The midyear figures from the Energy Information Administration confirm what the January forecasts promised. Developers and plant owners added 20.2 gigawatts of utility-scale capacity in the first half of 2024, 21% more than in the first half of 2023. Solar accounted for 12 GW, or 59%. Batteries added 4.2 GW and wind 2.5 GW. Retirements slowed to 5.1 GW, from 9.2 GW in the first six months of 2023.
The spring also produced a symbolic first. Wind generated more electricity than coal in both March and April, the first time it had done so for two months in a row. And yet, as of the end of May, US power plants held 138 million short tons of coal in their stockpiles, the most since the first half of 2020.
Those three facts look inconsistent at first glance. They are not. Together they show a power system in which new capacity is overwhelmingly renewable, energy output is shifting more slowly, and the remaining coal fleet is being run less while being kept available.
Where the new capacity went
Texas and Florida accounted for 38% of solar additions. The largest projects included the 690 megawatt Gemini solar and storage facility in Nevada and the 653 MW Lumina project in Texas.
Battery additions were even more concentrated. California took 37% of the US total, Texas 24%, Arizona 19% and Nevada 13%. Four states accounted for more than 90% of new storage. The largest projects were the 380 MW of storage at Gemini and the 300 MW Eleven Mile Solar Center in Arizona.
Wind additions were modest. Canyon Wind, at 309 MW, and Goodnight, at 266 MW, both in Texas, were the largest.
The second half is expected to be heavier still. Developers plan to add 42.6 GW between July and December, nearly 60% of it solar at 25 GW, followed by 10.8 GW of storage and 4.6 GW of wind. As usual, a large share of annual additions is scheduled for the final months of the year.
What retired, and why it was small
Gas made up 53% of retired capacity in the first half and coal 41%. The largest coal retirements were Seminole Electric Cooperative's Unit 1 in Florida, at 626.0 MW, in January, and Homer City Unit 1 in Pennsylvania, at 626.1 MW, in April. The largest gas retirement was the 1,413 MW Mystic Generating Station combined-cycle plant in Massachusetts, previously the third-largest power plant in New England.
Mystic is a good example of why retirements are not simply a matter of age. It had been kept running for several years under reliability arrangements because it was tied to an LNG import terminal that helped secure winter gas supply for the region. Its closure reflects a judgment that New England's winter fuel security can now be managed without it.
Wind passes coal, for a season
Wind turbines produced 45.9 terawatthours in March 2024, against 38.4 TWh from coal. In April, wind reached a record 47.7 TWh and coal fell to 37.2 TWh. Wind had first beaten coal in a single month in April 2023, but did not do so again for 11 months.
The EIA is careful to put this in context. Wind output peaks in spring in the United States, while coal plants often schedule maintenance in that season of moderate demand. Over the first four months of 2024 as a whole, coal generation was still 15% higher than wind. The crossover is seasonal, for now. It will become permanent only when the annual totals cross, and on current trends that is a matter of a few years rather than months.
Why stockpiles are high
The coal stockpile figure is the most telling of the three. At 138 million short tons at the end of May, inventories were the highest since early 2020, when the pandemic cut demand. More than 90% of coal plants now have enough coal on hand for 60 days or more of generation.
Plants normally build stocks in spring ahead of the summer peak. But the size of the inventory reflects something more: coal plants are burning less than they planned for. Cheap gas, as we discussed in our analysis of first-half gas prices, has displaced coal across most of the country. Coal contracts with mines and railroads were signed when demand expectations were higher. The coal arrives and sits.
That has two consequences. For the remaining coal fleet, high stocks mean plants can run when needed, which is useful for reliability in winter cold snaps or summer heat. For coal producers, it means weaker domestic orders over the next year, as utilities work down their inventories before buying more.
The shape of the transition
Putting these numbers together gives a picture of the transition at its current stage. New capacity is almost entirely solar, storage and wind. Retirements are slow, because grid operators and utilities are reluctant to close dispatchable plants before replacement capacity is proven. Coal plants remain on the system but run less, and hold more fuel than they need. Gas is the fuel that fills every gap, cheaply for now.
That is a sensible sequence. It keeps reliability margins comfortable while the new fleet grows. But it is also an expensive one in a quiet way. A coal plant that runs at a low capacity factor still has fixed costs, and those costs are spread over fewer megawatthours. Customers pay for keeping the plant available whether it runs or not.
What changes the sequence
Two developments would speed it up. The first is a sustained rise in gas prices, which would bring some coal back into dispatch in the short run but would strengthen the economics of renewables and storage. The second is the arrival of enough storage in the regions where coal still provides evening and winter capacity, which would make the case for retiring it much easier.
Two developments would slow it. The first is a surge in power demand from data centers and manufacturing, which some utilities are already citing as a reason to delay coal retirements. The second is a slowdown in solar and storage installations from trade restrictions or interconnection delays. The first-half data show no sign of the second. The first is already visible in utility plans.