I recently watched something a bit unusual: a live, staged power purchase agreement (PPA) negotiation, hosted in the European Parliament by MEP Mr. Gori and RE-Source Platform. Instead of the usual panel talking about PPAs in the abstract, they put an actual seller and an actual buyer on stage and had them negotiate a real-looking deal in front of everyone — a 100 MW solar project in Greece, seller side played by a developer/investor (Neoen), buyer side played by an aluminium producer (Metlen) that also happens to run its own electricity business.
The format sounds like a show, but it wasn’t. Watching two experienced negotiators go back and forth made the risk allocation part of a PPA — the part that’s usually buried in 100 pages of legal text — suddenly very clear. So I wanted to write up what stuck with me, partly as notes to myself, partly because I think anyone who touches renewable energy PPA contracts (or just wants to understand how the PPA negotiation actually works in practice) will find it useful.
First, why PPAs matter right now
Quick bit of context before the negotiation itself: PPAs are basically long-term supply contracts between a renewable energy producer (i.e. seller) and a buyer — could be a big tech company or a factory. The buyer gets price certainty and a way to decarbonize; the seller gets a guaranteed customer, which in turn makes it much easier to raise debt and actually build the project.
The EU is leaning on this tool pretty hard right now. The International Energy Agency expects PPAs to help finance something like 70% of new renewables projects through 2030. But some countries barely use them, and even in the more mature markets, growth has actually slowed a bit in 2025. Two of the biggest reasons for that slowdown came up again and again in the negotiation: negative electricity prices, and credit risk. More on both below.
The setup: who's negotiating what
- Seller: a solar developer/asset manager, negotiating on behalf of a 100 MW PV project in Greece, roughly a €100 million investment, expected grid connection in about two years.
- Buyer: an aluminium smelter — a genuinely huge, constant electricity consumer (about 3 terawatt-hours a year, roughly 6% of Greece’s entire national electricity consumption), looking to hedge a chunk of its future power needs and green up its supply chain at the same time.
Before any real negotiation starts, there’s a lightweight screening phase — buyer sends out an RFP (request for proposal), seller responds with indicative pricing and volumes, there’s a bit of a “getting to know you” round covering things like human rights due diligence in the supply chain. Then both sides sign a non-binding term sheet that locks in one binding thing: exclusivity. Neither party is allowed to shop the deal around elsewhere for a set window (four months, in this case).
The reason exclusivity matters so much here is basically a matching problem. There are a lot of sellers out there, and a buyer simply doesn’t have the bandwidth to run parallel negotiations with several of them at once — each one takes months of legal, financial and technical back-and-forth. So once both sides decide they’re serious about each other, they agree to stop shopping around and commit the time needed to actually get the deal done. One negotiator compared it to marriage, since you’re about to sign up for 8-20 years together.
Then the real negotiation — the risk allocation — begins. This is the part I actually want to walk you through.
The risk allocation table
Here’s the breakdown, item by item, of who wanted what and where they landed.
| Risk Area | Seller’s Starting Position | Buyer’s Starting Position | Where They Landed |
|---|---|---|---|
| COD timing risk (when does the power actually start flowing?) | Can’t commit to an exact commercial operation date — construction, permitting and equipment sourcing all carry delay risk | Wants certainty on exactly when the hedge kicks in | Buyer builds in a delay margin around the target date rather than expecting an exact one, and the contract includes liquidated damages (LDs) the seller owes if key construction milestones slip |
| Shape risk (does the power arrive when you need it?) | Only willing to sell “as produced” — won’t promise a fixed generation profile | Runs a constant, 24/7 load; a purely solar profile leaves big gaps | Seller adds co-located battery storage to smooth things out a bit; flatly refuses to offer true baseload power, since that would mean buying expensive night-time electricity to cover the gap |
| Contract length vs. contracted volume | Wants 8+ years minimum, for bankability | Tries to negotiate down from 10 years to 9 | They trade one variable for another: shorter term is offset by bumping the contracted share of output from 70% up to 75%, so the total hedge value stays the same. Seller also offers a 95% availability guarantee instead of a hard volume promise |
| Grid curtailment (what if the grid operator just… turns you off?) | Won’t eat the cost of curtailed hours | Worried about paying for power that never actually shows up | Battery charges during the curtailment window and discharges once it’s lifted — volumes get settled later. Risk is shared rather than dumped on one side |
| Negative prices (yes, this happens — generators sometimes have to pay to put power on the grid) | Doesn’t want to be forced to pay the buyer during negative-price hours | Doesn’t want to pay above the agreed price when the market goes negative | A “zero floor” — the buyer’s payment never drops below €0 even if wholesale prices go negative, but the seller also isn’t forced to eat the full loss. Split down the middle |
| Pricing structure | Prefers a simple fixed price (landed around €80/MWh) — easiest to finance against | Wants part of the price linked to the London Metal Exchange aluminium price, to hedge their own product revenue | Fixed price is the default in most deals (~80% of the time, per the seller). The commodity-linked structure is possible, but it gets routed through a trading counterparty, and that cost gets folded back into the fixed price (more on this below) |
| Credit support | Wants a parent company guarantee or letter of credit backing the deal — around €20 million in this case | Fine with it — routine for a company this size | Guarantee shrinks over time as exposure declines; arrangement is symmetrical, so the buyer is also protected if the seller’s project company defaults |
| ESG / human rights due diligence | Offers regular audit rights over the supply chain | Needs assurance — for their own investors — that assets aren’t linked to forced labour | Audit rights granted, on a recurring basis |
| Exclusivity | Wants the buyer locked in during negotiation | Wants the same in return | Mutual — the one clause in the term sheet that’s actually binding |
The bit that got the most questions from me: aluminium prices and electricity have nothing to do with each other, except they kind of do
The part I found most interesting wasn’t actually the electricity-specific stuff — it was the buyer asking for part of the electricity price to move with aluminium prices on the London Metal Exchange.
At first that sounds like total nonsense. What does the price of aluminium have to do with a solar PPA? But it makes sense once you think about the buyer’s actual exposure: electricity is 40% of their total production cost. So their profitability doesn’t just depend on what they pay for power — it depends on the relationship between what they pay for power and what they can sell aluminium for. If aluminium prices crash (say, because of tariffs or a demand shock) while they’re locked into a fixed electricity price, their margins get crushed even though nothing about the power contract itself changed.
So what they actually wanted wasn’t cheaper electricity — it was a way to keep their margin roughly stable regardless of which direction commodity markets move.
The seller’s response was interesting too: they said, sure, we can build that in, but we’re not going to carry that risk ourselves. A solar developer’s whole business model is building and financing power plants, not making directional bets on metals markets — that’s not their expertise and it’s not what their lenders signed up to finance. So instead, they’d take this request to a commodities trading firm, who would structure a hedge against it (effectively an insurance product against aluminium price swings) and charge a premium for taking on that risk. That premium then gets folded into the fixed electricity price the buyer ultimately pays.
Naturally I wondered: why doesn’t the buyer just go find a trader themselves and cut out the middleman? A few reasons came up worth remembering:
- The volume you’re hedging isn’t fixed. The whole deal is priced against the actual, hour-by-hour output of a solar farm, which fluctuates. Only the seller has visibility into that. If the buyer hedges separately with an outside trader, the two contracts won’t line up perfectly hour to hour, which creates its own mismatch risk.
- One contract beats two. Bolting the hedge onto the PPA means one counterparty, one settlement process, one set of legal and credit terms to manage — instead of running two separate relationships with two separate default risks.
- Not everyone has trader relationships. Large energy developers deal with commodity trading desks constantly and already have the banking relationships and credit lines to get competitive pricing. A mid-sized industrial buyer often doesn’t.
- The buyer still pays either way. Whoever arranges the hedge, the cost of it lands with the buyer eventually — the only real question is who does the legwork.
And to be clear — the aluminium price link has nothing to do with how much the sun happens to shine. Shape risk (does the power actually show up when needed) and the aluminium hedge (does the buyer’s overall margin stay stable) are two completely separate risk conversations that just happened to come up in the same negotiation
The bigger picture: what's actually slowing the PPA market down
A few voices from the European Commission and from wind/solar industry associations closed out the session, and two structural issues came up as the real bottlenecks — bigger than anything the two negotiators on stage could solve themselves:
- Negative prices are corroding the economics. Europe logged more than 10,000 hours of negative electricity prices in 2024 alone. The consensus in the room was that the actual problem isn’t “too much solar” — it’s too little flexibility (i.e., not enough battery storage) to absorb it. China installed roughly 25 GWh of battery storage in a single project last week — more than half of what Europe has built cumulatively over the last 20 years.
- Credit risk locks out smaller buyers. Sellers generally want investment-grade counterparties before they’ll sign a long-term deal, which quietly excludes a lot of mid-sized companies that would otherwise want to buy green power. State-backed guarantee schemes (France has one; the European Investment Bank has a new pilot programme) are being floated as a way to widen the pool of bankable buyers.
- Permitting and grid capacity are still the slow lane. One speaker put it bluntly: developers are still driving vans full of paper binders to permitting authorities. The rules to speed this up already exist on paper in the EU — the issue is application, not legislation.
- Carbon accounting rules matter more than people think. If EU rules on calculating a product’s carbon footprint don’t actually give credit for having signed a PPA, a big chunk of the incentive to sign one in the first place disappears — regardless of how good the hedge is.
Takeaway
What struck me most, watching this play out, is that a PPA isn’t really a single negotiation over “the price of electricity.” It’s a negotiation over which party is best positioned to absorb each individual risk — weather variability, grid curtailment, price volatility, counterparty credit, even downstream commodity exposure — and then pricing each of those allocations individually. The people who are good at this aren’t just negotiating a number; they’re taking a long list of genuinely different risks and finding, for each one, whoever can carry it most cheaply.
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