The Petroleum Truth ReportMy goal is to offer clear and direct explanations of energy reality. These posts are data-driven interpretations of oil and gas topics that often challenge conventional thinking.
It is more likely that oil prices will fall below $50 per barrel than that they will continue to rise toward $70. Prices have increased beyond supply and demand fundamentals because of premature expectations about the effects of an OPEC production cut on oil inventories.
Last week’s 13.8 million barrel addition to U.S. storage was the second largest in history. It moved U.S. crude oil inventories to new record high levels.
Meanwhile, 130 horizontal rigs have been added to tight oil drilling since the OPEC cut was first announced in September. That means that U.S. output will surge and will continue to be a drag on higher prices.
Comparative inventory analysis suggests that the current ~$53 per barrel WTI oil price is at least $6 per barrel too high. Don’t hold your breath for $70 oil prices.
Inventory Is The Key
Most analysts believe prices will increase steadily now that OPEC has decided to cut production. Their logic is that over-production caused lower oil prices and lower output should bring markets into production-consumption balance.
The problem is that production is not the same as supply and consumption is not the same as demand. Inventories lie in-between and modulate the flows from both sides of the production-consumption equation.
Inventory is clearly part of supply but is also a component of demand. Excess production goes into inventory when demand is less than supply. When consumption exceeds production, oil is withdrawn from inventory reflecting increased demand.
The International Energy Agency (IEA) reported last week that global liquids markets would move to a supply deficit by the first quarter of 2017 if OPEC production cuts take place as announced (Figure 1).
Yet the OECD inventories on which IEA’s forecast is based have increased and are now more than 400 million barrels above the 5-year average (Figure 2). In order for a supply deficit to develop in the first quarter of 2017, those stocks would have to be drastically reduced over the next 6 weeks. Comparative inventory analysis provides some context for the necessary magnitude of that reduction.
Comparative inventories index current storage levels against a moving average of values for the same calendar date over the previous 5 years. This provides the most reliable way of understanding oil-price trends by normalizing stock changes for seasonal variations and comparing them with 5-year average values.
Figure 3 shows that current OECD comparative inventories (C.I.) are at an all-time high level of more than 300 million barrels (absolute inventories are 3.1 billion barrels).
C.I. values around zero (+/- about 50 mmb) correspond to periods of high oil prices (>$80 per barrel) over the past decade. That suggests that comparative inventories need to fall approximately 200 to 300 million barrels to support $70 to $80 per barrel oil prices.
What IEA is apparently showing in Figure 1 as a “demand/supply balance” is really a demand/production balance. If OPEC cuts move forward as announced, consumption will exceed production in the first two quarters of 2017 and withdrawals from storage will occur. That is a legitimate demand increase.
The billions of barrels of working capacity remaining in inventory are not considered supply in this calculation of balance. That distorts the supply-demand relationship.* At the very least, it does not treat that the ~550 million barrels of incremental inventory that has accumulated since December 2013 in Figure 2 as supply.
Inventory is like a savings account for oil. It may be in a separate account from checking but it is part of total available supply. This sort of confusion over definitions of supply and demand is easily avoided by considering comparative inventories.
Figure 4 is a cross-plot of OECD comparative inventories and Brent prices. It shows that current prices of ~$55 per barrel are approximately $10 per barrel over-valued compared to the trend line. It further shows that comparative inventory levels must fall ~200 million barrels to support ~$70 per barrel oil prices.
Movement toward market balance cannot help but accelerate as a result of OPEC production cuts. Still, the massive stock reductions necessary to support higher oil prices will only occur over a much longer period.
It will take at least a year to reduce OECD inventories 400 mmb down to the 5-year average. This assumes that all OPEC cuts take place as announced and continue beyond the 6-month term of those agreements. It also assumes that non-OPEC production declines or at least remains static.
U.S. Production Will Not Remain Static
It is worth recalling that over-production by the U.S. and Canada was the trigger for the global oil-price collapse in 2014 (Figure 5). These two countries accounted for almost half (44%) of the incremental increase in crude oil and lease condensate production in the world as of March 2015 peak production levels.
U.S. production fell more than 1 million barrels per day (mmb/d) from April 2015 through September 2016 but is now recovering because of higher oil prices (Figure 6). EIA forecasts that field production will increase to 9.28 mmb/d by the end of 2017 and will reach almost 10 mmb/d by December 2018.
EIA does not predict that WTI oil prices will exceed $60 per barrel throughout this 2-year period. It is interesting to note that EIA shows prices falling below $50 per barrel in February 2017 and remaining at that level through mid-year.
After OPEC announced that a production cut agreement was evolving in September 2016, the U.S. horizontal tight oil rig count accelerated. Since then, 130 rigs have been added and 67% have been in the Permian basin tight oil play (Figure 7). In recent weeks, the Eagle Ford play rig count has made impressive gains and the Bakken rig count has steadily increased also.
This reflects a massive flow of capital into these plays that will certainly result in production increases. Approximately $10 billion was spent in 2016 on Permian basin drilling and completion costs for horizontal tight oil wells. An additional $28 billion was spent on Permian land acquisitions.
Don’t Hold Your Breath for $70 Oil Prices
Traders, analysts and the press have consistently looked for every possible reason to anticipate higher prices since the collapse in 2014. Expectation of an OPEC production cut or freeze has provided an artificial lift to oil prices for at least a year and now, probably accounts for at least $6 per barrel of current $53 per barrel NYMEX futures prices.
A recent Wall Street Journal article noted a new record in long crude oil futures positions during the last week in January. It went on to speculate that this meant a possible end to the over-supply of oil and that prices should increase.
That observation is not supported by history. In fact, record long positions are commonly followed by a drop in oil prices. Notable examples shown in Figure 8 include price declines around the 2008 Financial Collapse, the 2014 world oil-price collapse, and the brief rally to $60 prices in the Spring of 2015.
Inventory data provides compelling evidence that present oil prices are over-valued. Last week, 13.8 million barrels (mmb) were added to U.S. crude oil storage. That’s the second highest weekly addition ever–the highest was 14.2 mmb on October 28, 2016 when WTI prices were about $5 per barrel lower.
Current crude oil inventories are at record high levels of 509 mmb (Figure 9). That’s 37 mmb more than at this time in 2016 and 140 mmb above the 5-year average level.
Comparative inventories are also near record highs (Figure 10). When C.I. was at this level in March 2016, WTI prices were around $39 per barrel. When C.I. was slightly lower in August 2016, prices were about $47 per barrel. The trend line in Figure 10 shows that oil prices are probably about $6 or $7 per barrel over-valued.
Oil prices do not always reflect underlying fundamentals but markets eventually adjust because of them. Comparative inventory analysis suggests that current oil prices are over-valued. It is possible that markets have already priced in anticipated uplift from OPEC production cuts. If so, prices may not increase much beyond present levels and expectations of $70 prices any time soon are improbable.
OPEC cuts have almost certainly put a floor under oil prices but volatility will continue to characterize markets as it has for the past 2 years. U.S. production is a wild card that will almost certainly be a drag on upward price movement. My guess is that WTI prices are likely to move below $50 per barrel until effects of OPEC production cuts are reflected in falling global inventories.
*To its credit, IEA shows 2016 inventory declines reaching the maximum levels of the 2011-2015 average. That doesn’t change the fact that current stock levels are 400 mmb above the 2012-2016 5-year average. That’s why comparative inventories are essential.
The Keystone XL Pipeline (KXL) is a bet on much higher oil prices several years from now. It will take at least $85 oil prices to develop the new oil sand projects needed to fill the pipeline.
It is also a bet that U.S. tight oil output will continue to grow and will need heavy oil to blend for refining. Both bets are risky.
A Bet On Higher Oil Prices
KXL would add about 830,000 barrels per day (b/d) to the 1.3 million b/d already moving through the base Keystone Pipeline system completed in 3 phases between 2010 and 2014 (Figure 1) when oil prices were more than $90 per barrel.
It was not until prices exceeded $70 per barrel in 2005 (December 2016 dollars) that oil sands expansion began to accelerate (Figure 2). Since then, production has almost doubled from 1.3 to 2.4 mmb/d and cumulative production has increased from 5.4 to 10 billion barrels.
By comparison, the Bakken and Eagle Ford tight oil plays have each produced 2.4 billion barrels. The Permian horizontal tight oil plays–Spraberry, Wolfcamp and Bone Spring–have produced less than 1 billion barrels.*
In 2015, oil prices averaged only $43 per barrel. No new oil sand projects have been sanctioned since oil prices collapsed in 2014 although 3 pilot projects have been approved since prices moved into the $50 per barrel range. Approval is not the same as sanctioning and these 3 projects together would add only 35,000 b/d.
It seems unlikely that new greenfield projects will be sanctioned until oil prices move much higher (Canadian heavy oil (WCS) trades at a 25% discount to WTI). Assuming that prices stabilize in the $50 to $60 range, it is reasonable that pilots may evolve into brownfield expansion projects over the next year or two.
The Canadian Association of Petroleum Producers estimates that annual oil sand production will grow 128,000 b/d until 2021 and then, grow more slowly at 59,000 b/d. If all of that new oil were going to KXL, it would not reach capacity for about 10 years. But other pipelines are already approved for expansion and will probably get much of the oil before KXL is completed.
TransCanada’s bet, therefore, is that oil prices will move much higher and more quickly than most forecasts anticipate and that the volumes will be there by the time that the pipeline is built.
Light Oil and Heavy Oil
U.S. tight oil plays produce ultra-light oil. Almost all of it is too light for refinery specifications. That means that it must be blended with heavy oil in order to be refined and that is why there is demand for Canadian heavy oil.
The Keystone XL Pipeline is, therefore, a bet that tight oil plays will continue for several decades.
Similarly, Canadian viscous, heavy oil must be diluted with ultra-light oil to move through pipelines. Because of that, Canada is the biggest importer of U.S. light oil.
The U.S. imports almost 3 times more oil from Canada than from Saudi Arabia (Figure 3). Imports from Canada are roughly equal to the amount from Saudi Arabia, Venezuela, Mexico, Colombia and Iraq combined.
The average U.S. refinery is designed for 31° API gravity oil but 80% of domestic crude oil is more than 30° and 70% is more than 35° API gravity so it must be blended with heavier oil before it can be refined (Figure 4). The Keystone Pipeline carries oil that is approximately 22° API so the fit with lighter U.S. oil is perfect.
The increasing percentage of ultra-light oil (>40° API) after 2011 shown in Figure 4 is because of the growth of tight oil plays. More than 95% of tight oil is greater than 30° API and these plays now account for more than half (52%) of U.S. output.
It is, therefore, no surprise that 98% of the oil imported by the U.S. is heavy that is, less than 35° API gravity (Figure 5). The biggest sources of heavy oil other than Canada are Saudi Arabia, Venezuela and Mexico.
Production from Venezuela and Mexico is declining (Figure 6). Canada, Iraq and Saudi Arabia have strong production histories and are, therefore, more reliable long-term providers of heavy oil to the U.S. Canada has many advantages over other providers because of geographic proximity, supply security and price.
Venezuela has enormous reserves of heavy oil and declining production is mostly because of political and social instability. This could change but it is more likely that Venezuela’s problems will continue. Mexico’s production decline is more systemic because the country has not made a significant new discovery since 1980.
A Bet on Tight Oil
So far, so good for the Keystone XL Pipeline but what about the longevity of the tight oil plays?
Production from the Bakken and Eagle Ford plays is in marked decline and Permian tight oil production growth has slowed (Figure 7). This is despite record high numbers of producing wells in all 3 plays.
The Bakken and Eagle Ford plays have probably peaked based on remaining core area locations, generally poorer performance from recently drilled wells compared to older wells, and current rig activity. Assuming that oil prices recover to the $70 range in coming years, production should increase as more marginal locations become economically viable–just not to peak levels reached in 2015.
The Permian basin, on the other hand, should continue to grow for several years for all of the reasons that the Bakken and Eagle Ford will not. There are substantial areas in the Permian core that have not been fully developed. Well performance continues to improve and the horizontal rig count has increased 70% since mid-August to 243.
Most forecasts are optimistic about tight oil output. The EIA Annual Energy Outlook 2017 anticipates that tight oil production will decline in 2017 but recover to 2015 peak levels by 2019 (Figure 8). WTI oil prices are expected to be $64 per barrel then and slowly increase to $80 by 2025. Tight oil production will rise to 6 mmb/d by 2026.
Although the forecast seems reasonable, it assumes that 2016 was the oil-price floor and that prices will continue to increase. It also suggests that prices will not reach the $70 threshold for new oil sand projects for 5 years. Other forecasts like HSBC are more aggressive and anticipate mid-$70 WTI prices as early as 2018.
The Big Long
If the last few years since the oil-price collapse have taught us anything it is that prices are unlikely to move in one direction. Nor are they likely to conform to mainstream analyst views.
Markets have been driven partly by an expectation that prices must inevitably return to levels of at least $70 to $80 per barrel sooner than later. This belief has endured despite a persistent global supply surplus and outsized inventories. The long-anticipated OPEC deus ex machina was lowered onto the stage in late 2016 and markets responded enthusiastically. Yet WTI prices have not crossed $55 per barrel so far.
It is difficult to find supply-demand fundamentals support even for the limited price rally that began with the OPEC announcement. There may already be an expectation premium of $10-12 per barrel built into current prices. Yet markets don’t always follow fundamentals in the short term although they return to them eventually.
U.S. ultra-light oil production is a central component of the global supply dilemma. Permian basin companies are adding rigs like the boom days of 2011 to 2014 have already returned. When tight oil output is high, some fraction can neither be refined nor exported and simply adds to inventories. This occurs despite the best efforts of Canadian oil sand producers to bring as much heavy oil to the party as they can.
Oil consumption remains relatively weak in the U.S. This is disturbing against the backdrop of surging tight oil rig counts.
Consumption increased with very low oil prices in 2015 and early 2016 but not to the levels before the Financial Collapse of 2007-2008 (Figure 9). Most of the increase was from greater gasoline use and more refined products exports. Modestly increasing prices in 2016 dampened consumption suggesting that demand is highly price-sensitive.
This does not represent peak demand. All credible forecast anticipate oil-demand growth over the next decade or so, albeit at a slower rate. Instead, it reflects an economy weakened by excessive debt and changes in Federal Reserve Bank monetary policy after mid-2014.
These rather gloomy observations may explain TransCanada’s motivation to complete the Keystone XL Pipeline now. I’m talking about a long bet on oil prices.
Future supply constraints will become greater the longer new E&P project investments are deferred. At the same time, the decline of production from developed fields will be more pronounced. Improved production efficiency will further accelerate reserve depletion. Meanwhile, new field discoveries are at the lowest level in decades and the average reserve size of those discoveries has gotten smaller.
Oil prices will increase dramatically at some time in the next several years. That should lead to the next oil boom and the Keystone XL Pipeline will be there to provide heavy oil to U.S. tight oil plays.
There is little doubt that a supply crunch lurks in the future. The risk for the Keystone XL is that much higher prices will collapse the global economy before new projects can fill the pipeline and pay out the investment.
*EIA’s Drilling Productivity Report estimate of 4.8 billion barrels includes all conventional production in the counties in which the tight oil plays are located.
Matt Mushalik contributed to the research on light oil.
Natural gas prices averaged a little more than $2.50 per mmBtu (million British Thermal Units) in 2016. Those days are over. Prices will average at least $3.50 to $4.00 in 2017.
Prices have more than doubled since March 2016 but gas is still under-valued. Supply is tight because demand and exports have grown and shale gas production has declined.
In April of last year, I wrote that natural gas prices should double and they did. Henry Hub spot prices increased 2 1/2 times from $1.49 to $3.70 per mmBtu and NYMEX futures prices doubled from $1.64 to $3.30 per (Figure 1).
Nevertheless, gas prices are still too low. Storage was at record high levels throughout 2016 reaching 4.1 Tcf (trillion cubic feet) and 84% of working capacity in mid-December. Storage has fallen 1.1 Tcf in the last month to 61% of capacity. That is below the 5-year average (pink, dashed line in Figure 2).
Comparative inventory (C.I.) trends are the best indicators of gas price. These compare current storage to a moving average of levels for the same date over that last 5 years and correlate negatively with spot prices (Figure 3). C.I. fell 120% from May to December 2016 and gas prices doubled.
There are occasional short-lived excursions from the correlation. These typically occur when the market believes there is sufficient supply for the winter heating season in September or October. The market over-shoots with lower prices that are later corrected upward.
The November 2016 price drop shown in Figure 3 is an example of this phenomenon that occurred outside of the normal September-October pattern. A similar price drop began in January 2017.
Figure 4 shows the November and January price drops as departures from comparative inventory vs. spot price trend lines.* The current trend line (May 2016 – January 2017 in red) closely resembles trends for periods when gas prices were $4.00 per mmBtu or higher (August 2011 – March 2013 in orange and March 2013 – March 2014 in purple).
Recent price drops partly reflect market expectation of increased gas production in the Marcellus Shale play because of new 2017 pipeline capacity. They also suggest that the market anticipates greater tight oil and associated gas production following OPEC production cuts.
Figure 4 suggests that current gas prices are under-valued and should be at least $3.75 and probably closer to $4.00 instead of $3.27/mmBtu, last week’s average spot price.
Supply and demand fundamentals also support higher prices. Gas production has been declining since February 2016. At the same time, net imports are decreasing as pipeline and LNG exports increase.
Shale gas production is declining and conventional gas has been in terminal decline for the past 15 years. As a result, the supply surplus that has existed since December 2014 has disappeared and a supply deficit began in January (Figure 5).
During the last supply deficit from December 2012 to November 2014, Henry Hub spot prices averaged $4.05 per mmBtu. NYMEX futures prices reached $3.93 in late December 2016 before closing at $3.20 last week. Both spot and futures prices should return to $3.75 or higher once the market recognizes the reality of tighter gas supply.
Shale gas production has declined almost 1 Bcf per day since August 2016 and all shale gas plays are in decline (Figure 6).
Only the Marcellus and core Utica plays break even at $4 gas prices. The Marcellus has stopped growing and more pipeline capacity to better-priced markets won’t happen as quickly as some analysts believe. Although the Utica play has growth potential, it will be spread over several years and will be largely cancelled by increased exports.
Shale gas magical thinking remains strong but the paradigm of infinite, cheap supply is no longer working. There is now too much demand between power consumption and exports to keep up with declining production.
Once decline begins, it is almost impossible to turn around short of a massive drilling campaign. The requisite capital and public support are simply not there.
That means that prices will increase. Enough additional drilling will become marginally profitable to keep natural gas affordable but it is unlikely the U.S. will return to a supply surplus any time soon. The exuberant days of cheap, abundant natural gas are over.
*Developed by my colleague J. M. Bodell who has taught me everything that I know about comparative inventories.
An OPEC production cut offers oil producers hope for higher prices in 2017. But there is a dark cloud hanging over that expectation. Global storage inventories must be substantially reduced before higher oil prices can be sustained. Some of U.S. tight oil has nowhere to go but into storage because it can neither be refined nor exported.
If all OPEC cuts take place as announced, it will be at least a year before sufficient inventory reductions allow prices to move much higher than current levels. If not, lower oil prices will last even longer.
The OPEC Production Cut and Spare Capacity
OPEC agreed to cut production in November partly because it was incapable of sustaining output at 2016 levels. Announcing a cut is a good way to cover the reality that commercial reserve limits have been reached.
Analyst narratives have created the unfounded but widely accepted belief that OPEC has a strategy, and that strategy involves a price war with U.S. tight oil producers. The cartel’s inaction since 2014 more probably reflected an unwillingness to repeat the mistake of cutting output between 1980 and 1985: those cuts had little effect on world over-supply and damaged OPEC market share and revenue.
The possibility of a production freeze was suggested in February 2016 when oil prices were less than $30 per barrel. Expectation of OPEC action and improving fundamentals lifted prices to an average of $43 per barrel in 2016.
Failure to act in November probably would have sent prices into the mid-$30 range. As my colleague Allen Brooks remarked just after the cut was announced, this is more about setting an oil-price floor than about raising prices.
By July 2016, OPEC surplus production capacity had fallen to only 0.92 mmb/d (million barrels per day). The all-time low was 0.71 mmb/d in late 2004 (Figure 1).
The negative correlation between oil price and OPEC spare capacity is obvious. Low OPEC surplus after 2004 along with increased demand from China corresponded to rising oil prices that reached $146 per barrel in June 2008. The exception to the correlation in late 2006 resulted from demand destruction when real oil prices (2016 dollars) exceeded $85 per barrel for the first time since 1982.
A production cut may bring higher short-term prices but it should also result in higher OPEC spare capacity, a negative factor for higher prices.
Massive Oil Inventories Are The Problem
After the 2008 Financial Collapse, declining OPEC spare capacity, falling OECD inventories, low interest rates, and record-high oil prices produced a classic oil-production bubble.
The bubble burst in 2014 as over-production resulted in swelling inventories (Figure 2).
There is little chance that oil prices will return to the $70-80 range that many analysts predict until OECD storage falls approximately 400 million barrels to its 5-year average. If all the announced output cuts take place and extend beyond the 6-month term of the agreement, that will take at least a year.
The idea that there was a price war between OPEC and tight oil producers arose largely from a story line that analysts promoted. It was accepted and maintained largely by American hubris.
An over-supply of oil was the enemy if there was one and it negatively affected OPEC as much as other world producers. It resulted from the longest period of high oil prices in history. Brent was more than $90 per barrel from October 2010 through October 2014.
It is true that tight oil over-production was the biggest single offender in the supply glut and price collapse but all global producers contributed their share. It is likely that OPEC would have cut production in late 2014 if Russia had agreed to participate.
Ali Al-Naimi, the Saudi oil minister at that time said, “We met with non-OPEC producers, we asked ‘what are you going to do?’ They said nothing. We said the meeting is over.”
Tight Oil Is Not A Threat To OPEC
Tight oil has never been a long-term threat to OPEC because the reserves are relatively low. EIA year-end 2015 data indicates that U.S. tight oil proven reserves are less than 12 billion barrels.
Canada’s and Venezuela’s combined oil sands reserves exceed 350 billion barrels. Oil sands are Saudi Arabia’s and OPEC’s chief reserve competition, not U.S. tight oil (Figure 3).
In fact, tight oil production is a plus for OPEC. The U.S. must import increasing amounts of OPEC heavier oil for blending in order to refine the ultra-light oil produced from tight oil plays.
OPEC’S share of U.S. imports has increased 9% since January 2015. Total U.S. crude oil imports have increased about 1 million barrels per day and most of the increase has come from OPEC countries (Figure 4).
Canada could provide almost unlimited amounts of heavy oil to the U.S. but the Obama Administration’s decision to block the Keystone XL Pipeline means increasing reliance on OPEC.
Another Year of Lower Oil Prices
OPEC members leaked the possibility of a production freeze in early 2016 when oil prices were $26 per barrel. Fears of further price collapse began to fade reinforced by improving fundamentals.
The U.S. horizontal rig count fell almost 250 rigs (44%) between the end of 2015 and late May 2016. The world production surplus peaked in January 2016 and moved unevenly toward market balance throughout 2016 (Figure 5).
Oil prices rose to more than $50 per barrel by June but prices fell below $40 in August when an OPEC meeting in Doha failed to produce a production freeze agreement (Figure 6). Increased global output, slowing demand growth and higher petroleum products inventories also weighed on prices.
In late September, OPEC abandoned its market-based approach begun in 2014 and agreed to cut production. Prices moved up and down as the likelihood of a production cut waxed and waned through October and November. A deal was announced on November 30 and prices have increased from $43 to $54 per barrel mostly on sentiment.Without participation by Russia, there probably would have been no agreement to cut production.
It is clear that like the global economy, the oil-price recovery has been weak and fragile. Hope for some OPEC action has been a significant support for prices throughout 2016. There is probably $10 to $15 of “expectation premium” built into current oil prices.
Some analysts forecast $70 oil prices in 2017. I won’t recite the litany of reasons why OPEC members may cheat or that Libya and Nigeria may increase production. I am focused on the U.S. horizontal tight oil rig count that has increased 34% (85 rigs) since mid-September, 65% of which are in the Permian basin.
If two years of low oil prices have taught us anything it is that shale companies will produce oil at almost any price provided that investors give them money to drill. There does not seem to be any limit to investors’ willingness to believe that tight oil is a good bet.
There never was an over-riding strategy behind OPEC’s unwillingness to cut output over the last 2 years. More probably, it was based on a pragmatic recognition that cutting production without participation by Russia would not meet the cartel’s needs. Now that surplus capacity is exhausted and Russia has agreed to participate, a production cut makes sense.
U.S. output will rise but imports of heavier oil will be needed for blending. Excess tight oil will go into storage keeping U.S. inventories high and U.S. crude prices at a discount to Brent. OPEC will sell heavier oil to the U.S. at higher international prices. OPEC knows this but those who are celebrating what they believe is OPEC’s surrender in a make-believe price war, apparently do not.
Did you hear about the largest U.S. oil and gas field that’s in the Permian basin of west Texas?
That’s the one that’s not a field because it hasn’t been discovered yet. That’s the one whose 20 billion barrels are an estimate by the U.S. Geological Survey. That’s the one whose 20 billion barrels would lose $500 billion at today’s oil prices.
Wait a minute. What about the headlines?
Deutsche Welle: Largest US oil and gas discovery made – USGS
Read the source–the U.S. Geological Survey. The USGS did an assessment of the undiscovered, technically recoverable resources of the Wolfcamp shale in the Permian basin.
“Undiscovered” means what it says–it has not been discovered. It’s an estimate, an educated guess. “Technically recoverable resources” means the oil that could be produced if cost didn’t matter.
Where Did $900 Billion Come From?
Where did the $900 billion value come from? Multiply 20 billion barrels times $45 per barrel and you get $900 billion. In other words, if the oil magically leaped out of the ground without the cost of drilling and completing wells; if there were no operating costs to produce it; if there were no taxes and no royalties.
Sweet. Jeb Clampett shootin’ at some food.
In the real world, an average Wolfcamp well costs $7 million to drill and complete (Table 1 from my June 2016 post on the Permian basin plays). Average operating costs are about $12 per barrel. Severance taxes are almost 5% and the average net revenue per barrel after royalties is only 75%.
The obvious question that reporters apparently failed to ask is, What is all of this going to cost?
The USGS document “Fact Sheet 2016–3092” that summarizes the Wolfcamp study includes a table that allowed me to calculate the number of wells required to produce the estimated 20 billion barrels of oil.
For each subdivision of the Wolfcamp play or “AU” (Assessment Unit), the USGS provided a calculated mean number of potentially productive acres and the average drainage area of wells. By dividing the two, I was able to determine the number of wells (shown in yellow) for each Assessment Unit in Table 2.
According to the USGS’ input data, it would take 196,253 wells to produce the 20 billion barrels if it exists. At $7 million per well, that would cost almost $1.4 trillion in drilling and completion costs alone.
It would cost more than $1.4 trillion to generate $900 billion in revenue resulting in a net loss of $500 billion at $45 oil prices excluding all operating expenses, taxes and royalties–and no discounting.
That’s a discovery that no one can afford to make.
World oil production is in balance and U.S. marketed natural gas output fell for the first time since 2005.
The EIA (U.S. Energy Information Administration) published its Short Term Energy Outlook (STEO) today. Here are the highlights.
World oil (liquids) output for September was 96.47 mmbpd (million barrels per day) and consumption was 96.39 mmbpd. That resulted in a slight surplus of 80,000 bpd, about as close to balance as it gets (Figure 1). That’s bad news considering that the Brent price of $52 per barrel acts like there are a few million bpd of surplus. So much for the global economy.
EIA forecasts an average production WTI price of $50/barrel in 2017 with Brent $1/barrel higher.
The long decline in U.S. crude oil production appears to be over. September output increased 60,000 bopd (Figure 2).
Natural gas marketed production fell from 3.2 Bcf/d (billion cubic feet of gas per day) in 2016 but EIA expects it will magically gain 1 Bcf/d before the year is over (I doubt that).
Natural gas production continues its decline and total supply is projected to go into deficit in December 2016 (Figure 3).
This is the first annual decline in gas production since 2005. But never fear–EIA projects a 3.7 Bcf/d increase in 2017.
I’m not sure where that will come from given that their gas forecast is an average price of $3.07 for 2017 and the best shale gas areas need $4 while the other plays need more like $6/mmBtu.
I guess that hedges and awesome increases in productivity explain the expected production rally.
EIA forecasts gas prices to average $3.04 for fourth quarter. Too bad the price is $3.31/mmBtu today!