Costs for utility-scale solar photovoltaic (PV) systems have declined in recent years—most sources show that system costs on a per-watt basis have fallen about 10% to 15% per year from 2010 through 2016. The level of those costs in certain years often varies across sources for reasons largely attributable to the way these costs are estimated.
To estimate capital costs of generating technologies, analysts use one of two common methods—total reported costs or aggregated component costs. Both approaches help explain the cost of utility-scale solar PV systems.
Reported costs: Using actual project data provides an empirical analysis that captures a large range of reported project costs in the market and accounts for the substantial variability in project design, location, and timing observed in the real world. Challenges with this approach include uncertainty about whether certain cost components are included in reported system costs, such as interconnection costs and the treatment of financing expense. Also, the data for each year reflect projects completed in that year, which do not necessarily reflect the costs of projects initiated in that year.
Component costs: The component cost approach provides more detail on the impact of changes in component-level technology and costs, which can be significant in a fast-moving market like solar PV. Such approaches typically represent either best-in-class or common-practice project criteria and do not necessarily capture the wide range of real-world project cost factors. Estimates that exclude financing expenses are called overnight estimates (i.e., as if the plant could be built instantly with no financing requirement). Component-based estimates may not reflect all potential costs to a system, such as developer profit margins.
EIA started collecting data on total capital costs directly from project owners as a part of the Form EIA-860 Annual Electric Generators Report in 2013. Because of respondent confidentiality, EIA only publishes capacity-weighted average values of new projects coming online each year and has published data for 2013, 2014, and 2015. This data series includes facilities with a nameplate capacity of at least one megawatt of alternating current. Respondents are asked to exclude government incentives and financing expenses from the reported costs.
The U.S. Department of Energy’s Lawrence Berkeley National Laboratory (LBNL) begins with EIA’s capital cost dataset and gathers additional information from corporate financial reports, Federal Energy Regulatory Commission (FERC) filings, and the U.S. Department of the Treasury’s Section 1603 grant database. LBNL’s annual Utility-Scale Solar Report defines utility-scale solar facilities as those with at least five megawatts or more of alternating current, which cuts out some of the smaller plants included in EIA’s Electric Generator Report.
The U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) publishes the Solar PV System Cost Benchmark report with estimates of total system costs based on the most up-to-date information on reported component costs and conversations with industry. These costs do not include additional net profit components, which are common in the marketplace. Also, NREL’s bottom-up approach models costs for a project sized at 100 megawatts of direct current, which is large enough to have realized some economies of scale relative to smaller systems.
EIA also projects future capital costs as part of the Annual Energy Outlook (AEO). Starting costs of solar PV come from contracted capital cost studies based on information on system design, configuration, and construction derived from actual or planned projects, using generic assumptions for labor and materials rates.
Although EIA does not update the capital cost study each year, in years where the report data are not updated, EIA extrapolates cost trends observed in the literature, including the sources noted above, and considers expected cost declines from learning-by-doing. For 2018, AEO2018 projects installed capital costs of $1.85 per watt (AC) for fixed-tilt PV systems and $2.11 per watt (AC) for single-axis tracking systems.
Principal contributor: Cara Marcy
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The LG XBOOM Go PL2 is the smallest and least expensive offering in LG's latest speaker trio including larger PL7 and PL5 models. All three models share the same design language and all have Meridian-tuned audio.
LG XBOOM PL2 is portable, small and light enough to be transported easily and offers 10 hours of battery life so it can run almost for a full day without being plugged in.
+ IPX5 water resistant
+ Easy to setup and use
+ Meridian tuned sound
- No integrated voice assistant
- No EQ adjustments
The LG XBOOM PL2 has IPX5 splash proof rating, which means it can withstand being sprayed with water but should not be submerged. We ran it under a faucet for a few seconds and the speaker kept working as it should.
The PL2 is based on version 5.0 of the Bluetooth standard and the range is quite similar to that of other speakers in the same price range. It can remain connected to more than 25 feet indoors from the audio source.
Two acquisitions in the energy sector were announced in the last week that illustrate the growing divergence in approaching the future of oil and gas between Europe and the USA. In France, Total announced that it had bought Fonroche Biogaz, the market leader in the production of renewable gas in France. In North America, ConocoPhillips completed its acquisition of Concho Resources, deepening the upstream major’s foothold into the lucrative Permian Basin and its shale riches. One is heading towards renewables, and the other is doubling down on conventional oil and gas.
What does this say about the direction of the energy industry?
Total’s move is unsurprising. Like almost all of its European peers operating in the oil and gas sector, Total has announced ambitious targets to become carbon-neutral by 2050. It is an ambition supported by the European population and pushed for by European governments, so in that sense, Total is following the wishes of its investors and stakeholders – just like BP, Shell, Repsol, Eni and others are doing. Fonroche Biogaz is therefore a canny acquisition. The company designs, builds and operates anaerobic digestion units that convert organic waste such as farming manure into biomethane to serve a gas feedstock for power generation. Fonroche Biogaz already has close to 500 GWh of installed capacity through seven power generation units with four in the pipeline. This feeds into Total’s recent moves to expand its renewable power generation capacity, with the stated intention of increasing the group’s biomethane capacity to 1.5 terawatts per hour (TWh) by 2025. Through this, Total vaults into a leading position within the renewable gas market in Europe, which is already active through affiliates such as Méthanergy, PitPoint and Clean Energy.
In parallel to this move, Total also announced that it has decided not to renew its membership in the American Petroleum Institute for 2021. Citing that it is only ‘partially aligned’ with the API on climate change issues in the past, Total has now decided that those positions have now ‘diverged’ particularly on rolling back methane emission regulations, carbon pricing and decarbonising transport. The French supermajor is not alone in its stance. BP, which has ditched the supermajor moniker in favour of turning itself into a clean energy giant, has also expressed reservations over the API’s stance over climate issues, and may very well choose to resign from the trade group as well. Other European upstream players might follow suit.
However, the core of the API will remain American energy firms. And the stance among these companies remains pro-oil and gas, despite shareholder pressure to bring climate issues and clean energy to the forefront. While the likes of ExxonMobil and Chevron have balanced significant investments into prolific shale patches in North America with public overtures to embrace renewables, no major US firm has made a public commitment to a carbon-neutral future as their European counterparts have. And so ConocoPhillips acquisition of Concho Resources, which boosts its value to some US$60 billion is not an outlier, but a preview of the ongoing consolidation happening in US shale as the free-for-all days give way to big boy acquisitions following the price-upheaval there since 2019.
That could change. In fact, it will change. The incoming Biden administration marks a significant break from the Trump administration’s embrace of oil and gas. Instead of opening of protected federal lands to exploration, especially in Alaska and sensitive coastal areas and loosening environmental regulations, the US will now pivot to putting climate change at the top of the agenda. Although political realities may water it down, the progressive faction of the Democrats are pushing for a Green New Deal embracing sustainability as the future for the US. Biden has already hinted that he may cancel the controversial and long-running Keystone XL pipeline via executive order on his first day in the office. His nominees for key positions including the Department of the Interior, Department of Energy, Environmental Protection Agency and Council on Environmental Quality suggest that there will be a major push on low-carbon and renewable initiatives, at least for the next 4 years. A pledge to reach net zero fossil fuel emissions from the power sector by 2035 has been mooted. More will come.
The landscape is changing. But the two approaches still apply, the aggressive acceleration adopted by European majors, and the slower movement favoured by US firms. Political changes in the USA might hasten the change, but it is unlikely that convergence will happen anytime soon. There is room in the world for both approaches for now, but the future seems inevitable. It just depends on how energy companies want to get there.
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In its January Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global demand for petroleum liquids will be greater than global supply in 2021, especially during the first quarter, leading to inventory draws. As a result, EIA expects the price of Brent crude oil to increase from its December 2020 average of $50 per barrel (b) to an average of $56/b in the first quarter of 2021. The Brent price is then expected to average between $51/b and $54/b on a quarterly basis through 2022.
EIA expects that growth in crude oil production from members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) will be limited because of a multilateral agreement to limit production. Saudi Arabia announced that it would voluntarily cut production by an additional 1.0 million b/d during February and March. Even with this cut, EIA expects OPEC to produce more oil than it did last year, forecasting that crude oil production from OPEC will average 27.2 million b/d in 2021, up from an estimated 25.6 million b/d in 2020.
EIA forecasts that U.S. crude oil production in the Lower 48 states—excluding the Gulf of Mexico—will decline in the first quarter of 2021 before increasing through the end of 2022. In 2021, EIA expects crude oil production in this region will average 8.9 million b/d and total U.S. crude oil production will average 11.1 million b/d, which is less than 2020 production.
EIA expects that responses to the recent rise in COVID-19 cases will continue to limit global oil demand in the first half of 2021. Based on global macroeconomic forecasts from Oxford Economics, however, EIA forecasts that global gross domestic product will grow by 5.4% in 2021 and by 4.3% in 2022, leading to energy consumption growth. EIA forecasts that global consumption of liquid fuels will average 97.8 million barrels per day (b/d) in 2021 and 101.1 million b/d in 2022, only slightly less than the 2019 average of 101.2 million b/d.
EIA expects global inventory draws will contribute to forecast rising crude oil prices in the first quarter of 2021. Despite rising forecast crude oil prices in early 2021, EIA expects upward price pressure will be limited through the forecast period because of high global oil inventory, surplus crude oil production capacity, and stock draws decreasing after the first quarter of 2021. EIA forecasts Brent crude oil prices will average $53/b in both 2021 and 2022.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
You can find more information on EIA’s expectations for changes in global petroleum liquids production, consumption, and crude oil prices in EIA’s latest This Week in Petroleum article and its January STEO.