With gas prices plummeting over the last two weeks and storage space severely limited, it may not be long before producers start curtailing production. Analysts at Raymond James & Associates said last week if recent higher-than-average storage injections continue, “then U.S. producers would need to shut in about 10% of their production to rebalance the system over the next two months.”

The 108 Bcf storage injection for the week ending Sept. 8 implied that the U.S. gas supply/demand balance suddenly changed this month “from nearly 2 Bcf/d tighter than last year to 3.5 Bcf/d looser than last year,” said J. Marshall Adkins of Raymond James. “Frankly the abrupt magnitude of this apparent shift in U.S. gas supply/demand has left us scratching our heads wondering how could U.S. gas supply/demand possibly change that quickly.”

Adkins said the first thing that came to mind was the Energy Information Administration made a mistake or received faulty gas storage data from operators. “The most obvious answer is that it is a bad number that will likely be revised over the coming weeks.” However, the EIA reported no revisions last week and put out another larger-than-expected storage number, a 93 Bcf injection for the week ending Sept. 15.

Assuming these numbers are correct, several factors might explain them, Adkins said, including the Labor Day holiday Sept. 4, during which many industrial consumers shut down and reduce demand, and the extremely mild weather. “The only real logical explanation that we came up with is the fact that the price spreads between the near-month natural gas [futures] prices and the winter-month natural gas prices were at all-time record highs,” he added. “In fact, the steep contango has created an extraordinary incentive to put gas in storage today and sell at a price nearly double today’s in just three months. In other words, the current gas storage price arbitrage opportunity is unprecedented.”

On Sept. 1, the difference (spread) between January 2007 and October 2006 futures was $4.685, an enormous difference given historical spreads of about 50-70 cents. Over the last few weeks, the spread has fallen steadily and by last Thursday it was $3.10, still a very large difference driven in part by limited storage capacity and expectations of strong winter gas demand.

Working gas levels in storage already are near the 3.2 Tcf mark with about seven weeks left in the traditional storage injection season. On Sept. 15, there was 3,177 Bcf of working gas in storage, 12.5% more than the five-year average and 12.6% more than at the same time last year.

Working gas levels in the West are already only 17 Bcf less than their highest level in the 12-year history of EIA weekly storage data (427 Bcf compared to the 444 Bcf record on Nov. 11, 2005). Total working gas levels are only 150 Bcf less than the peak level in the weekly storage history of 3,327 Bcf set on Nov. 5, 2004 and are 295 Bcf less than the all-time peak working gas level of 3,472 Bcf set at the end of November 1990.

EIA said in a report last week that its best estimate of total working gas capacity in the United States is 3,593 Bcf, which means working gas levels on Sept. 15 were about 88% of total capacity (see related story).

“…[I]t now appears that we will test the limits of U.S. gas storage capacity over the next eight weeks,” said Adkins. “Given that we have limited storage capacity, the gas market is facing what most analysts call ‘gas on gas’ competition. This is the phenomenon where limited gas storage capacity forces producers to shut in production.”

The Federal Energy Regulatory Commission predicted such an outcome in May because the warm winter and demand destruction due to high prices left so much gas in storage entering the injection season. “As we go through the summer, we will fill storage. [There] will come a point where you can’t put anymore in,” said Steve Harvey of FERC’s Office of Enforcement. “That may well create a summer condition where if there isn’t any place to put extra gas…you actually have to start shutting it in.”

The conditions that led to the recent price drop took a while to develop, but the first two mild weeks in September and the continuing weakness of the hurricane season seemed to be the “straw that broke the camel’s back,” said consultant Stephen Smith of Stephen Smith Energy Associates. He noted that the mild weather has started to reverse the trend that had taken place late in the summer when record heat took about 500 Bcf out of the gas storage surplus.

“In the current weakening gas environment, North American gas producers are understandably focused on what sets the gas price floor,” Smith noted in his Monthly Energy Outlook. “From a short-term perspective there are only two remedies: North American producers can elect not to produce when gas prices become unacceptable and LNG cargoes can be redirected to global markets with higher prices. With spot Henry Hub at $5 and below, and some negative basis differentials exceeding $2, some North American producers would now be selling at losses based on replacement cost…”

Smith predicted that the U.S. rig count will begin to show declines. Over the last seven weeks, the Canadian rig count has averaged about 11% lower than last year, he noted. “This drilling slippage will become more pronounced in the next few months and the U.S. year-over-year gas rig ratio will begin to show declines as well.”

There already may be some evidence of production shut-ins beginning in the Rockies, according to Raymond James. “We are already seeing price induced curtailments in certain parts of the Rockies (Wyoming) where gas prices have become extremely volatile, bouncing around daily between $2 and mid $4 per Mcf as all storage capacity has become full in that particular region,” said Adkins. “Some believe that this implies that spot gas would need to fall to cash costs in other areas before operators would begin to shut in. The reality is that many begin shutting in before reaching cash costs, recognizing that they could likely sell that gas three months from now at much higher prices.”

Despite the collapse of gas prices on Kern River Gas Transmission to $1.73 on Sept. 15, Williams and EnCana, two of the Rocky Mountain region’s largest gas producers, told NGI that production curtailments still are not in their plans. “When you look at the pricing environment today, I think most people would say that it’s really just a short-term phenomenon,” said Williams spokesman Kelly Swan. “In terms of our [capital expenditures, they] have not changed. We have employed what we feel are some attractive hedges and at this point more than half of our production is hedged for 2006. Williams’ growth strategy is to rapidly develop our reserves in the Rockies.”

EnCana’s Alan Boras said the company has hedged about 97% of its production (3.6 Bcf/d in the second quarter) at $7.29 for the last half of 2006. He said all of EnCana’s Rockies production is protected by basis hedges at minus 65 cents compared to Kern River basis on Sept. 15 of minus-$3.25. “We’ve got a comprehensive risk management and hedging program in place to manage low prices,” he said. Boras also said EnCana has not altered its drilling plans. “We’re drilling in the neighborhood of 4,000-5,000 new wells this year. We drilled about 4,800 last year. We haven’t set a budget for next year, but over the long term we see natural gas as being an attractive investment.” He said EnCana also believes the current drop in prices will be temporary.

Smith, however, isn’t so sure. With working gas levels possibly rising to near 3.6 Tcf by November, Smith believes producers may be facing an extended period of lower prices. There probably won’t be a widespread storage capacity shortage but there certainly could some regional problems with storage availability, he said. Smith cut his fourth quarter Henry Hub gas price forecast to $5.90/MMBtu from $7.50 and said prices next year are now likely to average about $6.65.

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