What's behind the low US natural gas prices?
Demand has increased this year, but it is nowhere near large enough to soak up the extra supplies - instead the storage keeps filling up and the output keeps growing
Years of low natural gas prices in the US have done little to slow the shale-gas juggernaut. Producers are pumping gas at a record rate. Demand has picked up this year, but has been nowhere near strong enough to soak up the extra supplies. As a result, storage is piling up, and could be headed for an all-time high this winter. The result: prices could stay below $3.00/m Btu for the remainder of this year and there is little sign of a recovery on the horizon.
The Henry Hub benchmark gas price averaged just $2.81/m Btu through August this year. And hubs around the prolific Marcellus have been trading much lower at less than $2.00/m Btu. In contrast to the roller-coaster ride that oil prices have been on, gas has traded within a tight range all year.
Even with a scorching summer and record gas burn in the power sector, prices have not averaged more than $3.00/m Btu in any month this year – only the second time in 15 years that has happened. “The lack of volatility and general price stability in the US natural gas market is nothing short of astounding,” an analyst at Bank of America Merrill Lynch, Sabine Schels, wrote in a recent report.
And most expect gas prices to remain relatively low, though sub-$3.00/m Btu looks unsustainable. Raymond James recently lowered its forecast for 2015 from $3.00/m Btu to $2.80/m Btu and its long-term average price from $3.75/m Btu to just $3.25/m Btu. The Energy Information Administration – the Department of Energy’s statistical arm – expects prices to average $3.20 in 2016.
What is behind the persistently low prices? Supply, driven by strong growth from the Marcellus and Utica shale plays, has proven much more resilient to low prices than previously thought.
Rather than output stalling in the face of historically low prices, as many expected this year, growth over 2014 and 2015 is set to be one of the strongest two-year periods on record. The EIA now expects a 5.7% rise in output for 2015, bringing total US dry gas output to 74.3bn ft³/d. Production is now 11.5% higher than the 66.67bn ft3/d produced in 2013 and a quarter higher than five years ago.
That new supply has overwhelmingly come from two sources; the Marcellus and Utica shale plays in the northeast, which has surpassed 18bn ft3/d, and associated gas from surging shale oil production. Conventional gas plays in the Gulf of Mexico, Texas and elsewhere, by contrast, have seen production flatten, or enter into decline.
The northeast shale plays have seen extraordinary cost declines that have helped drillers withstand low prices. Huge improvements in drilling and completion technologies have led to 20% annual growth in efficiency. Producers are drilling wells with ever longer laterals with ever greater productivity, and they’re drilling them in record times. These improvements have pushed the breakeven point on the best Marcellus and Utica acreage – usually the areas that also yield the higher value natural gas liquids – under $2.00/m Btu. Dry gas areas, though, are profitable only at gas prices closer to $3.00/m Btu.
Not a bottomless pit
Still, the low prices have taken their toll and production growth should slow in 2016. Most companies have started to scale back activity in the face of persistently low prices. Some of the same financing issues – reduced access to debt, less attractive hedging opportunities and falling share prices – that have constrained shale oil producers over the past six months are also hitting gas producers.
As a result, the gas-directed rig count is down by 34% in the Marcellus over the past year and 54% in the more expensive Utica shale play. “Very few companies can stay profitable in even the best part of the Marcellus at current prices. In the Utica, the situation is arguably worse,” argues Schels. That led to a temporary slowdown in shale-gas supply growth this summer.
Still, in spite of these difficult conditions the production outlook from the northeast shale plays is very bright for the next 18 months, and likely longer. That is largely because a raft of new pipeline projects is scheduled to start up in the coming months and into early 2016 that will connect northeast gas to new markets in the Gulf Coast, Midwest and elsewhere. In total, an incredible 4bn ft3/d of new pipeline capacity will be added in the coming months, and pipeline capacity could triple by the end of the decade.
This influx of new takeaway capacity will unleash a surge of new production. Crucially, it should help to relieve local, oversupply conditions and reduce the steep discounts to Henry Hub seen at hubs around the northeast, improving the economics of wells. That will unlock supplies that are, as analysts at the investment bank Raymond James put it, “stuck behind the pipe.”
That is mostly gas in so-called drilled but uncompleted wells – wells that have been drilled but are waiting for pricing and logistical conditions to improve to be fracked and produced. Estimates for how many such wells there are vary, but Raymond James puts it at around 2,000 wells that could quickly be brought into production.
Given the low natural gas price, not all of that new pipeline capacity will be used. Raymond James expects about two-thirds of the new pipeline capacity to be used, allowing the northeast to produce about 1.4bn cf/d more in 2016 on top of the 0.6bn cf/d that would have happened anyway, bringing the total increase to 2bn cf/d.
How much new gas comes out of the northeast will over the next year will be crucial to the supply balance. That is because associated gas output for the Bakken, Eagle Ford and other oil plays has accounted for close to half the production gains seen in the past two years, making it a key pillar of production growth. But that pillar is falling away as shale oil drillers pull back in the face of low oil prices.
Analysts are split over how steep the decline in associated gas output will be. Raymond James expects a relatively modest 0.4bn cf/d decline in associated gas production. Some, however, see a sharper decline. BoAML’s Schels is much less bullish on the supply outlook, largely because she expects associated gas output to fall by 1.1bn cf/d, which would threaten drag overall gas production lower. Either way, the gas market will need to keep a close eye on what is going in the oil patch.
Less controversial is the negative effect low prices are having on conventional gas plays. Production from conventional gas fields has been on the decline for several years, and areas such as the Gulf of Mexico, Alaska, Wyoming and Louisiana that haven’t had shale development have seen output decline in recent years.
The production outlook for 2016, then, largely depends on whether or not gains from the northeast shale plays are enough to make up for losses everywhere else.
The EIA, for its part, now expects output to continue growing in 2016, albeit slower than the past few years. It forecasts the US adding 1.7bn cf/d of production in 2016, around 2.2% higher than 2015. “Most of the growth is expected to come from the Marcellus Shale as the backlog of uncompleted wells is reduced and as new pipelines come online,” the EIA argues.
At the same time supply growth has surged, demand growth hasn’t kept up, and inventory levels have been well above previous years. As of mid-September, storage levels were at 3.33 trillion ft3, 16% higher than last year and 4% higher than the 5-year average. Stocks have been building up in spite of very strong demand from the power sector, where low-priced gas has been pushing coal out of the mix. If it weren’t for the strong take up of natural gas in the power sector, gas markets could have seen a replay of 2012, when natural gas prices fell below $2.00/m Btu.
Nevertheless, stocks are expected to continue piling up until winter, and could surpass 4 trillion cf in October, which will help to keep prices below the $3.00/m Btu mark through the end of the year.
New demand for gas
Looking to 2016, there are a few key areas of demand to watch closely. One of the most important factors will be how gas does in the power mix. While coal-fired power is in structural decline in the US, short-term decisions to switch between coal and gas are almost completely driven by prices. And because the fuels are so closely priced in many regions, even a small rise in gas prices, which is expected, could see some of the gas switching that has taken place in 2015 reversed. Gas will find it particularly difficult to continue making inroads into the power mix if coal prices continue to decline, like they have over the past year. Across the US, the average price of coal delivered to power generators for the first half of the year is down around 5% compared to last year to the equivalent of 2.25/m Btu.
If El Niño drops large amounts of rain on the West Coast it could also push some gas out of the power mix if it results in a return of hydropower generation, which has been very low thanks to the drought. In April this year, gas overtook coal in the power mix for the first time. That is unlikely to be repeated in 2016. The EIA expects gas’ share in power mix to fall slightly from 31.4% in 2015 to 30.3% in 2016.
The start-up of a number of industrial projects should be more positive for gas demand after a very weak year in 2015 for industrial demand. A number of new methanol and ammonia-based fertilizer plants built to take advantage of low natural gas prices are expected to come online in 2016, which should drive relatively strong growth in demand. BoAML expects industrial demand to rise by 1.1bn cf/d after no growth this year.
Continued strong demand growth for imports from Mexico will also boost demand in 2016 as US gas producers continue to benefit from the country’s shift to gas-fired power. The ramp up of the Sierrita, which link the US with Mexico’s west coast, and Ramones, which runs through central Mexico, will lift import demand by around 0.7bn cf/d in 2016, and should continue to support demand growth for years to come.
Then there is the start-up of US liquefied natural gas (LNG) exports. The first LNG tanker is expected to be loaded up at Cheniere Energy’s Sabine Pass project in late 2015 and more should follow in 2016, though it will make up only a fraction of overall demand for now.
The wildcard, as ever, for natural gas markets will be the weather. Here, the signs point to lower-than-normal demand this winter. That is because El Niño is all but inevitable. The US government’s National Weather Service says there is a 95% chance of El Niño persisting through the winter. In addition to brining more rain to the West Coast, El Niño is expected to bring warmer temperatures to much of the northern US, which would damp demand.