In Texas, solar will soon push most of the remaining coal fleet offline, according to the Institute for Energy Economics and Financial Analysis (IEEFA). IEEFA’s recent report, Solar Surge Set to Drive Much of Remaining Texas Coal-Fire Fleet Offline, shared that this is largely due to the growth in utility-scale PV production and how it’s rapidly changing the Electric Reliability Council of Texas (ERCOT) market.
ERCOT manages the coal plants across the power-generation market, and the report shares just how vulnerable these are. It predicted a 70% rise in risk for daytime coal-fired generation in ERCOT by 2022. Let’s dive into the report and some key points.
How Wind Power Set the Stage for Solar in Texas – Coal market share cut almost in half over the last decade. Wind is now equal.
The report noted that the rise in solar is due to developments over the past decade, which have set the stage for more renewables. In 2009, coal-fired plants created 111.8 million MWh of electricity in the market. This accounted for almost 37% of ERCOT’s demand. In 2019, those numbers dropped to 77.9 million MWh. Despite the drop, electricity demand in ERCOT rose from 305.4 million MWh in 2009 to 284 million MWh by 2019. That was a 25.7% increase. Thus, coal’s market share fell to just above 20%.
It’s clear to see that despite the decline in coal generation, electricity was still being produced — mostly by wind power that doesn’t have any fuel costs. Along with wind, natural gas prices driven down by the surge in fracking pushed coal off the grid as well.
Installed wind capacity in ERCOT grew around 15,000 MW over the decade and raised total wind generation from 18.8 million MWh to 76.7 million MWh. This increased wind’s share of the ERCOT power generation market from just over 6% to almost 20%, making it an equal with the state’s coal generators.
A Look at Wind, Gas, and Coal
The chart below details just how these three energy sources compared over the span of a decade. While wind gave coal a push out the door, gas rose from 128.6 million MWh to 181.8 million MWh, an increase almost as large as wind’s.
Enter ERCOT’s Solar Surge
The report detailed two separate statistics that reflected the solar surge.
1. A wave of new generation capacity that is expected to come online within the next two years.
2. Current solar generation.
By the end of 2019, ERCOT saw the existence of 2,281 MW of utility-scale solar capacity. It marked a 15,107% increase from 2010 when ERCOT only had 15 MW of solar generation capacity. That is a huge increase that has gotten larger by 2020. At the end of May, ERCOT saw the addition of 420 MW (Elon Musk would love that) added to the generation stack and another 1,057MW of solar that had been synchronized with the grid as preparation for full deployment. This brought ERCOT’s total installed capacity to 3,748 MW.
There’s more. An additional 2,053 MW are in the queue and will probably be completed late this year or in 2021. These numbers are waiting on interconnection agreements to be secured along with project-specific financing to fund the transmission service provider (TSP) to complete any needed upgrades that might be required to bring the capacity online.
These 2,053 MW are not counted yet because they are not 100% certain to come online. An ERCOT official told IEEE that once projects reach this stage, they have a “strong likelihood” of entering commercial operation. There could be a bit of slippage from 2020 and into 2021, though, for projects that have a projected online date late in the year.
There are other indicators that show the rapid rise of solar (data through the end of June):
- Solar topped 2% of ERCOT’s daily demand only two times in 2019. In 2020, solar has been above that 2% level 88 times out of 182 days.
- Solar generation in ERCOT has been above the 30,000 MWh mark since May 4, and for 37 of the subsequent 57 days.
- Solar has averaged more than 32,000 MWh since June 1 and has only had 6 days below 30,000 MWh.
- Solar’s output topped the previous ERCOT high of 17,551 MWH that was set back in 2019 three times since May and 96 times throughout the first half of 2020.
- The total solar generation from January through June of 2020 was 88% higher than it was for the first 6 months of 2019.
May the 4th be with Solar
In 2020, May 4 was an interesting day for ERCCOT regarding solar generation. The chart above shows the Texas region’s daily generation mix for May 4, 2020, and although solar by itself is only at 3%, with 31,456 MWh, it’s quickly approaching nuclear energy, which produced half of what coal produced that day. The IEEFA expects those records to continue falling as additional capacity comes online.
Battery Storage will Push Solar’s Momentum
Solar plus batteries are the “Wrecking Crew” of the coal industry. The report mainly focused on the growing daytime effects of solar power generation, but wanted to also highlight just how battery storage will push solar’s momentum.
“Solar will become an increasingly round-the-clock force as developers and utility companies invest in a once-peripheral and now mainstream area of the electricity industry: Battery-storage technology, which has become de rigueur for many new utility-scale solar projects in states surrounding Texas and is being retrofit on a growing number of existing PV facilities,” the report said. It uses examples from other states:
- In Oklahoma, NextEra signed a contract with Western Farmers Electric Cooperative last year. The plan is to develop a 700 MW wind-solar-battery project that will include 200 MW of storage. It will be the largest project of its kind in the U.S.
- In Arkansas, Entergy was approved for a solar storage project that mixes 100 MW of generation with 10 MW of storage. This was approved back in April. (Yes, the report shares the MW figures for storage, not the MWh figures.)
- In New Mexico, the state’s Public Service Company is replacing its stake of 560 MW in the soon-to-be-retired San Juan Generating Station with a larger and modernized mix of new generation sources. Regulatory staff advised them to include 650 MW of solar and 300 MW of battery storage. Along with that, the state’s first tribally owned utility-scale solar project that was developed on Jicarcilla Apache land paired a 50 MW panel array with a 20 MW storage component.
- In Nevada, the Gemini Solar Project plans to be the largest solar farm in the U.S. It will include a 380 MW solar-powered battery system that is tied to a 690 MW array of collector panels. Also, NV Energy is building 1,200 MW of solar generation that will be paired with 590 MW of storage.
- In Arizona, its largest utility announced last week that it began a plan to transition entirely from fossil-powered generation. Arizona Public Service will rely heavily on battery storage as “the backbone of replacement capacity and energy as we look to exit coal completely by 2031.” It will build at least 2,500 MW of storage capacity by 2020 (this year), and as much as 10,500 MW by 2035.
- PacifiCorp, which is tied to 6 states in the West and Northwest, issued a request earlier this month for proposals that seek 595 MW of battery storage to complement its 3,743 MW of renewable energy capacity as it transitions away from coal.
- In California, the grid operator, California ISO, is expecting around 923 MW of battery storage to be in operation from new storage installments by the end of 2020 once the 250 MW Gateway Energy Storage is operational.
Using what it called a conservative approach, IEEFA predicted that 67% of daytime coal generation may not be needed anymore in 2022
IEEFA took a look at ERCOT’s generation data for the month of January 2020 and for the last week of May and the first week of June. This information helped the organization to estimate the measurements of the coming solar wave for 2022. IEEFA used data from the U.S. Energy Information Administration (EIA) and ERCOT. By using what it called a conservative approach, IEEFA predicted that 67% of daytime coal generation may not be needed anymore in 2022.
It seems that the not so sweet heat of the Texas sun will push coal right out. Clean energy, as Maye Musk so often says, will win. In this case, it is winning and coal could soon be out of the race.
All images courtesy IEEFA report.
Minnesota approves Xcel request to operate 2 coal plants seasonally
- Minnesota regulators on Wednesday approved Xcel Energy’s December request to operate its last two coal plants in the state seasonally.
- The Allen S. King plant and unit 2 of the Sherco facility will now sit idle six months out of the year, according to the Minnesota Public Utilities Commission (PUC). From June to August and December to February, the utility can operate the plants, unless they are otherwise needed for reliability needs. Xcel’s move is expected to save customers millions in dollars and in tons of carbon dioxide annually.
- A June report from Union of Concerned Scientists (UCS) found the utility operated its plants at a $55 million loss in 2018. Xcel disputes the study, saying that because its plants were are “long duration” they could not be shut off and on quickly, making it difficult to offer those units into the day-ahead market.
Utilities are coming under increasing scrutiny from state regulators in how they operate their coal-fired plants, as research from UCS and Sierra Club finds some coal-fired plants are operating at a loss for large portions of the year. Xcel requested the operations change in November of last year after state regulators opened a docket to examine the issue more closely. Minnesota was the first state in the country to do so and has been followed by Missouri and Indiana.
Ultimately, Xcel estimates it will save customers approximately $1.5 million in 2020 and up to $3.5 million by 2023. The plan would also reduce greenhouse gas emissions by up to 4.1 million tons in 2020 and up to 7.3 million tons by 2023, relative to the full dispatch operations. Minnesota law requires utilities in the state to reduce emissions 30% below 2005 level emissions by 2025, and this move alone will make up one-fifth of the reductions needed, according to the PUC.
“This is an important proposal and I appreciate Xcel Energy bringing it forward,” Commissioner Matt Schuerger said in a statement. “I think this highlights Xcel’s focus on saving their customers money, on meeting Minnesota’s environmental policies, and in being responsive to the investigation the Commission opened.”
Lead author of the UCS report Joe Daniel called the move “a welcome change in behavior. Xcel, like most utilities, was initially reluctant to recognize the costliness of uneconomic self-commitment. But now, both the utility and the state commission have codified a path forward that will save Xcel’s customers millions of dollars, not to mention the public health benefits of reduced pollution,” Daniel said in a statement. “Unfortunately, other utilities in Minnesota remain reticent when it comes to changing their operations.”
Xcel CEO Ben Fowke has indicated he’d be interested in exploring operation changes across the utility’s system, which stretches from Minnesota down to the southeast, to reduce the amount of time it operates its coal plants.
“We’re definitely looking at that down in the [Southwest] region. We’ve got some water issues that we need to address, and that could be solved with some seasonal dispatch,” he said in February.