Guest Editorial
By Cliff Hamal and Ian Smyth
From a distance, capacity markets show a lot of promise and there are indications that the Independent Electricity System Operator has grown enamored with the idea of adopting one in some form for Ontario. A move in this direction might allow for increased reliance on “market forces,” less outside intervention, more direct competition among all forms of supply and more efficient system operations. In reviewing the performance of capacity markets elsewhere, it is easy to come away with the sense that they have tremendous potential, despite needing a few tweaks to get them right. And there is no reason to worry about the need for some changes, as there is no shortage of suggestions of how they can be made better through modest adjustments of all kinds.
There is one recurring problem, however. No capacity market works well. The problem encountered is not associated with the general theory. It is the nitty-gritty messy issues that seem to keep cropping up as designers with the best of intentions always need just one more tweak to clean up one more loose end to try to make the market work as desired. Three regional transmission operators (RTOs) in the United States have struggled with capacity markets for a decade, and the United Kingdom is preparing for its first auction in December. And now there are signs that Ontario may join the party.
The history of capacity markets is a saga of the never-ending need for change and modification, along with the constant complaint of prices being too high or too low (or both), and reliability not being assured. Based on this evidence, and analysis of the mechanics of these markets, we conclude that the capacity market construct is fundamentally flawed and incapable of providing for a reliable system over the long term at a reasonable cost. These markets suffer from a problem that mathematicians would call being over-constrained. While individual problems can be resolved, there is no way to address the combination of challenges all at the same time. In layman’s terms, it is like trying to squeeze a balloon—it is obvious where it is bulging now, but attempts to squeeze that section will just make it pop out somewhere else.
The capacity markets we are describing have some key characteristics. They involve procurement of a uniform capacity product, measured in megawatts over a finite short period (typically a year). The markets are run by the system operator that holds a periodic auction that clears on the basis of procuring the capacity that the market needs to maintain reliability. Currently, such markets exist in the PJM control area, New York ISO and ISO New England. The auctions produce a market clearing price that is paid to all suppliers, with the cost passed on to all consumers. There are other ways to ensure sufficient capacity is maintained; that includes bilateral long-term contracting by the Ontario Power Authority, and other approaches used across the rest of the United States and Canada. Those do not involve a centralized auction to obtain capacity for the entire market.
The push for capacity markets came in restructured markets where energy revenues alone were thought to be insufficient to provide adequate return to new investment. Absent more money, new generators would not get built when needed. This shortfall is often referred to as “the missing money” in electricity markets. Capacity markets have been adopted to fill this gap and the three RTOs now oversee the transfer of billions of dollars a year from consumers to suppliers. For some suppliers, this money alone is sufficient proof that the markets are working and solving their “missing money” problem. For some consumers, however, the term “missing money” has taken on a new meaning as they are left wondering what value they have received for all of the money they are now missing.
In the United States, beyond the three eastern markets, there has been considerable opposition to the expansion of capacity market systems. That fact alone should give pause. And these eastern markets have been under a constant state of revision, with no end in sight. The Federal Energy Regulatory Commission (FERC) convened a technical conference on the overall status of these evolving markets last year, and thousands of pages of comments were filed by participants trying to improve their operation. It seems that everyone wants further changes to the markets and all are waiting for FERC’s summary report.
This is the first lesson from the U.S. experience: No one should be under the illusion that once you adopt a capacity market, you should expect “competition” to act freely without further changes. Capacity market prices are the result of complicated market rules, not competitive market forces. Yes, there is a role for market participation in the process, such as it is, but these prices are not the result of willing buyers and sellers coming together to purchase a price that both find to be acceptable. Instead, it is the price that results from complicated rules developed in highly-contested processes where critical issues are often resolved by the regulator, not the marketplace. As an example of the intricacies of the market rules, FERC recently ruled that the price curve for parts of New York should be based on cost of a specific technology that happens to never have been built, an F-Class frame generator with dual fuel capability and SCR. Hundreds of pages of testimony were filed by market participants in a high-stakes battle over this technicality. And the regulators (with formal training in law, political science and public administration) made the final decision over this technical issue. This was just one issue (among many) in one open docket (among dozens) before the FERC, and all of this regulatory activity involves just three U.S. capacity markets.
To dig into the problems associated with capacity markets, we start by considering the product itself. Capacity auctions require an interchangeable product, a megawatt, but not all capacity is the same. Traditional resource procurement readily allows for accommodation of different lead times, different operating characteristics, different policy goals (i.e., renewables) and the development of a diversified portfolio. All of those considerations are scrapped when an auction forces a standardized product. Among the very limited discussion by the IESO regarding its objectives, it states it seeks to, “support competition among imports, D[emand] R[esources] and generation to meet capacity needs.” Yet experience demonstrates that capacity markets struggle with this concept. PJM and ISO New England hold their auctions on a three-year forward basis, which supports new generation: commitments to construct can be made following the auction. But this creates major problems with capacity suppliers that work on the demand side, because customers typically do not commit to such actions until only prior to delivery. For imports, the problems have been three-fold: ensuring that generators are actually standing behind the commitment made years in advance, ensuring that the transmission system can accommodate the entirety of the imported capacity and ensuring long-term resource adequacy is maintained at a reasonable cost when imported capacity can enter and exit on a yearly basis. Thus, despite the best of intentions regarding promoting competition, embracing capacity markets could just introduce increased complications.
More fundamentally, thus far capacity markets have not been able to produce prices through market forces that are consistent with the market design objectives. Everyone agrees that capacity markets should produce a price that mildly fluctuates around the long-run cost of new capacity, with prices higher when new capacity is needed, and below when it is not. Most participants in electricity markets are familiar with hourly energy markets and the theory of bidding marginal costs to produce a market price. This concept runs into insurmountable problems when applied to capacity. With a one-year capacity product, most suppliers do not have significant marginal capacity costs over the one year time frame. While generators cost a lot of money to build, the entire cost of construction has to be incurred before the capacity can be delivered. Plus, those costs are recovered (and profits earned) over 30 years or more. As a result, those costs do not change as a result of whether the station provides capacity in the one year covered by the capacity product (i.e., those are not truly marginal costs). There might be some small costs associated with continued operations, such as staffing, and there certainly are fuel costs, but those will all be covered by the energy markets. As a result, unlike energy where there is at least theory supporting the concept of developing prices from marginal-cost bidding, there is no theory supporting the prices offered for capacity that produces the pattern of market prices that is desired.
On the demand side, designers in all markets have abandoned any attempt at full consumer participation in capacity auctions and have moved straight to an administrative demand curve. The exact shape and parameters of the curve are always intensely debated, with controversies over inflection points and slope angles merely emphasizing the non-market nature of the mechanism. In all U.S. markets some demand can participate as capacity supply, and unlike generation, will have marginal costs tied to providing the product for a year. As has been discussed, problems have arisen because the multi-year lead times needed for generation are inconsistent with demand-side market needs. In any event, demand side participation is only at moderate levels and does not resolve the problems caused by the lack of marginal costs among generators or the administrative demand curve.
On top of this, there are market power problems everywhere. The amount of capacity that is needed can be determined with precision. From a market perspective, however, when we have exactly what we need, every supplier has market power, because each could withhold and create a shortage. It makes no sense to build substantially more than that amount, simply so that we can create a competitive auction. The annual reports of the PJM Market Monitor point out the severe market power problems and make clear that there is no expectation that sufficient excess capacity will ever be built to solve the market power problem. Market power on the supply side is managed through bidding restrictions, which are largely must-offer requirements for most supply and cost justification of bids in other cases. There are also problems on the demand side. Buyers could profitably depress prices by contracting to have a little extra capacity built. Again, market rules and regulatory interventions attempt to minimize this kind of behavior. And in the final step of circular logic that underpins these markets, market performance is generally assessed on the basis of whether the final prices meet the designers’ expectations. And if it does not, further adjustments are made.
And those are just the big-picture problems. When locational needs develop, capacity markets are particularly dysfunctional. Those problems have led to Congressmen complaining to FERC about setting up zones in New York, prices around Boston skyrocketing to the upper limit and US Appeals Courts ruling that state regulatory commissions in Maryland and New Jersey were guilty of manipulating markets. Capacity markets cause problems in other areas where one might think they should be supportive. Many US states have policies to promote renewable resources, and strategies of supporting renewable investments can run into conflicts with capacity market rules that bar non-market funding that is perceived to be an exercise of buyer-side market power. Market participants attempting to ensure the system has adequate resources for other objectives, such as for adequate flexibility of generation and reliable fuel supplies (including such things as increased gas pipeline infrastructure), struggle with the constraints imposed by capacity market rules.
What may actually be the biggest problem is that all of this complexity just increases the volatility of revenues to generators, making it more costly to raise capital. Electric generation is hugely capital intensive. Stable revenues allow lower-cost financing, driving down costs. Relative to a system where long term bilateral contracts are available, the shift to capacity markets greatly increases revenue volatility and uncertainty, increasing the cost of financing, and ultimately driving up the cost of the capacity product that is being purchased. Economists love the auction-based mechanism, but most consumers who end up paying the bills could care less.
To lower the cost of capital, the UK market structure will allow for the auction to clear with commitments for payments up to 15 years long. Longer term commitments were also central to the reforms suggested in last year’s C.D. Howe’s Commentary on “A New Blueprint for Ontario’s Electricity Market.” But this just raises a different class of problems. In Boston, where market rules allowed a new generator to lock in prices for five years, other generators immediately complained of price discrimination and showed how such rules could prevent from achieving fair prices. Plus, the issues of addressing market power, solving for the market-clearing price and dealing with non-uniform product differences get more difficult when multi-year procurement through the auction is allowed.
After decades of market evolution it seems we have driven markets to the point where prices are clearly higher than they need to be, simply to achieve some theoretical concept of competition.
Market designers tend to agree on a pattern of capacity prices they want to achieve; history has demonstrated that the best of intentions does not a market make. The evidence provides little basis for confidence that there is a stable capacity market approach that could be adopted for Ontario. Instead, one should expect near-constant market intervention and revision. Investors looking to make huge investments in new generation are not building based on the auction process itself, but instead on the confidence in the regulator to continue to adjust the auction as needed to provide an adequate revenue stream in the future. That does not mean that reliability will necessarily be compromised. At some price level, developers will step in and build. But lenders at last year’s APPrO conference made clear that they will not continue to lend on the same basis with this kind of uncertainty.
It appears that Ontario faces intermediate-term capacity needs associated with the nuclear refurbishment program. Ontario is also likely to face increased challenges in balancing the system as the amount of dispatchable, fossil generation falls to historic lows. Nothing in this article suggests that competitive solicitations designed to procure the needed resources in a targeted fashion is inadvisable. Bilateral markets have worked in this manner for decades. But, the attempt to adopt a comprehensive capacity auction to address these kinds of issues will produce a host of problems.
If there is one simplistic conclusion that can be drawn from the experience of capacity markets, it is this: they have created situations where obvious problems, with obvious solutions, cannot be solved.
Post-publication note from the authors: Weeks after initial publication of this article, PJM staff issued a proposal (August 20, 2014) calling for a fourth capacity-related product. This product, called Capacity Performance, has been developed in response to concerns about resource performance during the severe conditions of last winter’s polar vortex. While the outcome of this proposal is uncertain, PJM’s clear recognition of market shortcomings and the need for further modification is consistent with the overall theme of this article: No capacity market works well and all are under near-constant revision.
Cliff Hamal is a Managing Director at Navigant Economics and has been involved in electricity market design since the Market Design Committee in Ontario, as well as other competitive markets across the U.S. and Canada. Some of his other writings on capacity markets are available at www.BiCapApproach.com. Ian Smyth is a Managing Director in Navigant Energy’s practice and brings over twenty years of experience in supporting governments, regulators and markets participants in the development and operation of evolving energy markets in the United Kingdom and other locations. For more information, see www.Navigant.com.
See also the following commentary by George Vegh on capacity markets:
Will capacity markets improve Ontario energy procurement?