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Contract No. DE-AC36-08GO28308

Market Designs for High Levels 

of Variable Generation

Preprint

M. Milligan,1 H. Holttinen,2 J. Kiviluoma,2

A. Orths,3 M. Lynch,4 and L. Söder5

1 National Renewable Energy Laboratory

2 VTT Technical Research Centre of Finland

3 Energinet

4 University College Dublin

5 KTH

Presented at the IEEE Power and Energy Society General Meeting

National Harbor, Maryland

July 27–31, 2014

Conference Paper

NREL/CP-5D00-62280

October 2014 
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Market Designs for High Levels of Variable Generation

Michael Milligan

National Renewable Energy Laboratory, 

Golden, CO, USA

Hannele Holttinen

Juha Kiviluoma

VTT Technical Research Centre of Finland

Antje Orths

Energinet, Fredericia, Denmark

Muireann Lynch

University College Dublin, Ireland

Lennart Söder

KTH, Stockholm, Sweden

Abstract—Variable renewable generation is increasing in 

penetration in modern power systems, leading to higher 

variability in the supply and price of electricity as well as lower 

average spot prices. This raises new challenges, particularly in 

ensuring sufficient capacity and flexibility from conventional 

technologies. Because the fixed costs and lifetimes of electricity 

generation investments are significant, designing markets and 

regulations that ensure the efficient integration of renewable 

generation is a significant challenge. This panel presentation 

reviews the state of play with regard to these issues in the United 

States and Europe and considers new developments in both 

regions. 

Index Terms—wind energy, power markets, adequacy, capacity

I. INTRODUCTION

Power systems have changed considerably in recent years. 

The liberalization of electricity markets has taken place on 

many systems, particularly in the United States and Europe. 

Concerns about climate change and energy security have led 

to a policy shift from fossil-fueled generation toward variable 

renewable generation (VG), particularly wind and

photovoltaics. These generation sources differ from 

conventional generation in terms of the variability and limited 

predictability of their output, their high capital costs and 

negligible operating costs, and the impact of geographic 

location on their output. Thus, market mechanisms that were 

designed to ensure efficient investments and operations of 

conventional generation may not prove efficient in integrating 

renewable generation. Difficulties include ensuring revenue 

adequacy for all market participants in markets with depressed 

spot prices; market scheduling, particularly between 

interconnected markets; and ensuring efficient transmission 

investments and operations. The low operating costs of 

renewable generation—along with nuclear, hydro, and 

combined heat and power generation—depressed spot prices,

and energy-only markets are unlikely to provide sufficient 

investment incentives. These challenges have seen varied 

responses from system operators and regulators through both 

market and regulatory mechanisms. This panel presentation 

examines the implications of these challenges in current 

modern power systems. Responses from regulators and policy 

makers are examined, with a focus on late-breaking work in 

both the United States and Europe.

II. MARKET CHALLENGES FROM VG

Increased variable and limited predictable renewable 

generation places new requirements on power system

operations and electricity markets. Variability and uncertainty 

means that more flexibility will be needed. Also, increased 

amounts of VG displace fossil-fueled generation and lead to 

less operating hours for conventional generation—as well as 

decreased electricity prices during hours of high renewable 

generation. 

A. Requirements for Flexibility

Renewable VG leads to higher variability in residual 

demand, which is given by demand minus renewable 

generation. This residual demand must be met by conventional 

generation units. At moderate VG penetration levels, midmerit power plants will operate in a more flexible way. At 

high penetration levels, baseload operation will also be 

impacted. 

There is significant interest in developing methods for 

assessing the flexibility needs and characteristics of the power 

system [1]; however, installing sufficient flexibility in the 

power system is not a sufficient condition for making that 

flexibility available when needed. Appropriate mechanisms

that allow system operators to obtain those services when 

necessary are also required to maintain system balance.

Existing market regulations and designs may not incorporate 

sufficient incentives and rewards for flexibility that will be 

required to ensure both efficient system operation and 

renewable integration.

Obtaining deployable flexibility has two components: (1) 

the economically efficient level of investment in flexible 

technologies must take place, and (2) once installed, price 

signals or regulatory requirements must incentivize generators 

to make these flexible capabilities available to system 

operators. As variable renewable penetration increases, 

flexible units may be operated in a manner that reduces their 

capacity factors and their online durations relative to those of 

baseload units, which in turn have reduced revenues. 
2

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Therefore, an energy-only market—in which remuneration is 

awarded for only energy provision and not performance—may 

penalize flexible units. Further, flexible units are more likely 

to serve as marginal units, so they cannot gain inframarginal 

rent during the hours that they set the market price. Regulatory 

measures designed to limit scarcity pricing, such as price caps, 

can exacerbate this problem. Reduced spot prices from 

technologies with low marginal costs reduce returns for 

conventional generators even further. Thus, there is cause for 

concern that traditional energy-only markets may lead to 

revenue inadequacy for conventional units and will also 

penalize flexible units. An energy-only market with only 

short-period trading can be found in Australia. (It is a 5-min 

real-time market with a very high price cap.) This design was 

presented in [2] and mitigates some of the above-mentioned 

challenges. 

B. Revenue and Price Impacts of Wind Penetration

Various studies have been conducted regarding the 

impacts of renewable generation on both electricity prices and 

the revenue that all types of generators can expect to earn. 

Renewable electricity is understood to reduce prices through 

the merit order effect, whereby renewable electricity is 

regarded as that from low, short-term, marginal-cost 

generators. Thus, the supply curve is shifted to the right and 

intersects the demand curve, which is fixed, at a lower point,

leading to lower prices. In the longer term, as old generation is 

retired and consumption may increase, the price curves will 

again cross at a higher level, on average, but with increased 

volatility. In Europe, several ex-post analyses have found that 

wind penetration leads to lower wholesale prices, with the 

reduction in prices greater than the subsidy mechanisms 

awarded to renewable generation [3]-[6]. In [7], it is found 

that the impact of increased wind generation on system 

balancing costs is much lower than estimated wind integration 

costs.

In the United States, there has been concern regarding 

revenue adequacy even without significant VG. For example,

New York (NYISO), which has a relatively small amount of 

wind energy, experienced prices below the cost of new entry 

in 2011 and 2012, according to a recent market report [8]. 

Market prices are coupled with both the dispatch stack and 

transmission constraints. In the United States, there have been 

cases of curtailment of wind power that were done outside of 

the market construct, resulting in uneconomic outcomes [9]. 

These generally occur during periods of low demand, high 

wind output, and with other generation constrained at 

minimum output. Several market areas in the United States

now do some form of economic dispatch on wind plants so 

that the impact on low/negative market prices is mitigated 

[10]. In European countries with high wind penetration,

negative market price signals are used to incentivize the 

downward dispatch of low-marginal cost units. The use of 

new forms of demand is also incentivized this way, e.g., heat 

boilers in the district heating system. When neighboring 

markets do not have synchronized price floors, a phenomenon 

can be observed in which bids are cut in one market while 

energy is imported into the same market, resulting in negative

prices on both sides of the border [9].

III. OVERVIEW OF CURRENT MARKET STRUCTURES

Market designs in Europe and the United States vary 

considerably, both between the two continents and among 

different markets and systems within each continent. The 

European Directive 2009/72/EC [11] requires member states 

to adapt their national laws, making countries move toward a 

common internal energy market (IEM) to be finalized by 

2014. Objectives of the IEM include requiring increased 

market coupling via interconnectors between different regions.

Markets in the United States must comply with regulatory 

orders set by the Federal Energy Regulation Commission. 

When considering renewable integration, of particular interest 

are day-ahead and intraday markets, capacity payment 

mechanisms, and locational versus zonal marginal pricing.

A. Day-Ahead and Intra-Day Markets

Future very-high penetration levels of low, short-term, 

marginal-cost units can profoundly change energy-only 

markets. For example, the Nordic market, which is hydro 

dominated, needs conventional generation to set prices as well 

as to optimize the use of water. Adding VG to this system will 

push conventional generation out, with only biomass-fueled 

combined heat and power remaining.

Many current power market structures have a day-ahead 

market closing approximately 12 to 36 hours before the realtime operation. The day-ahead market creates the first 

committed schedule. As the hour of operation gets closer, 

forecasts improve, and intraday markets can then be used to 

provide updated market positions. For example, the Nordic 

power system has a continuous intraday market that closes one 

hour before the operating hour, whereas the Spanish market 

has six intraday market sessions. The former results in a 

shorter gate closure, whereas the latter creates more liquidity. 

Finally, the transmission system operator manages the power 

system in real time with the help of ancillary service markets 

and reserves.

The proposed IEM requires harmonized trade over 

interconnectors, which should lead to a zonal market structure. 

All balancing area’s market participants are required to 

combine price and quantity pairs and submit these pairings to 

a power exchange that will in turn determine efficient 

interconnector flows on that basis. Further intraday trading 

then takes place within the market zones, with implicit trading 

between market zones. Each system has room for discretion to 

arrive at its price-quantity pairs, whether through bilateral 

trading, centralized dispatch, or some combination of the two.

B. Capacity Payment Mechanisms

Capacity payment mechanisms are mechanisms whereby 

units receive payments on the basis of their capacity and/or 

availability. Capacity payments are used as a means of 

responding to the “missing money” problem of revenue 

inadequacy as outlined in Section II. In general in Europe, two 

groups of capacity remuneration mechanisms are discussed: 

volume-based versus price-based mechanisms. Volume-based 

mechanisms can be targeted (strategic reserve) or market-wide 

(capacity obligations, capacity auctions, or reliability options). 

The most important requirement is to serve the purpose of 

ensuring generation adequacy without causing distortion to the 
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market. An analysis of the challenges with respect to the 

different mechanisms has been made by the Agency for the 

Cooperation of Energy Regulators (ACER) [12]. 

Experience with capacity payments to date is mixed. The 

single electricity market in Ireland has had a capacity payment 

mechanism in place since 2007. Ireland currently has capacity 

that far exceeds peak demand, but because this is in part 

because of a collapse in demand since 2008, it is difficult to 

determine whether the structure of the capacity payment 

mechanism is overly generous. The British market BETTA is 

currently an energy-only market based on bilateral trading; 

however, BETTA is introducing a capacity payment 

mechanism because prices have been below the long-run 

average cost [13], so new capacity has not been forthcoming 

and a capacity crunch is foreseen. The Nordic market is 

energy-only based, but each member country has some 

mechanism to ensure capacity adequacy, e.g., in Finland,

some old units receive capacity reserve payments to keep 

them from being dismantled. There are strategic reserves in 

Sweden [14] and different types of transmission system 

operator capacity responsibilities in Denmark and Norway;

however, both Norway and Sweden are heavily dependent on 

comparatively high MC units in neighboring countries. With 

discussions on additional low MC units and price-decreasing 

capacity markets in neighboring countries, there is concern 

regarding ensuring that prices are high enough to cover the 

costs of all units.

To date, the implementation of the IEM has been 

concerned with market coupling and capacity allocation across 

interconnectors. However, capacity remuneration 

mechanisms, both existing and proposed, in various European 

Union markets have led ACER to voice opinions on capacity 

markets [12], [15]. Although ACER does not explicitly 

recommend against capacity payments, ACER maintains that 

removing barriers to trade, such as price caps and concessions 

granted to renewable generators, may remove the need for 

capacity payments. Further, ACER insists that market 

integration is the priority, and capacity payments should not 

distort incentives or trade nor should they cause discrepancies 

among systems.

The U.S. market areas that have capacity markets include 

NYISO, ISONE, and PJM. The basic characteristics of these 

markets are shown in Table 1 below.

TABLE 1. CHARACTERISTICS OF NYISO, ISONE, AND PJM

Market Longest 

Forward 

Period

Longest 

Commitment 

Period

Demand 

Curve

Auction 

Product

ISONE3 years 5 years Vertical with 

descending 

clock auction

Installed 

capacity 

(ICAP)

NYISO 30 days 6 months Downward 

sloping

Unforced 

capacity 

(UCAP)

PJM 3 years 3 years Downward 

sloping

Unforced 

capacity 

(UCAP)

There is significant interest in the future role of capacity 

markets in regions that do not currently have them. One 

example is the Electric Reliability Council of Texas (ERCOT)

[16]. FERC recently held a technical workshop on centralized 

capacity markets [17] that explored and discussed the 

emerging impact of VG on prices and the potential need for 

capacity markets.

C. Locational Marginal Pricing

VG is often located in remote areas that have poor access 

to the transmission network, so as renewable generation 

penetration increases these geographic issues will have more 

bearing on generation curtailment and electricity prices. 

Locational marginal pricing (LMP) provides signals for the 

price of electricity generation at each node in the network,

which also incentivizes the efficient use of transmission assets. 

LMPs feature in many markets in the United States, including

PJM, ERCOT, and NYISO.

The European Target model, in contrast, envisages one 

price for each zone within the European market [11], [18]. 

This requirement for one clearing price for each zone all but 

precludes LMP within zones. This may lead to wrong price 

signals within a particular zone in which transmission 

constraints do not translate into a dynamic transmission price 

and cause the scheduled dispatch to diverge from the 

“optimal” in the case of no transmission constraints. In the 

single electricity market in Ireland, for example, constraint 

payments are made to generators for which real-time output as 

determined by the system operator differs from their 

scheduled output according to a market dispatch. Total 

constraint payments made in the years from 2008 to 2012 have 

been as high as 7% of total system costs [19]. In the absence 

of a policy shift at the European level in favor of including a 

location aspect to electricity pricing, it is unlikely that 

renewable generation can or will be located in an efficient 

manner in European systems [20].

IV. FUTURE MARKET STRUCTURES

Efficient integration of renewable electricity requires 

markets that are capable of addressing the specific issues that 

arise as a result of increased VG. These include the 

procurement of sufficient flexibility and capacity. Capacity 

typically involves fixed costs only, so it may be best procured 

by means of a fixed payment mechanism. Flexibility has both 

fixed and variable costs, so separate mechanisms are required 

to procure flexibility both in the short term and the long term.

A. Short-Term Procurement of Flexibility

Short-term flexibility could be incentivized through 

efficient reserve pricing mechanisms. In particular, a reserve 

pricing mechanism that renders the unit owner indifferent 

between energy and reserve provision will incentivize the unit 

to declare its full flexibility in gross pool markets. Inefficient 

pricing of reserve could lead to generation units either not 

declaring their full flexibility or entering long-term bilateral 

contracts with a supply company and limiting the range of 

their capabilities available to the system operator.

At higher shares of VG, it will become increasingly 

important to allow VG to participate in reserve provision. VG
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can provide upward reserve when it is dispatched down. 

During periods of power surplus, some conventional power 

plants remain online only to provide reserves. By using 

surplus VG for reserve provision, conventional units can be 

shut down, reducing fuel consumption and operational costs. 

Wind generators can also increase their revenues by acquiring 

reserve payments as well as energy payments [21].

If VG is allowed to participate in reserve products, it may 

become beneficial to utilize longer gate closures for reserve 

products when VG is forecasted to be low and shorter gate 

closures when VG is forecasted to be high. VG has 

considerable uncertainty, which decreases with forecast 

horizon. Moving the gate closure of the reserve products close 

to real time will decrease energy losses. The trade-off is not to 

forego cost-effective conventional units by using a gate 

closure that is too short. One option is to use a combination of 

longer and shorter gate closures, such as some frequency 

control reserve that are currently procured in Finland [22].

Uncertainty in demand and generation output levels may 

lead to a situation in which efficient reserve pricing cannot 

provide the correct long- and short-term signals [23]. 

Although stochastic techniques can be used to arrive at an 

efficient dispatch system, operators have shown a reluctance 

to rely on these tools without sufficient time to test them. This 

may lead instead to the specific design of products or 

payments that reward flexibility [24].

B. Long-Term Procurement of Flexibility

The long-term procurement of flexibility relates to the 

capabilities of the units. Because both the build times and the 

lifetimes of generation capacity are significant, there is a 

premium on certainty, and fixed payments for specific flexible 

capabilities may be useful. Determining the value of flexible 

characteristics of generators is a challenge, however, 

particularly over the long term because the value of the 

flexibility of a particular unit will depend on the capabilities of 

all other units on the system. Some possible solutions include 

procurement of system services by system operators using 

periodic auctions. This means that the value of flexible 

capabilities need not be calculated directly. Determining the 

time frame of such auctions is important. A short time frame 

may not enable all possible entrants to participate. A longer 

time frame, however, may lock a system operator into paying 

for capabilities that would not have been required if the 

generation portfolio had not evolved as expected.

C. Long-Term Procurement of Capacity

The design of efficient capacity payment mechanisms is 

nontrivial. Alternatives could include long-term capacity 

procurement contracts entered into by system operators, in a 

similar manner to long-term flexibility procurement. However,

such long-term agreements can be costly if the underlying 

assumptions do not play out as expected.

In principle, energy-only markets could provide price 

signals to invest in capacity, if marginal units are allowed to 

bid in high prices, taking into account that they need to cover

fixed costs with lower operating hours. This would mean that 

electricity prices would be at times very high and very low. 

This would incentivize demand-side flexibility, and at least 

lower the demand for extra capacity payments.

D. Interaction Between Flexibility and Capacity 

Procurement

A good market design principle is to have a separate 

product for each requirement in the power system. When a 

single unit can cater several needs, it follows that the separate 

products need to be procured simultaneously for optimality. 

For example, if capacity is acquired with an auction, the 

auctioneer needs to also consider how much flexibility at 

different time scales will be required in the future power 

system and how the auction will reward the flexibility in 

addition to capacity. This becomes a considerable planning 

task and may be difficult to implement without distortions. 

Alternatives at opposite sides of the spectrum include (1) 

short-term markets only with sufficient rewards for short-term 

flexibility and (2) monopoly on the asset ownership. The 

former would require contract markets to enable long-term 

investments.

Because risks and uncertainties in electricity generation 

are significant, it may be that there is an incentive on behalf of 

generators to enter into long-term bilateral contracts with 

suppliers. This limits the ability of system operators to utilize 

the full range of flexibility from generators. Thus, a welldesigned capacity payment mechanism may reduce 

uncertainty to generators and increase their incentive to 

declare short-term flexibility. Alternatively, stochastic 

optimization of a system may result in efficient price signals 

that may reduce the need for flexibility payments but will do 

little to incentivize capacity investment.

A hybrid mechanism that considers unit capability and 

enables long-term procurement of both flexibility and capacity 

may prove desirable. However, it is important to note that if 

such a mechanism can be designed to provide efficient

investment signals, then energy and reserve pricing should be 

limited to ensure that efficient operational signals are provided 

to avoid double counting and potential market distortion.

There is significant interest in the United States regarding 

(a) the effectiveness of the existing capacity markets; (b) 

whether other market areas need capacity markets, given the 

suppression of prices with high levels of wind/solar energy;

and (c) whether long-term capacity markets should include 

tranches of different flexibility characteristics, whether 

flexibility and capacity markets should be separate, or whether 

they should be somehow linked—and, if so, how. In Europe, 

in principle, the IEM allows different systems to put their own 

mechanisms in place for the procurement of system services 

such as flexibility. However, systems that do not include a 

capacity payment are expected to trade with systems that do, 

and if the first moves toward an equilibrium whereby price is 

driven by long-run marginal costs and the latter by short-run 

marginal costs, this may lead to systematic differentials in 

price. This may cause inefficient interconnector operation

such as that between Finland, which is energy-only for the 

most part, and Russia, where capacity payments form a large 

portion of the total generator revenue.
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V. TESTING FUTURE MARKET DESIGNS

Testing new market designs is an evolving area of 

research. As an example, markets in the United States are still 

changing, as new ancillary service markets are under 

consideration and as the role of capacity markets is receiving 

attention from transmission operators and the FERC. Capacity 

market definitions and structures have changed over the years. 

For example, in New England the initial capacity market 

design did not elicit sufficient forward capacity, and redesigns 

were necessary [14].

In our view, modeling may be a necessary, but not 

sufficient, condition to ensure that markets will perform as 

desired. Alternative approaches to help establish market 

designs include

• production/market simulation

• agent-based market simulation

• analyses of market incentives and potential unintended consequences

• market implementation and evolution

Many production/market models are linearized 

approximations of reality and thus may not adequately 

represent the actual operation of markets. This type of market 

may underestimate the role of agents that wish to maximize 

profit, and it may also use market characterizations of perfect 

competition for markets that may more closely resemble 

monopolistic competition and/or oligopoly. Agent-based 

simulations can sometimes overcome these limitations, but 

they may not fully and correctly specify the objective 

functions of agents. A more abstract analysis of markets and 

incentives may reveal unintended consequences of market 

designs. One example is the design of energy markets in much 

of the United States that ignores the importance of frequency 

response. These markets provide economic disincentives for 

generators to provide frequency response because of the 

structure of the energy markets [24]. Thus, all of the 

aforementioned approaches, and possibly others, are needed to 

ensure the proper performance of markets for capacity, 

flexibility, energy, and ancillary services.

VI. CONCLUSION

Electricity market evolution is complex and slow moving. 

In many cases, energy-only markets are being replaced by a 

combination of energy, ancillary service, and capacity 

markets, but the interactions among these markets are 

nontrivial and difficult to predict or model. Capacity markets 

are attracting interest from the FERC in the United States. In 

Europe, ACER is openly dubious about the need for capacity 

remuneration and is concerned about the impact on price 

signals and trade. Incentivizing capacity without consideration 

for capability is unlikely to lead to sufficient flexible 

generation investment, and specific incentives for flexible 

investment and operation may be required. Although there is 

certainly a connection between forward capacity markets and 

flexibility, the specific market mechanisms that will lead to 

both required long-term capacity and flexibility are as yet 

unclear.

VII. ACKNOWLEDGMENT

This work was supported by the U.S. Department of Energy 

under Contract No. DE-AC36-08-GO28308 with the National 

Renewable Energy Laboratory.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

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