Power markets · Valuation
Delivery risk in long-term power contracts
A fixed electricity price reduces exposure to wholesale markets. The seller's delivery obligations determine the cost of production shortfalls and the cash flows available to investors.
Constellation’s September 2024 announcement of a 20-year agreement with Microsoft illustrates the scale of long-term nuclear power contracting. The company announcement described an approximately 835 MW restart. The worked analysis below uses a separate 1,000 MW plant to examine contract structure.
Contract structure and production risk
A power-plant owner negotiating a long-term contract must evaluate the price offered against the obligation to supply electricity during an outage. Under an as-generated agreement, the buyer purchases a share of the electricity produced. A firm-volume agreement commits the seller to a specified quantity, requiring replacement purchases if the plant produces too little.
This illustrative analysis uses a 1,000 MW plant and assumed contract terms, separate from Constellation's Microsoft agreement. At 90% availability, the plant produces 7.884 million MWh annually. A contract covering 80% of the electricity produced at $65/MWh yields identical cash to a fixed annual delivery obligation of 6.3072 million MWh when production meets that assumption. Comparing the two contracts solely at expected output would leave their different treatment of production shortfalls unvalued.
Reduced price exposure and foregone revenue
Under the as-generated agreement, 80% of output receives the $65/MWh contract price and 20% sells at the wholesale price. At 90% availability, a $1/MWh movement in the market changes annual revenue by $1.58 million, compared with $7.88 million for a fully merchant plant selling all output at market prices. Revenue sensitivity falls by four-fifths, while the seller remains exposed to production losses, changes in operating costs, and customer nonpayment.
At a $30/MWh market price, the contract produces a $97.6 million annual cash inflow after operating costs, maintenance capital expenditure, and modeled tax. The merchant plant requires $90.6 million of cash to cover those expenditures. Contracted receipts therefore cover the assumed maintenance program during this low-price year. At $100/MWh, annual cash is $180.4 million under the contract, compared with $346.0 million from merchant sales, because most output continues to receive the agreed price.
The alternatives produce equal cash at $65/MWh. For the owner, the decision depends on the likelihood and duration of prices above and below that level, together with its ability to finance a low-price year. Reducing annual cash volatility may justify accepting less revenue when wholesale prices are high. Establishing a valuation benefit also requires measuring the expected revenue surrendered.
Annual cash by wholesale price
$m after operating costs, maintenance capital expenditure, and cash tax · 90% plant availability
View chart data · $m
| Wholesale price · $/MWh | Merchant output | 80% as-generated contract |
|---|---|---|
| 30 | -90.58 | 97.63 |
| 35 | -51.16 | 103.54 |
| 40 | -11.74 | 109.45 |
| 45 | 20.76 | 115.37 |
| 50 | 50.32 | 121.28 |
| 55 | 79.89 | 127.19 |
| 60 | 109.45 | 133.11 |
| 65 | 139.02 | 139.02 |
| 70 | 168.58 | 144.93 |
| 75 | 198.15 | 150.85 |
| 80 | 227.72 | 156.76 |
| 85 | 257.28 | 162.67 |
| 90 | 286.85 | 168.58 |
| 95 | 316.41 | 174.5 |
| 100 | 345.97 | 180.41 |
| 105 | 375.54 | 186.32 |
| 110 | 405.11 | 192.24 |
| 115 | 434.67 | 198.15 |
| 120 | 464.24 | 204.06 |
| 125 | 493.8 | 209.98 |
| 130 | 523.37 | 215.89 |
Replacement purchases under firm delivery
The firm-volume comparison requires delivery of 6.3072 million MWh every year. The seller purchases any shortfall at the wholesale price and sells any excess production into that market. Annual generation equals the delivery obligation at 72% availability, calculated as 80% of the expected 90% availability. Below this threshold, the plant becomes a net purchaser of electricity, so higher wholesale prices reduce its cash flow.
At 55% availability, generation declines to 4.818 million MWh and replacement purchases total 1.4892 million MWh. Annual cash is positive $35.9 million at a $75/MWh wholesale price and negative $63.9 million at $150/MWh. The almost $100 million deterioration results from purchasing the production shortfall at a higher price. At 90% availability, higher prices increase cash because the plant produces surplus electricity for sale.
The 70% availability case produces a smaller shortfall of 175,200 MWh. Cash declines as wholesale prices increase but remains positive throughout the plotted range. The production level at which price exposure changes direction therefore differs from the level at which cash becomes negative. For this contract, a production forecast should identify both the expected replacement volume and the prices at which those purchases create a cash deficit.
Annual cash with a fixed delivery obligation
$m per year · Delivery of 6.3072 million MWh at $65/MWh, with production shortfalls purchased at the wholesale price
View chart data · $m
| Wholesale price ($/MWh) | 55% plant availability | 70% plant availability | 90% plant availability |
|---|---|---|---|
| 30 | 86.13 | 91.06 | 97.63 |
| 45 | 69.38 | 89.09 | 115.37 |
| 60 | 52.62 | 87.12 | 133.11 |
| 75 | 35.87 | 85.15 | 150.85 |
| 90 | 19.12 | 83.18 | 168.58 |
| 105 | 2.36 | 81.2 | 186.32 |
| 120 | -19.19 | 79.23 | 204.06 |
| 135 | -41.52 | 77.26 | 221.8 |
| 150 | -63.86 | 75.29 | 239.54 |
Full original scenario grid
| Plant availability / Wholesale price · $/MWh | 30 | 45 | 60 | 75 | 90 | 105 | 120 | 135 | 150 |
|---|---|---|---|---|---|---|---|---|---|
| 55% | 86.13 | 69.38 | 52.62 | 35.87 | 19.12 | 2.36 | -19.19 | -41.52 | -63.86 |
| 60% | 87.77 | 75.95 | 64.12 | 52.3 | 40.47 | 28.64 | 16.82 | 4.99 | -9.11 |
| 65% | 89.42 | 82.52 | 75.62 | 68.72 | 61.82 | 54.92 | 48.03 | 41.13 | 34.23 |
| 70% | 91.06 | 89.09 | 87.12 | 85.15 | 83.18 | 81.2 | 79.23 | 77.26 | 75.29 |
| 75% | 92.7 | 95.66 | 98.61 | 101.57 | 104.53 | 107.48 | 110.44 | 113.4 | 116.35 |
| 80% | 94.34 | 102.23 | 110.11 | 118 | 125.88 | 133.76 | 141.65 | 149.53 | 157.42 |
| 85% | 95.99 | 108.8 | 121.61 | 134.42 | 147.23 | 160.04 | 172.86 | 185.67 | 198.48 |
| 90% | 97.63 | 115.37 | 133.11 | 150.85 | 168.58 | 186.32 | 204.06 | 221.8 | 239.54 |
| 95% | 99.27 | 121.94 | 144.6 | 167.27 | 189.94 | 212.6 | 235.27 | 257.94 | 280.6 |
Outage timing and settlement costs
The annual model applies one wholesale price to every surplus or shortfall. An agreement requiring hourly settlement can incur replacement costs even in a year with surplus generation. Lost output during high-price hours must be purchased at those prices, while surplus generation during cheaper hours earns less. Two years with equal total production can consequently generate different cash flows.
The exposure increases if an event interrupts plant production while also reducing supply across the grid. Assessing that possibility requires a scenario combining plant unavailability with high replacement prices. Treating outage probability and replacement cost as independent can understate the cost when they are correlated. The annual sensitivities establish the financial effect of each combination without assigning a probability to it.
For the seller in this example, outage allowances and limits on replacement purchases would change the acceptable contract price. Delivery schedules and settlement location would also affect the cost of fulfilling the agreement. A higher quoted price could compensate for more costly delivery obligations, so comparing proposed prices requires valuing the corresponding replacement purchases under a consistent set of production and market assumptions.
Contract price and the discount-rate assumption
At the assumed $70/MWh wholesale forecast, the as-generated contract reduces annual cash from $168.6 million to $144.9 million. The $23.7 million difference is the after-tax cost of selling 80% of generation at a $5/MWh discount. Discounting twenty years of level cash flows at 9.5%, with no terminal value, produces a $208.4 million present-value reduction from the price concession.
Applying a 7.5% discount rate to the contracted cash flows increases their present value by $200.3 million. The resulting $1,477.5 million valuation remains below the $1,485.6 million merchant value. The assumed two-percentage-point reduction in the discount rate almost offsets the price concession. Supporting that reduction would require evidence about the remaining risk in the contracted receipts.
Customer credit and payment security affect collection risk, while delivery obligations determine the seller's exposure to outages. Expected contract losses should be reflected in forecast cash, with a discount rate consistent with the risk of those cash flows. Any additional valuation premium should identify the risk reduction it compensates for, avoiding a second allowance for a benefit already recognized in the discount rate. Choosing 7.5% because it approximately compensates for the lower contract price would reverse this reasoning.
The example excludes debt financing. More predictable receipts may support a lower borrowing cost or greater debt capacity, but either benefit requires an assessment of borrowing terms and debt-service coverage. A reduction in the cost of debt also needs to be evaluated alongside the capital structure and the return required by equity before changing the discount rate applied to all asset cash flows.
Present value of merchant and contracted cash flows
$m present value · Twenty years of level annual cash flows with no terminal value
View chart data · $m
| Component | $m |
|---|---|
| Merchant PV | 1,485.64 |
| Price concession | -208.43 |
| Lower discount rate | 200.31 |
| Contract PV | 1,477.52 |
Capacity rights and investment requirements
The modeled receipts cover energy sales in MWh. Capacity is a commitment of resources to be available when the electricity system needs them, and PJM's explanation of its capacity market states that performance obligations accompany capacity payments. An energy contract's price alone establishes neither the ownership of capacity revenue nor responsibility for the associated obligations.
Including capacity value for this plant would require identifying the rights retained under the agreement and the capacity eligible for payment, together with its performance exposure. Evaluating a restart or new plant would also require the initial investment, which is excluded from the operating present values. These additions could change the return available to investors even if the energy contract produced the cash flows shown.
The assumptions and exclusions below define the worked scenario.
Model notes and assumptions
- Plant capacity 1,000 MW; expected availability 90%, producing 7.884m MWh annually. This is an assumed operating case.
- Variable cost $25/MWh; fixed operating costs plus maintenance capex $130m annually. Cash tax is 25% of positive pre-tax operating cash; negative periods receive no immediate tax benefit.
- An 80% as-generated PPA pays $65/MWh on 80% of actual generation. The firm-volume comparison instead commits 6.3072m MWh a year; excess production or shortfall settles at the plotted wholesale price.
- No transmission basis, hourly shape, escalation, capacity payments, production credits, new-build capex, or debt financing is modeled. The example separates price and delivery exposure.
- The valuation uses 20 end-year cash flows, expected wholesale price $70/MWh, and no terminal value. The discount-rate comparison is 9.5% versus 7.5%; it is an assumption, not a measured market risk premium.
The charts are not a price target or valuation of a named security.