In previous articles, I discussed the ramifications of
developments in the Shale Gas Revolution. The revolution
continues, and is taking some important turns; some expected,
some not entirely foreseen.
The price of natural gas, hovering around $3.50 per million
British Thermal Units (MBTU), nearly exactly equivalent to $3.50
per GigaJoule (GJ) or Thousand Cubic Feet (mcf), has tested much
lower levels, at around $1.90 in late April, when a warm winter
and high gas production produced an enormous inventory surplus
heading into the spring 'shoulder season' of low demand, and
higher levels more recently.
Production, responding to lower prices, has slowed down, and
excess inventory was consumed by electrical generation demand in
air conditioning in the hot, dry conditions that prevailed in
most of North America from late spring into the early
autumn. The current shoulder season has not proved to be
one with weaker pricing.
If the winter turns out to be close to normal, or even colder
than average, the entire excess inventory should be consumed, and
gas prices could, according to some traders of the commodity,
reach over $4 per GJ, maybe over $5, although the sustainability
of such a move is in some doubt.
One major change in behavior by producers has helped provide a
lift to the gas price. As victims of their own success,
that is, the great increase in gas production having lowered the
prices they receive -- they have curtailed their exploration
plans in many cases, sold off some properties and re-oriented
their focus to liquids-rich targets to take advantage of the
higher prices those commodities get.
These liquids comprise normal petroleum, natural gas liquids
(NGLs), and the similar liquefied petroleum gases. Natural
gas liquids trade off the price of oil, and thus are not as
vulnerable to decline as the price of natural gas itself.
NGLs have ready markets to chemical firms and heavy oil and oil
sands producers and shippers.
These explorers have largely been successful in this change of
strategy, and they have rescued themselves from financial peril,
at least so far. The increase in oil production in the
United States, and even conventional production in Canada, has
been impressive. However, there have been two important,
negative side-effects of this success. The first is that,
like the shale gas production growth, the increase in oil output
is lowering the price that producers are getting in mid-continent
West Texas Intermediate (WTI) continues to trade at a big
discount to the globally-traded crudes represented by the
revamped Brent oil price. Surging Bakken formation oil from
North Dakota and Saskatchewan trades at a discount even to WTI,
as pipelines to Cushing, Oklahoma are full, as are the ones to
the port of Vancouver, and to Chicago and eastern North America.
Oil is now being transported by Canadian and U.S. trains to the
West Coast and elsewhere, instead of pipelines.
) Keystone XL Express pipeline, a political football earlier in
the U.S. election season, will, should it be finally constructed,
not help prices greatly, as it will take yet more oil into
Cushing, depressing prices, but it will help producers offload
their production more easily. The fix of rerouting around
the Sand Hills area in Nebraska seems to have mollified
Keystone's main opponents, but final approval, at state and
federal level, will still have to wait until next year, at the
earliest, and it will take a year or more to build. It will
not be a crucial development, but it will, on the whole, be a
positive one, for producers.
), which is well placed to benefit from either increases in gas,
or oil production, by virtue of its large, extensive networks of
both sorts of pipelines and gathering systems continent-wide, has
proposed more than doubling the capacity of its
Edmonton-to-Vancouver oil pipeline, to take expanding oil sands
production from northern Alberta. This would be positive
for the shale oil and gas producers, as it would redirect
pipeline space demand from
) Alberta routes away from the mid-continent, making more
capacity available to the Bakken and Niobara (in Colorado and
However, the Kinder proposal has run into opposition from
environmental and other intervenors in British Columbia (B.C),
where most of the Vancouver route runs through, and in the
Vancouver area itself. Since the route is not a new one,
nor is the pipeline, having been in place for decades, this
should not be controversial, but it has become so. Kinder
had a bad leak a few years ago, caused by a non-Kinder
construction crew accidentally hitting the line. While not
its fault, it still affects perceptions.
Even worse, though, is the fall-out from the opposition to
Enbridge's proposed Northern Gateway pipeline, going from
Bruderheim, near Edmonton, generally following the northern
branch of the Yellowhead Highway to Kitimat on the West Coast of
British Columbia. There are three main issues: tanker
dangers at Kitimat and in the passage through the islands and
along the coast to that port; the hazards of spills on land and
in water bodies in the interior of B.C.; and, finally, the
less-than-stellar safety record of Enbridge itself.
The company did not respond quickly to a substantial spill into
the Kalamazoo river in Michigan a few years ago, and there have
been other apparently substandard incident responses documented
by critics and regulators. Another complication is that
Northern Gateway has become a B.C. provincial election campaign
issue, with all major parties competing to be more strident in
their skepticism and suspicion of the project. Gateway is
not only crucial for northern Alberta oil sands producers to get
their projected expansion of production to market, yet it also,
indirectly, affects shale oil producers in not just Canada, but
in the U.S., too.
If that expanded oil sands production does not find an outlet to
the West Coast, it will go to the mid-continent, and keep WTI
prices depressed, and reduce netbacks in North Dakota and Canada
even more than today. The proposed changes in TransCanada's
gas pipeline to Eastern Canada and the U.S. to take oil east
instead of gas will help somewhat, but current plans are not big
enough in scale to remedy the situation completely. There
are some lower capacity or shorter pipelines and pipeline
extensions throughout North America that will aid in a more even,
thorough distribution of both gas and oil that get little
publicity, including several in the mid-West and the Appalachian
regions, but these will take some time to have an impact.
Getting back to the shale explorers and producers, their refocus
on liquids superficially would appear to help reduce gas
production growth and oversupply, but there is another aspect to
it that is an unpleasant side effect. Their search for oil
has mostly been successful and production is climbing.
However, it is impossible to produce shale oil without producing
at least some gas, since the exploration is as much an art as a
As oil is the primary target, and, if the wells and attendant
fracking produce sufficient quantities of it to justify the cost
and risk, they do not care if they produce a little or a lot of
associated gas, and, accordingly, do not care much what price
they get for that gas, or that the price may decline; for many
producers, it is not a significant factor in their
Hence, there is, and will likely continue to be, a lot of gas
produced, and even more as the liquids plays become more
lucrative and production accelerates. The gas is a bonus,
but not crucial. Therefore, the refocus of the explorers on
liquids will not necessarily lower gas production or improve
pricing, in the short or long term.
Meanwhile, more and more users of gas are betting on continued
supply growth, and that prices will not escalate dramatically.
Nearly all new planned electrical generating capacity in North
America is natural gas fired. Not only is the fuel cheaper
than coal, but the plants are less expensive, faster to build,
and cleaner to operate. There will be nearly one hundred
million more people in North America in the next forty years, and
they will all need gas and electric service, assuring substantial
There is another unusual development that could foster the use of
natural gas for electricity: a new kind of fuel cell for
buildings. It takes in natural gas and converts about half
the energy to electric power. This is at least as efficient
as natural gas generators, and also eliminates the losses in
power from transmissions and substations, which can be as much as
50%, depending on the distance.
This technology is already commercial and being deployed in
office buildings in the U.S. Innovative, nascent industries
such as this one are hampered in some respects, being dependent
as it is on gas utilities and distributors; by their rate-base
regulated nature, there is little incentive for them to foster
such development; their kindred regulated electric utilities may
try to stop them entirely.
Meanwhile, the North American gas surplus has given confidence to
oil and gas majors that there will be enough supply to ship to
foreign markets and to support liquefied natural gas (LNG)
facilities, which have a high capital cost. There are now
at least five such facilities mooted for Kitimat to ship to
Korea, Japan, and elsewhere across the Pacific, and several
installations planned for the U.S. Gulf Coast. Curiously,
the natural gas pipelines that would take Northern B.C. gas to
Kitimat are attracting no opposition, despite the rancor directed
at the oil lines.
There is some concern that the U.S. federal government may not
give export permits to some or all exporters in the Gulf, but it
seems unlikely that jobs and revenues that would be generated
could be forsworn in the current stagnant, high unemployment
Probably the biggest single event validating the gas story is the
new push to build a trans-Alaska natural gas pipeline to take
North Slope, and, later, Beaufort Sea gas to the south to the
Gulf of Alaska, likely at Valdez, where the oil line terminates
as well. This gas, too, will be destined for Asia.
The cost will be staggering, and it will take a long time to
build. That is a good thing, because, despite a lot of
exploration, there is still not a lot of offshore gas developed
in Alaska's Arctic waters. The line is not dependent on
successful exploration, but it would help fill its capacity as
the onshore reserves deplete.
There has also been a considerable amount of natural gas proved
up onshore in the Mackenzie Delta in nearby northern Canada, gas
which had appeared to be stranded, as the long-proposed (since
the 1970's) pipeline to bring it south no longer makes sense with
all the surplus gas in southern Canada and the lower forty-eight
states of the U.S. Now, a relatively short lateral line
could take all that stranded gas along the coastal plain to the
Alaska pipeline, making both reservoirs even more valuable.
Outside North America, where gas prices only have indirect
relation to oil prices, gas contracts for customers explicitly
are tied to international oil prices. Thus, until recently,
companies developing reserves in Russian, Central Asia, and
offshore Australia for sale in Europe or South or East Asia were
confident that they would get prices of over $10 per GJ, far
higher than have been seen in North America for many years.
However, big buyers, generally electric or gas utilities, are now
aware of the big fields coming onstream, and even more aware that
they have choices, and can set sellers competing against each
other. This global 'gas-on-gas' competition is just
beginning; it has been prevalent in North America for decades,
now. It will take some time for prices in the rest of the
world to come down, and for them to rise in North America, as all
these projects will take years to compete and become operational,
while, at the same time, gas demand will continue to rise.
When it comes to international shale gas development, the only
place with real progress has been China. In the past
several months a number of new wells have been drilled, with,
apparently, some success. So far, the amounts proved up
have been kept secret, or may not be easily appraised.
Given the tight control that Beijing has over the national
industry, and the lack of commercial freedom, it would seem
unlikely that production will take off the way it has in North
America over the past decade. However, given all the
technology that has been developed, which China can simply
license or copy, they do not have to repeat all the mistakes and
learning process that the producers in the West had to go
In other high-potential regions, progress is still slow.
Argentina's turmoil and anti-business stance, let alone its
), has indefinitely delayed development of its still-hypothetical
reserves. In Africa, some nations are attempting to
retroactively change royalty, tax, and ownership regimes in their
governments' favor, retarding continued investment by foreign
majors and independents. However, huge new reserves found
offshore Mozambique look likely to be commercialized relatively
In Israel, offshore gas and some liquids could make that
nation energy independent within a few years' time. There
is also some progress on developing kerogen deposits.
Potential reserves could be 250 billion barrels of oil
equivalent. While there is little to no exploration risk,
getting the stuff to flow is itself energy intensive, and
requires current world oil prices to remain high for it to pay
off. Onshore Australia, coal bed methane (CBM) and tight
shale formations are adding to the offshore bonanza that is
generating over $100 billion in LNG facilities to serve
Asia. These will, as stated earlier, all take several years
to come to full service and production.
When it comes to offshore exploration in the U.S., outside the
Gulf of Mexico, it remains environmentally controversial, and
will take a lot of time to fully assess, let alone successfully
explore. Significant production is a long way off.
Should it occur, despite environmental opposition, it will have
little effect on oil prices in the U.S., as the offshore
precincts are more closely integrated with world markets and
pricing. The natural gas price could be affected, though,
depending on the magnitude of any volumes discovered.
More near-term, in Mexico, the new administration which will take
office in Mexico City on December 1st is determined to increase
production from the properties the national oil monopoly, Pemex,
controls. They plan to introduce legislation to make it
much easier for foreign firms to apply their technology and get
fully rewarded for it the more successfully it is applied.
As many firms are already operating there under contract, results
could be forthcoming relatively quickly. Mexico also has a
number of attractive shale formations.
There are a number of ways to play the expansion of shale gas and
liquids production and use. Probably the safest
alternatives are to invest in the carriers, such as Kinder
Morgan, TransCanada, and Enbridge. Mid-stream processors
are also in a good situation; they will make money as volumes
passing through continue to grow, along with the demand for
feedstock from chemical and fertilizer producers.
The developers of LNG and other processing facilities should
continue to do well for many years to come. They include
Chicago Bridge and Iron
), and others.
When it comes to the actual producers, the picture is
cloudier. As victims of their own success, they are on a
treadmill of having to find more and more reserves as prices
falter or even decline at times. The ones with the greatest
exploration success, and the ability to keep free cash flow
growing, even in depressed times, are the ones to examine
), and others, look how they performed in the second quarter of
this year, and watch the reports from Zacks to see which are
primed to outperform their peers over a sustained period.
It can be worth it to pay a premium for a proven survivor that
can thrive in adversity.
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