U.S. Arctic Oil & Gas Exploration: A Sense of Urgency

Guest serious post by David Middleton

I ran across a very lucid and informative article on Real Clear Energy today. The author is Robert Dillon, “a senior adviser on energy security at the American Council for Capital Formation and the former communications director of the Senate Energy and Natural Resources Committee.” The article includes numerous links to supporting information, particularly the National Petroleum Council’s (NPC) 2015 report on U.S. Arctic oil & gas resource potential.

A second look at Arctic energy exploration
by Robert Dillon
| March 30, 2019

America’s economy and high standard of living depend on our ability to access abundant and affordable domestic energy. While we are currently enjoying the benefits of cheap natural gas thanks to the shale boom, America’s continued energy dominance depends on our elected officials planning for the future. They must identify the natural resources we’ll need to keep pace with projected demand.

We may not be able to fully anticipate the direction of future advances in technology, but we should plan for continued economic expansion and demand for energy in the power and transportation sectors. To do any less would be defeatist.

That is why Energy Secretary Rick Perry’s decision to have the National Petroleum Council revisit its previous study of the resource potential of the Arctic is timely. Approximately 30 percent of the world’s oil and gas resources are estimated to be in the Arctic, much of it in U.S. waters off the northern coast of Alaska. Exploration of these resource-rich areas would signal to our adversaries who also have interests in the Arctic that the United States is serious about ensuring its long-term energy security.

Perry asked his NPC advisers to ensure federal regulations governing oil and gas activity on the Arctic outer continental shelf reflect the latest advances in technology and industry standards ahead of the release of a new five-year offshore lease plan for 2019-2024.

The original NPC study in 2015 was published shortly after the Obama administration issued a package of rules specifically targeting oil and gas activity along the Arctic frontier. 


Read the rest of the article at the Washington Examiner

The key findings of the 2015 NPC report were:

  1. Arctic oil and gas resources are large and can contribute significantly to meeting future U.S. and global energy needs.
  2. The arctic environment poses some different challenges relative to other oil and gas production areas, but is generally well understood.
  3. The oil and gas industry has a long history of successful operations in arctic conditions enabled by continuing technology and operational advances.
  4. Most of the U.S. Arctic offshore conventional oil and gas potential can be developed using existing field-proven technology.
  5. The economic viability of U.S. Arctic development is challenged by operating conditions and the need for updated regulations that reflect arctic conditions.
  6. Realizing the promise of Arctic oil and gas requires securing public confidence.
  7. There have been substantial recent technology and regulatory advancements to reduce the potential for and consequences of a spill.

Since 2014, 47 offshore exploration wells have been safely drilled in Arctic waters; only 2 of those were drilled on the U.S. OCS (Outer Continental Shelf). In terms of total exploration wells drilled the U.S. has lagged far behind our competitors since the end of the Reagan administration.

Figure 1-1. Arctic exploration wells by country and time period. (NPC)

Regulatory malfeasance is the primary reason the U.S. is falling behind our Arctic competitors. One of the most pernicious rules imposed by the Obama maladministration was the requirement for offshore Arctic operators to contract a second drilling rig or drill ship…

Operators also must have access to a separate relief rig able to drill a timely relief well under the conditions expected at the site in the event of a loss of well control; have the capability to predict, track, report, and respond to ice conditions and adverse weather events…


In the Gulf of Mexico, it’s relatively easy to “have access to a separate relief rig able to drill a timely relief well” because there are almost always dozens of rigs operating in the Gulf. Offshore Alaska is a different story; there’s rarely even one offshore rig operating. Shell’s efforts to drill their prospect portfolio in the Chukchi Sea were ultimately stymied by regulatory malfeasance, including the requirement that they contract a second drill ship to sit by idly while they drilled their “Burger” prospect.

“While we support regulations that enforce high safety and environmental standards, the unpredictable federal regulatory environment for the Alaska Outer Continental Shelf also made it difficult to operate efficiently,” he said.

Shell will retain the lease for the site on which it drilled its exploratory well.

“We are holding onto it because we believe there is value in the data gathered during our exploration efforts there,” Smith said.
The company will separately evaluate its leases in the Beaufort Sea off Alaska’s north coast, Smith said.

Shell spent $2.1 billion on 275 Chukchi Sea leases in 2008 and $7 billion overall on Arctic offshore development. Shell officials had called drilling there “a potential game-changer,” a vast untapped reservoir that could add to America’s energy supply for 50 years. The U.S. Geological Survey estimates 26 billion barrels of conventionally recoverable oil in U.S. Arctic waters.


Shell faced stiff regulatory oversight, including a requirement for two rigs in a drilling area in case one was damaged in a blowout.



Despite disappointing results from the initial exploratory well, the Chukchi Sea still holds massive resource potential, only topped by the Central Gulf of Mexico on the U.S. OCS.

The solution is to encourage offshore drilling in the Chuckchi and Beaufort Sea OCS (Outer Continental Shelf) areas, so that multiple rigs are operating during drilling season.

U.S. Arctic resource potential is second only to Russia’s.

Figure 1-2. Arctic resource potential (USGS, NPC)

Yet we are decades behind Russia and Norway in exploiting our own resources.

Figure 1-3. Arctic oil & gas discoveries.

The U.S. Arctic areas with the most resource potential (Chukchi Sea OCS, ANWR Area 1002 and Beaufort Sea OCS) are likely to be oil-prone, particularly ANWR.

Figure 1-4. U.S. Arctic resource potential split by liquids vs. natural gas.

The Sense of Urgency

Why is there a sense of urgency? I often hear people say things like, “The oil isn’t going anywhere, we don’t need it right now, just leave it in the ground until we need it.” The problem is that the infrastructure will go away unless the U.S. develops a sense of urgency regarding the exploitation of U.S. Arctic oil and gas resources. The Trans Alaska Pipeline System (TAPS) has a minimum operating threshold of about 200,000 barrels of oil per day (bbl/d). Technically, TAPS cannot operate effectively below about 300,000 bb/d. In July 2018, production averaged only 380,000 bbl/d and is currently around 480,000 bbl.d.

When DOE/NETL published Alaska North Slope Oil and Gas A Promising Future or an Area in Decline? in 2009, it appeared that the threshold would be crossed around 2040.

Figure 2-1. North Slope oil production, historical through 2007, forecast 2008-2050. (DOE/NETL).

Despite some promising North Slope discoveries over the past ten years, North Slope production has actually fallen below the 2009 forecast.

Figure 2-2. Figure 1 with production updated through 2017.

The resource potential is there… But it takes time to bring prospects to fruition, get them drilled and put on production. At the time DOE/NETL published their 2008 analysis, this was thought to be a reasonable timeline for North Slope exploitation and would have production peaking at about 3 million bbl/d in 2043, with ANWR Area 1002 and the Chukchi Sea OCS being the largest contributors.

Figure 2-3. North Slope exploitation scenario if all areas were open to E&P (exploration and production). This would actually require an expansion of TAPS’ capacity.

This timeline has been lengthened by regulatory malfeasance and eco-terrorist lawfare attacks, usually in the form of junk lawsuits filed against the regulatory agencies in front of Clinton- and Obama-appointed judges. You can’t get to the finish line if you’re constantly tripped at the starting gate.

So… What happens if TAPS drops below 200,000-300,000 bbl/d and is forced to shut down? It has to be dismantled, removed and the land under its right-of-way must be returned to nature. And this would be an unmitigated man-made national disaster. The premature dismantling of TAPS would permanently strand about 30 billion barrels of oil and 137 trillion cubic feet of natural gas under Alaska and its OCS (outer continental shelf).

• The Trans Alaska Pipeline System’s (TAPS) minimum flow rate of about 300,000 barrels of oil per day will be reached in 2025, absent new developments or reserves growth beyond the forecasted technically remaining reserves. An Alaska gas pipeline and gas sales from the Point Thomson field and the associated oil and condensate would provide another boost to oil production and extend the life ofTAPS for about one year to 2026. A shut down of TAPS would potentially strand about 1 billion barrels of oil reserves from the fields analyzed.

Page ix

• For the complete study interval from 2005 to 2050, the forecasts of economically recoverable oil and gas additions, including reserves growth in known fields, is 35 to 36 billion barrels of oil and 137 trillion cubic feet of gas. These optimistic estimates assume continued high oil and gas prices, stable fiscal policies, and all areas open for exploration and development. For this optimistic scenario, the productive life of the Alaska North Slope would be extended well beyond 2050 and could potentially result in the need to refurbish TAPS and add capacity to the gas pipeline.

• The forecasts become increasingly pessimistic if the assumptions are not met as illustrated by the following scenarios.

1. If the ANWR 1002 area is removed from consideration, the estimated economically recoverable oil is 29 to 30 billion barrels of oil and 135 trillion cubic feet of gas.
2. Removal of ANWR 1002 and the Chukchi Sea OCS results in a further reduction to 19 to 20 billion barrels of oil and 85 trillion cubic feet of gas.
3. Removal of ANWR 1002, Chukchi Sea OCS, and the Beaufort Sea OCS results in a reduction to 15 to 16 billion barrels of oil and 65 trillion cubic feet of gas.
4. Scenario 3 and no gas pipeline reduces the estimate to 9 to 10 billion barrels of oil (any gas discovered will likely remain stranded).

Some combination of these hypothetical scenarios is more likely to occur than the optimistic estimates.

Page viii

DOE/NETL, 2009

The 2017 tax reform bill, signed into law by President Trump, directed the Department of the Interior to open up ANWR Area 1002 for leasing.

Figure 2-4. ANWR is practically a “step-out” from Prudhoe Bay. Map of northern Alaska and nearby parts of Canada showing locations of the Arctic National Wildlife Refuge (ANWR), the 1002 area, and the National Petroleum Reserve—Alaska (NPRA). Locations of known petroleum accumulations and the Trans-Alaska Pipeline System (TAPS) are shown, as well as summaries of known petroleum volumes in northern Alaska and the Mackenzie River delta of Canada. BBO, billion barrels of oil (includes cumulative production plus recoverable resources); TCFG, trillion cubic feet of gas recoverable resources.” USGS Fact Sheet

The USGS estimates that ANWR’s mean technically recoverable oil resource is about 10.4 billion barrels. With its close proximity to Prudhoe Bay, ANWR discoveries could be quickly developed and tied back to existing infrastructure. This would be a big step in keeping oil flowing from the North Slope and TAPS operating for another 50 years. However, the clock is ticking.

Opponents to opening ANWR usually fall into one of three camps:

  • 10.4 billion barrels is only about 17 months of U.S. crude oil consumption.
  • It will take decades to establish meaningful production from ANWR.
  • We don’t need more oil right now.

No single oilfield or even oil play provides for more than a small fraction of U.S. crude oil demand. ANWR is just one, fairly big, piece of the puzzle. Refer to Figure 3 to see how each piece of the North Slope puzzle fits together. Each piece is vital to the whole of the puzzle.

However, if eco-zealots are allowed to take all of the pieces of the puzzle off the table… We freeze in the dark.

It is true that Arctic operations are challenging and that it will take years to go from the first ANWR lease sale to meaningful production rates. However, if there’s never a lease sale, no wells will be drilled and no production established… TAPS will be forced to shut down prematurely… And we’ll most likely have to import the 2-3 million bbl/d that would have been flowing through TAPS in 2040.

About the author: David Middleton has been a geologist/geophysicist in the oil & gas industry since 1981. He is a member of the Society of Exploration Geophysicists (SEG) and American Association of Petroleum Geologists (AAPG).


Tillerson, Rex W. and National Petroleum Council Staff. Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources. National Petroleum Council, 2015.

Thomas, Charles & B. North, Walter & C. Doughty, Tom & M. Hite, David & Sheets, Brent. (2009). Alaska North Slope Oil and Gas A Promising Future or an Area in Decline?.

United States Geological Survey. Arctic National Wildlife Refuge, 1002 Area, Petroleum Assessment 1998, Including Economic Analysis. USGS Fact Sheet FS-028-01, Apr. 2001

45 thoughts on “U.S. Arctic Oil & Gas Exploration: A Sense of Urgency

    • Part 1 of the NPC report has a very good synopsis of Canada’s early Arctic efforts.

    • Actually Trudeau and his ( Ex Chairman of Canada WWF) adviser Gerald Butts passed a moratorium on ALL drilling in the Arctic of Canada. This has had an effect on the locals in the area who were NOT consulted on this far reaching policy. The government in the north has been blind sided by this anti-drilling policy because these local governments were trying to entice oil and gas development in the north. To bring in the jobs and revenue to help get these areas off of the welfare status that they are in and the total dependency on the federal government of Canada for funds. Overnight 16.8 billion dollars of projects were cancelled and the Natural gas developments and pipeline that would bring gas to the southern markets was scraped. After 5 years of talks and engineering studies all of these plans were shelved at the stroke of a regulatory pen. Who needs law courts when you can place an un-elected high end Enviro-Nazy as the prime ministers chief adviser.

      One of the fall outs of this draconian Enviro-Nazy view was the town of Inuvik ran out of natural gas from the wells that they were using to power and heat the town through a untildor system. when the town of Inuvik tried to access some of the other natural gas in the area the Federal government would not issue the drilling permit so instead of burning local clean natural gas the town would have been forced to switch to trucked in diesel and bunker fuel from Edmonton where the refineries are. The refinery in Norman Wells was closed down in 1996. A novel approach was found but it is bizarre to say the least Fortis BC is trucking LNG to Inuvik from Delta BC 3700 KM but due to seasonal conditions they can only deliver this product 8 months of the year.

  1. Thanks David.
    This sort of reminds me of the cash for good used vehicles (“Cash for Clunkers”).
    Such things destroy wealth. Maybe that is the idea.

  2. Don’t hold your breath expecting anyone from the left getting a sense of urgency as they have been for far too long exhorting that it takes ten years to get off-shore production on line as a pretense for doing nothing now since it takes so long. All they can see is impending doom and gloom 10-12 years away, yet they believe a carbon tax will magically make that evil CO2 suddenly disappear.

  3. Nice report, David. A friend working in the oil sector in Alaska told me that the minimum TAPS flow issue was due to departure from laminar flow below the threshhold, with “slugging” developing. This slugging is when oil flows completely filling the pipeline, especially downhill, then there is an empty sector, then another filled space. The oil slugs impact the base of the downhill segment and produce a significant seismic event, which eventually damages the pipeline. The solution to this, and it has been implemented several times, is to mix hot water into the oil and create a larger volume, then separate the oil-water mixture at the terminal.
    One practical solution to the environmentalists against North Slope/Continental Shelf drilling would be to take them up there and stake them out naked on a summer day and let the mosquitos drill for blood. There are no hikers on the North Slope!

    • Surely there must be a “defend the mosquito” society to prevent such terrible cruelty!

  4. We can cut regulations and red tape – I’ll support that. But no way will I ever support subsidizing drilling in the north – it either makes a profit or it doesn’t. If business cannot keep the pipeline open, then let it fail.

    Resource extraction needs to be forced to put money to the side for spills, cleanup, and eventual retirement. They also need to put money aside for rescue – if they go building in the Arctic then they are responsible for the people they send there. If they can do all of that and still make a profit – Drill, Baby, Drill.

    In 50 years oil will only be mainly needed for the production of chemicals and plastics. By then (I sure hope) we should have viable electric cars and an infrastructure to support them – based on nuclear power. Even if the electric cars are still using combustion engines of some kind to turn a generator (so a type of hybrid), the fuel mileage should be triple or more what we get now (at least what I get now…).

    • Robert I agree but even if our individual oil and gas energy usage were to drop to a quarter the usage over the entire planet will still be closer to 100mmbbl/d than not.
      Everyone involved in the oil industry who has sweated over a field large or small marvels at how much the planet produces total.
      Its really hard to make a field produce for decades, its very technically difficult and financially a massive commitment.

    • Electric anything will need massive amounts of fossil fuel energy. It will be required just to manufacture the pipe dream of so called green resources.

      • old white guy – Robert said the electricity would be nuclear powered. He overlooks a few important items. 1) It will take a minimum of 30 years of honest education to get over the fear of nuclear energy that is taught so zealously in US schools today. 2) Then we would require about 5 years to revise our existing regulations to permit the building of nuclear power plants at a reasonable cost. 3) Then there would need to be 15 years crash development of sites, plans, engineering, logistics, and actual manufacturing. This would result in exorbitant costs alone, possible only by adding more fossil fuel power plants while the manufacturing was going on.

        Robert is an optimist – as are all of my timelines. Still, sometime in the future, I guess it could be done. I just don’t know why we would do it when fossil fuels are relatively abundant and cheap. Maybe the impetus would be safety. Nuclear has proved it is the safest power source around. Not sure that would do it.

    • “Even if the electric cars are still using combustion engines of some kind to turn a generator (so a type of hybrid), the fuel mileage should be triple or more what we get now (at least what I get now…).” –>

      which will transit from ICE / internal combustion energy production

      to INE / internal nuklear energy production

      other you’re thinking Amazon delivering energy parcels via drones to cars outside loading stations reach, Robert of Texas!

  5. “So… What happens if TAPS drops below 200,000-300,000 bbl/d and is forced to shut down? ”

    This is a looong ways off, even without access to additional acreage. Currently, production still just under 500 mbopd. Phase 1 of the Pikka development is forecast to bring on another 120 mbopd … with the possibility of another 3+ phases of similar size. And we both know big discoveries generally get bigger with time due to those crafty engineers :)) CP will bring on Willow & additional GMT pads for another 50-100 mbopd. The Nanushuk play is just opening up & has been aggressively leased for identified prospects similar to Pikka & Willow. There will be a lot more oil that will come out of that play.

    Not to say more acreage wouldn’t be welcomed but the TAPS argument doesn’t carry much weight, given the data.

    • Pikka, Willow, Smith Bay, etc. are great… but, so far, they haven’t done anything but offset declines… granted they are not fully developed and Smith Bay isn’t even on production yet. 2017 production was about 200,000 bbl/d below where they thought it would be in 2008.

      200,000-300,000 bbl/d is thought to be the minimum operating rate… but at the current 400,000-500,000 bbl/d rate, they’re having to “pig” the pipeline every 4 days.

      Big fields do tend to get bigger… but that just feeds the treadmill.

      • KIC-1 was drilled in the “deformed” area on the northeastern edge of ANWR Area 1002.

        About 95% of ANWR’s resource potential is in the “undeformed” area.

  6. If we’re not showing any urgency about the Arctic, the Russians are. link If we dither long enough, the Russians will take a lot of territory that should be ours.

  7. According to the April 1 Wall Street Journal (page A3) a federal judge in Alaska has stopped the president’s revocation of the last president’s executive order and requiring the permission of congress for opening “…vast swaths of the Arctic Ocean,…”. There is a picture of a sad polar bear with the article. If judges, journalists, and scientists all are convinced that they are the legislators we are the April fooled.

  8. “The solution is to encourage offshore drilling in the Chuckchi and Beaufort Sea OCS (Outer Continental Shelf) areas, so that multiple rigs are operating during drilling season.”

    Part of the problem besides the extremely high operating costs in the Beaufort and Chukchi seas is that we have only one remaining Arctic capable drilling vessel in the Beaufort Sea, the SDC (limited to 25′ to 78′), which fortunately is capable of drilling its own relief well in the event of a blowout. For both the Chukchi and Beaufort, there are no remaining shallow water (100′ to 900′) capable ice class floating drilling vessels in existence today as all have been scrapped or retrofitted for other more profitable opportunities. The only true ice class floater is the Stena IceMax which was built for deeper water applications in icy seas such as NE Greenland and worldwide deepwater operations. Multiple non-ice class drilling vessels can work in the Chukchi Sea during the 60-90 +/- day open water season but it would be very risky to deploy a non-ice class drilling vessel in the Beaufort. Last summer reminded us of that.

    • We have a similar problem in the Gulf of Mexico. There are only a couple of jackup rigs capable of drilling in 300′ water depths left in the Gulf… makes it difficult to drill shelf-edge prospects, particularly if you need to jackup over a platform.

      Of course, the relative lack of rigs in the Gulf is due to a lack of opportunities in that water depth range, not a lack of access.

  9. You don’t need this oil… the world’s car makers will be all electric within a few decades.

    • According to the IEA…

      “In order to limit temperature increases to below 2 degrees Celsius by the end of the century, the number of electric cars will need to reach 600 million by 2040”.

      600 million EV’s would consume 907% of the 2015 proved lithium reserves and 615% of the 2015 proved cobalt reserves.

      600 million EV’s would be less than half of all passenger vehicles and fuel for passenger vehicles will be the refined product of less than half of crude oil production in 2100. Crude oil demand growth will increasingly be driven by petrochemical demand.

    • Oil and coal and nuclear power will be required to charge all the useless electric vehicles and they will not last long. I want to see just how someone will produce the steel and plastics and other components required without the use of fossil fuels, mining, smelting, minor problems I am sure. sarc/

      • I am from alberta canada and was just reading about drilling in alaska and the taps pipeline needing a new source of oil supply i also noticed there was a pipeline going to the yokon maybe you should be looking south to alberta for a new supply of oil

    • Griff, “the world’s electric maker” Elon Musk IS already electric shaked awaiting the outcome of his Ponzi Scheme.

      Tweeted already about applied medical Hash – if memory serves me well.

  10. Mr. Middleton,
    I’m curious to know if you saw the news about ARAMCO’s disclosure of Ghawar’s maximum productive capacity?

  11. Dillon seems to be on point with many things but I cannot agree with “depends on our elected officials planning for the future”. It is true that we want our elected officials to stay out of the way. It is not obvious that they have a proper role in “planning for the future. In fact, every example in history shows that central planning by elected officials is less efficient and less effective than if they sit on their thumbs instead.

    Further down, Middleton seems to make an unsubstantiated leap from “What happens if TAPS drops below 200,000-300,000 bbl/d and is forced to shut down?” to “It has to be dismantled, removed and the land under its right-of-way must be returned to nature.” Why is that necessarily so? Why can’t it be mothballed in place against future need? Granted, there would be some maintenance costs. But that would be vastly lower than complete dismantling followed by complete replacement.

    • When the resources are largely under Federal lands and waters, elected officials are the single most important factor.

      The minimum flow volume is not known for certain. It’s thought to be in the 200,000 to 300,000 bbl/d range. However, the requirement to dismantle the pipeline is the law.

      The TAPS DR&R obligation originates in the pipeline right-of-way grant and lease agreements with the state and federal governments. Essentially identical DR&R stipulations in the state and federal agreements specify that:
      Upon completion of the use of all, or a very substantial part, of the Right-of-Way or other portion of the Pipeline System, Permittees [Lessees in state lease] shall promptly remove all improvements and equipment, except as otherwise approved in writing by the Authorized Officer [State Pipeline Coordinator for state lands], and shall restore the land to a condition that is satisfactory to the
      Authorized Officer [State Pipeline Coordinator] or at the option of Permittees pay the cost of such removal and restoration. The satisfaction of the Authorized Officer [State Pipeline Coordinator]
      shall be stated in writing. Where approved in writing by the Authorized Officer [State Pipeline Coordinator], buried pipe may be left in place, provided all oil and residue are removed from the pipe
      and the ends are suitably capped.11


      TAPS DR&R = Trans-Alaska Pipeline System Dismantling, Removal and Restoration

      The DOE/NETL report uses 200,000 bbl/d as the cut off. And they clearly enumerate the oil & gas volumes that would be permanently stranded if those areas are not exploited beforehand.

      The requirement to dismantle and remove idle pipelines and infrastructure is aggressively enforced in the Gulf of Mexico. It’s unlikely to be less aggressively enforced in Alaska.

    • Nothing in the article supports the notion that Ghawar is “fading.” Until Aramco’s decision to do an IPO, they did not publicly report anything or undergo independent audits. It had been assumed that Ghawar has been producing around 5 million bbl/d. An Aramco presentation on water cut management showed the production a little over 5 million bbl/d in 2004. The MSN article claims that the 2019 bond prospectus shows the maximum production to be 3.8 million bbl/d. If so, it’s now producing at a slightly lower rate than the entire Permian Basin.

      Ghawar has produced about half of the oil it will ever produce. It is in decline. It will produce for another 40 years or so, but the rate will steadily decline. This shouldn’t surprise anyone. There are hundreds of oilfields in Saudi Arabia, including several giants. The recent independent auditing of Aramco’s proved reserves actually increased them over Saudi Arabia’s “official” number.

    • The MSN article wasn’t even wrong…

      However, there is fairly little in this prospectus to give us a sense of Aramco’s coming production numbers in a week, a month, a year, or ten years. Nevertheless, an article was published on Tuesday claiming that Aramco’s supergiant oilfield Ghawar is “fading faster than anyone guessed,” and it helped move oil prices higher.

      The article incorrectly asserts that capacity at Ghawar field has dropped, though we do not know this to be true. Ghawar has long been the largest and most productive oilfield in the world, and the article accurately states that it produced 5 mbpd as recently as 15 years ago. It is the most famous oilfield and it is seen as a staple of oil production in the industry, so any news that it is getting old and declining sparks fear of “peak oil” among traders.

      In truth, the Aramco bond prospectus provides little information about Ghawar’s current or future production. The only information it does provide is in the form of something called the “MSC.” This term is refers to the capacity that Aramco is required by law to be able to access within a three-month timeframe.

      The Saudi Hydrocarbons Law sets the total Saudi MSC at 12 million bpd. In other words, Aramco must be able to ramp up production from whatever level it is producing to 12 million bpd in just three months time, and Aramco must be able to hold the 12 mbpd level for one year. In accordance with this requirement, Aramco breaks down that production by field. So, if for some reason it becomes necessary for Aramco to increase production to 12 million bpd, Ghawar field’s responsibility is to produce 3.8 million bpd.


  12. “Perry asked his NPC advisers to ensure federal regulations governing oil and gas activity on the Arctic outer continental shelf reflect the latest advances in technology and industry standards ahead of the release of a new five-year offshore lease plan for 2019-2024.”

    Who said there’s no use in “Planwirtschaft” aka “5-летний план”.

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