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Last week in the world oil:

Prices

  • While OPEC looks at ways to improve coordination among its members over the supply freeze, Saudi Arabia has pledged to cut its exports further in August to help reduce the global glut. Crude prices rose in response to this, hitting US$48/b for Brent and US$46/b for WTI, and increasing further as the UAE pledged further output cuts in September and Russia pushes for a 100% compliance with the current global deal.

Upstream & Midstream

  • Deregulation appears to be paying off for Mexico, as Eni announced that its Amoca field contains as much as a billion barrels of oil, joining the massive Zama field discovered last week. The giant new finds confirms that the ‘Mexican side of the Gulf is very prolific’ according to its oil regulator, prompting it to delay its new offshore round by a month to January 2018 to give international bidders more time to evaluate the newly announced assets. The round will also include the first areas from the Cordilleras Mexicanas basin, potentially sparking off a new oil rush.
  • Brazil’s oil regulator is mulling allowing more flexible local content rules to existing E&P contracts in a bid to revive crude projects put on ice in Brazil over low oil prices and tough local content rules, which may restart some key projects, including the subsalt region of the Santos basin.
  • The UK is hoping to capitalise on the recent spurt of activity in its continental shelf, launching an offshore licensing round that focuses on mature areas. Some 813 blocks over a combined area of 114,426 square kilometres in the Southern, Central and Northern North Sea, the West of Shetland and East Irish Sea are open for bidding until November, including some acreage that has not been available since 1965.
  • The US active rig count appears to be reaching saturation point at current price levels, losing two rigs overall last week as drillers held back on activity in an increasingly glutted market.

Downstream

  • Independent US refiner Tesoro, which will become Andeavor in August, has reached a new agreement with Pemex to enter Mexico’s terminal and transportation services sector, enabling access to Pemex’s pipelines and storage terminals in an attempt to break into the retail sector.
  • BP is reportedly considering spinning off some of its US pipeline assets in the Gulf and Midwest in an IPO, structuring them in a Master-Limited Partnership common to American pipeline companies. It is a revival of a plan first considered five years ago, shelved after oil prices crashed. If it goes through, BP will join other refiners like Valero and Marathon, who have created MLPs for their pipeline assets.

Natural Gas and LNG

  • Egypt expects its natural gas output to double by 2020, as the Zohr, North Alexandria and Nooros projects ramp up to ease the country’s current energy deficiency and move it to gas self-sufficiency. Early phases of Nooros and North Alexandria are already in production, increasing output to 5.1 bcf in 2017 from 4.4. bcf in 2016. So much natural gas is expected to come onstream that Egypt is now in talks with its LNG contractors to defer shipments.

Last week in Asian oil

Upstream

  • In an interesting thaw of relations, China’s foreign minister has said that he supports the idea of joint energy ventures with the Philippines in the disputed areas of the South China Sea claimed by both countries. With President Rodrigo Duterte aiming to develop oil fields in the Reed Bank, the overture by China seems to be aimed at diffusing a potential standoff. It could work out to China’s advantage though; if the Philippines agrees to cooperate with China on joint development, it would make future maritime border claims difficult when brought to the International Tribunal for the Law of the Sea.

Downstream

  • As the startup of Nghi Son, Vietnam’s second refinery, approaches – the refinery recently bought its first crude cargo, from Kuwait – the country is looking forward to plans to establish a strategic oil product reserve. It would follow the IEA guidelines to have at least 90 days worth of net imports, aiming to having the storage in place by 2020. Vietnam currently requires its refineries to have 15 days of their processing capacity in crude stockpiles and 10 days in oil products – equivalent to 30-35 days of its current level of net imports. The advent of Nghi Son may bump that up to 60-70 days by the end of the year, with the third refinery still far away.
  • South Korea is looking at easing blending restriction and rules at the country’s large oil storage terminals in the southern ports of Ulsan and Yeosu, as it aims to become a trading hub in Northeast Asia, and potentially challenging Singapore as Asia’s oil trading centre. Easing the blending rules will allow trading companies the leeway to meet client specifications, a key requirement to establishing a trading hub. South Korea’s proximity to China and Japan could definitely support the idea, but there is still a long way to go for Korea to create the necessary physical and financial infrastructure to displace Singapore.

Natural Gas & LNG

  • After what seems like decades of procrastination the Philippines is on the verge on signing on a partner for its US$2 billion LNG receiving and distribution facility. PNOC has shortlisted six countries for six potential partners – China, Japan, South Korea, Singapore, Indonesia and the UAE – which will help construct the facility by 2020, in time to replace the country’s dwindling supplies from the once prolific Malampaya gas field. The facility will likely be in Batangas, as will include new power plant facilities aimed at improving the country’s inconsistent electricity supply.
  • Petronas has delivered its first LNG cargo to Thailand, the first under a 15 year contract that will see the Malaysian state oil firm send up to 1.2 mtpa per year. Running short of natural gas from the domestic sources as well as piped natural gas from Myanmar, Thailand’s PTT has increasingly turned to LNG to meet the country’s growing demand for gas.

Corporate

  • India’s grand ambitions to merge its numerous state oil companies into a giant entity took one step forward with the sale of the state’s 51.1% stake  in HPCL to state upstream company ONGC for US$4.6 billion. This will create the first major India state vertically-integrated company, bringing together the upstream activities of ONGC and the refining and retail network of HPCL, exploiting synergies between the two.

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ConocoPhillips vs PDVSA - Round 2

Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.

In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.

In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.

The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.

But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.

Infographic: Venezuela oil nationalisation dispute timeline

  • 2003 – National labour strikes cripple Venezuela’s oil industry
  • 2005 – Hugo Chavez begins a re-nationalisation drive
  • 2007 – Oil re-nationalisation, PDVSA to have at least 50% of all projects
  • 2008 – ExxonMobil and ConocoPhillips launch dispute arbitration
  • 2012 – ExxonMobil awarded damages from PDVSA
  • 2014 – ExxonMobil awarded damages from government of Venezuela
  • 2018 – ConocoPhillips awarded damages from PDVSA
  • 2019 – ConocoPhillips awarded damages from government of Venezuela
March, 21 2019
This Week in Petroleum
The United States exported 2 million barrels per day of crude oil in 2018 to 42 different destinations

In 2018, U.S. exports of crude oil continued to increase to 2.0 million barrels per day (b/d), up 846,000 b/d (73%) from 2017 (Figure 1). The number of destinations for U.S. crude oil exports also increased from 37 to 42. Volumes by destination changed significantly between the first and second halves of 2018.

Figure 1. U.S. crude oil exports (1920 - 2018)

The increase in U.S. crude oil exports was the result of increasing U.S. crude oil production and infrastructure changes. U.S. crude oil production increased 1.6 million b/d from 2017 to 10.9 million b/d in 2018, with the U.S. Gulf Coast—where more than 90% of U.S. crude oil exports depart from—producing 7.1 million b/d. The increased production is mostly of light, sweet crude oils, but U.S. Gulf Coast refineries are configured mostly to process heavy, sour crude oils. This increasing production and mismatch between crude oil type and refinery configuration causes more of the increasing U.S. crude oil production to be exported.

In early 2018, modifications were made at the Louisiana Offshore Oil Port (LOOP) in the Gulf of Mexico to enable the loading of vessels for crude oil exports. LOOP is currently the only U.S. facility capable of accommodating fully loaded Very Large Crude Carriers (VLCC), vessels capable of carrying approximately 2 million barrels of crude oil. After LOOP was modified to also allow exports, the increase in cargo scale led U.S. crude oil exports to surpass 2 million b/d for 25 weeks in 2018 compared with just 1 week in 2017. In addition to LOOP, other U.S Gulf Coast export facilities in and around Houston and Corpus Christi, Texas, have been investing in increasing the scale of U.S. crude oil export cargos.

In 2018, Asia was the largest regional destination for U.S. crude oil exports, followed by Europe, and, as in previous years, Canada was the largest single destination for U.S. crude oil exports. Canada received 378,000 b/d of U.S. crude oil exports, representing 19% of total U.S. crude oil exports in 2018. South Korea surpassed China to become the second-largest single destination for U.S. crude oil exports in 2018, receiving 236,000 b/d compared with China’s 228,000 b/d (Figure 2).

Figure 2. 2018 U.S. crude oil export destinations

However, the distribution of U.S. crude oil exports by destination varied significantly from the first half of 2018 to the second half. In the first half of 2018, the United States exported 376,000 b/d of crude oil to China, which made China the largest single destination for U.S. crude oil exports for that period. However, in August, September, and October of 2018, the United States exported no crude oil to China, and then in November and December it exported significantly less than in earlier months. In the second half of 2018, the United States exported 83,000 b/d of crude oil to China, a decrease of 294,000 b/d from the first half (Figure 3).

Figure 3. U.S. crude oil exports by destination (1H 2018 vs. 2H 2018)

In the summer of 2018, as part of ongoing trade negotiations between the United States and China, China temporarily included U.S. crude oil on a list of goods potentially subject to an increase in import tariffs. At the same time, the difference between the international crude oil benchmark Brent and the U.S. domestic price West Texas Intermediate (WTI) futures prices narrowed rapidly between June and July 2018. Brent prices went from $9 per barrel (b) higher than WTI in June to $6/b higher than WTI in July. The rapidly narrowing price discount of U.S. crude oils versus international crude oils and the potential for higher import tariffs caused Chinese buying of U.S. crude oil to slow.

Although U.S. crude oil exports to China slowed in the second half of 2018, exports to South Korea, Taiwan, Canada, and India increased significantly. U.S. crude oil exports to South Korea increased 247,000 b/d (222%) between the first and second half of 2018. U.S. crude oil exports to other destinations in Asia also increased, particularly to Taiwan, which rose 111,000 b/d (168%) in the second half of 2018 compared with the first half, and to India, which increased 86,000 b/d (97%) during the same period.

Despite the volume changes in U.S. crude oil destination between the first and second halves of 2018, the list of destinations has remained consistent over the past three years. Of the 27 destinations that took U.S. crude oil in 2016, the first year of unrestricted U.S. crude oil exports, 22 destinations did so again in 2017 and again in 2018 (Figure 4). Furthermore, few destinations appear to be one-time recipients of U.S. crude oil, other than those such as the Marshall Islands that were listed because of data collection methods and ship-to-ship transfers.

Figure 4. U.S. crude oil export destinations

U.S. average regular gasoline price increases, diesel price falls

The U.S. average regular gasoline retail price rose nearly 8 cents from the previous week to $2.55 per gallon on March 18, down 5 cents from the same time last year. The East Coast price rose nearly 9 cents to $2.52 per gallon, the Gulf Coast price rose over 8 cents to $2.30 per gallon, the Midwest price rose nearly 8 cents to $2.48 per gallon, the Rocky Mountain price rose nearly 7 cents to $2.32 per gallon, and the West Coast price rose nearly 5 cents to $3.03 per gallon.

The U.S. average diesel fuel price fell nearly 1 cent to $3.07 per gallon on March 18, nearly 10 cents higher than a year ago. The Midwest price fell nearly 2 cents to $2.99 per gallon, the Gulf Coast price fell over 1 cent to $2.87 per gallon, and the West Coast price fell nearly 1 cent to $3.50 per gallon. The Rocky Mountain price increased nearly 1 cent, remaining at $2.94 per gallon, and the East Coast price rose less than 1 cent, remaining at $3.12 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 1.0 million barrels last week to 51.1 million barrels as of March 15, 2019, 6.3 million barrels (14.0%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories increased by 1.2 million barrels, 0.4 million barrels, and 0.1 million barrels, respectively, while Midwest inventories decreased by 0.7 million barrels. Propylene non-fuel-use inventories represented 12.1% of total propane/propylene inventories.

Residential heating fuel prices decrease

As of March 18, 2019, residential heating oil prices averaged nearly $3.22 per gallon, 1 cent per gallon below last week’s price but 16 cents per gallon above last year’s price at this time. Wholesale heating oil prices averaged $2.09 per gallon, nearly 4 cents per gallon less than last week’s price but 8 cents per gallon more than a year ago.

Residential propane prices averaged $2.41 per gallon, less than 1 cent per gallon lower than last week’s price and almost 8 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.84 per gallon, less than 1 cent per gallon above last week’s price but 3 cents per gallon below last year’s price.

March, 21 2019
U.S. renewable electricity generation has doubled since 2008

U.S. annual renewable generation

Source: U.S. Energy Information Administration, Electric Power Monthly

Renewable generation provided a new record of 742 million megawatthours (MWh) of electricity in 2018, nearly double the 382 million MWh produced in 2008. Renewables provided 17.6% of electricity generation in the United States in 2018.

Nearly 90% of the increase in U.S. renewable electricity between 2008 and 2018 came from wind and solar generation. Wind generation rose from 55 million MWh in 2008 to 275 million MWh in 2018 (6.5% of total electricity generation), exceeded only by conventional hydroelectric at 292 million MWh (6.9% of total generation).

U.S. solar generation has increased from 2 million MWh in 2008 to 96 million MWh in 2018. Solar generation accounted for 2.3% of electricity generation in 2018. Solar generation is generally categorized as small-scale (customer-sited or rooftop) solar installations or utility-scale installations. In 2018, 69% of solar generation, or 67 million MWh, was utility-scale solar.

U.S. annual net generation, wind and solar

Source: U.S. Energy Information Administration, Electric Power Monthly

Increases in U.S. wind and solar generation are driven largely by capacity additions. In 2008, the United States had 25 gigawatts (GW) of wind generating capacity. By the end of 2018, 94 GW of wind generating capacity was operating on the electric grid. Almost all of this capacity is onshore; one offshore wind plant, located on Block Island, off the coast of Rhode Island, has a capacity of 30 megawatts. Similarly, installed solar capacity grew from an estimated less than 1 GW in 2008 to 51 GW in 2018. In 2018, 1.8 GW of this solar capacity was solar thermal, 30 GW was utility-scale solar photovoltaics (PV), and the remaining 20 GW was small-scale solar PV.

Growth in renewable technologies in the United States, particularly in wind and solar, has been driven by federal and state policies and declining costs. Federal policies such as the American Reinvestment and Recovery Act of 2009 and the Production Tax Credit and Investment Tax Credits for wind and solar have spurred project development.

In addition, state-level policies, such as renewable portfolio standards, which require a certain share of electricity to come from renewable sources, have increasing targets over time. As more wind and solar projects have come online, economies of scale have led to more efficient project development and financing mechanisms, which has led to continued cost declines.

Conventional hydroelectric capacity has remained relatively unchanged in the United States, increasing by 2% since 2008. Changes in hydroelectric generation year-over-year typically reflect changes in precipitation and drought conditions. Between 2008 and 2018, annual U.S. hydroelectric generation was as low as 249 million MWh and as high as 319 million MWh, with hydroelectric generation in 2018 totaling 292 million MWh. Generation from other renewable resources, including biomass and geothermal, increased from 70 million MWh to 79 million MWh in the United States between 2008 and 2018, and it collectively represented 1.9% of total generation in 2018.

March, 20 2019