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| 1 |
ID:
137665
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| Summary/Abstract |
Hong Kong's electricity service is superbly reliable and price-reasonable when compared to those of the major cities in the OECD countries. Based on the rate of return regulation in the U.S., the current scheme of control agreement (SCA) regulating the two local integrated investor-owned utilities (IOUs) will expire in 2018 (or in 2023 after an optional 5-year extension), thus offering an opportune time to consider proposals with long lead time to modify or replace the SCA. The proposals made to date range from modifications of the SCA to electricity market restructure. These proposals, however, overlook two important aspects of regulatory governance: transparency and public involvement. This paper estimates consumer support for the proposal to establish a Hong Kong public utilities commission (HKPUC) to improve the current regulatory process. Based on the responses collected in mid-2014 via a face-to-face survey of 1100 Hong Kong residents, we find that at the 1.5% bill surcharge, about 70% the respondents are estimated to support an HKPUC. Thus, there is sufficient consumer support for a financially viable HKPUC, implying that Hong Kong should consider the possibility of establishing an HKPUC, notwithstanding the substantial challenges to be overcome prior to its implementation.
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| 2 |
ID:
119811
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2013.
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| Summary/Abstract |
Based on an econometric analysis of the annual growth data for China's GDP and electricity generation from 1953 to 2010, we find that electricity generation growth Granger causes GDP growth, but not vice versa. We also find that the GDP elasticity of electricity generation is about 0.6, implying that a 1% increase in China's electricity generation growth would increase GDP growth by 0.6%. While Deng's reform raised China's GDP growth rate by about 5% per year, it did not alter the GDP elasticity of electricity generation. Hence, an obvious strategy to promote China's economic growth would be accelerating electricity generation expansion. Rapidly adding thermal generation units, however, could have large-scale, adverse environmental impacts. We therefore support China's 2011 five-year plan, which calls for expanding investments in renewable energy, conservation and energy efficiency as well as improving China's integrated electricity planning and cost-based pricing decisions.
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| 3 |
ID:
105813
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2011.
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| Summary/Abstract |
The literature on renewable energy suggests that an increase in intermittent wind generation would reduce the spot electricity market price by displacing high fuel-cost marginal generation. Taking advantage of a large file of Texas-based 15-min data, we show that while rising wind generation does indeed tend to reduce the level of spot prices, it is also likely to enlarge the spot-price variance. The key policy implication is that increasing use of price risk management should accompany expanded deployment of wind generation.
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| 4 |
ID:
150438
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| Summary/Abstract |
We answer two policy questions: (1) what are the estimated merit-order effects of renewable energy in the California Independent System Operator’s (CAISO’s) day-ahead market (DAM) and real-time market (RTM)? and (2) what causes the hourly DAM and RTM prices to systematically diverge? The first question is timely and relevant because if the merit-order effect estimates are small, California’s renewable energy development is of limited help in cutting electricity consumers’ bills but also has a lesser adverse impact on the state’s investment incentive for natural-gas-fired generation. The second question is related to the efficient market hypothesis under which the hourly RTM and DAM prices tend to converge. Using a sample of about 21,000 hourly observations of CAISO market prices and their fundamental drivers during 12/12/2012–04/30/2015, we document statistically significant estimates (p-value≤0.01) for the DAM and RTM merit-order effects. This finding lends support to California’s adopted procurement process to provide sufficient investment incentives for natural-gas-fired generation. We document that the RTM-DAM price divergence partly depends on the CASIO’s day-ahead forecast errors for system loads and renewable energy. This finding suggests that improving the performance of the CAISO’s day-ahead forecasts can enhance trading efficiency in California’s DAM and RTM electricity markets.
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| 5 |
ID:
171379
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| Summary/Abstract |
Faced with reserve margin projections well below the adopted target of 13.75% of the system peak forecast, the Public Utility Commission of Texas on 01/17/2019 ordered the state's grid operator, the Electric Reliability Council of Texas, to “right shift” the operating reserve demand curve (ORDC) to increase generators' revenue from energy sales in ERCOT's real-time market (RTM). Using a large sample of 15-min data for the backcast period of 01/01/2015 through 12/31/2018, we calculate the ORDC shift's impact on RTM prices and investment incentives for natural-gas-fired generation (NGFG). Had the ORDC shift been in effect in the backcast period, the resulting RTM price increases in 2018 could suffice to justify NGFG investment, though not in the prior years of 2015, 2016 and 2017. While the actual ORDC shift occurred on 03/01/2019 had a large impact on RTM prices in the ensuing six-month period of March–August 2019, Texas's planned renewable generation is expected to erode NGFG's operating profit, thus diminishing the ORDC's investment incentive over time. Hence, Texas's energy-only market design will likely need further refinements to solve the missing money problem of inadequate NGFG investment incentive.
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| 6 |
ID:
109362
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2011.
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| Summary/Abstract |
This viewpoint reviews renewable energy development in 14 markets that differ in market structure (restructured vs. not restructured), use of feed-in-tariff (FIT) (yes vs. no), transmission planning (anticipatory vs. reactive), and transmission interconnection cost allocated to a renewable generator (high vs. low). We find that market restructuring is not a primary driver of renewable energy development. Renewable generation has the highest percent of total installed capacity in markets that use a FIT, employ anticipatory transmission planning, and have loads or end-users paying for most, if not all, of the transmission interconnection costs. In contrast, renewable developers have been less successful in markets that do not use a FIT, employ reactive transmission planning, and have generators paying for most, if not all, of the transmission interconnection costs. While these policies can lead to higher penetration of renewable energy in the short run, their high cost to ratepayers can threaten the economic sustainability of renewable energy in the long-run.
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| 7 |
ID:
105812
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2011.
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| Summary/Abstract |
The extant literature on wind generation and wholesale electricity spot prices says little about how wind generation may affect any price differences between two inter-connected sub-markets. Using extensive data from the four ERCOT zones of Texas, this paper develops a two-stage model to attack the issue. The first stage is an ordered-logit regression to identify and quantify, for example, the impact of wind generation in the West zone on the estimated probability of a positive or negative price difference between the North and West zones. The second stage is a log-linear regression model that identifies and quantifies the estimated impact of wind generation on the sizes of those positive and negative price differences. It is shown that high wind generation and low load in the wind-rich ERCOT West zone tend to lead to congestion and zonal price differences, that those differences are time-dependent, and that other factors such as movements in nuclear generation and natural-gas prices, as well as fluctuating non-West zone loads, also play a role. The results have broad implications for energy policy makers that extend well beyond the borders of Texas and, indeed, those of the United States.
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