The key claim made at that time was that unless the weather got very cold, very fast and stayed that way for a considerable part of the heating season, natural gas prices were likely to drop 20-30% relative to oil prices in short order. At the time, oil was in the mid to upper $50/bbl. range and gas was in the $11-12/mmBtu range. Cold weather did arrive in early December but then left as fast as it came. The brief price spike to $15/mmBtu on that cold snap is long past. Now that it appears that natural gas inventories are adequate for the heating season, the unusual price signals from the natural gas markets have disappeared and prices have dropped as predicted.

The return of the natural gas markets to more normal pricing can be seen in multiple dimensions. First, on a Btu-equivalent basis crude oil (in barrels) should be about six times the price of natural gas (in million Btu). In late November, at the time of the original article, the ratio was about 5:1 (e.g., $58 oil to $11.50 gas). In December, as gas spiked to $15/mmBtu, the ratio dropped as low as 4:1. The ratio now is roughly 6.7:1 (e.g., $64 oil to $9.50 gas). Natural gas is thus about 25% less expensive relative to oil than in late November. In terms of key refined products that compete with gas, especially #2 heating oil and #6 residual oil, natural gas is now in the traditional relative price range.

Second, the unusually wide spread between March NYMEX gas and April NYMEX gas, which had reached $3/mmBtu or more in mid December, is now around 30 cents/mmBtu. This decline indicates that the very large premium placed on an end-of-season storage shortfall has all but evaporated.

Third, the regional basis adjustments have moved towards normal levels. New York trades at about a $1/mmBtu premium to Henry Hub rather than the discount of six weeks ago. Chicago trades about even with Henry Hub. Basis discounts for major Western points have contracted from $4-5/mmBtu to roughly the $1.50 range.

In short, the drivers of natural gas pricing have now changed from an environment based on extreme fear of storage shortfalls during the heating season and near-crisis conditions along the Gulf Coast to one predicated on typical Btu-equivalence with substitutable refined products and the return of more normal basis discounts across the country.

Of course, cold weather, and plenty of it would change this situation. However, the weather forecasts for the remainder of the heating season don’t offer sufficient reasons to change the overall picture. The National Weather Service’s long-range forecasts continue to call for above-average temperatures in the key Midwestern markets and throughout the West and average temperatures in the East. Accu-Weather is forecasting colder than normal weather in parts of the East and Midwest during some periods of the next few months but not sustained cold over large segments of the major markets.

On the supply side, the cumulative Gulf of Mexico production shut-in due to the hurricanes is now 575 Bcf offshore and probably another 100 Bcf onshore, for a total of 675 Bcf. Daily shut-in production has declined to less than 2 Bcf. Even with the enormous amount of cumulative shut-in production since late summer, storage levels are in the normal range for this time of year. Since the weekly storage reports have generally shown lower withdrawals than the weather- and hurricane-adjusted models have predicted, the implication is that a lot of demand destruction is ongoing. There may also be some onshore production response from the large amount of drilling activity but this is not as significant as demand destruction. Since most of the literal demand destruction problems (e.g., flooded refineries) have been corrected, the balance must be price-sensitive loads. This would range from petrochemical plants throughout the country to residential users turning down their thermostats. In short, the self-adjusting price mechanism in the gas markets is working.

So where do we go from here? First, aside from the weather, since gas prices are now in the normal range relative to refined products, substitution back to gas usage is likely to increase and demand is likely to pick-up relative to recent weather-adjusted forecasts. However, gas/oil switching is not as big a market driver as it used to be so this will not determine the forward price of gas in a meaningful way.

Second, even at prices well below those only a few weeks ago, natural gas is still expensive, especially for manufacturers of such products as commodity petrochemicals and ammonia fertilizers. Many of these manufacturers have curtailed production recently in response to very high absolute and relative natural gas prices. The fact that gas and oil prices are at parity in the U.S. does not address the huge disparity between gas prices in the U.S. and gas prices in many overseas markets. Natural gas prices are below $2/mmBtu in numerous major producing areas, including Trinidad, Qatar, and Saudi Arabia. These pricing disparities will only intensify pressure on domestic manufacturers as overseas producers with large volumes of stranded gas add downstream operations. In response to this price disparity, considerable amounts of commodity chemical production capacity have left the U.S. and should continue to leave the U.S. These same pricing disparities are behind the recent large-scale investments in LNG infrastructure around the world.

Third, continued restoration of Gulf production and the continued increase in domestic production on the back of recent high levels of drilling activity should ensure adequate or more-than-adequate inventory levels heading into the summer peak electric demand season. In fact, if temperatures continue at their recent above-average levels, gas inventories could rise enough for the oil / gas price ratios to swing all the way to the other extreme; e.g., from 4:1 at the mid December peak to 6.7:1 now to as much as 8:1 in the spring if inventory levels appear too high at that time. This implies price risk to below $8/mmBtu at current oil prices.

There is, however, a very big and unappreciated caveat to this point. While North American drilling activity has been very high and short-term production has responded, depletion rates on existing fields are accelerating. Like the White Rabbit from Alice in Wonderland, North American drilling activity and new production has to accelerate simply to hold overall North American output constant. If gas prices were to drop to levels where the value of aggressive drilling became marginal, North American gas production would quickly decline and gas prices would again soar.

As the original version of this article noted, nothing has changed the bleak long-term outlook for North American natural gas supply against the relentless increases in demand from the residential, commercial, and electric power sectors. While double-digit gas prices will undoubtedly force significant amounts of industrial demand offshore, the other three sectors will be there to pick up the slack over time. The effect of potential increases in imported LNG several years from now is an open question.

The bottom line: Assuming no radical changes in North American and international economic growth rates or OPEC pricing and supply policies, oil prices should remain high and gas prices, now at parity with oil prices, should also remain high. Whether the oil/gas price ratio stabilizes at 6.7:1 or drifts towards 8:1 depends on the weather and the level of industrial demand over the next few months. If the weather remains warmer-than-average, gas prices will decline relative to oil, possibly another 20%. On the other hand, even an 8:1 oil/gas price ratio doesn’t offer much relief to U.S. consumers if the price of oil stabilizes above $60/bbl.

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