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This report is available at no cost from the National Renewable Energy Laboratory at www.nrel.gov/publications.
ancillary services; however, in typical power system operations, shortages will first result in
insufficient reserve capacity while load balance is maintained. Therefore, in practice, scarcity
prices typically depend on the ancillary service scarcity prices, which can be based on preset
price curves or more dynamic, system-based conditions.
One example of an ancillary service scarcity pricing mechanism is the operating reserve demand
curve (ORDC) within the Electric Reliability Council of Texas (ERCOT) region in the United
States. In many markets, energy and ancillary services are co-optimized to ensure the optimal use
of available units to meet energy, balancing, and other flexibility needs. As a result of this
linkage, the prices for energy and ancillary services are directly coupled. For example, when
reserves are short, the price of energy should increase. ERCOT, however, does not co-optimize
in real time and has instead implemented the ORDC to pay resources that can provide reserves
during the times of highest need. The ORDC is a continuous function of energy price adders
derived from the operating reserve level in the current hour, the resulting expectation of loss of
load probability, and the value of lost load. When operating reserves are low, this energy price
adder increases, driving the energy price higher, and providing similar results to what would be
expected in a co-optimized market. Despite concerns about the effectiveness of this mechanism,
general consensus has found the ORDC to function as intended and designed, though some
improvements could be made (ERCOT 2016). Other studies have shown the ORDC to be a
preferred market design option compared to fixed reserve prices or fixed capacity payments for
valuing incremental reserve capacity and helping to ensure revenue sufficiency (Levin and
Botterud 2015, 392–406). Nevertheless, when any linkage between energy and ancillary services
is not properly tuned or functioning, or if the reserve market in the case of ERCOT becomes
saturated, thereby avoiding the triggering of the ORDC price adders, then the resources that are
needed to ensure resource adequacy might not earn sufficient revenue to remain in the market
long term.
Scarcity pricing for energy has historically included administratively-set caps to prevent price
gouging or increases in prices that are too severe. In the United States, energy price caps are
nominally set at $2,000/MWh in most operating regions (FERC 2016b). ERCOT has applied a
significantly higher price cap, currently $9,000/MWh, in an attempt to allow energy prices to
reach levels that appropriately signal needed investment in capacity
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; however, the current
excess capacity in many systems, including ERCOT, has resulted in fewer hours with scarcity
pricing and—along with low natural gas prices and lower growth of demand than anticipated—
has contributed to the overall lower energy prices in recent years (e.g., Potomac Economics
2016a; Potomac Economics 2016b). In a more extreme example, Germany
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is moving from its
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As an energy-only market, ERCOT relies on high-price periods that exceed the marginal unit cost to achieve
revenue sufficiency. A higher price cap does not necessarily reflect the perception that market power challenges are
not significant. Like other operating regions with wholesale electricity markets, the Public Utility Commission of
Texas has
rules for monitoring and mitigating market power (see
https://www.puc.texas.gov/agency/rulesnlaws/subrules/electric/Electric.aspx
). One interesting item within these
rules is the so-called “Small Fish Rule,” which deems any electricity generating entity controlling less than 5% of
the total installed generation capacity in ERCOT as not having ERCOT-wide market power. The rule protects small
new entrants in the generation market from claims of market power abuse, providing the opportunity for a sufficient
return on investment and removing potential uncertainty that might otherwise discourage the entry of new
generation (Anderson 2015).
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The German wholesale electricity market consists of a forward market, day-ahead market, and intra-day market.
While many wholesale transactions occur through bilateral contracts, a growing portion of these transactions are