Few would argue with the claim that Texas has the best wholesale and the most competitive retail electricity market in the US, if not the world. But it suffers from an ailment called inadequate resource adequacy. Private investors, who are the key stakeholders in building generation capacity, appear unable and/or unwilling to invest sufficiently in what the regulators and the market operator would like to see in terms of a comfortable reserve margin.
The last 2 years, the Electric Reliability Council of Texas (ERCOT) has had a few close calls, made more pronounced by a prolonged drought, which increased summer air conditioning load to dangerous levels. ERCOT had to repeatedly call for voluntary conservation to make it through hot summer afternoons in 2011.
Going forward, ERCOT has warned that it expects its reserve margin to plunge to 9.8% as early as 2014, 6.9% in 2015, and to a negative margin by 2022. Making matters worse, ERCOT has set a 13.75% target for how much excess generation capacity it would like to have above the projected demand – don’t ask where this number comes from or why it is as high as it is. One explanation often heard is that ERCOT, being an electric island – i.e., not being interconnected to other grids in the US – is unusually vulnerable to supply shortages, and hence the need for the large reserve margin.
Understandably, the Public Utility Commission of Texas (PUCT), has been sympathetic to ERCOT’s plight, nor do any of its commissioners wish the lights to go out under their watch. In late October 2012, they decided to raise ERCOT’s offer cap from the current $4,500/MWh – the highest of any organized market in the US – to $5,000 in June 2013, $7,000 in June 2014, and $9,000 in June 2015. That would still be lower than the AUS$12,500 offer cap in Australia’s National Electricity Market (NEM), but not by a huge margin.
Offer cap, of course, is the maximum amount that generators can bid in the wholesale auction. The higher the offer cap, the more money generators, especially those with flexible peaking units, typically natural gas-fired plants, can make during those few hours when they are dispatched. This has been identified among the factors prohibiting more investment in new peaking generation, resulting in the dreaded resource adequacy and dangerously low reserve margins predicted by ERCOT.
Another alternative examined but rejected by the PUCT was the introduction of a capacity payment scheme, similar to the one in PJM market in the mid-Atlantic region.
France, on the other hand, has decided to introduce such a scheme starting in 2013:
Concerned about having sufficient capacity during periods of high demand, the French government is introducing a decree that would require electricity suppliers to buy and pay for peak load capacity from the end of 2013. The obligatory certificates would have to match their forecast needs 3 years in advance. The scheme is intended to discourage the closures of uneconomical plants and encourage generators to construct new flexible plants that can be easily turned on and off.
Once introduced, generators will be paid a premium based on their available peak load production capacity, not just electricity sales. According to sources familiar with the scheme, suppliers will have to secure sufficient capacity certificates to meet their demand projections using a competitive auction.
France’s power grid operator, RTE, claims that the country’s supply and demand balance has been weakening and may be in jeopardy by 2016 due to the planned closure of older thermal plants in response to European Union’s environmental directives. E.ON has announced it will close 4 of its 7 coal-fired power plants in France by end-2015 (see related article on E.ON in this issue).
The main challenge in France is not lack of capacity per se, but rather lack of flexible capacity. The French system is dominated by 58 nuclear reactors, providing 75-78% of the generation in a typical year. What it needs is more flexible capacity, the type provided by peaking gas-fired units to meet peak demand during periods of high demand, such as evening hours, especially during cold winter months when a significant electric heating load exacerbates spikes in the residential load.
The French move to establish a capacity payment scheme is closely watched elsewhere in the continent, including in Germany. BDEW, the lobbying group for the German power sector, has indicated that a similar scheme will also be needed for Germany by 2015, if not sooner, to manage the rapid growth of renewable resources.
The debate about paying or not paying for capacity in competitive wholesale markets, of course, is nothing new. For competitive markets to work, existing generators must make sufficient money to remain viable. Attracting investments for new capacity to replace retiring generation or meet growing demand is even more of a challenge since investors want some degree of assurance that they can recover their initial investments plus a reasonable margin over time allowing them to make a profit. Otherwise, why bother.
There are two schools of thought on this. Some experts believe that energy-only markets, where generators are only paid when they are dispatched, are adequate, provided the offer cap is sufficiently large to allow them to make a killing during times of scarcity. These people say high offer caps are necessary to attract new investment, especially for new peaking plant. ERCOT and Australia’s National Electricity Market (NEM) are often mentioned as examples of successful energy-only markets.
Another group of experts believe that there are inherent limits and/or flaws to energy only markets, usually referring to “missing money problem,” the fact that not all generators make enough to remain viable – it is a rather long and complex story. These experts have proposed markets with both energy and capacity payments. The main objective is to pay sufficient amounts to keep some of the marginal thermal plants at least marginally viable.
This can be done through a capacity payment for having capacity available just in case they are needed. In this case, some generators may get paid even if they are rarely, if ever, dispatched. This, of course, introduces perverse incentives to keep old and inefficient plants around just to get paid for having capacity available when/if needed.
The Texas commission’s recent decision did not surprise many given a report prepared by The Brattle Group in June 2012. The Brattle report concluded that new capacity investments in ERCOT were impeded by low wholesale prices due to low natural gas prices and an insufficient number of peaking units were being built partly due to limits on the offer caps.
Increasing the offer caps to $9,000/MWh would help somewhat but would only raise the reserve margin to around 10%, not 13.75% as recommended by the Federal Energy Regulatory Commission (FERC) and sought by ERCOT. The Brattle Group recommended instead that either the market design be adjusted or reliability objectives be revised downward.
The Brattle report also suggested that ERCOT’s higher reliability target could be achieved with a significant increase in price-responsive demand, also referred to as Demand Response but cautioned that “it would likely take several years before a sufficient level of demand response could be achieved.”
The PUCT’s decision to stick to its energy-only market was hailed by pure energy-only market enthusiasts. The move by France to introduce a capacity scheme, likely to be adopted by Germany and possibly others, suggests that the debate about the virtues of energy-only vs. energy and capacity payment schemes is far from over.
This post is extracted from EEnergy Informer, December 2012 issue.