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How do you compare generation choices?

November 21, 2017

In our workshops we spend an entire section of the day understanding and comparing different types of generation options (as well as demand side management options).  How do we do this fairly and come up with apples to apples comparisons—for example, how does solar generation compare to natural gas generation?  We present and discuss many ways one could compare these different technologies:  Which is the least cost to build or to run?  What is the most reliable?  What’s the most flexible?  Which is the cleanest or dirtiest?  Which uses the least water or uses the least amount of space?  It’s a very enlightening unit for everyone.


Cost is where most people go first and there are multiple ways to compare costs.  The most common method is called “Levelized Cost Of Energy” (LCOE), but there’s also “Levelized Avoided Cost of Energy” (LACE) or marginal cost measures to compare the value of different generation resources.  Discussions about each one of these approaches can quickly get in the weeds, so let’s focus on what they are, how they are different, and how they might be used.


Levelized Cost of Energy (LCOE) is a method used to compare the all-in COSTS of building and running a type of generation technology over a unit’s expected life.  What are the anticipated capital costs to build the unit, costs to acquire the site, the operational costs to run the generation resource, the costs to connect it to transmission, fuel and other variable costs, etc?  LCOE also looks at the operational realities of each of the different types of generation:  what percentage of time will it be producing energy during a standard time frame (its capacity factor).  Ultimately, the amount of energy (Megawatt-hours) it is capable of producing over its expected lifetime is then divided by its all-in lifetime costs, calculating a cost in $ per megawatt-hour that can than be used in apples to apples comparisons.  LCOE is a traditional method which has been used for many years by utility planners to determine what the least cost generation types might be to serve the future load needs of their customers.  The US Department of Energy’s Energy Information Adminstration (EIA) regularly publishes LCOE numbers for the US.  In addition, private companies, such as Lazard, put out some well-regarded LCOE reports.


But what if a project developer or independent power producer is looking to develop generation in order to sell it into one of the organized electricity markets or sell through a Public Utility Regulatory Policy Act (PURPA) contract and make money?  They might use a Levelized Avoided Cost of Energy (LACE) method.  It’s called avoided cost because it will look at the VALUE of grid costs AVOIDED by using the new generator instead of the status quo.  That is, if the unit is built, will it be called upon (dispatched) by the market operator to provide energy or capacity (via a capacity payment) or other grid services and how much will it be paid for those services over its running lifetime.  Developing an accurate market model and forecast is difficult and will be specific to each organized energy market, but necessary in order to get a true picture of the expected payment streams.  All of the value is then added up and divided by the number of expected generation hours, so a $ per megawatt-hour measure again will be determined.  The ultimate value (or potential profit) for a developer will be the LACE value minus the LCOE (cost of building and running the generation).  Is the net value high enough to go forward with the project?  That will be up to the developer.  Different conditions in the organized markets will also make some projects viable in one market versus another, so it may make sense to build a utility scale solar project for the California market and not for the PJM market, as an example.


What about comparing the value of different generation resources once they are already built and running?  This is where “marginal costs” might come in.  Very simply, the marginal cost of energy is the cost to produce one more unit (i.e. one more megawatt-hour, one more kilowatt-hour…) of energy.  It includes the fuel and operational costs that the generator would incur if it needed to add that additional unit of energy to the grid.  As one might imagine, renewable resources such as solar or wind or hydro have very low marginal costs ($0 fuel costs and little, if any, operational costs) of energy compared to traditional fossil or nuclear fueled resources.  BUT what if that generating resource is already producing its maximum energy?  Then the marginal costs would have to include the capital costs of putting in the next increment of a new generator to meet that increment of energy (i.e. adding another wind turbine, solar panel, or gas turbine).


The reality of today’s electric operations means that the industry is not just comparing the choices of generating more energy, it is also comparing whether energy should be generated versus whether customer load should be postponed or eliminated through demand management solutions (such as demand response, energy efficiency, and flexible loads).  When market generation resources begin to get scarce and marginal energy costs go up, demand management solutions become more cost- and operationally-effective.  Beyond cost benefits, when demand management solutions are employed, less generation resources are being used, and therefore there is less generator wear and tear, less water being used, and less emissions going into the air.


Moreover, while the industry tends to focus on cost to compare different types of generation there are a great number of other aspects which could be considered to gain greater understanding of generation and demand management choices.  In our workshops, we also highlight the space requirements, water requirements, siting requirements, regulatory challenges, operational issues, and green house gas emissions of each of the generation types to provide a more balanced view of the choices for operators and developers.

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