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National - Time to Lock-in: Favorable Prices May be Now
By Special Contributor, Andrew Weissman, Publisher, Energy Business Watch
For commercial and industrial
customers, the first few months of 2010 have been a good time to
be on the buyer’s side of the market for electricity and natural
gas. While prices have not returned to 2009 lows, the most
important factors driving electricity prices have all been
positive. Natural gas prices have remained low. Coal prices have
also been generally moderate, with the exception of North
Appalachian coal. While electricity demand has been increasing,
this has been partially due to much colder-than-normal winter
weather in regions that heavily utilize electric heating, and is
likely to slow down. During the summer, demand is likely to
remain far below 2007 and 2008 peaks. Not surprisingly,
therefore, given this combination of factors, electricity prices
have remained attractive. Notably, the 2011 and 2012 calendar
year strips have come down significantly, due largely to the
sharp decline in the forward delivery price curve for natural
gas.
Despite the economy’s nascent revival and oil
shooting back above $80/barrel, energy costs for many companies
are still near their lowest level in the past decade. Natural
gas has decoupled almost entirely with oil and the tie between
coal and oil is much weaker than in earlier years. As a result,
the link between U.S. electricity prices and the global oil
market that was starting to drive electricity prices up rapidly
just 24 months ago has largely disappeared. Increasingly, the
combination of low natural gas prices and attractive electricity
prices, in the most electricity-intensive economy in the world,
is giving U.S. manufacturers a competitive advantage in the
global export market. The most energy-intensive sectors of the
U.S. petrochemical industry now have a lower cost structure than
many of their competitors, reversing the pattern during most of
the past decade and reviving exports in industries in which it
had been expected that U.S. companies would no longer be able to
compete.
How long will the positive news continue? Will
natural gas and electricity prices fall sharply, as they did for
several months last year? Or will prices do a u-turn soon? If
the market reverses, how far will prices rise?
Near-term,
we believe the natural gas market is starting to bottom out. As
a result, we have advised our clients to begin looking for
opportunities to lock-in prices for any portion of their 2010
needs that is not yet protected. Increases in the spot market
price later this year, however, are likely to be modest. While
not yet widely understood, major structural changes are
occurring in the U.S. market that permanently reduce the likely
frequency and magnitude of price spikes. The full impact of the
market re-structuring that is underway, however, is not yet
fully priced into the 2011 and 2012 calendar year strips and is
even less significant on futures prices further out in time. We
have recommended, therefore, that longer-term commitments be
deferred, to allow prices more time to drop.
From a
customer’s standpoint, the most encouraging development this
year has been the release of EIA’s Monthly Production Report for
April, issued on April 29th – just a few days before this column
went to press, which provides monthly estimates of U.S.
production through February of this year. This estimate revealed
the extent of the impact shale production is already having on
the U.S. natural gas and electricity markets – and provides an
early indication of the sweeping impacts it is likely to have on
the U.S. energy market in future years.
In its report,
EIA applies for the first time a revised methodology for
estimating gross withdrawals from the lower 48 states from small
producers who do not report output directly to EIA on a monthly
basis. The methodology is intended to better reflect changes in
total production by small producers that were not adequately
captured in earlier reports.
Before EIA issued this
report, many industry insiders and speculative investors
believed that EIA’s Monthly Reports had been greatly overstating
U.S. production, which many market observers believed had fallen
significantly after the natural gas rig counted started to
plummet in late 2008 and early 2009. As a result, there was a
widespread expectation that the April Report would show that
current U.S. production is considerably below earlier levels and
has been trending downward, increasing the likelihood that the
market will significantly tighten later this year. If the April
Report had confirmed this view, the price of the June ’10
natural gas futures market might have quickly be driven back
above $5.00/mmBtu. This increase undoubtedly would also have
spilled over into the electricity market.
Instead, EIA’s
April Production Report blew these expectations out of the
water. While the April Report adjusted EIA’s earlier production
downward, even in the months with the largest adjustments, EIA’s
reductions were too small to drive the market back up.
The greatest shock, however, was EIA’s estimate for February
2010 production. Rather than reporting a steep decline from 2009
production levels, EIA reported a new all-time high for gross
withdrawals from wells in the lower 48 states of 63.85 Bcf/day.
EIA estimated that, on a sequential month-to-month basis,
withdrawals had increased by 1.0 Bcf/day from January to
February. This is a stunning increase, especially since
hurricane recovery was not an issue.
EIA’s revised
estimates showed that production had declined significantly in
Texas, New Mexico and Oklahoma during the past year. Significant
drops also undoubtedly also occurred in several other states for
which EIA does not separately report production. EIA’s revised
data, however, showed that these declines had been totally
offset by increases in Louisiana and in its “Other States”
category, which includes all of the production increases due to
rapidly growing shale production in Appalachia and Arkansas.
It will not be surprising if EIA reduces its initial
estimate for February by a few tenths of a Bcf/day when it
issues its May report. The likelihood of a steep production
increase in February, however, rings true. A variety of factors
contributed to this increase: deployment of a record number of
horizontal rigs (which currently account for more than half of
the natural gas rig count); a surge in production in the
Haynesville formation in Louisiana and East Texas (at which more
than 20% of all natural gas rigs were deployed during the first
few months of 2010); rapid increases in production at the
Fayetteville formation in Arkansas and the Marcellus Shale in
Appalachia; recovery from freeze-offs in December and January
and increased pipeline send-out capacity in several production
areas; and significant increases in production at Granite Wash
and the Woodford formation in Oklahoma and Eagle Ford in south
Texas (as a result of which production is starting to rebound in
both states).
While U.S. production almost certainly will
not surge as rapidly in future months, the growth in production
in February, coupled with the increases in the rig count late in
2009 and continued increases in the number of horizontal rigs
deployed during the first four months of 2010, reaching record
highs, suggests the potential for continued significant
increases in production for the next several months. This
significantly limits the potential for price increases during
this year’s injection season, especially since recent weather
forecasts suggest that weather-driven demand for natural gas
this summer is likely to fall well below normal.
The
impact of continued increases in U.S. production on prices
during the next several months, however, should not be
exaggerated. At the start of this year, the supply/demand
balance in the U.S. market was far closer to equilibrium levels
than it had been when 2009 began. Further, industrial demand has
increased sharply for the first time in years, due to the
combined impact of a rebound in industrial production and prices
low enough for the U.S. petrochemical industry to increase
exports at a rapid rate. At the same time, due to rapidly
declining production in Alberta, a steep fall-off in Canadian
imports into the U.S. could cancel out all or most of the impact
of increased U.S. production. LNG imports in May are expected to
fall to the lowest level in eight years, and are likely to
remain lower than previously expected if prices at Henry Hub
remain near current levels. As a result, the need for steep
price declines to induce sufficient substitution of natural gas
for coal to balance the market – which was the main factor
driving the spot market price of natural gas down to
breath-taking lows – is not likely to exist this year unless
summer air conditioning demand is exceptionally low, or the U.S.
market becomes the dumping ground for large amounts of LNG not
needed by the global market during off-peak months.
Instead, just the opposite could occur. Huge amounts of
additional storage capacity are being added to the North
American market, due to an unprecedented build-out of new
underground storage facilities, large increases in the total
amount of above-ground storage capacity at U.S. LNG terminals
and the addition of the Canaport terminal in New Brunswick.
Except in an extreme scenario that would severely reduce
weather-driven demand for natural gas, the addition of this
storage capacity reduces to near-zero the potential for price
spikes during this year’s injection season. This could entirely
eliminate the need for coal displacement and result in the spot
market price quickly returning to $4.37 to 4.54/mmBtu. Once the
likely availability of excess storage capacity during this
year’s injection season becomes better understood, the spot
market price could be pushed closer to $ 5.00/mmBtu. Prices
could be driven even higher if there is a significant loss of
production due to hurricanes during this year’s hurricane season
and/or as a reaction to a potential environmental catastrophe
from the explosion at the BP rig in April. This would be likely
to drive the forward delivery price for electricity higher at
the same time.
On a risk-adjusted basis, therefore, we
believe that the likelihood of a further price decline is
relatively low, with a significantly greater upside risk. In our
judgment, the time to cover remaining open requirements for 2010
may be near.
The long-term implications of the production
increase EIA reported in April, however, may be even greater.
Shale is here to stay, and is transforming the natural gas
industry and the U.S. electricity market. The successful
development of the Barnett Shale in Texas has spurred a
succession of huge new shale gas plays. Many of these formations
are even more prolific than the Barnett and also have
significantly lower cost structures in core areas. Production
from shale is growing explosively. This explosion is not likely
to be quickly halted. Too much production has already been
hedged. Further, many believe that 50% or more of the extant
drilling is required to avoid forfeiting leasehold interests in
reserves, many of which have been acquired at high prices.
Other factors, including Wall Street’s interest in companies
poised to become dominant players in shale, also could push
shale production higher for most of this year. Over the past 24
months, since the magnitude of Haynesville’s potential became
public, most large U.S. producers have “picked up stakes” to a
significant degree, allocating large shares of available capital
to developing shale formations that were not even on the
industry’s radar when 2008 began. The inflow of capital from
other sources has been even more impressive. ExxonMobil’s
acquisition of XTO in late 2009 made the biggest splash, but a
long list of other investors has bet tens of billions of dollars
on shale in a remarkably short time, including BP, Shell,
British Gas, Statoil, Total, major Japanese companies and an
increasing number of overseas players–many of whom have not
previously played a significant role in the U.S. market. Many of
these companies are committed strategically to becoming major
players in shale development, which require huge commitments of
capital and are expected to offer major economies of scale.
Given their strategic commitments, these companies are not
likely to give up lightly on their efforts to become industry
leaders in shale.
This is very positive news for
commercial and industrial users. Precisely because the
implications are far reaching, there is much to be discussed in
our future quarterly reports.
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