- "Having access to the Mountain Valley Pipeline would reduce customer costs by $1.7 billion by 2038, and $2.6 billion by 2050."
- "If you compare last year’s proposed carbon plan to the new proposal, we have actually moved back the proposed retirement dates for a couple of our [coal plant] facilities, Mayo and Cliffside 5. So you’re already seeing a little movement backward in terms of between now and 2035."
- "Part of [the reason Duke Energy Progress rates will increase more at first] is due to renewables. Solar, wind, and the associated battery storage would come into our Duke Energy Progress territory just because of the geography."
This week, Duke Energy released its new plan to meet carbon reduction requirements outlined in H.B. 951. Carolina Journal had the opportunity to catch up with Bill Norton, who works for Duke, about the details of their plan and the company’s perspective on energy policy over the next few decades.
Carolina Journal: Bill, thank you for taking some time to discuss Duke’s new proposal to satisfy the carbon reduction targets required by the new state law. Can you briefly walk us through Duke’s three proposed plans?
Bill Norton: This resource plan reflects Duke’s focus on delivering a path to cleaner energy that does not compromise grid reliability, affordability, or the energy demands of a growing and economically vibrant region. Let me break that down a little bit. Grid reliability is non-negotiable. Whatever plan we put forward has to be equally or more reliable than the system today. Then we have to do this at least cost as required by state law, and certainly, that is in the interest of our customers as well. And then you look at carbon reduction as required by House Bill 951. As required by H.B. 951, it has to be equally or more reliable, and it has to be least-cost. With those as non-negotiable, how can you drive out carbon?
H.B. 951 had specific caveats allowing the 70 percent reduction target to shift out if we are incorporating advanced nuclear, and Duke is proposing that. The first portfolio would meet [the 70 percent reduction target] by 2030; the second portfolio would meet the 70 percent reduction target by 2033; the third would do so by 2035. Duke believes that the [third] plan is the most executable from a technology standpoint, and it is also the least-cost option.
The emphasis that we have is that we really need an all of the above approach to the energy transition. As we get out of coal, and we have to get out of coal, even without H.B. 951, utilities as a whole are transitioning out of coal because of costs, because of regulations that have imposed higher costs. You add those things up, and you see the industry as a whole getting out of coal. You do not want to be the last one operating a coal plant. Coal is going to stop being mined over time. Railroads are going to stop shipping coal over time. So, we would have to make this transition even if H.B. 951 did not exist.
Our commitment is to retire all coal by 2035. How do we do that? Well, we have these three portfolios. All of them have an all of the above mix that includes new natural gas. All of the new facilities we build would be hydrogen-capable. You hear concerns critics have about natural gas plants being stranded assets. We believe the ability to add hydrogen in the future renders that argument moot. We are proposing new solar, new storage, both batteries, and an expansion of our pumped hydro storage at our facility down in South Carolina. We are looking at onshore wind. Offshore wind will certainly be needed to meet the end goal of carbon neutrality by 2050. We are still evaluating how quickly offshore wind might come into these portfolios. The most expensive portfolio might have 2.4 gigawatts coming in by 2035. The most conservative portfolio has anywhere from 0 to 1.6 gigawatts by 2035.
CJ: Going back to the coal that you mentioned earlier, many of those costs, as you said, depend on the national regulatory environment. Not to get too in the weeds on politics, but say you get a new administration that cuts down some of the current regulations on coal, and it does become cheaper. With this scenario in mind, as well as other considerations, would it not make sense to push back shutting down the coal plants a little bit further down the line, or why is it urgent to shut them down so soon?
BN: Well, if you compare last year’s proposed carbon plan to the new proposal, we have actually moved back the proposed retirement dates for a couple of our facilities, Mayo and Cliffside 5. So you’re already seeing a little movement backward in terms of between now and 2035. We are still planning on getting out by 2035. But a couple of the facilities we are anticipating sticking around a little bit longer than a year ago as a result of the massive growth that we are seeing and our commitment to not infringe upon reliability. In the long term, I think the industry is already committed to getting out of coal. That trend is accelerating even if you were to have some shifts in policy.
CJ: So the H.B. 951 allows some flexibility on the 2030 carbon reduction target. Would the North Carolina Utilities Commission be pushing back the timeline past 2030, or do you expect them to hold firm to 2030?
BN: What we point out is that all three portfolios will achieve that carbon neutrality by the 2050 target. If reaching the 70 percent interim goal by 2035 rather than 2030 does not cost us reliability and allows us to make that transition a little less expensive while still hitting the end goal, then it makes sense for us to pursue that path. Ultimately, it is the North Carolina Utilities Commission’s decision.
CJ: One other thing I noticed in Duke’s 2023 Carolinas Resource Plan is the possibility of a merger between Duke Energy Progress (DEP) and Duke Energy Carolinas (DEC) and how that could help mitigate costs in some ways. How much would costs be mitigated vs. how much differing rate impacts be smoothed? Or in other words, would there be any actual savings for customers across the board, or would costs simply be shifted?
BN: It would address both. [A merger would create] cost savings for customers, and it would also address the current imbalance between DEC rates and DEP rates.
CJ: How would the savings be found?
BN: I will say, the merger is something we have proposed, but it is not something [Duke] can do unilaterally. We believe it is in the best interest of our customers, but we still have to demonstrate that. South Carolina, North Carolina, and federal regulators would all have to approve [a merger]. We’ll demonstrate the benefits for customers throughout that process, and of course, we’ll be talking to the customers themselves about the benefits for them from the merger. Nothing happens to them without getting customer feedback.
CJ: How soon do you see the possibility of a merger?
BN: I can’t speak for the regulatory bodies, but if it were to be approved, 2027 would be the timeline for that. However, that is still subject to considerable input.
CJ: Changing topics a little bit, more and more people are buying Electric Vehicles (EVs). Governor Cooper has said he wants to have 1.25 million EVs on North Carolina roads by 2030. What kind of strain do you anticipate the increase in EVs putting on the power grid?
BN: That is part of why we have increased our projections for how much demand there is going to be. I think you saw the anecdote in the news release about the growth over the next 15 years being more than three states combined. However, EVs are not driving that growth in demand. EVs are part of it, but the biggest driver is how attractive North Carolina is to economic development these days and companies moving in. More than half of the increased demand we foresee is from large manufacturers, and large industrials moving in and wanting to be in the Carolinas. That’s more than half of it. EVs are the next largest chunk, and the third would be inmigration—people coming into the Carolinas. But really, mostly, it’s the economic development success our state is having.
CJ: I guess I mention EVs not only because of the strain but because of the timing of the strain. A lot of EV owners charge their cars overnight, for example, and solar power obviously doesn’t produce when the sun isn’t out. Does Duke have a plan to account for this type of shift in usage?
BN: Yes. In fact, we have incentives for that. We have rates that incentivize customers to recharge their EVs when demand is lowest. As you point out, solar isn’t providing power at night because the sun isn’t out. That is why we take an all of the above approach, meaning new natural gas, which is available 24/7. Nuclear plays a critical role. We are proposing extending the licenses of our existing nuclear fleet to keep them on the system longer and proposing new advanced nuclear. That 24/7, three hundred and sixty-five day a-year capability will be critical in a way that renewables or even battery storage cannot. Typical storage right now is 4-hour storage. That does not get you through back-to-back days of cloud cover in January, let alone the coldest possible nights. So nuclear and natural gas are essential.
CJ: I wanted to ask you about the Mountain Valley Pipeline (MVP). How much does the viability of the Mountain Valley Pipeline Southgate help Duke plan for reliable, least cost, replacement, and retirement of coal resources?
BN: I will say, the net new natural gas we proposed at our Roxboro facility, we see that coming whether MVP comes or not. As currently planned, that would be supplied by the Transco pipeline. Having said that, MVP would certainly add more security for our customers in terms of having a second pipeline supply, and it would reduce the costs. We project that if you are looking at our third portfolio, having access to MVP would reduce customer costs by $1.7 billion by 2038 and $2.6 billion by 2050.
Editors note: Norton also clarified that the $1.7 billion and $2.6 billion did not include additional savings that would occur if Southgate happens and that Duke would need to do additional modeling to provide a total savings estimate.
CJ: I noticed that the costs for Duke Energy Progress are projected to go up significantly more than Duke Energy Carolinas. Do you know what the reason is for that?
BN: Part of that is due to renewables. Solar, wind, and the associated battery storage would come into our Duke Energy Progress territory just because of the geography, so that is part of what is driving the higher increase. It’s flatter and more conducive there. Both our new nuclear and our Bad Creek pumped hydro storage are part of our Duke Energy Carolinas utility, and they come on later, so this is, in part, a timing issue. You have the more expensive stuff up front in Duke Energy Progress and the more expensive stuff later for Duke Energy Carolinas. The merger, if it were to happen, would help take care of that timing issue.
DEC markets like Charlotte and Greensboro benefit from electricity generated by solar that is built in eastern NC. By consolidating the utilities, we are smoothing these costs.
CJ: Bill, thank you again for joining us and taking some time to answer questions.
BN: Thanks for having me.
Duke’s full proposal can be found HERE.