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Saudi Arabia Sets A $20-$40 Price Range For Crude Oil, For Now
Published by: Panos Mourdoukoutas
Saudi Arabia has found itself between a rock and a hard place lately. When it comes to the direction of the price of crude oil, that is. More...
The Kingdom is caught in a situation where big swings in the price of crude oil in either direction are damaging to its economic and political future.
That’s why Saudi Arabia campaigned for production freezes back in January, as oil was heading towards the $20-mark, rather than for an outright production cut, in my opinion. A production freeze would help to keep the price of oil in the range of $20-$40 a barrel, while an outright production cut would cause a price spike well above $40.
Why would a price spike above $40 be a bad thing for Saudi Arabia?
Because it would provide a life support to American frackers who have undermined the pricing power of the Kingdom these days, as was discussed in a previous piece here.
But there’s another, more important problem: high crude prices can help Russia and Iran raise the funds they need to support insurgent movements that threaten the Kingdom’s regime.
As one of the commentators in my recent piece put it:
“The Saudi’s don’t care about frackers at this point. What they do care about is Russia and Iran being able to fund destabilizing groups that threaten their regime. Keeping oil down helps the US and somewhat prevents Russia and Iran from funding these groups to the point they can win. The Saudi Royals don’t want to give up power just yet. And the only way to do that at the moment is to keep oil low.”
“What’s happening right now is to artificially pump oil into the market to depress the prices such that the ISIS and Putin will run out of funds for their adventures,” adds another commentator.“It’s not a coincidence that the oil price started tanking when Putin invaded Ukraine.”
To be fair, Russia has been going along with Saudi Arabia’s freeze proposal. But what oil producing countries say in public and what they do in private isn’t necessarily the same thing. “A four nation price freeze at January production levels, which were already at their highest levels in years, does absolutely zilch to balance world supply and demand,” says Kevin Rooney, CEO, Oil Heat Institute of Long Island.
While too high crude oil prices are bad for the Kingdom, too low prices aren’t better either. For a different reason: they make it hard for Saudi Arabia to maintain its fiscal and social budget. As a third commentator put it:
“Saudi Arabia needs $80+ oil to balance fiscal and social budgets. As it is they had a $90 billion dollar deficit last year because of the lower prices.”
But there’re other ways for Saudi leaders to maintain their fiscal and social budget, like tapping into the country’s reserve funds, as they have already been doing. But these funds can burn fast. “The burn rate for KSA is significant — despite the reserves pre-collapse, they will reach a point of non-recovery in order to maintain some degree of social order,” adds a fourth commentator. “The last 10-15 years of seen their social program costs significantly multiply, which cannot be reversed to a significant degree without social unrest.”
Then there are the capital markets, where Saudi Arabia is already issuing billions of debt. And there’s the prospect of selling state assets.
That’s why I would place the country’s fiscal survival somewhere in the middle of the $20-$30 per barrel, in line with official assumptions for a $29 per barrel for 2016.
Still, being between a rock and a hard place is a difficult situation to be in. In the end, the Saudi Kingdom will have to decide what’s worse for its economic and political future — a higher crude oil price or a lower oil price.
Why we could see an oil price shock in 2016
Published by: James Stafford
The depletion of old oil wells is expected to surpass new sources of supply in 2016, as the ongoing oil price slump puts a long list of oil projects on the shelf. More...
Bloomberg flagged new data from the Norwegian consultancy firm Rystad Energy, which predicts that legacy production will tip the supply balance into the negative in 2016 for the first time in years.
The production from an average conventional oil field typically ramps up in the early years, plateaus and then enters a period of decline. Depletion rates vary wildly from field to field, but a rule of thumb for conventional oil fields – which make up the bulk of total global supply – is that they decline something like 6 percent per year on average. Again, those depletion rates can differ depending on location, levels of investment, etc., but one thing that is clear is that the oil industry needs to bring new oil fields online every year in order to merely keep production flat.
Rystad Energy estimates that the crash in oil prices has cut into upstream investment so severely that natural depletion rates will overwhelm the paltry new sources of supply in 2016. Existing fields will lose about 3.3 million barrels per day (mb/d) in production this year, while new fields brought online will only add 3 mb/d. This does not take into account rising oil demand, which will soak up most of the excess supply by the end of the year.
But the 3 mb/d of new supply in 2016 will mostly come from large offshore projects that were planned years ago, investments that were made before oil prices started crashing. The EIA sees four offshore projects starting up in 2016 – projects from Shell, Noble Energy, Anadarko, and Freeport McMoran – plus two more in 2017. The industry completed eight projects in the Gulf in 2015. U.S. Gulf of Mexico production will climb from 1.63 mb/d in 2016 to 1.91 mb/d by the end of 2017.
However, outside of these large-scale multiyear offshore projects, the queue of new oil fields is starting to be cleared out. By 2017, the supply/depletion balance will go deeper into negative territory. Depletion will exceed new sources of production by around 1.2 mb/d before widening even further in 2018 and 2019.
A few months ago, Wood Mackenzie estimated that around $380 billion in planned oil projects had been put on ice due to the crash in oil prices. Wood Mackenzie says that between 2007 and 2013, the oil industry greenlighted about 40 large oil projects on average each year. That figure plunged to fewer than 10 in 2015.
The coming supply crunch stands in sharp contrast to the short-term picture. The EIA reported on March 23 that crude oil storage levels once again increased, surging by 9.4 million barrels last week to break yet another record. Total inventories in the U.S. now stand at 532.5 million barrels. Record high storage levels, which continue to climb, are signs of short-term oversupply. The IEA expects supply to continue to outstrip demand by about 1.5 mb/d until later this year. Oil storage levels will have to fall to more normal levels before oil prices can rise substantially.
But the Rystad Energy figures show that the supply-demand balance could quickly swing back in the other direction as upstream investment has screeched to a halt. As soon as later this year, or perhaps in 2017, demand could catch up to supply. Inventories will begin falling quickly and prices will start to rise. However, since supply is inelastic in the short run, the industry may struggle to satisfy demand at stable prices. The oil markets have always suffered from booms and busts, and this is just more of the same. The current bust is sowing the seeds of the next boom.
Of course, U.S. shale has demonstrated its ability to ramp up quickly, and those short lead times could allow new supply to come online as prices rise. But it remains to be seen if U.S. shale, more or less on its own in the short run, can meet rising demand in 2017 and 2018 as conventional oil drilling remains on the sidelines.
The Good, the Bad and the Ugly: U.S. Crude Oil Production Declines and Eventual Rebound
Published by: Housley Carr
U.S. crude oil production is finally falling in response to the collapse in oil prices that started in mid-2014. More...
Output is now poised to drop below 9 MMb/d--700 Mb/d off its April 2015 peak—and the rate of decline is accelerating. That raises all-important questions of how low will production go, which shale basins will be hit the hardest, and the most important question of all - how much will oil prices need to rise to reverse those declines? Understanding the factors necessary to answer these questions is the focus of RBN’s latest Drill Down report that we highlight in today’s blog. The bottom line? All production economics is local.
In June 2014, just as oil prices were about to fall off a cliff, the U.S. was producing 8.7 MMb/d of oil and the Cushing, OK spot price for West Texas Intermediate (WTI) was $106/Bbl. Do the math; about $900 million/day of oil was being produced every 24 hours. Even as oil prices plummeted over the next few months (to less than $50/Bbl by January 2015), production kept rising, propelled in large part by the momentum of ever-growing drilling and completion that marked the previous few years. In fact, U.S. production didn’t peak until April 2015, at 9.7 MMb/d. Fast forward almost another year to now. As we said, production is down to about 9.0 MMb/d (but still 300 Mb/d higher than when prices started free-falling), and oil prices, while up from their recent lows in the mid-$20s, are hovering around $40/Bbl--$60-plus dollars lower than they were 21 months ago. The daily value of production is well under $400 million, and most industry participants are hurting, some of them badly.
In this environment, it’s hard to imagine a more timely and significant question than this two-worder: Now what? As we describe in our new Drill Down report (available to RBN Backstage Pass holders and for individual purchase), answering that question requires an investigation into not only the basin-by-basin economics of producing oil, but into production economics at a much more local level. For it is only when we understand the rate of return (or profitability) of wells at a more granular level then we can begin to figure out when it makes sense to drill and complete wells (or not) in each of the scores of counties within the Permian, the Eagle Ford, the Williston and other major U.S. basins. And that county-by-county information helps us develop production expectations for each basin and, from there, for the U.S. as a whole under various oil-price scenarios.
To get from here to there, we need to understand three key market factors: a) the decline rate of existing production, b) the economics of new well development, and c) the outlook for new producing wells based on the behavior of oil and gas producers. These three market factors can be used to create a production forecast, which will help us determine not only how much more production will decline, but which basins will be hit the hardest and how much oil prices will need to rise to spur an output rebound. Once you get a handle on all that you can put your feet up and call it a day.
The a), b) and c) market factors we just identified are the building blocks for a production forecast, and the production forecast helps to answer that all-important Now what? question. In the report we released today, we explain how to forecast a base level of production volume (that is, how much already-completed wells will continue producing), how to assess which new wells would generate attractive rates of return at a given oil price, and how to determine the number of wells likely to be drilled and completed in a given area at that price. By incorporating our market factors into a mathematical production model, we can arrive at a forecast of production. Then, by running various scenarios through our model, we can develop answers to our questions regarding how, when and where U.S. production is likely to decline.
As you might expect, a lot of this hangs on oil prices. If the price of oil is high, producers will realize higher rates of return and consequently drill more wells. That will result in production growth. This is the market environment producers enjoyed from 2010 through mid-2014, and that drove U.S. production to 9.7 MMb/d. As prices fell in the latter half of 2014 and in 2015, many producers were able to make do on the rate-of-return front by jawboning down their drilling costs and getting more volume out of their wells through better completion techniques. But lower costs and higher volumes can only go so far to offset lower oil prices. So by late 2015 and early 2016, the economics of drilling new wells had really deteriorated, and many drilling programs slowed dramatically or even stopped. That is the environment facing most producers as you read this today.
So, to forecast production, we need to estimate how many wells producers are likely to complete based on a given outlook for prices. Using this estimate for prices--together with all the other factors that go into a production economics model--we can compute a rate of return for prospective wells. This rate of return can then be the basis for estimating how many new wells will be completed. When this result is plugged into a model that incorporates the estimated production from each new well plus production from existing wells, voilà, we have our production forecast.
Getting to voilà involves a good bit of number crunching. And the biggest challenge comes from the economic diversity across different basins and within the individual basins. For example, well costs vary according to the depth of formations and the length of laterals. Well productivity varies based on the geology of the formation and characteristics of the rock. Prices differ based on the costs of getting the production to market. The variability in producer economics from basin to basin is significant. Within each basin, the characteristics of each geographic area can differ widely. And within each area there can be significant differences between individual wells. To model production, therefore, we must have a thorough understanding of production economics at some relatively granular level of aggregation. In other words, all production economics is local. Very local.
To show how all this works, we zero in on a major producing basin—the Eagle Ford—which, as we explain in the report, is the basin that experienced 1) the strongest production growth during the initial boom years of the Shale Revolution and 2) the biggest post-price-crash pullbacks in the number of active drilling rigs and the volume of oil being produced. That trigger-happy responsiveness to market conditions sets the Eagle Ford apart from the Permian and the other big basins. Then, we analyze rig counts, initial production (IP) rates, decline curves, production volumes and other key data for each of the 16 counties in the Eagle Ford responsible for most of the basin’s production (see Figure 1), and identify the Good, the Bad and the Ugly counties there—the Good being those whose wells are clearly profitable at a given price point, the Bad being those whose wells are either break-even or marginally profitable/unprofitable, the Ugly being … well, you get the picture.
What makes a basin Good, Bad or Ugly is the combination of well performance (volume), well cost (drilling cost, completion cost, operational costs, financial costs) and net price back to the wellhead (netback) for any given well or group of wells. These factors are the key inputs to a producer’s economic calculations and determine the producer’s rate of return--and thus the incentive (or lack thereof) to drill and complete new wells. For Bad and Ugly basins, the economics do not necessarily mean that zero wells will be drilled and completed, but instead that the economics do not support investment in most wells at prices essentially equivalent to the current crude oil forward curve (the futures price). Along the way, we discuss the significance that natural gas IP rates and production can play in boosting a well’s—or a county’s—rate of return.
Figure 2 indicates how our analysis classifies individual Eagle Ford counties into the Good, Bad and Ugly categories. Blue counties are oil dominant, while green counties are gas dominant. The dark blue counties (Karnes and DeWitt) are Good oil counties, while (dark green) Webb is a Good gas county. The implications for drilling and completion activities and consequently the impact on production volumes have been huge. Today only four counties account for 30 of the 41 rigs still active in the Eagle Ford (13 in Karnes, 8 in DeWitt, 4 in Webb, and 5 in La Salle.). Of the rest, Dimmit, Gonzales, Live Oak, and Zavala have a paltry 3 rigs each. McMullen, Atascosa, and Lavaca have only one rig each. Others have none. Producers have narrowed their focus dramatically, and zeroed in on a very short list of counties where they can get the most production bang for their drilling buck. As you might expect, production in the Bad and Ugly counties where drilling and completion has slowed or stopped is falling like a rock. And for the total Eagle Ford, there are simply not enough Good counties to make up the difference.
To demonstrate how these production dynamics play out at the local level, we select a representative county within the Eagle Ford and undertake an in-depth analysis of rig counts, IP rates, etc., and develop a production forecast based on a reasonable expectation of future oil price trends. Given that we’ve identified a representative county within a basin (the Eagle Ford) that has proven to be highly responsive, this single-county analysis can tell us a lot about how U.S. production will respond to rising (or falling) oil prices.
The bottom line is that the decline in oil prices since mid-2014 has amplified the differences between the Good, the Bad and the Ugly. When crude oil was selling for $100/Bbl or more, most crude wells in the major shale basins realized positive rates of return. That is no longer the case. With crude oil prices close to $40/Bbl, there now are large portions of all the major basins where the producer returns are negative, and in some cases well into the red, far below any rational threshold for new drilling activity. The ability to assess at the local level which wells make sense to drill (and which don’t) at any given oil price is the key to understanding what lies ahead.