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Long-time and long-term bulls on natural gas (as we are) need to look carefully at storage and production levels and the prices in the futures and spot markets. These signs suggest the potential for lower prices in the very near-term.

In the weeks leading up to the first cold snap of the year (mid-November), NYMEX Henry Hub futures for December were roughly $3/mmBtu higher than spot prices ($11-12/mmBtu vs. $8-9/mmBtu). This unusually wide difference between front-month futures and spot for the principal pricing point in the United States reflected (and continues to reflect) fears of very cold weather very early in the season. As the front-month futures wind toward expiration, this price gap for the same date at the same location obviously has to narrow to near zero. As of November 23, the gap was less than fifty cents. This narrowing, however, doesn’t provide any information about the overall direction of gas prices. We believe it is more likely that gas prices will decline in the short-term, potentially by 20-30% relative to oil prices. There are several factors behind this belief.

First, until the mid-November cold snap, spot prices throughout North America were a minimum of $1-2/mmBtu below the Henry Hub price, and as much as $4-5 lower in the Rockies and points further north and west. While large discounts to spot are common in the Rockies and Western Canada (because of limited take-away and storage capacity), the existence of any discount, let alone a large discount at points like the New York Citygate or the Chicago Citygate is highly unusual. Midwestern and Northeastern discounts to Henry Hub literally mean that if transportation were costless and instantaneous it would be profitable to ship natural gas from the major load centers to Southwest Louisiana. As of this writing (November 23), well into the first cold snap of the winter, spot prices across most of North America (now notably excluding New York) are still $2/mmBtu below the Henry Hub spot price. Such a situation can only arise from some combination of packed pipelines, very full storage, and mild weather at the load centers plus supply problems in Louisiana. Reports of shut-ins due to pipeline and storage constraints in places like South Texas and Georgia (far away from the hurricane impacts) support this conclusion.

Only cold weather, and plenty of it, can change this situation. The National Weather Service’s long-range forecasts call for above-average temperatures in many of the key Midwestern markets and throughout the West and average temperatures in the East. Accu-Weather is forecasting colder than normal weather in the Eastern third of the country but warmer than normal in the Western half. By no means do these forecasts imply substantially greater than average weather loads for the country or the gas-dependent markets.

Second, even with hurricane-related shut-ins exceeding 450 Bcf from offshore Gulf of Mexico facilities and probably another 100 Bcf from onshore Gulf Coast facilities, storage levels as of mid-November are almost 3.3 Tcf. The notion that storage could be near 3.3 Tcf in mid-November despite 550 Bcf of shut-in production is mind-boggling. Since the weather during September through mid-November was fairly mild, a small amount of this unexpectedly high storage level could be attributed to reduced weather-sensitive loads. The vast majority, however, must relate either to physical limitations on loads because of hurricane damage (e.g., refineries under water) or price-sensitive demand destruction in otherwise available facilities (e.g., shut-in ammonia manufacturing). Overall, our back-of-the-envelope estimate of the weather-adjusted demand reduction since the beginning of September is in the 3-4 Bcf/d range. This is consistent with other analysts’ reports, e.g., 3.7 Bcf/d estimated by Raymond James. These weather-adjusted demand reductions are now greater than the continuing offshore shut-in production (3.2 Bcf/d as of November 23). Excluding weather impacts, as offshore production continues to come back on-line either the loads previously off due to physical limits (e.g., submerged refineries) have to come back on-line or prices have to fall to induce the price-sensitive loads to come back.

Third, natural gas prices during the winter depend enormously on the market perception of the adequacy of storage at the end of the winter. Over the period from the summer of 2000 through the summer of 2001, prices went from $4/mmBtu to $9/mmBtu in mid-winter and back down to less than $3/mmBtu. Oil prices during the same period varied by less than half this amount. During the period from the summer of 2002 through the summer of 2003, gas prices went from about $3/mmBtu to $8/mmBtu in mid-winter and back down to less than $5/mmBtu. Again, oil prices during the same period varied by less than half this amount.

In the current run-up, the same roughly 2:1 dynamic is in place. Since the summer, spot natural gas prices roughly doubled from the $6-7/mmBtu range to the peak a few weeks ago while oil prices went up a maximum of roughly 40%. Should the same pattern hold through the end of the current heating season and should oil prices remain in the mid to upper $50/bbl range, spot Henry Hub prices would drop into the $8-9 range, or about 20-30% below current levels. If oil were to retrace its rise and stabilize in the mid $40s, gas would drop to the $6-7 range. The reason for the much greater volatility in natural gas prices is well-known and will not be repeated here. The point is that unless the weather loads are substantial enough to maintain the market perception of potential end-of-season shortages, gas prices are vulnerable to a 20-30% drop even with no change in oil prices.

None of this is inconsistent with the recent comments of FERC Chairman Kelliher. Kelliher focused on the weather, the rate of production recovery in the Gulf, and conservation by individual users, industrial users, and electric generators. He also noted, correctly, that LNG would not be coming to the rescue for several years, at the earliest. The point of this article, however, is different. The point here is that there is considerable downside risk to natural gas prices right now (20-30% assuming no change in oil prices) simply due to the potentially unsustainable situation outlined above and the much greater volatility of natural gas prices. While 20-30% isn’t going to make a huge difference to residential customers, since it would still leave gas prices roughly 1/3 higher than last winter, it would make a big difference to traders in the futures, physical, and equity markets.

In the bigger picture, nothing that took place this summer in gas production and demand and nothing relating to the storage or pipeline situation changes the bleak long-term outlook for North American gas supply against the relentless increases in demand. The Energy Information Administration recently reported that the industry’s reserve additions in 2004 were 118% of consumption versus 111% in 2003 and 118% in 2002 but that additions from new fields (as opposed to field extensions and new reservoirs in old fields) were by far the smallest they’ve been for at least the past 10 years. Despite all the drilling (and rapidly rising finding costs) roughly 90% of the reserve replacement is now coming from field extensions and barely 4% from new fields. The oil ratios are similar. From a short-term economic perspective, this increased intensity of operations at existing fields is a positive factor, indicating economic efficiency. From a long-term resource perspective, however, the implications are extremely adverse. The truly new resources simply do not exist at the quantities and the costs to which the country has become accustomed. None of this should surprise most industry observers. It is simply that, weather permitting, the crisis is likely to be deferred beyond the current heating season.