Power to the islands

The article below appeared in The Analyst column in the 26 July issue of Natural Gas Daily, a daily outlook on the gas and LNG markets by Interfax Global Energy. Peter Stewart spoke at the London Centre of International Law Practice on the Caribbean region’s oil and gas potential.
Small Island Developing States in the Caribbean are transitioning from legacy energy supplies based on refined products to renewable sources including solar, wind and biofuels. The region also has significant oil and gas potential, but unresolved border issues have discouraged its exploitation.
Whereas gas is being hailed by IOCs as the fuel of the future because it can support growth in renewables by reducing intermittency problems, the high cost of delivering gas to the islands makes it unviable in economic terms in the Caribbean.
So far, only three LNG terminals have been installed on the Caribbean islands. Jamaica installed the Golar Arctic FSU at Montego Bay under a two-year contract in 2016, adding to the land-based regas facilities at Penuelas in Puerto Rico (2000) and Punta Caucedo in the Dominican Republic (2003).
One of the challenges faced by the islands is the small scale of their LNG shipments. Typically, the three terminals take less than one cargo per month, which makes delivered costs high. Shipments of containerised LNG from the United States to Barbados in 2017, for example, have been priced at more than $10/MMBtu on a delivered basis – nearly double the average LNG spot price to Latin America, which is around $5.50/MMBtu.
LNG can be supplied from the 15 mtpa plant at Point Fortin in Trinidad and Tobago, operated by Atlantic LNG, but delivered costs are often dollars higher than prevailing wholesale prices because of the scale and logistics of deliveries.
Trinidad is already having difficulty meeting the growing demand for gas from local industry, which includes methanol and ammonia plants, while at the same time servicing its LNG export commitments. The country is exploring new gas-prone acreage, but only one project is due to start up soon: Juniper, owned by BP (70%) and Repsol (30%), in H2 2017. The project involves development of the Corallita and Lantana gas fields in the Columbus Basin to the southeast of Trinidad. Several hydrocarbon reservoirs off Trinidad are close to the marine border with Venezuela. Recent finds in the highly prospective waters offshore Suriname and Guyana are also close to Venezuelan waters.
The London Centre for International Law Practice seminar on hydrocarbons in the Caribbean, held on 21 July, heard that the lack of demarcation of marine boundaries between the islands and between them and countries such as Venezuela and Guyana has been a disincentive to developing the region’s substantial oil and gas resources.
Climate change targets
The Caribbean countries have extensive plans to mitigate the impacts of climate change in the Intended Nationally Determined Contributions made under the Paris agreement. Oil price volatility has also been a problem for the region, so focusing on renewables in the energy mix provides economic security as well as having environmental benefits.
The Caribbean Community Energy Policy (CEP) provides a regional framework for the implementation of national plans. The Caribbean Sustainable Energy Roadmap and Strategy was developed under the CEP to provide a coherent strategy for transitioning to sustainable energy. Targets include reducing energy intensity by 33% by 2027 and carbon dioxide emissions by 22% by 2022 and 36% by 2027. Building up renewables in power generation is crucial for these targets to be met: the CEP envisages renewables contributing 28% of power by 2022 and 47% by 2027.
A September 2015 study by the International Monetary Fund recommended that the Caribbean countries reduce their exposure to oil price volatility by diversifying the power supply mix and improving energy efficiency through energy-saving technologies on the demand side.

Fuel Oil on the boil as supplies tighten

Market analysis
Although fuel oil demand is under threat due to a bunker fuel specification change in 2020, recent production cuts from OPEC and several non-OPEC countries have provided a lifeline to the bottom of the barrel. Furthermore, the advent of complex refineries in the Middle East, Asia and Russia is leading to tighter supplies. The fuel oil market has been on boil in all key refining regions this year and any increase in OPEC cuts has the potential to keep on buoying its prices, although the end of the cooling demand season in the Middle East could put a ceiling on cracks.

  • In the Middle East, regional demand for fuel oil is at its seasonal peak. Saudi Arabia consumed 625,000 bpd of fuel oil in April, the highest since October 2016, although the total fuel oil burn over the summer looks likely to be less than last summer because the kingdom’s utilities are using more natural gas.
  • In South Asia, Pakistan is seeking 950,000 mt of fuel oil for September as stocks at the country’s power generators have fallen to just 3 – 4 days of supply compared to the obligatory level of at least 10 days. In Pakistan, debt-stricken power companies frequently fail to pay their fuel oil suppliers on time, which leads to knock on problems in the international market. There has been talk that the government in Islamabad may intervene, but a long-term solution is not in sight.
  • Fuel oil flows to the Far East from the West are well below normal levels, because the strong fuel oil market in Europe is limiting flows to Asia. Arbitrage shipments for July are estimated to be just 5 million mt.
  • Fuel oil cracks in Asia have been around $5/bbl stronger than last year. The discount of Singapore 380 cst fuel oil to Dubai crude averaged around $1/bbl in July this year, compared to around $6/bbl in July 2016.
  • Venezuela’s fuel oil exports to China have almost vanished from the market in the East, as refinery problems have tightened supply. The country’s refineries are operating at less than 50 percent of capacity according to the trade union representative of the Venezuelan Federation of Petroleum Workers. Moreover, some Venezuelan ports are also facing problems, reducing refined product exports to Asia and Europe. This has exacerbated an already tight market. Less and less fuel oil is being produced in China. In fact, fuel oil output in the Middle Kingdom was down more than 1.5 percent year-on-year in June.
  • Although flows from the Middle East could pick up once the cooling season is over, reports have circulated that Saudi Arabia might reduce its crude oil exports unilaterally by up to a further 1 million bpd. This would reduce medium and heavy sour crude supply, indirectly cutting fuel oil production capacity. This means that fuel oil cracks could remain supported even in the northern hemisphere winter, when demand for the fuel usually eases.
  • Tighter prompt fuel oil markets from Durban in South Africa to Rotterdam in Holland have led to a backwardated market structure. One reason for this has been lower inventories. In the US, for example, residual fuel inventories have fallen to their lowest levels since January 2015. in Singapore, fuel oil stocks remain seasonally low, although they have recovered from the 2 1/2 year lows seen at the beginning of June. Euroilstock data shows EU-16 fuel oil inventories in June stood at around 11.5 percent below levels a year ago. Fuel oil stocks in the Amsterdam-Rotterdam-Antwerp (ARA) are down around 12 percent year-on-year. Although fuel oil stocks are relatively abundant at Fujairah in the UAE, this is largely due to weaker bunker demand in the wake of a trade embargo on Qatar imposed by Saudi Arabia and a number of its regional allies.
  • Due to surging demand, some trading houses are opting for shorter-period stockpiling of fuel oil . In Singapore, fuel oil storage rates have tumbled to $5-6 per cubic metre from $6.50-7.00 per cubic metre a few years ago. Indeed, some traders are stockpiling fuel oil on tankers as VLCC freight is down more than 50 percent from levels 18 months ago.
  • The fuel oil price rally has been helped by OPEC’s decision to extend its 1.2 million bpd production cut until March 2018. OPEC agreed the cuts, which were supported by pledges for a further nearly 600,000 bpd by a group of non-OPEC countries, in November 2016. Resource Economist estimates the production cuts have taken as much as 1.3 million bpd of medium and heavy sour crude off the market. Lower supplies from Latin America have resulted partially from natural declines rather than the OPEC/non-OPEC agreement. Only Saudi Arabia has tried to reduce lighter crude exports instead of heavier barrels but any additional cuts if implemented are likely to be medium and heavy sour.
  • Global fuel oil production supply is also decreasing with the start-up of sophisticated new refineries in India, China and the Middle East, which produce little or no fuel oil. Their advent has also led to the demise of simpler refineries, further tightening fuel oil supply. Russian fuel oil exports are also falling as the country’s refineries boost their processing depth, while the Kremlin has imposed a tax regime that equalises export duties on crude and fuel oil, lessening the incentive to export fuel oil.
  • Though fuel oil demand has been falling in developed countries, a number of non-OECD nations still depend on fuel oil for power generation, particularly in the Far East, the Middle East and South Asia. While China is now gradually reducing its fuel oil consumption, South Asia along with neighbouring GCC countries have become the dumping ground for the bottom of the barrel.

Although the International Maritime Organization’s decision to reduce sulphur specifications in bunker fuel to 0.5 percent from 3.5 percent by 2020 will have a detrimental impact on fuel oil demand, rumours of the death of fuel oil look greatly exaggerated. Downward pressure on fuel oil may re-emerge when oil producers end their crude oil production cuts but until then, fuel oil cracks are likely to remain strong..

Iran threatens big rise in oil and gas output and exports

The article below appeared in the Analyst column in the 12 July 2017 edition of Natural Gas Daily, an Interfax newsletter focussed on the global gas and LNG markets.

Iran’s deputy oil minister, Amir Hossein Zamaninia, said at the World Petroleum Congress in Istanbul this week that his country planned to ramp up gas production to nearly 1.37 billion cubic metres per day and oil production to around 5 million barrels per day (MMb/d) by 2021.

Zamaninia said Iran currently produces more than 800 million cubic metres per day (MMcm/d) of gas, equivalent to over 292 bcm/y, although output in 2016 was estimated at 202 bcm/y by the BP Statistical Review of World Energy. Iran’s oil production is currently around 3.7 MMb/d.

The planned ramp-up in production capacity suggests Iran aims to become a major player in the global oil and gas market now the United States and Europe have eased sanctions on the country. Tehran is particularly bullish on its gas plans because it believes the fuel will supersede oil in the global energy mix “in a few years”, Zamaninia told Turkey’s Anadolu news agency. Iran holds the world’s second-largest gas reserves after Russia and the world’s fourth-largest oil reserves.

However, Iran’s ambitious plans could put it at odds with rival oil and gas producers in the Middle East that also aim to boost production. Iran signed up to OPEC’s agreement with non-OPEC producers to cut oil production, which came into effect at the start of this year and is due to expire in March 2018. Geopolitical tensions between Iran and Saudi Arabia, the world’s largest oil exporter, have escalated since the 2011 Arab Spring. The Saudis and a number of allies recently broke ties with Qatar – the world’s largest LNG exporter, which shares the world’s largest gas field with Iran. Riyadh accused Doha of being too cosy with its regional arch-enemy. Tehran subsequently upped the ante by sending food aid to Qatar.

Iran is negotiating with a number of IOCs about developing the country’s production potential, and Zamaninia said his country aims to sign 10 contracts over the next 10 months. Discussions are being held on 27 projects that are collectively worth $200 billion, and the country expects to sign deals with Russian firms within the next 5-6 months, Zamaninia added. Iran has been discussing upstream projects with Gazprom and Lukoil.
The plans suggest Tehran has not been thwarted by the threat of renewed US sanctions. Zamaninia said the recent deal with French major Total suggested a return to the era of sanctions is “very unlikely, if not impossible”.

South Pars contract

Iran signed its first memorandum of understanding since the sanctions were ended with Total in 2016, and earlier this month signed a $4.8 billion Iran Petroleum Contract with the French major and China National Petroleum Corp. (CNPC) to develop Phase 11 of the South Pars gas field. Total will be operator of the project, with a 50.1% share, while CNPC holds a 30% stake. Petropars, a subsidiary of state-owned National Iranian Oil Co., holds a 19.9% stake. The contract will be carried out in two phases over 20 years.
Iran said it expects to produce 56 MMcm/d (equating to 20.4 bcm/y) of gas from Phase 11 once it is in full production. South Pars holds gas reserves estimated at 51 trillion cubic metres as well as 50 billion barrels of condensate and NGLs.

Zamaninia said Tehran is also considering the viability of a pipeline to send Iranian gas to Europe via Turkey. The project has been mooted in the past but is unlikely to be developed anytime soon as it would put Iranian gas into competition with Russian exports in a market that has seen little growth in demand in recent years.
Russia is the largest supplier of gas to Europe and is a key regional ally of Turkey and Syria, which has long-standing ties with Iran. Meanwhile, Turkey plays a large role in the region’s geopolitics because it borders Syria, Iraq and Iran.

Peter Stewart

Crude oil quality differentials shrink as heavy sour grades tighten

The price differential between light sweet crude oils and heavier sour crudes has narrowed as OPEC and several non-OPEC oil producers’ continue to implement output cuts. Rising sweet crude production in Libya, Nigeria and the US have also contributed to exceptionally narrow sweet/sour differentials, leading refiners in the West to process more sweeter grades in their refineries.
The Brent/Dubai EFS has remained below $1/bbl for several months, while Urals in Europe is now trading at the narrowest discount against Dated Brent since November 2014. In the US, Mars is trading at a discount of less than $1/bbl to US benchmark West Texas Intermediate (WTI). At these levels, it does not pay to process too much medium and heavy sour crude, especially in the West as fuel oil demand in the Atlantic basin is falling.
OPEC agreed to implement production cuts of nearly 1.8 million bpd with a group of non-OPEC countries from January 2017, and the last OPEC meeting in May agreed that the cuts would be extended until March 2018.
Asia has been hit hard by OPEC production restraint, which have choked off its main source of medium and heavy sour crude oil supplies. Refiners in the East are either resorting to sweeter grades or buying spot barrels from other regions, as interregional spreads tighten. Indian refiners have already developed an appetite for Russia’s main export grade Ural. Now, they are switching to Mars. The state-owned Indian Oil Corporation (IOC) is bringing a VLCC carrying 1.6 million bbl of the US grade along with 400,000 barrels of Western Canadian Select (WCS) to its refineries.
Unlike in the West, fuel oil demand is still relatively healthy in Asia. Therefore, the East is unlikely to replace medium and heavy sour crude with sweeter crude. However, higher sweet crude processing in several parts of the world is further stretching the already tight fuel oil market. New sophisticated refineries in Asia and the Middle East are not capable of producing as much fuel oil as older and simpler refineries.
While sour crude supplies have been reduced significantly, oil storage tanks are brimming with light sweet supplies especially in the Atlantic Basin. Continued low oil prices prompted the Energy Information Administration in the US to revise down its production growth forecast for US shale oil recently to 310,000 bpd from its previous forecast of 320,000 bpd. However, the rising rig count is a harbinger of further production additions next year.
Libyan output has surpassed the 1 million bpd mark, the highest level since June 2013. Nigerian exports in August are expected to reach 2 million bpd. Indeed, OPEC might ask these African nations to limit their supplies but only if they continue to increase.
The upshot for OPEC and non-OPEC oil producers is that a cut of more than 1.5 million bpd of sour production has been replaced with a similar volume of sweet crude oil from Libya, Nigeria and the US. Sour crude availabilities could be hit further if geopolitical problems in Venezuela persist.
Some medium sour stocks are being drawn down to make up for production cuts but once these have been absorbed, the sour market will tighten further. This will impact gasoil and fuel oil supplies as medium and heavy sour crudes have higher middle distillate and heavy distillate yields.
This could mean that fuel oil supplies remain tight even after the peak demand period during the northern hemisphere summer, despite lower cooling demand.
Moreover, heating fuel supplies could be stretched especially if the winter is harsh. There are already signs of higher middle distillate demand. India is sucking up more and more diesel due to strong economic growth. European economies are recovering, resulting in higher diesel demand, while shale oil producers require more diesel to allow them to maximize oil production.
These are all ingredients which point to higher oil prices at the end of this year.
Ehsan Ul-Haq

Qatar’s liquefaction plans will extend LNG glut

The article below appeared in the July 5, 2017 edition of Natural Gas Daily, a daily gas publication from Interfax Global Energy

Qatar’s plan to sharply increase gas liquefaction capacity at its 77-mtpa Ras Laffan facility over the next five years puts the emirate on a potential collision course with the United States, which is dramatically expanding its own LNG export capacity. Qatar’s decision also threatens to extend the current glut of LNG – which many analysts had expected to be gradually absorbed over the next five years – until at least 2025.

Global LNG prices have dropped from peaks of $21/MMBtu in 2014 to around $5/MMBtu following the wave of new liquefaction projects that have been commissioned in Australia and the startup of the Sabine Pass plant on the US Gulf Coast in 2016.

Australia was expected to overtake Qatar as the world’s largest exporter of LNG in 2018 when its new plants, construction on which got under way from 2012 onwards, are due to be completed. The Australian projects, which will boost the country’s liquefaction capacity to more than 81 mtpa, typically have breakeven prices ranging from $10-15/MMBtu and have been relying on an improvement in global prices to ensure investment returns. After a wave of startups between 2014 and 2016, this March saw the third train at Chevron’s giant Gorgon plant commissioned. The Ichthys project is due online in Q3 2017, and the Prelude FLNG project should be completed next year.

The US projects, also under construction and due for completion by 2020, include the Freeport and Corpus Christi LNG projects in Texas, Cameron LNG in Louisiana, the smaller Cove Point project in Maryland, and new trains at Cheniere Energy’s Sabine Pass. When these are completed, the US will have an LNG export capacity of 70-75 mtpa. Cheniere sells LNG from Sabine Pass on a Henry Hub-linked formula, unlike the Australian projects, gas from which is typically sold on an oil-indexed basis.

The Australian and US projects combined will add at least 135 mtpa to global liquefaction capacity compared with 2011, when Japan was forced to hike LNG imports after the Fukushima disaster led to the shutdown of the country’s nuclear fleet. The latest GIIGNL annual report estimated global liquefaction capacity stood at 340 mtpa at the end of 2016, a 22% increase on the 278 mtpa of capacity in 2011.

Qatar boost

Qatar Petroleum announced this week that it will expand production capacity at the North Dome field – the world’s largest gas reservoir, which it shares with Iran, where the structure is known as South Pars. The expansion will allow Qatar to increase its LNG production capacity to 100 mtpa from the current 77 mtpa sometime between 2022 and 2024, the company said. Qatar had imposed a moratorium on new gas developments at the North Dome field, but this was lifted in April 2017.

US LNG exports started in February 2016 under former President Barack Obama, but the administration of Donald Trump has flagged expanding LNG exports as a key pillar of its plan to dominate world energy markets. US oil, NGL and coal exports have all risen sharply since Trump took office. The new president has also launched a campaign to secure outlets for US LNG in northern Asia, and his administration has held meetings with Chinese, South Korean and Japanese officials aiming to sign up customers for US exports, including LNG.

Qatar’s decision to boost LNG export capacity coincides with a breakdown in political ties with Saudi Arabia following a visit by Trump to Riyadh in May, during which the US president alleged Qatar had promoted terrorism in the Middle East. Saudi Arabia’s arch-enemy Iran has sent food aid to Qatar following the rift.

(C) Resource Economist