South Sudan gained independence from Sudan in July 2011. Although most of the oil production capacity in those two countries is in South Sudan, the country is landlocked and remains dependent on Sudan’s export pipelines and port. Civil unrest, disagreements over oil revenue sharing, and border disputes have curtailed oil production and investment in both countries.
South Sudan was officially recognized as an independent nation state in July 2011 following a referendum held in January 2011, when the South Sudanese voted overwhelmingly in favor of secession. Since the split, Sudan and South Sudan’s oil production has declined because of continued domestic political instability and conflict between the two countries.
The unified Sudan began producing oil in 1999, and as a result, the country tripled its per capita income within a decade.1 However, the secession of South Sudan significantly affected Sudan’s economy because it lost 75% of its oil production fields to South Sudan. According to an International Monetary Fund country report, Sudan’s government revenues and foreign exchange earnings fell by about one-half and two-thirds, respectively.2 Sudan and South Sudan’s oil sectors play a vital role in their economies and are closely linked; most of their producing assets are near or extend across their shared border. Although South Sudan now controls a substantial amount 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.3
Disruptions in oil production, disputes over oil revenue sharing, and lower oil prices have had a negative effect on both economies. In January 2012, South Sudan shut down virtually all of its oil production because of a dispute with Sudan over transit fees. The dispute was not resolved until April 2013 after protracted negotiations. In December 2013, a conflict between government forces and rebel factions led to a civil war in South Sudan. The peace agreement brokered in August 2015 provided a temporary reprieve, but fighting resumed in July 2016 and the security situation is still tenuous.4
Sudan has been more successful in weathering the downturn in oil prices in recent years by shifting to a more diversified economy. In addition, the partial lifting of U.S. sanctions on Sudan in October 2017 may provide more opportunities to attract additional foreign investment.5 Prospects for South Sudan are less optimistic, given the uncertain outcome for the ongoing peace process, its dependence on crude oil for revenue in the lower oil price environment, weak investor confidence, and a lack of functioning infrastructure.
After gaining independence in 1956, the unified Sudan fought two civil wars. The second civil war ended with a Comprehensive Peace Agreement (CPA) between the Sudanese government and opposition forces in 2005, and the outcome of the 2011 referendum led to a newly created independent state: South Sudan. Border issues are a major source of tension between the two countries post-secession, and political dynamics in both countries pose significant security risks for the oil sector.
Sudan has experienced two civil wars since gaining independence in 1956. The second civil war ended with the help of international observers and led to the signing of the CPA by the Sudanese government and the rebel factions in the southern region in 2005. The CPA established guidelines for oil revenue sharing and a timeframe to hold a referendum for independence of the South. The southern region overwhelmingly voted for secession, and in July 2011, South Sudan became an independent nation-state that is separate from Sudan, with Juba and Khartoum as their respective capitals.6
Armed conflict in both countries has persisted in the post-referendum period, as unresolved issues on domestic and interstate relations still linger. Both countries still contest some areas around the demarcated border the CPA established. Disputes over the Abyei area and the Heglig oilfield in South Kordofan state have been particularly contentious, as the areas have strategic importance for the oil sector and agricultural resources that both countries rely on, adding another layer of complexity to the disputes.7 In January 2012, South Sudan announced that it would shut its oil production over a dispute about oil transit fees. The dispute later turned violent, as the South Sudanese army–the Sudan People’s Liberation Army (SPLA)–and Sudanese opposition forces took control of the oilfield for more than a week and destroyed critical infrastructure, which temporarily reduced Sudan’s oil production by more than 50%. The conflict was resolved in November 2012 with support from the international community, and both governments reached an agreement on oil transit fees and on compensation for lost production.8
The cooperation agreements and implementation matrix, which states the timeframe to carry out the obligations stipulated in the cooperation agreements, paved the way for restarting oil production in April 2013. According to a Business Monitor Intelligence (BMI) Research report, South Sudan currently pays Sudan US $24.50/barrel, which consists of a US $9.50/barrel transit fee and a US $15/barrel fee to cover the cost of debt repayment that is shared between the two countries.9 The drop of oil prices in 2014, however, has significantly lowered export revenues. Because South Sudan’s Dar blend trades at a significant discount to Brent, a drop in the price of Brent could significantly affect South Sudan’s fiscal position.10
Since the signing of the implementation matrix, the governments of Sudan and South Sudan shifted their focus from border conflicts to the mitigation of their respective domestic opposition factions. In September 2013, large-scale protests broke out around Sudan in response to cuts in fuel and basic commodities subsidies. The Sudanese security forces responded with violence, leading to hundreds of casualties.11 Divisions within the South Sudanese government eventually led to a civil war that still continues as of January 2018. The domestic political dynamics and the security situations in both countries directly affected negotiations on oil production and transportation and will continue to be a potential risk for disrupting the countries’ oil supplies and exports.
Petroleum and other liquids
Most of Sudan’s and South Sudan’s proved reserves of oil and natural gas are located in the Muglad and Melut Basins, which extend into both countries. Natural gas associated with oil production is mostly flared or reinjected into wells, and neither country currently produces nor consumes dry natural gas.
According to BP’s Statistical Review of World Energy, Sudan and South Sudan had 1.5 billion barrels and 3.5 billion barrels of proved oil reserves, as of January 1, 2017, respectively. Most of these reserves are located in the oil-rich Muglad and Melut basins, which extend into both countries. Oil and natural gas exploration in Sudan and South Sudan is limited outside of these basins because of the lack of evidence of prospective acreage and the persistent civil unrest affecting both countries.12 Sudan has made efforts in the past few years to boost oil production levels by attracting new investment and awarding exploration licenses to develop several blocks, but progress has been slow.13
Natural gas associated with oil fields is mostly flared or reinjected. Despite proved reserves of 3 trillion cubic feet, natural gas development has been limited. According to the latest data provided by the National Oceanic and Atmospheric Administration (NOAA) and the World Bank’s Global Gas Flaring Reduction Partnership (GGFR), Sudan emitted approximately 13.8 billion cubic feet (Bcf) of flared natural gas in 2016. From 2013 to 2016, Sudan was ranked 39th in the world for flared natural gas volume and intensity.14
Oil sector management
Prolonged sanctions against the unified Sudan allowed Asian national oil companies to dominate Sudan’s and South Sudan’s oil sectors. The China National Petroleum Corporation, India’s Oil and Natural Gas Corporation, and Malaysia’s Petronas hold large stakes in the leading consortia that operate oil fields and pipelines. Sudan and South Sudan’s national oil companies, Sudapet and Nilepet, respectively, also hold small stakes in operations.
In Sudan, three main entities oversee activities in Sudan’s petroleum sector: the Ministry of Petroleum (MOP) administers and manages the Sudanese oil sector; the Sudanese Petroleum Corporation (SPC), a fully state-owned arm of MOP, is responsible for exploration, production, and distribution of crude oil and petroleum products; and Sudapet, the national oil company, holds minority stakes in each of the international consortia operating in the oil-producing blocks. 15
In South Sudan, the administrative structure largely mirrors Sudan’s. The Ministry of Petroleum and Mining is responsible for managing South Sudan’s petroleum sector. The National Petroleum and Gas Corporation (NPGC) is the main policymaking and supervisory body and reports directly to the president and national legislative assembly; it participates in all segments of the hydrocarbon sector and approves petroleum agreements on the government’s behalf. The Nile Petroleum Corporation (Nilepet) is South Sudan’s national oil company, and its activities mirror much of the responsibilities of its Sudanese counterpart. Nilepet oversees operations in the petroleum sector, and because of its limited technical expertise and financial resources, it holds minority stakes in production-sharing contracts with foreign oil companies.16 South Sudan’s Transitional Constitution, the 2012 Petroleum Act, and the 2013 Petroleum Revenue Management Act define the regulatory framework governing the hydrocarbon sector.17
Asian national oil companies (NOCs) dominate the oil sectors in both countries. The China National Petroleum Corporation (CNPC), India's Oil and Natural Gas Corporation (ONGC), and Malaysia’s Petronas hold large stakes in the leading consortia operating in both countries: the Greater Nile Petroleum Operating Company, the Dar Petroleum Operating Company, and the Sudd Petroleum Operating Company. The lifting of U.S. sanctions against Sudan in October 2017 may provide opportunities for other foreign investors to enter the industry.
|Greater Nile Petroleum Operating Company (GNPOC)||CNPC||China||40|
|Greater Pioneer Operating Company (GPOC)||CNPC||China||40|
|Dar Petroleum Operating Company (DPOC)||CNPC||China||41|
|Sudd Petroleum Operating Company (SPOC)||Petronas||Malaysis||67.9|
|Petro Energy Operating Company (PEOC)||CNPC||China||95|
|Petrolines for Crude Oil Ltd. (Petco)||Petco||Sudan||50|
|Source: Company websites, IHS Edin, IHS Markit, BMI Research|
Crude oil production
Sudan and South Sudan have experienced frequent disruptions to oil production because of disputes over oil revenue sharing and armed conflict. Maturing oil fields and persistent violence, in conjunction with a lower oil price environment, have dampened investor confidence in spite of efforts to attract foreign investment.
Most crude oil in Sudan and South Sudan is produced in the Muglad and Melut basins. South Sudan’s secession in 2011 substantially reduced Sudan’s oil production capabilities, because most of the oil fields are located in South Sudan. Sudan brought online two small oil fields in Blocks 6 and 17 at the end of 2012, and the country is exploring offshore production in the Red Sea basin. However, progress in developing the Red Sea basin area has been slow.18 In addition, Sudan’s oilfields are reaching maturity and thus nearing depletion. Sudan is trying to mitigate declining output by using enhanced oil recovery (EOR) techniques, but the decline is expected to continue.19
The partial lifting of U.S. sanctions imposed on Sudan has led to a renewed push by the Sudanese government to attract foreign investment in the upstream sector. In November 2017, Sudan put up 15 blocks for direct negotiation, with a possible second round in February 2018. Discussions of potential development projects between the government and State Oil Canada Ltd. and Russia-based Lukoil have been reported.20
In South Sudan, the ongoing civil war and political instability have undermined its ability to increase output to peak production capacity. Low investor confidence and the poor security situation pose serious obstacles to the government’s ability to boost crude oil production, and they may need to rely on deals that are privately negotiated with smaller companies such as Nigeria-based Oranto, which secured a 90% stake in Block B321. According to a recent study conducted by the World Bank Group on unsolicited proposals in infrastructure projects, privately negotiated transactions can face significant risk of cost overruns, delays in implementation, or early termination. Transactions that are privately negotiated, as opposed to transactions that use a competitive bidding process for procurement, are also more vulnerable than to allegations of corruption, whether perceived or real, which could complicate the execution of the project.22
South Sudan and, to a lesser extent, Sudan have experienced frequent disruptions to production because of disagreements over oil revenue sharing over the past few years. Damaged infrastructure and shut-in fields stemming from conflict have lowered overall production levels, and efforts to repair infrastructure or re-start production have been delayed. In 2016, combined production from both countries was 257,000 barrels per day (b/d)â€”lower than the peak production levels of 2010 when the unified Sudan produced approximately 486,000 b/d.23 Crude oil production in Sudan and South Sudan averaged approximately 102,000 b/d and 150,000 b/d in 2017, respectively.24 It is unlikely that either country will be able to increase production without significant improvements to the security situation or an increase in foreign investment.
|Block 1||Unity, Toma, Munga||Nile||GNPOC|
|Block 2||Heglig, Bamboo||Nile||GNPOC, Petrolines|
|Block 4||Diffra, Neem||Nile||GNPOC|
|Block 6||Fula, Hadida||Fula||Petro Energy|
|Block 25||Rawat Central, Wateesh||NA||Sudapet*|
|South Sudan||Block 1||Unity, Toma, Munga||Nile||GNPOC|
|Block 2||Heglig, Bamboo||Nile||GNPOC|
|Block 4||Diffra, Neem||Nile||GNPOC|
|Block 3 & 7||Palogue, Adar-Yale||Dar||DPOC|
|Block 5||Mala, Thar Jath||Nile||SPOC|
|Source: IHS Markit, IHS Edin, Rystad, BMI Research |
Note: Star Oil exited partnership in 2016, Sudapet now sole operator
Export oil pipelines, storage, and port
Sudan has two main export pipelines that travel north across the country to the Bashayer Marine Terminal, located about 15 miles south of Port Sudan. Most of Sudan’s storage facilities for crude oil and refined products are also located at the Bashayer Terminal. The Bashayer Marine Terminal has a storage facility with a capacity of 2.5 million b/d and an export/import facility with a handling capacity of 1.2 million b/d. The terminal is operated by the GNPOC. South Sudan currently does not have any significant storage capacity.25
South Sudan exports all of its crude oil via pipeline through Sudan. Plans for the construction of a separate pipeline have been reported that would allow South Sudan to export crude oil through neighboring Kenya or Djibouti via Ethiopia and avoid transit fees.26 However, it is unlikely that the pipeline will be built, because production in South Sudan has been affected by the natural maturation of its fields and by disruptions.
Sudan and South Sudan produce three crude oil blends: Dar, Nile, and Fula. The Dar blend (25.0° API gravity, 0.11% sulfur) is a heavy paraffinic type of crude oil that has a high acid content and must be heated during transport to avoid congealing in ship tanks.27 The Dar blend is produced at Blocks 3 and 7 in the Melut Basin, which is controlled by South Sudan.28The Nile blend (33.9° API gravity, 0.06% sulfur) is produced in the Muglad Basin at Blocks 1, 2, 4, and 5A; it is a medium, low-sulfur waxy crude oil and is a more attractive blend to refiners because of its high fuel and gasoil yields.29 The Fula blend is a highly acidic crude oil that is produced in the Muglad Basin at Block 6 and is transported via pipeline to the Khartoum refinery, where it is processed for domestic use rather than for export.30
The Petrodar (PDOC) pipeline transports crude oil from Palogue and Adar Yale oil fields (Blocks 3E and 7E) in the Melut Basin to the Bashayer Marine Terminal in Port Sudan. The pipeline is approximately 850 miles long with a design capacity of 500,000 b/d, and it has several heating units to facilitate the movement of the Dar blend crude oil along the pipeline.31
The Greater Nile Petroleum Operating Company (GNPOC) pipeline transports Nile blend crude oil from the Heglig oil fields (Blocks 2 and 4) in Sudan and the Thar Jath and Mala oil fields (Block 1 and 5A) in South Sudan to the Bashayer Marine Terminal in Port Sudan for export, and to two refineries in El-Obeid and Khartoum for refining and distribution to the domestic market. South Sudan’s Thar Jath-Heglig section of the pipeline is approximately 100 miles and has a capacity of 200,000 b/d; the Heglig-Port Sudan section is approximately 930 miles long with a design capacity of 450,000 b/d.32 In September 2014, ownership of the pipeline and facilities was fully transferred to a local Sudanese pipeline operator, Petrolines for Crude Oil Ltd. (PETCO).33
|Operator||Start of pipeline||Destination||Crude oil blend|
|Aprox. length (miles)||Design capacity|
|Main crude oil pipelines|
|DPOC||Block 3 and 7||Bashayer Terminal 2, Port Sudan||Dar||850||500|
|GNPOC||Heglig facilities||Bashayer Terminal 1, Port Sudan||Nile||1000||450|
|SPOC||Block 5A||Connects to Heglig facilities||Nile||60||200|
|CNPC||Block 6||Khartoum Refinery||Fula||450||200|
|Proposed crude oil pipelines|
|--||South Sudan||Lamu (Kenya)||--||--||450|
|--||South Sudan||Djibouti via Ethiopia||--||--||--|
|Source: Company websites, IHS Markit, BMI Research, IHS Edin|
Crude oil exports
China is the leading export destination for crude oil from Sudan and South Sudan. In 2016, China accounted for 94% and 100% of Sudan’s and South Sudan’s crude oil exports, respectively.
Sudan and South Sudan export the Nile and Dar blends to Asian markets. All crude oil produced in South Sudan is exported via pipeline to Sudan for refining or export, because South Sudan has no refining capacity, and Sudan is the only country in the region with the refining infrastructure capable of processing these particular blends.34 Crude oil is exported from Port Sudan to Asia via the Bab el-Mandeb Strait. Given the lack of alternative transit routes, Bab el-Mandeb is a strategically important chokepoint that if blocked or closed could lead to significant increases in shipping time and costs.35
According to the United Nations international trade statistics database (UN Comtrade), Sudan and South Sudan exported a total of approximately 127,000 b/d of crude oil in 2016. Although this level is higher than the 65,000 b/d exported in 2012 during the production shutdown, it is lower than the 182,000 b/d exported in 2014. China is by far the largest export destination for Sudan’s and South Sudan’s crude oil, receiving almost 99% of total exports. India and Japan also import relatively small volumes of Sudan and South Sudan’s crude oil.
Sudan has two oil refineries and three topping plants (smaller, less complex refineries) with a total capacity of 143,700 b/d. However, the only active refineries are the Khartoum (al-Jaili) refinery and the El-Obeid topping plant.36 The al-Jaili refinery, located approximately 45 miles north of Khartoum, is the country’s largest, with a capacity of 100,000 b/d. The other full-conversion refinery is the Port Sudan refinery (21,700 b/d), and the three topping plants are El-Obeid (10,000 b/d), Shajirah (10,000 b/d), and Abu Gabra (2,000 b/d).37
The al-Jaili refinery initially came online in 2000 with a capacity of 50,000 b/d and was a 50/50 joint venture between the Ministry of Energy and Mining (MEM) and CNPC. It was later expanded in 2006, increasing total capacity to 100,000 b/d and creating two production lines that would allow the refining of both Nile and Fula blend crude oils. The expansion was notable for using the world’s first delayed-coking unit, a unit required to process Fula crude oil because of its high acid and calcium content. Discussions between Sudanese and Chinese officials on a proposed second expansion that could double the refinery’s capacity have been reported, but no significant progress has been made.38 Petronas signed a contract with MEM to expand the currently inactive Port Sudan refinery through a 50/50 joint venture and to add 100,000 b/d to its capacity, but development has been postponed as a result of rising costs.39
In South Sudan, two refineries were under construction: a 3,000 b/d refinery at Bentiu in the Unity State and a 10,000 b/d refinery at Thiangrial in the Upper Nile region. Plans to expand the Bentiu refinery to increase its capacity to 5,000 b/d have been reported. However, security issues have delayed the completion of the refineries, and it is unclear when or if the refineries will be operational.40
|Port Sudan||21.7||Not operating||Sudapet|
|Abu Gabra||2||Not operating||Sudapet|
|Planned refineries||Operator and/or builder|
|South Sudan||Unity State (Bentiu)||5||Under construction||Safinat (Russia)/Nilepet|
|Upper Nile (Tangrial)||10||Suspended||Government of South Sudan|
|Source: BMI Research, IHS Markit, PFC Energy, African Development Bank |
Note: The initial plan for construction at the Bentiu refinery in South Sudan was to build facilities with a capacity to process 3,000 b/d. Plans for expansion to increase capacity to 5,000 b/d have been discussed, but no progress has been made.
Oil consumption in Sudan and South Sudan peaked at 125,000 b/d in 2009 and has slightly declined to about 105,000 b/d in 2017.41 Domestic consumption of petroleum products grew rapidly with increased industrialization, car ownership, and access to electricity in the 2000s; however, the persistent instability in both states has dampened consumption.
Petroleum consumption in Sudan has been met by domestically refined crude oil, although lower production levels over the past few years have led to an increase of imported petroleum products to meet shortfalls in domestic demand. According to the latest data from the International Energy Agency (IEA), diesel and fuel oil for electricity generation, followed by gasoline for transportation, make up a significant portion of Sudan’s oil consumption, constituting 40% and 17% of total consumption in 2015, respectively. Diesel/fuel oil and gasoline make up an ever larger share of South Sudan’s oil consumption at 73% and 10% in 2015, respectively, although in absolute terms, its oil consumption has been declining.42
Total electricity generation in Sudan was 12.7 billion kilowatthours (kWh) in 2015, of which 66% was generated by hydropower.43 Although power generation has continued to grow in the post-independence era, only 45% of the population had access to electricity in 2014, according to latest estimates from the World Bank.44 Approximately 40% of the population had access to electricity in 2013, with urban populations benefitting from a substantially higher level of access than rural populations, according to the most recent estimates made by African Development Bank (AfDB). Those not connected to a grid rely on biomass or diesel-fired generators for electricity.45 Sudan has two interconnected grids, the Blue Nile and Western grids, that cover a small portion of the country. An additional fourteen centers receive service from thermal generators and local distribution networks.46
Hydroelectricity is generated from seven dams: Roseires, Sinnar, Jebel Aulia, Khashm el-Girba, Merowe, Rumela, and Burdana. The Rumela and Burdana dams, located on the Upper Atbara and Setit rivers in eastern Sudan, were brought online in 2017 and are the most recent additions in hydropower generation. According to BMI Research reports, the two dams added 320 megawatts (MW) and 15 MW to total generation capacity, respectively.47 Development of the Kajbar dam, located further north in the Nile Valley, has stalled. The dam was strongly opposed by local communities because of its potentially significant environmental impact, and no evidence of progress regarding its construction is evident. The Kajbar dam, along with two other proposed hydropower projects, the Dal and El-Shireig dams, are heavily financed by the Saudi government.48
Regarding nonhydropower generation, the 500 MW Kosti Thermal Power Plant that came online in 2016 is an oil-fired plant jointly sponsored by the Sudanese and Indian government that was constructed by India-based Bharat Heavy Electricals Ltd.49 The Sudanese government is attempting to diversify its power generation mix by focusing on developing conventional thermal plants to meet domestic energy demand. However, the proposed projects are still at an early stage and rely heavily on Saudi financing. With the significant cuts in the Saudi budget as a result of lower oil prices, the future of these plants remains in doubt. Without diversification of its power generation mix, Sudan must rely heavily on hydropower to meet domestic demand, and will be especially vulnerable to weather patterns such as a severe or sustained drought.
South Sudan has one of the lowest electrification rates in the world, with only 5% of its population having access to electricity in 2014, according to the latest estimates from the World Bank. Total electricity generation was 310 million kWh in 2015.50 Those connected to the power network experience frequent blackouts or forced load shedding, making citizens rely on standby generators to meet energy needs.51 In April 2017, the AfDB approved a supplemental loan of US $14.57 million for a project approved in 2013 that supported the state-owned utility, the South Sudan Electricity Corporation, to strengthen and expand the country’s electricity distribution networks.52 AfDB project documents state that the additional financing was needed because the original grant underestimated project costs.53
According to BMI Research, five hydropower projects have been identified as potential opportunities for development: Fula Rapids (42 MW), Grand Fula (890 MW), Shukkoli (230 MW), Lakki (410 MW), and Bedden (570 MW). However, construction has been delayed because of low investor confidence and a lack of funding.54
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It was a headline that definitely opened eyes and definitely perked up ears. News that supermajor Shell was in the process of reviewing its holdings in the largest US oil field – the onshore Permian basin – came as a shock. On one hand, why was Shell looking to sell off its assets in the prized US shale patch only months after naming it one of its nine ‘core’ upstream areas? On the other hand, the prospect of taking over Shell’s sizable acreage in the Permian has set its competitors operating in the same shale patch sniffing around for opportunities.
The answer to the former has been most influenced by a recent judgement at a court in The Hague, where Royal Dutch Shell is headquartered. The court ruled that Shell’s carbon plans – which calls for a reduction of greenhouse gas emissions to net zero by 2050 and an absolute 20% reduction by 2030 – was insufficient and not in line with the climate change goals of the Paris Agreement. Instead, the court ordered that Shell must reduce its emissions by 45% from 2019 levels by 2030, siding with environmental NGO Friends of the Earth which brought on the case by claiming that Shell was violating human rights with its current plan. Crucially, and unusually, the court applied the verdict to Shell’s entire global operations, spanning multiple jurisdictions, rather than limited to just Dutch holdings. Shell has announced plans to appeal, which could drag the process on for years in higher courts. But on the off-chance that this judgement remains binding, it is perhaps looking for ways to shave off carbon-intensive assets.
Why else would chatter suddenly surface that Shell was considering selling off its collection of prime Permian acreage located in the prolific Delaware basin? After all, just a few months ago in February, Shell announced that it was planning to reshape its upstream business to focus on nine core areas that generated 80% of its revenue – Brazil, Brunei, the Gulf of Mexico, Kazakhstan, Malaysia, Nigeria, Oman, the UK North Sea and, of course, the Permian Basin in the US. Although Shell is not among the largest Permian players, its 260,000 acres are still sizable and its output of some 60,000 b/d ranks Shell among the Permian’s 20 largest producers. Valuations suggest that the sale could fetch as much as US$10 billion, which is a lot of cash that Shell could redirect to clean energy initiatives if the aim is to conform to the court order. Because Shell is not exactly in fire-sale mode; its asset divestment program to hive off non-core assets to pay for its US$53 billion acquisition of BG Group in 2015 was already complete.
To be fair, for all the activity in the Permian, sustained profitability has proven elusive. Not just to Shell, but other major players there as well. The rapid drop-off in well productivity after the first two years means that players have to be constantly drilling and discovering, while a large-scale traditional crude oil field could last for decades after initial production. Shell is also not the only one to consider shedding assets; Chevron and ExxonMobil are also rumoured to be considering divestment as well. And why not? With crude prices at their highest point since late 2018, it is a good time to fetch the best price for oil assets. Most Permian deals in 2021 have closed at between US$7,000 and US$12,000 per acre – already a major increase from 2020 and 2019 – but Shell’s prime 260,000 acres acquired from Chesapeake Energy and Anadarko in 2012 would fetch a major premium, possibly almost as high as US$40,000/acre that would be in line with Pioneer Natural Resources’ acquisition of DoublePoint Energy in April 2021. Any sale would definitely exceed Shell’s initial investment of US$1.9 billion, fetching a tidy profit. Of course, the move would also shrink Shell’s US footprint, limiting it to the Gulf of Mexico (where the Whale field FID is expected soon) and a single oil refinery (Norco), after selling its stake in the Deer Park refining site to Pemex from an unsolicited bid.
If the sale goes through – and it is still a big if at this point – then Shell’s loss will be someone else’s gain. Who would that be? Potential bidders include ConocoPhillips, Devon Energy, Chevron, EOG Resources or even private equity firms that have not been scared off by the potential debt burden of Permian assets. Shell is likely to be looking for an all-cash deal for the entirely of the asset, but is reportedly open to also parcelling up the land into multiple packages. According to sources, a data room with full information on the assets has already been opened.
Looking at the location of Shell’s Permian assets, synergies exist with ConocoPhiliips and Chevron, which both own acreage close to the Shell holdings. Other potential buyers that operate in the Delaware region of the Permian include Occidental and EOG, with Devon Energy being the smallest company that could likely afford a purchase. But Occidental is still busy adjusting after outbidding Chevron in a blockbuster acquisition of Anadarko, which could preclude a purchase by Shell’s partner in its Permian operations. Pioneer Natural Resources might also be excluded as a potential buyer, given that it primarily focuses on the Midland region east of Delaware. But even if the desire is there, there are additional hurdles. Given the immense focus on climate change and the industries that contribute to it, capital is increasingly a challenge, since the financing of fossil fuels is under massive pressure.
Not that those hurdles are insurmountable. The pressures facing a supermajor like Shell – or even ExxonMobil and Chevron – do not necessarily apply in the same measure to other players. If Shell is willing to sell, then there will be plenty of willing buyers vying for the assets. But what is also certain is that recent climate change moves that are ongoing in the boardrooms of energy giants are starting to have very concrete implications and applications on operations. The heat fuelling merger and acquisition activity in the Permian is about to get a lot hotter.
End of Article
It cannot be said that the conversation around sustainability and carbon intensity in the energy industry happened overnight, since the topic has been a subject for over five decades. But what has changed is that there has been a major acceleration in the discussion in the last year, and even the last month. The European majors and supermajors have all adopted ambitious carbon-neutral goals – even though some jurisdictions are saying that those aren’t even enough. Over the pond, even shareholders are pushing the traditionally more reticent American giants to adopting stronger climate change goals. Nothing is more emblematic of this change that the shareholder revolt at ExxonMobil’s recent AGM, where upstart activist investor Engine No. 1 managed to oust a quarter of ExxonMobil’s board; the initial tally saw two of its candidates elected, but the final numbers showed that three of Engine No. 1’s nominees now sit on the Board of Directors with a remit to initiate climate change manoeuvres from the inside.
That sort of conversation will be jittery for a particular section of the industry: Canadian oil sands – the heavy, sandy deposits of bitumen in Alberta that provide Canada with the third-largest proven oil reserves in the world. Extracting this heavy stuff is expensive, requiring large-scale excavation and massive capital spending that only really made economic sense with the oil price boom in the late 2000s. Shipping this tarry substance is also a challenge, necessitating dilution with lighter crudes to be shipped via pipeline – which is the only major viable route to market for landlocked Alberta, sending the tarry substance all the way south to the US Gulf Coast for processing. The problem is that extracting oil sands is extremely energy-intensive – with the main culprit being steam injection to liquify the underground bitumen – that has resulted in some of the highest carbon emissions per barrel in the world. In a world racing towards net zero carbon emissions, that is quickly proving to be unacceptable.
So while the climate change debate rages on in the boardrooms of the largest energy firms, the exit has already begun from Alberta, operationally and financially. The latest moves come from Chevron, which saw its shareholders overturn the company’s recommendation to instil stricter emissions targets for its crude, and the New York State Common Retirement Fund, the third-largest in the USA. Chevron’s CEO Mike Wirth recently signaled that he was open to offloading its 20% stake in the Athabasca oil sands project, stating that even though it generates ‘pretty good cash flow without needing much capital’ it was not a ‘strategic position’. Wirth insisted that Chevron wasn’t operating on a ‘fire-sale mentality’ but would consider selling if it got ‘fair value’ – with in business-speak is basically as invitation for offers. But would those offers be forthcoming? Investors all around the world have pulled back from financing Canadian oil sands, limiting the pool of potential buyers. In April, the New York state pension fund restricted investment in six oil sands companies – Imperial Oil, Canadian Natural Resources, MEG Energy Corp, Athabasca Oil Corp, Japan Petroleum Exploration and Cenovus Energy – claiming that they ‘do not have viable plans to adapt to the low-carbon future, posing significant risks for investors’. The amount of funds (US$7 million) is a drop in the ocean for the US$248 billion pension fund, but the message it sends is loud and clear.
Taken as it is, this could be an exit. But taken as a collective movement considering divestments over the past 3 years, this is an exodus. In May 2020, Norges Bank Investment Management – the world’s largest sovereign wealth fund with over US$1 trillion in assets gleaned from Norway’s oil industry – pulled back entirely from Canadian oil sands, selling nearly US$1 billion in four major firms citing concerns over carbon emissions. While no other major pension fund has followed suit, private investors have, including titan BlackRock that has begun to exclude oil sands from its major funds Financing is also proving tricky, with a string of major banks – including HSBC, ING and BNP Paribas – either paring back or stopping lending entirely to the industry; the insurance industry is also pulling back, with The Hartford stopping investing or insuring of the Alberta crude oil industry.
These high-profile investment and financing moves have dimmed the shimmer of an industry that was never that clean to begin with. But what will hurt is the pullback of upstream players, which hollows out the pool of companies left to exploit what is an increasingly unattractive asset. Before Chevron even contemplate its sale, Shell already sold its assets in 2017 for US$8.5 billion and ConocoPhillips offloaded to Cenovus Energy as part of a broader sale including gas assets for US$13.3 billion, also in 2017. Norway’s Equinor, too, has liquidated its position. Then in February 2021, ExxonMobil dropped a bombshell – effectively eliminating every drop of oil sands crude from its worldwide reserves, a tacit admission that oil sands would not form part of its upstream focus (at least at current prices) for the foreseeable future, especially with more attractive propositions in Guyana and the Permian. Given its recent shareholder revolt, it is unlikely that oil sands will be back on the menu ever.
The players in Alberta are trying to fight back. Having been consolidated in less than a dozen major players – from oil sands specialists to more integrated players such as Suncor – the industry is trying to rally institutional support, stating that traditional industry is still necessary to build the clean energy industries of the future. Suncor’s CEO Mark Little puts it this way: ‘this is way more complicated (than its seems)… the wind farm can’t be the solution to every problem. It’s not. So we need to find innovative solutions.” The oil sands patch’s biggest players are also banding together to form an alliance to achieve net-zero greenhouse gas emissions by 2050 – similar to the goals of most energy majors – as it tries to convince not just the world, but also Canada’s own government that Alberta has a continued role in the country’s energy transition. Efforts include linking facilities in Ford McMurray and Cold Lake to a carbon sequestration hub, expanding carbon capture and storage technology, accelerating clean hydrogen and other clean technologies such as direct air capture and fuel switching. The timeframe and viability of this is critical, given that Prime Minister Justin Trudeau has already announced plans to raise Canada’s carbon price steeply to accelerate its energy transition.
Those are bold plans and bold ambitions. But will it be enough? Can the exodus be stemmed? Or will the industry be whittled down to a handful of local players isolated from the wider energy world, removed from climate change engagement completely? It is difficult to tell at this point, but at the very least, things are starting to move in the right direction. Even if the pace is as slow as the crude sludge mined in Alberta.
End of article
- Crude price trading range: Brent – US$71-73/b, WTI – US$69-71/b
- Confidence in the crude markets has vaulted global price benchmarks to their highest level in two years, with both Brent and WTI exceeding the US$70/b psychological level
- Underpinning this rally are signs that vaccinations are boosting economic activity, with the likelihood of some travel and hospitality sectors reopening fully across the northern hemisphere’s summer, while crude marker indication show tightness in the market
- That will reinforce OPEC+’s position to ease its supply quotas from July onwards, with club’s goal likely to be keeping prices around US$70/b – a level that should stabilise internal finances and budgets for most member countries.
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It is only 5 months into 2021, and already Bloomberg estimates that merger and acquisition (M&A) activity in the US shale patch has more than doubled over the equivalent period in 2020 to over US$10 billion. Given that Covid lockdowns sapped energy from shale drilling from March 2020 and what was left was decimated again in April 2020 when US WTI prices (briefly) collapsed into negative territory. From this point onwards, it may not take much to maintain this doubling of M&A activity in the US shale patch over the next 7 months. But don’t call this a new trend; call it what it is: the inexorable centralisation of US shale as the long freewheeling Wild West years give way to corporate consolidation.
Even before Covid had been unleashed upon an unsuspecting world, this consolidation was already in full swing. When the US shale revolution first began accelerating in the early 2010s – when crude oil prices were high and acreage was cheap – there were thousands, maybe even tens of thousands, of small independent drillers vying alongside medium and large upstreamers busy striking riches across American shale basins such as Bakken, Eagle Ford, Marcellus and, of course, the Permian. But too many cooks spoiled the soup. The US shale drillers who were acting capitalistically without concern for discipline incurred the wrath of OPEC and caused the oil price bust in 2014/2015. For larger players were deep pockets and wide portfolios, the shock could be absorbed. But for the small, single field or basin players, it was bankruptcy staring them in the face. The sharp natural productivity dropoff of shale fields after initial explosive output meant profits had to be made super quick and super fast; if debt kept mounting up, then drillers must keep pumping to merely stay alive. But there is another option: merge or acquire. And so those thousands of players started dwindling down to hundreds.
But it wasn’t enough. Even though crude prices began to recover from 2016, it never again reached the dizzying levels of the boom years. Debt accumulated turned into debt to be repaid. And the financial community got wiser. Instead of being blinded by the promise of shale volumes, investors and shareholders started demanding value and dividends. Easy capital was no longer available to a small shale driller. And because of that no new small shale drillers emerged. Instead, the big boys arrived. Because shale oil and gas still held vast potential, the likes of ExxonMobil, Shell and Chevron started moving in. ExxonMobil went as far as calling the Permian its ‘future’ (though this was in the days before its super discoveries in Guyana were announced). With consolidation came cohesion. Instead of a complicated patchwork of small plots, a US shale operator’s modus operandi was now to look to its left or right for land that someone else owned which could be stitched up into its own acreage forming a contiguous asset. And so those hundreds of players started becoming dozens.
In late 2020, this drive ratcheted up as the prolonged Covid-caused fuels depression freed up plenty of candidates for deep-pocketed players. ConocoPhillips bought Concho Resources for US$9.7 billion. Pioneer Natural Resources snapped up Parsley Energy for US$4.5 billion. Chevron closed its US$5 billion acquisition of Noble Energy (after failing to acquire Anadarko after being outbidded by Occidental Petroleum in 2019), while Devon Energy snapped up WPX Energy for US$2.56 billion. All four were driven by the same motive – to expand foothold and stitch up shale assets (particularly in the Permian). This series of M&As rejigged the power balance in the Permian, propelling the four buyers into the top eight producers in the basin, joining Occidental, EOG, ExxonMobil and Chevron. These top eight Permian producers now have output of over 250,000 b/d, accounting for nearly 60% of the basin’s 4.5 mmb/d output.
You would think that this trend would continue until the Permian Big Eight became the Permian Big Four for Five. And this could still happen. But the latest M&A activity from a major Permian player suggests that the ambition may well be too constrained. Cimarex Energy, the tenth largest player in the Permian with output of some 100,000 b/d, just entered into a merger to create a US$17 billion Houston-based shale driller. But its partner was not, say, fellow Permian buddy SM Energy (80,000 b/d) or Ovintiv (75,000 b/d). Instead, Cimarex chose Cabot Oil & Gas, a gas-focused player that operates almost entirely in the Marcellus shale basin in Appalachia, over 1500km away from the Permian.
In response to the merger, share prices of both Cimarex and Cabot fell. Analysts cited a dilution of each company’s core focus (along with the meagre premium) as concerns; implying that investors would be happier if Cimarex stayed and grew in the Permian, and Cabot did the same in Marcellus. But that’s a narrow way of thinking that both Cimarex and Cabot were happy to refute. “This is a long term move,” said Cimarex CEO Tom Jorden. “This combination allows us to be ready for those (swings in commodity prices)”.
While pursuing in-basin opportunities could make shareholders happy in the short-term, a multi-basin deal might be a surprise but is also a canny long-term move. After all, at some point the Permian will run out of oil. And so will gas in Marcellus. Or the US government could accelerate its move away from fossil fuels. If an energy company puts all of its eggs into one basket – or basin, in this case – then when the river runs dry, the company’s profits evaporate. It is a consideration that other single-basin focused players like Pioneer, EOG and Diamondback will need to start thinking about, which is a luxury that other integrated players with Chevron and ExxonMobil already have. Consolidation in American shale basins is inevitable. But what is far more interesting is the new potential of cross-basin consolidation.