Solar pricing improved. Grid access became the hard asset.

Price shape is an operating question, not a slogan.

Sunday's 77.6% ratio is the counterexample to any claim that solar cannibalisation has ended. It shows a substantial daylight discount during a week with no negative 15-minute spot price in the retained daily reference series. Developers should stress-test the return of more abundant generation: a stronger solar build-out, more wind, improved nuclear availability or weaker demand can move prices without changing the PV hardware.

We would calculate three measures for every asset: the generation-weighted spot price, the achieved net price after balancing and offtake, and the restricted-energy value after dispatch or export limits. Each measures a different risk. The first answers market exposure, the second cash settlement, and the third whether the plant can physically sell the energy it could otherwise produce.

A 100 RON/MWh change in achieved price across 1,000 MWh delivered changes gross proceeds by 100,000 RON before costs. This arithmetic is a sensitivity, not a claim that any particular project generated or sold that volume. Investor committees should put this sensitivity beside a revised schedule and connection cost, rather than looking at PZU headlines alone.

On 22 and 27 October the daytime proxy exceeded the respective PZU daily base. On Sunday 25 October the ratio fell to 77.6%, and the lowest reported PT15 value was still positive at 578.94 RON/MWh. The coexistence of a positive price floor and a steep relative daytime discount shows why "no negative prices" cannot be confused with "no cannibalisation". [S01]

The production-weighted spot capture price is Σ (PT15 PZU price × matched PV MWh) / Σ matched PV MWh. The realised cash outcome then requires balancing costs, contracted offtake pricing, permitted export, curtailment, settlement and applicable fees. An unweighted 08:00–17:00 average does not answer either question. Do not use 95.1% as a project capture factor or as a bankable long-term merchant price.

The publication reveals 412 MW in 2032, 80 MW in 2035, 862 MW in 2036 and 212 MW in 2037. That is respectively 26.3%, 5.1%, 55.0% and 13.5% of the published total, with more than half the offer dated 2036. In a discounted-cash-flow model, the time of energisation is not footnote material: it determines how long development costs are carried and how many future income years remain before refinancing or sale.

The table divides capacity into network zones A–J. Those letters are not a licence to assign a project to a county without checking Transelectrica's zone map and the applicable network configuration. At a chosen node, developers must still assess ATR terms, reinforcement works, technical limits, allocation contract, security, land and construction schedule.

Zero in this auction table means no capacity is offered in that zone/year via this mechanism. It does not void earlier connection rights, rule out every connection at distribution level, or prevent projects with distinct valid arrangements from progressing. The dangerous media simplification is “Romania cannot connect anything until 2032.” The defensible conclusion is narrower — and still commercially important.

Separate grant availability from grant cash.

For sponsored and public-sector plants, documentation should distinguish the initial award, signed contract, incurred eligible costs, payment request, authorisation and receipt of funds. A grant pledged against construction may still create bridge-financing exposure if reimbursement takes longer than planned. A grid delay can compound that exposure by postponing revenues after the investment has been made.

The group's own reference to EUR 26 million in approved PNRR grants at OMV Petrom's commissioned assets is a useful example of precise wording. It does not establish the amount reimbursed to any individual SPV as of 28 October. Investors need drawdown evidence and remaining payment conditions independently from the media headline.

Frăsinet is a 72 MW project-level financing story; SANY concerns 153 MW of standalone BESS development; ENNA concerns 612 MWh of storage energy alongside solar. They are three distinct assets, with different maturity and different units. There is no sound aggregate MW figure that simply adds all three without assumptions about ENNA's power rating.