Coal and Oil Prevented US Blackouts this Winter

  • Date: 08/04/18
  • Dr John Constable: GWPF Energy Editor

New data and analysis from the US government shows that during the recent Bomb Cyclone storm of late December 2017 and early January this year, the electricity system of the eastern half of the country avoided blackouts only because of increased output from conventional sources, particularly coal and, incredibly enough, oil. The performance of renewables was disappointing. The warning for Europe is loud and clear.

From the 27thof December 2017 to the 8thof January 2018, the eastern half of the United States was severely affected by a major winter storm, referred to as a Bomb Cyclone . The high winds and low temperatures resulted in a substantial increase in consumer demand for energy, putting the electricity system, in particular, under major additional pressure. The system succeeded in meeting this demand, but the way it did so, through increased use of conventional energy, and in spite of mediocre to poor performance from renewables, has raised serious questions about the country’s ability to withstand similar shocks in the future, when much conventional capacity, mostly coal, will have retired without replacement.

The story is told in detail in a new study by the US government’s National Energy Technology Laboratory (NETL). The NETL authors provide a detailed analysis of the performance of the electricity sector during the cyclone, covering six Independent System Operator (ISO) areas:

  • ISO New England (ISO-NE)
  • New York ISO (NYISO)
  • PJM Interconnection (the largest of the ISOs, covering all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tenessee, Virigina, West Virginia, and the District of Columbia)
  • Midcontinent ISO (MISO)
  • Southwest Power Pool (SPP)
  • Electric Reliability Council of Texas (ERCOT).

The following map, not included in the study, shows the extent of the geography:

Figure 1: North American Regional Transmission Organizations. Source: Federal Energy Regulatory Commission (FERC).

The additional daily average demand for electricity over these areas, in the period 1 December to 26 December, just priorto the storm, was 6.3 TWh per day. During the storm, from the 27thof December to the 8thof January, daily load rose by just under 20% to 7.5 TWh per day, giving an additional daily load of about 1.2 TWh due to the storm (see Table 1–15 (p. 19). To put that in scale, average total daily transmission system load in the UK over December and January this winter has never exceeded 1 TWh per day. Even for a generation network as vast as that of the US, this incremental load was very large indeed.

In order to meet this additional requirement for electrical energy, conventional power stations had to increase their output. Coal rose by 63%, natural gas fuelled generators by 20%, nuclear by 5.3%, and various kinds of oil and, critically, duel fuel generators by 26%.

Renewables did not increase their output, with wind generation during the storm period actually falling by 12% as compared to the pre-storm period, thus contributing to the problems faced by the conventional sector. The authors of the study write:

cloud cover and wind speeds outside of operational parameters caused a reduction in average daily contribution from intermittent renewables during the BC event, essentially imparting a resilience penalty to the system. This resulted in a need for dispatchable fossil generation to make up this generation in addition to its resiliency role in meeting the greater demand during the event. (p. 4)

In other words, low solar output due to cloud cover and wind turbines shutting down to prevent mechanical damage in high winds, a phenomenon well-known in Europe, resulted in substantial declines in output. This was particularly evident in the crucial PJM area. NETL observes:

The low availability of renewables, particularly wind power, in PJM was substantially more evident in the Midcontinent ISO (MISO), Southwest Power Pool (SPP) and Electric Reliability Council of Texas (ERCOT) RTOs with declines in wind and solar output during the B[omb] C[yclone] of 19 percent, 29 percent, and 32 percent, respectively. (p. 5)

Indeed, it would be logical to attribute that large renewables shortfall to the storm, giving an incremental load resulting from the storm of 1,374 GWh, which is in fact what conventional generators had to supply, as shown in this chart from the NETL study:

Figure 2: Aggregate, average incremental daily load in the ISO-NE, NYISO, PJM, MISO, SPP, and ERCOT regions, during the Bomb Cyclone, 27 December 2017 to 8 January 2018. Source: NETL.

It was conventional energy, predominantly coal, that guaranteed security of supply, and the NETL authors leave no doubt as to the consequences if it had not done so in the crucial PJM zones:

“[…] without available capacity from partially utilized coal units, PJM would have experienced shortfalls leading to interconnect-wide blackouts” (p. 1).

Locally, there were important variations in this general pattern, and in New York and New England oil played the crucial role. Due to an increase in demand for natural gas for space and water heating, and limitations imposed by natural gas pipeline constraints, electricity generation from gas was unable to scale up, and the burden was transferred to oil as dual fuel generators switched over. Indeed, in New England, while wind and solar contributed less than 5% of generation at peak load, the region’s 6,200 MW of oil capable power stations contributed around 30% of peak load on every single day of the storm, consuming on average 160,000 barrels of oil per day (p. 10), a total of 2 million barrels over the storm (p. 4).

In the wake of this very narrow escape, the United States government will be doing some hard thinking. Improvements in natural gas pipelines in the New England area are now, obviously, a priority. Storms such as the Bomb Cyclone are thankfully infrequent, but, as the report notes they are not that unusual and indeed are “periodically certain” (p. 3). This will happen again. The question that the NETL study correctly raises is whether the  conventional electricity sector in the US will be of sufficient scale in the future to guarantee security of supply as it did this winter. As in Europe, and also thanks to decades of climate-dominated energy policy, the US power markets have weak to non-existent investment signals for conventional power, and NETL underlines the importance of rectifying this problem. President Trump’s support for coal, dismissed by many as mere politics, will certainly be reinforced by the experience of the Bomb Cyclone, and may even seem now to be rather prudent and far-sighted.

For European analysts and policy makers, the practical performance of the US system serves to bring into sharp focus what has been long suspected on theoretical grounds. In practice, the contribution of renewables to security of supply at times of exteme difficulty is negligible. Indeed, it is worse than that, since the presence of renewables imposes what the NETL authors drily term a “resilience penalty” (p. 15). The US electricity system would actually have been more robust without renewables. There is no reason for thinking that the European case is any different.



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