Insights

The old PV park holds the scarcest resource

Why the grid connection point has become worth more than the panels behind it

Elevat Solar Consulting · October 2026 · 11 min read

The most valuable thing in a PV park commissioned in 2012 is its grid connection point. The panels are 14 years old and produce less than they did in their first year.

The connection point was fought for, paid for, and it works. Behind it sit a signed connection agreement, built connection facilities, a detailed development plan in force, a building permit, settled land rights and road access. A greenfield project has to pay for all of that, and wait for it, before it produces a single kilowatt-hour.

All else being equal, an existing depreciated park upgraded with a battery, and where possible with wind, starts earning sooner and with less risk than a new project. Greenfield remains possible. But the grid connection point has become the scarce resource, and these parks already hold it.

It all depends on how much headroom actually sits behind the specific connection point. Without measured data on that, everything else is reasoning.

Where these parks stand today

The fleet was built in a short window. According to the Bulgarian Sustainable Energy Development Agency (SEDA), as of 31.01.2013, 770 of 1 207 registered photovoltaic plants, almost two thirds, were commissioned in 2012.

These parks started out on long-term feed-in contracts at preferential prices. For plants with a total installed capacity of 500 kW and above, the mechanism is now different. The energy is sold on the market, and the Electricity System Security Fund (ESSF) pays a premium under a premium compensation contract. The Energy and Water Regulatory Commission (EWRC) sets the premiums every year under Art. 21(1)(8b) of the Energy Act.

The transition came in three steps, through three amendments to the Energy Act. Plants of 4 MW and above moved to premiums under § 68 of the Transitional and Final Provisions of the act amending the Energy Act, State Gazette No 38 of 2018, with contracts in force no later than 01.01.2019. Plants from 1 to 4 MW moved under § 34 of the amending act published in State Gazette No 41 of 2019, with contracts in force no later than 01.10.2019. Plants from 500 kW to 1 MW moved under § 28 of the amending act published in State Gazette No 9 of 2021, from 01.07.2021.

In all three cases the premium is paid only on volumes up to the net specific production (NSP) on which the plant's preferential price was set. Above the NSP the park sells entirely at market price, without a premium.

The premium is the difference between the plant's preferential price and the forecast market price for the relevant group of producers. The word that matters is "forecast". For the PV group, EWRC derives this price from the baseload forecast and a group coefficient Ks, which reflects the prices the group actually achieved in the previous year.

In Decision No C-8 of 30.06.2026, for the period 01.07.2026 to 30.06.2027, the baseload forecast is 114.11 EUR/MWh, the Ks coefficient is 0.61437, and the forecast price for the PV group, as calculated by EWRC, is 70.10 EUR/MWh.

That is where the exposure comes from. The premium is fixed against a forecast for the group. The individual park receives whatever market price it achieves itself. If it achieves less than the forecast, the difference is its own loss.

Within the period, a correction is possible only under Art. 31b(2) of the Energy Act. When the deviation is substantial, EWRC amends the premiums, but no more often than once every six months. The precedent dates from 2021. Decision No C-25 of 01.07.2021 set the baseload forecast at 119.00 BGN/MWh (1 EUR = 1.95583 BGN). With Decision No C-2 of 01.01.2022, EWRC amended it to 293.37 BGN/MWh, and to 274.96 BGN/MWh for the PV group, because achieved exchange prices had exceeded the forecast many times over. The premiums shrank accordingly. The mechanism works in the opposite direction too.

That is why these parks carry market risk today, before their original contracts run out.

Cannibalisation can be measured

The clearest number comes from the regulator itself. In Decision No C-8 of 30.06.2026, EWRC simulates the participation of a group of PV plants in the day-ahead market for calendar year 2025. The average baseload price is 106.90 EUR/MWh. The volume-weighted price achieved by the group is 65.68 EUR/MWh. In other words, the group sold at 38.6 percent below baseload.

The trend is accelerating. According to an analysis by Capalo AI of 07.08.2026, based on ENTSO-E Transparency Platform data, the average price between 08:00 and 20:00 was level with the 24-hour average in 2023. In 2024 it fell below it by 5.56 EUR/MWh, in 2025 by 11.63 EUR/MWh, and in the first seven months of 2026 by 23.45 EUR/MWh. Negative-price hours numbered 11 in 2023, 55 in 2024, 170 in 2025 and 166 in the first seven months of 2026.

The average daily spread between the highest and lowest hourly price, according to the same analysis, was 126 EUR/MWh in 2023, 183 EUR/MWh in 2024, 165 EUR/MWh in 2025 and 149 EUR/MWh for 2026 up to the date of the analysis.

In its Q2 2026 forecast for Bulgaria, cited in an interview with Capital on 16.07.2026, Aurora Energy Research expects the solar capture price, the price actually achieved, to sit around 48 percent below baseload from 2030 onwards.

The conclusion for a business plan is simple. An average exchange price applied to a solar profile overstates revenue. The EWRC figure for 2025 shows by how much.

The grid is the bottleneck

In its Transmission Network Development Plan for 2025-2034, ESO, the Bulgarian transmission system operator, reports that investment intentions and signed agreements for the period add up to 22 743 MW of new capacity, of which 21 263 MW is renewable. The investment intentions for new renewable plants submitted to ESO exceed existing conventional generating capacity threefold.

The operator says something else too. In most cases investor interest does not coincide geographically with free grid capacity, and ESO cannot build new lines and substations at the pace at which renewables are being built.

This is the scarcity the thesis rests on. The existing park already has a connection point that works. Whether there is headroom behind it is a question for the specific site, and it is answered with measured data.

The procedure is lighter when connected capacity does not increase

A PV park is a generating facility, so it falls under Chapter Three of Ordinance No 6 of 28.03.2024 on the connection of facilities to the electricity grids, State Gazette No 28 of 02.04.2024, amended in No 84 of 04.10.2024 and No 35 of 14.04.2026.

What decides it is whether the connected capacity increases.

Without an increase. The amendment of 14.04.2026 introduced Art. 49b. When a non-standalone storage facility is added to an existing generating facility, and it will draw energy from the grid and so change the agreed terms of access and transmission without changing the connected capacity, no connection study request is filed. A written notification with the technical characteristics is filed instead, and the operator provides an annex to the access and transmission contract within 14 days.

Under Art. 59(12), when renewable generation and/or storage facilities are added to a facility with a signed connection agreement, without increasing the connected capacity, an annex to the connection agreement is signed. No guarantee under Art. 29(1) of the Energy from Renewable Sources Act is required, and the operator must sign the annex within 30 days.

With an increase. For the battery, a request is filed under Art. 49(1)(6). The operator issues its opinion within 40 days if it is a distribution company and within 60 days if it is ESO (Art. 56(1)(3)). Within three months of the opinion, the applicant provides a guarantee under Art. 57a(1) of 25 564.59 EUR per MW of increased connected capacity. Without the guarantee, the opinion is deemed invalid.

The counterparty is determined under Art. 50(1). It is ESO for a total installed generating capacity above 10 MW, and the local distribution company for 10 MW and below.

Metering. Under Art. 4(1), the added facility becomes part of the existing facility, with no separate connection facilities and no additional commercial meter, unless another regulatory or administrative act requires separate metering. Under Art. 4(2), however, a facility that only takes energy from the grid, only feeds energy into it and does not exchange energy with the existing facility is connected as a standalone facility, with separate metering. The connection scheme determines the regime.

Before filling in an operator's form, check which edition of the ordinance it refers to.

Why a battery, and where the benefit ends

A battery shifts existing production in time and captures energy that would otherwise be curtailed.

The connection point is most heavily loaded during the solar peak, around midday on clear days. Outside those hours there is free capacity into which the battery can export. How much, at the specific connection point and in which hours, only measurements can show.

The real limit lies elsewhere. The benefit depends on two measurable parameters: how much energy is actually lost to curtailment, and how wide the daily spread is at the specific site. If the park is hardly curtailed and the spread is narrow, the battery does not pay for itself, even though everything is technically possible.

Where the battery charges from also matters.

Charging only from the PV park does not require drawing from the grid. The battery absorbs the midday surplus and sells it in the evening, within the same connected capacity. It does not increase the park's production, so it does not move the NSP threshold either. It only moves the hour in which the energy is sold.

Charging from the grid opens up arbitrage as well, but it changes the agreed terms of access and goes through Art. 49b. For a park with an active ESSF contract it also raises a legal question. Grid energy and own production pass through the same commercial meter. How the energy eligible for the premium is separated has to be settled before the project goes ahead.

The revenue of a battery attached to a ground-mounted park breaks down by source:

sale of energy that would otherwise be curtailed;
shifting sales from midday to evening hours on the day-ahead and intraday markets;
lower imbalance costs;
subject to prequalification, the balancing market and reserves (FCR, aFRR, mFRR).

Each source carries its own assumption on cycles and availability. The result is given as a range with scenarios, never as a single number.

Wind is the harder case

Wind adds new generating capacity to the same connection point. In the hours when wind and sun produce at the same time, the sum can exceed the connected capacity.

The ordinance already addresses this case. Art. 49(1)(5) expressly covers a change in the type and technology of generating capacity, including where the existing facility will combine different types of generating capacity. Art. 59(12), for its part, offers a route for additional renewable capacity without increasing the connected capacity. Which of the two routes applies to a specific configuration has to be clarified with the operator before design. Under Art. 58(7), a preliminary connection agreement is valid for 2 years, and for wind facilities 3 years.

There is another route. An export limitation in which the combined output never exceeds the connected capacity, and the surplus goes into the battery or is curtailed. The cost is curtailed energy, and that volume is calculated.

The profiles complement each other only in part. Wind produces more in winter and runs at night, when the solar profile is weak or zero. But they do coincide at times, and those coincidences are exactly what creates the overrun. How far the profiles complement each other at a specific site is established from local data covering at least one year.

And wind brings things a battery does not. A wind turbine requires a detailed development plan, an environmental assessment under the Environmental Protection Act and the Biodiversity Act where applicable, and a building permit. It requires land rights for an entirely different type of construction, setback distances and a check of shading on the PV field. That is why wind keeps much less of the time advantage that a battery has.

When wind is added, the type of power generating module under Regulation (EU) 2016/631 is also checked. A change in combined capacity can move the facility into a higher type. For an existing module, the regulation applies upon substantial modernisation, by decision of the operator and the regulator, and the requirements may then extend to the existing PV part as well.

When it does not work

No headroom in the critical hours. If free capacity and curtailed energy are small, the configuration has nothing to stand on.

Existing equipment. The transformer station and cables are checked against load cycles; nameplate rating is not enough. A solar profile loads the transformer in a narrow window around midday, with night-time pauses for cooling. A battery cycling several times a day keeps it loaded longer, and in hours when it used to rest. Power quality and harmonics, the operator's reactive power requirements at the connection point, and the currents in cables and switchgear are checked as well.

The term of the land rights. A lease or building right that expires before the end of the battery's economic life stops the project at the financing stage.

The condition of the existing plant. With the connection point, the hidden defects of the facility are inherited too.

The active ESSF contract. The consequences of a configuration change for the premium contract are clarified legally before the project goes ahead.

Recommendation

The owner of a depreciated ground-mounted PV park in Bulgaria starts with measurement. Configuration comes after it.

First, one full year of measured data on the loading of the connection point, on curtailed energy and on the achieved price by hour.

Second, a legal review of the term and scope of the land rights and of the consequences of a configuration change for the ESSF contract.

Third, a configuration that stays within the connected capacity. A battery within the available capacity is the shortest route to a result. Wind is assessed as a second step, once the battery has shown that the site is worth it.

Greenfield will not disappear. But between a new project that still has to fight for a connection point and an old park that already holds one, the second starts from a better position, provided the headroom behind its connection point is real.

Sources

This text is analytical. It is not legal, investment or engineering advice. Legislation is cited as in force on 02.10.2026, and data are as of the dates of the sources given. Any technical decision is subject to review and signature by a designer holding a design licence under the Bulgarian Chambers of Architects and Engineers in Investment Design Act.

Elevat Solar Consulting · Independent technical advisor for solar and BESS projects · elevatsolar.eu
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