While TransCanada Corp’s Keystone XL is mired in
seemingly endless studies, a competing project that could carry
hundreds of thousands of barrels of oil sands crude to U.S.
refineries every day is sailing through its own regulatory
review.

Why the double standard? It’s well known that Keystone XL is
a cause celebre for environmentalists who see defeating the
pipeline as a way to halt the development of Canada’s oil sands
in the name of slowing climate change.

But what is really hurting Keystone XL is the lack of a
serious U.S. greenhouse gas policy and the need to go through a
far more stringent regulatory process than other projects.

Consider the plan hatched by gas-focused pipeline group
Energy Transfer Partners LP and Enbridge Inc,
the top shipper of oil sands crude, to convert part of ETP’s
Trunkline natural gas pipeline to oil service by 2015.

ETP must first get the approval of the Federal Energy
Regulatory Commission (FERC) to remove Trunkline from service, a
formal procedure known as abandonment. Part of this process is a
environmental assessment. That study was published quietly in
April and comment from the public closes on Wednesday.

The word “climate” appears only five times in the Trunkline
environmental assessment, largely in a single paragraph where
climate change is dismissed as a significant factor that needs
to be considered in the scope of the review.

The study admits “Trunkline has indicated the future
operator intends to use the abandoned pipeline for oil
transportation, the eventual disposition of the pipeline … is
not a key factor in the Commission’s decision to grant
abandonment.”

In other words Trunkline, which will facilitate the growth
of the oil sands business, need not face any formal study of the
broader implications of the conversion.

INCOHERENT POLICY

Indeed, the Trunkline draft environmental assessment goes on
to briefly discuss the planned conversion of the pipeline to oil
service while noting the future use of the line for shipping
crude oil is outside of FERC’s jurisdiction.

But at no time is the proposal subjected to a rigorous
review on its potential status as a “facilitator” of the oil
sands industry and the greenhouse gas emissions associated with
increased oil sands crude extraction – unlike Keystone XL.

Political posturing has forced Keystone XL to go through an
exhaustive review of various greenhouse gas emissions scenarios
in an effort to show construction of the pipeline will not have
an effect on emissions from the oil sands. Others are held to a
far lower standard.

This omission comes even as Enbridge and ETP have been
forthright about their plans to ship Canadian crude oil on the
pipeline since they announced the project in February. The
question to be asked: why the double standard?

Even if the Trunkline project does not cross the border with
Canada and directly increase imports of oil sands crude, it
makes oil sands production more viable by increasing market
access and hence, improving oil sands crude prices. Furthermore,
the project directly facilitates Enbridge’s own plans to
substantially increase the capacity of its own network to bring
in more oil sands crude into the United States.

The explanation for this is the fact that U.S. President
Barack Obama has not articulated a clear policy on climate
change and the use of energy in the United States. While it is
known that he backs measures to reduce America’s greenhouse gas
emissions, political opposition to those plans has led him to
prefer administrative rather than legislative approaches to the
problem.

Thus, greenhouse gas standards are being gradually
incorporated into environmental regulations. But in the absence
of a formal policy, many measures are undertaken on an ad hoc
basis.

Many observers suspect Obama does not share the doomsday
concerns that opponents of Keystone XL have raised about the
climate change effects associated with the pipeline’s
construction, but has chosen delay as a means of avoiding a
confrontation with his own core supporters.

Those suspicions are borne out when other cases, such as
Trunkline, are considered.

The converted Trunkline pipeline will move up to 600,000
barrels per day of oil from Patoka in southern Illinois to the
Louisiana Gulf Coast. The oil moved on the line will come from
Canada, where oil sands production dominates, and North Dakota’s
Bakken crude, itself an emissions-intensive crude, given the
high rate of natural gas flaring associated with oil production
in North Dakota.

But we don’t really know what the Obama administration
thinks about this issue. There has been no formal policy
articulated regarding America’s consumption of carbon-intensive
oil. Indeed, such a policy would likely be deeply unpopular,
given that it would force a long, hard look at the gas flaring
associated with the shale oil boom.

Instead all we really know is that regulatory arbitrage on
those issues is the best way to get an oil pipeline built. That
means avoiding agencies where political considerations can be
brought to bear on the review.

This serves neither the efficient development of North
America’s energy resources nor the longer-term fight against
climate change.

Nevertheless, the revelation that the European Union raided
the offices of oil majors BP, Shell and Statoil on Tuesday in
connection with an investigation into alleged oil price
manipulation has sent shockwaves into the broader market.

Price assessments underlie most of the oil and refined
products traded worldwide. Only a fraction of the world’s oil is
traded on a true spot basis. But these limited numbers of spot
trades are used to assess the daily value of crude oil and
various refined products at key trading hubs worldwide. These
assessments in turn are used to settle longer-term sales
agreements.

Only the most financially strong firms could contemplate
taking on the risk of doing most of their business on a spot
basis due to the price risk they would take on.

Exxon Mobil Corp, which is renowned in the oil industry for
its refusal to trade financial products, is probably the only
energy firm truly able to take on this risk and this is due more
to its vertically integrated business that allows it to offset
regional price swings internally than to its financial strength.

Everyone else relies to some extent or another on so-called
term deals, lasting weeks or months, that are usually indexed to
a public price assessment published by one of the major price
reporting agencies (PRAs) such as Platts, a unit of McGraw Hill
, or Argus Media, a closely-held British firm.

Why do this? The short answer is that it makes modern
commodity businesses possible. Term deals based on price
assessments allow end-users, traders and suppliers to hedge
their price exposure as they see fit, reducing an individual
business’s vulnerability to price volatility.

For instance a petrochemical firm contracts for delivery of
naphtha, the raw material for ethylene, at a set premium or
discount to a daily price assessment.

The petrochemical firm can then hedge its exposure to
fluctuations in the daily price assessment by taking out an
offsetting swap contract with a large bank, trading house or oil
major, paying its counterparty a fixed premium in return for
offloading the price risk.

PAPER-PHYSICAL EQUIVALENCE

All of this is possible through the simple fact that
exposure to the price of oil can be obtained or offset by either
physical or “paper” barrels. That is to say if a company is long
crude oil and short a financial product based on the price of
crude oil, it is market neutral.

Thus banks have a big role in commodity markets. Even if
they never touch the black stuff, pump fuel or hire a tanker
they can take on exposure to oil prices. By and large these
exposures are set off against different clients with most
profits coming not from price exposure but rather the spread
between long and short positions sold to different clients and
associated fees.

Or they can do what the oil majors and traders do: trade
both physical and financial products. Physical long positions
can be offset with paper positions. Moreover, there is no rule
that market participants have to be market neutral. Many
frequently make directional bets on outright prices or on the
price spreads between various products.

It is this paper-physical equivalence that is at the heart
of the modern oil trade that is frequently misunderstood by lay
persons. And it is likely at the heart of any alleged
manipulative practices in the oil market because the notional
value of many companies’ paper position is substantially greater
than their physical oil market position.

From late 2001 until the end of 2002 I worked as an oil
price reporter at Argus in London. During that time it was not
uncommon to hear suggestions that certain traders were allegedly
trying to “push” price assessments in a direction that favored
their positions. These accusations usually came from other
traders whose own positions perhaps lay in another direction.

Why push the physical market around? Because it determines
the value of a company’s paper position. Rival traders would
often suggest that some market participants were deliberately
taking a loss on physical trades to ensure a profit on a much
larger paper position.

Indeed, in the less liquid refined product markets the
volume of spot trade can be so small that losses on physical
positions could be tiny while the corresponding profits on a
paper position could be substantial. In many jurisdictions, the
practice, sometimes referred to as “jamming the physical,” is
not itself illegal.

The fundamental problem is that physical spot markets in oil
are illiquid. There can be days where there are no public trades
or where bids and offers fail to coincide due to limitations of
product specifications, timing and other factors. With only a
handful of firms participating in the market there are only a
few potential trades a day.

Reporters would also frequently hear that deals had been
concluded on a “P and C” basis (private and confidential) so no
pricing was available. And even when trading information was
disclosed, sometimes the whole story wasn’t there. On other
occassions aggressive traders would berate reporters to try and
get more influence over the daily assessment. Sometimes the
daily price was more a matter of a judgment call than a
conclusion drawn from plenty of evidence.

One of the first lessons taught to new reporters on the oil
price reporting beats is the challenge in understanding whether
or not bids or offers on the sale of a fuel cargo were
reflective of the broader market.

A trader could, for instance, bid for the delivery of a
cargo of jet fuel into a harbor with restrictions on the draft
of tankers. The price for such a delivery ought to be higher
than the overall market due to the difficulty in fulfilling the
order. But by how much? And what if it was the only public bid
going? What did that make the “broader market” price?

Or perhaps another trader might offer a cargo of fuel at a
particularly attractive price. Why so cheap when compared to
yesterday? It might turn out that the tanker carrying the cargo
was an older vessel that was not acceptable to most buyers.

More simply a large company with good market intelligence
would probably have a good idea where potential sellers would
have cargoes available. Thus a shrewd trader could, on slow
days, lodge aggressive bids for cargoes that had no hope of
succeeding but which would end up playing a role in determining
the daily price assessment.

To combat these practices oil price reporters are encouraged
to develop as many sources as possible with oil traders at
various firms to get as good a handle as possible on the daily
state of the market. Still, the disparity of access to market
information generally means that the media is among the last to
learn about market developments.

Platts, the only PRA to be directly drawn into this week’s
EU probe, says its current methodology, in place in Europe since
2002, is aimed at stamping out mischief by traders by making
assessments more rules-based and less reliant on reporters’
judgment.

Experienced price reporters can often ferret out
skullduggery but PRAs often face talent retention problems due
to pay, working conditions and opportunities elsewhere. It is
not uncommon for price reporters to become oil brokers or
traders. But oil brokers and traders almost never move in the
other direction.

Thus, both Platts and Argus operate with disclaimers
stating, essentially, that anyone who uses their price
assessments when conducting business does so at their own risk
and they make no warranty to the accuracy of these prices.

Thomson Reuters, my current employer, which competes with
both Platts and Argus in providing data and news to the energy
markets, operates on a similar basis. Prices and information we
disseminate about the market are for indicative purposes only.

Yet at the heart of the system are two assumptions. One is
that firms will be honest in their dealings with the media, the
other being that a competitive market makes it difficult for any
one actor to dramatically move prices in one direction for too
long. As the Libor scandal has shown these sorts of assumptions
rest on shaky ground.

Individual oil traders operate under a system of incentives
where outsized rewards are conferred largely based on the
profitability of a trading book, not for accuracy in reporting
trades to price reporting agencies. Since paper trades can be
hugely profitable, forcing even tiny moves in physical prices
that are imperceptible to ordinary consumers to benefit paper
positions must be tempting.

The end of the pipeline capacity crunch means a sea change
in the way North American oil will be priced, traded, and
balanced. With many new pipelines under long-term contracts, oil
flows will be significantly altered, potentially creating new
gluts but also pockets of scarcity.

That means the balance of power in the market will shift
away from refiners in some places. Instead of plunging crude
prices being the factor that rebalances regional markets, the
rapid erosion of refining margins will now govern balances in
places where outbound pipeline capacity, much of it locked up
under take-or-pay contracts, exceeds inbound capacity.

This is not to say that there will no longer be regional oil
gluts or no more need for more infrastructure development. But
we are entering a new era. For at least the next 12 to 18
months, the North American market will be dominated by an excess
of pipeline capacity in key regions.

Cushing, Oklahoma, the delivery point for West Texas
Intermediate oil futures, will be one such market. For years the
story has been one of a structural surplus: too little takeaway
capacity versus too many inbound pipelines. That made downward
moves in crude prices the only way to balance the market. Oil at
Cushing had to get cheap enough to stop anyone from sending more
and to spur the construction of new export lines.

That is no longer the case. With the expansion of the Seaway
pipeline to a nominal 400,000 barrels per day capacity, Cushing
is now in a structural deficit when refineries connected to the
hub operate normally. Since the system is not in equilibrium, it
is again price that will regulate the local market. But now the
price has to go up to kill off demand from regional refiners for
Cushing crude.

Already the balance at Cushing is not as favorable as it was
a year ago. Stockpiles at the hub are poised to drift lower
through the summer and with not one, but two major new pipelines
requiring perhaps 8 million barrels of linefill between November
and March 2014, the imbalance between inbound pipeline capacity
and outbound capacity is becoming acutely visible.

Those refineries like BP’s 405,000 barrels per day Whiting,
Indiana plant, which are directly connected to Cushing but have
the option of sourcing oil from many different markets, will cut
their demand for Cushing barrels as margins erode.

But if the imbalance persists, the blow will fall hardest on
refineries that have no alternative supplies. The golden age of
the refinery next door to Cushing is at an end.

TAKE-OR-PAY

It’s not just Cushing that is going into structural deficit.
A similar situation is brewing in the Permian Basin in West
Texas and the Eagle Ford shale in South Texas.

Although oil production in both areas is surging, it has
been at least temporarily eclipsed by the buildout of new
pipeline infrastructure, much of which steers crude away from
Cushing. Suddenly there is a surplus of pipeline capacity.

Don’t take my word for it. Listen to the people building
these pipelines.

Plains All American Pipeline LP, one of the oldest
and most market-savvy pipeline firms in North America, sees a
turn of the tables.

“We went through a period of time where we had a ramp up in
production and not enough capacity in either (the Permian or
Eagle Ford) areas … In the next twelve months or so you are
going to see more pipeline capacity than production in both
those areas,” Plains President Harry Pefanis said on a
conference call this week.

So what does this all mean? Generally a surplus of transport
capacity means producers can get the best possible price for
their product, so it means WTI, Permian Basin and Eagle Ford
crudes should rise in price relative to the rest of the market.

But here the importance of the contractual undertakings that
support the construction of new pipeline infrastructure cannot
be downplayed. Pipeline firms never build new facilities on a
speculative basis. A substantial amount of the capacity is
locked up under long-term contracts that oblige the shipper to
pay whether or not the line is used for a given period of time,
usually a number of years.

This upends the traditional arbitrage calculations. All
things being equal, if a refiner can buy a barrel of oil on his
or her doorstep for $100 the most this firm would pay for a
barrel at Cushing is $100 minus the cost of shipping between
Cushing and the refiner’s doorstep.

So if the cost of shipping is $2 a barrel that makes the
Cushing equilibrium price $98 a barrel. Below this, every
refiner will try to buy up the Cushing crude, moving the price
upward. Above $98 a barrel no one will buy it, pulling the price
down to a level where purchases begin.

Take-or-pay arrangements are the financial equivalent of a
wormhole. Why? Because suddenly in a simple arbitrage the cost
of shipping becomes irrelevant. And therefore the Cushing price
becomes equivalent to the refiner’s doorstep price, in our
example.

Why is this? Say Cushing oil costs $100 and refiner’s
doorstep oil costs $100. Because the refiner has already agreed
to pay the $2 shipping cost whether or not it uses the pipeline
from Cushing the effective cost of either barrel is $102 a
barrel.

Now imagine the impact of the logic of take-or-pay economics
on a situation where there is a structural deficit of crude oil
supply. Facing mandatory shipping costs whether pipelines are
used or not, shippers will have an incentive to maximize
throughputs on the newest pipelines as long as destination
markets remain attractive.

So a surplus of pipeline capacity in the Permian basin
should encourage more and more Permian basin oil to flow away
from the older pipeline network that is not under long term
contracts and onto the newer pipelines to the Gulf Coast.

That is to say the new Permian pipelines will tend to
accelerate the deficit at Cushing by shifting oil flows away
from the older routes to Cushing and other markets in the U.S.
Midwest. Permian oil will flow to the Gulf Coast until the
Cushing price rises high enough to compensate sellers for the
cost of their take-or-pay contracts.

By the same token, the new pipelines at Cushing will tend to
pull oil down to the Gulf Coast at the expense of older routes
to the north.

And since long-term capacity agreements on some of these
major new pipelines, including Seaway at Cushing and the
Longhorn line out of the Permian basin, cover up to 90 percent
of the available space on these lines the pull away from
traditional markets will be very great.

These two facts alone portend a great shift in U.S. oil
markets this year. Those who have bet on the existing paradigm
remaining in place have the energy market equivalent of the
Maginot Line.

NEW SAFETY VALVES

The effect is a sudden reversal of fortune for many inland
oil refineries. These plants have enjoyed bumper profits at the
heart of the supply glut and will now be on the leading edge of
the erosion of refining margins needed to combat the pipeline
glut.

But the implications of these developments are not limited
to inland refiners. The rapid collapse of the Brent-WTI spread
has also greatly reduced the appeal of switching to discounted
light sweet crude for more complex refineries.

When light sweet crude was in abundance, the profits from
refining these barrels were so high that inefficiencies in
complex refineries, such as underutilization of conversion
units, could be easily ignored.

To a great degree, this advantage is being wiped out.
Heavier, more sour crudes are regaining competitiveness with
complex refineries. That takes the market back to the old game
of squeezing out advantages in refining one crude over another.

But the return to a more normal refining market also implies
a return to more normal trading. A more efficient pipeline
network means a more efficient market, and one far more complex
than many traders have contemplated in recent years.
Opportunities for arbitrage will be more quickly eroded by
nimble firms. Price swings will be less dramatic.

All this means it is probably also the end to the hard-core
directional trade on the spread between Brent and WTI. The easy
money has been made. Now for the grind.

For one thing, Brent crude prices are hardly that weak. While the North Sea benchmark has dropped more than $10 a barrel from its high earlier this year, it is only now in line with the $100 a barrel target embraced by most members of the Organization of the Petroleum Exporting Countries.

The recent price decline comes as the U.S. dollar has been on the rise. The greenback is up nearly 4 percent against a basket of other currencies meaning OPEC members get more bang for the petro-bucks, undercutting one of the favorite arguments among OPEC price hawks for a higher oil prices.

And with the anticipated rise in oil demand in the third quarter, some of the slack currently in the market may well be mopped up by seasonally stronger consumption. So taking a decision now would almost certainly be premature.

Equally premature, it would seem, is the suggestion floated last week by Venezuelan Oil Minister Rafael Ramirez that OPEC members are talking about holding an extraordinary meeting.

While consultations between OPEC members likely picked up in recent weeks, there is no sign a meeting will be held before the next scheduled gathering in Vienna on May 31.

If someone was to bully Saudi Arabia into holding an emergency meeting, it would not be Venezuela. Caracas is marginalized within OPEC due to its slumping oil production capacity and limited diplomatic clout with the main Gulf Arab oil producers. With no other members calling for early talks, there is little likelihood of a formal meeting coming early.

Thus Ramirez’s talk should be seen more as an expression of the hope of Venezuela, one of the most cash-strapped members of the exporters’ club, than any sign of a policy shift.

SEASONALITY KEY

By the end of May, the main players in OPEC will have a much better idea about the state of global oil demand heading into the third quarter.

Key questions will have become clearer. Is China’s diesel export spree due to seasonal or fundamental factors? What is the scope of North Sea oil field maintenance? Are major non-OPEC supply expansions, such as Kazakhstan’s troubled Kashagan field, on track to start or are they, as is strongly rumored in the case of Kashagan, delayed again?

But even then, it is doubtful that OPEC will take any decisive action unless oil prices are weak when the group meets. A restatement of the group’s current ceiling and a vow to keep markets supplied as necessary to meet demand are the most likely outcome.

Deeper action on production would require a revival of the defunct quota system, something that cannot really be done without a major overhaul that recognizes the changes in production capacity within the group, such as the rise of Iraq and the decline of Iran and Venezuela.

Barring a serious crisis, OPEC, which cannot bring itself to agree on who should fill the largely ceremonial role of Secretary-General, will eschew the tough confrontation that would be needed to restore the quota system.

Oil at $100 a barrel is not a serious crisis for almost everyone in OPEC. And it is far from clear that oil at $90 a barrel would be a crisis either, at least for the key players within the group.

One of the least productive exercises in oil analysis is trying to figure out a short term floor for oil prices depending on the budgetary requirements of OPEC member states.

Government spending tends to rise, not only in OPEC nations, but worldwide, to match revenues. Moreover, most OPEC countries have been running healthy surpluses in recent years. Saudi Arabia, for instance, has not only been earning more than it expected due to higher prices, but also because of higher volumes.

Thus, a shortfall on oil prices ought not to immediately imply a budget crisis, at least in member states like Saudi Arabia, Qatar, the United Arab Emirates, and Kuwait, that together dominate the policymaking apparatus within OPEC.

None of the foregoing analysis, however, should be construed as concluding that OPEC is not concerned about the state of oil market today. There is a heightened awareness of the present soft state in the market but no serious conclusions have yet been drawn about the pace of oil market growth later this year.

Traders should not forget OPEC is in a stronger position now than it was a year ago when it comes to dealing with the market. The group has always been more successful at managing downside risk in the oil price than capping upward rises.

That, and the fact that the price of crude is still very comfortable for all but the most profligate OPEC members, suggests the group will continue to observe the market for some time yet.

(Editing by Marguerita Choy)

(Robert Campbell is a Reuters market analyst. The views expressed are his own)

The last wave of refining capacity rationalization has
largely run its course in the developed world. The United
States, Britain, Germany, Canada, Japan and Australia have all
seen multiple refineries close.

Yet these shutdowns have failed to keep pace with slipping
oil demand in the developed world, or to offset “capacity creep”
at other refineries. Indeed, some countries where oil demand has
fallen precipitously, such as Italy and France, have resisted
refinery closures as a means of preserving employment.

Having more than enough refining capacity to meet domestic
demand is not a problem when there are export markets that need
the product. Latin America’s deficit in refined products,
particularly diesel, has proven an important outlet for U.S.
plants.

But there is a problem here. Oil refining tends to be
fetishized by governments. The thinking goes, “it is bad enough
to depend on outsiders for crude oil, so let’s at least be able
to refine all the fuel we need.”

Thus, export markets for refined products are drying up.
China, which already has an estimated 12 million barrels per day
of refining capacity when so-called teakettle refineries are
included, continues to add new facilities.

Refining capacity expansion in China has been enough to turn
the country back into a net diesel exporter. China is expected
to export 400,000 tonnes of diesel this month amid bloated
domestic stocks and insufficient demand to mop up all the
supply.

With major new capacity expansions still due to be completed
in 2014 and 2015, China’s emergence as a diesel exporter looks
far from temporary. Indeed, with China’s track record of
overbuilding in other sectors, like steel and aluminum, oil
traders should be cautious about assuming a return to net
importer status.

NOT JUST CHINA

China alone building new refineries would be manageable. But
there are massive expansions under way elsewhere. Saudi Arabia’s
soon-to-be-completed 400,000 barrels per day refinery at Jubail
will cut deeply into the kingdom’s own deficit in some oil
products and increase surpluses in other categories. Jubail is
only the first of three such massive refineries due on stream.

Other Middle Eastern oil producers are adding refining
capacity, including the United Arab Emirates, Kuwait and Oman.
Other Asian oil importers are also adding capacity.

The surge in Asian refining capacity already has analysts
expecting the region will have to export fuel to Europe or
elsewhere to keep its own markets in balance.

The brunt of this blow has yet to be felt. Refined products
cracks, while weaker than they were at the start of the year,
are still attractive to refiners. The market has not yet priced
in much of the increase in diesel supply that seems to be
coming.

That is probably one reason why physical crude oil markets
outside of the North Sea have been showing resilience despite
the battering taken by oil and other commodities in futures
markets of late.

But with the world economy still struggling to shift into a
faster pace of expansion, the likelihood is that these
additional volumes of fuel will depress pricing once they hit
the market. Lower prices for fuel could encourage refiners to
cut runs, although experience shows that run cuts are slow to
materialize when prices fall unless the pain is sufficiently
intense.

What is probably needed to restore balance is another round
of refinery closures. Uncompetitive plants in Europe ought to be
the first to close. But many of these zombie refineries are kept
in business due to political pressure on oil companies from
governments struggling with Europe’s economic crisis.

That means the pain may have to get worse than expected in
order to force marginal plants in less dirigiste countries to
shut down. Refineries in Britain, Canada and the United States
are all at risk.

TURBULENCE AHEAD

Refineries that are prime candidates for closure are
merchant facilities with few competitive advantages. Delta Air
Lines’ experiment with a 185,000 barrel per day Trainer,
Pennsylvania refinery on the U.S. East Coast looks most
vulnerable.

Intended as a tool to hedge Delta’s exposure to record
refining margins for jet fuel, it is now giving Delta exposure
to poor refining margins for oil products in general. The plant
lost money in the first quarter and despite bullish predictions
from the airline for its unconventional approach to price risk
management, the prognosis looks poor.

The stubborn refusal of the U.S. gasoline market to return
to growth – American refineries are instead resorting to
exporting the fuel due to soft local demand – could prove fatal
to Trainer, which still makes a lot of gasoline.

Similarly geographically isolated plants in the Canadian
Maritime provinces, such as Imperial Oil’s
88,000 bpd Dartmouth refinery in Nova Scotia, are also at risk.
So, too, are refineries in places like Britain and Australia,
where closing down operations is relatively uncomplicated.

The problem is there are too many refineries worldwide that
operate on a non-economic basis. Heavy losses are tolerated in
China, for instance, or parts of Europe, or the Middle East, due
to ancillary concerns like employment.

That impedes an orderly rationalization of capacity. And
that makes the likelihood of a tough slog through a period of
poor profitability very real.

Although the incident has resulted in only a small spill in
a rural area, accidents involving crude oil being shipped by
trains are inevitable, and, according to safety data, likely to
be more frequent than spills from pipelines.

This is the key point. Any method of moving oil from point A
to point B involves risks and accidents are inevitable. A
coherent approach to resource development would rationally weigh
these risks and seek an optimal balance of risk, cost and
benefit.

This has not been the approach chosen. Rather, a haphazard
process that has seen largely unregulated oil movements by train
spring up from nothing while a minority of pipeline projects are
subjected to a regulatory process of immense complexity and
thoroughness.

As a result the Keystone XL pipeline has been in regulatory
limbo for years while existing pipelines, including major
conduits for oil sands crude, have sailed through much
lighter-touch reviews of their own expansion plans.

Meanwhile rail shipments, many of which must pass through
built up areas, have received even less scrutiny. Despite the
industry’s safety record there will be more accidents and more
oil spilled from trains.

The upshot is that the North American oil industry faces the
possibility that a sudden backlash against moving oil by rail
snarls the logistics of the continental energy system.

POLICY VACUUM

Certainly this is not to say oil movements by rail should be
halted or even reduced. While the accident rate when compared
with pipelines is higher, it is hardly the case that oil tank
cars are flying off the rails with an alarming frequency.

But what the Keystone XL saga has underscored is that high
profile projects or incidents attract a disproportionate amount
of scrutiny.

It is not hard to imagine the chaos that might ensue if a
crude oil unit train was to derail in the metropolitan Chicago
area, a key bottleneck for many shipments from North Dakota.

And given that rail movements out of Cushing, Oklahoma are
having a direct impact on the price of West Texas Intermediate
crude oil, close scrutiny of oil movements on trains could well
have a significant impact on global oil prices.

Although volumes of crude moving out of Oklahoma are
unclear, estimates peg shipments at anywhere from 50,000 to
100,000 barrels per day. Some of this oil is coming from shale
fields in Western Oklahoma. But a large chunk of this figure
represents unit trains at Stroud, Oklahoma being filled with
crude taken directly from the tank farms at Cushing.

A more coherent approach to the challenges of remaking the
North American oil logistics system would be a major improvement
on the current situation and would ease a risk for traders.

On balance it is a good thing that oil movements by rail are
on the rise.

By allowing more rapid development of frontier crude oil
deposits, North America as a whole is probably a considerable
beneficiary through jobs and a faster increase in domestic
energy output.

But rail shipments are also more risky, more expensive and
more energy intensive. It is hard to square these facts with the
stated desire of most people for cheaper, cleaner energy.

Public policy that aims for cheaper and cleaner energy must
ultimately come down in support of pipelines and their
expansion.

(Editing by Kenneth Barry)

Taking a pop at “Big Oil” helps politicians project an image
of caring about ordinary people without having to do anything.
Best of all, they can rarely do anything to actually make a
difference, so they cannot be criticized for inaction. Sound and
fury, signifying nothing.

This time it is different. Gasoline prices may well surpass
last year’s levels soon. And while crude oil is costly – the
usual and main reason for high fuel prices – the unintended
consequences of bad legislation are becoming especially
pernicious.

Last decade, under the administration of George W. Bush,
political opinion coalesced around the need to “break America’s
oil addiction.” For ideological reasons, conservation and demand
reduction measures were largely eschewed. But biofuels and other
alternatives to liquid hydrocarbons were heartily endorsed.

One result was the Renewable Fuel Standard, which mandated
the blending of an ever-rising volume of biofuels into the U.S.
gasoline pool. A key assumption behind this policy was the
belief that U.S. gasoline demand would keep growing.

That has not happened. Instead, the gasoline market has
shrunk while the biofuels mandate has risen. This year, it may
rise to the point where it causes a clash between reality on the
ground and the command economics of the RFS.

Although oil companies loathe the RFS, they have grudgingly
accepted ethanol and other biofuels up to a point. In the past,
corn-based ethanol was a boon, providing cheap, high-octane
blendstock for gasoline even as it was shielded by import
barriers and supported with tax subsidies.

The mandate was not a problem so long as the RFS volume
quota amounted to less than 10 percent of gasoline consumption
because there was no known product liability associated with
selling gasoline containing 10 percent ethanol, a level known as
the blendwall.

However fuel blends with greater than 10 percent ethanol are
not liability-free. Refiners worry that older cars could suffer
engine damage if they used high-ethanol blend gasoline, which
would expose them to lawsuits.

MAKE THIS FUEL OR ELSE

Until last year, this strategy worked. But as the RFS
mandate got bigger, the market neared the blendwall.

Now, oil companies say, the risk is the biofuels mandate
would require them to exceed the blendwall to comply with the
law. But most are refusing to make a “blendwall plus” gasoline,
arguing that to do so would unduly expose them to product
liability because older cars have not been certified to run on
these blends.

So the market is running up against oil companies’ refusal
to incur a potential liability from owners of older cars and the
law’s requirement that more biofuels be somehow stuffed into the
market.

To stay in compliance with the law while only producing
gasoline with 10 percent ethanol, the companies must either use
up blending credits saved from last year or buy them from other
companies.

When regulators drew up the 2013 version of the RFS rules,
they argued that excess blending credits generated in 2012
amounted to some 2.6 billion gallons, making problems with the
blendwall unlikely this year, although they admitted credits may
become hard to come by in 2014.

But what appears to be happening is that companies are
hoarding credits for fear of being caught short in 2014, when
even the government admits that compliance may become
impossible.

MANDATED BACKWARDATION

Here’s where the story gets interesting. There has been a
lot of talk that the high cost of credits, known in the industry
as RINs, are the reason why gasoline importers are balking at
bringing fuel to the U.S. East Coast, a partially isolated
region that depends on imports to meet local demand.

It is true that RINs have shot up in value, but the market
is thin and volatile.

Importers do not arrange trades on the day-to-day action in
RINs markets, but they are well aware of their liability under
the RFS. Like refiners, they must show they met their share of
the market quota for biofuels, either by blending ethanol into
gasoline and generating 2013 RINs or by using older RINs either
banked as credits or bought on the open market.

Already the fear is that the market will be net short of
RINs on an operating basis, i.e., every single participant will
have to rely on credits to comply with the law. So those holding
surplus RINs will only part with them at a good price.

The effect is to discourage the accumulation of inventories
because a company’s RINs liability is based on its market share.
If every gallon of inventory in excess of consumer demand means
a higher use of RINs, why would anyone stockpile fuel?

Thus we get the current situation on the gasoline futures
market. RBOB gasoline futures for delivery in April are at a
huge premium to contracts for delivery later in the year. The
market is screaming for gasoline to be available now.

But because of the penalty for exceeding local demand, the
market will supply only what can be immediately consumed unless
the price premium gets very strong.

And while the brunt of this unintended consequence of the
renewable fuels legislation will mainly fall on U.S. East Coast
consumers, it will have global ramifications.

RBOB gasoline is the world benchmark for gasoline prices. As
it goes higher, so too do gasoline prices everywhere else on
earth.

That in turn feeds into crude oil prices. If gasoline, a
product made from crude, is worth so much more, crude oil
sellers will be able to push prices up to capture some of those
gains.

In other words, bad policy, entirely the making of the U.S.
Congress, is playing a key role in driving up world oil prices.
But Congress can fix this error almost with the stroke of a pen.

The problem, then, would be what to replace it with. Beware
of future unintended consequences.

(Editing by Lisa Von Ahn)

About time, some might say. After 2012 began with oil price
spikes and squeezes amid shrinking supplies of Forties blend
crude, the key grade in the BFOE framework, calls for Brent
reform started to get loud in the spring. (See related column:
)

Months would go by as evidence mounted that the increasingly
narrow basis of the entire Brent market structure was proving to
be a fundamental problem.

By the summer the nature of the problem was clear.

Already roiled by the emergence of new demand for Forties
crude from South Korea due to the quirks of a trade treaty, the
market sudden rallied after a dramatic tightening from heavy
maintenance and a strike in Norway. (For a related column:
)

At the time, some influential actors in the Brent space
resisted any suggestion that the narrow basis of paper Brent was
itself adding to upward momentum in prices.

Yet here we are a few months later looking at proposals that
fundamentally aim to widen the basis amid broad agreement that
the measures will curb the upward bias to the Brent market
structure by enhancing the role of grades other than Forties.

FORTIES STILL KING

So far the market is still trying to figure out which of the
two competing reform proposals will attract the most liquidity.
But by and large this is a sideshow. One will win, and fairly
quickly, as the market more than anything abhors fragmented
liquidity.

The bigger picture is that the principle of price
“escalators” has now been enshrined in the paper Brent market.
How will this work and will it really curb the role of Forties?

The BFOE market is based on bilateral forward sales of
cargoes of North Sea oil. The seller has the option to deliver
any of the four grades – Brent, Forties, Oseberg or Ekofisk – to
the buyer.

The idea of making four grades deliverable was to lift the
basis of the Brent market to around 1 million barrels per day of
production. But that has not worked out as planned.

As Forties is generally a lot cheaper than the other three
grades due to its higher sulfur content, a seller faces a
considerable economic penalty if he chooses, or is forced, to
deliver a higher quality grade to satisfy his obligations.

As such, Brent effectively rests not on 1 million bpd of
North Sea output but rather on roughly 350,000 bpd of Forties
production.

This is the root of the problem with the entire Brent
structure. The wide price gap between Forties and the other
grades means any disruption to Forties output can become
enormously expensive.

As Forties output shrinks due to natural decline, the
situation gets worse. That, in turn, helps drive the strong
backwardation in Brent futures as traders try to hedge their
exposure to Forties or speculate on how Forties might affect
prices.

The changes proposed by Platts and Shell to BFOE will
reduce, but crucially, not eliminate the penalty for delivering
non-Forties grades. Both proposals would effectively rebate back
some, perhaps half, of the premium for alternatives to Forties
back to the selling party.

But because the entire premium is not rebated, Forties will
remain, under normal conditions, the most attractive grade to
deliver against a BFOE position.

KICKING THE CAN

So in many ways, the market will be unchanged from today.
Under most circumstances traders will still want to deliver
Forties whenever possible.

In an environment where Forties rises quickly in price
relative to the other grades, the new methodologies will more
quickly cap the gains by making Ekofisk, generally the
second-cheapest of the four grades, more competitive with
Forties.

So in theory, unplanned outages at the Buzzard field, which
supplies much Forties output and which wreaked havoc with Brent
trading last year, should have less impact.

Similarly, the impact of the “South Korean arb,” whereby
traders move Forties to Asia instead of delivering it on the
BFOE market, should be reduced.

But Forties price spikes will have a lingering effect.

Because both the Shell and Platts proposals derive their
escalators from past spot prices, a month where Forties prices
are strong relative to Ekofisk means a much smaller Ekofisk
escalator in the subsequent month.

So the risk is that a tight month in Forties will leave the
subsequent month more vulnerable to squeezes because the
escalator will smaller.

This is a situation that is bound to become more prevalent
as natural field decline eats away at the Forties production
base.

Effectively the Shell and Platts proposals are both only
half-measures. They curb, but do not eliminate, the
larger-than-life influence of Forties.

By leaving in some of the economic penalties for delivering
alternatives to Forties, the market’s basis has not been
substantially enhanced. Forties will remain a critical pricing
influence.

As such, Brent’s problems have not been resolved but merely
kicked down the road.

New rail facilities set to open up and down the coast next
year will give regional refiners the chance to replace a
significant chunk — perhaps half or even more– of the roughly
750,000 barrels per day in non-Canadian foreign crude they
currently import.

Factor in the possibility that U.S. crude oil from the Gulf
of Mexico could start being shipped to Eastern Canadian oil
refineries by tanker and a potentially dramatic shift in the
Atlantic basin market seems poised to occur.

First consider the growing rail infrastructure. Two railway
terminals at Albany, New York will have a combined nameplate
capacity of 295,000 bpd of crude.

Early next year rail unloading capacity at PBF Energy Inc’s
Delaware City refinery will rise to 110,000 bpd. A
similar story is unfolding at the nearby Philadelphia Energy
Solutions’ refinery, where rail unloading capacity will rise to
at least 140,000 bpd.

These three sites are only a sampling. Other terminals are
near completion in Virginia and Florida, where they will have
easy access to coastal barge networks.

The PBF facility may well be used to bring Canadian heavy
crude to the East Coast as the two PBF refineries at Paulsboro,
New Jersey and Delaware City, Delaware are the most capable of
handling lower quality crude in the coastal region.

That’s a potential threat to Saudi Arabia’s presence in the
U.S. East Coast market as PBF is the sole customer for the OPEC
heavyweight’s crude in the region.

That could well come as a godsend to hard-pressed Canadian
heavy oil producers who are currently facing prices below $60 a
barrel in Alberta amid pipeline constraints and heavy inland
competition for market share.

The other large, vulnerable chunk of the market is largely
made up of West African suppliers. Angolan and Nigerian crudes
figure prominently in the supply slate for most of the region’s
refineries.

West African grades, in particular, are likely to struggle
to compete on price with shale crudes, even if the huge costs to
move crude by rail then barge to refineries are included.

DATED BRENT EFFECT?

Since West African oil generally prices at a premium to
Dated Brent and then must be shipped to the U.S. at a cost of a
few dollars a barrel, these crudes are likely among the most
costly imported barrels in the United States.

Thus, so long as inland North American light sweet crude
remains cheap enough for refiners to be able to cover the
enormous costs of shipping it by rail, West African crude should
lose market share on the East Coast.

The impact of this sort of displacement should not be
underestimated. Already the loss of market share on the U.S.
Gulf Coast has put the price of West African crude under
pressure and provided some limited relief to European refineries
hard pressed by the natural decline of North Sea oil production.

For instance, U.S. East Coast refineries imported some
400,000 bpd of West African crude in September, according to
U.S. government data.

If only half of that amount is displaced back into the
Atlantic basin market some 6 million barrels of crude would have
to find a new home every month either in Europe or Asia.

Further displacement of West African crude from the North
American market may well push the prices of some of these
barrels to parity or below Dated Brent, giving European
refineries more room to maneuver in the face of very high North
Sea crude prices.

Whether any movement in West African crude pricing will be
sufficient to have a significant impact on the structure of
Brent futures prices is still unclear.

For now the shrinking pool of cargoes available to deliver
against the contract is likely to offset the incremental supply
gains in the Atlantic basin from West African crude being pushed
out of North America.

LLS TO MONTREAL?

Equally interesting is the likely possibility that Canadian
oil refiners will buy crude oil on the U.S. Gulf Coast for
shipment to refineries in the Canadian Maritime provinces and on
the St. Laurence River.

Unlike U.S. refineries, which would face high shipping costs
due to the constraints imposed by the Jones Act, Canadian
refineries would be free to charter foreign-flagged tankers to
move oil between ports in Louisiana and Texas and Canada.

While U.S. law generally bars exports of crude oil,
shipments to Canada have long been allowed and the U.S.
government has been granting new permits to move oil across the
northern border.

Already oil terminals along the Gulf Coast, including the
Louisiana Offshore Oil Port are retooling to facilitate the
loading as well as unloading of crude oil cargoes.

That puts the pieces into place for Light Louisiana Sweet to
move northward to displace West African crude from Canada if the
price is right. Given the high cost of West African oil and the
relatively cheap price for tanking shipping up the coast, these
new movements should be logistically easy.

But of course, all of this picture only hangs together if
inland North American crude prices stay substantially below
world prices. Rail movements to the coast are impossible without
a difference of some $15 to $20 below the landed cost of
imported crude.

Similarly, any sustained strength in LLS prices would kill
off the movement of U.S. crude between the Gulf Coast and
Eastern Canada.

This is the dilemma facing coastal refineries that have
pinned their hopes on cheaper crude supplies from inland
markets. So long as inland producers face bottlenecks in getting
their oil to market, discounts should be sufficient to make it
economical for barrels to move on trains to the coast.

But if market opportunities exceed supply, the inland price
will rise sharply to the point that marginal buyers are squeezed
out and forced back into the West African market.

WTI at Midland sank $13 a barrel to change hands near
$20 per barrel below the price of WTI at Cushing earlier
this week as traders dumped barrels ahead of December pipeline
scheduling.

Sister grade West Texas Sour , which is still a
component in some price formulas for foreign crude oil, suffered
a similar meltdown.

Dramatic moves indeed and worth closer examination. To be
sure, the magnitude of the weakness seen this week is mainly due
to the limited liquidity and volatility in U.S. physical crude
oil markets ahead of pipeline scheduling.

But the fact that such a huge decline can occur is
instructive. While a few years ago it would have been remarkable
for WTI at Midland to trade more than $1 below WTI at Cushing,
discounts are getting larger and larger.

What has happened? For a long time pipeline capacity out of
Midland exceeded demand. So that was the case the price of WTI
at Midland would be held by arbitrage forces at the Cushing
price less the cost of shipping.

But now pipeline capacity out of Midland is no longer
sufficient to meet demand. Growing oil output in the Permian
Basin has turned Midland into a “mini-Cushing.”

This is a critical point. When shipping capacity at a
pipeline hub is in surplus, market power accrues to the oil
producers who are able to charge top dollar for their product.

Yet once pipeline capacity is no longer enough to clear
demand market power swings violently to those with control over
the capacity. Anyone with more oil than pipeline space is at the
mercy of market forces.

FROM MINI-CUSHING TO MEGA-CUSHING

OK, no problem though, many may say. The problems at Midland
this week are of a one-off nature and besides, help in the form
of new pipelines that will send crude to Houston instead of
Midland and Cushing is on the way in early 2013.

There is nothing wrong here. The three-day period each month
when physical traders balance their books and dump odd lots of
oil always produce wild price action but very little oil
actually changes hands.

Moreover the extension of maintenance at Phillips 66′s
146,000 barrels per day Borger, Texas refinery cut
regional crude demand more than expected in November, leading to
a surplus of oil on hand.

And yes, there will be new pipelines. Lines out of Midland
will add a combined 80,000 bpd in capacity to Houston and
another 90,000 bpd to the Port Arthur area next year.

Similarly, the Longhorn project near El Paso will allow up
to 225,000 bpd of Permian oil to bypass Midland and Cushing
altogether and move directly to Houston starting in the first
quarter.

And finally, the 250,000 bpd Seaway pipeline expansion will
increase offtake from Cushing that should improve pricing at
that hub.

But hold on. All of this assumes that these new pipelines
clear the market and return pricing power to the hands of
producers.

Notice that these pipelines all add a huge amount of
capacity into Houston, most of which will be light oil. And this
all comes as Eagle Ford crude capacity into Houston keeps
rising.

In other words, is there not considerable risk that the
“Cushing problem” spreads from Cushing and Midland to engulf
Houston as well?

If that happens, will we not simply see light crude prices
plunge in Houston to levels well below the global market?

Indeed, Eagle Ford barrels and initial Seaway flows have
already displaced almost all of the imported light sweet crude
from Houston-area refineries, according to U.S. government data.

Some 150,000 bpd of foreign light-sweet crude was processed
in Houston-area refineries in August, far less than the expected
flood of new barrels into Houston from Cushing, the Permian
Basin and the Eagle Ford crude oil play.

That suggests light sweet crude in Houston will have to
compete on price to push out other foreign imported crude. How
much of a discount is anyone’s guess but due to restrictions on
U.S. crude oil exports, local refineries will hold considerable
sway over pricing.

That in turn means big discounts could be needed to sway
buyers, especially during periods of refinery maintenance. Next
year’s pipeline expansions will ensure a bigger market for North
American light sweet crude, but will it be big enough? And if
Houston is not big enough, can the market be sure that adding
more Gulf Coast outlets will be enough?