Regulatory resource: Who will be required to actively participate in the balancing market?

If you own a power generating module above 10 MW (wind, PV, gas, biomass, CHP), a battery storage system, or a smaller module or storage facility that has ever benefited from any support under the Polish RES Act, you are about to become a “regulatory resource.”

That is a new legal category invented by the draft new electricity system regulation (version dated 22 May 2026). It comes with mandatory active participation in the Balancing Market, appointment of a Balancing Service Provider, mandatory prequalification, and dispatch instructions from the Transmission System Operator (TSO). Miss the deadline and your ability to feed energy into the grid on commercial terms is at risk.

This article walks you through what “regulatory resource” means in practice, who falls in, who can escape, and how to prepare.

Today: an obligation limited to CDGUs

Under the current electricity system regulation of 2023, only owners of Centrally Dispatched Generating Units (“CDGUs”) must actively participate in the Balancing Market. CDGUs are essentially the large conventional units connected to the transmission grid, thermal condensing units above 100 MW connected to the coordinated 110 kV grid, and pumped-storage plants. Every CDGU must have a designated Balancing Service Provider (“BSP”) that submits balancing energy bids, reports schedules, and is subject to TSO dispatch.

Every other resource – onshore wind farms, photovoltaic installations, battery storage, gas-fired distributed generation, industrial CHP – can voluntarily participate in the Balancing Market but is not required to. In practice, this means a vast and growing share of installed capacity in the Polish power system currently sits outside active balancing mechanisms.

Tomorrow: the “regulatory resource” definition

The draft new electricity system regulation introduces a broader concept. A regulatory resource is a resource that is:

(a) a Centrally Dispatched Generating Unit (CDGU) – as before;

(b) a Centrally Coordinated Generating Unit (CCGU);

(c) a power generating module ≥ 10 MW, other than a CDGU or CCGU (e.g. wind farm, PV installation, biomass plant, gas peaker);

(d) an energy storage facility with storage and grid-injection capacity ≥ 10 MW;

(e) a power generating module 0.2–10 MW that has ever benefited from a support scheme under Article 69a of the RES Act – even if the support has since ended;

(f) an energy storage facility 0.2–10 MW that has ever benefited from an Article 69a support scheme – even if the support has since ended.

A hidden trap in categories (e) and (f). The reference to Article 69a of the RES Act is deceptively simple. Article 69a is not a single mechanism – it captures multiple RES support regimes: green certificates, feed-in tariffs and premiums, the auction system, operational auction support, prosumer net-billing, and energy cooperative settlements. Any power generating module or storage facility between 0.2 MW and 10 MW that has ever benefited from any of these mechanisms (including support received years ago under long-since-expired certificate schemes) falls within the regulatory resource definition. There is no time-limitation carve-out.

One important note: cogeneration support and offshore wind support are governed by their own separate acts (not by the RES Act) and are NOT part of Article 69a. A small CHP unit or offshore installation that relies solely on those regimes therefore does not trigger category (e) or (f) (although any generation ≥ 10 MW remains caught by category (c) or (d) regardless of its support scheme). Owners of legacy RES portfolios need to audit their support-scheme history carefully before assuming they are outside the new obligation.

The core obligation: appoint a BSP

The owner of a regulatory resource must designate, in the transmission or distribution services agreement, a Balancing Service Provider that carries out the obligations of active participation in the Balancing Market.

The BSP:

→ uses and disposes of the resource for balancing purposes;

→ submits work schedules and integrated scheduling process bids;

→ is a party to settlements with the TSO for balancing services provided, undelivered balancing capacity, and operating reserves.

The owner may either act as its own BSP, or empower (outsource) another entity  (typically a specialised trading house) to perform the role.

The CDGU “double qualification” trap

Here is a nuance most CDGU may overlook, and which could extend to all regulatory resources under the new regime. Under the current Balancing Terms and Conditions (TCM/WDB) issued by the TSO, the owner of a CDGU must obtain BSP qualification for the scheduling unit built from that CDGU regardless of whether it also empowers an external BSP. The reason is a “safeguard” mechanism: if the empowered BSP ceases activity for any reason, the scheduling unit is automatically reassigned to the CDGU owner as BSP, without any need for contractual amendments. That handover only functions if the owner is already qualified.

The compliance investment for a CDGU is therefore always double: the owner’s own BSP qualification, plus (optionally) contracting with an external BSP.

Whether this same double-qualification model will be extended to the newly captured categories (power generating modules and storage across RES, gas, biomass, CHP) is the single most important open question for compliance planning. The answer will be found in the new TCM the TSO must submit to the President of the Energy Regulatory Office (URE) within 4 months of the new regulation’s entry into force. Until we see that document, prudent owners of large RES and storage assets should assume double qualification will apply and price it in.

Exemption is possible – two paths

The draft electricity system regulation provides two exemption routes.

Path 1 – CDGUs (§ 15(1)): the TSO may, on application, change the module’s status to CCGU or fully exempt the owner from the BSP designation obligation.

Path 2 – other regulatory resources (§ 15(2)) – NEW: this is a new route available to categories (c) through (f). The TSO may exempt the owner from the BSP obligation, taking into account:

→ technological conditions of the asset’s operation;

→ commissioning date, technical condition and the investment cost of compliance;

→ significance of the asset for system security and system balancing.

Two aspects deserve particular attention. First, for resources connected to the distribution grid (which will be the case for almost all RES and storage in categories (c) to (f)) the DSO must cooperate with the TSO in verifying data submitted with the exemption application. This gives the DSO a substantive voice in the outcome. Applicants should therefore engage both operators early. Second, if the TSO refuses the exemption, it must provide reasons and notify the President of URE. The regulation does not spell out an explicit appeal path, but the mandatory URE notification effectively opens a channel for regulatory oversight and, if the refusal appears arbitrary, a dispute-resolution route before the President of URE.

Applications may be filed as early as when the applicant submits its application for grid connection conditions to the operator – and no later than the end of the 24-month adaptation window that starts when the amended TCM enters into force. Early filers benefit from a less crowded queue at the TSO.

When does the clock start ticking?

The obligation does not take effect when the regulation enters into force (expected 7 September 2026). It is introduced in stages:

1. Regulation enters into force: (per current draft version) 7 September 2026.
2. TSO submits amended TCM to URE: within 4 months of entry into force.
3. URE approves the amended TCM: uncertain duration.
4. 24-month adaptation window: starts from TCM approval.

Realistically, the earliest date on which existing power generating modules and storage facilities will need their BSP arrangement in place is around Q1–Q2 2029. This is not a reason to delay planning, as  BSP qualification, IT integration (LFC, SOWE, WIRE) and empowerment contracting typically consume 12–18 months of lead time.

A concrete example

Consider a Polish operator of a 50 MW onshore wind farm that won an support in the 2020 auction. Under the current regime, the farm participates passively: energy is scheduled through a Balance Responsible Party, the TSO does not dispatch the asset via the Balancing Market (non-market redispatching by the TSO is a separate mechanism). Under the new regime, the farm falls squarely within category (c). Within roughly 30 months of the regulation’s entry into force, the operator must either build in-house BSP capability (qualification, systems, personnel, procedures) or contract with an external BSP under an empowerment/outsourcing arrangement. If neither is done, its ability to feed energy into the grid on commercial terms is at risk. Alternatively, the operator may apply for an exemption under § 15(2) (filings can be made as early as the grid connection application stage) citing the specific technological, economic and system-security factors.

The cost dimension

Beyond the legal exposure, the transition also has significant cost implications that owners of newly captured regulatory resources should model early. The fixed compliance investment typically includes BSP qualification (which the TSO conducts based on documented technical parameters, tests and IT integration checks), the IT infrastructure required for real-time data exchange with the TSO’s dispatch systems (LFC, SOWE, WIRE), and the internal procedures and personnel needed to submit schedules, integrated scheduling process bids and to respond to dispatch instructions. For a mid-size asset in the 10–50 MW range, this can materially affect its operating economics.

On top of the fixed investment, recurring costs run either as the internal cost of operating a BSP function (systems, personnel, ongoing certification maintenance) or, if the BSP role is outsourced, as a fee paid to the empowered BSP. Empowerment fees are typically structured against volumes traded or capacity made available, and negotiated bilaterally.

This is where the market dynamic becomes relevant. Poland today has a limited number of specialised BSPs, sized for the current CDGU-only market. If hundreds of new regulatory resources come online in 2027–2029 all looking for a BSP, empowerment fees are likely to rise, potentially, significantly. Contracting early, well before the demand-side surge hits, may lock in materially better economics than contracting once the deadline is close.

Finally, the cost burden associated with the new regime interacts with the legacy support contracts that many affected assets rely on. Long-term auction contracts, cogeneration support arrangements and offshore support agreements were negotiated in an era when none of this compliance burden was contemplated. Whether these contracts contain change-of-law clauses that pass the burden through, or whether the burden remains with the asset owner, is a question worth resolving before the numbers get finalised.

Strategic checklist for asset owners and investors

Before your operational team becomes fully occupied with the transition, the following should be verified, and we are happy to help:

1. Support-scheme audit. Has this asset ever benefited from any Article 69a RES Act mechanism? Even a legacy green certificate, a past prosumer settlement, or membership in an energy cooperative can trigger category (e).
2. BSP structuring. Own BSP or outsourced (empowered) BSP? What contractual protections should the outsourcing agreement contain?
3. Exemption strategy. Are there specific factors supporting a § 15(2) application? When should the application be filed?
4. Existing support. Does your CfD contemplate the added compliance burden?
5. BSP market capacity. With hundreds of new regulatory resources coming under the obligation, will empowerment fees escalate?

 

This article is based on the draft new electricity system regulation version dated 22 May 2026, the current electricity system regulation of 2023, the Polish Energy Law, the Renewable Energy Sources Act, the current Balancing Terms and Conditions of the Polish TSO, and the explanatory memorandum to the draft.