Overview

For many decades, the companies that operated electricity grids had to do so with two objectives in mind: reliability (keeping the lights on) and cost (keeping electricity affordable). Despite the complexities of the electric grid, these two objectives were relatively simple to meet, in part because the regulatory system shifted a lot of the financial risk away from companies and onto ratepayers. It isn’t that hard to keep a power grid reliable by overbuilding it.

This lesson builds on the previous two objectives by adding a third to power grid operations – lowering the environmental footprint of power generation by adding large amounts of low-emissions generation resources. This is, very broadly, sometimes called the “renewable integration” challenge. The technical challenges in maintaining the balance of supply and demand are immense, but our focus is on the economic challenges, particularly in the context of electricity deregulation.

Learning Outcomes

By the end of this lesson, you should be able to:

• Define the term “Variable Energy Resource” (VER)
• Explain three reasons why large-scale power generation from VERs poses an economic challenge to the electricity industry, not just a technical challenge
• Identify the various types of ancillary services that electric system operators require to maintain reliability, and identify those that are likely to be particularly important for VER integration
• Explain capacity payments and the rationale for having separate payments for electric capacity and electric energy
• Explain how demand-side resources could participate in deregulated electricity markets

Reading Materials

There are a lot of good resources that describe the renewables integration challenge. We will lean on external readings more heavily in this lesson than in previous lessons.

• Carnegie Mellon University Scott Institute for Energy Innovation (2013). Managing Variable Energy Resources to Increased Renewable Electricity's Contribution to the Grid.
• Cardwell, D. (Aug. 15, 2013). Grappling with the Grid: Intermittent Nature of Green Power is Challenge for Utilities. New York Times.
• Reed, S. (Dec. 25, 2025). Power Prices Go Negative in Germany, a Positive for Energy Users. New York Times.
• Hittinger, E. (2012). Chapter 4: The Effect of Variability-Mitigating Market Rules on the Operation and Deployment of Wind Farms. In Energy Storage on the Grid and the Short-term Variability of Wind. [Doctoral Dissertation, Carnegie Mellon University.] The important part of this chapter is the discussion of different renewables integration policies around the world. Note that the link goes to the entire document but that you are required to read only Chapter 4.
• National Energy Technology Laboratory (2013). Ancillary Services Primer. This short paper describes different types of ancillary services and how generation companies can compete to provide these ancillary services. For related, optional reading, download this Power Market Primers ZIP file.
• Rocky Mountain Institute (n.d.). The Economics of Grid Defection. The report as a whole is worth a read, but the four-page summary captures the main points.
• Please watch the following video interview. If the video is slow to load on this page, you can always access it and all videos via the Media Gallery in Canvas.

Video: Interview with Liz Cook (43:29)

What is due for Lesson 12?

This lesson will take us one week to complete. Please refer to the Course Calendar in Canvas for specific due dates. Specific directions and grading rubrics for assignment submissions can be found in the Lesson 12 module in Canvas.

• Complete all of the Lesson 12 readings and viewings, including the lesson content
• Participate in the Zoom discussion
• Complete Quiz 9
• Project work - Electricity Market Sensitivities

Questions?

If you have any questions, please post them to our Questions? discussion forum (not email). I will not be reviewing these. I encourage you to work as a cohort in that space. If you do require assistance, please reach out to me directly after you have worked with your cohort --- I am always happy to get on a one-on-one call, or even better, with a group of you.

Before you get into the details of the lesson, please have a look at the following story from the New York Times about wind farms in Vermont: Intermittent Nature of Green Power is Challenge for Utilities.

Figure 12.1: A wind farm

Credit: Photo byKarsten Würth on Unsplash

As you are reading the story, think about the following questions (these would apply to solar as well as wind, but since the story is specifically about wind, we’ll pick on wind to frame the questions). Clearly, the integration of wind into the Vermont electric grid (which is interconnected to the rest of the New England grid) has not gone as smoothly as we might have hoped.

• Why does one wind farm in Vermont represent a challenge for ISO New England, which is the RTO that operates the electric transmission system in all six New England states (not just Vermont)? Isn’t this one wind farm too small to have much of an impact, relative to the entire New England power grid?
• What has ISO New England done in response to that challenge?
• How have other generation resources within Vermont or the New England grid been impacted?
• What is the impact of ISO New England’s operational rules and market structures on the financial viability of wind energy in Vermont? Of other generators in New England, given increasing wind penetration in the New England grid?
• Do you see any conflicts or complementarities between ISO New England’s operational rules and the desire of states within the ISO New England footprint to increase their utilization of renewable energy? The tension between RTO rules and state energy policy is a complex legal issue that is affecting many areas right now, not just one small state in New England.

Please read the “Overview” section (through page 14) from " Managing Variable Energy Resources to Increase Renewable Electricity’s Contribution to the Grid."

The terms “renewable energy resources” and “variable energy resources” are often used interchangeably when applied to electric power generation. The two are, in fact, not the same, although there is some overlap. The term “Variable Energy Resource” (VER) refers to any generation resource whose output is not perfectly controllable by a transmission system operator, and whose output is dependent on a fuel resource that cannot be directly stored or stockpiled and whose availability is difficult to predict. Wind and solar power generation are the primary VERs  since the sun does not shine all the time (even during the day, clouds and dust can interfere with solar power generation in surprising ways) and the wind does not blow all the time. In some cases, hydroelectricity without storage (so-called “run of river” hydro) could be considered a VER since its output is dependent on streamflows at any given moment. VERs are, in some sense, defined in relation to so-called “dispatchable” or “controllable” power generation resources, which encompass fossil-fuel plants, nuclear, and some hydroelectricity (with reservoir storage). The VER concept is pretty vague if you think about it – after all, coal or natural gas plants can sometimes break and so don’t have perfect availability. Fuel supply chains can also be disrupted for fossil plants. In addition, the “variable” aspect is, at least in concept, nothing new for system operators. Demand varies all the time and system operators are able to handle it without substantial negative impacts.

Keep in mind that the “variability” of VERs is different over different time scales. Figures 7-9 of “Managing Variable Energy Resources to Increase Renewable Electricity’s Contribution to the Grid” show how wind and solar are variable over time scales of days or fewer. Figure 12.2, below, shows wind energy production in the PJM RTO every five minutes over a period of two years. This figure shows how wind production varies seasonally and also inter-annually, with windier and less windy years.

Figure 12.2: Wind energy production in PJM, 2008 and 2009.

Credit: PJM data.

Variability with respect to electricity demand is also important. If you think about it, electric system operators don’t really care about variability in demand or in VERs per se – what they care about is being able to match supply and demand on a continuous basis. If variability between VERs and demand were perfectly synchronous, so that VERs would increase (or decrease) in output right at the moments when demand increased or decreased in output, then there would be no problems. If VERs and demand are anti-correlated or perfectly asynchronous, that poses more of a challenge. Part of the challenge with the wind in Vermont, as you have read, is that the wind tends to blow most strongly at night when there is less electricity demand and the power plants that are serving that demand are inflexible “base load” units that are difficult to ramp down. This is typical of wind – Figure 12.3 shows (normalized) wind and electricity demand by season in the PJM RTO. Solar, on the other hand, is much more highly correlated with electricity demand (at least on a day-to-day basis).

Figure 12.3: Normalized wind energy production and electricity demand in PJM, 2009.

Credit: PJM data.

Whether or not you believe that there is anything “special” about VERs, electric grid operators around the world are rethinking the way that they plan and operate their systems and markets in order to accommodate various forms of policy that are promoting investment in VERs. Read the introductory portion of Chapter 4 of Energy Storage on the Grid and the Short-term Variability of Wind and pp.15-20 of “Managing Variable Energy Resources to Increase Renewable Electricity’s Contribution to the Grid,” which discuss various types of strategies that grid operators have been using to manage large-scale VERs on the grid. As you may have gathered from the Vermont article, some of the control strategies used most often by grid operators (such as manually curtailing wind energy output during periods when supply exceeds demand) have also been the most controversial.

More generally, there are three economic challenges relevant to VER integration, each of which we will discuss in a bit more detail.

1. VERs tend to depress market prices for electric energy, sometimes even producing negative prices. These negative prices make some economists cringe but are completely sensible in the world of electricity. Remember from Lesson 11 that the Locational Marginal Price (LMP) at a specific location in the grid reflects the cost of delivering electricity to that location. If there is more demand than supply at a given location and the transmission grid is constrained, the LMP at that location will be high. But if there is more supply than demand at a given location, which could happen when there is more wind or solar energy produced than the grid can absorb, then the opposite effect happens with the LMP at that location and the LMP will become negative. This is good for consumers, but not so good for power producers (both conventional generators and VERs). While this has certainly been a challenge for states in the U.S. that have seen rapid growth in wind and solar (primarily California and Texas), it is by no means a challenge specific to the United States. Germany, which has been very aggressive towards a renewable power generation transition, has seen a rise in the frequency of negative prices, which is great for consumers (hey, you get paid to use cheap green electricity) but terrible for power generation companies. A solution to this challenge in some areas has been to establish “capacity” payments that are designed to make generators whole financially and keep power plants from retiring too early. You can see a nice animation of electricity prices, including when prices go negative, in this picture for the Texas grid, known as ERCOT.)
   The emergence of low-cost solar photovoltaics and energy storage presents an additional challenge to the business models of electric utilities. This is more complex than the disruptive competition that new technologies can generate, because the electric utility has a regulatory mandate to provide universal service at high reliability. If solar PV and energy storage steal business from the utility, then the social question arises of whether we find ways to continue to pay for the electric grid (for those who continue to depend on electric service from the grid) or whether we abandon the utility's social mandate to ensure electric reliability. You can read more about this in the report The Economics of Grid Defection from the Rocky Mountain Institute.
2. Fluctuations in VERs can sometimes happen too quickly for system operators to respond manually, so automated response systems are required. These are generically termed “ancillary services.” The economic challenge is that VERs increase the demand for ancillary services and probably require the establishment of new types of ancillary services.
3. Part of the reason that the first two challenges exist is because demand for electricity is treated as being “inelastic” or unresponsive to price. Designing a financial mechanism that matches demand with VER production is a major potential application of “smart grid” systems. For now, electricity markets have opened programs for “demand response,” which offer payments to customers that are able to adjust demand quickly.

Many restructured electricity markets offer power generators payments for the capacity that they have ready to produce electricity, not just for the electricity that they actually produce. For example, if you owned a 100 MW (100,000 kW) power plant and the capacity payment was $10 per kW per month, you would earn $12 million per year regardless of how much electricity you actually produced. In areas that have them, capacity payments have become a major portion of a generator’s revenue stream.

Capacity markets are a little bit odd. Almost no other market for any commodity, anywhere in the world, has them. (There is a capacity market for natural gas pipelines, but it is operated differently than electricity capacity markets.) In markets for other non-storable goods, like hotel rooms and seats on airplanes, any fixed costs of operations are rolled into the room rate or ticket price. If there is enough unused capacity, then it will exit the market (the hotel will close, or the airline will go bankrupt). Yet, this doesn’t really happen in electricity.

There are three features in electricity markets that have justified the need for capacity markets – two are regulatory interventions. The first goes back to 1965, when a large blackout crippled much of the U.S. Northeast [13]. Rather than being saddled with additional regulations imposed by an angry government, the electricity industry adopted a set of then-voluntary standards for reliability. (The standards are now mandatory.) One of these standards was called the “installed capacity” requirement, which stated that electric grid operators needed to control more capacity than they thought they would need to meet peak demand. For example, if annual peak electricity demand in your system was 100 MW, you might be required to own or control 120 MW of capacity, just in case your power plants broke; your estimate of demand was wrong; or some combination of both. This extra capacity requirement is sometimes called the “capacity margin.”

The second intervention goes back to California’s power crisis of 2000 and 2001. California was one of the first states to deregulate its electricity industry, and it got a lot wrong in the deregulation process. In particular, as firms like Enron found out, the markets created in California were ridiculously simple to manipulate. Prices could easily be driven to levels 100 times higher than normal. Following California’s debacle, other regions did push forward with deregulation, but no one wanted to be the next California. So, virtually all restructured markets instituted “caps” (or upper limits) on electricity prices. In PJM, for example, the price cap is set at $1,000 per MWh. This is the maximum amount that any company may charge for electricity. The markets also instituted watchdogs known as “market monitors” who are tasked with reviewing supply bids submitted by generating companies and flagging those that are deemed to be manipulative. California showed us that electricity markets (even those that are well-designed) are susceptible to manipulation, so many of these market monitors are quite aggressive, punishing firms that submit bids that are higher than marginal costs.

The final regulatory intervention is retail electric rates that are fixed and do not reflect fluctuations in the cost of generating electricity. This has partly been justified on the grounds of protecting consumers from volatile energy prices (the fact is that no energy commodity has more price volatility than does electricity), and also due to the fact that the electric meters that most customers have are still based on a century-old analog technology that does not allow the utility to bill customers based on time of use.

So, suppose that the electric system operator decided that a new power plant needed to be built “for reliability” (i.e., in order to meet the installed capacity requirement). In a market environment, all you would need is for someone to build the plant, operate it during times of peak demand when prices are relatively high, and rake in the dough. Sounds simple enough, right?

Figure 12.4 shows why, in fact, the situation is not so simple. The figure shows the average cost of producing one megawatt-hour from a new natural gas power plant (the “levelized cost of energy,” which we will meet in detail in a future lesson), as a function of how often the plant operates. The more hours the plant operates, the more productive hours over which it can spread its capital cost, so the lower price it would need to charge in order to be profitable. A typical power plant that would operate only during the highest-priced hours would need to charge a price higher than the price cap in order to remain financially solvent. Furthermore, consumers buying energy from that plant would pay the fixed retail rate, not the plant’s levelized cost of energy.

Figure 12.4: Levelized cost of energy for a new natural gas power plant

Click for a text description of Figure 12.4

The image is a graph showing the relationship between the levelized cost of energy (LCOE) and hours of operation per year for a power plant. The vertical axis represents the LCOE on a logarithmic scale, ranging from one dollar to 100,000.00 dollars. The horizontal axis displays hours operating per year, from 0 to 8000 hours. The graph features a blue curve that starts high on the left and declines sharply as you move right, flattening out at longer operating hours. A dashed red horizontal line labeled "Price Cap" is drawn across the graph at the one-thousand dollar level. Red text notes that the LCOE for a peaking plant is above this price cap, indicating a lack of profitability.

Credit: S. Blumsack © Penn State is licensed under CC BY-NC-SA 4.0

Figure 12.4 basically illustrates the conundrum: someone needs to build the plant for reliability reasons. But because of price caps and fixed retail pricing, no one would ever make money operating this plant. We are stuck in a contradiction – the system operator needs to maintain its installed capacity margin, but no power generation company has any incentive to build the plants that will meet this regulatory requirement.

In electric systems that have not restructured, this isn’t so much of a problem since the regulated utility can ask its public utility commission to pass through the costs of this plant to its ratepayers. But in a deregulated generation environment, there is no guarantee of cost recovery. This conundrum is sometimes called the “missing money” problem. Capacity payments are supposed to solve this problem by providing additional revenue to power plants to keep them operating. It is important to realize that capacity payments have been incredibly controversial since they are sometimes viewed as windfall profits for power generators.

To see the relevance to VER integration, let’s take our example of the uniform price auction from the previous lesson. In that example, we have five generators and demand is 55 MWh. Generator D clears the market and the SMP is $40/MWh. Profits are:

• Firm A: $300
• Firm B: $375
• Firm C: $200
• Firm D: $0
• Firm E: $0

You can see how Firm D might have a “missing money” problem since it produces electricity but earns no profits. If Firm D is the “marginal generator” too often, it will not be able to cover any fixed costs and will eventually go out of business. (We didn’t have fixed costs in the example, but most power plants do have some fixed costs of operation, like land leases or other rental payments.)

Figure 12.5: Illustrating the uniform price auction

Click for a text description of Figure 12.5

The image is a graph depicting the cost versus quantity for five generators labeled A through E. The horizontal axis represents quantity, ranging from 0 to 90, while the vertical axis represents cost in dollars, ranging from 0 to 80. Each generator is represented by a horizontal step in the graph, indicating its output and corresponding cost.

• Generator A covers up to 10 units at a cost of approximately $10.
• Generator B extends the quantity to about 20 units with a slightly higher cost.
• Generator C increases the quantity to 40 units at around $30.
• Generator D reaches around 50 units with a cost of about $40.
• Generator E continues to approximately 80 units at a cost near $70.

A dashed vertical line at 55 units marks the demand level labeled "Demand is 55 MWh" in red text at the top of the graph.

Credit: S. Blumsack © Penn State is licensed under CC BY-NC-SA 4.0

Now suppose that a 20 MW wind plant was built in this market. Wind energy has a very low marginal cost – so close to zero that we can just call it zero for this example. This new wind energy plant moves the entire dispatch curve to the right by 20 MW. If the wind is producing at full capacity and demand is 55 MWh, then Firm C becomes the market-clearing generator and the SMP falls to $30/MWh. (The 20 MW of wind with zero marginal cost has the same effect on Firms A through E as a 20 MW decline in electricity demand – why?) Try recalculating profits yourself under this scenario. You should get:

• Firm A: $200
• Firm B: $225
• Firm C: $0
• Firm D: $0
• Firm E: $0
• Wind Farm: $600

While it is nice that the wind farm’s profits are so high and that the wholesale price of power has fallen, three of the five existing generating firms are not making any profit and might consider shutting down altogether. But according to reliability rules, we need those plants to be operating in order to have enough bulk generation capacity. Because of this requirement, the wind farm has effectively instigated a “missing money” problem for some of the other generators in the system. Hence, there is some need for a capacity payment or other revenue stream, but only because of the regulatory requirements for installed capacity.

To figure out what the capacity payment needs to be for a specific generator, we can compare its revenues to its total costs. The difference represents the capacity payment needed for the power plant to break even. Consider two cases as an illustration. First, suppose that Firm C in our example above had fixed costs of $100. With the wind plant in the market, Firm C breaks even on its operating costs (the SMP is $30 per MWh and its production cost is also $30 per MWh) but covers zero of its fixed costs. So, the capacity payment needed for Firm C would be $100. As a second example, suppose that Firm A had fixed costs of $250. With the wind plant in the market, Firm A earns $200 in operating profit, but its fixed costs are $250. Its total profit would thus be -$50 and Firm A would need a capacity payment of $50 in order to break even.

Finally, suppose that Firm B had fixed costs of $100. With operating profits of $225, Firm B earns a total profit of $225 - $100 = $125. Thus, Firm B is profitable even without a capacity payment. Does that mean that Firm B is not allowed to earn a capacity payment in the electricity market? No - Firm B can compete in the capacity market and earn a capacity payment just like any other power plant. While the capacity market was set up because some power plants (like A and C in our illustrations) have revenue shortfalls, participation in the capacity market is not limited just to those plants who "need" a capacity payment to avoid losing money.

You might be wondering what happened to the 20 MW of new wind – doesn’t that count as “capacity?” The answer is that different regions have very different ways of allocating capacity credits to VERs. Typically, the system operator will let a VER count for a fraction of its capacity. So, our 20 MW wind farm in this example would count for perhaps 2 or 3 MW towards the system-wide installed capacity requirement.

In some areas with a high penetration of VERs, particularly wind, the price of electricity has started to become negative, meaning that suppliers must pay the system operator in order to keep producing electricity. This also means that consumers get paid to use more electricity, which sounds like a terrific deal. Here’s how such a thing is possible. Mount Storm Lake in West Virginia is home to both a large coal plant (one of the biggest in the state) and a large wind farm. These plants are connected to the same transmission line that winds its way towards Washington D.C. This transmission line is almost always congested, so the Mount Storm group of power plants cannot always produce at full combined capacity. During an autumn evening, when electricity demand is low, the Mount Storm coal plant is producing at full capacity and meeting electricity demand. All of a sudden, the wind picks up and the Mount Storm wind farm starts to generate a lot of power and there is excess supply at Mount Storm. What options does the system operator have? It could simply shut down the coal plant (which would be hard to do quickly since coal plants are inflexible) or shut down the wind farm (which, as you saw in Vermont, is not without its own problems). Or it could allow the price to go negative and charge either (or both) plants to continue to produce electricity. If there happened to be some electricity consumer at Mount Storm, that consumer could get paid for absorbing that excess supply locally.

In a power grid, supply and demand must be matched at every second. In order to keep the grid operating reliably, system operators need a portfolio of backup resources in case of unplanned events. These backup resources are collectively known as “ancillary services.” These are purchased by the system operator through a type of option arrangement. The system operator might have an agreement with a power plant that gives the system operator the right to start up or shut down that plant if a contingency arises on the power grid, or if demand increases or decreases in ways that the system operator did not predict.

A very simple example of how this might work is shown in Figures 12.6 and 12.7. Figure 12.6 illustrates a hypothetical power system with some amount of predicted or “scheduled” demand. Actual demand deviates from this scheduled demand by small amounts – sometimes higher and sometimes lower. Figure 12.7 shows how a generator providing ancillary services would change its output in response to demand fluctuations – a practice known as “load following.” Ancillary services are the primary mechanisms currently in place for system operators to accommodate unanticipated variations in VER output.

Figure 12.6: Scheduled and actual demand for the hypothetical power system

Credit: S. Blumsack © Penn State is licensed under CC BY-NC-SA 4.0

Figure 12.7: Dispatch of ancillary services in response to unscheduled fluctuations in electricity demand

Credit: S. Blumsack © Penn State is licensed under CC BY-NC-SA 4.0

There are many different flavors of ancillary services. Please read the “Ancillary Services Primer” which provides some more detailed information. Two types of ancillary services are of particular relevance for VER integration – reserves and regulation.

“Reserves” represent backup generation that can be called upon in a certain amount of time in case of a contingency on the power grid, like the unexpected loss of a generator or transmission line (interestingly enough, it’s not clear whether or not the unanticipated loss of a VER for resource reasons, like the wind stops blowing, is considered a “contingency” in the eyes of reliability regulators). There are two types of reserves:

1. Spinning Reserves: Generation that is synchronous with the grid (“spinning”) and is able to increase power in 10, 30, or 60 minutes (depending on the flavor).
2. Non-spinning reserves: Generation that can start up and provide power within a specified time frame (usually 30 or 60 minutes).

“Frequency regulation” or just “regulation” refers to the generation that can respond automatically to detected deviations from the frequency at which all generators in a synchronous AC system are rotating (in the US, this is 60 Hertz; some other countries use 50 Hertz). Regulation is sometimes called “automatic generation control” since the response is typically too fast for a human being to initiate.

Regulation is, at this point in time, the most relevant ancillary service for VER integration and is also one of the most difficult to understand. The frequency of the power grid needs to remain constant at 50 or 60 Hertz (depending on the country). That frequency is related to the demand-supply balance. It may be helpful to think about frequency as analogous to the water level in a bathtub, as illustrated in Figure 12.8. The balance of demand and supply is like the tub having an identically-sized faucet and drain. If the faucet is larger than the drain, the water level rises – and in a power grid if the supply is larger than the demand, then the frequency will go up. If the drain is larger than the faucet (or if demand exceeds supply), then the system frequency declines.

Figure 12.8: Bathtub analogy for system frequency

Credit: Joe Eto, LBNL

Frequency regulation as an ancillary service corrects for frequency deviations by increasing or decreasing the output of specific generators, usually by small amounts, in order to effectively increase or decrease the size of the faucet relative to the drain. Response times for generators providing regulation are typically on the order of seconds, which is primarily why frequency regulation is used as a way for system operators to ride through unanticipated fluctuations in VER output.

Recall from the Ancillary Services discussion that generators are used to provide frequency regulation by effectively increasing the size of the faucet relative to the drain. There is no particular reason that generators need to have a monopoly on this. If we were to change the size of the drain relative to the faucet, we would accomplish the same thing, right?

The idea of balancing supply and demand on the demand side rather than solely on the supply side is not that new – electric utilities have been paying their customers to put timers on thermostats or hot water heaters for decades. Some utilities have even figured out how to charge customers more for electricity during the day than at night. But following an order from the Federal Energy Regulatory Commission in 2012 (Order 745), there has been a renewed interest in developing mechanisms to pay people and businesses not to consume electricity. “Demand Response” refers to end-use customers adjusting demand in response to price signals, or energy conservation during periods of high demand (to prevent blackouts). Many electricity systems, particularly those with active wholesale markets, have implemented wholesale demand response programs that allow customers to offer demand reduction on the same basis that generators offer supply. There are two basic flavors of demand response:

• “Economic” Demand Response: You make a negative supply offer to the system operator, and you can then be “dispatched” to reduce demand. The system operator then pays you for reducing demand, relative to some measured “baseline.”
• “Capacity” Demand Response: You give the system operator the right to call upon you to reduce demand during reliability emergencies; typically on hot days during the summer.

Many electricity systems, both regulated and restructured, are also experimenting with allowing demand-side participants to offer ancillary services such as frequency regulation (remember the bathtub analogy and you will see that, at least in concept, this is a perfectly sensible idea). But to date, the vast majority of demand-side participation, and over 90% of all of the profits from demand response, has been through the capacity market. Figure 12.9 illustrates the rapid growth in demand-side capacity market participation. In recent capacity auctions, the largest source of new “capacity” was actually commitments to reduce demand rather than increase supply. This figure shows how the components of the PJM Base Residual Auction (BRA) for installed capacity (ICAP) changed over the years 2007-2015. The left side of the figure shows the components of capacity reductions in the form of retirements, derates, et cetera. The right side shows the components of the capacity additions in the form of new generation, demand response, et cetera. 

Figure 12.9: Capacity additions in PJM through its capacity market.

Credit: Brattle Group, "Third Triennial Review of PJM’s Variable Resource Requirement Curve"

The result has been to introduce volatility into capacity market pricing. Just as the introduction of VERs lowered the price in the electricity market in our previous example, so too has demand response lowered prices in the capacity market, to the point where generators have started to complain of a “missing money” problem in the capacity market as well!

The primary piece of regulation that has enabled demand response in electricity markets is known as FERC Order 745, which mandated that Regional Transmission Organizations compensate demand response at the prevailing market price under most conditions. This means that if you successfully offer electricity demand reduction to the RTO, you benefit twice. First, you benefit by not having to pay for the electricity that you did not consume. Second, you benefit because the RTO pays you the prevailing market price for all of that foregone consumption.

Because of the way that Order 745 has mandated that demand response be paid, it has been very controversial, so much so that it was successfully challenged in May of 2014 before the U.S. Circuit Court in Washington, DC. The gist of the arguments against Order 745 was as follows:

1. Paying demand response the prevailing market price is arbitrary and not justified by the value that it provides to the market;
2. Because demand response market participants are retail electricity customers, connected to the low-voltage local distribution grid, the U.S. federal government has no jurisdiction to set prices for those customers. Instead, that is the responsibility of the states.

The D.C. Circuit Court agreed with both of these arguments and overturned FERC Order 745, effectively removing economic demand response as a participant in U.S. electricity markets. In a moment that captured the attention of electric power industry geeks everywhere, the D.C. Circuit Court decision was appealed to the U.S. Supreme Court, which overturned the Circuit Court decision and allowed demand response to be paid the same way that power plants get paid. If you happen to be a legal junkie, you might like to read the Supreme Court's decision, which has had implications for a lot of different smart grid technology programs run by regional power markets.

Variable Energy Resources (VERs) - specifically wind and solar - do introduce some special economic challenges to power grids and electricity markets. Since VERs have such low marginal costs (remember that fuel from the wind and sun is free) they do have the potential to depress prices in the day-ahead and real-time energy markets, even producing negative prices in some cases. This creates challenges for system operators in restructured areas in particular, since they are charged with having enough generation capacity on the grid to meet reliability requirements, but individual generation owners will stay in the market based only on business criteria - whether they earn enough money to make continued operations worthwhile. The resulting conflict between market and regulatory signals has been called the "missing money" problem, and capacity payments have been introduced, albeit controversially, as a mechanism to make up for the "missing money." Energy output from VERs can also fluctuate faster than system operators are able to adjust for, so large-scale VER integration will almost certainly increase the demand for existing ancillary services (particularly frequency regulation) and may necessitate new types of ancillary services, which could be provided by either demand-side or supply-side resources.

Reminder - Complete all of the Lesson 12 tasks!

You have reached the end of Lesson 12! Double check the What is Due for Lesson 12? list on the first page of this lesson to make sure you have completed all of the activities listed there before you begin Lesson 13.