What Moves the Ex Post Variable Profit of Natural-Gas-Fired Generation in California?

• Author: Woo, Chi-Keung
• Position: Financial report

1. INTRODUCTION

   This paper is motivated by Professor Paul Joskow's insightful observation that: "Revenue adequacy has emerged as a problem in many organized wholesale electricity markets and has been of growing concern in liberalized electricity markets in the U.S. and Europe. The revenue adequacy or 'missing money' problem arises when the expected net revenues from sales of energy and ancillary services at market prices provide inadequate incentives for merchant investors in new generating capacity or equivalent demand-side resources to invest in sufficient new capacity to match administrative reliability criteria at the system and individual load serving entity levels" (Joskow, 2013, p. i).

   Joskow's observation applies to California and mirrors the concern of Peter Griffes, a senior manager of Pacific Gas and Electric Company (PG&E): (1) "Energy revenues based on competitive prices are often not compensatory to cover longer-term cost of building and operating a new plant. For example, in the California market in 2013, the Department of Market Monitoring estimated that energy market revenues for a new combined cycle plant would be $296.39/kW-yr. in comparison to the $256.78/kW-yr. in operating costs and $175.80/kW-yr. in annualized fixed costs" (Griffes, 2014, p. 27).

   The "missing money" problem stems from two transformative events that took place in the electricity industry around the turn of the century. The first event comprises the electricity market reforms that have resulted in competitive wholesale markets in parts of Europe, North America, South America, Australia, and New Zealand (Sioshansi and Pfaffenberger, 2006; Woo et al., 2006a; Sioshansi, 2013). Wholesale electricity spot-market prices are inherently volatile due to: (a) daily fuel-cost variations, especially for the natural gas that is now widely used by combustion turbines (CT) and combined-cycle gas turbines (CCGT); (b) hourly weather-sensitive demands with intra-day and inter-day fluctuations, which must be met in real time by generation and transmission facilities already in place; (c) planned and forced outages of electrical facilities; (d) hydro conditions for systems with significant hydro resources; (e) carbon-price fluctuations affecting thermal generation that uses fossil fuels; (f) transmission constraints that cause transmission congestion and generation re-dispatch; and (g) lumpy capacity additions that can only occur with long lead times (Li and Flynn, 2006; Bunn and Fezzi, 2007; Woo et al., 1998, 2007; Tishler et al., 2008; Newcomer et al., 2008). (2)

   These volatile spot-market prices, even with occasional spikes during hours of severe shortage, may not suffice to justify the generation investment necessary for reliable grid operation (Neuhoff and De Vries, 2004; Wangensteen et al., 2005; Roques et al., 2005; Newbery, 2010; Milstein and Tishler, 2012; Brattle Group, 2012; CAISO, 2014c). To remedy the "missing money" problem, capacity markets were introduced in the late 1990s in the U.S. deregulated markets of California, New York, PJM, and New England (Spees et al., 2013). A notable exception is Texas (Brattle Group, 2012), which continues to use an energy-only market design with a high price cap (e.g., US$7,000/MWH in 2014) to provide generation investment incentives.

   The second event contributing to the "missing money" problem is the development of wind and solar generation in many parts of the world due to resource abundance (e.g., Hoogwijk et al., 2004; Lu et al., 2009; Marini et al., 2014) and government policies that include easy and low-cost transmission access, financial incentives (e.g., feed-in-tariffs, government loans and grants, and tax credits), and quota programs (e.g., renewable portfolio standards (RPS)), cap-and-trade programs for carbon emissions certificates, and renewable-energy credits). (3)

   Wind generation displaces thermal generation with relatively high fuel costs and reduces wholesale market prices (European Wind Energy Association, 2010). This price-reduction effect, also known as the merit-order effect, has been demonstrated through model simulations (e.g., Morales and Conejo, 2011; Traber and Kemfert, 2011), as well as through regression analysis of market data for Spain (Gelabert et al., 2011; Gil et al., 2012), Germany (Sensfu[beta] et al., 2008), Denmark (Munksgaard and Morthorst, 2008; Jacobsen and Zvingilaite, 2010), Australia (Cutler et al., 2011), Texas (Woo et al., 2011b), PJM (Gil and Lin, 2013), the Pacific Northwest (Woo et al., 2013), and California (Woo et al., 2014a). While benefiting electricity consumers (e.g., Gil and Lin, 2013; Woo et al., 2011a, 2013, 2014a), the merit-order effect weakens the investment incentive for the CT and CCGT, as documented by the simulation study of Traber and Kemfert (2011), the regression analysis of Woo et al. (2012), and the descriptive assessment of Steggals et al. (2011). (4)

   The goal of this paper is to answer the question: what moves the ex post variable profit of natural-gas-fired generation in California, the ninth largest economy in the world? (5) Based on a regression analysis of a large sample of over 32,000 hourly observations over the 45-month period of April 2010 through December 2013, our answer disentangles the state's "missing money" problem, thereby highlighting the challenges in developing energy policies for a clean, reliable, and affordable electricity future (CEC, 2014). In particular, wind and solar generation development tends to reduce energy market prices in California. But it may also reduce investment incentives for the CT and CCGT, whose flexibility is essential for the California Independent System Operator (CAISO) to maintain the state's load-resource balance in real time (Griffes, 2014; CAISO, 2014a). Similarly, while expanding demand response (DR) programs can clip the state's peak demand, (6) it may also cut the market price spikes that afford the most profitable opportunities for a CT or a CCGT plant.

   Our regression-based analysis comprehensively examines the ex post, or realized, profit effects of a set of fundamental drivers on natural-gas-fired generation in California. These drivers include the natural-gas price, system loads, nuclear capacities available, hydro conditions, (7) and renewable-generation resources of small hydro, solar, and wind. (8) We are unaware of any study that has undertaken a similar examination to jointly assess the profit effects of all these drivers within a single empirical analysis.

   Based on the background information in Section 2, we choose California for our analysis of the ex post variable profit, which is defined here as the non-negative per MWH payoff, V = max(hourly price--per MWH variable generation cost, 0), from an assumed 1-MW ownership of natural-gas-fired generation. (9) For conciseness, we use the term "profit" to mean "ex post variable profit" throughout the rest of the paper.

   Consistent with what one would expect, we find that an increase in load within an electric region tends to increase profits from a gas turbine. Profits are reduced by increases in generation from baseload nuclear plants and wind farms. Our data analysis, however, reveals that changes in solar generation have a statistically insignificant effect on the profitability of natural-gas plants, although one may anticipate that this will change as solar energy increases its generation share in California's electricity market. Though raising a natural-gas power-plant's operating cost, an increase in natural-gas prices nonetheless enhances the plant's profits.

   This paper makes the following contributions. First, the analysis is new and comprehensive, and extends the extant studies, which in the main focus on the profit effect on market prices of a single resource such as wind generation (Steggals et al., 2011; Traber and Kemfert, 2011; Woo et al., 2012) or nuclear generation (Traber and Kemfert, 2012).

   Second, the paper reports the diminishing investment incentives for natural-gas-fired generation under California's adopted energy policy that promotes DR and renewable energy. (10) It corroborates the positive price and profit effects of nuclear-generation-plant shutdowns in Germany, which were estimated by Traber and Kemfert (2012).

   Third, its finding of diminishing investment incentives supports the state's adopted resource-adequacy program: " [e]ach LSE [load serving entity] is required to file with the [California Public Utilities] Commission demonstrating that they have procured sufficient capacity resources including reserves needed to serve its aggregate system load on a monthly basis. Each LSE's system requirement is 100 percent of its total forecast load plus a 15 percent reserve, for a total of 115 percent." (11)

   Finally, the paper enriches the extant literature by presenting an approach that can be used to analyze the profits from natural-gas-fired generation in other deregulated electricity markets that have data similar to those of California (e.g., Alberta and Ontario in Canada; Texas, PJM, New York and New England in the U.S; Germany and Spain in Europe; and Australia and New Zealand in the Asia Pacific region). For example, the same approach can be used to analyze how the retirement of baseload coal-power plants, aimed at reducing emissions of coal-fired generation (Venkatesh et al., 2012), affects the profit of natural-gas-fired generation.

   The paper proceeds as follows: Section 2 provides the background for our analysis; Section 3 presents our methodology; Section 4 describes our data and documents their construction; Section 5 presents our results; and Section 6 provides general conclusions.

2. BACKGROUND

   In addition to the state's size (12) and data availability, (13) we choose California for our study because it has features that enable an estimation of the profit effects of a set of fundamental drivers. First, the CAISO uses a nodal market design with real-time markets (RTM)...