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Last Updated: March 15, 2017
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PETRONAS’ financial year results that ended 31 December 2016 have shown improvements despite the challenging market environment. This was the result of the deliberate sequential measures undertaken by the Group in response to the low oil prices which included the Group’s transformation efforts and its continuous pursuit to optimise cost and improve efficiency.

PETRONAS’ profit grew by 12 per cent to record higher Profit After Tax (PAT) of RM23.5 billion, from RM20.9 billion recorded in 2015. This was mainly due to lower operating expenditures and tax expenses partially offset by lower average prices.

The Group’s revenue for the year dipped by 17 per cent to RM204.9 billion from RM247.7 billion in 2015. The decrease reflected the lower average prices in line with the downward trend of key benchmark prices (Dated Brent and Japan Customs Cleared Crude) coupled with the impact of lower sales volume.

Cumulative 2016 Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) was RM70.4 billion compared to RM75.5 billion recorded in 2015.

Cash flows from the Group’s operating activities also decreased from RM69.6 billion in 2015 to RM53.8 billion due to lower average prices, partially offset by lower tax paid.

The Group’s continuous efforts to reduce cost had contributed in 8 per cent or RM4.1 billion decrease in controllable costs to RM49.1 billion compared to RM53.2 billion in 2015.

Total assets and shareholders’ equity increased to RM603.3 billion and RM380.3 billion respectively, contributed by the impact of weakening of Ringgit against US Dollar exchange rate and favourable movement on fair value of available-for-sale financial assets.

Gearing ratio increased to 17.4 per cent compared to 16.0 per cent recorded last year. This was due to higher borrowings following additional drawdown made during the year. Return on Average Capital Employed (ROACE) increased to 5.3 per cent compared to 5.1 per cent in 2015 in line with the Group’s higher profits.

Capital investments for the year was reduced by 22 per cent to RM50.4 billion following project deferment and rephasing as well as cost optimisation efforts.

Meanwhile, PETRONAS’ quarter four profits recorded a strong 85 per cent jump in PAT to RM11.3 billion from RM6.1 billion recorded in the previous quarter. The RM5.2 billion increase was primarily driven by higher average realised product prices and sales volume mainly from LNG and processed gas as well as impact of favourable exchange rate partially offset by higher taxation.

Revenue rose by 20 per cent to RM58.6 billion from RM48.7 billion in the preceding quarter.

EBITDA for the quarter also grew by 44 per cent to RM21.9 billion in line with the Group’s higher profits.


Upstream


Upstream continued to focus on delivering its commitments across the oil and gas value chain while putting in measures to increase cash generation and optimise cost.

Malaysia and PETRONAS Group’s international total upstream production was 2,363 thousand boe per day in 2016, a three per cent increase compared to 2,290 thousand boe per day in 2015. This was mainly driven by the resumption of operations of the Sabah-Sarawak Gas Pipeline, higher facilities uptime in Malaysia and Canada, and higher production from Malaysia, Indonesia and Australia.

PETRONAS Group’s total Liquefied Natural Gas (LNG) third party sales volume for the year was 29.01 million tonnes, marginally higher compared to 28.49 million tonnes in 2015 mainly contributed by higher volumes from Train 9 in Bintulu and GLNG in Australia, partially offset by lower trading volume.

Average sales gas volume for Malaysia in 2016 was higher as compared to 2015 in line with higher demand.

Among notable achievements in Upstream for 2016 include acquisition of four international blocks which include two recently acquired blocks in Mexico and two in Myanmar, the commissioning and delivery of first LNG cargo from Train 9, and successful commissioning of PFLNG Satu.


Downstream


Downstream Business managed the impact of depressed market growth, lower product prices and spreads to record only a slight decline in the Downstream’s PAT from RM8.4 billion in 2015 to RM8.3 billion in 2016.

The collaborative efforts undertaken across the value chain led to higher utilisation of the Group’s manufacturing units in 2016. PETRONAS’ refineries in Malaysia and South Africa recorded strong refinery utilisation at 90.5 per cent and 89.9 per cent respectively.

Meanwhile, its petrochemical plants set a new record in utilisation since incorporation of 95.7 per cent, an improvement from the previous record of 85.3 per cent in 2015. This led to an increase in petrochemical products sales volume by 14 per cent from 6.4 million metric tonnes to 7.3 million metric tonnes.

Rationalisation of marketing and trading strategies to drive value focused activities, resulted in higher margins despite lower sales volume. Total petroleum products sales volume was 268.1 million barrels, 14.5 million barrels lower compared to 2015, while crude oil sales volume was 189.3 million barrels, 24.6 million barrels lower compared to the previous year.

Downstream projects continued to progress well. The Pengerang Integrated Complex as at February 2017 is close to 60 per cent completion and is on track to commence operations by 2019. Recently, PETRONAS signed a Share Purchase Agreement with Saudi Aramco for a 50 per cent equity in selected ventures and assets of the RAPID project. Meanwhile SAMUR is expected to begin commercial operations within the first half of 2017.


Outlook


The Group continues to maintain a conservative outlook for 2017 and expects prices to remain uncertain. PETRONAS will continue to focus on its group-wide efforts to reduce costs and further improve efficiency and sustain world-class operational efficiencies through collaborations within and outside the industry.


Datuk Wan Zulkiflee Wan Ariffin, President and Group CEO PETRONAS


"I am encouraged that PETRONAS has emerged from 2016 as a more resilient Corporation with strong underlying performance driven by our new structure, significant cost reductions and improved performance. We are in a stronger position heading into 2017."



Issued by


Media Relations Department


Group Strategic Communications


PETRONAS

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Your Weekly Update: 10 - 14 December 2018

Market Watch

Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b

  • Crude prices strengthened at the start of this week, with OPEC delivering an agreement that will see production across the OPEC+ alliance decline by 1.2 mmb/d beginning January 2019
  • Two-thirds or 800,000 b/d of the cut will be borne by OPEC – with most of it taken up by Saudi Arabia – while the non-OPEC group will take up a cut of 400,000 b/d, most of which will be taken up by Russia
  • Skepticism has reigned before the supply deal was reached, as the first day of the OPEC meeting in Vienna closed without consensus and the threads holding OPEC together showed some stress when Qatar decided to quit the group
  • Crude prices were also boosted by Libya declaring force majeure at its largest oil field at El Sharara over arm protests, while Canada’s Alberta province announced plans to pare back some 325,000 b/d of output to ease a huge glut
  • The coordinated supply deal by OPEC ‘was not easy’ according to UAE Minister of Energy and Industry, with Iran in particular balking at being asked to sign up to a symbolic cut; this might not augur well for future supply deals that might be necessary given current trends
  • However, the supply cut will only last until April 2019, when the terms are due for a review, which would give OPEC+ enough time to consider and deal with the expiration of American waivers for eight countries over continued import of Iranian crude in May
  • Meanwhile, America became a net oil exporter for the first time in almost 75 years, as the unprecedented boom in US crude oil fuelled by the shale revolution powers on, a development that could dilute OPEC+’s attempt to support global crude prices
  • The recent weakening of WTI prices saw the US lose 10 active oil rigs last week, however, the addition of 9 new gas rigs led to a net loss of only 1 in the Baker Hughes active US rig count
  • Crude price outlook: OPEC+’s decision might have provided some relief, but may not be enough to keep crude oil prices trending upwards. Expect prices to moderate to US$60-61/b for Brent and US$50-51/b for WTI

Headlines of the week

Upstream

  • ExxonMobil’s winning streak in Guyana continues, as it announces its 10th offshore discovery at the Pluma-1 well, boosting estimated recoverable resources in the Stabroek block by almost 1 mmb/d to over 5 mmb/d
  • Apache has initiated production at the Garten field in the UK North Sea, with an output rate of 13,700 b/d and 15.7 bcf/d of natural gas
  • Chevron has raised its capital expenditure for the first time since 2014 into US$20 billion, with a major focus on expanding operations in the Permian Basin as well as on the Tengiz megaproject in Kazakhstan
  • Canada’s Alberta province, weighed down by a supply glut caused by pipeline bottlenecks, has announced moves to reduce the region’s output by 325,000 b/d
  • Equinor and Faroe Petroleum have agreed to trade a number of assets in the Norwegian Sea and the Norwegian Continental Shelf North Sea, encompassing the Njord, Bauge Hyme, Vilje Ringhome, Marulk and Alve fields, with the deal described as a ‘balanced swap’ in terms of value with no cash consideration

Downstream

  • CNPC’s US$9.53 billion joint venture integrated 400 kb/d petrochemicals/refinery project with PDVSA in Jieyang, China has been reactivated, and is now expected to begin operations in late 2021
  • French president Emmanuel Macron has backtracked and suspended a planned fuel-tax hike, after weeks of violent riots by the so-called Yellow Vests grassroot groups of up to 300,000 protestors
  • Limetree Bay Ventures has secured US$1.25 billion in financing that paves the way for the Limetree Bay refinery in the US Virgin Islands to restart after being idled for years, partnering with BP Products North America on the project

Natural Gas/LNG

  • Equinor has received permission from the Norwegian government to proceed with the development of Troll Phase 3, delivering an additional 2.2 billion boe/d of natural gas with a planned start-up timeframe of 1H2021
  • Shell has completed the construction of Gibraltar’s first LNG regasification facility, a small-scale project that will feed a new power plant in the territory
  • Trinidad and Tobago has agreed to allow BP and Shell to extend the operational life of the Atlantic LNG Train 1 in Point Fortin by five years, with the country receiving the ability to sell LNG cargoes through its state gas firm
  • Tokyo Gas and the Philippines’ First Gen Corporation have signed a joint development agreement to build and operate an LNG receiving terminal, as the three-horse race narrows over the country’s first LNG import facility
  • American LNG player Tellurian has agreed to supply trader Vitol with some 1.5 mtpa of LNG over 15 years from its 27.6 mtpa Driftwood LNG export terminal currently being developed in Calcasiue River, Louisiana
  • Tanzania is opening talks with Equinor and ExxonMobil to launch the East African nation’s first LNG project, likely to derive gas from the Equinor-operated offshore Block 2
  • Shell is expecting to produce its first cargo of LNG from its Prelude FLNG facility in Australia before the end of 2018
December, 14 2018
Permian’s Pipeline Lifeline

The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.

The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.

Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.

And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.

Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.

As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”

The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.

Recent Announced Permian Pipeline Projects

  • September 2018 – EPIC Midstream Holdings – 675,000 b/d, 1125km, 24-30’ diameter, 4Q19 target opening
  • November 2018, Wolf Midstream Partners – 500,000 b/d, 65km, 16’ diameter, 2H2019 target opening
  • November 2018, Jupiter Energy – 1 mmb/d, 1050km, 36’ diameter, 2020 target opening
  • December 2018, Plains All American Pipeline – 575,000 b/d, 830km, 26’ diameter, 3Q19 target opening
December, 04 2018
Your Weekly Update: 3 - 7 December 2018

Market Watch

Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b

  • After falling down to fresh lows last week – with WTI prices dipping below US$50/b at one point – crude oil prices improved after the G20 meeting in Buenos Aires, where the US and China agreed to a temporary truce over their trade war
  • While no concrete agreements over energy were announced at the G20 summit, the slightly thawing in trade tensions allowed crude benchmarks to rise slightly, assisted by an announcement by Canadian producers in Alberta that output would be cut by 325,000 b/d beginning January
  • Russia and Saudi Arabia agreed at the G20 summit to extend the OPEC+ deal into 2019, suggesting that a coordinated oil output cut was in the works, also supported prices ahead of OPEC’s meeting in Vienna this week
  • Not present at the OPEC meeting, however, will be Qatar, which quit the oil cartel in a surprise move; the tiny sultanate said it was quitting due to its small oil production, choosing instead to focus on its LNG industry, but the move can be seen as a response to the Saudi-led boycott of Qatar, calling into question Saudi Arabia’s ability to hold the fragile OPEC coalition together
  • Consensus among analysts point to OPEC+ agreeing to remove some 800,000 b/d of crude oil from the market beginning January, aimed at establishing a floor for oil prices at some US$65/b
  • The downward spiral of crude prices has put the brakes on US drilling activity, with 2 new oil rigs offset by the loss of 5 gas rigs last week; analysts are expecting shale explorers to cut spending budgets in 2019 in response to weak prices, raising spectres of the 2015 price slump
  • Crude price outlook: Ahead of the OPEC meeting on December 6, crude should be kept up by expectations of a renewed supply cut, with Brent likely to trade rangebound around US$61-63/b and WTI at US$52-53/b

Headlines of the week

Upstream

  • Buoyed by the prolific nature of the Permian Basin, Shell has announced plans to nearly double its production in the shale patch with AI-powered technology
  • China and the Philippines have set aside sovereignty issues, signing an agreement for joint exploration and development in the South China Sea
  • Facing severe pipeline bottlenecks, Canada’s Alberta province is looking to purchase rail cars to ship more crude oil by train out of the province towards the US, as a temporary measure while new pipeline are proposed and built
  • Shell has completed the sale of Shell E&P Ireland to Nephin Energy Holdings, which includes a 45% in the Corrib gas venture, for US$1.3 billion
  • In Norway, Shell also sold its interests in the Draugen and Gjøa fields for US$526 million to OKEA AS, but retains its interests in the Ormen Lange and Knarr fields, as well as the Troll, Valemon and Kvitebjørn projects
  • Petrobras has sold its stake in 34 onshore production fields to Brazilian firm 3R Petroleum for US$453.1 million, as well as stakes in three shallow-water offshore fields off Rio de Janeiro to Perenco for US$370 million
  • Pemex tripled its estimated reserves in the Ixachi field to 1.3 billion barrels of oil, calling it the ‘most important onshore field in 25 years’ and expecting peak production of 80,000 b/d of condensate and 720 mscf/d of gas by 2022

Downstream

  • Uganda has pushed back the opening of its first oil refinery to 2023, in line with estimates by Total, CNOOC and Tullow Oil, as crude oil production is now only expected to begin in 2021
  • Malaysia will be introducing a B10 biodiesel mandate in December over a phased rollout, with complete implementation expected by February 2018
  • Pertamina expects to begin works on upgrading its Balikpapan refinery in early 2019, aimed to increasing fuel standards to Euro V and upgrading capacity to process sour crude together with its current medium heavies
  • ExxonMobil plans to upgrade its Rotterdam refinery to expand Group II base stock production, following the installation of a new hydrocracker
  • The US EPA has increased its annual blending mandate for advanced biofuels by 15% and kept conventional biofuels blending requirement steady for 2019, while maintaining waivers for selected refineries

Natural Gas/LNG

  • Petronas and Vitol Asia have signed a long-term LNG supply agreement, with Petronas providing LNG from the LNG Canada project in Kitimat, providing up to 800,000 tons per annum for 15 years beginning 2024
  • Eni and Anadarko have been giving a 2023 deadline to submit key development plans for the Area 1 and 4 LNG complex in Mozambique
  • Tullow Oil is backing the attempt by three former Cove Energy executives in the Comoros Islands by taking stakes in Discover Exploration’s blocks, hoping to repeat the trio’s success in discovering the Rovuma block
  • South Korea’s Posco Daewoo has signed a deal with Brunei National Petroleum Company to jointly explore LNG opportunities in Brunei, with specific focus on the development of the Dehwa area operated by Posco Daewoo
  • Rosnedt and the Beijing Gas Group have set up a joint venture focusing on building and operating a network of up to 170 CNG fuel stations in Russia, using LNG as motor fuel
December, 06 2018