NREL Forecasts Gas-Fired Power Capacity Will Grow Significantly to 2050 but Utilization Rates Will Drop Significantly: If That is to Be the Case, More Pipeline Capacity Will be Needed in the Near-Term and More Natural Gas Assets Will Be Stranded Sooner, Resulting in Losses for Utilities and Consumers

     The National Renewable Energy Laboratory (NREL) produced a report in December 2023 that confirms that even under a 95% decarbonization (mid-case) scenario, U.S. natural gas-fired electricity capacity will increase by a minimum of 130 GW by 2050. That amounts to an average of 4.81GW per year of natural-gas-fired capacity growth. However, less and less of that capacity is expected to be utilized through time under these scenarios.  The current policies scenario has natural gas-fired capacity increasing by 200GW, or 7.41GW per year. Specifically, the report highlights the following regarding natural gas-fired capacity:

“Natural gas capacity continues to expand. In the Mid-case with current policies, natural gas capacity increases by 200 GW through 2050, whereas it increases by 130 GW in the Mid-case with 95% net decarbonization imposed.”

“In later years, fossil generators without carbon capture play a reduced role in providing generation, but a larger role in providing firm capacity. By 2050, uncontrolled fossil generators (natural gas, coal, and oil without carbon capture and storage) provide only 14% of total generation in the Mid-case (1% through 24% across all scenarios), but 47% of total firm capacity (16% through 56% across all scenarios).”

While the capacity is set to increase, the capacity factor, or utilization rate, for natural gas is set to drop significantly. That suggests that pipeline capacity will be adequate in the long-term but what about the near-term?  

The scenario is dependent on carbon capture and storage ramping up significantly over the next few decades. Perhaps, the takeaway from this report by the nation’s “renewable” energy lab during an administration that strongly supports deep decarbonization, is that even under those scenarios, we will need to expand gas-fired capacity. These scenarios also assume that some older natural gas-fired capacity will be retired, and some will be utilized less so additional new capacity will have to take over those losses as well.

     In the 95% decarbonization by 2050 scenario natural gas capacity will not be reduced significantly until the mid-2040s. Under that scenario, solar will increase by about 30 times what it is now, and wind will increase by about 6 times what it is now. Those are very tall orders and I’ll believe it when I see it.

     Basically, these data are saying: Yes, build that advanced combined-cycle power plant because we really need it in the near-term for reliability, but expect to be forced to run it less and less as time goes on and expect to lose money from it. That will increase costs for utilities, which they will pass on to consumers. This is in addition to the very high upfront costs for wind, solar, storage, CCS, hydrogen, and other new technologies that utilities and consumers will have to bear. A fair chunk of the IRA has already been bit into by inflation. In any case, none of this will be easy or smooth sailing.

 

 

How Much More Natural Gas and Pipeline Capacity Would Be Required in the Near Term and for How Long?

 

     Under the 95% decarbonization scenario natural gas utilization will peak around 2025, next year. That seems difficult since record natural gas use is fairly assured for 2024 and it will have less than two years to start dropping, with deep drops expected from 2027-2030. If the peak of natural gas use is pushed back a mere 5-8 years, which seems quite plausible to me, then we will struggle with infrastructure adequacy. Using the avg. 2022 capacity factor for combined-cycle natural gas-fired plants (65.6%) and 2020 numbers for total gas power burn per total natural gas capacity one can rough calculate that the avg. annual growth in gas-fired capacity will require about 555MMCF per day more gas per year, or 5.55 BCF/day per decade, if gas utilization continues to grow. I hope I have this correct so don’t hold me to it. Just to supply that would require nearly 3 pipelines the size of the Mountain Valley Pipeline (2BCF per day max capacity) per decade. When the MVP pipeline finally comes online, presumably in 2024, it will have taken nearly a decade since permits were first applied for in 2015. We will need nearly three of those per decade to cover the 95% decarbonization scenario, on average. As we know from massive opposition to pipelines, that would be much easier said than done. That increase in capacity is perfectly doable as the avg. natural gas state-to-state transmission pipeline capacity increases have been about 11.2BCF/day per year over the past decade (from 2011 through 2022). Only 897MMCF of capacity was added in 2022, the lowest since 1995, according to the EIA. However, that will have to compete with projected increases for LNG exports of 10-15BCF/day over the next decade. Through 2022 the US exported about 11BCF/day of LNG, or about 10% of US total gas production. If that is to double as predicted it will require about 11 BCF of new pipeline capacity, some of which is now available or will be available in the Haynesville and Permian areas closer to export terminals. It is easier to build pipelines in those states. However, expanded natural gas power capacity will likely happen more in colder, more northern, and more power-hungry areas like the U.S. Northeast and Midwest, where pipelines have had the most difficulty being built. Additionally, some U.S. gas producers in the Appalachian region would like to export gas as LNG from the East Coast as only one small export terminal exports from there, Cove Point. They would like to do this to get better premiums for their gas. However, that plan will get significant push-back if it ever gets seriously pursued. The natural gas supply is there to increase exports and domestic power. However, in about a decade, the volumes from the Southern regions may exhibit some depletion, especially as more gas is exported from those reserves. The Appalachian region, however, will likely still have plenty of reserves. That is actually good for electricity consumers in the Northeast since the pipeline bottlenecks keep local gas prices low which in turn keeps electricity prices low as well since gas is the main source of electricity in the region.  

     Gas storage capacity may have to grow a bit as well. Plans are in place to add gas storage capacity in Texas to help power the ERCOT region that has experienced difficulties due to cold weather in recent years. Natural gas infrastructure and power plants also need to be adequately weatherized in all regions in order to be able to withstand cold snaps. Some overbuilding of both storage and pipeline capacity is one way to achieve resource adequacy in high demand periods.

     As I write this (January 15, 2024) we may be experiencing record natural gas consumption. Yesterday, according to Reuters:

 

“U.S. gas demand, including exports, will reach 164.6 bcfd on Jan. 15 and 171.9 bcfd on Jan. 16, according to LSEG.”

 

“Those daily demand forecasts would top the current all-time high of 162.5 bcfd set in December 2022 during Winter Storm Elliott, federal energy data from S&P Global Commodities Insights showed.”

 

“In Texas, ERCOT forecast power demand would peak at around 85,564 megawatts (MW) on Jan. 16 at around 8 a.m. local time, which would top the current all-time peak of 85,508 MW set in August 2023.”

 

Additionally, there will be a very similar event occurring in the same areas within a week as another polar vortex drops down into the U.S. so we may be looking at 4 or 5 days of record natural gas consumption. If gas plants and infrastructure stay operational this should be no problem as storage levels are more than high enough to accommodate. The only issue could be the usual issues in the Northeast where local pipeline capacity is inadequate so that more expensive, more polluting, and higher carbon emissions fuel oil will likely be burned instead of natural gas.

     The bottom line here are that these fast decarbonization scenarios are highly dependent on many things: quick and vast increases in solar, wind, storage, hydrogen, CCS, energy transition minerals mining, electricity transmission, and grid upgrades. These energy sources and technologies can be expanded but I am highly skeptical of the rates of expansion given in these scenarios. In addition, the utilities will be forced to strand more natural gas assets and under-utilize many of their most efficient natural gas resources. Let’s see where we’re at in a couple years. If Republicans take power in the U.S., either at the Presidential or Congressional level, it is likely that some of these plans will be slowed down, which in the long run is probably a good thing, if one considers electrical reliability and cost to consumers. The faster decarbonization, the more risk there is to reliability, the higher the costs will be to consumers, and the more intense will be the upheaval from local opposition to these expansion projects. It is hard to reconcile these rather unsettling facts with the aspiration for quick and deep decarbonization. Additionally, our dependence on China will increase drastically.  

 Addendum 01/16/2024

     Since the EIA came put with new projections today for energy sources on the U.S. power grid through 2025, I will compare them to the NREL projections. I had noted in mid-2023 that natural gas additions (in real generation, not capacity) were higher than projected for the first half of 2023, while solar and wind additions were less than projected. This was due to supply chain issues and other issues that slowed down renewables deployment. However, as EIA notes, wind and solar projects often come online near the end of the calendar year, which seems to be the case for 2023. For the nest two years they note:

“Solar is the fastest-growing renewable source because of the larger capacity additions and favorable tax credits policies. Planned solar projects increase solar capacity operated by the electric power sector 38% from 95 gigawatts (GW) at the end of 2023 to 131 GW by the end of 2024. We expect wind capacity to stay relatively flat at 156 GW by the end of 2024, compared with 149 GW in December 2023.”

Since solar is the big growth engine for renewables through 2024, it should be noted that capacity factors (utilization rate capabilities) for solar are much better in the South, Southeast, Southwest, and West, and not so good in the Northeast and Midwest. Thus, solar will have very little effect in those high power consumption areas in the winter. 2024 is expected to be the first year that wind and solar will lead new generation growth in terms of actual generation. The EIA predicts: “As a result of new solar projects coming on line this year, we forecast that U.S. solar power generation will grow 75% from 163 billion kilowatthours (kWh) in 2023 to 286 billion kWh in 2025. We expect that wind power generation will grow 11% from 430 billion kWh in 2023 to 476 billion kWh in 2025.” That is an absolutely massive and unprecedented amount of new solar generation in a short time period. I will believe it when I see it. It should be interesting to see how this new generation affects grid reliability and power costs. I know my own electricity bill went up by nearly 30% in 2023 which is difficult for me. I also have rooftop solar so I know how little it contributes in the winter months.

 

     Meanwhile, in Texas, it is hoped that the failures of the Texas natural gas system in 2021 have been fixed, so that power and heat will remain flowing. Fossil fuel hawk David Blackmon pointed out in an article for the Telegraph: “The state’s generation mix taken from ERCOT’s app at 7:19am. Monday {Jan. 15} tells that story pretty clearly. What we see is 0 per cent contribution from solar, 0.8 per cent from power storage, and just 6.8 per cent from wind. Meanwhile, the “fossil fuels” so detested by the state’s legacy media sites were kicking in 84.9 per cent of total generation, with a whopping 67.2 per cent coming from the state’s natural gas industry.” ERCOT requested energy conservation from 6AM to 10AM CST. They also mentioned “unseasonably low wind conditions” while also acknowledging the expected low contributions from wind in the winter.

I may have more addendums to this post in the days ahead to show what is happening with this current extended two-pronged cold weather event. 

Last Addendum: January 21

     For the 2nd day of ERCOT's low-margin cold weather event on Tuesday, January 16, it was solar generation and wind generation that ensured power availability. Record demand occurred on Monday and was covered by fossil generation, but Tuesday also had near-record demand which was helped much by the sun. It was a sunny day and solar generation was virtually absent the day before, with 20% of afternoon generation provided by solar on Tuesday. Excess solar generation also helped to charge batteries. Wind also helped the night before, accounting for 30% of generation. Thus, the conclusion that should be reached is that if it is windy and sunny enough (never really a given), then those resources can contribute significantly to adequate reserve margins. One might say that ERCOT got lucky. However, there was likely enough fossil generation to be adequate without wind and solar. If the state moves to make fossil generation less available, that would put future difficult weather situations at the mercy of sunniness and windiness. ERCOT noted that this weather event was the state's second-longest winter storm in the last 15 years and the third coldest. ERCOt noted: "This is the first time we've seen operational days significantly affected by the amount of solar during a winter storm." However, it should be noted that this weather event was much less severe than the February 2021 event in terms of time, coldness, and wind/solar availability. On the one hand, it shows that wind and solar can indeed be helpful. On the other hand, it does not change the fact that there is no guarantee of that happening.   

 

References:

U.S. gas-fired capacity to grow, even under 95% carbon reduction scenario: NREL. Ethan Howland. Utility Dive. January 12, 2024. US gas-fired capacity to grow, even under 95% carbon reduction scenario: NREL | Utility Dive

2023 Standard Scenarios Report: A U.S. Electricity Sector Outlook. Primary Authors: Pieter Gagnon, An Pham, and Wesley Cole. National Renewable Energy Laboratory. Technical Report. NREL/TP-6A40-87724. December 2023. 2023 Standard Scenarios Report: A U.S. Electricity Sector Outlook (nrel.gov)

Frigid temps cut US natural gas supply as demand soars, Texas faces possible shortfall. Scott DiSavino. Reuters. January 14, 2024. Frigid temps cut US natural gas supply as demand soars, Texas faces possible shortfall (msn.com)

Natural gas pipeline capacity additions between states are the lowest since 1995. Energy Information Administration. Natural Gas Weekly Update. February 23, 2023.  Natural Gas Weekly Update (eia.gov)

The Texas power grid is on the verge of another fatal collapse. Green energy is absent. David Blackmon. THe Telegraph. January 16, 2024. The Texas power grid is on the verge of another fatal collapse. Green energy is absent (msn.com)

Solar and wind to lead growth of U.S. power generation for the next two years. Energy Information Administration. Today In Energy. January 16, 2024. Solar and wind to lead growth of U.S. power generation for the next two years - U.S. Energy Information Administration (EIA)

How Texas' power grid weathered the latest freeze. Jacob Knutsen. Axios. January 20, 2024. How Texas' power grid weathered the latest freeze (msn.com)