,020
6,480
71.8
700
7.8
490
5.4
1,350
15.0
1978
7,500
4,880
65.1
600
8.0
2,020
26.9%
Technical officials in the petroleum ministry decided in October 1977 that oil
output at Ghawar should be substantially pared to hasten pressure restoration. This cut
dovetailed with the longstanding conservationist concerns on oil reserve drawdowns.
Moreover, the market was slack and Saudi Arabia's OPEC partners were pressing for
price increases to offset the revenues being lost because of lower exports. By
November 1977, oil minister Yamani apparently had approved a decision to limit
Arab Light crude to 65 percent of 1978 output-a decision that served simultaneously
to lower output from Ghawar, conserve Arab Light, and enhance the export prospects
of other OPEC countries.
The Saudis further decided in January 1978 that production mix guidelines
would be strictly enforced at an average annual level that must be reconciled at the
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? Aramco was not formally notified of the production ratio until mid-
February 1978.
? The company was not informed until April that the measure was
retroactive to 1 January.
? Until May, Aramco operated under the impression that the ratio would be
applied to the existing 8.5 million b/d overall production ceiling rather than
actual production.
Impact on Saudi Oil Output
The maximum amount of Arab Light that can be produced under ratio guidelines
is 5.5 million b/d, 65 percent of the 8.5 million b/d ceiling. This assumes that other
types of crude produced by Aramco (Arab Heavy, Arab Medium, and Berri) average
3.0 million b/d (the remaining 35 percent). Because of limited development or
production restrictions at fields which produce these other types of crude, available
capacity outside the Arab Light fields barely approximates this level.
The retroactive notification on implementation of the ratio restriction caused the
company to allow substantial overliftings. During the first half 1978, production of
Arabian Light averaged about 5.3 million b/d, more than 69 percent of total Aramco
Aramco: Crude Oil Production, by Type, 1978
Percent of
Total
Production
Ist Qtr
2d Qtr
Ist Half
(1st half)
Arabian Light ..........................................
5,725
4,795
5,260
69.4
Arabian Berri ..........................................
575
585
580
7.7
Arabian Medium ....................................
390
640
515
6.8
Arabian Heavy ..........................................
1,060 .
1,380
1,220
16.1
Total Aramco ..........................................
7,750
7,400
7,575
100.0
output. But a sharp tightening by the company management beginning in May caused
Arabian Light production in June to fall to 4.3 million b/d or 59 percent and Aramco
will have to hold Arab Light output down for the remainder of the year to compensate
for the overlift in the first half.
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The Aramco shareholders have agreed that each parent company is responsible
for keeping the ratio of its export stream in balance. Aramco is authorized to refuse
monthly nominations that run over the quota. Mobil and Exxon lifted a greater
proportion of Arab Light in the first part of the year than did Standard Oil of
California and Texaco; the former two companies will be somewhat more restricted in
the fourth quarter.
The enforcement of the crude type ratios and other rules has led to a drop in
Ghawar's oil output to about 3.6 million b/d in May and June 1978 compared to an
average of 5.3 million b/d in 1977. Although productive capacity will be added over
the near term at some fields which produce other than Arab Light crude, the Saudis
probably will gradually implement more stringent ratio rules than the 65 percent one
now in force. The net effect is that sustained production at Ghawar is not likely to
increase sharply within the next couple of years; and availability of Arab Light crude
from Saudi Arabia is not likely to rise substantially.
Oil Market Impact
The Saudi move to reduce light crude oil output should help tighten the current
weak oil market and increase demand for light crudes. Moreover, if the Aramco
partners do not significantly expand Arab Heavy and Medium crude production, total
Saudi output should remain below the production ceiling.
OPEC oil output was down sharply in first half 1978 but should rebound strongly
during the second half. OPEC output, including 750,000 b/d of natural gas liquids
(NGL), fell to about 29 million b/d during first half 1978-down nearly 3 million b/d
from the 1977 average. Saudi crude output led the decline as production fell about 15
percent, dropping nearly 1.4 million b/d.
Second half demand for OPEC oil is expected to average about 32 million b/d
(including NGL)-nearly 3 million b/d above first half levels. The large buildup in oil
stocks that occurred late last year has been worked off. Free World oil consumption in
January-May was 3 percent above year earlier levels. Preliminary data for May
indicate consumption was 4 percent above the previous year. The oil market will be
bolstered in the second half by a spurt in US oil import demand now that the Alaskan
oil flow has leveled off. US oil imports are expected to rise about 400,000 b/d in
second half 1978.
By fourth quarter 1978, demand for OPEC oil should strengthen even further
and average between 32 and 33 million b/d (including NGL). In calculating this
increased demand, toward yearend, we assume: (1) normal fourth quarter seasonally
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Underutilization
1st
2d
Available
of Productive
Capacity
1977
Qtr
Apr
May
Jun
Jan-May
Qtr
Capacity
(2d Qtr)
Saudi Arabia 2 ............
9,020
7,750
7,840
7,090
7,290
7,630
7,400
8,500
1,100
Iran ................................
5,660
5,470
5,610
5,720
5,630
5,550
5,650
6,500
850
Iraq ..............................
2,330
2,130
2,300
2,000
2,100
2,140
2;130
3,000
870
Venezuela ....................
2,240
1,830
2,230
2,220
2,320
1,990
2,260
2,300
40
Nigeria
2,100
1,580
1,690
1,720
1,890
1,630
1,770
2,300
530
Libya ............................
2,080
1,820
1,870
1,930
2,000
1,850
1,730
2,300
370
UAE ............................
2,010
1,820
1,750
1,870
1,840
1,830
1,820
1,870
50
Abu Dhabi ..............
1,660
1,440
1,370
1,480
1,450
1,440
1,430
1,460
30
Dubai ......................
320
350
360
370
370
360
370
360
10
Sharjah ....................
30
30
20
20
20
30
20
50
30
Kuwait ........................
1,780
1,670
1,780
1,650
1,740
1,690
1,720
2,000
280
Indonesia ....................
1,690
1,700
1,680
1,700
1,620
1,700
1,670
1,700
30
Algeria ........................
1,040
1,000
1,000
1,000
1,000
1,000
1,000
1,080
80
Qatar ............................
430
450
510
380
450
450
450
600
150
Neutral Zone ..............
370
380
420
320
380
380
380
600
220
Gabon ............................
230
220
220
220
220
220
220
225
5
Ecuador ......................
180
180
230
200
210
190
210
225
15
OPEC Total ................
31,160
28,000
29,130
28,020
28,680
28,250
28,610
33,200
4,590
Excluding Saudi
Arabia ...... ...............
24,700
3,490
' Excluding natural gas liquids.
s Excluding share of Neutral Zone production.
high demand, and (2) no drawdown in petroleum stocks--a reversal of normal
seasonal inventory reductions-because buyers will be anticipating a 1 January 1979
OPEC price increase, and (3) a continuation of US and Japanese demand for
government strategic oil storage.
The higher fourth quarter demand could tighten the oil market considerably.
With Saudi output expected to average only about 8.1 million b/d (7.6 million b/d for
Aramco, 300,000 b/d of NGL, and 200,000 b/d from the Neutral Zone) other
members of OPEC would be required to produce about 24 million b/d-close to the
current available productive capacity. Since stocks would be unseasonally high,
however, oil availability to consumers would not likely be curtailed. Moreover, the
tightness in the market would be short lived, easing considerably in first quarter 1979
when stocks would be drawn down and OPEC production slackens.
Some international oil companies are considering beginning their anticipatory
liftings unusually early this year out of a concern that, OPEC members might
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themselves prepare for higher prices by limiting production surges in the fourth
quarter. For many OPEC producers, large advanced sales are generally followed by
sharp drops in output after price increase takes effect and buyers begin working off
stocks. The oil exporting countries, therefore, stand to gain in revenue from selling
later at the higher prices. Moreover, unsatisfied speculative demand creates the
illusion of a tight market and reinforces demands for higher prices.
As a result, OPEC exports may increase before the end of the third quarter, and
the fourth quarter advance might not be as large as in some earlier cases. The
companies will weigh the costs of hedge buying (about 15-20 cents per barrel each
month to cover storage and financing) against the size of the price increase they expect
($1.27 per barrel of Saudi benchmark crude if a 10 percent increase is adopted).
Crude Oil Supplies
The additional supplies of non-OPEC crude which are expected to come on
stream this year along with the current excess capacity will ease the impact of the
Saudi restrictions on Arab light output in the near term. The North Sea will continue
to supply large volumes of higher quality crudes which will enable many refineries to
offset the decline in the availability of Arab Light. A 700,000 b/d gain is expected in
the North Sea this year. Mexican crude, similar in quality to Arabian Light, is also
being looked to as a possible replacement, and output in Mexico is expected to rise
nearly 400,000 b/d this year.
Spare capacity of nearly 1.8 million b/d is currently available in four key OPEC
countries-Iraq, Nigeria, Libya, and Algeria.
To examinethe effect of the Saudi output mix requirement on the oil market, we
divided crude production OPEC into three categories by gravity:
? Heavy crudes are considered to be all crudes with an API gravity below 32
degrees. Included in this group will be both Arabian Heavy (27 degrees) and
Arabian Medium (31 degrees).
? Medium crudes are all those of 32 degrees through 36.9 degrees gravity.
Arabian Light (34 degrees) is included in this group.
? Light crudes are those 37 degrees and above. Arabian Berri (39 degrees) is
included in this group.
The countries that ostensibly stand to be hurt the most from the Saudi output mix
requirement are the heavy crude oil producers. Iran, Venezuela, and Kuwait produce
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much of the world's heavy, high-sulfur crude oil. The drop in overall Saudi output,
however, has helped minimize the impact on heavy crude oil producers. Saudi Arabia,
the second largest producer of heavy crude oil in OPEC, has been unable to
significantly expand production of Arab Medium and Heavy crude oil. This has
contributed to an upward trend in the oil output in most other heavy crude oil
producing countries in recent months.
OPEC Countries: Heavy' Crude Oil Production, 1977
Production
(Thousand b/d)
Percent of
Country's Total
Production
Total ......................
10,610
34.0
Iran ....................
2,660
47.0
Kuwait ................
1,780
100.0
Saudi Arabia........
1,840
20.4
Venezuela ..........
1,630
72.8
Nigeria ................
1,060
50.5
Indonesia ..............
410
24.1
Neutral Zone ......
330
88.9
UAE ...................
320
15.9
Dubai ..............
320
100.0
Iraq ......................
250
10.7
Ecuador. ...............
180
100.0
Gabon ...............
150
66.4
Liftings of Iranian Heavy (31 degrees) crude remained relatively unchanged
during first half 1978, compared to full year 1977. Kuwait, which produces only a
heavy export blend, also managed to maintain production by cutting its price
(differential) by 15 cents per barrel. Kuwaiti output averaged almost 1.7 million b/d,
down less than 100,000 b/d from its 1977 annual rate.
Venezuela, another major producer of heavy crude, has not been adversely
affected by the Saudi restrictions primarily because of its favorable proximity to the
US market. Output in early 1978 had been running well below 1977 levels because oil
companies were working off stock built up last year. Venezuelan production has
recovered in recent months and averaged more than 2.3 million b/d in June.
Nevertheless, the market is glutted with fuel oil as evidenced by falling spot
market prices. Consumption of heavy fuel oil is weak due to sluggish industrial output
and substitution of alternative energy sources. At the same time, light product demand
is rising. Refineries are forced to accumulate large excess stocks of heavy fuel oil,
which they are having difficulty working off because of the volumes produced as they
refine crude to obtain light products.
23 August 1978 SECRET
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Along with the expected upturn in oil import demand anticipated later this year,
demand for heavy crude oil should pick up sharply in late summer when companies
begin rebuilding inventories for the 1978-79 winter.
Medium crude producers stand to benefit the most from Saudi restrictions on the
production of Arabian Light. Liftings of Iranian Light (34 degrees) increased nearly
20 percent in second quarter 1978 compared with first quarter. As overall demand
increases, production of Iranian Light will provide some flexibility for those refineries
forced to substitute for Arabian Light.
Iraq, another major producer of medium crudes, has not yet benefited from the
Saudi cutbacks. Iraqi production has fluctuated between 2.0 and 2.3 million b/d
during the first 6 months of 1978. With almost 900,000 b/d of spare capacity
available, Iraq could be an important source of medium crude as supply tightens.
Percent of
Production Country's Total
(Thousand b/d) Production
Total ...................... 13,790 44.3
Saudi Arabia........ 6,480 71.8
Iran ...................... 3,000 53.0
Iraq ...................... 2,080 89.3
Indonesia ............. 850 50.3
Venezuela .......... 540 24.0
Nigeria ........ 500 23.8
Qatar ......._....._.. 120 27.9
UAE .................. 80 4.0
Abu Dhabi ......... 80 4.7
Gabon ....... ........ 50 22.1
Neutral Zone ...... 40 11.1
Libya .. ..... 30 1.6
Algeria.. --------- 20 2.1
There has already been some indication that refineries will begin to look to Iraq rather
than Saudi Arabia for incremental crude supplies especially if they are required to
take a percentage of heavier Saudi grades along with Arabian Light. Baghdad has
indicated, however, that restrictions may be placed on the amount of crude available
in the fourth quarter.
The major African crude producers were forced to lower prices in both the first
and second quarters in order to maintain sales. Nigeria has offered an additional
discount to buyers willing to meet specified minimum lifting commitments in the
third quarter. Output, which had fallen substantially during late 1977 and early 1978
due to increased supplies of high quality North Sea crudes, has grown in recent
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Production
(Thousand b/d)
Percent of
Country's Total
Production
Total ......:..............
6,760
21.7
Libya ..................
2,050
98.4
UAE ....................
1,610
80.1
Abu Dhabi ......
1,580
95.3
Sharjah ............
30
100.0
Algeria ..................
1,020
97.9
Saudi Arabia........
700
7.8
Nigeria ................
540
25.7
Indonesia ..............
430
25.6
Qatar ..................
310
72.1
Venezuela ..........
70
3.2
Gabon ..................
30
11.5
months in response to the price reductions and Saudi restrictions. Nevertheless,
production remains below last year's levels. About one-half of Nigeria's capacity is in
heavy crudes with a very low sulfur content which makes them very competitive.
These crudes should not be directly affected by the Saudi restrictions.
Light crude producers in general should benefit because their crudes are
generally suitable for blending with Saudi heavy crude supplies. Libya, the largest
producer of light crude in OPEC, probably will make some gains from the Saudi
restrictions. In the Persian Gulf, Abu Dhabi is the leading producer of light crude;
however, the Emirate already is producing close to a recently imposed government
ceiling.
Price Trends
The limitations on Saudi light output have bolstered spot market prices of
alternative Middle East crudes while heavy crude oil prices remain weak. Spot prices
of light crudes from Saudi Arabia, Iran, and Iraq have risen from 9-15 cents per barrel
in the past few months. A reduction in the credit terms offered on Arabian Light have
in effect increased its spot price to $12.79 per barrel. Spot sales of Arabian Light are
being tied to the purchase of specified volumes of Arabian Heavy. With large volumes
of Arabian Heavy being made available, its spot price has continued to weaken,
primarily through the extension of credit terms. Credit terms have ballooned from 90
days in second half 1977 to as much as 150 days currently. Each additional 15 day
period is worth about 3-4 cents per barrel.
23 August 1978 SECRET
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 Approved For Release 2002/01/30 : CIA-RDP80T00702A001100040004-1
Trends in spot prices, when discernible, are usually a good indicator of future
changes in differentials (reflecting differences in quality and transportation costs of
various crudes). OPEC countries are waiting for the market to adjust before taking any
additional steps to remedy the gap between market values and official differentials. In
general, heavier crudes yield relatively more heavy products (fuel oil, asphalt, and
heavy gas oil) than light crudes which yield a greater proportion of light products
(gasoline, naphtha, kerosene, and diesel fuel).
Since light products, e.g., gasoline, often require more costly refining processes,
they are priced higher relative to heavy products which approach the residual portion
of the barrel. Therefore, crude lighter than Saudi benchmark (above 34 degrees API)
has usually sold for more than benchmark while heavier crudes (below 34 degrees API
gravity) have sold for less. Concomitantly, products with less sulfur burn cleaner and
are considered more desirable. Therefore, crudes with a lower sulfur content have an
increased value. Since Saudi benchmark crude has a sulfur content of 1.7 percent, the
sulfur differential of other crudes are determined by their relationship to this figure.
The disadvantage to refiners of the Saudi ratio restriction on crude types is caused
by the oversupply of heavy products. Aramco now requires all of its customers to
accept a certain volume of Arab Medium or Heavy with each purchase of Arab Light.
Aramco shareholders and third party buyers not only must evaluate the return on each
barrel of Arab Light they intend to run through a refinery, but also must calculate the
costs that must be absorbed in taking each barrel of Arab Heavy or Medium.
Although, Saudi Arab Light crude appears price competitive with other similar crudes
per se, e.g., Iranian Light, this requirement diminishes its true value. The obvious
remedy is to lower prices on Saudi heavy crudes so that each of the crudes remains
competitive. However, this is not a company decision, it is one that Saudi Arabia will
have to consider. If Riyadh were interested in increasing sales volume, it could adjust
its price differential. Thus far, the Saudis do not appear sufficiently concerned about
sales volumes to make this move.
Oil Refining
In the near term the international refining industry will be able to adjust easily to
the new Saudi production mix restrictions. Many primary and some secondary
refining facilities are either shut down or operating below capacity and there is
flexibility in the international refining industry to handle modest changes in crude
supply streams without serious disruptions. *
* This flexibility involves such factors as secondary refining facilities which enable a refinery to alter significantly the
product yield and specifications from a given barrel of crude; the ability of major companies to coordinate refining
operations of a number of refineries to meet their total product demand; and the ability of major companies to
transport crude end products for blending and other purposes.
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Nevertheless, selected refiners may have to handle larger proportions of heavy crude
than they would prefer with a resulting rise in their high sulfur fuel oil output.
With the basic crude distillation process common to most refineries outside of the
United States, Arab Heavy crude yields about 15 percent more fuel oil than Arab
Light. The yield of distillate is about 17 percent lower and the gasoline/naphtha
volume about 16 percent less. Moreover, the sulfur content of residual fuel oil from
Arab Heavy crude is about 1.25 percent higher than that from Arab Light.
The most modern refineries are equipped with vacuum distillation units which
reduce the residual yield significantly but at different rates for different crudes, i.e.,
about 70 percent on Arabian Light but only 50 percent on Arabian Heavy. Many also
include cracking and other secondary facilities which further increase gasoline and
distillate yields and reduce fuel oil yields. By use of a coker, for example, about 70
percent of the heavy residual from the vacuum unit can be converted into gasoline
and distillate, with the remainder being coke.
Light
Crude Unit
Unfinished
Gasoline
Middle
gistilletes
Residual
46.1
Vacuum
Unit
Vacuum
Gas
Oil
32.5
Heavy
Residual
13.6
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Although modern secondary refining techniques-catalytic and other types of
cracking in particular-can alter the mix of products produced from a given crude oil,
investment in the required facilities is costly,* and most West European refineries are
not equipped to do this further processing. Indeed, because European demand
traditionally has grown faster for heavy fuel oil than other major products, and
suitable crudes were available, catalytic cracking capacity accounts for about 5
percent of total refining capacity in Western Europe. Most European refineries thus
have limited flexibility to make significant changes in the product mix except by
changing the gravity of the crude refined.
The European refining industry shifted gears following the 1973 oil crisis. Faced
with surplus refining capacity and an expected shift in the composition of refined
product demand toward more lighter products, European refineries began plans for
expanding cracking capacity.
According to a recent industry study, about 540,000 b/d of new cracking capacity
is under construction or planned in the European Community (EC). The total outlay
for this is estimated to be more than $3.5 billion. Based on current plans, cracking
capacity in the EC countries will reach 2 million b/d in 1982 compared with 1.4
Thousand b/d
Under Construction or Planned
Installed (Indicated Year of Completion) Forecast
Capacity Capacity
1 Jan 1978 1978 1979 1980 1981 1 Jan 1982
Fluid Catalytic Cracker 840 82 83 110 32 1,147
Thermal Cracker ............. 316 36 5 0 0 357
Visbreaker .......................... 192 50 94 37 0 373
Hydrocracker .................... 76 14 0 0 0 90
Total ................................. 1,424 182 182 147 32 1,967
million b/cl on 1 January 1978. About 40 percent of the increase will result from
revamping oil crude units and their heaters, eliminating some of the surplus primary
distillation capacity. The EC accounts for about 80 percent of Western Europe's
refining capacity. Projects in non-EC Europe, particularly in Spain, will push the new
cracking capacity higher by the end of 1981.
Saudi Arabia's move to adjust its output mix should encourage refineries to
accelerate investments in sophisticated refining equipment needed to process larger
volumes of heavy high sulfur crude oil while meeting the mix of refined product
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demand. Oil Minister Yamani indicated in Geneva in June that Saudi Arabia's light-
heavy crude oil export balance may be tipped further toward the heavy end in the
future. Moreover, the composition of future oil product consumption will reinforce the
need for additional cracking capacity. Light oil product demand growth is expected to
outpace demand for heavier products.
In markets like the United States, sulfur limitations complicate the ability of
refiners to handle additional quantities of Arabian Heavy. In the United States,
available sweet crude supplies are declining, and the capacity to handle sour
(sulphurous) crudes needs to be increased through 1981 at a rate of about three times
that of the past four to five years. Although the United States has most of the world's
catalytic cracking capacity, this capacity was designed to use sweet (low sulfur) crude
and would corrode if charged with the sour heavy crudes now in excess supply.
The high sulfur heavy crude glut could be reduced by large increases in catalytic
cracking and desulfurization facilities. Although companies have plans to increase the
needed capacity, the current poor operating environment has discouraged new
investments. Moreover, even if refiners began constructing cracking facilities today, it
would be 1980 or so before they could be put on line.
? Primary distillation capacity charges crude oil and separates it into a few
basic fractions, usually naphtha (unfinished gasoline, middle distillates, and
residual). The capacity of the crude unit determines the size of the refinery.
In most cases, yields from the crude unit are considered unmarketable and
require further refining, treating, or blending.
? Secondary facilities charge the output of the primary facility or of other
secondary facilities to make finished marketable produce. The construction
and operating costs of these units is much higher than the primary unit. The
cracking units convert heavier products into lighter ones. Reforming converts
naphtha into high octane gasoline and hydroprocessing mainly removes
sulfur.
? Vacuum distillation is the most common secondary process. It charges
residual from the crude unit from which it extracts additional distillate
(vacuum gas oil) leaving a heavy residual as the remaining material. (Secret
Noforn-Nocontract-Orcon)
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The OPEC committee of financial experts that met in London 14-17 July to
discuss the effects of the decline of the US dollar recommended indexing oil prices to
the Geneva II basket of currencies. Saudi Arabia and the U AE stood alone in
opposition. Iran remained neutral at the meeting but is expected to come around to
the indexation side when the political climate is more favorable.
To be implemented, the plan must be adopted at the scheduled OPEC policy
meeting in December or at an extraordinary meeting that some OPEC price hawks
hope to convene in September. Even if an extraordinary meeting is held, Saudi dissent
is sufficient to delay all price increases until January and to moderate the size of the
eventual increase.
The majority of the OPEC experts meeting in London agreed on a new oil pricing
arrangement that has these features:
? Oil revenues would continue to be collected in US dollars.
? Oil export prices would continue to be quoted in US dollars.
? Dollar oil prices would be adjusted to match the value of a basket of
currencies.
? The dollar oil price would be adjusted on 1 October 1978 and then
readjusted annually or quarterly if the currency basket deviated by more
than 1 percent from the previously pegged base.
? Oil prices would be based on the currency basket values with a December
1976 parity.
The currency basket that won the support of the London meeting was the original
eleven country Geneva II basket modified to include the US dollar and weighted
according to OPEC imports from the countries whose currencies are included. The
Special Drawing Right (SDR) of the International Monetary Fund was rejected as a
currency basket on which to base oil prices because it was considered too heavily
weighted with the dollar. Since the last general oil price hike in January 1977, the
modified Geneva II basket has appreciated against the dollar twice as fast as the SDR.
The committee was very concerned about the impact OPEC decisions might have
on the US dollar and on the world economy. All of the experts acknowledged that a
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Suggested Currency Baskets for Pricing Oil:
Shares of Included Currencies
SDR
Recommended
Geneva II Basket
Import Weighted
Australian dollar ................................................................ 1.5
1.2
Austrian shilling .................................................................. 1.0
0
Belgian franc ...................................................................... 3.5
2.6
British pound ...................................................................... 9.0
10.0
Canadian dollar .................................................................. 6.0
1.9
Danish krona ...................................................................... 1.5
0
Dutch guilder ...................................................................... 4.5
3.4
French franc ...................................................................... 7.5
9.9
Italian lira .......................................................................... 6.0
8.3
Japanese yen ...................................................................... 7.5
18.1
Norwegian krone ................................................................ 1.5
0
South African rand .............................................................. 1.0
0
Spanish peseta .................................................................... 1.5
0
Swedish krona .................................................................... 2.5
2.0
Swiss franc ............................................................................
0
2.2
US dollar ............................................................................
33.0
24.5
West German mark ..........................................................
12.5
16.1
' The composition of the SDR was revised on 1 January 1978. The Danish krona and the South African rand
were replaced with the Saudi Arabian riyal and the Iranian rial.
Alternative Pricing of Saudi Bench Mark Crude
Dollar Price
SDR Price
Recommended
Geneva II Basket
Including US Dollar
1976
4th Qtr ........................................ 11.27
11.27
11.27
1977
1st Qtr
........................................
11.84
11.86
11.92
2nd Qtr
........................................
11.84
11.91
12.03
3rd Qtr
........................................
12.44
12.57
12.78
4th Qtr
........................................
12.44
12.77
13.20
1978
1st Qtr
........................................
12.50
13.21
13.75
2nd Qtr ........................................ 12.50
13.27
13.94
' Price paid by Aramco partners. Third party buyers pay the official sales price currently set at $12.70 per
barrel.
23 August 1978 SECRET
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switch to currency basket indexation might have a psychological impact that would
temporarily weaken the dollar. All except the Saudis, however, argued that indexation
would provide an incentive for other countries to support the dollar in order to avoid
triggering oil price increases. They also believed that the US trade balance would be
harmed proportionately less by oil price rises than would the trade balances of other
major countries-an effect that would tend to strengthen the dollar relative to the
other major currencies. (Secret Noforn-Orcon)
Although Saudi Arabia contains the largest accumulation of known oil reserves
in the world, a great many misconceptions persist concerning the size and location
of these deposits. This article examines the distribution of Saudi oil reserves,
particularly in the large number of reservoirs which have yet to be produced, and
describes development activity to date.
In recent press releases, Aramco has cited the existence of 37 oilfields in Saudi
Arabia, only 15 of which have ever produced oil. The impression conveyed by these
statements is that the 22 unproduced fields contain vast untapped oil deposits rivaling
those of the major fields now being produced. In reality, the combined reserves of
these virgin reservoirs amount to only a small fraction of the Saudi total.
Reserves by Field
Aramco estimates its proved reserves (which exclude the Neutral Zone) at 110.4
billion barrels at the end of 1977. The 15 producing fields contain 105.6 billion barrels
(96 percent); the other fields are estimated to have less than 4.8 billion barrels in the
proved category. Estimates of proved reserves by their nature are conservative.
Because many of the 15 fields now in production have been extensively drilled and
studied, a relatively high proportion of their total reserves already has been identified
as "proved." The untapped oilfields, on the other hand, have had only limited
development and "proved" totals are likely to rise significantly.
Aramco estimates its probable reserves (including the "proved" category) at
177.6 billion barrels. The 15 producing fields contain 165.2 billion barrels (93 percent);
the other fields are calculated to have probable reserves of 12.4 billion barrels. Unlike
proved reserves, the probable category is not necessarily conservative. Indeed, as
untapped reservoirs are developed and better understood, probable reserves in some
fields might be revised downward.
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Saudi Arabia: Approximate Location of Oilfields
Irani
Iraq *KUWAIT
Saudi Arahia Kuwatt 1
,,Neutral Zone... -
nnagl
(neutral zone) Maharah
Rlmthanf Fereidoan Oran)
Qibdibah Sa a~y arjon C
Suban 'Ribyan lawhah
Watban Jurayd Swarar Tll~anifa Baran
Abu Hudri" (uraln
Lana Persian
EI-Raba Bakr Khursaniya "
errs
FadhiR
Dammam - ,,MAN AMA Gulf
Bag~
bq iq 11 _ l
RIYADH*
Abu Jifan Qirdi
Mazalij rmaliyah
p~ y DOHA
caatar
23 August 1978 SECRET
-3r
ABU DHABI`
I.T_1
r. b.
Im ra~es
Srrait ``~1
ar VI
Nnrmur
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Saudi Arabia: Aramco Estimate of Oil Reserves in the
Producing Oilfields, Year End 1977
Billion barrels
Field
Proved
Reserves
Probable
Reserves
Possible
Reserves
Total ......................
105.6
165.2
225.4
Gbawar ..............
49.1
65.1
80.8
Abgaiq ................
3.9
7.0
9.0
Fadhili ...............
0.4
0.7
1.2
Abu Hadriyah ..
0.9
1.4
1.9
Harmaliyah .......
0.9
1.1
1.6
Damman
0.5
0.6
0.8
Qatif ..................
Z6
7.0
11.5
Marian ..............
1.3
6.0
9.8
Zuluf .................
5.2
13.8
18.1
Abu Safah .......
3.7
4.5
6.7
Khurais ..............
5.1
10.5
12.5
Khursaniyah .._..
1.9
2.0
4.3
Safaniya .............
14.1
25.2
37.5
Manifa ................
8.5
9.6
14.9
Berri _ .......... _ ....
7.3
10.6
14.8
Including Proved Reserves.
: Including Proved and Probable Reserves.
Aramco also has a category of possible reserves, estimated at 247 billion barrels.
This figure is calculated by the same method as probable reserves, but assumes the
application of enhanced recovery techniques to increase the amount of oil-in-place
that will ultimately be recovered. About 225.4 billion barrels (91 percent) of possible
reserves are found in the 15 oilfields currently being produced. The 22 untapped
oilfields contain only 21.5 billion barrels (9 percent) of possible reserves.
Development Activity
Aramco historically has found more oil each year than it has produced, but
production (3.3 billion barrels) and reserve additions in 1977 were approximately the
same. Exploratory drilling was virtually at a standstill last year. Reserve additions
came from development work at the 15 producing oilfields and primarily involved
shifting crude reserves from one category to another.
Although several of the untapped fields are in close proximity to producing
reservoirs, Aramco has not moved to develop them. Their potential output would be
more costly to develop, per barrel of daily capacity, than fields now producing. The
Saudis earlier had pressed to have some of these fields brought on line but have agreed
in the last year or so to set aside this effort, at least for the time being.
20 SECRET 23 August 1978
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Saudi Arabia: Aramco Estimates of Oil Reserves in the
Untapped Oil Fields
Field
Proved
Reserves
Probable
Reserves'
Possible
Reserves
Total ......................
4,750
12,446
21,505
Shaybah..............
2,852
4,664
9,329
Rimthan ............
452
964
1,982
Mazalii ................
338
1,162
1,493
Abu Jifan
279
759
976
Lawhah ............
276
1,330
1,817
Jurayd ................
163
302
'755
Suban ..................
72
124
218
Maharah ............
72
1,231
1,456
El Haba ..............
57
121
355
Jana ....................
43
190
558
Bakr ................
37
75
155
Qirdi ..................
36
99
141
Sharar ................
25
482
902
Ramlah ..............
15
107
220
Karan ..................
10
91
184
Ribyan ...............
9
613
'700
Dibdibah ..........
7
73
152
Habari ..............
3
6
10
Watban ..............
2
23
34
Jaham ................
1
16
39
Sabah ................
1
11
23
Kurayn ..............
0
3
6
'Including Proved Reserves.
2Including Proved and Probable Reserves.
Only one of the 22 untapped fields-Shaybah-has been substantially drilled.
The peripheral limits of the field are well defined. As a result, Shaybah accounts for
60 percent of total proved reserves in the fields not yet under production. It comprises
37 percent of probable reserves and 43 percent of possible reserves among these 22
oilfields. It lies, however, about 600 kilometers southeast of Dammam in the Rub Al-
Khali (Empty Quarter), a largely uninhabited desert region. The need for a pipeline to
link it to existing port-loading facilities and field-maintenance requirements (e.g., for
gas injection and water handling) would make exploitation more costly than expand-
ing capacity in currently producing oilfields.
Shaybah was included in an earlier Aramco plan to raise total sustainable
capacity in the Aramco areas to 16 million b/d by 1985. It was to have accounted for
500,000 b/d of this total. That plan has since been abandoned because of cuts in
investment funding and other constraints, and development: work at Shaybah has
ceased.
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The other 21 unproduced oilfields have been only marginally explored. Deter-
mining the extent of recoverable reserves and whether an oilfield is commercial
normally requires at least three or four wells. However, 15 of these fields have only
T
C
~Gy
.O Q
0
ti
c
o .r
a
Fa?
c3
~.G .C X i ~.G .
O O O 000 c o o 1=00
c o o - - - - - - - - - - - -
000 0 0 0 000
000 ... ==O 000
000 c o o 000 000
.^'. ~ ~ ?"G ' !. ~ p ?~ i~5 !. Sri ~ F+ /.~
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Saudi Arabia: Types of Wells Located in the Untapped Oilfields' (Continued)
Completed Wells
Total
Completed
Abandoned
Oil
Observation
Standing
Oil
Shut-in
Oil
Abandoned
Drilling
Drilling
Suspended
Qirdi
July 1976._....._
1
0
o
0
March 1977 ....
1
0
0
0
0
March 1978 ....
1
0
0
0
0
Sharar
July 1976..........
0
0
0
1
0
March 1977 ....
0
0
0
0
1
March 1978 ....
0
0
0
1
2
Ramlah
July 1976..........
2
0
0
0
0
2
0
3
March 1977 ...
2
0
0
0
0
2
0
3
March 1978 ....
2
0
0
0
0
2
0
3
Karam
July 1976..........
0
0
0
0
0
0
0
1
March 1977 ....
0
0
0
0
0
0
0
1
March 1978 ....
0
0
0
0
0
0
0
1
Ribyan
July 1976.. ........
1
0
0
0
0
1
0
0
March 1977 ....
1
0
0
0
0
1
0
0
March 1978 ....
1
0
0
0
0
1
0
0
Dibdibah
July 1976..........
0
0
0
0
0
0
0
1
March 1977 ....
0
0
0
0
0
0
0
1
March 1978 ....
0
0
0
0
0
0
0
1
Habari
July 1976..........
0
0
o
0
0
0
0
0
March 1977 ....
2
0
0
0
0
2
0
0
March 1978 ....
2
0
0
0
0
2
0
0
Watban
July 1976 ..........
1
0
0
0
0
1
0
0
March 1977 ....
1
0
0
0
0
1
0
0
March 1978 ....
1
0
0
0
0
1
0
0
Jaham
July 1976..........
2
0
0
0
0
2
0
0
March 1977 ....
2
0
0
0
0
2
0
0
March 1978 ....
2
0
0
0
0
2
0
0
Sabah
July 1976..........
0
0
0
0
0
0
0
0
March 1977 ....
0
0
0
0
0
0
0
0
March 1978 ....
0
0
0
0
0
0
0
0
Kurayn
July 1976 ..........
1
0
0
0
0
1
0
0
March 1977 ....
1
0
0
0
0
1
0
0
March 1978 ....
1
0
0
0
0
1
0
0
C O
G (D
OQ .s O
X' O
t~
(D
sz
rt Q
CD
?
O~ n
'There are no producing, injection, or water injection supply wells in any of these fields. Standing oilwells will be moved to the "Producing"
category when the field comes on stream.
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Crude Types
The 15 untapped oilfields which we are able to identify by crude types t have a
reserve ratio of light (Arab Light and "extra light") to heavy (Arab Medium and Arab
Heavy) crude fairly similar to those of the oilfields currently in production. However,
Shaybah's "extra-light" crude is the largest single crude category. If, as we expect, the
Saudi Arabia: Distribution of Reserves by Crude Type
Percent ire Producing Oilfields
Extra Light ......................
6.9
6.3
6.4
Berri
Arab Light ...._......_......... ..
52.3
45.5
42.3
Chawar, Abqaiq, Fadhili, Abu Hadriyah,
28.0
Harmaliyah, Damman
Qatif, Marian, Zuluf, Berri, Abu Safah, Khurais,
Arab Heavy ......................
21.6
21.2
23.3
Khursaniyah
Safaniya, Manila
Total .............................
100.0
100.0
100.0
Percent in Untapped Oilfields
Extra Light ........ . _._.......
60.0
37.5
43.4
Shaybah
Arab Light ........................
1.7
2.3
3.3
Jana, Qirdi
Arab Medium ....................
21.8
37.0
27.7
Mazalij, Abu Jifan, Lawhah, Suban, Maharah
Arab Heavy ......................
16.5
23.2
25.6
Rimthan, Jurayd, El Haba, Bakr, Sharar, Ribyan,
Dibdibah
Saudis reduce the allowable production ratio of Arab Light to other crudes from 65
percent of the total to 55 or 50 percent in the next couple of years the reduced
availability of Saudi light crudes may eventually make the development of Shaybah
commercially attractive. This assumes, however, that this crude type (similar to Berri)
will not fall within quotas established by the Saudis. (Confidential Noforn)
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25X6
USSR: DEVELOPMENT OF THE GAS INDUSTRY *
Soviet natural gas production will continue to grow rapidly and to provide the
USSR with a growing source of energy for domestic use or export through the 1980s.
? Soviet natural gas reserves of 28 trillion cubic meters (cu m) are possibly
the world's largest and would provide more than 80 years output at the 1977
production level of 346 billion cu m per year.
* This article summarizes the key judgments of the research paper USSR: Development of the Gas Industry, ER 78-
10393, July 1978, unclassified.
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? Gas extraction grew from 12 billion cu m in 1956 to 346 billion cu m in
1977, an impressive average annual rate of 17 percent, and should continue
to grow at about 6 percent a year into the 1980s, reaching 415 billion to 420
billion cu m in 1980, 560 billion to 600 billion cu m in 1985, and possibly
more than 700 billion cu m by 1990.
? The Soviet gas trunkline system now extends well over 100,000 kilometers
(km), linking major gasfields in West Siberia and Central Asia with Soviet
and European consumers. Although the Soviets do not yet possess a gas
distribution system capable of satisfying all consumer needs year-round, they
have made some progress in that direction.
? Natural gas will become an increasingly important hard currency earner
for the Soviets in trade with the West. It already is a major factor in the
Soviets' position as chief energy supplier to Eastern Europe.
? Gas will contribute more than any other fuel to increments in total Soviet
energy production between now and 1990. By 1990 it could constitute the
largest single source of domestically produced energy.
Development of the Soviet gas industry through the 1980s will focus on West
Siberia.
? Gas production at older fields in the European USSR has begun to decline
fairly steeply and growth in Central Asia has slowed.
? West Siberia's northern Tyumen' Oblast holds over two-thirds of Soviet gas
reserves, and new discoveries are continuing to add to the region's reserves.
? Present Soviet plans call for West Siberian gas production to increase from
68 billion cu m in 1977 to more than 150 billion cu m in 1980.
? The region will account for up to 80 percent of all additions to Soviet gas
production during 1976-80 and will provide virtually all increases in output
in the 1980s.
Several persistent problems will confront the Soviet gas industry in the next
decade, restraining growth in output and raising costs of gas extraction and
transport.
? Pipeline capacity has continually lagged behind drilling and has caused the
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gas industry to fail to fulfill annual and five-year plans. It probably will be
responsible for below-plan production in 1980.
? Inadequate compressor power is a principal bottleneck in expansion of
pipeline capacity and will remain so at least through 1980. Constructing
pipelines in permafrost has also required increased time plus greater
investment-particularly in Western large-diameter pipe-and the costs of
gas transport are rising substantially.
? Gas extraction costs, already rising faster than those of any other Soviet
energy industry, will continue to grow markedly. Increasing well depths-
particularly in older producing regions-are a major cause, as are the high
costs of gasfield development in the Siberian arctic.
? West Siberia's northern Tyumen' Oblast will become the source of most of
the gas industry's future problems as well as the base for production growth.
Inadequate infrastructure and technical difficulties posed by drilling, pipe-
laying, and pipeline operation in the severe climate probably will limit the
development pace.
? The older fields in the European USSR and Central Asia will become an
increasing drag on national gas production, absorbing a continued high level
of investment while output stagnates or declines.
? Soviet shortcomings in production of large-diameter gas pipe, compressor
stations, and exploration, drilling, gas processing, and other equipment will
lead to continued Soviet dependence on imports from the West.
Natural gas will not prove a panacea for Soviet energy problems caused by a
future decline in oil production.
? Gas will prove difficult to substitute for oil in several sectors of the Soviet
economy, particularly agriculture and transportation. Gas consumption will
continue to grow in industry, where its use is already substantial. Electricity
generation will also provide a significant area of gas-for-oil substitution in
the early 1980s.
? Gas will not match oil as a hard currency earner by 1980, although it
probably will become the leading Soviet trade commodity well before 1985,
earning several billion dollars a year. (Unclassified)
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CHARTERING FLURRY BUOYS TANKER RATES
Increased chartering activity in all major loading areas has pushed the Mullion
Index for voyage charters in the crude trades to Worldscale 80, its highest level since
the yearend 1977 rush to move oil cargoes before the anticipated OPEC price boost.
The current firming trend in charter rates began in the Persian Gulf, where average
rates for shipments to Europe on very large crude carriers (VLCCs) have risen from
$3.38 per ton in early June to more than $6.76 a ton, as of 18 August 1978. At these
levels the efficient owner with tankers in operation is better off hiring his ships out
than keeping them idle or putting them into lay-up. Operating costs are covered, but
most capital costs are not.
Voyage-chartered ships carry less than one-half of the oil loaded in the Gulf.
Ships owned and time-chartered by the oil companies carry a majority of the cargoes.
The volume carried in voyage-chartered ships varies considerably from week to week
because shippers use such vessels for their marginal requirements.
Voyage chartering on the Gulf-to-Europe route reached a historic high of 4.3
million tons during the week ending 4 August, up from around 1.3 million a week the
previous month, but slumped again during the week ending 11 August to 1.8 million
tons. Adding to the pressure of increasing demand, the short-term supply of ships
available for charter in the Gulf (operational tankers waiting for business) dropped
sharply from 3 million deadweight tons (dwt) as of mid-June to 0.8 million dwt in
mid-July and was probably eliminated entirely by early August.
By mid-July the revitalization of the tanker charter market had spread to the
Mediterranean, Caribbean, and West African loading areas where both voyage-
charter volumes and rates have also risen. Rate increases have been tempered by a
larger short-term supply of tankers in these regions.
The increase in voyage chartering reflects a rise in loadings rather than a shift to
oil company owned or controlled tonnage. Resurgence in demand has been attributed
in some quarters to an early initiation of advanced liftings in anticipation of an OPEC
price increase. Japan's implementation of its scheme to store oil in large tankers has
undoubtedly put short-term pressure on rates. This program involves only 5 million
dwt of tankers, however, at a time when the worldwide surplus is close to 150 million
dwt.
Ironically, the current market upturn began just as the tonnage of laid-up oil
carriers was reaching a record high-56 million dwt at the end of June. Even though
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Voyage Charter Rate Indexes'
Weighted Average for VLCC
Voyage Charters Persian Gulf
o(.1 1 111 1ili[ilIiIIIii]IIIIIiiiilililii il,1,IIIliIIIIli
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
1. These indexes apply only to charters for the carriage of so-called-"dirty" cargoes which include crude oil and
heavy petroleum products such as residual fuel oil.
2: A table of oil shipment costs on various trade routes for a standard tanker with fixed parameters (size, speed,
fuel consumption, manning requirements, etc.) used on the tanker market to express voyage charter rates.
3. This index reflects all rates available to. the compilers (the London tanker brokerage Mullion and Company) for
single voyage charters of tankers In all trades agreed to (fixed) during the week in question and all previously
fixed: single voyage charters still Ineffect on Friday of that week.
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high reactivation costs and uncertainty over the duration of the current chartering
wave will discourage many owners from taking tankers out of lay-up, enough owners
probably will be returning tankers to service to cause a leveling of rates within a
month. (Unclassified)
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