Duke Energy Corp. would retire all of its power plants in the Carolinas that "rely exclusively on coal" within the next 10 years and add between 1,050 MW and 7,400 MW of storage to its portfolio under the six scenarios outlined in its recently proposed 2020 integrated resource plans.

The 15-year plans, or IRPs, filed with state regulators in North Carolina and South Carolina by Duke Energy Carolinas LLC and Duke Energy Progress LLC are designed to allow Duke Energy to achieve its goal of a 50% reduction of carbon emissions by 2030 from 2005 levels and net-zero emissions by 2050. Certain scenarios are also designed to align with the North Carolina Clean Energy Plan, which calls for up to a 70% reduction in greenhouse gas emissions by 2030 from 2005 levels.

An S&P Global Market Intelligence analysis shows Duke Energy operates about 9,000 MW of coal-fired generation in the Carolinas. The 2,462-MW Roxboro, 2,220-MW Belews Creek and 2,078-MW Marshall coal plants are in North Carolina and are among Duke Energy's 10 largest operating plants in the region.

Duke Energy Carolinas, or DEC, operates the 1,360-MW Bad Creek Pumped Storage Project in Oconee County, S.C., but has only 5 MW of battery storage under development in the state with no current operating capacity. Duke Energy Progress, or DEP, has 9 MW of operating battery storage capacity in Asheville, N.C., with 4 MW of proposed capacity at the Hot Springs Solar site.

The six scenarios in the IRPs call for varying additions of renewable, storage and natural gas capacity.

By 2035, a base-case scenario without a carbon policy would add 8,650 MW of new solar capacity, 1,050 MW of battery storage and 9,600 MW of gas along with 2,050 MW of energy efficiency and demand response to the combined portfolios of DEC and DEP, while 3,050 MW of coal capacity "capable of co-firing on natural gas" would remain online. No new wind power would be installed under the base case.

A base-case scenario with a carbon policy would add 12,300 MW of solar, 750 MW of onshore wind, 2,200 MW of storage, 7,350 MW of gas, 2,050 MW of energy efficiency and demand response and keep 3,050 MW of dual-fuel coal capacity online.

A scenario with no new gas additions by 2035 would require 7,400 MW of new storage and keep 2,200 MW of dual-fuel coal capacity online through that year.

Both a high wind and no new gas scenario rely on about 2,650 MW of offshore wind capacity by 2035, but Duke Energy contends both of these scenarios are heavily dependent on technology and policy advancement. A high wind pathway, which includes 2,850 MW of onshore capacity, relies on new transmission infrastructure that could cost as much as $4.6 billion. These scenarios also involve delaying the retirements of Roxboro units 1 and 2, as well as one Belews Creek coal unit until the end of 2029 to "allow for the integration of offshore wind by 2030."

"While offshore wind is not necessarily a new technology, deployment in the [U.S.] at large scale is yet to be demonstrated," DEP wrote in its resource plan. "The cost of the resource and getting the energy from coastal Carolinas to the load centers in the central part of the states will present implementation challenges. These challenges can be mitigated with effective political and regulatory support and policy."

DEP currently has about 17 MW of planned solar capacity.

DEC, meanwhile, has begun construction on a new simple-cycle 400-MW natural gas unit at its Lincoln Combustion plant, which is expected online in December 2024. The utility also has about 100 MW of solar under construction at its Maiden Creek and Gaston County sites.

Duke Energy has said it plans to bring 16,000 MW of solar, wind and biomass online by 2025 companywide. The company also plans to increase the capacity at its Bad Creek pumped-storage hydro plant in South Carolina by about 320 MW and seek a second 20-year renewal of the operating licenses for 11 nuclear reactors in the Carolinas beginning with DEC's 2,618-MW Oconee nuclear plant in 2021.

DEC and DEP evaluated the addition of small modular reactors, or SMRs, under both a 70% emissions reduction and no new gas generation pathway. A "high SMR" scenario envisions adding 1,350 MW of incremental new nuclear reactor capacity to the utilities' generation mix by 2035.

"The High SMR case also assumes that SMRs are in service by 2030," the utilities wrote. "However, the challenges with integrating a first of a kind technology in a relatively compressed timeframe are significant. Therefore, these cases are intended to illustrate the importance of advancing such technologies as part of a blended approach that considers a range of carbon-free technologies to allow deeper carbon reductions."