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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: 18 - 22 March 2019

Market Watch

Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b

  • Global crude oil prices slipped at the start of the week, as OPEC and its OPEC+ allies met in Azerbaijan to discuss the state of the club’s oil output cuts
  • Crude oil prices had risen prior as on speculation that the OPEC+ group would extend its supply deal, but this was dashed when OPEC+ instead decided to defer a decision until June, scrapping a planned OPEC extraordinary meeting in April because it was ‘too soon to make a decision on extending oil-supply cuts’
  • Observed friction between Russia and Saudi Arabia over the cuts could be behind the delay; Saudi Energy Minister Khalid al-Falih is said to be in favour of continue supply reduction through 2019 while his Russian counterpart Alexander Novak said that uncertainty over Venezuela and Iran would ‘make it difficult’ to decide until May or June
  • Other OPEC members have also not expressed any more willingness to extend the cuts, and Saudi Arabia seems to be unusually focused on a united front, rather than strong-arming the rest of the gang to its own aims
  • Some reprieve could be coming for OPEC, as the US Energy Information Administration trimmed its 2019 output forecast by 110,000 b/d to 12.3 mmb/d, seeing a scale-back in smaller shale plays and the US Gulf of Mexico
  • Echoing this, the US active rig count declined for a fourth consecutive week, following up a 9 and 11 rig drop with the net loss of a single oil rig
  • A better prognosis on demand leading into the northern summer and faith that OPEC+ will continue to work towards preventing a major crude surplus from returning should keep crude prices trending higher. We are looking at a range of US$66-68/b for Brent and US$58-60/b for WTI

Headlines of the week

Upstream

  • Eni has announced a major oil discovery in Angola’s Block 15/06, with the Agogo prospect joining the Kalimba and Afoxé discoveries, adding some 450-650 million barrels of light oil in place to the block
  • ExxonMobil has delayed its US$1.9 billion, 75,000 b/d Aspen oil project as Canada’s Alberta province continues to grapple with the pipeline bottleneck that has caused a glut of production trapped in the inland province
  • Lukoil had hit a new milestone with the Vladimir Filanovsky field, which has now reached 10 million tons of crude oil supplied through the Caspian Pipeline Consortium (CPC) system, transporting oil to the Black Sea for transport
  • ExxonMobil is looking to reduce field costs in its Permian Basin assets to about US$15/b, a highly-competitive target usually only seen in the Middle East
  • Eni and Qatar Petroleum have agreed to a farm-out agreement that will allow QP to take a 25.5% interest in Mozambique’s Block A5-A, joining other partners Sasol (25.5%) and Empresa Nacional de Hidrocarbonetos (15%)
  • Successive industrial action strikes have begun in the UK, affecting the Shetland Gas Plant and Total Alwyn, Dunbar and Elgin platforms in the North Sea
  • ADNOC has begun planning for an output drive at its Umm Shaif field, which would increase output at the giant field to 360,000 b/d

Midstream & Downstream

  • Shell is planning to restart the Wilhelmshaven refinery in Germany through a deal with terminal firm HES, which will re-convert the existing tank farm into a 260 kb/d refinery that will focus on producing IMO-mandated low sulfur fuels
  • Petronas is offering first oil products cargos from its 300 kb/d RAPID refinery in April, ahead of planned full commercial production in October 2019
  • Lukoil is now planning to invest some US$60 million in its 320 kb/d ISAB refinery in Augusta, Italy to produce high-quality, low-sulfur fuels to meet IMO standards, instead of selling it as previously considered in 2017
  • The Ugandan government has approved the technical proposal for the country’s first refinery in Kabaale, which will run on crude from the Albertine rift basin
  • Kenya expects to have the Lamu crude export terminal operational by the end of 2019, syncing with the start of Tullow Oil’s Kenyan oilfields

Natural Gas/LNG

  • The UK Onshore Oil and Gas body has published updated figures for UK onshore shale potential based on three test sites in north England, estimating that productivity could be at 5.5 bcf per well leading to annual gas production reaching 1.4 tcf by the early 2030s
  • Eni’s winning streak in Egypt continues, announcing a new gas discovery in the Nour 1 New Field Wildcat, which join its existing assets under evaluation there
  • Conrad Petroleum’s development plan for the Mako gas field in Indonesia has been approved by Indonesian authorities, paving way for development to start on the field with its estimated 276 bcf of recoverable resources
  • Ventures Global LNG is planning to double the capacity of its LNG projects – including the Calcasieu Pass and Plaquemines LNG sites in Louisiana – from 30 mtpa to a new 60 mtpa, having already booked all output from Calcasieu
  • Darwin LNG is set to choose the source of its backfill gas by the end of 2019, with the Barossa field more likely to be taken than the Evans Shoal field
March, 22 2019
Technology may be a game changer for future oil supply

Risk and reward – improving recovery rates versus exploration

A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.

How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.

1. Reserve growth

An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.

2. pre-drill tight oil inventory and conventional pre-FID projects

They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve. 


3. Contingent resource


These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.

4. Yet-to-find

Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.

Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.

But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.

To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).

Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.

Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.

If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects. 


Global oil supply through 2040 


March, 22 2019
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