On Monday, MIT released a study titled “Managing Large-Scale Penetration of Intermittent Renewables.” It’s 36 megabytes and 240 pages. Last April, MIT gathered more than 70 experts at a symposium to discuss how to manage the growth of wind and solar. The first 50 pages of the document is a summary of the studies and discussions that took place during the symposium. The following 190 pages are seven white papers that were presented.
After going through the document, the report would be a sobering read if I were in the renewables industry. The wind industry took part in the discussions but several of the conclusions contradicted the claims from the wind industry for its projected savings on costs and emissions from wind. There are five main areas of concern with wind and solar that emerged from the symposium (pasted below):
- Emissions: While renewables can generate emissions-free electricity, the limited ability to store electricity, forecast renewable generation, and control the availability of intermittent renewables forces the rest of the electric power system to adapt with less efficient ramping and cycling operations. These operations potentially reduce the emissions benefits of renewables.
- Unintended consequences: Many power systems operate under mandated renewable portfolio standards that change existing market structures. The combination of mandates, markets, and physical system requirements present technological, economic, and policy-related integration challenges with unintended consequences to system planners and market participants. For example, mandates requiring renewable dispatch may increase the total system cost of generating electricity.
- Future generation mix: What does a well-adapted generation mix look like? How many gas peaking units and baseload plants does this mix require? What types of regulatory support are needed for units that contribute to reliability, but would likely have low-utilization rates? How will this generation be compensated? What regulatory structures are required to ensure adequate compensation? Spot prices may decline in the short term due to the fuel cost of renewables, but will this lead to an economically efficient generation mix in the long term?
- Electricity markets: The electricity market generally dispatches generation on a least-cost basis. Should the market treat renewables as any other generator, subject to scheduling penalties? For example, currently, renewable generators self-schedule their generation by declaring how much electricity they expect to generate in the next hour. The system operator takes these self-schedules into account when deciding which other plants to dispatch. If wind generators schedule themselves for 100 megawatts per hour (MWh) of electricity generation in the next hour, but are only able to generate 80 MWh, should the operator require that they purchase the remaining 20 MWh in the open market? Or, should the operator allow wind generators to exist independent from all, or a subset, of economic signals? Is priority dispatch justified?
- Regulation: Traditional regulations of transmission, business models, cost allocations, and planning criteria may not properly address the needs of renewables. The current regulatory system encourages cost reduction and reliability, not innovation. This may be inadequate to incentivize the development of the new transmission and generation technologies required to fully enable large-scale renewable generation.
Below are a number of informative paragraphs and charts from the report worth highlighting.
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Backup Capacity Needed
P. 21 - Participants discussed and disagreed about creating a “rule of thumb” for the amount of capacity that would be necessary to provide backup generation from intermittent resources. Several participants noted that a Carnegie Mellon University (CMU) study provides the only numbers available for planning future systems with large amounts of wind generation. Taking a resource level view, the CMU study assumes that 3 MW of [natural gas combined cycle] will be required for every 4 MW of wind. There was strong resistance from some participants to the use of the CMU numbers.
Levelized cost of electricity
P. 31 - LCOE comparisons frequently rely on the assumption that different generation technologies will operate at specific capacity factors and do not consider operational issues, such as cycling and ramping capabilities. These assumptions lead to higher LCOEs for technologies that have lower assumed capacity factors. Figure 9 shows the LCOE for NGCC, subcritical coal plants, and supercritical coal plants with and without dispatch considerations. At equal capacity factors of 85%, the LCOEs are essentially the same for all three technologies. However, when the expected dispatch considerations are included, the cost of NGCC plants increases significantly compared to the coal technologies. Figure 9 provides an extreme result by choosing a very low NGCC capacity factor for illustration, in addition to using high natural gas and low coal prices relative to today’s prices. Planning for future power systems will require modeling based on the assets in place today and a realistic understanding of actual dispatch considerations and practices. Several participants urged that economic dispatch be included in the future as an essential feature of any system modeling in order to ensure more accurate results. System-wide modeling using a unit commitment dispatch model was also highlighted as important for accurate and useful data and information for decision making.
Value of Nuclear
P. 32 - The business model of a nuclear plant relies on high-capacity factors to recoup the initial investment costs and to establish reasonable rates of return; nuclear plants serve baseload demand for economic reasons. In effect, because capital costs dominate the LCOE for nuclear power, the LCOE is nearly inversely proportional to capacity factor. Given these risks and the high upfront costs for nuclear technology in today’s economic environment, there was general consensus among participants that investors today prefer natural gas-fired power plants.
Unlike nuclear, the operational costs for natural gas plants mostly involve fuel costs, and investors can pass fuel price volatility on to consumers. In liberalized power systems where gas-fueled mid-range and peaking units frequently set the marginal price for electricity, prices for natural gas and electricity are highly correlated. Simulations presented in the Nuttall white paper [p. 140 of 240 in the pdf] show that under scenarios with tightly correlated gas and electricity prices, the net present value of a combined cycle gas turbine (CCGT) matches the net present value of a nuclear plant. In these cases, nuclear’s primary value is its ability to serve as a hedge against gas prices (in addition to providing emissions-free electricity).
Participants noted that natural gas prices and technologies currently set the benchmark for investment. Discoveries of new sources of natural gas are likely to keep gas prices relatively low for the near future, and most participants felt that over the next decade, investors are unlikely to take on new nuclear projects in the US (beyond those investors that have benefited from substantial “first mover” federal subsidies).
CO2 Reduction
P. 20 - Nationally, the abatement of one ton of CO2 requires between 1 and 12 MWh of wind generation depending on the power system and its generation mix. MISO, because of its coal-heavy generation mix, can save one ton of CO2 by replacing approximately one megawatt (MW) of its generation with wind. BPA, because of its gas- and hydro-heavy generation mix, however, needs to replace slightly more than 12 MW of its generation to save one ton of CO2. The current production tax credit for wind in the US is $22/MWh, and the pretax value of this subsidy is $34/MWh. Using a “first order” estimation based on the pretax subsidy value, the per ton mitigation costs of CO2 are $33 in MISO and $420 in BPA. The nation’s average abatement cost for one ton of CO2 is $56. [Chart below from page 108.]
Renewable Portfolio Standards
P. 38 - Currently, 29 states have some form of RPS. Most state RPS mandates have 15%–25% renewable generation by 2015–2025. When combined, these state mandates would require the installation of 60,000 MW of renewable energy by 2025. Texas has the largest installed capacity of wind generation with over 10 GW installed, and Iowa has the highest percentage of renewables in its system at 25% of installed capacity.
Renewable Incentives
P. 39 - The PTC provides a 2.2¢/kWh tax credit for electricity produced from wind and 1.1¢/kWh tax credit for electricity produced from solar for the first ten years the plants are in service. The PTC for wind will expire in December 2012, and the PTC for solar will expire in December 2013. The ITC allows solar and small wind projects to receive a tax credit equal to 30% of investment costs. The American Recovery and Reinvestment Act (ARRA) of 2009 provides taxpayers who are eligible for the PTC and ITC with a one-time cash grant in lieu of the tax credits. In total, it is projected that the cost of these credits is $5.1 billion per year. [Chart below from page 102.]
Peak/Off-Peak Generation
P. 39 - Discussions about issues with wind capacity frequently focus on not having enough power during periods of peak load. However, often the largest operational challenge associated with intermittent renewables is having too much generation. For example, on a typical spring night with high wind and low electricity demand, wind generation dispatched to comply with a mandate may unintentionally force baseload technologies (such as nuclear and coal) to ramp down. “Must-run” requirements associated with mandates do not correlate with peak wind generation (normally overnight) and peak electricity demand (normally during the day and early evening hours). As noted earlier, this translates into increased fuel requirements and higher O&M costs and emissions.
European Union’s Struggles
P. 44 - As currently implemented, however, the GHG and RPS policies in the EU both overlap. Under the current 20-20-20 policy, a change in the market price for GHGs does not move the RPS target for total energy use. Regardless of how many nuclear plants the EU builds to help reduce GHG emissions, it will still have to build renewable generation facilities to meet the RPS goal.
In addition, in the EU, the public has been told that the renewables policy will reduce GHGs. In reality, because the GHG emissions level is set independently from the level of renewables deployment, newly installed wind turbines do not directly lower the emissions cap for GHGs. Consider the fictional case of the EU securing 100% of its electricity from wind generation. If, in this scenario, the EU does nothing with the GHG cap, then other sectors (such as transportation) can emit more GHGs to take advantage of the electricity sector’s savings. Acting independently of the GHG requirement, the RPS target places downward pressure on carbon prices, depressing the development of non-renewable low-carbon and carbon-free technologies. Low carbon prices, however, do little to discourage coal and gas generation.
Technology mandates appear to be in conflict in a decision environment driven by economic efficiency. Compounding the economic conflicts, the electricity sector will pay proportionally more than other sectors for these policies. In order to help the EU reach its 20% renewables goal by 2020, the UK, for example, has committed to acquiring 15% of its total energy from renewable resources. For the electricity sector, the RPS target binds more tightly than the GHG goal because renewables cost less to implement in the electricity sector than in the transport sector. To meet the total renewables target of 20%, countries like the UK will need to lean heavily on their electricity sectors. Current estimates suggest that the UK’s electricity sector will need to acquire at least 30% of its electricity generation by 2020 from renewables to meet the RPS goal.
Cost of Grid Integration
P. 40 - The costs of wind integration have been studied by NERC, CAISO, New England ISO (ISO-NE), ERCOT, New York ISO (NYISO) and the states of Minnesota, Colorado, and Idaho. Although these discrete studies vary in scope and methodology, in general, they find that intermittent renewable generation will increase the need for regulation, load-following capacity, and ancillary services with a cost to the system ranging from $5–$20/MWh.
… some participants expressed concern that the costs of wind and its impacts on thermal generation are more highly scrutinized because, as one participant put it, wind is the “new kid on the block.”
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The report is quite a useful assessment of understanding the challenges with relying on nature. If you have the time, there are many more informative nuggets and charts in the pdf on this issue.
Comments
James Greenidge
Queens NY
Ahem...