Dear Members, Associates and Friends of the Malaysian Gas Association,
Ladies & Gentlemen,
As we usher in the new year, I am excited with developments achieved in the Malaysian gas industry. The gas industry reforms remains on track. The grace period for the Third Party Access ends in January 2018 and the regulated gas price is projected to achieve market price by 2019. Malaysia is well underway advancing towards a sustainable gas industry.
Looking back to 2017, MGA is proud to gain further recognition of our role as the voice of the gas industry when we were appointed into both the steering and technical committees for the national Gas Price Rationalisation Communication Plan, led by the Economic Planning Unit (EPU). MGA will be playing an active role in communicating the benefits of the gas industry reforms to key stakeholders, providing perspective as an industry representative.
2017 has been quite a busy and eventful year for MGA. Our priorities for 2017 has been the following;
2.Enhancing Value Proposition for Members
We stepped up our Gas Advocacy with more engagements with policy makers, series of interviews and articles in the newspapers, face to face engagements at our booths in major exhibitions and media launch of the report on “Natural Gas: Flipping the Switch’. We ended the year with a “Gas Advocacy Series” campaign on social media.
In addition to gas advocacy, MGA members benefited from the multiple networking platforms established by MGA. We continued our annual networking events, namely the Industry Golf and Industry Gala Dinner, and have increased members activities with more industry talks, a technical visit to RAPID in Pengerang and a CSR intiative in the form of a Blood Donation Drive. We also kept members regularly informed through the newly introduced Quarterly bulletins. This in addition to the regular updates via e-mails and posts on our webpage and social media.
On the international front, as part of the Executive Committee, MGA plays a key role in charting the direction of the International Gas Union (IGU). IGU have similarly stepped up Gas Advocacy on the global arena, engaging global bodies such as United Nation, G20, World Bank and International Energy Agency (IEA). 2017 also saw the election of the first Women President of IGU. Ms. Li Yalan will be the first woman to lead IGU when China assumes the Presidency of IGU for the Triennium 2021-2014. Her appointment gives encouragement for more active participation by women in the energy sector, especially in leadership positions.
Likewise, MGA recognised the importance of women in the energy sector when we organised the inaugural Forum in Women in Energy; an event supported by women networks in member companies.
In 2017, MGA continued our outreach to students in schools and higher learning institutions. We are delighted to share that several schools and universities found our outreach so beneficial that they have invited us to collaborate.
2017 is also the year of collaborations for MGA. In addition to universities, MGA collaborated with other organisations, such as MOGSC, 30% Club and PEMANDU, and with MGA’s own member companies to organised major events.
We are extremely grateful for the support and contribution from our members throughout 2017. We are particularly appreciative of the efforts put in by the following working committees;
•Regulatory and Government Affairs
•Learning and Development
•Communications and Multimedia
•Membership and Social
the taskforce on Promotion of Cogeneration and the respective organising committees for our major events. Your commitment and contributions ensured the success of our activities. On average, we have organised 2 events or major activities per month, more than what we have achieved in the previous years.
Going into 2018, we expect our priorities to remain. We will be stepping up our Gas Advocacy even further with more advocacy related activities, more communication and more engagements with the media.
The country needs to increase utilisation and demand for gas in order to make the market more attractive to third party gas suppliers. MGA has proposed to collaborate with Federation of Malaysian Manufacturers (FMM) to jointly promote cogeneration and will be collaborating with PEMANDU Associates to organise an “Increasing Gas Demand” workshop.
2018 will also see IGU organising the World Gas Conference (WGC2018) in Washington DC, USA. We urged members to participate in this prestigious triannual congregation of global gas industry players. WGC2018 will be expecting 500 speakers and 12,000 participants.
Before I sign-off, I would like to take the opportunity to congratulate and thank the MGA Secretariat for their keen dedication and oustanding efforts.
On behalf of the Council of MGA, I close by again thanking all our members, including all the volunteers from members organisations, for your keen support and participation in all our activities. We look forward to similar support in the coming year.
I wish everyone a happy and successful 2018.
Hazli Sham Kassim
Malaysian Gas Association
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
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.
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
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