Gas price volatility has declined and forward spreads have contracted. With plenty of shale gas around, “who needs gas storage capacity?” is a question on the lips of some. But with the heart of winter fast approaching, attitudes could change, a storage developer told NGI.
“It’s an environment [for gas storage] that’s not unlike what I remember it being in the immediate post-Enron period or death of the merchant energy players back in the early 2000s,” Peregrine Midstream Partners CEO John Hopper told NGI. Back then, the former chief of Falcon Gas Storage said he would hear, “‘You don’t need storage; there’s no value to it.’
“And we’re hearing some of the same stuff now. We’ve seen this movie before, and it will change. I can’t tell you exactly when.”
Seasonal price variations and the arbitrage opportunity they offer have narrowed indeed. Over the last four years, the spread between the price for delivery in February and delivery in November has narrowed from about 65 cents/MMBtu in October 2010 trading to about 24 cents/MMBtu in October 2013, the U.S. Energy Information Administration (EIA) said in a recent note. EIA attributed the decline in seasonality of prices to a few factors.
Increased gas production, particularly in consuming regions in the Northeast (from the Marcellus Shale) has made for a lighter call on gas storage, EIA said. Net storage withdrawals decreased last winter compared to the winter of 2010-2011 in spite of higher levels of consumption and lower net imports of gas.
As gas replaces coal as a power plant fuel, it has reduced gas demand seasonality in the power sector. When gas markets tighten and coal becomes more attractive, demand from gas-fueled plants slackens and that gas is released to the market, EIA said. Further, gas use during non-winter months for things such as power generation has increased relative to the November-February period, EIA said.
“There’s just not enough price differentiation between the peak and the off-peak,” Hopper said. “The perception is we’ve got plenty of gas out there and that’s not an issue. It’s more than a perception. It’s a reality to a point. I’d certainly like to see what kind of price response we’d see if we really got a cold, sustained winter. That would be interesting to see if during the winter peak, if it’s really cold, whether gas supply can respond to that. I just don’t think we know that yet. Maybe we’ll find out this winter.”
Hopper said he’s heard the theory expressed by some that producers will move their rigs back to the Haynesville Shale and start producing more dry gas as soon as prices improve.
“I just fundamentally disagree with that. Producers, they’re not going to do that because prices all of a sudden go from $3.50 to $5.50 unless they see that the whole back end of the curve has that kind of response going out five or 10 years,” he said. “There is a number at which they would do that, but only if that gives them a better return on invested capital than drilling for oil and wet gas.”
Even if gas went to $5.00-5.50 and stayed there, if oil is at $100 rigs will stay put in the wet plays, Hopper said. “I don’t think producers are necessarily going to move a bunch of rigs out of the Permian or out of the Eagle Ford to run up to the Haynesville and poke a bunch of holes in the ground. I just don’t see that. There won’t be this real-time supply response to that demand.”
And more demand for gas is coming, not just from power generators but from the petrochemical sector and for exports of liquefied natural gas (LNG). Some are going to be surprised, Hopper said. “…I think what will surprise people is a lot of that demand is going to come on within a fairly tight time frame, from 2015 to 2017, and it’s all going to kind of hit at the same time. I think people are going to be surprised at the impact that that will have on pricing.”
Prices could get up to the high $5s or even $6 area, he said. “On a sustained basis I can’t promise that that would happen, but I certainly can see it happening.”
Petrochemical sector demand will be mostly baseload, but LNG exports could be lumpier due to seasonality and where cargoes are destined, Hopper said.
“Gas-fired generation, of course, there’s a seasonal and intraday demand component to it. So if we’re consuming more to work off the baseload and then we have a peak, that’s a good thing for storage, seasonal peak and intraday obviously,” he said. “I think those [demand factors] all fit together to create a positive scenario for storage longer term, and I think particularly gas-fired generation, just because of the dispatch profile.”
Peregrine currently has only one storage facility, Ryckman Creek in Uinta County, WY, near the Opal Hub. A portion of the facility was destroyed by an explosion and fire last April. It has been providing limited service since. Subsidiary Ryckman Creek Resources LLC is rebuilding, and the facility’s nitrogen rejection unit rebuild is expected to be completed during the third quarter of next year. “Our plan is to have that up and running next fall, which will be a good thing, obviously,” Hopper said. Peregrine is not working on any other storage projects. “It’s pretty quiet in the gas storage development space these days.”
Hopper said the average contract tenor for Ryckman is more than seven years, but storage operators are feeling downward pressure on terms.
“…[I]n today’s market it just kind of depends upon who the contracting party is. If it’s a marketer who’s still in that business, it’s going to be one to three years. If it’s a utility, it could be five or more, five to 10. If it’s a producer, it could be all over the place if it’s strategic to them. One of our customers is a producer in the Rockies where our storage is strategic to them. They signed a longer-term contract. So it really just kind of depends. Certainly, they’re not willing to pay today the rates that they were willing to pay two years ago, three years ago.”
© 2022 Natural Gas Intelligence. All rights reserved.
ISSN © 1532-1231 | ISSN © 2577-9877 | ISSN © 1532-1266 |