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

An Examination of Avoided Costs in Utah

The Utah Wind Working Group (UWWG) believes there are currently opportunities to encourage wind power development in the state by seeking changes to the avoided cost tariff paid to qualifying facilities (QFs). These opportunities have arisen as a result of a recent re-negotiation of Pacificorp’s Schedule 37 tariff for wind QFs under 3 MW, as well as an ongoing examination of Pacificorp’s Schedule 38 tariff for wind QFs larger than 3 MW. It is expected that decisions made regarding Schedule 38 will also impact Schedule 37. Through the Laboratory Technical Assistance Program (Lab TAP), the UWWG has requested (through the Utah Energy Office) that LBNL provide technical assistance in determining whether an alternative method of calculating avoided costs that has been officially adopted in Idaho would lead to higher QF payments in Utah, and to discuss the pros and cons of this method relative to the methodology recently adopted under Schedule 37 in Utah. To accomplish this scope of work, I begin by summarizing the current method of calculating avoided costs in Utah (per Schedule 37) and Idaho (the “surrogate avoided resource” or SAR method). I then compare the two methods both qualitatively and quantitatively. Next I present Pacificorp’s four main objections to the use of the SAR method, and discuss the reasonableness of each objection. Finally, I conclude with a few other potential considerations that might add value to wind QFs in Utah

Using RPS Policies to Grow the Solar Market in the United States

The market for photovoltaics in the United States remains small relative to the nation's solar resource potential. Nonetheless, annual grid-connected PV installations have grown from just 4 MW in 2000 to over 100 MW in 2006, fast enough to the catch the attention of the global solar industry. The state of California deserves much of the credit for this growth. The State's historical rebate programs resulted in roughly 75% of the nation's grid-connected PV additions from 2000 through 2006 being located in California, and the $3 billion California Solar Initiative will ensure that the State remains a mainstay of the US solar industry for years to come. But California is not the only market for solar in the US; other states have recently developed policies that may rival those of the western state in terms of future growth potential. In particular, 25 states, as well as Washington, D.C., have established renewables portfolio standards (RPS), sometimes called quota systems in Europe, requiring electricity suppliers in those states to source a minimum portion of their need from renewable electricity. (Because a national RPS is not yet in place, my focus here is on state policies). Under many of these state policies, solar is not expected to fare particularly well: PV installations simply cannot compete on cost or scale with large wind plants in the US, at least not yet. In response, an expanding list of states have established solar or distributed generation (DG) set-asides within their RPS policies, effectively requiring that some fraction of RPS-driven supply derive from solar energy. The popularity of set-asides for solar and/or DG has increased dramatically in recent years. Already, 11 states and D.C. have developed such RPS set-asides. These include states with outstanding solar resources, such as Nevada, Arizona, Colorado, and New Mexico, as well as areas where the solar resource is less robust, including North Carolina, Maryland, Pennsylvania, New Jersey, New York, New Hampshire, Delaware, and DC. Among those states with set-asides, two are restricted to PV applications, nine also allow solar-thermal electric to qualify, three allow solar heating and/or cooling to qualify, and three have broader renewable DG set-asides. The policies also differ in their targets and timeframes, whether projects must be located in-state, the application of cost caps, and the degree of oversight on how suppliers contract with solar projects. Only three of these states have more than two years of experience with solar or DG set-asides so far: Arizona, Nevada, and New Jersey. And yet, despite the embryonic stage of these policies, they have already begun to have a significant impact on the grid-connected PV market. From 2000-2006, 16% (or 48 MW) of grid-connected PV installations in the US occurred in states with such set-asides, a percentage that increases to 67% if one only considers PV additions outside of California. The importance of these programs is growing and will continue to expand. In fact, if one assumes (admittedly somewhat optimistically) that these policies will be fully achieved, then existing state solar or DG set-asides could result in 400 MW of solar capacity by 2010, 2,000 MW by 2015, and 6,500 MW by 2025. This equates to annual additions of roughly 100 MW through 2010, increasing to over 500 MW per year by 2015 and 700 MW per year by 2020. PV is not assured of all of this capacity, and will receive strong competition from solar-thermal electric facilities in the desert southwest. Nonetheless, set-asides in those states outside of the southwest will favor PV, and even some of the southwestern states have designed their RPS programs to ensure that PV fares well, relative to other forms of solar energy. Since 2000, Arizona and, more recently, New Jersey have represented the largest solar set-aside-driven PV markets. Even more-recent additions are coming from Colorado, Nevada, New York, and Pennsylvania. In the long-term, the largest markets for solar electricity are predicted to include New Jersey, Maryland, Arizona, and Pennsylvania. How do these states stack up against California, with a goal of 3,000 MW of new solar capacity by 2016? Though none of the states with solar set-asides are predicted to reach 3,000 MW of solar from their RPS policies alone, three are expected to exceed 1,000 MW (New Jersey, Maryland, and Arizona). And, if stated on a percentage-of-load basis, then the solar targets in New Mexico, Arizona, New Jersey, and Maryland all exceed California's goal. Of course, achieving these targets is not assured. States with solar set-asides have developed various types of cost caps, many of which may ultimately become binding, thereby limiting future solar growth. Penalties for lack of compliance may be insufficient. Finally, some states continue to struggle with how to encourage long-term contracting for solar generation, and to ensure continued rebate programs for smaller PV installations

Benchmarking Anticipated Wind Project Lifetimes: Results from a Survey of U.S. Wind Industry Professionals

This paper draws on a survey of wind industry professionals to clarify trends in the expected useful life of land-based wind power plants in the United States. The expected useful life of a project affects expectations about its profitability, the timing of possible decommissioning or repowering, and its levelized costs. We find that most wind project developers, sponsors and long-term owners have increased project-life assumptions over time, from a typical term of ~20 years in the early 2000s to ~25 years by the mid-2010s and ~30 years more recently. Current assumptions range from 25 to 40 years, with an average of 29.6 years. The estimated average levelized cost of energy (LCOE) for new wind projects built in 2018 is $40.4/MWh (real 2018$), assuming a 20-year project life. With a 25-year useful life and no change in assumed operations and maintenance (O&M) expenditures or wind plant performance over time, LCOE declines by 10%, to $36.2/MWh, because capital costs are recovered over five additional years of production. At the now-common 30-year assumed life, levelized costs decrease another 7$33.5/MWh (under the same unaltered assumptions about O&M and performance). Even longer assumed lifetimes lead to further (but diminishing) LCOE reductions—e.g., to $31.7/MWh and$30.3/MWh for 35- and 40-year lives, respectively. 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 wind industry, helping developers and assets owners to compare their expectations with those of their peers

Effects of Temporal Wind Patterns on the Value of Wind-Generated Electricity in California and the Northwest

Wind power production is variable, but also has diurnal and seasonal patterns. These patterns differ between sites, potentially making electric power from some wind sites more valuable for meeting customer loads or selling in wholesale power markets. This paper investigates whether the timing of wind significantly affects the value of electricity from sites in California and the Northwestern United States. We use both measured and modeled wind data and estimate the time-varying value of wind power with both financial and load-based metrics. We find that the potential difference in wholesale market value between better-correlated and poorly correlated wind sites is modest, on the order of 5-10 percent. A load-based metric, power production during the top 10 percent of peak load hours, varies more strongly between sites, suggesting that the capacity value of different wind projects could vary by as much as 50 percent based on the timing of wind alone

Supporting Solar Power in Renewables Portfolio Standards: Experience from the United States

Among the available options for encouraging the increased deployment of renewable electricity, renewables portfolio standards (RPS) have become increasingly popular. The RPS is a relatively new policy mechanism, however, and experience with its use is only beginning to emerge. One key concern that has been voiced is whether RPS policies will offer adequate support to a wide range of renewable energy technologies and applications or whether, alternatively, RPS programs will favor a small number of the currently least-cost forms of renewable energy. This report documents the design of and early experience with state-level RPS programs in the United States that have been specifically tailored to encourage a wider diversity of renewable energy technologies, and solar energy in particular. As shown here, state-level RPS programs specifically designed to support solar have already proven to be an important, albeit somewhat modest, driver for solar energy deployment, and those impacts are projected to continue to build in the coming years. State experience in supporting solar energy with RPS programs is mixed, however, and full compliance with existing requirements has not been achieved. The comparative experiences described herein highlight the opportunities and challenges of applying an RPS to specifically support solar energy, as well as the importance of policy design details to ensuring that program goals are achieved

An Analysis of the Effects of Residential Photovoltaic Energy Systems on Home Sales Prices in California

An increasing number of homes in the U.S. have sold with photovoltaic (PV) energy systems installed at the time of sale, yet relatively little research exists that estimates the marginal impacts of those PV systems on home sale prices. A clearer understanding of these possible impacts might influence the decisions of homeowners considering the installation of a PV system, homebuyers considering the purchase of a home with PV already installed, and new home builders considering including PV as an optional or standard product on their homes. This research analyzes a large dataset of California homes that sold from 2000 through mid-2009 with PV installed. It finds strong evidence that homes with PV systems sold for a premium over comparable homes without PV systems during this time frame. Estimates for this premium expressed in dollars per watt of installed PV range, on average, from roughly $4 to$5.5/watt across a large number of hedonic and repeat sales model specifications and robustness tests. When expressed as a ratio of the sales price premium of PV to estimated annual energy cost savings associated with PV, an average ratio of 14:1 to 19:1 can be calculated; these results are consistent with those of the more-extensive existing literature on the impact of energy efficiency on sales prices. When the data are split among new and existing homes, however, PV system premiums are markedly affected. New homes with PV show premiums of $2.3-2.6/watt, while existing homes with PV show premiums of more than$6/watt. Reasons for this discrepancy are suggested, yet further research is warranted. A number of other areas where future research would be useful are also highlighted

Implications of Wide-Area Geographic Diversity for Short- Term Variability of Solar Power

Worldwide interest in the deployment of photovoltaic generation (PV) is rapidly increasing. Operating experience with large PV plants, however, demonstrates that large, rapid changes in the output of PV plants are possible. Early studies of PV grid impacts suggested that short-term variability could be a potential limiting factor in deploying PV. Many of these early studies, however, lacked high-quality data from multiple sites to assess the costs and impacts of increasing PV penetration. As is well known for wind, accounting for the potential for geographic diversity can significantly reduce the magnitude of extreme changes in aggregated PV output, the resources required to accommodate that variability, and the potential costs of managing variability. We use measured 1-min solar insolation for 23 time-synchronized sites in the Southern Great Plains network of the Atmospheric Radiation Measurement program and wind speed data from 10 sites in the same network to characterize the variability of PV with different degrees of geographic diversity and to compare the variability of PV to the variability of similarly sited wind. The relative aggregate variability of PV plants sited in a dense 10 x 10 array with 20 km spacing is six times less than the variability of a single site for variability on time scales less than 15-min. We find in our analysis of wind and PV plants similarly sited in a 5 x 5 grid with 50 km spacing that the variability of PV is only slightly more than the variability of wind on time scales of 5-15 min. Over shorter and longer time scales the level of variability is nearly identical. Finally, we use a simple approximation method to estimate the cost of carrying additional reserves to manage sub-hourly variability. We conclude that the costs of managing the short-term variability of PV are dramatically reduced by geographic diversity and are not substantially different from the costs for managing the short-term variability of similarly sited wind in this region