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As of June 1, the spread between Brent and WTI – the two major world oil benchmarks – has widened to US$11/b. This is essentially the widest level in 3 years, and although it pales in comparison to the peak spreads of US$26/b in 2012, it also points to some fundamentals issues within crude supply and demand at the moment.
At least until three months ago, the Brent-WTI spread was within the US$4-5/b region. Now it has doubled. What happened? Brent prices have risen some 14% over the past three months, while WTI is up just 7.5%. The last time this happened – in the 2011-2013 period – it was because the US was still maintaining its ban on crude oil exports, which meant that soaring shale oil production was trapped within continental US, and with US refineries geared towards producing heavier, sourer crude grade, the domestic refining industry was not able to convert them into exportable products. Too much oil sloshing around in the US that was trapped, while crudes based on Brent pricing were free to move around the world. The lifting of the crude export ban in 2015 seemed to solve that issue, but now something else has risen its head.
A different bottleneck seems to have emerged – a shortage of pipeline capacity to bring shale supplies to the benchmark delivery point in Cushing, Oklahoma, and then a further shortage of pipeline and port capacity to send US crude to a hungry world market. That’s been depressing WTI prices, but it is also accurate to say that Brent crude is facing issues that are inflating its price levels – causing the growing gap.
With Iran and Venezuela facing new sanctions designed to punish their crude exports, Brent – as the global benchmark – has been spooked into higher levels due to this. Which explains why Russia and Saudi Arabia have made very recent public statements that they are willing to reverse their course of maintaining the OPEC-NOPEC supply freeze levels, in order to keep a lid on soaring prices. Rosneft is already testing for increased crude output capacity and Saudi Arabia seems happy to corral the rest of its OPEC allies into ‘turning the tap of spare capacity on.’ This should help plug any potential gap caused by the departure of Iranian and Venezuelan volumes – which could reach up to 500-600,000 bd. It is almost amusing to see how Saudi Arabia, which only a few weeks ago was championing higher prices while the rest of OPEC was content to have prices stabilise at US$70/b, reversing its position. WTI prices may be depressed now because of infrastructure constraints, but once those are solved – though it may take years – Saudi Arabia does not want to run the risk of encouraging more US shale production that necessary, leading to another oil price crash in the near future. A dramatically widening Brent-WTI is an issue that presages problems in the future; tackling it is a prudent way of mitigating potential threats to the future stability of oil prices.
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The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.
How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.
The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.
The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.
On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.
But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.
For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.
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In the perennial struggle between resources owners and resource exploiters, Mexico’s latest move surrounding its largest private oil discovery ever has echoes of many past battles. There are only a few countries in the world that have both the physical energy assets and the technological know-how to exploit it, such as the US, UK and Norway. Even other major producers such as Saudi Arabia, Russia, Iran and Venezuela had plenty of outside help before nationalisation took over; to say nothing of the new players to hydrocarbons such as Guyana or Ghana. So Mexico’s decision to designate its state oil firm Pemex as the sole operator of the Zama field over the private consortium (led by Houston-based Talos Energy) that made the discovery has plenty of precedent. And is also a chilling reminder that the battle between national pride and international experience will always play out.
The Zama field, located in Block 7 of the Sureste Basin in the Gulf of Mexico, was discovered in July 2017 from the first exploration well to be drilled by the private sector in the country. The Zama-1 well struck oil at a depth of nearly 170m, and subsequent appraisal wells estimate the total recoverable reserves at nearly a billion barrels. Talos Energy, which holds a 35% stake in the block, is the current operator, sharing it with consortium partners Sierra Oil and Gas (40%) and Premier Oil (25%). First oil is expected by 2022 and peak production should stand at around 100,000 b/d. In many ways, Zama was a game changer for the Mexican upstream industry. At the point of discovery, Mexican oil production had been waning and discoveries lacking; Zama was proof that there was still significant amounts of oil left to be found.
The fact that Zama was the result of the first private sector exploration ever (well, at least for in over 80 years) was key. The fact that it was a huge resource was icing on the cake. Because in 2013, the Energy Reform allowed private and foreign investor across the entire energy value chain in Mexico for the first time since 1938, breaking Pemex’s monopoly in an effort to combat what was seen then as a chronic decline in Mexican energy. On the downstream side, international fuel brands penetrated the market for the first time, setting up what are now lucrative fuel station networks. But the biggest impact was on the upstream side. In the years following the 2013 Energy Reform, the Mexican National Hydrocarbons Commission awarded 107 oil and gas exploration and production contracts to over 73 companies from 20 countries.
The Zama discovery was born out of this de-monopolisation drive, and the companies currently drilling wells and making discoveries across Mexico include those from as far as Thailand and Malaysia. The string of new discoveries that have followed Zama’s are the fruits of this labour. Pemex still plays a vital role in the country – including running one of the world’s largest crude hedging programmes – but its loss of relevance has rankled some nationalists. Which is why in 2018, when new President Andrés Manual López Obrador (AMLO) took office on a nationalist platform, issuance of new E&P contracts have slowed down to a near trickle and new crude auctions have been suspended, as AMLO’s administration tries to assert domestic interests. His stated goal is to return Pemex to glory, which will mean rolling back the energy reforms that (briefly) made Mexico an upstream investment darling between 2014 and 2018.
Zama – as the most high-profile of all the private-led discoveries so far – has been at the centre of this tug-of-war. There is some basis to the government’s decision to hand over Zama to Pemex; this is not just some flimsy asset-grab attempt. Since the Zama field shares the same reservoir as one belonging to Pemex, the dispute has raged over whether Talos or Pemex has operational rights. A unification process to establish a joint area has been underway since 2018, with a study commissioned by both parties concluding that Pemex has a slight majority share with 50.4% of the shared reservoir. That ordinarily should have led to a new joint venture recognising the shared resource, but instead Mexico has decided to name Pemex as sole operator. It is a decision that should send chills down the spine of other international firms.
Because if it could happen to Talos, then it could happen to Lukoil, which just agreed to acquire a 50% interest in the Area 4 Ichalkil and Pokoch fields in the Bay of Campeche from Fieldwood Energy. It could happen to Petronas, which has made a string of offshore discoveries including from the Polok-1 and Chinwol-1 wells in 2020. It could happen to Eni, which holds rights in six E&P blocks (six as the operator) in the Sureste Basin. It could happen to anyone, because the AMLO administration has indicated with this approach that it is ready to confront the frustration and concern of foreign investors in order to polish Pemex. This could bring Mexico in the crosshairs of the Biden administration, since Talos is an American firm and this could fly in the face of some terms in the new North American trade deal. And more concerning is whether Pemex even has the resources and skills to operate Zama. The energy reform in 2013 happened precisely because Pemex couldn’t deliver operationally. Six years on and not much has changed at Pemex, so will there be any difference beyond nationalistic pride? Talos has made the full investment at Zama so far, while Pemex has yet to drill a single well after cancelling plans in June at the reservoir. Indonesia attempted something similar; and despite grand ambitions, Pertamina is no Petronas and the Indonesian upstream sector has languished.
Time will tell if this is a one-off or a trend in Mexico. But odds are that it will be the latter, given the nationalist bent pursued by AMLO and his relatively high popularity. But this shouldn’t be a surprise to any international firm operating in the sector. It happens everywhere. It is currently happening in Guyana, which is currently debating new petroleum laws to give the state a greater share of oil revenue after ExxonMobil was attracted there on favourable terms to make blockbuster oil discoveries. It is at the heart of the crisis in Papua New Guinea where the new government is attempting to extricate better terms from ExxonMobil and Total after their LNG projects took off. It resulted in Eni being ordered by a Ghanian court to place 30% of the Sankofa field’s revenue in an escrow account after the Italian major defied Ghana’s request to combine its field with the neighbouring Afina field owned by Springfield. Competing national interests and commercial rights are reality in the upstream world. And if those signs coming out of Mexico are correct, then current private firms sitting on Mexican assets should be wary. At least until this attempt fails and a new politician initiates a U-turn.
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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).
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.
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.
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.
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.
