The Visible Hand: Ensuring Optimal Investment in Electric Power Generation.

• Author: Leautier, Thomas-Olivier

1. INTRODUCTION

   An essential objective of the restructuring of the electric power industry in the 1990s was to "push to the market" decisions and risks associated with investment in power generation, i.e., to have market forces, not bureaucrats, determine how much investment is required, and to have investors, not rate-payers, bear the risks of excess capacity, construction cost overruns and delays.

   However, since the early 2000s, generation adequacy has become an issue of concern for policy makers, power System Operators (SOs), and economists. It would appear that, contrary to the initial belief, the market does not necessarily provide for the adequate level of generation capacity. Britain, that pioneered the restructuring of the electricity industry in 1990, constitutes the most recent and striking example: Ofgem, the energy regulator recently warned that, in its high demand scenario, involuntary curtailment of customers will be imposed for 8 hours on average during the winter 2015/2016 (Ofgem, 2013).

   Operating and regulatory practices aimed at preventing the exercise of market power are often considered to be the primary cause of this market failure. As shown in Marcel Boiteux (1949)'s seminal analysis, high prices a few hours per year are required to finance the optimal capacity. However, in most jurisdictions SOs impose de jure or de facto price caps, that deprive producers of these high prices. This revenue loss, called "missing money", is considered an important driver of underinvestment in generation (Joskow, 2007).

   Therefore, SOs and policy makers worldwide have designed and implemented a variety of mechanisms to correct this apparent market failure (Finon and Pignon, 2008). For example, most US power markets have adopted highly structured and prescriptive physical certificates markets, and many European countries are considering, designing or implementing capacity mechanisms. (1)

   These mechanisms are extremely complex, hence expensive to set up and run. Furthermore, they constitute a partial reversion towards central planning, which restructuring precisely attempted to eliminate: using a centralized system reliability model, the SO sets a generation capacity target, and organizes its procurement. Risk of overcapacity is borne by consumers, while risk of cost overrun is borne by investors. A rigorous economic analysis of the performance of the various market designs implemented by SOs to restore investment incentives is therefore required. This is the objective of this article. I am not aware of any previous systematic analytical comparison of these designs.

   This work draws on a rich literature, that can be structured along two themes. A first group of articles examines generation investment in restructured power markets. While these works differ in important aspects, most model two stage games: in stage 1, producers decide on installed capacity; in stage 2 they produce and sell in the spot markets, subject to the installed capacity constraint. For example, Borenstein and Holland (2005) and Joskow and Tirole (2007), building on Boiteux (1949) and Crew and Kleindorfer (1976), have developed the benchmark model of optimal investment and production when (i) demand is uncertain at the time the investment decision is made, and ii) a fraction of the demand does not react to price. The former article considers the perfect competition case, while the latter introduces some elements of imperfect competition. Murphy and Smeers (2005) have developed models of closed- and open-loop Cournot competition at the investment and spot market stages, and characterized the equilibria of these games. Boom (2009) and Boom and Buehler (2014) have examined the impact of vertical integration on equilibrium investment, while Fabra et al. (2011) have examined the impact of the structure of the auction in the spot market on the equilibrium investment. A more recent literature (e.g., Garcia and Shen, 2010) examine multiperiod investment decisions. This article builds on the two-stage Cournot game formalized in Zottl (2011).

   A second group of works describes and analyzes the possible corrective mechanisms. (2) Stoft (2002) discusses average Value of Lost Load (VoLL) pricing, Hogan (2005) proposes an energy cum operating reserves markets, and Cramton and Stoft (2006 and 2008) and Cramton and Ockenfels (2011) propose a financial reliability options mechanism. (3) Joskow and Tirole (2007) show that a capacity market and a price cap do not restore the first best with more than two states of the world. Chao and Wilson (2005) examine the impact of options on spot market equilibrium, investment, and welfare. Zottl (2011) determines the welfare maximizing price cap in the spot market. However, none of these works presents a rigorous comparison of these mechanisms in a general and common setting. This article bridges these two strands of literature, that analyzes the proposals described in the second group of articles using a rigorous economic model developed in the first group: an extension of the two-stage Cournot model developed by Zottl (2011) to include both "price reactive" customers and "constant price customers", the latter being unable to react to spot energy prices and being rationed in some instances (Borenstein and Holland, 2005, Joskow and Tirole, 2007, Stoft, 2002, and Hogan, 2005). Its contribution is to propose clear policy recommendations, building on the economic analysis of these mechanisms. While this work's primary focus is the electric power industry, the analysis presented here can serve as a basis to examine (under)investment issues in other industries where participants must select capacity in the presence of significant demand variability and uncertainty and limited storage possibilities, for example telecommunications and transport networks.

   This article yields three main analytical findings. First, it examines the equilibrium of markets where energy and forward physical installed capacity certificates are separately exchanged. This is the case for example in the Northeast of the United States: 3 to 5 years ahead, the SO procures from producers physical capacity certificates (usually 15 to 20% higher than anticipated peak load to protect against supply and demand fluctuations). The cost of these purchases is then passed on to customers. Proposition 1 shows that the SO must impose a "no short sale" requirement, i.e., require producers to sell less certificates than have installed capacity (or to build as much capacity as they have sold certificates). If she does, a physical capacity certificates market restores investment incentives: the resulting capacity installed is optimal. For a given price cap, social welfare is thus maximized. However, producers profits are higher than the imperfect competition outcome without the capacity market. Numerical illustration suggests the additional rent from the capacity market is not negligible, that ranges ranges between 10 to 16% of the investment cost.

   Second, this article analyzes the equilibrium of another form of forward markets, where producers are required to sell, through the SO, financial call options to customers, covering all the demand up to a certain level at a given strike price. Option sellers pay customers the difference between the actual spot energy price and the strike price (Oren, 2005, Cramton and Stoft, 2006 and 2008, Cramton and Ockenfels, 2011).

   Proposition 2 proves that options sale reduces but does not eliminate market power. Installed capacity is higher with options sale than without, but still lower than socially optimal. To ensure optimal investment, the SO must again impose a "no short sale" requirement. If she does, Proposition 3 shows that financial reliability options and physical capacity certificates with the "no short sale" conditions are equivalent if the "technical" parameters are identical (e.g., if the option strike price equals the wholesale price cap). Reliability options thus also sur-remunerate strategic underinvestment. While Propositions 2 and 3 are consistent with Chao and Wilson (2005) and Allaz and Villa (1993)'s theoretical analysis of the interaction between forward and spot markets, they are new to the literature.

   Finally, this articles examines the "energy cum operating reserves market" proposed by Hogan (2005). SOs procure operating reserves to protect against an unplanned generation outage. Hogan (2005) proposes the SO balances supply against demand for energy and operating reserves, using the average VoLL as a price cap. Producers should receive additional revenues since: (i) the resulting power price is higher than when the SO balances supply against demand for energy alone, and (ii) capacity providing operating reserves--but no energy--is remunerated. This additional revenue is expected to resolve the missing money problem, hence restores investment incentives. However, Proposition 4 shows this intuition is invalid: since these additional revenues are already accounted for in the determination of the installed capacity, the situation is isomorphic to standard peak-load pricing.

   Each of these three mechanisms is examined individually in this article, while they may be implemented jointly in practice. For example, most US markets have a physical certificate mechanism and co-procurement of energy and operating reserves.

   The analysis yields clear policy recommendations. If policy makers and the SO are confident a market is sufficiently competitive, as may be the case in Texas, there is no need to impose a price cap and set up a forward capacity market (physical or financial), which are complex and costly to administer. Average VoLL pricing or an energy cum operating reserves market are simple to set up and, if the VoLL used is close enough to the real VoLL, cause limited distortion compared to the optimum. Furthermore, an energy cum operating reserves market remunerates flexibility, an important issue which...