Benchmarking Utility-Scale PV Operational Expenses and Project Lifetimes: Results from a Survey of U.S. Solar Industry Professionals

This paper draws on a survey of solar industry professionals and other sources to clarify trends in the expected useful life and operational expenditure (OpEx) of utility-scale photovoltaic (PV) plants in the United States. Solar project developers, sponsors, long-term owners, and consultants have increased project-life assumptions over time, from an average of ~21.5 years in 2007 to ~32.5 years in 2019. Current assumptions range from 25 years to more than 35 years depending on the organization; 17 out of 19 organizations surveyed or reviewed use 30 years or more. Levelized, lifetime OpEx estimates have declined from an average of ~$35/kWDC-yr for projects built in 2007 to an average of ~$17/kWDC-yr in 2019. Across 13 sources, the range in average lifetime OpEx for projects built in 2019 is broad, from $13 to$25/kWDC-yr. Operations and maintenance (O&M) costs—one component of OpEx—have declined precipitously in recent years, to $5-8/kWDC-yr in many cases. Property taxes and land lease costs are highly variable across sites, but on average are—together—of similar magnitude. Other OpEx line items include security, insurance, and asset management. Given 2007-2009 values for not only project life and OpEx but also other drivers of the levelized cost of energy (LCOE, excluding the investment tax credit), the LCOE for utility-scale PV projects built from 2007 through 2009 averaged$305/MWh. Using 2019 values for all parameters yields an average LCOE of $51/MWh. The decline in LCOE from$305/MWh to $51/MWh was predominantly caused by reductions in up-front expenditures (and, to a much lesser extent, by changes in capacity factors, financing costs, and tax rates), but 9$22/MWh) of the overall decline is due to improvements in project life and OpEx. Project life extensions and OpEx reductions have had similarly sized impacts on LCOE over this period, at $11/MWh each. Had project life and OpEx not improved over the last decade, LCOE in 2019 would have instead been$73/MWh—43% higher. Given the limited quantity and comparability of previously available data on these cost drivers, the data and trends presented here may inform assumptions used by electric system planners, modelers, and analysts. The results may also provide useful benchmarks to the solar industry, helping developers and assets owners compare their expectations for project life and OpEx with those of their peers

Impacts of High Variable Renewable Energy Futures on Electric-Sector Decision Making: Demand-Side Effects

Previous work by the Berkeley Lab describes how high shares of variable renewable energy (VRE) such as wind and solar power could change wholesale electricity price dynamics. These include the timing of when electricity is cheap or expensive, locational differences in the cost of electricity, and the degree of regularity or predictability in those costs. Many decentralized decision-makers on the demand-side may not yet have considered the implications of these possible future changes. In this report, we evaluate the sensitivity of a set of demand-side decisions to different levels of VRE penetration ranging from a low of 5-20% to a high of 40-50%. The analysis builds on hourly wholesale energy and capacity prices in different VRE scenarios for four wholesale markets in the United States for the year 2030 (CAISO, ERCOT, NYISO, and SPP). The principal question for this exploration is whether private and public electric-sector decisions that are made based on assumptions reflecting low VRE levels still achieve their intended objective in a high VRE scenario with 40-50% wind and solar? This scoping report evaluates the impacts of changing patterns of peak system needs on the benefits of demand reductions by examining the altered value of different energy efficiency (EE) measures. Similarly, we investigate new opportunities for large energy consumers that may arise from periods with very low wholesale electricity prices. We calculate the value of new process investments (e.g., hydrogen production and other generalized electro-commodities), showcase the varying value of new product storage investments (such as reservoir extensions at a desalination plant), and estimate the benefits of increased process flexibility that uses electricity as a process-input in addition to traditional fossil fuels (e.g., district energy systems). Finally, many decentralized decision-makers and end-use customers are not directly exposed to wholesale electricity prices but instead receive price signals from their retail electricity rates. As wind and solar shares increase, we compare the economic efficiency of flat retail rates relative to more dynamic time-of-use tariffs with and without critical peak-pricing events

Impact of Wind, Solar, and Other Factors on Wholesale Power Prices: An Historical Analysis—2008 through 2017

Wholesale power markets have evolved. Some of the most prominent changes over the last decade in the United States include growth in wind and solar, a reduction in the price of natural gas, weakened load growth, and an increase in the retirement of thermal power plants. Here we empirically assess the degree to which wind and solar—among other factors—have influenced wholesale electricity prices. We show that wind and solar have contributed to reductions in overall average annual wholesale electricity prices since 2008, but that natural gas prices have had the largest impact. More notable is that expansion of variable renewable energy has led to significant changes in locational, time of day, and seasonal pricing patterns in some regions. These altered pricing patterns reflect a fundamental shift, and hold important implications for the grid-system value of wind and solar, and for other electric-sector planning and operating decisions

Socio-economic and Engineering Assessments of Renewable Energy Cost Reduction Potential

This dissertation combines three perspectives on the potential of cost reductions of renewable energy – a relevant topic, as high energy costs have traditionally been cited as major reason to vindicate developments of fossil fuel and nuclear power plants, and to justify financial support mechanisms and special incentives for renewable energy generators. First, I highlight the role of market and policy drivers in an international comparison of upfront capital expenses of residential photovoltaic systems in Germany and the United States that result in price differences of a factor of two and suggest cost reduction opportunities. In a second article I examine engineering approaches and siting considerations of large-scale photovoltaic projects in the United States that enable substantial system performance increases and allow thus for lower energy costs on a levelized basis. Finally, I investigate future cost reduction options of wind energy, ranging from capital expenses, operating expenses, and performance over a project’s lifetime to financing costs. The assessment shows both substantial further cost decline potential for mature technologies like land-based turbines, nascent technologies like fixed-bottom offshore turbines, and experimental technologies like floating offshore turbines. The following paragraphs summarize each analysis:International upfront capital cost comparison of residential solar systemsResidential photovoltaic (PV) systems were twice as expensive in the United States as in Germany (median of $5.29/W vs.$2.59/W) in 2012. This price discrepancy stems primarily from differences in non-hardware or “soft” costs between the two countries, of which only 35% be explained by differences in cumulative market size and associated learning. A survey of German PV installers was deployed to collect granular data on PV soft costs in Germany, and the results are compared to those of a similar survey of U.S. PV installers. Non-module hardware costs and all analyzed soft costs are lower in Germany, especially for customer acquisition, installation labor, and profit/overhead costs, but also for expenses related to permitting, interconnection, and inspection procedures. Additional costs occur in the United States due to state and local sales taxes, smaller average system sizes, and longer project-development times. To reduce the identified additional costs of residential PV systems, the United States could introduce policies that enable a robust and lasting market while minimizing market fragmentation. Regularly declining incentives offering a transparent and certain value proposition—combined with simple interconnection, permitting, and inspection requirements—might help accelerate PV cost reductions in the United States. Performance analysis of large-scale solar installations in the United StatesThis paper presents the first known use of multi-variate regression techniques to statistically explore empirical variation in utility-scale PV project performance across the United States. Among a sample of 128 utility-scale PV projects totaling 3,201 MWAC, net capacity factors in 2014 varied by more than a factor of two. Regression models developed for this analysis find that just three highly significant independent variables – the level of global horizontal irradiance (GHI), the use of single-axis tracking, and the inverter loading ratio (ILR) – can explain 92% of this project-level variation (with GHI alone able to explain 71.6%). Adding the commercial operation year as a fourth independent variable and three interactive variables (tracking x GHI, tracking x ILR, GHI x ILR) improves the model further and reveals interesting relationships (e.g., the performance benefit of tracking increases with a higher GHI but diminishes with a higher ILR). Taken together, the empirical data and statistical modeling results presented in this paper can provide a useful indication of the level of performance that solar project developers and investors can expect from various project configurations in different regions of the United States. Moreover, the tight relationship between fitted and actual capacity factors should instill confidence among investors that the utility-scale projects in this sample have largely performed as predicted by our models, with no significant outliers to date. Holistic assessment of future cost reduction opportunities of wind energy applicationsWind energy supply has grown rapidly over the last decade. However, the long-term contribution of wind to future energy supply, and the degree to which policy support is necessary to motivate higher levels of deployment, depends—in part—on the future costs of both onshore and offshore wind. Here, I summarize the results of an expert elicitation survey of 163 of the world’s foremost wind experts, aimed at better understanding future costs and technology advancement possibilities. Results suggest significant opportunities for cost reductions, but also underlying uncertainties. Under the median scenario, experts anticipate 24–30% reductions by 2030 and 35–41% reductions by 2050 across the three wind applications studied. Costs could be even lower: experts predict a 10% chance that reductions will be more than 40% by 2030 and more than 50% by 2050. The main identified drivers for near term cost reductions are rotor-related advancements and taller towers for onshore installations, fixed-bottom offshore turbines can benefit from an upscaling in generator capacity, streamlined foundation design and reduced financing costs, while floating offshore turbines require further progress in buoyant support structure design and installation process efficiencies. Insights gained through this expert elicitation complement other tools for evaluating cost-reduction potential, and help inform policy, planning, R&D, and industry strategy