Oil company proved reserves additions in 2017 were most since 2013 while expenditures were about half
In 2017, a group of the world’s largest publicly traded oil and natural gas producers added more hydrocarbons to their resource base than in any year since 2013, according to the annual reports of 83 exploration and production companies. Collectively, these companies added a net 8.2 billion barrels of oil equivalent (BOE) to their proved reserves during 2017, which totaled 277 billion BOE at the end of the year. Exploration and development (E&D) spending in 2017 increased 11% from 2016 levels, but remained 47% lower than 2013 levels.
Of the 83 companies, 18 held more than 80% of the 277 billion BOE in proved reserves at the end of 2017. While many of these companies have global operations, some are national oil companies with reserves concentrated in their home countries including Russia, China, and Brazil. Proved reserves change from year to year because of revisions to existing reserves, extensions and discoveries of new resources, purchases and sales of proved reserves, and production. Figure 1 illustrates the 83 companies’ combined proved reserves changes during 2017.
Organic additions to proved reserves, or reserves added through improved recovery and extensions and discoveries, are linked directly with capital expenditures in E&D. Proved reserves acquired through purchases do not represent E&D capital investment, but rather reflect transfers of assets between companies. Revisions to proved reserves are usually more significantly influenced by changes in crude oil and natural gas prices than by E&D investment.
Of the 17.7 billion BOE in organic proved reserves added in 2017, slightly less than half (8.5 billion BOE) were in the United States, while Russia, Central Asia, and the Asia-Pacific region accounted for 24% (4.3 billion BOE). Canada (which includes oil sands and synthetic crude oil), Latin America, and the Middle East and Africa regions each added more than 1.1 billion BOE. Regionally, Europe accounted for the fewest organically added proved reserves for the sixth consecutive year, adding 0.3 billion BOE of proved reserves in 2017, 2% of the world total (Figure 2).
Global E&D spending by region was similarly distributed. Of the $285 billion companies spent on E&D in 2017, 33% ($95 billion) was in the United States, with the Russia, Central Asia, and Asia-Pacific region accounting for 30% ($85 billion) and all other regions each accounting for 10% or less. Changes in nominal year-over-year E&D spending varied across regions, increasing by 36% in the United States and by 15% each in Canada and the Russia, Central Asia, and Asia-Pacific region. Spending declined by 24% in Europe, 16% in the Middle East and Africa, and 15% in Latin America (Figure 3). Because significant cost deflation has occurred in the oil and natural gas industry since 2014, nominal spending values in different years may not be directly comparable.
Because of a disparity between the timing of companies’ capital expenditures and the formal reporting of changes to their proved reserves, standard practice is to average the results over several years. Analyzed this way, E&D costs declined significantly on a per BOE basis from the 2012–2014 average to the 2015–2017 average (Figure 4). Three-year average E&D capital expenditures per BOE of organic proved reserves additions decreased in all regions except Latin America. On an annual basis, 2017 represented the lowest E&D capital expenditures per additional BOE to proved reserves during the 2012–2017 period at $16.12/BOE.
First quarter 2018 capital expenditures for this set of companies were 16% higher than the first quarter of 2017, suggesting that many of these companies have increased their E&D budgets, which will likely contribute to further organic proved reserves additions in 2018.
U.S. average regular gasoline and diesel prices decrease
The U.S. average regular gasoline retail price decreased 3 cents from last week to $2.88 per gallon on June 18, 2018, up 56 cents from the same time last year. Gulf Coast and East Coast prices each decreased over four cents to $2.65 per gallon and $2.80, respectively, Midwest prices decreased nearly three cents to $2.79 per gallon, West Coast prices decreased nearly two cents to $3.43 per gallon, and Rocky Mountain prices decreased over one penny to $2.98.
The U.S. average diesel fuel price decreased over 2 cents from last week to $3.24 per gallon on June 18, 2018, 76 cents higher than a year ago. Midwest prices declined nearly three cents to $3.17 per gallon, East Coast and Gulf Coast prices each declined over two cents to $3.24 per gallon and $3.02 per gallon, respectively, West Coast prices declined nearly two cents to $3.75 per gallon, and Rocky Mountain prices decreased less than one cent to $3.34 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 3.2 million barrels last week to 54.1 million barrels as of June 15, 2018, 9.5 million barrels (14.9%) lower than the five-year average inventory level for this same time of year. Midwest, Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories increased by 1.2 million barrels, 1.1 million barrels, 0.7 million barrels, and 0.2 million barrels, respectively. Propylene non-fuel-use inventories represented 5.0% of total propane/propylene inventories.
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The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.
The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.
Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.
And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.
Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.
As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”
The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.
Recent Announced Permian Pipeline Projects
Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b
Headlines of the week
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