This winter’s series of cold spells in the US placed a serious strain on the ability of US power companies to meet significant spikes in peak demand. The situation was compounded, because, in the last ten years, power companies have expanded the use of natural gas to generate electricity. In the past, there was little connection between natural gas deliverability and the electrical system. Now, the two systems are closely connected. During summer peak load, there are few problems. In winter peak periods, however, demand for gas causes rises in gas prices and fills pipeline capacity for heating, crowding out gas for electrical generation. This winter’s experience has demonstrated that power companies and grid managers need to pay much more attention to these developments.
The staff at the Federal Energy Regulatory Commission has issued a preliminary report outlining causes and impacts of this winter’s colder weather.
One particularly interesting feature has nothing to do with gas-fired generation. It turns out that significant problems with coal-fired and nuclear powered generators contributed to this winter’s crisis.
Mechanical failures in generator systems, fuel deliverability and fuel handling problems in the extreme low temperatures experienced this winter led to high levels of forced generation outages. These levels contributed to the stressed conditions in the markets that lead to emergency actions and higher prices.
During the early January event, the RTOs estimate generation on forced outages and derates ranged from about 7 to 30% of the load on the peak day. Significant portions of those outages were related to fuel issues including gas curtailments, no fuel, oil delivery and frozen coal. For example, PJM estimates that about one quarter of the forced generation outages on January 7 were fuel related. In addition, 5,000 MW of combustion turbines failed to start when called. During the latter January events, gas curtailments declined in PJM as did start failures for combustion turbines. However lack of fuel, oil delivery and frozen coal persisted in causing forced outages of 5,000 MW and 8,000 MW in late January. Similarly, MISO experienced a large volume of outages on January 7, about 20% of those were fuel related, and lower but still significant outages during the later January cold weather events. NYISO also experienced a high level of fuel and cold weather related outages on January 7, which declined significantly during the latter January and early February cold events. Although SPP lost generation on January 6 due to gas supply constraints, they experienced no weather related outages during the later January and early February cold weather events. ISO-NE experienced a lower level of forced generation outages on January 7 relative to other RTOs, however all of the outages were attributed to intraday natural gas procurement difficulties. ISO-NE experienced similar levels of outages on January 22 and 27 with under 15% attributed to fuel issues. However, as noted above, these forced outages did not cause the ISO or RTOs to drop firm load and overall, generator performance generally improved after the January 7 event.
So the electrical system’s problems weren’t just caused by not enough natural gas pipeline capacity for both heating and power generation. The cold weather affected all fossil fuel generation. We know from FirstEnergy’s recent investor call that the company was forced to buy electricity on the spot market just when prices were at their highest because one of their biggest coal burning units was down and a 960 MW unit of the company’s Beaver Valley nuke plant was down during the coldest weather. Big base load generators are reliable, except when they aren’t. When big units are down, they leave huge holes in the electric grid.
As the FERC staff’s report points out, despite a very complex combination of causes and effects, overall, the system was able to cope with the large number of problems. And there was one important resource that did not depend on fuel at all.
Demand response resources were activated to help manage the emergency. PJM activated about 2,000 MW of demand response resources for several hours during the morning and evening peaks of January 7. Over 2,500 MW of demand response resources were activated for several hours on January 23 and on January 28. NYISO requested voluntary reduction from about 900 MW of its demand resources on January 7. Demand resources were notified of possible deployment on January 28, but were not activated. ISO-NE’s Winter Procurement Program provided 21 MW of demand response on five occasions during the winter. MISO didnot activate their demand response programs during the winter events.
Note that 2500 MW is almost equal to a big coal-burning plant, such as WV’s John Amos.
The other interesting part of the report has to do with a new cost that has been introduced into the electrical system by deregulation. Five of the last pages of the 21 page report deal with attempts by FERC to detect manipulation of electricity markets during the times when supplies were tightest and prices were peaking. In times of crisis, as Enron demonstrated clearly in its California criminality, the big banks and energy traders have opportunities to feast on everyone else’s problems. This is a cost that did not exist when all power companies were confined to state boundaries and were all regulated by state regulators. The pages on manipulation lack the detail and statistical description that staffers used in the rest of the report. That’s because traders’ actions are hard to detect in the millisecond operation of trades and transfers in the real time electricity markets. It is likely that very little of the fraud and manipulation by energy traders ever faces FERC enforcement action.
The FERC report is a quick read and gives you a good snapshot of the brave new world of electricity that we now inhabit.