Feasibility of pico-hydro and photovoltaic hybrid power systems for remote villages in Cameroon

Pico-hydro (pH) and photovoltaic (PV) hybrid systems incorporating a biogas generator have been simulated for remote villages in Cameroon using a load of 73 kWh/day and 8.3 kWp. Renewable energy systems were simulated using HOMER, the load profile of a hostel in Cameroon, the solar insolation of Garoua and the flow of river Mungo. For a 40% increase in the cost of imported power system components, the cost of energy was found to be either 0.352 €/kWh for a 5 kW pico-hydro generator with 72 kWh storage or 0.396 €/kWh for a 3 kWp photovoltaic generator with 36 kWh storage. These energy costs were obtained with a biomass resource cost of 25 €/tonne. The pH and PV hybrid systems both required the parallel operation of a 3.3 kW battery inverter with a 10 kW biogas generator. The pH/biogas/battery systems simulated for villages located in the south of Cameroon with a flow rate of at least 92 l/s produced lower energy costs than PV/biogas/battery systems simulated for villages in the north of Cameroon with an insolation level of at least 5.55 kWh/m²/day. For a single-wire grid extension cost of 5000 €/km, operation and maintenance costs of 125 €/yr/km and a grid power price of 0.1 €/kWh, the breakeven grid extension distances were found to be 12.9 km for pH/biogas/battery systems and 15.2 km for PV/biogas/battery systems respectively. Investments in biogas based renewable energy systems could thus be considered in the National Energy Action Plan of Cameroon for the supply of energy to key sectors involved in poverty alleviation.     

Wind energy as a potential generation source at Ras Benas,Egypt

Analysis of the wind characteristics in Ras Benas city located on the east coast of Red Sea in Egypt using measured data (wind, pressure and temperature) and Weibull function were made.Statistical analysis model to evaluate the wind energy potential was introduced. According to the power calculations done for the site, the annual mean wind density is 315 kW/m² at a height of 70 m above ground level. This station has a huge wind energy potential for electricity generation, especially during spring and summer seasons, comparing with some European countries.In addition, the monthly wind turbine efficiency parameter (η_monthly) has been calculated by using a commercial wind turbine 1 MW with 70 m hub height to help designers and users in evaluating the potentialities and choosing the suitable wind turbine for the considered site. The use of wind turbine with capacity greater than 1000 kW at this station was recommended.Ras Benas station was selected to install 30 MW-wind farm consists of 20 commercial wind turbines (Nordex S 77) with hub heights and Rotor diameter were 100 and 77 m, respectively. This site has annual wind speed more than 9.8 m/s at 100 m height and enough area to locate these turbines.The estimated energy production using WASP Program of these wind farm was 130 GWh/year. Furthermore, the production costs was found 1.3€ cent/kWh, which is a competition price at the wind energy world market.     

Unravelling historical cost developments of offshore wind energy in Europe

This paper aims to provide insights in the cost developments of offshore wind energy in Europe. This is done by analysing 46 operational offshore wind farms commissioned after 2000. An increase of the Capital Expenditures (CAPEX) is found that is linked to the distance to shore and depth of more recent wind farms and commodity prices. Analysis results indicate that these two factors are only responsible for about half of the observed CAPEX increase, suggesting other factors such as turbine market with limited competition also led to an increasing CAPEX. Using CAPEX, Annual Energy Production, Financings costs and Operational Expenditures, the development of average Levelized Cost of Electricity (LCoE) is shown to increase from 120 €/MWh in 2000 towards 190 €/MWh in 2014, which is a direct result of the CAPEX increase. The results indicate very different LCoE values among European countries, from currently about 100 Euro/MWh in Denmark and Sweden to 150-220 Euro/MWh in all other countries investigated suggesting an effect of national policy frameworks on the LCoE of offshore wind energy.     

Price development of photovoltaic modules,inverters, and systems in the Netherlands in 2012

Since 2010 the Dutch photovoltaic (PV) market has been growing fast, with around doubling of installed capacity in 2011 and 2012. Four quarterly inventories have been made in 2012 for modules, inverters, and systems that are presently available for purchase in the Netherlands. We have found that the average selling price of modules, inverters, and systems decreased with 44.3, 14, and 7.3–10.2%, respectively: average selling prices are 1.26 €/Wp, 0.41 €/Wp, and 1.46 €/Wp for modules, inverters, and systems on tilted roofs, respectively, at the end of 2012. Average installation costs amount to 0.43 €/Wp. Using an energy yield of 900 kWh/kWp, 25 years system lifetime, 6% discount rate, and 1% operation and maintenance (O&M) cost, a levelized cost of electricity (LCOE) is calculated for a 2.5 kWp system to be 0.194 €/kWh for a system price of 1.98 €/Wp (including installation). Grid parity conditions are apparent, with electricity retail prices of around 0.23 €/kWh.     

Performance of simulated flexible integrated gasification polygeneration facilities,Part B: Economic evaluation.

This paper investigates the economics of integrated gasification polygeneration (IG-PG) facilities and assesses under which market conditions flexible facilities outperform static facilities. In this study, the facilities use Eucalyptus wood pellets (EP), torrefied wood pellets (TOPS) and Illinois #6 coal as feedstock to produce electricity, FT-liquids, methanol and urea. All facilities incorporate CCS. The findings show production costs from static IG-PG facilities ranging between 12 and 21 €/GJ using coal, 19–33 €/GJ using TOPS and 22–38 €/GJ using EP, which is above the average market prices. IG-PG facilities can become competitive if capital costs drop by 10%–27% for coal based facilities. Biomass based facilities will need lower biomass pellet prices or higher CO₂ credit prices. Biomass becomes competitive with coal at a CO₂ credit price of 50–55 €/t CO₂. Variations in feedstock, CO₂ credit and electricity prices can be offset by operating a feedstock flexible IG-PG facility, which can switch between coal and TOPS, thereby altering its electricity production. The additional investment is around 0.5% of the capital costs of a dedicated coal based IG-PG facility. At 30 €/t CO₂, TOPS will be the preferred feedstock for 95% of the time at a feedstock price of 5.7 €/GJ. At these conditions, FT-liquids (gasoline/diesel) can be produced for 15.8 €/GJ (116 $/bbl). Historic records show price variations between 5.7 and 7.3 €/GJ for biomass pellet, 1.0–5.6 €/GJ for coal and 0–32 €/t CO₂. Within these price ranges, coal is generally the preferred feedstock, but occasionally biomass is preferred. Lower biomass prices will increase the frequency of switching feedstock preference from coal to biomass, raising the desire for flexibility. Of the three investigated chemicals, an IG-PG facility producing FT-liquids benefits the most from flexibility. Our study suggests that if the uncertainty in commodity prices is high, a small additional investment can make flexible IG-PG facilities attractive.     

Assessment of renewable energy reserves in Taiwan

Since Taiwan imports more than 99% of energy supply from foreign countries, energy security has always been the first priority for government to formulate energy policy. The development of renewable energy not only contributes to the independence of energy supply, but also achieves benefits of economic development and environmental protection. Based upon information available to public, the present paper reassesses reserves of various renewable energies in Taiwan. The assessment includes seven kinds of renewable energies, namely, solar energy, wind power, biomass energy, wave energy, tidal energy, geothermal energy and hydropower, which are all commercialized and matured in terms of current technologies. Other renewable energies, which have not proven as matured as the aforementioned ones, are only assessed preliminarily in this paper, such as second generation of biomass, deep geothermal energy, the Kuroshio power generation and ocean thermal energy conversion.According to the estimation of this paper, the reserve of wind energy, up to 29.9 kWh/d/p (i.e., kWh per day per person), is the largest one among seven kinds of renewable energies in Taiwan, followed by 24.27 kWh/d/p of solar energy, 4.55 kWh/d/p of biomass, 4.58 kWh/d/p of ocean energy, 0.67 kWh/d/p of geothermal energy and 16.79 kWh/d/p of hydropower. If regarding biomass as a primary energy, and assuming 40% being the average efficiency to convert primary energy into electricity, the total power of the seven kinds of renewable energy reserves is about 78.03 kWh/d/p, which is equal to 2.75 times of 28.35 kWh/d/p of national power generation in 2008. If the reserves of 54.93 kWh/d/p estimated from other four kinds of renewable energies that have not technically matured yet are also taken into account, it will result that the reserves of renewable energy in Taiwan can be quite abundant.Although the results of the assessment point out that Taiwan has abundant renewable energy resources, the four inherent shortcomings – low energy density, high cost of power generation, instability of power supply, and current cost of renewable energy being still higher than that of fossil energy – have to be overcome first, before renewable energy is actually formed as a main component in national energy mix. The measures executed by government to break through these barriers further include the upgrade of the technological level, the formulation of the necessary policies, and the work together from all levels for the overall promotion.     

The economical and environmental performance of miscanthus and switchgrass production and supply chains in a European setting

The purpose of this study is to analyse the economical and environmental performance of switchgrass and miscanthus production and supply chains in the European Union (EU25), for the years 2004 and 2030. The environmental performance refers to the greenhouse gas (GHG) emissions, the primary fossil energy use and to the impact on fresh water reserves, soil erosion and biodiversity. Analyses are carried out for regions in five countries. The lowest costs of producing (including storing and transporting across 100 km) in the year 2004 are calculated for Poland, Hungary and Lithuania at 43–64 € per oven dry tonne (odt) or 2.4–3.6 € GJ^?1 higher heating value. This cost level is roughly equivalent to the price of natural gas (3.1 € GJ^?1) and lower than the price of crude oil (4.6 € GJ^?1) in 2004, but higher than the price of coal (1.7 € GJ^?1) in 2004. The costs of biomass in Italy and the United Kingdom are somewhat higher (65–105 € odt^?1 or 3.6–5.8 € GJ^?1). The doubling of the price of crude oil and natural gas that is projected for the period 2004–2030, combined with nearly stable biomass production costs, makes the production of perennial grasses competitive with natural gas and fossil oil. The results also show that the substitution of fossil fuels by biomass from perennial grasses is a robust strategy to reduce fossil energy use and curb GHG emissions, provided that perennial grasses are grown on agricultural land (cropland or pastures). However, in such case deep percolation and runoff of water are reduced, which can lead to overexploitation of fresh water reservoirs. This can be avoided by selecting suitable locations (away from direct accessible fresh water reservoirs) and by limiting the size of the plantations. The impacts on biodiversity are generally favourable compared to conventional crops, but the location of the plantation compared to other vegetation types and the size and harvesting regime of the plantation are important variables.     

Biomass and central receiver system (CRS) hybridization: Volumetric air CRS and integration of a biomass waste direct burning boiler on steam cycle

Concentrated solar power (CSP) plants generate an almost continuous flow of fully dispatchable “renewable” electricity and can replace the present fossil fuel power plants for base load electricity generation. Nevertheless, actual CSP plants have moderate electricity costs, in most cases quite low capacity factors and transient problems due to high inertia. Hybridization can help solve these problems and, if done with the integration of forest waste biomass, the “renewable” goal can be maintained, with positive impact on forest fire reduction. Local conditions, resources and feed in tariffs have great impact on the economical and technical evaluation of hybrid solutions; one of the premium European locations for this type of power plants is the Portuguese Algarve region.Due to the concept innovation level, conservative approaches were considered to be the best solutions. In this perspective, for a lower capital investment 4 MWe power plant scale, the best technical/economical solution is the hybrid CRS/biomass power plant HVIB3S4s with CS3 control strategy. It results in a levelized electricity cost (LEC) of 0.146 €/kWh, with higher efficiency and capacity factor than a conventional 4 MWe CRS. A larger 10 MWe hybrid power plant HVIB3S10s could generate electricity with positive economical indicators (LEC of 0.108 €/kWh and IRR of 11.0%), with twice the annual efficiency (feedstock to electricity) and lower costs than a conventional 4 MWe CRS. It would also lead to a 17% reduction in biomass consumption (approximately 12,000 tons less per year) when compared with a typical 10 MWe biomass power plant – FRB10; this would be significant in the case of continuous biomass price increase.     

California offshore wind energy potential

This study combines multi-year mesoscale modeling results, validated using offshore buoys with high-resolution bathymetry to create a wind energy resource assessment for offshore California (CA). The siting of an offshore wind farm is limited by water depth, with shallow water being generally preferable economically. Acceptable depths for offshore wind farms are divided into three categories: ≤20 m depth for monopile turbine foundations, ≤50 m depth for multi-leg turbine foundations, and ≤200 m depth for deep water floating turbines. The CA coast was further divided into three logical areas for analysis: Northern, Central, and Southern CA. A mesoscale meteorological model was then used at high horizontal resolution (5 and 1.67 km) to calculate annual 80 m wind speeds (turbine hub height) for each area, based on the average of the seasonal months January, April, July, and October of 2005/2006 and the entirety of 2007 (12 months). A 5 MW offshore wind turbine was used to create a preliminary resource assessment for offshore CA. Each geographical region was then characterized by its coastal transmission access, water depth, wind turbine development potential, and average 80 m wind speed. Initial estimates show that 1.4–2.3 GW, 4.4–8.3 GW, and 52.8–64.9 GW of deliverable power could be harnessed from offshore CA using monopile, multi-leg, and floating turbine foundations, respectively. A single proposed wind farm near Cape Mendocino could deliver an average 800 MW of gross renewable power and reduce CA's current carbon emitting electricity generation 4% on an energy basis. Unlike most of California's land based wind farms which peak at night, the offshore winds near Cape Mendocino are consistently fast throughout the day and night during all four seasons.     

Carbon prices and CCS investment: A comparative study between the European Union and China

Carbon Capture and Storage is considered as a key option for climate change mitigation; policy makers and investors need to know when CCS becomes economically attractive. Integrating CCS in a power plant adds significant costs which can be offset by a sufficient CO₂ price. However, most markets have failed: currently, the weak carbon price threatens CCS deployment in the European Union (EU). In China, a carbon regulation is appearing and CCS encounters a rising interest. This study investigates two questions: how much is the extra-cost of a CCS plant in the EU in comparison with China? Second, what is the CO₂ price beyond which CCS plants become more profitable than reference plants in the EU and in China? To address these issues, I conducted a literature review on public studies about CCS costs. To objectively assess the profitability of CCS plants, I constructed a net present value model to calculate the Levelised Cost of Electricity and the breakeven CO₂ price. CCS plants become the most profitable plant type beyond 115 €/tCO₂ in the EU vs. 45 €/tCO₂ in China (offshore transport and storage costs). I advise on the optimal plant type choice depending on the CO₂ price in both countries.     

Evaluation of optimal power options for base transceiver stations of Mobile Telephone Networks Cameroon

Photovoltaic hybrid systems (PVHS) with 2 days of energy autonomy are shown to be optimal options for the supply of the daily energy demands of 33 base transceiver stations of MTN Cameroon. PVHS were computed for all sites using the technical data for a 150 Wp mono-crystalline module, the site specific hourly load data, the average monthly solar radiation and temperature. Hourly solar radiation data for all sites were downloaded using the solar resource module of HOMER and geographical coordinates of the selected sites. The 3-hourly temperature data available on a website maintained NASA was used to generate average monthly hourly temperatures needed in the calculation of the output of solar modules. The energy costs and breakeven grid distances for possible power options were computed using the Net Present Value Technique and financial data for selected power system components. The results with a PV module cost of 7.5 €/Wp, a remote diesel price of 1.12 €/l, a general inflation rate of 5% and a fuel escalation of 10% showed that the annual operational times of the diesel generator were in the range 3–356 h/year with renewable energy fractions in the range 0.89–1.00. However, only 22 PVHS had two parallel battery strings as stipulated in the request for proposal launched by MTN Cameroon in 2008. The PV array sizes evaluated for the 22 PVHS were found to be the range 2.4–10.8 kWp corresponding to daily energy demands in the range 7.31–31.79 kW h/d. The energy costs and breakeven grid distances determined were in the ranges 0.81–1.32 €/kW h and 10.75–32.00 km respectively.     

Power output variations of co-located offshore wind turbines and wave energy converters in California

The electric power generation of co-located offshore wind turbines and wave energy converters along the California coast is investigated. Meteorological wind and wave data from the National Buoy Data Center were used to estimate the hourly power output from offshore wind turbines and wave energy converters at the sites of the buoys. The data set from 12 buoys consists of over 1,000,000 h of simultaneous hourly mean wind and wave measurements. At the buoys, offshore wind farms would have capacity factors ranging from 30% to 50%, and wave farms would have capacity factors ranging from 22% to 29%. An analysis of the power output indicates that co-located offshore wind and wave energy farms generate less variable power output than a wind or wave farm operating alone. The reduction in variability results from the low temporal correlation of the resources and occurs on all time scales. Aggregate power from a co-located wind and wave farm achieves reductions in variability equivalent to aggregating power from two offshore wind farms approximately 500 km apart or two wave farms approximately 800 km apart. Combined wind and wave farms in California would have less than 100 h of no power output per year, compared to over 1000 h for offshore wind or over 200 h for wave farms alone. Ten offshore farms of wind, wave, or both modeled in the California power system would have capacity factors during the summer ranging from 21% (all wave) to 36% (all wind) with combined wind and wave farms between 21% and 36%. The capacity credits for these farms range from 16% to 24% with some combined wind and wave farms achieving capacity credits equal to or greater than a 100% wind farm because of their reduction in power output variability.     

Outlook for advanced biofuels

To assess which biofuels have the better potential for the short-term or the longer term (2030), and what developments are necessary to improve the performance of biofuels, the production of four promising biofuels—methanol, ethanol, hydrogen, and synthetic diesel—is systematically analysed. This present paper summarises, normalises and compares earlier reported work. First, the key technologies for the production of these fuels, such as gasification, gas processing, synthesis, hydrolysis, and fermentation, and their improvement options are studied and modelled. Then, the production facility's technological and economic performance is analysed, applying variations in technology and scale. Finally, likely biofuels chains (including distribution to cars, and end-use) are compared on an equal economic basis, such as costs per kilometre driven. Production costs of these fuels range 16–22 €/GJ_HHV now, down to 9–13 €/GJ_HHV in future (2030). This performance assumes both certain technological developments as well as the availability of biomass at 3 €/GJ_HHV. The feedstock costs strongly influence the resulting biofuel costs by 2–3 €/GJ_fuel for each €/GJ_HHV feedstock difference. In biomass producing regions such as Latin America or the former USSR, the four fuels could be produced at 7–11 €/GJ_HHV compared to diesel and gasoline costs of 7 and 8 €/GJ (excluding distribution, excise and VAT; at crude oil prices of ∼35 €/bbl or 5.7 €/GJ). The uncertainties in the biofuels production costs of the four selected biofuels are 15–30%. When applied in cars, biofuels have driving costs in ICEVs of about 0.18–0.24 €/km now (fuel excise duty and VAT excluded) and may be about 0.18 in future. The cars’ contribution to these costs is much larger than the fuels’ contribution. Large-scale gasification, thorough gas cleaning, and micro-biological processes for hydrolysis and fermentation are key major fields for RD&D efforts, next to consistent market development and larger scale deployment of those technologies.     

Environmental,technical and financial feasibility study of solar power plants by RETScreen,according to the targeting of energy subsidies in Iran

In this study, based on new electricity tariffs, three scenarios have been developed with The RETScreen International Photovoltaic Project Model, according to the targeting of energy subsidies in Iran. We have also dedicated one of our scenarios to the reduction of greenhouse gasses.In the first case the electricity price was set to 3.75 Cents/kWh (450 Rial/kWh) and no credit was assigned to the reduction of greenhouse gasses (GHG), therefore equity payback (Return positive cash flow) has been 12.1 year. In the second case the electricity price was set to 17.5 Cents/kWh, therefore equity payback (return positive cash flow) was 8 year. Finally in the last scenario by considering a credit to the reduction of greenhouse gasses and electricity price being 175 Cents/kWh and applying solar panels with high efficiency and suitable batteries (DOD = 60%), equity payback (return positive cash flow) reached within 6 years.     

A review on wind energy and wind–hydrogen production in Turkey: A case study of hydrogen production via electrolysis system supplied by wind energy conversion system in Central Anatolian Turkey

Studies about investigation of hydrogen production from wind energy and hydrogen production costs for a specific region were reviewed in this study and it was shown that these studies were rare in the world, especially in Turkey. Therefore, the costs of hydrogen, hydrogen production quantities using a wind energy conversion system were considered as a case study for 5 different locations of Nigde, Kirsehir, Develi, Sinop and Pinarbasi located in the Central Anatolia in Turkey. Annual wind energy productions and costs for different wind energy conversion systems were calculated for 50 m, 80 m and 100 m hub heights. According to wind energy costs calculations, the amounts and costs of hydrogen production were computed. Furthermore, three different scenarios were taken into account to produce much hydrogen. The results showed that the hydrogen production using a wind energy conversion system with 1300 kW rated power had a range from 1665.24 kgH₂/year in Nigde at 50 m hub height to 6288.59 kgH₂/year in Pinarbasi at 100 m hub height. Consequently, Pinarbasi and Sinop have remarkable wind potential and potential of hydrogen production using a wind–electrolyzer energy system.     

Wind energy resources in the Ionian Sea

The wind speed and direction as well as the availability, the duration and the diurnal variation of two offshore sites, Zakinthos and Pylos (BZK and BPY) in the Ionian Sea were assessed. For an analysis period of two years, the mean wind speed at 10 m was determined as 5.7 ± 0.1 m s^?1 and 5.8 ± 0.1 m s^?1 for the BZK and BPY sites, respectively. The wind speed variations over the hours of the day were quite small. The monthly variation in the average wind speeds was between 4.3 (May) and 7.5 m s^?1 (December) for the BZK site and 4.4 (August) and 7.3 m s^?1 (December) for the BPY site. Moreover, QuikSCAT satellite mean values for the grids of the two buoy regions were systematically overestimated in comparison to the buoy data with differences in the range from 8 to 13%. Statistical analysis revealed the high QuikSCAT data uncertainty for wind speeds less than 5 m s^?1 as the major factor of the observed mean value differences. The mean wind power densities were calculated with the buoy wind speed measurements and were found more than 250 W m^?2 at 10 m, suggesting the suitability of the sites for offshore wind energy applications. Capacity factors of up to 48% for energy production were calculated with the existing offshore turbines technology at a hub height of 100 m. Furthermore, the energy yield for different wind turbines and a service life of 20 years were determined from 6.5 to 8.7 and the energy pay-back periods from 2.8 to 2.1 years, respectively. The maximum avoided greenhouse emissions were 140 kt CO₂-e for an offshore turbine generator of 5 MW and a period of 20 years.     

An agro-economic analysis of willow cultivation in Poland

Bioenergy is recognized as the most important renewable energy source in Poland in several national policy documents. This has spurred an in increasing interest in energy crops, particularly willow, due to the large areas of arable land in Poland. However, in order for willow to be adopted by farmers, this crop must be perceived to be at least as profitable as cereal crops, such as wheat and barley, which compete for the same land. The objective of this study was to calculate the economics of growing willow on relatively large farms from a farmer's perspective in Poland. An additional objective was to relate the viability of growing willow to that of growing wheat and barley. Our calculations show that growing willow can indeed be an economically viable alternative to wheat and barley. At the current Polish price of wood chips (about 33 PLN/MWh or 7.5 €/MWh), the viability of willow is similar to that of barley given our assumptions on yields, etc. Wheat is the most viable crop of the three crops studied. Willow, however, is more profitable than both wheat and barley assuming a wood chip price of 50 PLN/MWh (11 €/MWh), which better represents the price in Europe as a whole. Despite good viability, willow is unlikely to be adopted by a great number of farmers without active support mechanisms and long-term stability of the status of energy crops in the Polish and the EU common agricultural policy.     

Ethanol from lignocellulosic biomass: techno-economic performance in short-, middle- and long-term

The state of the art of hydrolysis-fermentation technologies to produce ethanol from lignocellulosic biomass, as well as developing technologies, is evaluated. Promising conversion concepts for the short-, middle- and long-term are defined. Their technical performance was analysed, and results were used for economic evaluations. The current available technology, which is based on dilute acid hydrolysis, has about 35% efficiency (HHV) from biomass to ethanol. The overall efficiency, with electricity co-produced from the not fermentable lignin, is about 60%. Improvements in pre-treatment and advances in biotechnology, especially through process combinations can bring the ethanol efficiency to 48% and the overall process efficiency to 68%. We estimate current investment costs at 2.1 k€/kW_HHV (at 400 MW_HHV input, i.e. a nominal 2000 tonne dry/day input). A future technology in a 5 times larger plant (2 GW_HHV) could have investments of 900 k€/kW_HHV. A combined effect of higher hydrolysis-fermentation efficiency, lower specific capital investments, increase of scale and cheaper biomass feedstock costs (from 3 to 2 €/GJ_HHV), could bring the ethanol production costs from 22 €/GJ_HHV in the next 5 years, to 13 €/GJ over the 10–15 year time scale, and down to 8.7 €/GJ in 20 or more years.     

Consequences of a carbon tax on household electricity use and cost,carbon emissions,and economics of household solar and wind

The study was conducted to determine the consequences of a carbon tax, equal to an estimated social cost of carbon of $37.2/Mg, on household electricity cost, and to determine if a carbon tax would be sufficient to incentivize households to install either a grid-tied solar or wind system. U.S. Department of Energy hourly residential profiles for five locations, 20 years of hourly weather data, prevailing electricity pricing rate schedules, and purchase prices and solar panel and wind turbine power output response functions, were used to address the objectives. Two commercially available household solar panels (4 kW, 12 kW), two wind turbines (6 kW, 12 kW), and two price rate structures (traditional meter, smart meter) were considered. Averaged across the five households, the carbon tax is expected to reduce annual consumption by 4.4% (552 kWh/year) for traditional meter households and by 4.9% (611 kWh/year) for households charged smart meter rates. The carbon tax increases electricity cost by 19% ($202/year). For a household cost of $202/year the carbon tax is expected to reduce social costs by $11. Annual carbon tax collections of $234/household are expected. Adding the carbon tax was found to be insufficient to incentivize households to install either a solar panel or wind turbine system. Installation of a 4 kW solar system would increase the annual cost by $1546 (247%) and decrease CO₂ emissions by 38% (2526 kg) valued at $94/household. The consequence of a carbon tax would depend largely on how the proceeds of the tax are used.     

Realistic generation cost of solar photovoltaic electricity

Solar photovoltaic (SPV) power plants have long working life with zero fuel cost and negligible maintenance cost but requires huge initial investment. The generation cost of the solar electricity is mainly the cost of financing the initial investment. Therefore, the generation cost of solar electricity in different years depends on the method of returning the loan. Currently levelized cost based on equated payment loan is being used. The static levelized generation cost of solar electricity is compared with the current value of variable generation cost of grid electricity. This improper cost comparison is inhibiting the growth of SPV electricity by creating wrong perception that solar electricity is very expensive. In this paper a new method of loan repayment has been developed resulting in generation cost of SPV electricity that increases with time like that of grid electricity. A generalized capital recovery factor has been developed for graduated payment loan in which capital and interest payment in each installment are calculated by treating each loan installment as an independent loan for the relevant years. Generalized results have been calculated which can be used to determine the cost of SPV electricity for a given system at different places. Results show that for SPV system with specific initial investment of 5.00 $/kWh/year, loan period of 30 years and loan interest rate of 4% the levelized generation cost of SPV electricity with equated payment loan turns out to be 28.92 ¢/kWh, while the corresponding generation cost with graduated payment loan with escalation in annual installment of 8% varies from 9.51 ¢/kWh in base year to 88.63 ¢/kWh in 30th year. So, in this case, the realistic current generation cost of SPV electricity is 9.51 ¢/kWh and not 28.92 ¢/kWh. Further, with graduated payment loan, extension in loan period results in sharp decline in cost of SPV electricity in base year. Hence, a policy change is required regarding the loan repayment method. It is proposed that to arrive at realistic cost of SPV electricity long-term graduated payment loans may be given for installing SPV power plants such that the escalation in annual loan installments be equal to the estimated inflation in the price of grid electricity with loan period close to working life of SPV system.