Easwaran Kanason

Co - founder of NrgEdge
Last Updated: September 25, 2016
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At this time of writing, a 27,500 ton Tension Leg Platform (TLP) is being installed in waters 500m deep off the coast of Sabah. When full installed, the stage will be set for first oil to flow in 2017 at the Malikai deepwater project. Led by Shell, Malikai represents several firsts for upstream in Malaysia and leads the path forward for the industry in the country.

First sanctioned in 2013, Malikai consists of two main reservoirs – Kinarut and Kamunsu-2, with peak production of 60 kb/d a day expected. Shell has a 35% stake in the project, together with ConocoPhillips (35%) and Petronas Carigali (30%). Malikai received its FID (final investment decision) during the heady days of US$100/b oil. And though crude oil prices have more than halved since, Malikai is the blueprint for the future of Malaysian upstream. 

The deep waters off Sabah hold plenty of hydrocarbons, and with offshore production off the east coast of Peninsular Malaysia dwindling, new crude output must come from Sabah and Sarawak to keep production up. With shallow water blocks well surveyed, players – Malikai’s three partners, as well as Murphy Oil, JX Nippon and others – are venturing into deeper water. Malikai is the second of two mega deepwater projects to come onstream, after Gumusut-Kakap (another Shell project) in 2012. 

The TLP used in Malikai is believed to be the first  fabricated in Malaysia, by France’s Technip in Pasir Gudang, and the first in the world outside of Gulf of Mexico. The skills and expertise for deepwater platforms are now in Malaysia, and can therefore be used for future projects – both within Malaysia, and also deepwater potential fields in Brunei and Indonesia.

Malikai also marks the maturation of Malaysia’s planned oil and gas hub. Malikai crude will be partially processed by the TLP, before being evacuated to the Kebabangan shallow water platform – an offshore hub for collating oil and gas from various fields – then sent onshore to the Sabah Oil & Gas Terminal for storage and loading onto tankers. In the decades to come, the vision is that of deepwater fields in the waters all connecting back to Kebabangan as a central repository and channel to onshore storage, an elegant situation that reduces costs for all parties and possible only under the encompassing eye of Petronas. 

So when Malikai oil begins to flow next year, it will be heralded as a new dawn for upstream in Malaysia. Are there any pitfalls? Certainly. Low oil prices does make operating Malikai a challenge, to say nothing of also curbing exploration activities in other promising deepwater areas. Petronas believes deepwater is the future for Malaysia and is still untapped, with Shell in agreement, making deepwater a focus for its upstream activities despite a reduction of overall upstream capex. Between Petronas and Shell, a healthy eco-system for deepwater is being nurtured in Sabah. Which is good for the industry as a whole, but there is also another thorn – all the deepwater fields in Sabah skirt perilously close to China’s vague ‘nine-dashed line’ that the country claims as its territorial waters. That, however, is a bilateral argument for the future and until it rears its head, the upstream industry in Malaysia will keep going deeper and deeper.

Are you part of the Malikai Project?  Share your story in NrgEdge or simply tag yourself to this prestigious project here: https://www.nrgedge.net/project/malikai-deepwater-project

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Russia Is Heating Up The Arctic

After a year of securing deals, finalising details and even projecting way beyond the current, Novatek’s Arctic LNG 2 was been given its Final Investment Decision (FID), paving its way for a 2023 start. Led by Russia’s largest independent gas producer, the 19.8 million ton per annum project is also joined by Total, CNPC, CNOOC and the Japan Arctic LNG consortium (consisting of Mitsui & Co and JOGMEC).

The make-up of the project stakeholders is telling. There is Novatek, which aims to catch up with Gazprom as Russia’s largest gas player. Then there is Total, whose savvy deals have propelled it to become the second largest private gas player (behind Shell) through a diversified portfolio. Japan – currently the world’s largest LNG importer – is well represented, while the fast-growing demand market of China is in there as well. Each of the minority players owns a 10% stake but Total also has a 19.4% stake in Novatek, bringing its total economic interest to 21.6%.

The geography of the project is interesting as well. Centred on the Trekhbugornly and Gydanskiy fields, the terminal at Utrenniy and a large-scale liquefaction plant in the remote Gydan Peninsula, passage from this part of Russia’s Arctic is difficult. Which is why Novatek is also partnering with Sovcomflot to build a fleet of 17 icebreaker-class LNG carriers to ferry the super-chilled liquid through the Arctic to Northeast Asia. That’s the Northern Sea Route, the closest direct route to Asia available and it might even get easier. Climate patterns have shifted the Arctic’s ice floes, with new shipping channels opening up from thawing ice in the summer. The journey rivals delivery times from Qatar to Tokyo, or Australia to Shanghai – which explains the high interest from Japanese and Chinese parties. For Total, which has a global presence, Arctic LNG 2 will also be able to deliver cargoes to Europe via transhipment terminals in the Murmansk region.

It also explains why Novatek is already thinking beyond this. Arctic LNG 2 will consist of 3 phases. Train 1 is scheduled for 2023, while Train 2 and Train 3 planned for 2024 and 2026. But Novatek has already made overtures to expand its assets in the Gydan – part of West Siberia’s Yamal-Nenets region. Novatek’s ambitions call for up to 140 mtpa of LNG production in Gydan and Yamal, from its current 16.5 mtpa Yamal LNG and the 19.8 mtpa Arctic LNG 2, though Gazprom has pushed back on Novatek’s lobbying of the Russian government on the issue. However, plans have already been made for at least one more LNG project – oddly titled Arctic LNG 1 – that would focus on the Soletsko-Khanaveyskoye field in the Kara Sea, which has an estimated 2.18 bcm of gas in place.

The net result of this is that Russia will become a more diversified gas player. Besides the Sakhalin II and Yamal LNG projects, Russia primarily sells its gas by pipeline to Europe. But with resistance there increasing – see the furore over the Nord Stream 2 pipeline – Russia needs more options. Geography and weather have always presented challenges to export Siberian gas to Asia and the rest of the world, but Arctic LNG 2 offers a very promising glimpse of a possibly profitable future.

Arctic LNG 2:

  • Stakeholders: Novatek (60%), Total (10%), CNPC (10%), CNOOC (10%), Japan Arctic LNG (10%)
  • Capacity: 19.8 million tons per annum through 3 Trains
  • Location: Gydan Peninsula, West Siberia
September, 18 2019
Natural gas and wind forecast to be fastest growing sources of U.S. electricity generation

In its latest Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that natural gas-fired electricity generation in the United States will increase by 6% in 2019 and by 2% in 2020. EIA also forecasts that generation from wind power will increase by 6% in 2019 and by 14% in 2020. These trends vary widely among the regions of the country; growth in natural gas generation is highest in the mid-Atlantic region and growth in wind generation is highest in Texas. EIA expects coal-fired electricity generation to decline nationwide, falling by 15% in 2019 and by 9% in 2020.

The trends in projected generation reflect changes in the mix of generating capacity. In the mid-Atlantic region, which is mostly in the PJM Interconnection transmission area, the electricity industry has added more than 12 gigawatts (GW) of new natural gas-fired generating capacity since the beginning of 2018, an increase of 17%.

This new natural gas capacity in PJM has replaced some coal-fired generating capacity—6 GW of coal-fired generation capacity has been retired in that region since the beginning of 2018. The Oyster Creek nuclear power plant in New Jersey was also retired in 2018, and the Three Mile Island plant in Pennsylvania plans to shut down its last remaining reactor this month.

These changes in capacity contribute to EIA’s forecast that natural gas will fuel 39% of electricity generation in the PJM region in 2020, up from a share of 31% in 2018. In contrast, coal is expected to generate 20% of PJM electricity next year, down from 28% in 2018. In 2010, coal fueled 54% of the region’s electricity generation, and natural gas generated 11%.

PJM annual electric power sector generation

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

Wind power has been the fastest-growing source of electricity in recent years in the Electric Reliability Council of Texas (ERCOT) region that serves most of Texas. Since the beginning of 2018, the industry has added 3 GW of wind generating capacity and plans to add another 7 GW before the end of 2020. These additions would result in an increase of nearly 50% from the 2017 wind capacity level in ERCOT. EIA expects wind to supply 20% of ERCOT total generation in 2019 and 24% in 2020. If realized, wind would match coal’s share of ERCOT's electricity generation this year and exceed it in 2020.

ERCOT annual electric power sector generation

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

Natural gas-fired generation in ERCOT has fluctuated in recent years in response to changes in the cost of the fuel. EIA forecasts the Henry Hub natural gas price will fall by 21% in 2019, which contributes to EIA’s expectation that ERCOT’s natural gas generation share will rise from 45% in 2018 to 47% this year. Although EIA forecasts next year’s natural gas prices to remain relatively flat in 2020, the large increase in renewable generating capacity is expected to reduce the region’s 2020 natural gas generation share to 41%.

September, 18 2019
Your Weekly Update: 9 - 13 September 2019

Market Watch  

Headline crude prices for the week beginning 9 September 2019 – Brent: US$61/b; WTI: US$56/b

  • Hope reigns as the market banks on signs that the US and China could reach a trade deal would eliminate one of the largest risks to current oil prices: a full-blown global recession
  • However, this is merely the latest in a series of dashed hopes that has seen the trade war between the US and China – using tariffs as weapons – escalate dramatically over the year; new tariffs entered play September 1 and more could come, with both sides already feeling the pinch
  • But crude prices did get a lift from EIA data showing that US crude stockpiles fell far more than expected, down by 4.8 million barrels to its lowest level since October 2018 – an indication of strong demand, with US refinery utilisation at 94.8%
  • However, there are fissures appearing on the supply side that could trigger some risk premiums; in Venezuela, the upstream crisis continues with the latest blow being a Chinese contractor halting work over claims over non payment
  • More importantly, Saudi Oil Minister – or rather former Saudi Oil Minister Khalid al-Falih – was dismissed from the government; after initial reports suggested that al-Falih would focus on energy policy after the oil ministry was split, a royal decree issued days later confirmed his sacking
  • Saudi Arabia and its allies have been at pains to re-assure the market that the dismissal of al-Falih – who is respected around the world – will not impact Saudi production or the current OPEC+ supply pact
  • This will be confirmed at the upcoming OPEC+ meeting this week, which will be the first under Saudi Arabia’s new Energy Minister, one of the King’s sons Prince Abdulaziz bin Salman
  • Against this backdrop of turmoil, the active US rig count fell yet again; after two weeks of double-digit losses, US drillers lost four oil and two gas rigs, with losses seen once again in the Permian
  • Power moves within Saudi Arabia may have sent some tremors to the market, but it is likely that OPEC+ will stick to its commitments; with no signs that the US and China were doing anymore more than talking about talking, crude prices will remain rangebound – US$59-61/b for Brent and US$54-56/b for WTI

Headlines of the week

Upstream

  • Total has suspended plans for the US$3.5 billion crude export pipeline that would connect Ugandan oilfield to port facilities in Tanzania after a failure to buy a stake in Tullow Oil’s upstream assets in Uganda linked to tax negotiations; this will require a complete restart for the Uganda project
  • With other supermajors pulling out, Total remains committed to the North Sea, with CEO Patrick Pouyanne looking to invest up to US$10 billion over the next five years but cautions that Total maintain strict cost discipline
  • The Norwegian Petroleum Directorate (NPD) has consented to the startup of the giant Johan Sverdrup field, a potential 660,000 b/d resource that has been called the North Sea’s ‘last hurrah’
  • Permian-focused player Concho Resource has agreed to sell its assets in the New Mexico Shelf to Spur Energy Partners for US$925 million, continuing a wave of consolidation in the US shale arena
  • Shell has announced plans to start drilling in the offshore Saturno field in Brazil, becoming one of the first private players tapping the pre-salt Santos Basin

Midstream/Downstream

  • Sinopec’s new 160 kb/d Yangzi refinery has begun production of Europe-standard gasoline, providing an outlet for Chinese fuel products amid a domestic glut that has seen refiners look overseas for sales
  • Petrobras is extending the deadline for interested parties for its four refineries on sale from September 16 to September 27, citing high investor interest for the refining assets that represent 37% of Brazilian capacity
  • Saudi Aramco continues its downstream push in China, signing an MoU with the Zhejiang Free Trade Zone that could pave the way for further investments beyond current plans to acquire 9% of the Zhejiang Petrochemical refinery
  • Russia’s Sibur will be cutting back LPG exports to Europe to some 2 million tons from a typical 3.5-4 million tons per year, redirecting the LPG to be used as feedstock for its ZapSibNefteKhim petrochemicals plant in Western Siberia

Natural Gas/LNG

  • Months of uncertainty have been put to rest as the government of Papua New Guinea endorsed the US$13 billion Papua LNG project, following some new commitments by project leader Total – primarily on local content
  • Also in PNG, the government has approved Australian independent Twinza Oil’s Pasca gas/condensate project - the country’s first offshore gas project
  • ExxonMobil and its partners have sanctioned plans for the 6.2 mtpa Sakhalin 1 LNG plant on Sakhalin Island in Russia’s far east, with easy access to Japan
  • Argentina’s YPF is pushing ahead with plans to build a US$5 billion LNG export terminal – tapping into the Vaca Muerta shale basin – despite continued domestic political and financial chaos hanging over the project
  • Petronas has agreed to purchase natural gas that is set to produced from the Gorek, Larak and Bakong fields in the SK408 area in Sarawak, jointly operated by SapuraOMV Upstream, Petronas Carigali and Shell
  • Qatar Petroleum has booked 100% of regasification capacity at the Fluxys Zeebrugge LNG terminal until 2044, consolidating Qatar’s hold on one of Northwest Europe’s important gas entry nodes
  • Equinor has brought the Snefrid Nord gas field online, which is the first of several planned projects related to the Aasta Hansteen field to begin production, with an initial output of 4 mcm/d
September, 13 2019