· This edition of the Short-Term Energy Outlook is the first to include forecasts for 2019.
· Benchmark North Sea Brent crude oil spot prices averaged $64 per barrel (b) in December, an almost $2/b increase from the November average and the highest monthly average since November 2014.
· Brent crude oil prices averaged $54/b in 2017 and are forecast to average $60/b in 2018 and $61/b in 2019. West Texas Intermediate (WTI) crude oil spot prices are forecast to average $4/b less than Brent prices in both 2018 and 2019. EIA’s forecast for the average WTI price for December 2018 of $58/b should be considered in the context of NYMEX contract values for December 2018 delivery. NYMEX contract values traded during the five-day period ending January 4 suggest that a range of $40/b to $85/b encompasses the market expectation for WTI prices in December 2018 at the 95% confidence level.
· U.S. regular gasoline retail prices averaged $2.48 per gallon (gal) in December, down almost 9 cents/gal from the average in November but 22 cents/gal higher than at the same time last year. U.S. regular gasoline retail prices averaged $2.42/gal in 2017 and are forecast to average $2.57/gal in 2018 and $2.58/gal in 2019.
· U.S. crude oil production averaged an estimated 9.3 million barrels per day (b/d) in 2017 and is estimated to have averaged 9.9 million b/d in December. U.S. crude oil production is forecast to average 10.3 million b/d in 2018, which would mark the highest annual average production in U.S. history, surpassing the previous record of 9.6 million b/d set in 1970. EIA forecasts production to increase to an average of 10.8 million b/d in 2019 and to surpass 11 million b/d in November 2019.
· Dry natural gas production is forecast to average 80.4 billion cubic feet per day (Bcf/d) in 2018, a 6.9 Bcf/d increase from the 2017 level, which would be the highest year-over-year increase on record. Forecast dry natural gas production increases by an average of 2.6 Bcf/d in 2019.
· Henry Hub natural gas spot prices are forecast to average $2.88 per million British thermal units (MMBtu) in 2018 and $2.92/MMBtu in 2019, compared with the 2017 average of $2.99/MMBtu. EIA’s forecast for the average Henry Hub price for December 2018 of $3.04/MMBtu should be considered in the context of NYMEX contract values for December 2018 delivery. NYMEX contract values traded during the five-day period ending January 4 suggest that a range of $1.83/MMBtu to $4.89/MMBtu encompasses the market expectation for Henry Hub prices in December 2018 at the 95% confidence level.
· Coal production increased by 45 million short tons (MMst) (6%) in 2017 in response to high demand for U.S. coal exports. Coal production is forecast to decline by 14 MMst (2%) in 2018 and by 18 MMst (2%) in 2019, as export demand is expected to slow and natural gas prices are expected to stay below $3/MMBtu during much of the forecast period, which contributes to less coal use for electricity generation.
· EIA expects the share of U.S. total utility-scale electricity generation from natural gas to rise from 32% in 2017 to 33% in 2018 and to 34% in 2019, as a result of low natural gas prices. Coal's forecast generation share falls from 30% in 2017 to slightly lower than 30% in 2018 and 28% in 2019. The nuclear share of generation was 20% in 2017 and is forecast to average 20% in 2018 and 19% in 2019. Nonhydropower renewables provided almost 10% of electricity generation in 2017, and its 2018 share is expected be similar before increasing to almost 11% in 2019. The generation share of hydropower was more than 7% in 2017 and is forecast to be slightly lower than 7% in both 2018 and 2019.
· After declining by 1.0% in 2017, energy-related carbon dioxide (CO2) emissions are forecast to increase by 1.7% in 2018 and by 0.2% in 2019. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, and energy prices.
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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.
The history of OPEC – the cartel, of some of the world’s largest crude oil producers, has been one of historic co-operation or divergence. When OPEC acts in concert, it can awe the world in either direction; see the terrifying oil shocks of the 1970s or the unprecedented 2020 deal that removed nearly 10 mmb/d of supply to stabilise the market in response to Covid. The addition of Russia and other countries into the broader OPEC+ club bolstered the firepower of the group, but also ratcheted up the tensions within. Because when OPEC fails to agree, the results can also be spectacular, leading to unfettered production and devastating price wars. Typically, the instigators of a showdown tends to be Saudi Arabia (or Russia in OPEC+), or one of the more recalcitrant members like Iran, Iraq or Nigeria. But the latest rupture has come from an unlikely quarter. The previously pliant United Arab Emirates is now holding up OPEC+’s path forward as an unlikely source of drama.
It was supposed to have been easy. After several months of routine meetings followed more routine approval of cautious monthly eases of the group’s supply quotas, the July OPEC+ meeting was expected to be more of the same. Resurgent demand amid economic re-openings and accelerating vaccinations dampening the potency of new Covid-19 variants saw oil supply/demand balances tighten. OPEC+ discipline was key to this, allowing crude oil benchmark to rise to their highest levels in nearly 3 years, with US$70/b being a sweet spot that satisfies domestic budgets and consumption concerns. Ahead of the July 1 OPEC+ meeting, the ministerial panel had recommended that the group adds 400,000 b/d in volumes every month from August to December, and that the wider agreement itself should be extended in full to December 2022 (from its original end date of April 2022). This would be more cautious than required by the market but, the OPEC+ ministers argued, was necessary in case Covid resurgences turned into another series of devastating waves.
The loggerheads over the recommendations was always expected to be between Saudi Arabia and Russia: the former representing the voice of caution and a need for discipline, while the latter argues that additional barrels can still be absorbed by the market as it attempts to flex its production prowess. But, as is turns out, all members of OPEC+ had reportedly signed up to the new recommendation. All except one.
The history of the UAE in OPEC is one of alliances. Along with Kuwait, the UAE has always been #TeamSaudi within the club, supporting the kingpin across the various heated discussions and decisions. In the realm of geopolitics, Saudi Arabia and the UAE are staunch allies. They did, after all, engineer a remarkable blockade of Qatar for nearly 4 years in response to alleged support of terrorism through links with Iran. But the strength of alliances ebb and flow. And in January this year, the break between the two allies was starting to show.
Key behind this is the UAE’s grievance that it had been handed an unfair baseline – the level which all OPEC+ countries are expected to measure their production cuts or increases against. The current level for the UAE is 3.2 mmb/d, and it argues that this should be raised to 3.8 mmb/d if it is to endorse any extension. And the logic behind that is the UAE has been investing heavily in output expansions and is itching to capitalise on that, particularly since it wants extra liquidity to boost its attempt to convert its Murban crude futures contract into a regional crude benchmark. Both Saudi Arabia and Russia have rejected the argument for re-calculating the output target, fearing that everyone else in OPEC+ will ask for the same treatment. This impasse – which is essentially UAE vs everyone else – could potentially unravel the deal that took several weeks of intense negotiation and the assistance of the White House to broker.
In the absence of a new deal, there is a fallback deal. And that is to maintain supply levels at July levels for the rest of the year. But that itself is a risk, since global oil supply is lagging behind demand, and the inflationary effects of elevated crude oil prices are starting to show. Keeping production flat – assuming there are no breaches of compliance – risks further price spikes, and other producers rushing in to fill the gap at the expense of OPEC+ market share. Which is the last thing OPEC+ wants, especially is the rush is from US shale producers.
But an even more dramatic scenario could see a full-scale rebellion of the UAE against its quotas and potentially its exit from the cartel, a possibility strategically ‘leaked’ to reporters back in January. This would break OPEC+ unity, risking a free-for-all situation that could crash prices is other producers follow suit and trigger a punishing price war. In a show of just how close this nightmare scenario is, Saudi Energy Minister Prince Abdulaziz bin Salman has publicly stated that he has not spoken to his counterpart in Abu Dhabi as the July 1 meeting stretched further and further with all parties attempting to come to a compromise. And a compromise is still the most likely resolution, since it is against all interests to jeopardise the stabilised crude oil situation with a price war now. The most likely result is that – after plenty of sound and fury – OPEC+ will endorsed the supply increases for August to December, but not extend the duration of the deal beyond April 2022.
How long and deep will this chasm grow between Saudi Arabia and the UAE? How will this fundamentally reshape the politics within OPEC+? On all evidence right now, it seems like it could be quite a while. Because this is bigger than just oil. Riyadh and Abu Dhabi have been on a crash course for a while now. The UAE has been developing its own foreign policy themes, which are increasingly independent of its Saudi ally – see its recognition of Israel and its position on Yemen. Saudi Arabia’s call for international firms operating in the Middle East to move their regional headquarters to Riyadh has also been interpreted as a threat to Dubai. And in a chilling reminder of the Qatar blockade, travel between the two countries has been restricted. The healing of this rift will be key, not just to the future of OPEC+ but the incendiary geopolitical dynamics of the regions, especially with the incoming return of Iran from the cold to the oil markets and the wider world. OPEC+ has just experienced an earthquake, and now it is time to see what the aftershocks are going to be.
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