The role and economic viability of different kinds of power plants involves highly interdependent value propositions because decisions affecting installed capacity of one type of power plant affects the break-even cost of production for many if not all of the others.
This primer to optimizing the system average (levelized) cost of electricity production is divided into two segments.
Part I (today) suggests that most of our electricity generators fall into one or both of two general categories, serving two basic roles or “essential market segments.” A third type is also defined and discussed. The post suggests an importance of optimizing the utilization rate of both existing and new generating resources, and that the amount of such importance corresponds to the extent and duration a resource has fixed costs.
Part II (tomorrow) discusses in more detail the third category of generators and how the design and operational characteristics and market share of plants in that category influence the breakeven cost of electricity from the primary types described in Part I. Part II will establish terms of comparative value between the third type and the first two types by process of elimination using the major components of cost as described in the EIA Forecast Levelized Cost report.
Part II then suggests how the thesis from parts one and two could be superimposed onto regulatory decision making for long-term system planning with the goal of making the U.S. as competitive as possible in energy intensive manufacturing, while contributing to the stability of, and potential increase in, standard of living for American citizens.
It is hoped that this post will help policymakers as well as the interested lay public understand what is so unique about electricity: that instantaneous production to match usage is required, given that the cost of electricity storage is very high and impractical to scale up for longer time periods. This is why certain forms of power generation are so valuable versus other forms. Specifically, forms whose fuel supply (timing and location) is not under human control must be valued according to the system costs they can avert on net, or the technologies avoided entirely if electricity rates are to remain a competitive tool for the U.S. economy and its citizens’ standards of living.
Some readers will notice herein some unqualified simplifications. As such, the concepts discussed here do not necessarily correspond with current system operator energy and capacity auction constructs or outcomes. I expect most of the simplifications advanced readers observe are intentional on my part. These simplifications have been made to:
PART 1: Electricity generating resources (power plants) fall into two basic categories: base-load (full-time-capable) and load-following (responsive / part-time-capable)
I. Baseload Resources
Resources designed and constructed to run almost all the time at or near their rated capacity are known as “base-load resources.” A hallmark of this class of generators is the requirement they have access to a secure, steady and reliable source of fuel to power them. There are three major fuels in use today and three corresponding types of major base-load power plants important to the grid and to this discussion. Coal, enriched uranium and natural gas are the fuels. We will refer to the plant types as coal, nuclear and combined cycle gas turbines, or “CC Gas” for simplicity.
The U.S. Energy Information Administration (EIA) lists the near-full-time capability of these generator types in its annual forecast using a measure called capacity factor (CF). While EIA uses the measure as predictive, CF is typically a historical measure defined as the energy a generator produced over a year compared to its theoretical maximum output, displayed as a percent. The theoretical maximum is the nameplate capacity (usually stated in megawatts (MW)) times 8,760, which is the number of hours in one year.
CF = MWh per year / (nameplate MW * 8,760)
No generators achieve a 100% capacity factor because they all have to shut down or slow down for maintenance, refueling, to address unexpected malfunctions, or because electricity demand is sometimes not high enough to warrant them running at full power.
The U.S. Department of Energy’s Energy Information Administration (EIA) forecast uses the term a little differently. They don’t list it as a historical measure. Instead they use it to mean the highest utilization rate a class of generators could achieve in the absence of competition. They then use this specially-defined capacity factor to estimate “levelized cost” of electricity from a hypothetical new generator coming on line five years into the future.
EIA lists the capacity factors that could be achieved under “ideal market conditions.” That is, if a base-load generator served an unlimited steady demand level, how much output, could it produce in a year compared to its theoretical maximum (nameplate capacity times 8,760). EIA arrives at the following levels for the major base-load capable technologies: 
Coal: 85%; Nuclear: 90%; CC Gas (conventional or advanced): 87%; CT Gas (conventional or advanced): 30%
It is worth offering here that an analysis of the Federal Energy Regulatory Commission (FERC) Form 1 filings databases indicates fleet-average capacity factors for several existing generator types are substantially lower than those assumed in the EIA Forecast. Specifically:
Coal: 62%; CC Gas: 45%; CT Gas: 5%
To the extent we rely on new or existing dispatchable, base-load capable resources with high fixed costs in future years, the increasing presence of wind electricity would increase the cost of electricity paid by consumers.
Existing nuclear units actually exceed the 90% level as a fleet today, with some units achieving into the low to mid 90% range.
II. Load-following Resources
Resources designed to or which actually run only occasionally or at partial output are called “load following” or “peaking” resources. These also require a dependable source of fuel whenever such fuel is requested, and especially at times when electricity demand is expected to reach annual or season highs. Load following and peaking resources can generally be turned on/off and up/down quickly, and so play a vital role ensuring the proper amount of electricity is produced as society’s demand fluctuates moment by moment, hour by hour, day by day and season by season.
Many coal and CC gas units do provide some load following (a role which by itself reduces their achievable annual capacity factor). A fourth type of facility called “simple cycle combustion turbines” or “combustion turbines,” are a staple provider of capacity when demand levels are high or increasing rapidly. These also provide stability to the voltage and frequency of electricity flowing through the transmission system at various points. This is especially important when electricity demand changes too rapidly for other generators to keep up with or when a large generating plant experiences an unexpected outage. The most common fuel for CT plants today is natural gas although many CTs are designed to run on petroleum products such as diesel fuel or a blend of hydrocarbon fuels if and when fuel prices or supply constraints make it prudent or necessary to do so.
EIA considers the “ideal” or “maximum achievable” capacity factor for CT gas plants to be 30%. Load following and peaker units ensure we have enough electricity at high demand times and keep the power quality within acceptable tolerances as supply and load dynamics dictate. They aren’t as fuel efficient. Combined with the fixed cost of building them, and then using them at low capacity factors, these characteristics dictate that electricity from them is relatively expensive compared to electricity from base-load resources.
III. Summary of I and II
Baseload resources do the heavy lifting, providing about 70% of all electricity. To the extent base load resources are run at relatively steady output and at high annual capacity factors they keep system average electricity costs, heat rates and emissions low. CT gas is the main provider of peaking capacity and steep load following generation. The four generator classes (coal, nuclear CC gas and CT gas) discussed to this point provide about 85% of all electricity.
The combined shaded areas in this representation show electricity demand (load) over a one week period in a typical US grid control region during August, 2013. The raspberry shaded area illustrates the amount of full-time demand on the system over that week. The blue shaded area represents demand which is present less than 100% of the time period and so must be met with generators that are varying their output and/or operating at partial capability.
IV. Intermittent Resource: Hydro
Another 7% of all our primary electricity is generated by hydro resources. Hydro resources have different capabilities on various time scales depending on:
Hydro impoundment reservoirs (as well as any higher elevation melting snow pack feeding a watershed used by a hydro facility) can be thought of more or less as sources of short to medium-term “on location fuel storage.” Reservoirs provide firm storage as long as the watershed provides a rate equal to or greater than the plant’s usage rate, while snow pack represents a forecast resource for months when melting is expected to occur.
Hydro generators use the force of gravity and the weight of a column of water to generate power. In general, the higher in elevation the water is above the generator (i.e. the height/weight of the column of water), the more power can be generated per gallon of water. For that reason the economics of hydro facilities tend to be more favorable in mountainous or regions.
From year to year, season to season and even week to week, even with large dams impounding vast quantities of water, the fuel supply (water) is not as dependable and controllable by human intervention as the fuels coal, enriched uranium and natural gas. For this reason, the EIA classifies hydro as a separate – our third – type of power plant; an “intermittent resource.” However, hydro power plants with impoundment can be relied upon over periods of days, weeks and sometimes much longer to provide either full-time or load following output.
V. Intermittent Resource: Wind
Another intermittent resource is wind electricity. The fuel in this case is moving air currents. While water can be impounded and along with mountain snow melt can provide some inventory of fuel for hydro, wind currents cannot be controlled at all and often vary widely hourly, daily and seasonally – even across large grid management zones of the US. Generation from wind turbines can be slowed down or shut off, of course, if they “are not needed,” but if wind currents are not available when electricity demand is high, there is nothing anyone can do to deliver more fuel at that time, nor that anyone could have done to “save up some wind” for use when needed.
Unfortunately wind as fuel is generally least available at periods of highest electricity demand, and most available at times of moderate or low electricity demand. For these reasons, wind turbine energy can be a fuel substitute, but is an extremely poor conventional power plant (capacity) substitute. In fact, in general approximately the same number of “dispatchable” power plants will be needed on a system regardless of how many wind turbines are operating across that system.
Adding wind electricity, therefore, saves some fuel cost but at the same time reduces the capacity factors of the plants whose fuels have been displaced by wind currents.
The more wind turbines operating on a system, the lower must be the capacity factors of base-load capable power plants on that system.
VI. Other Considerations
Capacity factors influence the economics of base-load capable resources
Operating a plant at or near its maximum output almost all the time offers an inherent cost advantage in the most basic micro-economic terms. As a plant produces more and more electricity over a given time period (such as a year), the ongoing fixed costs of construction debt repayment (initial mortgage) and upgrading and maintaining that plant will be spread out across more and more units of electricity sold, lowering the fixed cost per unit of electricity. Simple enough: whether over a year or a lifespan breakeven cost per unit of electricity produced falls as facility utilization rate (CF) rises. Compensation to cover the break-even cost and provide for profit is important, but not pertinent quite yet. Let’s just focus on the cost of generating electricity for now.
Utilization economics afford efficiency and environmental improvements
The cost advantage of operating base-load resources most of the time at or near their maximum output rating has an additional benefit beyond simply offering long-term financial solvency to ensure repayment of the original construction loan. Low fixed costs per MWh lower the electricity cost impact of additional investment in fuel efficiency that might be considered by or required of a power plant developer. Such fuel efficiency investments, in turn, lower variable costs per unit of electricity produced. Elementary: Consume less fuel per unit of electricity produced; the cost to produce it goes down. This is the true essence of economy of scale.
Incremental investment in emissions-reducing equipment tends to work the other way, raising a resource’s “heat rate” (measured in Btu/MWh) – which has the same meaning as “lowering fuel efficiency.” But the same economies of production scale apply: if a plant can sell more units of electricity annually, any voluntary or required emissions control investments become less painful to ratepayers. If we could truly count on running (more expensive but cleaner) plants more of the time over their financial repayment lifespans, the cost of making them cleaner would be considerably less.
Tom Stacy is a citizen intellectual activist and Ohioan for Affordable Electricity. His previous posts at MasterResource can be found here.