Editorial Comment

	Vol. 227 No. 8
PERRY A. FISCHER, EDITOR

US gas prices: Bulls, bears and bankers. Occasionally, I run across something so good that I feel compelled to share it with you. Such is the case this month. I stumbled across it on the Web while looking for data on future prices for this month’s issue. What follows was written by Harry Chernoff.

Let’s start with the bears’ punch line: As of mid-June, gas in storage is roughly 450 Bcf (or 22%) above the year-ago level and roughly 650 Bcf (or 35%) above the five-year average. Without a major hurricane, gas prices will decline significantly in coming months and regional discounts will widen, especially in the Rocky Mountains.

The bulls’ case. First, at $70/bbl, crude is trading at more than 10:1 versus the gas price. The long-run average is closer to 6:1. More importantly, natural gas at $6.50/MMBtu (Henry Hub) is trading about 10% below 3%-sulfur residual fuel on a Btu basis. This is unusual since residual fuel typically sets the floor price for gas. Fuel switching should add a couple of Bcfd to load.

Second, with basis discounts already exceeding $1/MMBtu in the Rockies and parts of the Mid-Continent, and approaching $1.50/MMBtu for late summer futures in several major producing regions, price-sensitive industrial load unrelated to fuel switching will return, adding another couple of Bcfd to load. Liquids stripping in the NGL industry will absorb another couple of Bcfd versus long-run averages at current and future relative oil/gas prices.

Third, as summer heat kicks in and peaking plants crank up for the ever larger housing stock, utilities will turn to gas in larger quantities. Additionally, the low price of gas will encourage utilities to use more gas and less coal to conserve below-average coal inventories. The combined effect of fuel switching, industrial load pick-up, NGL liquids stripping and summer peaking demand will absorb at least 5 Bcfd more than average through the summer, allowing storage to trend toward normal levels by the end of injection season, even without a hurricane.

Fourth, the futures markets are saying that gas this winter (and at least the next three winters) will be closer to $10/MMBtu. That means the futures markets do not believe we will enter winter with enough storage surplus to keep prices depressed.

Fifth, the gas strip is set by winter prices, which are set by heating loads, which are set in the residential sector. The US is rapidly increasing its gas-heated housing stock, making five-year average storage levels unrepresentative of the levels required to meet winter heating loads. The storage surplus is nowhere near as large, relative to normal winter loads, as it appears. The excess storage today is a byproduct of last winter’s unseasonably warm weather. Don’t count on it happening again.

Sixth, North American gas producers have dramatically increased exploration and production spending in the past few years, with little or no net impact on production. Even a slight pull-back in capital expenditures, without any production shut-ins, will put the already severe depletion curves back into play. Any surplus will disappear in short-order.

Finally, Hurricanes Katrina and Rita combined to shut-in almost 800 Bcf offshore and probably another 100 Bcf onshore and are continuing to shut-in more than 1 Bcfd, nearly a year later. Hurricane Ivan shut-in hundreds of Bcf the year before. The hurricane season currently forecast, even if only at the smaller Ivan level, is more than enough to eliminate the current storage surplus.

The bottom line for bulls: gas prices are near a bottom relative to competing fuels, loads are going to pick-up from multiple industrial and power generation uses at current prices, and the storage surplus – which isn’t as big as it appears assuming only average weather – is going to be largely absorbed by the end of injection season without any further price declines. Even a moderately active hurricane season will send spot prices back into double-digits.

The bears’ case. First, total switchable load (industrial and power generation) is no more than about 2 – 3 Bcfd, and most of the load that can switch, has switched, because gas has been priced below residual fuel oil for months now. Similarly, NGL liquids stripping, which can vary by several Bcfd depending on relative prices, should already be near a maximum for the same pricing reasons. While these two factors could, at most, account for 20 – 30 Bcf per week of gas diverted from storage, the pricing relationships have been in place long enough that very little price-sensitive switching or stripping is left.

Second, price-sensitive industrial load that hasn’t switched to gas isn’t coming back until prices are much lower, stay that way for an extended period of time, and occur in an otherwise favorable long-term business environment. Industrial loads are not ramped up or down weekly or monthly as if linearly tied to gas prices. It will take a great deal of time and business confidence to restore the multiple Bcfd of industrial load lost to last year’s high prices. Meanwhile, demand destruction from Katrina doesn’t reappear simply because gas is “only” $6/MMBtu. It’s gone. Production of gas-intensive commodities, like ammonia, has permanently moved to locations like the Middle East and the Caribbean to take advantage of much lower feedstock costs (e.g., $2/MMBtu).

Third, coal inventories at power plants were low in the winter because of rail problems, which have mostly been resolved, and coal inventories are now acceptable. Nuclear and hydro are operating at higher capacity factors than last year, and electricity generation is down versus last year. There is some deterioration in the average heat rates of gas plants, but it’s worth no more than 1 – 2 Bcfd. If there is prolonged heat through early-September, the incremental gas absorption for power generation and air conditioning would be around 100 Bcf. This is only 20% of the current surplus. The next meaningful increment of gas demand is substitution for coal. For this to happen, gas has to be closer to $4/MMBtu, not $6/MMBtu.

Fourth, the futures markets are not going to sustain a $3 – $4 winter premium to spot if the current injection and storage patterns hold much longer. From the perspective of the hedge funds, the futures markets are in extreme contango (near months priced much lower than far months), which costs the funds substantial amounts of money each month as they roll their positions over. From the perspective of the producers, the incentive to sell the strip forward, or at least hedge the winter months at a $3 – 4 premium, is going to become irresistible as operational flow orders loom. Storage was 2.5 Tcf as of mid-June. In the past eight years, the earliest date that storage approached 2.5 Tcf was the third week of July in 2002, which was also the last time that gas was below $3, and the last time that the oil/gas price ratio hit 10:1.

If current storage trends continue, operational flow orders from the pipelines will force production shut-ins. Without shut-ins or hurricanes, average summer injections would take storage to the traditional maximum fill of about 3.3 Tcf by the end of August. This would leave no place to put September and October injections – typically totaling almost 600 Bcf.

Fifth, winter prices may spike in February or March if it’s cold, but this has little meaning over the next few months if storage hits 3.3 Tcf in by early September. Moreover, the combination of a hot summer and a cold winter only represents about 450 – 500 Bcf more than average loads. Normally, this would be an enormous increment and raise important questions about storage adequacy and winter deliverability, but this year it’s no more than the year-over-year storage surplus.

Sixth, the big increase in expenditures in the past few years has at least temporarily reversed the production decline. Production in 2006 is up versus 2005. It’s not much in the context of the other supply/ demand imbalances, but it’s adding to the storage and pricing pressure.

Finally, a hurricane having an impact between that of Ivan and Katrina would definitely absorb the storage surplus for at least a short period of time. However, Katrina and Rita combined to eliminate close to 900 Bcf (offshore and onshore) and 10 months later we’re 500 Bcf above average. Mild weather since the hurricanes cannot explain more than about 1/3 of that swing. Price-sensitive demand destruction and literal demand destruction were, and are, the larger reasons for the surplus.

The bottom line for bears: without production shut-ins, gas prices will drop toward $5 at the Henry Hub and $4 or lower in regions with the biggest supply/ demand imbalances, notably the Rockies. Major price-sensitive demand from utilities firing coal won’t kick-in until that point. The idea that oil-to-gas fuel switching, industrial load, NGL liquids stripping, and utility peaking load at $6/MMBtu can reliably absorb 5 Bcf/d above current levels is wishful thinking.

The bankers’ case. The bankers are aware of the tug-of-war between the bulls and bears over all of the above factors. The bankers are also aware of the producers’ budgeted 2006 oil and gas price decks (about $56/bbl and $7/MMBtu) and the levels at which spending would be significantly cut back (about $42/bbl and $5/MMBtu), assuming the lower prices were in place for at least three to six months.¹ 

The bankers are also aware that statistically (based on crude and products prices, gas storage levels, and seasonal factors) spot gas prices actually should be closer to the double-digit futures prices for the winter months than the current $6 – 7 level. These statistical inferences aren’t reliable in the current situation, however. Storage levels are far outside the historical range used to establish the pricing relationships, and short-term gas demand is demonstrably less price-elastic than the models assume. 

These factors wreak havoc with models that require continuous substitutability between residual oil and gas; a relationship that has obviously broken down in the face of the current storage surplus and oil/gas price relationship. In other words, it’s more prudent to believe the physical surplus than the regression models for now.

According to a survey of 41 bankers, the forecast mean gas price for the second through fourth quarters of 2006 is $6.66/MMBtu. For 2007, the figure is $6.32. For 2008 and later years, it’s below $6/MMBtu. The sensitivity case downside values are $5.37, $4.84, and mid $4s for those same periods, respectively.²

The bankers’ price forecasts do not take aim at the bull-bear argument between $6 summer gas and $10 winter gas. They take aim at the argument between $6 gas and $70 oil. The same banker survey puts the crude oil forecast at roughly $48 (WTI) for the second through fourth quarters of 2006, $44 for 2007, and $40 or below thereafter. The downside mean values are roughly 20% lower.

With the important caveat that the market views of bankers and oil and gas producers reflect very different risk-reward dynamics, the implication of the bankers’ forecasts versus current strip prices is greater price risk in the crude strip than the gas strip. This has significant implications for the bull-bear gas argument. If relative oil prices slip like the bankers’ forecast, then the case for gas-for-oil substitution and NGL liquids stripping becomes weaker and natural gas inventories expand.

Additionally, the bankers’ oil price deck versus current world prices is consistent with either or both 1) a US and probably worldwide macroeconomic slowdown and reduction in demand or, at least, demand growth, and 2) a large increase in oil supply arising from the large recent increase in E&P capital expenditures. Through some combination of a shift in the demand curve downward or a shift in the supply curve upward, the equilibrium price for oil would decline. 

With respect to gas (though not oil), the long-term validity of these relatively conservative forecasts is subject to dispute for one gigantic reason – the unstoppable acceleration of North American depletion rates over time.

For the short-term, however, the bankers’ view of the world challenges one, and possibly both of the major price-related demand underpinnings from the bulls’ case: 1) increasing gas-for-oil substitution at the industrial level, NGL liquids stripping, gas-for-oil and, ultimately, gas-for-coal at the utility level, and 2) absolute price-sensitive load increases at the industrial level. To support gas prices at current levels this summer without large production shut-ins, the position of the bankers can be summed up in one word: hurricanes. 

This article was taken from the website www.energypulse.net.

LITERATURE CITED

¹ Lehman Brothers, Oil Services & Drilling Original E&P Spending Survey, June 21, 2006.

² Tristone Capital’s Energy Lender Price Survey, Oil and Gas Investor, p. 11, June, 2006.