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Without Shut-ins, Analysts See Fall Price Plunge

Although early autumn gas futures prices are still above $7, quite a few analysts are saying they could drop as much as $3, maybe more, before the injection season ends. Energy and Environmental Analysis Inc. (EEA), predicted last week that Henry Hub prices could hit $4/MMBtu or even lower as many storage fields approach their maximum capacity.

Even with some hurricane related production shut-ins this year, several other consultants said there is still a strong possibility that gas storage will fill up early, backing up supply on the pipeline grid and forcing prices much lower so that natural gas can compete more favorably with coal for a larger piece of the power generation market.

"Barring significant hurricane activity in the Gulf of Mexico, it is unlikely that 2006 natural gas prices will average last year's levels," Arlington, VA-based EEA said in its Monthly Gas Update. EEA expects Henry Hub spot prices to average near $6.30/MMBtu this year, almost $2.50 less than prices in 2005 ($8.80/MMBtu). June through October prices are projected to average less than $5.50/MMBtu. "Absent a major hurricane, some producers may even curtail production in September and October if no storage space is available and prices are down near $3.00/MMBtu," EEA said.

However, the near-month futures contract still stubbornly sat in the $6.20s on Friday. Henry Hub cash slipped to about $6.15 in the daily market. October futures were still above $7.

Based on EEA's prediction, and the forecasts of Ron Denhardt of Strategic Energy and Economic Research, consultant Stephen Smith and analyst John Gerdes of SunTrust Robinson Humphrey/The Gerdes Group, the gas market will face sharp declines in the near term.

There is more uncertainty, however, about what prices will do once the injection season is over, with most analysts still considering the possibility of a significant price rebound given normal winter weather. Raymond James & Associates, the perennial market bulls, predict a "big surprise" next winter when there is a "resurgence" in industrial demand and a price return to 6:1 parity with oil.

The forward futures curve still indicates that the "gas equation will reset in November, with next winter's gas model reverting back to a more normalized winter ending storage level of 1.3 Tcf," said J. Marshall Adkins and Darren Horowitz of Raymond James.

"From a demand perspective, the gas market should look significantly better this winter," they said in a report to clients last week. "The lost demand from last year appears to have already returned to the market. Over the past four weeks, the year-over-year weather adjusted, supply/demand equation is 1.5 Bcf/d tighter than last year. If this trend holds up, this winter should see weather-adjusted demand up by about 5.5 Bcf/d over last winter. In an attempt to err on the side of conservatism, we are only modeling a 4.5 Bcf/d improvement in nonweather related winter over winter gas demand."

Over the last several weeks, storage data, including last week's report of a 79 Bcf injection for the week ending June 16, have indicated that the market has "tightened" some, possibly due to stronger industrial demand as Raymond James suggest. Some deny that's the cause. But the real problem is that the market hasn't tightened enough to prevent an early storage fill, said Ron Denhardt.

Denhardt said some experts are speculating that storage injections might be sharply lower in the last half of the injection season, preventing an early season storage fill. The question is where would all that excess gas go if not into storage. It would have to hit the market, driving prices much lower, he said.

And according to Denhardt, even if storage injections continue at a somewhat subdued pace, gas storage still would end October at 3,600 Bcf unless there is lost production because of hurricanes. He said only hotter than normal weather (5% warmer than normal) and about 150 Bcf of production shut-ins could reduce working gas injections enough to put season ending storage at 3,400 Bcf.

Last year's hurricanes took about 300 Bcf off the market during the injection season and Hurricane Ivan in 2004 took about 100 Bcf off the market, said Denhardt. Before those years, however, the average annual shut-ins due to hurricane damage was negligible, he said. Should we expect this year to be like last year, the year before or the annual average before that? he asked. Absent 150 Bcf of shut ins this year and a hot summer "gas must compete with coal at $5.00/MMBtu or less," he said.

The "bull case" requires "substantial recovery" in year-over-year industrial gas demand," but analyst John Gerdes said he doesn't see enough evidence that recovery is occurring. "Continued flat year-over-year industrial gas demand poses a far greater threat to the bull case for natural gas than the recent strength in gas-fired power, as the magnitude of lower industrial demand (2.1 Bcf/d) last year is materially greater than the projected growth in gas-fired power demand (0.7 Bcf/d) this year," he said.

Gas storage injections year-to-date "do not reconcile with a noticeable, sustained year-over-year increase in industrial gas demand," said Gerdes. "Moreover, given the surge in gas-fired power output last summer, unless natural gas prices decline to $4-$4.50/MMBtu and allow gas-fired generation to compete with coal-fired power on the basis of relative fuel costs, the upside to our year-over-year projection for growth in gas-fired generation is limited."

If industrial gas demand does not recover from last year's losses, "then either storage is likely to exceed even our elevated projection or the line pressure of the U.S. pipeline/gathering infrastructure is likely to increase and act as pseudo storage," said Gerdes. "More probably, a combination of these two phenomena would occur. Moreover, elevated line pressure would also act as a governor on U.S. gas production."

Under any of Gerdes' assumptions, 500-plus Bcf of excess gas supply could remain entering the heating-season, with 200-300-plus Bcf related to storage and 200-300-plus Bcf of pseudo storage related to line pack. "Needless to say, none of these scenarios are positive for natural gas prices or E&P [exploration and production] company operating performance. Our energy investment outlook remains negative."

Consultant Stephen Smith said his base case estimate is for Nov. 3 gas storage to reach 3,552 Bcf. "Most estimates of storage capacity fall in the range of 3,400-3,700 Bcf -- our base case projection falls just about in the middle of this range," he said.

Smith said if hurricanes reduce supply by 200 Bcf then the "possibility of a storage crunch would be greatly reduced. If however, there are no new shut-ins impacting fall supply, then we cannot currently exclude the possibility of a capacity crunch in the fall. Under this scenario, storage growth would have been managed downward by the market via voluntary producer shut-ins driven by lower gas prices."

EEA also projects that working gas levels in storage will end the injection season at a record high of more than 3,600 Bcf. But domestic gas production also seems to be in the gas market bears' favor, the consulting firm said. EEA believes that gas production is on the rise again and will grow to nearly 52 Bcf/d by the end of the year in large part because of production increases in Central and East Texas.

Another bearish contributor in the second half of the year will be rising liquefied natural gas (LNG) imports, according to EEA. LNG is expected to average near 2 Bcf/d for the remainder of the year, which is much higher than in the first half of the year when European imports were relatively high because of warm weather.

And lastly, summer gas demand from gas-fired power generation is expected to be lower than last summer, which was 18% warmer than normal. Gas demand from generators is expected to average about 18.1 Bcf/d from June through September, which is about 1 Bcf/d less than during the same period in 2005, according to EEA.

However, the downward turn in the market should be short-lived, according to EEA. "The overall natural gas supply-demand balance remains tight," the firm said. "Given normal weather, natural gas prices should rise appreciably above 2006 levels. We expect 2007 Henry Hub prices to average approximately $7.65/MMBtu." The key reasons for this are a return to more normal storage levels of 1.25 Tcf in April and 3.35 Tcf next November, continuing growth in gas-fired power usage (0.9 Bcf/d more than in 2006), and only a modest increase in domestic gas production and LNG imports (500 MMcf/d more LNG than in 2006 and 1.6 Bcf/d more production)."

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