Easwaran Kanason

Co - founder of PetroEdge
Last Updated: January 1, 2017
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Business Trends
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Oil in 2017

With OPEC defying the pessimists and actually agreeing on a production freeze, oil prices have rallied. Will this be a good sign as we enter into 2017? The World Bank predicts that oil prices would average US$53-55/b over 2017, a sentiment echoed by the EIA in the US. Both have no issued new forecasts since OPEC’s agreement to slash production by 1.2 mb/d, but it is likely that the target range has now shifted to the a range of US$60-65/b.

With Saudi Arabia already informing its customers of cuts in their January 2017 deliveries, it seems there is will enough within OPEC to follow through on the agreement. The issue now moved from agreement to enforcement, and therein lies some thorns. Historically, the Gulf state – Saudi Arabia, UAE and Kuwait – have been the most disciplined in enforcing cuts, with members elsewhere – Venezuela, Ecuador and Angola – more likely to discreetly flout the quotas. OPEC is also meeting with some non-OPEC producers in Vienna this week to see if consensus can be made on non-OPEC cuts; Russia has publically agreed to a 300 kb/d cut (with caveats, of course), and OPEC says a non-OPEC cut of 600 kb/d is a ‘must.’

This might be an issue in the US, particularly with the new Trump administration that wishes to encourage drilling. While oil prices rose immediately in the wake of the OPEC announcement, they fell back quickly again as US oil production announced a weekly increase. The Baker Hughes survey of active oil rigs in the US has risen to its highest weekly level in almost a year, as onshore producers restarted rigs in response to higher price signal. From US$55/b last Thursday, crude oil prices are now in the low US$50s. Donald Trump’s provisional cabinet is full of climate skeptics and energy bulls and he has named Scott Pruitt as the head of the new American Environmental Protection Agency, with the fossil fuel industry ally is likely to call for further deregulation in American hydrocarbons. With Keystone XL back as a possibility and longer-term moves to open up drilling in new areas like the Arctic likely, it could unleash a new wave of oil in the market depressing prices. The US under Trump is not going to agree to any supply cuts, which may very well defeat the entire purpose of the OPEC exercise. Saudi Arabia’s attempt to wipe up US shale oil by keeping prices down has only kept the shale producers at bay, who will return once prices hit a decent level. This ebb and flow will persist, and we believe a general oversupply will endure.

Here’s our prediction. The OPEC quotas will hold, but the cuts will not be as deep as envisioned because some members – especially Iran – will take advantage of the situation to sneak extra sales. The big producers – Russia, Saudi Arabia, Iraq and Iran will focus on relative pricing to defend their market share. American production will continue to be nimbly driven by price signals, balancing out the cuts elsewhere. Oil prices will strengthen – probably to the US$55-60/b level – which is a good place to be, all things considered. It won’t be the dramatic recovery that many will hope for, but it won’t be a complete collapse either, and in this environment that’s good enough already.

Natural Gas in 2017

With OPEC and a group of major non-OPEC producers coming together to agree on shave up to 1.8 mb/d in their oil production, it is a rising tide that will lift all other energy commodities. This includes natural gas, once the red-headed cousin of oil but now a crowning beauty of its own.

In the natural gas space, this will lead to higher prices for pipeline gas, rising slightly from prices that are already relatively cheap. With a cold winter expected, natural gas demand will be high in the northern hemisphere as well, while domestic consumption in both Europe and the US is on a steady growth trend. However, the bigger impact will be in the LNG space.

On the LNG side, higher crude prices means higher LNG prices. Spot prices in Asia have already hit US$8.10/mmbtu in the last week, the highest since mid-2015, due to the OPEC agreement and cold weather in north Asia and Europe. LNG, though, is a contract market. It is estimated that some 80% of LNG sold in the world in based on long-term contracts linked to oil. Typically a function of oil, indexation may vary but the general rule of thumb is that a US$1/b increase leads to a US$0.07-0.15/mmbtu increase in oil-indexed LNG contract prices. But those are for existing contracts, inherited from the days when the seller was king and could command all sorts of price structures – S-curves, for example - to benefit them. Today, that is a thing of the past. With the glut of LNG currently existing and more still to come – Wheatstone and Gorgon in Australia being the two big ones in 2017 – LNG has been a buyer’s market for the last two years And the buyers are getting bolder.

Specifically, the Japanese buyers are getting bolder. If 2015 and 2016 were the years when Japanese buyers realised that a low price environment gave them far more clout, 2017 will be the year when they begin to assert themselves. Moves towards this are already happening. Japan is trying to render location destination clauses in existing long-term LNG contracts void through anti-competitive laws, which would free Japan buyers like Tokyo Gas and Chubu Electric to swap and re-route cargoes, instead of being locked into specific ports. Newer contracts will probably have to do away with the clauses altogether. This creates a more dynamic environment where buyers can move their LNG cargoes around based on supply and demand, effectively becoming traders. It is a step towards creating an Asia trading hub for LNG, with Singapore having already developed its own sport LNG price assessments and agreeing to work with Japan to possibly create a Singapore-Japan benchmark. China and Korea, both large LNG consumers as well, have also launched attempts of their own, with the Shanghai gas derivatives exchange starting up last month. Efforts towards this will continue, and 2017 will see a more vibrant LNG trading market.

Looking ahead, there is so much LNG coming onto the market that it is almost a tsunami. Canada’s projects on the BC Pacific Coast. The US Gulf of Mexico projects, with the newly-expanded Panama Canal as a conduit. The vast projects off Western Australia. Plenty of supply coming from Mozambique and Papua New Guinea as well. All of these volumes will be chasing Asian clients. LNG will be a buyer’s market for a long time to come, and 2017 will be the year that companies, utilities and governments will step up to expand and create infrastructure to support a gas-rich future.

Downstream Oil in 2017

The upstream portion of the oil industry is ending the year on a bit of a cheer, with rallying crude prices. In the downstream section, however, it has been a challenging year and 2017 repeats the same situation as 2016.

Looking specifically at Asia, refined oil product demand is slowing down. Part of this is due to the natural decline in Japan and South Korea, and part of this is due to a natural deceleration in China, where annual growth rates at 9-10% could never be sustained indefinitely. Demand growth in India and developing economies is improving, but years of high oil prices have pushed their infrastructure in different directions, not necessarily to the benefit of oil, even in a lower price environment.

Even if there is good demand growth, not all of it will benefit refineries. One bright spark in the downstream arena has been petrochemicals, with countries like China still adding capacity. Traditionally, these have depended on naphtha as their feedstock – hence the trend over the past decade for integrated refinery-petchem facilities. US shale gas remains a gamechanger here. There is so much ethane (and to a lesser extent, LPG liquids propane and butane) coming out of the US that prices are low and petrochemical operations in Asia are reconfiguring to focus on natural gas liquids as feedstock. BP estimates that a third of global downstream demand growth may bypass refineries altogether, placing further pressure on refineries.

This is not good for refiners. In general, refined oil product cracks in Asia have been at historical lows in 2016, thought there are few bright spots like naphtha. Though this will ebb and flow depending on shortages and seasonal demand, the overall trend is shrinking cracks. Cheap oil prices have not caused an equivalent surge in Asian oil demand. In fact, there is simply too much product sloshing around the market. This is been exacerbated in 2016 when Chinese independent refiners – the teapots – were granted licences to import crude for the first time, leading to them raising runs to records levels and lifting Chinese exports. Far from being a ‘sink’ for refined products, China is now becoming a net exporter. However, in a move last week, China removed export quotas for the teapots, effectively preventing them from exporting any of their products. Their import licences may still be held steady, but the teapots will now have to consider the limited domestic market when planning runs. This could improve the supply glut in Asia somewhat, but traditional product ‘sinks’ are evolving on their own.

Vietnam’s second refinery, Nghi Son, is supposed to start up in mid-2017. It will face delays. And if Dong Quat is any precedent, Nghi Son will face production troubles in its first year. So Vietnam will remain a reliable product ‘sink’ in 2017, but this will dissipate when Nghi Son comes onstream. India, where oil product growth has been strong this year, will also absorb major amounts of products, but the Indian refiners – IOC, BPCL and HPCL – all have extensive capacity upgrade plans over the next five years, removing this window. Indonesia continues to claim ambitious refining plans that could potentially eliminate the need for imports, but it has been spouting this line for a decade now and there seems to be little movement beyond announcement in this arena, leaving Indonesia a large ‘sink’ for the time being. But Indonesian oil product specs are generally lower than the average Asian standards, limiting the refineries it can buy product from. There will be growth else – notably Myanmar and Bangladesh – but this will be unable to offset the declines in Japan and South Korea.

This is a death knell for major export-oriented refinery projects in Asia. Projects like Petronas’ RAPID in Malaysia, due for startup in 2019, will go ahead, but fewer will make it off the drawing board. New refineries will be contained to net importer countries, as they try to reduce their import burden, as we have seen this year in Pakistan, Uganda and Middle East countries moving up the value chain. Product demands will also continue to move up the barrel, placing more pressure on simple, topping refineries. 2016 saw a slew of refinery sales and closures in Europe – even low oil prices couldn’t help a determined structural trend – and that is a likely future for Asian downstream. There will be no major surprised downstream in 2017, just confirmation of ongoing trends.

Corporate Oil in 2017

Rex Tillerson, head of ExxonMobil since 2006, is packing his bags and heading to the White House to serve as Donald Trump’s Secretary of State. As part of his job, he will be jetting around the world promoting American interests. That’s not much different in scope from his current position, except that corporate deal-making is very different from diplomacy.

It’s an indication that 2017 will be a pivot away from prevailing corporate trends in the energy business. Under Tillerson, US ties with Russia are likely to get closer, as the Trump administration places business and capitalist interests above issues such as healthcare, environment and social justice that have taken the forefront. Tillerson will pass his seat to Darren Woods, the current head of refining at ExxonMobil, with the company likely to be the only one that will pursue a diversified strategy among the supermajors. Under Woods, ExxonMobil’s refining arm has remained strong despite low margins, having already embarked on a divestment drive that saw the company dispose of peripheral assets in marginal markets.

ExxonMobil, like Shell and Chevron, will remain global brands. But the assets will no longer be controlled by them. Shell has been following ExxonMobil’s move, selling its downstream and upstream assets globally to pay for its pricey acquisition of the BG Group. Natural gas and chemicals are in Shell’s future, with downstream now of lesser concern; Shell, like ExxonMobil in Latin America, will now merely licences its name to third-party players. BP has already done the same over the last decade, with its logo now a rarity in retail across the world, though oddly enough it is tying up with Reliance in India. Chevron’s divestment extends further than downstream, moving into smaller-scale upstream assets, with its attempt to exit Bangladesh and Thailand in recent months. 2016 has been a year of divestments and debt-paring among the supermajors as they seek to become leaner and meaner, just like Petrobras, though for completely different reasons. Meanwhile, France’s Total still has ambitions of being a global behemoth that the supermajors once were, picking up assets in Asia and Africa. This will continue in 2017, with the directions clear. Shell to natural gas and chemicals, BP to LNG, Chevron to large-scale upstream and ExxonMobil everywhere, with top priority to sort out its acquisition of InterOil in PNG.

The vacuum left by the supermajors particularly in downstream has been picked up by global traders. Players like Vitol, Glencore and Gunvor have been extending their trading empires to actual retail participation since 2013, and the move will continue in 2017. Some might even try to set up brands of their own, instead of piggy-backing on existing ones (and their associated licensing fees).

Meanwhile, the national counterparts of the supermajors, the major NOCs, will still find 2017 a challenging year. Oil prices have risen, but nowhere near the level that required to balance national budgets. Saudi Aramco and to a lesser extent Adnoc and KPC have the reserves to see through the storm, but PDVSA is in trouble. Iraq and Iran will flout OPEC supply quotas to sneak a few extra sales to resume what they see as their rightful position, while Libya tries to rebuild its infrastructure and Nigeria tries its hand at privatisation. Indonesia’s Pertamina will continue to flounder in too many directions, Malaysia’s Petronas will remain weak and Brazil’s Petrobras will continue its fire sale to reduce its huge debts. China’s triad – PetroChina, Sinopec and CNOOC – will continue to extend their tendrils oversees, while Japan’s bloated energy sector will try to consolidate. And largely fail, resulting in a friendly informal cooperation instead. Russia has a lot of debt issues simmering under Putin’s bluster. India’s state players are probably in the best position, where energy demand is sprinting ahead.

Higher crude oil prices will be a good way to start off 2017 for most energy companies; but there’s still a lot of work to be done. Much like the global political landscape, corporate energy players will become more insular, focusing on specific areas of profit instead of a broad-based strategy. The notion of an integrated player with tentacles in every pie is over. With the possible exception of ExxonMobil.

Have a productive year ahead!

 

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Your Weekly Update: 10 - 14 June 2019

Market Watch

Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b

  • With US’s trade and tariff assault abating for the moment, crude oil prices have consolidated their trends to steady up as OPEC+ nations signal their desire to continue stabilising the oil market ahead of a June 25 meeting in Vienna
  • Despite some background squabbles between Russia and Saudi Arabia – with Russia at pains to emphasise its position regarding lower oil prices – the group has seemingly come together
  • Saudi Arabia has reportedly corralled the OPEC group to agreeing to extending the current supply deal to December, even Iran, but convincing Russia has been a harder task and adherence may continue to be an issue
  • Meanwhile, the US continues to tighten the screws on Venezuela and Iran, announcing sanctions on Iranian petrochemicals exports and targeting Venezuela’s trade in diluents that are used to blend heavy crude down
  • With reports that Iranian crude exports were down to an estimated 400 kb/d in May, tensions in the Persian Gulf continue with the latest incident being attacks on tankers; this risk factor will lift the floor for oil prices for now
  • After a brief rise last week, American drillers dropped 11 oil rigs but added 2 gas rigs according to Baker Hughes for a net loss of 9 active sites, bringing the total active rig count down to 975
  • As OPEC prepares to meet, the market has seemingly locked in an extension of the supply deal into projections, which will leave little room for gains; expect Brent to fall to the US$60-62/b range and WTI to trade at US$51-53/b

Headlines of the week

Upstream

  • BP is selling its stakes in its Egyptian concessions in the Gulf of Suez to Dubai-based Dragon Oil (a subsidiary of ENOC), which do not include BP’s core production assets in the West Nile Delta production area
  • Eni’s African streak continues with its fifth oil discovery in Angola’s Block 15/06 at the Agidigbo prospect, bringing total resources to 1.8 billion barrels
  • Also in Angola, ExxonMobil and its partners are looking to invest further in offshore Block 15 that will see Sonangol take a 10% interest in the PSA
  • Russia’s Lukoil has inked a deal with New Age M12 Holding to acquire a 25% interest in the offshore Marine XII licence in the Republic of Congo for US$800 million, covering the producing Nene and Litchendjili fields
  • Buoyed by recent discoveries in the Caribbean, the Dominican Republic is launching its first licensing round in July, offering 14 blocks in the onshore Cibao, Enriquillo and Azua basins and the offshore San Pedro basin
  • W&T Offshore and Kosmos Energy have struck oil in the Gladden Deep well in the US Gulf of Mexico, the first of a four-well programme that includes the Moneypenny, Oldfield and Resolution prospects with estimates of 7 mmboe

Midstream & Downstream

  • Shell is increasing storage capacity at its Pulau Bukom refinery in Singapore, adding two new crude oil tanks to increase capacity by nearly 1.3 million barrels
  • A new swathe of American sanctions against Iran is now targeting Iranian petrochemical exports, clipping a major regional revenue source for Iran
  • Angola is looking overhaul its refining sector, by attracting investment o overhaul facilities and building a new refinery in Soyo that will be the third ongoing refining project after the 200 kb/d Lobito and Cabinda plants
  • BP and Mexico’s IEnova have signed a deal allowing BP to use IEnova’s new gasoline and diesel storage and distribution facilities in Manzanillo and Guadalajara, allowing access to over 1 million barrels of storage
  • British petrochemicals firm INEOS has announced plans to invest US$2 billion in building three new petchem plants in Saudi Arabia that would form part of the wider Saudi Aramco-Total Project Amiral petrochemicals complex
  • The saga of Russia’s bankrupt 180 kb/d Antipinsky refinery continues, with SOCAR Energoresurs (a JV including Sberbank) acquiring an 80% stake in the refinery with the aim of restarting operations
  • Mexico has kicked off construction of its US$7.7 billion oil refinery, aimed to overhauling the Mexican refining industry after years of underperformance

Natural Gas/LNG

  • Toshiba is exiting the Freeport LNG project in Texas, paying Total US$815 million and handing over its 20-year liquefaction rights by March 2020
  • China’s CNOOC has officially acquired a 10% stake in the Arctic LNG 2 project by Novatek, solidifying natural gas ties between Russia and China
  • Cheniere has taken FID to add a sixth liquefaction train to its Sabine Pass export project in Lousiaina, which would add 4.5 mtpa of capacity to the plant
  • Novatek, Sinopec and Gazprombank have created a China-focused joint venture to market LNG and natural gas from Novatek’s Arctic projects in China
June, 17 2019
Upcoming OPEC Meeting: What to Expect

A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.

That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.

That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.

Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.

Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?

Expectations at the 176th OPEC Conference

  • 25 June 2019, Vienna, Austria
  • Extension of current OPEC+ supply deal from end-June 2019 to end-December 2019
June, 12 2019
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • Brent crude oil spot prices averaged $71 per barrel (b) in May, largely unchanged from April 2019 and almost $6/b lower than the price in May of last year. However, Brent prices fell sharply in recent weeks, reaching $62/b on June 5. EIA forecasts Brent spot prices will average $67/b in 2019, $3/b lower than the forecast in last month’s STEO, and remain at $67/b in 2020. EIA’s lower 2019 Brent price path reflects rising uncertainty about global oil demand growth.
  • EIA forecasts global oil inventories will decline by 0.3 million barrels per day (b/d) in 2019 and then increase by 0.3 million b/d in 2020. Although global liquid fuels demand outpaces supply in 2019 in EIA’s forecast, global liquid fuels supply is forecast to rise by 2.0 million b/d in 2020, with 1.4 million of that growth coming from the United States. Global oil demand rises by 1.4 million b/d in 2020 in the forecast, up from expected growth of 1.2 million b/d in 2019.
  • Annual U.S. crude oil production reached a record 11.0 million b/d in 2018. EIA forecasts that U.S. production will increase by 1.4 million b/d in 2019 and by 0.9 million b/d in 2020, with 2020 production averaging 13.3 million b/d. Despite EIA’s expectation for slowing growth, the 2019 forecast would be the second-largest annual growth on record (following 1.6 million b/d in 2018), and the 2020 forecast would be the fifth-largest growth on record.
  • For the 2019 summer driving season, which runs from April through September, EIA forecasts that U.S. regular gasoline retail prices will average $2.76 per gallon (gal), down from an average of $2.85/gal last summer. The lower forecast gasoline prices primarily reflect EIA’s expectation of lower crude oil prices this summer.

U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

World liquid fuels production and consumption balance


Natural gas

  • The Henry Hub natural gas spot price averaged $2.64/million British thermal units (MMBtu) in May, almost unchanged from April. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019. EIA expects Henry Hub natural gas spot prices will average $2.77/MMBtu in 2019, down 38 cents/MMBtu from 2018. EIA expects natural gas prices in 2020 will again average $2.77/MMBtu.
  • EIA forecasts that U.S. dry natural gas production will average 90.6 billion cubic feet per day (Bcf/d) in 2019, up 7.2 Bcf/d from 2018. EIA expects natural gas production will continue to grow in 2020, albeit at a slower rate, averaging 91.8 Bcf/d next year.
  • U.S. natural gas exports averaged 9.9 Bcf/d in 2018, and EIA forecasts that they will rise by 2.5 Bcf/d in 2019 and by 2.9 Bcf/d in 2020. Rising exports reflect increases in liquefied natural gas exports as new facilities come online. Rising natural gas exports are also the result of an expected increase in pipeline exports to Mexico.
  • EIA estimates that natural gas inventories ended March at 1.2 trillion cubic feet (Tcf), 15% lower than levels from a year earlier and 28% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections will outpace the previous five-year average during the 2019 April-through-October injection season and that inventories will reach almost 3.8 Tcf at the end of October, which would be 17% higher than October 2018 levels and about equal to the five-year average.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants to rise from 35% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts that the share of generation from coal will average 24% in 2019 and 23% in 2020, down from 27% in 2018. The forecast nuclear share of generation falls from 20% in 2019 to 19% in 2020, reflecting the retirement of some nuclear reactors. Hydropower averages a 7% share of total generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided 10% of U.S. generation in 2018. EIA expects they will provide 11% in 2019 and 13% in 2020.
  • EIA forecasts that renewable fuels, including wind, solar, and hydropower, will collectively produce 18% of U.S. electricity in 2019 and almost 20% in 2020. EIA expects that annual generation from wind will surpass hydropower generation for the first time in 2019 to become the leading source of renewable electricity generation and maintain that position in 2020.
  • EIA forecasts that U.S. coal consumption, which reached a 39-year low of 687 million metric tons (MMst) in 2018, will fall to 602 MMst in 2019 and to 567 MMst in 2020. The falling consumption reflects lower demand for coal in the electric power sector.
  • After rising by 2.7% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 2.0% in 2019 and by 0.9% in 2020. EIA expects U.S. CO2 emissions will fall in 2019 and in 2020 because its forecast assumes that temperatures will return to near normal, and because the forecast share of electricity generated from natural gas and renewables increases while the forecast share generated from coal, which produces more CO2 emissions, decreases. Energy-related CO2 emissions are sensitive to weather, economic growth, energy prices, and fuel mix.

U.S. natural gas prices


U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

June, 12 2019