Malaysian Gas Association, the prominent voice of the natural gas industry in Malaysia. MGA is a non-profit organization representing members and companies involved in the entire value chain of the Malaysian gas industry.
1. Malaysian Gas Association, also known as MGA, has been around since 1986 with its vision to promote the gas industry and its utilization as a clean an efficient energy source. What are the biggest achievements in the recent years, for the natural gas industry?
Malaysian Gas Association (MGA) represents 150 members, with one common mission to promote the advancement of sustainable gas industry in Malaysia. Our membership comprises companies serving the entire value chain of the natural gas industry; from upstream, midstream and to downstream, including major gas consumers.
MGA is excited to play its part in the transformational changes undergone by the natural gas industry in recent years.
Natural gas supply to Peninsular Malaysia is no longer an issue with the introduction of Re-Gasification Terminal (RGT1) in Sungai Udang, Melaka, back in 2013. RGT1 enables import of Liquefied Natural Gas (LNG) to supplement the gas supply from indigenous resources. The second RGT for the country, RGT2 in Pengerang, Johor, is expected to start commercial operation in 2018.
The completion of LNG import facility in RGT1 paved way for the implementation of Third Party Access (TPA) in January 2017. TPA opens the gas supply market to third parties. Now, anyone can sell gas to any consumer in Malaysia.
To enable TPA and open competition, the natural gas industry is transiting from regulated to market-based pricing. To achieve this, the regulated gas price has been increased by RM1.50 per mmBtu every six months. Once the gas price has achieved market parity, gas transactions will be based on willing buyer-willing seller concept. Gas at market price will attract more players to supply gas to consumers.
At MGA, we are encouraged that the Malaysian government has been fully committed to ensure this market liberalisation and market reforms. This will pave way towards realising MGA’s vision of a vibrant and sustainable gas industry that benefits the nation and its citizens.
2. With the Malaysian government moving to reduce carbon emission by 45% by 2030, how does this impact gas production?
International Energy Agency (IEA) has on 14 November 2017 launched their World Energy Outlook 2017. The report singled out natural gas as the best fossil fuel to complement renewable energy going towards 2040. This is because natural gas can operate in continuous base load, emitting the least CO2 and most flexible to support renewable energy. During the press conference to launch the WEO 2017, IEA regarded natural gas as “a good husband” to renewables. In fact, IEA expected natural gas to be the only fuel to increase by 2040.
Similarly, as Malaysia aspires to increase share of renewable energy in the energy mix, natural gas plays an even more important role in power generation. With majority of renewable energy expected to be generated by solar photovoltaic (PV), the electricity grid will need flexible power plants that can react quickly to the intermittent nature of power from PV. Gas turbine power plants are perfect for this role. Gas turbines can react quickly and emits much less CO2 in comparison to power plants using other fossil fuel.
In the transport sector, greater utilisation of natural gas for heavy transport, such as city buses and long haul commercial vehicles, can further reduce CO2 emissions.
In the industrial sector, combined heat and power using gas turbines in cogeneration application increases efficiency of the system. This means less fuel is needed and less CO2 emitted.
In conclusion, in order to achieve target GHG emission reduction, the nation needs natural gas even more
3. Global demand for natural gas has been increasing steadily over the years. When do you foresee a peak in demand for gas?
DNV GL this year released a report on “Energy Transition Outlook 2017” foresee that natural gas is set to be the largest single source of energy towards 2050 with peak demand occurring in 2035.
In Malaysia, MGA is constantly promoting greater utilisation of gas in all sectors, including power generation, transport, industrial and commercial. The third party access is expected to further spur the growth of demand for natural gas.
4. How has technology helped in shaping the industry? Can you share an example of advancement in technology that has spurred the growth for gas production?
We are proud that MGA members are leaders in innovation and technological advancement.
PETRONAS for example continues to be a pioneer in global gas industry, being innovative in the fast track construction of the re-gasification terminal using floating storage units (FSU) in Melaka and the world’s first floating LNG (FLNG) plant that will unlock small and stranded gas fields that were once uneconomical to explore.
5. What are the biggest challenges in the foreseeable future for the industry?
Malaysia’s gas industry entered an exciting phase this year with The Implementation of the third party access, enabling any supplier to bring natural gas into Malaysia. TPA ensures sufficient supply and energy security for the nation. For TPA to be successful, there should be higher demand for natural gas in Malaysia, creating a market large enough to attract third parties.
In 2015, the power generation sector consumed more than 50% of the total natural gas supplied in Malaysia, making that sector the most attractive market for gas suppliers. However, natural gas share in the power generation mix is set to drop from 46% in 2015 to a mere 32% in 2026. In contrast, coal share increases from 48% to 56%. Coal is preferred over gas due to lower cost of generating power, even though the CO2 and pollutant emissions are higher.
6. In today’s world, what do you think are the necessary skills and traits that are important for a young professional to have when entering the job market?
MGA recently organised a three-day programme for final year university students called PRESTIGE that includes exposing them to careers in the oil & gas industry. We arranged for oil & gas professionals from varied backgrounds to share their career experiences and provide career tips. One of the tips given that resonates with the students was to keep gaining knowledge. Learning does not stop once a student graduates.
7. With the advancement of technology and the internet, how do you think young professionals should capitalize on this to further their career and self-improvement?
Learning does not stop once a student graduates. The advice from a seasoned oil & gas professional during MGA’s PRESTIGE programme was to keep gaining knowledge. The digitalised and borderless world enables easy access to beneficial knowledge.
8. How important has collaboration and professional networking been in reaching where you are today in life?
MGA is a charter member of the International Gas Union (IGU), the global voice for gas, with members from 90 countries. IGU provides global networking platform for its members to share knowledge and best practices in the industry.
In Malaysia, MGA continuously collaborate with several other organisations. This year, we collaborated with PEMANDU Associates to organise the inaugural Forum on Women in Energy (FoWiE). Other organisations that supported FoWiE were 30% Club, PETRONAS Leading Women Network, Shell Women Action Network and General Electric Women Network. Such collaborations increase networking opportunities for MGA and its members. FoWiE provided a rare and unique platform for women in the energy sector to congregate, network and discuss common issues.
9. What is next in the development and progress plans of gas industry in Malaysia?
To achieve a sustainable gas industry, it is imperative that the gas industry reform and market liberalization remain on track and demand growth for gas increase exponentially.
One of the priorities for MGA is to enhance gas advocacy. Gas has all the attributes to support the national aspirations to ensure energy security whilst achieving reduction in carbon emission as committed in the Paris Agreement.
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Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.
The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can.
This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.
The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.
The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis.
Current OPEC membership:
U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) averaged 1.8 million barrels per day (b/d) in 2018, setting a new annual record. The U.S. Energy Information Administration (EIA) expects oil production in the GOM to set new production records in 2019 and in 2020, even after accounting for shut-ins related to Hurricane Barry in July 2019 and including forecasted adjustments for hurricane-related shut-ins for the remainder of 2019 and for 2020.
Based on EIA’s latest Short-Term Energy Outlook’s (STEO) expected production levels at new and existing fields, annual crude oil production in the GOM will increase to an average of 1.9 million b/d in 2019 and 2.0 million b/d in 2020. However, even with this level of growth, projected GOM crude oil production will account for a smaller share of the U.S. total. EIA expects the GOM to account for 15% of total U.S. crude oil production in 2019 and in 2020, compared with 23% of total U.S. crude oil production in 2011, as onshore production growth continues to outpace offshore production growth.
In 2019, crude oil production in the GOM fell from 1.9 million b/d in June to 1.6 million b/d in July because some production platforms were evacuated in anticipation of Hurricane Barry. This disruption was resolved relatively quickly, and no disruptions caused by Hurricane Barry remain. Although final data are not yet available, EIA estimates GOM crude oil production reached 2.0 million b/d in August 2019.
Producers expect eight new projects to come online in 2019 and four more in 2020. EIA expects these projects to contribute about 44,000 b/d in 2019 and about 190,000 b/d in 2020 as projects ramp up production. Uncertainties in oil markets affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.
Source: Rystad Energy
Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to reconsider future exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2018.
Crude oil price increases in 2017 and 2018 relative to lows in 2015 and 2016 have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discoveries in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead they affect the discovery of future fields and the start-up of new projects.
Source: U.S. Energy Information Administration, Monthly Refinery Report
The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.
API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.
The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.
Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.
Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report
When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.
Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.
By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.
East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.