Victims of their own success
Shale-gas drillers are struggling to cope with the cheap prices brought by their onslaught of supply
Production continues to outstrip demand, despite a jump in the use of gas in the power sector at the expense of coal. Prices remain low, with little sign of recovery. The US natural gas sector is struggling to maintain momentum.
In the short term, hot weather and a surge in power demand for air conditioning could be producers’ best hope.
But, in the longer term, they will be looking to a spate of new processing facilities based on cheap gas feedstock, scheduled to come on stream in the next couple of years, and the advent of US LNG exports to provide support for the market. Fast growth in the US economy would help too.
While US gas production continued to grow modestly over the past year, the short-term outlook is looking less rosy, with output from the main shale gas plays forecast to fall between June and July this year, according to the Energy Information Administration (EIA) (Table 1).
One of the leading indicators of the gas sector’s plight at present is the rise in gas held in storage, which the EIA estimates rose 42.9% in the year to 12 June, 2015, reaching 2,433bn cf.
Such evidence of lukewarm demand means few are predicting a rise in natural gas prices in the short to medium term with futures on the benchmark Henry Hub contract trading well below $4/mn Btu for several years ahead (see demand and prices box).
Low hydrocarbons prices have already initiated what may turn into a major restructuring of the US upstream activities, as companies with too little financial strength struggle to stay afloat.
However, this is primarily driven by oil rather than gas market considerations, and the appetite of larger players to pick off their smaller cash-strapped rivals has so far proved limited – a reflection of the puny rewards on offer.
To take one example, Whiting Petroleum, a Denver-based shale oil and gas producer, reportedly put itself up for sale in March, following its takeover of rival Kodiak Oil & Gas last December.
The purchase left it cash-strapped just at a time when revenues were coming under pressure. Having failed to find a buyer it has instead re-financed itself and is striving for efficiency improvements in the hope that it can survive until markets recover.
Indebtedness bedevils the sector. A June Bloomberg Intelligence report showed that interest payments accounted for more than 10% of revenues for 27 out of 62 shale drillers surveyed, while debt among the overall group rose 16% from last year to $235bn.
Few analysts think a sector-wide recovery, either in the US or globally, is around the corner and high profile mergers, such as that between oilfield services firms Halliburton and Baker Hughes, suggest the industry’s leading players don’t either.
However, some observers expect bigger names to dip into their war chests in the near future to take advantage of more realistic stock valuations.
“A tremendous amount of capital has been on the sidelines for the last four or five years, because valuations and prices have been ridiculously high. So this is a great window of opportunity to buy,” says John Saucer, an analyst at Mobius Risk Group, in Houston. “If we were having this conversation in a few years’ time, there would be a lot of new faces involved.”
The woes of the oil sector are inextricably linked with those of gas producers, as most drillers have a foot in both camps and because many wells produce both oil and gas. Falling revenues for the liquids means less money to invest in dry gas.
Jim Williams, of Arkansas-based WTRG Economics, estimates that, taking benchmark oil and gas prices as a rough guide, revenues from both shale gas and oil have fallen by around a third across the US as a whole over the past year, albeit with regional variations.
“The problem for people who you would normally expect to drill profitably for gas at $3 [per 1,000 cf] is that they have also drilled for oil, so their income statements aren’t looking that good – and that total revenue influences the amount you have for capital spending,” says Williams.
As companies have slashed spending plans, the rig counts have plummeted. Chesapeake Energy, a big gas producer, said in March it was reducing its capex for 2015 to $3.5bn-4bn from an originally envisaged $4bn-4.5bn and would operate just 20-25 rigs in 2015. In 2014 it deployed 64. The US rotary rig count for gas-oriented drilling has plummeted by almost 29% over the past year to 221 rigs, according to Baker Hughes (Table 2).
Also significant is the near 59% fall in the number of rotary rigs targeting oil, both onshore and offshore, to 635 wells. Around 10% of total US gas production is associated gas from oil wells, so less oil drilling also means less gas.
”A lot of the increase in gas production last year came from associated gas production from the oil plays,” says Williams. With shale oil production under pressure, a decline in associated gas output looks highly likely, he adds.
While overall gas production is predicted to decline between June and July, output per rig is forecast to rise by a rig-weighted average of 75,000 cf/d to 2.41mn cf/d, with the biggest productivity gain of 255,000 cf/d per rig in the Utica play, the only shale region where gas production is currently expanding, EIA data shows.
Lower prices may cause headaches for producers, but they also provide some mitigating benefits. Cheap gas makes more sense as a power-station feedstock, while the sharp decline in rig demand from the oil sector has at least freed up capacity for gas production, which was regarded as a less profitable business than oil drilling until recently.
A greater availability of rigs – and their crews – means lower costs for those that do have the resources and markets to drill for gas.
“The best quality rigs and crews are obviously more available than they were a year ago and the cost of drilling is probably off something like 20%,” says Williams, noting that companies still have to be able to afford to drill at all to take advantage.
Marcellus leads way
Predictably, the Marcellus, the country’s biggest play, accounting for more than a third of total US shale gas production, has provided the backbone for output growth over the past year. The EIA forecasts production there in July 2015 to be some 1.5mn cf/d, about 10% higher than a year before. Most other plays registered similar percentage gains with the exception of the neighbouring, and much smaller, Utica play, where production grew 80%.
However, most of the sector’s gains were made in 2014, with the data for this year reflecting a slowing in production growth. Output from most regions is likely to begin falling over the summer months.
It’s not all gloom, because at least the practice of fracking is getting wider approval. A draft report from the US Environmental Protection Agency, which surfaced in June, suggested that shale drilling did not have a widespread or systemic effect on the quality of drinking water supplies.
That raises the possibility that US states that ban fracking may change their minds – and indeed the finding was enough to cause a temporary weakening in gas prices in anticipation of even more gas flooding the market.
However, analysts say the report reveals little that will be new to those most closely involved in the fracking debate in those states and is unlikely to be responsible, on its own, for a change in thinking.
The report doesn’t say anything we haven’t known for four or five years. This isn’t suddenly going to make the state of New York stop its fracking ban,” says Williams.
Demand and prices
US gas prices could remain around present levels for several years, given increasing production, the high levels of gas in storage and slow economic growth, even allowing for new processing capacity and LNG exports.
Certainly that view is built into the futures market. Even when natural gas was trading at around $2/mn Btu in 2012, the forward futures curve still offered prices of $4-6 for the following years. Now the curve is even flatter – with contracts still generally well below $4/mn Btu until 2020.
The one area of gas demand that is booming is electricity generation. Lower prices make gas a more attractive feedstock option for the power industry, which is already under regulatory pressure to switch from coal to fuels that emit less carbon dioxide. The most readily available of these fuels is natural gas.
For the year to end-March 2015, the share of natural gas as a feedstock for US power generation rose to 28.7% from 27.1%, while that of coal fell to 37.12% from 39.5%, according to the EIA. For the month of March 2015 alone, the share of natural gas was 30.5%, with coal on 33.5%. Gas was once primarily used to cater for peak demand, but low prices now make it attractive for baseload power provision too.
More demand for gas for power could help strengthen gas prices – though quite how high they could rise before electricity generators baulked is unclear. While tougher emissions regulations developed by the Environmental Protection Agency have played an important role in prompting coal-to-gas switching, some analysts believe that Henry Hub needs to stay around $3/million Btu to keep the power buyers interested.
Gas producers will be pinning their hopes on even tighter emissions regulations being introduced, higher coal prices (they are currently hovering around five-year lows) and compensatory demand from new gas processing facilities and the LNG export industry.
The first LNG exports from the US are due to start at the end of this year, when Cheniere Energy’s Sabine Pass plant becomes operational. Four other large export facilities have been given final approval for global exports, with dozens more developers filing applications for projects.
In practice, it is unlikely that more than five or six big projects will ever get off the ground, especially since falling global gas prices are testing the sector’s economic viability. Access to the international market will help US producers, but probably won’t revive prices given that, in turn, this would dull gas’s ability to steal market share from coal.
Billions of dollars worth of new petrochemicals capacity, much of it on the Gulf of Mexico coast, designed specifically to absorb increased US shale gas production, is another source of future demand.
Some 10mn tonnes a year (t/y) of ethylene capacity is due on stream in the US by 2018, along with 13mn t/y of methanol capacity. Meanwhile the switch by US crackers, which previously used naphtha as feedstock, to cheaper shale gas has also caused a tightening of US propylene supply, leading to an increase in propylene production capacity on the Gulf coast.
“People are more encouraged about the demand side of the equation next year, but having been burned before, people might want to see it before they believe it,” says John Saucer, of Mobius Risk Group.