2020 was a year of change and hardship, a year the global pandemic changed lives, hammered the global economy, and disrupted normal routines. It also was a year that the results of modeling for the Council’s next Northwest power plan predicted an energy future that is nothing short of revolutionary.
In response to the pandemic, the Council, like so many other employers, closed it offices and asked its employees to work remotely. The timing was challenging in that the Council’s Power Planning Division staff were hard at work on the next power plan, due to be released in draft for public comment this July. The plan, which the Council revises every five years, guides the Bonneville Power Administration in its decisions about how to meet the future electricity needs of its more than 140 public utility customers across its 300,000-square mile service territory in the Northwest.
Despite the disruption of the normal routine, the staff, Council members, and the Council’s power-planning advisory committees continued to meet, if virtually. In the midst of a most unusual year, the analysis and power system modeling that underlies the plan developed some most unusual – if still preliminary – results.
Now, with the end in sight, the Council’s power planning director, Ben Kujala, took the opportunity at the April meeting of the Council’s Power Committee to reflect on the lengthy process to date and the preliminary modeling results, which he described as “revolutionary.” He said the analyses for the 2021 Plan will break new ground in several areas. These include:
- Incorporating climate change risk at every level of input and analysis
- Detailing the role of hydropower generation in a changing energy landscape that increasingly eschews traditional, thermal generating resources in favor of more renewable energy
- Capturing transformation in the mix of electricity generating technologies in the West and the associated impacts to the wholesale power market
- Allowing for electricity resource decisions that are responsive to the social cost of carbon – the cost we are willing to pay as a society to reduce the impacts of carbon emissions
- Demonstrating that the economics of renewable resources have changed dramatically – flipped, in fact – compared to what was accepted just a few years ago.
Work on the new plan began in February 2019, and by August 2020 it was evident that the models, using traditional utility planning inputs, were showing results that seemed highly irregular.
“In that month, we presented a draft electricity price forecast to the Power Committee,” Kujala recalled in a memo to the committee this month. “This was the cumulative result of countless hours collecting policy targets, potential loads, resource costs, and etc. The preliminary result had a forecast of building 50,000 megawatts of new natural gas generation in the Western Electric Grid, which did not sit well with our advisory committees or the Power Committee.”
Part of the reason for the huge buildout of natural gas-fired power plants was to replace the power generated by aging coal-fired power plants that are being retired throughout the West. These retirements are in response to factors such as the cost of running the plants and also state policies requiring that emissions of greenhouse gases like carbon dioxide must be reduced dramatically over the next 20-30 years. So it was something of a nonstarter to suggest a massive amount of new, natural gas-fired generation.
Why did the Council’s model suggest such a thing?
“The forecast still had elements of how we’d forecast prices in our previous power plans,” Kujala explained. “It used methods prevalent in the utility industry that have been through dozens if not hundreds of utility Integrated Resource Plans. But we had hit a point where standard industry planning practices diverged starkly from the policy landscape in the West.”
With state policies focused on reducing carbon emissions, it obviously was time for the Council’s models to be recalibrated to reflect the new reality.
“So the Power Committee asked for an alternative perspective that limited new natural gas generation, and over the next four months we struggled to find a forecast that balanced power system adequacy with heavy limitations on new natural gas generation,” Kujala wrote.
The revised modeling predicted thousands of megawatts of new renewable resources, primarily solar power, and energy storage, that, Kujala wrote, “far exceeded my expectation.” One reason the modeling picked renewables was that their cost has come down dramatically over the last decade or so, compared to other types of generation. Another reason was that the huge renewables buildout “represented the aggregation of public policy and a power system that moved beyond natural gas generation as a technology to replace retiring resources and support new load.”
Building fewer renewable energy plants than the modeling suggested was either more expensive because of the mix of renewable and thermal technologies, or less adequate and thus degraded the reliability of the electric grid, he said.
So as the Council progresses toward a revolutionary new power plan that responds to revolutionary changes in how electricity is generated in the West, Kujala sees challenges ahead – how to maintain reliability in an altered grid, how to find a robust resource plan when so much uncertainty lies outside the region’s borders.
“The 2021 Plan likely will leave us with a full slate of new questions and future analytical challenges,” he said. “But still, I expect a revolutionary plan that breaks with the past, and I believe it will meet the moment.”