top of page

Constellation Energy: A Lot Working Well for America's Nuclear Behemoth

DISCLAIMER: Any written content contained herein should be viewed strictly as analysis, observation & opinion and not in any way as investment advice. No compensation was received for this report. Visitors to this site are encouraged to conduct their own due diligence.

Late last week Constellation Energy (CEG) reported its Q4/2022 financial results which handily beat expectations with adjusted EBITDA of $605M (consensus $536M) and provided for a bullish FY/2023 outlook. Given that FY/2022 adjusted EBITDA of $2.667B surpassed revised guidance calling for between $2.450B-$2.650B, FY/2023 adjusted EBITDA guidance is now expected between $2.900B-$3.300B, with even the low end being considerably higher than the FY/2022 figure. Gross margins for FY/2023 and FY/2024 were established at $8.350B and $8.950B respectively, both above consensus estimates. On the corporate front, an initial capital allocation strategy was announced with $1.0B in share repurchases authorized along with the doubling of the corporate dividend (now reaching a quarterly $0.282 per common share for an annual ~1.41% yield) with a targeted 10% future growth rate thereafter.

In terms of investments, approximately $1.5B has been earmarked for 2023-2025. Of which, $900M was allocated for commercial scale hydrogen production (a greenfield production facility), $350M for wind re-powering projects, $100M for nuclear uprates (at Byron and Braidwood - upsized to $800M as announced today) and $100M for growth capex. Certain costs were considerably higher this year compared to 2021 - prices for nuclear fuel conversion and enrichment services were between 50%-100% higher. Steps have been taken to increase inventory in order to mitigate the risk (extending until 2028) of possible Russian supply disruptions. Note that post-2028, western enrichment providers expect to have additional capacity online. Until then, fuel costs are expected to rise in the coming years but management expects the increase to remain under the $6.00/MWh threshold until 2028.

Note that after deciding to spin-out from from Exelon Corporation (EXC), since the January 19, 2021 IPO, Constellation Energy has gained +70% to date:

Costs aside, the earnings and corporate updates reflect the overall resiliency of the company in light of the currently strong fundamentals. We continue to be very positive on the company given tailwinds from the recently passed IRA Production Tax Credits (PTCs) coupled with the fact that Constellation Energy’s entire nuclear generating capacity (~24,000 MW) is 100% unregulated.

1) Nuclear IRA Provisions: Though the Inflation Reduction Act provides provisions for wind, solar, hydro, nuclear, natural gas and even hydrogen development/production, nuclear generating capacity is the only one which is both zero carbon and baseload capacity. In short, looking specifically through the nuclear lens, the IRA provides for a maximum credit of $35/MWh at a theoretical power price of $0/MWh. The PTC provides support of up to $15.00/MWh for units when revenues are between $25.00/MWh and $43.75/MWh while preserving the ability of the unit to participate in upside from commodity markets. The credit reduces to $0/MWh for power prices exceeding $43.75/MWh given the pricing mechanism is structured as a contract of difference framework. Depending on the company, nuclear generating capacity will have a minimum floor price for (in the least) the 10 next years. This level of certainty will spur both further investments and life extensions for many aging nuclear reactors. Coupled with the fact that natural gas prices have been rising in North America, the IRA pricing floor will ensure that nuclear will once again become economic LT. As evidence of the IRA’s pricing support, we have already seen numerous nuclear power plants announce life extensions while others which were slated to close, will continue to operate for years to come.

2) Unregulated Capacity: This category comprises Independent Power Producers (IPPs) / merchant generators. These are essentially electric generators with no assigned service territory that produce and sell electricity into wholesale power markets at market based wholesale rates (or based on power sales contracts). This is unlike the regulated utilities which have been granted monopoly power in pre-defined territories, and must sell at state-regulated rates. Another differentiation feature is that traditional regulated utilities usually provide bundled services to consumers – that is generation, transmission, distribution and any other ancillary service. IPPs do not own any transmission assets nor do they sell to retail customers. The concepts between regulated versus unregulated can come down to rate based growth (regulated) versus competitive power (unregulated).

Our current preference for unregulated nuclear utilities stems from the fact that the IRA’s PTCs essentially provide the benefits of regulated utilities’ stability and cash flow certainty, without the constraints of being regulated operationally and financially. Unregulated utilities are not as constrained by the heavy burden of regular debt and equity funding required to build and maintain power plants to meet future load growth and offset planned retirements. Growth is much harder as a regulated utility as risk adjusted returns need to be found in a more limited pool of assets found in states with advantageous or incentive based (or supportive) rate making. Every facet of bundled electricity (again, this means generation, transmission, distribution and service) must always be considered as a regulated utility. In addition to pricing upside, unregulated businesses have much more potential M&A upside and have accordingly demonstrated much higher growth rates historically. In our view, the key to a successful utility is relatively simple:

1) Increase capex in order to grow earnings (keep investors happy)

2) Capex spend for resiliency and reliability (keep regulators happy)

3) Minimize opex to keep rates in check (keep consumers happy)

For an unregulated business, point 2 is much less of a concern or burden. As such capex via M&A is much more active. For this reason (and as demonstrated by Constellation’s outperformance over the last year since IPO), unregulated nuclear businesses are now benefitting from cash flow visibility/stability for the next decade+ while also having more options on the M&A front.

The bottom line is that we see strong downside support given the pricing guarantees as provided by the PTC over the next 10 years coupled with the unregulated nature of CEG’s nuclear fleet. As illustrated above (graph given CEG forecasts), it is estimated that the Federal nuclear PTC would enable Constellation’s plants to earn between $40-$44/MWh of revenue across a wide range of power market environments. It is expected that the PTC would effectively lock in a floor level of revenue in the low-mid ~$40s/MWh. The PTCs are single handedly the largest reasons as to why numerous nuclear power plants have been announcing life extensions while others have been delaying plans to decommission. Given the nearly -15% selloff since the late November highs, we feel that much of the PTC impact on CEG is being discounted (or misunderstood, or plainly ignored) by the market. Therein lies the current opportunity.

Constellation Energy has previously demonstrated its competence both with its best in class nuclear fleet along with its operating acumen. Historically, the operating capacity factors for the nuclear fleet has consistently outperformed the domestic industry averages.

As further evidence of nuclear power’s resiliency and reliability, Constellation management announced that PJM interconnect* bonuses are expected to be awarded seeing as the entire nuclear fleet was operating at 100% during the December 23-25 Winter Storm Elliot period. This 100% reliability compared to only 62% reliability from natural gas and 83% reliability from coal. Within the greater PJM region, during the winter storm period, nearly 23% of PJM capacity failed, with ~90% of the outages courtesy of fossil fuels.

*The PJM region is a regional transmission organization encompassing the electrical transmission system serving all or parts of Delaware, Illinois, Kentucky, Indiana, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. The PJM Interconnection region serves over ~65.0M people in total.

bottom of page