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Last Updated: January 10, 2020
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In 2019, natural gas spot prices at the national benchmark Henry Hub in Louisiana averaged $2.57 per million British thermal units (MMBtu), about 60 cents per MMBtu lower than in 2018 and the lowest annual average price since 2016. Lower natural gas prices in 2019 supported higher consumption—particularly in the electric generation sector—and higher natural gas exports. Continued growth in domestic production of natural gas also supported lower natural gas prices throughout the year.

Monthly average natural gas prices at most key regional trading hubs in 2019 reached their highest levels in February, and they were relatively low and stable from April through December. In the Northeast, additional imports of liquefied natural gas (LNG) into New England limited price spikes during the winter of 2018–19. Despite a cold snap in the Midwest in February 2019, natural gas prices at Chicago Citygate were lower than during previous extreme weather events.

However, in the Pacific Northwest, unseasonably cold weather at the end of winter coupled with regional supply constraints and decreased storage inventories led to significant price spikes at the Northwest Sumas hub in March. Additional pipeline takeaway capacity in the Permian region eased some infrastructure constraints and increased regional prices at the Waha hub in western Texas after six consecutive months of prices lower than $1/MMBtu (March through August).

monthly average natural gas spot prices at key trading hubs

Source: U.S. Energy Information Administration, based on Natural Gas Intelligence

Natural gas consumption in the residential and commercial sectors increased by 2% in 2019 compared with 2018, based on the U.S. Energy Information Administration’s (EIA) monthly data through October and estimates for November and December. Natural gas use in the electric generation sector also increased in 2019, particularly in July and August when a heat wave in the Midwest and the Northeast led to record-high generation by natural gas-fired power plants.

Lower summer natural gas prices, which averaged $2.33/MMBtu in June through August (the lowest summer average Henry Hub natural gas price since 1998), have supported higher natural gas-fired generation in the summer months.

Dry natural gas production has grown every year since 2016. Production increased by 7.5 billion cubic feet per day (Bcf/d) (9%) through the first 10 months of the year after record growth in 2018. Sustained growth in natural gas production put downward pressure on prices, which continued to decline for most of 2019.

Natural gas storage inventories ended the withdrawal season at the end of March at their lowest levels since 2014. However, record natural gas production growth supported near-record injection activity during the injection season through October. The injection season ended with the second-highest net injection volume since 2014.

Most new pipelines placed in service in 2019 were located in the South Central and Northeast regions. These pipelines provide additional takeaway capacity out of the Permian and Appalachian supply basins and will serve growing demand for LNG exports, pipeline exports to Mexico, and U.S. natural gas-fired power generation.

In 2019, natural gas exports—both by pipeline to Mexico and as LNG—continued to grow. U.S. natural gas exports to Mexico by pipeline averaged 5.1 Bcf/d in the first 10 months of 2019, 0.4 Bcf/d more than the 2018 average. Following an expansion in U.S. cross-border pipeline capacity, several new pipelines in Mexico continued to experience delays, limiting growth in exports.

U.S. LNG exports set a new record in 2019, averaging an estimated 5.0 Bcf/d (69% higher than in 2018) as the United States became the third-largest global LNG exporter. Several new LNG facilities were placed in service in 2019. Louisiana’s Cameron LNG placed its first liquefaction unit (referred to as a train) in service in May. Texas’s Freeport LNG exported its first cargo from the newly commissioned Train 1 in September, followed by its first export cargo from Train 2 in December. Corpus Christi LNG (also in Texas) commissioned its second train in July. In December, Georgia’s Elba Island placed in service the first three of its moveable modular liquefaction system (MMLS) units and exported its first LNG cargo.

monthly natural gas trade

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

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Your Weekly Update: 13 - 17 January 2020

Market Watch   

Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b

  • Tensions in the Persian Gulf have abated, but not disappeared, as both the US and Iran stepped back from going to war; the buck, so far, has stopped with Tehran’s retaliation to the US assassination of its top general with a barrage of missile strikes at US bases in Iraq
  • The underlying situation is still fragile, with the Iranian population swinging from supporting the government to protesting its accidental downing of a commercial Ukraine Airlines plane; with the risk of war easing, crude prices have fallen back to their pre-crisis levels
  • However, American and foreign oil companies have pulled their staff from crude fields in northern Iraq and Kurdistan, including Chevron, as the oil industry in Iraq monitors the risk – and consequences – of military action
  • In precaution, oil tankers have begun boosting their rates once again to haul crude through the Persian Gulf, with quoted rates now at their highest level since the 2019 attacks on ships passing through the narrow straight
  • Although political tensions remain fresh, Saudi Arabia said that OPEC and the OPEC+ club were instead focused on using their window of production cuts to reduce excess oil stockpiles to levels ‘within the contours of 2010-2014’
  • In the US, not only is shale output staying strong, but production in the US Gulf of Mexico also made history, exceeding 2 mmb/d for the first time ever in 2019, beating the previous high recorded in 2018
  • Worries about the health of global oil demand persist… although the US and China signed a Phase 1 trade deal, the agreement is more about halting escalation of the trade war than repairing inflicted damage; a slowdown in Chinese economic growth could lead to oil demand growth halving in 2020 in China according to CNPC
  • The US active rig count fell for a second consecutive week, losing 15 rigs – 11 oil and 4 gas – for the 17th weekly decline of the past 20 weeks; losses in the Permian were once again high, shedding a total of 6 rigs
  • Crude oil prices should remain rangebound with Brent at US$63-65/b and WTI at US$57-59/b, as the market retreats back to its ever-present worries about demand while geopolitical risk premiums scale back


Headlines of the week

Upstream

  • Guyana’s success is now extending to its neighbours, with Total and Apache announcing a ‘significant’ oil discovery at their Maka Central-1 well in Suriname’s Block 58, which lies adjacent to the prolific Stabroek Block
  • BP has agreed to sell its operating interest in the UK North Sea’s Andrew assets – including the Andrew platform as well as the Andrew, Arundel, Cyrus, Farragon, and Kinnoull fields – along with its 27.5% non-operating interest in the Shearwater field to Premier Oil for some US$625 million
  • Liberia will kick start its next offshore licensing round in April 2020, offering nine blocks in the Harper basin, one of the few offshore regions in West Africa that remains unexplored and undrilled
  • Equinor has extended the life of its Statfjord assets beyond 2030, with plans to commission up to 100 new wells over the next decade, deferring decommissioning with a goal of maintaining current output levels beyond 2025
  • After Murphy Oil, Petrofac and ExxonMobil, Repsol is the latest major considering an upstream exit from Malaysia, covering assets that include six development blocks and the major Kinabalu oilfield in Sabah
  • Senegal’s government has approved Woodside’s offshore Sangomar Field Development, which will involve the drilling of 23 subsea wells and a FPSO with the capacity to process up to 100,000 b/d of crude
  • Equinor has announced plans to reduce greenhouse gas emissions from its offshore fields and onshore plants in Norway by 40% by 2030, 70% by 2040 and to near zero by 2050 from 2019 levels

Midstream/Downstream

  • Shell is reportedly seeking buyers for its 144 kb/d Anacortes refinery in Washington state, which would be its third North American sale in two years after divesting its Martinez refinery in California and Sarnia refinery in Ontario
  • Shell has announced plans to increase its share of the Mexican fuel market to 15%, which would require considerable growth in its network of 200 fuel stations in 12 states that currently represent 1% of the market
  • Occidental Petroleum plans to reduce its holdings in Western Midstream Partners – acquired as part of its controversial takeover of Anadarko – to less than 50%, potentially removing up to US$7.8 billion of debt

Natural Gas/LNG

  • Sempra Energy and Saudi Aramco have signed an agreement that will see the Saudi giant play a bigger part in the planned 22 million tpa Port Arthurt LNG project, following an existing agreement to purchase 5 mtpa signed in May 2019
  • Kuwait Petroleum Corp has agreed to purchase 3 million tpa of LNG from Qatar Petroleum for 15 years beginning 2022, with Kuwait remaining one of the few countries in the Middle East that remain neutral to the Saudi-Qatar standoff
  • ExxonMobil has signed an agreement with midstream company Outrigger Energy II to build a 250 mmscf/d cryogenic gas processing, gathering and pipeline system in the Bakken’s Williston Basin in North Dakota
  • The Larak gas field in Sarawak has achieved first gas, operated by SapuraOMV Upstream as part of the SK408 PSC that includes the Gorek and Bakong fields, with output planned to be processed into LNG at Petronas’ Bintulu complex
  • Russia’s TurkStream natural gas pipeline – connecting Russia, Turkey, Bulgaria and eventually Serbia and Hungary - has officially begun operations, delivering up to 13 bcm of Russian gas that can be rerouted from the Ukraine route
January, 17 2020
EIA forecasts slower growth in natural gas-fired generation while renewable energy rises

annual U.S. electric power sector generation by energy source

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

In its latest Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that generation from natural gas-fired power plants in the electric power sector will grow by 1.3% in 2020. This growth rate would be the slowest growth rate in natural gas generation since 2017. EIA forecasts that generation from nonhydropower renewable energy sources, such as solar and wind, will grow by 15% in 2020—the fastest rate in four years. Forecast generation from coal-fired power plants declines by 13% in 2020.

During the past decade, the electric power sector has been retiring coal-fired generation plants while adding more natural gas generating capacity. In 2019, EIA estimates that 12.7 gigawatts (GW) of coal-fired capacity in the United States was retired, equivalent to 5% of the total existing coal-fired capacity at the beginning of the year. An additional 5.8 GW of U.S. coal capacity is scheduled to retire in 2020, contributing to a forecast 13% decline in coal-fired generation this year. In contrast, EIA estimates that the electric power sector has added or plans to add 11.4 GW of capacity at natural gas combined-cycle power plants in 2019 and 2020.

Generating capacity fueled by renewable energy sources, especially solar and wind, has increased steadily in recent years. EIA expects the U.S. electric power sector will add 19.3 GW of new utility-scale solar capacity in 2019 and 2020, a 65% increase from 2018 capacity levels. EIA expects a 32% increase of new wind capacity—or nearly 30 GW—to be installed in 2019 and 2020. Much of this new renewables capacity comes online at the end of the year, which affects generation trends in the following year.

Forecast generation mix varies in each of the 11 STEO electricity supply regions. A large proportion of the retired coal-fired capacity is located in the mid-Atlantic area, where PJM manages the dispatch of electricity. EIA forecasts that coal generation in the mid-Atlantic will decline by 37 billion kilowatthours (kWh) in 2020. Some of this decline is offset by more generation from mid-Atlantic natural gas-fired power plants; EIA expects generation from these plants to grow by 23 billion kWh.

forecast annual change in electric power sector generation by fuel

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

In the Midwest, where the Midcontinent ISO (MISO) manages electricity, EIA expects coal generation to fall in 2020 by 33 billion kWh. This decline is offset by an increase in natural gas electricity generation (12 billion kWh) and by nonhydropower renewable energy sources (13 billion kWh). The regional increase in renewables is primarily a result of new wind generating capacity.

The electric power sector in the area of Texas managed by the Electric Reliability Council of Texas (ERCOT) is planning to see large increases in generating capacity from both wind and solar. EIA expects this new capacity will increase generation from nonhydropower renewable energy sources by 24 billion kWh this year. EIA expects the increased ERCOT renewable generation will lead to a regional decline of natural gas-fired generation and coal generation of 14 billion kWh for each fuel source in 2020.

EIA expects these trends to continue into 2021. EIA forecasts U.S. generation from nonhydropower renewable energy sources will grow by 17% next year as the electric power sector continues expanding solar and wind capacity. This increase in renewables, along with forecast increases in natural gas fuel costs, contributes to EIA’s forecast of a 2.3% decline in natural gas-fired generation in 2021. U.S. coal generation in 2021 is forecast to fall by 3.2%.

January, 17 2020
EIA forecasts that crude oil prices will fall during the first half of 2020, then increase through 2021

In the U.S. Energy Information Administration’s (EIA) January Short-Term Energy Outlook (STEO), EIA forecasts that the Brent crude oil spot price will average $65 per barrel (b) in 2020 and $68/b in 2021 (Figure 1). EIA forecasts that the West Texas Intermediate (WTI) spot price will average $59/b in 2020 and $62/b in 2021. EIA forecasts that crude oil prices will remain elevated in the first few months of 2020, reflecting a price premium on crude oil from recent geopolitical events. However, this price premium will diminish in the first half of 2020 and market fundamentals will drive the crude oil price forecast in the second half of 2020 and in 2021.

Figure 1. West Texas Intermediate and Brent crude oil prices

Several geopolitical events have provided upward pressure on crude oil prices in recent months. These events include attacks on oil tankers transiting the Persian Gulf and the Red Sea, the September 2019 attack on Saudi Arabia’s energy infrastructure, and recent tensions between the United States and Iran.

Although the immediate price spike following the mid-September attacks on Saudi Arabia was relatively short-lived, the attacks contributed to increased price risk. As a result, monthly average Brent prices rose from $63/b in September to $67/b in December. Crude oil prices increased during this period despite global liquid fuels inventories growing by 130,000 barrels per day (b/d). Further increasing the geopolitical risk premium on global oil prices, the U.S. military action in Iraq in January 2020 increased uncertainty about potential disruptions to oil production and shipping in the Middle East. Following these developments, the price of Brent crude oil reached $70/b, but prices have subsequently fallen.

As the risk premium decreases, EIA assumes that Brent prices will decline in early 2020 to an average of $62/b in May. EIA does not forecast supply disruptions, and any physical supply disruptions would put upward pressure on prices.

In the first half of 2020, EIA expects significant liquid fuels supply growth. Production restraint from members of the Organization of the Petroleum Exporting Countries (OPEC) and several non-member countries (OPEC+), most notably Russia, and accelerating global demand growth will be more than offset by non-OPEC production, largely in the United States, Norway, Brazil, and Canada. EIA forecasts an average global stock build of 520,000 b/d in the first half of the year, which will put downward pressure on crude oil prices (Figure 2). However, later in 2020 and in 2021, non-OPEC production growth (particularly from U.S. tight oil) will slow significantly, which will contribute to tightening market balances and upward pressure on crude oil prices. Although the pace of global economic growth and resulting changes to oil consumption remain uncertain, EIA expects liquid fuels consumption growth to increase from 2019 levels.

Figure 2. World liquid fuels production and consumption balance

In December, OPEC+ announced an agreement to deepen production cuts through March 2020. The group is now targeting production that is 1.7 million b/d lower than in October 2018, compared with the former target reduction of 1.2 million b/d. EIA forecasts that 2020 OPEC crude oil production will average 29.2 million b/d and 2021 production will average 29.3 million b/d, down from an average of 29.8 million b/d in 2019. In the forecast, OPEC production remains lower than 2019 levels because EIA assumes that OPEC will limit production through all of 2020 and 2021 to maintain balanced global oil markets and because of continuing production declines in Venezuela and Iran.

The crude oil price forecast is also driven by a forecast that global economic growth will be higher in 2020 than in 2019. Based on forecasts from Oxford Economics, EIA adjusted its global oil-weighted gross domestic product (GDP) growth forecast for 2020 up slightly to 2.4% and further to almost 3.0% in 2021, up from GDP growth of 1.9% in 2019. EIA forecasts that global liquid fuels consumption will increase by 1.3 million b/d in 2020 and 1.4 million b/d in 2021. On December 13, the Office of the United States Trade Representative announced that the United States and China reached an agreement for a trade deal, which was signed on January 15. Global trade conditions are among the many factors that may influence the pace of economic growth in the coming quarters.

EIA forecasts that non-OPEC liquid fuels production will increase by 2.6 million b/d in 2020 and by 0.9 million b/d in 2021. Growth in 2020 is largely driven by production increases in the United States, Norway, Brazil, and Canada. Total U.S. liquid fuels production is forecast to increase by 1.7 million b/d in 2020, but production growth slows to 0.6 million b/d in 2021. Most U.S. liquids production growth is from crude oil, which will grow by 1.1 million b/d in 2020 and by 0.4 million b/d in 2021. EIA expects that crude oil production growth will slow as a result of declining rig counts. However, EIA forecasts that production will continue to grow as a result of rig efficiency and well productivity that is expected to rise during the forecast period.

EIA forecasts that combined liquids production in Norway, Brazil, and Canada will grow, averaging 860,000 b/d in 2020 and 450,000 b/d in 2021. In Norway, Phase 1 of the Johan Sverdrup field came online in October 2019 and EIA forecasts that it will drive most of Norway’s production growth during the forecast period. In Brazil, seven floating production, storage, and offloading vessels (FPSO) came online in 2018 and 2019 and are now producing at maximum or near maximum capacity. FPSOs will continue to be the main driver of growth in Brazil; at least four more are expected online through 2023. EIA expects that Canada’s production growth will accelerate compared with 2019 as the Alberta government’s production curtailments are reduced and more rail takeaway capacity gives producers an outlet for supplies.

U.S. average regular gasoline and diesel prices decline

The U.S. average regular gasoline retail price fell nearly 1 cent from the previous week to $2.57 per gallon on January 13, 32 cents higher than the same time last year. The Rocky Mountain price fell more than 3 cents to $2.61 per gallon, the East Coast price declined 2 cents to $2.52 per gallon, the West Coast price fell nearly 1 cent to $3.20 per gallon, and the Gulf Coast price fell less than 1 cent, remaining at $2.28 per gallon. The Midwest price rose nearly 1 cent to $2.44 per gallon.

The U.S. average diesel fuel price fell nearly 2 cents from the previous week to $3.06 per gallon on January 13, 9 cents higher than a year ago. The Rocky Mountain price fell nearly 4 cents to $3.07 per gallon, the West Coast price fell more than 2 cents to $3.59 per gallon, the Gulf Coast price fell nearly 2 cents to $2.81 per gallon, the Midwest price fell more than 1 cent to $2.97 per gallon, and the East Coast price fell nearly 1 cent to $3.11 per gallon.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 0.9 million barrels last week to 87.9 million barrels as of January 10, 2020, 15.0 million barrels (20.6%) greater than the five-year (2015-19) average inventory levels for this same time of year. Gulf Coast, East Coast, and Midwest inventories decreased by 0.4 million barrels, 0.3 million barrels, and 0.2 million barrels, respectively. Rocky Mountain/West Coast inventories remained unchanged. Propylene non-fuel-use inventories represented 7.0% of total propane/propylene inventories.

Residential heating oil prices decrease, propane prices increase

As of January 13, 2020, residential heating oil prices averaged nearly $3.11 per gallon, 1 cent per gallon below last week’s price and 3 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged more than $2.03 per gallon, almost 14 cents per gallon lower than last week’s price but more than 5 cents per gallon higher than a year ago.

Residential propane prices averaged almost $2.01 per gallon, less than 1 cent per gallon above last week’s price but nearly 42 cents per gallon less than a year ago. Wholesale propane prices averaged $0.64 per gallon, 2 cents per gallon lower than last week’s price and more than 14 cents per gallon below last year’s price.

January, 16 2020