The New Normal for Electricity Markets Conjures Bad Memories; Forewarned, Will We Be Better Prepared?

March 1, 2019.

A Friday.

The weekend lay ahead; it was a normal day, right?

Not if you were in the electric power sales business. In that industry, one that is virtually hidden to most people – you flip a switch, the lights come on – the day was anything but normal. And that abnormality was a sign of a rapidly emerging new normal, a new normal that, on that day, was three things for those who supply the electricity we all consume in the Northwest: instructional, a harbinger of the future, and an unsettling reminder of the past.

“On March 1, the warning light came on. What are we going to do about it?” asked Larry Bekkedahl, vice president for grid architecture, integration, and system operations at Portland General Electric. He was a panelist at the annual Northwest Power Markets Conference, a gathering of electric utility executives, utility regulators, and energy organizations in Portland in May. This year, the conference, co-hosted by Energy NewsData, publisher of the weekly energy industry newsletter Clearing Up, and CJB Energy Economics, a Seattle consultancy, focused on a theme that captures the moment: Transition in Progress.

Charlie Black, principal of CJB Energy Economics, said the event was an opportunity for people in the industry to talk to each other, compare notes, and discuss change and solutions. “We’ve been talking about change in the industry for years,” said Black, a former power planning director at the Power and Conservation Council. “Now we are in the process of implementing change in the industry.”

The present moment has an element of déjà vu as well as anxiety. That is because some of the same events that played out in the late 1990s and led to the disastrous energy crisis of 2000/2001, when wholesale electricity prices briefly spiked to nearly 100 times normal and stayed high for months, may play out again in the Northwest. The question raised over and over at the Portland conference was, “this time, will we be ready?” The answer is yes, probably, but a number of actions need to be taken to ensure the power system remains reliable, adequate, and affordable.

The primary concern is over what power planners call capacity – the ability to meet (usually) brief periods of high demand for power – a cold snap or a heat wave, for example, when demand rises sharply for hours and sometimes days at a time. The situation in 2019 has eerie similarities to the Northwest energy situation in the late 1990s, when there were several years of under-investment in energy generating and efficiency resources, which resulted in a reduced West coast supply. The crisis of prices was triggered by the onset of poor hydropower conditions in the late spring of 2000, and lasting into the winter, leading to the second-lowest Columbia River runoff in 2001 since 1929. The near-record low runoff resulted in almost 4,000 average megawatts less hydroelectric energy available than in an average year (4,000 average megawatts would supply about 3.1 million Northwest homes under normal conditions), and even less compared to the relatively wet years of 1995-1999. The crisis was made much worse by a deeply flawed electricity market design in California and opportunism by some of the participants in that market that led to price manipulation. Prices spiked for at least an hour on a cold day in December 2000 at more than $1,200 a megawatt-hour, compared to a normal price of around $50. Prices came down but remained high, forcing utilities that needed power to pay high prices, impacting residential, commercial, and industrial ratepayers.

Fast forward to March 1, 2019, when prices exceeded $900 per megawatt-hour, driven up by lingering cool temperatures, low river runoff, depletion of natural gas storage both in the Northwest and in California (natural gas is the fuel for many power plants), and low electricity exports to the Northwest from California driven by policy requirements of one of the state’s largest utilities. The next day, prices relaxed to normal, but for that one day the cost was very high. It was, as Bekkedahl said, a warning.

Concerns about future resource adequacy in the Northwest are growing because several western states including Washington and California have recently passed laws – Oregon is considering one – that address climate change impacts by reducing or eliminating fossil fuels, particularly coal, or creating incentives to limit carbon emissions from electricity production, over the next 10 to 30 years. These new carbon-reduction policies, along with declining cost-effectiveness of coal-fired generation, are leading owners of multiple coal plants to schedule them for retirement. Meanwhile, wind and solar power are leading the charge to increased use of renewable energy in the West. While these renewable resources provide clean, low-cost energy, they are intermittent – producing power when the wind blows and the sun shines. As a result, wind and solar generating plants provide only limited capacity to meet peak requirements, particularly during the winter.

The sense of déjà vu was palpable at the conference. Steve Wright, manager of the Chelan County Public Utility District in Wenatchee, Washington, and administrator of the Bonneville Power Administration during the 2000-2001 crisis, put it bluntly:

“2001 was a failure of public policy,” he said, recalling that he was the one who made the decisions in response to high power prices that shuttered the then-struggling aluminum industry in the Northwest, putting 8,000 people out of work. Today, he said, “temperature excursion is our biggest challenge. If we have more than five days of [extreme heat or cold], we will have challenges.”

How great might the capacity challenge be?

Addressing the Portland conference, John Fazio, the Council’s senior power systems analyst, said preliminary results from power system adequacy modeling conducted by the Council show the power supply fails to meet the Council’s adequacy standard (5 percent “loss of load” probability) by 2021 because of the impending retirements of some of the coal-fired generators at Boardman, Oregon, and Centralia, Washington. Importantly, the loss of load probability does not mean the probability of a blackout, but rather the likelihood of a shortfall (not necessarily an outage) occurring anytime in the year being examined.

The loss-of-load probability increases from 6 percent in 2021 to 7 percent in 2022, and to 8 percent in 2024. The analysis shows that the region will need about 800 megawatts of new capacity to maintain adequacy through 2024. If some of the coal-fired generators at the Jim Bridger plant in Wyoming and the two other generators at the Centralia plant retire by 2024, as currently planned, the probability would increase to about 30 percent a situation similar to what happened in the 1990s that led to the West Coast energy crisis, when the problem was not retiring existing plants but just not building enough new ones. He stressed that these results are worst-case – assuming the retired generating capacity is not replaced – and preliminary and are likely to change when a new adequacy model is used for the analysis, but the potential problem won’t disappear.

What to do?

Because of new state laws reducing or eliminating fossil fuel power generation, the list of solutions is “fairly short if you can’t build dispatchable capacity,” said Randy Hardy, who was administrator of the Bonneville Power Administration through most of the 1990s and the keynote speaker at the conference. Today, Hardy is a Seattle-based energy consultant. Hardy praised the region’s best-in-the-nation energy efficiency accomplishments over the last 30 years, which have reduced the need for new generating plants and helped ease peaks in demand. But while efficiency can be seen as a capacity resource, in that it has the ability to reduce peak loads, its output can’t be increased when needed as with a power plant. Thus, ensuring reliable capacity remains an issue.

Hardy offered four solutions: 1) Development of a voluntary, “common resource adequacy standard,” for the West, a task he said will be difficult given the number of utilities that share power and transmission lines; 2) utility-scale batteries and pumped storage facilities than can fill in the gaps when wind and solar power aren’t available; batteries are becoming more and more powerful, but are expensive, and pumped storage, while it is well understood, is expensive and difficult to site; 3) new high-voltage transmission lines to make it easier to move power around the region and the West; and 4) refocus long-term planning from day-to-day energy to capacity –“more power from renewables makes energy planning more difficult,” he said. This could include development of a West-wide, short-term market for capacity, an effort that already is underway.

Hardy added a fifth: “Pray for rain and mild weather, that’s my best solution,” he said to polite laughter from the audience. But turning serious, he added, “We have to do something and we have to do it quickly. We have a 30-50 percent chance of a major outage in the next 10 years. If that happens, renewables will be blamed. Utilities will be blamed. That’s not acceptable, and we’ve got to be better than that.”