An overwhelming bearishness has persisted for U.S. natural gas prices, with investor sentiment increasingly negative on the warm winter weather, but if there’s a hot summer, look for some upside in prices, according to analysts.
Raymond James & Associates Inc. last week held its 37th annual institutional investor conference, which included the yearly energy dinner, where more than 110 energy executives and buy-side investors shared their perspectives.
While there was “broad-based agreement that a durable oil recovery will soon be on deck,” investors were much less enthusiastic about natural gas prices, said J. Marshall Adkins, Pavel Molchanov and associate Marnie Georges.
“Close to 80% of respondents forecasted a 2016 average below $2.50/Mcf, with 30% below $2.00,” Adkins wrote. “Our $2.00 forecast is right in-line with consensus in this case. With new pipelines coming online, storage remains materially oversupplied, and there is slim visibility as to when meaningful demand improvement” will materialize from growth on the industrial demand front or gas exports.
There is some disagreement as to when oil prices will strengthen, but when it comes to U.S. gas “we would be hard-pressed to identify any significant disagreements. Nearly everyone at the conference was bearish on gas market fundamentals and the resulting outlook for Henry Hub pricing.”
With an unseasonably warm winter again weighing on demand, as well as disappointing industrial demand and slow-to-start gas exports, investors have had no reason to change their bearish view, said the Raymond James team.
“There is some division as to the current ‘breakeven’ price for gas, with roughly two-thirds placing it between $2.25/Mcf and $2.75/Mcf and another 20% placing it below $2.00/Mcf.”
A widespread understanding persists that demand drivers, particularly industrial demand, have been slow to develop, while liquefied natural gas (LNG) exports won’t be a material contributor until “2018 at the earliest…” In any case, exports and growth in industrial demand “will hardly be a cure-all even then.”
Investors surveyed at the dinner expect 2016 Henry Hub to average $2.23/Mcf, versus a Raymond James view of $2.00 and the current futures strip of $2.15.
Temperatures last week reached an unseasonable high of 75 degrees in New York City, and it could portend a hot summer in the United States, which would be good news for the natural gas market, “which needs all the additional demand it can get,” Barclays Capital analyst Nicholas Potter said in a separate note on Monday.
“Plugging in the latest summer weather forecasts to our models boosts power burn about 400 MMcf/d above our 10-year normal summer base case scenario. This results in an end-October inventory level of 3.85 Tcf, compared with our base case of 4 Tcf,” he said.
“Should this scenario emerge, it would support prices heading into the winter of 2016-17. A warmer-than-normal summer would reinforce our argument that natural gas prices should find renewed strength” in the second half of this year as production declines and new demand emerges.
“Even after rallying 6% since the end of February, winter 2016-17 could, we think, still be an attractive trade,” Potter wrote. “Despite significant weakness in the front of the curve over recent weeks, the back of the curve, specifically winter 2016-17, has found some strength.”
Gas storage may hit 4 Tcf heading into next winter, assuming a normal summer, and the market “will likely want to see production declines before getting bullish,” he said.
For now, two major bearish factors are underway: high storage and high production levels. The Energy Information Administration recently revised down its price forecast and revised higher by 2.5 Bcf/d its unconventional gas production forecast for March (see Daily GPI, March 8).
Those types of revisions “are bound to make people question declining 2016 production,” Potter said.
“However, for those following daily pipeline volumes, the data mentioned...should not come as a huge surprise,” Potter said. “Recent daily production estimates may finally be showing proof of declines. On March 8, production estimates came in at 73 Bcf/d, with the latest estimates for March 11 showing production at 72 Bcf/d, a 1 Bcf/d drop in a relatively short time.
“These production numbers, along with an eight-to-15 day March weather forecast that has now returned to normal, were enough to help prices rally last week: the prompt contract was up 8% and was trading at $1.82/MMBtu as of March 11.”
Jefferies LLC has reduced its exit-2016 domestic gas supply expectation because of declining spending by producers. Analyst Jonathan Wolff and his colleagues said their onshore 21-basin model now shows the U.S. exit rate supply down 5.1%, versus a previous forecast of a 3.2% decline.
“After incorporating expectations for exports to Mexico and reduced Canada imports, we expect total supply available to the U.S. to fall 6.0%, versus 3.8% previously,” Wolff said.
Jefferies is forecasting a much better outlook for gas prices next winter. The 2016/2017 New York Mercantile Exchange forecasts of $3.00-3.50/Mcf “may look aggressive today. But we think that current high storage levels will build slower over the summer months, leaving storage volumes only 11% above average by the beginning of next winter's withdrawal season” starting Nov. 1.
As to when oil prices may recover, investors surveyed at the Raymond James dinner expect them to bounce by year-end, and expect the U.S. rig count will begin to recover.
“At the energy dinner, the most common view was for WTI to exit the year at $40-50/bbl,” wrote Adkins and crew. “For context, our forecast is for recovery to $65 by year-end (and a 2017 average of $75), which is considerably more bullish than the consensus opinion.
“Along those lines, the group projects an average 2017 U.S. rig count of 600-800, versus our 2017 forecast of 1,030,” the Raymond James team said. “There is plenty of debate about the timing and magnitude of the oil recovery, but it's safe to say that our view is on the optimistic end of the spectrum.
Labor constraints are expected to hamper the drilling recovery, too. In talking at the dinner with executives of exploration and production companies (E&P) and oilfield service firms, “labor concerns arose repeatedly, cited as why it will be difficult for the rig count to recover beyond 700-800. Because of how deep and prolonged this downturn has been, energy executives spoke to the difficulty of recruiting people who have left for other industries -- and upward wage pressures are likely to materialize as activity ramps back up.”
E&Ps in any case plan to rebuild balance sheets before adding rigs, according to those surveyed. Capital markets remain accessible, but more than half favored paying down debt as the most prudent use of rising cash flow instead of more drilling.