Integrating Thermal and Hydro Electricity Markets: Economic and Environmental Costs of not Harmonizing Pricing Rules.

• Author: Villemeur, Etienne Billette de
• Position: Report - Statistical data

1. INTRODUCTION

   While many economic and environmental issues have become global, electricity markets have, to a large extent, remained local. Despite the existence of numerous regional integration initiatives, many obstacles continue to hinder the transformation of electricity markets. In the United States, for instance, in 2005, strong state-level political opposition halted the plan to implement regional transmission organizations (RTOs), all of which following a standard market design (FERC, 2005). Even in Europe, where a 1996 European Union directive set the objective to progressively open the electricity market to create a single market, progress has been slow and plans had to be revised. If standard microeconomic theory would justify removing some regulation and barriers to trade, as many natural monopoly features have disappeared in the electricity sector, only a limited number of states have opted to harmonize their electricity market with that of their neighbors. Such integration would indeed lead to price and quantity adjustments, along with associated political challenges. As was clearly established in an important literature review commis-sioned by the World Bank (ECA, 2010) to look at regional power sector integration, these issues remain poorly documented. With the introduction of a model for analyzing the impact of trade and of the creation of a common market between two jurisdictions (i.e., the province of Ontario, Canada, where power generation is mainly thermal-based and the province of Quebec, also in Canada, where hydropower provides most electricity), our paper seeks to remedy this situation.

   Price, electricity production, consumption levels and GHG emission levels are estimated using various scenarios, permitting integration outcomes to be clearly illustrated. Our results show that if the hydro jurisdiction were to keep its average cost pricing regulation, while the thermal jurisdiction maintained its competitive market model, although trade would slightly improve total welfare, when ignoring GHG emissions, emissions would increase with trade. The welfare improvement would amount to $21.5 per tonne, which can also be seen as the GHG abatement cost associated with transmission capacity removal. By contrast, we estimate that a negative abatement cost of $37 per tonne could be achieved with greater integration, i.e., if electricity trade were complemented by the implementation of marginal cost pricing in the hydro jurisdiction. The story is however not the same for producers and consumers in both markets: while consumers in the thermal jurisdiction would stand to gain from trade and market harmonization, their counterparts in the hydro jurisdiction would lose out with the end of price regulation. Producers, on the other hand, would lose out with trade in the thermal jurisdiction but increase their profits in the hydro jurisdiction. When transmission capacity increases, all of these impacts increase.

   The rest of the paper is divided into four sections. In section 2, we provide a literature review. Section 3 presents the detailed hourly model, empirically calibrated to capture the features of electricity markets in two neighboring jurisdictions: Ontario and Quebec, both in Canada. The Ontarian market is depicted as the competitive "thermal" market, while the Quebec market is depicted as the average cost pricing "hydro" market. Results are discussed in section 4, which is followed by a conclusion.

2. LITERATURE REVIEW

   To date, most of the literature on electricity market reforms has looked at competition levels, market design, transmission pricing rules and other issues, in a context of isolated electricity markets (see for instance Newbery, 2000, or Stoft, 2002, and the abundant literature they refer to). Despite the important potential benefits of regional electricity market integration, literature on harmonization reforms is limited.

   This point is specifically documented in a substantial literature review that was made for the World Bank's Energy Sector Management Assistance Program, ECA (2010). It states that there are "few academic studies which have real theoretical depth [on regional power sector integration]" (ECA, 2010: 2) and that there is a need for "theoretical analysis of the way in which benefits are distributed" (ECA, 2010: 12). This is happening in a context where there exist many initiatives promoting regional power sector integration, especially in developing countries. See for instance WEC (2005) and UNECA (2006) for perspectives from international organizations on energy integration in Africa. UN (2006) attempts to make the case for international electric power grid interconnections, while clearly underscoring potential costs and institutional challenges. World Bank (2010) draws lessons from the study of various integration cases, both in developed and developing nations, and from a literature review (ECA, 2010). The review summarizes the following expected benefits from regional integration: improved economic efficiency (in a broad sense), reduced costs (in operations and investment), improved supply conditions and various possible social, environmental and even political gains (ECA, 2010: 4-5). There is however no mention of any rigorous analysis of such benefits or subset of benefits. Some assessments have been made, such as the economic benefits of RTOs in the U.S. (IFC, 2002), but they remain very general and provide little information on the distribution of benefits (among regional producers and consumers) and on environmental impacts. An exception is Finon and Romano (2009), who discuss the impact of market integration on producer's profits, in the lower cost jurisdiction, but welfare is not included in their analysis.

   A key issue in electricity market integration is the protection of "native load," which is associated with "end-use customers that the Load-Serving Entity is obligated to serve" (NERC, 2011). In most cases, such obligations come with a regulated price based on local production costs, which can be especially low if large amounts of hydropower are available. In the U.S., federal regulation promoting wholesale competition protects native load by making generation and transmission capacity planned to meet this native load unavailable to non-local purchasers. See in particular the Federal Energy Regulatory Commission (FERC) orders 888 and 890. This ensures that integration remains "shallow," as it only allows limited transactions, and maintains potentially important price differences between neighboring markets.

   Our paper presents a two-market model for assessing "shallow" and "deep" integration, to use the World Bank (2010) terminology. In the first case, the two jurisdictions are interconnected but keep their distinct market organization: one is competitive and the other follows an average-cost pricing regulation. In the second case, both jurisdictions are competitive: native load commitments are removed. Changes in outcomes can clearly be observed from the three integration regimes: no interconnection (autarky), shallow and deep integration.

   The paper's contribution is twofold. First, it proposes a model for straightforward comparison of shallow and deep integration outcomes, with detailed impacts on consumers, producers and emission levels. Second, it provides empirically-based welfare estimates of GHG abatement costs in the electricity sector. By including transmission constraints and costs, it also captures their impact upon the electricity trade.

   The paper builds on a stream of articles dealing with associated topics. Billette de Villemeur and Pineau (2010) identified conditions under which trade between two jurisdictions is environmentally damaging, without, however, looking at any change in market organization. Billette de Villemeur and Pineau (2012) focused on such market changes (integration regime changes), but from a purely theoretical perspective, and without considering intertemporal arbitrage in the hydro jurisdiction. In Billette de Villemeur and Pineau (2012), a key result is that deep integration, as compared to shallow integration, yields a decrease in total consumption and an increase in the overall welfare. This result is empirically illustrated in this paper, further making the point that deep integration could be beneficial, especially from an environmental perspective.

   Intertemporal arbitrage possibilities are studied in Billette de Villemeur and Vinella (2011), but in a single market. The current paper uses, and expands upon, the model found in Forsund (2007). However, in his study of hydropower economics, Forsund did not look at a regulated hydro jurisdiction trading with a competitive one, as is the case here. The Forsund model was recently used in Green and Vasilakos (2012) to study wind and hydro trade between Denmark and Norway. These two countries have a competitive market. In this paper, we look at Ontario and Quebec, two neighboring Canadian provinces that are engaged in trade, but with very different pricing rules.

3. TRADE IN ELECTRICITY MARKETS: A MULTI-PERIOD ANALYSIS

   Our model, which is formally presented in section 3.2, focuses on the role of hydropower, which requires multiple periods when storage is available. Indeed, thermal electricity is seldom constrained by the available quantity of primary energy (uranium, coal, natural gas or oil) and, as compared to demand fluctuations, production costs are essentially stationary. Market equilibrium analysis can thus legitimately be performed in a static framework when the entire electricity supply stems from thermal technologies. By contrast, hydropower supply is almost completely inelastic, due to the exogenous character of water provision (i.e., water inflow from rainfall). When a dam is used, hydro production can be easily modulated to meet time-varying demand. Indeed, water reserves can be almost freely allocated across time if there is sufficient storage...