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Following the rapid growth of U.S. crude oil production since 2010, the U.S. government lifted restrictions on crude oil exports in December 2015. Before the restrictions were lifted, exports were less than 0.5 million barrels per day (b/d), but subsequent U.S. production growth caused price spreads between international (Brent) and domestic (West Texas Intermediate, or WTI) crude oil benchmark prices to widen. WTI averaged $10 per barrel (b) less than Brent from 2011 to 2014. Since the policy change in 2015, U.S. crude oil exports have increased significantly and have averaged more than 3.0 million b/d since 2019, despite narrowing price spreads, significant price drops, reduced demand, and less production since early 2020, when the U.S. market began to react to the COVID-19 pandemic. Weekly export data from our Weekly Petroleum Status Report show a slight growth trend in crude oil exports since June 2021. As of the week of July 9, 2021, U.S. crude oil exports averaged 3.51 million b/d, and Brent and WTI spot prices averaged $76.13/b and $73.35/b, respectively (Figure 1).

Figure 1. Crude oil spot prices and four-week average U.S. crude oil exports

Since 2015, U.S. crude oil export infrastructure, including pipelines and terminals, has expanded rapidly in the Texas Gulf Coast, particularly at the ports in Corpus Christi and Houston. As a result of this infrastructure expansion and a significant increase in domestic production, crude oil exports grew rapidly when benchmark prices remained above $50/b in 2018 and 2019, and they declined only moderately when the market dropped sharply in 2020. Between March 20 and June 19, 2020, four-week average U.S. crude oil exports declined about 31% and refinery inputs declined 13%. Crude oil exports declined more than refinery inputs in the same time period. In early 2021, both Brent and WTI prices increased to 2019 levels, and the price spread between Brent and WTI had narrowed to less than $2/b as of June 25 from about $8/b at the end of 2019. Four-week average crude oil exports had increased to 3.5 million b/d during the same period. In addition, WTI prices higher than $70 will contribute to an increase in U.S. crude oil production, which in turn will likely contribute to growth in U.S. crude oil exports.

The growth in U.S. crude oil exports in the first half of 2021 has been predominantly sourced from oil produced in the Permian, Eagle Ford, and Bakken regions, but crude oil exports also increasingly contain Federal Offshore Gulf of Mexico crude oils such as Mars and Southern Green Canyon, based on export data from ClipperData (Figure 2). Because the Permian and Eagle Ford regions are close to the Texas Gulf Coast, crude oil produced in these regions is usually exported from the Gulf Coast region (PADD 3). Prior to pipeline networks expanding to connect to the shale regions in North Dakota and Texas, rail transportation was an important means of delivering crude oil, mainly from the Bakken region in the Midwest (PADD 2), to refineries and crude oil export terminals.

Figure 2. U.S. monthly crude oil exports by select production regions

Pipeline development continues to play an important role in the growth of U.S. crude oil exports. Historically, U.S. refiners imported crude oil to the Gulf Coast by marine vessels and then transported some of the imported crude oil to the Midwest through pipeline systems such as Seaway and Capline, which flowed north from the Gulf Coast to the Midwest.

With rapidly increasing crude oil production, the demand to move imported crude oil from the Gulf Coast to the Midwest declined. As a result, the volume of crude oil moving through the Seaway pipeline dropped, and the pipeline was reversed in June 2012 to flow south and transport growing domestic crude oil production from the Bakken to the Gulf Coast. The Houma-to-Houston (Ho-Ho) pipeline, renamed the Zydeco Oil Pipeline in 2014, was also reversed in December 2013 to transport crude oil from the Texas Gulf Coast to Louisiana Gulf Coast primarily for refinery processing.

Such structural changes diminished the flow of crude oil from the Gulf Coast to the Midwest and contributed to the rapid increase of crude oil exports (Figure 3). Most U.S. crude oil exports leave the country from Texas ports, but some leave from Louisiana ports. Based on estimates from ClipperData, crude oil exports from Texas have been as high as 1.9 million b/d at Corpus Christi in June 2021 and 0.9 million b/d at Houston in May 2019. In Louisiana, they have also been as high as 0.4 million b/d at Morgan City in April 2021 and 0.3 million barrels at Baton Rouge in July 2018.

Figure 3. Monthly crude oil pipeline movements

Crude oil exports could further expand as more infrastructure is modified. Recently, Marathon Pipeline (MPLX) announced Capline’s reversal proposal. The total Capline pipeline capacity of more than 1 million b/d from the Louisiana Gulf Coast to the Midwest has been idled for several years as domestic crude oil and crude oil from Canada displaced imported light crude oil. In the proposal, light crude oil produced in Bakken and heavy crude oil from Canada will be transported from Patoka, Illinois, to St. James, Louisiana, via the reversed Capline pipeline. The initial reversal project planned for light domestic oil to be transported from Cushing, Oklahoma, to Memphis, Tennessee, via the existing Diamond pipeline through an extension and a newly constructed connection to Capline (Byhalia Connection). The pipeline would then travel from Memphis, Tennessee, to St. James, Louisiana, via the reversed Capline (Figure 4). On July 2, 2021, however, project developers Plains All American and Valero announced they were canceling the Byhalia Connection project, which our pipeline database had expected to be in operation by the first quarter of 2022.

Figure 4. Expected change in Capline pipeline flows

The Memphis Valero refinery owns an existing pipeline, the Collierville pipeline (not illustrated in Figure 4), connecting the refinery at Memphis and a terminal of Capline pipeline in Collierville, Tennessee. The Byhalia connection was proposed as an expansion of the Collierville pipeline. Because the Byhalia project was canceled, the future of the idling Collierville pipeline is uncertain. However, the pipeline could be an option to bridge not only the Memphis Valero refinery with Capline to source Canada’s and the Bakken’s crude oil but also allow WTI crude oil to flow to the Gulf Coast on the Capline pipeline.

Nonetheless, if Capline is fully reversed, it could transport light crude oil from the Bakken region and Canada to Louisiana for refinery processing and exports. In addition to increasing U.S. export capacity, such a reversal may continue to contribute to significant changes in the U.S. petroleum industry, particularly in heavy oil imports from Canada to the Gulf Coast, refinery inputs in the Gulf Coast and Midwest, and crude oil exports from the Gulf Coast.

U.S. average regular gasoline and diesel prices increase

The U.S. average regular gasoline retail price increased more than 1 cent to $3.13 per gallon on July 12, 94 cents higher than the same time last year. The Rocky Mountain price increased more than 5 cents to $3.49 per gallon, the Gulf Coast price increased 3 cents to $2.83 per gallon, the West Coast price increased nearly 3 cents to $3.87 per gallon, and the East Coast price increased nearly 1 cent, remaining virtually unchanged at $3.01 per gallon. The Midwest price decreased less than 1 cent to $3.02 per gallon.

The U.S. average diesel fuel price increased less than 1 cent to $3.34 per gallon on July 12, 90 cents higher than a year ago. The Rocky Mountain price increased nearly 8 cents to $3.59 per gallon, the West Coast price increased nearly 1 cent to $3.91 per gallon, and the Gulf Coast and East Coast prices each increased nearly 1 cent, remaining virtually unchanged at $3.08 per gallon and $3.31 per gallon, respectively. The Midwest price decreased less than 1 cent, remaining virtually unchanged at $3.26 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 1.6 million barrels last week to 59.6 million barrels as of July 9, 2021, 13.1 million barrels (18.0%) less than the five-year (2016-2020) average inventory levels for this same time of year. Midwest, East Coast, and Gulf Coast inventories increased by 0.7 million barrels, 0.6 million barrels, and 0.3 million barrels, respectively. Rocky Mountain/West Coast inventories decreased slightly, remaining virtually unchanged.

Brent crude oil exports imports pipelines WTI West Texas Intermediate EIA
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The Race To Cut Carbon Emissions: China, the EU and the US

Two very different economic blocs. Two pathways to a carbon-free future, one younger and one more mature. And one more with plenty of ambition but hamstrung by inaction. Between China, the EU and the US, three of the most powerful economies in the world all agree that pursuing a carbon neutral future is necessary if the planet is to limit global warming levels to 1.5 degrees Celsius above preindustrial levels, as committed under the Paris Climate Agreement. But the question of how to get there is the tricky one. In the past two weeks, both China and the EU have unveiled their own sweeping plans meant to limit greenhouse gas emissions, both incredibly ambitious in their own right but both also facing headwinds.

Let’s start with China. In Shanghai, the Shanghai Environment and Energy Exchange launched the country’s national emissions trading system on July 16. Currently focused on its own companies, the Chinese emissions trading system is already the world’s largest carbon market from the first day of operations. Covering an initial 2225 power plants that are estimated to emit more than 4 billion tonnes per annum of carbon dioxide, that amount already exceeds the European Union’s scheme, which covers about 2 billion tpa of emissions according to the International Emissions Trading Association. And there is still plenty of room to grow.

China decided to kick off its carbon trading platform with a focus only on power companies, given that they are among the most polluting of industries contributing to roughly 40% of China’s annual carbon emissions and roughly 14% of global carbon emissions from fossil fuel combustion according to the IEA. This initial phase allows the domestic participating companies to cover their own emissions by purchasing surplus allowance from those that have been able to cut their emissions through the exchange. Within the first week, Chinese energy giant Sinopec already closed a huge bulk deal by buying a 100,000 tonnes of carbon emission quota through its subsidiary Unipec. In the first day alone, a total of 4.1 million tonnes were traded, with the price rising from the opening CNY48 (US$7.41) to CNY51.23 (US$7.89), reflecting strong demand as the Chinese state aims to reach peak carbon emissions by 2030 and carbon neutrality by 2060. While the current price is still well under the €50 ($58.87) per tonnes under the EU emissions trading scheme, it is a bold step forward that can only grow.

In time, China intends to add other sectors such as iron and steel, cement, aluminium, paper, domestic aviation, building materials, and petrochemicals to future phases of the trading scheme. In addition, the first phase of the Chinese ETS is only limited to spot transactions by domestic players, but over-the-counter transactions and foreign/individual investors are expected to be added eventually one the exchange matures. Stricter carbon caps by industry may also be added, although the timing and scope have yet to be determined; China’s scheme is based on carbon intensity, rather than the EU’s absolute cap on emissions, which means that total emissions can still rise as power generation grows. For now, the price paid per on will be passed on to consumers, which promotes efficiency and incentivises emissions-cutting by giving a cost advantage to companies that are able to slash their carbon faster than required.

It’s a good start, even though it is unlikely to result in an acceleration of emissions reduction soon, given that there is not enough surplus renewables capacity to match the emissions of carbon-intensive industries. Which means that China will need to continue on its mammoth rollout of solar, wind and nuclear energy over the next decade to truly make a difference.

If China is just starting out with a framework that will service it for the next half century, then the EU is racing ahead to beat its own previous targets. The EU Commission has unveiled a new – dubbed the European Green Deal – that intends to achieve and exceed its commitments under the Paris Agreement, which bound the bloc to cutting greenhouse gas emissions by 55% in 2030 from 1990 levels and achieve net-zero emissions by 2050. The adoption of this target has already had ramifications across the continent, with almost all major energy companies adopting carbon neutral targets along the same timeline. And in some cases, even further, with the recent court judgement in the Netherlands that Royal Dutch Shell must accelerate its emissions-slashing plans globally from its already ambitious plan.

The new EU proposal aims to cut reliance on fossil even further and promote renewables. Central to this is a requirement that the share of renewable energy sources as part of Europe’s mix must rise to 40% from 20%, while limiting pollution from fossils fuels from key sectors like power, transportation, shipping, agriculture and housing – resulting in a 61% fall from 2005 levels by 2030, compared to the current target of 43%. Controversially, the EU proposal also deals with the idea of ‘imported pollution’ – carbon leakage that is caused by shifting production to countries with loose or no emissions rules by imposing a carbon import tax that will begin in 2023 for full implementation in 2026. This would ensure domestic competitiveness within the EU while incentivising trading partners that do adopt carbon plans by allowing the carbon price (as determined through China’s emissions trading system, for example) to be deducted from the carbon cost bill when entering the EU. It is a plan that has already sent shudders through global supply chains, triggering accusations of bias by developing countries. But there is also dissent for the plan in Europe itself. Emmanuel Macron’s government in France, one of the main pillars of the EU, is reportedly already lobbying to watering down the proposal to create a new carbon market for domestic heating and road transport, and phasing out all combustion engine cars by 2035. Other countries, including the Netherlands and Hungary, are also worried about the social impact, since the plan would drive up costs for average citizens. The EU Commission claims the increase in costs will not be too much, on the assumption that revenues generated from the new carbon market will be channelled to subsidise fuel bills of low- and middle-income households. 

Between China and the EU, bold moves have been made to progress on a carbon neutral future. But there is one major player that has plenty of ambition as well, but is unable to proceed with similar bold steps due to politics. Since taken over the White House in January, US President Joe Biden has made renewables a focus of his administration – announcing initiatives to scale back on fossil fuels and move to 100% carbon-free electricity by 2035. But his ability to push further – by, say, creating a national renewable standard or fund renewable infrastructure is hampered by Republican obstruction and state pushback. The likelihood that the Republicans may increase their power in the next mid-term elections also pours water on the idea that Biden’s big ideas can take shape eventually. But where the American government can’t step up, private investors can step in: witness the recent shareholder revolts at Chevron and ExxonMobil. The march towards carbon neutrality will be tortuous and long, but at least there is some progress happening now to ease the difficult path the world must take in the future.

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Market Outlook:

  • Crude price trading range: Brent – US$74-76/b, WTI – US$73-75/b
  • Despite continued worries over the Covid-19 delta variant, global crude prices continued to push higher after faltering mid-month; increases in consumption in the US and China is underpinning this, but that demand recovery is uneven globally
  • Active rigs in the US continue to gain at 491, just shy of the 500 site mark; while this illustrates the recovery in the US shale patch, this is still a major reduction from the active site count the last time WTI prices were this high, illustrating the new restrained and disciplined approach taken by the onshore industry there

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July, 30 2021
Renewables became the second-most prevalent U.S. electricity source in 2020

In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.

In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.

Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.

We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.

monthly U.S electricity generation from all sectors, selected sources

Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.

July, 29 2021
PRODUCTION DATA ANALYSIS AND NODAL ANALYSIS

Kindly join this webinar on production data and nodal analysis on the 4yh of August 2021 via the link below

https://www.linkedin.com/events/productiondataanalysis-nodalana6810976295401467904/

July, 28 2021