Soon, it will be two years from Malaysia’s historic general election, where the ruling Barisan Nasional coalition was swept out of power for the first time in over 60 years. Opinions are divided on how effective the new government, under an old Prime Minister has been, but there has certainly been progress on a number of issues. And one of those issues is the relationship between Peninsular Malaysia and the Bornean states of Sabah and Sarawak. This is where most of Malaysia’s oil and gas fields lie, and appeasing the states that became a backbone of the 2018 general election victory is important enough that the Malaysian government is considering selling stakes in its crown jewel Petronas to them.
To understand the situation, one has to understand Malaysia. Malaysia – in its modern incarnation is a federation within a federation. The Federation of Malaya was formed in 1948, comprising the nine states and two British Straits Settlements of Peninsular Malaysia, gaining independence in 1957. In 1963, Malaysia was formed through the Malaysia Agreement, become a federation of Malaya, North Borneo (now Sabah), Sarawak and Singapore. This is known as the MA63 agreement, and through that, Sabah and Sarawak retain a unique status within the federation and considerable autonomy.
Autonomy that has been eroded over the decades, as more power was progressively transferred to the federal government of Malaysia since the 1960s. The seeds of Sabah and Sarawak’s current discontent over their oil royalties date back to 1974, when the state oil firm Petronas was formed, with the mandate of developing the entirety of oil and gas resources in Malaysia. In the early years, oil reserves were exploited off the east coast of Peninsular Malaysia, with the fields in Terengganu yielding the once-benchmark Tapis blend. In charge of extracting, processing and selling the oil, Petronas paid an oil royalty back to the states where it was found. Set at 5%, that rate has been the subject of grouses, with the states complaining that the royalty was too low. These complaints ebbed and flowed depending on which party was in charge of the state government, but were largely contained. As crude production in Peninsular Malaysia abated and the focus shifted to the huge reserves and untapped potential in Sabah and Sarawak, however, the oil royalty issue has taken on a new dimension.
According to the MA63 agreement, Sabah and Sarawak were considered independent nations that voluntarily joined the Federation of Malaysia in 1963, enshrining their additional rights. Given that the Bornean states now hold over 60% of the country’s oil reserves, they have been demanding a higher oil royalty. This carries more weight than a complaint from Terengganu, which was part of the original Federation of Malaya. This has a political dimension as well, since Sabah and Sarawak are guaranteed 25% of federal parliamentary seats – effectively making the states kingmakers in national elections. It was a shift in political tides in Sabah in 2018 that swept the new government in, in part due to the fact that the now-ruling coalition promised to restore Sabah and Sarawak to their MA63 status.
In the 2018 campaign, a promise to increase the oil royalty from 5% to 20% for Sabah and Sarawak was floated. It proved to be an effective one, but one that the government says it is facing challenges in meeting due to the fiscal irresponsibility of previous governments and to prevent a negative impact on Petronas. This has ruffled a lot of feathers in Sabah and Sarawak, which could colour future general elections and impending by-elections. Which is why alternatives – including selling stakes in Petronas – have been proposed. That was immediately rejected by both states, and talks continue. At stake is not just several billion in oil royalties, but the political future of Malaysia.
Malaysian oil & condensate production by region, 2018
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This winter, natural gas prices have been at their lowest levels in decades. On Monday, February 10, the near-month natural gas futures price at the New York Mercantile Exchange (NYMEX) closed at $1.77 per million British thermal units (MMBtu). This price was the lowest February closing price for the near-month contract since at least 2001, in real terms, and the lowest near-month futures price in any month since March 8, 2016, according to Bloomberg, L.P. and FRED data.
In addition, according to Natural Gas Intelligence data, the daily spot price at the Henry Hub national benchmark was $1.81/MMBtu on February 10, 2020, the lowest price in real terms since March 9, 2016. Henry Hub spot prices have ranged between $1.81/MMBtu and $2.84/MMBtu this winter heating season (since November 1, 2019), generally because relatively warm winter weather has reduced demand for natural gas for heating. Natural gas production growth has outpaced demand growth, reducing the need to withdraw natural gas from underground storage.
Dry natural gas production in January 2020 averaged about 95.0 billion cubic feet per day (Bcf/d), according to IHS Markit data. IHS Markit also estimates that in January 2020 the United States saw the third-highest monthly U.S. natural gas production on record, down slightly from the previous two months.
IHS Markit estimates that U.S. natural gas consumption by residential, commercial, industrial, and electric power sectors averaged 96 Bcf/d for January, which was about 4.4 Bcf/d less than the average for January 2019, largely because of decreases in residential and commercial consumption as a result of warmer temperatures.
However, IHS Markit estimates that overall consumption of natural gas (including feed gas to liquefied natural gas (LNG) export facilities, pipeline fuel losses, and net exports by pipeline to Mexico) averaged about 117.5 Bcf/d in January 2020, an increase of about 0.2 Bcf/d from last year. This overall increase is largely a result of an almost doubling of LNG feed gas to about 8.5 Bcf/d.
Because supply growth has outpaced demand growth, less natural gas has been withdrawn from storage withdrawals this winter. Despite starting the 2019–20 heating season with the third-lowest level of natural gas inventory since 2009, by January 17, 2020, working natural gas inventories reached relatively high levels for mid-winter. The U.S. Energy Information Administration’s (EIA) data on natural gas inventories for the Lower 48 states as of February 7, 2020, reflect a 215 Bcf surplus to the five-year average. In EIA’s latest short-term forecast, more natural gas remains in storage levels than the previous five-year average through the remainder of the winter.
According to the National Oceanic and Atmospheric Administration (NOAA), January 2020 was the fifth-warmest in its 126-year climate record. Heating degree days (HDDs), a temperature-based metric for heating demand, have been relatively low this winter, which is consistent with a warmer winter. During some weeks in late December and early January, the United States saw 25% to 30% fewer HDDs than the 30-year average. This winter, through February 8, residential natural gas customers in the United States have seen 11% fewer HDDs than the 30-year average.
Source: U.S. Energy Information Administration, based on National Oceanic and Atmospheric Administration Climate Prediction Center data
Headline crude prices for the week beginning 10 February 2020 – Brent: US$53/b; WTI: US$49/b
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