Last Updated: October 6, 2020
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The Malampaya gas field, located in the West Philippine Sea, off the coast of Palawan, was discovered in 1989 through the Camago-1 well. It was the first major natural gas discovery in the Philippines, and indeed, the first major upstream discovery of any kind. Developed by Shell, Chevron and the Philippine National Oil Company (PNOC), first gas flowed in 2001 and commercial production in 2002. Malampaya Phase 2 kicked off in 2013 and Phase 3 in 2015, while the gas itself powered a huge gas-to-power network in the industrial city of Batangas that provides up to 40% of the energy demand in the island of Luzon. For a single project to have such impact is transformative. But that’s not the problem. The problem is that Malampaya is still the only major upstream project in the Philippines. And it won’t be around forever.

In fact, if estimates are correct, it won’t even be around for another decade. Output from current wells is expected to fall steeply in 2024 and dry out in 2027. If that happens, the complicated network of pipelines criss-crossing the sea into Batangas and then north towards the capital will be empty. What options does the Philippines have?

Of course, Malampaya itself isn’t fully tapped. In fact, there is an undeveloped portion called Malampaya East that could hold up to 2.83 bcm of natural gas. If correct and commercialised properly, the lifespan of Malampaya could be extended into the early 2030s. However, the entire field lies in challenging deep waters. Global supermajors Shell and Chevron had the expertise to draw those volumes of hydrocarbons to the surface, but now they want out. Chevron exited Malampaya in November 2019, as part of an asset review to re-focus on shale, selling its 45% stake to local player Phoenix Petroleum that is part of the Udenna conglomerate. And now Shell, which is operator of Malampaya, wants out as well, offering up its own 45% stake as it starts rationalising its own portfolio. In a Covid-19 world, no major player wants to be holding on to a depleting asset, unless there are national issues at stake.

The natural candidate to acquire Shell’s departing stake would be PNOC, which is already 10% owner of Malampaya, since that would bring the disparate and minor upstream assets in the Philippines under more centralised control. PNOC has already expressed interest. Politically-connected Udenna also wants to expand, calling itself the ‘most suitable party’ to assume Shell’s interest (in Malampaya). And finally, San Miguel Corp, which owns and operates the power plants running on Malampaya gas (under service contracts that expire in 2022/24) is also keen to secure its crucial supply. On paper, all three are suitable suitors. In reality, however, none has the depth of technical expertise required to expand and explore Malampaya. They could be custodians of an expiring asset but may not be able to jolt it back to life.

Efforts by the Philippines to replace Malampaya have been not very successful, with only minor fields to show. Coupled with the country’s on-again, off-again showdown with China in the portion of the South China Sea that falls within the so-called ‘nine-dash line’, it is unlikely that a second Malampaya will ever be discovered very soon. Maritime confrontations have so far centred around fishing rights, but that’s only because no large hydrocarbon assets have been found in disputed waters. And, given Rodrigo Duterte’s current stand towards China, it is unlikely to change substantially.

Which leaves the Philippines one more option to replace Malampaya: LNG. The master plan for LNG centred around replacing and supplementing the infrastructure in Batangas with LNG receiving and regasification operations. Various versions of this plan have been floating around since the mid-2000s. In fact, the Philippine government reportedly came close to approving one of the several competing LNG project plans, some backed by international players, but most consisting of domestic firms, several times over the last ten years. But for some reason or other, no official order was ever issued. And time is running out.

Buying gas into the Philippines is relatively more straight forward, compared to exploring and investing into new gas fields. There’s plenty of LNG around: from Australia, Qatar, the US, even nearby from Malaysia or Indonesia. With the current glut in the market, it would have been an easy option to secure a major long-term supply contract that secure the future of natural gas in the Philippines now. Nothing has been built yet.

But it soon might. The Philippine government has finally given the official nod to an LNG scheme by local player First Gen Corporation (backed by Japan’s Tokyo Gas). The plan calls for an FSRU to be operational by 2H 2022, which is quite an ambitious timeline. Allowing for inevitable delays, the First Gen LNG project will cut it quite close to the projected plunge in Malampaya volumes due in 2024. It might be the first, but it won’t be the last. The Philippines will need more LNG infrastructure built to power its own growing demand. This all could have been put into motion several years ago if the government had not dragged its feet. Better late than never, but the result is a country cutting it very close to a depleting energy line.

End of Article

Market Outlook:

  • Crude price trading range: Brent – US$38-40/b, WTI – US$36-38/b
  • Oil prices slide back a notch below the US$40/b level, with growing concerns that the nascent recovery in demand will be cut short by the current second – and potentially wider – resurgence in the global Covid-19 pandemic
  • A huge gasoil glut in Europe – triggered as refineries cut back on jet fuel and moved to diesel – might grow worldwide as well; several European refineries are already idling and making plans to permanently move away from refining
  • The return of supply from Libya is also a concern; OPEC+ is also grappling with quota flouts not just from the usual suspects but also Saudi allies, which might rumble the club’s plan to stick to its tiered schedule for production cuts

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Natural gas generators make up largest share of U.S. electricity generation capacity

operating natural-gas fired electric generating capacity by online year

Source: U.S. Energy Information Administration, Annual Electric Generator Inventory

Based on the U.S. Energy Information Administration's (EIA) annual survey of electric generators, natural gas-fired generators accounted for 43% of operating U.S. electricity generating capacity in 2019. These natural gas-fired generators provided 39% of electricity generation in 2019, more than any other source. Most of the natural gas-fired capacity added in recent decades uses combined-cycle technology, which surpassed coal-fired generators in 2018 to become the technology with the most electricity generating capacity in the United States.

Technological improvements have led to improved efficiency of natural gas generators since the mid-1980s, when combined-cycle plants began replacing older, less efficient steam turbines. For steam turbines, boilers combust fuel to generate steam that drives a turbine to generate electricity. Combustion turbines use a fuel-air mixture to spin a gas turbine. Combined-cycle units, as their name implies, combine these technologies: a fuel-air mixture spins gas turbines to generate electricity, and the excess heat from the gas turbine is used to generate steam for a steam turbine that generates additional electricity.

Combined-cycle generators generally operate for extended periods; combustion turbines and steam turbines are typically only used at times of peak load. Relatively few steam turbines have been installed since the late 1970s, and many steam turbines have been retired in recent years.

natural gas-fired electric gnerating capacity by retirement year

Source: U.S. Energy Information Administration, Annual Electric Generator Inventory

Not only are combined-cycle systems more efficient than steam or combustion turbines alone, the combined-cycle systems installed more recently are more efficient than the combined-cycle units installed more than a decade ago. These changes in efficiency have reduced the amount of natural gas needed to produce the same amount of electricity. Combined-cycle generators consume 80% of the natural gas used to generate electric power but provide 85% of total natural gas-fired electricity.

operating natural gas-fired electric generating capacity in selected states

Source: U.S. Energy Information Administration, Annual Electric Generator Inventory

Every U.S. state, except Vermont and Hawaii, has at least one utility-scale natural gas electric power plant. Texas, Florida, and California—the three states with the most electricity consumption in 2019—each have more than 35 gigawatts of natural gas-fired capacity. In many states, the majority of this capacity is combined-cycle technology, but 44% of New York’s natural gas capacity is steam turbines and 67% of Illinois’s natural gas capacity is combustion turbines.

October, 19 2020
EIA’s International Energy Outlook analyzes electricity markets in India, Africa, and Asia

Countries that are not members of the Organization for Economic Cooperation and Development (OECD) in Asia, including China and India, and in Africa are home to more than two-thirds of the world population. These regions accounted for 44% of primary energy consumed by the electric sector in 2019, and the U.S. Energy Information Administration (EIA) projected they will reach 56% by 2050 in the Reference case in the International Energy Outlook 2019 (IEO2019). Changes in these economies significantly affect global energy markets.

Today, EIA is releasing its International Energy Outlook 2020 (IEO2020), which analyzes generating technology, fuel price, and infrastructure uncertainty in the electricity markets of Africa, Asia, and India. A related webcast presentation will begin this morning at 9:00 a.m. Eastern Time from the Center for Strategic and International Studies.

global energy consumption for power generation

Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)

IEO2020 focuses on the electricity sector, which consumes a growing share of the world’s primary energy. The makeup of the electricity sector is changing rapidly. The use of cost-efficient wind and solar technologies is increasing, and, in many regions of the world, use of lower-cost liquefied natural gas is also increasing. In IEO2019, EIA projected renewables to rise from about 20% of total energy consumed for electricity generation in 2010 to the largest single energy source by 2050.

The following are some key findings of IEO2020:

  • As energy use grows in Asia, some cases indicate more than 50% of electricity could be generated from renewables by 2050.
    IEO2020 features cases that consider differing natural gas prices and renewable energy capital costs in Asia, showing how these costs could shift the fuel mix for generating electricity in the region either further toward fossil fuels or toward renewables.
  • Africa could meet its electricity growth needs in different ways depending on whether development comes as an expansion of the central grid or as off-grid systems.
    Falling costs for solar photovoltaic installations and increased use of off-grid distribution systems have opened up technology options for the development of electricity infrastructure in Africa. Africa’s power generation mix could shift away from current coal-fired and natural gas-fired technologies used in the existing central grid toward off-grid resources, including extensive use of non-hydroelectric renewable generation sources.
  • Transmission infrastructure affects options available to change the future fuel mix for electricity generation in India.
    IEO2020 cases demonstrate the ways that electricity grid interconnections influence fuel choices for electricity generation in India. In cases where India relies more on a unified grid that can transmit electricity across regions, the share of renewables significantly increases and the share of coal decreases between 2019 and 2050. More limited movement of electricity favors existing in-region generation, which is mostly fossil fuels.

IEO2020 builds on the Reference case presented in IEO2019. The models, economic assumptions, and input oil prices from the IEO2019 Reference case largely remained unchanged, but EIA adjusted specific elements or assumptions to explore areas of uncertainty such as the rapid growth of renewable energy.

Because IEO2020 is based on the IEO2019 modeling platform and because it focuses on long-term electricity market dynamics, it does not include the impacts of COVID-19 and related mitigation efforts. The Annual Energy Outlook 2021 (AEO2021) and IEO2021 will both feature analyses of the impact of COVID-19 mitigation efforts on energy markets.

Asia infographic, as described in the article text

Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)
Note: Click to enlarge.

With the IEO2020 release, EIA is publishing new Plain Language documentation of EIA’s World Energy Projection System (WEPS), the modeling system that EIA uses to produce IEO projections. EIA’s new Handbook of Energy Modeling Methods includes sections on most WEPS components, and EIA will release more sections in the coming months.

October, 16 2020
Global liquid fuels production outages have increased in 2020

Disruptions to crude oil and condensate production from members of the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC countries have risen considerably since last year. These outages have contributed to reduced liquid fuel supply and, along with crude oil production declines agreed to among OPEC and partner countries (OPEC+), have contributed to global liquid fuels inventory draws since June.

So far in 2020, monthly oil supply disruptions have averaged 4.6 million barrels per day (b/d) and reached 5.2 million b/d in June, the highest monthly levels since at least 2011, when the U.S. Energy Information Administration (EIA) began tracking monthly liquids production outages. Global oil supply disruptions averaged 3.1 million b/d in 2019, and rising outages in Iran have been the main drivers of the year-on-year increase. EIA does not include field closures for economic reasons or oil demand declines in its accounting of supply disruptions.

Libya, Venezuela, and Iran (the OPEC countries exempt from the latest OPEC+ agreement) were the main contributors to these outages. Domestic political instability in Libya has removed about 1.2 million b/d from oil production since February 2020. The Libyan National Army, the warring faction in eastern Libya, blockaded five of the country’s oil export terminals and shut in oil production from major fields in the southwestern region in January 2020, causing Libya’s production to fall to less than 100,000 b/d by April.

U.S. sanctions have led to production outages in Venezuela and Iran. U.S. sanctions placed on oil-trading companies and shipping companies that facilitated exports of Venezuela’s crude oil in the first half of 2020 removed 500,000 b/d of crude oil production from global markets by August. Ongoing U.S. sanctions on Iran’s crude oil and condensate exports have kept Iran’s disruption levels elevated through 2020, and disruptions there have increased by another 100,000 b/d since January.

Non-OPEC oil supply disruptions, mostly from the United States and Canada, rose to nearly 800,000 b/d in August. Disruptions in Canada occurred when operators ordered nonessential staff to stop work because of coronavirus outbreaks at production sites. In the United States, hurricane-related disruptions and unplanned maintenance affected oil production this summer. Other non-OPEC countries experienced temporary field closures for various reasons such as coronavirus outbreaks among workers, logistical issues moving workers or equipment during the pandemic, fires at field operations in Canada, or other natural disasters.

EIA publishes historical unplanned production outage estimates in its Short-Term Energy Outlook (STEO). In its estimates of outages, EIA differentiates among declines in production resulting from unplanned production outages, permanent losses of production capacity, and voluntary production cutbacks. EIA’s estimates of unplanned production outages are calculated as the difference between estimated effective production capacity (the level of supply that could be available within one year) and estimated production.

October, 14 2020