NrgEdge Editor

Sharing content and articles for users
Last Updated: March 21, 2019
1 view
Business Trends
image

The United States exported 2 million barrels per day of crude oil in 2018 to 42 different destinations

In 2018, U.S. exports of crude oil continued to increase to 2.0 million barrels per day (b/d), up 846,000 b/d (73%) from 2017 (Figure 1). The number of destinations for U.S. crude oil exports also increased from 37 to 42. Volumes by destination changed significantly between the first and second halves of 2018.

Figure 1. U.S. crude oil exports (1920 - 2018)

The increase in U.S. crude oil exports was the result of increasing U.S. crude oil production and infrastructure changes. U.S. crude oil production increased 1.6 million b/d from 2017 to 10.9 million b/d in 2018, with the U.S. Gulf Coast—where more than 90% of U.S. crude oil exports depart from—producing 7.1 million b/d. The increased production is mostly of light, sweet crude oils, but U.S. Gulf Coast refineries are configured mostly to process heavy, sour crude oils. This increasing production and mismatch between crude oil type and refinery configuration causes more of the increasing U.S. crude oil production to be exported.

In early 2018, modifications were made at the Louisiana Offshore Oil Port (LOOP) in the Gulf of Mexico to enable the loading of vessels for crude oil exports. LOOP is currently the only U.S. facility capable of accommodating fully loaded Very Large Crude Carriers (VLCC), vessels capable of carrying approximately 2 million barrels of crude oil. After LOOP was modified to also allow exports, the increase in cargo scale led U.S. crude oil exports to surpass 2 million b/d for 25 weeks in 2018 compared with just 1 week in 2017. In addition to LOOP, other U.S Gulf Coast export facilities in and around Houston and Corpus Christi, Texas, have been investing in increasing the scale of U.S. crude oil export cargos.

In 2018, Asia was the largest regional destination for U.S. crude oil exports, followed by Europe, and, as in previous years, Canada was the largest single destination for U.S. crude oil exports. Canada received 378,000 b/d of U.S. crude oil exports, representing 19% of total U.S. crude oil exports in 2018. South Korea surpassed China to become the second-largest single destination for U.S. crude oil exports in 2018, receiving 236,000 b/d compared with China’s 228,000 b/d (Figure 2).

Figure 2. 2018 U.S. crude oil export destinations

However, the distribution of U.S. crude oil exports by destination varied significantly from the first half of 2018 to the second half. In the first half of 2018, the United States exported 376,000 b/d of crude oil to China, which made China the largest single destination for U.S. crude oil exports for that period. However, in August, September, and October of 2018, the United States exported no crude oil to China, and then in November and December it exported significantly less than in earlier months. In the second half of 2018, the United States exported 83,000 b/d of crude oil to China, a decrease of 294,000 b/d from the first half (Figure 3).

Figure 3. U.S. crude oil exports by destination (1H 2018 vs. 2H 2018)

In the summer of 2018, as part of ongoing trade negotiations between the United States and China, China temporarily included U.S. crude oil on a list of goods potentially subject to an increase in import tariffs. At the same time, the difference between the international crude oil benchmark Brent and the U.S. domestic price West Texas Intermediate (WTI) futures prices narrowed rapidly between June and July 2018. Brent prices went from $9 per barrel (b) higher than WTI in June to $6/b higher than WTI in July. The rapidly narrowing price discount of U.S. crude oils versus international crude oils and the potential for higher import tariffs caused Chinese buying of U.S. crude oil to slow.

Although U.S. crude oil exports to China slowed in the second half of 2018, exports to South Korea, Taiwan, Canada, and India increased significantly. U.S. crude oil exports to South Korea increased 247,000 b/d (222%) between the first and second half of 2018. U.S. crude oil exports to other destinations in Asia also increased, particularly to Taiwan, which rose 111,000 b/d (168%) in the second half of 2018 compared with the first half, and to India, which increased 86,000 b/d (97%) during the same period.

Despite the volume changes in U.S. crude oil destination between the first and second halves of 2018, the list of destinations has remained consistent over the past three years. Of the 27 destinations that took U.S. crude oil in 2016, the first year of unrestricted U.S. crude oil exports, 22 destinations did so again in 2017 and again in 2018 (Figure 4). Furthermore, few destinations appear to be one-time recipients of U.S. crude oil, other than those such as the Marshall Islands that were listed because of data collection methods and ship-to-ship transfers.

Figure 4. U.S. crude oil export destinations

U.S. average regular gasoline price increases, diesel price falls

The U.S. average regular gasoline retail price rose nearly 8 cents from the previous week to $2.55 per gallon on March 18, down 5 cents from the same time last year. The East Coast price rose nearly 9 cents to $2.52 per gallon, the Gulf Coast price rose over 8 cents to $2.30 per gallon, the Midwest price rose nearly 8 cents to $2.48 per gallon, the Rocky Mountain price rose nearly 7 cents to $2.32 per gallon, and the West Coast price rose nearly 5 cents to $3.03 per gallon.

The U.S. average diesel fuel price fell nearly 1 cent to $3.07 per gallon on March 18, nearly 10 cents higher than a year ago. The Midwest price fell nearly 2 cents to $2.99 per gallon, the Gulf Coast price fell over 1 cent to $2.87 per gallon, and the West Coast price fell nearly 1 cent to $3.50 per gallon. The Rocky Mountain price increased nearly 1 cent, remaining at $2.94 per gallon, and the East Coast price rose less than 1 cent, remaining at $3.12 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 1.0 million barrels last week to 51.1 million barrels as of March 15, 2019, 6.3 million barrels (14.0%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories increased by 1.2 million barrels, 0.4 million barrels, and 0.1 million barrels, respectively, while Midwest inventories decreased by 0.7 million barrels. Propylene non-fuel-use inventories represented 12.1% of total propane/propylene inventories.

Residential heating fuel prices decrease

As of March 18, 2019, residential heating oil prices averaged nearly $3.22 per gallon, 1 cent per gallon below last week’s price but 16 cents per gallon above last year’s price at this time. Wholesale heating oil prices averaged $2.09 per gallon, nearly 4 cents per gallon less than last week’s price but 8 cents per gallon more than a year ago.

Residential propane prices averaged $2.41 per gallon, less than 1 cent per gallon lower than last week’s price and almost 8 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.84 per gallon, less than 1 cent per gallon above last week’s price but 3 cents per gallon below last year’s price.

crude oil Gulf Coast international PADD 3 refining
3
1 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

What Stays, What Goes

It was a headline that definitely opened eyes and definitely perked up ears. News that supermajor Shell was in the process of reviewing its holdings in the largest US oil field – the onshore Permian basin – came as a shock. On one hand, why was Shell looking to sell off its assets in the prized US shale patch only months after naming it one of its nine ‘core’ upstream areas? On the other hand, the prospect of taking over Shell’s sizable acreage in the Permian has set its competitors operating in the same shale patch sniffing around for opportunities.

The answer to the former has been most influenced by a recent judgement at a court in The Hague, where Royal Dutch Shell is headquartered. The court ruled that Shell’s carbon plans – which calls for a reduction of greenhouse gas emissions to net zero by 2050 and an absolute 20% reduction by 2030 – was insufficient and not in line with the climate change goals of the Paris Agreement. Instead, the court ordered that Shell must reduce its emissions by 45% from 2019 levels by 2030, siding with environmental NGO Friends of the Earth which brought on the case by claiming that Shell was violating human rights with its current plan. Crucially, and unusually, the court applied the verdict to Shell’s entire global operations, spanning multiple jurisdictions, rather than limited to just Dutch holdings. Shell has announced plans to appeal, which could drag the process on for years in higher courts. But on the off-chance that this judgement remains binding, it is perhaps looking for ways to shave off carbon-intensive assets.

Why else would chatter suddenly surface that Shell was considering selling off its collection of prime Permian acreage located in the prolific Delaware basin? After all, just a few months ago in February, Shell announced that it was planning to reshape its upstream business to focus on nine core areas that generated 80% of its revenue – Brazil, Brunei, the Gulf of Mexico, Kazakhstan, Malaysia, Nigeria, Oman, the UK North Sea and, of course, the Permian Basin in the US. Although Shell is not among the largest Permian players, its 260,000 acres are still sizable and its output of some 60,000 b/d ranks Shell among the Permian’s 20 largest producers. Valuations suggest that the sale could fetch as much as US$10 billion, which is a lot of cash that Shell could redirect to clean energy initiatives if the aim is to conform to the court order. Because Shell is not exactly in fire-sale mode; its asset divestment program to hive off non-core assets to pay for its US$53 billion acquisition of BG Group in 2015 was already complete.

To be fair, for all the activity in the Permian, sustained profitability has proven elusive. Not just to Shell, but other major players there as well. The rapid drop-off in well productivity after the first two years means that players have to be constantly drilling and discovering, while a large-scale traditional crude oil field could last for decades after initial production. Shell is also not the only one to consider shedding assets; Chevron and ExxonMobil are also rumoured to be considering divestment as well. And why not? With crude prices at their highest point since late 2018, it is a good time to fetch the best price for oil assets. Most Permian deals in 2021 have closed at between US$7,000 and US$12,000 per acre – already a major increase from 2020 and 2019 – but Shell’s prime 260,000 acres acquired from Chesapeake Energy and Anadarko in 2012 would fetch a major premium, possibly almost as high as US$40,000/acre that would be in line with Pioneer Natural Resources’ acquisition of DoublePoint Energy in April 2021. Any sale would definitely exceed Shell’s initial investment of US$1.9 billion, fetching a tidy profit. Of course, the move would also shrink Shell’s US footprint, limiting it to the Gulf of Mexico (where the Whale field FID is expected soon) and a single oil refinery (Norco), after selling its stake in the Deer Park refining site to Pemex from an unsolicited bid.

If the sale goes through – and it is still a big if at this point – then Shell’s loss will be someone else’s gain. Who would that be? Potential bidders include ConocoPhillips, Devon Energy, Chevron, EOG Resources or even private equity firms that have not been scared off by the potential debt burden of Permian assets. Shell is likely to be looking for an all-cash deal for the entirely of the asset, but is reportedly open to also parcelling up the land into multiple packages. According to sources, a data room with full information on the assets has already been opened.

Looking at the location of Shell’s Permian assets, synergies exist with ConocoPhiliips and Chevron, which both own acreage close to the Shell holdings. Other potential buyers that operate in the Delaware region of the Permian include Occidental and EOG, with Devon Energy being the smallest company that could likely afford a purchase. But Occidental is still busy adjusting after outbidding Chevron in a blockbuster acquisition of Anadarko, which could preclude a purchase by Shell’s partner in its Permian operations. Pioneer Natural Resources might also be excluded as a potential buyer, given that it primarily focuses on the Midland region east of Delaware. But even if the desire is there, there are additional hurdles. Given the immense focus on climate change and the industries that contribute to it, capital is increasingly a challenge, since the financing of fossil fuels is under massive pressure.

Not that those hurdles are insurmountable. The pressures facing a supermajor like Shell – or even ExxonMobil and Chevron – do not necessarily apply in the same measure to other players. If Shell is willing to sell, then there will be plenty of willing buyers vying for the assets. But what is also certain is that recent climate change moves that are ongoing in the boardrooms of energy giants are starting to have very concrete implications and applications on operations. The heat fuelling merger and acquisition activity in the Permian is about to get a lot hotter.

Market Outlook:

  • Crude price trading range: Brent – US$72-74/b, WTI – US$70-72/b
  • Both global crude benchmarks – Brent and WTI – cross the US$70/b threshold, recording the highest level of crude prices since October 2018, as the market focuses on the sustained improvements in fuel demand heading into the crucial summer season in the normal atmosphere that typically boosts road and air travel
  • The outbreak of new Covid variants is still a concern, but the accelerating pace of vaccinations – even in the hardest-hit countries– are providing some reassurance that any current lockdowns will not be prolonged
  • OPEC+ is predicting that oil demand growth will jump by 5 mmb/d in the 2H21 from 1H21 levels, setting the stage for further easing of the OPEC+ supply quotas; Iran’s return to international crude markets is likely to be further afield as talks to revive the 2015 nuclear deal enter into roadblocks

End of Article

Get timely updates about latest developments in oil & gas delivered to your inbox. Join our email list and get your targeted content regularly for free. No alt text provided for this image

Learn more about this course - here


June, 19 2021
What’s Next For Canadian Oil Sands

It cannot be said that the conversation around sustainability and carbon intensity in the energy industry happened overnight, since the topic has been a subject for over five decades. But what has changed is that there has been a major acceleration in the discussion in the last year, and even the last month. The European majors and supermajors have all adopted ambitious carbon-neutral goals – even though some jurisdictions are saying that those aren’t even enough. Over the pond, even shareholders are pushing the traditionally more reticent American giants to adopting stronger climate change goals. Nothing is more emblematic of this change that the shareholder revolt at ExxonMobil’s recent AGM, where upstart activist investor Engine No. 1 managed to oust a quarter of ExxonMobil’s board; the initial tally saw two of its candidates elected, but the final numbers showed that three of Engine No. 1’s nominees now sit on the Board of Directors with a remit to initiate climate change manoeuvres from the inside.

That sort of conversation will be jittery for a particular section of the industry: Canadian oil sands – the heavy, sandy deposits of bitumen in Alberta that provide Canada with the third-largest proven oil reserves in the world. Extracting this heavy stuff is expensive, requiring large-scale excavation and massive capital spending that only really made economic sense with the oil price boom in the late 2000s. Shipping this tarry substance is also a challenge, necessitating dilution with lighter crudes to be shipped via pipeline – which is the only major viable route to market for landlocked Alberta, sending the tarry substance all the way south to the US Gulf Coast for processing. The problem is that extracting oil sands is extremely energy-intensive – with the main culprit being steam injection to liquify the underground bitumen – that has resulted in some of the highest carbon emissions per barrel in the world. In a world racing towards net zero carbon emissions, that is quickly proving to be unacceptable.

So while the climate change debate rages on in the boardrooms of the largest energy firms, the exit has already begun from Alberta, operationally and financially. The latest moves come from Chevron, which saw its shareholders overturn the company’s recommendation to instil stricter emissions targets for its crude, and the New York State Common Retirement Fund, the third-largest in the USA. Chevron’s CEO Mike Wirth recently signaled that he was open to offloading its 20% stake in the Athabasca oil sands project, stating that even though it generates ‘pretty good cash flow without needing much capital’ it was not a ‘strategic position’. Wirth insisted that Chevron wasn’t operating on a ‘fire-sale mentality’ but would consider selling if it got ‘fair value’ – with in business-speak is basically as invitation for offers. But would those offers be forthcoming? Investors all around the world have pulled back from financing Canadian oil sands, limiting the pool of potential buyers. In April, the New York state pension fund restricted investment in six oil sands companies – Imperial Oil, Canadian Natural Resources, MEG Energy Corp, Athabasca Oil Corp, Japan Petroleum Exploration and Cenovus Energy – claiming that they ‘do not have viable plans to adapt to the low-carbon future, posing significant risks for investors’. The amount of funds (US$7 million) is a drop in the ocean for the US$248 billion pension fund, but the message it sends is loud and clear.

Taken as it is, this could be an exit. But taken as a collective movement considering divestments over the past 3 years, this is an exodus. In May 2020, Norges Bank Investment Management – the world’s largest sovereign wealth fund with over US$1 trillion in assets gleaned from Norway’s oil industry – pulled back entirely from Canadian oil sands, selling nearly US$1 billion in four major firms citing concerns over carbon emissions. While no other major pension fund has followed suit, private investors have, including titan BlackRock that has begun to exclude oil sands from its major funds Financing is also proving tricky, with a string of major banks – including HSBC, ING and BNP Paribas – either paring back or stopping lending entirely to the industry; the insurance industry is also pulling back, with The Hartford stopping investing or insuring of the Alberta crude oil industry.

These high-profile investment and financing moves have dimmed the shimmer of an industry that was never that clean to begin with. But what will hurt is the pullback of upstream players, which hollows out the pool of companies left to exploit what is an increasingly unattractive asset. Before Chevron even contemplate its sale, Shell already sold its assets in 2017 for US$8.5 billion and ConocoPhillips offloaded to Cenovus Energy as part of a broader sale including gas assets for US$13.3 billion, also in 2017. Norway’s Equinor, too, has liquidated its position. Then in February 2021, ExxonMobil dropped a bombshell – effectively eliminating every drop of oil sands crude from its worldwide reserves, a tacit admission that oil sands would not form part of its upstream focus (at least at current prices) for the foreseeable future, especially with more attractive propositions in Guyana and the Permian. Given its recent shareholder revolt, it is unlikely that oil sands will be back on the menu ever.

The players in Alberta are trying to fight back. Having been consolidated in less than a dozen major players – from oil sands specialists to more integrated players such as Suncor – the industry is trying to rally institutional support, stating that traditional industry is still necessary to build the clean energy industries of the future. Suncor’s CEO Mark Little puts it this way: ‘this is way more complicated (than its seems)… the wind farm can’t be the solution to every problem. It’s not. So we need to find innovative solutions.” The oil sands patch’s biggest players are also banding together to form an alliance to achieve net-zero greenhouse gas emissions by 2050 – similar to the goals of most energy majors – as it tries to convince not just the world, but also Canada’s own government that Alberta has a continued role in the country’s energy transition. Efforts include linking facilities in Ford McMurray and Cold Lake to a carbon sequestration hub, expanding carbon capture and storage technology, accelerating clean hydrogen and other clean technologies such as direct air capture and fuel switching. The timeframe and viability of this is critical, given that Prime Minister Justin Trudeau has already announced plans to raise Canada’s carbon price steeply to accelerate its energy transition.

Those are bold plans and bold ambitions. But will it be enough? Can the exodus be stemmed? Or will the industry be whittled down to a handful of local players isolated from the wider energy world, removed from climate change engagement completely? It is difficult to tell at this point, but at the very least, things are starting to move in the right direction. Even if the pace is as slow as the crude sludge mined in Alberta.

End of article 

Market Outlook:

-       Crude price trading range: Brent – US$71-73/b, WTI – US$69-71/b

-       Confidence in the crude markets has vaulted global price benchmarks to their highest level in two years, with both Brent and WTI exceeding the US$70/b psychological level

-       Underpinning this rally are signs that vaccinations are boosting economic activity, with the likelihood of some travel and hospitality sectors reopening fully across the northern hemisphere’s summer, while crude marker indication show tightness in the market

-       That will reinforce OPEC+’s position to ease its supply quotas from July onwards, with club’s goal likely to be keeping prices around US$70/b – a level that should stabilise internal finances and budgets for most member countries. 

Get timely updates about latest developments in oil & gas delivered to your inbox. Join our email list and get your targeted content regularly for free.

Submit Your Details to Download Your Copy Today

No alt text provided for this image

Learn more - here

June, 13 2021
M & A in the US Shale Patch

It is only 5 months into 2021, and already Bloomberg estimates that merger and acquisition (M&A) activity in the US shale patch has more than doubled over the equivalent period in 2020 to over US$10 billion. Given that Covid lockdowns sapped energy from shale drilling from March 2020 and what was left was decimated again in April 2020 when US WTI prices (briefly) collapsed into negative territory. From this point onwards, it may not take much to maintain this doubling of M&A activity in the US shale patch over the next 7 months. But don’t call this a new trend; call it what it is: the inexorable centralisation of US shale as the long freewheeling Wild West years give way to corporate consolidation.

Even before Covid had been unleashed upon an unsuspecting world, this consolidation was already in full swing. When the US shale revolution first began accelerating in the early 2010s – when crude oil prices were high and acreage was cheap – there were thousands, maybe even tens of thousands, of small independent drillers vying alongside medium and large upstreamers busy striking riches across American shale basins such as Bakken, Eagle Ford, Marcellus and, of course, the Permian. But too many cooks spoiled the soup. The US shale drillers who were acting capitalistically without concern for discipline incurred the wrath of OPEC and caused the oil price bust in 2014/2015. For larger players were deep pockets and wide portfolios, the shock could be absorbed. But for the small, single field or basin players, it was bankruptcy staring them in the face. The sharp natural productivity dropoff of shale fields after initial explosive output meant profits had to be made super quick and super fast; if debt kept mounting up, then drillers must keep pumping to merely stay alive. But there is another option: merge or acquire. And so those thousands of players started dwindling down to hundreds.

But it wasn’t enough. Even though crude prices began to recover from 2016, it never again reached the dizzying levels of the boom years. Debt accumulated turned into debt to be repaid. And the financial community got wiser. Instead of being blinded by the promise of shale volumes, investors and shareholders started demanding value and dividends. Easy capital was no longer available to a small shale driller. And because of that no new small shale drillers emerged. Instead, the big boys arrived. Because shale oil and gas still held vast potential, the likes of ExxonMobil, Shell and Chevron started moving in. ExxonMobil went as far as calling the Permian its ‘future’ (though this was in the days before its super discoveries in Guyana were announced). With consolidation came cohesion. Instead of a complicated patchwork of small plots, a US shale operator’s modus operandi was now to look to its left or right for land that someone else owned which could be stitched up into its own acreage forming a contiguous asset. And so those hundreds of players started becoming dozens.

In late 2020, this drive ratcheted up as the prolonged Covid-caused fuels depression freed up plenty of candidates for deep-pocketed players. ConocoPhillips bought Concho Resources for US$9.7 billion. Pioneer Natural Resources snapped up Parsley Energy for US$4.5 billion. Chevron closed its US$5 billion acquisition of Noble Energy (after failing to acquire Anadarko after being outbidded by Occidental Petroleum in 2019), while Devon Energy snapped up WPX Energy for US$2.56 billion. All four were driven by the same motive – to expand foothold and stitch up shale assets (particularly in the Permian). This series of M&As rejigged the power balance in the Permian, propelling the four buyers into the top eight producers in the basin, joining Occidental, EOG, ExxonMobil and Chevron. These top eight Permian producers now have output of over 250,000 b/d, accounting for nearly 60% of the basin’s 4.5 mmb/d output.

You would think that this trend would continue until the Permian Big Eight became the Permian Big Four for Five. And this could still happen. But the latest M&A activity from a major Permian player suggests that the ambition may well be too constrained. Cimarex Energy, the tenth largest player in the Permian with output of some 100,000 b/d, just entered into a merger to create a US$17 billion Houston-based shale driller. But its partner was not, say, fellow Permian buddy SM Energy (80,000 b/d) or Ovintiv (75,000 b/d). Instead, Cimarex chose Cabot Oil & Gas, a gas-focused player that operates almost entirely in the Marcellus shale basin in Appalachia, over 1500km away from the Permian.

In response to the merger, share prices of both Cimarex and Cabot fell. Analysts cited a dilution of each company’s core focus (along with the meagre premium) as concerns; implying that investors would be happier if Cimarex stayed and grew in the Permian, and Cabot did the same in Marcellus. But that’s a narrow way of thinking that both Cimarex and Cabot were happy to refute. “This is a long term move,” said Cimarex CEO Tom Jorden. “This combination allows us to be ready for those (swings in commodity prices)”.

While pursuing in-basin opportunities could make shareholders happy in the short-term, a multi-basin deal might be a surprise but is also a canny long-term move. After all, at some point the Permian will run out of oil. And so will gas in Marcellus. Or the US government could accelerate its move away from fossil fuels. If an energy company puts all of its eggs into one basket – or basin, in this case – then when the river runs dry, the company’s profits evaporate. It is a consideration that other single-basin focused players like Pioneer, EOG and Diamondback will need to start thinking about, which is a luxury that other integrated players with Chevron and ExxonMobil already have. Consolidation in American shale basins is inevitable. But what is far more interesting is the new potential of cross-basin consolidation.

Market Outlook:

  • Crude price trading range: Brent – US$67-69/b, WTI – US$64-66/b
  • Global crude oil prices remain locked in their current ranges, with bullish signs of fuels demand recovery in North America, Europe and China offset by signs that the Iranian nuclear deal could be revived, which would lead increase OPEC supply
  • Iran, if reports are accurate, has already been preparing for this, establishing contact with former clients to gauge interest and pave way for its re-entry to the global oil markets, which could swell OPEC production by nearly 4 mmb/d
  • This will be a point of contention within the OPEC+ supply deal framework, since Iran would argue for exemptions (as Russia, Kazakhstan and Libya have) from official quotas; although the latest rhetoric from Iran suggests there are still plenty of gaps to restore the original 2015 nuclear agreement, allaying fears of a quick ramp-up
June, 08 2021