Analysts with Tudor, Pickering, Holt & Co. (TPH) said the market should not get "sucked in" to the pull on storage this winter, nor the rise in natural gas prices. It's not likely to be repeated next year -- and the market still is oversupplied.
TPH's team picked an opportune time to refresh the seven-year model to 2020 for North American gas markets. Analysts throughout the energy firm over the past few weeks have put pencils to paper, motivated by investors wondering what to make of the dropping storage levels and higher gas prices. Recent cold temperatures aside, North America has plenty of supplies to replenish the market -- sooner rather than later.
"The single most important takeaway" from the research "is not to get sucked in by temperature changes in the supply balance," said analyst Brandon Blossman on Monday during a conference call. "It has been cold, and residential demand, in particular, has been up because it's been cold...But going forward, this isn't going to be repeated every winter.
"We assume a return to normal weather, a return back to a fundamentally oversupplied gas market."
That "fundamental oversupply" should be in place for three or four years, which means prices will be "hard pressed to move above $4.00/Mcf materially for a long period of time."
Analysts are more bullish on the back-end of the curve to 2020 and "very comfortable" with $4.50/Mcf on a sustained basis post 2018, when liquefied natural gas export demand and net import/exports "go in our favor..." Working through the oversupply, however, "is going to take years, not months."
Blossman, Matt Portillo and other TPH analysts have been talking with clients to compare their research with what's happening on the ground.
"The bigger picture, the longer term discussion, primarily remains around what to do with equities on a go-forward basis, how we think about volatilities, not only around differentials, but around the gas price over the next few years," said Portillo.
Once the winter weather is over, domestic gas will move into high gear and into an oversupply, with significant differentials emerging into the Northeast "as we move into the summer period and shoulder demand."
The flip side is TPH's view of high-cost gas basins, including the Pinedale Anticline, the Piceance Basin, and the Haynesville and Barnett shales.
While investors will continue to pour capital into low-cost Appalachian supplies, the gassy regions should be structurally impaired from a capital perspective over the next few years, said Portillo.
"By 2016, we do foresee the risk to gas is $2.50...to rebound the market from a supply/demand perspective." By then, the higher-cost gas basins for companies with leveraged risk, could be in peril, he noted.
Some operators, including Chesapeake Energy Corp., are raising the ante in the Haynesville by increasing the rig count (see Shale Daily,Feb. 6). The risks to adding more gas rigs in high-cost U.S. basins, such as the Haynesville, remain minimal for close to a year, because it would take at least six months for any potential gas production to connect to sales.
However, more gas rigs going up in Canada "ultimately will lead to gas-on-gas competition in 2015, 2016," in areas like Chicago, Portillo said. "This forces the AECO basis differential to look very similar to the producing regions of the Northeast for a period of time, which will ultimately affect some of the legacy producers in the basin."
Once TPH's analysts refreshed their basin economics, they found that the majority of rigs today operate in basins that generate a 10% rate of return on $3.00/Mcf gas. But there are 30-40 rigs in operation today that "need $4.00 gas to generate a return of 10%," said Portillo. Only a "handful" of big operators are able to run those lower rate rigs, he added.
U.S. gas demand to 2020 should be "modest," but there are potholes, said Blossman. From 2013 to 2020, TPH is forecasting an incremental 17 Bcf/d of gas demand, and "most important number by far in our view is the power demand growth," said Blossman.
Of the forecasted 17 Bcf/d, 6 Bcf/d would be incremental power demand. The next biggest slug would be the change in net imports/exports. Mexican exports should be north of 2 Bcf/d to fill a proposed pipeline into the central part of the country. The pushback there is that the Eagle Ford Shale in Northern Mexico, helping to provide some demand.
The "biggest wildcard" is the net import/export numbers from Canada, he said.
"That Canadian gas has to go somewhere, and the United States now makes up about 40% of the Canadian gas market...We're assuming here, as do most forecasts, that it gets backed out slowly over time to the tune of about 400-500 MMcf/d per year on a year/year basis" to 2020.
If Canadian supply doesn't decline, flattens or were to increase, "you'll have incremental supply looking for a market...at the margin in the U.S., and that means that Canadian and U.S. gas will see gas-on-gas competition, with the inevitable result of lower prices at AECO and into the Midwest, Chicago specifically."