Integrated Solar Combined Cycle Power Plants (ISCCs), composed of a Concentrated Solar Power (CSP) plant and a Natural Gas-fired Combined Cycle (NGCC) power plant, have been recently introduced in the power generation sector as a technology with the potential to simultaneously reduce fossil fuel usage and the integration costs of solar power. This study quantifies the economic benefits of an ISCC power plant relative to a stand-alone CSP with energy storage, and a NGCC plant. A combination of tools is used to estimate the levelized cost of electricity (LCOE) and the cost of carbon abatement (CoA) for CSP, NGCC and ISCC technologies under different natural gas prices, and at several locations experiencing different ambient temperatures and solar resources. Results show that an ISCC with up to 10-15% of nameplate capacity from solar energy can be cost effective as a dispatchable electricity generation resource.Integrating the CSP into an ISCC reduces the LCOE of solar-generated electricity by 35-40% relative to a stand-alone CSP plant, and provides the additional benefit of dispatchability. An ISCC also outperforms a CSP with energy storage in terms of LCOE and CoA. The current LCOE of an ISCC is lower than that of a stand-alone NGCC when fuel price reaches 13.5 $/MMBtu, while its CoA is lower at a fuel price of 8.5 $/MMBtu.Although, under low to moderate natural gas price conditions an NGCC generates electricity and abates carbon emissions at a lower cost than an ISCC; small changes in v the capacity factor of an ISCC relative to the NGCC, or capital cost reductions for the CSP component have great impact tilting the balance in the ISCC's favor.

This paper presents a first-order analysis of the feasibility and technical, environmental, and economic effects of large levels of solar photovoltaic (PV) penetration within the services areas of the Duke Energy Carolinas (DEC) and Duke Energy Progress (DEP). A PV production model based on household density and a gridded hourly global horizontal irradiance data set simulates hourly PV power output from roof-top installations, while a unit commitment and real-time economic dispatch (UC-ED) model simulates hourly system operations. We find that the large generating capacity of base-load nuclear power plants (NPPs) without ramping capability in the region limits PV integration levels to 5.3% (6510 MW) of 2015 generation. Enabling ramping capability for NPPs would raise the limit of PV penetration to near 9% of electricity generated. If the planned retirement of coal-fired power plants together with new installations and upgrades of natural gas and nuclear plants materialize in 2025, and if NPPs operate flexibly, then the share of coal-fired electricity will be reduced from 37% to 22%. A 9% penetration of electricity from PV would further reduce the share of coal-fired electricity by 4-6% resulting in a system-wide CO2 emissions rate of 0.33 to 0.40 tons/MWh and associated abatement costs of 225-415 (2015$ per ton).

The policy decision of extending electric power transmission lines to connect a remote area to a primary grid vs. developing local electricity generation resources must be informed by studies considering both alternatives’ economic and environmental outcomes. Such analysis must also consider the uncertainty of several factors such as fuel prices, the cost and performance of renewable and conventional power generation technologies, and the value of environmental benefits. This paper presents a method for this analysis, making two main contributions to the literature. First, it shows how to characterize the two alternatives (i.e., main-grid extension vs. local power generation) in detail for precise quantification of their capital and operating costs while guaranteeing that they are both adequate to meet forecast demand and operating reserves. Second, it shows how to properly account for the economic and environmental implications of renewable energy intermittency and uncertainty through the optimization of capital investments and hourly operations. The method is illustrated by applying this analysis method to Saudi Arabia, where the government is struggling to outline a strategy to meet residential and commercial loads reliably and sustainably in the country’s remote, scattered, isolated areas. To meet this demand, the Saudi government is considering two main alternatives: (1) extending the primary power transmission grid; or (2) installing an optimal combination of off-grid distributed generation (DG) resources, including solar PV, wind, diesel, oil, heavy fuel oil, and Li-ion batteries, to generate the electricity locally. Results suggest that under most scenarios of capital costs, fuel prices, and costs of air pollution, developing a microgrid with a large share of wind and solar power is more cost-effective than extending a primary grid 150 km or more away. Extending a primary grid powered by gas-fired combined-cycle power plants is more economical only if the load is not very high, the distance is not more than 350 km, and oil prices are relatively high compared to natural gas.

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This paper estimates the maximum integration level of residential rooftop solar photovoltaic (PV) capacity within the power network of the Duke Energy Progress (DEP) and Duke Energy Carolinas (DEC) under two scenarios embodying different assumptions about the flexibility of nuclear power plant (NPP) operations. A mixed-integer optimization model was constructed and simulated to find out the maximum solar penetration level under each scenario and to calculate the expected total system’s electricity generation costs, energy mix, atmospheric emission reductions, and emission abatement costs. Analysis reveals that improving NPP operation maneuverability would increase the maximum solar PV penetration level in the DEP and DEC power networks by 39%, from 8.9% to 12.4% of the total system’s electricity generation. Consequently, it would further improve the electricity generations’ unit costs and CO2 emission reductions by 3% and 8% points, respectively. On the other hand, increasing the solar PV penetration limit under high flexible NPP operation scenario leads to increase in the CO2 emission abatement costs by 8% points. The results of the study indicate that the flexibility of existing power system resources may present a barrier for a large uptake of solar energy.

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