Duke Energy has detailed the various paths its utilities in the Carolinas could take over the next 15 years, a choice that will determine how quickly Duke cuts its carbon footprint and how much it will cost.
Duke’s 2020 integrated resource plan (IRP), filed Tuesday with state regulators, lays out six scenarios for reaching its challenging goals of halving its emissions by 2030 and hitting net-zero carbon by 2050.
All of the scenarios go well beyond Duke’s previous IRPs in leaning more heavily on solar, onshore wind and energy storage. The utility has also opened the door to offshore wind in its future mix. Duke has already committed to doubling its 8 gigawatts of renewables by 2025 and to retiring its roughly 10,000 megawatts of coal generation by 2030.
But that’s about where the similarities stop. The six options Duke is presenting to North Carolina and South Carolina regulators take notably different routes for adding 4,600 megawatts of new resources to its current 23,200-megawatt generation fleet in the states. That’s how much additional capacity Duke expects to need in the next 15 years to make up for the retirement of its coal-fired power plant fleet and aging natural-gas plants.
Duke operates utilities in six states and is one of the country’s largest independent renewable energy developers. But Duke Energy Carolinas and Duke Energy Progress are its biggest vertically integrated utilities, serving a combined 3.2 million residential, commercial and industrial customers in the Carolinas.
Six pathways, many uncertainties
While Duke has committed to reaching net zero over the long term, its nearer-term challenge is meeting its 50 percent carbon-reduction target for 2030. The six “pathways” put forward in the IRP include two aimed at meeting that target and four that go even further.
The two most moderate scenarios include a “base case” that assumes no price is put on carbon pollution and a “carbon policy” case that assumes a price is implemented. While both pathways would more than halve Duke’s emissions by 2030, they’re nevertheless likely to draw fire from critics of the utility’s cautious approach to phasing out fossil-fueled generators.
Despite Duke’s decision to abandon the Atlantic Coast Pipeline project, which raises questions about how it will get the natural-gas supplies it is counting on, the company is still planning to build new gas plants over the next 15 years under most of its scenarios.
The exception to this is the appropriately named “no new gas generation” pathway, which would rely on “diverse, new carbon-free sources and even larger additions of energy storage and offshore wind as well as the adoption of supportive policies at the state and federal level,” Duke states in its IRP.
The two pathways that would yield the most dramatic carbon reductions are based on North Carolina’s evolving Clean Energy Plan stakeholder process, which is evaluating policy options for cutting emissions 70 percent by 2030 (versus 2005 levels).
To reach such a level, Duke fleshed out two possible options: The first is a “high wind” path that would capture the offshore wind potential of the Carolinas coastal waters, but it would require policy changes in both states and increased investment in supply chain and transmission capacity. The second is a “high SMR” case reliant on the commercial availability of small modular nuclear reactors over the coming decade.
Duke’s IRP was developed over six months of workshops and comments involving more than 200 stakeholder groups, ranging from power providers and large energy customers to environmental and consumer advocates.
The filing opens up another round of deliberations by regulators, and it is sure to serve as a flashpoint of debate over whether the utilities are properly balancing the costs of moving toward a cleaner energy system against the threats of moving too slowly.
Big growth for solar and storage, possible role for offshore wind
Unsurprisingly, the six scenarios yield significantly different projections of renewable energy and energy storage growth over the next 15 years.
Solar growth by 2035 stalls at 8,650 megawatts under Duke’s base case, but rises to 12.3 gigawatts under its carbon policy case — and up to 16.4 gigawatts under its most aggressive scenario.
All of the scenarios are less reliant on wind power, which plays little role in the Southeastern U.S. energy mix today, although Duke’s most aggressive case sees up to 2,650 megawatts of offshore wind by 2035. Iberdrola’s Avangrid holds the rights to a large offshore wind development zone off the coast of North Carolina.
Meanwhile, Duke’s “high SMR” case would require 1,350 megawatts of small nuclear capacity by 2035, and its no-new-gas scenario presumes 700 megawatts of this resource.
As for energy storage, Duke points to just over 1,000 megawatts in its base case, rising to 7.4 gigawatts in its no-new-gas scenario. That’s more energy storage than exists in the country today, and far more than Duke had previously projected building.
That “presents increased system risks, given that there is no utility experience for winter peaking utilities in the U.S. or abroad with operational protocols to manage this scale of dependence on short-term energy storage.”
Looking at the price tags
Duke represented the costs in terms of its impact on the average monthly bills of a residential customer of Duke Energy Carolinas, which now stands at roughly $104. For the less costly pathways, monthly rates would rise an average of 1.3 to 1.5 percent per year to add between $23 to $25 per month to bills by 2035. For the more costly pathways, the increase would be between 2.4 to 2.5 percent per year, adding $45 to $47 per month by 2035.
A big chunk of the difference between the two ends of the spectrum comes from the relative levels of new transmission investment Duke foresees needing. Under its base cases, Duke expects to invest about $1 billion in transmission over the next 15 years. But in the high-wind and no-new-natural-gas scenarios, those costs increase to between $7.5 billion and nearly $9 billion.
Duke also plans at least 2,050 megawatts of energy efficiency and demand response by 2035, and as much as 3,350 megawatts under its more aggressive carbon-reduction cases.
In the IRP, Duke noted that its more aggressive pathways “have a greater dependence on technology advancements and projected future cost reductions, thus requiring near-term supportive energy policies at the state or federal levels."
That makes for more uncertainty and the potential for even higher costs if regulators choose them — the same conditions utilities around the world face as they contemplate decarbonizing their power grids.