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Last Updated: September 15, 2017
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Last week in World oil:

Prices

  • Oil prices remained mixed at the start of this week, with Brent at US$53/b and WTI at US$48/b. The aftermath of Hurricane Irma hitting the Caribbean and Florida has stoked fears over demand, while there has been some delay in Texas refineries restarting post-Hurricane Harvey. Rumblings that Saudi Arabia and the UAE were pushing for a new extension in the OPEC supply cut agreement did provide some lift.

Upstream

  • Azerbaijan’s Socar is playing hardball as it negotiates new production sharing agreements with BP and the consortium for the Azeri-Ciraq-Gunashli oil fields. Originally signed in 1994, all parties want to extend it beyond expiration in 2024, but Azerbaijan is reported demanding its share to be increased to 20% from 11.6%. BP would be the major loser under this proposition, having its share reduced from 35.8% to 30%.
  • After gaining approval to move ahead with the Karish-Tanin natural field gas in Israel last week, Greece’s Energean Oil and Gas has also gained approval for Kataloko oil field in Western Greece. This will be Energean’s third project in the eastern Mediterranean, with a target of producing 11 million barrels of oil by 2020 and FID expected in 2018.
  • The rebalancing in Canadian heavy oil sector continues, as Canadian Natural Resources purchased Cenovus Energy’s Pelican Lake project in northern Alberta for US$788 million. Cenovus has been selling off assets acquired from ConocoPhillips in March to optimise its portfolio, allowing Canadian Natural to pick up its second major purchase this year, having bought Shell and Marathon Oil’s oil sands production for US$10.3 billion.
  • The US lost 3 oil rigs last week – the third fall in the past four weeks – although this was offset by a gain of 4 gas rigs, leading to a net gain of one.

Downstream & Midstream

  • Shell has joined the race for Mexico’s fuel retail sector, opening its first gas station last week as Pemex’s monopoly ends. The inaugural station is located in Mexico City, with Shell reporting that more will come as investments of up to US$1 billion are planned over the next decade.
  • Magellan Midstream Partners will be expanding its refined products pipeline system to handle emerging demand for gasoline, gasoil and jet fuel in Central and North Texas. A new 216-km pipeline will be build from Magellan’s terminal to Hearne, in partnership with Valero Energy, while an existing pipeline will be reversed and linked to the new segment.

Natural Gas and LNG

  • Angola will be selling LNG from its sole export facility to Vitol in its first long-term deal. Prior to this, Angolan LNG had been sold entirely via competitive tenders on the spot market, as concerns over plant reliability and consistent supply failed to create multi-year deals. Details of the agreement are confidential, but are part of a growing trend of traders securing long-term deals with producers to create a global LNG portfolio.

Corporate

  • Chinese conglomerate CEFC will buy a 14.16% stake in Russia’s Rosneft from Glencore and the Qatar Investment Authority for US$9.1 billion, boosting energy partnership between China and its largest supplier.

Last week in Asian oil

Upstream

  • The latest revisions to Indonesia’s new oil and gas production sharing contracts are seen as positive steps to attract investors. The latest tweaks keeps the government’s share at 52% for gas and 57% of oil production, but increase other components such as contractors’ share of output in the second and third stages of production or where assets have higher sulphur content. The Indonesian Petroleum Association described the revisions as ‘encouraging’, also praising the new tax incentives being drafted to make new energy contracts more attractive.

Natural Gas & LNG

  • India’s Reliance and BP have revived investment plans for the gas-rich NEC-OSN-97/2 block in the Bay of Bengal, within the offshore Mahanadi basin. Plans to develop the block were originally hindered by objections from the Defence Ministry due to its proximity to the Chandipur missile test base. These objections appeared to have been assuaged, and Reliance is now proceeding with development. This would be the second major project for Reliance and BP, which recently signed off on a US$6 billion plan to develop the Krishna-Godavari offshore basin, part of the India government’s plan to revive and boost domestic natural gas production.
  • BP has begun drilling its first shale gas well in the Neijiang-Dazhu block in China’s Sichuan basin, under a PSC with CNPC. This will be the first shale gas well to be drilled by a foreign major in China in several years, although CNPC is technically the block’s operator under the PSC terms. The block is one of two PSCs signed by BP with CNPC in the Sichuan basin, the other being Rongchangbei. Both blocks are understood to contain shale gas and conventional natural gas, but recent disappointments by Shell, Chevron and Hess in Sichuan and Guizhou may mean that the assets may not be commercially viable.
  • Australia’s Senex Energy will be developing a new gas field in the Surat Basin in Queensland, aiming to offer first gas to a tight local market by 2019. Senex gained the acreage for free on the condition that it be used to supply the Australian east coast market, and is next to Shell’s QGC acreage and close to existing gas pipeline infrastructure.
  • India’s Petronet LNG has announced a joint venture with Japanese and Sri Lankan partners to build an LNG terminal in Colombo. The plant is aimed at supplying gas to Sri Lanka’s power and transport sector, with initial design and capacity still under discussion. Completion is expected within two years of FID.
  • Western Australia has temporarily banned onshore hydraulic fracturing as it assesses environment risks associated. The state joins Victoria in banning fracking, with other Australian state also having moratoriums.

Corporate

  • Fresh of China’s acquisition of a stake in Rosneft by CEFC, Japan has also expressed interest in investing in energy companies, specifically citing Rosneft. The expressions of interest are by the Japan Oil, Gas and Metals National Corporation (JOGMEC), and can be seen as an attempt to not be left behind by China’s drive to acquire strategic stakes in key producers.

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TODAY IN ENERGY: Drop in petroleum demand led to rise in crude oil inventories and low refinery utilization

The U.S. Energy Information Administration’s (EIA) latest Petroleum Supply Monthly shows the significant changes in petroleum markets that occurred in April, when most of the United States was under stay-at-home orders to limit the spread of coronavirus. In April, commercial crude oil inventories increased by 46.7 million barrels (10%)—the largest monthly increase in EIA data going back to 1920. U.S. refineries operated at 70% of their capacity, the lowest utilization rate in EIA’s monthly data series dating back to 1985. Demand for finished petroleum products fell to 11.7 million barrels per day (b/d), the lowest level since at least 1981.

April’s crude oil inventory increase is a result of refinery runs falling more quickly than crude oil supply, which is determined by domestic production and imports. U.S. crude oil production in April averaged 12.1 million b/d, a decrease of 669,000 b/d (5%) from March. This decrease represents the largest month-over-month decline since September 2008, when Hurricanes Ike and Gustav hit the U.S. Gulf Coast. U.S. crude oil imports fell by 776,000 b/d (12%) from March to April, further decreasing crude oil supply in the United States.

The combined drop in production and imports was smaller than the decline in gross inputs to refineries, resulting in record increases in crude oil inventories. Based on estimates in EIA’s Weekly Petroleum Status Report, commercial crude oil inventories reached a record high of 541 million barrels in the week ending June 19 and have fallen slightly in the weeks since then.

U.S. product supplied of gasoline, distillate, and jet fuel

Source: U.S. Energy Information Administration, Petroleum Supply Monthly

Changes in travel patterns resulted in the lowest levels of U.S. demand for finished petroleum products (as measured by product supplied) in decades. Transportation fuels have been affected differently by changes in travel: demand for jet fuel and motor gasoline fell much more than distillate fuel, which is primarily consumed as diesel. From March to April, product supplied of finished motor gasoline decreased a record 1.9 million b/d (25%) to 5.9 million b/d, the lowest monthly value since the mid-1970s.

In the span of two months, U.S. demand for jet fuel fell by more than half, from 1.6 million b/d in February to 691,000 b/d in April. Before April, U.S. jet fuel demand had not been less than 700,000 b/d since the mid-1970s.

Distillate demand fell by 408,000 b/d, or about 10%, from March to April. Although the change in distillate demand was less drastic than the changes in motor gasoline and jet fuel demand, distillate consumption in April 2020 was the lowest in more than a decade.

July, 10 2020
U.S. natural gas exports to Mexico set to rise with completion of the Wahalajara system

Exports of natural gas to Mexico by pipeline are the largest component of U.S. natural gas trade, accounting for 40% of all U.S. gross natural gas exports in 2019. EIA expects these exports to increase with the completion of the southern-most segment of the Wahalajara system, the Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline. VAG began operations in June 2020, connecting new demand markets in Mexico to U.S. natural gas pipeline exports.

The Wahalajara system is a group of new pipelines that connects the Waha hub in western Texas, a major supply hub for Permian Basin natural gas producers, to Guadalajara and other population centers in west-central Mexico. The Wahalajara system provides U.S. natural gas to meet growing demand from Mexico’s electric power and industrial sectors. With the 0.89 billion cubic feet per day (Bcf/d) VAG pipeline entering service, EIA expects utilization of the Wahalajara system to quickly ramp up, resulting in increased U.S. natural gas exports to Mexico out of western Texas and additional takeaway capacity out of the Permian Basin.

Since 2016, Mexico has been expanding its natural gas pipeline system, which has supported continual growth in U.S. natural gas exports. Most of this growth has been in U.S. natural gas exports from southern Texas after the existing U.S. pipeline infrastructure was expanded and the Los Ramones Phase II pipeline in central Mexico was completed.

Since the Sur de Texas-Tuxpan pipeline was completed in September 2019, U.S. natural gas exports to Mexico reached a record 5.5 Bcf/d in October 2019. U.S. natural gas exports from the border at Brownsville, Texas, to the southeastern state of Veracruz in Mexico averaged 0.6 Bcf/d during the last quarter of 2019, or about 20% of the pipeline’s capacity.

Overall, U.S. natural gas exports from this region have only increased by 0.2 Bcf/d from 2016 to 2019 because of delays in pipeline construction in Mexico. In particular, two regional pipelines were completed in 2017 but have not been used near their capacity:

  • The 1.1 Bcf/d Comanche Trail pipeline, which delivers natural gas to Mexico from San Elizaro, Texas
  • The 1.4 Bcf/d Trans-Pecos pipeline, which crosses the border at Presidio, Texas 

U.S. monthly natural gas exports to Mexico by region

Source: U.S. Energy Information Administration, Natural Gas Monthly

The Comanche Trail pipeline has been delivering an average of 0.1 Bcf/d of natural gas to Mexico since the San Isidro-Samalayuca pipeline entered service in June 2017. Pipeline operators do not expect flows to rise until the 0.47 Bcf/d Samalayuca-Sásabe pipeline is completed in either late 2020 or early 2021 in Mexico.

The Trans-Pecos pipeline, the U.S. segment of the Wahalajara system, did not transport significant volumes of natural gas until October 2018; it is currently only operating at 10% to 15% of its total capacity. Most of the demand centers are in southern Mexico, waiting to be connected to the VAG pipeline. Three of the project’s four pipelines in Mexico that are currently in-service include

  • Ojinga-El Encino: 1.4 Bcf/d, entered service in June 2017
  • El Encino-La Laguna: 1.5 Bcf/d, entered service in January 2018
  • La Laguna-Aguascalientes: 1.2 Bcf/d, entered service in December 2019

Before the economic impacts and uncertainty associated with COVID-19 mitigation efforts and declining crude oil prices, S&P Global Platts expected U.S. natural gas exports to Mexico to increase immediately by 0.3 Bcf/d to 0.4 Bcf/d on the Wahalajara system. However, given the decreased demand for natural gas in Mexico in response to the economic impact of COVID-19 mitigation efforts, growth is likely to be slower than expected. Beyond these volumes, additional export volumes will be limited by how quickly customers in Mexico can be connected to the pipeline system.

These connections include new natural gas-fired combined-cycle generators and the scheduled 2020 completion of the 0.89 Bcf/d Tula-Villa de Reyes pipeline, which will deliver natural gas to central Mexico. Deliveries from the Wahalajara network are likely to partially displace higher-cost liquefied natural gas (LNG) imports into Mexico’s Manzanillo terminal, which serves markets in Guadalajara and Mexico City.

As U.S. natural gas exports on the Wahalajara system rise and crude oil prices remain low, EIA expects the price at the Waha hub in the Permian Basin, which had been steeply discounted to the Henry Hub national benchmark, to continue to strengthen.

July, 07 2020
The Oil World’s Ongoing Impairments

Officially, we are past the half point of 2020 and with that the end of the second quarter. And what a quarter it has been. WTI prices plunged into negative territory (as low as -US$37/b) then recovered to US$40/b as OPEC+ moved from infighting to coordinating the largest crude production cut in history. In between, the Covid-19 pandemic wreaked havoc with the global economy, setting off a chain reaction within the oil world whose full impact is still unknown.

Opinions on a post-Covid oil world are divided. Some voices, the more optimistic ones, think that oil demand could recover to pre-Covid levels within a year or two. The more pessimistic ones think that this will never happen, that Covid-19 has hastened the trend away from fossil fuels to sustainable energy against the backdrop of climate change. Either way, this has thrown a spanner in the works of the giant, multi-billion oil and gas projects that were announced over the past two years as the energy world began to wake up from its post-2015 price crash investment hibernation. Those projects were made at a time when oil prices were at US$50-60/b. Since oil prices are now only at US$40/b, the current value and the future worth of these assets have now declined. Energy companies account for this by adjusting the value of their portfolios in accordance to the projected value of crude: an upward adjustment is known as a revaluation, and a negative one is known as an impairment.

This is a term that will crop up many times over 2020, as energy companies close their quarterly financial books and report their results to shareholders. The plunge in crude oil prices and the uncertain outlook for oil demand means that publicly-traded companies must account for this to their shareholders. Chevron was the first supermajor to book an impairment, in late 2019 when it took a US$10 billion hit to its oil and gas assets. It wasn’t the only one: firms all across the oil chain also reduced the value of their assets, from Repsol to Equinor.

Further impairments were made in April 2020 when the Q1 financial results were announced, mainly in response to the triggering of the OPEC+ price war (which saw crude prices halve from US$60/b to US$30/b) and the Covid-19 pandemic accelerating to a point where over half of the world’s population went into lockdown. But the major impact will come in Q2 2020, when the roil in the oil markets truly began to boil uncontrollably. BP has announced that it may take up to a US$17.5 billion impairment in its Q2 2020 financial results, while Shell has just admitted that it may have to shave US$22 billion from its asset value.

This has roots not just in the depressed demand for energy due to Covid-19, but also the ongoing conversation on climate change. Almost all supermajors have announced intentions to become carbon neutral by the 2050 timeframe. That may be good news for the planet, but it is bad news for the companies’ portfolio. Put simply, it means that some of the assets that they have invested billions in are now not only worth a lot less (due to Covid-19) but they may in fact be worth nothing at all, because climate change considerations mean that they will never be exploited. Challenging projects such as Total’s deepwater Brulpadda discovery in turbulent South African waters or Pertamina/ExxonMobil/Total/PTTEP’s beleaguered and complicated East Natuna sour gas asset in Indonesia may never be commercialised, either because of uneconomic prices or because they run counter to the goal of becoming carbon neutral. The Financial Times estimates that the amount of unviable or stranded hydrocarbon assets could reach as much as US$900 billion; that figure is pre-Covid, and could now become even higher.

There is one supermajor bucking the trend though. The biggest supermajor of all, in fact. Unlike its peers, ExxonMobil has not yet succumbed to impairments. If fact, it has not announced any negative revaluations at all over the past decade, even during the 2015 oil price crash. ExxonMobil claims that this is because it books the value of new assets ‘very conservatively’ and does not ‘adjust values to short-term price trends’, but critics say that it has an ongoing history of vastly overestimating its assets’ value. Along with Chevron, ExxonMobil does not disclose price assumptions in its financials. But unlike Chevron, ExxonMobil has not yielded to climate change through an official emissions target or asset revaluations.

On paper, that will make ExxonMobil look better than its supermajor brothers. But behind the scenes, this reluctance to admit that the future is less rosy than expected could be trouble waiting to be unleashed. Impairments are a necessary reality check: an admission by a company that things have changed and it is starting to adapt. Most have accepted that reality. ExxonMobil seems to be resisting. But even it is not immune. In pre-Q2 2020 results guidance that was just announced, ExxonMobil admitted that it expects to take a hit of some US$3.1 billion and slump to a second straight quarterly loss. In terms of Covid-19 impairments, that’s small. But it is, at least, a start.

Market Outlook:

  • Crude price trading range: Brent – US$40-44/b, WTI – US$38-42/b
  • A swathe of positive economic data is supporting oil prices within its current range, with US light crude settling above US$40/b for the first time in four months
  • The relaxation of Covid-19 restrictions has led to improvements in most economic indicators, but the risk of the situation reversing is also higher, given the accelerating cases being reported in part of the USA, South America and India
  • On the supply side, OPEC+ is making adherence a priority, with lagging members now bucking up and swing producer Saudi Arabia also keeping its promises by throttling crude exports in June to some 5.7 mmb/d

End of Article

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July, 04 2020