Every week, the EIA proclaims a new record for natural gas production. But their own forecasts show that the U.S. will be short on supply by October of this year. A price increase is inevitable beginning later in 2016.
Popular Myth vs Reality
The popular myth is that gas production will continue to increase and that prices will remain low for years. In the myth, price has no effect on production. The reality is that price matters and production is down 1.2 bcfd1 since September 2015
The production increases reported by EIA are year-over-year comparisons that don’t reflect declines during the last 4 months.
Prices have fallen to less than half what they were in early 2014. The average price for the first quarter of 2016 is only $2.25 per MBTU2
Hedges made when prices were in the $5-range carried many companies through falling prices as they continued to produce like there was no tomorrow. Tomorrow has arrived and the hedges are gone.
Over-production in the Marcellus Shale means that producers have to compete for limited pipeline capacity by deeply discounting their sales price. The best core area locations are commercial at $4 per mcf3 but wellhead prices averaged only $1.75 per mcf in 2015.
No Simple Solution to Falling Supply
There is no simple solution to falling supply. That’s because almost half of U.S. supply is conventional gas and it is in terminal decline. Now, shale gas is also in decline
Conventional gas supply has fallen 16.75 bcfd since July 2008. Until July 2015, increases in shale gas production more than offset those losses.
Conventional gas will continue to decline at about 5% per year because few companies are drilling those plays. Shale gas must, therefore, continue to grow by at least 15 bcfd per year just to offset annual conventional gas decline (~2.5 bcfd per year) and legacy shale gas production decline (~12.5 bcfd per year).
It will take 15 bcfd of new shale gas production in 2016 to keep U.S. production flat.
Shale gas production replacement and growth for 2015 were 14.5 bcfd, down from almost 18 bcfd in 2014. It will be difficult to match 14.5 bcfd in 2016 because shale gas production has been falling 0.72 bcfd (~2.2 bcfd annualized) for the last 4 months of data
Although additional reserves exist in the Barnett and Fayetteville plays, the core areas have been largely developed and marginal areas require substantially higher gas prices to be commercial. There is only one horizontal rig operating in the Barnett and there are none in the Fayetteville.
Production in the Haynesville Shale has decreased by 3.64 bcfd since its peak. High costs and relatively low EURs make the play uneconomic below about $6.50 gas prices. Parts of the core areas remain under-developed at today’s prices.
Marcellus production declined 0.52 mcfd since July 2015. Most of this probably represented intentional shut-ins because of low wellhead prices. Marcellus production can grow but new pipelines are needed to turn reserves into supply. Even with additional infrastructure, production will peak in the next few years just like in the older plays.
Production in the Utica and Woodford plays is increasing but it is largely offset by declining associated gas from the Eagle Ford, Bakken and other tight oil plays.
A Supply Deficit Even In The Optimistic EIA Case
The EIA forecasts that net dry gas production will increase 1.4 bcfd in 2016 and 1.6 bcfd 2017. Even with that optimistic forecast, their data still shows that the U.S. will have a supply deficit beginning in the last quarter of 2016
A supply deficit does not mean that there won’t be enough gas. There is ample gas presently in storage to cover a supply shortfall for awhile. That is what happened during the supply deficit in 2013-2014 (Figure 5). That deficit was created by flat production similar to what EIA predicts for the first 3 quarters of 2016.
What is different this time, however, is that net imports will reach zero in early 2017 because of decreasing imports from Canada and increasing exports. Add to that the challenge of replacing conventional gas depletion, and there is a much more serious supply problem than EIA’s already questionable forecast suggests.
Another big difference is that in 2013-2014, capital was freely available with average oil prices above $90 per barrel and average gas prices more than $4 per MBTU. Today, the oil and gas industry is in financial shambles with both oil and gas prices at very low levels, and it is unlikely that companies can raise the capital necessary to ramp up gas drilling quickly if at all.
Export plans of at least 7 bcfd by 2020 are not helpful considering the challenges of meeting domestic supply in coming years
The prospect of exports increasing to 13 bcfd by 2030 is even more troubling absent some new shale gas play that we don’t know about yet.
Higher Gas Prices Are Inevitable
A few years ago, the oil and gas industry convinced the world that the U.S. had 100 years of natural gas. Some of us cautioned that it is worth reading the fine print, that there is a difference between a resource and a reserve. The harsh light of reality eventually reveals that what seems too good to be true usually is.
The obvious solution to declining gas supply is higher prices.
The EIA’s STEO forecast calls for $3.17 per MBTU gas prices by December 2016 and for $3.62 by December 2017. Those prices will not support necessary drilling in legacy shale gas plays. EIA’sAEO 2015 reference case does not call for gas prices to reach $5 per mcf until 2025. We can’t afford to wait 9 years.
It is, therefore, inevitable that natural gas prices must increase sooner, preferably in the next 12 to 24 months. If oil prices remain low, a shale-gas revival may save the domestic E&P business. During the last supply deficit in 2014, gas prices averaged $4.36 per mcf compared to only $2.63 in 2015.
But it will take time for producers to reverse the decline in drilling and production. It may be difficult to raise capital for renewed drilling given the current distress in the oil and gas industry.
Something will have to give sooner than later. That will be natural gas export.
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Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b
Headlines of the week
Midstream & Downstream
The world’s largest oil & gas companies have generally reported a mixed set of results in Q1 2019. Industry turmoil over new US sanctions on Venezuela, production woes in Canada and the ebb-and-flow between OPEC+’s supply deal and rising American production have created a shaky environment at the start of the year, with more ongoing as the oil world grapples with the removal of waivers on Iranian crude and Iran’s retaliation.
The results were particularly disappointing for ExxonMobil and Chevron, the two US supermajors. Both firms cited weak downstream performance as a drag on their financial performance, with ExxonMobil posting its first loss in its refining business since 2009. Chevron, too, reported a 65% drop in the refining and chemicals profit. Weak refining margins, particularly on gasoline, were blamed for the underperformance, exacerbating a set of weaker upstream numbers impaired by lower crude pricing even though production climbed. ExxonMobil was hit particularly hard, as its net profit fell below Chevron’s for the first time in nine years. Both supermajors did highlight growing output in the American Permian Basin as a future highlight, with ExxonMobil saying it was on track to produce 1 million barrels per day in the Permian by 2024. The Permian is also the focus of Chevron, which agreed to a US$33 billion takeover of Anadarko Petroleum (and its Permian Basin assets), only for the deal to be derailed by a rival bid from Occidental Petroleum with the backing of billionaire investor guru Warren Buffet. Chevron has now decided to opt out of the deal – a development that would put paid to Chevron’s ambitions to match or exceed ExxonMobil in shale.
Performance was better across the pond. Much better, in fact, for Royal Dutch Shell, which provided a positive end to a variable earnings season. Net profit for the Anglo-Dutch firm may have been down 2% y-o-y to US$5.3 billion, but that was still well ahead of even the highest analyst estimates of US$4.52 billion. Weaker refining margins and lower crude prices were cited as a slight drag on performance, but Shell’s acquisition of BG Group is paying dividends as strong natural gas performance contributed to the strong profits. Unlike ExxonMobil and Chevron, Shell has only dipped its toes in the Permian, preferring to maintain a strong global portfolio mixed between oil, gas and shale assets.
For the other European supermajors, BP and Total largely matched earning estimates. BP’s net profits of US$2.36 billion hit the target of analyst estimates. The addition of BHP Group’s US shale oil assets contributed to increased performance, while BP’s downstream performance was surprisingly resilient as its in-house supply and trading arm showed a strong performance – a business division that ExxonMobil lacks. France’s Total also hit the mark of expectations, with US$2.8 billion in net profit as lower crude prices offset the group’s record oil and gas output. Total’s upstream performance has been particularly notable – with start-ups in Angola, Brazil, the UK and Norway – with growth expected at 9% for the year.
All in all, the volatile environment over the first quarter of 2019 has seen some shift among the supermajors. Shell has eclipsed ExxonMobil once again – in both revenue and earnings – while Chevron’s failed bid for Anadarko won’t vault it up the rankings. Almost ten years after the Deepwater Horizon oil spill, BP is now reclaiming its place after being overtaken by Total over the past few years. With Q219 looking to be quite volatile as well, brace yourselves for an interesting earnings season.
Supermajor Financials: Q1 2019
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions
In its May 2019 edition of the Short-Term Energy Outlook (STEO), EIA revised its price forecast for Brent crude oil upward, reflecting price increases in recent months, more recent data, and changing expectations of global oil markets. Several supply constraints have caused oil markets to be generally tighter and oil prices to be higher so far in 2019 than previous STEOs expected.
Members of the Organization of the Petroleum Exporting Countries (OPEC) had agreed at a December 2018 meeting to cut crude oil production in the first six months of 2019; compliance with these cuts has been more effective than EIA initially expected. In the January STEO, OPEC’s crude oil and petroleum liquids production was expected to decline by 1.0 million b/d in 2019 compared with the 2018 level, but EIA now forecasts OPEC production to decline by 1.9 million b/d in the May STEO.
Within OPEC, EIA expects Iran’s liquid fuels production and exports to also decline. On April 22, 2019, the United States issued a statement indicating that it would not reissue waivers, which previously allowed eight countries to continue importing crude oil and condensate from Iran after their waivers expired on May 2. Although EIA’s previous forecasts had assumed that the United States would not reissue waivers, the increased certainty regarding waiver policy and enforcement led to lower forecasts of Iran’s crude oil production.
Venezuela—another OPEC member—has experienced declines in production and exports as a result of recurring power outages, political instability, and U.S. sanctions. In addition to supply constraints that have already materialized in 2019, political instability in Libya may further affect global supply. Any further escalation in conflict may damage crude oil infrastructure or result in a security environment where oil fields are shut in. Either situation could reduce global supply by more than EIA currently forecasts.
In the May STEO, total OPEC crude oil and other liquids supply was estimated at 37.3 million b/d in 2018, and EIA forecasts that it will average 35.4 million b/d in 2019. EIA assumes that the December 2018 agreement among OPEC members to limit production will expire following the June 2019 OPEC meeting.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions
U.S. crude oil and other liquids production is sensitive to changes in crude oil prices, taking into account a lag of several months for drilling operations to adjust. As crude oil prices have increased in recent months, so too have EIA’s domestic liquid fuels production forecasts for the remaining months of 2019.
U.S. crude oil and other liquids production, which grew by 2.2 million b/d in 2018, is forecast in EIA’s May STEO to grow by 2.0 million b/d in 2019, an increase of 310,000 b/d more than anticipated in the January STEO. In 2019, EIA expects overall U.S. crude oil and liquids production to average 19.9 million b/d, with crude oil production alone forecast to average 12.4 million b/d.
Relative to these changes in forecasted supply, EIA’s changes in forecasted demand were relatively minor. EIA expects that global oil markets will be tightest in the second and third quarters of 2019, resulting in draws in global inventories. By the fourth quarter of 2019, EIA expects that inventories will build again, and Brent crude oil prices will fall slightly.
More information about changes in STEO expectations for crude oil prices, supply, demand, and inventories is available in This Week in Petroleum.