The costs of generating electricity from various technologies is always a contentious subject, but particularly so in Ontario, where 2009's Green Energy Act entrenched a feed-in tariff (FIT) regime specifically to grow the presence of variable Renewable Energy Sources (vRES) in Ontario's high-baseload electricity system. With the new nuclear build for Darlington also prominent in a supply picture being redrawn with a new long-term energy plan, it's an important time to define the value proposition, for the public, for Ontario's generation options.
A value proposition is not solely about costs, but it's important to address the cost factors more thoroughly than the standard levelized unit costs that historically have formed the basis to compare different supply options.
The Ontario Power Authority (OPA), tasked with preparing an Integrated Power System Plant (IPSP) in 2011 presented the levelized cost estimates, from the U.S. Energy Information Administration (EIA), for a variety of new generation sources.
The 2011 EIA document provides a guide to establishing costs only if the columns containing the assumptions/parameters aren't ignored in jumping to the final column containing the levelized cost.
Firm price contracts for each unit of output, whether they are referenced as feed-in tariffs or strike prices, are easy to misinterpret as representing a levelized unit cost to a consumer, but they do not. A recent report from the Organization for Economic Co-Operation and Development and the Nuclear Energy Agency (OECD/NEA) [2] attempted to quantify "grid-level systems costs" for a variety of generation technologies in a number of countries:
These costs far exceed the EIA's 2011 levelized cost estimates for transmission investments; a great portion of the difference is in the accounting for "back up" dispatchable capacity - a shortcoming of the EIA's analysis that they tacitly admit to by 2013's estimates, when the levelized cost estimates for wind and solar are demoted to a "Non-Dispatchable Technologies" section of the table. [4]
With the increasing presence of vRES in generation mixes, the particular figures contained in full-cost estimates are not as important as understanding the elements of costs; figures are useful to establish why that is, and why an altogether different view is required to establish costs of a new generation source within a supply mix.
The estimates for "Conventional Combined Cycle" natural gas-fired generation (CCGT) are instructive"; the EIA estimates the "total system levelized cost" of $65.1/MWh based on a capacity factor of 87% leading to distribution of capital costs, operations and maintenance and transmission capital costs across a high level of production.
Ontario does not have 87% capacity factors currently, or envisioned, for it's CCGT generators. Amir Shalaby, of the OPA, delivered a presentation late in 2012 that forecast 9 TWh of gas-fired generation would be produced from 9300MW of capacity in 2015, which corresponds to an 11% capacity factor. Without dwelling on the details, in Ontario the average cost of a unit of production from CCGT generators contracted since 2004 would be ~$82/MWh at the mythical 87% capacity factor, but ~$360/MWh at an 11% capacity factor.
Examining the characteristics impacting the costing of natural gas-fired generation is relevant to discussing the value proposition of vRES (wind and solar) and nuclear; in the OPA presentation it is both increasing nuclear production and increasing vRES output that drives down the productivity of CCGT generators. This is a clear indication that new generation sources with no ability to displace "dispatchable technologies" have a poor value proposition, and in Ontario this is the case with industrial wind energy.
The wind profile being used by Ontario's system operator anticipates only approximately 13.5% of nameplate capacity to be produced by the turbines during peak summer demand periods [5]. This means that a system can only replace 13.5 MW of dispatchable capacity for each 100MW of industrial wind capacity added; that means that the value of almost all wind output can be measured as simply the cost of the fuel displaced.
In Ontario, if we assume all wind production displaces, as intended, natural gas-fired generation, the extra cost of wind is therefore the contracted rate (the vast majority of wind contracted by 2013 was contracted at a rate of $135/MWh), less the cost of the fuel not used. For 2000MW of wind capacity - approximately the contracted capacity in Ontario, this amounts to ~$490 million a year. [6]
If we count savings of displaced natural gas-fired generation equal to 13.5 (270MW), this reduces to ~$447 million per year.
Estimating avoided emissions from the displace fuel, a carbon cost of ~230/metric ton CO2 equivalent is required to justify the expense in the scenario where each unit of wind production displaces a unit of natural gas-fired generation
This seems very high considering the government of the United States recently escalated it's estimate of the social cost of carbon to only $36/metric ton, but it is a fictional "best case" figure. The actual situation is worse.
For the 12 month period from July 2012 through June 2013, the output of nuclear, hydro-electric and contracted non-utility generators exceeded Ontario demand ~29% of all hours. During those hours wind either displaced non-carbon emitting generation with low, or no, fuel costs, or there were additional cost to curtail committed generation, or carbon was displaced in a jurisdiction other than Ontario, or some combination of the above.
Over the most recent 12-month period the carbon cost required to justify the in-service industrial wind production is ~$325/ton CO2e, and the systemic cost, ignoring the significant transmission costs, over half a billion dollars.
This for 2000MW of capacity - the current plan calling for another 6000MW.
In a traditional levelized unit cost accounting the impact of adding set-priced vRES is to drive up the levelized cost of increasingly less-utilized dispatchable assets. This has lead to jurisdictions adding vRES capacity now being characterized by escalating total system capacity, escalating consumer rates, and escalating accusations that it is the traditional capacity driving the rate hikes.
If one is using an abstract levelized unit cost model, the addition of non-dispatchable, low capacity value generation has the systemic impact of driving up the levelized cost of the dispatchable high capacity value generation.
The only appropriate measurement of the cost of adding a generator to a system is the additional systemic cost resulting from the addition of that generator. For wind capacity in service in Ontario, that is over half a billion dollars annually, but the methodology won't simply expose wind as a high cost source - both solar and demand response will fare poorly in a systemic approach to estimating costs.
A value proposition is not solely about costs, but it's important to address the cost factors more thoroughly than the standard levelized unit costs that historically have formed the basis to compare different supply options.
 |
| 2011 IPSP Stakeholder Consultation Supply Presentation, Slide 39 [1] |
The Ontario Power Authority (OPA), tasked with preparing an Integrated Power System Plant (IPSP) in 2011 presented the levelized cost estimates, from the U.S. Energy Information Administration (EIA), for a variety of new generation sources.
The 2011 EIA document provides a guide to establishing costs only if the columns containing the assumptions/parameters aren't ignored in jumping to the final column containing the levelized cost.
Firm price contracts for each unit of output, whether they are referenced as feed-in tariffs or strike prices, are easy to misinterpret as representing a levelized unit cost to a consumer, but they do not. A recent report from the Organization for Economic Co-Operation and Development and the Nuclear Energy Agency (OECD/NEA) [2] attempted to quantify "grid-level systems costs" for a variety of generation technologies in a number of countries:
The results show that system costs for the dispatchable technologies are relatively modest and usually below USD 3 per MWh. They are considerably higher for variable technologies and can reach up to USD 40 per MWh for onshore wind, up to USD 45 per MWh for offshore wind and up to USD 80 per MWh for solar, with the high costs for adequacy and grid connection weighing heaviest.In Ontario, such costs have been reported at over $60/MWh for industrial wind turbines. [3]
These costs far exceed the EIA's 2011 levelized cost estimates for transmission investments; a great portion of the difference is in the accounting for "back up" dispatchable capacity - a shortcoming of the EIA's analysis that they tacitly admit to by 2013's estimates, when the levelized cost estimates for wind and solar are demoted to a "Non-Dispatchable Technologies" section of the table. [4]
With the increasing presence of vRES in generation mixes, the particular figures contained in full-cost estimates are not as important as understanding the elements of costs; figures are useful to establish why that is, and why an altogether different view is required to establish costs of a new generation source within a supply mix.
The estimates for "Conventional Combined Cycle" natural gas-fired generation (CCGT) are instructive"; the EIA estimates the "total system levelized cost" of $65.1/MWh based on a capacity factor of 87% leading to distribution of capital costs, operations and maintenance and transmission capital costs across a high level of production.
Ontario does not have 87% capacity factors currently, or envisioned, for it's CCGT generators. Amir Shalaby, of the OPA, delivered a presentation late in 2012 that forecast 9 TWh of gas-fired generation would be produced from 9300MW of capacity in 2015, which corresponds to an 11% capacity factor. Without dwelling on the details, in Ontario the average cost of a unit of production from CCGT generators contracted since 2004 would be ~$82/MWh at the mythical 87% capacity factor, but ~$360/MWh at an 11% capacity factor.
Examining the characteristics impacting the costing of natural gas-fired generation is relevant to discussing the value proposition of vRES (wind and solar) and nuclear; in the OPA presentation it is both increasing nuclear production and increasing vRES output that drives down the productivity of CCGT generators. This is a clear indication that new generation sources with no ability to displace "dispatchable technologies" have a poor value proposition, and in Ontario this is the case with industrial wind energy.
The wind profile being used by Ontario's system operator anticipates only approximately 13.5% of nameplate capacity to be produced by the turbines during peak summer demand periods [5]. This means that a system can only replace 13.5 MW of dispatchable capacity for each 100MW of industrial wind capacity added; that means that the value of almost all wind output can be measured as simply the cost of the fuel displaced.
In Ontario, if we assume all wind production displaces, as intended, natural gas-fired generation, the extra cost of wind is therefore the contracted rate (the vast majority of wind contracted by 2013 was contracted at a rate of $135/MWh), less the cost of the fuel not used. For 2000MW of wind capacity - approximately the contracted capacity in Ontario, this amounts to ~$490 million a year. [6]
If we count savings of displaced natural gas-fired generation equal to 13.5 (270MW), this reduces to ~$447 million per year.
Estimating avoided emissions from the displace fuel, a carbon cost of ~230/metric ton CO2 equivalent is required to justify the expense in the scenario where each unit of wind production displaces a unit of natural gas-fired generation
This seems very high considering the government of the United States recently escalated it's estimate of the social cost of carbon to only $36/metric ton, but it is a fictional "best case" figure. The actual situation is worse.
For the 12 month period from July 2012 through June 2013, the output of nuclear, hydro-electric and contracted non-utility generators exceeded Ontario demand ~29% of all hours. During those hours wind either displaced non-carbon emitting generation with low, or no, fuel costs, or there were additional cost to curtail committed generation, or carbon was displaced in a jurisdiction other than Ontario, or some combination of the above.
Over the most recent 12-month period the carbon cost required to justify the in-service industrial wind production is ~$325/ton CO2e, and the systemic cost, ignoring the significant transmission costs, over half a billion dollars.
This for 2000MW of capacity - the current plan calling for another 6000MW.
In a traditional levelized unit cost accounting the impact of adding set-priced vRES is to drive up the levelized cost of increasingly less-utilized dispatchable assets. This has lead to jurisdictions adding vRES capacity now being characterized by escalating total system capacity, escalating consumer rates, and escalating accusations that it is the traditional capacity driving the rate hikes.
If one is using an abstract levelized unit cost model, the addition of non-dispatchable, low capacity value generation has the systemic impact of driving up the levelized cost of the dispatchable high capacity value generation.
The only appropriate measurement of the cost of adding a generator to a system is the additional systemic cost resulting from the addition of that generator. For wind capacity in service in Ontario, that is over half a billion dollars annually, but the methodology won't simply expose wind as a high cost source - both solar and demand response will fare poorly in a systemic approach to estimating costs.
Notes
[1] 2011 IPSP Stakeholder Consultation Supply Presentation | Amir Shalagy | May 31, 2011, Slide 39.
[3] Omitted Costs, Inflated Benefits: Renewable Energy Policy in Ontario | Parker Gallant and Glenn Fox | Bulletin of Science Technology & Society published online 30 September 2011
[4] Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013 | US. Energy Information Administration
[5] The calculation is done using the summer figures provided by the the IESO in table 4.1 of their 18-Month Outlooks.
The figure is questionable as the actual wind output is often below that level.
[6] assumptions/figures used in estimates:
13.5% capability factor for industrial wind (expected output during peak summer demand periods)
$13,187/MWmonth net revenue requirement (NRR), or capacity payment, for natural gas-fired generation - from The High Costs of Ontario's very provincial electricity debacle
$4/MMBtu natural gas price
7.5 Heat rate
$135/MWh contracted cost for wind turbine output
30% annual capacity factor for wind turbines
398 kg/MWh of CO2 equivalent emissions from natural gas-fired generation
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