Easwaran Kanason

Co - founder of NrgEdge
Last Updated: November 7, 2016
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Business Trends
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Last week in world oil:

OPECs internal squabbling has erased all its efforts to raise oil prices from languishing in the US$40/b range, as hope fades that the quixotic supply cut could be engineered. In fact, whispers suggest that Saudi Arabia is mulling punishing the rest of the organisation by pumping more oil to cause prices to free fall in a harsh attempt to get the other members in line. The next OPEC meeting begins November 30. Analysts remain split about   its success.

Venzuelas PDVSA has completed deals with Delta Petroleum and Indias ONGC totalling US$1.45 billion to raise production at their joint venture operations. The Delta Petroleum deal will see US$1.13 billion pumped in to raise production at Petrodelta from 40 kb/d to 110 kb/d, while the ONGC agreement will inject US$318 billion into Petrolera Indovenezolana to double production at the Cristobal field to 40 kb/d.

After a brief break, the operating oil rig count in the US resumed its climb, adding nine new oil and three new gas rigs, bringing the total up to 450 and 117, respectively, even as oil prices retreated from recent highs over uncertainty in OPEC and a massive crude build reported by the EIA.

Curacaos divorce with Venezuela over the Isla refinery now seems imminent, with Chinas Guangdong Zhenrong Energy now moving to secure funds for its US$5.5 billion plan to upgrade the refinery, a strategic spot in the Caribbean that serves as a oil hub for the Atlantic. PetroChina, Sinopec and CNOOC are expected to collaborate with the state-owned firm in the project, which now includes plans for the natural gas terminal.

Just weeks after announcing a new retail fuel pricing plan, Petrobras is now changing its pricing for LPG. Aimed to eliminating indirect subsidies by charging more for distributors using its facilities, it is the latest in Petrobras attempt to bolster earnings to pare down debt.

Canada has approved the C$1.3 billion expansion of the NOVA Gas Transmission natural gas gathering pipeline. The project by TransCanada will streamline some 75% of natural gas (some 11.3 bcf) in western Canada, including the Montney and Duverney shale fields in BC and Alberta, with completion expected in Q2 2018.

Shell and BP have both reported higher-than-expected earnings for Q316, with Shell reporting a rare instance of higher revenue than ExxonMobil. Much of the improvement in earnings comes from the supermajors sustained cost cutting, their adaptation strategy to low prices.

General Electric will merge its oil and gas business with Baker Hughes to create the second-largest oilfield services company in the world, behind Schlumberger. To be known as Baker Hughes, A GE Company, the new US$32 billion company will combine GEs equipment expertise with Baker Hughes speciality in drilling and fracking, as the industry responds to the prolonged slump in crude oil prices.

Italys ENi has signed four agreements with Bahrain to move into onshore and offshore upstream activities in Bahrain. The agreements were signed by Bahrain Petroleum Company (Bapco) and Tatweer Petroleum, representing a preliminary step in evaluating selected E&P assets in Bahrain that may eventually led to asset stakes for Eni if viable.

Malaysias Petronas is stoking some interest in the battered offshore contracting industry by requesting submissions for its K5 sour gas project off Sarawak in Malaysia. If the project, with its 4 tcf of recoverable gas, moves ahead, it will require a large production facility, and the possibility of Petronas moving ahead with the project has whet the appetite for a industry currently starved of projects.

In a bid to spur Chinas oil exports given that the country is now swamped with an oversupply of oil products the export tax rebate for gasoline, diesel and jet fuel has been raised to 17% effective November 1. The rebate, which eliminates double taxation for exported goods, comes as China is swamped by an oversupply of oil products, owing to vast expansions of refining capacity by the state players and a flood of products coming from independent teapot refiners after crude imports were deregulated last year. Unable to the consumed domestically, the products must now head out, contributing to the continued glut in Asia.

ExxonMobils acquisition of InterOil central to its plans to exploit the vast natural gas potential of Papua New Guinea has hit a snag. An objection by InterOils founder filed in Canada has moved to the appeals court, which overturns approval of the US$2.5 billion sale, potentially derailing the deal. The Canadian approval is the sole remaining hurdle to the completion of the deal, and now ExxonMobil must move to appease InterOil founder Phil Mulacek to salvage its plans.

Tokyo Gas, the largest city gas supplier in Japan, has signed an MoU with Malaysias Petronas that will see the two companies co-operating over existing and future natural gas and LNG projects in Southeast Asia. Tokyo Gas has worked with Petronas LNG for over 33 years, buying LNG from three Petronas projects, and the agreement will deepen the ties as Tokyo Gas seeks to secure more supply to feed Japans appetite for natural gas.

Indias Reliance has been slapped with a US$1.55 billion fine by the Indian government for allegedly extracting and selling gas belonging to ONGC in the KG basin of the Bay of Bengal over the last seven years. It is claimed that up to 11 bcf of gas seeped from ONGCs blocks to the adjacent block held by Reliance, BP and Niko Resources. Reliance will contest the fine

Keppel Corp had agreed to purchase bonds offered by struggling oil and gas explorer KrisEnergy, raising its stake in the company to as much as 67.33%. Much of the offshore marine contracting and engineering industry in Singapore is withering, with smaller firms unable to service debt, raising that possibility that the government may officially step in to offer direct aid, as well as through government-linked companies.

Have a productive week ahead!

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Ecuador Exits OPEC

Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.

The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can. 

This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.

The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.

The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis. 

Current OPEC membership:

  • Middle East: Iran, Iraq, Kuwait, Saudi Arabia, UAE
  • Africa: Algeria, Angola, Equatorial Guinea, Gabon, Libya, Nigeria, Republic of Congo
  • Latin America: Venezuela
  • Total: 13
  • Withdrawing: Ecuador (January 2020)
  • Membership under consideration: Sudan (October 2015)
October, 18 2019
U.S. Federal Gulf of Mexico crude oil production to continue to set records through 2020

U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) averaged 1.8 million barrels per day (b/d) in 2018, setting a new annual record. The U.S. Energy Information Administration (EIA) expects oil production in the GOM to set new production records in 2019 and in 2020, even after accounting for shut-ins related to Hurricane Barry in July 2019 and including forecasted adjustments for hurricane-related shut-ins for the remainder of 2019 and for 2020.

Based on EIA’s latest Short-Term Energy Outlook’s (STEO) expected production levels at new and existing fields, annual crude oil production in the GOM will increase to an average of 1.9 million b/d in 2019 and 2.0 million b/d in 2020. However, even with this level of growth, projected GOM crude oil production will account for a smaller share of the U.S. total. EIA expects the GOM to account for 15% of total U.S. crude oil production in 2019 and in 2020, compared with 23% of total U.S. crude oil production in 2011, as onshore production growth continues to outpace offshore production growth.

In 2019, crude oil production in the GOM fell from 1.9 million b/d in June to 1.6 million b/d in July because some production platforms were evacuated in anticipation of Hurricane Barry. This disruption was resolved relatively quickly, and no disruptions caused by Hurricane Barry remain. Although final data are not yet available, EIA estimates GOM crude oil production reached 2.0 million b/d in August 2019.

Producers expect eight new projects to come online in 2019 and four more in 2020. EIA expects these projects to contribute about 44,000 b/d in 2019 and about 190,000 b/d in 2020 as projects ramp up production. Uncertainties in oil markets affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.

anticipated deepwater Federal Gulf of Mexico field starts

Source: Rystad Energy

Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to reconsider future exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2018.

Brent crude oil price and U.S. Gulf of Mexico rig count

Source: U.S. Energy Information Administration, Thompson Reuters, Baker Hughes

Crude oil price increases in 2017 and 2018 relative to lows in 2015 and 2016 have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discoveries in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead they affect the discovery of future fields and the start-up of new projects.

October, 17 2019
Crude oil used by U.S. refineries continues to get lighter in most regions

API gravity of U.S. refinery inputs by region

Source: U.S. Energy Information Administration, Monthly Refinery Report

The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.

API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.

The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.

Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.

Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.

lower 48 states production of crude oil by API gravity

Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report

When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.

Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.

By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.

U.S. refinery inputs by region

Source: U.S. Energy Information Administration, Monthly Imports Report and Monthly Refinery Report

East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.

October, 14 2019