Oil prices fell to multi-month lows at the end of the week.
Friday, November 9, 2018
Oil prices fell to multi-month lows at the end of the week, as a confluence of factors all point in a bearish direction.
U.S. oil production surges. The EIA reported that U.S. oil production skyrocketed to 11.6 million barrels per day (mb/d) for the week ending on November 2. Despite fears that shale output would plateau because of pipeline constraints, the shale industry is firing on all cylinders. The figures also help explain the recent downturn in prices.
Russia could benefit from OPEC+ cut. Russia’s oil production is at a post-Soviet record high, but a cut in output may actually work to the benefit of Russian producers. “Producing less at $80 per barrel is better than producing at current levels and at $70 per barrel,” Alexander Losev, chief executive officer of Sputnik Asset Management, told Bloomberg. “A certain output decline will also help the companies to reduce operating costs and further improve their financials, including free cash flow.”
OPEC+ cut would be third reversal. Saudi Arabia increased production in 2015, 2016 and again this year. The first two times, the kingdom backtracked as oil prices sank amid swelling inventories. The potential third production cut in four years suggests Saudi Arabia once again ramped up too quickly, Bloomberg argues. A technical committee for OPEC+ is set to meet this weekend to consider options for 2019, including a possible production cut.
Chevron considers Venezuela exit. Chevron (NYSE: CVX) is one of a handful of oil majors that have stuck it out in Venezuela even as the country continues to fall apart. The oil major’s assets are no longer profitable, and the Wall Street Journal reports that the company is growing weary of the problems. In response to the article, Chevron denied the potential exit. “We’re committed to Venezuela and we plan to be there for many years to come,” Clay Neff, Chevron’s president for Africa and Latin America, said in an interview late Thursday with Bloomberg. The reporting that Chevron might pack up and leave “is not accurate.”
Natural gas prices up sharply. Natural gas prices jumped more than 7 percent on a single day this week, on reports that colder than normal weather is about to hit much of the country. Henry Hub prices jumped to $3.50/MMBtu, the highest level since January. With natural gas inventories at a 15-year low, the buffer the U.S. has heading into winter is unusually thin, which could heighten volatility during periods of abnormally cold weather over the next few months.
Keystone XL construction blocked by court. A U.S. federal court on Thursday blocked construction of the Keystone XL pipeline, ruling that the Trump administration failed to offer a sufficient justification for its approval. The Obama administration blocked the pipeline on grounds that the project’s negative impact on climate change was too large. In approving it quickly after coming to office, Trump did not offer an adequate justification. “The Department instead simply discarded prior factual findings related to climate change to support its course reversal,” a federal judge wrote in his decision.
Imperial Oil gives FID to oil sands project. Imperial Oil (NYSEAMERICAN: IMO) gave the go-ahead to a $2.6 billion bitumen project in Alberta, the first new oil sands project to receive a final investment decision since 2013. Construction on the 75,000-bpd project is set to begin this quarter, with first oil scheduled to come online in 2022. The project will also represent the first application of next-generation oil sands recovery technology. ExxonMobil (NYSE: XOM) is a majority owner of Imperial Oil.
Shale companies to pivot back to Permian. Carrizo Oil & Gas (NASDAQ: CRZO) is considering shifting oil rigs back to the Permian basin, just months after moving them elsewhere. Carrizo was forced to slow drilling plans this year due to pipeline bottlenecks, but the potential plans to add rigs back into the field suggests that the lull in the Permian could be nearing an end, Bloomberg reports.
Enbridge pipeline at risk after elections. Enbridge’s (NYSE: ENB) Line 5 pipeline, which ferries oil from Canada, through Michigan and into Ontario for refining, could come under political fire now that the state of Michigan has elected a governor opposed to the project. The aging 65-year-old pipeline, with a capacity of 540,000 bpd, presents an environmental risk to the Great Lakes and Michigan’s waterways, Governor-elect Gretchen Whitmer has argued. She has indicated that she might push for the pipeline’s closure. If it were shutdown, it would cause the discounts for Canadian oil to balloon.
Wind and solar cheaper than coal. Renewable energy has been gaining ground at the expense of coal for some time, but a new study estimates that wind and solar are not just cheaper than new coal plants, but actually cheaper than simply running existing coal plants. According to Lazard, the all-in levelized cost of electricity for wind ranges from US$29-$56 per megawatt hour, without subsidies. The marginal cost of merely running a coal plant is US$27-$45 per MWh. Wind competes without subsidies; with supports, it is far cheaper than existing coal plants.
Saudi think tank explores non-OPEC world. A Saudi think tank is undertaking a research study to explore the ramifications of a hypothetical scenario in which OPEC fell apart or was disbanded. It’s not that Riyadh is considering such a move, but they want to know what the consequences will be. “We’re looking at what happens if there’s no spare capacity,” Adam Sieminski, the former head of the U.S. EIA and who now heads up the King Abdullah Petroleum Studies and Research Center in Riyadh, told Bloomberg. “One scenario to that is OPEC doesn’t exist.”
China’s oil imports still strong. China imported a record volume of oil in October, dispelling fears that the Chinese economy is slowing down. China imported 9.61 million barrels per day in October, up an astounding 31.5 percent from a month earlier. However, some of the factors driving imports higher are temporary, such as the need to fill strategic storage, plus a one-off buying spree by small refiners who had quotas that were nearing expiration. Still, with China’s production gradually declining, and the economy still humming along, high demand is not going away.
Oil prices fell to multi-month lows at the end of the week, as a confluence of factors all point in a bearish direction.
U.S. oil production surges. The EIA reported that U.S. oil production skyrocketed to 11.6 million barrels per day (mb/d) for the week ending on November 2. Despite fears that shale output would plateau because of pipeline constraints, the shale industry is firing on all cylinders. The figures also help explain the recent downturn in prices.
Russia could benefit from OPEC+ cut. Russia’s oil production is at a post-Soviet record high, but a cut in output may actually work to the benefit of Russian producers. “Producing less at $80 per barrel is better than producing at current levels and at $70 per barrel,” Alexander Losev, chief executive officer of Sputnik Asset Management, told Bloomberg. “A certain output decline will also help the companies to reduce operating costs and further improve their financials, including free cash flow.”
OPEC+ cut would be third reversal. Saudi Arabia increased production in 2015, 2016 and again this year. The first two times, the kingdom backtracked as oil prices sank amid swelling inventories. The potential third production cut in four years suggests Saudi Arabia once again ramped up too quickly, Bloomberg argues. A technical committee for OPEC+ is set to meet this weekend to consider options for 2019, including a possible production cut.
Chevron considers Venezuela exit. Chevron (NYSE: CVX) is one of a handful of oil majors that have stuck it out in Venezuela even as the country continues to fall apart. The oil major’s assets are no longer profitable, and the Wall Street Journal reports that the company is growing weary of the problems. In response to the article, Chevron denied the potential exit. “We’re committed to Venezuela and we plan to be there for many years to come,” Clay Neff, Chevron’s president for Africa and Latin America, said in an interview late Thursday with Bloomberg. The reporting that Chevron might pack up and leave “is not accurate.”
Natural gas prices up sharply. Natural gas prices jumped more than 7 percent on a single day this week, on reports that colder than normal weather is about to hit much of the country. Henry Hub prices jumped to $3.50/MMBtu, the highest level since January. With natural gas inventories at a 15-year low, the buffer the U.S. has heading into winter is unusually thin, which could heighten volatility during periods of abnormally cold weather over the next few months.
Keystone XL construction blocked by court. A U.S. federal court on Thursday blocked construction of the Keystone XL pipeline, ruling that the Trump administration failed to offer a sufficient justification for its approval. The Obama administration blocked the pipeline on grounds that the project’s negative impact on climate change was too large. In approving it quickly after coming to office, Trump did not offer an adequate justification. “The Department instead simply discarded prior factual findings related to climate change to support its course reversal,” a federal judge wrote in his decision.
Imperial Oil gives FID to oil sands project. Imperial Oil (NYSEAMERICAN: IMO) gave the go-ahead to a $2.6 billion bitumen project in Alberta, the first new oil sands project to receive a final investment decision since 2013. Construction on the 75,000-bpd project is set to begin this quarter, with first oil scheduled to come online in 2022. The project will also represent the first application of next-generation oil sands recovery technology. ExxonMobil (NYSE: XOM) is a majority owner of Imperial Oil.
Shale companies to pivot back to Permian. Carrizo Oil & Gas (NASDAQ: CRZO) is considering shifting oil rigs back to the Permian basin, just months after moving them elsewhere. Carrizo was forced to slow drilling plans this year due to pipeline bottlenecks, but the potential plans to add rigs back into the field suggests that the lull in the Permian could be nearing an end, Bloomberg reports.
Enbridge pipeline at risk after elections. Enbridge’s (NYSE: ENB) Line 5 pipeline, which ferries oil from Canada, through Michigan and into Ontario for refining, could come under political fire now that the state of Michigan has elected a governor opposed to the project. The aging 65-year-old pipeline, with a capacity of 540,000 bpd, presents an environmental risk to the Great Lakes and Michigan’s waterways, Governor-elect Gretchen Whitmer has argued. She has indicated that she might push for the pipeline’s closure. If it were shutdown, it would cause the discounts for Canadian oil to balloon.
Wind and solar cheaper than coal. Renewable energy has been gaining ground at the expense of coal for some time, but a new study estimates that wind and solar are not just cheaper than new coal plants, but actually cheaper than simply running existing coal plants. According to Lazard, the all-in levelized cost of electricity for wind ranges from US$29-$56 per megawatt hour, without subsidies. The marginal cost of merely running a coal plant is US$27-$45 per MWh. Wind competes without subsidies; with supports, it is far cheaper than existing coal plants.
Saudi think tank explores non-OPEC world. A Saudi think tank is undertaking a research study to explore the ramifications of a hypothetical scenario in which OPEC fell apart or was disbanded. It’s not that Riyadh is considering such a move, but they want to know what the consequences will be. “We’re looking at what happens if there’s no spare capacity,” Adam Sieminski, the former head of the U.S. EIA and who now heads up the King Abdullah Petroleum Studies and Research Center in Riyadh, told Bloomberg. “One scenario to that is OPEC doesn’t exist.”
China’s oil imports still strong. China imported a record volume of oil in October, dispelling fears that the Chinese economy is slowing down. China imported 9.61 million barrels per day in October, up an astounding 31.5 percent from a month earlier. However, some of the factors driving imports higher are temporary, such as the need to fill strategic storage, plus a one-off buying spree by small refiners who had quotas that were nearing expiration. Still, with China’s production gradually declining, and the economy still humming along, high demand is not going away.
Volf
09.11.2018 kl 21:57
1107
U.S. Shale Is Entering A Post-Expansionary Phase
US shale oil production has surged this year, underlining the short-cycle nature of the resource, but what goes up can come down. Shale oil production is much more responsive to price than the majority of conventional drilling and there are early indicators that recent output gains are already topping out.
Such has been the jump in production that the US Energy Information Administration (EIA) now predicts total US liquids supply this year of 17.83 million b/d, more than 1 million b/d higher than it forecast for 2018 a year ago, largely as a result of increased shale oil drilling.
The jump in US output, higher production from Saudi Arabia and Russia, Washington’s granting of sanctions waivers to key importers of Iranian crude and an increasingly gloomy economic outlook, have all served to take the heat out of the oil market.
The result has been the liquidation of long positions by hedge funds and traders, a drop in oil prices, and a softening of the market’s backwardated structure.
However, while US oil production may now be quicker to take advantage of high returns, that same short-cycle responsiveness also works in the opposite direction.
Coming in from the cold
Prior to the late-2000s, the oil majors at least saw the future as being offshore in ever deeper water and harsher environments. This would require big capital, long-lead times and expertise only they possessed.
The prospect of the marginal barrel taking around five years to come into production meant a reinforcement of the long-term cyclical nature of the oil market.
Given the potential for both demand and supply-side shocks, the only stabilising factor was the holding of spare capacity, a role taken on in theory by OPEC, but in practice by Saudi Arabia, and to a lesser extent commercial and strategic reserves, fostered by the International Energy Agency and supported by the governments of countries dependent on oil imports.
Independent US drillers, however, had other ideas. Shale, or Light Tight Oil (LTO) to give it its broader title, fundamentally altered this dynamic.
LTO meant new wells could be brought into production in weeks rather than years. Non-OPEC production capacity could even be stored in the form of uncompleted wells (DUCs) to be brought on-stream when prices or company requirements warranted. The marginal barrel had come onshore, and taken up residence in the shale plays of the US.
Short versus long-cycle dynamics
This meant the oil market would be governed by a new set of supply-side responses to price. Compare, for example, LTO with US offshore production.
When the oil price headed unrelentingly south from July 2014, it took only nine months before US LTO output started to contract, shrinking by about 800,000 bpd over the ensuing 18 months. The Gulf of Mexico by contrast saw a succession of major projects -- planned and costed in higher-priced times – coming on-stream, keeping production on a rising trend throughout the low oil price period.
WTI hit a nadir of close to $30/b in February 2016 before entering a new up cycle. The LTO response was again quick, taking just nine months for output to start rising in earnest, this time from a much lower cost base as a result not just of productivity gains, but the sharp fall in input costs brought about by the decline in oil prices and contraction in demand for oil services.
Legacy decline
But as prices soften, LTO’s unique short-term cyclical dynamic again comes to the fore. It concertinas not just the supply response to price but the decline rate.
LTO wells are most productive in the first months of their lives and then see a sharp decline with a long tail of relatively low output. As drilling activity rises and production ramps up, the legacy decline of existing wells also increases with a lag of about six months. However, when prices start to fall and drilling flattens off, that legacy decline is still building, following production like a billowing rain cloud.
The US Energy Information Administration’s October Drilling Productivity Report (DPR) predicts for November a production gain from new LTO drilling of 626,000 bpd offset by a legacy decline of 528,000 bpd to give a net add to output of 98,000 bpd.
In an expansionary phase, the net gain will build each month. However, the DPR figures suggests that the net gain from the seven major shale plays it considers peaked in May-June above 140,000 b/d. New production remains high, but has been broadly flat since May, while the legacy of earlier drilling continues to rise. In short, US shale has entered a post-expansionary phase in which net gains decelerate.
Cost pressures
This is not the only process under way.
In the expansionary phase, input costs – chemicals, fracking sand, rigs etc – generally rise as slack is taken out of the oil services market. Average day rates for high specification land rigs in the US, according to oil and gas portal Daleel, bottomed out at $21,000 in first-quarter 2017, but had risen to $23,000 by first-quarter 2018. Not a huge jump, and rates have stayed flat since then, but an indication of growing cost pressures.
These pressures are offset by productivity gains, but after rising fairly consistently, productivity took a dive in 2017, dropping in November of that year to an average 589 b/d per rig from 632 b/d in November 2016, according to the EIA. The good news is that shale drillers have reversed this trend, and new well oil production per rig was up at 668 b/d for November 2018. However, this represents just a 5.7% gain over two years, compared with a doubling of productivity between November 2014 and November 2016.
So the squeeze is there – falling returns from lower oil prices on the one hand, and higher input costs for drilling and completions on the other. While there is no single breakeven cost for shale wells, some of the least rewarding prospects will start to drop off the bottom of the balance sheet. If the squeeze gets tighter, the stock of DUCs is likely to rise, and the legacy decline of the expansionary phase will eat further into new drilling, reducing the net gains.
The expansionary phase should take another 9 months or so to move from deceleration to actual contraction, if prices continue to weaken, so further output gains will be made as we move into 2019. This presents a massive dilemma for OPEC and Russia because any action to reign in supply and support prices will only serve to put the lead back in US producers’ drills.
US shale oil production has surged this year, underlining the short-cycle nature of the resource, but what goes up can come down. Shale oil production is much more responsive to price than the majority of conventional drilling and there are early indicators that recent output gains are already topping out.
Such has been the jump in production that the US Energy Information Administration (EIA) now predicts total US liquids supply this year of 17.83 million b/d, more than 1 million b/d higher than it forecast for 2018 a year ago, largely as a result of increased shale oil drilling.
The jump in US output, higher production from Saudi Arabia and Russia, Washington’s granting of sanctions waivers to key importers of Iranian crude and an increasingly gloomy economic outlook, have all served to take the heat out of the oil market.
The result has been the liquidation of long positions by hedge funds and traders, a drop in oil prices, and a softening of the market’s backwardated structure.
However, while US oil production may now be quicker to take advantage of high returns, that same short-cycle responsiveness also works in the opposite direction.
Coming in from the cold
Prior to the late-2000s, the oil majors at least saw the future as being offshore in ever deeper water and harsher environments. This would require big capital, long-lead times and expertise only they possessed.
The prospect of the marginal barrel taking around five years to come into production meant a reinforcement of the long-term cyclical nature of the oil market.
Given the potential for both demand and supply-side shocks, the only stabilising factor was the holding of spare capacity, a role taken on in theory by OPEC, but in practice by Saudi Arabia, and to a lesser extent commercial and strategic reserves, fostered by the International Energy Agency and supported by the governments of countries dependent on oil imports.
Independent US drillers, however, had other ideas. Shale, or Light Tight Oil (LTO) to give it its broader title, fundamentally altered this dynamic.
LTO meant new wells could be brought into production in weeks rather than years. Non-OPEC production capacity could even be stored in the form of uncompleted wells (DUCs) to be brought on-stream when prices or company requirements warranted. The marginal barrel had come onshore, and taken up residence in the shale plays of the US.
Short versus long-cycle dynamics
This meant the oil market would be governed by a new set of supply-side responses to price. Compare, for example, LTO with US offshore production.
When the oil price headed unrelentingly south from July 2014, it took only nine months before US LTO output started to contract, shrinking by about 800,000 bpd over the ensuing 18 months. The Gulf of Mexico by contrast saw a succession of major projects -- planned and costed in higher-priced times – coming on-stream, keeping production on a rising trend throughout the low oil price period.
WTI hit a nadir of close to $30/b in February 2016 before entering a new up cycle. The LTO response was again quick, taking just nine months for output to start rising in earnest, this time from a much lower cost base as a result not just of productivity gains, but the sharp fall in input costs brought about by the decline in oil prices and contraction in demand for oil services.
Legacy decline
But as prices soften, LTO’s unique short-term cyclical dynamic again comes to the fore. It concertinas not just the supply response to price but the decline rate.
LTO wells are most productive in the first months of their lives and then see a sharp decline with a long tail of relatively low output. As drilling activity rises and production ramps up, the legacy decline of existing wells also increases with a lag of about six months. However, when prices start to fall and drilling flattens off, that legacy decline is still building, following production like a billowing rain cloud.
The US Energy Information Administration’s October Drilling Productivity Report (DPR) predicts for November a production gain from new LTO drilling of 626,000 bpd offset by a legacy decline of 528,000 bpd to give a net add to output of 98,000 bpd.
In an expansionary phase, the net gain will build each month. However, the DPR figures suggests that the net gain from the seven major shale plays it considers peaked in May-June above 140,000 b/d. New production remains high, but has been broadly flat since May, while the legacy of earlier drilling continues to rise. In short, US shale has entered a post-expansionary phase in which net gains decelerate.
Cost pressures
This is not the only process under way.
In the expansionary phase, input costs – chemicals, fracking sand, rigs etc – generally rise as slack is taken out of the oil services market. Average day rates for high specification land rigs in the US, according to oil and gas portal Daleel, bottomed out at $21,000 in first-quarter 2017, but had risen to $23,000 by first-quarter 2018. Not a huge jump, and rates have stayed flat since then, but an indication of growing cost pressures.
These pressures are offset by productivity gains, but after rising fairly consistently, productivity took a dive in 2017, dropping in November of that year to an average 589 b/d per rig from 632 b/d in November 2016, according to the EIA. The good news is that shale drillers have reversed this trend, and new well oil production per rig was up at 668 b/d for November 2018. However, this represents just a 5.7% gain over two years, compared with a doubling of productivity between November 2014 and November 2016.
So the squeeze is there – falling returns from lower oil prices on the one hand, and higher input costs for drilling and completions on the other. While there is no single breakeven cost for shale wells, some of the least rewarding prospects will start to drop off the bottom of the balance sheet. If the squeeze gets tighter, the stock of DUCs is likely to rise, and the legacy decline of the expansionary phase will eat further into new drilling, reducing the net gains.
The expansionary phase should take another 9 months or so to move from deceleration to actual contraction, if prices continue to weaken, so further output gains will be made as we move into 2019. This presents a massive dilemma for OPEC and Russia because any action to reign in supply and support prices will only serve to put the lead back in US producers’ drills.