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 20 May 2019 – Brent: US$73/b; WTI: US$63/b
Headlines of the week
Midstream & Downstream
At first, it seemed like a done deal. Chevron made a US$33 billion offer to take over US-based upstream independent Anadarko Petroleum. It was a 39% premium to Anadarko’s last traded price at the time and would have been the largest industry deal since Shell’s US$61 billion takeover of the BG Group in 2015. The deal would have given Chevron significant and synergistic acreage in the Permian Basin along with new potential in US midstream, as well as Anadarko’s high potential projects in Africa. Then Occidental Petroleum swooped in at the eleventh hour, making the delicious new bid and pulling the carpet out from under Chevron.
We can thank Warren Buffet for this. Occidental Petroleum, or Oxy, had previously made several quiet approaches to purchase Anadarko. These were rebuffed in favour of Chevron’s. Then Oxy’s CEO Vicki Hollub took the company jet to meet with Buffet. Playing to his reported desire to buy into shale, Hollub returned with a US$10 billion cash infusion from Buffet’s Berkshire Hathaway – which was contingent on Oxy’s successful purchase of Anadarko. Hollub also secured a US$8.8 billion commitment from France’s Total to sell off Anadarko’s African assets. With these aces, she then re-approached Anadarko with a new deal – for US$38 billion.
This could have sparked off a price war. After all, the Chevron-Anadarko deal made a lot of sense – securing premium spots in the prolific Permian, creating a 120 sq.km corridor in the sweet spot of the shale basin, the Delaware. But the risk-adverse appetite of Chevron’s CEO Michael Wirth returned, and Chevron declined to increase its offer. By bowing out of the bid, Wirth said ‘Cost and capital discipline always matters…. winning in any environment doesn’t mean winning at any cost… for the sake for doing a deal.” Chevron walks away with a termination fee of US$1 billion and the scuppered dreams of matching ExxonMobil in size.
And so Oxy was victorious, capping off a two-year pursuit by Hollub for Anadarko – which only went public after the Chevron bid. This new ‘global energy leader’ has a combined 1.3 mmb/d boe production, but instead of leveraging Anadarko’s more international spread of operations, Oxy is looking for a future that is significantly more domestic.
The Oxy-Anadarko marriage will make Occidental the undisputed top producer in the Permian Basin, the hottest of all current oil and gas hotspots. Oxy was once a more international player, under former CEO Armand Hammer, who took Occidental to Libya, Peru, Venezuela, Bolivia, the Congo and other developing markets. A downturn in the 1990s led to a refocusing of operations on the US, with Oxy being one of the first companies to research extracting shale oil. And so, as the deal was done, Anadarko’s promising projects in Africa – Area 1 and the Mozambique LNG project, as well as interest in Ghana, Algeria and South Africa – go to Total, which has plenty of synergies to exploit. The retreat back to the US makes sense; Anadarko’s 600,000 acres in the Permian are reportedly the most ‘potentially profitable’ and it also has a major presence in Gulf of Mexico deepwater. Occidental has already identified 10,000 drilling locations in Anadarko areas that are near existing Oxy operations.
While Chevron licks its wounds, it can comfort itself with the fact that it is still the largest current supermajor presence in the Permian, with output there surging 70% in 2018 y-o-y. There could be other targets for acquisitions – Pioneer Natural Resources, Concho Resources or Diamondback Energy – but Chevron’s hunger for takeover seems to have diminished. And with it, the promises of an M&A bonanza in the Permian over 2019.
The Occidental-Anadarko deal:
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.
Source: U.S. Energy Information Administration, based on Baker Hughes
Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.
EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.
India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.
If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.