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Impacts of High Variable Renewable Energy Futures on Wholesale Electricity Prices, and on Electric-Sector Decision Making
Abstract and Figures
Increasing penetrations of variable renewable energy (VRE) can affect wholesale electricity price patterns and make them meaningfully different from past, traditional price patterns. Many long-lasting decisions for supply- and demand-side electricity infrastructure and programs are based on historical observations or assume a business-as-usual future with low shares of VRE. Our motivating question is whether certain electric-sector decisions that are made based on assumptions reflecting low VRE levels will still achieve their intended objective in a high VRE future. We qualitatively describe how various decisions may change with higher shares of VRE and outline an analytical framework for quantitatively evaluating the impacts of VRE on long-lasting decisions.
We then present results from detailed electricity market simulations with capacity expansion and unit commitment models for multiple regions of the U.S. for low and high VRE futures. We find a general decrease in average annual hourly wholesale energy prices with more VRE penetration, increased price volatility and frequency of very low-priced hours, and changing diurnal price patterns. Ancillary service prices rise substantially and peak net-load hours with high capacity value are shifted increasingly into the evening, particularly for high solar futures.
While in this report we only highlight qualitatively the possible impact of these altered price patterns on other demand- and supply-side electric sector decisions, the core set of electricity market prices derived here provides a foundation for later planned quantitative evaluations of these decisions in low and high VRE futures.
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... Consequently, PV-linked ESS operators continue to set and operate their ESSs with fixed charging and discharging patterns without installing communication and control equipment. However, this operational strategy fails to reflect current system conditions and market prices or the system marginal price (SMP), given the increased proportion of renewable energy [12]. Furthermore, operating ESSs with fixed charging and discharging patterns without considering variations in SMP patterns during weekdays, weekends, and holidays is inefficient for both PV-linked ESS operators and system operators. ...
... On average (No. [1][2][3][4][5][6][7][8][9][10][11][12], the charging amounts for the PV-linked ESS operators increased by 11.84% following the application of the proposed charging strategy from January to April 2023. ...
With the intensification of the global commitment to renewable energy, South Korea’s rapid expansion in renewable capacity necessitates efficient operational strategies to address the inherent variability of these energy sources. Despite the implementation of policies aimed at integrating energy storage systems (ESS) with renewable generation, such as providing additional renewable energy certificates (RECs), the measures undertaken remain relatively ineffective. Thus, this study evaluates the shortcomings of existing policies and proposes an innovative operational strategy tailored to Korea’s energy landscape. The strategy is implementable immediately using existing facilities, without requiring any new equipment, and facilitates profits of up to 12.45% greater compared with those generated using the original approach. Moreover, the results are nearly as effective as an ideal scenario wherein the PV generation and system marginal price are accurately known. Additionally, the decreased economic feasibility of ESS owing to the discontinuation of subsidies is highlighted and solutions are proposed to mitigate the problem. This underscores the urgent need for improved regulatory measures and enhanced operational strategies. The proposed approach highlights the potential to considerably reduce inefficiencies and operational costs, thereby contributing to more sustainable energy management practices within Korea.
... Under high VRE shares, the demand for reserves tends to increase to mitigate forecast errors [207]. However, the German experience shows the opposite. ...
... ii) Limited metal mining capacity and reserves, infrastructure build rates, and availability of financial capital will delay-and likely disrupt-the transition from fossil fuels to electricity, creating system-wide instability (Allwood et al. 2021;Michaux 2021Smil 2016Smil , 2022. iii) Even if average electricity prices fall as the transition proceeds, absent new technology to store power or balance variable supplies, wind and solar grids will lead to large diurnal and seasonal price variation and volatility and make shortages more likely (Michaux 2021;Seel et al. 2018). ...
Like everything for the past 2 centuries, agriculture has depended increasingly on fossil fuel energy. Pressures to shift to renewable energy and changes in the fossil fuel industry are set to massively alter the energy landscape over the next 30 years. Two near-certainties are increased overall prices and/or decreased stability of energy supplies. The impacts of these upheavals on specialty crop production and consumption are unknowable in detail but the grand lines of what will likely change can be foreseen. This foresight can guide the research, extension, and teaching needed to successfully navigate a future very unlike the recent past. Major variables that will influence outcomes include energy use in fertilizer manufacture, in farm operations, and in haulage to centers of consumption. Taking six increasingly popular fruit and vegetable crops and the top two horticultural production states as examples, here we use simple proxies for the energy requirements (in gigajoules per ton of produce) of fertilizer, farm operations, and truck transport from Florida or California to New York to compare the relative sizes of these requirements. Trucking from California is the largest energy requirement in all cases, and three times larger than from Florida. As these energy requirements themselves are all fairly fixed, but in future will likely rise in price and/or be subject to interruptions and shortages, this pilot study points to two commonsense inferences: First, that fruit and vegetable production and consumption are set to reposition to more local/regional and seasonal patterns due to increasing expenses associated with fuel, and second, that coast-to-coast produce shipment by truck will become increasingly expensive and difficult.
... A nivel mundial, algunos estudios analizaron el efecto del aumento de energía renovable variable en los precios horarios de mercados eléctricos con predominio de generación térmica y nuclear, como en el caso de México [10] y algunas zonas de Estados Unidos [8], [11]. ...
The increase in solar and wind generation carries flexibility problems for electrical systems, which could be solved by implementing large-scale energy storage plants. Arbitrage buying energy, storing it, and then selling it at a higher price is one of the primary sources of revenue for large-scale storage plants. To financially evaluate an arbitration project, it is necessary to estimate hourly spot prices for time horizons comparable to the project's lifespan, which is a very complex task due to the multiple variables that affect the price of electricity. This paper seeks to answer the following questions: will arbitration be enough to make large-scale storage projects viable in Colombia, assuming a massive incursion of solar and wind energy And which variables affect the arbitrage potential We developed a dynamic simulation model to estimate hourly spot prices over a 12-year horizon. We find that the massive incursion of solar and wind generation will decrease the arbitrage potential, making the storage projects that depend exclusively on this income unfeasible. This result implies that project developers and regulators must structure other remuneration mechanisms to incentivize large-scale storage construction.
... For example, lower output variability could reduce the required total capacity of reliability services products like frequency regulation and spinning reserves. Hybrid systems with more predictable, uniform output could also provide these reliability services instead of being a reason for their procurement (Seel et al., 2018). However, market participation models need to be studied, developed, and adopted for the full value of hybrid resources to be realized in electricity markets (Goggin et al., 2018;Stenclik et al., 2022). ...
As shares of variable renewable energy (VRE) on the electric grid increase, sources of grid flexibility will become increasingly important for maintaining the reliability and affordability of electricity supply. Lithium-ion battery energy storage has been identified as an important and cost-effective source of flexibility, both by itself and when coupled with VRE technologies like solar photovoltaics (PV) and wind. In this study, we explored the current and future value of utility-scale hybrid energy systems comprising PV, wind, and lithium-ion battery technologies (PV-wind-battery systems). Using a price-taker model with simulated hourly energy and capacity prices, we simulated the revenue-maximizing dispatch of a range of PV-wind-battery configurations across Texas, from the present through 2050. Holding PV capacity and point-of-interconnection capacity constant, we modeled configurations with varying wind-to-PV capacity ratios and battery-to-PV capacity ratios. We found that coupling PV, wind, and battery technologies allows for more effective utilization of interconnection capacity by increasing capacity factors to 60%–80%+ and capacity credits to close to 100%, depending on battery capacity. We also compared the energy and capacity values of PV-wind and PV-wind-battery systems to the corresponding stability coefficient metric, which describes the location-and configuration-specific complementarity of PV and wind resources. Our results show that the stability coefficient effectively predicts the configuration-location combinations in which a smaller battery component can provide comparable economic performance in a PV-wind-battery system (compared to a PV-battery system). These PV-wind-battery hybrids can help integrate more VRE by providing smoother, more predictable generation and greater flexibility.
... The inputs of the hydropower model are hourly inflows of corresponding reservoirs and hourly energy prices. We obtained inflow data from the United States Geological Survey's National Water Information System, and future energy prices from Seel et al. (2018), which predicts hourly energy prices based on historical prices. These values consider the increasing penetrations of variable renewable energy, and show a pattern similar to those reported by the California Independent System Operator (Guo et al., 2021). ...
Forest restoration through mechanical thinning, prescribed burning, and other management actions is vital to improving forest resilience to fire and drought across the Western United States, and yields benefits that can be monetized, including improvements in water supply and hydropower. Using California's Sierra Nevada as a study area, we assess the water and energy benefits of forest-restoration projects. By using a scalable top-down approach to track annual evapotranspiration following forest disturbance, coupled with hydropower simulations that include energy-price information, and marginal prices for water sales, we project the potential economic benefits of hydropower and water sales accruing to water-rights holders. The results found that water-related benefits from strategically planned fuels-reduction treatments now being carried out can be sufficient to offset costs of management actions aimed at forest restoration, especially in the face of climate change. Our findings justified investments in restoring forests and reinforce the central role of water and hydropower providers in partnerships for management of source-water watersheds. Results also highlighted the importance of accurate, scalable data and tools from the hydrology and water-resources community.
... In addition, they find that that the revenue wind generators receive for constraining output has significant consequences on the resulting capacity mix. Seel et al. (2018) have used marginal costs to analyse wholesale price patterns in the four grid regions of the USA. Using a capacity expansion model to derive high VRE scenarios, they found a reduction in average annual prices throughout but differing average price patterns based on VRE mix and region. ...
With the decarbonisation of electricity generation, large scale heat pumps are becoming increasingly viable for district heating combined with thermal energy storage, district heating can provide flexibility to the electricity grid by decoupling demand from supply. This thesis examines how district heating with heat pumps and thermal energy storage can integrate with and provide a benefit to an electricity system with predominantly renewable generation. The scope of work comprises three interlinked models underpinned by the same set of meteorology data, fundamentally coupling supply and demand. First, heat load data are surveyed, and an hourly demand profile is simulated. Disaggregation of district heating loads from the national demand is accomplished via segmentation of the building stock to model heat demand at high spatiotemporal resolution. Second, a novel method of pricing hourly electricity in a zero carbon, capital-intensive renewable system with electricity storage is developed and applied to a dispatch simulation to generate hourly electricity prices. Third, a dynamic model of district heating is constructed to simulate the meeting of heat loads with different design configurations using electricity as the energy source. Model predictive control is applied with varying forecast horizons so as to minimise the cost of electricity to meet the heat demand given a time series of hourly prices and consequently optimising the capacity of thermal energy storage. It was found that a thermal energy storage capacity equivalent to 1.3% of annual demand is sufficient to minimise operating costs. Finally, the potential impact of district heating on balancing the electricity system is analysed and an equivalence between thermal and electric storage is examined. While this is highly dependent on annual conditions, it can be as much as 3.5 units of thermal storage for every unit of electrical grid storage on the system. This could potentially reduce the investment in grid storage by £36 billion, underlining the significant financial benefits of thermal storage to the whole system. The research highlights the important potential of district heating to the UK’s energy system strategy.
The US electrical grid has undergone substantial transformation with increased penetration of wind and solar forms of variable renewable energy (VRE). Despite the benefits of VRE for decarbonization, it has garnered some controversy for inducing unwanted effects in regional electricity markets. In this study, the role of VRE penetration is examined on the system electricity price and price volatility based on hourly, real-time, historical data from six independent system operators (ISOs) in the US using quantile and skew t-distribution regressions. After correcting for temporal effects, we found an increase in VRE penetration is associated with a decrease in system electricity price in all ISOs studied. The increase in VRE penetration is associated with a decrease in temporal price volatility in five out of six ISOs studied. The relationships are nonlinear. These results are consistent with the modern portfolio theory where diverse volatile assets may lead to more stable and less risky portfolios.
Fundamental characteristics of solar and wind power have generated controversy about their economic competitiveness and appropriate techniques for assessing their value. This research presents an approach to quantify the economic value of variable renewable capacity and demonstrates its dependence on renewable deployment levels, regional resource endowments, fleet flexibility, and trade assumptions. It assesses economic and technical impacts of large-scale renewable penetration by linking two models, representing electric-sector investments and detailed operations. Model results for California and Texas suggest operational constraints and costs of dispatchable generators (e.g., minimum load levels, ramping limits, startup costs) can impact renewable integration costs, but the temporal and spatial variability of solar and wind are larger determinants of their value. Restrictions on transmission and regional coordination in capacity planning and dispatch decrease the economic value of variable renewable energy, highlighting the potential roles of market design and trade. Energy storage is shown to be a valuable balancing asset at higher solar and wind penetration levels, but potential revenues diminish with increased storage deployment.
Revenue insufficiency, or the missing money problem, occurs when the revenues that generators
earn from the market are not sufficient to cover both fixed and variable costs to remain in the
market and/or justify investments in new capacity, which may be needed for reliability. The
near-zero marginal cost of variable renewable generators further exacerbates these revenue
challenges. Estimating the extent of the missing money problem in current electricity markets is
an important, nontrivial task that requires representing both how the power system operates and
how market participants behave.
This paper explores the missing money problem using a production cost model that represented a
simplified version of the Electric Reliability Council of Texas (ERCOT) energy-only market for
the years 2012–2014. We evaluate how various market structures—including market behavior,
ancillary services, and changing fleet compositions—affect net revenues in this ERCOT-like
system.
In most production cost modeling exercises, resources are assumed to offer their marginal
capabilities at marginal costs. Although this assumption is reasonable for feasibility studies and
long-term planning, it does not adequately consider the market behaviors that impact revenue
sufficiency. In this work, we simulate a limited set of market participant strategic bidding
behaviors by means of different sets of markups; these markups are applied to the true
production costs of all gas generators, which are the most prominent generators in ERCOT.
Results show that markups can help generators increase their net revenues overall, although net
revenues may increase or decrease depending on the technology and the year under study.
Results also confirm that conventional, variable-cost-based production cost simulations do not
capture prices accurately, and this particular feature calls for proxies for strategic behaviors (e.g.,
markups) and more accurate representations of how electricity markets work.
The analysis also shows that generators face revenue sufficiency challenges in this ERCOT-like
energy-only market model; net revenues provided by the market in all base markup cases and
sensitivity scenarios (except when a large fraction of the existing coal fleet is retired) are not
sufficient to justify investments in new capacity for thermal and nuclear power units. Overall, the
work described in this paper points to the need for improved behavioral models of electricity
markets to more accurately study current and potential market design issues that could arise in
systems with high penetrations of renewable generation.
Most analyses of energy efficiency investments ignore that the value of electricity varies widely across hours. We show how much timing matters. Using novel hourly consumption data from an air conditioner rebate program in California, we find that energy savings are concentrated in high-value hours. This significantly increases the value of these investments, especially after we account for the large capacity payments that electricity generators receive to guarantee supply in peak hours. We then use engineering predictions to calculate timing premiums for a wide range of energy efficiency investments, finding substantial variation in economic value across investments. (JEL L94, L98, Q41, Q48)
Electricity prices have fallen significantly since 2008, putting commercial nuclear reactors in the United States under substantial financial pressure. In this market environment driven by persistently low natural gas prices and stagnant electricity demand, we estimate that about two thirds of the 102 GW nuclear capacity are uncompetitive over the next few years under the current trajectory. Among those, 18 GW are retiring or are merchant plants at high risk of retiring prematurely.
The potential consequences of the hypothetical withdrawal of 20 GW of nuclear capacity include: 1) a ~3.2% increase in carbon emissions of the power sector if replaced by gas-fired units or 2) a significant increase in cost if replaced by renewables.
Without a carbon price, out-of-the-market payments would be needed to effectively maintain merchant nuclear capacity. Filling the revenue gap would come at a fleet-average cost of $3.5–5.5/ MWh for these plants, which is much lower than the cost of subsidizing wind power. The policy support could take the form of direct zero-emission credits, renewable portfolio standard expansion, or clean capacity market mechanisms. As a last resort, the exercise of a new mothballing status could prevent the irreversible retirement of nuclear power assets.
Adding large solar photovoltaic (PV) resources into an electric grid influences the flexibility characteristics of its net load profile. The dispatch of the existing generation fleet changes as it adjusts to accommodate the new net load. This study categorizes and defines these flexibility characteristics. It utilizes a unit commitment and dispatch (UC&D) model to simulate large solar generation assets with different geographic locations and orientations. The simulations show the sensitivity of the wholesale energy price, reserve market prices, total dispatch cost, fuel mix, emissions, and water use to changes in net load flexibility requirements. The results show that generating 22,500 GW h of solar energy in a 2011 simulation of the Electric Reliability Council of Texas (ERCOT) reduces total dispatch cost by approximately 10 million (a 3% increase). The results also show that PV reduces water consumption and water withdrawals as well as CO2, NOx, and SOx emissions. It also reduces peak load by 4% but increases net load volatility by 40–79% and ramping by 11–33%. In addition, west-located, west-oriented solar resources reduce total dispatch cost more than the other simulated solar scenarios. The west-located, west-oriented solar simulation required greater system flexibility, but utilized more low-cost generators and fewer high-cost generators for energy production than other simulated scenarios. These results suggest that the mix of energy provided by different generation technologies influences the dispatch cost more than the net load flexibility requirements.
As states consider revising or developing renewable portfolio standards (RPS), they are evaluating policy costs, benefits, and other impacts. We present the first U. S. national-level assessment of state RPS program benefits and impacts, focusing on new renewable electricity resources used to meet RPS compliance obligations in 2013. In our central-case scenario, reductions in life-cycle greenhouse gas emissions from displaced fossil fuel-generated electricity resulted in 5.2 billion in the central case. Further benefits accrued in the form of reductions in water withdrawals and consumption for power generation. Finally, although best considered resource transfers rather than net societal benefits, new renewable electricity generation used for RPS compliance in 2013 also supported nearly 200,000 U. S.-based gross jobs and reduced wholesale electricity prices and natural gas prices, saving consumers a combined 1.3–4.9 billion. In total, the estimated benefits and impacts well-exceed previous estimates of RPS compliance costs.
This study presents an assessment of both the merit-order effect and the market values of electricity generated from variable renewable energy sources, namely wind and solar photovoltaics. The historical price development in several European countries – that cover 73% of the renewable energy source share in Europe’s regional electricity markets – has been taken into account. To gain insights into the impact of renewable electricity on prices, market values and the merit-order effect were calculated using a multivariate regression analysis and ex-post calculations. All the countries analyzed show a consistent, negative impact of renewable electricity on electricity spot market prices and a decreasing market value of renewable energy source, possibly attributable to increased shares. The coefficients are economically and statistically significant. This study provides insights into a large geographical spread of European electricity markets, enables a comparison between countries, and therefore has valuable implications for policy makers.