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Journal articles on the topic 'UK natural gas market'

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Author: Grafiati

Published: 10 December 2022

Last updated: 28 January 2023

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1

Hobæk Haff, Ingrid, Ola Lindqvist, and Anders Løland. "Risk premium in the UK natural gas forward market." Energy Economics 30, no. 5 (September 2008): 2420–40. http://dx.doi.org/10.1016/j.eneco.2007.12.002.

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2

van Goor, Harm, and Bert Scholtens. "Modeling natural gas price volatility: The case of the UK gas market." Energy 72 (August 2014): 126–34. http://dx.doi.org/10.1016/j.energy.2014.05.016.

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3

Devine, Mel T., James P. Gleeson, John Kinsella, and David M. Ramsey. "A Rolling Optimisation Model of the UK Natural Gas Market." Networks and Spatial Economics 14, no. 2 (January 29, 2014): 209–44. http://dx.doi.org/10.1007/s11067-013-9216-4.

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4

Kremser, Thomas, and Margarethe Rammerstorfer. "Predictive Performance and Bias: Evidence from Natural Gas Markets." Journal of Management and Sustainability 7, no. 2 (May 30, 2017): 1. http://dx.doi.org/10.5539/jms.v7n2p1.

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This paper sheds light on the differences and similarities in natural gas trading at the National Balancing Point in the UK and the Henry Hub located in the US. For this, we analyze traders’ expectations and implement a mechanical forecasting model that allows traders to predict future spot prices. Based on this, we compute the deviations between expected and realized spot prices and analyze possible reasons and dependencies with other market variables. Overall, the mechanical predictor performs well, but a small forecast error remains which can not be characterized by the explanatory variables included.

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5

Acquah-Andoh, Elijah, Augustine Ifelebuegu, and Stephen Theophilus. "Brexit and UK Energy Security: Perspectives from Unconventional Gas Investment and the Effects of Shale Gas on UK Energy Prices." Energies 12, no. 4 (February 14, 2019): 600. http://dx.doi.org/10.3390/en12040600.

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Many aspects of the present and future effects on the UK economy, industry, and households, of Brexit have been researched. One thing which appears certain about Brexit is the shadow of uncertainty it casts on the future of business in the UK and its telling effects on the UK economy. It is believed that Brexit has negatively affected the level of investments in the UK, including investments in energy and crucially the upstream oil and gas, with the UK North Sea being starved of investments since 2014, leading already to increased energy bills. The UK is a net importer of natural gas—a major source of its energy, with some dependence on supplies from interconnectors from Europe. At the same time, UK energy companies participate in the common energy market which enables them to undertake arbitrage trading under the common market rules. However, both of these benefits could be lost under a Brexit scenario where the UK and EU come to a no-deal or hard border arrangement. Meanwhile, domestic production of energy in the UK has declined for nearly two decades now and import bills for natural gas are growing—they were £14.2 billion in 2017; £11.7 billion in 2016 and £13.4 billion in 2015—with Government projections indicating an upward trajectory for natural gas imports. It is however believed that the UK has great potential to exploit shale gas to her advantage in order to reduce her reliance on foreign energy which is: (1) less predictable in terms of supply and price affordability and (2) dependent on exchange rates—a primary means through which energy prices increased in 2016/17 post-Brexit referendum vote. The current study extends discussions on shale gas to cover a review of the potential of natural gas from shale formations to cushion UK households against further erratic gas prices due to Brexit and also assesses the potential effects Brexit may have had on the level of investments in shale gas, in order to suggest policy options for government consideration. Contrary to popular studies, we find evidence to suggest that shale gas has the potential to reduce energy prices for UK businesses and households at commercial extractions, under both hard and soft Brexit scenarios, but with more benefits under hard Brexit. Importantly, we find that from 2008 to 2017, average UK net export of natural gas was 5,191 GWh per year to the EU. We also find and argue that Brexit may have starved the nascent fracking industry of investments in a similar way it did to investments in conventional oil and gas and could have increased investor risk premium for shale gas development, the ultimate effect of which was a categorisation of fracking (company stock) as riskier asset for investors on the London Stock Exchange. We recommend that shale gas development be expedited to maximise its benefits to UK energy consumers post-Brexit or economic benefits from the resource could be diminished by rising operator costs due to delays and effects of the public’s perceived negative opinion of the method of extraction.

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6

Timitimi, Bodisere T. "An Examination of the Nigerian Gas Law and Policy: Facilitating Domestic Gas." American Journal of Law 4, no. 2 (October 20, 2022): 35–45. http://dx.doi.org/10.47672/ajl.1237.

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The Federal Government of Nigeria based on its sizable gas reserves, identified the need for accelerated development of the gas industry as a focal strategy for achieving the national aspiration of aggressive GDP growth. Endowed with energy resources, Nigeria has about 188tcf of proven reserves. Active power plants are mainly gas-fired, but they face feedstock shortages, as a result of a dearth of infrastructure investment. Nigeria’s gas industry is still in its infant stage unlike the UK and US. Oil and gas companies have historically flared natural gas into the environment mainly because it was considered an oil by-product and not an economic product. The development of a domestic market today is the top of the government's agenda. The Federal Government recently approved the Nigerian National Gas Policy 2017. The goal as highlighted in the policy is the commercialization of gas to boost the economy, electricity undoubtedly being central to economic growth. This paper discusses, gas pricing, unbundling and open access and the Domestic Gas Obligation. The purpose of this study is to highlight various areas of improvement and provide an analysis of existing laws and policy. Results suggest that market liberalization and increase in private sector involvement are the two strengths agreed upon. In addition, the participants concur on the importance of increasing share of LNG in the total natural gas supply.

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Devine, Mel T., and Marianna Russo. "Liquefied natural gas and gas storage valuation: Lessons from the integrated Irish and UK markets." Applied Energy 238 (March 2019): 1389–406. http://dx.doi.org/10.1016/j.apenergy.2019.01.157.

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8

Dominguez-Gonzalez, German, Jose Ignacio Muñoz-Hernandez, Derek Bunn, and Carlos Jesus Garcia-Checa. "Integration of Hydrogen and Synthetic Natural Gas within Legacy Power Generation Facilities." Energies 15, no. 12 (June 20, 2022): 4485. http://dx.doi.org/10.3390/en15124485.

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Whilst various new technologies for power generation are continuously being evaluated, the owners of almost-new facilities, such as combined-cycle gas turbine (CCGT) plants, remain motivated to adapt these to new circumstances and avoid the balance-sheet financial impairments of underutilization. Not only are the owners reluctant to decommission the legacy CCGT assets, but system operators value the inertia and flexibilities they contribute to a system becoming predominated with renewable generation. This analysis therefore focuses on the reinvestment cases for adapting CCGT to hydrogen (H2), synthetic natural gas (SNG) and/or retrofitted carbon capture and utilization systems (CCUS). Although H2, either by itself or as part of SNG, has been evaluated attractively for longer-term electricity storage, the business case for how it can be part of a hybrid legacy CCGT system has not been analyzed in a market context. This work compares the power to synthetic natural gas to power (PSNGP) adaptation with the simpler and less expensive power to hydrogen to power (P2HP) adaptation. Both the P2HP and PSNGP configurations are effective in terms of decarbonizations. The best results of the feasibility analysis for a UK application with low CCGT load factors (around 31%) were obtained for 100% H2 (P2HP) in the lower range of wholesale electricity prices (less than 178 GBP/MWh), but in the higher range of prices, it would be preferable to use the PSNGP configuration with a low proportion of SNG (25%). If the CCGT load factor increased to 55% (the medium scenario), the breakeven profitability point between P2HP and PSNGP decreased to a market price of 145 GBP/MWh. Alternatively, with the higher load factors (above 77%), satisfactory results were obtained for PSNGP using 50% SNG if with market prices above 185 GBP/MWh.

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Tveten, Åsa Grytli, and Torjus Folsland Bolkesjø. "Energy system impacts of the Norwegian-Swedish TGC market." International Journal of Energy Sector Management 10, no. 1 (April 4, 2016): 69–86. http://dx.doi.org/10.1108/ijesm-07-2014-0003.

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Purpose – The purpose of this study is to analyze the power market and greenhouse gas (GHG) emission effects of the joint Norwegian–Swedish tradable green certificates (TGCs) market, which is established to support investments according to a 26.4 TWh increased annual renewable electricity generation (REG) by 2020. Design/methodology/approach – The study applies an energy system model with high granularity in time and space, and detailed power system data for the Nordic countries, Germany, The Netherlands and UK. Findings – The results show that the TGC scheme will cause a 8.7-9.3 /MWh reduction in average electricity prices in the Nordic countries. The price decrease will to a limited extent pass through to Germany, The Netherlands and UK. When assuming a low carbon price level, the new REG will reduce annual GHG emissions by 10.9 Mtonnes in 2020, primarily through substitution of German natural gas power. A sensitivity analysis shows that the GHG emission effect of the TGCs is highly sensitive to changes in the carbon price. Investment levels up to a 90 TWh increased REG per year are found to cause increasing GHG emission reductions. Originality/value – The study results signal the importance of taking the TGC policy into account in decision-making processes in the Northern European power system, in particular for market actors in the Nordic area. The authors conclude that the Nordic countries potentially can play a vital role in a future Northern European low carbon power system through export of green balancing power, substitution of thermal power and reduced GHG emissions from the Northern European power sector.

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Shishikin, V. G. "BRITISH FUEL AND ENERGY INDUSTRY DURING THE 1967 AND 1973–1974 OIL CRISES." Вестник Пермского университета. История, no. 4(59) (2022): 40–50. http://dx.doi.org/10.17072/2219-3111-2022-4-40-50.

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The article examines the development of three key components of the UK fuel and energy industry during the 1967 and 1973–1974 oil crises. The object of research was studied in the context of European energy policy, which in the 1960s–1970s was codified in a form of directives and was practically implemented by creating fuel reserves in case of a decrease in fuel supplies from the Middle East. The article focuses on the special place the UK held in the EEC, and specific policy that the country maintained to develop the national fuel and energy industry. All this is because the UK had an elaborate management system within the industry, possessed significant amount of energy resources and owned prospective fuel fields in the North Sea, discovered in the mid-1960s. During the researched period, the UK government implemented measures targeted at the reduction of the national coal mining industry, which failed to meet economic needs of the country. At the same time, the UK started the development of oil and gas fields in the North Sea, which gained momentum after the 1967 and 1973–1974 oil crises were over. The management structures of gas and coal industries served as an interface of the national energy industry. This enabled the government to consistently substitute coal with natural gas, while still allowing it to play a significant role in the economy. Oil exploration and production companies with a high degree of autonomy adopted an independent policy while working on domestic and foreign markets. However, they suffered the most during the 1973–1974 crisis, which led to a partial loss of the national fuel market, an increase in prices on resources, and a strain in their relations with the government. In conclusion, the author states that the developed fuel and energy industry, fuel fields’ exploitation and validated management techniques allowed the UK to smooth out the effects of the 1967 and 1973–1974 crises and continue the modernization of the national fuel industry in the years to come.

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11

Kemp, Alexander G., and Linda Stephen. "Recent and Prospective Developments in Natural Gas Markets in the UK and Continental Europe." Energy Exploration & Exploitation 14, no. 3-4 (July 1996): 295–318. http://dx.doi.org/10.1177/014459879601400307.

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12

Glennie, K. W. "Exploration activities in the Netherlands and North-West Europe since Groningen." Netherlands Journal of Geosciences - Geologie en Mijnbouw 80, no. 1 (April 2001): 33–52. http://dx.doi.org/10.1017/s0016774600022150.

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AbstractOnce the great size of the Groningen Field was fully realized late in 1963, exploration in the southern North Sea was a natural development as the reservoir bedding dipped westward. The origin of that bedding was not certain, one possibility, dune sands, led immediately to a program of desert studies.Licensing regulations for Netherlands waters were not finalized until 1967, offshore exploration beginning with the award of First Round licenses in March 1968. In the UK area, the Continental Shelf Act came into force in May 1964, paving the way for offshore seismic, the first well being spudded late in that year. The first two wells were drilled on the large Mid North Sea High; both were dry, the targeted Rotliegend sandstones being absent. Then followed a series of Rotliegend gas discoveries, large and small, west of Groningen, so that by the time exploration began in Netherlands waters the UK monopoly market was saturated and exploration companies were already looking north for other targets including possible oil.The Rotliegend was targeted in the earliest wells of the UK central North Sea even though there had already been a series of intriguing oil shows in Chalk and Paleocene reservoirs in Danish and Norwegian waters. These were followed early in 1968 by the discovery of gas in Paleocene turbidites at Cod, near the UK-Norway median line. The first major discovery was Ekofisk in 1969, a billion-barrel Maastrichtian to Danian Chalk field. Forties (1970) confirmed the potential of the Paleocene sands as another billion barrel find, while the small Auk Field extended the oil-bearing stratigraphy down to the Permian. In 1971, discovery of the billion-barrel Brent field in a rotated fault block started a virtual ‘stampede’ to prove-up acreage awarded in the UK Fourth Round (1972) before the 50% statutory relinquishment became effective in 1978.Although the geology of much of the North Sea was reasonably well known by the end of the 1970s, new oil and gas reservoirs continued to be discovered during the next two decades. Exploration proved the Atlantic coast of Norway to be a gas and gas-condensate area. The stratigraphiC range of reservoirs extended down to the Carboniferous (gas) and Devonian (oil), while in the past decade, forays into the UK Atlantic Margin and offshore Ireland met with mixed success. During this hectic activity, Netherlands exploration confirmed a range of hydrocarbon-bearing reservoirs; Jurassic oil in the southern Central Graben, Jurassic-Cretaceous oil derived from a Liassic source mainly onshore and, of course, more gas from the Rotliegend. German exploration had mixed fortunes, with no commercial gas in the North Sea and high nitrogen content in Rotliegend gas in the east. Similarly in Poland, where several small Zechstein oil fields were discovered, the Rotliegend gas was nitrogen rich. The discovery of some 100 billion barrels of oil and oil equivalent beneath the waters of the North Sea since 1964 led to an enormous increase in geological knowledge, making it probably the best known area of comparable size in the World. The area had a varied history over the past 500 million years: platete-tonic movement, faulting, igneous activity, climatic change, and deposition in a variety of continental and marine environments, leading to complex geometrical relationships between source rock, reservoir and seal, and to the reasons for diagenetic changes in the quality of the reservoir sequences. Led by increasingly sophisticated seismic, drilling and wireline logging, and coupled with academic research, the North Sea developed into a giant geological laboratory where ideas were tested and extended industry-wide.

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13

Eberspaecher, Kai C. "The case for shared infrastructure to unlock onshore resources." APPEA Journal 60, no. 2 (2020): 431. http://dx.doi.org/10.1071/aj19020.

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This paper outlines the current state of the upstream industry for smaller oil and gas developers in Australia’s mature onshore basins. In particular, a strategic review of the market landscape based on Porter’s Five Forces model is undertaken from a junior exploration company’s perspective with a focus on barriers to market entry, such as access to infrastructure, capital, assets and expertise. In the strategic framework context, the paper examines the opportunities to break down natural monopolistic structures and barriers to entry across incumbent producers, pipeline transportation companies and contractors. It also investigates potential changes in resource policy dealing with access to infrastructure and general development requirements. In its analysis, the importance of junior explorers to extend the longevity of mature basins by looking at other petroleum provinces around the globe is highlighted. Examples in North America (onshore) and the UK (offshore) are used to showcase approaches in assisting smaller companies converting resources into reserves. In its conclusion, the paper demonstrates qualitatively how shared infrastructure, coopetition and incorporating renewables can be game changers for junior explorers in unlocking further resources and new prospects in the Australian onshore hydrocarbon provinces. The paper also calls for further coordination between companies, industry bodies and government under an improvement framework to ensure continued success.

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Snow, D. J. "Noise control in power plant." Proceedings of the Institution of Mechanical Engineers, Part A: Journal of Power and Energy 211, no. 1 (February 1, 1997): 73–93. http://dx.doi.org/10.1243/0957650971537015.

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During the last decade the shape of the UK non-nuclear electricity generation industry has changed fundamentally from a stable monopoly providing power primarily from large coal-fired units to a rapidly developing competitive industry with a wide range of plant types. The removal of the restrictions on burning natural gas in power stations and the introduction of flue gas desulphurization on some of the traditional plants has highlighted the reduced cost and lower emissions of gas-powered generation, leading to a major increase in the use of this fuel in more efficient combined cycle gas turbine (CCGT) plant. Outside the United Kingdom, the economics and politics of fuel supply and electricity production may be different, and both traditional plant and new CCGT projects are being constructed in overseas markets by UK utilities, often in partnership arrangements with other companies. In parallel with these developments there is significant new effort expended on the development of combined heat and power (CHP) plant and renewable energy sources, especially wind power. Although relatively small in MW terms, the latter plant type presents significant and particular noise control requirements. On the horizon, new coal plant using coal gasification or fluidized bed technologies may be anticipated. At the same time as these major changes in plant selection are occurring there are simultaneous developments in the methods of environmental noise assessment. In this article the use of noise control within the electricity generation industry is reviewed and the influence of the changing trends in plant and environmental noise assessment are discussed.

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Krayev, Vyacheslav M., Alexey I. Tikhonov, and Irina Kuzmina-Merlino. "Perspectives for the Use of Hydrogen Energy in European Countries." Nature Environment and Pollution Technology 21, no. 3 (September 1, 2022): 1439–44. http://dx.doi.org/10.46488/nept.2022.v21i03.053.

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The most actual environmental problems in the XXI century are the following: global warming due to greenhouse gas emissions, energy production at coal, oil and power plants, air pollution, water pollution and waste recycling. Other environmental problems can be added to this short list, but the authors solve a specific task of promoting the idea of a promising “green” energy that will help humanity in conservation and development. European Union (EU) countries are planning to solve the main environmental challenges for the transition to low-carbon electricity by 2050. In many countries in the world every year there are more and more supporters of reducing emissions of carbon dioxide CO2, nitrogen oxides NO and NO2 and other greenhouse gases into the atmosphere. In recent years, EU has been consistently pursuing its own policy in the field of environmental protection, carrying out large-scale environmental measures. In Germany, United Kingdom (UK) and other European countries, a number of environmental initiatives are already gaining the status of state policy, which is being formalized in laws and regulations. Russian Federation acts on the world market as a leading country that produces and supplies significant energy resources not only to Europe, but also to many countries in the Asia-Pacific region. It is clear that the competitive stability of Russian energy companies significantly depends on the situation on the world energy market, but with the right strategy, Russia can actively influence the state of the entire energy market. With a confident leadership position, provided with significant natural, technological and human resources, Russian Federation has undeniable advantages over other energy-producing countries. It is Russia that can become the main supplier of clean energy for all other countries of the world, where tougher environmental requirements for energy generation are being cultivated. The authors of the study are considering the possibility of producing environmentally friendly hydrogen in Russia based on renewable energy sources (RES). The performed analysis shows the undeniable advantages of Russia in the export of hydrogen to other European countries.

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16

JOHNSON, JEFF. "NATURAL GAS MARKET MUDDLE." Chemical & Engineering News 81, no. 42 (October 20, 2003): 20–21. http://dx.doi.org/10.1021/cen-v081n042.p020.

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17

Russell, P., and S. D. Probert. "The UK natural-gas industry." Applied Energy 31, no. 4 (January 1988): 263–303. http://dx.doi.org/10.1016/0306-2619(88)90032-3.

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18

Correljé, Aad. "The European Natural Gas Market." Current Sustainable/Renewable Energy Reports 3, no. 1-2 (July 25, 2016): 28–34. http://dx.doi.org/10.1007/s40518-016-0048-y.

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19

McKinnon, James. "Regulation in the UK gas supply market." Utilities Policy 2, no. 4 (October 1992): 276–78. http://dx.doi.org/10.1016/0957-1787(92)90003-2.

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20

Kevo, Dominik, Ivan Smajla, Daria Karasalihović Sedlar, and Filip Božić. "CROATIAN NATURAL GAS BALANCING MARKET ANALYSIS." Rudarsko-geološko-naftni zbornik 35, no. 4 (2020): 45–56. http://dx.doi.org/10.17794/rgn.2020.4.5.

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The Network Code on Gas Balancing of Transmission Networks stimulates the development of the wholesale gas market by encouraging balance responsible parties to use standardized balancing mechanisms. To balance their portfolios, balance responsible parties can use renominations of quantities at entry and exit points, trade on a virtual trading point or trade on a trading platform. In the event of a system imbalance, Plinacro, as the operator of the gas transmission system in the Republic of Croatia, activates the balancing energy to return the system within acceptable limits. In accordance with the Rules on the Organization of the Gas Market, the Croatian Energy Market Operator performs a monthly calculation of the daily imbalance charge, trades conducted on the trading platform for balancing activities, a neutrality charge and a charge for deviation from the nominated quantities which have been analysed in this paper based on the case study of a chosen balancing group. The analyses conducted in the paper have shown that the balance responsible party may be entitled to compensation or be liable to pay compensation based on the monthly calculation of the Croatian Energy Market Operator, HROTE, depending on the value of each charge. Plinacro as the forecasting party is preparing a new model for the allocation of gas quantities that will affect the operations of gas suppliers, DSOs and especially BRPs. Based on this analysis, it could be concluded that more accurate estimated consumption for a balancing group leads to cost optimization and a more transparent gas market.

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21

Makholm, Jeff D. "The Mysterious US Natural Gas Market." Climate and Energy 37, no. 4 (October 12, 2020): 21–27. http://dx.doi.org/10.1002/gas.22199.

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22

Mallett, Elizabeth. "The Emerging Certified Natural Gas Market." Climate and Energy 39, no. 5 (November 9, 2022): 1–9. http://dx.doi.org/10.1002/gas.22319.

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23

Martin, Robert W. "The Natural Gas Perspective." Energy Exploration & Exploitation 4, no. 2-3 (May 1986): 145–49. http://dx.doi.org/10.1177/014459878600400206.

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Market responsive pricing is a fundamental requirement if natural gas is to play its full part in meeting Canada's energy needs. Regulation must be modified to enable flexibility in buying, transporting and selling natural gas in a market responsive manner. Taxes should be based on profits, not on revenues and, because utility costs, by definition, flow through to the customers, taxation of natural gas utilities should be equitable in relation to electric power utilities.

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24

Egging, Rudolf G., and Steven A. Gabriel. "Examining market power in the European natural gas market." Energy Policy 34, no. 17 (November 2006): 2762–78. http://dx.doi.org/10.1016/j.enpol.2005.04.018.

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Boschee, Pam. "Comments: Growth in Battery Storage Sparks Chase for Metals." Journal of Petroleum Technology 73, no. 04 (April 1, 2021): 10. http://dx.doi.org/10.2118/0421-0010-jpt.

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Natural gas is considered the fossil fuel to facilitate the transition from hydrocarbons to lower-emissions energy sources such as renewables. Wind and solar projects factor significantly into major international oil and gas companies’ goals of achieving net-zero emissions in the future. For example, both BP and Royal Dutch Shell intend to reach net zero by 2050. The International Energy Agency (IEA) forecasts total installed wind and solar PV capacity is on course to surpass natural gas in 2023 and coal in 2024. This represents progress toward the achievement of the 2050 goals. However, wind, solar, and hydropower, which together account for about 90% of all renewable-electricity generation, are largely dependent on variable weather conditions. And the variability in weather translates to an undesired variability in availability and reliability. For wider adoption, utility-scale batteries are needed to store energy for use when a light breeze barely whispers, or the skies are cloudy. Battery-storage projects are not a new concept, but their recent growth is notable. Although California is the global leader in the deployment of high-capacity batteries, news from other parts of the world offers indicators of progress. In 2020, global installed energy-storage capacity totaled 173.6 GW, including pumped-hydroelectric, compressed-air, advanced battery-energy, flywheel-energy, thermal-energy, and hydrogen-energy storage systems. The US had 0.74 GW of rated-power battery-storage projects based on lead-acid, lithium-ion, nickel-based, and sodium-based batteries. A Tesla subsidiary, Gambit Energy Storage LLC, is currently constructing a 100-MW+ battery-storage facility in Angleton, Texas, about 40 miles south of Houston. It is expected to become operational 1 June. Elon Musk (best known for his Tesla electric vehicles and SpaceX) launched a 100-MW lithium-ion battery project in South Australia in 2017 adjacent to a wind farm. Soon to become a “hot(ter)” commodity will be the lithium, rare earths, and other minerals needed to build the batteries. The global lithium and cobalt markets rallied in January and February in response to the resurgence of demand for electric vehicles (EV) in Europe. Last year, sales in battery EVs and plug-in-hybrid EVs in Europe outpaced those in China. Adamas Intelligence reported that the second half of 2020 saw a global 205% increase in battery cobalt deployed, a 192% increase in battery lithium deployed, and a 135% increase in battery nickel deployed vs. the second half of 2019. Investors and companies are chasing this potentially lucrative sector. Startup DeepGreen Metals, whose partners include Maersk and Allseas, aims to mine the deep sea for battery metals and on 4 March announced an agreement to merge with Sustainable Opportunities Acquisition Corp. to list on the Nasdaq. Cornish Lithium, holding rights to explore for lithium within geothermal waters in areas off the north and south coasts of Cornwall, UK, recently signed on MarineSpace to help it begin its desk-based exploration program to identify potential geological targets for later research. Physical exploration work is not expected for at least 4 years.

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Smead, Richard G. "Natural Gas Matters: State of Play in the Natural Gas Generation Market." Natural Gas & Electricity 30, no. 4 (October 18, 2013): 25–28. http://dx.doi.org/10.1002/gas.21725.

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27

Le, Duong Thuy. "Price Volatility in the Natural Gas Market." International Finance and Banking 4, no. 2 (September 6, 2017): 49. http://dx.doi.org/10.5296/ifb.v4i2.11768.

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This paper examines the causes and behavior of price volatility in the US natural gas market. Although natural gas prices are among the most volatile, they have received limited academic scrutiny heretofore. The study’s main findings are: (1) the natural gas market is characterized by volatility persistence, (2) predicted volatility increases more following a positive shock than an equal negative shock, (3) there are day-of-the-week and month-of-the-year patterns in this market, (4) surprises in the change in natural gas in storage cause increased volatility, (5) volatility tends to be higher during and immediately after bid week, and (6) volatility tends to be higher on winter days when the temperature is lower than normal. The model developed and employed in this research is an improved procedure for testing and quantifying the hypothesized volatility determinants within a GARCH type model.

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Hulshof, Daan, Jan-Pieter van der Maat, and Machiel Mulder. "Market fundamentals, competition and natural-gas prices." Energy Policy 94 (July 2016): 480–91. http://dx.doi.org/10.1016/j.enpol.2015.12.016.

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Chai, Jian, Zhaohao Wei, Yi Hu, Siping Su, and Zhe George Zhang. "Is China's natural gas market globally connected?" Energy Policy 132 (September 2019): 940–49. http://dx.doi.org/10.1016/j.enpol.2019.06.042.

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30

Asche, Frank, Petter Osmundsen, and Ragnar Tveteras. "Market integration for natural gas in Europe." International Journal of Global Energy Issues 16, no. 4 (2001): 300. http://dx.doi.org/10.1504/ijgei.2001.000925.

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31

Alger, Dan, and Michael Toman. "Market-based regulation of natural gas pipelines." Journal of Regulatory Economics 2, no. 3 (September 1990): 263–80. http://dx.doi.org/10.1007/bf00134064.

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Smead, Richard G. "Natural Gas Market Movement and Enforcement Risk." Natural Gas & Electricity 31, no. 12 (June 17, 2015): 15–19. http://dx.doi.org/10.1002/gas.21842.

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Holtberg, Paul. "Repowering: New Potential Market for Natural Gas." Natural Gas 10, no. 12 (August 20, 2008): 12–15. http://dx.doi.org/10.1002/gas.3410101204.

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Price, Catherine. "Natural gas in the UK: Options to 2000." Energy Policy 14, no. 5 (October 1986): 457–58. http://dx.doi.org/10.1016/0301-4215(86)90049-2.

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Makagon, Andrey Vitalievich. "Prospects for gas hydrate technologies in natural gas shipping market." Vestnik of Astrakhan State Technical University 2021, no. 2 (November 30, 2021): 43–55. http://dx.doi.org/10.24143/1812-9498-2021-2-43-55.

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The article considers the modern problems and prospects of the development of technologies of transporting the natural gas by sea due to the fact that gas hydrate deposits are found on the bottom of Lake Baikal, the Black Sea, the Caspian Sea and the Okhotsk Sea. It has been stated that despite the proved gas hydrate deposits the fields have not been explored yet. Introducing the technology for transporting gas by sea in gas hydrate form is being substantiated. Comparative analysis of LNG, CNG and NGH technologies for sea transportation of natural gas proved that the transport component of the NGH technological chain has significant advantages over LNG and CNG technologies. The process of converting thermal energy of the ocean has been proposed to use for increasing the energy efficiency of methane production from subsea gas hydrate deposits in the gas hydrate cycle, which can save 10-15% of the produced methane for electricity generation. A schematic and technological solution of a gas production complex is presented, according to which carbon dioxide is introduced into the gas hydrate layer to extract methane from gas hydrates. To improve the kinetics of replacing methane with carbon dioxide in gas hydrates it is proposed to recycle a portion of CO2. Due to the specific and diversified geographic, economic, political and other conditions the conventional technologies for pipeline transportation of gas and LNG cannot fully meet the requirements of gas export and production projects. It has been inferred that NGH technology is most suitable for solving the problem of diversifying natural gas supplies from the Arctic regions, the Black Sea and in the development of offshore gas and oil fields.

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Cabalu, Helen, and Chassty Manuhutu. "Vulnerability of Natural Gas Supply in the Asian Gas Market." Economic Analysis and Policy 39, no. 2 (September 2009): 255–70. http://dx.doi.org/10.1016/s0313-5926(09)50020-3.

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Zhang, Jindong, Yufei Tan, Tiantian Zhang, Kecheng Yu, Xuemei Wang, and Qi Zhao. "Natural gas market and underground gas storage development in China." Journal of Energy Storage 29 (June 2020): 101338. http://dx.doi.org/10.1016/j.est.2020.101338.

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Herbert, John H. "Do Changes in Natural Gas Futures Prices Influence Changes in Natural Gas Spot Prices?" Energy Exploration & Exploitation 11, no. 5 (October 1993): 467–72. http://dx.doi.org/10.1177/014459879301100506.

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Data on natural gas futures and spot markets are examined to determine if variability in price on futures markets influences variability in price on spot markets. Using econometric techniques, it is found that changes in futures contract prices do not precede changes in spot market prices.

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Wright, Blake. "ROPES Offers an Energy Transition Solution to Pipeline Decommissioning." Journal of Petroleum Technology 74, no. 08 (August 1, 2022): 32–36. http://dx.doi.org/10.2118/0822-0032-jpt.

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Oil and gas companies around the world are repositioning themselves to face the energy transition—whether that means embracing the fact that the green economy of the future calls for less hydrocarbon use or something more radical, like Lundin Energy’s (now called Orrön Energy) recent move to sell off its oil and gas assets to become a pure renewables player. One certainty is that as companies trend away from oil and gas and toward a lower-carbon frontier there will still be plenty of “cleanup” to do while players figure out exactly what to do with more than 100 years of oil and gas infrastructure. Offshore, decommissioning of platforms and pipelines is a capital-intensive business and one that is expected to grow in the coming years. Last year, IHS Markit released a forecast predicting global offshore decommissioning spending to reach almost $100 billion for the 2021–2030 period, up by more than 200% compared to the previous 10-year period. According to the forecast, nearly 2,800 fixed platforms and 160 floating platforms could be decommissioned. That represents 33% of fixed platforms and 43% of floating platforms currently in operation. Additionally, more than 18,500 wellheads, 2,850 subsea trees, and 83000 km of offshore pipelines and umbilicals currently in operation are subject to decommissioning during the same period. More than 50% of the expected activity is spread across four countries: the UK, US, Brazil, and Norway. The financial burden and safety liability of marine decommissioning have prompted some to look at the potential for repurposing the hardware and using it in moving toward the drive to net-zero emissions: platforms that could be used to host wind turbines, vessels that could be redesigned to collect hydroenergy, and pipelines that could be repurposed for potential battery storage. Repurposing offshore pipeline as energy storage (ROPES) is a concept that is being investigated by a partnership of offshore projects and services specialists Subsea 7 and offshore energy storage startup Flasc. Flasc was founded as a spinoff from the University of Malta in 2019 and is based in the Netherlands. The concept was described in a paper presented at the 2022 Offshore Technology Conference in Houston (OTC 31703). Subsea 7 and Flasc signed a cooperative exclusivity agreement in late 2020 to work toward the commercialization of Flasc’s patented hydro-pneumatic energy storage (HPES) concept offshore. HPES combines pressurized seawater with compressed air to create an efficient, large-scale energy storage device that can be applied across a wide range of offshore applications. Energy is stored by pumping seawater into a closed chamber to compress a fixed volume of precharged inert gas. The energy can be recovered by allowing the compressed gas to push the water back out through a hydraulic turbine generator (Fig. 1). The technology leverages existing infrastructure and supply chains, along with the marine environment itself as a natural heatsink. The first working prototype was successfully tested in 2018, and DNV has granted the technology a Statement of Feasibility based on a technical and commercial assessment. “The hydro-pneumatic technology is at the core of the ROPES concept, but can also be applied to other embodiments,” said Daniel Buhagiar, co-founder and chief executive of Flasc. “Within this collaboration, we’ve looked at doing some different designs and different products, and ROPES emerged as a very interesting opportunity. Typically, we’re looking at doing new infrastructure, [for instance] installing a bundle or a new piece of kit to store the pressurized fluids. ROPES, we thought, was really the low-hanging fruit because the pipeline infrastructure is already there, and we can create a use case for it beyond the typical applications, such as hydrogen and carbon capture, which are not always possible.”

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Kumar Kar, Sanjay, and Subrat Sahu. "Managing natural gas business: a case of Bharat Natural Gas Company Limited." Emerald Emerging Markets Case Studies 2, no. 1 (March 9, 2012): 1–22. http://dx.doi.org/10.1108/20450621211214450.

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Subject area Marketing - value proposition and value delivery, switching cost, customer acquisition and retention, positioning, pricing, distribution and retailing, role of trust and transparency to build sustainable relationship in B2B context, and efficient service delivery. Study level/applicability Undergraduate and graduate students in marketing, business administration, strategy, retailing, B2B marketing, services marketing and general management courses. Also, it can be used for executive management/training programmes. Case overview The case focuses on an existing scenario of a natural gas business in Gujarat, India, in order to provide understanding of marketing challenges, especially in the B2B context, faced by organisations in this evolving business environment. The case examines the strategies and policies implemented by the company and their impact on the customer. The case presents reactions and responses from the concerned customers. The case illustrates the criticalness of understanding customer expectations and designing and delivering customer centric strategies to sustain market leadership in an evolving and competitive market. Expected learning outcomes The case study enables the students to understand and analyse: the current business environment; the important factors impacting natural gas business; economic analysis of energy; opportunity and challenges for doing cleaner and greener business; role of cleaner fuel to reduce carbon footprint; and carbon credit impacting top line and bottom line of a customer. The case provides students the opportunity to understand and analyse the importance of switching costs to acquire a new customer; and devising and implementing marketing strategies to expand customer base and enter into new territories. Supplementary materials Teaching notes.

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Waddams Price, Catherine, and Matthew Bennett. "New gas in old pipes: opening the UK residential gas market to competition." Utilities Policy 8, no. 1 (March 1999): 1–15. http://dx.doi.org/10.1016/s0957-1787(99)00010-7.

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Zanetti, Eduarda Maria, and Lara Lis Acha Kohler. "Henry Hub natural gas futures market: fundamental analysis." Rio Oil and Gas Expo and Conference 20, no. 2020 (December 1, 2020): 339–40. http://dx.doi.org/10.48072/2525-7579.rog.2020.339.

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Musina, D. R., G. Z. Nizamova, and M. M. Gaifullina. "PRICING IN THE WORLD MARKET OF NATURAL GAS." Oil and Gas Business, no. 2 (April 2018): 188–208. http://dx.doi.org/10.17122/ogbus-2018-2-188-208.

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Núñez, Héctor M., Andres Trujillo-Barrera, and Xiaoli Etienne. "Declining integration in the US natural gas market." Resources Policy 78 (September 2022): 102872. http://dx.doi.org/10.1016/j.resourpol.2022.102872.

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Kim, Sang-Hyun, Yeon-Yi Lim, Dae-Wook Kim, and Man-Keun Kim. "Swing Suppliers and International Natural Gas Market Integration." Energies 13, no. 18 (September 8, 2020): 4661. http://dx.doi.org/10.3390/en13184661.

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This study explores the international natural gas market integration using the Engle–Granger cointegration and error correction model. Previous studies have suggested that liquefied natural gas (LNG) and oil-linked pricing with a long-term contract have played key roles in gas market integration, especially between European and Asian markets. There is, however, little discussion of the role of the emergence of a swing supplier. A swing supplier, e.g., Qatar or Russia, is flexible to unexpected changes in supply and demand in both European and Asian markets and adapts the gas production/exports swiftly to meet the changes in the markets. Qatar has been a swing supplier since 2005 in the global natural gas market. In 2009, Qatar’s global LNG export share reached above 30% and has remained around 25% since then. Empirical results indirectly support that the emergence of a swing supplier may tighten market integration between Europe and Asia. The swing supplier may have accelerated the degree of market integration as well, particularly after 2009.

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Kalashnikov, Vyacheslav V., Gerardo A. Pérez-Valdés, Timothy I. Matis, and Nataliya I. Kalashnykova. "US Natural Gas Market Classification Using Pooled Regression." Mathematical Problems in Engineering 2014 (2014): 1–9. http://dx.doi.org/10.1155/2014/695084.

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Natural gas marketing has considerably evolved since the early 1990s, when a set of liberalizing rules were passed in both the United States and the European Union that eliminated state-driven regulations in favor of open energy markets. These new rules changed many things in the business of energetics, and therefore new research opportunities arose. Econometric studies about natural gas emerged as an important area of study since natural gas may now be sold and traded in a number of stock markets, each one responding to potentially different behavioral drives. In this work, we present a method to differentiate sets of time series based on a regression model relating price, consumption, supply, and other factors. Our objective is to develop a method to classify different areas, regions, or states into groups or classes that share similar regression parameters. Once obtained, these groups may be used to make assumptions about corresponding natural gas prices in further studies.

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Chiou-Wei, Song-Zan, Sheng-Hung Chen, and Zhen Zhu. "Natural gas price, market fundamentals and hedging effectiveness." Quarterly Review of Economics and Finance 78 (November 2020): 321–37. http://dx.doi.org/10.1016/j.qref.2020.05.001.

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Sutherland, Ronald J. "Natural gas contracts in an emerging competitive market." Energy Policy 21, no. 12 (December 1993): 1191–204. http://dx.doi.org/10.1016/0301-4215(93)90269-l.

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Guldmann, Jean-Michel, and Donald A. Hanson. "Natural gas market expansion and delivery infrastructure costs." Resources and Energy 13, no. 1 (April 1991): 57–94. http://dx.doi.org/10.1016/0165-0572(91)90020-4.

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Shukla, P. R., and Subash Dhar. "Regional cooperation towards trans‐country natural gas market." International Journal of Energy Sector Management 3, no. 3 (September 11, 2009): 251–74. http://dx.doi.org/10.1108/17506220910986798.

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PurposeIndia began gas imports since 2004 through liquified natural gas (LNG) route. Imports through trans‐country gas pipelines could help in bringing gas directly into the densely populated Northern part of India, which are far from domestic gas resources as well as coastal LNG terminals. The purpose of this paper is to report scenarios, which quantify the impacts for India of regional cooperation to materialize trans‐country pipelines. The analysis covers time period from 2005 to 2030.Design/methodology/approachThe long‐term energy system model ANSWER‐MARKAL is used for the analysis.FindingsTrans‐country pipelines could deliver direct economic benefit of US$310 billion for the period 2010‐2030. Besides these, there are positive externalities in terms of lower greenhouse gas emissions and improved local environment, and enhanced energy security. However, the benefits are sensitive to global gas prices as higher gas prices would reduce the demand for gas and also the positive externalities from using gas.Practical implicationsTrans‐country pipelines are of great importance to India as they add 0.4 per cent to gross domestic product over the period besides yielding positive environmental externalities and improved energy security.Originality/valueQuantification of benefits from trans‐country pipeline proposals till 2030.

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