Spot natural gas prices have been trading at a significant discount to futures prices on the New York Mercantile Exchange (Nymex), signaling the likelihood of more near-term futures weakness and possible additional gas production curtailments by producers, several energy analysts said last week.

The Energy Information Administration reported a 62 Bcf injection for the week ending Oct. 6, which put working gas levels at 3,389 Bcf, easily surpassing the weekly storage report record of 3,327 Bcf recorded for the week ended Nov. 5, 2004. The EIA’s weekly storage report records go back to December of 1993. Delving deeper into EIA’s monthly storage report records, current stocks are just shy of the 3,467 Bcf in storage at the end of October 1990 and the all-time record posted at the end of November 1990 of 3,472 Bcf.

In its October 2006 Short-Term Energy Outlook, the EIA predicted that end-of-October levels would reach 3,538 Bcf. EIA said in a recent report that the noncoincident peak working gas capacity in the U.S. is about 3,593 Bcf.

With so much gas in storage this winter, Bill O’Grady, vice president of AG Edwards in St. Louis, said mild weather could set the stage for further price declines. “It all ties to weather, and if the weather turns out mild for the winter, then we are just at the early stages of a market downtrend.” O’Grady pointed out that the January and February contracts had just recently fallen below $8, and those contracts will fall close to current spot prices in the $5 range if weather conditions don’t improve for the bulls. “In fact prices could fall even further, for at present there is some demand for storage, but that will dissipate after the end of October.

“The risk you take is that the long-term forecasts turn out to be wrong, and that would not be the first time,” he said. “Using climatological data to predict the future is tough. You are dealing with a mathematically chaotic environment.”

In the near-term, O’Grady said cash prices in the $5.400 range should prevent the November contract from falling below $5 as the October contract did. (The October contract expired at $4.201.) However, Henry Hub cash dropped nearly 50 cents on Thursday to average $5.16.

“November could trade below the cash, but probably would not stay there very long. If the cash market deteriorated further, then November would follow,” O’Grady said. As volatile as the November contract has been, dropping over 10.5% in just Wednesday’s and Thursday’s trading sessions, “the greatest downside potential is in the deferred contracts.”

Houston-based analyst John Gerdes of SunTrust Robinson Humphrey/the Gerdes Group told clients in a note last week that the “unusually high level of gas in storage, and consequently, diminished physical storage capacity, should have meaningfully lowered October gas storage demand. Thus, the significant variance in the cash and near-month futures prices is probably signaling the likelihood of a significant ($1/MMBtu) decline in the November Nymex contract price during October.”

A $1/MMBtu decline in the November Nymex gas contract, and the realization of historically high gas in storage by early November, is likely to weigh on the December and ’07 Nymex futures contracts, said Gerdes. The November contract posted two consecutive 30-plus-cent losses on Wednesday and Thursday last week and showed continuing weakness on Friday. “Consequently, we remain cautious as to natural gas-weighted [exploration and production] E&P names near-term as a continuance of weak gas prices appears necessary to correct the oversupply imbalance that developed in late ’05.”

One indicator of increasing storage constraints, said Gerdes, would be increasing differentials between regional gas producing hubs (such Colorado Interstate Gas) and South Louisiana’s Henry Hub, the physical settlement location for Nymex futures contracts.

Prior to the latest storage report from EIA, Denver-based consulting firm Bentek Energy reported that five U.S. storage facilities already were at or above 100% full and nine other facilities were at 95-99% of capacity. “As anticipated in our reports over the past three weeks, a number of facilities are testing and exceeding their reported maximum inventory levels,” Bentek said.

As of Oct. 6, working gas in storage was an astounding 410 Bcf higher than the same time last year and 358 Bcf above the five-year average of 3,031 Bcf.

“If gas storage was already reaching capacity, gas transporters/marketers would be compelled to ratchet down their demand for gas in concert with the lack of storage demand for gas,” Gerdes noted. “Lower gas demand due to gas storage limitations in turn would lower gas prices. Lower gas prices would be especially evident in the regional producing regions given their more limited access to the market. Conversely, Henry Hub, given its position as the settlement location for Nymex gas contracts and its multitude of access routes to consuming markets should experience relatively less price erosion.”

Energy analyst Stephen Smith of Stephen Smith Energy Associates said the week ending Oct. 20 is projected to have 22 heating day degrees (HDD), or 34% more (colder) than normal. “This colder weather, plus known and probable production shut-ins, should combine to yield a projected early November storage peak which is closer to 3,500 Bcf than our previous estimate of 3,600 Bcf. But even at this lower level, the projected surplus remains formidable.”

Chesapeake Energy Corp. announced a partial production shut-in in September, and Questar’s E&P subsidiary followed with a shut-in announcement earlier this month (see NGI, Oct. 9). The total gross production shut in by the two companies could total up to 220 MMcf/d.

“We expect to see other producers follow suit in the coming weeks, and we expect to see more operational flow orders related to high line-pack and regional storage capacity issues (which are likely to reduce production as well),” said Smith.

The gas price differentials between Henry Hub and the other primary regional gas producing hubs remain within a “normal” range, which Gerdes said suggests “the regional hubs have yet to experience an acute decrease in gas demand brought on by a lack of storage capacity.” In fact, he said, regional gas price differentials relative to Henry Hub recently have narrowed, with the overall decline in gas prices.

Even as storage approaches 3,600 Bcf, likely supply-side adjustments still support stronger gas prices in 2007, Gerdes wrote. In the third quarter, against the backdrop of generally weak gas prices, liquefied natural gas (LNG) imports fell below 1 Bcf/d, well below his expectation of 2+ Bcf/d in imports. In the next six months, given current weak gas prices and intense competition for LNG supplies from Europe during the winter, Gerdes said LNG imports are likely to average only 1 Bcf/d before increasing to 2+ Bcf/d later in 2007.

Because of the less bullish signal sent by 2007 Nymex gas futures, Gerdes lowered his U.S. 2007 gas rig count prediction to 1,475 from 1,540 rigs. The lower rig count reduced his U.S. gas supply by 0.4 Bcf/d.

“Given that U.S. gas producers in aggregate are free-cash-flow neutral at about $7.50/MMBtu, a gas price expectation modestly above that level would seem to reconcile with a modest increase in drilling activity as E&P companies generally budget to spend within cash generation,” Gerdes wrote. “The ’06 U.S. gas rig count should average about 1,370 rigs.”

Gerdes also lowered projected growth of Canadian gas well completions by 2.5% this year and by 5% in 2007, which lowers a forecast on gas exports to the United States by 0.4 Bcf/d. However, a “modestly” higher $7.75/MMBtu gas price next year “is expected to halt further recovery in the industrial gas demand lost in 2005 and provide the gas supply necessary to satisfy 2007-2008 winter spacing heating demand (3,200-3,250 Bcf), while permitting modest (fuel switching) growth in gas-fired power generation.”

Gerdes’ forecast for 2007 oil ($62/bbl) and gas ($7.75/MMBtu) “should result in the unwinding of the fuel switching evidenced this year that favored burning natural gas over residual fuel oil. Consequently, we expect fuel switching to residual oil to reduce the growth in gas-fired power generation by about 0.7 Bcf/d next year. A $62/Bbl Nymex oil price equates to about a $7.00/MMBtu Nymex gas price assuming 1% residual fuel oil trades at its historical discount of roughly 70% of Nymex oil.”

Assuming a West Texas Intermediate oil price of $55-70/bbl and using weather service projections through Oct. 20, Smith’s price outlook through Nov. 3 estimates an Oct. 20 gas-to-resid spread in the range of minus $1/MMBtu to minus $1.50/MMBtu. A resid price of $6/MMBtu for late October would “imply a November Henry Hub bidweek price of $4.50-5.00/MMBtu,” up by 25 cents from Smith’s forecast earlier this month.

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