Enthusiasts believe that shale gas is simultaneously cheap, abundant and profitable thus defying all rules of business and economics. That is magical thinking.
The recently released EIA Annual Energy Outlook 2016 sparkles with pixie dust as it forecasts almost unlimited gas supply at low prices out to 2040 and beyond. Exuberant press reports herald a new era of LNG exports that will change the geopolitical balance of the world and make America great again.
But U.S. shale gas production is declining because of low prices and shale gas companies are in deep financial trouble because in the real world, price and cost matter.
That is not magical.
First Quarter 2016 Financial Performance
The financial performance of shale gas-weighted E&P companies in the first quarter of 2016 was a disaster.
Chesapeake Energy, the biggest shale gas producer in the world, had negative cash from operations.
That means that oil and gas sales didn’t even cover operating costs much less capital expenditures like drilling and completion.
Other shale gas-weighted companies including Anadarko, Comstock and Petroquest also had negative cash from operations. Goodrich and Sandridge are in bankruptcy and Exco and Halcon will soon follow. Ultra, Forest, Quicksilver, Swift and Talisman were lost in action last year.
On average, surviving companies out-spent cash flow by two-to-one both in 2015 and 2016 but many normally strong companies greatly increased negative cash flow this year.
Devon Energy has been cash-flow neutral through much of the shale gas revolution but disturbingly increased capex-to-cash flow 5-fold in the first quarter of 2016. Similarly, Southwestern Energy has had an excellent record of near-cash flow neutrality but doubled its negative cash flow in 2016.
The debt side of first quarter earnings is far more disturbing. The average debt-to-cash flow ratio for shale gas companies increased almost 4-fold to more than 7, up from less than 2 in 2015.
Devon’s debt-to-cash flow was more than 21 and Southwestern’s, more than 17. Gas prices below $3 cannot be sustained without damaging the balance sheets and income statements of even well-managed companies.
Debt-to-cash flow is a critical determinant of risk from a bank’s perspective because it measures how many years it would take to pay off debt if 100% of cash from operations were used for this purpose.
This means that it would take these companies an average of 7 years to pay down their total debt using all cash from operating activities.
The energy industry average from 1992-2012 was 1.53 and 2.0 was a standard threshold for banks to call loans based on debt-covenant agreements. That threshold increased in recent years to about 4 but 7 years to pay off debt is clearly beyond reasonable bank exposure risk.
Low Gas Prices and Declining Production
Shale gas is the principal support for all U.S. gas production since conventional gas is in terminal decline. U.S. dry gas production has declined almost 1 Bcf per day since September 2015 largely because of low gas prices
Henry Hub gas prices have fallen for the last 2 years from more than $6/mmBtu in January 2014 to $2 today and prices have been below $3/mmBtu since early 2015. A similar gas-price decline occurred from June 2011 to April 2012 (Figure 3). Then, dry gas production fell when prices dropped below $3/mmBtu.
$3 is well below the break-even gas price for any operator in any play. Even in the Marcellus–the most commercially attractive shale gas play–break-even prices are more than $3.
Shale gas production has fallen 0.83 Bcf/d since February 2016 All plays have declined from their respective peaks except the Utica Shale. Marcellus production accounts for more than a third (-0.36 Bcf/d) of shale gas decline in 2016. There is certainly no shortage of supply in that play but low prices and related delays in pipeline commitments have taken their toll on production.
There are no longer any horizontal rigs drilling in the Barnett or Fayetteville, plays that were supposed to help provide the U.S. with 100 years of gas supply. That is the intersection of magical thinking and low gas prices.
Posted in The Petroleum Truth Report on May 24, 2016
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It has been 21 years since Japanese upstream firm Inpex signed on to explore the Masela block in Indonesia in 1998 and 19 years since the discovery of the giant Abadi natural gas field in 2000. In that time, Inpex’s Ichthys field in Australia was discovered, exploited and started LNG production last year, delivering its first commercial cargo just a few months ago. Meanwhile, the abundant gas in the Abadi field close to the Australia-Indonesia border has remained under the waves. Until recently, that is, when Inpex had finally reached a new deal with the Indonesian government to revive the stalled project and move ahead with a development plan.
This could have come much earlier. Much, much earlier. Inpex had submitted its first development plan for Abadi in 2010, encompassing a Floating LNG project with an initial capacity of 2.5 million tons per annum. As the size of recoverable reserves at Abadi increased, the development plan was revised upwards – tripling the planned capacity of the FLNG project to be located in the Arafura Sea to 7.5 million tons per annum. But at that point, Indonesia had just undergone a crucial election and moods had changed. In April 2016, the Indonesian government essentially told Inpex to go back to the drawing board to develop Abadi, directing them to shift from a floating processing solution to an onshore one, which would provide more employment opportunities. The onshore option had been rejected initially by Inpex in 2010, given that the nearest Indonesian land is almost 100km north of the field. But with Indonesia keen to boost activity in its upstream sector, the onshore mandate arrived firmly. And now, after 3 years of extended evaluation, Inpex has delivered its new development plan.
The new plan encompasses an onshore LNG plant with a total production capacity of 9.5 million tons per annum. With an estimated cost of US$18-20 billion, it will be the single largest investment in Indonesia and one of the largest LNG plants operated by a Japanese firm. FID is expected within 3 years, with a tentative target operational timeline of the late 2020s. LNG output will be targeted at Japan’s massive market, but also growing demand centres such as China. But Abadi will be entering into a far more crowded field that it would have if initial plans had gone ahead in 2010; with US Gulf Coast LNG producers furiously constructing at the moment and mega-LNG projects in Australia, Canada and Russia beating Abadi’s current timeline, Abadi will have a tougher fight for market share when it starts operations. The demand will be there, but the huge rise in the level of supplies will dilute potential profits.
It is a risk worth taking, at least according to Inpex and its partner Shell, which owns the remaining 35% of the Abadi gas field. But development of Abadi will be more important to Indonesia. Faced with a challenging natural gas environment – output from the Bontang, Tangguh and Badak LNG plants will soon begin their decline phase, while the huge potential of the East Natuna gas field is complicated by its composition of sour gas – Indonesia sees Abadi as a way of getting its gas ship back on track. Abadi is one of Indonesia’s few remaining large natural gas discoveries with a high potential commercialisation opportunities. The new agreement with Inpex extends the firm’s licence to operate the Masela field by 27 years to 2055 with the 150 mscf pipeline and the onshore plant expected to be completed by 2027. It might be too late by then to reverse Indonesia’s chronic natural gas and LNG production decline, but to Indonesia, at least some progress is better than none.
The Abadi LNG Project:
Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b
Headlines of the week
Midstream & Downstream
A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.
That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.
That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.
Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.
Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?
Expectations at the 176th OPEC Conference