OPEC still needs Russia to prop up oil markets, but the arguments for an even closer relationship with the cartel are weakening.
The Kremlin’s two-year-long alliance with the 14-member group has been useful up to a point. On the one hand, oil diplomacy has helped to bolster President Vladimir Putin’s growing regional ambitions in the wider Middle East. On the other, Russia’s economy has also benefited from higher prices buffing up Putin’s financial credentials and popularity at home.
Russia’s oil minister and Putin loyalist Alexander Novak is an advocate of the OPEC deal. He said this week oil prices would have dropped to levels below the $27/barrel recorded in 2016 without his country’s commitment to the group’s cuts and pledged his ongoing support for cooperation on supply. It’s a view not necessarily shared by everyone in Russia. Rosneft’s chief executive Igor Sechin has previously been a powerful critic of working with the cartel.
“Reports this week indicate that the head of Rosneft continues to oppose ceding market share to the US, which may echo the opinion of others in the oil industry,” said Paul Sheldon, S&P Global Platts Analytics’ chief geopolitical adviser. “First, Russia’s budget still depends on oil revenues, and comments from President Putin in November point to a preference for Brent to remain around $60 per barrel. In addition, the geopolitical benefits of cooperating with US ally Saudi Arabia are likely appealing to the Kremlin.”
Falling behind the US
Rosneft’s Sechin may have a point. There have been negative consequences for snuggling up closer to OPEC. Bound by the group’s rigid production quotas, Russia’s once fast-growing oil industry has fallen behind its major rival. The country now ranks below the US as the world’s largest producer of petroleum liquids. Its semi-independent producers like Rosneft must now toe the line with output policies conceived in Riyadh and OPEC’s headquarters in Vienna.
Rosneft, which pumped almost 4.7 million barrels per day of petroleum liquids on average last year, complained last week it may have to slow down the development of several oil projects to fit OPEC’s strategy of managing the pace of supply in line with demand. Meanwhile, total US production is expected to hit a new record above 13 million barrels per day in 2020, according to the Energy Information Administration.
“If US shale production continues to grow at or near its current pace for the next few years, decisions for both Russia and Saudi Arabia will become more difficult down the road,” said Sheldon.
Despite the critics, it’s a scheme devised with the help of Russia, and has worked by preventing another collapse in prices. The cartel now hopes it can lock Russia into extending its pact, effectively binding some of the world’s largest producers together into a price regulating powerhouse on a scale not seen since the days of Standard Oil’s monopoly in the US at the beginning of the last century. Together the so called “OPEC+” alliance controls almost half the world’s supply of oil.
OPEC in the crosshairs
But the pact’s dominant position also brings dangers for Moscow. As with Standard Oil – broken up by US lawmakers in 1911 – OPEC is increasingly seen as an anti-competitive threat to America’s homegrown brand of “laissez faire” free-market capitalism. The proposed No Oil Producing and Exporting Cartels Act – also known as NOPEC – hangs over the group’s future in the US like a dark cloud.
The draft legislation has already scared some Middle East petro-states into rethinking their allegiances. Qatar’s decision to leave OPEC in January after 50 years of membership may have been partly influenced by the fear of being frozen out of the world’s biggest economy if NOPEC legislation should become law. Russia is already subject to Western sanctions and its ever closer association with OPEC could easily turn toxic.
Moscow’s relationship with both sides of the political divide in Washington is already complicated. Russia faces the prospect of tougher sanctions being imposed by the US as part of mandatory penalties doled out last year. Meanwhile, new US legislation could target Russia’s conventional oil industry, hurting some of the country’s most valuable assets. Ironically, Russia’s OPEC pact has arguably set its oil industry back more than sanctions.
Even with its current OPEC deal, Russia needs special treatment due to the structure of its oil industry. Output fell to 11.4 million barrels per day in January, but that’s still 185,000 barrels per day above its output quota of 11.19 million b/d, according to official data. Without Russia’s participation then responsibility will almost entirely fall on Saudi Arabia’s shoulders to ensure the 1.2 million barrels per day of output cuts agreed by OPEC and its allies are delivered.
“Russia’s cooperation in the 2016 and 2018 OPEC decisions to cut production were crucial to getting both deals over the finish line. And the short-term economic benefits of doing so the first time were clear, considering that the oil price impact proportionally outweighed Russia’s own loss of supply,” said Sheldon.
The same argument holds true today but a longer-term relationship with OPEC has other political and economic consequences that Putin would be reckless to ignore.
This article previously appeared as a column in The Telegraph
Ferrous markets continued to focus on the fallout from Vale’s catastrophic iron ore dam failure, with far-reaching Brazilian legislation now responding to the disaster. Neighboring Venezuala is still in the grip of political turmoil, meanwhile, with consequences for global oil trade flows and supply chains further downstream.
New state and Brazilian federal government legislation restricting the use of tailing dams may have a significant and permanent impact on iron ore production in the southeastern state of Minas Gerais, the country’s biggest producer, with both market and political implications, state government and iron ore market sources say.
The February 16 Nigerian election pits incumbent President Muhammadu Buhari against Atiku Abubakar from the People’s Democractic Party, in what is expected to be a close race. For Africa’s largest oil producer, the impact of the vote could stretch across the barrel, from crude oil exports to the domestic gasoline market.
Supply disruptions in the Asia Pacific region have failed to lift LNG spot prices, amid lackluster demand in northeast Asia and ample supplies elsewhere in the market. Despite production cuts at the Pluto, Wheatstone and Gorgon facilities in Australia, and Bintulu in Malaysia, there were three to five excess cargoes available for March delivery, LNG trading sources said.
The bunker industry in Singapore should brace itself for volatile barging costs once the International Maritime Organization’s tighter sulfur limit rule is implemented in 2020, a development which could further squeeze barge companies that are already facing tough market conditions.
THE LAST WORD
“Probably for the next couple of years we will see US LNG in Italy, because the market is in such a situation that we think there will be room,” said Eni head of gas and LNG marketing, Massimo Mantovani, addressing the EGYPS conference in Cairo.
In the event of Brexit there could be long-term consequences for UK-Russia energy links, if the UK’s policy on sanctions against Russia changes to reflect its vocal opposition to the current Russian government, and close relationship with the US.
“There is a good chance the UK would eventually toughen sanctions against Russia, if and when a deal to leave the EU is finalized,” Paul Sheldon at Platts Analytics said. Currently the UK is a participant in EU sanctions against Russia introduced gradually since 2014 in response to Russia’s role in the conflict in Ukraine. These include restrictions on Russian oil and gas companies’ access to long-term financing and technology used in offshore Arctic, shale and deep-water oil production.
UK officials have indicated they will carry over all EU sanctions and can do so via the Sanctions and Anti-Money Laundering Act passed last year.
If Brexit goes ahead there may be a greater chance of the EU and UK pursuing different sanctions policies in the longer term, however. The UK has long been one of the most vocal critics of the Russian government within the EU. Last year it pushed for harsher sanctions in the wake of suspected Russian involvement in the poisoning of former intelligence officer Sergei Skripal in the UK. While other EU countries offered support by expelling some Russian diplomats, they were reluctant to introduce broader measures. Further risks lie in ongoing investigations into alleged Russian interference in the Brexit referendum, which could spark fresh calls for new sanctions.
The UK’s close relationship with the US could also fuel calls for harsher measures. “Several uncertainties persist, led by the fate of Brexit itself and the potential for tighter U.S sanctions on Russian oil at the conclusion of ongoing investigations. In the event of the latter, Brexit would make it easier for the UK to act in solidarity with the U.S.,” Sheldon said.
US lawmakers have pushed for harsher sanctions against Russia in response to allegations of Russian interference in the 2016 presidential election, and it is likely that some of these proposals will come into force. This may include restrictions on the energy sector, including development of the Nord Stream 2 gas pipeline.
This has led to a divergence in approach between the EU and the US. While they remain aligned in opposition to Russian interference in Ukraine, there is no consensus in Europe on introducing fresh sanctions on major energy projects including Nord Stream 2. TheEU is looking to apply stronger regulations to Nord Stream 2, but it stands to lose out if the project is delayed or blocked, as it involves investment from several European companies and would increase gas supply capacity to Europe.
UK energy assets in Russia
Sanctions aside, analysts do not expect Brexit, if it goes ahead, to have any immediate impact on the UK’s energy interests in Russia. UK companies have continued to develop their operations in Russia in recent years, despite living with sanctions and the significant deterioration in the two countries’ political relationship.
Any changes to UK sanctions policy are unlikely to put those projects at risk, Platts Analytics believes. “We do not currently anticipate new sanctions on BP cooperation with Rosneft in conventional oil fields, or other penalties outside of the already-restricted upstream sectors of shale, Arctic, and deepwater,” Sheldon said.
The cornerstone of UK-Russian energy links is BP’s cooperation with Russia’s largest oil producer Rosneft. BP owns a 19.75% stake in the company itself, as well as stakes in joint ventures. A company spokesman said that BP’s share of output in Russia averaged around 1.1 million barrels of oil equivalent per day in 2018, around a third of the company’s overall output. This is likely to grow in future if plans to increase output from the Taas-Yuryakh and Kharampur projects go ahead.
BP closed deals to join these two projects since sanctions were introduced. It has also expanded cooperation with Rosneft outside of Russia, with Rosneft taking a 30% stake in the Zohr gas fieldin Egypt in 2017. In recent years BP officials have indicated that they want to continue to develop operations in Russia and with Rosneft, but will adhere strictly to sanctions.
British-Dutch company Shell also continues to operate in Russia, through its joint projects with Gazprom. It holds a 27.5% stake in the Sakalin 2 oil, gas and LNG project, and a 50% stake in Salym Petroleum, which produces around 120,000 b/d of oil. Shell is also one of the investors in the Nord Stream 2 pipeline project.
Narrower price spreads between US crudes and Dubai-based crudes have limited arbitrage opportunities to export US crude to Asia recently, S&P Global Platts data shows. However, some deals continue to get done as US crude delivered to Asia remains at a slight discount to competing grades.
In the first 29 trading days of 2019, the spread between LOOP Sour and Dubai has averaged about $2.60/b. That is compared with an average spread of $2.75/b during the same period a year ago.
As Dubai’s premium over LOOP decreases, US-based sour crudes become less competitive with comparable Dubai-based grades in export markets. The Dubai/LOOP Sour spread reached its widest point of the year so far on January 11 at $5.11/b. Its narrowest point of the year came January 25 at 90 cents/b.
The LOOP Sour-Dubai spread has been mostly narrowing since the fall as US Gulf Coast sour crude differentials have soared in recent weeks. US crudes, particularly sour grades, have jumped on concerns over the supply of medium and heavy sour crudes due to OPEC production cuts and uncertainty arising from US sanctions on Venezuela.
The 10-day moving average between LOOP Sour and Dubai was $2.40/b on Monday compared with $3.60/b one month ago and $4.40/b two months ago. One US-based crude buyer for an Indian refinery said that US crude differentials are too expensive at the moment to make export deals work.
“Prices are too high,” the crude trader said. “The arb is closed.” While the window of opportunity to move US crude is limited, some deals continue to get done, likely because values for delivered US crude to Asia remain at a discount to competing grades.
On Monday, S&P Global Platts assessed LOOP Sour CFR North Asia at $62.13/b. It is still at a small discount to comparable values for competing grades as Dubai was assessed at $63.10/b, and Basrah Light at $62.80/b.
Buyers in Asia may be looking to alternatives to expensive VLCCs in order to move crude from the US. ATMI on Friday was heard to have fixed the Suezmax Sonangol for a US Gulf Coast to West Coast India voyage in February. Oxy also arranged for a VLCC to carry US crude to China in March. No US-to-East fixtures were heard done Monday.
The US will become a net oil exporter sometime next year. That is, total exports of both crude oil and refined petroleum products will exceed total imports.
It’s a remarkable milestone, even if it doesn’t mean that the US is self-sufficient in oil production or insulated from the global market. It reflects the staggering growth in US production in recent years. At the same time, it exposes the importance of crude quality – because the US produces type of oil that most of its refiners were not configured to process.
President Donald Trump praised the milestone in his State of the Union speech to Congress Tuesday, albeit before it actually happens. “The United States is now the number one producer of oil and natural gas anywhere in the world. And now, for the first time in 65 years, we are a net exporter of energy,” Trump said.
The Energy Information Administration expects the US to flip from longtime net oil importer to net oil exporter in the third or fourth quarter of 2020. A decade ago, EIA forecast in its 2009 Annual Energy Outlook that foreign crude would meet 44% of US demand in 2020. Imports met 60% of US consumption in 2006 and were projected to fall to 50% by 2010, according to the 2009 report. That was before the US tight oil revolution got underway in earnest.
The 2019 AEO report released in January predicts foreign oil will meet just 7.5% of US demandthis year. EIA’s projections have accelerated as US oil production growth keeps beating expectations. Even just two years ago, EIA’s 2017 AEO forecast the US remaining a net importer through 2050, with foreign oil meeting 17.7% of national consumption that year. Last year’s AEO predicted the US would gain net exporter status in 2029 – nine years later than the current forecast.
The US became the world’s top oil producer last year. It pumped 11.9 million b/d of crude in November, the latest data available, and may have already crossed the 12 million b/d mark. EIA sees US output hitting the next threshold of 13 million b/d in October 2020. “We expect the United States to remain the world’s largest producer,” EIA Administrator Linda Capuano said in January.
Anyone who follows US energy policy knows that the US’ top producer status doesn’t keep global market forces out of American drivers’ pocketbooks. Look at US oil policy just in the last year and see the many times the White House leaned on foreign oil producers to increase their own supply in order to keep American gasoline pump prices low.
Leaning on OPEC
President Donald Trump practically invited himself to last year’s OPEC meetings by tweeting his wishes for more production and lower prices. When the US moved to reimpose sanctions on Iran, the White House kept a close watch on global crude prices and again leaned on OPEC producers like Saudi Arabia to pump more. Brent prices rose sharply in October on expectations of strict enforcement of the sanctions, until the White House granted a raft of waivers to Iran’s top oil customers including China, India, Japan and South Korea.
“There’s been a big reduction in the overall price of oil and particularly since we instituted the Iran sanctions,” Treasury Secretary Steven Mnuchin said January 28 during a White House briefing announcing the Venezuela oil sanctions. “I think you know we’ve been very careful in making sure that these costs don’t impact the American consumer,” he added.
“Gas prices are almost as low as they’ve been in a very long period of time. These refineries impact a specific part of the country. And I think, as you’ve said, we’re very comfortable that they have enough supply that we don’t expect any big impact in the short term.”
Crude quality matters
However, the interconnectedness of the global oil market often gets lost when Washington policy makers talk about US oil abundance. “One of the things I’ve heard from the Americans is, ‘We’re producing all this crude, we don’t need any Canadian crude,'” said Jonathan Stringham, manager of fiscal and economic policy at the Canadian Association of Petroleum Producers.
The US imported 4.2 million b/d of Canadian crude in November, according to the latest EIA data. Some Gulf Coast refiners are hoping to use heavy crude barrels from Alberta to replace Venezuelan imports blocked by the recent US sanctions, although pipeline and rail constraints will keep Canada from meeting any more than about 100,000 b/d of additional heavy crude demand this year, according to S&P Global Platts Analytics.
“What we’re trying to communicate to the average American is that Canadian crudes don’t compete with American crudes,” Stringham said. “With the different quality adjustments and types of crude – heavy, light — there’s still a need for heavy crudes in the Gulf.”
The US snagged the net oil exporter title for all of one week last November, driven by a surge of 3.2 million b/d in crude exports that pushed crude and product exports above 9 million b/d, according to Platts Analytics. Whether and when the US becomes a net exporter on a monthly and annual basis of course depends on oil prices.
EIA’s reference case projects US net oil imports of 1.58 million b/d in 2019 before flipping to net exports of 460,000 b/d in 2020. Net exports would max out at 3.68 million b/d in 2034 before starting to decline. EIA’s low price scenario shows the US never reaching net oil exporter status through 2050. A high price scenario, however, shows US net imports of 50,000 b/d this year before switching to US net exports of 2.51 million b/d in 2020 that keep rising until 8.39 million b/d in 2033.
Strong demand for sour crude grades helped boost LOOP Sour deliveries in January.
In a recent report from the Louisiana Offshore Oil Port, the company said LOOP Sour demand nearly tripled month on month, increasing by some 620,000 barrels to more than 985,000 barrels, which is about 32,000 b/d. It was the largest volume of LOOP Sour crude pulled from the Louisiana storage cavern since September.
A shortage of sour crudes along the US Gulf Coast has inverted the typical sweet-sour relationship globally. Additionally, US sanctions on Venezuela could further increase demand for sour grades.
LOOP Sour comprises US Gulf of Mexico grades Mars and Poseidon and a crude blend called Segregation 17, named after a cavern into which the Middle Eastern grades Arab Medium, Basrah Light and Kuwait Export Crude can be delivered. The grade has been most similar to Mars in terms of API gravity over the past 12 months, averaging 0.33 degree off Mars’ typical 29.44; and from a sulfur standpoint, averaging 0.02 percentage point off Arab Medium’s typical 2.53%.
LOOP Sour delivered ex-cavern in January was slightly heavier and sweeter than the month before, averaging 29.9 API and 2.23% sulfur.
Separately, the Louisiana Offshore Oil Port will auction 7,200 capacity allocation contracts in its monthly crude storage auction on Tuesday, which collectively equal 7.2 million barrels of storage for the medium crude blend LOOP Sour. The minimum bid price LOOP will accept during the auction is 5 cents/b. Monthly storage for LOOP Sour traded around 5 cents/b for all of 2018.
Auction cohost Matrix Markets said LOOP will sell up to 3,600 storage futures contracts and 3,600 physical forward agreements. The front-month contract of March will see 400 CACs put up for sale.
Last month LOOP and Matrix sold a total of 6,690 CACs of the 7,350 that were offered.
Venezuela should be a global oil-exporting superpower. Instead, the Marxist junta ruling the country teeters on the brink of complete economic collapse, with hyperinflation reminiscent of Weimar Germany and the chances of a political coup d’état in Caracas rising every day.
Despite its enfeebled state, Venezuela punches above its weight in oil markets. Uncertainty over its supply has helped to push up prices by almost 20% since the start of the year. That’s because many refineries in Texas and Louisiana – America’s fuel-producing engine – are configured to process Venezuela’s heavy blend of crude.
The country supplies about 50% of the oil used by the southern states’ plants dotted around the Gulf of Mexico. Finding suitable alternatives at short notice won’t be easy.
“Crude oil production in Venezuela, and especially exports to the US, are expected to drop in response to the growing political crisis and the US implementing new sanctions against its state-run oil company, PDVSA,” said Ole Hansen, head of commodity strategy at Saxo Bank.
Daily shipments to the world’s largest economy have slumped below 500,000 barrels, down from over 1.2 million b/d a decade ago, according to the Energy Information Administration. US President Donald Trump’s decision to slap punitive sanctions on state-controlled oil giant PDVSA is a further economic hammer blow aimed at Nicolas Maduro, his Venezuelan counterpart.
The embargo comes at a tricky time for oil markets and consumers. Saudi Arabia is pushing its partners in OPEC to implement deep output cuts the cartel agreed last December in order to boost depressed global prices. Venezuela is a founding member of the production group, which in alliance with Russia controls around 40% of world oil supply. Venezuela signed OPEC’s original charter in Baghdad in 1960 alongside Iran, Iraq, Saudi and Kuwait.
Back then, Venezuela’s people were among the most prosperous on the planet.
This year, Venezuelan oil minister and Maduro loyalist Manuel Quevedo is due to take over the revolving presidency of OPEC – traditionally an important role for coordinating among the cartel’s 14 members. However, his status grows ever more uncertain as opposition leader and self-appointed alternative president Juan Guaido draws throngs of disgruntled supporters to his cause.
Although Guaido’s “shadow government” lacks control of the military and a legitimate cabinet of ministers, the 35-year-old leader of the National Assembly has moved swiftly in his attempt to seize control of the nation’s crucial oil riches. He ordered congress this week to nominate a new board of directors at PDVSA and its US refining subsidiary Citgo.
US sanctions will help his strategy by choking off Maduro’s access to oil revenues, the president’s final source of income to prop up the regime. US Treasury Secretary Steve Mnuchin said last week: “If the people in Venezuela want to continue to sell us oil, as long as the money goes into blocked accounts we will continue to take it.” However, sanctions could prove sensitive if a spike in prices pushes up the cost of gasoline for American motorists, a raw nerve for the grassroots supporters of Trump’s government. Analysts agree regime change could still take months.
“The Trump administration appears to be making a major bet on squeezing Venezuela economically to accelerate regime change, which for the oil industry could eventually bring sanctions relief, foreign investment, and a return to production growth. But this ultimately hinges on co-operation from the Venezuelan military, the leaders of which continue to publicly support Maduro despite signs of cracking at lower levels,” wrote S&P Global Platts Analytics in a research note.
Sanctions have had mixed results for Trump elsewhere. Legislation introduced last year targeting Iran raised concerns in the market about potential supply shortfalls until the US introduced temporary waivers for several major customers of its crude. However, these dispensations will expire soon, further tightening an already constricted oil market and potentially pushing up prices.
Maduro may also find an ally in Russia’s President Vladimir Putin. Venezuela gives Moscow access and influence in America’s back yard.
“The duration of the sanctions regime will ultimately hinge on Maduro’s staying power and Moscow could play a critical role in determining the trajectory of the crisis. Russia has extended multiple, multi-billion dollar financial lifelines to the country, enabling the cash strapped national oil company to avoid a catastrophic default that would have resulted in asset seizures by creditors,” warned Helima Croft, head of commodity strategy at RBC Capital Markets in a research note.
Venezuela’s oil industry has suffered a staggering decline of fortunes over the last 20 years amid chronic mismanagement, systemic corruption and continual political acrimony. Its proven reserves are by some measures thought to be the world’s largest at almost 300 billion barrels. By comparison, Saudi Arabia holds just under 270 billion barrels. Venezuela’s total petroleum reserves could be much greater, especially in its rich Orinoco basin.
In theory, a new government could turn things around quickly. Reform of the oil sector would deliver an economic dividend and a boost to supply. But unless the country can attract investment from international oil companies its potential will be constrained. Resource nationalism remains a potent political totem on the streets of Caracas.
Despite its embarrassment of oil riches, Venezuela’s economy is in free fall. The IMF estimates that GDP has collapsed by 50% since 2013. Meanwhile, oil production – its main source of hard foreign currency earnings – has plummeted. “Hyperinflation and outward migration are also projected to intensify in 2019,” said the fund in its latest assessment of the region’s prospects. “Evolving political developments add another layer of uncertainty to the country’s outlook.”
Output will now keep falling because of sanctions pushing up the cost of production. S&P Global Platts estimates total daily output could drop to 1.15 million b/d – a decline of 175,000 – by the end of the year. A separate survey of OPEC output conducted recently by Platts paints an even bleaker picture with Venezuela pumping just 1.17 million b/d in December.
Maduro’s regime has no means of replacing this lost revenue and instead faces a slow and agonizing death by economic strangulation. Instead of being among Latin America’s most prosperous nations, Maduro has unleashed a catastrophe on his own people. His failure to take advantage of Venezuela’s wealth in natural resources is nothing short of a tragedy.
This article previously appeared as a column in The Telegraph.
Activity in what has been a mostly sluggish US Gulf of Mexico is expected to increase modestly in 2019, bringing production growth and more exploration aimed at finding the elephant fields of the future.
Brent crude has fallen $20 from highs in the mid-$80s/b months ago, but US Gulf operators, especially in deepwater, aren’t phased by volatile prices, analysts say. Instead, operators are deciding to grow in the gulf because of the industry’s increasing ability to make those fields more economic.
Logistical and operational efficiencies, lower oilfield service costs, scaled designs and better engineering have combined to make the region more profitable than it was even before the 2014 industry downturn.
“Generally, when industry is at peak efficiency and operating at its best, industry fundamentals aren’t bad and oilfield costs are relatively low,” said William Turner, a Gulf of Mexico analyst at energy consultancy Wood Mackenzie.
2019 will mark the first increase in US Gulf exploration in four years, Turner said. About 21 or 22 exploration and appraisal wells are expected this year in the US Gulf, up from 19 last year, according to Wood Mac. That compares with 40-50 wells drilled three or four years ago.
The increase is “from a low base,” Turner noted. “Certainly, we’re not at 2014 levels of exploration.”
The US Gulf accounts for nearly 16% of the US’ roughly 11.5 million b/d of oil production. Its crude oil production averaged 1.8 million b/d in Q4 2018, according to the US Energy Information Administration, compared with just less than 1.25 million b/d in 2013.
The EIA projects US Gulf production will crack the 2 million b/d mark in about a year. Meanwhile, S&P Global Platts Analytics projects oil output will end 2022 at 1.82 million b/d, up from a recent low of 1.50 million b/d in December 2018.
Deepwater US Gulf spending is projected at about $10 billion this year, about the same as in 2017 but down from $16 billion in 2015, according to Wood Mac data. Contributing a swath of this year’s production will be Shell’s Appomattox field, capable of producing 175,000 barrels of oil equivalent per day at peak. Chevron’s Big Foot field, which debuted in November 2018, will ramp up this year; its peak production is 75,000 b/d of oil and 25,000 Mcf/d of natural gas.
Several smaller fields are due to come online in 2019, including Buckskin, Stonefly and Nearly Headless Nick from LLOG Exploration, with a combined production of 40,000-50,000 b/d.
Growing small operator Talos Energy, which acquired Stone Energy last year, said wells will come online this year at its Tornado and Boris field. The Tornado #3 well will debut at 10,000-15,000 boe/d, while Boris #3 should contribute 3,000-5,000 boe/d.
Despite uncertain oil prices, enthusiastic operators say improved technology makes the area economic. Last month, BP outlined new US Gulf discoveries and nearly 1.5 billion additional barrels of oil it uncovered using improved seismic technology at its giant Thunder Horse and Atlantis fields. And Hess Corp. showcased numerous tieback opportunities at 50% to 100%-plus return rates during a December analyst meeting.
This year’s exploration plate will also see Hess spudding Esox, its first US Gulf exploration well in years, while Chevron already has a rig in place to drill the Yarrow prospect in the Mississippi Canyon area, south of Alabama.
Oil breakevens in the US Gulf average around $55-$60/b, Wood Mackenzie’s Turner said, although some projects are lower. Shell said its Vito development, which is slated for first oil in 2021, has a breakeven price less than $35/b.
While tiebacks to existing fields will comprise a major part of US Gulf work this year, the big challenge is to “squeeze the efficiencies they’ve achieved and maintain them,” S&P Global Platts Analytics analyst Sami Yahya said. “What’s really important is the confidence of the market to maintain oil prices,” Yahya said. “They can’t sanction projects without fully knowing they can survive in a low-price environment.”
In addition, 2019 may see a significant project sanction: Chevron-operated Anchor in the Green Canyon area offshore Louisiana. Anchor is an early 2015 oil discovery the company at the time described as “significant.”
Anchor is not only important reserve-wise, but success and invocations there could open development opportunities across the industry, analysts said.
The field is ultra-high-pressure—20,000 pounds per square inch—compared to a current produceable limit around 15,000 psi. Technology is advancing to produce 20K fields, but few operators are large or able enough to take on the gamble.
If Chevron green-lights Anchor, which could happen by mid-year, it could open the frontier play to industry. That might result in a “gold rush” of new leasing and investment in remote, deep and technologically complex fields, Wood Mackenzie’s Turner said.
Another potential hot spot is the Appomattox field, which represents the first output from the Norphlet play offshore Alabama and Mississippi. Depending on how it performs, Appomattox could spur more Norphlet activity, analysts said.
US light sweet crudes such as WTI Midland and Bakken have been offered into Asia at lower premiums in recent months amid a drop in freight rates from the US Gulf Coast to the Far East, sources in Asia said Monday.
Taiwan’s CPC was heard to have bought 4 million barrels of WTI Midland crude from an unknown seller for March Loading. The cargo was priced around a $2.25/b premium to Dated Brent on a CIF Taiwan basis. CPC seems to enter the US Gulf Coast market when prices are ideal. The company last bought 4 million barrels of WTI Midland for January loading. But CPC did not seek any WTI spot cargoes for February.
WTI Midland’s differential to WTI cash averaged minus $7.39/b in December, down from minus $5.78/b in November and lower than minus $3.95/b so far in January, according to data from S&P Global Platts.
While most January cargoes have already been sent and few may be sent to Asia in February, March could bring a flurry of US Gulf Coast-to-Asia fixtures as the opportunity reemerges. Upcoming spring refinery maintenance season in the US Gulf Coast region could make more domestic crude barrels available for export, with April differentials for both sweet and sour grades heard to be trading lower.
On Monday, WTI MEH March volumes were assessed at WTI cash plus $5.15/b, with April volumes heard to be traded 25 cents/b lower at plus $4.90/b. Medium sour grade Mars was assessed at WTI cash plus $5.05/b for March volumes, with April volumes heard to be trading 35 cents/b lower. Lower second-month differentials imply weaker demand in April for domestic crude volumes.
US crude continues to make inroads in other countries in Asia. Vietnam’s 148,000 b/d Dung Quat refinery is set to receive its first crude cargo from the US when 1 million barrels of WTI crude will arrive there in April. If testing of that initial cargo is positive, the refinery will likely take more WTI in the future.
Freight rates for VLCCs heading to China out of the US Gulf Coast on a 270,000 mt basis have fallen $400,000 since they reached their January peak at lump sum $7.4 million or $27.41/mt, ($3.54/b) with indications last heard Monday morning in line with the last assessed level of lump sum $7 million or $25.93/mt ($3.34/b).
Overall, freight rates have been weaker over the past month, averaging lump sum $6.94 million or $25.70/mt ($3.32/b) so far in January, compared to $8.26 million or $30.59/mt ($3.95/b) in December 2018. VLCC rates from the US Gulf Coast to Singapore typically follow rates to China, but are typically $1 million cheaper than those to China.
Shareholder activism has a long history in commodities. In the early 17th century, Isaac Le Maire, grain trader and disgruntled former governor of the Dutch East India Company, attempted to break the company’s monopoly by speculatively trading its shares.
His scheme failed, but Le Maire’s desire to shake up the status quo of the trade route between Europe and India eventually led to the discovery of Cape Horn.
Skip forward 400 years and shareholder activism in another Dutch-origin resources giant has taken on a less selfish hue.
In December, the Church of England, along with other investors in Shell, helped to persuade the energy giant to commit to setting targets to cut its carbon footprint by 20% by 2035 and half by 2050. The company’s achievements in reducing carbon emissions is to be linked to executive pay, subject to a shareholder vote in 2020.
The Paris agreement commits signatories to taking action to limit temperature rises “well below” 2 C, though many poorer and low-lying coastal countries felt this did not go far enough, and wanted an agreement to limit rises to 1.5 C. Global temperatures have already climbed by around 1 C.
The significant findings of the IPCC special report are that serious environmental changes occur at lower temperatures than previously thought and, while more damaging than a 1 C rise, 1.5 C represents a much more habitable planet than 2 C.
National commitments fall short
One important factor in these changes is the potential feedback loops at certain critical trigger points. For example, the thawing of the northern permafrost, or melting of large sections of polar ice caps. Such events would release large amounts of additional greenhouse gases, or lead to large rises in sea levels. Such events could create feedback loops in the global climate system, locking in further heating of the planet.
So far, so terrifying. But there’s more.
Current commitments by national governments are expected to lead to around 3 C of warming by 2100, with further warming beyond that date. The IEA said in its latest World Energy Outlook that CO2 emissions under planned policies are on a slow upward trend to 2040, and are “far out of step” with what is needed to tackle climate change.
The IPCC says staying within a 1.5 C rise requires “rapid and far-reaching transitions in energy, land, urban and infrastructure (including transport and building), and industrial systems” that are “unprecedented in terms of scale, but not necessarily in terms of speed.”
On the current course, global warming is expected to reach 1.5 C between 2030 and 2052. Limiting temperature rises to 1.5 C requires a 45% reduction in anthropogenic CO2 emissions by 2030 from 2010 levels, and net zero by 2050, according to the IPCC report.
The scale of the challenge highlights the importance of commitments made by the likes of Shell, and the influence shareholders can have in the fight against climate change. National governments – on current commitments – will fall short of their obligations. And with important consumer and producer countries such as the US and Brazil under climate-change-skeptical leadership, the onus falls increasingly on other sections of society.
The motive goes beyond the purely altruistic, though. Agricultural companies’ businesses could be devastated by climate change, with crop yields potentially falling, and harvests failing more often. And energy giants could find themselves owners of billions of dollars of stranded assets, should climate change come to be taken seriously enough to keep fossil fuels in the ground.
Shell case emboldens activists
Following its success with Shell, the Church Commissioners for England, along with the head of New York State’s retirement fund, Thomas DiNapoli, turned their attention to American giant ExxonMobil. Shortly before Christmas, the investor-campaigners filed a shareholder resolution for consideration at the major’s next annual meeting requiring it disclose greenhouse gas reduction targets for the short-, medium- and long-term, in an effort to limit global temperature increases to 1.5 C.
But the campaigners could have their work cut out. ExxonMobil has already attempted to block the Massachusetts Attorney General’s investigation into its research into climate change, although the US Supreme Court rejected the appeal in early January.
As pressure mounts on the energy industry to change, both from governments and from shareholders, we may yet see more companies taking a lead on climate change policy.
This article previously appeared as a column in The National