Stop arguing and cut emissions.

The expert and policy communities have invested enormous effort in debating what greenhouse gas (GHG) emissions target to aim for, or which decarbonization policies and technologies should be mandated or banned. Because multiple trajectories can achieve similar targets and timelines, some scenario analysis is useful. However, with many players involved, it will be impossible to remain on anyone's optimal trajectory. As one of the world's largest contributors to the climate crisis, the US should stop arguing about perfect solutions and get on with reducing emissions in ways that are feasible and affordable.

Greenhouse Gas Estimates of LNG Exports Must Include Global Market Effects.

We conduct a consequential lifecycle analysis (LCA) of greenhouse gas (GHG) emissions from North American liquefied natural gas (LNG) export projects, estimating the change in global natural gas and coal use resulting from the market effects of increased LNG trade. We estimate that building a 2.1 billion cubic feet per day (Bcfd) LNG export facility, equivalent to one of the larger LNG projects under development in the US today, will change global GHG emissions -39 to 11 Mt CO2e (90% range) with a median value of -8 Mt CO2e. Previous attributional LCA methods for electricity generation with LNG replacing coal find a much larger benefit of LNG exports, a median value of -36 Mt CO2e for this size project. The smaller decrease in GHGs is attributable to higher domestic coal use and a smaller decrease in international coal use than assumed by previous methods. Net global emission change estimates are most sensitive to the uncertainty in economic elasticities outside of North America. Given the scale of planned and proposed LNG export terminals, project regulators and policymakers must account for market effects to more accurately estimate the global net change in GHG emissions.

A Solar-Centric Approach to Improving Estimates of Exposure Processes for Coronal Mass Ejections.

We present a solar-centric approach to estimating the probability of extreme coronal mass ejections (CME) using the Solar and Heliospheric Observatory (SOHO)/Large Angle and Spectrometric Coronagraph Experiment (LASCO) CME Catalog observations updated through May 2018 and an updated list of near-Earth interplanetary coronal mass ejections (ICME). We examine robust statistical approaches to the estimation of extreme events. We then assume a variety of time-independent distributions fitting, and then comparing, the different probability distributions to the relevant regions of the cumulative distributions of the observed CME speeds. Using these results, we then obtain the probability that the velocity of a CME exceeds a particular threshold by extrapolation. We conclude that about 1.72% of the CMEs recorded with SOHO LASCO arrive at the Earth over the time both data sets overlap (November 1996 to September 2017). Then, assuming that 1.72% of all CMEs pass the Earth, we can obtain a first-order estimate of the probability of an extreme space weather event on Earth. To estimate the probability over the next decade of a CME, we fit a Poisson distribution to the complementary cumulative distribution function. We inferred a decadal probability of between 0.01 and 0.09 for an event of at least the size of the large 2012 event, and a probability between 0.0002 and 0.016 for the size of the 1859 Carrington event.

Empirical prediction intervals improve energy forecasting.

Hundreds of organizations and analysts use energy projections, such as those contained in the US Energy Information Administration (EIA)'s Annual Energy Outlook (AEO), for investment and policy decisions. Retrospective analyses of past AEO projections have shown that observed values can differ from the projection by several hundred percent, and thus a thorough treatment of uncertainty is essential. We evaluate the out-of-sample forecasting performance of several empirical density forecasting methods, using the continuous ranked probability score (CRPS). The analysis confirms that a Gaussian density, estimated on past forecasting errors, gives comparatively accurate uncertainty estimates over a variety of energy quantities in the AEO, in particular outperforming scenario projections provided in the AEO. We report probabilistic uncertainties for 18 core quantities of the AEO 2016 projections. Our work frames how to produce, evaluate, and rank probabilistic forecasts in this setting. We propose a log transformation of forecast errors for price projections and a modified nonparametric empirical density forecasting method. Our findings give guidance on how to evaluate and communicate uncertainty in future energy outlooks.

Evaluation of a proposal for reliable low-cost grid power with 100% wind, water, and solar.

A number of analyses, meta-analyses, and assessments, including those performed by the Intergovernmental Panel on Climate Change, the National Oceanic and Atmospheric Administration, the National Renewable Energy Laboratory, and the International Energy Agency, have concluded that deployment of a diverse portfolio of clean energy technologies makes a transition to a low-carbon-emission energy system both more feasible and less costly than other pathways. In contrast, Jacobson et al. [Jacobson MZ, Delucchi MA, Cameron MA, Frew BA (2015) Proc Natl Acad Sci USA 112(49):15060-15065] argue that it is feasible to provide "low-cost solutions to the grid reliability problem with 100% penetration of WWS [wind, water and solar power] across all energy sectors in the continental United States between 2050 and 2055", with only electricity and hydrogen as energy carriers. In this paper, we evaluate that study and find significant shortcomings in the analysis. In particular, we point out that this work used invalid modeling tools, contained modeling errors, and made implausible and inadequately supported assumptions. Policy makers should treat with caution any visions of a rapid, reliable, and low-cost transition to entire energy systems that relies almost exclusively on wind, solar, and hydroelectric power.

Emissions and Economics of Behind-the-Meter Electricity Storage.

Annual installations of behind-the-meter (BTM) electric storage capacity are forecast to eclipse grid-side electrochemical storage by the end of the decade. Here, we characterize the economic payoff and regional emission consequences of BTM storage without colocated generation under different tariff conditions, battery characteristics, and ownership scenarios using metered loads for several hundred commercial and industrial customers. Net emissions are calculated as increased system emissions from charging minus avoided emissions from discharging. Net CO2 emissions range from 75 to 270 kg/MWh of delivered energy depending on location and ownership perspective, though in New York, these emissions can be reduced with careful tariff design. Net NOx emissions range from -0.13 to 0.24 kg/MWh, and net SO2 emissions range from -0.01 to 0.58 kg/MWh. Emission rates are driven primarily by energy losses, not by the difference between marginal emission rates during battery charging and discharging. Economics are favorable for many buildings in regions with high demand charges like California and New York, even without subsidies. Future penetration into regions with average charges like Pennsylvania will depend greatly on installation cost reductions and wholesale prices for ancillary services.

Quantifying the hurricane catastrophe risk to offshore wind power.

The U.S. Department of Energy has estimated that over 50 GW of offshore wind power will be required for the United States to generate 20% of its electricity from wind. Developers are actively planning offshore wind farms along the U.S. Atlantic and Gulf coasts and several leases have been signed for offshore sites. These planned projects are in areas that are sometimes struck by hurricanes. We present a method to estimate the catastrophe risk to offshore wind power using simulated hurricanes. Using this method, we estimate the fraction of offshore wind power simultaneously offline and the cumulative damage in a region. In Texas, the most vulnerable region we studied, 10% of offshore wind power could be offline simultaneously because of hurricane damage with a 100-year return period and 6% could be destroyed in any 10-year period. We also estimate the risks to single wind farms in four representative locations; we find the risks are significant but lower than those estimated in previously published results. Much of the hurricane risk to offshore wind turbines can be mitigated by designing turbines for higher maximum wind speeds, ensuring that turbine nacelles can turn quickly to track the wind direction even when grid power is lost, and building in areas with lower risk.

Regional variations in the health, environmental, and climate benefits of wind and solar generation.

When wind or solar energy displace conventional generation, the reduction in emissions varies dramatically across the United States. Although the Southwest has the greatest solar resource, a solar panel in New Jersey displaces significantly more sulfur dioxide, nitrogen oxides, and particulate matter than a panel in Arizona, resulting in 15 times more health and environmental benefits. A wind turbine in West Virginia displaces twice as much carbon dioxide as the same turbine in California. Depending on location, we estimate that the combined health, environmental, and climate benefits from wind or solar range from $10/MWh to $100/MWh, and the sites with the highest energy output do not yield the greatest social benefits in many cases. We estimate that the social benefits from existing wind farms are roughly 60% higher than the cost of the Production Tax Credit, an important federal subsidy for wind energy. However, that same investment could achieve greater health, environmental, and climate benefits if it were differentiated by region.

Can hybrid solar-fossil power plants mitigate CO2 at lower cost than PV or CSP?

Fifteen of the United States and several nations require a portion of their electricity come from solar energy. We perform an engineering-economic analysis of hybridizing concentrating solar thermal power with fossil fuel in an Integrated Solar Combined Cycle (ISCC) generator. We construct a thermodynamic model of an ISCC plant in order to examine how much solar and fossil electricity is produced and how such a power plant would operate, given hourly solar resource data and hourly electricity prices. We find that the solar portion of an ISCC power plant has a lower levelized cost of electricity than stand-alone solar power plants given strong solar resource in the US southwest and market conditions that allow the capacity factor of the solar portion of the power plant to be above 21%. From a local government perspective, current federal subsidies distort the levelized cost of electricity such that photovoltaic electricity is slightly less expensive than the solar electricity produced by the ISCC. However, if the cost of variability and additional transmission lines needed for stand-alone solar power plants are taken into account, the solar portion of an ISCC power plant may be more cost-effective.

Costs of solar and wind power variability for reducing CO2 emissions.

We compare the power output from a year of electricity generation data from one solar thermal plant, two solar photovoltaic (PV) arrays, and twenty Electric Reliability Council of Texas (ERCOT) wind farms. The analysis shows that solar PV electricity generation is approximately one hundred times more variable at frequencies on the order of 10(-3) Hz than solar thermal electricity generation, and the variability of wind generation lies between that of solar PV and solar thermal. We calculate the cost of variability of the different solar power sources and wind by using the costs of ancillary services and the energy required to compensate for its variability and intermittency, and the cost of variability per unit of displaced CO(2) emissions. We show the costs of variability are highly dependent on both technology type and capacity factor. California emissions data were used to calculate the cost of variability per unit of displaced CO(2) emissions. Variability cost is greatest for solar PV generation at $8-11 per MWh. The cost of variability for solar thermal generation is $5 per MWh, while that of wind generation in ERCOT was found to be on average $4 per MWh. Variability adds ~$15/tonne CO(2) to the cost of abatement for solar thermal power, $25 for wind, and $33-$40 for PV.

Quantifying the hurricane risk to offshore wind turbines.

The U.S. Department of Energy has estimated that if the United States is to generate 20% of its electricity from wind, over 50 GW will be required from shallow offshore turbines. Hurricanes are a potential risk to these turbines. Turbine tower buckling has been observed in typhoons, but no offshore wind turbines have yet been built in the United States. We present a probabilistic model to estimate the number of turbines that would be destroyed by hurricanes in an offshore wind farm. We apply this model to estimate the risk to offshore wind farms in four representative locations in the Atlantic and Gulf Coastal waters of the United States. In the most vulnerable areas now being actively considered by developers, nearly half the turbines in a farm are likely to be destroyed in a 20-y period. Reasonable mitigation measures--increasing the design reference wind load, ensuring that the nacelle can be turned into rapidly changing winds, and building most wind plants in the areas with lower risk--can greatly enhance the probability that offshore wind can help to meet the United States' electricity needs.

Net air emissions from electric vehicles: the effect of carbon price and charging strategies.

Plug-in hybrid electric vehicles (PHEVs) may become part of the transportation fleet on time scales of a decade or two. We calculate the electric grid load increase and emissions due to vehicle battery charging in PJM and NYISO with the current generation mix, the current mix with a $50/tonne CO(2) price, and this case but with existing coal generators retrofitted with 80% CO(2) capture. We also examine all new generation being natural gas or wind+gas. PHEV fleet percentages between 0.4 and 50% are examined. Vehicles with small (4 kWh) and large (16 kWh) batteries are modeled with driving patterns from the National Household Transportation Survey. Three charging strategies and three scenarios for future electric generation are considered. When compared to 2020 CAFE standards, net CO(2) emissions in New York are reduced by switching from gasoline to electricity; coal-heavy PJM shows somewhat smaller benefits unless coal units are fitted with CCS or replaced with lower CO(2) generation. NO(X) is reduced in both RTOs, but there is upward pressure on SO(2) emissions or allowance prices under a cap.

Implications of compensating property owners for geologic sequestration of CO2.

Geologic sequestration (GS) of carbon dioxide (CO2) is contingent upon securing the legal right to use deep subsurface pore space. Under the assumption that compensation might be required to use pore space for GS, we examine the cost of acquiring the rights to sequester 160-million metric tons of CO2 (the 30-year emissions output for an 800 megawatt power plant operating with a 60% capacity factor and at 90% capture efficiency) using a probabilistic model to simulate the temporal-spatial distribution of subsurface CO2 plumes in several brine-filled sandstones in Pennsylvania and Ohio. For comparison, the Frio Sandstone in the Texas Gulf Coast and the Mt. Simon Sandstone in Illinois were also analyzed. The predicted median values of CO2 plume footprints range from 4500 km(2) to 11,000 km(2) for the Ohio and Pennsylvania sandstones compared to 320 km(2) and 300 km(2) for the thicker Frio and Mt. Simon Sandstones, respectively. We use these footprints to bound the cost to use pore space in Pennsylvania and Ohio and, alternatively, the cost of piping CO2 from Pennsylvania and Ohio to the Mt. Simon or Frio Sandstones for sequestration. The results suggest that pore space acquisition costs could be significant and that using thin local formations for sequestration may be more expensive than piping CO2 to thicker formations at distant sites.

Near-term implications of a ban on new coal-fired power plants in the United States.

Large numbers of proposed new coal power generators in the United States have been canceled, and some states have prohibited new coal power generators. We examine the effects on the U.S. electric power system of banning the construction of coal-fired electricity generators, which has been proposed as a means to reduce U.S. CO2 emissions. The model simulates load growth, resource planning, and economic dispatch of the Midwest Independent Transmission System Operator (ISO), Inc., Electric Reliability Council of Texas (ERCOT), and PJM under a ban on new coal generation and uses an economic dispatch model to calculate the resulting changes in dispatch order, CO2 emissions, and fuel use under three near-term (until 2030) future electric power sector scenarios. A national ban on new coal-fired power plants does not lead to CO2 reductions of the scale required under proposed federal legislation such as Lieberman-Warner but would greatly increase the fraction of time when natural gas sets the price of electricity, even with aggressive wind and demand response policies.

Air emissions due to wind and solar power.

Renewables portfolio standards (RPS) encourage large-scale deployment of wind and solar electric power. Their power output varies rapidly, even when several sites are added together. In many locations, natural gas generators are the lowest cost resource available to compensate for this variability, and must ramp up and down quickly to keep the grid stable, affecting their emissions of NOx and CO2. We model a wind or solar photovoltaic plus gas system using measured 1-min time-resolved emissions and heat rate data from two types of natural gas generators, and power data from four wind plants and one solar plant. Over a wide range of renewable penetration, we find CO2 emissions achieve approximately 80% of the emissions reductions expected if the power fluctuations caused no additional emissions. Using steam injection, gas generators achieve only 30-50% of expected NOx emissions reductions, and with dry control NOx emissions increase substantially. We quantify the interaction between state RPSs and NOx constraints, finding that states with substantial RPSs could see significant upward pressure on NOx permit prices, if the gas turbines we modeled are representative of the plants used to mitigate wind and solar power variability.

Short run effects of a price on carbon dioxide emissions from U.S. electric generators.

The price of delivered electricity will rise if generators have to pay for carbon dioxide emissions through an implicit or explicit mechanism. There are two main effects that a substantial price on CO2 emissions would have in the short run (before the generation fleet changes significantly). First, consumers would react to increased price by buying less, described by their price elasticity of demand. Second, a price on CO2 emissions would change the order in which existing generators are economically dispatched, depending on their carbon dioxide emissions and marginal fuel prices. Both the price increase and dispatch changes depend on the mix of generation technologies and fuels in the region available for dispatch, although the consumer response to higher prices is the dominant effect. We estimate that the instantaneous imposition of a price of $35 per metric ton on CO2 emissions would lead to a 10% reduction in CO2 emissions in PJM and MISO at a price elasticity of -0.1. Reductions in ERCOT would be about one-third as large. Thus, a price on CO2 emissions that has been shown in earlier workto stimulate investment in new generation technology also provides significant CO2 reductions before new technology is deployed at large scale.

Regulating the geological sequestration of CO2.

Governments worldwide should provide incentives for initial large-scale GS projects to help build the knowledge base for a mature, internationally harmonized GS regulatory framework. Health, safety, and environmental risks of these early projects can be managed through modifications of existing regulations in the EU, Australia, Canada, and the U.S. An institutional mechanism, such as the proposed Federal Carbon Sequestration Commission in the U.S., should gather data from these early projects and combine them with factors such as GS industrial organization and climate regime requirements to create an efficient and adaptive regulatory framework suited to large-scale deployment. Mechanisms to structure long-term liability and fund long-term postclosure care must be developed, most likely at the national level, to equitably balance the risks and benefits of this important climate change mitigation technology. We need to do this right. During the initial field experiences, a single major accident, resulting from inadequate regulatory oversight, anywhere in the world, could seriously endanger the future viability of GS. That, in turn, could make it next to impossible to achieve the needed dramatic global reductions in CO2 emissions over the next several decades. We also need to do it quickly. Emissions are going up, the climate is changing, and impacts are growing. The need for safe and effective CO2 capture with deep GS is urgent.

Should a coal-fired power plant be replaced or retrofitted?

In a cap-and-trade system, a power plant operator can choose to operate while paying for the necessary emissions allowances, retrofit emissions controls to the plant, or replace the unit with a new plant. Allowance prices are uncertain, as are the timing and stringency of requirements for control of mercury and carbon emissions. We model the evolution of allowance prices for SO2, NOx, Hg, and CO2 using geometric Brownian motion with drift, volatility, and jumps, and use an options-based analysis to find the value of the alternatives. In the absence of a carbon price, only if the owners have a planning horizon longer than 30 years would they replace a conventional coal-fired plant with a high-performance unit such as a supercritical plant; otherwise, they would install SO2 and NOx, controls on the existing unit. An expectation that the CO2 price will reach $50/t in 2020 makes the installation of an IGCC with carbon capture and sequestration attractive today, even for planning horizons as short as 20 years. A carbon price below $40/t is unlikely to produce investments in carbon capture for electric power.