Gasoline prices in California have increased by a total of 60 cents per gallon (gal) in the past three weeks, according to data in the U.S. Energy Information Administration’s (EIA) Gasoline and Diesel Fuel Update. Regular retail gasoline prices averaged $4.09/gal as of Monday, October 7, the highest price for the state since mid-2014. Several refineries in the area are experiencing operational issues, which has limited gasoline production.

Gasoline prices in California are now $1.45/gal more than the U.S. average and $0.45/gal more than the West Coast average, the largest difference in these prices in EIA’s data series dating back to May 2000.

The West Coast region is a relatively tightly balanced petroleum market, so any supply disruptions tend to have larger price effects than similar issues elsewhere in the country. California also has more stringent transportation fuel regulations and higher transportation fuel taxes than most of the country, which contribute to its higher gasoline prices.

EIA’s study on West Coast Transportation Fuels Markets examined the gasoline, diesel, and jet fuel markets in the region. Although that study was released in 2015, most of the factors affecting West Coast markets have not changed significantly in the past four years.

After declining for several weeks, West Coast gross refinery inputs (refinery runs) fell to 2.24 million barrels per day (b/d) in the week ending September 27—the lowest weekly value since late October 2016—according to EIA’s Weekly Petroleum Status Report. In the following week, West Coast refinery runs rose to 2.51 million b/d, suggesting that some refineries may be returning to normal operation. West Coast refinery inputs were also relatively low earlier this year following several planned and unplanned refinery outages.

California’s recent gasoline price increase is the largest weekly change since 2015 when an explosion at the Torrance refinery and several subsequent disruptions led to higher gasoline prices in the state. California’s more stringent fuel specifications make replacing disrupted supply difficult.

Few other refineries in the United States are configured to produce the motor gasoline that meets California's specifications, so regional inventories and imported volumes are used to close the gap when refinery production is low. Following the outage at Torrance, California’s motor gasoline imports increased to more than 10 times its typical level.

As part of the weekly Gasoline and Diesel Fuel Update, EIA surveys gasoline and diesel prices to produce point-in-time prices as of each Monday morning at 8:00 a.m., local time. EIA publishes these values on the same Monday afternoon, making the Gasoline and Diesel Fuel Update one of the few same-day data series provided by a statistical agency of the U.S. government. EIA’s weekly gasoline price survey provides data for 10 U.S. metropolitan areas, 9 states, 5 U.S. regions (Petroleum Administration for Defense Districts), and 4 subdistricts.

Principal contributors: Owen Comstock, Hannah Breul

http://go.usa.gov/xVeGf

Tracking progress

Since 2000, HDV energy consumption and tailpipe CO 2 emissions have expanded by about 2.2% per year, and trucks account for more than 80% of this growth. In the near term, vehicle efficiency standards, together with co‑ordinated efforts by multiple stakeholders to improve logistics and operational efficiency, are needed to dampen this growth. Building upon recent momentum, rapid adoption of battery electric buses and trucks in cities will not only reduce energy consumption but also cut local pollutant and CO 2 emissions. Finally, heavy-duty trucks with regional and long-haul missions, which account for three-quarters of HDV fuel consumption, will need to transition to low-carbon alternative fuels and powertrains. Options include electrification and hydrogen fuel-cell electric vehicles (EVs), advanced biofuels and electrofuels. Rising emissions and energy use are driven primarily by strong economic activity and increased demand for goods, which translates into more delivery and more trucking activity. However, in contrast with strong policy coverage for LDVs (about 85% of cars and light commercial vehicles sold in 2018 were covered by fuel economy standards), vehicle efficiency regulations currently cover only about half of the heavy-duty market.

Share of sales in countries with adopted fuel economy (and/or GHG/CO2) standards Efficiency policy coverage for trucks and other HDVs is ten years behind that of LDVs 

Source: New vehicle registrations as tracked in the IEA Mobility Model (May 2019 version). For light-duty vehicles, fuel economy policy coverage is tracked by the Global Fuel Economy Initiative (GFEI).

Despite the shift away from diesel cars following the Volkswagen emissions scandal, diesel remains the main fuel for HDVs. In fact, the share of diesel in oil-based road fuels consumed rose from 38% in 2000 to 44% in 2018, largely due to growing road freight activity.

Policy developments Substantial progress has been made recently in establishing vehicle efficiency and CO 2 emissions standards for HDVs. India put new HDV fuel economy standards in place in April 2018, raising policy coverage of new bus and truck sales to around half.

put new HDV fuel economy standards in place in April 2018, raising policy coverage of new bus and truck sales to around half. In January 2019, trucks in the four classes that account for the majority of HDV emissions and fuel consumption, with a gross vehicle weight (GVW) of more than 7.5 tonnes and produced for sale in the European Union , became subject to mandatory monitoring and reporting of fuel consumption and CO 2 emissions using the Vehicle Energy consumption Calculation TOol (VECTO). In February, the European Parliament and the Council reached a provisional agreement to reduce the average specific fuel consumption of regulated classes of new trucks by 15% in 2025 and 30% in 2030 (compared with the July 2019-June 2020 reference period). This will be the baseline for HDV CO 2 emissions standards in the European Union and will raise coverage of all HDVs sold globally to an estimated 55% in 2019. The 2030 target is binding but subject to review in 2022.

, became subject to mandatory monitoring and reporting of fuel consumption and CO emissions using the Vehicle Energy consumption Calculation TOol (VECTO). In February, the European Parliament and the Council reached a provisional agreement to reduce the average specific fuel consumption of regulated classes of new trucks by 15% in 2025 and 30% in 2030 (compared with the July 2019-June 2020 reference period). This will be the baseline for HDV CO emissions standards in the European Union and will raise coverage of all HDVs sold globally to an estimated 55% in 2019. The 2030 target is binding but subject to review in 2022. China’s Phase III standards, which take effect in July 2019, will begin raising the efficiency of new buses and trucks sold in the world’s largest HDV market.

Phase III standards, which take effect in July 2019, will begin raising the efficiency of new buses and trucks sold in the world’s largest HDV market. Japan updated its fuel efficiency standards for trucks and buses on 29 March 2019. Setting 2025 as the target year and 2015 as the base year, the standards mandate efficiency improvements of 13.4% for trucks and 14.3% for buses.

updated its fuel efficiency standards for trucks and buses on 29 March 2019. Setting 2025 as the target year and 2015 as the base year, the standards mandate efficiency improvements of 13.4% for trucks and 14.3% for buses. Brazil, Mexico and South Korea are in various stages of developing policies to improve the efficiency of their HDV fleets. Since the US Environmental Protection Agency (EPA) introduced its flagship SmartWay programme in 2004, more than 30 countries have established green freight programmes (GFPs) or have joined regional or global GFPs. Fuel economy regulations and GFPs complement each other well, with the former setting minimum thresholds for vehicle efficiency performance and GFPs promoting business and operational efficiency as well as efficient technologies and best practices. In 2017, Chile became the latest country to establish a national GFP, the Giro Limpio.

became the latest country to establish a national GFP, the Giro Limpio. Argentina has set up a road freight efficiency pilot programme (the Programa Transporte Inteligente) and is in the initial phases of putting together its own GFP.

Electrification Urban buses are one of the great success stories of rapid EV market uptake. Leveraging the suitability of their fixed routes and schedules, their frequent stops and municipalities’ ambitions to reduce local air pollution, as well as the longer-term investment portfolios of (certain) municipal fleet managers, a market for electric buses emerged quickly. China has led the way in bringing domestically made batteries and buses to market, first to Chinese cities (Shenzhen became the global model when it transitioned entirely to electric city buses within only a few years) and increasingly to European and Latin and North American ones. Commercial trucks operating in urban environments, especially those belonging to large, well-co‑ordinated fleets and logistics services, may be the next to electrify. Long-term payback of initial capital investments, together with the need to address broad sustainability issues such as tailpipe pollutant and CO 2 emissions, may incite these fleets to electrify even more quickly than privately owned cars. City-level efforts to contain air pollution, including targets for phasing out diesel and internal combustion engines, together with corporate efforts to anticipate and take the lead on pressing public issues, will further spur EV adoption for light-duty commercial fleets. For a GVW of less than 16 tonnes, an increasingly wide selection of all-electric trucks is reaching the market. In fact, major postal and package delivery companies, including DHL, UPS and FedEx, are expanding their fleets, and the Swiss and Austrian postal services have pledged to transition to all-electric fleets by 2030 or earlier. Meanwhile, momentum continues in the demonstration and commercialisation of zero-emission trucks – the majority of which are also electric. With greater battery capacity, the GVW and range thresholds for electric vehicles continue to rise. In addition to leading in electrifying buses, light commercial vehicles, and even medium-duty trucks, China has introduced fleets of hydrogen fuel-cell electric trucks and buses, most of which operate on reliable routes and refuel centrally at a single station. In stepping beyond demonstrating small fleets of zero-emission HDVs, China has moved ahead of the rest of the world into uncharted territory. South Korea and Japan also have ambitious plans to use hydrogen fuel cell technology in the heavy-duty subsector.

Zero-emission medium- and heavy-freight trucks The number of zero-emission trucks in production and customer testing continues to grow rapidly.

For classes of trucks greater than 16 tonnes, most manufacturers have partnered with customers to test real-world operations. The experiences of major haulers in accommodating the constraints and leveraging the advantages of electric drive will help in identifying technologies and use cases with competitive value relative to conventional diesel trucks. Demonstration projects of fully battery electric trucks, as well as of dynamic charging and Electric Road System (ERS) concepts, also continue to gain momentum, and the performance and economics of both the vehicles and the demonstrations are improving steadily.

Recommended actions

While the scope of efficiency and emissions regulations is being expanded, it will be increasingly important to continuously test the limits of possibility for efficiency technologies.

Vehicle efficiency standards As HDV efficiency standards will need to be introduced in countries where they do not yet exist, a clean transport task group of the G20 is helping countries begin to benchmark current technologies, categorise truck and bus operations, and use models such as VECTO and the Greenhouse Gas Emissions Model (GEM) to obtain the information necessary to design regulations. Meanwhile, countries that already have standards in place will need to make them more stringent to cut emissions further; China in particular would benefit from stronger Phase III standards.

Policies for zero-emission vehicles Policies also need to stimulate the adoption of zero-emission vehicle technologies. EU regulators considered using either super credits or a zero- and low-emission vehicle (ZLEV) mandate, both of which would ultimately reward manufacturers of zero- and low-emission trucks and buses by relaxing HDV CO 2 emissions standards. They ultimately adopted a super-credit system through 2024, and a benchmark that relaxes fuel economy standards for manufacturers achieving a 2% market share of ZLEVs after 2025, but it is capped at 3%. While in principle such schemes promote market adoption of electric and hydrogen trucks, if they are not designed to consider the variability within heavy-duty vehicle segments, they may actually compromise the efficacy of emissions standards. It is crucial that standards take into account the unevenness of electrification potential (in the absence of policies) and of differing emissions implications among segments. For instance, urban buses and municipal fleets are likely to electrify rapidly, but since most emissions come from regional and long-haul trucking, providing too many credits to manufacturers of electric urban buses and municipal trucks is likely to arbitrarily reward certain manufactures while diluting the effect of the standards.

Extending regulations to trailers Finally, regulations will need to extend beyond trucks to the trailers they pull. Canadian and US second-phase GHG emissions standards are the first in the world to regulate trailer emissions, and although the United States has temporarily suspended this component of its legislation, Canada’s has gone forward.

Innovation gaps

With the exception of the long-range Tesla semi variant and the prototype Nikola trucks, the range of zero-emission trucks is limited to below 600 kilometres. Together with the time required to recharge depleted batteries (or the high amperage, voltage, and power draw requirements of very fast charging), this points to the need for alternative infrastructure and operational models for long-haul trucking. To date, three competitors seem most promising: dynamic charging on Electric Road System (ERS) corridors; continuing improvements in the performance, capacity, and costs of advanced lithium batteries; and hydrogen.

Cost-competitive hydrogen fuel cell systems for FCEVs There are two main types of zero-emissions vehicles: BEVs and FCEVs. Because of the long charging time and short range of EVs, FCEVs hold promise as a complementary technology, but they remain costly and their availability is limited. Transport modes such as trucks, buses, maritime and locomotive applications, may particularly benefit from fuel cell rather than pure electric, battery-based drivetrains. Several steps can be taken to reach cost targets: reduce precious metal use by downsizing the fuel cell stack; boost production of fuel cells and all ancillary components to obtain economy-of-scale cost reductions; and deploy targeted refuelling infrastructure tailored to specific modes and applications. Read more about this innovation gap →

Deploying Electric Road System (ERS) corridors With the exception of the long-range Tesla semi variant and the prototype Nikola trucks, the range of zero-emission trucks is limited to below 600 kilometres. Together with the time required to recharge depleted batteries (or the high amperage, voltage, and power draw requirements of very fast charging), this points to the need for alternative infrastructure and operational models for long-haul trucking. To date, three competitors seem most promising: dynamic charging on Electric Road System (ERS) corridors, continuing improvements in the performance, capacity, and costs of advanced lithium batteries, and hydrogen. Read more about this innovation gap →

Improving the cost and performance of lithium-ion batteries For trucks operating on regional delivery and long-haul segments, the suitability of electrification will depend upon continuing energy density improvements and cost reductions in lithium-based batteries. There is a broad consensus that the ‘floor’ costs of current lithium-ion technologies may be around 80 USD/kWh. Going beyond that threshold is necessary in the SDS after around 2030, and will require the development of technologies that are currently in very early stages of development. In long-haul, heavy-duty applications, gravimetric energy density is an important performance criterion on which advanced lithium-ion batteries will have to continue to improve in order to compete with fossil (diesel and natural gas) powered trucks. Advanced solid state chemistries may be able to achieve energy densities of 300-400 Wh/kg, and even more advanced chemistries (such as Lithium-Air) may have the potential to reach densities as high as 1000 Wh/kg or more. Read more about this innovation gap →

Additional resources

Acknowledgements

http://bit.ly/35KUicA

Tracking progress

Reducing CO 2 emissions while producing enough cement to meet demand will be very challenging, especially since demand growth is expected to resume as the slowdown in Chinese activity is offset by expansion in other markets. Key strategies to cut carbon emissions in cement production include improving energy efficiency, switching to lower-carbon fuels, reducing the clinker-to-cement ratio and advancing process and technology innovations. The latter two contribute the most to direct emissions reductions in the Sustainable Development Scenario (SDS).

Demand trends Demand for cement in the construction industry drives production, and thus it is an important determinant of cement subsector energy consumption and CO 2 emissions. Initial estimates suggest that cement production returned to 4.1 gigatonnes (Gt) globally in 2018, a 1% increase following annual declines of 1% during 2014‑17. China is the largest producer of cement, accounting for close to 60% of global production, followed by India at 7%.

Cement production After several years of moderate decline, estimates indicate that cement production increased slightly in 2018.  

Without efforts to reduce demand, annual cement production is expected to grow moderately to 2030. Production is likely to decline in China in the long term, but increases are anticipated in India, other developing Asian countries and Africa as these regions develop their infrastructure. Adopting material efficiency strategies to optimise the use of cement would help reduce demand along the entire construction value chain, helping to cut CO 2 emissions from cement production. Lower cement demand can be achieved through actions such as optimising the use of cement in concrete mixes, using concrete more efficiently, minimising waste in construction, and maximising the design life of buildings and infrastructure. Material efficiency efforts have gained increasing support in recent years.

Energy efficiency and alternative fuels Globally, the energy intensities of thermal energy and electricity have continued to gradually decline as dry-process kilns – including staged preheaters and precalciners (considered state-of-the-art technology) – replace wet-process kilns, and as more efficient grinding equipment is deployed. The thermal energy intensity of clinker is estimated to have fallen to 3.4 GJ/t on average globally in 2017, representing an annual decrease of 0.4% since 2014. Fossil fuels continue to provide the majority of energy in the cement sector, with alternative fuels such as biomass and waste accounting for only 6% of thermal energy used in 2017.

Global clinker thermal energy intensity and consumption by fuel Thermal energy intensity must fall by 0.5% per year, to 3.2 GJ/t, for alignment with the SDS. Biomass, waste and other renewables 

Note: Thermal energy intensity of clinker does not include any impacts related to other carbon mitigation levers beyond improving energy efficiency (e.g. it does not include the energy penalty from deploying carbon capture).

In the SDS, the thermal energy intensity of clinker production declines by 0.5% per year to a global average of 3.2 GJ/t of clinker, and the electricity intensity of cement production falls by 0.5% to 85 kWh per tonne of cement. Progress is particularly needed in the Eurasian region (Russia and the Caspian countries), which has the highest thermal energy intensity of clinker production (5.4 GJ/t), primarily due to the continued use of wet-process kilns. (Beyond process technology choice, regional factors affect the thermal intensity of clinker, such as moisture content and burnability of raw materials, typical clinker composition and average capacity of cement plants.) The share of alternative fuels increases to 18% by 2030 in the SDS. There is considerable regional variation, with the European Union accounting for almost 50% of the share.

Clinker-to-cement ratio Clinker is the main ingredient in cement, and the amount used is directly proportional to the CO2 emissions generated in cement manufacturing, due to both the combustion of fuels and the decomposition of limestone in the clinker production process. From 2014 to 2017, the clinker-to-cement ratio increased moderately by 0.5% per year, reaching 0.66 in 2017; this rise was the main reason for the increase in direct CO2 intensity of cement over the period. Although China has one of the lowest clinker-to-cement ratios globally, a local shortage of other cementitious materials caused China's clinker-to-cement ratio to rise from 0.57 to 0.60 during 2014‑17, driving the global increase. In the SDS, the clinker-to-cement ratio falls to a global average of 0.64 by 2030 owing to greater use of blended cements and clinker substitutes, including industrial by-products such as blast furnace slag and fly ash. In the long term, however, alternative clinker replacements that are widely available – such as calcined clay in combination with limestone – will become more important, as the decarbonisation of power generation as well as iron and steelmaking will reduce the availability of these industrial by-products.

Innovation CCUS will be crucial to reduce cement sector CO 2 emissions, particularly the process emissions released during limestone calcination. While current commercial deployment of CCUS is limited, there have been a number of innovation efforts underway in recent years, including: Between 2013 and 2016, chemical absorption, the most advanced post-combustion CO 2 capture technology, was successfully trialled in a cement plant in Brevik, Norway, and became operational in a cement plant in Texas, United States.

capture technology, was successfully trialled in a cement plant in Brevik, Norway, and became operational in a cement plant in Texas, United States. In Dania, Denmark, oxy-fuel capture was successfully piloted in a kiln precalciner. A first demonstration project of oxy-fuel capture technologies is planned in Europe, but funding uncertainty makes realisation unlikely before 2020. Carbon capture technologies other than post-combustion and oxy-fuel are also being explored.

Direct separation, which captures process CO 2 emissions by applying indirect heating in the calciner, is being piloted at a cement plant in Belgium (2017‑20).

emissions by applying indirect heating in the calciner, is being piloted at a cement plant in Belgium (2017‑20). The CLEANKER project is developing pre-commercial demonstration of a calcium looping carbon capture process at a cement plant in Vernasca, Italy. To be on track to achieve SDS decarbonisation, oxy-fuel carbon capture technologies in cement production should be demonstrated at commercial scale by 2030. It will also be necessary to gain experience in large-scale post-combustion capture technologies. Alternative binding materials could also be key to reduce cement production emissions, particularly process emissions. They rely on raw materials or mixes different from those of ordinary Portland cement (OPC) clinker, and are currently at various stages of development. Several alternative binding materials are currently commercially available, although their use so far has been relatively limited to niche applications. Barriers to wider market deployment are related to technology and raw material costs, technical performance, range of possible market applications and standardisation levels for the materials. Continued innovation could further develop and advance opportunities to deploy these materials. Other innovative processes also offer cement decarbonisation potential. The European Cement Research Academy has established a pre-competitive research project dedicated to energy-efficient grinding in the cement industry, which involves equipment suppliers and other cross-sectoral stakeholders. In Sweden, cement producer Cementa (a subsidiary of Heidelberg Cement) and energy producer Vattenfall are working together on the CemZero project to explore opportunities to electrify cement production (Cementa, 2019; Bioenergy International, 2019). Electrifying production would reduce emissions by using low-emissions electricity and by facilitating the capture of process CO 2 emissions (i.e. emissions from limestone decomposition during clinker production). The feasibility study, completed in early 2019, showed that electrified cement production is technically possible and likely cost-competitive with other options to substantially reduce emissions. The next step will be an in-depth study on how to construct a pilot plant.

Policy developments Policy and private sector efforts are facilitating reductions in energy use and emissions in key cement-producing economies. As part of its 13th Five-Year Plan (2016-20), China aims to reduce the thermal energy intensity of clinker production to 3.07 GJ/t clinker on average by 2020, which would shrink the gap between the current level and best available technology thermal energy performance by two-thirds.

Between 2011 and 2015, 85 cement plants in India participated in the first cycle of Perform, Achieve, Trade (PAT), a market-based mechanism to improve energy efficiency. They achieved energy demand reductions equivalent to 9% of India’s 2014 cement sector energy consumption, and the cement sector is now involved in the second PAT cycle, with higher targets and coverage.

In Europe, the mandate to develop cement standards within the European Committee for Standardisation was recently widened to allow possible low-carbon alternatives to OPC clinker that rely on different raw materials or mixes.

In 2015 in the private sector, 18 key cement companies developed the shared objective to reduce their CO 2 emissions by 20-25% from the business-as-usual level by 2030, equivalent to 1 GtCO 2 . Nevertheless, further policy efforts across all countries will be required to achieve necessary cement sector decarbonisation.

Recommended actions

Decarbonisation of the cement sector is challenging due to the relatively few emissions mitigation options currently available and the limited economic incentives to reduce emissions in the absence of strong carbon pricing policies.

Energy and material efficiency Energy efficiency can be accelerated through collaborative efforts among industry, public sector and research partners to share best practices on state-of-the-art technologies and to develop plant-level action plans that would increase the speed and scale of technology deployment. Ensuring efficient equipment operation and maintenance would also help guarantee optimal energy performance, as would the use of energy management systems. Furthermore, ensuring efficient equipment operation and maintenance will help guarantee optimal energy performance. This can be reinforced by implementing energy management systems. The cement industry can also take advantage of opportunities for industrial symbiosis – including using the waste or by-products from one process to produce another product of value – to help close the material loop, reduce energy use and reduce emissions in the case of carbon capture and utilisation. Examples include using steel blast-furnace slag in cement production and waste from other industries as alternative fuels for cement production.

Alternative fuels Greater uptake of alternative fuels can be facilitated by redirecting waste from landfills to the cement sector and by co‑ordinating the supply of sustainably sourced biomass across sectors to enable cost-competitive access for the cement sector.

Low-carbon technologies Accelerating innovation and deployment of innovative low-carbon technologies – particularly CCUS and alternative binding materials – will be key to reduce cement production emissions after 2030; RD&D over the next decade is therefore imperative. Increased support for RD&D is needed from governments and financial investors, particularly to advance the large-scale demonstration and deployment of technologies that have already shown promise. Private-public partnerships can help, as can green public procurement, which generates early demand and can enable producers to gain experience and bring down costs. Government co‑ordination of stakeholder efforts can also direct focus to priority areas and avoid overlap. Governments may also need to develop or modify regulations to facilitate technology uptake. For example, shifting from prescriptive to performance-based design standards (e.g. within building codes) would stimulate uptake of lower-carbon blended cements and cements that include alternative binding materials.

Mandatory CO2 emissions policies Policy makers can promote CO 2 emissions reduction efforts by adopting mandatory reduction policies, such as a gradually increasing carbon price or tradeable industry performance standards that require average CO 2 intensity for production of each key material to decline across the economy and permit regulated entities to trade compliance credits. Adopting these policies at lower stringencies within the next three to five years will provide an early market signal, enabling industry to prepare and adapt as stringency increases over time. It can also help reduce the costs of low-carbon production methods, softening the impact on cement prices in the long term. Complementary measures may be useful in the short to medium term, such as differentiated market requirements, that is, a government-mandated minimum proportion of low carbon cement in targeted products. While a considerable proportion of cement production is not exposed to cross-border competition, measures may be needed to help ensure the competitiveness of domestic industries and prevent carbon leakage if the strength of policy efforts differs considerably from one region to another. Examples include time-limited measures to ease transition, such as declining free allocation of permits, or novel measures to apply emissions regulations on the lifecycle emissions of end-products rather than directly on materials production. The latter could potentially be used to apply border carbon adjustments, provided that they are implemented in line with international trade rules. Governments can extend the reach of their efforts by partaking in multilateral forums to facilitate low-carbon technology transfer and to encourage other countries to also adopt mandatory CO 2 emissions policies.

Improve data collection Improving the collection, transparency and accessibility of cement subsector energy performance and CO2 emissions statistics would facilitate research regulatory and monitoring efforts (including, for example, multi-country performance benchmarking assessments). Consistently-reported data covering a larger share of global production is especially needed, as reporting from some key regions is currently limited. Industry participation and government co‑ordination are both important to improve data collection and reporting.

Innovation gaps

Technology innovation will be crucial to reduce cement subsector emissions, particularly process emissions for which commercially available mitigation options are relatively limited. CCUS can play a key role, with post-combustion chemical absorption carbon capture currently the most advanced technology. Other capture options under development include oxy-fuel capture, membrane CO 2 separation and calcium looping. Processes are also being developed to utilise captured CO 2 for inert carbonate materials in concrete aggregates. Alternative cement constituents, which can be blended into cement to replace a portion of the clinker, require further deployment. R&D is needed on alternative binding materials that rely on raw materials or mixes different from those of OPC clinker, and in many cases result in lower emissions. Of the various alternative binding materials under development, belite calcium sulphoaluminate (BCSA) shows particular promise in terms of a reasonable balance between remaining technical hurdles and CO 2 emissions reduction potential.

Alternative cement constituents Including a larger proportion of alternative constituents in cement (likely possible in the 15‑35% mass range – and potentially even up to 50%) reduces the quantity of clinker required as well as the process and energy-related CO 2 emissions associated with clinker production.

emissions associated with clinker production. Using newer alternative cement constituents, such as ground limestone, calcined clay, volcanic ash, rice husk ash, and silica fume, will be increasingly important in the future because fly ash from coal power plants and granulated blast furnace slag from steel production – currently commonly used as alternative cement constituents – will likely become less available. Technology principles: Clinker is the main active ingredient in cement, and producing it is the most emissions-intensive step of cement production. Alternative constituents are materials that can replace a portion of it while conserving the required performance properties of the cement. The resulting cement is commonly referred to as blended cement. Read more about this innovation gap →

CCS applied to cement manufacturing CO 2 capture could produce capture yields of up to 95%, and widespread application would reduce clinker production process emissions, for which reduction options are limited. Technology principles: A number of CCS technologies are available for application in the cement sector, with the two most advanced being chemcial absorption post-combustion and oxy-fuel capture.

In chemical absorption post-combustion capture, CO 2 is separated from the clinker kiln exhaust gases using a chemical sorbent at the end of the production process. Due to high sorbent costs, however, additional thermal energy is required to regenerate the saturated sorbent to make it reusable, and electricity is also needed to operate the capture unit.

is separated from the clinker kiln exhaust gases using a chemical sorbent at the end of the production process. Due to high sorbent costs, however, additional thermal energy is required to regenerate the saturated sorbent to make it reusable, and electricity is also needed to operate the capture unit. In oxy-fuel capture, oxygen is separated from air prior to combustion, so that flue-gases are composed of mainly CO 2 and water, making capture easier. Read more about this innovation gap →

Using BCSA clinker as an alternative binding material Using belite calcium sulphoaluminate (BCSA) clinker can result in process CO 2 emissions 20‑30% lower than those of Ordinary Portland Cement (OPC) clinker. Technology principles: Clinker is the main active ingredient in cement. During its production, calcination results in process emissions, which account for about two-thirds of cement production emissions. Using alternative binding materials that rely on raw materials or mixes different from OPC clinker can help reduce process emissions. Read more about this innovation gap →

Additional resources

References

Bioenergy International (2019), Vattenfall and Cementa proceed towards climate neutral cement with CemZero, , https://bioenergyinternational.com/heat-power/vattenfall-and-cementa-take-the-next-step-towards-a-climate-neutral-cement. Bjerge, L-M. and P. Brevik (2014), "CO2 capture in the cement industry, Norcem CO2 capture Project (Norway)", Energy Procedia, No. 63, pp. 6455-6463. Carbonfree Chemicals (2017), "Capture harmful pollutants with Skymine", Carbonfree Chemicals, http://www.carbonfreechem.com/technologies/skymine. Cementa (2019), "CemZero – for a climate-neutral cement production", , https://www.cementa.se/sv/cemzero. CLEANKER (2019), "Project contents", , http://www.cleanker.eu/the-project/project-contents. ECRA (2017), Development of State of the Art-Techniques in Cement Manufacturing: Trying to Look Ahead, European Cement Research Academy, Düsseldorf, Germany. IEA GHG TCP (IEA Greenhouse Gas Technology Collaboration Programme) (2014), "Pilot plant trial of oxy-combustion at a cement plant", IEAGHG information paper 2014‑IP7, Cheltenham, UK. Gartner, E. and T. Sui (2018), "Alternative cement clinkers", Cement and Concrete Research, No. 114, pp. 27-39. LC3 (Limestone Calcined Clay Cement) (n.d.), "New cement blend to cut CO2 emissions by up to 30%", , https://www.lc3.ch/new-cement-blend-to-cut-co2-emissions-by-up-to-30/. LEILAC (Low Emissions Intensity Lime & Cement project) (2017), LEILAC website, www.project-leilac.eu/. Perilli, D. (2015), "The Skyonic SkyMine: The future of cement plant carbon capture?", Global Cement Magazine, No. 5, Epsom, UKpp. 8-12. UN Environment (United Nations Environment programme) (2017), "Eco-efficient cements: Potential economically viable solutions for a low-CO2 cement-based materials industry", , http://wedocs.unep.org/handle/20.500.11822/25281. USGS (United States Geological Survey) (2019), "Cement mineral commodity summary 2019", , https://minerals.usgs.gov/minerals/pubs/commodity/cement/mcs-2019-cemen.pdf. USGS (2018), Cement Minerals Yearbook 2015, , https://minerals.usgs.gov/minerals/pubs/commodity/cement/myb1-2015-cemen.pdf.

Acknowledgements

http://bit.ly/2BnHx9N

DUBAI — Saudi Aramco said Sunday the timing of its long-awaited stock market debut "will depend on market conditions," after the latest delay in the blockbuster initial public offering.

The IPO forms the cornerstone of a reform program conceived by Crown Prince Muhammad Bin Salman, deputy premier and minister of defense, to wean the Saudi economy off its reliance on oil.

Aramco was expected to launch the first part of a two-stage listing in the coming week, but the energy giant decided to push the trading date back to December or January, a person familiar with the situation told AFP last Thursday.

Sources had told AFP in mid-September that the mammoth share offering could be delayed after an attack on Saudi oil facilities.

"The company continues to engage with the shareholders on IPO readiness activities," Aramco said in a statement to AFP.

"The company is ready and timing will depend on market conditions and be at a time of the shareholders' choosing," it said without giving further details.

The government seeks $2 trillion valuation for the IPO.

A prior initiative to list Aramco was postponed last year due to disappointment over the valuation during a weak period for oil prices.

Aramco has envisioned a two-stage listing, with about two percent of the capital trading on the Tadawul Stock Exchange in Saudi Arabia and an additional three percent on a foreign exchange.

With a $2 trillion valuation, the five percent sale could raise some $100 billion, in what would be the largest IPO ever. It would eclipse the 2014 listing of Alibaba which raised $25 billion.

Aramco sits on 263 billion barrels of crude oil and 320 trillion cubic feet of natural gas, much more than any other private or state oil company, and the firm reports impressive earnings.

"But Riyadh's apparent desire for a valuation of $2 trillion could still be difficult to justify," said Russ Mould, director at Bell Investment.

The company's expected dividend yield is well below those offered by most of the world's major oil firms, Mould said.

The Saudi government has not given any explanation for the IPO delays. — AFP

http://saudigazette.com.sa/article/580348/BUSINESS/Aramco-stock-market-launch-will-depend-on-market-conditions&ct=ga&cd=CAIyGjNhNDcwMGYyZTUwNGQ4MmM6Y29tOmVuOkdC&usg=AFQjCNENUr1lVFxD0Pt6cnPWm1ZJaxgc2

Schlumberger NV’s (SLB.N) new chief executive officer wielded an ax to the company’s asset-heavy businesses, taking a $12.7 billion charge in the face of weaker shale drilling and sliding profits.

The move by Olivier Le Peuch reverses his predecessors’ big investments that took the world’s largest oilfield services company deeper into shale and oilfield operations and shows that he intends to shift the company toward more software and services-driven arms.

The charge pushed the company to post a more than $11 billion loss, its largest ever.

Excluding the charge, the company’s profit beat Wall Street estimates as higher international drilling activity boosted demand for its equipment and services and helped counter weakness in North America.

Shares of the company rose 2.8% in early trading and were the biggest boost to the S&P’s energy index.

A cut in spending by oil and gas producers has hit North America pressure pumping business the hardest, forcing rival Halliburton Co (HAL.N) to cut 650 jobs across Colorado, Wyoming, New Mexico and North Dakota, while sources told Reuters that ProPetro Holding Corp (PUMP.N) slashed 150 workers this month.

The charge included $1.58 billion related to the pressure pumping business in North America, Schlumberger said.

“That’s a sizable writedown from pressure pumping business. That just tells you the state of the North American onshore market being pretty poor,” said Anish Kapadia, founder of London-based oil and gas consultancy firm AKap Energy.

North America rig count stood at 1,002 as of Oct. 11, 256 fewer than a year earlier. Globally traded Brent crude prices LCOc1 have fallen about 18% in the third-quarter to average $62.03 per barrel, amid trade tensions and oversupply from U.S. shale fields.

Revenue from the company’s international business rose 8% in the third quarter, while revenue from North America fell 11%.

The international business has been a bright spot for Schlumberger since last year as investor pressure to improve returns has forced North American oil and gas producers to rein in drilling new wells in a volatile price environment.

Excluding items, the company earned 43 cents per share, beating estimates of 40 cents, according to Refinitiv IBES data.

Revenue was largely unchanged at $8.54 billion, but beat expectation of $8.50 billion.

https://www.reuters.com/article/us-schlumberger-results/schlumberger-profit-beats-as-international-gains-offset-weak-north-america-idUSKBN1WX1C4

The startup of the Power of Siberia Russia-China natural gas pipeline in December is expected to weigh on the mid-term LNG demand growth potential of China, the world's second largest importer of the fuel, adding another bearish factor to an already oversupplied Asian market.

The immediate impact on the region's spot fundamentals and prices for this coming winter will likely be limited, however, given the relatively small volume that will be injected into the pipeline network over the first year.

The construction of the northern section of the China-Russia gas pipeline eastern route was completed Wednesday, and PetroChina is expecting supplies into northern China to commence December 1, the state-owned major said Thursday.

"The growth of China's LNG imports is expected to be affected," said a source with one of China's major city gas suppliers, adding that they would consider lowering LNG imports into northern China once Russian pipeline gas is made available.

Two Chinese end-users said they were contemplating reselling some of their winter LNG cargoes into the spot market if the pipeline starts up as planned.

"You might see us in the market this winter, perhaps not to buy, but to sell," said a Chinese LNG importer.

The Power of Siberia is one of the most anticipated energy projects in Asia, with significant implications for China's natural gas supply, LNG import demand in the region and Moscow's energy strategy in Asia.

The project will further enhance China's supply security, and follows Beijing's decision to merge gas pipelines of the three national oil companies to boost connectivity and ease infrastructure constraints.

IMPACT ON WINTER MARKET

Although pipeline imports from the Power of Siberia will certainly help slow Chinese LNG import growth in the medium term, they are unlikely to have a significant impact on Asian LNG spot markets this winter, according to S&P Global Platts Analytics.

The initial flows will be relatively small and will only reach a select area in northern China, said Jeff Moore, Platts Asia LNG Analytics manager.

"Mild weather, slowing activity in energy-intensive sectors or a lack of new regasification capacity would be more likely to negatively impact Chinese LNG imports this winter," Moore said.

Russian pipeline gas supplies in the first year of operations are forecast at 5 Bcm/year, which would only account for around 1.6% of China's total gas supply estimates of 316 Bcm in 2019, according to Platts Analytics and China's National Development and Reform Commission.

Once it reaches full capacity of 38 Bcm/year in 2022-23, it would account for around 9.5% of China's total gas supply estimates of 402 Bcm for 2022.

NORTHERN CHINESE USERS

With a length of 1,067 km, the northern section will connect Russian gas supplies with customers in northeastern China and Beijing-Tianjin-Hebei regions, helping improve supply optionality and energy security in the country's biggest winter demand center.

"We have many city gas supply projects in the northeast, so the startup of the China-Russia gas pipeline is expected to ease our supply pressure in the winter peak season," the source with the city gas supplier said.

The full Russia-China gas pipeline is expected to be completed by 2022-23 and will have a length of 3,371 km in China, which will be divided into three sections -- north, central and south.

It will terminate in Shanghai, passing through nine provinces and autonomous regions, connecting with the Northeast pipeline network, Shaanxi-Beijing pipeline network and West-East pipeline network, according to PetroChina.

PetroChina's parent company China National Petroleum Corp signed a 30-year SPA with Russia's Gazprom in 2014 to purchase gas from the Power of Siberia pipeline. The total gas supply is estimated to exceed 1 trillion cu m, with annual supplies expected to reach 10 Bcm/year by 2021 and 32 Bcm/year by 2022-23.

https://www.spglobal.com/platts/en/market-insights/latest-news/natural-gas/101819-russia-pipe-gas-supplies-may-further-slow-chinas-lng-import-growth

Pieridae Energy (PEA.V) moved closer to building a liquefied natural gas (LNG) export terminal on Canada’s East Coast after taking ownership of fields from Royal Dutch Shell (RDSa.L) which will feed gas into the plant, the company said.

The Goldboro LNG terminal would be the first on Canada’s East Coast and compete with the growing number of plants on the U.S. Gulf Coast, hoping its shorter distance to Europe and further west will help sell its LNG by cutting shipping costs.

Pieridae said in a statement late on Thursday it had closed a C$190 million ($145 million) acquisition of Shell’s gas assets in Alberta’s Foothills region, giving it most of the gas needed to supply the first of two plants at the Goldboro terminal.

“We will now complete our negotiations with Kellogg Brown & Root Limited for a fixed price contract to construct the Goldboro LNG facility so that we can then proceed to complete the project financing and final equity raise and make a final investment decision (FID),” Pieridae CEO Alfred Sorensen said.

The Canadian LNG industry has been slower than its U.S. counterpart to take advantage of soaring gas demand around the world and build export plants, in part due to securing feedstock supplies for the terminals.

This contrasts to the U.S. Gulf Coast, where there is so much gas being produced thanks to the shale revolution, some producers have had to pay buyers to take it off their hands. This makes it easier for LNG projects there, which tend to buy gas rather than own gas assets.

Five large LNG export terminals operate in the United States including the 25 million tonne a year (mtpa) Sabine Pass, operated by Cheniere Energy (LNG.A). By contrast, there are no operating LNG export facilities in Canada although Shell has begun constructing a massive one on the West Coast.

Unusually for LNG projects in the developed world, Pieridae has a $4.5 billion German government guarantee and has one German buyer, Uniper (UN01.DE), for all 5 million tonnes a year produced by its first train, a large contract by industry standards.

Pieridae said the Shell deal allows it to begin to leverage a $1.5 billion of the German government guarantee for the upstream gas production part of its project. The rest of the guarantee applies to the construction of the terminal itself.

Germany, as yet, has no facilities to import LNG but three import terminals have been proposed, including in Wilhelmshaven, a project owned by Uniper Global Commodities.

Europe’s gas production is expected to fall in future years with the shutdown of the huge Dutch Groningen gas field and the gradual depletion of reserves in the North Sea.

As part of Germany’s involvement in the project, 1.5 million tonnes of LNG sold to Uniper must land in the Netherlands and the subsequent regasified gas shipped to Germany by pipeline, Pieridae’s corporate documents showed.

https://www.reuters.com/article/us-canada-lng/canadian-e-coast-lng-export-plans-progress-with-pieridaes-shell-deal-idUSKBN1WX1RR

Despite a surge last year, oil prices have been generally depressed since early 2015. The low prices have pushed down stock prices in the energy sector, which has paradoxically opened an opportunity for income investors.

The energy sector’s production companies benefit from dealing in commodities – oil and gas – that are always in demand. They have high overhead, but they also have a ready market for the product and consequent strong cash positions. Low share prices are attractive to investors, and the companies have been following two strategies to boost their shares.

First, they are simply buying back shares to support the price. And second, they are paying out high dividend yields, offering investors a steady income stream from the stocks. Average dividend yield in the energy sector is up to 3.9%, almost double the S&P 500’s average yield of 2.1%. Income investing is a viable option for energy investors; since 1998, dividends in the energy sectors have brought triple the returns of simple price appreciation.

We’ve taken a dive into TipRanks’ Stock Screener tool to find three energy stocks offering investors the best combination – "strong buy" consensus, and dividend yields above 9%.

MPLX LP (MPLX)

When you think of the energy industry, chances are you picture an oil well out West, or the gas station down the street. But between the actual extraction and the end user, there is a string of processes, refineries, pipelines, and transport systems that make up the midstream infrastructure of the industry. MPLX, a partnership formed by Marathon Petroleum Corporation (MPC), owns and operates an array of these midstream assets, including pipelines, inland shipping, product terminals, refinery storage, and the docks and loading systems associated with them. In effect, MPLX handles the product transport while Marathon handles extraction and production. Marathon owns a 20.4% interest in MPLX.

In addition to transport infrastructure, MPLX also operates a series of natural gas gathering systems, processing the untreated gas to extract various components. These include ethane, ethylene, propane, butane, gasoline, propylene. The company then sells these natural gas products. The most important feature of MPLX’s business model, however, lies in the simple utility of energy transport niche. No matter what the price of crude oil or natural gas, the product still must reach the end user, and MPLX will get paid for that transportation.

The infrastructure and natural gas-product niche has been good for MPLX. Since 2018, the company has consistently posted earnings between 52 cents and 62 cents per share. The most recent report, for Q2 CY19, showed revenues of $1.63 billion, just below the estimate of $1.64 billion. The year-over-year gain was modest, at $60 million. Shares slipped $1 after the report, and have been volatile since.

MPLX has used its steady earnings to support a reliable, paying out 66.75 cents per share quarterly, or $2.67 per year. The company has been raising the dividend payment steadily since 2014, and the yield has increased from 2.1% then to the current 9.96%.

Wall Street analysts have been pleased with MPLX and its performance. For example, Barclays’ analyst Christine Cho reinstated her bullish stance on the stock and pointed out that the company has plenty of options to streamline operations without compromising profitability. Cho rates MPLX an Overweight (i.e. "buy") along with a $33 price target, indicating room for over 20% upside. (To watch Cho's track record, click here)

The analyst noted, “While the company today has a far broader set of assets to rely upon during periods of change across the industry, management has also made it clear that perhaps their assets are spread across too many basins and they could be looking to sell interests down the road. We believe investors would support asset sales as the company focuses on competing in its core basins in the Permian and Northeast.”

Wall Street backs Cho's bullish bite into the energy player as well as TipRanks analytics exhibit MPLX as a Strong Buy. Out of 7 analysts polled in the last 3 months, 6 are bullish on the stock, while only one remains sidelined. With a return potential of 25%, the stock's consensus target price stands at $33.57. (See MPLX stock analysis on TipRanks)

Story continues

https://finance.yahoo.com/news/3-strong-buy-energy-stocks-142822575.html

zoom Image courtesy of Tepco

Japanese imports of liquefied natural gas (LNG) have rebounded in September following a dip during the previous month.

According to the provisional data released by Japan’s Ministry of Finance, a total of 6.44 million tons of the chilled fuel were imported into Japan during the month under review, 2.6 percent up on the volumes imported in September 2018.

The value of September LNG imports was about $3.14 billion, edging up 5.3 percent on year.

The data shows that imports of US LNG jumped 79.7 percent, reaching 334,000 tonnes. Imports from Asian sources such as Malaysia, Indonesia, Papua New Guinea, and Bruneiedged up 6.3 percent compared to the corresponding month in 2018, reaching 1.30 million tonnes.

Imports of US LNG jumped 79.7 percent, reaching 334,000 tonnes.

The country’s coal imports for power generation stands at 9.19 million tonnes, edging 0.6 percent below the corresponding month in 2018.

LNG World News Staff

http://bit.ly/2P6Cna8

The United States Federal Energy Regulatory Commission (FERC) granted Sempra Energy to start the commissioning process of the second liquefaction train at the Cameron LNG plant in Hackberry, Louisiana.

FERC granted the permit for the variance request related to the commissioning procedures for the Train 2 MR and PR gas turbine solo runs, and to introduce hazardous fluids and commission the Train 2 ISBL hot oil system and to introduce hazardous fluids and commission the Train 2 PR gas turbine.

FERC noted in its order that Cameron LNG must comply with all applicable remaining terms and conditions of the order, as well as procedures stipulated in your previous filings and that this approval does not grant Cameron LNG the authority to introduce hazardous fluids or commission other project facilities at the LNG terminal.

Cameron LNG is jointly owned by affiliates of Sempra LNG, Total, Mitsui, and Japan LNG Investment. Sempra Energy indirectly owns 50.2 percent of Cameron LNG.

The project includes three liquefaction trains with a projected export capacity of more than 12 million tonnes per annum of LNG, or approximately 1.7 billion cubic feet per day.

Train 2 and Train 3 are expected to begin producing liquefied natural gas (LNG) in the first quarter of 2020 and the second quarter of 2020, respectively.

http://bit.ly/2pCMsRx

China’s latest economic data continues to paint a subdued picture for commodity and energy demand, while lower drilling counts in the US raise questions about the pace of future supply growth. S&P Global Platts editors shed light on these and other trends, including a Nordic wind power boom, US-Turkey steel trade, and more.

1. China and commodities: a tale of two inflations

What’s happening? China’s consumer price index (CPI), released last week, hit a nearly 6 year high, as pork prices drove it higher following a more than 40% decline in China’s pig herd due to African Swine fever. This has caused much consternation among consumers, with the average price of pork nearly doubling since the beginning of the year. It’s also a major concern for the Chinese government, which wants to avoid a discontented populace. But strip away food and energy, and inflation is the lowest it’s been for over three years, due primarily to weak demand. The Producer Price Index (PPI) – reflective of prices at the factory gate also declining to their lowest level for more than 3 years, as low commodity prices due to weak demand feeds through to lower prices at the factory gate and weakening industrial profits.

What’s next? China’s latest GDP data was released last Friday, which showed real growth the lowest it’s been since 1992 when quarterly figures were first reported. Or nearly 30 years. But don’t expect the stimulus cavalry to ride to the rescue – the government doesn’t want to flood the economy with liquidity, create more unproductive white elephant projects and pile more onto China’s already considerable pile of debt. A pickup in the global economy or a resolution of the trade dispute with US may help boost demand at the margin, but with a slowing domestic economy, Chinese commodities and energy demand has probably tuned a corner – the future is likely to be a case of lower for longer.

2. US drilling decline stokes concerns over pace of shale supply growth

What’s happening? US oil and gas rig counts dropped to their lowest level since mid-March 2017 last week fueling market concerns that a protracted oil price bear market stoked by recession fears will stunt the outlook for US shale supply growth. The US oil and gas rigs fell by 19 to 900, according to Enverus/DrillingInfo, with the drop coming almost totally from oil-directed rigs, which fell 18 to 724. The data shows a large drop occurred in Texas’ Fort Worth shale area, where rigs fell to six in the week to October 11, from 12 the previous week. Among large shale basins, the biggest changes in rig counts came from the Permian Basin of West Texas/New Mexico and the SCOOP-STACK in Oklahoma.

What’s next? With Brent crude prices lingering at or below $60/b since the start of the month due to demand-side concerns, talks of renewed capital disciple and consolidation among shale industry players have resurfaced in recent weeks, particularly among small-to-midcap operators. The market will likely be watching for any further signs that US drilling activity is slowing in response capex cuts to gauge the likely impact on US oil supply forecasts. The International Energy Agency recently trimmed its oil supply outlook for US oil growth in 2019 and 2020 to reflect the drilling slowdown.

3. Nordic wind boom to be felt across Europe

What’s happening? The Nordic wind boom is driving the region’s electricity surplus up. By 2025 the surplus is forecast to reach 45 TWh. This cheap power needs a home, and Norway, Denmark and Sweden plan to double interconnection capacity to 2030. Great Britain and Germany will be the main beneficiaries, with the Netherlands and Baltics also.

What’s next? The supply gains are forecast to outweigh demand gains with new interconnectors helping to integrate plentiful Nordic hydro and wind, while supporting Nordic power prices, already at a discount to most European markets. For 2020, Nordic power is over Eur10/MWh cheaper than that in NW Europe. Should, however, the wind blow more in Germany or the UK, the new cables could also help preserve Nordic hydro reservoir stocks, that can as seasonal storage during the winter peak.

4. Trump’s threat to hike Turkish steel tariff rattles market

What’s happening? Turkey-US trade in steel was plunged into uncertainty last week, when US President Donald Trump threatened to re-impose 50% tariffs on steel imports from Turkey, as relations with the country became strained over the situation in Northern Syria. Turkish steel export volumes to the US dropped sharply after US President Donald Trump raised Turkey’s steel tariff rate from 25% to 50% in August 2018, amid increased political tension between the two countries due to the detention of US Pastor Brunson in Turkey. The US import tariff on Turkish steel was later dropped back to 25% in May 2019, but this has so far not triggered the notable rise in export volumes to the US that Turkish producers expected.

What’s next? The prospect of a return to 50% tariffs last week led to the cancellation of recently agreed rebar contracts between US buyers and Turkish mills. Despite Trump calling off the threat on Friday, the uncertainty could have a further chilling effect on steel flows between the two countries, with US buyers now looking to Southern Europe as an import alternative. However, lower US domestic rebar prices could reduce import interest.

5. Volatile European gas prices stir Norwegian gas flows

What’s happening? Norwegian gas flows to continental Europe and the UK are on the rise, a sign that state oil and gas company Equinor’s commercial turndown may be coming to an end. The flows were triggered by a sharp increase in gas prices mid-October, before a milder forecast October 17 took the shine off the market.

What’s next? More exports means more supply in what remains a fundamentally bearish gas market, so expect further European gas price volatility after major swings in pricing over the past few weeks. If Norwegian flows continue at current levels and forecast healthy LNG supply materializes, prices above Eur12/MWh at the benchmark Dutch TTF hub are seen as unlikely by S&P Global Platts Analytics.

6. US-Brazil corn export price spread narrows

What’s happening? Export prices for the US corn have reduced in comparison with Brazilian corn in recent weeks. The US and Brazil are huge corn producers and compete for export share. Around May, US corn prices rose on the back of difficult weather conditions that led to historical delays in corn planting. This benefited Brazil’s corn exports. However, in recent weeks, corn prices FOB US Gulf have narrowed the gap to FOB Brazil, Santos. In the week to Oct. 11, US corn prices were seen lower than Brazil’s.

What’s next? The market will be watching whether the US is able to boost its corn exports due to the narrowing spread with Brazil. Analysts have mixed views on the situation, but some expect a seasonal pickup of pace in US exports, led by upcoming harvest pressure and the dollar backing off a bit, which would make exports more attractive.

Reporting by Andreas Franke, Henry Edwardes-Evans, Kira Savcenko, Viral Shah, Abdulrhman Ehtaiba, Sebastian Lewis, Rob Perkins, Rohan Somwanshi, Mugunthan Kesavan

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Washington — Political risks to Canada's 590,000 b/d Trans Mountain oil pipeline have grown as tight polls ahead of Monday's federal election increase the odds of a minority government, even though both leading candidates support the project that would expand Alberta oil producers' access to Asian markets.

Under an election scenario that Prime Minister Justin Trudeau's Liberal Party wins the most votes but not enough for a majority government, he would need New Democratic or Green party support to stay in power. Both parties have campaigned on stopping the Trans Mountain pipeline expansion to British Columbia.

Trudeau supports the pipeline, having approved the federal government's unusual nationalization of the project to move it forward. But some election observers question if he would agree to concessions that significantly delay the pipeline in order to form a government with the NDP or Green Party.

"There are some concerned that a Liberal minority which forms a coalition with a less industry-friendly party could lead to challenges on the Trans Mountain expansion's ability to proceed," said Matt Murphy, an analyst with Tudor, Pickering, Holt.

NDP leader Jagmeet Singh has not ruled out the possibility of joining a coalition with Trudeau's Liberals, saying he would "work on ensuring that we are as responsible as possible with moving forward with an asset that I would not have bought," according to the Toronto Star.

Conservative leader Andrew Scheer, who appears virtually tied with Trudeau, has fewer options for building a coalition government should he get the most votes but not a majority.

Given the uncertainties surrounding a possible minority government, it may take weeks to know whether Monday's election changes Trans Mountain's fate or shifts Canada's climate policy.

Click here for full-size infographic

TRUDEAU, SCHEER FACE OFF

Trudeau has promised to continue implementing a national climate policy, including taxing carbon emissions and setting targets for reaching carbon neutrality by 2050.

Scheer has promised to scrap Trudeau's climate policies and wants to build a coast-to-coast energy corridor to accelerate permitting of pipelines, electricity projects and other infrastructure.

Traders and analysts said they did not see a win by Scheer as eliminating challenges to the Trans Mountain expansion.

"I don't think it really matters if the Conservative Party wins," a Calgary-based trader said. "There may be a little more push to get some infrastructure going, but I doubt they can move mountains."

A lack of sufficient pipeline capacity to move Alberta's oil to market pushed Western Canadian Select crude to a record wide discount to WTI late last year, forcing the provincial government to impose output curtailments in January.

S&P Global Platts assessed WCS-Hardisty at a $17/b discount to WTI-Cushing Thursday, 30 cents/b wider than Wednesday and the widest since May 30.

Alberta has eased the curtailment month by month, with October cuts at 100,000 b/d, narrowing to 80,000 b/d by December. S&P Global Platts Analytics expects Alberta production to trend upward through April, before falling for spring maintenance.

Because the output cuts are handled at the provincial level, any change in federal leadership would not affect them.

US COURT CHALLENGES

Likewise, two of three stalled Canadian oil pipelines will not be affected by Monday's vote. The fates of Enbridge's 370,000 b/d Line 3 expansion and TransCanada's 830,000 b/d Keystone XL pipeline largely rest in the US, where court challenges and regulatory hurdles have slowed their progress.

Trans Mountain plans to start construction this fall, but court challenges still loom.

Under Trudeau, the federal government took the unusual step in May 2018 of buying the existing 300,000 b/d pipeline and 590,000 b/d expansion project from Kinder Morgan for $3.5 billion.

Scheer has floated the idea of reviving applications to build the 525,000 b/d Northern Gateway to the west coast and 1.1 million b/d and then-TransCanada's Energy East pipelines to the east coast, both of which Trudeau's government canceled. But Scheer has not given any details on how he would revive the projects, or if either company would even be interested.

"You've canceled two pipelines, and the one you bought you can't build," Scheer told Trudeau during an October 7 debate. "You've let tens of thousands of people in Alberta and Saskatchewan down, and you failed to recognize that indigenous communities are hurt by this as well."

Trudeau responded: "I recognize I'm going to be attacked for not building pipelines from some and for building pipelines from others."

CUTTING CARBON EMISSIONS

Trudeau called climate change "the defining issue of our time," promising to fight the conservative provincial leaders of Alberta and Ontario on the issue. He said Canada is 75% of the way to reaching its 2030 carbon targets.

"We know how important it is to move forward, and right now Mr. Scheer has promised that the first thing he would do is rip up the only real plan to fight climate change that Canada has ever had," Trudeau said.

Scheer said provinces should not be forced to accept a federal carbon tax, which he said was increasing the costs of gasoline, groceries and other essentials.

"He is refusing to tell Canadians how high his carbon tax will go if he's re-elected," Scheer said. "The conservative government under my leadership will scrap the carbon tax."

-- Meghan Gordon, with Pat Harrington in Houston, newsdesk@spglobal.com

-- Edited by Alisdair Bowles, newsdesk@spglobal.com

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Permian Basin pure-play Callon Petroleum Co., which is in a battle with major shareholders over plans to expand its focus with the takeover of Carrizo Oil & Gas Inc., expects third quarter production to average 37,500-37,900 boe/d, 78% weighted to oil.

The Houston independent said lease operating expenses are forecast to average $5.60-5.80/boe.

"We have continued to make significant progress toward our goal of enhanced shareholder value through growing, repeatable free cash flow generation," CEO Joe Gatto said. "Our field level performance during the third quarter exemplified our team's ongoing efforts to reduce capital and operating costs, which translates into enhanced capital efficiency across the combined asset footprint in 2020 and beyond.

“This incremental value will accrue to our shareholders as we execute on our deleveraging goals and improve overall shareholder returns."

Callon is working to buy Carrizo in an estimated $3.2 billion deal to expand its Permian leasehold and open up new territory in the Eagle Ford Shale. Some Callon shareholders have questioned the value of acquiring the “inferior” Eagle Ford assets. In its third quarter projections issued last week, Carrizo estimated that volumes averaged 69,500-69,600 boe/d, a 6% sequential increase.

Callon said operational capital spending during 3Q2019 is expected to be $114-118 million, in line with projected full-year expenditures of $495-520 million. Pre-hedge realized prices are projected to average roughly $54/bbl of oil and $1.55/Mcf of natural gas.

In reaction, Tudor, Pickering, Holt & Co. said Callon’s preliminary 2020 outlook has a free cash flow (FCF) breakeven of $50/bbl. As it expects $300 million of FCF through 2021 at $55/bbl, “we’ll be looking to see how plans may potentially change with our price deck of $51/bbl for 2020 and $50/bbl in 2021-plus, particularly how management plans to balance growth versus FCF.”

Williams Capital Group LP said the preliminary forecast was in line with pricing expectations but “it may take a couple quarters for investors to see and appreciate the benefits” of the Carrizo acquisition from synergies/asset sales, improved financial leverage and enhanced FCF generation.

https://www.naturalgasintel.com/articles/119945-callon-says-permian-capital-operating-costs-coming&ct=ga&cd=CAIyHDA0MGM0YTczNTcwYmNjYWE6Y28udWs6ZW46R0I&usg=AFQjCNFGrt5kD6V-CIYyBfrARVxaGWM-2

Drilling Down: Houston company makes big push in Spraberry play

Houston oil company Birch Resources is planning to make a big push in the Permian Basin’s prolific Spraberry field. Houston oil company Birch Resources is planning to make a big push in the Permian Basin’s prolific Spraberry field. Photo: Jon Shapley, Houston Chronicle / Staff Photographer Photo: Jon Shapley, Houston Chronicle / Staff Photographer Image 1 of / 1 Caption Close Drilling Down: Houston company makes big push in Spraberry play 1 / 1 Back to Gallery

Houston oil company Birch Resources is planning a big push in the Permian Basin’s prolific Spraberry field.

The company is seeking permission from the Railroad Commission of Texas to develop 19 horizontal wells targeting the Spraberry at total depths ranging from 7,600 to 9,1000 feet. The project is located on the company’s Big Jay leases about 7 miles southeast of Lenorah i Martin County.

Birch has filed for 74 drilling permits so far this year. All of them have targeted the Spraberry field in either Howard or Martin counties. The company’s 162 leases produced 712,000 barrels of crude oil and nearly 2.9 billion cubic feet of natural gas in 2018.

Birch mostly names its leases after college sports mascots or wrestling stars. Big Jay is a reference to the University of Kansas mascot while the company’s Mike the Tiger leases are a nod to Louisiana State University. Other leases names include Andre The Giant and Jake The Snake.

Permian Basin

After going nearly a year without filing a drilling permit, Midland oil company OGX Resources is getting back in the game with plans to develop saltwater disposal wells in Howard County. The company is seeking permission to drill five injection wells on its Quinn SWD leases about 10 miles southwest of Big Spring. The wells target the Spraberry formation to a depth of 13,000 feet.

Top 10 Texas Drilling Permits (October 9 through October 15) Birch Resources 19 Rockcliff Energy 9 WPX Energy 9 Laredo Petroleum 8 Pioneer Natural Resources 8 Occidental Petroleum 7 Sanchez Energy 6 EOG Resources 6 OGX Operating 5 ConocoPhillips 5 Source: Railroad Commission of Texas

Eagle Ford Shale

Houston oil company EOG Resources plans to drill six horizontal wells split between five leases in McMullen County and another in neighboring Karnes County. The wells target the Eagleville field of the Eagle Ford geological layer at totals depths up to 11,500 feet.

Haynesville Shale

Houston oil company Rockcliff Energy plans to develop nine horizontal wells seeking natural gas on seven leases in Panola County and another two in Harrison County. The wells target the natural gas-rich Carthage field of the Haynesville Shale.

Barnett Shale

Louisiana oil and gas company White Knight Production is planning to drill a horizontal well on its Jolliff lease in Jack County. Located about eight miles south of Jacksboro, the well targets the natural gas-rich KRS field of the Marble Falls geological layer down to a total depth of 5,500 feet.

Conventionals

Richardson oilfield water company Taurus Midstream filed its first ever drilling permit as part of a saltwater disposal well project in Martin County. The company plans to drill an injection well on its Lone Ranger SWD lease about four miles northeast of Tarzan. The vertical well targets the Spraberry field to a depth of 14,100 feet.

https://www.chron.com/business/energy/article/Drilling-Down-Houston-company-makes-big-push-in-14548499.php&ct=ga&cd=CAIyHDM2NzYyZTdmOGQyMDc4MGI6Y28udWs6ZW46R0I&usg=AFQjCNGWM_iZVd5EGHZmhyQIugiKhVQ4y

HOUSTON--(BUSINESS WIRE)--Halliburton Company (NYSE:HAL) announced today net income of $295 million, or $0.34 per diluted share, for the third quarter of 2019. This compares to reported net income for the second quarter of 2019 of $75 million, or $0.09 per diluted share, and adjusted net income for the second quarter of 2019 of $303 million, or $0.35 per diluted share, excluding impairments and other charges. Operating income was $536 million during the third quarter of 2019, compared to reported operating income of $303 million and adjusted operating income of $550 million for the second quarter of 2019.

“Our organization executed effectively in the third quarter. We managed the market dynamics and delivered our financial results as per expectations,” commented Jeff Miller, Chairman, President and CEO.

“Total company revenue was $5.6 billion and operating income was $536 million, representing decreases of 6% and 3%, respectively, compared to revenue and adjusted operating income in the second quarter of 2019.

“International revenue, which was flat sequentially, was up 10% year to date and we remain confident that we will achieve high single-digit international growth for all of 2019. International growth continues across multiple regions, benefitting both our Drilling and Evaluation and Completion and Production divisions.

“Our North America revenue decreased 11% sequentially driven by customer activity declines and the execution of our new playbook. I am proud of how our team performed in this challenging market. We are successfully implementing our new strategy and are focused on taking the right actions to deliver returns and cash flow for our shareholders.

“As the international recovery continues and the North American market matures, our strategy is allowing us to thrive in this dynamic environment, generate strong free cash flow and produce industry-leading returns,” concluded Miller.

Operating Segments

Completion and Production

Completion and Production revenue in the third quarter of 2019 was $3.5 billion, a decrease of $299 million, or 8%, when compared to the second quarter of 2019, while operating income was $446 million, a decrease of $24 million, or 5%. These results were primarily driven by lower pressure pumping activity and pricing in North America land, coupled with decreased completion tool sales in Latin America and reduced stimulation activity in Middle East/Asia. These declines were partially offset by increased cementing activity in the Eastern Hemisphere, improved completion tool sales in Europe/Africa/CIS, and higher stimulation activity in Latin America.

Drilling and Evaluation

Drilling and Evaluation revenue in the third quarter of 2019 was $2.0 billion, a decrease of $81 million, or 4%, when compared to the second quarter of 2019, while operating income was $150 million, an increase of $5 million, or 3%. These results were driven by reduced drilling and wireline activity in North America and lower project management activity in Middle East/Asia. These declines were partially offset by higher drilling activity in the Eastern Hemisphere, fluids activity in Latin America and higher testing and software sales globally resulting in better overall margins.

Geographic Regions

North America

North America revenue in the third quarter of 2019 was $2.9 billion, an 11% decrease when compared to the second quarter of 2019, primarily associated with lower activity and pricing in pressure pumping and well construction services in North America land.

International

International revenue in the third quarter of 2019 was $2.6 billion, essentially flat when compared to the second quarter of 2019, with increased cementing activity in the Eastern Hemisphere and activity increases in Argentina offset by lower project management and stimulation activity in Middle East/Asia.

Latin America revenue in the third quarter of 2019 was $608 million, a 6% increase sequentially, resulting primarily from higher activity in multiple product service lines in Argentina, increased testing activity and artificial lift sales across the region and improved fluids activity in Mexico. These improvements were partially offset by lower completion tool sales in Brazil.

Europe/Africa/CIS revenue in the third quarter of 2019 was $831 million, essentially flat when compared to the second quarter of 2019. Higher activity across multiple product service lines in Russia, Caspian and the North Sea offset lower activity in West Africa.

Middle East/Asia revenue in the third quarter of 2019 was $1.2 billion, a 4% decrease sequentially, largely resulting from reduced project management and stimulation activity across the region. These declines were partially offset by increased activity in multiple product service lines in Indonesia.

Selective Technology & Highlights

Halliburton announced the execution of an integrated services contract with Petrobras for pre-salt development in the Santos Basin. The thirty-month contract will provide drilling and completion services to drive greater efficiency by applying pre-salt expertise and integrating multiple product offerings.

Woodside Energy (Senegal) BV awarded Halliburton nine contracts, conditional on the final project FID, for drilling and completion services for SNE Field Development Phase 1 offshore Senegal. Halliburton will provide drilling, logging, cementing, lower completions, e-line/slick line, coiled tubing and well testing services for the drilling campaign, which is due to start in late 2020 or early 2021.

Halliburton introduced 3D reservoir mapping, a new logging-while-drilling (LWD) capability that provides a detailed representation of subsurface structures to improve well placement in complex reservoirs.

Ten new DecisionSpace® 365 E&P cloud-native applications were released, leveraging advances in digital technology to help operators reduce exploration risk, improve reservoir characterization and boost drilling efficiency. DecisionSpace® 365 is an integrated suite of E&P cloud applications that empowers customers to be creative and realize their business objectives.

Halliburton unveiled the Commander™ Full Bore Cement Head, a product that enables rotation and reciprocation of 4½ - 6 inch production strings to help increase reliability and reduce risk during the well cementing process. Advanced wireless functionality and faster rig-up time help increase efficiency and improve safety for land-based cement jobs, particularly in unconventional formations.

QuickPulse™ Automated Directional Gamma Service, a new measurement while drilling (MWD) technology, was launched, providing quick and reliable downhole information at extended depths to deliver wells faster. This capability helps operators drill longer laterals, make improved geosteering decisions and reduce well time to maximize their asset value.

Halliburton announced an asset acquisition of electromechanical downhole cutting tools and tubing punches from Westerton (UK) Ltd. These services provide operators with a safe and reliable alternative to traditional pipe recovery and intervention across the well lifecycle from exploration to abandonment. This new technology complements Halliburton's extensive well intervention portfolio, helping operators reduce the cost to construct new wells and extend the life of old wells.

About Halliburton

Founded in 1919, Halliburton celebrates its 100 years of service as one of the world's largest providers of products and services to the energy industry. With approximately 60,000 employees, representing 140 nationalities in more than 80 countries, the company helps its customers maximize value throughout the lifecycle of the reservoir – from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production throughout the life of the asset. Visit the company’s website at www.halliburton.com. Connect with Halliburton on Facebook, Twitter, LinkedIn, Instagram and YouTube.

NOTE: The statements in this press release that are not historical statements, including statements regarding future financial performance, are forward-looking statements within the meaning of the federal securities laws. These statements are subject to numerous risks and uncertainties, many of which are beyond the company's control, which could cause actual results to differ materially from the results expressed or implied by the statements. These risks and uncertainties include, but are not limited to: the continuation or suspension of our stock repurchase program, the amount, the timing and the trading prices of Halliburton common stock, and the availability and alternative uses of cash; changes in the demand for or price of oil and/or natural gas; potential catastrophic events related to our operations, and related indemnification and insurance matters; protection of intellectual property rights and against cyber-attacks; compliance with environmental laws; changes in government regulations and regulatory requirements, particularly those related to oil and natural gas exploration, radioactive sources, explosives, chemicals, hydraulic fracturing services, and climate-related initiatives; the impact of federal tax reform, compliance with laws related to income taxes and assumptions regarding the generation of future taxable income; risks of international operations, including risks relating to unsettled political conditions, war, the effects of terrorism, foreign exchange rates and controls, international trade and regulatory controls and sanctions, and doing business with national oil companies; weather-related issues, including the effects of hurricanes and tropical storms; changes in capital spending by customers; delays or failures by customers to make payments owed to us; execution of long-term, fixed-price contracts; structural changes and infrastructure issues in the oil and natural gas industry; maintaining a highly skilled workforce; availability and cost of raw materials; agreement with respect to and completion of potential acquisitions and integration and success of acquired businesses and operations of joint ventures. Halliburton's Form 10-K for the year ended December 31, 2018, Form 10-Q for the quarter ended June 30, 2019, recent Current Reports on Form 8-K and other Securities and Exchange Commission filings discuss some of the important risk factors identified that may affect Halliburton's business, results of operations, and financial condition. Halliburton undertakes no obligation to revise or update publicly any forward-looking statements for any reason.

(a) During the three months ended June 30, 2019, Halliburton recognized a pre-tax charge of $247 million related to asset impairments and severance costs. See Footnote Table 1 for further details. See Footnote Table 1 for Reconciliation of As Reported Operating Income to Adjusted Operating Income. See Footnote Table 2 for Reconciliation of As Reported Net Income to Adjusted Net Income.

(a) During the nine months ended September 30, 2019, Halliburton recognized a pre-tax charge of $308 million related to asset impairments and severance costs. During the nine months ended September 30, 2018, Halliburton recognized a pre-tax charge of $265 million related to a write-down of its remaining investment in Venezuela, consisting of receivables, fixed assets, inventory and other assets and liabilities.

HALLIBURTON COMPANY Condensed Consolidated Balance Sheets 

(a) During the first quarter of 2019, Halliburton adopted a new lease accounting standard, resulting in $1.0 billion of additional assets and liabilities on the balance sheet.

HALLIBURTON COMPANY Condensed Consolidated Statements of Cash Flows (Millions of dollars) (Unaudited) Nine Months Ended Three Months

(a) Working capital includes receivables, inventories and accounts payable. See Footnote Table 3 for Reconciliation of Cash Flows from Operating Activities to Free Cash Flow.

HALLIBURTON COMPANY Revenue and Operating Income Comparison By Operating Segment and Geographic Region (Millions of dollars) (Unaudited) 

HALLIBURTON COMPANY Revenue and Operating Income Comparison By Operating Segment and Geographic Region (Millions of dollars) (Unaudited) 

FOOTNOTE TABLE 1 HALLIBURTON COMPANY Reconciliation of As Reported Operating Income to Adjusted Operating Income (Millions of dollars) (Unaudited) 

FOOTNOTE TABLE 2 HALLIBURTON COMPANY Reconciliation of As Reported Net Income to Adjusted Net Income (Millions of dollars and shares except per share data) (Unaudited) 

FOOTNOTE TABLE 3 HALLIBURTON COMPANY Reconciliation of Cash Flows from Operating Activities to Free Cash Flow (Millions of dollars) (Unaudited) 

Conference Call Details

Halliburton Company (NYSE: HAL) will host a conference call on Monday, October 21, 2019, to discuss its third quarter 2019 financial results. The call will begin at 8:00 AM Central Time (9:00 AM Eastern Time).

Please visit the website to listen to the call via live webcast. You may also participate in the call by dialing (888) 393-0263 within North America or +1 (973) 453-2259 outside of North America. A passcode is not required. Attendees should log in to the webcast or dial in approximately 15 minutes prior to the start of the call.

A replay of the conference call will be available on Halliburton’s website until October 28, 2019. Also, a replay may be accessed by telephone at (855) 859-2056 within North America or +1 (404) 537-3406 outside of North America, using the passcode 6347766.

https://www.businesswire.com/news/home/20191021005098/en/Halliburton-Announces-Quarter-2019-Results&ct=ga&cd=CAIyHGI5ZGQzZTA5NzE2NzVkOTk6Y28udWs6ZW46R0I&usg=AFQjCNHbhxiQz0PUvuehah1YFkyyELrvz

News Uhuru dims plan to build refinery for Kenya crude

President Uhuru Kenyatta said Sunday that Kenya would use the Lamu Port to export crude from the Turkana oil fields, dimming plans of building a refinery at the facility. FILE PHOTO | NMG

President Uhuru Kenyatta said Sunday that Kenya would use the Lamu Port to export crude from the Turkana oil fields, dimming plans of building a refinery at the facility.

Mr Kenyatta said Kenya’s oil would be exported in form of crude. The government had earlier announced plans to build an oil processing facility following assessments that the country’s crude oil deposits were insufficient to justify the construction of a refinery.

“Lamu will play host to the newest port on the East African coast, which will begin its operations initially as a transshipment hub for global shipping lines,” said Mr Kenyatta while addressing the nation during Mashujaa Day celebrations in Mombasa.

"It will be supported by a special economic zone that is expected to attract investors from across the world to undertake various economic activities and create jobs for our people," he added. "Our aspiration is to link the Lamu port, to the Lamu Port, South Sudan, Ethiopia, transport corridor through road infrastructure. Our aim being to make the Lamu the port of choice for transshipment, export of goods through the EPZ as well as exports of Kenya’s crude oil."

The port is Mr Kenyatta’s government initiative to develop a second deep sea port along the Kenyan coast. The first berth at the port is complete with the second and third berths expected to be completed by December 2020. Construction of the first three berths out of the 32 expected started with dredging works in December 2016.

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Mr Kenyatta’s announcement Sunday underlines the government’s reluctance to build an oil refinery. Petroleum Principal Secretary Andrew Kamau had earlier said that a refinery would make money only when it has refining capacity of at least 400,000 barrels a day.

Kenya previously had a crude oil refinery in Mombasa but halted its operations in 2013 after plans for a Sh100 billion upgrade were abandoned on the advice of consultants who said they were not economically viable. The government took it over in 2016 and converted it into a storage facility.

In June, the government signed agreements with Total, Tullow Oil and Africa Oil Corp to develop a 60,000 -80,000 barrels per day crude processing facility for oil discovered in northern Kenya. In addition to the processing facility, a crude oil export pipeline from Lokichar in Turkana County to Lamu was also part of the deal.

"The infrastructure installed for the foundation stage will be utilised for the development of the remaining oil fields and future oil discoveries in the region, allowing the incremental development of these fields to be completed at a lower unit cost," Tullow Kenya had said earlier.

Kenya discovered commercial oil in 2012 in its Lokichar basin, which Tullow Oil estimates contains an estimated 560 million barrels in proven and probable reserves. Tullow has said this would translate to 60,000 to 100,000 barrels per day of gross production.

https://www.businessdailyafrica.com/news/Uhuru-dims-plan-to-build-refinery/539546-5319340-vj8fi7/index.html&ct=ga&cd=CAIyGmVlZjU3YTM5NTlmOTE2ZDg6Y29tOmVuOkdC&usg=AFQjCNHczukGOoI5cXXgPUP5Eqyxe7RbU

SOFIA (Bulgaria), October 21 (SeeNews) - Bulgaria inaugurated on Monday an 11-km gas pipeline from the Turkish border to compressor station Strandzha, which will serve as part of the extension of Gazprom's TurkStream pipeline toward Serbia, the energy ministry said.

The project also included the construction of Strandzha gas metering station, the ministry said in a statement.

The construction of the Balkan Stream pipeline and gas metering station is an expression of Bulgaria's commitment to retain its strategic position on the European gas market, the ministry noted.

Works on the project were completed by a local tie-up under a 27.7 million levs ($15.8 million/14.2 million euro) contract.

According to registry agency data, Stroymontazh controls 50% interest in the tie-up, Glavbolgarstroy owns a 45%, while GBS - Infrastructurno Stroitelstvo holds 5%.

Last month, Bulgaria's gas transmission system operator Bulgartransgaz signed a 1.1 billion euro contract with Saudi-led consortium Arkad for the construction of a gas pipeline, which will connect the country's existing gas transmission system to the border with Serbia, and will carry gas from TurkStream.

The offshore section of the TurkStream pipeline stretching 930 km across the Black Sea from Russia to Turkey consists of two parallel strings with annual throughput capacity of 15.75 billion cubic metres of gas each. One string is intended for consumers in Turkey, while the second will carry gas to customers in Europe through Bulgaria.

(1 euro = 1.95583 levs)

https://seenews.com/news/bulgaria-inaugurates-11-km-gas-pipeline-section-of-balkan-stream-673239&ct=ga&cd=CAIyGjU0NTE4ZWVlZTY3NTRiMmQ6Y29tOmVuOkdC&usg=AFQjCNH4-R1GiNeJwfEkBI0AdEpnFJqwu

U.S. oilfield services company McDermott International Inc (MDR.N) on Monday agreed with some of its lenders for additional funding of up to $1.7 billion, sending its shares up 25% in trading before the bell.

Under the terms, the company said it would have immediate access to $650 million in financing, comprising $550 million under a term loan facility and $100 million under a letter of credit facility.

“The agreement provides near-term liquidity for the company to manage working capital and provide performance guarantees on expected new awards,” Chief Executive Officer David Dickson said.

The company said it intends to use the funds to finance working capital and support issuance of required performance guarantees new projects.

The Houston-based company also withdrew its full-year forecast. It had previously forecast 2019 revenue of $9.5 billion and an adjusted loss of 32 cents per share.

McDermott also said it had terminated its previously announced sale of its industrial storage tank business.

https://www.reuters.com/article/us-mcdermott-international-outlook/mcdermott-international-in-financing-deal-of-up-to-17-billion-idUSKBN1X01DT

Royal Dutch Shell plans to sell its onshore upstream assets in Egypt’s Western Desert to focus on expanding its Egyptian offshore gas exploration, Shell Egypt said on Sunday.

Having won three oil and two gas concessions in Egypt last February, senior executive last week told Reuters that the company would start operating the new areas in the second half of next year.

“We remain committed to Egypt and see our future in supporting the government’s energy hub vision by growing Shell positions across the offshore and LNG value chain,” Wael Sawan, Shell upstream director, said in a statement.

“This is where we can best leverage our expertise, deliver the strongest added value to Egypt and optimise our portfolio to ensure the company delivers a world class investment case.”

Shell Egypt Chairman Khaled Kacem said that he expects talks with potential buyers of the Western Desert assets to start in the final quarter of this year.

https://uk.reuters.com/article/shell-egypt/shell-egypt-to-sell-assets-in-western-desert-idUKL5N2750FH

Africa’s biggest crude producer remains stuck on imported fuels

By Elisha Bala-Gbogbo on 10/21/2019

ABUJA (Bloomberg) --Africa’s biggest oil producer is trying to get its refineries working in an attempt to wean itself off imported fuel. Yet again.

Over the past 12 years, Nigeria tried and failed four times to crank up its aging and unprofitable crude-processing plants. Now the state-run energy company is giving it another shot that, if successful, could end the nation’s reliance on fuel imports. However, the country’s recent track record means there’s skepticism about the latest effort.

“For our refineries that have not been properly maintained for years, it might be easier to build a new one,” said Cheta Nwanze, head of research at SBM Intelligence, a Lagos-based risk advisory.

Refining Revamp. The West African country of about 200 million people imports more than 90% of products like gasoline and diesel, swapping its prized export -- crude -- for petroleum products that people need in their everyday lives.

The Nigerian National Petroleum Corp., or NNPC as the state energy company is known, operates four refineries that have long run at a fraction of their capacity. The newest is almost four decades old. By successfully making its own fuels, Nigeria would stop being reliant on traders bringing supplies on tankers from thousands of miles away -- with all the extra costs that entails.

Truly Committed. Mele Kyari, the newly appointed group managing director of NNPC, says this time will be different.

He’s made fixing the plants a key part of his agenda since taking the helm of the company in July, and says President Muhammadu Buhari is the country’s first leader in years to be committed to the revamp. Kyari has revived a target to upgrade the plants and end fuel imports by 2023, after the company missed a previous goal for the end of this year.

Minister of State for Petroleum Resources Timipre Sylva said in an interview in London this month that the overhaul should be successful this time because Nigeria is asking the owners of the refinery technology to get more involved in the work. Once the plants are operational, they will be run by external people, which will also help, he said.

The work is scheduled to begin in earnest in January, first on the Port Harcourt complex, a two-refinery facility with the capacity to process 210,000 boepd. Repairs will then move to the smaller refineries.

Dangote Boost. Some of Nigeria’s challenges to become more self-sufficient in fuel may soon be alleviated for another reason. In the next few years, a new, privately owned 650,000 bpd refinery is due to come online. In theory, it could meet all of the country’s fuel needs and have enough left over for exports.

The plant, being built by Africa’s richest man Aliko Dangote, is not owned by the Nigerian state though. That means that the country would have to pay market prices -- similar to those charged by traders -- for the fuel the refinery churns out. There would be little reason for Dangote to subsidize Nigeria’s domestic fuel prices if it were more profitable for the refinery to sell elsewhere.

The skepticism that state-run plants can return to full operation stems from NNPC’s previous attempts. Efforts to overhaul its refining industry -- in 2007, 2010, 2012 and 2016 -- all failed to work out. The state energy company has to compete with other domestic demands for funding, such as health care, education and other social services.

Three years ago, Nigeria sought external financing for its refineries following a plunge in crude prices, oil theft and attacks on its pipelines by militants and other saboteurs. That effort crumbled after it failed to convince investors of the viability of the venture.

NNPC is talking to the African Export-Import Bank and other financial institutions to fund the revamp.

“The money to comprehensively fix the refineries is simply not there,” said Ayodele Oni, chair of the energy and natural resources practice at Bloomfield Law in Lagos. “It is a difficult task to attract any significant funding required for their repairs in their present state.”

Related News ///

FROM THE ARCHIVE ///

http://ow.ly/r5WO50wQE4q

U.S. mulls extending Chevron’s Venezuela waiver, with more conditions

By Ben Bartenstein and Saleha Mohsin on 10/20/2019

WASHINGTON (Bloomberg) - The Trump administration is considering an extension of Chevron’s waiver to operate in Venezuela, albeit with even greater limitations, according to people familiar with the matter.

The 90-day sanctions reprieve would allow Chevron to continue its role as the last major U.S. oil producer in the nation beyond the Oct. 25 expiration date. Still, the Treasury Department wants to advance its “maximum pressure strategy” to further limit Venezuela’s crude production, the people said.

One of the people, all of whom were granted anonymity to discuss the deliberations, said on Friday evening that the decision-making process was in its final stages. Another person said that no final decision has been made and it was unclear whether other companies might receive a similar break.

The concern is that Chevron’s joint-venture projects in Venezuela are providing financing to help Nicolas Maduro’s regime pay back its debt to Russia’s state oil giant Rosneft PJSC, which could encourage more loans in the future. Still, there’s also a desire to maintain some American presence in the nation’s oil industry in the event of a political transition. The U.S. and nearly 60 countries recognize National Assembly President Juan Guaido as Venezuela’s rightful leader.

“We are a positive presence in Venezuela, and we are hopeful that General License 8C is renewed so that we can continue operations in the country for the long-term,” Ray Fohr, a Chevron spokesman, said Friday night in a statement. “We have dedicated investments and a large work force who are dependent on our presence.”

The Treasury Department did not respond to a request for comment.

Chevron has operated in the South American nation for almost a century, since the discovery of the Boscan field in the 1920s. It has outlasted many other oil companies, including Exxon Mobil Corp., which left after a series of industry nationalizations during Hugo Chavez’s time as president.

Venezuela’s oil output has fallen from a high of 3.7 MMbpd in 1970 to less than 700,000 today, according to data compiled by Bloomberg.

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FROM THE ARCHIVE ///

http://ow.ly/dYER50wQmJt

Phoenix Petroleum Philippines plans to formalize a joint venture agreement with CNOOC Gas and Power Group Co. Ltd., a subsidiary of China National Offshore Oil Corp. for an integrated liquefied natural gas project this year. Phoenix signed a memorandum of understanding with CNOOC Gas for the construction of a new integrated LNG import and regasification terminal in Batangas in April 2018. Phoenix said a prospectus submitted to the stock exchange that a formal joint venture agreement was “expected to be entered into between the parties during the second half of 2019.” CNOOC is the largest offshore oil and gas company in China and one of the largest independent oil and gas exploration and production companies in the world. “Discussions [are] still ongoing with CNOOC. In parallel, we are exploring other routes to market LNG leveraging on our existing capabilities as a trading/marketing company. We continue to engage various stakeholders for the project for potential commercial partnerships,” Phoenix senior vice president Raymond Zorrilla said. Phoenix said the company planned to own a 40-percent stake in Tanglawan Philippine LNG Inc. with the remaining 60 percent of shares in Tanglawan to be held by CNOOC Gas. Phoenix, on the other hand, will own 60 percent of shares in Liwanag Philippine Property Management Inc. with the remaining 40 percent of shares to be held by CNOOC Gas.Both Tanglawan and Liwanag are special purpose vehicles. Tanglawan will be responsible for the construction, operation and maintenance of the LNG facilitywhile Liwanag will be responsible for the land and other permit requirements related to the LNG project. Tanglawan secured a notice to proceed from the Department of Energy on Dec. 21, 2018 which stipulated that the LNG project would be located on a plot of land in Bauan, Batangas. “Formal agreements relating to the LNG facility project, such as a project development agreement and both shareholder agreements for Tanglawan and Liwanag are still ongoing,” Phoenix said. Phoenix said it would pursue the LNG project, cognizant of the increasing demand for cleaner and more secure energy alternatives. “The company believes that LNG will serve as a critical energy source for the future as the Philippines transitions from conventional fuels to renewables in an attempt to de-risk its energy dependence on imported energy resources,” it said.

http://manilastandard.net/business/power-technology/308105/phoenix-set-to-sign-final-contract-with-cnooc-gas.html&ct=ga&cd=CAIyGjhhN2FiYzg4ZWE0MjI3MzE6Y29tOmVuOkdC&usg=AFQjCNGZ7N0faByeFYaqSVHfpnTD3MWoG

The first and third-largest oilfield service companies in the world saw their earnings hit in the third quarter due to the slowdown in U.S. shale drilling.

Schlumberger took a $12.7 billion impairment charge related to its North American business, a rather dramatic write-down. That led to an $11.4 billion loss for the quarter, the largest in the company’s history. “That’s a sizable writedown from pressure pumping business. That just tells you the state of the North American onshore market being pretty poor,” said Anish Kapadia, founder of oil and gas consultancy firm AKap Energy.

Halliburton also saw its earnings hit by the slowdown in shale drilling and the oilfield services giant shifted its focus to international markets as the signs of a shale rebound do not appear to be imminent.

Rig counts have fallen sharply over the past year, down more than 20 percent from late 2018. The number of wells drilled has also declined and production growth has dramatically slowed. Halliburton said that its third-quarter revenues from North America plunged by 11 percent from the prior three-month period as shale E&Ps cutback on activity.

“US and international markets continue to diverge,” Halliburton CEO Jeff Miller said on an earnings call on Monday. “International activity growth is gaining momentum across multiple regions. Meanwhile, operators' capital discipline weighs on North American activity levels.”

Miller said that he was “excited” after visiting Halliburton customers in the “eastern hemisphere,” and that the company sees strong growth in Europe, Asia, and Australia.

But the mood surrounding U.S. shale was entirely different. Miller noted that the U.S. land rig count fell by 11 percent between the second and third quarters, the sharpest contraction for the time of year in a decade. “While, historically, the third quarter used to be the busiest in terms of hydraulic fracturing activity in the US, stage counts declined every month this quarter,” Miller said.

He added that because oil producers themselves are under fire from investors, they are haggling with service companies (like Halliburton and Schlumberger) for lower prices. Related: The Pipeline That Could Derail China's LNG Boom

Halliburton stacked more equipment in the third quarter than it did in the first and second-quarter combined. “While this impacts our revenues, we would rather err on the side of stacking than work for insufficient margins and wear out our equipment,” Miller said.

Schlumberger echoed Halliburton’s description of the divergence between U.S. and international markets.

The outlook going forward does not look any better. WTI is in the low-$50s, with little signs of life. Worse, most analysts see a supply glut in 2020, which seems to pose more downside risk to oil prices than upside.

In the fourth quarter, “we expect customer activity to decline across all basins in North America land, impacting both our drilling and completion businesses,” Miller warned. Low natural gas prices are also adding to the industry’s woes.

Schlumberger’s outlook was similar. “We are anticipating a year-end slowdown in North America similar to last year due to operator budget constraints,” Schlumberger CEO Olivier Le Peuch told investors on its earnings call. But, the deceleration in 2019 “started earlier” and will be “more pronounced” compared to last year, he said.

Le Peuch said that U.S. oil production growth rate has declined for the last eight months, and will declined further in 2020. “That’s sort of a recession,” Le Peuch said, but “the prospect for international activity growth remain firmly in place.” He did caution, however, that activity could decline in Ecuador and Argentina, both of which are facing political and economic headwinds that could impact the oil industry.

Miller said that Halliburton will undertake “further cost reductions,” which could save $300 million. Less than two weeks ago, the company said that it was laying off 650 workers across Colorado, New Mexico, North Dakota and Wyoming.

Halliburton’s share price jumped roughly 7 percent after its earnings release on Monday, most likely related to the pledge for more “cost-cutting,” which may turn out to be a euphemism for more layoffs. The company declined to offer more details on this plan when pressed by analysts on its earnings call.

Evercore ISI analyst James West, who was on the call, said Halliburton was “showing leadership by walking away from unprofitable or low return work.” Related: There’s Tremendous Room For Growth In Offshore Oil & Gas

The oilfield services company is one of the largest in the sector, and its chief executive argued that it could essentially batten down the hatches and ride out the storm. Smaller competitors will get dragged under, and the attrition has and will continue to take hold. Halliburton’s size allows it to “flex down with the market,” Miller said.

Ultimately, the problems afflicting Halliburton and Schlumberger are illustrative of the broader slowdown in the shale industry, weighed down by debt, lack of profits and increased investor scrutiny. This has already translated into slower oil production growth. “The record-breaking 2018 growth will not be replicated in 2019,” Miller said. “In fact, current projections for 2020 indicate a further decline in production from the current-year estimates.”

Miller saw the upside in this. Slower oil production from the U.S. might mean that activity will need to pick up internationally in order to fill the gap, something that ends up offering opportunities to multinational oilfield service companies.

By Nick Cunningham of Oilprice.com

More Top Reads From Oilprice.com:

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Australia-listed Oil Search Ltd on Tuesday posted a 24% drop in quarterly revenue and cut its 2019 production guidance after damage to a mooring system dented output.

The company also reduced 2019 capital spending by about 15%, due to delays in securing agreements with the Papua New Guinea government so preliminary engineering work can begin on a $13 billion plan to double the country’s LNG exports.

Papua New Guinea’s biggest company restricted output in August after damage to the mooring system at a facility in the Gulf of Papua.

For the three months to Sept. 30, production slipped 10% to 6.81 million barrels of oil equivalent (mmboe) - its lowest September quarter output since 2014.

Quarterly revenue fell to $361.1 million from $474.9 million last year, which the company blamed on lower sales and weaker liquefied natural gas (LNG) and oil prices.

Both figures missed UBS estimates. The brokerage had estimated output at 7.4 mmboe, while sales revenue was expected at $379 million.

The oil and gas explorer said it now expects 2019 full year production of 27-29 million barrels of oil equivalent (mmboe), from an earlier forecast of 28-31 mmboe.

Repairs to the damaged mooring chain had been completed successfully in mid-October and normal loading operations have now resumed, it said, with production ramping up.

The cut in capital spending comes as Oil Search gears up for the next leg of development with its partners through the Papua LNG project, led by Total SA, and an expansion of PNG LNG, led by Exxon Mobil Corp.

The Papua LNG project was sanctioned by the government in September, relieving uncertainty stemming from new prime minister James Marape’s agenda for the country to reap more from its resources sector.

However Exxon now needs to reach an agreement with the government for the development of the P’nyang gas field before the companies can begin engineering design work for the PNG LNG expansion.

“Discussions ... on the P’nyang Gas Agreement recommenced late in the third quarter, with the agreement targeted to be signed before year end,” Managing Director Peter Botten said in a statement.

The partners had hoped to begin preliminary work before the end of this year, aiming to make a final investment decision on the project in 2020.

https://uk.reuters.com/article/oil-search-outlook/update-2-oil-search-cuts-2019-production-outlook-slashes-capex-on-project-delays-idUKL3N2764YS

A lawyer for New York’s attorney general on Tuesday told a state judge Exxon Mobil Corp (XOM.N) used two sets of books to hide the true cost of climate change regulations from investors, while an attorney for the oil major assailed the claims as false and politically motivated.

The lawyers’ opening statements kicked off a long-awaited trial in a civil lawsuit filed by the attorney general last year accusing Exxon of defrauding investors out of up to $1.6 billion.

The trial, expected to last up to three weeks, will take place before Justice Barry Ostrager in Manhattan Supreme Court without a jury and could feature testimony from Rex Tillerson, who served as Exxon chief executive officer and U.S. Secretary of State.

It is the first of several lawsuits currently pending against major oil companies related to climate change to go to trial.

The attorney general sued Exxon in October 2018 under the Martin Act, a New York state law that had been used primarily to go after financial fraud.

The lawsuit claimed Exxon falsely told investors it had properly evaluated the impact of future climate regulations on its business using a “proxy cost” of up to $80 per ton of carbon emissions, but internally used figures as low as $40 per ton or none at all.

“Exxon only ever told its investors about a single set of assumptions,” Kevin Wallace, acting chief of the New York Attorney General’s Investor Protection Bureau, told Ostrager Tuesday.

“What we are saying, and the law demands, is that Exxon not mislead its investors,” he said.

Theodore Wells, a lawyer for Exxon, said that after Tillerson became chief executive in 2006, the company put in place a “robust system” to manage the risk of increasing climate change.

He said the $80 per ton proxy cost represented a “global,” “macro level” assessment of the cost, while lower figures, known as greenhouse gas or GHG costs, were used for particular capital projects.

“There is no document that says ... proxy costs and GHG costs were one and the same,” he said.

Wells also accused former New York Attorney General Eric Schneiderman of bringing the case for political reasons.

“They didn’t stay in their lane of objectivity and fairness,” he said.

Massachusetts is separately investigating whether Exxon concealed its knowledge of the role fossil fuels play in climate change.

Both Massachusetts and New York began investigating Exxon after news reports in 2015 saying company scientists had determined that fossil fuel combustion must be reduced to mitigate the impact of climate change.

Those reports, by InsideClimate News and the Los Angeles Times, were based on documents from the 1970s and 1980s. Exxon said the documents were not inconsistent with its public positions.

Exxon and other oil companies including BP Plc (BP.L), Chevron Corp (CVX.N) and Royal Dutch Shell (RDSa.AS) face lawsuits by cities and counties across the United States seeking funds to pay for seawalls and other infrastructure to guard against rising sea levels brought on by climate change.

https://www.reuters.com/article/us-exxon-mobil-lawsuit/exxon-new-york-prosecutors-face-off-in-climate-change-fraud-trial-idUSKBN1X1181

London — LNG shipping rates remained near 10-month highs Tuesday as US sanctions on a Chinese shipping giant led to a vessel shortage in both the Atlantic and Pacific basins, S&P Global Platts data show.

Reload opportunities for Atlantic Basin traders to move cargoes east to take advantage of the rising Asian market are limited though.

The rally in freight rates has eaten into or shut arbitrage incentives to reload LNG, and while the spike is thought to be short-lived, LNG may continue to respond to lingering strength in freight rates, according to sources.

The Platts LNG freight rate for cargoes loading out of Zeebrugge, Belgium to Japan or South Korea hit $3.36/MMBtu October 17, its highest level since December 2018. The shipping rate has remained little changed since then and was assessed at $3.33/MMBtu Tuesday.

Europe looks set for more LNG imports in the near term as the TTF and NBP prompt months are due to retain premiums to the JKM spot price amid the rising charter costs to Japan and South Korea, traders say.

US sanctions against subsidiaries of Chinese shipping company COSCO triggered spot requirements for loading out of Tangguh, Indonesia, and Australia, as at least five vessels part-owned by COSCO subsidiaries could not carry out loadings.

"Part of the higher rates is because of the US sanctions. But if a trade agreement is reached between US and China, what will then happen?" a Germany-based natural gas trader said.

Despite a number of specialized Arc7 icebreaker vessels serving the Novatek-operated Yamal LNG plant in northern Russia no longer being subject to US sanctions, they are not active in the spot market and unlikely to put any pressure on freight rates as a result.

EARLY NOVEMBER ARRIVALS

European LNG market participants are anticipating a swathe of arrivals in early November.

A London-based trader said the volume of cargoes arriving in November will balance fundamentals slightly by taking length out of the market.

Another London-based trader said he believed cargoes are likely to remain stuck in the Atlantic Basin for now, despite expectations of lower shipping rates as the spread between TTF and JKM is not wide enough yet for most traders to reload and send LNG to Asia.

The spread between the Platts Northwest European second half of November price and the JKM H2 December price currently sits at $2.106/MMBtu, as of Tuesday, Platts data showed, making Europe the more attractive destination for spot Atlantic LNG cargoes.

The Platts JKM, the benchmark Asian LNG price, was last assessed at $6.817/MMBtu, and despite showing signs of recovery since mid-March, the Atlantic arbitrage to Asia - Atlantic LNG cargoes diverted to Asia - remains largely closed with shipping rates where they were assessed Tuesday.

European regasification rates have remained strong as a result, with sendout across the UK, Belgium, France, the Netherlands, Italy and Spain at 208 million cu m/d Monday, data from S&P Global Platts Analytics shows. This represent a 30% increase compared with Gas Year 2018 and a near threefold increase from GY-17's regasification rate.

LNG volumes are set to remain strong since US exports continue to mainly head to Europe rather than Asia. The TTF-US Gulf Coast netback has recovered its premium to the JPN-USGC netback in October, with the premium rising to 0.562 cent/MMBtu on Tuesday.

FREIGHT OUTLOOK

Market participants expect the surge in rates to calm down in the fourth quarter of 2019, leaving room for Atlantic sellers to keep offers into Europe elevated, amid a well bid Northeast Asian market for December. Offers for cargoes delivered into Northwest Europe for December are currently heard flat to TTF.

For now though, Atlantic sellers remain incentivized to keep cargoes within the basin as the current strength of freight rates does not favor longer journeys.

Further out, Atlantic Basin market participants will be watching for the possibility of a prolonged cold snap in Asia, which could lead to Atlantic cargoes being shipped eastward, and eating into the vast volume of gas in storage at European terminals.

Other supportive factors in the Asian market include South Korea's KOGAS seeking higher volumes heading into the winter months, according to market participants.

-- Antoine Simon, antoine.simon@spglobal.com

-- Piers De Wilde, piers.de.wilde@spglobal.com

-- Wyatt Wong, wyatt.wong@spglobal.com

-- Edited by Keiron Greenhalgh, keiron.greenhalgh@spglobal.com

http://plts.co/8Xwz50wSkDP

Washington — Political risks to Canada's 590,000 b/d Trans Mountain oil pipeline expansion appear to have eased after Prime Minister Justin Trudeau's Liberal Party picked up enough seats to resist pressure from smaller parties on the left that oppose the project.

Still, the project to move more Alberta heavy crude barrels to British Columbia and onto Asian importers remains far from a done deal, with more legal and regulatory challenges possible.

Trudeau's Liberals won 157 seats in Parliament, according to preliminary results, 13 seats short of a majority government but more than pollsters had predicted.

A smaller margin could have forced Trudeau, who supports the Trans Mountain expansion, to strike a deal with the New Democrat or Green parties to form a government. Both groups campaigned to stop the project.

"The fact that this is a relatively strong minority government ... definitely tilts it more in favor of the Liberals' prior policy preferences," said Rory Johnston, commodity economist at Scotiabank. "But a minority is still a minority.

"Whether it's one or 30 votes you need, you're still going to need to work with another party. And that party could theoretically take down the government if they wanted to, but I think at this stage no one really wants to."

Finance Minister Bill Morneau said in a BNN Bloomberg interview Tuesday that the government remained committed to completing Trans Mountain.

THREE DELAYED PIPELINES

S&P Global Platts Analytics did not change its outlook for Trans Mountain to start up sometime in 2022.

"The stronger-than-expected election result for Trudeau's Liberal Party directionally reduces risks to his favored Trans Mountain expansion, especially if the federal government must navigate legal and political obstacles that could arise in the months ahead," said Paul Sheldon, Platts Analytics' chief geopolitical adviser.

"But we did not expect yesterday's election to notably change the fate of the project, regardless of the result, due to support from both Trudeau and the Conservatives," Sheldon added.

Platts Analytics expects at least two of Canada's three delayed oil export projects to be completed by the end of 2022: Trans Mountain, Enbridge's 370,000 b/d Line 3 replacement to the US Midwest and TC Energy's 830,000 b/d Keystone XL pipeline to Nebraska.

ENERGY STAKES

The Conservative Party led by Andrew Scheer won 121 seats, a gain of 23 seats, compared with the Liberals' loss of 29 seats.

Trudeau campaigned on implementing a national climate policy, including taxing carbon emissions and setting targets for reaching carbon neutrality by 2050.

Scheer has promised to scrap Trudeau's climate policies and proposed building a coast-to-coast energy corridor to accelerate permitting of pipelines, electricity projects and other infrastructure.

A lack of sufficient pipeline capacity to move Alberta's oil to market pushed Western Canadian Select crude to a record wide discount to WTI late last year, forcing the provincial government to impose output curtailments in January.

S&P Global Platts assessed WCS-Hardisty at a $17.05/b discount to WTI-Cushing Monday, 5 cents/b wider than Friday and the widest since May 30.

Alberta has eased the curtailment month by month, with October cuts at 100,000 b/d, narrowing to 80,000 b/d by December. Platts Analytics expects Alberta production to trend upward through April, before falling for spring maintenance.

-- Meghan Gordon, meghan.gordon@spglobal.com

-- Edited by Richard Rubin, newsdesk@spglobal.com

http://plts.co/7tWa50wRAQb

Washington — The US may intervene in the interim Venezuelan government's legal fight with creditors over control of Citgo, but it wants negotiations over this weekend's bond payment deadline to play out first, a State Department official said Tuesday.

PDVSA has until Sunday to make a $913 million payment on 2020 bonds, which are backed by a 50.1% stake in its US refining arm Citgo.

"We've been tracking the negotiations very, very closely, and we want to make sure that there's an opportunity for this to be resolved between the parties before there's any other action taken," US State Department Deputy Assistant Secretary Carrie Filipetti said Tuesday on the sidelines of an Atlantic Council event in Washington.

"We're aware of the sensitivity of this issue," Filipetti added. "It's important to us that we're doing as much as we can to resolve it in a fair way."

Control of Citgo's three complex US refineries are at stake: its 418,000 b/d plant in Lake Charles, Louisiana; 157,000 b/d plant in Corpus Christi, Texas; and 179,265 b/d plant in Lemont, Illinois.

Before the US imposed sanctions in January, PDVSA depended on Citgo for supply of refined products and diluent, and as an export destination for its crude.

PDVSA ASKS FOR MORE TIME

Alejandro Grisanti, a director on the interim government's PDVSA board, told reporters at the same event he remains optimistic either a deal for a new payment plan can be reached with bondholders or the US administration can take action to prevent a default.

The 2020 bondholders currently have a Treasury Department license shielding them from Venezuela sanctions. The administration could revoke the waiver to block bondholders from taking control.

Grisanti said the Guaido administration has been making the case to the US government that losing Citgo would be a major blow for Venezuela's transition to democracy.

"The people need to recognize and understand that these are debt that we are receiving from Nicolas Maduro," he said. "The transition is taking longer than what we expected and would like, but we are sure we will win this battle.

"We're basically asking for time in order to try to look for the solution of all the claims that PDVSA has," he added.

Grisanti said Venezuela's oil production collapse will accelerate as long as Maduro stays in power, likely hitting 450,000 b/d next year.

VENEZUELA OIL OUTPUT

S&P Global Platts estimates Venezuela's October oil production at 650,000 b/d, which it sees falling to 550,000 b/d by December 2020. However, "risks are greater to the downside," said Paul Sheldon, chief geopolitical adviser.

Venezuela's crude output shrank to 600,000 b/d in September, according to the latest Platts OPEC survey, even less than the 650,000 b/d it pumped in January 2003 amid a PDVSA strike.

Luisa Palacios, Citgo's chairwoman, said in Washington earlier this month the company has aggressively tried to consolidate its debt, including replacing maturing $1.2 billion lines of credit with a five-year, $1.2 billion term loan, and $1.87 billion in bonds with a four-year term loan and five-year bonds.

Palacios said Citgo still represents roughly 10% of total finished product exports out of the US Gulf Coast, but said this year has been a challenge for the company, primarily because it lost its biggest customer, PDVSA. But other factors, including Mexico's declining oil output and production cuts in Alberta, Canada, have caused heavy crude supply to shrink.

"This is not the best environment, particularly for the type of refineries that we have," she said.

CHEVRON SANCTIONS WAIVER

State's Filipetti on Tuesday also shed light on the decision to extend Chevron's sanctions waiver allowing it to continue operating in the Venezuelan upstream until January 22. She said the Trump administration was concerned that Chevron's exit would mean a slower restoration of Venezuela's oil sector once Maduro leaves power.

"We need to consistently be aware of the day-after scenario," she said during the Atlantic Council event.

"If some of this infrastructure collapses, there could be a real challenge, in terms of the amount of time that it takes to rehabilitate," she said. "That was part of the thinking here, as to why this is consistent with our foreign policy. I can't judge whether or not the analysis will shift over time, but the license was provided for the next 90 days consistent with that line of thinking."

-- Meghan Gordon, meghan.gordon@spglobal.com

-- Brian Scheid, brian.scheid@spglobal.com

-- Edited by Jim Levesque, newsdesk@spglobal.com

http://plts.co/2jvt50wRzKt

Shell exits two Caspian Sea projects due to high costs

By Nariman Gizitdinov on 10/21/2019

ALMATY (Bloomberg) - Royal Dutch Shell abandoned two oil projects off Kazakhstan after stubbornly high costs made them uneconomic.

Shell has exited the Khazar field, while North Caspian Operating Co. -- a joint venture including Shell -- has quit the Kalamkas-Sea project, according to TOO PSA, an entity run by the Kazakh Energy Ministry. The retreat from the fields in the Kashagan area reflects an industry-wide push to cut break-even costs as megaprojects give way to smaller endeavors with quicker returns.

Shell confirmed its withdrawal, saying the projects were “not competitive enough versus other opportunities.”

The Caspian Sea fields had seemed like an obvious fit for Shell, which is among companies already pumping oil from the giant Kashagan complex. But that project proved challenging to get going, costing Shell and its partners upwards of $50 billion as they struggled with extremes of hot and cold, as well as toxic hydrogen-sulfide gas. This time around, the steep expense couldn’t be justified.

“The decision itself highlights the project’s marginal economics in the highly competitive global portfolios of the majors,” Ashley Sherman, principal analyst at Wood Mackenzie Ltd., said in a note. “This is another reality check for the Caspian region’s oil and gas industry.”

Kazakhstan may seek new investors to develop the Kalamkas-Sea site, the Energy Ministry said in a statement. If the remaining partners in the Khazar field also decide to exit, Kazakhstan may seek other investors there too.

Khazar is part of the Zhemchuzhiny offshore development, where state-owned KazMunayGas National Co. and Oman Oil Co. work with Shell. The Anglo-Dutch oil major has already invested $900 million in the field, the ministry said.

No one at Oman Oil could be reached for comment.

North Caspian Operating Co. runs both the Kashagan and Kalamkas-Sea projects. Other partners in NCOC include Italy’s Eni SpA, KazMunayGas, Exxon Mobil Corp., Total SA and China National Petroleum Corp. The companies have worked to reduce costs at Kalamkas-Sea but have found it hard to make the development affordable, people familiar with the matter said in September.

Kazakhstan has said it expects international oil companies to invest more than $5 billion by 2025 in new developments, mostly in Kalamkas-Sea and Khazar. Yet the government has a history of disputes with foreign investors over revenue, taxes and cost-sharing at the country’s energy projects.

Related News ///

FROM THE ARCHIVE ///

http://ow.ly/43wO50wS0ou

The U.S. Supreme Court has rejected requests by a number of oil companies to block three lawsuits launched against them by state and local governments for their role in climate change.

Bloomberg reports that the oil companies—including BP, Chevron, ConocoPhillips Exxon, Shell, and Phillips 66—had requested that the cases which have been filed in Maryland, Rhode Island, and Colorado, respectively, be moved to federal court. Corporations tend to have a better chance at winning a case at federal court, Bloomberg notes.

However, the Supreme Court judges ruled that this was unnecessary, and let the cases proceed.

The plaintiffs argue that their respective jurisdictions are suffering the effects of climate change, including floods, heat waves, and storms, and the associated higher emergency response costs.

The defendants in the Maryland case argued to the Supreme Court that they will have to incur “duplicative and unrecoverable” litigation costs if the case went forward.

The Supreme Court’s ruling coincided with the start of the trial against Exxon, which New York’s Attorney General has accused of misleading investors about the effect that anti-climate change regulation and climate change itself would affect its profits. Related: Two Dead Following ISIS Attack On Iraqi Oil Field

"Exxon in effect erected a Potemkin village to create the illusion that it had fully considered the risks of future climate change regulation and had factored those risks into its business operations," the prosecution said. "As a result of Exxon's fraud, the company was exposed to far greater risk from climate change regulations than investors were led to believe."

Exxon, for its part, claims that it did not mislead investors and says the lawsuit is motivated by politics rather than anything else.

Last year, a similar case brought by the cities of San Francisco and Oakland against Big Oil ended with a ruling in favour of Big Oil. The judge in charge of the case ruled that there was no conspiracy to suppress facts about climate change.

By Irina Slav for Oilprice.com

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In 2018, the Trump administration put forward a highly controversial plan to expand offshore drilling off the U.S. Pacific and Atlantic coasts, the west coast of Florida in the Gulf of Mexico, and Alaska. Though this drilling proposal has been delayed as a result of litigation, coastal communities remain deeply concerned that the administration’s final decision will irreversibly damage the health of America’s coastal and marine environments.

Opposition to the Trump administration’s offshore drilling plan has been widespread and bipartisan. It includes governors from 17 coastal states; more than 330 municipalities; more than 2,100 local, state, and federally elected officials; the U.S. Department of Defense; the U.S. Air Force; the Florida Defense Support Task Force; NASA; and an alliance representing more than 43,000 businesses and 500,000 fishing families. Furthermore, 60 percent of voters oppose expanding offshore drilling, and more than 70 percent favor giving states the power to veto federal offshore drilling plans near their coastlines. A recent House bill to ban offshore drilling in the Atlantic and Pacific Outer Continental Shelf (OCS) planning areas passed the House with 238 votes, including 12 votes from Republicans.

Global consequences of Trump’s offshore drilling plan

The vast scale of the Trump administration’s drilling plan deserves more scrutiny and attention. Not only would it risk additional catastrophic oil spills, but it would also burn vastly more fossil fuel at a time when the Intergovernmental Panel on Climate Change says that the world has just 11 years to dramatically reduce greenhouse gas emissions in order to avoid the worst effects of climate change. In 2016, the Obama administration recognized the severity of the climate crisis and issued National Environmental Policy Act (NEPA) climate change guidance. This guidance required agencies to consider climate effect in their federal decision-making, including projects involving infrastructure, oil and gas leasing, and pipelines. Yet President Trump rescinded this guidance soon after his inauguration, leaving agencies such as the U.S. Department of the Interior without a template on how to assess climate impacts.

Increase in greenhouse gas emissions

Since Trump’s proposed plan fails to outline its true costs, CAP used calculations outlined by the Bureau of Ocean Energy Management (BOEM) and the Environmental Protection Agency (EPA) to determine the greenhouse gas (GHG) emissions that would result from the plan’s implementation.

The data show that if this plan were implemented, the resulting combustion of the additional fossil fuels extracted would add as many as 46 billion metric tons of GHG emissions to the world’s atmosphere. That is nearly seven times more than all GHG emitted by the entire United States each year. Put another way, such an increase is the equivalent of the yearly emissions from nearly 10 billion cars—nine times as many cars as are on the road worldwide today.

This vast increase in emissions has global consequences. In order to limit global temperature rise to fewer than 2 degrees Celsius, the world must restrict global emissions to fewer than 1 trillion tons of carbon, which was the central goal of the Paris climate agreement. According to current estimates, more than half of this carbon “budget” has already been emitted. The 46 billion metric tons of carbon that would be released by Trump’s plan would account for more than 3 percent of what remains in the entire global carbon budget.

More large oil spills

According to CAP estimates, the Trump administration drilling plan would also lead to more than 10 times more large oil spills than the current plan. (see Figure 2) Based on the spill rate associated with increased drilling activity, the number of large oil spills—those of at least 42,000 gallons, or 1,000 barrels—would increase from eight to 92 over the 30-year course of the plan. For comparison, the 2015 Santa Barbara oil spill that caused significant damage to beaches and wildlife spilled approximately 140,000 gallons. Even if all 92 oil spills were the minimum size in their respective class—42,000 gallons for large spills and 420,000 gallons for huge spills—this would still lead to more than 9 million gallons of oil being spilt into the ocean. For context, the 1989 Exxon Valdez disaster spilled nearly 11 million gallons into Prince William Sound, which is still polluted to this day.

Yet even this significant increase in large oil spills is likely a conservative estimate for two reasons. First, this spill rate excludes rare, catastrophic events such as the 2010 Deepwater Horizon incident in the Gulf of Mexico, which BOEM deemed an outlier, or the ongoing Taylor Energy leak, which may actually be one of the largest spills in history. However, if the Trump drilling plan went fully into effect, it would increase the likelihood of such catastrophic oil spills. Second, this estimate does not account for the impacts of increasing frequency and intensity of extreme weather. The government’s own 2018 analysis on oil spill occurrence frequencies in the OCS regions shows that extreme weather will likely be more of a problem for drilling in the newly opened Atlantic Ocean than it has been in the Gulf of Mexico, since hurricanes are expected to hit the Atlantic coast twice as often as they hit the Gulf. Meanwhile, in the Arctic Ocean, low temperatures are likely to increase incidents of human error and instances of equipment and mechanical failure. These two factors are already the main causes of small and medium oil spills in the Gulf of Mexico, but they could also lead to more and larger oil spills in the Arctic, where there is little to no infrastructure to handle a spill and no response plan in place.

Conclusion

The health of the world’s climate and ocean—as well as 2.6 million sustainable jobs and $180 billion in gross domestic product—is at risk. These resources are worth more than the potential of tapping fossil fuel reserves that would meet only six years of the nation’s oil demand and natural gas needs. Trump’s offshore drilling plan deserves to remain where it is: sunk deep in the courts, out of sight and unimplemented.

Margaret Cooney is the campaign manager for Ocean Policy at the Center for American Progress. Mary Ellen Kustin is the former director of policy for Public Lands at the Center.

The authors would like to thank Miriam Goldstein, Matt Lee-Ashley, Sally Hardin, Marc Rehmann, Steve Bonitatibus, and Chester Hawkins for their contributions to this column.

Methodology

CAP’s GHG analysis uses the estimated extractable amount of oil and gas in the National OCS Oil and Gas Leasing draft proposed program (DPP). CAP used data given for a high-price market scenario of oil selling for $160 per barrel (bbl) of oil and natural gas for $8.54 per thousand cubic feet (mcf). The DPP states that the new plan would lead to the extraction of up to 68.17 billion bbl of oil and up to 173.95 billion mcf of gas. Using calculations outlined in the BOEM’s 2016 “OCS Oil and Natural Gas” report as well the EPA’s GHG conversions rates, CAP calculated indirect carbon dioxide equivalent emissions—emissions associated with combustion—based on the predicted oil and gas extraction amounts stated in the DPP. These calculations include the full “indirect” carbon dioxide equivalent emission estimates for carbon dioxide, methane, and nitrous oxide but do not include “direct” emissions from the drilling and extraction process itself.

For the carbon budget calculation, CAP used the Global Carbon Project’s cumulative carbon emission estimates to calculate that there are only 385 gigatons of carbon (GtC) left in the global budget. The subsequent calculations for carbon emissions in the DPP would spend 3.35 percent of what is left.

To calculate the likelihood of spills, CAP used spill rates given for billions of barrels handled via offshore platforms and pipelines provided in the BOEM and Bureau of Safety and Environmental Enforcement (BSEE) “2016 Update of Occurrence Rates for Offshore Oil Spills.” CAP did not include natural gas in the spill rate because it was not included in the above report, but rather estimated spill rates based on the DPP’s assessment that the new plan would lead to the extraction of up to 68.17 billion bbl.

https://www.americanprogress.org/issues/green/news/2019/10/23/475732/trumps-offshore-drilling-plan-environmental-disaster/&ct=ga&cd=CAIyGmNkODMzMDNjMGU4NGQ4ZWU6Y29tOmVuOkdC&usg=AFQjCNHR6xjXxc57ntWS9tO8i_Hw2-aqD

Colder-trending weather models boost natural gas futures

Permian Basin pricing returns to negatives. Goldman Sachs analysts said with Permian Highway delayed, they expect “the extended bottleneck to keep Waha gas prices under pressure for longer, with relief dependent on seasonal support to demand and exports to Mexico”

Variability in the latest weather models worked in favor of natural gas bulls on Tuesday, with data pointing to chillier temperatures at the end of October/early November. With strong cash prices in tow, the supportive weather data boosted November Nymex gas futures by 3.4 cents to settle at $2.272. December climbed less than a penny to $2.449.

Cash prices continued to strengthen as a strong weather system tracked across the Midwest and into the East with rain and snow, while others were fresh on its tail. One glaring exception to the overall market strength was in the Permian Basin, where prices once again plunged below zero. The NGI Spot Gas National Avg. ultimately jumped a dime to $2.010.

There is no denying that the United States is on the cusp of widespread cold as the latest weather data showed a series of weather systems intensifying as each one travels across the country, according to NatGasWeather. In the near term, a strong weather system with rain and snow continued tracking across the Midwest and into the East, along with cooler conditions as overnight temperatures dip into the 20s to 40s.

A reinforcing cold shot was forecast to follow into the Midwest and east/central United States Thursday to Saturday for stronger national demand, the forecaster said. However, a pronounced break over the eastern half of the United States was still expected late this weekend with highs in the 60s to 80s.

“...The strongest cold shot in the series remains on track to advance into the northern and central United States Oct. 28-Nov. 3 with widespread lows of teens to 30s for strong demand,” NatGasWeather said. It is this system that the midday Global Forecast System weather model showed being more extreme and moving deeper into the South.

However, a warmer flow is within the eastern third during this time period, leading to more widespread above-normal temperatures from the Midwest to South and East, according to Maxar’s Weather Desk. There is additional warm risk if a more amplified pattern takes shape across the East, and this is reflected best within the European model as it supports above-normal anomalies.

“While a week of solid cold is helpful, is it going to be enough to resume the strong rally if warming quickly follows, especially when considering yet another record in production?” NatGasWeather said.

Indeed, production hit record levels over the weekend and has proven to be resilient over the last four months even as Henry Hub prices have averaged just above $2.25 in that time, according to Mobius Risk Group.

“The typical season decline in demand from mid-July through the fall has helped to keep production levels in the limelight versus demand intensity/degree day,” the Houston-based firm said.

The average storage injection over the past seven weeks has been 95 Bcf, with average weekly population-weighted degree days totaling 68, according to Mobius. Under similar weather conditions during the spring, the seven-week average injection was 103 Bcf.

“Directionally, it is clear the market has tightened as prices have fallen; however, a storage surplus of approximately 500 Bcf, more than 5 Bcf/d of year/year production growth and at least four more weeks until withdrawals begin is enough to embolden market bears who have continually looked for selling opportunities.”

Weather aside, there are some other supportive fundamentals at play, according to Bespoke Weather Services.

Liquefied natural gas intake continues to hold near 7 Bcf, and power burns were revised a little stronger and now show some improvement over last week, the firm said. “So the balance picture in total today is a little improved day/day, although still is quite weak overall.”

With the weather pattern showing some cold on the way entering November, price support in the low $2.20s may be able to hold for awhile, according to the firm. “Durability is still our biggest concern” and thus, Bespoke maintains a neutral near-term view with the current combination of weather and fundamentals.

Waha Bargain Basement

The price improvement experienced after Permian associated gas volumes started flowing on Kinder Morgan Inc.’s Gulf Coast Express (GCX) has taken a dramatic turn only a month after the 2 Bcf/d pipeline’s full in-service.

After nearing $2 in the weeks after GCX went online, Permian cash prices have sunk to the bargain-basement levels experienced this summer. Waha cash plunged 43 cents to average only 5 cents on Tuesday, although trades were seen as low as minus 30 cents. Other regional pricing hubs traded only marginally higher.

The price weakness was to be expected as rampant production growth in the Permian has necessitated additional gas takeaway in the region. Kinder Morgan executives have indicated that GCX is already running full, and the targeted startup for the second Permian project, Permian Highway Pipeline, has been extended from October 2020 to early 2021.

In a recent note, Goldman Sachs analysts said with Permian Highway delayed, they expect “the extended bottleneck to keep Waha gas prices under pressure for longer, with relief dependent on seasonal support to demand and exports to Mexico.”

And with temperatures in California starting to recede a bit, demand in that downstream market is waning. SoCal Citygate spot gas tumbled 39 cents to $3.475.

Prices elsewhere in Texas were stronger from the chillier temperatures on tap for the rest of the week. Katy next-day gas climbed 13 cents to $2.065.

Similar strength was seen in the Midcontinent, although Southern Star jumped a more pronounced 19.5 cents to $1.745 on some restrictions set to be implemented.

From Wednesday to Thursday, Southern Star Pipeline is scheduled to conduct emergency shutdown tests around the Blackwell compressor station in Kay County, OK. While several meters and compressor stations would be restricted during this time, the most critical of the limitations would be at the Blackwell compressor station itself, which directs gas toward Southern Star’s Market Area.

Flows through Blackwell have averaged 530 MMcf/d over the past 30 days, and operational capacity is to be limited to 311 MMcf/d for the two-day period, according to Genscape Inc. Around 219 MMcf/d of flows would be restricted at a time when the latest forecasts indicate that regional temperatures will be about 10 cooling degree days colder than seasonal averages.

Planned maintenance was also set to begin Wednesday on Texas Gas Transmission (TGT), limiting capacity at the Columbia compressor station in Caldwell Parish, LA, through Saturday. Flows through the station have averaged 1.11 Bcf/d (maxing at 1.13 Bcf/d) over the past 30 days, and would be limited to 1.04 Bcf/d during this event, according to Genscape. On average, this should limit 70 MMcf/d northbound to TGT’s mainline.

Given the slightly colder-than-normal outlook for the downstream Midwest market for the rest of the week, prices were up between 10 cents and 20 cents across the region.

Similar increases were seen across Louisiana as well as Appalachia. The exception in the Northeast producing region was at Tennessee Zn 4 313 Pool, where next-day gas shot up 29 cents to $2.045.

In the Northeast, Transco Zone 6 non-NY climbed 21.5 cents to $2.08.

https://www.naturalgasintel.com/articles/119973-natural-gas-futures-bounce-as-near-term-cold-seen-more-extreme-permian-trades-negative&ct=ga&cd=CAIyGmIyMzkzNGFiNzQ2ZGQyMWQ6Y29tOmVuOkdC&usg=AFQjCNF_h_2i_j3MKxb3w1sqntQn7Ctjc

Norway’s Equinor (EQNR.OL) reported a bigger-than-expected drop in its third-quarter profit on Thursday, dented by a significant decline in the volume and price of natural gas sold to Europe.

Adjusted earnings before interest and tax (EBIT) fell to $2.59 billion in the third quarter from $4.84 billion during the same period last year. A poll of 23 analysts compiled by Equinor had expected adjusted EBIT to come in at $2.69 billion.

“We maintain strong cost and capital discipline, but our results are affected by lower commodity prices in the quarter. In addition, we have decided to use our flexibility to defer gas production to periods with higher expected prices,” Equinor’s Chief Executive Eldar Saetre said.

Equinor’s giant Johan Svedrup oil field, which started in early October, has already achieved a daily production above 200,000 barrels, and will have a capacity of well above 300,000 barrels by the end of November.

The company said it marked impairment charges of $2.79 billion, of which $2.24 billion is related to its onshore shale oil and gas assets in North America due to “more cautious price assumptions”.

Equinor’s total equity oil and gas production stood at 1.9 million barrels of oil equivalent per day in the third quarter, down 8% from the same period in 2018, while gas production off Norway fell by 17% over the same period.

https://uk.reuters.com/article/uk-equinor-results/equinor-third-quarter-profit-drops-more-than-expected-on-low-gas-sales-idUKKBN1X30HX

Singapore — India has further liberalized its energy sector by opening up its retail transportation fuel sector to non-oil companies, a move that will intensify competition in a segment dominated by state refiners, while private and global oil majors seek to expand their presence.

It will also help to boost consumption of cleaner fuels, such as LNG, as New Delhi has now made it mandatory for those outlets to sell at least one "new generation alternative fuel."

The decision by Prime Minister Narendra Modi's cabinet to allow non-oil companies to enter the retail business comes at a time when global giants, like Saudi Aramco and Shell, as well as private oil refiners, such as Reliance Industries and Nayara Energy, are also aiming to have a bigger retail footprint.

The move is seen as another major step for its retail fuel sector. It comes more than two years after India aligned its transportation fuels with the global oil market by allowing its state-owned oil marketing companies to adjust daily prices of gasoline and diesel -- two products that together account for about 60% of total oil products consumption.

"The existing policy for granting authorization to transportation fuel marketing has not undergone any changes for the last 17 years since 2002. It has now been revised to bring it in line with the changing market dynamics and with a view to encourage investment from private players, including foreign players, in this sector," the Indian government said in a statement.

"Non-oil companies can also invest in the retail sector. Requirement of prior investment in the oil and gas sector, mainly in exploration and production, refining, pipelines and terminals has been done away with," the statement added.

The policy reform is expected to attract more private and foreign players to invest in retail fuel marketing, leading to better competition and services for consumers, it added.

"This should help to induce competition, which should be beneficial for consumers. Fuel retailers will not only have to be competitive in terms of pricing but will have to differentiate themselves by providing better services," said Lim Jit Yang, adviser for oil markets at S&P Global Platts Analytics.

EASE OF DOING BUSINESS

Under the previous rules, a new player seeking to operate a retail fuel outlet needed to make a minimum investment commitment of Rupee 20 billion ($282 million) for the country's oil and gas sector. Under the new set of guidelines, that is no more a requirement. Now, any company having a minimum net worth of Rupee 2.5 billion can apply for a license.

"In addition to conventional fuels, the authorized entities are required to install facilities for marketing at least one new generation alternate fuel -- like CNG, LNG, biofuels and electric charging -- at their proposed retail outlets within three years of operationalization of the said outlet," the statement said.

India has nearly 60,000 retail fuel outlets spread across the country, out of which the three state-run firms -- Indian Oil Corp., Hindustan Petroleum Corp. and Bharat Petroleum Corp. -- account for more than 90% of the market share.

As per the new rules, the companies will be required to set up minimum 5% of their total retail outlets in remote areas within five years.

"The policy reform to allow non-oil firms is a welcome move for the industry provided there is no intervention by the government in controlling retail prices in any form in the future," said Senthil Kumaran, Consultant at Facts Global Energy.

"The government is targeting small towns, growing rural markets and new highways for future expansion of retail outlets. Sourcing of products, inland freight, tankage and other infrastructure will be challenging. Operational costs will be higher in remote and low-serviced areas," he added.

Many global oil companies have set their eyes on the growing Indian oil products market. Shell was the first overseas oil company to venture into the Indian fuel retailing market.

In August this year, BP would expand its current partnership with Reliance to include retail fuel, convenience retailing and aviation fuels in India. Under the deal, the partners have agreed to set up a new joint venture, which will assume ownership of Reliance's existing Indian fuel retail network.

Even France's Total is looking into the possibility of investing in India's retail fuel sector.

India's oil demand growth has eased this year due to slowing economy and transport fuel consumption dampened by weak vehicle sales. But demand should strengthen as the economy picks up.

Demand outlook for the next few years is expected to be stronger with an average annual growth of around 200,000 b/d, supported by population growth and an increase in disposable personal incomes, according to Platts Analytics.

-- Sambit Mohanty, sambit.mohanty@spglobal.com

-- Ratnajyoti Dutta, newsdesk@spglobal.com

-- Edited by Kshitiz Goliya, kshitizgoliya@spglobal.com

http://plts.co/32HI50wSK5X

Singapore — Crude oil futures were lower during mid-morning trade in Asia Thursday, retreating from overnight highs, where both benchmark contracts had jumped by more than $3/b.

Latest comments made by Russia on OPEC's production cut agreement also weighed prices down, analysts said.

At 11:00 am in Singapore (0300 GMT), ICE Brent December futures fell 42 cents/b (0.69%) from Wednesday's settle to $60.75/b, while the new front-month NYMEX December light sweet crude futures contract was 50 cents/b (0.89%) lower at $55.47/b.

Crude prices rose by more than $1/b during Wednesday's trading session after the US Energy Information Administration on Wednesday reported that US crude inventory had fallen by 1.7 million barrels to 433.15 million barrels.

"The market had been expecting a rise," ANZ analysts said in a note Thursday.

Analysts surveyed Monday by S&P Global Platts were looking for US crude stocks to have increased by 4.7 million barrels last week.

US distillate stocks on the other hand fell 2.72 million barrels to 120.79 million barrels last week, while US gasoline stocks fell 3.11 million barrels to 223.09 million barrels, according to EIA data.

The surprise fall reported in US crude and product inventory data pushed prices higher during the overnight trading session and some of those gains were given up during the Asian morning session on Thursday, amid profit taking, analysts said.

Moreover, recent comments made by Russia on the possibility of OPEC and its allies deepening their production cut agreement also weighed down on prices, analysts said.

Russian energy minister Alexander Novak said Wednesday that no official proposal has been made to change production levels under the OPEC+ agreement, the Prime news agency reported.

"At the moment, no official proposals have been received from anyone to adjust the agreement," Novak said, according to the report.

He added that the group continues to monitor the situation.

"Oil prices buckled after the Russian Energy Minister said today that no OPEC+ participants had proposed changing the current level of output contradicting earlier media reports," Stephen Innes, market strategist at AxiTrader, said in a note Thursday.

This comes at a time when market participants were seeking clarity after news released earlier this week around OPEC and its allies deepening their production cut agreement to support crude prices.

As of 0300 GMT, the US Dollar Index was down 0.06% at 97.18.

Avantika Ramesh, avantika.ramesh@spglobal.com

Edited by Norazlina Juma'at, norazlina.jumaat@spglobal.com

http://plts.co/GXeU50wSGGY

Despite the fact that they make some of the most efficient and cost-effective solar equipment available, it’s simply not a fair fight when First Solar products have to compete against rock-bottom lows in gas prices, and earnings have suffered as a result.

The last two quarters have featured huge misses of the Zacks consensus Earnings Estimate and the forecast when they report quarterly results on Thursday night has fallen 13% in the past 90 days – from $1.22/share to $1.06.

Based on recent periods, it would seem that the chances of a positive surprise are smaller than those of a significant disappointment.

It’s way too early in the game for investors to give up on solar energy, but it might be rough sledding for a while. JinkoSolar (JKS - Free Report) and Sunnova Energy (SOL - Free Report) , both Zacks Rank #2 (BUY), are better bets than First Solar, but it also might be a good time to go light on solar investment and wait to see how the cards fall over the next several quarters.

NYSE and AMEX data is at least 20 minutes delayed. NASDAQ data is at least 15 minutes delayed.

https://www.zacks.com/commentary/580830/bear-of-the-day-first-solar-fslr&ct=ga&cd=CAIyHGRiM2IwYmIzNGE1ZDFkM2Y6Y28udWs6ZW46R0I&usg=AFQjCNFmA2f2Hu3aGDzYhZ1ZFmhfPPiV0

Despite challenges, Mexico is close to completing its notorious oil hedge, unnamed sources told Reuters, adding that the government had used the services of Goldman Sachs, JP Morgan, Citigroup, BNP Paribas, and Shell.

The Mexico oil hedge is the most famous one, with investment banks vying every year for a role in it. Worth around US$1 billion, it is done every year and is believed to be the largest oil trade.

The deal is the most secretive in the oil world and is followed closely by banks as a sort of weathervane for oil prices. A handful of these are directly involved in the hedge: Mexico buys put options on oil from them and from oil supermajors in a series of about 50 transactions.

This year was unusually challenging for the hedge because of the excessive volatility of prices, Reuters noted, as well as because the Mexican government changed the pricing formulas that underpin the country’s oil exports.

This year’s oil sales in Mexico were hedged at US$55 per barrel, with the total value of the put options bought standing at US$1.23 billion.

Related: Chinese Oil Giant Significantly Boosts Shale Reserves

It remains unclear how big next year’s hedge is since the government’s silence on the sensitive matter is as notorious as the hedge itself. Opinions also differ on how close to completion the deal is, with some putting it at over 90 percent while others see it closer to 75 percent.

Mexico’s Deputy Finance Minister Gabriel Yorio said the government was setting $49 per barrel as the price, on whose basis it would calculate its 2020 oil export revenues in the draft budget that is currently the subject of debate and has yet to be voted on.

“This is a price at which we can control the risks of a fall in the oil price and, obviously, if the price is higher, we’ll have higher income,” Yorio told the Mexican Congress. “So I believe we are covered against the downside risk.”

By Irina Slav for Oilprice.com

More Top Reads From Oilprice.com:

https://oilprice.com/Latest-Energy-News/World-News/The-Worlds-Most-Exiting-Oil-Hedge-Nears-Completion.html&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNEykjuD-bwJZe54uZPmML6WURcd8

Lloyds Energy is studying the feasibility of direct shipments of LNG from the Alaska North Slope to Asia, officials with Lloyds subsidiary Qilak LNG said Wednesday.

With an overland 800-mile gas pipeline to southern Alaska apparently on the back burner, Lloyds is the first to propose an alternative project in to ship gas from the North Slope in ice-breaking tankers through the Beaufort Sea and Bering Strait.

"We've been trying to market North Slope gas by pipeline for 50 years and nothing has worked. It's time to try something different," former Alaska Lieutenant Governor Mead Treadwell said in a press conference in Anchorage Wednesday. Treadwell is chairman and CEO of Qilak LNG, which is based in Alaska.

If the feasibility study is positive and the project moves ahead an investment decision could come in 2022 and shipments of LNG could start as early as 2024, Treadwell said.

Dubai-based Lloyds Energy was formed in 2013 to develop floating LNG projects. One project the company is now engaged in, with Mitsubishi. is an LNG-fueled 1,200-MW power plant in the Philippines.

For the Alaska project ExxonMobil has signed a preliminary agreement to supply gas to an LNG plant from the ExxonMobil-operated Point Thomson gas field east of Prudhoe Bay. David Clarke, Qilak Energy's chief operating officer, said in a briefing for reporters. Clarke said the gas volume is sufficient to allow the export of 4 million mt/year of LNG.

That would increase to 6 million mt/year if other gas owners at Point Thomson contribute gas, Clarke said. BP is the principal minority owner after ExxonMobil, the majority owner.

Point Thomson holds about 8 Tcf of gas and 200 million barrels of liquid condensate.

BP's Point Thomson holdings are being sold to Hilcorp Energy, which is also buying BP's share in the Prudhoe Bay Field. Clarke said Qilak Energy hopes to negotiate a preliminary gas sales agreement with Hilcorp similar to one now held with ExxonMobil.

ExxonMobil is now operating a gas cycling and concentrate production project at the field, injecting produced gas back into the high-pressure reservoir and shipping the liquid condensate by pipeline 60 miles west to the Trans Alaska Pipeline System. The gas cycling and condensate project has been technically challenged, however. Clarke said elimination of the gas injection by selling produced gas as LNG for export will allow ExxonMobil to maximize liquid concentrate output.

Treadwell said a preliminary feasibility assessment indicates than an Alaskan Arctic LNG project could supply LNG to Asia for about $1,250/mt at 4 million mt/year, about half of $2,150/mt of LNG for the proposed Alaska LNG Project, which must ship 20 million mt/year to be viable.

The shipping distance from an Arctic LNG plant to Asia via the Bering Strait is also about the same as from Cook Inlet, in southern Alaska, to Asia.

The location also has an advantage over the Yamal LNG project in Russia's Arctic, which now ships LNG via a route across the top of Russia, Treadwell said.

"LNG tankers from Yamal must travel 2,600 miles to reach ice-free waters," he said. "From the North Slope the distance is 600 miles."

Clarke said Qilak Energy would have an LNG plant built at a fabrication center in more temperate climates and move it to Point Thomson by barge in an open-water summer "sealift." The plant would be positioned six to 10 miles offshore Point Thomson and supplied with gas by pipeline.

The company has idenfied one site north of Flaxman Island, northwest of Point Thomson, where bottom conditions are favorable for a construction of a structure to support the LNG plant, he said.

Winter ice in the Beaufort Sea is mostly first-year ice, thin enough for navigation by icebreaking tankers similar to those used on the Yamal project, Treadwell said.

Clarke said the company would likely position an icebreaker off Point Barrow as a contingency. Point Barrow is a geographic feature extending out from the Alaska coast that is sometimes an impediment to shipping because of ice jams.

https://www.spglobal.com/platts/en/market-insights/videos/platts-insight/102419-lng-asia-stocks-spot-demand

Oilfield services firm Patterson-UTI reported a smaller-than-expected loss on Thursday, as cost cuts helped it limit the impact of an ongoing decline in North American shale activity.

An investor push toward higher returns instead of growth amid weak oil prices has prompted U.S. shale producers to reduce spending, forcing rig providers to lower costs in the face of weak demand.

The Houston, Texas-based company’s direct operating costs fell 28.5% in the quarter. It also lowered its full-year capital spending forecast to $350 million from previous projection of $400 million.

Patterson-UTI’s move comes after bigger rival Halliburton Co promised more cost cuts after reporting a bigger-than-expected drop in quarterly revenue earlier this week due to dwindling demand from oil and gas producers.

The shale slowdown across North America more than halved Patterson-UTI’s revenues and margins in the pressure pumping business, with the company warning that activity is likely to fall further in the current quarter.

“As pressure pumping activity is expected to fall further in the fourth quarter, we will continue to evaluate the economics of working versus idling spreads on a spread-by-spread basis,” Chief Executive Officer Andy Hendricks said.

Reuters had reported in June the company is exploring potential divestment of its pressure pumping business, a deal that could be worth around $1 billion.

Separately, Canadian rival Precision Drilling reported a narrower quarterly loss, as it reaped the benefits of efforts to cut costs.

Net loss attributable to Patterson-UTI widened to $262 million, or $1.31 per share, in the third quarter ended Sept. 30, from a loss of $75 million, or 34 cents per share, a year earlier.

The company took multiple charges in the quarter, including $173 million for the retirement of 36 rigs and other drilling assets.

Excluding items, loss per share was 27 cents.

Analysts had on average estimated loss of 30 cents per share, according to Refinitiv IBES data.

Revenues fell 31% to $598.5 million.

https://www.reuters.com/article/us-patterson-uti-results/patterson-uti-cost-cuts-help-it-post-smaller-than-expected-loss-idUSKBN1X316O

A Columbian energy company was approved by the U.S. federal government to form a joint venture with one of the Permian Basin’s top oil and gas producers.

Ecopetrol announced regulatory approvals were received on Tuesday for the deal with Occidental Petroleum to develop land in the Permian for oil and gas production.

The transaction was expected to close by the end of 2019.

The deal was announced in July and would see Ecopetrol develop 97,000 acres of Occidental’s Midland Basin properties on the Texas side of the basin which stretches across West Texas and southeast New Mexico.

The agreement allowed Ecotpetrol to book about 160 million barrels of oil equivalent of proven but undeveloped oil and gas reserves, and access to “one of the most prolific resource plays in the world,” read and Ecopetrol news release.

The company will pay Occidental $750 million in cash and another $750 million in carried capital for a 49 percent stake in the venture, while Occidental will own a 51 percent interest.

“This will enable Ecopetrol to advance its expertise in shale development and ensure technology and knowledge transfer from the Permian Basin to its assets in Colombia,” read a statement from Ecopetrol.

“The deal is fully aligned with Ecopetrol’s strategic priorities outlined in the 2019-2021 business plan, which focus on reserves and production growth, under a strict capital deployment discipline.”

Ecopetrol President Felipe Bayon said the move would help the company develop expertise in shale development and technologies which it could then bring back to Columbia.

Occidental and Ecopetrol Team Up in the Midland

Ecopetrol Reports Discovery

It would also assist Occidental in increasing its Permian Basin production, while oil and gas continued to boom in the region.

“We are excited to partner with one of the largest operators in the Permian Basin, especially one we have worked successfully with for so many decades,” Bayon said.

“This is a key step to enhance our reserve base and production growth whilst we strengthen our capabilities in shale development and bring this technology to Colombia for the economic benefit of the country.”

The news of the deal came just months after Occidental completed its acquisition of major oil and gas producer in the Permian, following a bidding war with global oil and gas giant Chevron.

Occidental closed on the deal to purchase Anadarko Petroleum on Aug. 8, with the transaction valued at $55 billion including Anadarko’s debt.

Occidental Chief Executive Officer Vicki Hollub said the company was working to solidify its presence in the booming Permian Basin and its focus on developing oil and gas throughout the prolific region.

Following the deal, the company was valued at $100 billion globally with assets totaling 1.4 million barrels of oil equivalent per day.

“Occidental is a leader in using technological innovation to create value, and we will deploy our expertise to enhance the performance and productivity of Anadarko’s assets not only in the Permian, but globally,” she said.

“Occidental and Anadarko have a highly complementary asset portfolio, providing us with a unique opportunity to realize significant operating, cost, and capital allocation synergies and achieve near-term cash flow accretion.”

https://www.oilandgas360.com/occidental-petroleum-sale-of-permian-assets-to-ecopetrol-given-the-green-light/

Brazil’s Petrobras reported an increase in 3Q net income, largely reflecting the increase in oil and gas production and the capital gain from the sale of fuel distributor BR Distribuidora.

Net income attributable to Petrobras’ shareholders for the quarter was R$9,1 billion, up from R$ 6,6 billion in the third quarter of 2018.

Petrobras said that in 3Q, the sharp drop in Brent was mitigated by the good operating performance and by the increase in pre-salt share in total production (60.4% of oil production in the quarter).

According to the CEO Roberto Castello Branco, oil and gas production reached a record level of 3.0 MMboed in August, when a daily record of 3.1 MMboed was also reached, and the cost of the lifting of pre-salt oil dropped to only five dollars a barrel.

“The ramp-up of the new platforms significantly influenced production growth, with pre-salt accounting for 60.4% of Petrobras’ total oil production in Brazil…Pre-salt cash cost (lifting cost) reached an unprecedented level of US$ 5.0 per boe, which contributed to the company’s average lifting cost averaging less than US$ 10 per boe (US$ 9.7 per boe),” the CEO said.

In 3Q19, investments in the Exploration and Production segment totaled US$ 1.9 billion, down from $3.4 billion a year ago.

According to data shared by Petrobras, 50 percent of its oil product exports went to the U.S., while 64 percent of its crude oil exports went to China.

Debt reduced but still heavy

Commenting on  Petrobras’ debt, the CEO said: “Petrobras’ gross debt reached US$ 90 billion on 9.30.2019 against US$ 101 billion at the end of 2Q19, which happened to be equal to Argentina’s current foreign debt… However, we have to recognize that much remains to be done, we are only at the beginning of a journey with many important

obstacles to overcome. We are still a heavily indebted company with high costs in an industry that faces major challenges in a global scenario of rapid changes and growing interdependence between different economic activities.”

“Recognition of our deficiencies increasingly encourages us to work towards becoming the best energy company in generating shareholder value, focused on oil and

gas, with safety, respect to people and to the environment.”

Petrobras concluded the public offering of BR Distribuidora shares in July, which, together with the cash inflow from the Pargo cluster sale, signed in 2018, resulted in a cash inflow of US$ 2.9 billion in 3Q19. In addition, Petrobras has signed contracts for the sale of shallow and terrestrial water fields for a total of US$ 213 million.

“These transactions, although of low values relative to the total of the portfolio of divested assets, are of paramount importance for efficient portfolio management and cost savings, as they are non-core assets. These sales have contributed to our total US$ 15.3 billion in total signed and completed divestment transactions by 2019 to date, including transactions signed in 2018 and completed 2019,” Petrobras said.

https://www.offshoreenergytoday.com/higher-production-divestments-boost-petrobras-3q-result/

Italian energy group Eni <ENI.MI> racked up its highest ever production rate in the third quarter and said more was to come as net profits fell sharply on lower oil and gas prices.

Output jumped 6% to 1.89 million barrels of oil equivalent per day in the three months to September, boosted by production at its giant Zohr field in Egypt, new fields in Mexico and higher output in Kazakhstan and Ghana.

The company said it expected production to increase further in the final quarter.

Third-quarter adjusted net profit fell 44% to 776 million euros ($862 million), impacted by lower crude prices and the loss of earnings from its former Eni Norge unit after a merger.

The result was in line with an analyst consensus provided by the company of 0.77 billion euros.

"Eni's efficient portfolio can achieve breakeven at prices well below current difficult conditions," Chief Executive Officer Claudio Descalzi said.

The group, which confirmed a 2019 target for cash flow from operations before working capital at replacement cost of 12.8 billion euros, said it expected to invest slightly less than the 8 billion euros it had previously set.

https://uk.finance.yahoo.com/news/eni-third-quarter-profits-fall-061830716.html?guccounter=1&guce_referrer=aHR0cHM6Ly93d3cuZ29vZ2xlLmNvbS8&guce_referrer_sig=AQAAAHpKJ99GOoY-wOI1iGxHGB0kPYUyHsTrYExj2Gwcb8g5-jzlUv92pc6IB_zNsR1zelCIXyOviLwC3DKE7q0prShHcgf8fud8s23ceW5LCO0cfReNFUNN2YYGiK5CkY_k9wWjGlgHNpo-mnOp-MYPvlJ3nyjh5cxXtMvcVdNMeP4A