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Last Updated: November 24, 2016
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Tighter marine fuel sulfur limits will spark changes by both refiners and vessel operators.

The sulfur content of transportation fuels has been declining for many years due to increasingly stringent regulations. In the United States, federal and state regulations limit the amount of sulfur present in motor gasoline, diesel fuel, and heating oil. New international regulations limiting sulfur in fuels for ocean-going vessels, set to take effect in 2020, have further implications for both refiners and vessel operators at a time of high uncertainty in future crude oil prices, which will be a major factor in their decisions.

Bunker fuelthe fuel typically used in large ocean-going vesselsis a mixture of petroleum-based oils. Residual oilthe long-chain hydrocarbons remaining after lighter and shorter hydrocarbon fractions such as gasoline and diesel have been separated from crude oilcurrently makes up the largest component of bunker fuel. The sulfur content of crude oil tends to be more concentrated in heavier hydrocarbon molecules, with heavier petroleum products such as residual oil having higher sulfur content than lighter ones like gasoline and diesel.

The International Maritime Organization (IMO), the 171-member state United Nations agency that sets standards for marine fuels, decided in October to move forward with a plan to reduce the maximum amount of sulfur and other pollutants present in marine fuels used on the open seas from 3.5% by weight to 0.5% by weight by 2020. This decision follows several other marine fuel regulations limiting sulfur content, such as the implementation of Emissions Control Area (ECA) requirements in coastal waters and specific sea-lanes in North America and Europe, where the maximum sulfur content of fuels was limited to 0.1% by weight starting in July 2015 (Figure 1).

Additionally, the state of California and the European Union have regulations on the sulfur content of marine fuels, and the types of fuel used when ships are at dock, waiting to dock, or are maneuvering within port. For example, a vessel approaching the port of San Francisco may have to change its fuel mix twice: once when going from the open seas higher-sulfur fuel of mostly residual oil, to an ECA compliant lower-sulfur fuel mix, and again to a marine diesel fuel compliant with California's ocean-going vessel regulations for use within ports (Figure 2).

The IMO sulfur limits that take effect in 2020 will affect the fuel used in the open seas, the largest portion of the approximately 3.9 million barrels per day of global marine fuel use, according to the International Energy Agency, presenting several challenges for both refiners and shippers.

The first challenge for refiners is to increase the supply of lower-sulfur blendstocks to the bunker fuel market. Refiners have several potential paths. One approach is to divert more low sulfur distillates into the bunker fuel market. Another option would be to use low sulfur intermediate refinery feedstocks in bunker blends. In both cases, care is required to assure that new fuels continue to meet specifications for use in marine engines.
A second challenge for refiners is what to do with the high sulfur residual oil that can no longer be blended into bunker fuel. Adding capacity to desulfurize residual oil is one option, but the economics do not currently appear to be attractive. An alternative strategy is to build or expand refinery units that take heavy hydrocarbons, such as residual oil, and upgrade them into lighter, more valuable products, but this would require large investments. In either of these cases, refineries would be faced with investments and costs that are acceptable only if there is certainty of future demand from the shipping industry.

Vessel operators also have several choices for compliance with the new IMO sulfur limits. For example, IMO regulations allow for the installation of scrubbers, which remove pollutants from ships exhaust, allowing them to continue to use higher-sulfur fuels. Some ship owners that operate primarily in coastal areas, such as cruise lines and ferries, opted to install scrubbers on their vessels as the new ECA regulations came into force. The possibility of widespread scrubber installations, which would allow for continued use of higher sulfur residual oils, could make refiners hesitant about making large investments to build refining units capable of upgrading the residual oils.

Ships also have the option of switching to new lower sulfur blends or to non-petroleum based fuels. Some newer ships and some currently being built have engines that would allow them to use liquefied natural gas (LNG) rather than petroleum-based products. However, the infrastructure to support use of LNG as a shipping fuel is currently limited in both scale and availability.
Vessel operators and shippers will also likely be faced with the higher costs as the sulfur content in marine fuels decreases and the role of distillate in the bunker fuel market increases. An example of the price difference between fuels can be observed at the refining and trading hub in Northwest Europe, known as the ARA, collectively the cities Amsterdam and Rotterdam, in the Netherlands and Antwerp, in Belgium. Prices for low sulfur gasoil, a type of distillate, in the ARA has averaged over $20 per barrel more than high sulfur fuel oil (residual oil for use as a fuel) to date in 2016. Fuel blends used to meet the new IMO regulations are likely to price somewhere in between these two fuels (Figure 3).

U.S. average regular gasoline and diesel retail prices decline
The U.S. average regular gasoline retail price dropped three cents from the previous week to $2.16 per gallon on November 21, up six cents from the same time last year. The Gulf Coast price fell six cents to $1.92 per gallon, while the West Coast, Rocky Mountain, and East Coast prices each fell five cents to $2.59 per gallon, $2.19 per gallon, and $2.17 per gallon, respectively. The Midwest price rose two cents to $2.01 per gallon.

The U.S. average diesel fuel price dropped two cents to $2.42 per gallon, down two cents from the same time last year. The Rocky Mountain price fell four cents to $2.46 per gallon, while the West Coast and Midwest prices each fell three cents to $2.73 per gallon and $2.36 per gallon, respectively. The Gulf Coast price dipped two cents to $2.30 per gallon, and the East Coast price fell a penny to $2.44 per gallon.

Propane inventories gain U.S. propane stocks increased by 1.8 million barrels last week to 102.7 million barrels as of November 18, 2016, 3.5 million barrels (3.3%) lower than a year ago. Gulf Coast and Rocky Mountain/West Coast inventories increased by 1.7 million barrels and 0.1 million barrels, respectively, while East Coast and Midwest inventories remained virtually unchanged. Propylene non-fuel-use inventories represented 4.0% of total propane inventories.

Residential heating oil price unchanged while residential propane price increases as of November 21, 2016, residential heating oil prices averaged around $2.38 per gallon, virtually unchanged from last week and less than one cent per gallon higher than last year at this time. The average wholesale heating oil price is $1.55 per gallon, nearly eight cents per gallon higher than last week and 13 cents per gallon more than a year ago.

Residential propane prices averaged nearly $2.06 per gallon, one cent per gallon more than last week and almost 11 cents per gallon more than one year ago. Wholesale propane prices averaged $0.62 per gallon, about the same price as last week but 13 cents per gallon more than last year's price.

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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