Data Center PPA: Annual Volume Match but Hourly Mismatch
A data center uses 150 GWh per year with a flat 24/7 load. A developer offers a 15-year solar PPA at $49/MWh for an 80 MWac plant expected to produce 160 GWh annually; RECs are included. The data center also has a 40 MW/160 MWh battery that can shift 30 GWh per year, with 10% round-trip losses. Midday solar capture is $18/MWh; evening market purchases average $65/MWh. On an annual basis the PPA exceeds load by 10 GWh, so the CFO calls it a perfect match. The developer wants firm offtake, no curtailment rights, and a 15% letter of credit. The buyer wants negative-price protection, hourly RECs, and change-in-law relief.
1. Using annual volumes, assume 110 GWh is consumed instantaneously, 50 GWh is sold into the midday market at $18/MWh, and 40 GWh must be bought in the evening at $65/MWh. What is the effective cost per MWh of the 150 GWh load? Compare with a flat $60/MWh supply contract.
Read the worked answer
PPA cost = 160,000 MWh × $49 = $7.84 million. Midday sales credit = 50,000 × $18 = $0.90 million. Evening purchases = 40,000 × $65 = $2.60 million. Net cost = $7.84 - $0.90 + $2.60 = $9.54 million for 150,000 MWh, or $63.60/MWh. A flat $60/MWh contract costs $9.00 million. The solar PPA is about $0.54 million per year more expensive despite matching annual volume, because the 10 GWh surplus is sold at a low price while evening load is bought at a high price. If RECs are worth $2/MWh on 160 GWh, the credit is $0.32 million, still leaving the PPA about $0.22 million above the flat contract. The annual volume match is not an hourly match; the CFO should compare shaped cost, not headline PPA price.
2. The seller refuses to shape. Which contractual features should the buyer prioritize, and what amendments would you propose? Quantify battery shifting if 30 GWh is moved from $18 to $65 with 10% losses.
Read the worked answer
Battery shifting: to deliver 30 GWh at evening, charge 33.3 GWh because of 10% losses. The buyer forgoes selling 33.3 GWh at $18 = $0.599 million and avoids buying 30 GWh at $65 = $1.95 million, a gross benefit of about $1.351 million per year before battery cost. That closes much of the $0.54 million gap if battery levelized cost is below roughly $45/MWh delivered. Contract priorities should be negative-price treatment, curtailment rights, REC transfer, volume tolerance, and change-in-law. Proposed amendments: buyer may curtail when day-ahead price is below -$5/MWh without paying for unscheduled energy; buyer retains RECs for curtailed volume or pays a small reservation fee; ±10% annual volume tolerance; change-in-law pass-through capped at 5%; collateral reduced to 10% of annual contract value with a rating trigger.
3. How should negative-price and curtailment risk be allocated, and what happens to RECs if the buyer curtails?
Read the worked answer
The buyer should have a unilateral curtailment right during negative prices, with no energy payment for curtailed MWh. The seller may keep and sell the curtailed energy, but the buyer's REC claim must be protected: either the seller transfers RECs for curtailed production for a small fee, or the buyer must replace those RECs and should receive a price adjustment. A clean structure is: buyer may curtail below -$5/MWh; seller retains energy and RECs unless buyer elects to pay $1/MWh to keep RECs; buyer is not obligated to buy replacement power from seller. For system-wide curtailment, allocate by cause: seller bears if due to its equipment, buyer bears if due to its election. Change-in-law costs should be shared with a cap. This prevents the buyer from paying $49/MWh for energy it cannot use while still preserving the hourly renewable claim.