Accelerating residential PV expansion: demand analysis for competitive electricity markets

This article quantifies the potential market for grid-connected, residential photovoltaic (PV) electricity integrated into new homes built in the US. It complements an earlier supply-side analysis by the authors that demonstrates the potential to reduce PV module prices below $1.5/W_p by scaling up existing thin-film technology in 100 MW_p/yr manufacturing facilities. The present article demonstrates that, at that price, PV modules may be cost effective in 125,000 new home installations per year (0.5 GW_p/yr). While this market is large enough to support multiple scaled up thin-film PV factories, inefficient energy pricing and demand-side market failures will inhibit prospective PV consumers without strong public policy support. Net metering rules, already implemented in many states to encourage PV market launch, represent a crude but reasonable surrogate for efficient electricity pricing mechanisms that may ultimately emerge to internalize the externality benefits of PV. These public benefits include reduced air pollution damages (estimated costs of damage to human health from fossil fuel power plants are presented in Appendix A), deferral of transmission and distribution capital expenditures, reduced exposure to fossil fuel price risks, and increased electricity system reliability for end users. Thus, net metering for PV ought to be implemented as broadly as possible and sustained until efficient pricing is in place. Complementary PV “buydowns” (e.g., a renewable portfolio standard with a specific PV requirement) are needed to jumpstart regional PV markets.     

The feasibility of renewable energies at an off-grid community in Canada

Three renewable energy technologies (RETs) were analyzed for their feasibility for a small off-grid research facility dependent on diesel for power and propane for heat. Presently, the electrical load for this facility is 115 kW but a demand side management (DSM) energy audit revealed that 15–20% reduction was possible. Downsizing RETs and diesel engines by 15 kW to 100 kW reduces capital costs by $27 000 for biomass, $49 500 for wind and $136 500 for solar.The RET Screen International 4.0^® model compared the economical and environmental costs of generating 100 kW of electricity for three RETs compared to the current diesel engine (0 cost) and a replacement ($160/kW) diesel equipment. At all costs from $0.80 to $2.00/l, biomass combined heat and power (CHP) was the most competitive. At $0.80 per liter, biomass’ payback period was 4.1 years with a capital cost of $1800/kW compared to wind's 6.1 years due to its higher initial cost of $3300/kW and solar's 13.5 years due to its high initial cost of $9100/kW. A biomass system would reduce annual energy costs by $63 729 per year, and mitigate GHG emissions by over 98% to 10 t CO₂ from 507 t CO₂. Diesel price increases to $1.20 or $2.00/l will decrease the payback period in years dramatically to 1.8 and 0.9 for CHP, 3.6 and 1.8 for wind, and 6.7 and 3.2 years for solar, respectively.     

The cost estimate for a novel cheap solar cell

The estimate for the lowest cost of SODL (silicon on defect layer) solar cell is made according to the price standard of present market. The estimate shows that the PV (photovoltaics) energy costs can be reduced from today's 25–30 cents/(kW h) to 7–8 cents/(kW h) which is comparable with the present cost of electricity generated by traditional energy sources such as fossil and petroleum fuels. The PV energy costs could be reduced to a value lower than 7–8 cents/(kW h) by developing SODL technology. The SODL solar cell manufacture featuring simple processes is suitable to large scale automated assembly lines with high yield of large area cells. Some new ideas are suggested, favoring the further reduction in the cost of commercial solar cells.     

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.     

Thin film PV manufacturing: Materials costs and their optimization

Thin film PV technologies face a number of hurdles as they advance towards low-cost goals that would make them competitive with traditional sources of electricity. The US Department of Energy cost goal for thin films is about $0.33/W_p, which corresponds to module efficiencies of about 15% and module manufacturing costs of about $50/m². Past papers have provided a framework for examining thin film efficiencies and manufacturing costs, especially those costs for equipment, labor, materials, utilities, and others. Although materials costs appear to be a large fraction of the total, we have not yet broken them down in enough detail to seek significant improvement. In the future, with more mature thin film production, materials costs such as those from semiconductor layers, contacts, pottants, substrates, and electrical interconnection will dominate total module cost. This paper (1) breaks down the materials costs into two broad categories (active and inactive materials) and then (2) investigates the issues associated with reducing their costs much below today's levels. Materials will likely be such an overwhelming cost-driver for mature manufacturing of thin film PV that issues associated with their optimization should be examined as soon as possible in order to meet the DOE long-term goals for PV module costs.     

Techno-economic assessment of a synthetic fuel production facility by hydrogenation of CO2 captured from biogas

In this study, a thermodynamic and economic analysis of a synthetic fuel production facility by utilizing the hydrogenation of CO₂ captured from biogas is carried out. It is aimed to produce methanol, a synthetic fuel by hydrogenation of carbon dioxide. A PEM electrolyzer driven by grid-tie solar PV modules is used to supply the hydrogen need of methanol. The CO₂ is captured from biogas produced in an actual wastewater treatment plant by a water washing unit which is a method of biogas purification. The required power which is generated by PV panels, in order to produce methanol, is found to be 2923 kW. Herein, the electricity consumption of 2875 kW, which is the main part of the total electricity generation, belongs to the PEM system. As a result of the study, the daily methanol production is found to be as 1674 kg. The electricity, hydrogen and methanol production costs are found to be $ 0.043 kWh^?1, $ 3.156 kg^?1, and $ 0.693 kg^?1, respectively. Solar availability, methanol yield from the reactor, and PEM overpotentials are significant factors effecting the product cost. The results of the study presents feasible methanol production costs with reasonable investment requirements. Moreover, the efficiency of the cogeneration plant could be increased via enriching the biogas while emissions are reduced.     

The long-term life cycle private and external costs of high coal usage in the US

Using four times as much coal in 2050 for electricity production need not degrade air quality or increase greenhouse gas emissions. Current SO_x and NO_x emissions from the power sector could be reduced from 12 to less than 1 and from 5 to 2 million tons annually, respectively, using advanced technology. While direct CO₂ emissions from new power plants could be reduced by over 87%, life cycle emissions could increase by over 25% due to the additional coal that is required to be mined and transported to compensate for the energy penalty of the carbon capture and storage technology. Strict environmental controls push capital costs of pulverized coal (PC) and integrated coal gasification combined cycle (IGCC) plants to $1500–1700/kW and $1600–2000/kW, respectively. Adding carbon capture and storage (CCS) increases costs to $2400–2700/kW and $2100–3000/kW (2005 dollars), respectively. Adding CCS reduces the 40–43% efficiency of the ultra-supercritical PC plant to 31–34%; adding CCS reduces the 32–38% efficiency of the GE IGCC plant to 27–33%. For IGCC, PC, and natural gas combined cycle (NGCC) plants, the carbon dioxide tax would have to be $53, $74, and $61, respectively, to make electricity from a plant with CCS cheaper. Capturing and storing 90% of the CO₂ emissions increases life cycle costs from 5.4 to 11.6 cents/kWh. This analysis shows that 90% CCS removal efficiency, although being a large improvement over current electricity generation emissions, results in life cycle emissions that are large enough that additional effort is required to achieve significant economy-wide reductions in the US for this large increase in electricity generation using either coal or natural gas.     

Seamless electricity trade between Canada and US Northeast

We analyze how the wholesale electricity market deregulation could modify exchanges between three Canadian regions (Ontario, Quebec and New Brunswick) and two US regions (New York and New England), on the base of their loads and available resources when the regulatory change took place in 1997. We find that the pre-1997 exchanges already made possible fuel cost savings of $397.2 million per year while deregulation adds annual savings of $358.7 million. Canadian regions are the main beneficiaries under the assumption that exports are priced at the marginal costs of the importing regions. Imports from the Canadian regions, although significant, are not large enough to lower the marginal costs of the US regions. Hence electricity deregulation across the border should not significantly decrease prices in the US regions although the latter are becoming more dependent upon imports from Canada. Greenhouse gas emissions increase by 4.3 Mt CO₂ eq. in the wake of the open wholesale electricity market because of the low cost of coal, particularly in Ontario. Environmental concerns and the limited availability of additional hydroelectric power in Canada could change the trade patterns as electricity demand continue to grow.     

电力市场下光伏上网定价模型研究

针对电力市场环境下现行的光伏固定上网统一电价忽略了电力系统为应对其出力波动性而增加的热备用容量成本的问题,为了合理体现光伏发电的真实价值,提出光伏竞价上网的电价模型,根据历史数据进行未来日的出力预测并参与竞价,而采用该竞价模型所产生的部分费用反补给常规发电机组,可减少购电总成本。进而基于果蝇优化算法,运用Matlab软件对一个仅包含2个常规发电机组和1座光伏电站的电力系统进行优化求解与仿真,数值结果验证了本文模型的正确性和有效性。     

The cost of transmission for wind energy in the United States: A review of transmission planning studies

Rapid development of wind capacity in the United States has been coupled with a concern that increasing wind capacity will require substantial transmission infrastructure. This report summarizes the implied transmission cost per kW of wind from a sample of 40 transmission studies. This sample of studies, completed from 2001 to 2008, covers a broad geographic area across the U.S. The primary goal in the review is to develop a better understanding of the transmission costs needed to access increasing quantities of wind generation. A secondary goal is to gain a better appreciation of the differences in transmission planning approaches, in order to identify those methodologies that seem most able to estimate the incremental transmission costs associated with wind development. The total range in transmission costs per kW of wind implicit in the study sample is vast - ranging from $0/kW to over $1500/kW. The median cost of transmission from all scenarios in the sample is $300/kW, roughly 15-20% of the cost of building a wind project. The median cost of transmission is near the upper end of the range implied by two higher-level assessments of transmission required to provide 20% wind electricity in the U.S. by 2030.     

Off-grid hybrid renewable energy system with hydrogen storage for South African rural community health clinic

Most inhabitants of rural communities in Africa lack access to clean and reliable electricity. This has deprived the rural dwellers access to modern healthcare delivery. In this paper, an off-grid renewable energy system consisting of solar PV and wind turbine with hydrogen storage scheme has been explored to meet the electrical energy demands of a health clinic. The health clinic proposed is a group II with 10 beds located in a typical village in South Africa. First, the wind and solar energy resources of the village were analysed. Thereafter, the microgrid architecture that would meet the energy demand of the clinic (18.67 kWh/day) was determined. Some of the key results reveal that the average annual wind speed at 60 m anemometer height and solar irradiation of the village are 7.9 m/s and 4.779 kWh/m²/day, respectively. The required architecture for the clinic composes of 40 kW solar PV system, 3 numbers of 10 kW wind turbines, 8.6 kW fuel cell, 25 kW electrolyser and 40 kg hydrogen tank capacity. The capital cost of the microgrid was found to be $177,600 with a net present cost of $206,323. The levelised cost of energy of the system was determined to be 2.34 $/kWh. The project has a breakeven grid extension distance of 8.81 km. Since this distance is less than the nearest grid extension distance of 21.35 km, it is established that the proposed renewable energy microgrid with a hydrogen storage system is a viable option for the rural community health clinic.     

Lower electricity prices and greenhouse gas emissions due to rooftop solar: empirical results for Massachusetts

Monthly and hourly correlations among photovoltaic (PV) capacity utilization, electricity prices, electricity consumption, and the thermal efficiency of power plants in Massachusetts reduce electricity prices and carbon emissions beyond average calculations. PV utilization rates are highest when the thermal efficiencies of natural gas fired power plants are lowest, which reduces emissions of CO₂ and CH₄ by 0.3% relative to the annual average emission rate. There is a positive correlation between PV utilization rates and electricity prices, which raises the implied price of PV electricity by up to 10% relative to the annual average price, such that the average MWh reduces electricity prices by $0.26–$1.86 per MWh. These price reductions save Massachusetts rate-payers $184 million between 2010 and 2012. The current and net present values of these savings are greater than the cost of solar renewable energy credits which is the policy instrument that is used to accelerate the installation of PV capacity. Together, these results suggest that rooftop PV is an economically viable source of power in Massachusetts even though it has not reached socket parity.     

Economic evaluation of a stand-alone residential photovoltaic power system in Bangladesh

The economics of stand-alone photovoltaic power system is studied to test its feasibility in remote and rural areas of Bangladesh and to compare renewable generators with non-renewable generators. The life cycle cost of these generators are determined using the method of net present value analysis. It is found that the life cycle cost of this experimental PV system is Tk. 43.40/kWh for one family (US $1.00 = Bangladeshi taka Tk.50.00). The life cycle cost for grid electricity is Tk. 20.00/kWh and Tk. 7.75/kWh for generation of fuel costs of Tk. 6.80/kWh and Tk. 0.47/kWh respectively. For a village 1 km away from the distribution line, this cost becomes Tk. 125.00/kWh for a family. For petrol generator life cycle cost is Tk. 50.00/kWh at fuel price of Tk. 22.00 per litre. For diesel generator life cycle cost is found to be Tk. 46.10/kWh at fuel cost of Tk. 15.00 per litre. It is observed that the life cycle cost of one unit of energy from grids that are 1 km away from a village is much higher than the cost of energy from a PV system. Thus, the use of PV system is economically feasible in rural villages and remote areas of Bangladesh, where grid electricity is not available.     

Study of a solar PV–diesel–battery hybrid power system for a remotely located population near Rafha, Saudi Arabia

This study presents a PV–diesel hybrid power system with battery backup for a village being fed with diesel generated electricity to displace part of the diesel by solar. The hourly solar radiation data measured at the site along with PV modules mounted on fixed foundations, four generators of different rated powers, diesel prices of 0.2–1.2US$/l, different sizes of batteries and converters were used to find an optimal power system for the village. It was found that a PV array of 2000 kW and four generators of 1250, 750, 2250 and 250 kW; operating at a load factor of 70% required to run for 3317 h/yr, 4242 h/yr, 2820 h/yr and 3150 h/yr, respectively; to produce a mix of 17,640 MWh of electricity annually and 48.33 MWh per day. The cost of energy (COE) of diesel only and PV/diesel/battery power system with 21% solar penetration was found to be 0.190$/kWh and 0.219$/kWh respectively for a diesel price of 0.2$/l. The sensitivity analysis showed that at a diesel price of 0.6$/l the COE from hybrid system become almost the same as that of the diesel only system and above it, the hybrid system become more economical than the diesel only system.     

Techno-economic study of off-grid hybrid photovoltaic/battery and photovoltaic/battery/fuel cell power systems in Kunming,China

The objective of this study is to evaluate the technical and economic feasibility of stand-alone hybrid photovoltaic (PV)/battery and PV/battery/fuel cell (FC) power systems for a community center comprising 100 households in Kunming by using the Hybrid Optimization Model for Electric Renewable (HOMER) software. HOMER is used to define the optimum sizing and techno-economic feasibility of the system equipment based on the geographical and meteorological data of the study region. In this study, different hybrid power systems are analyzed to select the optimum energy system while considering total net present cost (NPC) and levelized cost of energy (COE). The results showed that the optimal hybrid PV/battery system comprised 500 kW PV modules, 1200 7.6-kWh battery units, and 500 kW power converters. The proposed system has an initial cost of $6,670,000, an annual operating cost of $82,763/yr, a total NPC of $7,727,992, and a levelized COE of $1.536/kWh. While the PV/battery/FC power system is possible, the cost increases were due to the investment cost of the FC system. The optimal PV/battery/FC system has an initial cost of $6,763,000, an annual operating cost of $82,312/yr, a total NPC of $7,815,223, and a levelized COE of $1.553/kWh.     

Review of research on autonomous wind farms and solar parks and their feasibility for commercial loads in hot regions

In the wake of rising cost of oil and fears of its exhaustion coupled with increased pollution, the governments world-wide are deliberating and making huge strides to promote renewable energy sources such as solar–photovoltaic (solar–PV) and wind energy. Integration of diesel systems with hybrid wind–PV systems is pursued widely to reduce dependence on fossil-fuel produced energy and to reduce the release of carbon gases that cause global climate change. Literature indicates that commercial/residential buildings in the Kingdom of Saudi Arabia (KSA) consume an estimated 10–40% of the total electric energy generated. The study reviews research work carried out world-wide on wind farms and solar parks. The work also analyzes wind speed and solar radiation data of East-Coast (Dhahran), KSA, to assess the technical and economic potential of wind farm and solar PV park (hybrid wind–PV–diesel power systems) to meet the load requirements of a typical commercial building (with annual electrical energy demand of 620,000 kWh). The monthly average wind speeds range from 3.3 to 5.6 m/s. The monthly average daily solar global radiation ranges from 3.61 to 7.96 kWh/m². The hybrid systems simulated consist of different combinations of 100 kW wind machines, PV panels, supplemented by diesel generators. NREL (and HOMER Energy's) HOMER software has been used to perform the techno-economic study. The simulation results indicate that for a hybrid system comprising of 100 kW wind capacity (37 m hub-height) and 40 kW of PV capacity together with 175 kW diesel system, the renewable energy fraction (with 0% annual capacity shortage) is 36% (24% wind + 12% PV). The cost of generating energy (COE, $/kWh) from this hybrid wind–PV–diesel system has been found to be 0.154 $/kWh (assuming diesel fuel price of 0.1$/L). The study exhibits that for a given hybrid configuration, the number of operational hours of diesel generators decreases with increase in wind farm and PV capacity. Attention has also been focused on wind/PV penetration, un-met load, excess electricity generation, percentage fuel savings and reduction in carbon emissions (relative to diesel-only situation) of different hybrid systems, cost break-down of wind–PV–diesel systems, COE of different hybrid systems, etc.     

Should we drill in the Arctic National Wildlife Refuge? An economic perspective

This paper provides model-based estimates of the value of oil in Alaska's Arctic National Wildlife Refuge (ANWR). The best estimate of economically recoverable oil in the federal portion of ANWR is 7.06 billion barrels of oil, a quantity roughly equal to US consumption in 2005. The oil is worth $374 billion ($2005), but would cost $123 billion to extract and bring to market. The difference, $251 billion, would generate social benefits through industry rents of $90 billion as well as state and federal tax revenues of $37 billion and $124 billion, respectively. A contribution of the paper is the decomposition of the benefits between industry rents and tax revenue for a range of price and quantity scenarios. But drilling and development in ANWR would also bring about environmental costs. These costs would consist largely of lost nonuse values for the protected status of ANWR's natural environment. Rather than estimate these costs and conduct a benefit–cost analysis, we calculate the costs that would generate a breakeven result. We find that the average breakeven willingness to accept compensation to allow drilling in ANWR ranges from $582 to $1782 per person, with a mean estimate of $1141.     

Cost estimates for nuclear power in the UK

Current UK Government support for nuclear power has in part been informed by cost estimates that suggest that electricity from new nuclear power stations will be competitive with alternative low carbon generation options. The evidence and analysis presented in this paper suggests that the capital cost estimates for nuclear power that are being used to inform these projections rely on costs escalating over the pre-construction and construction phase of the new build programme at a level significantly below those that have been experienced by past US and European programmes. This paper applies observed construction time and cost escalation rates to the published estimates of capital costs for new nuclear plant in the UK and calculates the potential impact on levelised cost per unit of electricity produced. The results suggest that levelised cost may turn out to be significantly higher than expected which in turn has important implications for policy, both in general terms of the potential costs to consumers and more specifically for negotiations around the level of policy support and contractual arrangements offered to individual projects through the proposed contract for difference strike price.     

The economic costs of reducing greenhouse gas emissions under a U.S. national renewable electricity mandate

The electricity sector is the largest source of greenhouse gas emissions (GHGs) in the U.S. Many states have passed and Congress has considered Renewable Portfolio Standards (RPS), mandates that specific percentages of electricity be generated from renewable resources. We perform a technical and economic assessment and estimate the economic costs and net GHG reductions from a national 25 percent RPS by 2025 relative to coal-based electricity. This policy would reduce GHG emissions by about 670 million metric tons per year, 11 percent of 2008 U.S. emissions. The first 100 million metric tons could be abated for less than $36/metric ton. However, marginal costs climb to $50 for 300 million metric tons and to as much as $70/metric ton to fulfill the RPS. The total economic costs of such a policy are about $35 billion annually. We also examine the cost sensitivity to favorable and unfavorable technology development assumptions. We find that a 25 percent RPS would likely be an economically efficient method for utilities to substantially reduce GHG emissions only under the favorable scenario. These estimates can be compared with other approaches, including increased R&D funding for renewables or deployment of efficiency and/or other low-carbon generation technologies.     

SOCIO-ECONOMIC ASPECTS OF THE AUSTRIAN 200 kWp-PHOTOVOLTAIC-ROOFTOP PROGRAMME

Between 1992 and 1994 a 200 kWp-rooftop programme to promote small grid-connected Photovoltaic (PV) systems was conducted in Austria. Within this programme about 100 PV systems with an average capacity of 2.28 kWp were installed. This paper investigates the socio-economic aspects of this programme and the prospects for a further dissemination of this technology. The major conclusions of this investigation are as follows: (1) The motives to invest in a PV system are: (i) environmental protection; (ii) an alternative to nuclear power; (iii) technical interest. Yet, it is also important that the public supports this purchase by means providing subsidies. (2) The purchase of a PV system leads to different changes in consumer behaviour. Consumers with low initial consumption increased their electricity demand slightly, while the majority of consumers with high initial electricity demand saved electricity. (3) The financial incentives in the programme were not optimally designed. With the same amount of total subsidies it would have been possible to promote more PV systems. (4) The key factors for a further dissemination of PV systems are: (i) financial incentives; (ii) a reduction of the investment costs; (iii) increase in reliability; (iv) distribution of information; (v) enhancement of environmental awareness.