About a month ago, I wrote about what has since become known as Winter Storm Uri and how it affected communities and the energy sector. At this point, after many hearings at the state and federal levels, I am writing to summarize what I have heard from public power utilities from Texas to Illinois to Arizona (yes, Arizona) about what went right, what went wrong, and what needs to change.
What Went Right
System integrity was maintained. The physical infrastructure was not significantly impacted by the massive fluctuation in the sudden supply/demand imbalances experienced primarily in the Electric Reliability Council of Texas (Texas), Southwest Power Pool (states geographically north and east of Texas), and Midcontinent Independent System Operator (states north of SPP’s footprint). Electrical fluctuations can cause physical damage when transformers blow, and, if not managed properly, power plants can be damaged at the point of interconnection. Many people have heard a transformer blow, or even seen one catch fire, when the imbalance occurs at the distribution level. If that happens at the bulk power system level – with large transformers, transmission lines, and generation facilities – it would be extremely problematic. This is all a result of the physics of electricity – it is not storable on a very large scale (yet) and must be generated and consumed instantaneously. To maintain that balance 24/7/365 is a feat – requiring lots of planning, contingency planning, and as much redundancy as customers are willing to pay for.
The preventative measures put in place by ERCOT, SPP, and MISO included “load shedding,” whereby distribution utilities had to take customers (i.e., load) offline – whether throughout their service territories or in parts of them. This enabled the bulk power system to rebalance without overloading and causing that physical damage. Our members, public power utilities, are such utilities – also known as “load-serving entities.” Each of these entities has plans in place to manage such load-shedding events within their service territories, which are typically the boundaries of cities or towns but can be entire counties or sub-counties. These plans are uniquely configured based on the characteristics of the community (e.g., which customers are most vulnerable to loss of electricity, how much onsite power generation they have, and the physical configuration of their electrical systems). Because of these variables, each public power utility managed the load-shedding event slightly differently. But they were “all-hands-on deck,” working at every moment to keep the power on, restore power, or rotate outages.
What Went Wrong
From what I have heard and read, there was some miscommunication from grid operators, at least in ERCOT, about the speed at which load shedding from load-serving entities was going to happen. There was also an assumption that rotating outages were possible, when in some places they were not – this is a complicated engineering situation that I could not completely explain even if I tried.
Because this event was so massive, distribution utilities and grid operators couldn’t really exercise response plans well in advance. There will certainly be lessons learned about how to manage such events in the future. Then again, we don’t want this to happen again in the future, which leads me to another, much more fundamental, situation that went wrong.
Supply was severely limited at the same time that demand was unexpectedly high – not good. We all know that power plant winterization was an issue for some in Texas, although not so much for public power members. Their communities invested in such winterization, especially after a harbinger event in 2011. Winterization also was more the norm in the SPP and MISO regions, although my members there said they were concerned about diesel fuel freezes, especially when they had to use it as a replacement for natural gas. It was really cold – even colder than many in those cold states had experienced in recent memory, and for such a sustained amount of time. My member utilities want to keep the lights on – they have done so better than their peers for years (check out U.S. Energy Information Administration data for verification) – they are going to set themselves up as much as possible to do so. In many cases, they have onsite generation in the form of natural gas, diesel, dual-fuel gas and diesel, coal, community solar, and even things like landfill-gas-to-energy. During the storm, they were required to share that generation for the good of the entire system – for the reasons cited above. That was the right thing to do and it would have helped even more if they had access to more natural gas. At the bulk power system level, the wind wasn’t blowing much (in SPP/MISO) and some turbines were frozen (ERCOT), so the need for natural gas was even more acute. It was there, but not in the quantities it should have been.
And, for the gift that keeps on giving … not only was a large chunk of natural gas supply unavailable when it was most needed, it was priced at levels that are almost unimaginable – 16,000% higher in some cases. As publicly owned, not-for-profit utilities, my members hedge their fuel prices as much as possible, and, as mentioned above, they also invest in physical hedges – i.e., other power plants – when possible. But you can’t plan for the price increases they experienced during Winter Storm Uri. These prices were felt as far away as Arizona and wiped out some annual fuel budgets in just a few days.
What Needs to Change
The supply issue is serious and must be remedied. Natural gas is an essential fuel for electricity – and electricity is needed to pump natural gas, so the relationship is symbiotic. I’m surprised that there is not more of an outcry that a fuel source so essential was not there when it was needed. The time has come to remedy that situation.
There was also the circumstance that power plants were offline for scheduled maintenance. The irregularities of the weather patterns lately may mean that such planned maintenance needs to be staggered, or otherwise managed more granularly in the future – at face value, a relatively easy fix.
One question my members and I have is whether market manipulation (price gouging) was involved, a la Enron (Note the Federal Energy Regulatory Commission is investigating whether such gouging occurred and I just sent a letter with Dave Schryver of the American Public Gas Association asking the Commodity Futures Trading Commission to investigate as well). We also have questions about how both the gas markets and the electricity markets allowed prices to stay so high without some sort of off-ramp mechanism. And what about the “gas day” versus the “electric day”? The issue from the electric side is that you have to lock in fuel before gas traders go home for the weekend, at whatever the price is at that point. In the case of Winter Storm Uri, which happened over a holiday weekend, prices had to be locked in for even longer, with no chance to adjust for three days. While I recognize there are scheduling and planning concerns from the natural gas side, something’s got to give.
These and many other questions deserve answers. We at APPA are working with our members to craft solutions for policymakers to consider implementing so that this doesn’t happen again.