Relatively mild weather, weak weekend demand, declining storage space and slowly returning Gulf production pressured prices much lower on Friday with quite a few points down more than a dollar and the majority off more than 60 cents from levels on Thursday.

Prices were down more than $1.10 in Chicago to just over $11. New England and Northeast points slipped 50-75 cents and declines in the Gulf Coast Louisiana region were generally 60-75 cents compared to prices on Thursday. Larger drops were seen in the West, with Opal, SoCal Border and San Juan prices all off about a buck. Some Texas markets also dropped by more than a dollar, including Houston Ship Channel, Tennessee Zone 0 and Texas Eastern.

Western markets, however, were still down only about 30 cents on average from price levels the previous Friday (Oct. 7) and were still well above bidweek levels in contrast to Gulf Coast, Northeast and Midwest markets, which all declined sharply for the week and are in some case more than $2 below bidweek levels. Points in the Northeast area all at least $1.50 below index.

Chicago prices on Friday were about $1.45 less than where they had been a week earlier and about $1.10 less than the bidweek index. Midwest spreads to the Henry Hub also widened significantly over the course of the week, illustrating the abundance of Canadian supply at Chicago and the continuing supply problems in Louisiana.

Meanwhile, there’s a chance that price weakness could continue given the mild shoulder month weather. The six to 10-day forecast calls for above normal temperatures east of the Continental Divide and only a sliver of a chance for below normal temperatures along the California coast and northwestern Washington state. Normal weather is predicted over New England, the Florida peninsula and nearly all of the West.

The mild weather has left few options other than continued storage injection, sources said Friday. “Our storage, like everyone else’s, is getting pretty full at this point, and the weather remains mild relative to normal,” noted a Northeast utility buyer. “We haven’t been buying our day-to-day planned amount. We bought some gas out of Texas, which was much cheaper than Louisiana, and we bought some out of Canada. But we only bought about half of our planned amount. We just don’t need it right now.

“It’s warm and wet in the Northeast and as we get near the end of the injection season, there’s just no room left in storage. We are leaving a little hole in storage just for flexibility,” he said. “We’ll get to 95-97% full and leave a little space just in case we have some warm weather early in November and need some place to put the gas.

“I also get the feeling from the notices this week on Tennessee Gas that some of their shut-in supply is going to start to work again hopefully within a month. Right now, gas out of Louisiana is still scarce and much more expensive than gas out of Texas.” Tennessee said that starting Friday any shippers with facilities east of Cocodrie station and south of the Port Sulphur station in southern Louisiana could begin delivering gas to the new Discovery pipeline interconnect or to other meters that allow for gas processing and alternative transportation.

According to Golden, CO-based consulting firm Bentek Energy, about 1,725 MMcf/d is still shut in upstream of Tennessee Gas, 826 MMcf/d is shut in upstream of Southern Natural and 521 MMcf/d is still offline upstream of Transco. Sea Robin began flowing a little gas on Friday, but Mississippi Canyon, High Island and Stingray are still not receiving any production.

The Minerals Management Service (MMS) reported Friday that 5,647.25 MMcf/d of total offshore Gulf of Mexico gas production was still shut in. That was only down about 52 MMcf/d compared to shut-ins on Thursday, but it was down 794 MMcf/d from the shut-ins reported a week earlier on Friday Oct. 7.

According to MMS data, about 2,975.8 MMcf/d of production has been returned since post-Hurricane Rita shut-ins peaked on Sept. 26 at 8,623 MMcf/d. That’s an average daily increase of about 165 MMcf/d. If production continued to return at that rate, full production would be restored in only about 34 days, but most industry analysts predict some production will be down through the winter. The big question is how much.

Arlington, VA-based consulting firm Energy and Environmental Analysis Inc. (EEA) said in a presentation during the week that it expects 2.6 Bcf/d will still be shut in by the middle of December and 1 Bcf/d will still be shut in by the middle of next March. About 2 Bcf/d on average is expected to be offline during the winter. EEA forecasts that cumulative shut-ins by next March will reach 680 Bcf of gas, or 6% of total U.S. production. U.S. dry gas production isn’t expected to return to pre-hurricane season levels until next August, which by the way, is after the next hurricane season begins.

Bentek said Friday that cumulative onshore and offshore production shut-ins already totaled 304.7 Bcf (MMS has cumulative offshore shut-ins at 288.9 Bcf). Bentek said 5,572 MMcf/d of onshore and offshore Louisiana production and 330 MMcf/d of onshore and offshore Texas production was still offline on Friday. A total of 7,918 MMcf/d of Gulf gas production was scheduled to flow on Friday on the major regional pipelines compared to 13,820 MMcf/d on Aug. 26, the consulting firm said. Bentek collects its data from official pipeline company bulletin boards. The data represent gas production that was scheduled to flow on the pipeline systems.

“We’re looking at the possibility that Tennessee’s system will be short supply this winter,” the utility buyer said, “but we have some other options that we’re working on and based on those I think we’ll be fine. We expect that prices will still be enormous, but we also have seen demand drop because of that. Even residential customers aren’t turning on their furnaces as early this year. At these temperatures we anticipated the demand to be ‘X’ but it has been ‘X minus’ at the start of October because people are just holding off from turning on their heat. As far as industrial demand, I don’t have a close feel for that but I’m sure that’s been cut as well.”

Dawn prices were in the $12.60s and $12.70s Friday, which, considering the fuel and transport charges, made it a good supply alternative for Northeast buyers compared to Gulf Coast Louisiana production, which was hovering between $12.70 and $13 on most pipes. Texas gas production was quite cheap in the $10.50 to $10.70s because there’s not much demand right now in East Texas.

“There is some generation demand available because of the maintenance that’s taking place on coal and nuclear units and the mid-80s high temperatures we’re seeing, but I’ve been struggling to find a buyer,” said a Midcontinent marketer. “Without much demand out there I’ve been putting my gas in storage just like everyone else. But those maximum daily quantities for storage injections are beginning to ratchet down a little bit.

“Prices came up a little bit at the end of trading, so I guess some people found some storage space and were taking advantage of spreads, but storage is becoming harder to come by.”

Working gas levels in storage rose to 3,327 Bcf on Nov. 5 last year, the highest level in the last decade. With the 58 Bcf injection last week, working gas levels rose to 2,987 Bcf, which means there’s at least 340 Bcf of additional space left in storage that could be filled.

There are only about four more weeks left in the traditional storage injection season, but in 2001 injections continued until the end of November for a total of eight additional weeks because of warm weather and a strong economic incentive to store gas. Over the last five years an additional 185 Bcf of gas on average was added from the same week in October until net weekly withdrawals began. If a similar amount is added this year, working gas levels will enter the winter heating season at about 3,172 Bcf, or 34 Bcf above the five-year average but 155 Bcf less than last year.

EEA’s Kevin Petak, director of modeling and forecasting, said in his presentation at the EIA Winter Fuels conference during the week that the lower than expected storage refill this fall due to the hurricane-related production shut-ins should continue to provide price support this winter. He said industrial demand destruction will balance the market, but Petak is predicting Henry Hub gas prices will average $13/MMBtu for the winter with significant price volatility.

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