At what level natural gas storage inventories will be at the end of this month remains an open-ended question. It all depends on the weather. However, natural gas producers and some analysts are sanguine stocks will bounce back through the summer in time for the next withdrawal season.
Several executives at IHS CERAWeek in Houston, which ended Friday, expressed hope that a ramp-up in the onshore basins will fill storage in the coming months. But gas has to be at an attractive-enough price.
“We believe North America has the capacity to supply far more natural gas than we are doing now at a reasonable price,” said Statoil ASA’s William Maloney, who is executive vice president of development and production for North America. The biggest challenge isn’t increasing supplies but rather increasing domestic demand, he told the audience.
“Is there enough demand to lead to sustained higher prices?” he asked. “Can matching midstream and upstream capacity happen in a continuous way?”
The number of gas rigs on the ground is steadily falling, and combined with freeze-offs and shut-ins in severe winter weather, producers have pulled back in the gassy areas. Watch out, though, once spring arrives. More efficient rigs and new technology have allowed operators to finesse their drilling programs to easily churn more output.
Efficiencies already have improved Statoil’s programs in the Marcellus and Bakken shales by 25-50%, Maloney said. “We’re not going to stop improving.” Statoil recently has brought online some gas wells after taking a pause on lower prices. “The rigs are not going away,” he said. “We will continue drilling.”
ExxonMobil Corp.’s Rob Franklin, who presides over the company’s gas and power marketing arm, echoed some the comments at the conference. Gas prices spiked in January in response to winter constraints, but overall, producers had few problems. “In January we broke the record for demand five times,” he noted. “There are enough rigs…We are more than able to keep up.”
Some analysts are less sure producers will be able to respond — or be willing — to increase supplies over the rest of the year for next winter’s withdrawal season.
“The forward curve is telling [producers] not to go out and drill a gas well,” said IHS Director Bob MacKnight. He told the IHS CERAWeek crowd that gas prices would have to increase to $5.00/MMBtu “for a sustained period” before drilling activity strengthens much.
Teri Viswanath, who directs natural gas commodity strategy for BNP Paribas, told NGI she sees “very aggressive supply gains,” but “the net result is still a lingering storage deficit ahead of next winter.”
To “shore-up an acceptable inventory buffer, the industry will have to stock away a record amount of supplies over the course of the summer,” Viswanath said. “Given the decade-long expansion of the unconventional resource base, there appears to be little doubt that supply will materially contribute in bringing the market back into equilibrium.
“However the challenge this time around is that, having gotten used to low prices, consumers might be less accommodating. This means that the period of tightness might persist longer than the market anticipates.”
Severe winter weather has fundamentally altered many analysts’ market outlook, including BNP.
“In the space of just a few short months, the multi-year surplus has disappeared with the rapid system-wide destocking that has fundamentally altered our outlook on the market,” Viswanath said. “Despite the industry’s best efforts to bring additional supplies to market, we believe that it will take more than a single injection season to swing the market back into equilibrium.”
Analyst Stephen Smith, who provides weekly and monthly data on the U.S. energy markets via Stephen Smith Energy Associates, now expects a storage deficit of “roughly” 660 Bcf relative to the 2006-2010 seasonal norms, “by far the largest deficit for at least the last six years.”
In January Smith told NGI he had been running a model that indicated 1.4-1.5 Tcf for the end of heating season but at that time, he said it was beginning to look like there would be 1.2 Tcf at the end of March (see Daily GPI, Jan. 24). Most analysts now expect that storage will end at or below 1 Tcf by the start of April.
Wood Mackenzie consultants also wonder where storage levels will be by the next November, particularly in light of this winter’s extreme weather. Winter weather has helped push both Henry Hub prices and several regional points to levels not seen in years and in some cases, ever.
This winter weather has been a “1-in-14” cold, and the coldest since the winter of 2000-2001, senior analyst Amber McCullagh told NGI. Most important for the gas market, the weather has been concentrated on several exceptionally cold days. Of the 20 coldest days in the past five years, 12 have been this winter.
This winter, however, is going to impact summer prices. Wood Mackenzie is forecasting U.S. inventories to end at about 1.05 Tcf by the start of April.
Not that long ago, producers were most concerned about the impact of Gulf of Mexico hurricanes on gas storage. Today, it’s concern about winter.
“The winter weather, the freeze-offs are the new hurricane risks,” McCullagh said, with the difference being that the winter storm risks come in the midst of the peak heating season, while Gulf storms are not as critically timed. And also the onshore is now where gas supply is produced; only a small fraction today is being carrying from the offshore.
Despite the recent peak demand, there are signs that not as much gas supply is needed. Most of the increase in gas demand in the power sector this winter only has come from “really cold days,” McCullagh said. “On other days, it’s been lower than in previous years. But its not as much lower as we expected going into winter, given how high prices were.”
Wood Mackenzie is anticipating end-of-October inventories are going to be lower than in 2013. Even refilling U.S. storage to 3.65 Tcf would “support incremental storage summer demand of 2.3 Bcf,” with Henry Hub prices of about $4.25. About 2.4 Bcf/d of production growth is forecast over the course of the summer, most coming from the Northeast.
Withdrawals this year have been higher than average levels, but “historic temperature relationships with demand explain much of the variance,” McCullagh said. Withdrawals still exceed expected weather-adjusted levels by 2 Bcf/d. U.S. and Canadian production declined an average 1 Bcf/d in January and February on freeze-offs and processing plant issues. Northern, liquids-rich producing areas are are going to be more vulnerable to interruption because of cold weather.
“Gas-fired generation has been very high this winter, but these high gas loads are concentrated on the coldest days,” said McCullagh. “On normal and warmer-than-normal winter days, gas-fired generation is lower than in previous years, as higher gas prices relative to coal make more coal-fired generation economic. As we see fewer of these extremely cold days, then the supply-demand balance will begin to look loose and storage inventories will recover.”
Smith’s base case scenario, combining ongoing trend production growth and a 3% hotter-than-normal summer, suggests peak fall storage at around 3,300 Bcf, versus the 2006-2011 average peak of about 3,650 Bcf.
“A peak storage level of 3,300 Bcf might lead to some upward price pressure this fall,” Smith said. “In the wake of the 2013-2014 polar vortex winter, we suspect that some residual concerns about a polar vortex replay might make the market particularly sensitive.”
Smith’s base base pricing model projects an average 4Q2014 Henry Hub price of more than $5.00/MMBtu.
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