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Last Updated: September 9, 2017
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Hurricane Harvey disrupts U.S. Gulf Coast refineries, infrastructure, and supply chainsWith its landfall near Corpus Christi, Texas as a Category 4 storm two weeks ago on August 25, 2017 and subsequent path along the Gulf Coast, Hurricane Harvey caused substantial disruptions to crude oil and petroleum product supply chains and prices because of the high concentration of petroleum infrastructure in the Gulf Coast, Petroleum Administration for Defense District (PADD) 3. Just over half of all U.S. refinery capacity is located in PADD 3; Texas alone represented 31% of all U.S. refinery capacity as of January 2017. These refineries supply petroleum products to local markets, domestic markets on the East Coast (PADD 1) and in the Midwest (PADD 2), and international markets. As of March 2017, PADD 3 accounted for 49% of total U.S. working crude oil storage capacity and over 40% of working storage capacity for both motor gasoline and diesel fuel. Furthermore, PADD 3 represented 62% of total U.S. crude oil production in 2016, with an additional 18% coming from the Federal Offshore Gulf of Mexico.

Hurricane Harvey’s most significant effect on petroleum markets was to curtail refinery operations in Texas. Refinery operations are largely dependent on a supply of crude oil and feedstocks, electricity, workforce availability and safe working conditions, and outlets for production. As a result of Hurricane Harvey, many refineries in the region either reduced runs or shut down in its aftermath. For the week ending September 1, 2017, gross inputs to refineries in PADD 3 fell 3.2 million barrels per day (b/d) (-34%) from the previous week and were down 2.8 million b/d (-31%) from the same time last year. Four-week average PADD 3 gross refinery inputs fell to just above that measure’s five-year average of 8.5 million b/d (Figure 1). Outages and reduced runs resulted in PADD 3 refinery utilization falling from 96% to 63%, while other areas of the country remained virtually unchanged.

Figure 1. Gulf Coast (PADD 3) gross refinery inputs

In addition to refineries, many crude oil and petroleum product pipelines reduced operations or shut down. The most prominent of these was the Colonial Pipeline system, a 2.5 million b/d petroleum product pipeline consisting of approximately 5,500 miles of pipeline that consistently operates at or near full capacity. Colonial connects 29 refineries and 267 distribution terminals, carrying gasoline, diesel, and jet fuel from Houston, Texas to New York Harbor. Decreased supplies of petroleum products available for the pipeline in Houston and Port Arthur, Texas, forced Colonial Pipeline to curtail operations and ship intermittently for a brief period of time before continuous operations at reduced rates were restored on September 6.

Disruption to Colonial Pipeline supplies reduced PADD 1 total motor gasoline inventories by 2.2 million barrels to 60.5 million barrels for the week ending September 1. Of this drawdown, 2.1 million barrels occurred in the Lower Atlantic (PADD 1C) states. This draw is less than a previous outage of the Colonial Pipeline in September 2016, when PADD 1C inventories fell nearly 6 million barrels.

Another logistical complication was created when the ports of Corpus Christi and Houston-Galveston were closed to ship traffic as a result of the storm. Large volumes of crude oil and refined products are both imported and exported through these ports.

In PADD 3, the net result of all these events led to Gulf Coast crude oil inventories to build by 1.7 million barrels for the week ending September 1, 2017. With refinery operations on the Gulf Coast disrupted, crude oil inventories in Cushing, Oklahoma also increased by 800,000 barrels.

The net effect on PADD 3 motor gasoline inventories because of impaired refinery runs and transportation options was a draw of 60,000 barrels to 82.4 million barrels for the week ending September 1, 2017, but inventories remain 9.2 million barrels (13%) higher than the five-year average.

Both crude oil and gasoline prices were influenced by the effects of Hurricane Harvey. Because of lower refinery runs and limited reductions in crude oil production, West Texas Intermediate (WTI) crude oil futures prices on the New York Mercantile Exchange (NYMEX) decreased from $48 per barrel (b) on August 25 when Hurricane Harvey made landfall, to $46/b on August 30. WTI crude oil futures prices have since increased, reaching $49/b on September 6.

By contrast, gasoline futures as well as wholesale and retail prices for gasoline increased because of the impacts on refineries and pipeline infrastructure. On the Gulf Coast, the wholesale price of gasoline increased from $1.66 per gallon (gal) on August 25, 2017 to $2.05/gal on August 31. The benchmark Reformulated Blendstock for Oxygenate Blending (RBOB) gasoline NYMEX futures price increased from $1.67/gal to $2.14/gal over the same period (Figure 2).

Figure 2. Gasoline spot and futures prices

As a result of the changes in wholesale and futures prices, retail prices for gasoline also increased. The U.S. average regular retail gasoline price increased $0.28/gal to $2.68/gal between August 28 and September 4, 2017. The PADD 3 and Houston, Texas prices both increased $0.35/gal to $2.51 per gallon and $2.43/gal, respectively. The statewide Texas average regular retail gasoline price increased $0.40/gal to $2.56/gal (Figure 3).

Figure 3. Regular gasoline retail prices - all formulations

Unlike previous significant Gulf Coast hurricanes, such as Katrina (2005), Gustav (2008), and Ike (2008), Hurricane Harvey had a more westward path, with the strongest effects of the storm mostly missing the largest concentration of offshore oil and gas production facilities. The Bureau of Safety and Environment Enforcement estimates that approximately 2.0% of Gulf of Mexico platforms were evacuated as of September 4, representing shut-in oil production of 121,484 b/d. According to the Texas Railroad Commission and other public sources, EIA estimates the highest on-shore crude oil production outages of approximately 500,000 b/d occurred around August 25 and 26.

The outcomes from Hurricane Irma are likely to be very different. While Hurricane Harvey impacted a major source of U.S. transportation fuels supply, demand in unaffected areas remained intact. Irma, which is projected to impact Florida and potentially the Eastern Seaboard, will likely disrupt demand centers.

Because of the displacement, evacuations, and other safety measures initiated as a result of the Hurricane Harvey, some respondents to EIA’s surveys may not have been able to submit data within the reporting window. EIA has and will continue to work diligently with respondents to ensure robust and accurate statistics.

U.S. average regular gasoline and diesel retail prices increase

The U.S. average regular gasoline retail price increased 28 cents from the previous week to $2.68 per gallon on September 4, up 46 cents from the same time last year. The East Coast price rose nearly 39 cents to $2.72 per gallon, the Gulf Coast price rose 35 cents to $2.51 per gallon, the Midwest price rose 23 cents to $2.54 per gallon, the Rocky Mountain price rose 14 cents to $2.61 per gallon, and the West Coast price rose over 11 cents to $3.02 per gallon.

The U.S. average diesel fuel price increased 15 cents to $2.76 per gallon on September 4, 35 cents higher than a year ago. The Gulf Coast price rose 19 cents to $2.62 per gallon, the East Coast price rose over 16 cents to $2.79 per gallon, the Midwest price rose 14 cents to $2.71 per gallon, the West Coast price rose 13 cents to $3.04 per gallon, and the Rocky Mountain price rose 8 cents to $2.80 per gallon.

Propane inventories gain

U.S. propane stocks increased by 6.3 million barrels last week to 79.9 million barrels as of September 1, 2017, 19.2 million barrels (19.4%) lower than a year ago. Gulf Coast, Midwest, East Coast, and Rocky Mountain/West Coast inventories increased by 4.5 million barrels, 1.4 million barrels, 0.3 million barrels, and 0.2 million barrels, respectively. Propylene non-fuel-use inventories represented 4.3% of total propane inventories.

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Your Weekly Update: 7 - 11 January 2019

Market Watch

Headline crude prices for the week beginning 7 January 2019 – Brent: US$57/b; WTI: US$49/b

  • Crude oil looks set to climb back to previous support levels as OPEC’s new supply deal kicks in and the US Federal Reserve sought to soothe investor confidence after initiating a surprise hike in interest rates that caused widespread global financial panic in December
  • Even as OPEC+ moves forwards with a planned 1.2 mmb/d cut in collective output, production across OPEC had already fallen over November and December as Saudi Arabia throttled production to support falling prices
  • Together with dwindling production in Venezuela, disruptions in Libya and losses in Iran, oil output from OPEC countries has already fallen by 530,000 b/d in December to 32.6 mmb/d, the sharpest pullback since January 2017
  • This has managed to re-assure the market that the global supply/demand balance is on firmer footing, even as Russian oil output reached a post-Soviet high of 11.16 mmb/d, just slightly off the all-time record of 11.42 mmb/d in 1987
  • With the recovery in prices, planned upstream projects will be back on firmer footing, with Rystad Energy expecting some US$123 billion of offshore projects to be sanctioned over 2019 if Brent crude averages US$60/b
  • Also supporting the upward momentum is the removal of 8 oil rigs from the active US rig count, as American drillers weighed up the risks of the fragile trajectory in WTI prices
  • Crude price outlook: Momentum is with crude oil prices this week, and we expect that to continue as OPEC+ implements its production plan, with Brent recovering to US$60-62/b and WTI to US$51-53/b


Headlines of the week

Upstream

  • Eni has acquired the remaining 70% of the Oooguruk field in Alaska from Caelus Natural Resources, bringing its stake to 100% to synergise with the nearby Nikaitchuq field, where Eni also owns a 100% interest interest
  • The deepwater Egina field in Nigeria, operated by Total through an FPSO, has started up production, with peak output expected at 200,000 b/d
  • Commercial production of crude at PAO Novatek/Gazprom’s Yaro-Yakhinskoye field has commenced, with output expected at 24,000 b/d
  • Total has sold a 2% interest in Oman’s Block 53 to Sweden’s Tethys Oil, bringing it into Occidental Petroleum’s 100,000 b/d Mukhaizna field
  • Brazil is preparing for its sixth round of upstream auctions, offering up pre-salt acreage in five areas expected to raise more than US$2 billion in sales
  • After recently making its 10th discovery in Guyana, ExxonMobil has its sights set on more as it drills two more exploration wells – Haimara-1 and Tilapia-1 – in the prolific Stabroek block, both close to existing discoveries
  • Ecuador is initiating a probe into some US$4.9 billion worth of oil-related infrastructure projects initiated by the previous administration on charges of corruption and looting

Downstream

  • China appears to be tempering crude demand, with the first batch of crude oil import quotas issued to state and private refineries at 26% lower than 2018, with quotas for teapots at some 78% of the 89.84 million tons approved
  • Saudi Aramco has acquired complete ownership of German specialty chemicals producers Lanxess AG by acquisition Dutch firm Arlanxeo’s 50% stake at €1.5 billion, strengthening its foray into petrochemicals
  • Iran will be investing some US$212 million into Chennai Petroleum’s 180 kb/d expansion of the Nagapatinam refinery on India’s east coast, as Iran looks for ways to ensure captive demand for its crude in one of its largest markets
  • The Mariner East 2 NGLs pipeline – transporting ethane, propane and butane over 560km to the Marcus Hook processing plant in Pennsylvania – has been completed, with the Mariner East 2X pipeline schedules for late 2019

Natural Gas/LNG

  • Shell’s 3.6 mtpa Prelude FLNG has finally started up initial production, the last of Australia’s giant natural gas projects to be completed
  • Brunei Shell Petroleum (BSP) has completed the onshore Darat Gas Project in Lumut, expanding LNG capacity in Brunei by 5% at the Rasau station
  • ExxonMobil’s Rovuma LNG project in Mozambique will be aiming to sanction FID in 2019 for its first phase, involving two trains with a combined capacity of 7.6 million tpa from the offshore Area 4 block
  • As LNG developments in Papua New Guinea move quickly to commercialisation, the PNG government has passed new laws to impose a domestic gas requirement and other provisions for new gas projects, to ensure adequate supply of resources for growing local demand
January, 11 2019
The Prospects of Venezuelan Oil

At some point in 2019, crude production in Venezuela will dip below the 1 mmb/d level. It might already have occurred; estimated output was 1.15 mmb/d in November and the country’s downward trajectory for 2018 would put December numbers at about 1.06 mmb/d. Financial sanctions imposed on the country by the US, coupled with years of fiscal mismanagement have triggered an economic and humanitarian meltdown, where inflation has at times hit 1,400,000% and forced an abandonment of the ‘old’ bolivar for a ‘new bolivar’. PDVSA – once an oil industry crown jewel – has been hammered, from its cargoes being seized by ConocoPhillips for debts owed to the loss of the Curacao refinery and its prized Citgo refineries in the US.

The year 2019 will not see a repair of this chronic issue. Crude production in Venezuela will continue to slide. Once Latin America’s largest oil exporter – with peak production of 3.3 mmb/d and exports of 2.3 mmb/d in 1999 – it has now been eclipsed by Brazil and eventually tiny Guyana, where ExxonMobil has made massive discoveries. Even more pain is on the way, as the Trump administration prepares new sanctions as Nicolas Maduro begins his second term after a widely-derided election. But what is pain for Venezuela is gain for OPEC; the slack that its declining volumes provides makes it easier to maintain aggregate supply levels aimed at shoring up global oil prices.

It isn’t that Venezuela doesn’t want to increase – or at least maintain its production levels. It is that PDVSA isn’t capable of doing so alone, and has lost many deep-pocketed international ‘friends’ that were once instrumental to its success. The nationalisation of the oil industry in 2007 alienated supermajors like Chevron, Total and BP, and led to ConocoPhillips and ExxonMobil suing the Venezuelan government. Arbitration in 2014 saw that amount reduced, but even that has not been paid; ConocoPhillips took the extraordinary step of seizing PDVSA cargoes at sea and its Caribbean assets in lieu of the US$2 billion arbitration award. Burnt by the legacies of Hugo Chavez and now Nicolas Maduro, these majors won’t be coming back – forcing Venezuela to turn to second-tier companies and foreign aid to extract more volumes. Last week, Venezuela signed an agreement with the newly-formed US-based Erepla Services to boost production at the Tia Juana, Rosa Mediano and Ayacucho 5 fields. In return, Erepla will receive half the oil produced – generous terms that still weren’t enough to entice service giants like Schlumberger and Halliburton.

Venezuela is also tapping into Russian, Chinese and Indian aid to boost output, essentially selling off key assets for necessary cash and expertise. This could be a temporary band-aid, but nothing more. Most of Venezuela’s oil reserves come from the extra-heavy reserves in the Orinoco Belt, where an estimated 1.2 trillion barrels lies. Extracting this will be extremely expensive and possibly commercially uneconomical  – given the refining industry’s move away from heavy grades to middle distillates. There are also very few refineries in the world that can process such heavy crude, and Venezuela is in no position to make additional demands from them. In a world where PDVSA has fewer and fewer friends, recovery will be extremely tough and extremely far-off.  

Infographic: Venezuelan crude production:

  • 2015: 2.7 mmb/d (output), 1.9 mmb/d (exports)
  • 2016: 2.6 mmb/d (output), 1.8 mmb/d (exports)
  • 2017: 2.1 mmb/d (output), 1.5 mmb/d (exports)
  • 2018: 1.3 mmb/d (output), 1.2 mmb/d (exports)
  • November 2018: 1.15 mmb/d (output), 1.05 mmb/d (exports)
January, 10 2019
Your Weekly Update: 31 December 2018 - 4 January 2019

Market Watch

Headline crude prices for the week beginning 31 December 2018 – Brent: US$54/b; WTI: US$46/b

  • Crude oil will start 2019 on a stronger note after being routed last month over concerns that surging American production will swamp OPEC’s supply efforts and a global financial panic triggered by US trade policies and tighter monetary policy by the Federal Reserve
  • OPEC is continuing to re-iterate that it will play a strong role in managing global oil supply and demand, but there are worries that it may have to switch tactics to deal with the non-stop rise in US shale volumes
  • Concerns over the health of the global economy are also on the minds of traders, with signs that the Chinese economy is slowing down as the country’s manufacturing index has begun to contract
  • Suppression of demand growth could cap the ability for crude oil to rise up to the predicted average of US$70/b for the year, making supply management all the more important with Saudi Arabia pledging ‘deeper cuts’
  • American drillers added 3 new rigs in total heading into the new year, underscoring the continuous upward trajectory for US oil production – with signs pointing to the 12 mmb/d mark likely to be hit by mid-2019
  • Crude price outlook: The market should stabilise itself at US$54-55/b for Brent and US$46-47/b for WTI, with traders watching for signs over the implementation of OPEC+’s new supply deal

 

Headlines of the week

Upstream

  • BP is aiming to sanction development of the Platina field in Angola’s deepwater Block 18 in 1H2019, which would be the supermajor’s first new development in the country since 2013, following an extension of Greater Plutonio to 2032
  • Shell has completed the sale of its New Zealand upstream assets – including the Māui, Pohokura and Tank Farm entities – to Austria’s OMV for US$578 million
  • Eni UK has begun drilling in Rowallan well in the Central North Sea with Serica Energy, targeting condensate-rich volumes in well 22/19c-G
  • In South Africa, Total has begun drilling the Brulpadda-1AX well in offshore Block 11B/12B, with prospective resources of 500 million barrels of crude
  • Equinor has completed the sale of two assets on the Norwegian Continental Shelf, selling a 77.8% stake in King Lear to Aker BP for US$250 million as well as a 42.38% stake in Tommeliten Unit and 30% in PL044 to Poland’s PGNiG for US$220 million
  • Commercial crude production at the SARB and Umm Lulu fields in Abu Dhabi has begun, with Cepsa offering first crude from the sites last month

Downstream

  • Saudi Aramco has established the Saudi Aramco Retail Company (RetailCo), a new subsidiary focus on fuel retailing in the Kingdom as part of its plan to expand its business further downstream
  • After starting up official commercial production last month, Vietnam’s Nghi Son refinery has offered up its first cargo of jet fuel, joining the site’s existing slate of gasoline and gasoil volumes
  • BP and SOCAR have signed an agreement for a new petrochemicals joint venture in Turkey, with the proposed site in Aliaga aiming to have a capacity of 1.25 mtpa of PTA, 840,000 tpa of paraxylene and 340,000 tpa of benzene
  • Total and Angola’s Sonangol are extending their partnership downstream, forming a joint venture to focus on fuel and lubricants distribution and sales in Angola, as well as developing a new fuel retail network

Natural Gas/LNG

  • Australia’s Woodside Petroleum has inked a new mid-term deal with German utility RWE supplying LNG from the Corpus Christi LNG project in Texas from 4Q2020 to 4Q2022 – an extension of the 12 cargo, 2-year contract signed between both parties last year
  • Gazprom and Itochu have signed an MoU to cooperate on the proposed Baltic LNG export project, a 10 mtpa liquefaction plant planned in Leningrad
  • Eni has received permission from the Indonesian government to fast-track the Merakes Development Project in Kalimantan’s Kutei Basin, aimed at delivering additional volumes to the Bontang LNG plant
  • Indonesia is reviewing Inpex’s revised development plan for the Abadi LNG project as the Japanese firm has reportedly identified a small island in South Tanimbar as the location for the plant
January, 03 2019