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Last Updated: November 8, 2019
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Overview

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.[1]

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.[2] 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).[3]

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.[4] 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.

Sector organization

  • 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 state–owned Sudanese Petroleum Corporation (SPC) was dissolved in March 2019, by order of Prime Minister Mohamed Tahir Ayala, and all assets and employees were transferred to the Ministry of Petroleum. The SPC was responsible for the exploration, production, and distribution of crude oil and petroleum products. The reason for the dissolution of the SPC has not yet been released.[5]


Petroleum and other liquids

Exploration and production

  • The 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 during the past few years, but Sudan has not made any substantial progress toward developing new fields that would lead to increased production.
  • In March 2019, an offer of 10 oil and natural gas exploration blocks in the Red Sea’s Halayeb triangle sparked a dispute between Egypt and Sudan. Egypt controls the territory, but Sudan has claimed the territory as Sudanese since the 1950s.[6]
  • South Sudan has restarted production at some of its previously shut-in fields in the Toma South and Unity fields in September 2018 and January 2019, providing a marginal increase to its total production. South Sudan seeks to increase total production to more than 200,000 b/d by the end of 2019. However, uncertainty remains on whether Sudan can do so under the export licensing restrictions the U.S. Department of State imposed on South Sudan’s Ministry of Energy, Nilepet (the National Oil and Gas Corporation of South Sudan), and the three major oil field operators in the country: DPOC, GPOC, and SPOC.[7] The licensing restrictions hinder the operators’ ability to secure the equipment and services required to develop or re-start production at its fields.[8]
  • In 2018, the government withdrew from negotiations to explore and develop blocks B1 and B2, and it is reportedly in talks with CNPC to acquire the blocks.[9]

Midstream infrastructure

  • 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 through Ethiopia to avoid transit fees.[10] However, the pipeline is not likely to be built in the near future because of the overall weak security environment and resulting supply disruptions to crude oil production in South Sudan.

Refining and refined oil products

  • Discussions between Sudanese and Chinese officials on a proposed second expansion to the refinery in Khartoum that could double the refinery’s capacity have been reported, but no significant progress has been made.[11]
  • Petronas signed a contract with the Ministry of Energy and Mining to expand the 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.[12]
  • 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 completion, and unclear when or if the refineries will be operational is unclear.[13]

Petroleum and other liquids exports

  • According to ClipperData, Sudan and South Sudan exported about 114,000 b/d of crude oil in 2018. 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 the largest export destination for Sudan’s and South Sudan’s crude oil. China received almost 60% of both countries’ total exports in 2018, although the total volume of exports has declined during the past few years. India and the United Arab Emirates have also imported relatively small volumes of Sudan and South Sudan’s crude oil.



Natural gas

  • 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 estimates provided by the National Oceanic and Atmospheric Administration (NOAA), Sudan flared about 13.5 billion cubic feet of natural gas in 2017.[14]



Energy consumption

  • Petroleum consumption in Sudan and South Sudan peaked at 140,000 b/d in 2016 and has remained steady since then.[15]
  • In 2016, total primary energy consumption in Sudan was 0.357 quadrillion British thermal units (Btu) and in South Sudan was 0.017 quadrillion Btu, according to latest estimates. About 80% of total primary energy consumption in Sudan is derived from petroleum and other liquid fuels, and the remainder comes from renewables such as biomass. In South Sudan, nearly all of the primary energy consumption was from petroleum and other liquid fuels.[16]


Electricity

Sudan

  • Total electricity generation in Sudan was 14 billion kilowatthours (kWh) in 2016, of which 57% was generated by hydropower.[17]
  • Although power generation has continued to grow in the post-independence era, only 39% of the population had access to electricity in 2016, according to latest estimates from the World Bank.[18] Urban populations benefit from a substantially higher level of access than rural populations, according to the most recent estimates from the African Development Bank (AfDB). People who are not connected to a grid rely on biomass or diesel-fired generators for electricity.[19]
  • Given its heavy reliance on hydropower to meet its electricity needs, the government of Sudan has sought to diversify its power portfolio mix with thermal and even nuclear power sources. However, it is uncertain whether there will be significant progress towards constructing power plants utilizing these fuel types.[20]

South Sudan

  • Total electricity generation in South Sudan was 0.4 billion kWh in 2016, nearly all of which was generated by crude oil.[21]
  • South Sudan has one of the lowest electrification rates in the world; only 9% of its population had access to electricity in 2016, according to the latest estimates from the World Bank.[22]
  • In 2018, the government of South Sudan commissioned a 100 megawatt (MW) thermal power plant in Juba, which could potentially meet a substantial portion of the country’s electricity needs. The plant is expected to reduce consumption of heavy fuel, upon which generators, the primary source of electricity in the country, rely.[23]
  • The government of South Sudan signed an agreement with the government of Uganda in October 2017 to construct an interconnection line between the two countries. The line will connect the electricity grid in Kampala, the Ugandan capital, and supply electricity to Kaya and Nimule, two of South Sudan’s border towns. The agreement is reportedly in line with the East African Power Pool agreement and should address the serious lack of access to electricity in the remote and rural areas of South Sudan.[24]


Renewable Energy Sources

Hydroelectricity

  • 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 there has been no sign of progress on its construction. The Kajbar dam, along with two other proposed hydropower projects, the Dal and El-Shireig dams, are heavily financed by the Saudi government.[25]
  • 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 a lack of funding.[26]


Sudan South Sudan petroleum production supply oil products natural gas electricity renewable energy
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January, 24 2020
EIA expects U.S. net natural gas exports to almost double by 2021

In its Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that U.S. natural gas exports will exceed natural gas imports by an average 7.3 billion cubic feet per day (Bcf/d) in 2020 (2.0 Bcf/d higher than in 2019) and 8.9 Bcf/d in 2021. Growth in U.S. net exports is led primarily by increases in liquefied natural gas (LNG) exports and pipeline exports to Mexico. Net natural gas exports more than doubled in 2019, compared with 2018, and EIA expects that they will almost double again by 2021 from 2019 levels.

The United States trades natural gas by pipeline with Canada and Mexico and as LNG with dozens of countries. Historically, the United States has imported more natural gas than it exports by pipeline from Canada. In contrast, the United States has been a net exporter of natural gas by pipeline to Mexico. The United States has been a net exporter of LNG since 2016 and delivers LNG to more than 30 countries.

In 2019, growth in demand for U.S. natural gas exports exceeded growth in natural gas consumption in the U.S. electric power sector. Natural gas deliveries to U.S. LNG export facilities and by pipeline to Mexico accounted for 12% of dry natural gas production in 2019. EIA forecasts these deliveries to account for an increasingly larger share through 2021 as new LNG facilities are placed in service and new pipelines in Mexico that connect to U.S. export pipelines begin operations.

Net U.S. natural gas imports from Canada have steadily declined in the past four years as new supplies from Appalachia into the Midwestern states have displaced some pipeline imports from Canada. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.

U.S. pipeline exports to Mexico increased following expansions of cross-border pipeline capacity, averaging 5.1 Bcf/d from January through October 2019, 0.5 Bcf/d more than the 2018 annual average, according to EIA’s Natural Gas Monthly. The increase in exports was primarily the result of increased flows on the newly commissioned Sur de Texas–Tuxpan pipeline in Mexico, which transports natural gas from Texas to the southern Mexican state of Veracruz. Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020:

  • Pipelines in Central and Southwest Mexico (1.2 Bcf/d La Laguna–Aguascalientes and 0.9 Bcf/d Villa de Reyes–Aguascalientes–Guadalajara)
  • Pipelines in Western Mexico (0.5 Bcf/d Samalayuca–Sásabe)

U.S. LNG exports averaged 5 Bcf/d in 2019, 2 Bcf/d more than in 2018, as a result of several new facilities that placed their first trains in service. This year, several new liquefaction units (referred to as trains) are scheduled to be placed in service:

  • Trains 2 and 3 at Cameron LNG in Louisiana
  • Train 3 at Freeport LNG in Texas
  • Trains 5–10, six Moveable Modular Liquefaction System (MMLS) units, at Elba Island in Georgia

In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d (baseload) and 10.8 Bcf/d (peak). EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.

monthly natural gas trade

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

January, 24 2020
EIA forecasts U.S. crude oil production growth to slow in 2021

In the January 2020 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that U.S. crude oil production will average 13.3 million barrels per day (b/d) in 2020, a 9% increase from 2019 production levels, and 13.7 million b/d in 2021, a 3% increase from 2020. Slowing crude oil production growth results from a decline in drilling rigs during the past year that EIA expects will continue through most of 2020. Despite the decline in rigs, EIA forecasts production will continue to grow as rig efficiency and well-level productivity rise, offsetting the decline in the number of rigs until drilling activity accelerates in 2021.

Figure 1. U.S. crude oil production

EIA’s U.S. crude oil production forecast is based on the West Texas Intermediate (WTI) price forecast in the January 2020 STEO, which rises from an average of $57 per barrel (b) in 2019 to an average of $59/b in 2020 and $62/b in 2021. The price forecast is highly uncertain, and any significant divergence of actual prices from the projected price path could change the pace of drilling and new well completion, which would in turn affect production.

Crude oil production in the Lower 48 states has a relatively short investment and production cycle. Changes in Lower 48 crude oil production typically follow changes in crude oil prices and rig counts with about a four- to six-month lag. Because EIA forecasts WTI prices will decline during the first half of 2020 but begin increasing in the second half of the year and into 2021, forecast U.S. crude oil production grows slowly month over month until the end of 2020. In contrast, crude oil production in Alaska and the Federal Offshore Gulf of Mexico (GOM) is driven by long-term investment that is typically less sensitive to short-term price movements.

In 2019, Lower 48 production reached its largest annual average volume of 9.9 million b/d, and EIA expects it to increase further by an average of 1.0 million b/d in 2020 and 0.4 million b/d in 2021. EIA forecasts the GOM region will grow by 0.1 million b/d in 2020 to 2.0 million b/d and to remain relatively flat in 2021 because several projects expected to come online in 2021 will not start producing until late in the year and will be offset by declines from other producing fields. Alaska’s crude oil production will remain relatively unchanged at about 0.5 million b/d in 2020 and in 2021.

The Permian region remains the most prolific growth region in the United States. Favorable geology combined with technological improvements have contributed to the Permian region’s high returns on investment and years of remaining oil production growth potential. EIA forecasts that Permian production will average 5.2 million b/d in 2020, an increase of 0.8 million b/d from 2019 production levels. For 2021, the Permian will produce an average of 5.6 million b/d. EIA forecasts that the Bakken region in North Dakota will be the second-largest growth area in 2020 and 2021, growing by about 0.1 million b/d in each year (Figure 2).

Figure 2. Monthly U.S. crude oil production by region

EIA expects crude oil prices higher than $60/b in 2021 will contribute to rising crude oil production because producers will be able to fund drilling programs through cash flow and other funding sources, despite a somewhat more restrictive capital market. Financial statements of 46 publically-traded U.S. oil producers reveal that these companies generated sufficient cash from operating activities to fund investment and grow production with WTI prices in the $55/b–$60/b range. The 46 selected companies produced more than 30% of total U.S. liquids production in the third quarter of 2019. The four-quarter moving average free cash flow for these companies ranged between $1.7 billion and $3.5 billion from the fourth quarter of 2017 through the second quarter of 2019. The third quarter of 2019—the latest quarter for which data are available—had less cash from operations than investing activities, but this figure was skewed by the large, one-time acquisition cost of Anadarko Petroleum by Occidental, valued at $55 billion (Figure 3).

Figure 3. Cash flow statement items for 46 U.S. oil producers

Results for these 46 publicly traded companies do not represent all U.S. oil producers because private companies that do not publish financial statements are not included in EIA’s analysis. The Federal Reserve Bank of Dallas Energy Survey sheds some light on the financial position of a broader set of companies. Released quarterly, the bank’s survey asks oil companies about business activity and employment and asks a few special questions that change each quarter. The number of companies that participate varies each quarter, but generally the survey includes about 100 exploration and production companies. In the most recent survey (from the fourth quarter of 2019), 75% of survey respondents said they can cover their capital expenditures through cash flow from operations at a WTI price of less than $60/b. In addition, 40% of survey respondents plan to increase capital expenditures in 2020 compared with 2019, while 24% of respondents expect to spend about the same (Figure 4).

Figure 4. Selected questions from the Federal Reserve Bank of Dallas' Energy Survey

Since about 2017, large, globally integrated oil companies have acquired more acreage in Lower 48 regions, particularly in the Permian. These companies have announced investment plans to make Lower 48 production an increasing portion of their portfolios. These companies can typically fund their investment programs through cash flow from operations and are generally less susceptible to tighter capital markets than smaller oil companies. The financial results of the public companies shown in Figure 3 and the Federal Reserve survey support EIA’s production forecast and suggest that U.S. crude oil production can continue to grow under EIA’s price forecast for 2020 and 2021 because many companies are less dependent on debt or equity to fund investment.

U.S. average regular gasoline and diesel prices decline

The U.S. average regular gasoline retail price fell more than 3 cents from the previous week to $2.54 per gallon on January 20, 29 cents higher than the same time last year. The Midwest price fell over 5 cents to $2.39 per gallon, the Gulf Coast price fell nearly 5 cents to $2.23 per gallon, the Rocky Mountain price fell more than 3 cents to $2.57 per gallon, the East Coast price fell more than 2 cents to $2.50 per gallon, and the West Coast price fell nearly 2 cents to $3.18 per gallon.

The U.S. average diesel fuel price fell nearly 3 cents from the previous week to $3.04 per gallon on January 20, 7 cents higher than a year ago. The Rocky Mountain price fell nearly 6 cents to $3.01 per gallon, the East Coast price fell nearly 4 cents to $3.08 per gallon, the Midwest price declined almost 3 cents to $2.94 per gallon, the West Coast price fell nearly 2 cents to $3.57 per gallon, and the Gulf Coast price dropped more than 1 cent to $2.80 per gallon.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 1.4 million barrels last week to 86.5 million barrels as of January 17, 2020, 17.1 million barrels (24.6%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, East Coast, Gulf Coast, and Rocky Mountain/West Coast inventories decreased by 0.7 million barrels, 0.4 million barrels, 0.2 million barrels, and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 6.9% of total propane/propylene inventories.

Residential heating fuel prices decrease

As of January 20, 2020, residential heating oil prices averaged nearly $3.07 per gallon, 3 cents per gallon below last week’s price and 10 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged almost $1.96 per gallon, more than 7 cents per gallon below last week’s price and more than 7 cents per gallon lower than a year ago.

Residential propane prices averaged almost $2.01 per gallon, less than 1 cent per gallon below last week’s price and more than 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.60 per gallon, nearly 4 cents per gallon lower than last week’s price and 20 cents per gallon below last year’s price.

January, 24 2020