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U.S. annual renewable generation

Source: U.S. Energy Information Administration, Electric Power Monthly

Renewable generation provided a new record of 742 million megawatthours (MWh) of electricity in 2018, nearly double the 382 million MWh produced in 2008. Renewables provided 17.6% of electricity generation in the United States in 2018.

Nearly 90% of the increase in U.S. renewable electricity between 2008 and 2018 came from wind and solar generation. Wind generation rose from 55 million MWh in 2008 to 275 million MWh in 2018 (6.5% of total electricity generation), exceeded only by conventional hydroelectric at 292 million MWh (6.9% of total generation).

U.S. solar generation has increased from 2 million MWh in 2008 to 96 million MWh in 2018. Solar generation accounted for 2.3% of electricity generation in 2018. Solar generation is generally categorized as small-scale (customer-sited or rooftop) solar installations or utility-scale installations. In 2018, 69% of solar generation, or 67 million MWh, was utility-scale solar.

U.S. annual net generation, wind and solar

Source: U.S. Energy Information Administration, Electric Power Monthly

Increases in U.S. wind and solar generation are driven largely by capacity additions. In 2008, the United States had 25 gigawatts (GW) of wind generating capacity. By the end of 2018, 94 GW of wind generating capacity was operating on the electric grid. Almost all of this capacity is onshore; one offshore wind plant, located on Block Island, off the coast of Rhode Island, has a capacity of 30 megawatts. Similarly, installed solar capacity grew from an estimated less than 1 GW in 2008 to 51 GW in 2018. In 2018, 1.8 GW of this solar capacity was solar thermal, 30 GW was utility-scale solar photovoltaics (PV), and the remaining 20 GW was small-scale solar PV.

Growth in renewable technologies in the United States, particularly in wind and solar, has been driven by federal and state policies and declining costs. Federal policies such as the American Reinvestment and Recovery Act of 2009 and the Production Tax Credit and Investment Tax Credits for wind and solar have spurred project development.

In addition, state-level policies, such as renewable portfolio standards, which require a certain share of electricity to come from renewable sources, have increasing targets over time. As more wind and solar projects have come online, economies of scale have led to more efficient project development and financing mechanisms, which has led to continued cost declines.

Conventional hydroelectric capacity has remained relatively unchanged in the United States, increasing by 2% since 2008. Changes in hydroelectric generation year-over-year typically reflect changes in precipitation and drought conditions. Between 2008 and 2018, annual U.S. hydroelectric generation was as low as 249 million MWh and as high as 319 million MWh, with hydroelectric generation in 2018 totaling 292 million MWh. Generation from other renewable resources, including biomass and geothermal, increased from 70 million MWh to 79 million MWh in the United States between 2008 and 2018, and it collectively represented 1.9% of total generation in 2018.

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Natural gas inventories surpass five-year average for the first time in two years

Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.

Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.

When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.

This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.

In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.

The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.

Lower 48 natural gas inventories, difference to five-year average

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report

The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.

By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.

Lower 48 natural gas inventories and Henry Hub futures prices

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)

October, 21 2019
Your Weekly Update: 14 - 18 October 2019

Market Watch  

Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b

  • Crude oil prices remain stubbornly stuck in their range, despite several key issues that could potentially move the market occurring over the week
  • The sudden thawing of the icy trade relations between the US and China last week – announcing a partial trade deal where new tariffs would be halted – was a positive for the waning health of the global economy; this, however, failed to send prices any higher as previous optimism has always been dashed
  • The trade spat has already caused fears of an economic recession and tumbling global oil demand, with the IEA projecting yet another drop in the demand that has neutralised another possible ‘geopolitical premium’ on prices
  • That geopolitical premium focuses on the fragile situation in the Middle East, with risk spiking up as Iran announced that one of its tankers in the Red Sea – far away from the Persian Gulf - had been struck by missiles; an initial accusation that Saudi Arabia was behind the attack was later withdrawn
  • Meanwhile, news emerged that Nigeria had been quietly handed an increased quota under the OPEC+ supply deal, from 1.685 mmb/d to 1.774 mmb/d, in July, which would help it meet compliance under the deal
  • After more than two months of continuous declines, the US active rig count increased for the first time, but not by much; two oil rigs were added, offset by the loss of a gas rig, but a net gain of 1 to a total of 856
  • We expect prices to remain entrenched as it displays resilience against political and economic factors, with Brent hovering in the US$58-60/b area and WTI at the US$52-54/b range


Headlines of the week

Upstream

  • The US Department of the Interior will be opening up 722,000 acres of federal land along California’s central coast near Fresno, San Benito and Monterey for oil and gas leasing – the first sale in the state since 2013
  • Alongside the lease sale in California, the US will also be opening up some 78 million acres in Gulf of Mexico federal waters for sale in 2020, covering all available unleased areas not subject to Congressional moratorium
  • Santos has confirmed oil flows at the Dorado-3 well in the Bedout Basin offshore Western Australia, with some 11,1000 b/d in place
  • After having exited Norway, ExxonMobil is now reportedly looking into selling its Malaysian offshore upstream assets as part of its divestiture programme, fetching up to US$3 billion for assets including the Tapis Blend operations
  • Equinor has won a new exploration permit – WA-542-P – in the offshore Western Australia Northern Carnarvon Basin, located new the Dorado well
  • Nigeria is looking to settle a US$62 billion income-sharing dispute with international oil firms such as ExxonMobil, Shell, Chevron, Total and Eni operating in the country, with hopes of reaching a settlement
  • Barbados is looking to emulate its nearby neighbour Guyana as it gears up for its third offshore bid round that will launch in early 2020
  • Petroecuador has been forced to declare force majeure on its crude exports, as widespread protests over the removal of fuel subsidies have led to the shutdown of some oilfields
  • Abu Dhabi is looking to create a new benchmark price for Middle Eastern crude based on its Murban grade that could compete with Brent and WTI

Midstream/Downstream

  • Aruba has ended its contract with Citgo – PDVSA’s US refining arm – to operate its 209,000 b/d refinery that is currently idled; a new operator is being sought, paralleling the situation over Curacao’s Isla refinery and PDVSA
  • Poland’s crude pipeline operator expects to only be able to clear its system of contaminated Russian oil from the Druzhba incident by July 2020
  • Gunvor’s Rotterdam refinery will only be able to produce low sulfur fuel oil by March 2020, part of a larger planned overhaul of the 88,000 b/d site

Natural Gas/LNG

  • After Total’s departure, it is now the turn of CNPC to quit the South Pars Phase 11 project in Iran, leaving Iran to go ahead alone its largest natural gas project ever as the threat of US sanctions bites down
  • CNPC has taken over operation of the Chuandongbei sour gas field in China’s Sichuan basin from Chevron, and will kick of Phase 2 development soon
  • Qatar has invited ExxonMobil, Shell, Total, ConocoPhillips and some other ‘big players’ to assist in the North Field expansion that will underpin its ambitions to boost gas output to 110 million tpa from a current 77 million tpa
  • The FID on the Rovuma LNG project in Mozambique has been pushed back by a year, with first production now expected by 2025 at the earliest
  • Pakistan has cancelled a ‘huge’ 10-year tender covering 240 LNG cargoes to its second LNG terminal, turning instead to spot cargoes due to inadequate demand
  • Inpex has formally received a 35-year extension for the PSC covering the Abadi LNG project in Indonesia, extending its operation of the Masela block to 2055
October, 18 2019
Ecuador Exits OPEC

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:

  • Middle East: Iran, Iraq, Kuwait, Saudi Arabia, UAE
  • Africa: Algeria, Angola, Equatorial Guinea, Gabon, Libya, Nigeria, Republic of Congo
  • Latin America: Venezuela
  • Total: 13
  • Withdrawing: Ecuador (January 2020)
  • Membership under consideration: Sudan (October 2015)
October, 18 2019