Natural Gas – Stuck in a Range

Natural Gas – Stuck in a Range

We lowered our 2012 average natural gas price forecast to
$2.70/mmBtu, from $3.85/mmBtu. Our new forecast suggests
downside risk remains relative to the forward curve. Unseasonably
mild weather during November–January reduced
heating demand by ~450 bcf versus our forecast, creating material
downside risk in the near term owing to
ratchet-enforcement issues.* However, if current near-term
weather forecasts prove accurate, large-scale production
shut-ins should not be needed. As we look toward October,
coal-to-gas switching should meaningfully reduce the risk of
storage congestion

Natural gas will likely be range-bound between $2.50/
mmBtu and $3.00/mmBtu for much of 2012. Barring any
surprises from weather or rig efficiency, we believe it is unlikely
that gas prices will break out of a narrow channel over the
coming months. The US gas market is currently oversupplied,
which must be addressed through either lower prices and demand
stimulation or shut-in production. Our deep-dive analysis
into the power market, as well as coal and gas economics, with
Morgan Stanley’s coal and utilities equity analysts, suggests that
at prices below $3.00/mmBtu, incremental gas power demand
(coming at the expense of coal) could generate upwards of
2.0–2.5 bcf/d. After accounting for this incremental demand, we
now see end-October inventory of 4.15 tcf, which will be a record,
but not enough to trigger storage congestion issues.

We see more downside risk to natural gas prices over the
next few months versus later in the year, as we believe the
probability of a potential ratchet-enforcement issue in March is
much greater than any storage congestion issue in October.

* Ratchet enforcements occur when gas storage operators force gas owners to either cycle out
their gas or have it confiscated, thereby collapsing spot gas purchases and driving down
prices.

Whatever the outcome of weather/prices in the next few weeks,
this market is likely to start the injection season with near 2.3 tcf
of inventory, or lower, owing to constraints imposed by ratchet
enforcement. In other words, even if inventory trends are poor
through March, this should have little bearing on October
storage levels, which will also benefit from a longer period of
elevated gas-fired power demand.

Any price surge or collapse would likely be short-lived.
Prices can certainly dip below $2.50/mmBtu or rally above
$3.00/mmBtu temporarily, given bullish or bearish
weather-related demand, but we believe natural gas is unlikely
to trade outside this range on a sustained basis through October.

More specifically, if poor weather-related demand results
in ratchet enforcement in end-March or storage congestion
issues in end-October, the forced liquidation could cause a
collapse in spot prices, but we believe that this would be
short-lived. Gas prices below $2.50/mmBtu on a sustained
basis will bring on a large amount of incremental coal-to-gas
switching in both the Eastern and Western power grid (likely
more than 5 bcf/d year/year), quickly balancing a significantly
oversupplied market and eliminating the need for shut-in
economics (which we estimate occurs below $2.00/mmBtu).

To be clear, gas fundamentals are extremely weak, and
weather surprises can quickly change the outlook, but our
analysis suggests concerns are overblown about storage congestion
or a need to drive large-scale production shut-in. In our
base case, we expect end-March inventory to come in at ~2.2
tcf, with October ending at 4.15 tcf.

The latest weather forecasts show February gas-weighted
heating degree days (GWHDD) averaging 7.4% below the
30-year normal indicated by the National Oceanic and Atmospheric
Administration (NOAA), and we are assuming
March GWHDD will average 1% below NOAA 30-year normal
(colder on a relative basis to Nov-Jan weather, which averaged
15% warmer than NOAA 30-year normal). For the cooling
season, we assume 10-year normal weather.

Coal-to-gas switching economics should create a floor for
natural gas prices, based on our analysis, and this should
limit the need for shutting in production. Beyond the factors
noted above, our key conclusions include:

 Powder River Basin (PRB) coal starts to become vulnerable
below $2.50/mmBtu gas, which should put a floor
under gas. Not only will we see even greater demand for
gas from gas-fired power plants in the Mid-Atlantic and
Southeast at sub-$3.00/mmBtu prices, but as gas prices
approach $2.50/mmBtu, gas generation will also become
competitive against PRB coal-fired plants in Texas, the
Midwest, and the West. As PRB coal moves out of the
money, the incremental power demand would quickly balance
even a significantly oversupplied gas market.

 Large-scale production shut-ins should not be required
to balance the market, since cash costs for gas production
are generally below $2.00/mmBtu. Unless February and/or
March remain as unseasonably mild as November–January,
lower gas prices should be able to spur enough incremental
gas power demand to balance the market at prices above
$2.00/mmBtu.

On the other side of the range, a number of bearish risks
remain that should keep a lid on gas prices. On the upside,
we believe that gas prices above $3.00/mmBtu are unlikely to
be sustainable through at least end-October. We expect
bloated inventories together with still-expanding production to
prevent gas prices from rallying significantly beyond this level,
unless we encounter bullish weather events. Beyond the inventory
overhang, a number of additional hurdles remain,
particularly at higher gas prices.

 Weather is a wild card: Warmer-than-normal winter
weather is primarily responsible for the precarious state of
the gas market. GWHDDs were about 15% below normal in
November-January. We estimate this milder weather removed
some 450 bcf of heating demand relative to our base
case. We have assumed warmer temperatures continue
into February and March, but not at the levels experienced
from November–January. Continuation of extremely bearish
weather could have very negative implications for the
gas market, particularly over the coming months.

 Risk of ratchet enforcement: In our base case, we model
end-March inventory at ~2.2 tcf, very close to estimated
enforcement levels of 2.3 tcf. If demand is weaker than we
model (or supply is greater), it could tip the market into a
state of required liquidation and lead to a temporary collapse
in spot market prices. This dynamic could be part of the
reason the market has been pushing down spot prices.

 Rig efficiency has been improving over the past few
months. If rig efficiency improves materially from here, our
production estimates and, by extension, end-October storage
estimates, will ultimately prove too low.
 Limits on coal-to-gas switching owing to transmission
constraints, utility coal contracts, and power price hedging.
Although we have factored in these issues by using
less-than-optimal capacity factors/utilization rates for
gas-fired power plant capacities, there is always the risk that
logistical challenges limit the magnitude of coal-to-gas
switching.

 Higher gas prices could stimulate production and erode
some of the gains from power-related demand. While
the economic decision to switch from Central Appalachian
(CAPP) coal power plants to gas-fired plants is still supported
above $3.00/mmBtu, and this decision is unlikely to
be reversed on a short-term gas price recovery, a higher gas
price would not only limit further gas switching but could also
bring some lower-cost coal plants back online. At the same
time, the rig count should continue to fall in 2012 – in response
to current oversupply – and any premature price
reversal could quickly arrest the recent decline.