IEA 2025 forecast analyzed

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cmm3rd
Posts: 420
Joined: Tue Jan 08, 2013 4:44 pm

IEA 2025 forecast analyzed

Post by cmm3rd »

From IV Energy Investing mb:

Oil demand balance to 2025
I would like to visit some of the details in the IEA November 2025 forecast (https://www.iea.org/newsroom/news/2018/ ... shock.html).The IEA says that we need to bring online 35M barrels in new production between 2017 and 2025 to keep the market in balance (meeting demand growth and offsetting declines). This is where these barrels will come from according to the IEA:

Part of this 35 mb/d gap is filled by conventional projects already under development. There is also growth in conventional NGLs, extra-heavy oil and bitumen, tight oil in areas outside the United States, and other smaller increases elsewhere. In total these sources add around 11 mb/d new production between 2017 and 2025. Another portion of the gap would be filled by new conventional crude oil projects that have not yet been approved. Around 16 billion barrels of new conventional crude oil resources in new projects are approved each year in the New Policies Scenario between 2017 and 2025: these provide around 13 mb/d additional production in 2025.

11M conventional NGLs, extra heavy and bitumen, tight oil ex-US.
13M from from new conventional oil developments.

The total of the above is 24M barrels, this still leaves 11M missing, this is where we will get it them:

This leaves around 11 mb/d. In the New Policies Scenario, this is filled by US shale liquids – also known as “tight liquids” – which includes tight crude oil, tight condensates and tight NGLs. Shale liquids production in the United States in 2017 was just over 7.5 mb/d. If investment were to have stopped in 2017, shale liquids production would have fallen by around 4 mb/d to 2025. However, we have seen that investment and production has actually soared over the course of 2018, and average production in 2018 is set to be close to 9.5 mb/d.

In the New Policies Scenario, shale liquids grow by another 5 mb/d to 2025 (i.e. total growth of 7 mb/d from 2017). So from 2017, and including the production to offset declines, US shale liquids provide the additional 11 mb/d production that is required to fill the remainder of the supply-demand gap. This would represent a huge increase in oil production: the growth between 2015 and 2025 would surpass the fastest rate of growth ever seen previously over a 10-year period (Saudi Arabia between 1967 and 1977).

What does the above mean is that the US needs to bring in 5M barrels in net tight oil supply between 2018 and 2025, or 830K per year. (Due to the high decline rate, 11M barrels in new shale is required to generate a 5M barrels net increase.)

In 2019, the US all liquids growth will be 1.74M (EIA OCTOBER STEO), thus the US will exceed the 830K annual growth target, next year US liquids supply will be 730K, thus will only slightly undershoot the 830K per year target. Looking at these numbers one would say perhaps 830K per year growth until 2025 is perhaps doable, but there is a catch, for the call on shale to be 830K until 2025, conventional production approvals need to run at 16B in conventional oil resources per year. WE ARE NO WHERE CLOSE TO THAT. Again from the IEA:

It is worth looking in more detail at the assumption that 16 billion barrels resources are approved in new conventional crude oil projects each year from 2018 onwards. In the years since the oil price crash in 2014, the average annual level of resources approved has been closer to 8 billion. The volumes of conventional crude oil receiving development approval would therefore need to double from today’s levels, alongside robust growth in other sources of production, if there is to be a smooth matching of supply and demand in the New Policies Scenario.

What happens if conventional approvals don't pick up and stay at current levels? The IEA answers:

In this case, US tight liquids production would need to grow by an additional 6 mb/d between now and 2025. Total growth in US tight liquids between 2018 and 2025 would therefore be around 11 mb/d: roughly equivalent to adding another “Russia” to the global oil balance over the next 7 years.

What the above means is that US shale (all liquids) needs to add 6M barrels on top of the 5M barrels in net growth between 2018 and 2025, this would equate to 1.83M in annual growth for US (all liquids) EVERY YEAR between 2018 and 2025.

Long story short, the IEA is saying that if conventional investments double, US liquids need to grow by 830K per year until 2025, if conventional investments stay where they are, US liquids need to grow by 1.83M per year until 2025. Does anyone believe such growth in US shale is possible for the next 5 to 6 years? Does anyone believe conventional oil approvals will double anytime soon considering where oil prices are and in light of all the climate change pressures? I would say even the less dire scenario of 830K annual call on shale until 2025 is a stretch, let alone the 1.83M growth required if conventional investment don't pick up.
dan_s
Posts: 34465
Joined: Fri Apr 23, 2010 8:22 am

Re: IEA 2025 forecast analyzed

Post by dan_s »

At today's luncheon in Dallas I will show why EIA's lofty U.S. oil production estimates are unreachable at today's active rig count.

Shale Oil: A Startling Prediction Using the Latest Statistical Techniques
10/ 09/ 2019
Topics: Oil Markets, Commodities, Natural Resources

“Under any scenario, future shale growth looks set to slow dramatically.”

Developments in the US shale basins have never been more important for global crude fundamentals. Over the past decade, the US has represented more than 100% of total non-OPEC growth and this growth has come exclusively from the shales. Had it not been for the US shales, the global oil market would have been in serious deficit.

We have been shale investors since their start over 15 years ago and have followed the trends extremely closely. In our Q1 2019 letter, we explained how we took our knowledge of the shales and combined it with the latest statistical techniques. Using artificial-intelligence tools from Google, cloud computing resources from Amazon, and well data from ShaleProfile, we built a “deep neural network” to analyze trends in the three major shale oil basins (the Eagle Ford, Bakken, and Permian).
ACCESS OUR Q1 2019 LETTER HERE: The Bell Has Been Rung

Most people (including us), believed that improvements in drilling and completion techniques had driven the recent increase in well productivity. Instead, our models now tell us that the E&P industry had undertaken a massive high-grading exercise. Operators had gone from drilling approximately 50% Tier 1 wells in 2014 to nearly 70% today.

We also confirmed a long-held belief (echoed by shale pioneers such as Mark Papa) that a Tier 1 well was approximately twice as productive as a Tier 2 well (all else being equal). Furthermore, we realized that enhancements in drilling and completion techniques (namely, longer wells and larger, more sand-intense frac jobs) were not delivering nearly as much productivity gains as originally believed. The implications were tremendous. Considering the rapidly dwindling inventory of undrilled Tier 1 acreage (primarily in the Bakken and Eagle Ford), we stated that drilling productivity was set to slow dramatically as companies were forced to drill increasing amounts of less productive Tier 2 acreage. We concluded that the only source of non-OPEC growth over the past decade was at risk of disappointing materially.

Applying our neural network historically, we can very accurately model production in the Eagle Ford, Bakken, and Permian using only a well’s location, lateral length and proppant size as inputs. In the following chart we have graphed historical production from these three basins against the predicted output from our neural network. As you can see, the results are excellent with an R2 in excess of 0.9.

Before we continue, we should point out that our new model largely confirmed our previous results. For example, we confirmed that a Tier 1 well is slightly more than twice as productive as a Tier 2 well in the Eagle Ford, Bakken, and Permian.

The critical question for global oil markets going forward is what level of growth we can expect from the major shale basins. We turned to our neural network for guidance. For each basin we modeled two scenarios. We used the average rig count over the last few months as our starting point (which may be too optimistic given we’re currently shedding rigs). Our base case assumes the current high-grading continues for as long as possible. For example, operators in the Eagle Ford will continue to drill 60% Tier 1 wells until they run out of inventory. Similarly, operators in the Bakken and Permian will drill ~70% and ~65% Tier 1 wells, respectively, for as long as possible. Our downside case assumes that future wells are drilled according to their remaining inventory. For example, of the remaining wells in the Eagle Ford, only 45% are Tier 1 and so future drilling will also be 45% Tier 1. For the Bakken this figure is 48% and 52% for the Permian. For each basin, we assumed that all future wells were drilled and completed using the most recent advanced techniques.

Under any scenario, future shale growth looks set to slow dramatically. In our past letters, we explained how we believed the Eagle Ford and Bakken would only grow moderately from here (if at all). Our neural network now confirms these views. Our base case (which assumes continued high grading) suggests the Eagle Ford can only grow another 380,000 b/d cumulatively over the next decade (or ~35,000 b/d per year) while our conservative case suggests the field will only grow by another 280,000 b/d (or 25,000 b/d per year). To put these figures into context, the Eagle Ford grew by 330,000 b/d on average each year between 2012 and 2015 and by 120,000 b/d in 2018.

Similarly, the Bakken can grow another 500,000 b/d cumulatively over the next 16 years (or ~35,000 b/d per year) before peaking under the base case. Under the conservative case, the Bakken will grow another 300,000 b/d over the next 23 years or 13,000 b/d per year. This compares with 250,000 b/d average annual growth in each of the last two years. As we have discussed previously, the Permian still has room to grow production. Under both scenarios, the Permian should grow production by another 2 m b/d before peaking around 6.5 m b/d sometime between 2029 and 2032. This explains why most of our E&P investments today are in the Permian basin. However, while this growth is impressive, it only represents growth of ~200,000 b/d per year, far below the ~700,000 b/d of yearly growth over the last two years.

In total, we expect the three major US shale basins will grow by another 2.7 to 2.9 m b/d in total before peaking around 10 m b/d sometime between 2027 and 2029. This equates to somewhere between 275,000 and 360,000 b/d of growth per year compared with nearly 1 m b/d of annual growth from the three basins each year between 2017 and 2019.

We should point out that these figures may be slightly higher in the early years and 2019 could actually see growth in excess of 700,000 b/d from January 1st to December 31st. However, we believe 2019 will be the last time growth exceeds 500,000 b/d as production starts to slow dramatically. Furthermore, we expect our projections are somewhat optimistic given that oil companies tend not to drill at an even pace until the entire drilling inventory is exhausted. Instead, drilling rates will likely taper as we progress through the next several years. As a result, the peak may occur further out in time but at a lower maximum level.
Dan Steffens
Energy Prospectus Group
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