The US natural gas glut
A recent bounce in natural gas prices might prove short-lived. But the longer-term future for the US gas sector is bright, writes Derek Brower
BY THE standards of recent months, the rise in US gas prices in the first two weeks of September was positively exuberant. Having crashed to seven-year lows earlier in the year, Nymex's front-month contract gained more than 50% in just under a fortnight, surging from $2.50/'000 cubic feet (cf) to around $3.80/'000 cf (see Figure 5, p38).
The most obvious reason for the rise was a brightening of the US' economic prospects. Last month, Ben Bernanke, head of the Federal Reserve, said the recession, which has hung over energy markets since mid-2008, appears to be ending. And common sense says that when gas is cheaper as a heat source than wood or wood pellets – and competitive with coal for electricity generators – the market has tested the bottom. And the coming winter is forecast to be chilly.
But even accounting for the recent jump in prices, US gas remains cheap. In June 2008, for example, wellhead prices averaged well over $10/m Btu (see Figure 1), almost triple last month's price, even after the surge. And there are plenty of reasons for prices to fall back – and to remain much lower for the coming months. This is good news for anyone who buys gas. And in the longer term it could support a revolution in the way Americans drive and use energy. But for the rest of 2009, it is likely to remain a headache for gas producers and marketers.
The numbers tell a story of oversupply and weak demand. As the economy went into its tailspin last year, industrial and residential gas consumption plummeted. In June, demand was around 1.5 trillion cf, according to the Department of Energy's (DOE) Energy Information Administration (EIA). That was slightly higher than in May, but well beneath January's 2.7 trillion cf. The last time summer demand reached the depths plumbed this year was in 2004.
For all of 2009, the EIA expects that the US will consume 2.4% less gas than it did last year; and that demand will remain flat in 2010. In 2008, it rose by just 0.4%. Those numbers are slightly skewed by the rapid growth of 6.3% in 2007. Nonetheless, the trend is clear: consumption has been falling (see Figure 2). In the industrial sector, the decline has been especially pronounced, with a drop in demand of 12% during the first six months of the year.
There are some exceptions. Cheap gas is now competitive with coal (which peaked at around $2.30/m Btu in March and was expected to average $2.18/m Btu last month). Consequently, the EIA says that for the second half of 2009, power sector demand will rise by 4.3% compared with second-half 2008. Coal demand in the electricity sector fell by 11% in the first six months of the year. And residential consumers will also use a little more gas in 2010 than they did this year, predicts the EIA.
Those are not reasons yet to support a sustained surge in prices, however. Nor, says Stephen Schork, editor of market newsletter the Schork Report, is cold weather likely to come to the rescue. "The market seems to think the ice age is about to arrive," he says, referring to higher prices along Nymex' futures curve. Yet even if the winter is bitter, the stock draw needed to bring inventories back in line with historical trends is well beyond what can be reasonably expected. The EIA's own forecasts do not offer much optimism. It expects the price for 2009 to average just $3.65/'000 cf and, next year, to rise to an average of just $4.78/'000 cf.
Gas in storage nears its peak
The first hurdle to any lasting price recovery lies in the depleted oilfields, aquifers and subterranean tanks that are now bursting with excess gas. At the end of August, gas in storage amounted to more than 3.3 trillion cf – over 0.5 trillion cf more than the five-year average. Midway through last month, it was over 3.4 trillion cf. And the stockpiles are expected to keep rising, reaching more than 3.8 trillion cf at the end of the injection season (31 October).
No-one knows the US' total storage capacity, although some analysts say it is around 4 trillion cf. We may find out. And, as Schork says, only a monumental draw in the next few months – of around 2.4 trillion cf – will bring levels back in line. Meanwhile, although the recession may be ending, unemployment is still rising, which could weaken residential demand whatever the weather. Steel production also remains depressed, along with other industrial users gas. It will take months before things are ticking along as they should.
Beyond the evaporation of demand, however, the other forces driving the glut of gas have been the success of the US' big gas producers and the start-up of new liquefied natural gas (LNG) capacity. Last year, domestic production of 56.3bn cf/d was the highest since 1973. Meanwhile, despite a drop in the market share of imports in 2008 – from 16% to 13% – three new LNG receiving terminals entered service: Sabine
Pass, Louisiana; Freeport LNG, in Texas; and Northeast Gateway, offshore Massachusetts.
Having heeded the market's demand for new supplies just four years ago, the new terminals' timing could not have been worse. During 2008, the EIA says, net LNG imports fell by 58%. LNG's share of imports slumped from 17% to 9%. But despite this the EIA expects LNG imports to keep rising, from 350bn cf last year to 460bn cf next year and 0.66 trillion cf in 2010. Existing on the market's margins, the availability of LNG receiving capacity – last year seven terminals imported gas – will keep a cap on prices, even if the cargoes never arrive.
Domestically, meanwhile, the rise in output confirms the gas market is working. High demand and energy prices, and easy access to credit in recent years prompted explorers to drill. This time last year, gas rig counts – which account for about 80% of all rotary rigs – reached 1,606, the highest number ever in operation in the US, says Baker Hughes.
About 30% of those rigs were tapping horizontal wells. The widespread use of horizontal drilling, hydraulic fracturing and other techniques to tap unconventional gas reserves was another result of the boom in commodity prices in recent years. As with unconventional oil production, output from reserves in plays such as the Fayetteville Shale, Arkansas, the Haynesville Shale, Louisiana, and myriad others, was once considered prohibitively expensive and fraught with problems.
Almost en masse, the majors left these fringe hydrocarbons to independent producers. Now shale, tight gas and coal-bed methane reserves are going mainstream (see p12). Texas' Barnett Shale on its own accounts for 6% of the US' total gas supply.
The price of developing these unconventional sources has also come down, say analysts. Schork says many of the biggest fields are now viable at prices under $3/'000 cf – less than half the breakeven price assumed in recent years. The proof of this is that output keeps rising, as the largest producers bring new fields on stream, despite months of depressed gas prices.
Indeed, Devon Energy and XTO Energy, Chesapeake Energy and Anadarko – each with large unconventional gas positions – all announced large rises in output this year. While other energy producers have suffered through exposure to oil price fluctuations, the US' gas producers have countered by increasing output, helping to staunch falling share-price valuations along the way (see Figure 3). Devon is the only company so far to have said it will shut in output, taking some of its wells at the Powder River play, in Wyoming, out of action.
The decision by most of the big producers to keep raising output looks risky. But it may pay dividends next year. While these large developers continue to invest, smaller operators are reigning in their upstream businesses, tightening the rig count in the process. In mid-September, Baker Hughes said that just over 1,000 rigs were operating – barely half the figure from a year earlier, and the fewest since 2003.
Total capital expenditure is also likely to fall next year, even if the biggest producers keep theirs relatively steady. Fadel Gheit, an analyst at investment bank Oppenheimer, says more than 40% of the US' gas is produced by privately owned companies, many with limited access to capital markets. That should lead to a reduction in spending while gas prices struggle to break beyond $5/'000 cf.
At the same time, "meaningful" output growth by the large shale-gas players is likely to come through acquisitions next year, suggests Gheit. That combination – slower upstream activity, cannibalism among the rivals and moderate increases in gas prices – could make US producers a canny investment bet, even if the glut takes time to clear.
Beyond how the developers fare in the coming year, however, is the question of what the US will do with all its new gas. Recent discoveries – especially shale and tight gas – have yielded reserves that could transform the country's energy sector. Some claim that, with the right policies, gas could solve the energy security worries that have vexed the nation and its politicians for years.
In June, the Colorado School of Mines' Potential Gas Committee (PGC), an independent authority on the US' gas reserves, said its estimate of the recoverable resource had grown by almost 60% in the past four years, to 2,074 trillion cf. Shale gas accounts for about a third of the resource. The study, said PGC, offers "an exceptionally strong and optimistic gas supply picture for the nation".
That could be an understatement. Notwithstanding some environmental opposition to shale-gas development, recently established reserves should end the US' need to import significant volumes of gas. Unconventional gas supplied about 30% of the US market in 2000, according to Ziff Energy, a Canadian consultancy. By 2020, it will meet the bulk of demand.
This is bad news for LNG exporters – as well as for Canadian piped gas. There, the same wealth of reserves has depressed domestic prices just as the main export market looks increasingly saturated. The speculative plans of companies such as Russia's Gazprom, which has talked of exporting gas to the US, can also now be discounted.
But it could be good news as the US' attempts to wean itself off foreign energy. And forget the cries to drill for more crude in Alaska's untouched wilderness, because gas – not oil – could provide the energy the US relies on in the future.
That is the argument of men such as T Boone Pickens, the tycoon who has crusaded relentlessly (and spent heavily on advertising) in the past year to promote a plan to convert the US to a combination of wind power and gas-powered vehicles (NGVs). He has won support for his plan from environmentalists, including former vice-president and climate-change agitator Al Gore. Pickens was quick to comment on the PGC's reserves statement, saying it would support his campaign to kick-start the transition.
His plan is making headway in Washington. During the summer, the House of Representatives approved a bill that would give the DOE $150m over five years to research and develop NGVs (PE 9/09 p18). Other legislation could increase tax credits for new NGVs. This has all been tried before – the Clear Act component of the 2005 Energy Policy Act brought several incentives for NGVs, among other alternative-fuel vehicles – but the rapid growth in the US' gas reserves is bringing greater momentum.
There is some way to go before the plan can achieve mass penetration. Honda is the only auto-manufacturer in the US market supplying vehicles that run on natural gas. And the country's fleet accounts for just over 1% of the world total. Yet the Pickens Plan suggests that it is the infancy of the US's NGV market and infrastructure that makes the transition attractive. Freeing up excess gas spent generating electricity – by expanding wind-power capacity – building a network of filling stations, and converting existing engines to handle the fuel would generate jobs. To take just one of these: at present the US has only 1,100 NGV filling stations, but more than 200,000 conventional ones.
The US has not been shy about Keynesian-style stimulus spending to generate jobs; investing to free the US of its oil-import dependency, argues the Pickins Plan, makes sense – especially if the country will spend $10 trillion on oil imports in the next decade.
Yet there are other problems. Natural gas does not carry the same calorific punch as gasoline, so NGVs have a smaller range. That could be a difficult sell in the home of the open highway (although such concerns are irrelevant in cities, which NGV America, an advocacy group, says will see the biggest growth).
An even bigger threat will come from the ethanol and oil lobbies, which will be reluctant to cede their dominant positions. But that could change if the majors – most of which ignored the unconventional gas plays – go shopping for shale assets, as BP has already started to do. Congressmen from coal states could also be difficult to persuade to back natural gas.
Nevertheless, gas has geology on its side, especially where oil is the alternative. Short of annexing Canada's oil sands, there is nothing the US can do to reverse the long-term decline of its oil reserves and production. By contrast, cheap, plentiful and cleaner-burning gas could become the country's dominant fuel.
Imagine a world in which the US' appetite for foreign oil is greatly diminished, alongside the country's greenhouse-gas emissions. Hydraulic fracturing does not sound too glamorous, but its arrival in the mainstream could be one of the most important developments in the energy sector in decades.