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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Headline crude prices for the week beginning 11 November 2019 – Brent: US$62/b; WTI: US$56/b
Headlines of the week
The year’s final upstream auctions were touted as a potential bonanza for Brazil, with pre-auction estimates suggesting that up to US$50 billion could be raised for some deliciously-promising blocks. The Financial Times expected it to be the ‘largest oil bidding round in history’. The previous auction – held in October – was a success, attracting attention from supermajors and new entrants, including Malaysia’s Petronas. Instead, the final two auctions in November were a complete flop, with only three of the nine major blocks awarded.
What happened? What happened to the appetite displayed by international players such as ExxonMobil, Shell, Chevron, Total and BP in October? The fields on offer are certainly tempting, located in the prolific pre-salt basin and including prized assets such as the Buzios, Itapu, Sepia and Atapu fields. Collectively, the fields could contain as much as 15 billion barrels of crude oil. Time-to-market is also shorter; much of the heavy work has already been done by Petrobras during the period where it was the only firm allowed to develop Brazil’s domestic pre-salt fields. But a series of corruption scandals and a new government has necessitated a widening of that ambition, by bringing in foreign expertise and, more crucially, foreign money. But the fields won’t come cheap. In addition to signing bonuses to be paid to the Brazilian state ranging from US$331 million to US$17 billion by field, compensation will need to be paid to Petrobras. The auction isn’t a traditional one, but a Transfer of Rights sale covering existing in-development and producing fields.
And therein lies the problem. The massive upfront cost of entry comes at a time when crude oil prices are moderating and the future outlook of the market is uncertain, with risks of trade wars, economic downturns and a move towards clean energy. The fact that the compensation to be paid to Petrobras would be negotiated post-auction was another blow, as was the fact that the auction revolved around competing on the level of profit oil offered to the Brazilian government. Prior to the auction itself, this arrangement was criticised as overtly complicated and ‘awful’, with Petrobras still retaining the right of first refusal to operate any pre-salt fields A simple concession model was suggested as a better alternative, and the stunning rebuke by international oil firms at the auction is testament to that. The message is clear. If Brazil wants to open up for business, it needs to leave behind its legacy of nationalisation and protectionism centring around Petrobras. In an ironic twist, the only fields that were awarded went to Petrobras-led consortiums – essentially keeping it in the family.
There were signs that it was going to end up this way. ExxonMobil – so enthusiastic in the October auction – pulled out of partnering with Petrobras for Buzios, balking at the high price tag despite the field currently producing at 400,000 b/d. But the full-scale of the reticence revealed flaws in Brazil’s plans, with state officials admitting to being ‘stunned’ by the lack of participation. Comments seem to suggest that Brazil will now re-assess how it will offer the fields when they go up for sale again next year, promising to take into account the reasons that scared international majors off in the first place. Some US$17 billion was raised through the two days of auction – not an insignificant amount but a far cry from the US$50 billion expected. The oil is there. Enough oil to vault Brazil’s production from 3 mmb/d to 7 mmb/d by 2030. All Brazil needs to do now is create a better offer to tempt the interested parties.
Results of Brazil’s November upstream auctions:
Global liquid fuels
Electricity, coal, renewables, and emissions