A spatial equilibrium model of the world coal market is developed that accounts for coal to natural gas switching in the electricity sector in the United States and Europe, the potential for China to exercise monoposony power in its coal purchasing behavior, and the impact of increasing the western US coal export port capacity. The global coal market equilibrium is computed as the solution to a nonlinear complementarity problem. Where possible parameters of the model are estimated econometrically. Where this is not possible the parameters are calibrated to global coal market outcomes in 2011. The model is used to assess how the shale gas boom in the United States impacts global coal market outcomes for dierent models of Chinese coal buyers' purchasing behavior and dierent scenarios for the capacity of coal export terminals on the US west coast.  Although reductions in US and European natural gas prices reduce coal consumption in the US and Europe, the percentage reduction in coal consumption in Europe is much less than that in the US. Increasing US west coast port capacity increases coal exports from the western US and reduces Chinese coal production. US coal prices increase which causes more coal to natural gas switching in the US, further reducing global greenhouse gas emissions. Modeling China as a monopsony buyer of coal reduces the absolute magnitude of these impacts.

The variability of solar and wind generation increases transmission network operating costs associated with maintaining system stability. These ancillary services costs are likely to increase as a share of total energy costs in regions with ambitious renewable energy targets. We examine how ecient deployment of intermittent renewable generation capacity across locations depends on the costs of balancing real-time system demand and supply. We then show how locational marginal network taris can be designed to implement the ecient outcome for intermittent renewable generation unit location decisions. We demonstrate the practical applicability of this approach by applying our theory to obtain quantitative results for the California electricity market.

Electricity tariff reforms will be an essential part of the clean energy transition. Existing tariffs rely on average cost pricing and often set a price per unit that exceeds marginal cost. The higher price encourages over-adoption of residential solar panels and under-adoption of electric alternatives to fossil fuels. However, an efficient tariff based on fixed charges and marginal cost pricing may harm low-income households. We propose an alternative methodology for setting fixed charges based on the predicted willingness-to-pay of each household. Using household data from Colombia, we show the fiscal burden and economic inefficiency of the existing tariffs. We then show how our new tariff methodology could improve economic efficiency and create incentives for the adoption of clean energy technologies, while still leaving low-income households better off.

We investigate the relationship between accumulated experience completing wind power projects and the cost of installing wind projects in the U.S. from 2001-2015. Our modeling framework disentangles accumulated experience from input price changes, scale economies, and exogenous technical change; and accounts for both firm-specific and industry-wide accumulated experience. We find evidence consistent with cost-reducing benefits from firm-specific experience for that firm’s cost of future wind power projects, but no evidence of industry-wide learning from the experience of other participants in the industry. Further, our experience measure rapidly depreciates across time and distance, suggesting a stable industry trajectory would lower project costs.

This paper identifies the key features of successful electricity market designs that are particularly relevant to the experience of low-income countries. Important features include: (1) the match between the short-term market used to dispatch generation units and the physical operation of the electricity network, (2) effective regulatory and market mechanisms to ensure long-term generation resource adequacy, (3) appropriate mechanisms to mitigate local market power, and (4) mechanisms to allow the active involvement of final demand in a short-term market. The paper provides a recommended baseline market design that reflects the experience of the past 25 years
with electricity restructuring processes. It then suggests a simplified version of this market design ideally suited to the proposed East and Western Sub-Sahara Africa regional wholesale market that is likely to realise a substantial amount of the economic benefits from forming a regional market with minimal implementation cost and regulatory burden. Recommendations are also provided for modifying the Southern African Power Pool to increase the economic benefits realised from its formation. How this market design supports the cost-effective integration of renewables is discussed and future enhancements are proposed that support the integration of a greater share
of intermittent renewables. The paper closes with proposed directions for future research in the area of electricity market design in developing countries.

Significant political barriers to implementing na- tional climate policies exist in both the US and China. Successful linkage of regional climate policies in the two countries can help overcome these impediments. Each country can be seen as willing to cooperate with the other to address the global climate challenge, which can help each national government overcome the resistance to formulating its own national climate policy.

Solving the climate challenge involves many years of sustained actions coordinated across the major emitting countries. Like any long journey, it begins with︎ a first step. Coordinating regional policies is such a step.

Californians like to think of themselves as environmentally conscious and forward-thinking. The state’s energy and environmental policies reflect these sentiments. With the passage of SB 100, California has one of the nation’s most ambitious renewable energy goals for its electricity supply industry. The California Solar Initiative rebate program has led to more rooftop solar capacity in the state than the total rooftop solar capacity installed in the next eight highest-capacity states. AB32 established California as the only state with its own cap-and-trade market for greenhouse gas emissions. This market currently sets the nation’s highest price for a ton of greenhouse gas emissions. California recently set a goal of five million electric vehicles in the state by 2030. Under AB 2514, California’s three investor-owned utilities are required to purchase 1,325 megawatts of grid-scale storage capacity and AB 2868 requires them to purchase 500 megawatts of behind-the-meter storage capacity. All of these policies have made California a global leader in the transition to a less carbon-intensive energy sector.

There is one major downside to California’s energy and environmental policies: they are extremely expensive for California consumers. Average residential electricity prices in California are among the highest in the nation—not because it is so expensive to produce electricity in the state, but because the costs of these policies are recovered from retail electricity prices. A comparison to Texas, another large state that also uses natural gas to power most of its electricity generation fleet, illustrates this point. According to the US Energy Information Administration (US-EIA), average residential electricity prices in California are currently about 20 cents per kilowatt-hour (kWh) versus 10 cents per kWh in Texas. However, average wholesale electricity prices in the two states are roughly equal.

This difference in retail prices is primarily due to different policy responses in the two states to the shale gas boom that started in the mid-2000s and ultimately led to a roughly 66 percent decline in the wholesale price of natural gas. California responded to these low natural gas prices with spending on the policies described above and no reductions in retail electricity prices, despite average wholesale electricity prices in California falling by one-half to two-thirds relative to their pre-shale gas boom levels. Texas responded to this decline in natural gas prices by implementing vigorous retail competition for all classes of customers, which passed on the resulting lower wholesale electricity prices into lower retail electricity prices.

What is more surprising about the Texas-versus-California comparison is that over this same time period Texas managed to build more zero-carbon wind and solar generation capacity than California. Texas currently has more than 22,000 megawatts (MWs) of grid-scale wind and solar capacity versus about 17,000 MWs in California. Different from California, Texas has accomplished this massive renewable generation buildout which also produces more renewable energy on an annual basis than California with no state-mandated financial support mechanisms beyond its competitive renewable energy zone (CREZ) policy that proactively expanded the state’s transmission network to regions with significant renewable resources. Texas’s market-based approach to fostering renewable generation entry has led to more capacity at significantly lower cost relative to California’s legislatively mandated and consumer-financed approach.

Because Californians are likely to want to continue to lead the energy transition, the relevant policy design question is: How can the state achieve these low-carbon energy goals in a more cost- effective manner?