Easwaran Kanason

Co - founder of NrgEdge
Last Updated: June 20, 2020
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Business Trends
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Just a few days ago, Chevron sent a tremor through the LNG industry when it announced that it was putting its stake in Australia’s giant North West Shelf project up for sale, having received ‘unsolicited approaches from a range of credible buyers’. The term to zoom in on is ‘unsolicited’. Meaning that Chevron wasn’t actively considering selling its stake in Australia’s oldest LNG project, but had been cajoled into starting a formal sales process by attractive offers. And that itself says a lot about the state of the LNG industry going forward.

A bit of history. The North West Shelf Project kicked off in the 1980s, then the largest engineering project in the world and remains the largest LNG project in Australia, even after the new wave of Western Australian LNG projects over the last decade. Formed as an equal joint venture between Chevron, Woodside Petroleum, BHP Billiton, BP, Shell and Japan Australia (owned by Mitsubishi Corporation and Mitsui & Co) – each holding a 1/6th stake – the North West Shelf brought together gas producing assets in the huge Carnarvon Basin, tying together fields like Perseus, North Rankin and Goodwyn into total reserves of 33 tcf. It put Australian LNG in the headlines, established the healthy LNG trade relationship between Japan and Australia, and transformed the economy of Western Australia;

Three decades later, the North West Shelf is still Australia’s most prodigious LNG-producing project. But one thing has changed. The natural gas drawn from its fields is drying up, or – to use a more appropriate term – evaporating. There’s still plenty of gas in the Carnarvon Basin, but not enough to power LNG production fully for the foreseeable future. Which is why NWS has started to shift its focus to tolling. In this context, it essentially means that the NWS will sells its liquefaction and associated infrastructure capacity to other gas producers in the region, who will process their natural gas into LNG through NWS before selling it on to their own customers. That would flip the NWS – in its current structure – from having full control over assets and production to being a landlord, renting out its infrastructure for someone else to use.

And there are plenty of ‘someone’s around. BHP and Woodside Petroleum’s Scarborough natural gas development is a perfect example, with Woodside also have its Browse project. These assets are nearby, and tying them to the NWS facilities is considerably more economic than having to build a new liquefaction plant from scratch. Even Chevron has its own assets in the area – the giant Gorgon and Wheatstone LNG project – but due to geography and proximity, has developed these as independent projects with individual facilities. The problem is that the potential third-party assets to be tied into NWS are owned by some of the NWS’ own stakeholders. This would upset the delicate balance between the NWS partners – who designed the structure to be equal and equitable.

With this significant misalignment between Chevron and its partners, it makes sense that Chevron would want to sell out of the project, particularly since the sale could fetch as much as US$4 billion, which is a nice chunk of change to help Chevron weather the current Covid-19 storm. It won’t just be Chevron considering this; BP and Shell will be thinking about this as well, although the Japanese partners are likely to remain to continue siphoning the LNG back home. While the potential suitors have not been named, the most likely candidate is Woodside, who could use its additional clout to convince the remaining NWS partners to agree on feeding Browse gas into NWS, a proposal that it has had difficulties with so far. Key Asian LNG buyers could be potential suitors as well, particularly Korean or Chinese companies that are keen to secure LNG assets for their own growing demand.

This problem won’t be unique to the North West Shelf. It is one that most giant LNG projects that were developed in the 1980s and 1990s must confront soon: with associated natural gas reserves running low, these projects must now look for alternative sources to continue LNG production. For some, circumstances may dictate that decommissioning makes more sense. But for others, like the North West Shelf, the presence of other nearby assets is a double-edged sword: it means that the project can keep running, but will have change its business model to adapt. That means ruffling a few feathers. Chevron might be one of the first to take this step, but it certainly will not be the last.

End of Article

Market Outlook:

  • Crude price trading range: Brent – US$38-42/b, WTI – US$36-39/b
  • Fears of a second wave of Covid-19 infections is crippling any optimism in the market, with infections in the US and Latin America still rising, and China reporting new clusters in Beijing and possibly Shanghai
  • This negated signs that OPEC+’s habitual cheaters had improved on their compliance to the supply deal, with Iraq implementing its quota in full for June and agreeing to compensate for falling short in May; other erring countries should follow suit
  • BP joined ExxonMobil and Chevron is writing down the value of its energy assets, which could the largest in its history at between US$13 – 17.5 billion
  • The WTI discount to Brent has narrowed to US$2/b, but could start to widen as US shale production is recovering quickly and possibly unsustainably; however, the US active rig count continues to languish below 300 sites, down 680 rigs y-o-y

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U.S. oil and natural gas production to fall in 2021, then rise in 2022

U.S. monthly crude oil and natural gas production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)

In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that annual U.S. crude oil production will average 11.1 million b/d in 2021, down 0.2 million b/d from 2020 as result of a decline in drilling activity related to low oil prices. A production decline in 2021 would mark the second consecutive year of production declines. Responses to the COVID-19 pandemic led to supply and demand disruptions. EIA expects crude oil production to increase in 2022 by 0.4 million b/d because of increased drilling as prices remain at or near $50 per barrel (b).

The United States set annual natural gas production records in 2018 and 2019, largely because of increased drilling in shale and tight oil formations. The increase in production led to higher volumes of natural gas in storage and a decrease in natural gas prices. In 2020, marketed natural gas production fell by 2% from 2019 levels amid responses to COVID-19. EIA estimates that annual U.S. marketed natural gas production will decline another 2% to average 95.9 billion cubic feet per day (Bcf/d) in 2021. The fall in production will reverse in 2022, when EIA estimates that natural gas production will rise by 2% to 97.6 Bcf/d.

U.S. monthly crude oil production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)

EIA’s forecast for crude oil production is separated into three regions: the Lower 48 states excluding the Federal Gulf of Mexico (GOM) (81% of 2019 crude oil production), the GOM (15%), and Alaska (4%). EIA expects crude oil production in the U.S. Lower 48 states to decline through the first quarter of 2021 and then increase through the rest of the forecast period. As more new wells come online later in 2021, new well production will exceed the decline in legacy wells, driving the increase in overall crude oil production after the first quarter of 2021.

Associated natural gas production from oil-directed wells in the Permian Basin will fall because of lower West Texas Intermediate crude oil prices and reduced drilling activity in the first quarter of 2021. Natural gas production from dry regions such as Appalachia depends on the Henry Hub price. EIA forecasts the Henry Hub price will increase from $2.00 per million British thermal units (MMBtu) in 2020 to $3.01/MMBtu in 2021 and to $3.27/MMBtu in 2022, which will likely prompt an increase in Appalachia's natural gas production. However, natural gas production in Appalachia may be limited by pipeline constraints in 2021 if the Mountain Valley Pipeline (MVP) is delayed. The MVP is scheduled to enter service in late 2021, delivering natural gas from producing regions in northwestern West Virginia to southern Virginia. Natural gas takeaway capacity in the region is quickly filling up since the Atlantic Coast Pipeline was canceled in mid-2020.

January, 15 2021
So, Why Is Saudi Arabia Doing This?

Just when it seems that the drama of early December, when the nations of the OPEC+ club squabbled over how to implement and ease their collective supply quotas in 2021, would be repeated, a concession came from the most unlikely quarter of all. Saudi Arabia. OPEC’s swing producer and, especially in recent times, vocal judge, announced that it would voluntarily slash 1 million barrels per day of supply. The move took the oil markets by surprise, sending crude prices soaring but was also very unusual in that it was not even necessary at all.

After a day’s extension to the negotiations, the OPEC+ club had actually already agreed on the path forward for their supply deal through the remainder of Q1 2021. The nations of OPEC+ agreed to ease their overall supply quotas by 75,000 b/d in February and 120,000 b/d in March, bringing the total easing over three months to 695,000 b/d after the UAE spearheaded a revised increase of 500,000 b/d for January. The increases are actually very narrow ones; there were no adjustments for quotas for all OPEC+ members with the exception of Russia and Kazakshtan, who will be able to pump 195,000 additional barrels per day between them. That the increases for February and March were not higher or wider is a reflection of reality: despite Covid-19 vaccinations being rolled out globally, a new and more infectious variant of the coronavirus has started spreading across the world. In fact, there may even be at least of these mutations currently spreading, throwing into question the efficacy of vaccines and triggering new lockdowns. The original schedule of the April 2020 supply deal would have seen OPEC+ adding 2 million b/d of production from January 2021 onwards; the new tranches are far more measured and cognisant of the challenging market.

Then Saudi Arabia decides to shock the market by declaring that the Kingdom would slash an additional million barrels of crude supply above its current quota over February and March post-OPEC+ announcement. Which means that while countries such as Russia, the UAE and Nigeria are working to incrementally increase output, Saudi Arabia is actually subsidising those planned increases by making a massive additional voluntary cut. For a member that threw its weight around last year by unleashing taps to trigger a crude price war with Russia and has been emphasising the need for strict compliant by all members before allowing any collective increases to take place, this is uncharacteristic. Saudi Arabia may be OPEC’s swing producer, but it is certainly not that benevolent. Not least because it is expected to record a massive US$79 billion budget deficit for 2020 as low crude prices eat into the Kingdom’s finances.

So, why is Saudi Arabia doing this?

The last time the Saudis did this was in July 2020, when the severity of the Covid-19 pandemic was at devastating levels and crude prices needed some additional propping up. It succeeded. In January 2021, however, global crude prices are already at the US$50/b level and the market had already cheered the resolution of OPEC+’s positions for the next two months. There was no real urgent need to make voluntary cuts, especially since no other OPEC member would suit especially not the UAE with whom there has been a falling out.

The likeliest reason is leadership. Having failed to convince the rest of the OPEC+ gang to avoid any easing of quotas, Saudi Arabia could be wanting to prove its position by providing a measure of supply security at a time of major price sensitivity due to the Covid-19 resurgence. It will also provide some political ammunition for future negotiations when the group meets in March to decide plans for Q2 2021, turning this magnanimous move into an implicit threat. It could also be the case that Saudi Arabia is planning to pair its voluntary cut with field maintenance works, which would be a nice parallel to the usual refinery maintenance season in Asia where crude demand typically falls by 10-20% as units shut for routine inspections.

It could also be a projection of soft power. After isolating Qatar physically and economically since 2017 over accusations of terrorism support and proximity to Iran, four Middle Eastern states – Saudi Arabia, Bahrain, the UAE and Egypt – have agreed to restore and normalise ties with the peninsula. While acknowledging that a ‘trust deficit’ still remained, the accord avoids the awkward workarounds put in place to deal with the boycott and provides for road for cooperation ahead of a change on guard in the White House. Perhaps Qatar is even thinking of re-joining OPEC? As Saudi Arabia flexes its geopolitical muscle, it does need to pick its battles and re-assert its position. Showcasing political leadership as the world’s crude swing producer is as good a way of demonstrating that as any, even if it is planning to claim dues in the future.

It worked. It has successfully changed the market narrative from inter-OPEC+ squabbling to a more stabilised crude market. Saudi Arabia’s patience in prolonging this benevolent role is unknown, but for now, it has achieved what it wanted to achieve: return visibility to the Kingdom as the global oil leader, and having crude oil prices rise by nearly 10%.

Market Outlook:

  • Crude price trading range: Brent – US$55-57/b, WTI – US$51-53/b
  • Global crude oil benchmarks jumped several levels to a new higher range, as Saudi Arabia supplemented OPEC+’s decision to allow a minor increase in supply quotas for February and March with a massive 1 mmb/d voluntary cut over the same period
  • There are signs that the elevated level of crude pricing is tempting American drillers back to work, with Baker Hughes reporting a massive 67-site gain in active rigs over the first week of 2021; this will present another headache for OPEC+ when it comes time to debate the supply deal path forward for April and beyond
January, 14 2021
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

  • This edition of the Short-Term Energy Outlook (STEO) is the first to include forecasts for 2022.
  • The January STEO remains subject to heightened levels of uncertainty because responses to COVID-19 continue to evolve. Reduced economic activity and changes to consumer behavior in response to the COVID-19 pandemic caused energy demand and supply to decline in 2020. The ongoing pandemic and the success of vaccination programs will continue to affect energy use in the future.
  • Economic assumptions are among the most important drivers of the U.S. Energy Information Administration’s (EIA) forecasts. EIA’s U.S. macroeconomic assumptions are based on forecasts by IHS Markit and EIA’s global economic assumptions are based on forecasts from Oxford Economics. After falling by 3.5% in 2020, IHS Markit forecasts that U.S. real gross domestic product (GDP) will increase by 4.2% in 2021 and 3.8% in 2022. Rising GDP contributes to EIA’s forecast of rising total energy use in the United States during 2021 and 2022. After falling by 7.8% in 2020, EIA forecasts that total U.S. energy consumption will rise by 2.6% in 2021 and by 2.5% in 2022, reaching 97.3 quadrillion British thermal units (quads), 3.0 quads less than in 2019.
  • EIA forecasts Brent crude oil spot prices to average $53 per barrel (b) in both 2021 and 2022 compared with an average of $42/b in 2020.
  • EIA estimates that global consumption of petroleum and liquid fuels averaged 92.2 million barrels per day (b/d) for all of 2020, down by 9.0 million b/d from 2019. EIA expects global liquid fuels consumption will grow by 5.6 million b/d in 2021 and 3.3 million b/d in 2022.
  • EIA forecasts crude oil production from the Organization of the Petroleum Exporting Countries (OPEC) will average 27.2 million b/d in 2021, up from an estimated 25.6 million b/d in 2020. Forecast growth in output reflects OPEC’s announced increases to production targets and continuing rise in Libya’s production. On January 5, 2021, OPEC and partner countries (OPEC+) announced that they will maintain the previously agreed-upon January 2021 production increase of 0.5 million b/d. The latest OPEC+ agreement also calls for production increases from Russia and Kazakhstan in February and March. However, additional voluntary cuts by Saudi Arabia for February and March result in lower overall OPEC+ production in early 2021. EIA forecasts that OPEC crude oil production will rise by 1.1 million b/d in 2022.
  • EIA estimates global liquid fuels inventories rose at a rate of 6.5 million b/d in the first half of 2020 before declining at a rate of 2.4 million b/d in the second half of 2020. EIA forecasts global inventories will continue to fall in the forecast, declining at a rate of 0.6 million b/d in 2021 and 0.5 million b/d in 2022.
  • U.S. regular gasoline retail prices averaged $2.18 per gallon (gal) in 2020, compared with an average of $2.60/gal in 2019. EIA forecasts motor gasoline prices to average $2.40/gal in 2021 and $2.42/gal in 2022 U.S. diesel fuel prices averaged $2.55/gal in 2020, compared with $3.06/gal in 2019, and EIA forecasts them to average $2.71/gal in 2021 and $2.74/gal in 2022.
  • EIA estimates that U.S. crude oil production fell from the 2019 record level of 12.2 million b/d to 11.3 million b/d in 2020. EIA expects that annual average production will fall to 11.1 million b/d in 2021 before rising to 11.5 million b/d in 2022.
  • U.S. liquid fuels consumption in 2020 averaged 18.1 million b/d, down 2.5 million b/d (12%) from 2019 consumption. EIA forecasts U.S. liquid fuels consumption will rise to 19.5 million b/d in 2021 and then to 20.5 million b/d in 2022 (almost equal to the 2019 level).
  • Henry Hub natural gas spot prices averaged $2.03 per million British thermal units (MMBtu) in 2020. EIA expects Henry Hub prices will rise to an annual average of $3.01/MMBtu in 2021, limiting natural gas use for power generation amid reduced natural gas production. EIA forecasts Henry Hub prices will rise to an average of $3.27/MMBtu in 2022.
  • U.S. working natural gas in storage ended October at more than 3.9 trillion cubic feet (Tcf), 5% more than the five-year (2015–19) average and the fourth-highest end-of-October level on record. EIA forecasts that declines in U.S. natural gas production this winter compared with last winter will more than offset the declines in natural gas consumption, which will contribute to inventory withdrawals outpacing the five-year average during the remainder of the winter, which ends in March. Forecast natural gas inventories end March 2021 at 1.6 Tcf, 12% lower than the 2016–20 average.
  • EIA estimates that U.S. natural gas consumption averaged 83.1 billion cubic feet per day (Bcf/d) in 2020, down 2.5% from 2019. EIA expects that natural gas consumption will decline by 2.8% in 2021 and by 2.1% in 2022. Most of the decline in natural gas consumption is the result of less natural gas use in the power sector, which EIA forecasts to decline because of rising natural gas prices. These declines are partly offset by rising natural gas use in other sectors.
  • EIA estimates that 2020 dry natural gas production averaged 90.8 Bcf/d, down 2.5% from 2019. EIA expects U.S. dry natural gas production to average 88.2 Bcf/d in 2021, down by 2.8% from 2020, and then rise to 89.7 Bcf/d in 2022.
  • EIA forecasts that total consumption of electricity in the United States will increase by 1.5% in 2021 after falling by 4.0% in 2020. The pandemic significantly affected electricity consumption in the commercial and industrial sectors in 2020. EIA estimates retail sales of electricity to the two sectors fell by 6.0% and 7.9%, respectively. EIA expects commercial electricity use in 2021 to rise by 0.9% and industrial electricity use to rise by 1.2%. Social distancing guidelines have caused people to spend more time at home, resulting in increased residential electricity use. In 2020, retail sales of electricity to the residential sector were 1.3% higher despite a mild winter earlier in the year. EIA expects residential electricity use will rise by 2.4% in 2021 as colder winter weather leads to more heating demand. Total forecast electricity consumption in 2022 will rise by 1.7%.
  • EIA expects the share of U.S. electric power sector generation from natural gas will decline from 39% in 2020 to 36% in 2021 and 34% in 2022 in response to significantly higher natural gas fuel costs and increased generation from renewable energy sources. Coal’s forecast share of electricity generation will rise from 20% in 2020 to 22% in 2021 and 24% in 2022, which is close to its share in 2019. Electricity generation from renewable energy sources will rise from 20% in 2020 to 21% in 2021 and 23% in 2022. The nuclear share of U.S. generation will decline from 21% in 2020 to 20% in 2021 and 19% in 2022.
  • During the next two years, EIA expects electricity generation capacity from renewable energy sources to continue growing. Although EIA expects both wind and solar capacity growth, solar capacity grows at a faster rate in the forecast. Based on EIA survey data, large-scale solar capacity growth in gigawatts (GW) will exceed wind growth for the first time in 2021.
  • EIA estimates that total U.S. coal production decreased by 24% to 537 million short tons (MMst) in 2020. This decline largely reflected lower demand for coal from the electric power sector and the coal export market. Lower natural gas prices made coal less competitive for power generation. In 2021, EIA expects coal production to increase by 12% to 603 MMst because of a forecast 41% increase in natural gas prices for electricity generators, making coal more competitive in the electric power sector. EIA forecasts coal production will rise to 628 MMst in 2022.
  • After declining by 11.1% in 2020, EIA forecasts that total energy-related carbon dioxide (CO2) emissions will increase by 4.7% in 2021 and by 3.2% in 2022. Even with growth over the next two years, forecast CO2 emissions in 2022 remain 3.9% lower than 2019 levels. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.


World liquid fuels production and consumption balance

U.S. natural gas prices


U.S. residential electricity price

January, 14 2021