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2
Yvonne Levy*
At pr~sent,WestCoast refineries are unable
to utilize all of the crude oil produced on the
Alaskan. North Slope, largely because of the
eff~9ts. of restrictive governmental regulations.
Re~trictions on sulfur-dioxide emissions, for
example, have forced refiners to install more
desulfurization capacity in order to process the
high-sulfur Alaskan crude. At the same time,
price controls on refined petroleum products
have reduced the incentive for refiners to invest
in such capacity-or to invest in the capacity
required to tailor the Alaskan end-product mix
closer to the regional end-product demand.
Other regulations have forced the oil industry
to use inefficient methods for delivering surplus
Alaskan oil to other regions of the United
States. At present, U.S. tankers carry that oil to
Gulf Coast refineries through the Panama Canal, which is a relatively high-cost method for
dealing with the surplus. However, this is the
only currently available option, because of laws
which effectively ban Alaskan oil exports and
prohibit the use of foreign vessels in U.S.
intercoastal trade, and because of lengthy permit processes which have long delayed the
construction of domestic pipelines. These difficulties also reduce the incentive to develop
Alaskan resources, since North Slope producers' higher transportation costs reduce the
wellhead price which they now receive.
The proposals for eliminating the surplus
generally focus on increasing the ability of West
Coast refineries to utilize heavy high-sulfur
crude or on developing alternative transportation and marketing options. Some observers
propose expanding West Coast refinery desulfurization capacity, or even constructing a desulfurization facility at the terminus of the
Trans-Alaska pipeline system itself. Others pro* Economist, Federal Reserve Bank of San Francisco.
pose transportation alternatives, including pipelines to. convey the surplus to other domestic
markets or international exchange ("swap")
arrangements which would achieve the same
aim indirectly.
Other alternatives have hardly been considered, although they might be even more efficient
methods for dealing with the Alaskan-oil problem. These include the possible relaxation of
California environmental-quality standards and
the use of foreign-flag tankers in U.S. intercoastal trade. Policymakers apparently believe
that such measures would undermine other
high-priority national objectives, such as protection of the environment and national security, and hence they will not be discussed further
here. This paper instead analyzes certain transportation and marketing alternatives, to determine whether the various options would help
achieve the key objective of the nation's energy
policy: namely, to reduce U.S. dependence on
foreign-oil imports and to reduce its vulnerability to supply interruption.
The first section provides background information on the development of the Alaskan
North Slope oil reserves and the reasons for the
current surplus relative to West Coast refinery
capacity. It attributes the surplus largely to the
particular density and sulfur characteristics of
North Slope crude, and to the limited refinery
capacity existing on the West Coast for processing that crude into the products demanded by
end-users in the region. The second and third
sections consider the alternatives to the current
inefficient method of dealing with the surplus,
that is, shipment by U.S. flag tanker to Gulf
Coast refineries through the Panama Canal.
The analysis shows that export exchanges
represent the most efficient method of marketing Alaskan North Slope crude, and thus would
result in the greatest producer cost savings on
Dennis Barton provided research assistance for this paper.
3
the crude that otherwise would be shipped
through the Panama Canal. As a result, exchanges would provide the greatest producer
return at the wellhead, and thus the greatest
incentive for increased Alaskan oil production.
On the other hand, exchanges would increase
gross imports relative to other alternatives, and
thus would embody a higher risk of supply
interruption. Largely on these grounds of energy security, Congress to date has maintained
restrictions on the export of Alaskan oil.
I. Development of the Alaskan Oil "Surplus"
The huge Prudhoe Bay oil deposit on the
Alaskan North Slope-estimated to contain
some 9.4 billion barrels of crude-was discovered in early 1968, but none of that oil came
to market until nine years later, because of
environmental controversies and delays in developing a delivery route. But with the help of
the energy-crisis atmosphere created by the 1973
Arab oil embargo, Congress authorized the
accelerated construction of the Trans-Alaska
Pipeline System. The 789-mile pipeline, linking
the vast Prudhoe Bay field with the southern
Alaskan port of Valdez, was completed in July
1977 with an initial capacity of 1.2 million
barrels per day, and with an ultimate design
capacity of 2.0 million bid. North Slope production began in mid-I977, and output gradually expanded to the 1.2 million bl d level by
September 1978, with a further increase to 1.5
million bid attained by late 1979.
The process was complicated by the fact that
West Coast refineries lacked the sp~cialized
equipment required to process the relatively
heavy, high-sulfur Alaskan crude, to make the
end-product mix produced from that oil Ganform more closely with the composition of the
region's end-product demand. 2 Gasoline, jet
fuel, diesel and other "light" products distilled
in the initial stages of refining account for the
bulk of West Coast product demand. But Noah
Slope crude yields a relatively large percentage
of high-sulfur residual products, such as heavy
fuel oil, asphalt and petroleum coke. Moreover,
even after those products are removed in the
refining process, a heavy residuum remains,
which can be converted into the desirable light
products only through the use of additional
expensive cracking equipment.
The high-sulfur content of North Slope crude
also poses major emission-control problems
under current air-quality regulations. California
utilities, under pressure to reduce their sulfurdioxide (SO 2) emissions, require residual oil
with a sulfur content of no more than 0.5
percent. But Western refiners cannot provide
utilities with a fuel oil of that type from North
Slope crude without the use of expensive desulfurization equipment.
Yet the economic environment under domestic oil-price controls has not provided refiners
with the incentive to make those necessary
investments. Under the Federal price-control
system instituted in 1973, refiners were permitted to raise their prices above the May 15, 1973
level to reflect increased costs. But for certain
products-gasoline, diesel fuel and home heating fuel-refiners could allocate increased costs
only proportionally to the volume of such
products produced. 3
For items such as gasoline, production costs
are disproportionately high relative to their
Reasons for the surplus
The Federal Energy Administration and the
oil industry originally believed that West Coast
consumption of refined petroleum products
would continue to grow at the 5-percent annual
rate experienced during the decade preceding
the 1973 oil embargo. They thus predicted that
West Coast (District 5) refineries would be able
to utilize the entire production of Alaskan
North Slope crude anticipated during the first
few years of pipeline operation. I But the Arab
oil embargo, the attendant sharp run-up in
world oil prices, and the 1974-75 recession all
led to an alteration of historical consumption
patterns. West Coast consumption of refined
products increased at only a 2Y2-percent annual
rate during the recession and recovery of the
1974-78 period, so that refinery crude-oil requirements fell considerably below the original
forecasts.
4
share of total production, so that refiners have
been unable to pass on all of the increased costs
of such items. Indeed, price controls on gasoline
were liberalized to permit a better recovery of
costs only in March 1979. Moreover, strict
environmental requirements often have posed a
roadblock to the expansion or modification of
refinery capacity. Environmental regulations
and price controls on refined products thus have
been largely responsible for the surplus of
Alaskan oil on the West Coast.
Chart 1
Sources of West Coast (D istrict V) Crude Oil Supplies1
Refinery Inputs (thousands of barrels per day)
“Backing out” imports
1 District V includes Alaska, Arizona, California, Hawaii,
Nevada, Oregon and Washington.
Nevertheless, within the limits of their techni
cal capacity to process relatively heavy, highsulfur crude, West Coast refineries have been
able to use North Slope crude to “back out” or
displace foreign oil of comparable quality. This
is shown in the changing composition of West
Coast refinery crude-oil supplies (Table 1 and
Chart 1). As Alaskan oil production rose from
about 191,000 b/d to 1.2 million b/d over the
1975-78 period—reflecting the start-up of Prud-
hoe Bay production—that state’s share of total
West Coast supplies rose from 10 to 44 percent.4
California’s share meanwhile dropped from 45
to 35 percent, although that state experienced
rising output over the period. More important
ly, foreign oil imports declined sharply both in
absolute volume and as a share of total supplies
(from 43 to 21 percent). By 1978, imports of
Table 1
Origins of West Coast Crude Oil Supplies1
(thousands of barrels per day)
Percent of
Total Supplies
1978
1975
1976
1977
1978
1975
1076.1
1068.7
1424.4
2171.6
54.7
79.3
191.3
882.7
173.1
463.6
12 16.0
9.7
44.4
893.2
957.8
951.2
44.9
34.7
All Other West Coast*2
2.1
1.8
3.0
4.4
.1
.2
Imports From Other States
38.7
17.6
3.9
2.2
2.0
.1
851.5
1008.8
1040.8
564.9
43.3
20.6
1966.3
2095.1
2469.1
2738.7
100.0
100.0
Total West Coast Production
Alaska
California
Foreign Imports
Total Crude Oil Supplies
' Including lease condensate (i.e., natural gas liquid).
2 Arizona and Nevada.
Source:
U.S. Department of Energy, Energy Information Administration, Energy Data Reports: Crude Petroleum,
Petroleum Products, A nd Natural Gas Liquids; and Energy Data Reports: Crude Petroleum, Petroleum Products,
A nd Natural Gas Liquids in P.A.D. District V.
5
1.0 million bid of the 1.2 million bl d flowing
from Prudhoe Bay. But in November, a project
to raise the capacity and flowthrough. of. the
Trans-Alaska pipeline to 1.5 million bl d was
completed, raising the surplus by year-end to
about 500,000 bid. The 1.0 million bid now
being absorbed by refineries may represent just
about. a maximum, given the limitations on
their capacity for processing high-sulfur crude.
As a result, a 500,000 bid surplus of Alaskan oil
now exists in terms of Western refinery consumption.
sour (high-sulfur) crude from Saudi Arabia,
Iran and other Persian Gulf nations had largely
been displaced (Table 2), and import~of sweet
(low-sulfur) crude, except. Indonesian. sweet
crude, also declined over the 1975-78 period.
Recent data suggest that further displacement
of imports occurred during the first half of 1979.
During that period, the shortage of foreign oil
and consequent shortage of gasoline>encouraged West Coast refineries to run less efficiently so as to make additional use of North Slope
oil. Indeed, as 1979 progressed, the Alaskan oil
surplus dwindled as those refineries absorbed
Table 2
Origins of West Coast Crude 011 Imports
(thousands of barrels per day)
Percent of
Total Supplies
Sweet Crude, by Source
1975
1976
1977
1978
1975
1978
Indonesia
Other S.E. Asia l
295.4
450.0
424.1
386.4
34.7
68.4
5.3
15.2
60.6
41.6
.6
7.4
Canada
South America 2
Africa]
163.5
87.3
20.1
11.9
19.2
2.1
5.3
4.3
4.3
1.8
.6
.3
22.2
30.0
10.5
0
2.6
0
Total Sweet
491.7
586.8
519.6
441.7
57.7
78.2
95.6
179.7
197.8
15.8
11.2
2.8
49.9
84.5
125.9
80.1
5.9
14.2
Iran
Other Persian Gulf4
South Americas
105.2
90.0
99.8
0
12.4
0
96.8
45.3
54.0
25.3
11.4
4.5
12.3
22.5
43.7
2.0
1.4
.3
Total Sour
359.8
422.0
521.2
123.0
42.3
21.8
851.5
1008.8
1040.8
564.9
100.0
100.0
Sour Crude, by Source
Saudi Arabia
United Arab Emirates
TOTAL WEST COAST
Malaysia and Brunei
Bolivia and Chile
] Algeria, Angola, Gabon, Libya, Nigeria, and Tunisia
4 Egypt, Iraq, Kuwait, Oman, Qatar
5 Ecuador and Venezuela
I
2
Source:
U.S. Department of Energy, Energy Information Administration, Energy Data Reports: Crude Petroleum.
Petroleum Products, and Natural Gas Liquids.
6
II. Alternatives for Dealing with the Surplus
The present 500,000 bl d "surplus" of Alaskan
North Slope crl1de is noW' shipped by U.S. flag
taIlk~rs.frorn •. t~e . ;\lfsk~ . IJipeline terminusft
Vald.fi.g/ito.(iulfCoast •.• refineries • through the
Pa.nama Canal (Figure 1). But this is one of the
most costly ways of marketing Alaskan oil,
thostly because the Jones Act, of 1917 vintage,
requires that all domestic cargoes be carried by
U.S. flag vessels. The present transportation
system also yields Alaskan producers a relatively lower price at the wellhead. s This is because
petroleum's selling price in any given market is
based on the average landed price for comparable quality OPEC crude, which means that
~orth Slope producers must absorb transportation costs in order to compete agaInst foreign
crude in those markets.
In the interest of raising the wellhead price,
those producers have proposed several alternatiyes for dealing with the surplus Alaskan. oil.
These alternatives have included: 1) construction of additional desulfurization and cracking
911pacity on the West Coast; 2) construction of
()"erland pipelines to U.S. refineries farther
East; and 3) exchanges with foreign nations on a
barrel-for-barrel basis. In the latter two cases,
domestic markets farther East would eventually
receive the Alaskan oil, or equivalent amounts
of foreign oil acquired through exchanges.
on the other hand, could supply West Coast
refineries with larger quantities of low-sulfur
crude, well-suited to present refinery configurations and end-product demand.
Pipeline option
Some government and industry leaders have
proposed building pipelines as a means
transporting the West Coast surplus to U.S.
markets farther East (Figure 1). Domestic altef..
natives include the Sohio(PACTEX) line or the
Northern Tier line, both of which would traverse
only U.S. territoI}'. But there are several Canadian alternatives~the Trans-Mountain, Kitimat
and Foothills pipelines~although only the former appears to bea viable competitor to the U.S.
pipelines.
of
a) Sohio pipeline. In 1974, Standard Oil
Company of Ohio (Sohio)~which is a partnet
of British Petroleum, the major North Slop¢
producer~began to develop plans for a $1billion project to move crude from Long Beach,
California, to Midland, Texas. The proposed
PACTEX system would include construction of
a terminal at Long Beach, conversion of 778
miles of an existing natural-gas pipeline, and
construction of about 215 miles of new pipeline,
with an initial capacity of about 500,000 bl d.
In March 1979, however, Sohio announced
that it was abandoning the PACTEX project
because of delays in pipeline authorization,
which it said made the project no longer economically feasible. The company had counted
on the pipeline being in operation in 1978, when
the surplus first developed. But now, even if
construction were to start immediately, the
pipeline would not be completed until sometiII1~
in 1982~not too long before a projected decline
in Prudhoe Bay production. The company
claims that it could not justify the pipeline on
the basis of as yet undiscovered and undeveloped Alaskan resources. The pipeline may not
be completely dead, however, because the Fed...
eral goverllrnent would like to revive the project
on national-security grounds.
b) Northern Tier pipeline. The Administration
has announced its support for a $1.4-billion
Refinery modification option
The West Coast (District 5) market~serviced
primarily by California and Washington
terineries~is the most attractive domestic market for Alaskan crude. West Coast sales yield
North Slope producers the greatest price at the
wellhead, because of that market's proximity to
the production source and therefore low transportation costs. The surplus thus could be
r~duced ifoil firms installed the cracking capacity and desulfurization equipment necessary to
handle greater amounts of North Slope crude,
eitherate~isting West Coast refineries or at new
f~cilities> near the Trans-Alaska pipeline terminus at.yaldez.••. Retrofitting existing refineries
would enable those plants to utilize greater
quantities of high-sulfur Alaskan crude. Construction of a desulfurization plant at Valdez,
7
Figyre .1
Alaskan Crude.QU .·IransportationAlternatives
...............
Current tanker route via Panama Canal
Existing pipelines
Proposed pipelines
-
-~
Proposed tanker route to Japan (equivalent amount to be returned to United States)
Note: The Trans-Mountain proposal calls for the reversal and possible expansion of that existing east-to-west pipeline.
project developed by a· number of railroads,
consulting firms· and smalloil companies, which
would move crude between Port Angeles, Washin.gton, and Clearbrook, Mirinesota, and thence
by existing pipelines torefirieriesinthe Midwestern states. The project would entail construction
of a maririe terminal atP6rt Angeles, and a
1,568-milepipelinefrom thereto Clearbrook,
with initial capacity of 600,000 bl d.
The pipeline would be especially helpful for
refineries in the Northern Tier states bordering
on Canada (such as Montana, North Dakota
and Minnesota). Those refineries are almost
wholly dependent upon Canadian crude, which
will become unavailable after 1982 because of
Canada's own domestic needs.
Export·exchange option
co has been frequently mentioned· as a possible
third party in such a swap arrangement. However,this option remains precluded by the
Trans-Alas~a Pipeline Authorizatioll Act of
1973 and also by the 1977 and 1979 amendments to the Export Administration Act.
The 1973 legislation prohibits exports of
domestic crude oil transported by pipeline over
Federal rights-of-way---unless such exports are
exchanged with adjacent nationS to promote
transportation efficiency, or unless the President finds that an export transaction is in the
national interest and does not "diminish the
totalquaritity or quality of petroleum available
to the United States." The restriction.s have been
tightened even further by· the 1977 and 1979
amendments to the Export Admin.istration Act.
The latest legislation requires the President to
certify that any export proposal would actually
help reduce the cost to refineries, distributors
and consumers, and also requires explicit Congressi()nal approval of any export transaction.
Under export-exchange (swap) arrangements,
Alaskan. oil would be shipped to Japan, .in
exchange for which an equivalent amount of
Japan-bound foreign-produced crude would be
diverted to the U.S. Gulf or East Coasts. Mexi-
III. The Altemativesand National Energy Policy
OPEC oil alone rising from 20 to 42 percent of
total consumption. Between 1972 and 1977, oil
imports in value terms jumped from $5 billion
to $45 billion, and thus accounted for a major
share of the nation's deteriorating foreign-trade
balance. This situation reflected the effects of
domestic oil-price controls in encouraging the
growth of consumption and discouraging in-
In deciding upon the appropriate method for
dealing with surplus Alaskan oil, policymakers
should consider not only the relative efficiency
of the various options, but also the contribution
they can make to the nation's energy-policy goal
of reduced U.S. dependence on foreign oil.
Alaskan North Slope production, since coming
on stream in July 1977, has contributed significantly to that goal. Production has risen gradually to a current level of 1.5 million bl d, displacing a roughly equivalent amount of foreign
crude oilatU.S. refineries on the West and Gulf
Coasts.
Chart 2
U. S. Petroleum Consumption
Barrels/ Day
(Millions)
20
Impottproblem
Prior to the start-up of Prudhoe Bay producUnited States had made no real progress in slowing the import flow, despite the
nearly fivefold increase in world oil prices over
the 1972-77 period. On the contrary, imports of
crudean.drefiriedptoducts ··almostdoubled
between 1972 and 1977, toa record high of 8.8
millionb I d (Chart 2). Over the fiVe-year period,
imported oil jumped from 29 to 46 percent of
the nation's total petroleum requirements, with
16
o
1965
1970
1975
'Crude oil and refined petroleum products
9
1978
creased domestic production. Between 1972 and
1977, U.S. consumption of refined petroleum
products rose by 12 percent, while domestic
crude production dropped by 13 percent.
Late in 1977, however, North Slope oil began
to displace some foreign crude of comparable
sulfuq:ontent and gravity, not only in the West
but in other areas of the nation. Imports of
crude and refined products fell nearly 9 percent
in volume and 6 percent in value terms in 1978.
This displacement occurred because North
Slope producers had priced their crude competitively on a delivered-cost basis with
comparable-quality foreign oil, and because
refiners purchasing North Slope crude had
received the same entitlement benefits for Alaskan as for foreign oil. 6
But imports increased again in 1979, despite a
slight decline in U.S. petroleum consumption.
This came about as domestic crude-oil production resumed its decline in the face of a stable
North Slope production rate of 1.2 million
bl d at least until late in the year when production rose to 1.5 million bid. In fact, Energy
Department projections suggest that imports
could rise to 13 million bid by 1990, even with a
modest 2-percent average annual increase in
U.S. petroleum consumption. 7 At that point,
imports would comprise more than 50 percent
of total domestic consumption. That level of oilimport dependency could place a severe strain
on the U.S. balance of payments-~and on the
international value of the dollar-especially in
view of the expected continuation of sharp
increases in world oil prices. 8
To forestall that development, the Administration announced its proposed oil-import reduction program in July 1979. Over the longrun, the program focuses heavily on the
development of synthetic fuels to reduce import
requirements. However, it will take at least a
decade or more for the production of oil from
coal and shale to reach a significant volume. In
the short-run, therefore, a solution will have to
involve both the conservation and increased
domestic production of conventional crude oil.
Table 3
Estimated Undiscovered Alaskan
Oil Resources, 1975
Range of Estimates
(billions of barrels)
Low
Mean
High
37
56
81
6
12
19
16%
21%
23%
10
26
49
3
15
31
30%
58'){
63%
United States
50
82
127
Alaska
12
27
49
24%
33%
39%
Onshore
United States
Alaska
Alaska as percent
of U.S.
Expansion of domestic production
At the present time, Alaska provides the best
hope of once again reversing the declining pattern of domestic oil production. Despite a
recent lowering of estimates of undiscovered
recoverable oil resources, Alaska continues to
be the nation's most promising target for petroleum exploration and development. Indeed,
according to the latest (1975) estimates of the
U.S. Geological Survey, Alaskan fields probably contain 12 to 49 billion barrels of undiscovered oil-about one-third of the nation's
total undiscovered oil resources (Table 3). But
the bulk of these potential resources may be
located offshore in the Outer Continental Shelf,
and thus may require vast sums to develop.
Based on existing proven reserves, Alaska's
crude oil production may decline around the
mid-1980's as the Prudhoe Bay reservoir becomes depleted. To arrest this decline, some of
Offshore
United States
Alaska
Alaska as percent
of U.S,
Totals
Alaska as percent
of U.S,
Source:
U.S. Geological Survey. Geological E51imates of
Undiscovered Recoverable Oil and Gas Resources
in the United States, Geological Survey Circular
725 (Washington. D,C: June 1975). pp. 28-31.
10
after July I when OPEC prices were raised in
several stages again.
Producer after-tax revenues could be increased further by reductions in Alaskan state
taxesand/or Federal income taxes (Table 4).
Transportation cost savings, by raising the
wellhead. price on applicable volumes, would
also provide an incentive to expand
production-in addition to economizing on rea!
economic resources. But none of these avenues
would offer as much potential relief as increases
in world oil prices.
the state's undeveloped resources will have to be
translated into proven reserves. The extent to
which producers are encouraged to make those
necessary investments will depend upon the
prices realized at the wellhead. That incentive
has improved dramatically over the course of
the past year because of sharply rising OPEC
selling prices-and because the U.S. government has permitted North Slope crude to be
priced competitively in all markets with
comparable-quality imported oil, provided the
producer price at the wellhead does not exceed
the upper-tier ceiling. For the past few months,
North Slope wellhead prices have been bumping
against the Federal ceilings, currently at
$13.55/barrel. But producers will benefit from
higher OPEC selling prices as domestic crudeoil prices are gradually deregulated by late 1981.
For any given selling price, a reduction in
transportation costs also increases the producer
price at the wellhead. So when policymakers
determine the appropriate means for dealing
with the West Coast surplus, they must consider
the extent to which each alternative would
lower transportation costs. It is assumed that
North Slope producers, in the absence of an
export ban, would be permitted to exchange
only that volume of production which West
Coast refineries cannot handle. Otherwise, they
would be tempted to market all of their production overseas, because transportation costs associated with export exchanges would be even
lower than those incurred in supplying the
Western refinery market.
Nonetheless, rising world oil prices represent
the dominant factor in boosting Alaskan wellhead prices, and thus in stimulating increased
production. After all, North Slope producers
generally stand to benefit on their entire production from every increase in the OPEC price,
whereas transportation-cost savings on the surplus would increase the wellhead price for only
that volume of oil that otherwise would have to
be shipped through the Panama Canal. During
the first half of 1979 alone, wellhead prices for
North Slope oil sold on the West and Gulf
Coasts rose by 75 and 112 percent, respectively,
simply on the basis of the sharp run-up in the
OPEC landed prices for comparable-quality'
oil. 9 Still further sharp increases were realized
Policy trade-offs
Two questions must be asked regarding the
various alternatives for dealing with the Alaskan
oil surplus. How much would each reduce transportation costs, and thus provide increased incentive for the expansion of domestic production? And how much would each stimulate the
development of the domestic refining capacity
and 1or transportation network required to utilize domestic production efficiently within the
United States? The difficulty in selecting an
appropriate strategy, of course, is that the options involve trade-offs among various policy
objectives.
1. Export-exchange option. This alternative
would be the most efficient, or least-cost method,
for dealing with the West Coast surplus. It would
reduce transportation costs the most relative to
the current system of shipment through the
Panama Canal, and thus would provide the
greatest incentive for expanding Alaskan production. 1O On the other hand, this option would
involve a greater risk of supply interruption than
the other alternatives, and would frustrate development of a domestic refinery 1distribution infrastructure for handling Alaskan oil.
In June 1979, North Slope crude sold for an
estimated $17.551 barrel on the U.S. Gulf Coast
(Table 4). However, North Slope producers
received a wellhead price of only about
$7.981 barrel, after subtracting the trans-Alaskan
pipeline tariff of $6.321 barrel and the ValdezPanama Canal-Gulf Coast shipping cost of
$3.25/barrel. But under a swap arrangement,
North Slope oil could be shipped to Japanese
refineries in foreign tankers at a cost of only
about $0.40/barrel, and this cost saving would
II
reached its potential capacity of 1.5 million bl d,
and will probably fall below that level by the
mid-1980's. Some output may become available
from the nearby-as yet untapped-Lisburne
and Kuparuk reserves. But a major expansion of
production-sufficient to meet the pipeline's full
potential of 2.0 million b / d-will require heavy
expenditures for developing high-cost reserves in
the Beaufort Sea and other new areas. ll
The major drawback to the swap optioninsecurity of supplies-has led Congress to continue its strict restrictions on Alaskan oil ex-
mean a $2.85/ barrel increase in the wellhead
price to North Slope producers. If Mexico Were
the third party in the exchange, Mexican producers similarly would benefit from diverting their
Japan-bound crude to U.S. Gulf Coastrefineries
at a shipping cost of only $0.40/ barreL
Proponents of export exchanges maintain that
transportation-cost savings and wellhead-price
increases of these magnitudes are essential to
generate the necessary investments in expanded
North Slope production. Output from the main
Prudhoe Bay reservoir-the Sadlerochit~has
Table 4
Estimated Net Return to Alaskan North Slope Oil Producers
In Selling to Various Markets, June 1979
(dollars per barrel)
Japan 2
United States'
Delivered Price
Less shipping cosl
Value at Valdez
Less Alaskan pipeline tariff 4
Value at Wellhead
West Coast
Gulf Coast
Scenario A
Scenario B
16.80
17.55
16.55
15.32
.95
3.25
15.85
14.30
.40'
16.15
14.92
6.32
6.32
6.32
6.32
9.53
7.98
9.83
8.60
2.11
.40
Less severance tax (11.54%). state
royalty (12.5%). and property tax
2.32
1.97
2.39
Less operating costs & depreciation
1.53
1.53
1.53
1.53
5.68
4.48
5.91
4.96
Pretax Net
Less state income tax (9.36%)
Less Federal income tax (46%)
Net Income Per Barrel
.53
.42
.55
.46
2.37
1.87
2.47
2.07
2.78
2.19
2.89
2.43
Delivered prices and costs for selling North Slope crude on the West and Gulf Coasts based on estimates by the PelToleum
lntel/igence Weekly, as modified by the author through further investigation. "Delivered price" in any given market usually
equals the delivered price of Saudi marker crude. plus or minus any quality differential. Saudi marker delivered price is the
posted price Lo.b. in the Persian Gulf ($14.54 in June) plus the transportation cost to the particular market ($1 to the West
Coast. and $1.75 to the Gulf Coast). June selling prices in U.S. markets exceeded the prices this computation would yield.
however. due to the breakdown of the traditiot'laluniform OPEC pricing structure and the resultant surcharges added, to
posted prices by many OPEC producers.
2 The delivered price for North Slope crude in Japan (Scenario A) was estimated by first determining an effective rather thana
posted Saudi market price. That effective price was estimated to be roughly equal to the selling price of North Slope crude on
the Gulf Coast ($17.55) plus a quality differential (+$.50) minus transportation costs from the Persian Gulf (-$1.75), or to
$16.30. Using that Saudi marker price ($16.30). we then added the transportation costs from the Persian Gulf to Japan
(+$.75) minus a quality differential (~$.50) to derive art estimated delivered price of North Slope crude in Japan of$16.55.ln
Scenario B. it is assumed North Slope producers share half of the transportation cost savings ($1.43) with Japanese refineries.
J Based on the use of foreign flag VLCC tankers atWorld-scale 50. Using U.S. !lag tankers. the rate would be about $1.30 per
barrel.
4 Includes charges for liability fund ($.05) and pipeline less ($.05).
Source:
Petroleum lnte/ligence Weekly, June 18. 1979. page 9; estimates developed by the author through contacts with oilindustry analysts.
I
12
ports. Of course, increased domestic
production-with or without swap
arrangements-will tend to reduce net imports
of petroleum for any given level of consumption,
and thus will help to improve the U.S. oil-trade
balance. But swaps increase gross imports, and
so. do not reduce susceptibility to a cutoff of
foreign oil. Even if Alaskan oil were channeled
back into the domestic market during a supply
crisis, that action would simply transfer the
dislocation to Japan and would thus undermine
Japan-U.S. relationships.
Lifting the ban on exports also would eliminate all. incentive for West Coast refiners to
retrofit their. plants to handle more Alaskan
crude, or for North Slope producers or other
investors to build pipelines to improve domestic
distribution of crude. Since the export-exchange
arrangement would be the least-cost (and most
profitable) method for dealing with the Alaskan
surplus, the overseas market would be the preferred market for selling the crude. Without
assurance that Alaskan supplies would be available on the West Coast, refiners would have no
incentive to retrofit their plants. Similarly, without any surplus to transport to other areas of the
nation, investors would have no incentive to
pursue the less efficient pipeline alternative.
2. Refinery modification option. Within the
United States, transportation costs are lowest for
the West Coast market (Table 4), although costs
there are slightly higher than they would be
under the swap option because of the costly
requirement for using American-flag tankers. If
West Coast refiners carried out the necessary
modifications to fully utilize Alaskan production, North Slope producers would realize this
transportation cost saving per each barrel of oil
thatothenyise would be shipped through the
Panama Canal.
Elimination of price controls onrefined products would provide refineries with a strong
incentive to make the necessary investments.
\\lith • decontrol, they could recover their increased. costs and perhaps even widen their profit
margins. In this regard, they have already benefitted from the so-called "tilt" rule for gasoline
pricinge-instituted in early March of 1979. 12
Still, they.\Vould have no incentive to modify
facilities if the swap option were available.
North Slope producers would incur higher
production costs in serving the West Coast
market if they themselves built a desulfurization
plant at Valdez to upgrade their oil. These added
costs would offset some of the transportation
costs saved in not having to ship oil through the
Panama Canal. But producers also would realize
the price premium that low-sulfur crude commands on the West Coast. On balance, then,
producers might benefit as much from this option as from the refinery modification alternative.
3.Pipeline option. It is very difficult, if not
impossible, to evaluate the relative costs and
prices associated with this alternative. None. of
the proposed pipelines has received final approval, although the Administration has. announced
its support of the Northern Tier line. Thus, startup and completion dates cannot be determined,
and overall cost and tariff estimates are highly
tenuous. Furthermore, comparisons are difficult
because one proposed pipeline would be built
from scratch while others would incorporate
existing pipelines; in the latter case, for example,
the nominal cost of transportation would tend to
underestimate the true economic cost of replacement.'3 The tariff per barrel associated with any
pipeline also would be highly dependent upon
the operating rate-that is, the amount of
throughput-yet rates of capacity utilization are
unknown.
Recent estimates suggest, however, that transportation costs could be lower with the Sohio
pipeline than with the Panama Canal alternative,14 which means of course higher wellhead
prices for producers. But in general, producers
apparently would benefit less from the pipeline
option than they would from the refinerymodification option.
Summary and conclusions
Government regulations have been largely
responsible for creating a "surplus" of Alaskan
North Slope oil, defined in terms of West Coast
refinery capacity to process that relatively heavy,
high-sulfur. crude.. Because of .environmental
regulations as well as the composition of regional
refined-product demand, West Coast refineries
need additional desulfurization and downstream
cracking capacity to fully utilize North Slope
supplies. Yet price controls on refined products
13
savings for North Slope crude that otherwise
would have to be shipped through the Panama
Canal. These savings would translate into the
greatest increase in producer wellhead prices,
and thus the greatest added incentive for increased North Slope and other Alaskan production. Each of the other options would call for
various amounts of investment in new construction. As such, each would provide relatively less
of a transportation cost saving and relatively less
inducement for expanded production than export exchanges. There is no clear "second best"
alternative to export exchanges in terms of
efficiency, largely because of the highly uncertain
nature of the estimated costs involved.
While economic efficiency alone would dictate
the adoption of the export-exchange option~
that is, the removal of Alaskan oil-export
controls~certain trade-offs associated with this
approach must also be considered. Export exchanges, although not affecting net oil imports,
would increase gross imports and thus increase
the nation's susceptibility to supply interruptions. Also, if Congress permitted this option, it
would thereby tend to reduce, or even eliminate,
the incentive for producers or refiners to undertake any of the other possible alternatives.
Regardless of what distribution option is
adopted, rising world oil prices will improve the
economic climate for expanded Alaskan production. The issue of whether or not to permit
Alaskan oil exports boils down to whether or not
the advantages of economic efficiency (and
greater producer price incentive) outweigh the
disadvantages of increased risk of supply interruption such exchanges would entail. Economic
factors alone argue in favor of export exchanges.
A decision to retain controls on exports requires
a political judgment that energy security is a
more important policy consideration than economic efficiency alone.
have inhibited refineries from making the neCessary investments. And because of other regulations delaying domestic pipeline construction,
banning exports, and forbidding the use of
foreign tankers in U.S. intercoastal trade, North
Slope producers are required to ship their excess
output by U.S. tankers to Gulf Coast refineries
through the Panama Canal. But this approach is
one of the most inefficient possible ways of
dealing with the surplus.
In evaluating various alternatives, policymakers must decide not only which alternative provides for the most efficient use of resources, but
also which is most effective in achieving the
nation's key energy objective of reduced reliance
on foreign oil imports. These two objectives are
of course somewhat related. The primary Way to
reduce reliance on oil imports is to increase
domestic production through the mechanism of
price incentives. Yet reducing transportation
costs through a more efficient distribution system raises the producer price at the wellhead
and thus increases price incentives.
The current method of disposing of the
surplus~the Panama Canal approach~tends to
reduce the producer price at the wellhead, and
also to depress the North Slope selling price on
the West Coast. This approach consequently
serves to restrain potential increases in output,
since a major portion of any substantial production increase also would end in the "surplus"
stream and receive a lower wellhead price. Each
of the alternatives discussed 'in this paper--export exchanges, pipelines, refinery retrofitting, crude desulfurization~aredesigned in One
way or another to eliminate the bottleneck and
provide greater production incentive.
Export-exchange arrangements· would provide the least cost, or most efficient, rneansof
dealing with the surplus. Such a.rrangements
would provide the maximum transportation cost
FOOTNOTES
1. United States, Federal Energy Administration, North
Slope Crude-Where to? How? An Analysis of the
Alternatives Available for the Transportation and Disposition of Alaskan North Slope Crude, (November 29,
1976), pp. 15-17.
2. North Slope oil is described as being heavy (27
degrees American Petroleum Institute (API) gravity)
and sour (1 percent sulfur content). Heavy crude oils
are those with a high density or low API gravity. Gener-
ally, crude oils having a gravity of 32 degrees API or less
are called heavy crude oils. Sour crude oils are those
that contain relatively high amounts of sulfur (greater
than 0.5 percent).
3. United States, Presidential Task Force on Refonn of
Federal Energy Administration Regulation, Report on
Federal Energy Administration Regulation, ed. MacAvoy (Washington, D.C.: American Enterprise Institute
for Public Policy Research, 1977), pp. 8-9, 60-64.
14
ed in the light Of recent Iranian and Saudi Arabian
production plans.
4. Alaska had been a significant oil producer prior to
the onset of Prudhoe Bay production in mid-1977. In
1976, the state produced about 190,000 bid of oil, with
most of that output coming from the Kenai Peninsula/
Cook Inlet area in the southern part of the state.
9. Delivered price for North Slope crude in any given
market usually equals the delivered price for Saudi
marker crude, plus or minus any quality differential.
During 1979, there was a breakdown in the traditional
uniform OPEC pricing structure, however, as a result of
the Iranian crisis and consequent surcharges added to
posted prices among markets served by various producers. North Slope selling and wellhead prices were
similarly distorted.
5. At present, only one of the three major Prudhoe Bay
producers-namely, Standard Oil Company of Ohio
(Sohio)-has no refineries on the West Coast and thus
must transport North Slope crude to Gulf Coast refineries through the Panama Canal. IfAlaskan production
were to expand without a commensurate increase in
West Coast refining capacity to handle that crude, other
producers also could be confronted with the problem of
transporting their surplus through the Panama Canal.
10. It is for these reasons that the State of Alaska has
repeatedly pressed for export exchanges. That state
would benefit not only in terms of the return on its
royalty, i.e., ownership share, but from increased tax
revenues.
6. The entitlements program was established in 1973 to
equalize the effective acquisition costs of oil obtained
by U.S. refiners under the multi-tiered system of oil
prices resulting from Federal price controls on
domestically-produced oil. Under this program, refiners having access to supplies of cheaper oil make cash
payments to refiners who depend on more expensive
oil, thus tending to equalize the effective acquisition
cost of lower-tier, upper-tier and imported crude oil to
the refiner. North Slope oil has been granted the entitlement status of upper-tier or "new" oil which sells at the
world price. As a result, U.S. refiners using that oil are
granted the same entitlements benefits for Alaskan as
for foreign oil.
11. For a discussion of this point see Howard M. Wilson,
"How Operators View Prudhoe Bay Now," The. Oil and
Gas Journal (February 6, 1979), p. 71; also, Arion R.
Tussing, The Effects of Crude Oil Pipeline Tariffs on the
Economics of Petroleum Development in Arctic Alaska
(Seattle, Washington: July 5, 1978).
12. The "gasoline tilt" rule, adopted by the Department
of Energy on March 1, 1979, permits up to 110 percent
of crude oil cost increases to be allocated to gasoline on
a pro-rata, volumetric basis; it also allows refiners to
allocate to gasoline a percentage of refining costs
greater than the volumetric ratio. Previously, increases
in crude oil and refining costs (above the 1973-base
period) were allocated to refined products strictly on a
pro-rata volumetric basis. The average refinery crude
oil run yields about 44 percent gasoline. Consequently
only about 44 percent of crude oil and refinery cost
increases could be passed on in gasoline prices, despite the fact that the costs of producing gasoline are
greater than those for most other refined products.
7. U.S. Executive Office of the President, The White
House Fact Sheet on the President's Oil Import Reduction Program (Washington, D.C., July 15, 1979), p. 2.
For a similar forecast see U.S. Congress, Congressional Budget Office, The Decontrol of Domestic Oil Prices:
An Overview (Washington, D.C.: U.S. Government
Printing Office, May 1979) p. 14.
8. A number of independent studies have concluded
that world oil prices will rise sharply in real terms
between now and the early 1990's. See, for example,
Workshop on Alternative Energy Strategies, Energy:
Global Prospects, 1985-2000 (New York: McGraw-Hili,
1977); Organization for Economic Cooperation and
Development, World Energy Outlook (Paris: OCED,
1977); United States Central Intelligence Agency, The
International Energy Situation: Outlook for 1985
(Washington, D.C.: Central Intelligence Agency, April
1977). The prospect of supply stringency has intensifi-
13. This point was stressed by Arion R. Tussing in
Economic and Policy Consideration in Choice of a
West Coast Oil Port (West Coast Oil Ports Inquiry,
Vancouver, British Columbia, November 1977), pp. 5-7.
14. Statement of Alton W. Whitehouse, Jr., Chairman of
the Board, The Standard Oil Company (Ohio), before
the Senate Committee on Energy and Natural Resources (Washington, D.C., March 27, 1979), p. 8.
REFERENCES
Tussing, Arion R. The Effects of Crude Oil Pipeline
Tariffs on the Economics of Petroleum Development in Arctic Alaska. Seattle, Washington: July 5,
1978.
_ _ _ _ . Economic and Policy Considerations in
Choice of a West Coast Oil Port. West Coast Oil
Ports Inquiry, Vancouver, British Columbia, November 1977.
U.S. Central Intelligence Agency. The International
Energy Situation: Outlook to 1985. Washington,
D.C.: Central Intelligence Agency, April 1977.
U.S. Congress, Congressional Budget Office. The Decontrol of Domestic Oil Prices: An Overview. Washington, D.C.: U.S. Government Printing Office, May
1979.
California State Lands Commission. California and the
Disposition of Alaskan Oil and Gas, A Working
Paper. Sacramento, June 1976.
Chevron U.S.A. Incorporated. North Slope Oil and the
West Coast. San Francisco: Chevron, February
1977.
Clement, M., Swift, W.H., et al. North Slope Royalty Oil
Market, Pricing, and Revenue Analysis. Richland,
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Kresge, David T., Thomas A. Morehouse and George W.
Rogers. Issues in Alaska Development. Seattle:
University of Washington Press, 1977; Chapter 4.
Organization for Economic Co-operation and Development. World Energy Outlook. Paris: OECD, 1977.
15
U.S. Presidential Task Force on Reform of Federal
Energy Administration Regulation. Report on Federal Energy Administration Regulation, edited by
Paul W. MacAvoy. Washington, D.C.: American
Enterprise Institute for Public Policy Research,
1977.
U.S. Senate, Committee on Interior and Insular Affairs.
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Government Printing Office, 1974.
_ _ _ _. Committee on Interior and Insular Affairs
and Committee on Commerce. Joint Hearing:
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Whitehouse, Alton W., Jr., Chairman of the Board, The
Standard Oil Company (Ohio). Statement before
the Senate Committee on Energy and Natural
Resources. Washington, D.C., March 27, 1979.
Wilson, Howard M. "How Operators View Prudhoe Bay
Now," The Oil and Gas Journal. February 26, 1979.
Workshop on Alternative Energy Strategies. Energy:
Global Prospects, 1985-2000. New York: McGrawHill, 1977.
U.S. Department of Energy, Office of Policy Analysis,
Petroleum Supply Alternatives for the Northern
Tier and Inland States Through the Year 2000. Draft
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U.S. Executive Office of the President, The White
House Fact Sheet on the President's Oil Import
Reduction Program. Washington, D.C., July 15,
1979.
U.S. Federal Energy Administration. North Slope
Crude-Where to? How?An Analysis of the Alternatives Available for the Transportation and Disposition of Alaskan North Slope Crude. November 29,
1976.
U.S. General Accounting Office. Effects of Alaskan
North Slope Crude Oil and Continued Crude Oil
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Washington, D.C.: U.S. General Accounting Office,
JUly 19, 1978.
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