The following slides highlight how a statute restricting
how goods move between U.S. ports distorts petroleum flows,
increases costs to deliver petroleum to refiners and consumers,
and in some cases even gives foreign competitors a transportation
cost advantage when competing in the United States.
The Jones Act is a federal statute signed into law by President
Woodrow Wilson in 1920 that requires all waterborne shipping
between U.S. ports to be carried out by U.S.-flag ships that
are constructed in the U.S. and owned by U.S. citizens. The
Jones Act doesn’t explicitly require U.S. citizen crews.
But U.S. manning laws (46 U.S.C. 8103) require that on U.S.-flag
vessels all licensed officers and 75% of unlicensed crew be
The general purpose of the Jones Act was for national defense
and to enhance commercial strength by creating and maintaining
a merchant marine fleet. The requirement that vessels be built
in the U.S. also served the purpose of finding use for cargo
ships that had been built by the U.S. Shipping Board during
World War I. The Jones Act authorized sale of these vessels
to the private sector.
A Maritime Administration (MARAD) study showed that “the
total average cost of operating a U.S.-flag vessel in foreign
commerce was 2.7 times higher than the cost incurred by foreign-flag
equivalents.” 1 This cost difference increases consumer
costs for petroleum, and affects the competitive landscape for
1 U.S. Department of Transportation Maritime Administration, “Comparison
of U.S. and Foreign-Flag Operating Costs,” September 2011,
Note: Transportation costs are estimated based on information from publicly-available sources. The values should not be relied upon by individual refiners. Transportation costs typically vary by length of journey, type of ship, capacity, market demand for transportation services, and other market forces
The entire U.S. Jones Act fleet is large and contains many
vessels not suitable for moving petroleum. These vessels travel
inland waterways as well as coastal routes. MARAD indicates
on its website that “U.S.-flag domestic cargo fleet supporting
this massive inland and ocean trade was made up of more than
38,000 vessels (mostly tugs and barges).”
Petroleum (crude oil, refined products and petrochemicals)
is moved on large vessels. The smallest petroleum vessels (10,000 –
30,000 barrels) are barges that travel the inland waterways
such as the Mississippi and coastal canals. Larger ocean-going
vessels move petroleum along the coasts. These vessels include
coastal barges, such as large articulated tug barges (ATB’s),
which might run 200,000 barrels or more; and self-propelled
tankers, which carry over 300,000 barrel of crude or refined
This presentation is focused on coastal water movements.
The total coastal Jones Act fleet is about 5,400 vessels, and
coastal vessels carrying petroleum represent about 25 –
30 percent of the tonnage capacity of this total coastal fleet.
1 For more Jones Act vessel background, see John Frittelli, “Shipping
U.S. Crude Oil by Water: Vessel Flag Requirements and Safety
Issues,” Congressional Research Service, July 21, 2014,
This table details the larger coastal vessels that move petroleum.
It excludes the 11 dedicated tankers that move Alaskan crude
oil down to West Coast ports. Note that most of the vessels
are on the Gulf Coast, although these vessels sometimes travel
up the East Coast to deliver product or crude oil to the Northeast.
The West Coast vessels are mainly used to distribute product.
Pipelines do not connect the major refining centers in Washington,
Northern California and Southern California, so waterborne movements
provide the balancing transportation.
The remaining slides illustrate some regional volume balances
for crude oil, gasoline and diesel, and how waterborne transportation
costs impact that balance.
In general, Jones Act vessels cost more than foreign flagged
alternatives. In many regions, imports compete for U.S. market
share with U.S. crude and refined product suppliers. And in
some regions, the transportation cost gap between Jones Act
vessels and foreign-flagged vessels results in some suppliers
seeing better economics exporting petroleum than moving it to
other U.S. locations. Overall, the higher operating cost and
limited capacity of Jones Act vessels vs. foreign-flag ships
create higher costs to transport petroleum, and thus contribute
to higher costs for consumers.
Please note that the information on volumes and costs represents
averages and estimates from publicly available sources. Generally
the data reflect the first half of 2015, which is typical for
most regions. The West Coast is an exception, which is highlighted
in later slides.
Also note that product volumes do not include biofuels such
as ethanol or biodiesel.
The Northeast refiners only supply a little over 1/3
of the gasoline demand in the Northeast (supplemented marginally
by refineries in Ohio) leaving the region short by 850 to
900 thousand barrels per day (KBPD) of gasoline. The first
two choices to fill this void are 1) from the Gulf Coast
via the Colonial Pipeline and 2) from Eastern Canadian refineries
(excess of Canadian demand). These have strong transportation-related
strategic advantages over other options. The combined volume
of these two choices (through the first half of 2015) equaled
just over 500 KBPD.
The remaining void (about 340 KBPD) in the gasoline balance
is made up by other waterborne imports, primarily from Europe.
Incremental increases or decreases in gasoline consumption
will directly impact the volume of these waterborne imports.
Very little gasoline volume (1.2 KBPD) travels via Jones
Act vessels from the Gulf Coast into the Northeast, mainly
due to the high transportation cost of this route, which
increases the waterborne delivered product costs from the
Gulf Coast refiners relative to Gulf Coast refiners’
European competitors serving the Northeast.
Similar to the gasoline balance, the Northeast is also
dependent on outside sources to meet diesel demand, with
local refiners supplying about 44 percent of regional demand.
The region relies on base volumes sourced from the Gulf
Coast and Eastern Canada; however, very little volume travels
to the Northeast via Jones Act vessels. The balance
of supply, after those volumes from Gulf Coast and Eastern
Canada are accounted for, is relatively small (~50 to 60
KBPD) and comes from a variety of locations, with the Former
Soviet Union generally being the largest supplier.
Western Europe is in short supply for diesel, and does not
typically export much product to the Northeast.
While annual average diesel imports outside of Canada
are not large compared to gasoline imports, they are highly
seasonal. These imports help to meet winter heating needs
and can be quite large in some months. Historically during
cold snaps, diesel imports have been the major source of
surge supply rather than volumes from the Gulf Coast suppliers.
These suppliers face high Jones Act transportation costs
and limited Jones Act vessel surge capacity to meet unusual
Northeast demand increases.
Pipeline product transportation costs from the Gulf Coast
and waterborne shipping costs from Canada are generally
the lowest. Colonial Pipeline transportation costs are well
known since they are regulated by FERC. Shipments from Canada
come into the Northeast from many different ways that impact
the cost of transportation. Products from the Eastern Canadian
refineries in St. John and Come by Chance come down the
Eastern seaboard about 500 miles to Boston and New York
Harbors. Waterborne movements from the Quebec City and Montreal
refineries have to go around Prince Edward Island, a trip
that is about three times longer than the Irving or Come
by Chance trips. The longer trip results in higher costs.
Additionally, there are some limited movements into western
New York from Ontario refineries.
With transportation costs from Europe to the Northeast
averaging about $2.50 per barrel, compared to about $5.00
using Jones Act vessels from the Gulf Coast, imported products
from Europe have a significant transportation cost advantage
over waterborne U.S. products from the Gulf Coast. Furthermore,
Gulf Coast refiners see lower transportation costs to move
their supplies to foreign ports (on foreign-flagged vessels),
such as Brazil, than to use waterborne transportation to
At a minimum, the Jones Act is encouraging more product
imports in the Northeast and exports from the Gulf Coast.
It may also be pushing consumer petroleum product costs
higher than would otherwise be the case in an open market
As previous slides indicated, there is much product market
competition from suppliers outside of the local refiners
operating in the Northeast. In 2010 and 2011, 60 percent
of the refining capacity in the Northeast (over 900 KBPD)
was either shut down, idled, or put up for sale while still
operating. These refiners were almost totally dependent
on imported crude oil, and product market competition was
creating a difficult economic environment. But with the
increased production of U.S. light tight oil, Northeast
refining economics improved. While some of that capacity
at risk in 2010/2011 is operating today, ultimately almost
400 KBPD (25 percent of the 2010/11 Northeast refining capacity)
Currently, this region is less dependent on waterborne
crude imports than in the past, as it now receives an increasing
share of crude by rail from the Bakken region and Canada.
Very little crude oil travels from the Gulf Coast to the
Northeast via Jones Act vessels.
The Northeast refiners’ current crude oil supply
reflects dramatic changes with domestic light tight oil
(LTO) development. As the shale revolution caused a drastic
upturn in domestic production, the industry invested in
rail transportation assets to move inland-produced crude
eastward. Recently, about 40 percent of crude sourced into
the Northeast has come via rail from the U.S. Bakken formation,
which produces crude oil well suited to Northeast refiners.
Rail also allowed for Northeast refiners to source heavy
Canadian crude from Alberta.
Very little crude oil volume moves via Jones Act vessels
from the Gulf Coast to the Northeast. Rail transport proved
a more economic solution to access Bakken crude due to transportation
costs and lack of available tanker capacity. Jones act vessels
have been diverted to move growing volumes of domestic crude
oil along the Gulf Coast, from areas like Houston and Corpus
Christi, to refiners in Louisiana.
Despite longer voyages to Canada and Europe, shipping
U.S. crude from the Gulf Coast to those destinations1
costs significantly less than to the U.S. Northeast
due to Jones Act requirements. The significant crude
transportation advantage to Canada and Europe is important
in that these foreign areas compete for product demand
in the Northeast against both U.S. Northeast refiners
and Gulf Coast refiners.
Since mid-2014, some volumes of processed condensate
have been exported to Europe and elsewhere, but until
the recent change (end of year 2015) removing all crude
export restrictions, U.S. crude could not be sent to
Europe (although re-exports of Canadian crude were allowed).
Also, exports of U.S. crude to Canada were not restricted,
although historically, very limited volumes (primarily
advantaged cross-border movements) were actually exported.
As U.S. domestic crude production increased, those allowable
exports to Canada grew significantly, exceeding 450
KBPD in the first half of 2015.
(Note that crude transportation costs per barrel
generally are less than product transportation costs
since crude oil can be moved on larger vessels (economies
of scale) and products need “clean” vessels
that prevent product contamination.)
1 While crude exports to Europe (and most other countries)
were effectively banned through 2015, shipping costs
are available because some crude imports to the Gulf
Coast are re-exported to Europe, and some condensate
is being exported as well.
Today, the Northeast receives gasoline and diesel
from foreign sources, even though Gulf Coast refiners
have excess product that is being exported. With pipelines
full from the Gulf Coast to the Northeast, additional
Gulf Coast volumes would have to travel via Jones Act
vessel to the Northeast, which is less economic for
Northeast consumers than foreign product supplies delivered
via foreign tanker. Such inefficient market hurdles
can result in higher regional prices for gasoline and
Northeast refiners today are getting most of their
crude via rail from the Bakken region and from Canada.
In contrast, East Canadian refiners can import U.S.
crude oil from the Gulf Coast at a transportation cost
of $2/bbl versus $6/bbl to move the same crude oil to
Northeast refiners. Canadian refiners then produce products
from Gulf Coast crude oil to send back into the Northeast
market. These products travel back to the U.S. on foreign-flagged
vessels that also help to keep their costs down.
Furthermore, with U.S. crude oil exports now allowed,
those European refiners that export product to the U.S.
should see a waterborne transportation cost advantage
for U.S. crude oil from the Gulf Coast over Northeast
refiners’ waterborne costs from the Gulf Coast.
Simultaneously, crude export opportunities may add upward
price pressure to some U.S. crude oils, including Bakken
crude favored by Northeast refiners.
The Southeast market has different supply arrangements
than the Northeast. With no internal production, it
depends entirely on sources outside the region. In general,
the Southeast states, except Florida, are almost entirely
dependent on pipeline product supply from the Gulf Coast.
Florida, on the other hand, is mainly dependent on Jones
Act vessel delivery of product from refining centers
on the Gulf Coast.
The Gulf Coast is by far the most significant source
of gasoline to the Southeast. Gulf Coast refiners are
estimated to have supplied over 1.1 million BPD of gasoline
(93%) into Southeast markets during the first half of
2015. This is done through two major pipeline systems –
the Colonial Pipeline and the Plantation Pipeline (760
KBPD), which serve nearly all of the Southeast markets,
with the exception of Florida, which gets about 350
KBPD by Jones Act ships. Imports from Europe, Eastern
Canada and elsewhere make up the difference, generally
averaging less than 100 KBPD in recent years (86 KBPD
in the first half of 2015).
While Florida relies heavily on Gulf Coast gasoline
supply, it is also the major recipient of Southeast
gasoline imports, which averaged over 60 KBPD during
the first half of 2015. However, imports generally represent
less than 10 percent of the state’s supply, with
the rest arriving by Jones Act vessel from other parts
of the Gulf Coast.
Nearly an identical story to the region’s gasoline
balance (previous slide), the Southeast relies heavily
on Gulf Coast diesel, primarily delivered by pipeline,
to supply the region’s 600+ KBPD of consumption.
As with gasoline, Florida is the exception, with much
of the state’s demand being met by Jones Act vessel
movements from the Gulf Coast, amounting to 93 KBPD
in the first half of 2015. Eastern Canadian refineries
supply almost 50 KBPD of diesel to the Southeast and
waterborne imports from other countries are very limited
(6 KBPD in the first half of 2015).
Most of the southeast is not directly affected by
the Jones Act, as it is mainly supplied via pipeline.
The Jones Act is an issue with Florida, which receives
most of its gasoline and diesel fuel via Jones Act vessels
from refining sources on the Gulf Coast. Despite high
Jones Act costs, Gulf Coast suppliers remain the most
economic source of product for that state.
Florida competes with the other markets served by
Gulf Coast refiners, including foreign export markets.
But Florida is close enough to Gulf Coast suppliers
to remain more attractive than some export markets despite
the high Jones Act costs. For example, Jones Act product
transportation costs from Gulf Coast suppliers ran about
$2.50 – $3.00 per barrel for the first half of
2015, while foreign flagged vessels delivered product
from the Gulf Coast to Brazil (one of the significant
export markets) for $4.00 per barrel. (See Northeast
Products Transportation Costs slide.) This implies Florida
was not generally at a transportation disadvantage to
this export market.
However, Florida’s dependence on Jones Act
vessels can become an issue during times of emergency,
such as when hurricanes hit the Gulf Coast region and
disrupt infrastructure. During hurricanes, Jones Act
waivers can be a solution to delivery problems, but
without Presidential support, waivers are not usually
Petroleum product supply and demand are not evenly
distributed on the West Coast. Furthermore, pipelines
do not exist to connect refining centers in Washington,
Northern California and Southern California. As a result,
Jones Act vessels serve to move products from West Coast
regions with excess supply to areas with less supply
Declining demand on the West Coast has opened the
door to more product exports when all refineries are
operating under normal market conditions, but there
are times when refinery outages require a shift in waterborne
movements along the coast to fill the temporary supply
gap. Generally there are no extra Jones Act vessels
on the West Coast, so any needed increases in volumes
transported by water may not be possible in the short
run. In addition, the unique clean-burning gasoline
California requires cannot be produced by all refiners,
so suppliers on the West Coast have limited options
to draw on outside the region when unexpected supply
In 2015, the West Coast experienced some loss of
refining capacity due to an unexpected shutdown. Production
in 2014 represents something closer to normal operation
on the West Coast.
In general, refineries on the Pacific Coast Northwest
(PCNW) supply gasoline to the states of Washington and
Oregon, with some additional volume flowing to California
via Jones Act vessels. A small amount of excess also
is exported to Alaska or foreign countries. Some product
also moves from refineries in Utah and Montana into
Eastern Washington to help meet West Coast needs.
The San Francisco refineries supply northern California
and northern Nevada, and have surplus supply for other
areas. The surplus volumes help supply southern California
and make up the majority of foreign exports from the
The Los Angeles refineries supply southern California,
southern Nevada, and a portion of Arizona demand. Even
with normal throughputs, the Los Angeles refineries
are short product. With no pipelines connecting Los
Angeles and San Francisco refining centers, waterborne
transportation is the only option for balancing those
two parts of the state.
In 2015, supply flows were significantly impacted
by the fluid catalytic cracking (FCC) outage at a refinery
in Torrance, California, which resulted in lower gasoline
production in the Los Angeles area. Additional production
was incentivized from Bay Area and Pacific Northwest
Comparing the 375 KBPD regional gasoline production
estimate for the first half of 2015 to our 2014 estimate
(see preceding slide), gasoline volumes were down roughly
30 KBPD on average for the region. Generally, there
would not be extra Jones Act vessels available to increase
waterborne flows of product on the West Coast, which
could (and have) create(d) a temporary bottleneck. Additional
vessels have to come from the Gulf Coast, presumably
loaded with product, but it takes weeks for that to
occur. After a vessel is loaded on the Gulf Coast, transit
time alone to Los Angeles through the Panama Canal takes
around 13 days, with the costs including an empty return
The diesel balance on the West Coast is similar to
the gasoline balance. Washington and the Bay Area have
surplus product, while Los Angeles is reasonably close
to being balanced. This results in some exports going
to Central and South American countries on the Pacific
side, and relatively little movement by Jones Act tankers
in the region when all refineries are operating.
(Note that the 2015 FCC unit outage did not have
as much impact on West Coast diesel volumes as it did
on gasoline since an FCC unit primarily produces gasoline.)
Product movements on the West Coast have several
destinations as previously discussed. Generally the
high-cost Jones Act vessel transportation costs from
Washington and San Francisco to Los Angeles are less
than transportation costs to send or receive products
from Latin America or the Middle East.
Similar to Florida, the main Jones Act concern relative
to product movement is when supply disruptions occur
and more waterborne movement is needed. Unlike Florida,
the West Coast supply disruptions are generally not
widespread events like hurricanes, but more localized
like a serious large unplanned refinery outage. In many
cases, a Jones Act waiver might help to relieve regional
imbalances quickly, but this has not been done on the
Crude supply to the West Coast shifted towards imports
as Alaskan crude production declined. But the emergence
of domestic light tight oil production has begun to
counteract that shift toward more imports. Jones Act
vessels have a potential role in how that shift evolves.
During the first half of 2015, the West Coast
imported more than 750 KBPD of crude from outside the
U.S., sourced primarily from the Middle East, Colombia
and Ecuador. Also arriving on the water is Alaskan
North Slope (ANS) crude via Jones Act shipping.
This amounts to more than 450 KBPD in 1H2015.
Because ANS production has been slowly declining for
many years, these volumes have also been declining.
The most economic crudes for California and Washington
refiners come from local production and Alaskan North
Slope crude that is shipped down via Jones Act tankers.
The remainder is supplied as follows:
Sweeping gains in domestic crude production over
the past decade led to stranded crude oil in some inland
crude production areas. Midstream operators could
not build pipeline capacity fast enough, and rail movements
grew. While dollar/barrel rail transportation
costs are higher than pipeline costs, refiners value
the flexibility that rail transportation gives, and
thus, a significant volume of Bakken, Niobrara and other
crudes move by rail.
The large majority of railed crude oil that goes
to the West Coast is directed to Washington refineries
that built out rail-unloading capacity. But crude
delivered into Washington State could flow by water
to California via Jones Act vessels.
While interest sometimes turns to the coming widening
of the Panama Canal, which will allow larger tankers
to pass through, this route still is not likely to be
economic for crude flows from the Gulf Coast to the
West Coast. The 5,000 mile journey on expensive
Jones Act tankers, along with Canal fees, may keep that
route from carrying much U.S. crude volume.
The cost to move crude oil from Alaska to California
is comparable to moving volumes from the Middle East
or from South America.
Several new crude terminal facilities are being considered
in Washington state (primarily on the Columbia River)
for the purpose of receiving crude from inland U.S.
locations and then transporting it by marine vessel
to California refinery destinations. If these new facilities
are permitted and constructed, recent Jones Act vessel
costs indicate that moving the crude oil from these
terminals to California would cost a similar amount
to transporting crude oil from the Middle East or South
America to California. However, if “all in”
costs (handling, transhipping from rail, etc.) are included,
foreign producers would have a transportation cost advantage
over U.S. inland crude producers whose crude oil is
available from these terminals in Washington State.
Jones Act restrictions impact crude and product movements
differently on the West Coast. As domestic crude production
increases from tight oil formations like the Bakken,
the opportunity for moving that crude oil from Washington
State terminals to California via water will evolve.
All-in crude oil shipping costs from Washington to California
may exceed transportation costs for moving crude oil
from foreign locations to California, which would give
foreign crude oil an economic advantage over U.S. crude
Regarding products, Jones Act vessels currently balance
the supply and demand flows among the Pacific Northwest,
northern California, and southern California regions.
Under normal conditions the network works well. But
when a local disruption like an unplanned refinery outage
occurs, flows need to change to fill the gap. There
generally are no extra West Coast Jones Act vessels
to adjust that flow, and at this point, waivers have
not been seen as an option. This leaves the West Coast
market with temporary product imbalances that can take
some time to resolve.
Jones Act waivers are provided for in the law, but
are difficult to obtain.
The difficulty of achieving waivers without explicit
presidential support means this relief valve is generally
not available except during hurricanes or other widespread
events that destroy energy infrastructure.
In most cases, Jones Act waivers have been granted
in association with widespread damage caused by hurricanes.
While the shipping industry resisted granting waivers
during hurricanes Rita and Katrina, it did not object
to a waiver during Sandy.
Jones Act waivers have not been used to help relieve
supply shortfalls on the West Coast mainly due to high
hurdles for obtaining a waiver, including obtaining
strong political support that generally has been needed
for waivers in other parts of the country in the past.
American Fuel & Petrochemical Manufacturers
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