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Natural gas futures gained close to a nickel Tuesday as guidance showed winter sticking around at least through the first half of March, with the potential for cold risks to form later in the month.
Spot prices strengthened across most regions and especially along the populated East Coast, where forecasts called for winter weather to arrive by Wednesday; the NGI National Spot Gas Average added 12 cents to $2.62/MMBtu.
The April contract settled at $2.749 Tuesday, up 4.5 cents from Monday’s settle, a relatively small change that still managed to seem downright volatile compared to moves of less than a penny the prior two trading days. May settled at $2.778, up 4 cents.
“It’s a 4.5 cent move. I think it’s as simple as the market reacting to colder weather,” INTL FCStone Financial Inc. Senior Vice President Tom Saal told NGI Tuesday. “And it’s seasonal cold weather. The North Pole didn’t show up here, but it’s colder nonetheless.”
NatGasWeather.com said Tuesday that “while overnight weather data was little changed, the early morning and midday Global Forecast System weather model was colder trending. The model still favors a mild ridge building over the southern and eastern U.S. March 16-20 for lighter demand, just not quite as strong with it.
“In addition, the data also favors opportunity for colder weather systems to return across the northern and eastern U.S. March 21-25...it’s possible the markets see the pattern as cold enough to satisfy, especially if March 21-25 were to trend colder.”
Saal said at this point in the season the market is viewing these last blasts of winter in terms of the end-of-season storage inventories.
“The more gas we pull out of storage, it’s going to require that much more gas that we’ll have to put back in,” he said. “It’s going to be lower than last year, and it’s going to be lower than the five-year, so these benchmarks that people use are going to show a lower level. But the bearish case is that supply is plentiful and it won’t be a problem. We’ll just have to wait and see what happens.”
Citing production growth, the Energy Information Administration (EIA) said Tuesday that it’s lowering its 2018 Henry Hub price forecast to $2.99, down from $3.20 forecast last month. EIA said it now expects 2019 prices to average $3.07.
Dry natural gas production, which averaged 73.6 Bcf/d last year, will average a record 81.7 Bcf/d in 2018 and will increase another 1.0 Bcf/d in 2019, EIA said in its latest Short-Term Energy Outlook.
"Following record high gas inventory withdrawals in early 2018, the short-term outlook estimates that inventories for March 2018 will total 1,481 Bcf, which represents a nearly 28% drop from March 2017. In fact, March 2015 was the last time inventories came close to that level," EIA Administrator Linda Capuano said.
While production remains strong, the recent start-up of exports at Dominion Energy’s Cove Point liquefied natural gas (LNG) terminal teases the prospect of new structural demand growth that could soak up excess domestic supply.
“The prospect for U.S. LNG is structurally bullish as global demand grows. Growth in export capacity, coupled with strong global demand from Asia and Europe, gives low-cost U.S. shale producers a strategic advantage,” analysts with Morningstar Commodities Research wrote in a note this week.
“As supply of natural gas has grown over the past few years, demand has also grown domestically and overseas. However, the ability to transport natural gas domestically between regions will be key to meeting all demands. As more projects in the development queue move to later stages at a time when production is expected to flatten, the U.S. could find itself in an undersupplied situation.”
With domestic export capacity projected to reach 11.8 bcf/d by 2020, the U.S. market will become increasingly sensitive to overseas fundamentals, the Morningstar team said.
“Competition for supply between exporters and domestic users injects complexity into U.S. regional fundamentals and could well pull prices higher,” the analysts said. “The LNG export market in the U.S. is developing quickly and provides great opportunities for those willing to jump in, setting the U.S. up to be a major global supplier.
“The long-term impact of this overseas adventure on domestic fundamentals will provide its own levels of excitement in a market weary of the burdens of oversupply.”
In the spot market Tuesday, East Coast points strengthened for a second straight trading day as forecasts called for another winter storm to drop as much as a foot or more of snow on parts of the Northeast.
Algonquin Citygate surged 56 cents to $3.85, while Transco Zone 6 New York gained 26 cents to $3.03
“Lower 48 demand is ticking back up for what may be the last push of winter 2017/18,” Genscape Inc. said in a note to clients Tuesday. “During the weekend, aggregate demand slipped to an 18-day low of 73.2 Bcf/d. But the resumption of the workweek along with a trailing cold front settling over the eastern seaboard has lifted today’s estimate to 77.2 Bcf/d, and our daily supply and demand forecast is projecting increases to a peak of 85.3 Bcf/d Wednesday and Thursday.”
Demand gains are expected to be focused in the eastern third of the country as western temperatures start to warm following a sustained period of colder-than-normal conditions, the firm said.
Points along the Gulf Coast followed the futures higher Tuesday, as next-day deliveries at Henry Hub gained 6 cents to average $2.73. In South Texas, Tres Palacios tacked on 7 cents to end at $2.70.
In West Texas, Transwestern added 19 cents to $2.10, while Waha climbed 4 cents to $2.15.
With Permian Basin producer economics tied to oil, natural gas prices at Waha will likely continue to see downward pressure over the next couple years, analysts with Tudor, Pickering, Holt & Co. (TPH) said Tuesday.
“Permian production economics are governed by liquids pricing as around 80% of basin revenue is levered to West Texas Intermediate” prices, the TPH analysts said. “Though associated gas production will ramp massively as wells are completed, the roughly 6.8 Bcf/d of growth through year end 2020 has relatively little impact on producer income statements.
“For the largest in-basin gas producers, we see a roughly 2-4% change in cash flow for every 50 cents/Mcf swing in Waha pricing. This insensitivity has driven little to no revision to producer growth plans as the Waha forward curve has fallen to around $1.85 and $1.70/Mcf in 2018 and 2019 respectively.”
Waha pricing should continue to see downward pressure due to infrastructure constraints, “with an increasing reliance on Mexican exports before greenfield capacity arrives in the form of Gulf Coast Express in fourth quarter 2019,” TPH said. “Permian pipes to Mexico may need to ramp to around 2.4 Bcf/d ahead of Gulf Coast Express in-service, a volume that surpasses industry expectations for total Mexican demand growth through end of the decade.”