US Gas Production – More Than Just a Local Affair10 Dec, 2012
This week’s article is the Timera Energy Blog’s inaugural Guest Post written by Howard Rogers, the Director of Natural Gas Research at the Oxford Institute for Energy Studies.
Despite being the world’s largest and oldest natural gas production province, the US natural gas sector has wrong-footed many players over the last 20 years. The gas bubble/sausage of the 1990’s ended abruptly in the cold winter of 2000/2001 when Henry Hub prices spiked to $8.90/mmbtu (monthly average) and US production then commenced its decline, despite rising rig-counts and prices into the mid-2000s. The industry rushed to build US LNG re-gas terminals (currently some 170 bcma capacity); some just completed as the shale gas boom rendered them largely without purpose in their existing configuration.
Since the recent low point of 2005, US production, due to shale gas, has increased 27% to 2011’s annual level of 651 bcm. Although demand has also risen, (most notably in the power generation sector), this excess of supply has led to high storage inventories, weighing heavily on prices. In April 2012 the monthly average HH price was $1.95/mmbtu.
Henry Hub has since risen; at the time of writing the January 2013 Nymex contract is $3.54/mmbtu (tempered by expectations of a relatively mild winter). This is still below the generally accepted price range necessary to remunerate full-cycle investment in a dry shale gas well (between $5 and $7/mmbtu). As gas-directed drilling has stalled in the US (Figure 1.), natural gas production has remained broadly on a plateau for the past 12 months (Figure 2.).
When viewing Figure 2 it should be borne in mind that the underlying average producing well decline rate in the US is some 30% per year; in plain terms the US has to create ‘two Norways’ worth of new gas production every year just to keep production level. Devotees of ‘Economics 101’ would no doubt conclude that in the near to medium term US gas production should be expected to decline gradually (relative to demand) until price levels rise to the $5 to $7/mmbtu range where dry shale gas economics are viable. As ever though, there are a number of other factors to be considered:
- Although Figure 1 confirms that fewer dry shale gas wells are being drilled, there is strong anecdotal evidence that wet shale gas plays are now the target (with NGL’s revenues compensating for lower gas prices) and with associated gas also being produced from new shale oil plays.
- As a counter to this point, NGL’s prices are of late allegedly suffering from excess of supply, and so this effect may be less dramatic going forward.
- Forward curve hedging may still provide some price cushion for many players.
- Farm-ins by large players ‘late to the party’ has resulted in wells being drilled contractually despite economics having deteriorated.
- Wells have been drilled to prevent lease expiries. Anecdotally, this is a huge factor in the Marcellus shale where drilling activity has run ahead of gas gathering and processing infrastructure. This represents ‘pent-up’ supply potential for which money-forward economics are favourable; the major capital cost having been sunk.
- As US gas prices rise we will see a reversal of the relatively recent gas – coal substitution in the power generation sector. Although many older coal stations have been retired, I am informed that the ‘switch-back’ potential is still very significant. This would serve to reduce gas demand as price rises and dampen the rate at which Henry Hub prices rise.
Despite the comprehensive and timely nature of the EIA’s statistical service, many of the factors above can only be tested at a level of granularity below that of the available data. It should also be borne in mind that EIA ‘actual’ data on US gas production is allegedly based partly on predictive algorithms until firm returns are received from operators at a later date.
Individual players will expound a narrative based on a subset of the above factors which best suits their business strategy. However, quite apart from working out exactly what is happening now (or at least in the recent past), the key question looking forward is ‘how will US gas production respond as prices rise?’.
LNG or not LNG?…..
That is the question which needs to be considered by the US authorities in deciding which of the many proposed LNG export projects will be awarded the prized ‘non-FTA’ export licence. Recent sentiment has it that projects representing a total volume of some 60 to 75 bcma could be approved (though this may be speculation). Whatever price correction is needed to place the US production base on a more sustainable footing is likely to have taken place prior to the start-up of US LNG export projects (late 2015 as the earliest). This is where the price-production potential relationship becomes key; the fear being that too great an export volume would increase US prices to the detriment of US consumers if the production-price response disappoints. This said however, at Henry Hub prices much above $6/mmbtu, given the cost of liquefaction tolling fees, shipping costs and regas costs, it is difficult to see much volume pricing itself into Europe (above $10/mmbtu) and a liquid Asian LNG spot market (above $12/mmbtu). Arbitrage could to a large degree self-correct price differentials (and prevent US prices rising much above $6/mmbtu) by adjusting the volume of exports.
We’ve Got the World Looking In
The debate in the US has been understandably internally focussed. However, the prospect of LNG exports from North America has excited passions and raised expectations (and concerns) in the world’s other key regional gas markets. In Asia, LNG buyers (particularly those in Japan who are struggling with JCC-linked contract prices in the absence of lower-cost nuclear power generation) have already committed to Henry-Hub plus tolling and transport volume deals in the event future projects are approved. (Note: there has so far been no mention in the media of exporting to South Korea – an FTA country – with the intention to re-export the cargoes to non-FTA countries, though it may just be a matter of time). In Europe the arrival of 75 bcma of LNG (either directly from the US or as volumes displaced from Asia) represents 50% of current Russian gas pipeline imports; clearly Moscow is following the story closely and should be considering a price – volume strategy for its own supplies which defends market share. Given that the LNG world is already shaping up for a post 2015 LNG wave from Australia and East Africa; superimposing another significant tranche from North America would leave regional dynamics (and price formation mechanisms) shaken and stirred – especially if Asian demand growth slows as it has been doing (apart from Japan’s post Fukushima demand surge) over the past 12 months.
Howard Rogers is a chapter author in the the recently published book ‘The Pricing of Internationally Traded Gas‘. The OIES Natural Gas Programme published working papers are avaiable at: http://www.oxfordenergy.org/category/gas-programme/working-papers-gas-programme/