I am tired of hearing about the unbelievable impact of technology on collapsing U.S. shale production costs. The truth is that these claims are unbelievable. The savings are real but only about 10% is from advances in technology. About 90% is because the oil industry is in a depression and oil field service companies have slashed prices to survive.
Zero Hedge posted an article yesterday called How OPEC Lost The War Against Shale, In One Chart that featured the chart shown below from a Goldman Sachs note.
Figure 1. Short-cycle shale has engendered a structural deflationary cycle. Source: Zero Hedge and Labyrinth Consulting Services, Inc.
Zero Hedge (and/or Goldman Sachs) erroneously states that “the cost curve has massively flattened and extended as a result of shale productivity.” If I read the chart correctly, the flat portion attributed to “shale” represents ~ 10 mmb/d but tight oil only produces ~3 mmb/d.
This little arithmetic problem and the fact that the entire 2017 cost curve has shifted downward ~$15/barrel from the 2014 curve indicates that the true point and message of the graph is that break-even costs for all producers have fallen almost 25%.
My business is working with clients who drill onshore U.S. oil and gas wells. Rig rates have fallen 40% since the oil-price collapse. One client had a bid for a drilling rig in September 2014 for $27,000 per day. By the time he signed the contract in March 2015, the rate was only $17,000 per day. Another client recently ran a special high-tech log in a well whose list price was $75,000 but he only paid $15000 after discounts were applied.
Most of the celebration of efficiency and productivity is really about a depression in the oil industry that has resulted in massive price deflation. I estimate that only about 10-12% of the cost reduction is because of technology and most of that was a one-time benefit in the first year or so it was used. Going forward, efficiency gains are a few percent at most.
“Our forecast assumes that productivity declines 8% by the end of 2018…We believe a significant portion of the productivity gains being experienced by the sector outside of the Permian are the result of high grading and will revert in future years. Cost pressures are already surfacing in the Permian, which will dampen capital efficiency going forward.”
—Bernstein E&Ps ( 10 March 2017)
Break-even price is mostly a function of well cost, flow rate and EUR.
I have already addressed well cost. Most companies and analysts routinely exclude G&A (General and Adminstrative costs or overhead), royalty payments, federal income taxes, depreciation and amortization (“EBITDAX”) from their costs. Excluding cost is an excellent way to reduce break-even price except that it does not accurately represent break-even price.
Even if we accept these break-even prices, does anyone knowingly invest in things that don’t make any money? Sorry, I forgot about negative interest rateEuropean bonds.
The EUR used for break-even prices in charts like Goldman Sachs’ are largely unknown but bigger EUR means lower break-even prices.
Companies routinely report EUR in barrels of oil equivalent (BOE) that use a natural gas-to-BOE conversion of 6:1 based on energy content but a value-based conversion including natural gas liquids is 15:1.
For gassy plays like the Eagle Ford and Permian basin, this conversion sleight-of-hand produces ~35% inflation in EUR. It is perfectly legal for reserve reporting but it is a dishonest way to represent break-even price since companies are getting ~$2.50/mmBtu for gas and not the $6.25/mmBtu implied by the 6:1 conversion.
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Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.