Thursday, February 1, 2018
S&P Global Platts writes that while concerns remain with respect to the response of U.S. shale oil to higher prices, the shale hype seems to be over, with CEOs and management teams being held strongly accountable to deliver positive cash flow over production growth even with oil prices above $60/bbl.
“Planned capital investments across oil over the next couple of years of around $300 billion show that the industry is not under investing and is on target,” says Chris Midgley, global head of analytics at S&P Global Platts. “However, these new projects will not emerge until well into the 2020s and in the short term—2019-2021—it would appear that we might be heading toward a period of supply tightness and will be relying on U.S. onshore shale to respond to fill the gap.” In addition, he notes the World Bank’s announcement that it will stop financing most upstream oil and gas projects after 2019 may have a significant impact on new projects.
The consultancy comments that global oil market rebalancing accelerated in 2017 with surplus stocks falling 1 MMbbld during the course of the year, virtually eliminating the entire overhang. Strong oil demand growth and the OPEC/non-OPEC cuts were the key factors driving the inventory decline. Further, 2018 will see global supply, led by U.S. shale, grow faster than demand; but stocks will still decline, supporting oil market backwardation and relatively strong nominal prices.
With strong demand growth and ongoing refinery capacity limitations expected to continue in 2018, refinery margins will stay strong with healthy gasoline cracks, higher distillate cracks, and ongoing firmness in heavy fueloil cracks. U.S. crude oil exports will increase further, with coastal grades continuing to price in export parity. But West Texas Intermediate (Cushing, Okla.) price differentials versus coastal grades and Brent will be firmer in the first quarter of this year, with new pipelines starting up that will allow excess inland crude stocks to decline.
Regarding the outlook for national gas, Midgley comments, “New production, particularly in the Permian, has increasing associated gas, putting downward pressure on Henry Hub prices. Meanwhile, growing exports of U.S. LNG connect Japan-Korea Marker prices in Asia back to the U.S., which in turn now have to compete with carbon-adjusted coal import prices to China as the market becomes increasingly liquid and less reliant on long-term contracts.”
He adds that the development of new LNG liquefaction remains caught between producers wanting to sign long-term contracts in order to secure financing and consumers wanting maximum buying flexibility and showing little interest in making such a commitment. As well, an aggressive shift in Chinese policy toward rapidly improving air quality has led to a major uptick in seasonal LNG buying patterns, where price is seemingly no object.
Qatar’s lifting of its gas development moratorium triggered a wakeup call to competitors that lowering LNG costs will be necessary to compete. Like the Saudis, Qatar is concerned that the value of its assets in the ground has peaked, so the impetus for delaying development is no longer in place. The onslaught of new LNG supply arriving in 2018 will test the market’s ability to consume or store it during the second and third quarter of the year without a major reduction in price.
At the same time, Japan’s massive increase in LNG contract obligations will create a choice for its buyers: either force-burn LNG at the expense of coal, oil, and additional nuclear restart delays, or push large unsold volumes back into the spot market.
Qatar will offer to adapt spot pricing to such points as Japan-Korea Marker, Dutch Title Transfer Facility, and Virtual Trading Point as its new Asian and European standards, this as its legacy oil-indexed contracts begin to roll off heavily in 2022.
Looking at petrochemicals and NGLs, Midgley observes that crude oil demand is increasingly being substituted by other liquids such as biofuels, NGLs, and LNG, resulting in the call on refining being significantly depressed compared with the growing demand for liquid oil products. “Ethane has become the chameleon of the hydrocarbons, either appearing or being accounted as gas if rejected into natural gas, or being treated as a liquid if used as a chemical feedstock, thus creating the connection between oil and gas prices through chemical cracker feed optimization.”
Petrochemical feedstocks will continue to outpace the growth of other hydrocarbons, and will be the fastest-growing sector in 2017 and 2018. Total world ethylene cracker capability has been on the rise over the past several years. The capacity growth in 2017 was a high of 7.9 million metric tons, or 4.7% of world capacity. Expansions in 2017 were primarily in the U.S., China, and South Asia.
Finally, S&P Global Platts saw coal bouncing back last year. Coal demand surged in several markets around the world in 2017. From unwinding of coal-to-gas switching in the U.S., to sizeable overall energy demand growth in China, to underperforming nuclear generation, coal was generally the fuel of choice to meet incremental fossil fuel demand in the power sector outside of Europe. However, President Trump’s support for the U.S. coal industry did not move the needle, despite promises to the contrary.
Coal demand is seen as decelerating in 2018, led by China. A combination of surging renewable generation and a clean-air policy will reduce China’s coal consumption, which will have an outsized bearish impact on the global coal market. Recovering nuclear output in Europe and Asia will also serve to constrain coal-fired generation. Also, 2018 could be the first year of coal-to-gas switching in Asia. With surging LNG supply from the U.S. and Australia, coupled with sizeable growth in contracted LNG supply into Japan and South Korea, there are risks that excess gas supply will need to be disposed of in the power sector at the expense of coal.
(SOURCE: The Weekly Propane Newsletter, January 29, 2018. Click subscriptions to subscribe for once or twice weekly updates.)
“Planned capital investments across oil over the next couple of years of around $300 billion show that the industry is not under investing and is on target,” says Chris Midgley, global head of analytics at S&P Global Platts. “However, these new projects will not emerge until well into the 2020s and in the short term—2019-2021—it would appear that we might be heading toward a period of supply tightness and will be relying on U.S. onshore shale to respond to fill the gap.” In addition, he notes the World Bank’s announcement that it will stop financing most upstream oil and gas projects after 2019 may have a significant impact on new projects.
The consultancy comments that global oil market rebalancing accelerated in 2017 with surplus stocks falling 1 MMbbld during the course of the year, virtually eliminating the entire overhang. Strong oil demand growth and the OPEC/non-OPEC cuts were the key factors driving the inventory decline. Further, 2018 will see global supply, led by U.S. shale, grow faster than demand; but stocks will still decline, supporting oil market backwardation and relatively strong nominal prices.
With strong demand growth and ongoing refinery capacity limitations expected to continue in 2018, refinery margins will stay strong with healthy gasoline cracks, higher distillate cracks, and ongoing firmness in heavy fueloil cracks. U.S. crude oil exports will increase further, with coastal grades continuing to price in export parity. But West Texas Intermediate (Cushing, Okla.) price differentials versus coastal grades and Brent will be firmer in the first quarter of this year, with new pipelines starting up that will allow excess inland crude stocks to decline.
Regarding the outlook for national gas, Midgley comments, “New production, particularly in the Permian, has increasing associated gas, putting downward pressure on Henry Hub prices. Meanwhile, growing exports of U.S. LNG connect Japan-Korea Marker prices in Asia back to the U.S., which in turn now have to compete with carbon-adjusted coal import prices to China as the market becomes increasingly liquid and less reliant on long-term contracts.”
He adds that the development of new LNG liquefaction remains caught between producers wanting to sign long-term contracts in order to secure financing and consumers wanting maximum buying flexibility and showing little interest in making such a commitment. As well, an aggressive shift in Chinese policy toward rapidly improving air quality has led to a major uptick in seasonal LNG buying patterns, where price is seemingly no object.
Qatar’s lifting of its gas development moratorium triggered a wakeup call to competitors that lowering LNG costs will be necessary to compete. Like the Saudis, Qatar is concerned that the value of its assets in the ground has peaked, so the impetus for delaying development is no longer in place. The onslaught of new LNG supply arriving in 2018 will test the market’s ability to consume or store it during the second and third quarter of the year without a major reduction in price.
At the same time, Japan’s massive increase in LNG contract obligations will create a choice for its buyers: either force-burn LNG at the expense of coal, oil, and additional nuclear restart delays, or push large unsold volumes back into the spot market.
Qatar will offer to adapt spot pricing to such points as Japan-Korea Marker, Dutch Title Transfer Facility, and Virtual Trading Point as its new Asian and European standards, this as its legacy oil-indexed contracts begin to roll off heavily in 2022.
Looking at petrochemicals and NGLs, Midgley observes that crude oil demand is increasingly being substituted by other liquids such as biofuels, NGLs, and LNG, resulting in the call on refining being significantly depressed compared with the growing demand for liquid oil products. “Ethane has become the chameleon of the hydrocarbons, either appearing or being accounted as gas if rejected into natural gas, or being treated as a liquid if used as a chemical feedstock, thus creating the connection between oil and gas prices through chemical cracker feed optimization.”
Petrochemical feedstocks will continue to outpace the growth of other hydrocarbons, and will be the fastest-growing sector in 2017 and 2018. Total world ethylene cracker capability has been on the rise over the past several years. The capacity growth in 2017 was a high of 7.9 million metric tons, or 4.7% of world capacity. Expansions in 2017 were primarily in the U.S., China, and South Asia.
Finally, S&P Global Platts saw coal bouncing back last year. Coal demand surged in several markets around the world in 2017. From unwinding of coal-to-gas switching in the U.S., to sizeable overall energy demand growth in China, to underperforming nuclear generation, coal was generally the fuel of choice to meet incremental fossil fuel demand in the power sector outside of Europe. However, President Trump’s support for the U.S. coal industry did not move the needle, despite promises to the contrary.
Coal demand is seen as decelerating in 2018, led by China. A combination of surging renewable generation and a clean-air policy will reduce China’s coal consumption, which will have an outsized bearish impact on the global coal market. Recovering nuclear output in Europe and Asia will also serve to constrain coal-fired generation. Also, 2018 could be the first year of coal-to-gas switching in Asia. With surging LNG supply from the U.S. and Australia, coupled with sizeable growth in contracted LNG supply into Japan and South Korea, there are risks that excess gas supply will need to be disposed of in the power sector at the expense of coal.
(SOURCE: The Weekly Propane Newsletter, January 29, 2018. Click subscriptions to subscribe for once or twice weekly updates.)
