South Sudan was officially recognized as an independent nation state in July 2011 following a referendum held in January 2011. The South Sudanese voted overwhelmingly in favor of secession, which led to Sudan losing 75% of its oil reserves to South Sudan. Although South Sudan now controls a substantial number of the oil–producing fields, it is dependent on Sudan for transporting oil through its pipelines for processing and export. The transit and processing fees South Sudan must pay to Sudan to transport its crude oil are an important revenue stream for Sudan.
After an agreement was reached on the transit dispute that led to a temporary shutdown of crude oil production, the governments of Sudan and South Sudan shifted their focus from border conflicts to the mitigation of their respective domestic opposition factions. The domestic political dynamics and the security situations in both countries will continue to be a potential risk for disrupting the countries’ oil supplies and exports.
In Sudan, the economic shock of the secession has had a significant effect on the economy, which has been hurt by economic mismanagement, corruption, and unsustainably high levels of spending on the military. The partial lifting of U.S. sanctions on Sudan in October 2017 has allowed for increased foreign investment, but Sudan has made little progress toward developing the upstream sector. In August 2019, Sudan’s military and civilian leaders signed a power-sharing deal that paved the way for a transitional government led by Abdalla Hamdok, an economist, to take power in the hope this government would address the country’s problems. However, Sudan remains on the U.S. government’s list of state sponsors of terrorism, which prevents the country from receiving debt relief through the World Bank-International Monetary Fund’s Heavily Indebted Poor Countries Initiative (HIPC).
In South Sudan, President Salva Kiir and the leader of the main opposition faction, Riek Machar, reached a peace agreement in September 2018, which led to reduced violence from the civil war in South Sudan. Although the peace agreement indicates progress, whether the agreement will bring prolonged stability and an inclusive and stable form of governance is unclear. The current agreement is similar to the previous one, which was signed in 2016 and collapsed after two months, and the current iteration does not address crucial elements such as power sharing between the factions and security arrangements that would allow Machar to safely return from exile. Without significant progress in improving the security and political environment, South Sudan’s ability to attract investors and restart production at its fields to increase production will be limited.
Petroleum and other liquids
Exploration and production
Refining and refined oil products
Petroleum and other liquids exports
Renewable Energy Sources
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2019 has been a fairly good year for big hydrocarbon discoveries. After several years of depressed activities, a slew of major upstream finds were announced this year as oil and gas companies recovered from the slump in oil prices to begin drilling once again. Despite the onshore shale revolution, the US Gulf of Mexico keeps giving, with Shell landing a huge oil discovery in the Perdido Corridor. In Russia, Gazprom hit payday with a 17 tcf gas find in the Dinkov and Nyarmeyskoye fields in the Yamal Peninsula. Beyond established upstream basins, large finds have also come in from new frontiers. In South Africa, Total made a huge discovery at Brulpadda that could transform the economy, while in Guyana, ExxonMobil and Tullow keep adding on to a long list of major oil finds dating back to 2015. Up to 8 tcf of gas was hit in Cyprus – though that lies in disputed waters claimed by Turkey – while Kosmos Energy announced the largest gas discovery of the year at the Orca-1 well in Mauritania.
And then there is Iran. Hammered by US sanctions that have severely curbed its oil exports – and scaring off international investors – Iran has continued to go alone in exploration work within its borders. Just last week, Iran announced that it had struck a new field in its southwest that contains up to 53 billion barrels of oil. This single field would increase Iran’s proven oil reserves by a third. In any other scenario, this would be a trigger for a swathe of investment. But in this geopolitical climate, the question instead is: can Iran even develop this field?
To be fair, the Khuzestan field isn’t actually new. Named Namavaran, the reservoir was first probed in 2016, when the relationship between Iran and the West had thawed with the nuclear agreement deal, with an initial 33 billion barrels proven. Since then, additional test wells recently revealed that Namavaran is far bigger than expected. Stretching over 2,400km from Bostan near the Iraqi border to the Omidiyeh province, an additional 20 billion barrels or so were identified, increasing the total figure to 53 billion barrels. Some of this would have been siphoned off from existing assets that were thought to be standalone – including the Ab Teymour, Mansouri, Soosangerd, Darkhovin, Jofeir and Sepehr fields – but even so, the estimated new exploitable reserves from Namavaran number in the 22-27 billion barrel range.
The problem is who will help Iran tap into this. Initially lured by the promise of the geopolitical cooldown, major players such as Total have since abandoned their assets in Iran in the wake of the new US sanctions. Even China is not immune; CNPC also exited the giant South Pars gas project this year while the imposition of sanctions on China Ocean Shipping threw the global tanker market into disarray in October. But it is apparently on China (and Russia) that Iran is depending on. News in the market suggests that Iran is in talks with Chinese companies to develop and commercialise Namavaran, as part of the latter’s Belt and Road global plan. The same news also suggests that a few international firms – hinted to include Shell and Total – are also interested in participating. But given the current tension between Iran and the US and its Middle East allies, foreign participation is a huge question mark at the moment.
A few months ago, it looked like war was imminent in the Middle East. Today, it seems as if the situation has thawed slightly. Some experts even believe that the US may begin easing sanctions – particularly with the exit of ultra-Iran-hawk John Bolton as National Security Advisor. If this happens (and it is a big if), there are many willing parties waiting at Iran’s doors to help exploit the giant Namavaran field. Even if the door is shut, Iran is ready to go ahead alone, not least because it needs a fair amount of oil for its own domestic use. And when this happen, it will spin a new problem: in a world where OPEC is trying desperately to control prices, how will it deal with an Iran whose oil reserves have just increased by a third?
The Namavaran field in Iran:
The U.S. Energy Information Administration (EIA) revises the U.S. crude oil production forecast it publishes in each Short-Term Energy Outlook (STEO) based mainly on two factors: updates to EIA’s published historical data and EIA’s crude oil price forecast. In the November 2019 STEO, EIA increased its forecast of U.S. crude oil production in 2019 by 30,000 barrels per day (b/d) (0.2%) from the October STEO. EIA increased its 2020 crude oil production forecast by 119,000 b/d (0.9%) compared with the October STEO (Figure 1). The increases in crude oil production forecast in the November STEO were primarily driven by
In the November STEO, EIA increased its U.S. benchmark West Texas Intermediate (WTI) crude oil price forecast by $2 per barrel (b) in November to $56/b and by $1/b in both December and January to $55/b and $54/b, respectively. The slight increase in crude oil prices also contributed to EIA’s increased production forecast for the first half of 2020 because of EIA’s assumption of a six-month lag between a crude oil price change and a production response.
In the November STEO, EIA now forecasts U.S. crude oil production will increase to 12.3 million b/d in 2019 from 11.0 million b/d in 2018. Production in the Permian region is the primary driver of EIA’s forecast crude oil production growth, and EIA forecasts Permian production will grow by 915,000 b/d in 2019 and by 809,000 b/d in 2020 (Figure 2). Increases in Permian production are supported by the crude oil pipeline infrastructure expansion seen earlier this year, which helped alleviate the transportation bottleneck and supported prices for WTI in Midland, Texas (the price producers may expect to receive in the Permian region), relative to prices for WTI-Cushing. The higher relative prices in the Permian should continue to encourage production in the region. EIA forecasts that the Bakken region will have the next largest crude oil production growth in 2019, and it is forecast to grow by 152,000 b/d in 2019 and 96,000 b/d in 2020. EIA forecasts that production in the Federal Offshore Gulf of Mexico will increase by 138,000 b/d in 2019 and 116,000 b/d in 2020.
Although EIA forecasts that overall U.S. crude oil production will increase, EIA expects the growth rate to decline from 11.8% in 2019 to 8.1% in 2020. One of the primary indicators of a slowdown in production growth is the decline in oil-directed rigs. According to Baker Hughes, active rig counts fell from 877 oil-directed rigs in the beginning of January 2019 to 674 rigs in mid-November. Rig counts in the Permian region also declined during this period, falling from 487 to 408 (Figure 3). Because EIA expects WTI-Cushing crude oil prices to stay below $55/b until August 2020, EIA anticipates that drilling rigs will continue to decline as producers cut back on their capital spending, resulting in notable slowing in the growth of domestic crude oil production over the next 14 months.
Although U.S. rig counts are declining, improvements in rig efficiency, which allows fewer rigs to drill the same number of wells, partially offset declining rig counts. In addition, higher initial production from wells (although not necessarily the total estimated ultimate recovery) is offsetting some of the slowdown in rigs.
U.S. average regular gasoline prices fall, diesel prices increase slightly
The U.S. average regular gasoline retail fell more than 2 cents from the previous week to $2.59 per gallon on November 18, 2 cents lower than the same time last year. The West Coast price fell by more than 5 cents to $3.54 per gallon, the Gulf Coast price fell by more than 4 cents to $2.22 per gallon, the East Coast price fell by more than 2 cents to $2.45 per gallon, and the Midwest price fell less than 1 cent, remaining at $2.44 per gallon. The Rocky Mountain price increased by nearly 2 cents to $2.84 per gallon.
The U.S. average diesel fuel price rose by less than 1 cent to remain at $3.07 per gallon on November 18, 21 cents lower than a year ago. The Rocky Mountain price increased by nearly 3 cents to 3.23 per gallon, and the East Coast price rose by less than 1 cent, remaining at $3.05 per gallon. The Gulf Coast price fell by less than 1 cent to $2.79 per gallon, and the West Coast and Midwest prices each decreased by less than 1 cent, remaining at $3.76 per gallon and $2.97 per gallon, respectively.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 3.4 million barrels last week to 94.2 million barrels as of November 15, 2019, 5.8 million barrels (6.6%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast and Midwest inventories decreased by 2.5 million barrels and 1.5 million barrels, respectively. East Coast inventories increased by 0.5 million barrels, and Rocky Mountain/West Coast inventories increased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 5.4% of total propane/propylene inventories.
Residential heating fuel prices
As of November 18, 2019, residential heating oil prices averaged almost $2.99 per gallon, more than 1 cent per gallon above last week’s price but 33 cents per gallon below last year’s price at this time. Wholesale heating oil prices averaged nearly $2.06 per gallon, almost 3 cents per gallon more than last week’s price but nearly 13 cents per gallon less than a year ago.
Residential propane prices averaged more than $1.99 per gallon, 5 cents per gallon higher than last week’s price but more than 43 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.85 per gallon, almost 9 cents per gallon higher than last week’s price but nearly 6 cents per gallon below last year’s price.
Brazil’s growth in distributed generation from renewable resources—especially solar—has increased since it implemented net metering policies in 2012. As of mid-November 2019, owners have installed more than 135,000 renewable distributed generation systems in Brazil, totaling about 1.72 gigawatts (GW) of capacity, according to the Brazilian Electricity Regulatory Agency (ANEEL).
Solar photovoltaic accounts for the largest share of the total installed distributed generating resources, representing about 1,571 megawatts (MW), or 91%, of the country’s total distributed generation capacity. Small hydroelectric and wind account for 97 MW and 10 MW, respectively. Net metering policies allow owners of the renewable distributed generation systems to sell excess electricity to the grid for billing credits.
ANEEL’s policy initially allowed small generators using hydro, solar, biomass, wind, and qualified cogeneration of renewable sources of up to 1 MW of capacity to qualify for net metering. In 2015, ANEEL amended the rule to increase the maximum capacity for up to 3 MW for small hydropower and up to 5 MW for other qualified renewable sources.
Qualified generators can choose to sell surplus generated electricity back to Brazil’s grid in return for billing credits. As part of the billing credit structure, net-metering customers can generate credits earned on days when they generated more electricity than they consumed. Before 2015, these credits expired after 36 months, but now credits for excess generation expire after 60 months.
Most of Brazil’s distributed generation units are in the southern, southeastern, and northeastern regions of the country. The states with the most distributed generation units are Minas Gerais with 372 MW, Rio Grande do Sul with 223 MW, and São Paulo with 194 MW.
Source: U.S. Energy Information Administration, based on data from the Brazilian Electricity Regulatory Agency (ANEEL)
At the end of 2018, ANEEL released a regulatory impact analysis and conducted a series of public hearing meetings to discuss economic aspects and sustainable growth of distributed generation in the country.