| NEW YORK, July 9
NEW YORK, July 9 Four years into the shale
revolution, the U.S. is on track to pass Russia and Saudi Arabia
as the world's largest producer of crude oil, most analysts
agree. When that happens and by how much, though, has produced
disparate estimates that depend on uncertain factors ranging
from progress in drilling technology to the availability of
financing and the price of oil itself.
Forecasts for U.S. shale oil production vary from an
increase of 7.5 million barrels per day by 2020 - almost
doubling current domestic output of 8.5 bpd -- to a gain of 1.5
million bpd, or less than half of what Iraq now produces.
The disparities are a function of the novelty of the shale
boom, which has consistently confounded forecasts. In 2012, the
U.S. Energy Information Administration (EIA) estimated that
production from eight selected shale oil fields would range from
700,000 bpd of so-called tight oil to 2.8 million bpd by 2035. A
year later, those predictions had been surpassed.
"The key issue is not whether production grows, it's by how
much," said Ed Morse, global head of commodities research at
Citigroup in New York. "We're only at the beginning of the first
inning and this is a nine-inning game."
The stakes couldn't be bigger, ranging from the
multibillion-dollar investments needed to explore and drill to
oil supply issues that go to the heart of U.S. foreign policy.
Relations with countries ranging from Iraq and Iran to Russia,
Ukraine, Libya and Venezuela are colored to one degree or
another by the question of energy.
The U.S., a nation transformed by the 1973 Arab oil embargo,
could become energy independent by 2035, according to bullish
forecasts from BP Plc and the International Energy
Agency. Coupled with growing output from oil-rich neighbors, the
continent has a growing shield from supply shocks.
"Looking at North America, including Canada and Mexico,
we're much more politically stable," said Lisa Viscidi, program
director of the Inter-American Dialogue in Washington.
Still, many drillers have found that healthy forecasts of
oil in the ground don't guarantee it can be economically
For example, based on the promise of free-flowing oil,
Chesapeake Energy's then-top executive Aubrey McClendon
bought up land in Ohio's Utica shale oil field and touted it in
2011 as a $500-billion opportunity. State geologists estimated
the shale play could hold as much as 5.5 billion barrels of
But last year, after months of drilling, Chesapeake's
average output per well per day was just 80 barrels. Competitor
BP wrote off $521 million and exited the Utica just two years
after leasing 85,000 acres.
Shale production from the oldest shale patch, the Bakken of
Montana and North Dakota, alone may rise to as much as 1.74
million barrels per day in the second half of this decade,
according to the highest of six estimates compiled by Reuters.
The lowest was 1 million bpd. Even that range belies
disagreement over just how fast output will grow -- and when it
may peak. (Graphic: link.reuters.com/ref32w)
The EIA, the U.S. agency responsible for energy forecasts,
predicts that tight oil output will rise 37 percent from about
3.5 million bpd in 2013 to 4.79 million barrels per day by 2020.
The forecast includes the Bakken, Three Forks and Sanish, Eagle
Ford, Woodford, Austin Chalk, Spraberry, Niobrara, Avalon/Bone
Springs and Monterey.
"There are other forecasts that are much more optimistic
than this one," said agency administrator Adam Sieminski,
speaking at a conference in New York. "We're still a little
concerned about what the geology looks like for crude oil
production. As technology moves, these numbers could grow."
The agency has already made some big adjustments to previous
estimates. It recently slashed its forecast recoverable reserves
for California's Monterey shale to just 600 million barrels, 96
percent less than the total amount of oil in place, citing the
difficulty in pumping it out economically.
IHS Energy's projections are higher, with an estimated 6
million bpd from the Bakken, Eagle Ford and sections of the
Permian and Niobrara by the end of 2020.
At the low end, Energy Aspects Ltd sees production of 3.5
million barrels a day from shale by 2017, a 1.5-million bpd
increase from its current output estimate of 2 million bpd.
"In order to keep production going, you have to maintain
your drilling and therefore, capex investments need to be in a
continuous cycle," said Virendra Chauhan, an oil analyst at
Energy Aspects in London.
McKinsey & Co.'s forecasts illustrate the uncertainty. While
the consulting firm uses a reference case that puts tight oil
production at the equivalent of 7.1 million bpd by 2020, it said
the number could range from 5 million to 9 million bpd.
In its annual outlook released last month, BP estimated that
U.S. tight oil production will increase to 4.5 million bpd in
2035. Exxon Mobil Corp. says global tight oil
production, driven by North America, will rise 11-fold from 2010
to 2040, when it will account for 5 percent of global liquids
output. Exxon added that in 2015, North American tight oil
supply in 2015 will likely surpass any other OPEC nation's
current oil production, with the exception of Saudi Arabia. Iran
is the second largest OPEC producer, with about 4.2 million bpd.
Production forecasts are inherently problematic, especially
years in the future, as they fail to anticipate major new
discoveries or abrupt depletion rates.
Even so, the industry's reliance on multi-year mega-projects
such as those off the coast of Angola or in Brazil's sub-salt
region -- which progress along generally predictable time frames
and produce stable volumes of oil for years afterward -- made it
relatively simpler to anticipate new oil coming onto the market.
The shale oil industry is more complicated.
For instance, the rapid development of reserves in places
like China and Russia could force prices lower, curtailing U.S.
drilling. New technology may render development cheaper and more
efficient, speeding it up. A change in current domestic policy,
particularly an easing of the ban on crude exports, would also
shape the forecasts.
Add to that growth the pipelines connecting Canadian
producers to U.S. refiners, including TransCanada Corp's
830,000 bpd Keystone XL pipeline, whose approval has
been delayed by the U.S. government for more than five years.
Never mind the vagaries of the credit cycle, which has also
become a larger part of the puzzle. Companies face high levels
of reinvestment to ensure the same levels of return for drilling
oil, meaning companies have to take on additional amounts of
Consultancy Wood Mackenzie estimates that it would require
capital spending of $9.58 to $32.97 a barrel to drill in the
Eagle Ford basin, depending upon which part of the formation was
"We're operating at present in a low interest rate
environment, but a risk is what happens if the cost of credit
rises," Energy Aspects' Chauhan said.
(Reporting by Catherine Ngai, editing by Jessica Resnick-Ault
and John Pickering)