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This is part of its ambitious drive to push renewables to 23% by 2025.


Bloomberg reported that Indonesia will not approve any new coal-fired power stations on the heavily-populated island of Java as the country strives to reach its renewable energy development targets, the energy minister said on Thursday.

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EIA expects natural gas production and exports to continue increasing in most scenarios

According to projections published in the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook 2020 (AEO2020), total dry natural gas production in the United States will continue to increase until 2050 in most of the AEO2020 cases, primarily to support growing U.S. exports of natural gas to global markets. The United States began exporting more natural gas than it imports on an annual basis in 2017, driven by increased liquefied natural gas (LNG) exports, increased pipeline exports to Mexico, and reduced imports from Canada. In most of the AEO2020 cases, net natural gas exports continue to increase through 2050, and most of the increase is in the near term.

The AEO2020 Reference case represents EIA’s best assessment of how U.S. and world energy markets will operate through 2050, assuming no significant changes in energy policy occur. Side cases show the effects of changing model assumptions: the High and Low Oil Price cases simulate international conditions that could drive crude oil prices higher or lower, and the High and Low Oil and Gas Supply cases vary production costs and resource recoverability within the United States.

U.S. dry natural gas production, AEO2020 reference case

Source: U.S. Energy Information Administration, Annual Energy Outlook 2020

EIA expects dry natural gas production to total 34 trillion cubic feet (Tcf) in 2019 once the final data is in. In the AEO2020 Reference case, EIA projects that U.S. dry natural gas production will reach 45 Tcf by 2050. Production growth results largely from continued development of tight and shale resources in the East, Gulf Coast, and Southwest regions, which more than offsets production declines in other regions. Dry natural gas production from these three regions accounted for 68% of total U.S. dry natural gas production in 2019 and, in the Reference case, 78% of dry natural gas production in 2050.

Most of the increase in dry natural gas production is coming from natural gas formations such as the Marcellus and Utica in the East region and the Haynesville in the Gulf Coast region. A smaller but still significant portion of the growth is from natural gas production in oil formations (also known as associated gas), especially in the Permian Basin in the Southwest region.

U.S. natural gas trade, aeo2020 reference case

Source: U.S. Energy Information Administration, Annual Energy Outlook 2020

In the Reference case, both U.S. natural gas exports by pipeline and U.S. LNG exports continue to grow through 2030. LNG exports account for most of the export growth because more LNG export facilities are becoming operational and more projects are under construction. In the Reference case, EIA projects that LNG exports will almost triple, from 1.7 Tcf in 2019 to 5.8 Tcf in 2030, the equivalent of nearly 16 billion cubic feet per day (Bcf/d). LNG exports remain at this level through 2050 as U.S.-sourced LNG becomes less competitive in world markets and as more countries become global LNG suppliers.

U.S. LNG exports are more competitive when oil prices are high (as in the High Oil Price case) and U.S. natural gas prices are low (as in the High Oil and Gas Supply case) because of pricing structures that link Brent crude oil prices to LNG prices in many world markets. In the High Oil Price case, U.S. natural gas net exports reach nearly 13 Tcf by the late 2030s, most of which is LNG. Conversely, in the Low Oil Price case and Low Oil and Gas Supply case, U.S. LNG is less competitive globally and remains lower than 5 Tcf per year through 2050.

By comparison, pipeline trade of U.S. natural gas is less sensitive to changes in assumptions about domestic natural gas supply and world oil prices. Pipeline trade of natural gas is highest in the High Oil and Gas Supply case because low domestic natural gas prices reduce U.S. natural gas imports from Canada.

U.S. natural gas net trade

Source: U.S. Energy Information Administration, Annual Energy Outlook 2020

February, 20 2020
Natural gas prices fall to lowest level since 2016, the lowest February prices in 20 years

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.

lower 48 states working natural gas in storage

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and Short-Term Energy Outlook

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.

U.S. natural gas customer-weighted heating degree days

Source: U.S. Energy Information Administration, based on National Oceanic and Atmospheric Administration Climate Prediction Center data

February, 17 2020
Your Weekly Update: 10 -14 February 2020

Market Watch   

Headline crude prices for the week beginning 10 February 2020 – Brent: US$53/b; WTI: US$49/b

  • The demand destruction caused by the Covid-19 pandemic – also known as the Wuhan coronavirus – has dragged crude prices to fresh lows, with OPEC+ struggling to present a united front to respond to the demand crisis
  • Earlier indications that OPEC+ was preparing to call for an emergency meeting mid-February to discuss the pandemic’s impact on the oil market were dashed, hinting at divisions within the oil club
  • Reportedly, OPEC’s technical committee was proposing to extend the club’s supply quota agreement through June 2020; Saudi Arabia – along with Iran and Bahrain – were the strongest supporters, but Russia remains reticent to commit
  • A group of key Russian oil producers are in support of extending the OPEC+ cuts, with Gazprom, Lukoil and Rosneft indicating that it ‘made sense’
  • In the face of the huge impact of Covid-19, the so-called Brent red spread sank into contango, indicating an intensely bear-ish market
  • Although the fatality rate of the new coronavirus is much lower than SARS, the spread has been far more severe and wider, with confirmed cases nearing 70,000 and deaths nearing 1,500
  • After being on lockdown for weeks, Chinese factories and businesses have gradually returned to work at a glacial pace, impacting gasoline, gasoil and - most significantly – jet fuel demand, causing Chinese refineries to slash output
  • News that China and the US would both implement tariff cuts on the pre-Phase 1 trade deal levies on February 14 failed to calm the market, supporting the floor for prices rather than raising the ceiling
  • Amid that chaos, the US active rig count dropped four rigs, falling down to 790 total and down 255 sites y-o-y; however, the relationship between this proxy and actual production has diminished over the past two years, as the US continues to produce more oil from less rigs
  • Hopes that the outbreak might have peaked has supported crude oil prices this year, although a major spike in confirmed cases from a wider diagnosis tool nipped that in the bud; expect crude oil prices to continue hovering around the US$50/b mark, at US$51-53/b for Brent and US$49-51/b for WTI


Headlines of the week

Upstream

  • Chevron and Petrobras will be selling their stakes in the heavy oil Papa-terra field in the Campos Basin, seeking new operatorship for the BC-20 concession asset that is currently split 62.5/37.5 between Petrobras and Chevron
  • Shell plans to boost its output in the Permian Basin to some 250,000 b/d by end-2020, up from a current production level of 100,000 b/d as it announced plans to invest up to US$3 billion per year in the prolific US shale area
  • Eni’s oil production in Libya has halved to 160,000 b/d, as the country continues to grapple with a blockade started by military strongman Khalifa Haftar
  • Disappointing results in Africa have forced Tullow Oil to reduce its headcount in Kenya by 40%, with operations in Kenya, Uganda and Ghana all yielding either poor results or in danger of significant delays
  • BP and Shell have brought the Alligin field in the UK West of Shetlands region online, with initial output at a better-than-expected 12,000 b/d
  • Guyana’s oil riches keep increasing; after ExxonMobil upped estimates at the Stabroek block last month, Eco Atlantic (together with Tullow Oil and Total) have upped reserves in the Orinduik block from 3.98 mmboe/d to 5.14 mmboe/d

Midstream/Downstream

  • Reports suggest that Chinese independent teapot refineries in Shandong have slashed their utilisation rates by 30-50%, scaling down in response to severely diminished fuel and petrochemicals demand due to the Covid-19 pandemic
  • Chinese state refiners are following suit with slashing output, with CNOOC, Sinopec and PetroChina all lowering their throughput rates by 10-15%
  • Shell has finalised the sale of its Martinez refinery in California, selling it to PBF Energy for some US$1.2 billion, including its supply/offtake agreements
  • Botswana is accelerating its US$4 billion coal-to-liquids refinery project, now expecting to complete the site by 2025, with the aim of tapping into the country’s major coal reserves that are some of the largest in Africa
  • The UK has extended its goal to end the sale of all gasoline- and diesel-powered vehicles in the UK by 2035 to include hybrid vehicles, which would move transport fuel demand entirely to electric vehicles then

Natural Gas/LNG

  • Abu Dhabi and Dubai report that they have made a major natural gas find, with the Jebel Ali reservoir located between the two largest sheikhdoms in the UAE holding some 80 tcf of resources - the world’s largest gas find in 15 years
  • The government of Papua New Guinea has walked away from talks over the P’nyang gas field, impacting the planned expansion of ExxonMobil’s PNG LNG project; the government had previously tried a similar tactic with Total
  • The EU has imposed sanctions on Turkey, in retaliation for its continued exploration of gas resources in the disputed waters off Cyprus that Turkey claims is part of the breakaway Turkish province in the north of the island
  • CNOOC has declared force majeure on some LNG contracts due to the ongoing impact of the Covid-19 outbreak, but two of the world’s largest LNG traders – Shell and Total – have rejected the Chinese attempt to nullify contractual terms
  • Centrica will take a major write-down on its gas assets in Europe, continuing a trend of the global natural gas glut eroding the value of gas assets worldwide
  • GeoPark has made a new natural gas discovery in Chile, with the Jauke Oeste field in the Fell block of the Magallanese Basin yielding small-but-significant gas flows of some 4.4 mscf/d
February, 14 2020