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THE VALUE OF FLEXIBILITY WHEN 5 MINUTES MEANS MILLIONS

Republished with permission from CyberTech, Inc.http://www.energycentral.com is a hub on the Internet for electric power professionals searching for  information, products and services related to the energy industry. By teaming with companies that service the energy industry, Energy Central provides a broad base of information products - news, directories, events, databases, books, periodicals, reports - all focused on a single industry and all accessible from a single site on the World Wide Web. If your job requires you to know what's happening in the electric power industry, Energy Central is the site where you begin.

Weather, line congestion, generator outages and the inherent variability of renewable energy lead to instability in the supply of electricity, which leads to volatile energy prices. If price events are foreseen hours in advance slower resources can be called upon to fill the need, but often the events happen with little to no warning. The speed with which the balance of fleet can attend to fluctuations can have a dramatic impact on the outcomes, from the cost of a portfolio to serve load all the way to the profitability of individual generators. How volatility is viewed differs from market to market, but in all cases flexible capacity adds value.


California, for example, intends to meet or exceed its renewable portfolio standard of 33% by the year 2020 with a substantial portion of its need met by solar. As solar wanes with sunset, the CAISO system will need to meet average net load ramps of 12GW or more across approximately 3 hours. This could lead to the impression that a fleet of combined cycles would be sufficient to meet ramping needs.

However, volatility at shorter time intervals cannot be met with resources that take 1 to 3 hours to respond. CAISO anticipates 15 minute ramps exceeding 2 GW, which can only be met by agile, fast response assets. CAISO needs flexible capacity to support renewable integration.

California, for example, intends to meet or exceed its renewable portfolio standard of 33% by the year 2020 with a substantial portion of its need met by solar. As solar wanes with sunset, the CAISO system will need to meet average net load ramps of 12GW or more across approximately 3 hours. This could lead to the impression that a fleet of combined cycles would be sufficient to meet ramping needs.

However, volatility at shorter time intervals cannot be met with resources that take 1 to 3 hours to respond. CAISO anticipates 15 minute ramps exceeding 2 GW, which can only be met by agile, fast response assets. CAISO needs flexible capacity to support renewable integration.


ERCOT (Texas) intends to maintain capacity reserve margins by allowing price volatility in the market, placing high caps on energy prices ($9,000/MWh) and using price adders when the available capacity gets tight. The economic expectation is that the price cap will only be reached several times a year, but the revenues for on-line generators during price events will stimulate investment and maintain adequate reserve margins. In the majority of cases these price events occur in the 5-minute real time (RT) market, which can be leveraged by fast, flexible generation. ERCOT relies on volatility to stimulate investment, and flexible capacity is best suited to maximize revenues in such an environment.
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Joseph Ferrari - Contact

  Joseph Ferrari

   Market Development Analyst
   Wärtsilä Energy Solutions
   
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CAISO and ERCOT are two examples, but pricing volatility across all markets can only be expected to increase with looming coal retirements, expansion of wind, utility scale and rooftop solar, and as transmission systems get ever more constrained. Flexible gas-fired capacity will be tasked with meeting a large part of new capacity additions, the question is how can market participants leverage this volatility? The answer lies in flexible capacity (see insert).



Volatility is a central feature of electricity markets,
impacting the profitability investors
realize from their power plants or portfolios




SPP 
– Load serving entities (LSEs) in SPP must have enough capacity to serve their load + required system margin. An investment in gas generation would allow the LSE to choose to serve load through self-generation or through market purchase. Self-generation could imply energy sale into the day ahead (DA), 5-minute real time (RT) and/or participation in Ancillary Service (AS) markets (e.g., Spin or Regulation). Looking at the first full year of market data from SPP, a 200 MW investment in flexible Wärtsilä ICE capacity would earn a positive net cash flow of 8 MUSD, with 5 MUSD of that total attributable to the ability of ICE technology to be dispatched economically in the 5-minute real time market. That is; being dispatchable in 5 minutes literally means millions in revenue. No other gas-fired technology can match this performance (for example, popular gas-turbine alternatives dispatched into the

ERCOT
– While one of the goals of an LSE is to minimize costs, the goal of an Independent Power Producer (IPP) is to maximize profits. A good gage of profitability is the internal rate of return on equity (leveraged IRR). Flexible ICE plants can participate in energy (DA and RT) and ancillary service markets to provide the greatest profitability for investors. An investment in Wärtsilä ICE assets with 30% equity would have net IRR (across market years 2011-2014) of 22.5% (8.5% from DA, and 14% from flexible market operations in RT and AS markets) more than double that of the most common alternative technology considered (lower cost industrial gas turbines). Investors in ERCOT want to capitalize on (or sell a hedge against) the occurrence of highly volatile price spikes. The conventional thinking is to invest in units with the lowest possible capital cost. The numbers show, however, that the lowest capital cost option is not the most profitable. Units with greater flexibility and lower operations costs provide greater return on investment!

PJM – Across the years 2011-2014 Independent Power Producers in the PJM market would have enjoyed equity IRRs for large scale (300+ MW) flexible Wärtsilä plants of 37% (11% from DA, and 26% from flexible market operations in RT and AS markets), or approximately double that of a comparable sized advanced gas turbine combined cycle (CC). A Wärtsilä plant would run an average of 5000 hours/year, only slightly lower than the 5900 hours expected for a combined cycle. While the CC dispatches primarily for energy in the DA market based on low marginal cost, the Wärtsilä plant dispatches against DA, RT and Ancillary Service markets. Similar to the SPP and ERCOT markets, substantial run hours and revenues from the RT market are attributable to 5-min start, no restrictions on dispatch, and zero start cost. Ancillary service revenues are made possible by the high part load efficiency and low minimum loads of the Wärtsilä plant. In regions such as PJM and NYISO with active capacity markets Wärtsilä assets are an attractive investment for IPPs in comparison to other gas-fired technologies, including combined cycles.


Market-Cases



Key Features

• Full load in 5 minutes or less (for true dispatch in 5-min real time markets)

• Minimal to no restrictions on run up/down time (units can jump in/out of the market as needed)

• No maintenance impact from frequent starts (units can dispatch multiple times per day with no economic penalties).

• Minimum stable loads of 30% less.(maximizes the ramp capacity for A/S).

• High efficiency at full and part load

• Modular (10 or 20 MW unit sizing for plants up to 500+ MW)

• Investment cost competitive with alternative technology choices

• Established technology: GW of installed references and decades of experience

• No water consumption



  WHY IS FLEXIBILITY SO VALUABLE



 

This video will answer that question and explain the logics behind the new business case! Have a look yourself and see why Smart Power Generation and sub-hourly Real Time markets are the perfect match!



Taking the Long View – Resource Planning

Some load serving entities such as Investor Owned Utilities (IOUs) evaluate investment decisions in a long-term integrated resource planning context (IRP), which is different than simply evaluating the economics of alternatives for a given project. In the IRP context, utilities evaluate their portfolio across multi-year horizons taking load growth, retirements, reliability constraints and mandates on renewable energy into account simultaneously. The goal is to determine the type and timing of new capacity investments that minimizes total net present value (NPV) of capital and operations costs across the 10 or 20 year horizon.

We evaluated a west coast California IOU across a planning horizon 2013-2022. This utility has approximately 30 GW of capacity (in 2012) with 6 GW of steam-boiler retirements occurring and a buildout of solar and wind to meet 33% RPS obligations for the year 2020. We used advanced chronological long term planning, an approach found in state of the art simulation tools such as PLEXOS and AuroraXMP (as opposed to more traditional load duration curve approaches). This choice of modeling technique was significant in that it is the only class of models that can inherently account for net load volatility and the associated costs in a long term capacity expansion plan. Systems approaching 20% or higher annual provisions of energy from wind/solar tend to be net-load driven systems with significant net load ramping. In the case of the chosen CA utility, net load ramps in excess of 6 GW/hour were expected in shoulder months starting in 2020. Two scenarios were explored. The first assumed the only new-build simple cycle gas-fired options were the traditional lineup of industrial and aeroderivative gas turbines. The second assumed all of the same gas-turbine options only now the model could also select one more option, Wärtsilä gas-fired ICE capacity.

Simply adding Wärtsilä capacity to the pool of potential newbuild choices allowed the utility to meet load and reserve obligations with 10% less new capacity and with NPV savings of 900 MUSD across the 10 year horizon.

The 900 MUSD savings was due to a number of factors. Less capacity was needed as the exact amount of capacity could be installed in approximately 10 or 20 MW increments, without the “lumpy investment” problem associated with larger power blocks. The installed ICE capacity was more efficient and flexible than alternative GT solutions and was able to attend to net load ramping more effectively from a part load state. This, in turn, freed up the most efficient assets in the fleet, the combined cycles, to attend to energy provision. Without the flexibility provided by Wärtsilä the CCs would otherwise be cycling, starting and stopping more often, increasing costs and reducing overall system efficiency. With the ICE capacity additions, the entire portfolio for the utility became more efficient, as manifested by a 1.5% reduction in CO2 generation. Flexible Wärtsilä capacity optimizes utility portfolios and yields substantial longterm savings.

 




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