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Last Updated: May 20, 2017
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One of the biggest conundrums of the OPEC / NOPEC production cut from a ClipperData perspective is that no sooner does a producer appear to be showing compliance via lower exports, lo and behold, volumes rebound.

Some producers have been fairly consistent in their discipline, barring a few blips (bravo, Saudi), while others stand on the sidelines, looking in the other direction (here’s looking at you, Iraq).

But the overarching theme is that a combination of reckless abandon at the end of last year (in terms of higher exports) and the lack of a unified effort to cut crude hitting the global market this year has meant OPEC still remains a country mile away from achieving its goal of lowering global inventories. Hark, a couple of insights on the matter:

Last month we highlighted how UAE was finally exhibiting signs of compliance. ADNOC gave a heads-up earlier in the year that scheduled maintenance would be undertaken for its Murban grade in March, and for Das in April, reducing production and exports of both.

True to its word, we saw Murban exports drop in March to the lowest level since at least 2012, while Das export loadings in April dropped to an 8-month low. There’s the rub, however. Exports of Murban rebounded in April, and are even higher in May thus far. As for Das, it too is rebounding after ebbing last month:

Das%20and%20Murban%20May%202017.jpg?resize=625%2C435 625w, 938w, 1250w, 1563w, 1875w" alt="Das and Murban May 2017.jpg" width="625" height="435">

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As OPEC put the pedal to the metal at the end of last year, pushing out as much crude onto the global market as it could before th

As OPEC put the pedal to the metal at the end of last year, pushing out as much crude onto the global market as it could before the production cut deadline, flows of OPEC crude into the U.S. in January reached their highest level since the summer of 2013 (when domestic production was only 7.5 million barrels per day!!).

Despite expectations for lower flows in the months following, we have seen OPEC exports to the U.S. averaging nearly 3.4mn bpd for February, March and April – which is 9 percent above year-ago levels, and up 28 percent versus 2015. Imports so far in May are holding up, currently at 3.4mn bpd, just a smidge below year-ago levels.

But with the latest OPEC meeting fast approaching, Saudi Arabia cut its exports last month to the lowest level since late 2015. This means less crude will be arriving in the U.S. from the OPEC kingpin into June.

OPEC%20to%20US%20May%202017%20ClipperData.jpg?resize=613%2C458 613w, 920w, 1226w, 1533w, 1839w" alt="OPEC to US May 2017 ClipperData.jpg" width="613" height="458">

Finally, Libya and Nigeria are another layer to the onion of OPEC production cut complexity. Libyan production has been estimated above 800,000 bpd in recent weeks, although it is currently experiencing supply hiccups. Given low domestic consumption, this rise in output is working its way into higher exports fairly swiftly, up to 550,000 bpd this month.

As for Nigeria, exports this month are at their quickest pace so far this year. Exports were already strong, but are further being bolstered by the first loading of Forcados at its SBM since November, as the Trans Forcados export pipeline gets up and running again: over a million barrels were loaded there on Wednesday.

Nigeria%20Libya%20exports%20May%202017.jpg?resize=601%2C463 601w, 902w, 1202w, 1503w, 1803w" alt="Nigeria Libya exports May 2017.jpg" width="601" height="463">

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Fossil fuels continue to account for the largest share of U.S. energy

Fossil fuels continue to account for the largest share of energy consumption in the United States. In 2018, about 79% of domestic energy production was from fossil fuels, and 80% of domestic energy consumption originated from fossil fuels.

The U.S. Energy Information Administration (EIA) publishes the U.S. total energy flow diagram to visualize U.S. energy from primary energy supply (production, imports, and stock withdrawals) to disposition (consumption and exports). In this diagram, losses that take place when energy is converted to the secondary forms that are delivered to customers—primarily electricity and gasoline—are allocated to those customers. The result is a visualization that associates the primary energy with customers, even though the amount of energy they purchase is much less.

U.S. energy production by source

Source: U.S. Energy Information Administration, Monthly Energy Review
Note: Natural gas plant liquids (NGPL) denoted at top of left panel in brown.

The share of U.S. total energy production from fossil fuels peaked in 1966 at 93%. Total fossil fuel production has continued to rise, but so have non-fossil fuel sources, mainly renewables like wind and solar energy. As a result, fossil fuels have accounted for close to 80% of U.S. energy production over the past decade. Since 2008, production of crude oil, dry natural gas, and natural gas plant liquids (NGPL) has increased by 12 quadrillion British thermal units (quads), 11 quads, and 3 quads, respectively. These increases have more than offset decreasing coal production, which has fallen 9 quads since its peak in 2008.

U.S. primary energy overview and net imports share of consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum has the largest share of U.S. energy trade, accounting for 67% of energy exports and 86% of energy imports in 2018. Much of the imported crude oil goes to U.S. refineries and is then exported as petroleum products. Petroleum products accounted for 71% of total U.S. energy exports in 2018.

In 2018, net energy imports reached the lowest level since 1963. U.S. net energy imports as a share of consumption peaked in 2005 when it reached 30%; in 2018, energy net imports fell to only 4% of consumption.

U.S. energy consumption by source and primary energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy consumption that originated from fossil fuels has fallen from its peak of 94% in 1966 to 80% in 2018. The total amount of fossil fuels consumed in the United States has also fallen from its peak of 86 quads in 2007. Since then, coal consumption decreased by 10 quads and petroleum by 2 quads, more than offsetting a 7 quad increase in natural gas consumption.

EIA previously published articles detailing the energy flows of petroleum, natural gas, coal, and electricity. More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

September, 19 2019
Russia Is Heating Up The Arctic

After a year of securing deals, finalising details and even projecting way beyond the current, Novatek’s Arctic LNG 2 was been given its Final Investment Decision (FID), paving its way for a 2023 start. Led by Russia’s largest independent gas producer, the 19.8 million ton per annum project is also joined by Total, CNPC, CNOOC and the Japan Arctic LNG consortium (consisting of Mitsui & Co and JOGMEC).

The make-up of the project stakeholders is telling. There is Novatek, which aims to catch up with Gazprom as Russia’s largest gas player. Then there is Total, whose savvy deals have propelled it to become the second largest private gas player (behind Shell) through a diversified portfolio. Japan – currently the world’s largest LNG importer – is well represented, while the fast-growing demand market of China is in there as well. Each of the minority players owns a 10% stake but Total also has a 19.4% stake in Novatek, bringing its total economic interest to 21.6%.

The geography of the project is interesting as well. Centred on the Trekhbugornly and Gydanskiy fields, the terminal at Utrenniy and a large-scale liquefaction plant in the remote Gydan Peninsula, passage from this part of Russia’s Arctic is difficult. Which is why Novatek is also partnering with Sovcomflot to build a fleet of 17 icebreaker-class LNG carriers to ferry the super-chilled liquid through the Arctic to Northeast Asia. That’s the Northern Sea Route, the closest direct route to Asia available and it might even get easier. Climate patterns have shifted the Arctic’s ice floes, with new shipping channels opening up from thawing ice in the summer. The journey rivals delivery times from Qatar to Tokyo, or Australia to Shanghai – which explains the high interest from Japanese and Chinese parties. For Total, which has a global presence, Arctic LNG 2 will also be able to deliver cargoes to Europe via transhipment terminals in the Murmansk region.

It also explains why Novatek is already thinking beyond this. Arctic LNG 2 will consist of 3 phases. Train 1 is scheduled for 2023, while Train 2 and Train 3 planned for 2024 and 2026. But Novatek has already made overtures to expand its assets in the Gydan – part of West Siberia’s Yamal-Nenets region. Novatek’s ambitions call for up to 140 mtpa of LNG production in Gydan and Yamal, from its current 16.5 mtpa Yamal LNG and the 19.8 mtpa Arctic LNG 2, though Gazprom has pushed back on Novatek’s lobbying of the Russian government on the issue. However, plans have already been made for at least one more LNG project – oddly titled Arctic LNG 1 – that would focus on the Soletsko-Khanaveyskoye field in the Kara Sea, which has an estimated 2.18 bcm of gas in place.

The net result of this is that Russia will become a more diversified gas player. Besides the Sakhalin II and Yamal LNG projects, Russia primarily sells its gas by pipeline to Europe. But with resistance there increasing – see the furore over the Nord Stream 2 pipeline – Russia needs more options. Geography and weather have always presented challenges to export Siberian gas to Asia and the rest of the world, but Arctic LNG 2 offers a very promising glimpse of a possibly profitable future.

Arctic LNG 2:

  • Stakeholders: Novatek (60%), Total (10%), CNPC (10%), CNOOC (10%), Japan Arctic LNG (10%)
  • Capacity: 19.8 million tons per annum through 3 Trains
  • Location: Gydan Peninsula, West Siberia
September, 18 2019
Natural gas and wind forecast to be fastest growing sources of U.S. electricity generation

In its latest Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that natural gas-fired electricity generation in the United States will increase by 6% in 2019 and by 2% in 2020. EIA also forecasts that generation from wind power will increase by 6% in 2019 and by 14% in 2020. These trends vary widely among the regions of the country; growth in natural gas generation is highest in the mid-Atlantic region and growth in wind generation is highest in Texas. EIA expects coal-fired electricity generation to decline nationwide, falling by 15% in 2019 and by 9% in 2020.

The trends in projected generation reflect changes in the mix of generating capacity. In the mid-Atlantic region, which is mostly in the PJM Interconnection transmission area, the electricity industry has added more than 12 gigawatts (GW) of new natural gas-fired generating capacity since the beginning of 2018, an increase of 17%.

This new natural gas capacity in PJM has replaced some coal-fired generating capacity—6 GW of coal-fired generation capacity has been retired in that region since the beginning of 2018. The Oyster Creek nuclear power plant in New Jersey was also retired in 2018, and the Three Mile Island plant in Pennsylvania plans to shut down its last remaining reactor this month.

These changes in capacity contribute to EIA’s forecast that natural gas will fuel 39% of electricity generation in the PJM region in 2020, up from a share of 31% in 2018. In contrast, coal is expected to generate 20% of PJM electricity next year, down from 28% in 2018. In 2010, coal fueled 54% of the region’s electricity generation, and natural gas generated 11%.

PJM annual electric power sector generation

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

Wind power has been the fastest-growing source of electricity in recent years in the Electric Reliability Council of Texas (ERCOT) region that serves most of Texas. Since the beginning of 2018, the industry has added 3 GW of wind generating capacity and plans to add another 7 GW before the end of 2020. These additions would result in an increase of nearly 50% from the 2017 wind capacity level in ERCOT. EIA expects wind to supply 20% of ERCOT total generation in 2019 and 24% in 2020. If realized, wind would match coal’s share of ERCOT's electricity generation this year and exceed it in 2020.

ERCOT annual electric power sector generation

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

Natural gas-fired generation in ERCOT has fluctuated in recent years in response to changes in the cost of the fuel. EIA forecasts the Henry Hub natural gas price will fall by 21% in 2019, which contributes to EIA’s expectation that ERCOT’s natural gas generation share will rise from 45% in 2018 to 47% this year. Although EIA forecasts next year’s natural gas prices to remain relatively flat in 2020, the large increase in renewable generating capacity is expected to reduce the region’s 2020 natural gas generation share to 41%.

September, 18 2019