with each other due to the substituting character for specific utilization (e.g. heating oil/gas vs. heating with biomass vs. electricity) and the direct usage of energy fuels in downstream markets (e.g. coal, oil andgas as fuel input for electricity) the relations between markets need to be accounted in estimates of future developments. In addition energy markets often rely on network structures which add a spatial layer to the problem. This interaction of energy markets is particular relevant for naturalgasandelectricity systems. The increasing importance of emission reductions raises the need for a shift from coal based to naturalgas fired units. Similar the increased utilization of intermittent renewable generation units raises the need for more flexible generation units as back-up capacities which are mainly assumed to be gas fired. These developments will likely increase demand for naturalgas in the electricity sector which can raise the need for investment in gas infrastructure. On the supply side the development of unconventional gasand further increases in the LNG infrastructure can lead to shifts in the global naturalgas market prices (IEA, 2011b) which in turn will have an impact on the dispatch order of existing electricity units and influence investment incentives. As this interaction is becoming increasingly relevant for gasandelectricity markets due to the importance of gas as future fuel and the network characteristics of both markets research addressing this interaction has enlarged in recent years. Rubio et al. (2008)provide a review on integrated naturalgasandelectricity system planning and highlight economic and market related aspects.
four node test case anda stylized representation of the continental European naturalgasandelectricity markets, we can present two important insights for future market evalu- ations. First, the meshed nature of electricity transmission and power flows leads to a high complexity that needs to be captured in investment models to provide reasonable evaluations. This issue is techno-economic in nature and requires the inclusion of basic electrical-engineering elements in market models. A simplified representation of power flows via pure (directed) trade flows is likely to provide biased results. Second, naturalgasandelectricity markets face a mutual interdependence in investment decision that requires acombined approach to be adequately captured within model estimates. As optimal investment decision of substituting alternatives (i.e. pipeline and power plant investments vs. transmission line and plant investments) depend on the locational price spreads in the markets which in turn strongly depend on the chosen investments an integrated assessment is needed. Capturing this interaction in separated models is likely to provide biased results. The investment substitution aspect is furthermore amplified by the problems of meshed electricity networks. The paper provides further insights for the ongoing discussion about the future development about market design in gasandelectricity markets. Most of this discussion is focused on single aspects – i.e. the capacity market debate in electricity generation or the question about optimal network regula- tion to foster optimal investments – although they are finally interlinked and therefore warrant a comprehensive and encompassing approach. The developed model can help to provide such a bridge between the ongoing fields and help to develop robust market and policy recommendations for the challenges at hand.
Naturalgas plays an important role in the future development of electric- ity markets, as it is the least emission-intensive fossil generation option and additionally provides the needed plant operating flexibility to deal with in- termittent renewable generation. As both the electricityand the naturalgas market rely on networks, congestion in one market may lead to changes in the other. In addition, investment in one market impacts investment in the other market to the extent that these investments may even become substi- tutes for each another. The objective of this paper is to develop a dynamic model representation of coupled naturalgasandelectricitynetwork markets to test the potential interaction with respect to investments. The model is tested under simplified conditions as well as for a stylized European network setting. The results indicate that there is sufficient potential for investment substitutionand market interactions that warrant the application of coupled models, especially with regard to simulations of long-term system develop- ments.
rectly to low electricity prices via end use fuel substitutionand only captures the impact of changes in
the dispatch of gas fired power plants. Price changes due to variations in the consumption of coal are
also not included, which could lead to a further demand decrease or increase in the naturalgas sector.
Finally, the emission permit price is exogenous to the model. Thus, resulting plant dispatch decisions
This work wants to bridge the gap between the mid-term time horizon of the network developments plans and the long-term payback time of grid investments, often linked to energy security arguments. It wants to add insight of the long-term horizon given by transformation processes such as the German Energiewende to a mid-term grid expansion planning process with a special focus on energy security. In literature, many studies deal with policy perspectives of energy security [7,8], analyze the naturalgas supply security , provide an index for assessing national energy security  or develop methods to examine how a linkage of electricityandnaturalgas system effects energy security [11–13]. But yet no study considered the long-term impacts of transforming energy systems on the naturalgas transport grid and its influence to grid expansion planning in a comparable manner. To achieve this, the status quo of the gas transport system in Germany is analyzed in Section 2. The presented data is basis of the gas flow calculations performed for this work. The applied methods for estimating the long-term gas demand in accordance with the goals of the Energiewende and related gas flow calculations are given in Section 3. Section 4 shows the results with a focus on energy security and Section 5 gives a final discussion.
Moreover, the historical non-viability of domestic commercial utilisation of gas has severely discouraged investments in gas projects by most companies, who do not see returns on their investment guaranteed by the current market-structure. This has locked underground a relevant share of Nigerian gas, that is non-associated gas: almost 60% of the gas produced in Nigeria today is associated (see Figure 18). Associated gas is usually present at a low pressure, and hence requires compressing facilities to be present before been sent through the transmission network, leading the cost of delivery to the point of use up to 4-times higher than non-associated gas. Given that the location of most gas-to-power projects in Nigeria has been determined with more attention to political relevance of constituencies than to the cost of getting gas to the site, is not surprising that the old Power Holding Company of Nigeria had a long history of under-payment (and the new generating companies are rapidly building a similar reputation). The implicit assumptions in the Nigerian power system that it is better to transport gas than electricity over long distances and that gas will always be available on the generation site have been proven wrong multiple times. Given the current level of domestic gas price, private companies cannot be expected to embark on investment in infrastructure of the level required to upgrade the transmission network to a suitable standard for power generation (US$ 1.5-2 billion between 2014 and 2019). A better solution would be to site any new gas-fired generation unit near to a non-associated gas field while providing clear and favourable fiscal terms so to bring them to productive use.
There are numerous literature sources that discuss the role of different technologies, such as EVs, hydrogen, power-to-heat, etc. for the European energy transition. Jimenez-Navarro et al. [ 5 ] examined the role of centralized cogeneration plants in the future decarbonized energy system. Roach and Meeus [ 6 ] developed a partial equilibrium model for the power andgas sectors to analyze future investments, whereas Emosnt et al. [ 7 ] focused on the hydrogen infrastructure. Paviˇcevi´c et al. [ 8 ] combineda long-term planning tool with a unit commitment model of power markets. Although they considered multiple sectors in their analysis, they neither considered the naturalgas markets nor modeled the effect of strategic behavior. Brown et al. [ 9 ] discussed the coupling of electricity to other energy sectors, such as transport and heating, and investment in transition networks, whereas Steinmann et al. [ 10 ] focused on storage technologies (PtH, etc.) as a way to achieve the sector coupling. While many of these studies focus on one or two aspects of sector coupling, they miss the linkage with the naturalgas sector.
When both the German and the French energy systems were close to a breakdown on February 9 th , 2012, energy policymakers and regulators „discovered“ that electricity networks and the naturalgas in- frastructure, which had been treated independently from each other for the last decades, are closely interconnected. A cold spell in continental Europe sent electricity demand in France to a long-time high of 100 GW. In the meantime, six German nuclear power plants that previously assured cheap electricity exports to France had been shut down following the moratorium on nuclear power after the Fukushima accident in March 2011. Gas-fired combined cycle plants in the South of Germany could not substitute for the loss of power from the nuclear plants due to a lack of access to gas pipeline ca- pacity. At the same time, plenty of naturalgas was transported from Austria and South Germany to Italy (EC, 2012). While rolling blackouts could be avoided due to active demand management by the French operators, the issue of electricity-naturalgas interdependence was launched and led to a ma- jor enquiry by the European Commission, with concrete regulatory action most likely upcoming. The issue of electricity-naturalgas interdependence it not specific to the one case mentioned and is becoming a major energy policy and regulatory issue in all jurisdictions around the world undergoing the transformation to a lower-carbon and/or renewables-based energy system. Naturally the issue rose to top priority in Japan after the closing down of nuclear power in 2011 and likewise advanced to center stage in North America following the „shale gas revolution“, e.g. in PJM (Sotkiewicz, 2012). Fur- thermore, the developments of the Arab Spring and the recurrent disputes between Russia and its gas transit countries Belarus and the Ukraine highlighted the issue of supply security of the import de- pendent European Union.
The situation in Rwanda is totally different: in view of the over-reliance on energy imports, the dependency on declining hydropower performance, and the lack of sustainable options for expanding existing hydroelectricity capacities, the government is feverishly seeking alternatives. At present it is unable to cope with past levels of demand, let alone the sharp growth in demand of 15% per year that has arisen out of economic growth fired par- ticularly by a boom in the construction sector. If the Rwandan leadership wants to legitimate itself as a guarantor of progress and economic growth, it has to provide affordable energy. As already mentioned, diesel generation as an immediate practical solution to the energy crisis is adding to the eco- nomic burden on the country. In addition to this, only 5% of the population is connected to the grid, with 60% of those connected living in Kigali. Ninety percent of Rwanda’s 8.1 million people live in rural areas, where electricity provision is still more or less non-existent. Rural electrification would be an effective option for handling the growing, though silent, dissatisfaction with the concentration of development efforts on Kigali.
3.1. The data
The data cover a time series between 1965 and 2012, and the relevant data can be from BP Statistical Review of World Energy 2013 and the World Bank. This paper considers six predictive vari- ables that are important for forecasting the naturalgas consump- tion in the future, including (1) GDP (the annual growth rate), (2) urban population (UPOP, the percentage of urban population to the total population which stands for the urbanization level), (3) energy consumption structure (ECST, the percentage of coal con- sumption to the total energy consumption), (4) industrial struc- ture (INST, the percentage of value-added of heavy industry to GDP, which is an indicator of industrial structure), (5) energy efficiency (EEFF, the added production value divided by energy consumption of industry) and (6) exports of goods and services (EPGS, the an- nual growth rate). Here, naturalgas price is not taken as an impor- tant factor in our consumption forecast, because the Chinese ad- ministration imposes a price control system on naturalgas; thus, the price cannot significantly reflect the change of naturalgas con- sumption.
The objective of reform is not to save “gas” as a gaseous state, to use existing infrastructure, but to use (or: develop) infrastructures to serve full decarbonization. The pro-industry narrative is one of “energy gases”, driven by the wish to keep the existing LNG, transmission and distribution infrastructure alive, and well-remunerated for its capital investors, without much of a risk. However, as we have shown above, other energy gases will not necessarily substitute fossil gas; this might as well be done by electricityand firm and/or liquid bio-energies. The rhetoric of many “shades of gas”, including “green”, “blue”, “grey”, “synthetic” but renewable, and yet other names and games, mainly targets the infrastructure issue, to create a sense of justification to maintain the fossil-induced infrastructure. This is neither technically nor economically justified. The failed history of global LNG markets (Jensen 2004; Neumann 2009) suggests not to bet on “globalization” of other gases, such as synthetic fuels or hydrogen. The hypothesis of global gas markets has not worked for LNG, which can be standardized quite easily, and it is much less likely to work for other types of gases, in particular hydrogen. Even though some quantities are currently being traded internationally, e.g. between Australia and Japan to fuel the 2021 Olympics, it is unlikely that large-scale hydrogen from renewables takes a significant share in the decarbonization agenda. If some energy gases remain in the energy mix (which is possible but not necessary), they should be locally sourced, and locally consumed.
Reducing building energy consumption would change the picture significantly; energy standards and codes for new constructions have been effective tools in increasing energy efficiency levels in new buildings constructed. However, improving the efficiency of existing building stock, which accounts for approximately 33 million units (Department of Treasury, 2011) is also important. It is likely that 2020 European targets will be feasible with specific policies directed at reducing energy consumption in the existing stock of buildings and the promotion of renewable energy deployment as well. Despite the effort taken, there is a substantial “efficiency gap” betweena consumer’s actual investment in energy efficiency and those that appear to be in the consumer’s own interest (Andersson and Baker 1993). This efficiency gap is defined as the difference between the highest implicit discounted rate and the market rate of return associated with the consumer’s decision process. Although most of the energy efficiency measures are cost- effective with a positive net present value, they are not implemented. There are various reasons that explain the existence of an energy efficiency gap which in turn hinders the realization of energy improvements. Such reasons include financial barriers, insufficient information/knowledge and analytical capacity (Sanstand e Howarth, 1994), low priority of energy issues, transaction costs, uncertainty of savings, split incentives, liquidity constraints in capital markets (Blumetein, 1990), and the need for investments in upfront costs. A key issue emerging within the debate in previous years, is on how policy and programs may influence consumer perception and enable investment in energy efficiency.
counterparts. The liberal twins US and UK had thus initiated a still ongoing worldwide liberalization of power sectors, which fundamentally changed the rules of the game 6 . Today the liberalization of most industrialized power sectors has been enacted and markets are changing gradually in response to the new regimes 7 . The outcomes of reforms are still unclear though; for current states see for example the studies in Siosahnsi & Pfaffenberger (2006) and Sioshansi (2008), and the overview of problems by Wilson (2002). But, as will be shown below, a properly functioning market is seen as the most important device to accomplish the low-carbon transition by many policy makers. First experiences if markets and particular designs have worked well are ambiguous though; cp. Beneyto (2010). On one side the Pennsylvania-New Jersey-Maryland (PJM) market in the US is often named as a positive example for keeping the promise of efficiency. Likewise, the north European Nordpool market has also performed quite well. On the other side, some schemes have clearly failed: in California design flaws have led to a great crisis in 2001 as documented by Sweeney (2002). For the UK, Thomas (2006b) claims that the so called “British Model” had failed, mainly due to a not properly developed wholesale marketplace lacking both liquidity and unrestricted access. Moreover, Woo et al. (2003) point out the negative influence of market power in several countries. The distinct outcomes of liberalizations have motivated comparative studies trying to identify reasons; see for example Thomas (2006a) and Hadjilambrinos (2005) for a comparison of Britain and Norway/Nordpool. They find that the particular generation mix and the adherence to public ownership instead of privatization played an important role for the success of latter and the failure of the former model. On a more general level, they conclude that the socio-political dimensions underlying and shaping the reforms are a crucially important factor. Notwithstanding early experiences whatsoever, the major challenge for liberalized markets is to provide appropriate capacity in the long run. And in this regard the success of reforms is still unproven.
Figure 5: Pipeline expansions in scenario EU1 with destination within the EU-27 member states (lower part of horizontal axis is the pipeline’s origin; in EJ/y)
Five major pipeline projects can be identified: First, the exogenously included Nord Stream pipeline from Russia to Germany (2.25 EJ/y) is built until 2015 and won’t be further expanded. Sec- ond, the White Stream pipeline is endogenously added to the European pipeline system in order to bring Caspian naturalgas to Romania and central Europe from 2020 on. This means a major expan- sion between the Caspian region and Romania (by 1.29 EJ/y), from Romania to Hungary (by 1.19 EJ/y) and further to Austria (by 1.06 EJ/y). From there, additional pipeline capacity to Germany (plus 1.25 EJ/y) is needed while the existing one from Austria towards Italy is sufficient. Third, capacity is added endogenously from Africa to Italy (GALSI pipeline with 1.10 EJ/y) to satisfy Italian demand and to further transport it to Western and Central Europe via Austria. This result in an expansion from Italy to Austria (by 0.25 EJ/y) and also explains the significant expansion between Austria and Germany (see above). The fourth major expansion project towards Europe can be seen between Africa and Spain (Medgaz pipeline with 0.96EJ/y). This endogenous expansion is partly explained by African ex- ports to France, which is reflected in additional capacity from Spain towards France (0.42 EJ/y). Final- ly, the first section of South Stream is included with exogenous expansions between Russia and Bul-
customers who terminated their relationship (“customer recovery”) has become increasingly important for organizations. With the growing importance of customer recovery in present times, organizations face even more challenges pertaining to risk of making wrong investment decisions. Organizations can either mistakenly invest in customer relations that are “alive” or irretrievably “dead.” Furthermore, it has the risk of not investing in inactive customer relations that have a chance to be revived (“dying”). Consequently, it is necessary for
as centralized and decentralized solutions. Thus, a more diverse range of fuel supplies will be used, with (biogenic) low-caloric gases such as syngas and coke oven gas (COG) among them. Typical for theses low-caloric gases is the amount of hydrogen, with a share of 50% and even higher. However, hydrogen mixtures have a higher reactivity than naturalgas (NG) mixtures, burned mostly in today’s gas turbine combustors. Therefore, in the present work, acombined experimental and modeling study of nitrogen-enriched hydrogen-air mixtures, some of them with a share of methane, to be representative for COG, will be discussed focusing on laminar flame speed data as one of the major combustion properties. Measurements were performed in a burner test rig at ambient pressure and at a preheat temperature T 0 of 373 K. Flames were stabilized at fuel-air ratios between about φ = 0.5 - 2.0 depending on the
2.3.2 Typical APG Monetization Project Disruption
Normally a conventional APG recovery and monetization facility is constructed and built to a given capacity following the initial APG streams. However, down the line during monetization, APG productions do see a decrease owing to oil production reduction. For an on-site monetization facility supplied from a single oil field, the APG facility operation is tied to resource streams as oil is produced. Around the world, with time traditional standalone APG monetization facilities may experience shutdowns while oil production is still possible. This is envisaged following continuous low supplies of APG from oilfield far below the monetization plant capacity requirements after few years of commencing monetization. Depending on the type of monetization technology being considered, and if such resource decline was analysed during project evaluation stage; otherwise this can bring the overall monetization project to run on the region of unacceptable capacity factor 5 .
the economics of this technology which is hitherto little explored research-wise. The work presents cost components, business models and organizational structures of infrastructure management in the case of fast charging for EV. It touches upon metrics used in investment analysis, such as Return on Investment and cost annuities. Calculations of contribution margins allow for an insight into the economics of EV fast charging systems in a short-term perspective. The equilibrium model Esymmetry (Traber & Kemfert 2011a) is used to model the electricity market dispatch under oligopolistic competition of Cournot type. It is used to replicate electricity market prices and to address the question whether market power affects the attractiveness of station operation from the perspective of electric utilities. The results are very pessimistic about the operational margins of station operations and they suggest that charging stations must be complemented with other purposes than pure power sales to generate profits.
Original scientific paper DOI: 10.2298/TSCI151001209E
Calcium looping is promising for large-scale CO 2 capture in the power generation
and industrial sectors due to the cheap sorbent used and the relatively low energy penalties achieved with this process. Because of the high operating temperatures the heat utilisation is a major advantage of the process, since a significant amount of additional power can be generated from it. However, this increases its complexity and capital costs. Therefore, not only the energy efficiency performance is im- portant for these cycles, but also the capital costs must be taken into account, i. e. techno-economic analyses are required in order to determine which parameters and configurations are optimal to enhance technology viability in different integration scenarios. In this study the integration scenarios of calcium looping andnaturalgascombined cycles are explored. The process models of the naturalgascombined cy- cles and calcium looping CO 2 capture plant are developed to explore the most
The general principle of daily balancing as defined in the Network Code on Gas Balancing implies that grid users’ end‐of‐day positions are relevant. Moreover, TSO may offer line‐pack flexibility, again following the end‐of day principle.
However, with variable demand and supply, unpredictable short‐term variations also for very short time horizons occur. Hence, it is debated if we need even shorter period intraday markets with standardized products until 1h before real‐time, or within‐day gas balancing. In this context, the additional need for coordination betweengasandelectricity TSOs, especially after gate closure, remains open, however. In addition to TSO cooperation, also other trade‐offs arise when enhancing flexibility. For instance, making contracts quick and flexible creates an issue on the storage side, where storage facilities are not necessarily built for flexible and fast use.