The U.S. natural gas market appears to be evolving beyond the regional redefinitions, as summer demand continues to provide more parity to the winter markets.
At the Energy Metro Desk's Weather & Price Tealeaves II conference held earlier this month, PointLogic Vice President Jack Weixel, who handles analysis, offered some insight into the dynamic domestic gas markets picture.
"Elevated demand patterns" during in the summer months point to a "new normal" for domestic gas consumption, Weixel said. The supple Northeast shales also are amply supplying the region during the coldest of winters, reducing volatility.
Gas supply "is a hostage no more" because of the Northeast shales, which are going to offer "escape routes" in every direction, he said. The Northeast's gas supply has been strong enough to quench demand for the entire United States, and the pipeline operators are obliging as takeaway expands.
"All in all about 30 Bcf/d of incremental capacity is going forward through the end of 2018," Weixel said.
Good news? Maybe. But unlike 2014, new capacity from the Northeast isn't 100% full, according to PointLogic data. Rockies Express Pipeline (REX) was 78% utilized in September, with 400 MMcf/d available. Tetco's Uniontown to Gas City was 69% utilized in September, with 130 MMcf/d available.
"This isn't exactly the same reaction that pipeline companies were expecting when extensions in 2014 filled up right away," he said. "The prevailing rumor is that downstream receipts on REX, east of dome 2, haven't been quite yet connected. They are waiting to fill that capacity..." Overall, about 0.5 Bcf/d in the Northeast could be on the market that's not on the market, he said. Prices could be even lower.
The "saving grace" has been the extreme, back-to-back winters, combined with robust summer demand. Peaks in demand in the last two winters was about 7.4 Bcf/d and 5.5 Bcf/d, Weixel said.
"But we still have a net outflow situation that started earlier in the year...The Northeast can certainly handle this elevated demand. Winter spreads are in fact narrowing with new routes and a longer market." There's also "no reason for demand to dip going into late shoulder season" because as exports to Mexico persist and the price "is suitable for power generators."
For example, power demand was up 4 Bcf/d this summer, with Mexico demand up 1 Bcf/d. That compares with the summer of 2014 for the same period, when total demand rose 3.3 Bcf/d.
Onshore supply actually underwhelmed demand this summer, a reversal from last year. In the summer of 2014, gas supply totaled about 3.5 Bcf/d, with 3.3 Bcf/d of dry gas production with 0.3 Bcf/d in Canadian imports. Demand last summer reached 4.3 Bcf/d, including 3.2 Bcf/d in power generation and 1.1 Bcf/d in Mexican exports.
Compare that to this summer, when the estimate was about 0.8 Bcf/d short, equating to 173 Bcf less gas available to inject into storage. PointLogic estimated there was about 5.8 Bcf/week lower injections over the 30 weeks of summer.
That could mean something to the markets this winter. For prices, it is a coin toss. November prices could dip lower if Lower 48 storage approaches its historical fill record. Or there could be "modest upward pressure" into January or February as power and Mexican export demands persist, and as initial LNG commissioning cargoes arrive.
Next summer still is looking bearish.
Lower 48 "production pains weigh on growth potential," and the "silver linings are becoming harder to find," Weixel said. The pipeline projects from the Northeast "provide a cushion for production levels but they may not fill right away." But in any event, the market still looks to exit this coming winter "on the high side of storage inventories under most scenarios, unless serious winter shows."
In plotting the last three years of U.S. onshore production, the slowdown is obvious, he noted. "We had the first slowdown coming out of 2012" followed by a "huge increase" in 2014. Between 2014 and 2015, there's now "really no place for producers to hide anymore. We don't have the big value gap that we were experiencing in peak of production last year. Everything simmered down..."
Associated gas declines aside, production momentum is waning from a variety of things -- lower spending, debt, declines in cash flow, and on and on.
"On the bright side...we are still seeing reduced drill times and service companies willing to accept less, which is helping to improve margins ever so slightly. Certainly there are a lot of uncompleted wells out there still waiting on pipeline capacity as well."
Those positives are enough to create "modest growth" for domestic output this year, which is expected to increase to about 74.6 Bcf/d, basically 0.4 Bcf/d higher from September to next March.
Lower 48 production overall is seen growing 1.8 Bcf/d this winter from a year ago. The Northeast's output is forecast to be the main supplier, up 2.3 Bcf/d, while the West would contribute 0.3 Bcf/d, the Rocky Mountains 0.4 Bcf/d, Midcontinent 0.2 Bcf/d and the Gulf of Mexico 0.5 Bcf/d. Declines are expected in the Southeast (down 0.6 Bcf/d) and in Texas, where gas production is seen declining by 1.3 Bcf/d.