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Days of Shock and Awe About to Hit the Natural Gas and Power
Markets Part 1 |
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To say the
least, the picture that emerges is sobering. If there
were any prior doubt, after this past winter heating season it should be
crystal clear that the U.S. natural gas market is experiencing a severe
structural deficit. As explained below, supplies of natural gas available to
the U.S. market in 2003 are certain to fall at least 1.0 – 1.5 TCf below the
Energy Information Agency’s (“EIA’s’) most recent forecast of expected U.S.
demand for the year. This is a
staggering shortfall, with profound implications for energy companies and for
the health of the U.S. economy. Yet, the potential for a deficit of this
magnitude is not yet widely recognized. Nor are most end users or state
regulators prepared for the profound dislocations that are likely to occur in
both the natural gas and power markets over the next 90 to 120 days. Further,
this growing imbalance between available supplies of natural gas and expected
demand is not likely to be short-lived. Instead, it reflects the early stages
of a long-term structural imbalance, in which supplies of natural gas available
to the U.S. market are likely to consistently fall 10% or more below the
levels achieved during the 1990’s, at the same time that the underlying rate
of demand is likely to continue to increase every year -- at least at prices
anywhere near current levels. These continuing increases in the amount of
natural gas needed to supply the U.S. market are due primarily to increased
demand in the power sector -- which is expected to increase by at least 2.5 –
3.0 TCf between now and the end of the decade. See earlier articles on The
Coming Natural Gas Crisis and A Cautionary Tale. Absent
adequate supplies of natural gas to fuel the 200,000 MW + of new gas-fired
capacity built over the past 4 years (at a cost of more than $ 100 billion),
there is no readily apparent means to meet the incremental electricity needs
of the U.S. economy over the next 5 – 7 years – raising serious question as
to how the growth of the U.S. economy will be sustained during the remainder
of this decade, while new, longer-term source of natural gas supply are being
developed. Urgent
National Concern As serious a
threat as this long-term structural imbalance is likely to pose during the
remainder of the decade, however, the energy industry and the economy face a
particularly daunting challenge right now. This
challenge arises from the urgent need to inject unprecedented amounts of
natural gas into underground storage during the remainder of this year’s
Refill Season and the lack of adequate supplies to meet minimum storage
targets required to protect public safety and reduce the risk of runaway
natural gas prices this coming winter. The need to
inject record amounts of natural gas into storage could not come at a more
difficult time – i.e., just as U.S. production is about to hit its lowest
level in 16 years. During the remainder of this year, imports of natural gas
from Canada also are likely to decline sharply. Exports of natural gas to
Mexico are likely to rapidly increase. To make
matters worse, inventories of distillate also are near record low levels --
limiting the potential for fuel switching. As this
article is being written, only 24-25 weeks remain in the Refill Season (i.e.,
less than 175 days). The amount of working gas in underground storage remains
only modestly above the all-time record lows reached in mid-April. Despite the
short time remaining, however, there does not yet appear to be any clear
recognition of how steep a price increase is likely to be necessary in order
to free-up the additional supplies of natural gas needed to rebuild storage
or the extent of the potential run-up that may occur in the spot market price
for electricity before the end of this summer. Comparison
to Injection Levels Required in Earlier Years In the
aftermath of this past winter’s record draw downs from storage, most Local
Distribution Companies (LDC’s) east of the Rocky Mountains are keenly aware
that they will need to begin injecting natural gas into underground storage
earlier than has been necessary in the past and to inject significantly
larger quantities into storage than in prior years. The
potential cumulative impact, however, of many LDC’s simultaneously
stepping-up their purchases during a single, compressed time period in a
chronically under-supplied market is not yet well understood. This past
winter, end-of-withdrawal season storage in the U.S. reached an all-time
record low, with the amount of working gas in underground storage bottoming
out at 623 BCf on April 11th. Just as significantly, underground storage in
Canada was depleted even more severely than in the U.S., with the amount of
natural gas in underground storage in Canada falling to a level almost 70%
below end-of-season storage levels last year. To restore
the amount of natural gas in storage to year-ago levels, all-time record
injections will be required in both the U.S. and Canada. This should
give rise to grave concern – even before taking into account factors that may
cause the supply demand balance in the North American market to deteriorate
further between now and the end of this year. As explained
in prior articles, relative to historical norms on a weather-adjusted basis
the amount of natural gas in storage in the U.S. has been declining for
fifteen consecutive months. Month after month, injections during the Refill
Season have been falling significantly below the 5-year average and
withdrawals during the winter heating season have been consistently exceeding
the same benchmark. The size of the deviation from historical norms (both
injections and withdrawals) generally has been increasing over time. The U.S.
market has never previously experienced a continuing decline in storage
relative to historical norms of this magnitude. On an aggregate basis, the
total decline in storage during this 15-month period, after adjusting for
weather and for seasonal variations in demand, is more than 1.25 TCf. This is a
stunning decline. It only can be explained as a result of a severe mismatch
between newly available supplies and seasonally adjusted demand. This
mismatch appears to be widening over time. For many
months, the emergence of this deficit was masked by the combination of a
severe manufacturing recession in 2001, the further adverse impact on the
U.S. economy of the September 11th terrorist attacks and the extraordinarily
mild temperatures that occurred during the ‘01/’02 winter heating season.
This unique combination of events resulted in a record build-up in storage
during 2001 and early 2002, with the amount of natural gas in storage peaking
on a seasonally adjusted basis in February of 2002 at almost 700 BCf above
the 5-year average. This existence of this surplus in turn allowed the U.S.
natural gas market to operate in a deficit condition for more than a year
without a sharp run-up in prices. The storage
build up that occurred in 2001 and early 2002, however, has now been entirely
eliminated. In its
place, in a remarkably short time span, storage has been reduced to an
all-time record low (viz., as of the week ended May 2nd, 821 BCf – i.e., 545
BCf (or 40%) below the 5-year average for this date). This rapid decline in
storage has occurred even though, as recently as last October 24th of last
year, the amount of natural gas in storage was still 189 BCf above the 5-year
average – a drop of more than 725 BCf relative to historical norms in just
the past 6 months. There is no
compelling reason to expect this 15-month pattern of continuing declines to
suddenly reverse. Unless it does, however, even matching last year’s
end-of-Refill Season storage level of 3,172 BCf may prove to be a nearly
impossible task, at least without unprecedented increases in the spot market
price for natural gas. Ensuring
Adequate Levels of Storage If the
challenge facing the industry weren’t already sufficiently daunting, however,
one lesson that is – or at least should be -- crystal clear after last winter
is that merely matching last year’s end-of-Refill Season storage level again
this October will not be adequate to protect against severe price spikes or
even to protect public safety going into next winter. As discussed
in detail later in this article, contrary to what many analysts assume,
temperatures last winter were slightly milder than historical norms. If the
weather last winter had matched the last recent colder-than-normal winter
(i.e., the winter of ‘00/’01), the total withdrawal from storage could easily
have been another 500 -- 600 BCf greater than the withdrawal that actually
occurred last winter – when the cash price in the day ahead market at Henry
Hub reached all-time record high. In all
likelihood, if temperatures last winter had matched the ‘00/’01 winter
heating season, the amount of working gas in storage would have been reduced
to near-zero levels and prices would have spiked even higher than they did
this past February and March. If anything,
therefore, last winter’s experience strongly suggests that, in a
rapidly-changing market, in which residential and power sector demand is
growing every year and supplies available to the U.S. market are continuing
to decline rapidly, even filling storage to the brim – i.e., in the U.S., a
little over 3,450 BCf – might not fully protect the public interest. Instead,
there appears to be an urgent need, to expand existing storage capacity –
perhaps by as much as 20 -- 25% (i.e., to at least 4,175 BCf). As a
practically matter, given the short time that remains between now and the end
of the Refill Season in mid-to-late October, it is not physically possible to
expand storage quickly enough to increase the amount of natural gas that can
be stored this winter. At a
minimum, however, given the huge withdrawals from storage that occurred this
past winter (in a winter that was slightly milder than historical norms),
prudent planning requires that the industry attempt to fill existing storage
as close as possible to maximum capacity in both the U.S. in Canada before
the end of the Refill Season in mid-to-late October. This in turn
requires LDC’s and their suppliers to inject an additional 2.65 TCf into
storage in the U.S. and more than 350 BCf in Canada in a span of no more than
24-25 weeks. This rate of
injections has never previously been achieved in the North American market in
any prior Refill Season. These record
injections are necessary in order to: (i) protect against the potential for a
colder-than-normal winter; (ii) provide adequate reserves to protect against
continued declines in production, pipeline failures, potential outages at
nuclear plants and other contingencies; and (iii) ensure that, in the words
of one LDC, that “no one’s grandmother freezes to death in late March or
early April” if a cold snap hits late in the winter (as occurred in early
April of this year in the midwest). The same
underlying structural supply deficit, however, that caused withdrawals from
storage to far exceed historical norms this winter make this an impossible
goal, at least at prices anywhere near current levels (which, in recent weeks
have ranged between $ 5.25 and $ 5.75/MMBTU in the day ahead cash market at
Henry Hub in the Producing Region in Louisiana). Indeed, if
anything, at current price levels, it is not clear that injections into
storage will even match last year’s anemic levels – in which a meager 1,500
BCf was injected into storage during the period between May 2nd and the first
withdrawal of the season in the last week of October. This is
particularly true as a result of the likely impact on natural gas supplies of
the NOx trading cap that went into effect in the Northeast beginning on May
1st . Over the
course of the summer, this cap is likely to significantly increase use of
natural gas in the generation sector -- and therefore to further reduce the
amounts of natural gas available to inject into storage. Under the
new cap, utilities in the Northeast will be required to reduce power plant
emissions of NOx by approximately 1/3rd during the period between May 1st and
September 30th compared to emissions during the same 5-month period last
year. (NOx is a precursor of urban smog, which is believed to cause asthma
and other serious health problems.) In order to
comply with the cap, as the summer progresses, many coal-burning utilities in
New York, along the Mid-Atlantic seaboard and in Pennsylvania and Virginia
are likely to find it necessary to ratchet back significantly on their use of
coal compared to last summer and to substitute instead what last year would
have been out-of-merit order dispatch of gas-fired generating units.
(Gas-fired units emit far lower amounts of NOx than units that burn coal or
oil and therefore consume a far smaller number of credits for each megawatt
hour of electricity produced.) Depending in
part upon the severity of summer temperatures and the availability factor for
nuclear units in the region, this could result in a major increase in the use
of natural gas compared to last year. These increases are not yet fully
reflected in most forecasts of power-industry consumption of natural gas
during June, July, August and September of this year. This
potential increase in natural gas consumption as a fuel to generate
electricity in turn could make it even more difficult to match last year’s
puny injection levels and create significant further upward pressure on the
price for natural gas beginning as early as this coming June or July. Potential
National Crisis Looming Even if the
industry still were able to match last year’s anemic injection levels,
however, repeating last year’s injections again this year still would leave
the total amount of natural gas in storage as of late October at no more than
2,321 BCf (i.e., storage as of May 2nd of 821 BCf + an injection of 1,500 BCf
= total late October storage of 2,321 BCf). This is more
than 1.0 TCf below our estimate (discussed in detail below) of the minimum
end-of-Refill Season storage level required to protect public safety this
coming winter. This is
an alarming deficit, which should give rise to grave concern on the part of
the industry and policy-makers at the federal and state level. Neither the
LDC’s (who take their responsibility to protect public safety very seriously)
nor state regulators nor state governors can – or will -- allow end of Refill
Season storage to remain at such precariously low levels. Many state
regulators and power companies do not yet appear to fully appreciate the
gravity of the crisis the current storage deficit is likely to create over
the next several months. As the
Refill Season progresses, however, we believe it will become increasingly
apparent that absent steep further increases in the price for natural gas to
free-up much larger supplies of natural gas for injection into storage this
Spring and early Summer (when the largest injections into storage typically
occur) the amount of natural gas injected into storage during the Refill
Season is likely to fall far short of the minimum levels required to protect
public safety, in both the U.S. and Canada. Indeed,
given the short time remaining between now and the end of the Refill Season
in mid to late October, even with aggressive actions to replenish storage,
the combined storage deficit in the U.S. and Canada as of the end of the
Refill Season still is likely to be in the range of at least 500 – 750 BCf. This is a
deficit of staggering proportions that raises public safety issues of great
national urgency in both the U.S. and Canada. As the
severity of the crisis we face becomes more apparent, LDC’s and their
suppliers on both sides of the U.S./Canadian border are likely to come under
the increasing pressure to enter the spot market in order to buy up larger
and larger supplies of natural gas for injection into storage in an
increasingly constrained market. The specific
timing of when the next run-up in natural gas prices will occur will depend
on how quickly the LDC’s and their suppliers begin to enter the spot market
aggressively to step up purchases of natural gas. Many LDC’s
have not yet begun their refill purchases, at least at a significant enough
level to materially impact the market. This is because to accelerate the
timing of their purchases many LDC’s must obtain approval from their state
regulatory commissions to implement revised storage refill plans. Many LDC’s
already are seeking these approvals, but final orders have often not yet been
issued, delaying the start date for refill injections. Ironically,
however, the longer it takes before the LDC’s begin taking aggressive action
to refill storage, the more intense the upward pressure is likely to be on
price of natural gas once such purchases begin, since the less time will
remain to overcome a deficit that already is at record levels. Once these
purchases begin to accelerate, upward pressure on the spot market price for
natural gas is inevitable. By the end
of the summer, we expect natural gas prices to return to the $ 8.00 –
10.00/MMBTU range experienced this past winter – an unprecedented level for
summer months. By the fall, prices well above $ 10.00/MMBTU may be
inevitable. As the severity of the storage deficit becomes increasingly
apparent, the potential for even higher prices cannot be ruled out. Further, as
the run-up in natural gas prices begins to occur, it could have an even more
severe impact on power prices, especially as we enter into the heart of the
summer in mid-July and early August, when demand for electricity typically is
at its peak. During the
peak weeks of the summer, if natural gas prices are in the $ 8.00 –
10.00/MMBTU range (as we believe is likely to occur), the impact on the spot
market price of electricity could be dramatic in any region of the country in
which gas-fired capacity is the marginal source of supply (i.e., at this
juncture, most of the U.S.). Further,
even with natural gas prices at these levels, we are likely to head into the
winter heating season with amounts of natural gas in underground storage at
precariously low levels – i.e., certainly well below last year’s 3,172 BCf,
and quite possibly below the 2,549 BCf peak-to-trough withdrawal that
occurred during this past winter’s (milder than normal) withdrawal season. Thus, unless
temperatures next winter prove to be extraordinarily mild (which, as
discussed below, is relatively unlikely), the price spikes next winter could
make the run-ups that occurred this past February look tame. As 2003
progresses, we believe that the impact of tighter natural gas supplies on
both the natural gas and power markets is likely to become the dominant issue
facing the energy industry – and, to a significant degree, the economy as a
whole. The long
term impact on the E&P and power industries may well depend to no small
degree upon whether the energy industry is able to explain more convincingly
than in the past why these price increases are occurring, what price levels
are reasonable to expect longer term and what steps, if any, can be
responsibly taken to minimize further price increases, to the extent it is
realistic to limit the extent of further price run-ups, both for electricity
and for natural gas. Lessons
Learned from This Past Winter The national
media focused considerable attention this past winter on the record prices
for natural gas reached during the second half of the winter. This focus
on “sticker shock” is hardly surprising – and not inappropriate. For the
second time in the past three winters, natural gas prices rose to levels far
higher than most analysts predicted before the winter heating season began. In late
February and early March, spot market prices in the day ahead market at Henry
Hub reached an all-time high – with intra-day prices on the Intercontinental
Energy Exchange reportedly peaking at levels above $ 27.00/MMBTU on February
25th, and closing the day at $ 18.85 (the highest close ever). The delivered
price at City-gate locations in Chicago, New York, Boston and other major
delivery points in the eastern U.S. frequently traded well above $
20.00/MMBTU on a number of separate occasions in February and early March,
and in some instances at some locations traded well above $ 30.00/MMBTU. Further, the
near-month contract on the New York Mercantile Exchange (NYMEX) briefly shot
above $ 11.00/MMBTU (another all-time high) and for several weeks traded in
the $ 8.00 – 9.00/MMBTU range. But for a
much earlier-than normal arrival of Spring-like conditions in much of the
U.S. at the end of the second week of March that persisted for most of the
remainder of the month, prices might have risen to even higher levels later
in March, since continued cold weather could have driven storage in the East
Consuming Region and the Producing Region to near zero levels. Record
Decline in Storage These
soaring prices, however – as painful as they may have been to end use
customers – at best are only half of the story. Instead, at
least as significant is the astonishing decline that occurred in the amount
of natural gas in underground storage over the winter months and what it
indicates about the magnitude of the structural deficit that exists in the
U.S. market. From peak to
trough, the total withdrawal from storage during this year’s withdrawal
season was a remarkable 2,549 BCf (i.e., specifically, from 3,172 BCf as of
the week ended 10/24/02 to 623 BCf as 4/11/03). This is by
far (i.e., specifically, by 250 BCf) the largest withdrawal ever recorded
since EIA began tracking withdrawals in the early 1970’s (i.e., a period of
almost 30 years): All-Time
Record Withdrawal From Storage
*If
climatologically normal weather between November 1st and March 31st The amount
of natural gas in underground storage deteriorated at a particularly rapid
rate during the first 10 weeks of 2003 – with a net decline in storage of
1,695 BCf during the period between January 3rd and March 14th. This 10-week
withdrawal was almost as large as the withdrawals that typically during the
course of an entire winter heating season. This past winter, however, 1,695
was withdrawn in a period of just 70 days (i.e., less than ½ of the winter
heating season). This is a sure sign that the supply/demand balance was badly
out of whack (since temperatures in the aggregate during this 10-week period
were close to historical norms). Magnitude
of ‘02/’03 Withdrawals Not Attributable to Unusual Weather Many
analysts have attributed the huge withdrawals that occurred this past winter
to colder than normal weather. Any notion
that this past winter was colder than historical norms, however, is plainly
false -- as can be readily confirmed from publicly available data. (See, in
particular, the data on Heating Degree Days available on the web site for the
National Weather Service’s Climate Prediction Center, which can be found at
www.cpc.ncep.noaa.gov.) This past
winter, unlike a number of winters in the late 1990’s, there were several
very cold weeks, especially in the northeast. Further, most of these weeks
occurred relatively late in the winter heating season (i.e., specifically, in
January and February). As a result, the end-of-season cold spell tends to
stand out in many recaps of last winter’s events. It is important
to keep in mind however, that while certain weeks this past January and
February were particularly cold, January and February typically are the
coldest months of the year. As compared to historical norms, measured in
terms of gas-weighted Heating Degree Days ((HDD’s), even the coldest week
this past winter (i.e., the week ending January 24th), was only 23 HDD’s (or
a little over 10%) above climatologically normal weather for the week (i.e.,
specifically, 244 gas-weighted HDD’s vs. a norm for the same week of 221
HDD’s). While this
severe cold undoubtedly added to gas consumption during the week ending
January 24th (and therefore to the told withdrawal from storage during that
week), even in the most extreme week of the winter the increase in consumption
attributable to the weather in all likelihood was less than 30 BCf. Further,
while there were several bitter cold weeks in January and February of this
year, there also were a number of reasonably mild weeks even in January and
February which partially counter-balanced the effect of the
colder-than-normal weeks. During the
remainder of the winter heating season, temperatures on average were
reasonably mild. For a
stretch of nearly five weeks, for example, from December 10th through January
10th, temperatures in much of the country were unseasonably warm (i.e., more
like early to mid November than late December or early January, which in some
recent years have been the coldest part of the winter). During this period,
the total number of gas-weighted HDD’s fell 166 HDD’s below the historical
norm for these same weeks – exceeding by more than 30 HDD’s the total number
of excess HDD’s for the 5 weeks this winter that most exceeded historical
norms. This streak
of milder-than-normal weather immediately before the coldest weather hit in
mid-January significantly reduced natural gas consumption for several weeks
and allowed the amount of natural gas in storage to regain gain ground
relative to the 5-year average in December and early January despite the
overall undersupply condition in the market. If this warm
spell had not occurred, storage in the East Consuming Region and the
Producing Region might have come perilously close to being drawn down to zero
before the end of the winter heating season and problems in maintain
pressures in the pipeline system could have become widespread and severe. Beginning
around March 14th, the weather again turned suddenly Spring-like over much of
the country (i.e., more like late-April or early-May) and remained that way,
with only brief interludes of colder weather, for most of the remainder of
the month. For the
winter heating season as a whole, the data couldn’t be clearer: as measured
in terms of gas-weighted Heating Degree Days (the most objective measure
available), the weather was 3% milder than historical norms. Only two months
(i.e., November and February) were colder than historical norms. Even in
those months the exceedances were surprisingly small: ‘02/’03
Winter Heating Season vs. Historical Norm
Further,
while temperatures for the winter season as a whole were colder than
historical norms in some regions (including, in particular, New York, the
Mid-Atlantic Region and New England, where much of the national media live),
temperatures in the Midwest were milder than historical norms. This is
important, since the Midwest has a large population and very cold winters,
with the highest penetration rate for natural gas heating of any region in
the country. As a result,
it accounts for more than 40% of heating-related load in winter months. The milder
than normal temperatures in the Midwest more than offset the impact of
colder-than-normal temperatures in the east, where the Atlantic Ocean tends
to moderate temperatures and the penetration rate for natural gas heating is
significantly lower. Unmistakable
Evidence of Large Structural Deficit Quite
clearly, therefore, the huge withdrawals from storage that occurred this past
winter can not be explained based upon colder-than-normal weather. To the
contrary, total demand for natural gas would have been significantly larger
if temperatures had more closely approximated historical norms. If weather-induced
consumption is not the explanation, however, the conclusion becomes
inescapable: the huge withdrawals from storage this past winter could only
have occurred as a result of newly available supplies of natural gas falling
massively short of weather-normalized demand. We estimate
that, during the period from November 1st through March 31st, total
withdrawals from storage were approximately 843 BCf greater than should have
been expected after fully normalizing for weather: Excess
Withdrawals Not Related to Weather
This should
be seen as an alarming figure – raises issues of urgent national concern. It reflects
a huge shortfall in supply -- far larger than the largest supply deficit that
has occurred in any previous winter in the U.S. By way of
comparison, it is greater than the total shortfall in supply that occurred in
all of the year 2000 (i.e., a “current account” deficit of 805 BCf). The shortfall
in supply that occurred in 2000 was sufficient to cause natural gas prices to
quadruple in the last 8 months of that year. It also was a major
precipitating cause of the meltdown in California – which resulted in $ 14
billion in unanticipated power supply costs in California alone, forced the
largest utility in the state to file for bankruptcy and nearly bankrupted the
entire state. It hardly
should be surprising, therefore, that as a direct result of an even larger
“current account” deficit this past winter, natural gas prices again set an
all-time record. Further,
this supply deficit did not emerge suddenly in early November. Instead, as
has been discussed in earlier articles, it has been building for more than a
year, as reflected in a steady decline in the amount of natural gas in
underground storage that has been occurring since early February of 2002. Even before
the winter heating season began, storage already had fallen by more than 500
BCf relative to the 5-year average:
Once this
winter heating season began, storage then dropped like a rock – both in
absolute terms and relative to the 5-year average:
In total,
during the 15-month period between February 1, 2002 and March 31, 2003,
supplies of natural gas delivered to the U.S. market have fallen a whopping
1.25 TCf below actual consumption during this period. The U.S. has
never previously experienced a mismatch between supply and demand of this
magnitude, persisting for such a sustained period. As noted
earlier, the amount of natural gas in underground storage now stands at 545
BCf below the 5-year average – with little or no prospect for restoring
storage to more normal levels any time this year. The exposure
of the U.S. market to a further severe run-up in natural gas prices,
therefore, is clearly far greater today than it was at the end of April last
year -- when the amount of natural gas in storage was more than twice current
levels (i.e., as of May 2nd, 1,645 BCf, 824 BCf above the 5-year average). Agenda
for Secretary Abrams and Other Policy-Makers Given these
circumstances, at least three issues need to be addressed urgently at the
national level: 1. Given the
experience this past winter, what level of storage is needed to protect
public safety and protect against the possibility of extreme price run-ups
this coming winter? Given the
urgency of the issues at stake, we urge the Secretary of Energy to
immediately convene a senior level task force or blue ribbon panel to
comprehensively address all three issues on an urgent, priority basis. We also urge
the major Local Distribution Companies, in concert with the National
Association of Regulatory Commissioners (NARUC) to meet on an emergency basis
to develop comprehensive plans for addressing these issues. In the hopes
of stimulating further discussion, the remainder of this article will present
some initial thoughts regarding the first and second issue. A subsequent
article will address potential solutions, both short and longer-term. Establishing
a New Storage Target As with any
planning decision, there is no, single objective “right” answer to the
question of “how much end-of-Refill Season storage is enough?” During the
last half of the 1990’s, the general belief within the industry was that
end-of-Refill Season storage would be adequate if the total amount in storage
was in the range of 2,800 – 3,200 BCf. This amount,
in turn, consisted of two components:
Based upon
the experience this past winter, however, it should be obvious that the
question of “how much storage is adequate” needs to be entirely rethought. Further,
this reexamination needs to occur immediately. Only 24 to
25 weeks remain in the Refill Season. Further, the largest injections occur
near the beginning of the season (i.e., between late April and the end of
June). After then,
the injection rate tends to taper off fairly rapidly – first due to peak
summer demand for electricity and then due to the early stages of the heating
season. While injections still occur in late September and early October,
they typically are very small. (The last 4 injections last year, for example,
averaged only 40 BCf per week.) The time
remaining to refill storage in anticipation of the next withdrawal season,
therefore, is dwindling far more rapidly than many observers realize. With
each passing week, it becomes increasingly difficult – potentially to the
point of becoming physically impossible – to compensate for significant
deficits in prior weeks. Size of
the Potential Withdrawal As in prior
years, the first step in the process of establishing a reasonable
end-of-season target is to estimate the likely maximum size of the withdrawal
for the next winter. During the
second half of the 1990’s, the total withdrawal from underground storage
during the ‘95/’96 winter heating season provided a fairly good proxy for the
likely maximum withdrawal in future years. This is
because the winter of ‘95/’96 was the coldest winter in many years, with a
total withdrawal of 2,300 BCf (i.e., 250 BCf less than the total withdrawal
this past winter). While the
winter of ‘95/’96 didn’t set an all-time record for the highest number of
Heating Degree Days (HDD’s), it came close. Further,
during 1995-1999 timeframe, total demand for natural gas varied little from
year to year. Total supplies also were nearly the same every year. Given this
stable pattern, it was perfectly reasonable to assume that the maximum
withdrawal in any winter heating season was not likely to be materially
larger than the withdrawal that occurred during the ‘95/’96 season (i.e., the
coldest year of the decade). The
experience this past winter, however, clearly blows the ‘95/’96 standard out
of the water (even though some analysts still appear to be assuming that
there is no need to adjust this year’s refill target to reflect this past
winter’s experience). For openers,
as noted earlier, the actual withdrawal during the last withdrawal season,
peak to trough, was 2,549 BCf -- i.e., 250 BCf greater than the previous
record withdrawal of 2,300 BCf. Even the
most superficial analysis, therefore, suggests that the end-of-season target
of 2,800 – 3,200 BCf (including a working reserve) should be increased by at
least this amount, to a minimum of 3,050 BCf to 3,350 BCf – i.e., 2,550 BCf
actual peak-to-trough withdrawal + 500 – 800 BCf working reserve = minimum
acceptable reserve of 3,050 – 3,350 BCf. Further,
even this target almost certainly is too conservative. Storage last
fall started at almost precisely the mid-point of the range just suggested
(i.e., specifically, 3,172 BCf as of the week ended October 24, 2002). Nonetheless,
even though winter temperatures this past winter were slightly milder than
historical norms, prices spiked to all-time record levels before the end of
February. In addition, serious operating problems were experienced in much of
the eastern U.S. in late February and the first two weeks of March. These
problems in all likelihood would have become significantly worse if the
weather during the second half of March had not suddenly turned unusually
mild and remained that way across most of the U.S throughout the remainder of
March. At a bare
minimum, therefore, prudence strongly suggests that, going into the current
Refill Season, the end-of-Refill Season target ought to be set at the upper
end of the range suggested above (i.e., 3,350 BCf). Anything less would leave
the U.S. market vulnerable to price spikes and/or operating difficulties at
least as severe as those experienced this past winter even if temperatures
this coming winter were identical to last winter (i.e., milder than the
historical norm). Even this
adjustment, however, understates significantly the size of the withdrawal
that could occur next winter – and therefore the appropriate end-of-season
target for this year’s Refill Season. In
particular, in estimating the size of the potential withdrawal this coming
winter (i.e., the first step in the process, before adding a working
reserve), a prudent planner undoubtedly would want to take into account at
least three other factors: 1. Likely
increase in consumption if weather matched historical norms. As noted earlier,
despite the widespread believe to the contrary, temperatures this past
winter, as measured in terms of gas-weighted Heating Degree Days, in fact
were milder than historical norms. Further,
this deviation from historical norms was not simply a matter of normal
fluctuations from historical norms (although normal variations could easily
have produced variations of the magnitude that occurred). Instead, at
least a portion of the variance that occurred this past winter is directly
attributable to the El Nino-like conditions that existed in the Pacific from
the Spring of last year through at least the end of January. These
conditions did not prove to be nearly as powerful as the National Weather
Service predicted throughout much of the winter. See, for example, the
Weather Service’s 90-day outlook issued January 9, 2003, which predicted much
warmer than normal winter temperatures, particularly in the Midwest and the
Northeast, for most of January, February and March of this year. (Even though
the Weather Service’s January 9th forecast proved to be far off the mark, it
had a significant impact in limiting increases in the price of natural gas,
both in the day ahead spot market and in the futures market, in January and
early February, setting the stage for particularly steep increases later in
February.) While the
Weather Service’s forecast of reasonably strong El Nino affects this past
winter proved to be dead wrong, there were mild El Nino-like conditions
earlier in the winter (i.e., particularly in November, December and early
January). These conditions moderated temperatures during the first half of
the winter, but would not be expected to reoccur in a more normal year. The El
Nino-like conditions that existed in the Pacific this past winter, however, have
now largely dissipated; unlike conditions a year ago, surface water
temperatures in the Pacific conditions are now back within normal ranges, and
most forecasters are not currently predicting El Nino conditions for next
winter. Thus, while
it is certainly possible that temperatures next winter will be as mild as
this past winter, at this point in the year, in establishing storage targets
for this coming winter, there is no defensible basis for assuming that
milder-than-normal conditions are likely to reoccur this coming winter. Instead, at
a bare minimum, in assessing the potential size of the withdrawal from
storage next winter, any prudent planner would undoubtedly adjust the size of
any projected withdrawal to take into account what the magnitude of the
withdrawal would have been last winter if temperatures had matched historical
norms. Even this
minimal adjustment, however, increases the size of the potential withdrawal
next winter by at least 200 - 225 BCf, from 2,549 BCf to 2,750 – 2,800 BCf. The effect
of this adjustment is to increase the minimum storage target from the 3,050 –
3, 350 BCf range suggested previously to 3,250 – 3,575 BCf (i.e., a potential
withdrawal of 2,750 – 2,800 BCf + a working reserve of 500 – 800 BCf = a
minimum target of 3,250 – 3,575 BCf). This in turn
immediately creates a problem. As discussed previously, given the price
spikes and operating difficulties experienced this past winter, the
appropriate target probably should be set at or near the upper end of this
range (i.e., 3,575 BCf). The maximum current storage capacity in the U.S.,
however, currently is only 3,450 BCf (i.e., 125 BCf below the target range). Just to
prepare for the possibility of a statistically normal winter, therefore,
would require end-of-Refill Season storage in excess of current total U.S.
storage capacity. 2. Allowance
to take into account potential for colder-than-normal weather. Even this
adjusted target, however, does not make any allowance for the potential that
next winter could prove to be colder than normal – even though statistically
there is a 50/50 probability that temperatures this coming winter will be
colder than historical norms. As with any
planning decision, there is no clear objective standard as to how cold a
winter a prudent planner ought to assume (i.e., 1 year in 5, 1 year in 10
etc.). The issue, however, obviously needs to be taken very seriously; the
safety of the public depends upon LDC’s and their suppliers injecting
sufficient natural gas into storage during the Refill Season to ensure that,
no matter how cold the weather might be this coming winter, adequate natural
gas will remain in storage near the end of the season to meet whatever
heating demand may still arise if a string of colder-than-normal days should
occur in the second half of March or April. At a
minimum, therefore, presumably the amount of natural gas in storage at the
end of the current Refill Season should be sufficient to meet the withdrawals
that would be likely to occur if the weather this coming winter were to be an
exact repeat of the last colder-than-normal winter – i.e., in this instance,
the ‘00/’01 winter heating season (just three years ago). If
temperatures this past winter, however, had been identical to temperatures
three winters ago, when the number of gas-weighted Heating Degree Days
between November 1st and March 31st was 426 gas-weighted HDD’s higher than
this year (i.e., 4,156 HDD’s in ‘00/’01 vs.3,730 HDD’s in ‘02/’03), the total
withdrawal this past winter in all likelihood would have been at least 500 --
550 BCf higher than the 2,550 BCf peak-to-trough withdrawal that actually
occurred this past winter. This in turn would have resulted in a total
withdrawal of approximately 3,050 BCf. Adding a 500
– 800 BCf working reserve to this total would require a total amount of
natural gas in storage as of the end of the Refill Season of 3,550 BCf to
3,850 BCf – i.e., 100 – 400 BCf greater than total current storage capacity
in the U.S. 3.
Adjustments for expected increases in demand and/or reductions in supply. Finally,
even this estimate of the potential withdrawal for next winter does not yet
taken into account the impact of known or expected increases in demand or
decreases in supply. At this
juncture, a number of factors already can be identified that are likely to
cause the supply/demand balance to deteriorate compared to last winter. These
include:
These factors could be partially offset by a modest increase in
imports of Liquefied Natural Gas (“LNG”) and by the potential that there will
be greater opportunities for fuel switching next winter than there were
during the past winter heating season. On a net,
all-in basis, however, we expect the overall supply/demand balance this
coming winter to deteriorate by at least another 1.5– 2.0 BCf/day compared to
last winter. This in turn could increase the size of the withdrawal over the
‘03/’04 winter heating season by another 225 -- 300 BCf compared to last
year. |
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Do you agree or disagree with this article? If you disagree, send in a rebuttal piece.
Readers Comments
|
Date |
Comment |
|
Anne
Keller |
Mr.
Weismann's analysis seems to assume that the LDC's have the ability to create
more gas to put into storage and/or that gas producers can produce large
amounts of additional gas if the price goes high enough. The recent press
release from the U.S. Minerals Management Service points out that gas
production in the most prolific region of the country, the Gulf of Mexico, is
continuing to fall in spite of high prices and very active drilling in the deepwater
portion of the region as well as in new deep wells in shallow zones.
Basically, you can't store what isn't there no matter what the price is. When
prices rise to levels never before seen later this year (assuming industrial
users don't shut down completely) and the finger-pointing begins, hopefully
some of the fingers will be pointing toward the credit rating agencies. The
ongoing credit crisis has brought the energy industry to its knees. Companies
that would ordinarily have been busy drilling for more gas have been paying
down their debt to satisfy their banks and investors. Their balance sheets
are much healthier now, but the loss of 3-6 months of drilling activity is
going to have a big impact on gas supply this summer and winter. Many long time industry
participants have been warning anyone who will listen ever since the previous
supply crunch in 2000-2001 that gas supplies were under pressure and that
prices were going to rise if investors refused to fund expansion, but we were
ignored when prices "returned to normal" in 2002. At this point, about all
we can do is cross our fingers and hope for cooler weather this August! Anne B. Keller Jacobs
Consultancy, Inc. Houston Texas |
|
Bruce Oliver |
Thank you, Mr. Weissman, for this well developed presentation on
a most important set of issues. A few of us within the industry have been
trying to draw attention to these concerns for over the last several years
with only limited success. I hope this article is widely distributed and
carefully read. The only
point that I think might deserve greater emphasis in Mr. Weissman's article
is that the problems he cites are occurring within the context of at best a
weak U.S. economy. If the economy is to recover and support increased levels
of growth, energy demand (and particularly demand for natural gas) must also
grow. However, as Mr. Weissman clearly demonstrates, meeting even the demands
of a weak economy is highly problematic. Thus, a key point that must be
conveyed to legislators is that there can be NO sustained economic growth
over the next several years without significant growth in natural gas supply
and long-term policies that support increased reliance on fuels other than
natural gas to meet growth in electricity demand. Furthermore, without significant
increases in natural gas supply, any resurgence of the economy will be
quickly constrained by increases in natural gas and electricity prices. Bruce R.
Oliver, Revilo Hill Associates, Inc., Fairfax Station, VA |
|
Timothy
Welty |
Thank
you, Mr. Weissman, for such an informative, albeit lengthy, presentation. To me, one of the big
roots of these problems is that long-term energy supply planning for the
overall common benefit of the U. S. population and the short-sighted capital
gain of investors and banks are not just out of sync, but fighting each
other. Gas turbine generating stations for peak demand may solve the
short-term problem of readily available peak generating capacity, but at what
cost? Natural gas prices are obviously not as low as when someone came up
with the idea to build more gas-fired plants in part because they were
relatively quick to construct, relatively easy to start up and stop, and
relatively clean-burning. Who would have thought ahead that the supply of gas
simply wouldn't keep up with the increased demand of these gas-fired units?
Who would have thought ahead that eventually John Q. Public would start
taking it in the pocketbook as a result? While most people I know keep their
wintertime thermostat between 65F and 70F, the supply that is there is still
being gobbled up by gas-fired units. I agree with Mr. Oliver and Ms. Keller.
We need long-term energy policies that incorporate the use of multiple energy
sources, admittedly each with their advantages (such as nuclear's base load
capability, amongst other things) but in competition. We must also take a
hard look at the banking and investment industries in terms of how their
decisions are made regarding profit-taking and risk-sharing. Nothing but the
dollar bill drives their decisions, but the search for, development of, and
efficient use of the world's energy supply affects ALL of us. Finally, is it
entirely reasonable to believe that the natural gas industry really wants to
build its supply too much, given the supply-price relationship? What are the
numbers that everyone can compromise at to suit the majority involved? Tim Welty, Cedar Rapids,
Iowa |
|
James Carson |
Just to add a footnote to an already lengthy article, I have
noticed this spring that the price per mmBtu of natural gas versus heating
oil has behaved strangely. Normally, heating oil is priced at a hefty premium
to natural gas, generally 50% greater on Btu content. However, the current
price per mmBtu is actually 15% LESS for heating oil than for natural gas and
that relationship holds for the entire summer on the NYMEX. My
interpretation of this is that the market is sending a powerful signal to
market participants: substitute heating (or fuel) oil wherever possible. James Carson
jbcarson@risquant.com |
|
Chuck
Leuw |
I think
one comment needs to be made, and that refers to the statement "...
there does not yet appear to be any clear recognition of how steep a price
increase is likely to be necessary in order to free-up the additional
supplies of natural gas needed to rebuild storage..." Sometimes
regardless of price, in the short-term, supply will not be available. You may
get a shift, or as happened in 1977, a prioritisation. In the medium term, if
the problem of supply continues, you should see further adjustment of the
energy supply mix away from domestic gas, and/or towards more imported LNG,
Arctic gas, and possibly coal seam methane from Alberta (which has ultimate
potential of 3000 tcf). Environmental issues should preclude a medium or
long-term shift to LFO. From a public policy
view, I would be highly surprised if legislators could sustain the outcry of
long-term very high gas prices and supply shortages. In the end, unless gas
can be seen to be less volatle in price and supply as it has been, and which
may continue, the fuel mix to the power market may need to change, the
investment in gas-fired generation tol be used at the margin, serving as very
cheap capacity for a hybrid of alternative energy supplies having less
constancy and reliability of supply, such as wind power. Chuck Leuw
chuck@aceonline.com.au |
|
Michael Jones |
It appears to me that Andrew in his statement "... there
does not yet appear to be any clear recognition of how steep a price increase
is likely to be necessary in order to free-up the additional supplies of
natural gas needed to rebuild storage..." was trying to politely refer
to the politically sensitive issue of demand destruction. By increasing the
price of a commodity, consumption by price sensitive consumers will reduce,
thereby freeing up supply to go into storage. Essentially, if prices go high
enough, a significant portion of the industrial usage (the most price
sensitive class) will be driven out of the market (and potentially out of
business). This happens to be the ugly side of how a market economy
functions. |
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