Solar O&M vs Asset Management: Where the Boundary Should Be

It is tempting to buy O&M and asset management as one package, or to let the O&M contractor’s monthly report stand in for asset performance. That is where money leaks: the O&M contract is built to keep the plant available and maintained, while nobody is paid to ask whether the plant is earning what the business case promised. On the O&M vs asset management question, my position is simple: O&M is measured on response times, availability and preventive maintenance completed on time, while asset management is measured on financial performance and on how well it controls the O&M contractor. Because the two roles overlap, the boundary has to be written down rather than assumed.

O&M vs asset management: two jobs, two objectives

SolarPower Europe’s O&M Best Practice Guidelines, now in version 6.0, describe a professional O&M package as one that keeps a PV plant at a high level of technical and safety performance, and therefore economic performance, over its life ^[1]. Power plant operation covers monitoring and supervision, fault diagnosis, service dispatch, the grid operator interface, grid code compliance and maintenance scheduling. Power plant maintenance covers preventive, corrective and extraordinary work ^[1]. Asset management has had its own guidelines since 2020 ^[1].

Those Asset Management Best Practice Guidelines, version 2.0, draw the distinction in one sentence: “Asset Managers are responsible for the commercial and financial management of a solar investment and the supervision and control of technical activities” ^[2]. They add that asset managers manage a company or a portfolio rather than a power plant, and that each plant or special purpose vehicle (SPV) should be run as a stand-alone business, aiming to raise revenue and lower the levelized cost of electricity ^[2]. This matches ISO 55000, which frames asset management around realizing value from assets ^[3].

My position follows the same split. I judge O&M on KPIs such as response time, which keep the park up and reliable, and on whether preventive maintenance is completed on time. Asset management should focus on keeping the park financially performing: deciding how many times to clean the modules, planning ongoing capex to lift production on tracker and bifacial plants, choosing the best commercial terms and structuring electricity sales, and, while doing all of this, controlling the O&M contractor. Having worked across project development, EPC management and asset management, and with 170 MWp currently under asset management, I treat the boundary as a governance question first and a technical one second.

The two jobs meet at reliability. IEC TS 63019 gives the information model for classifying plant time and deriving availability ^[4], and IEC TS 63265 frames operational reliability around secure production and revenue and the cost of unreliability ^[5]. O&M delivers reliability. Asset management decides how much of it is worth paying for and checks that it was delivered.

Where the two overlap: technical asset management

SolarPower Europe is candid that the line is not sharp ^[2]. Its asset management guidelines describe a block of technical asset management (TAM) tasks, including technical reporting, warranty management, insurance claims, contract management, regulatory compliance and technical optimization, that either the O&M contractor or the asset manager can perform ^[2]. Large O&M contractors tend to take these on, and the O&M guidelines confirm that operations teams often do ^[1]. How the tasks are allocated is ultimately a matter of the owner’s operational risk policy and corporate governance ^[2].

The overlap has a cost. It can duplicate workload and analysis, particularly when performance analysis extends into root cause analysis and the resulting warranty or insurance claims ^[2]. The opposite failure is just as expensive: when several contracts together cover a plant’s O&M, the owner has to define each party’s obligations precisely to avoid gaps in risk allocation ^[1].

The guidelines therefore treat a division of responsibility (DOR) matrix, built from a full analysis of the contracts, as a minimum requirement, and say the asset manager should be able to assess a site’s technical health on its own, whoever performs the TAM tasks ^[2]. I would go one step further: agree the DOR matrix before the O&M tender, because it defines what the O&M fee is supposed to buy.

What the O&M contract guarantees, and what it leaves to the owner

The best-practice O&M contract is a fixed fee plus escalation for a defined scope, with extraordinary maintenance and many additional services priced separately under pre-agreed rates ^[1]. Its performance protection rests on two mechanisms ^[1]:

• An availability guarantee. Contractual availability is technical availability with agreed exclusion factors removed, calculated at inverter level over a year. The guidelines put the best-practice minimum guarantee at 98% to 99% or more ^[1]. Outperformance can be shared through a bonus scheme, and shortfalls are compensated through liquidated damages (LDs) equal to the revenue lost against the base case ^[1].
• Response time price adjustments. Response time runs from the alarm until a technician is on site and is guaranteed by fault class. In the guidelines’ example, a full plant outage requires a response within 4 daytime hours, a loss of more than 30% or more than 300 kWp within 24 hours, and smaller losses within 36 hours ^[1]. Resolution time is generally not guaranteed, because repairs often depend on factors outside the contractor’s control ^[1].

What the contract does not cover matters just as much. The standard exclusion list includes force majeure, snow and ice, grid operator disconnections and power regulation, output reductions ordered by the owner, inverter and medium-voltage failures that need manufacturer support or parts, serial defects and delays in owner approvals ^[1]. Annual LDs should be capped at 100% of the annual O&M fee ^[1]. Performance ratio (PR) guarantees are no longer standard in the third-party market, because PR depends largely on equipment choice, design and construction, over which an independent O&M provider has little influence beyond vegetation control and module cleaning ^[1].

The asset management contract does not close this gap either. SolarPower Europe recommends a fixed annual fee, notes that asset management agreements generally carry no contractual guarantees, and describes a liability cap usually equal to the annual fee ^[2]. It also cautions against buying strategic services such as O&M on price alone ^[2].

This is the core of my argument. A plant can meet a 99% availability guarantee and still miss its budget through curtailment, negative prices, soiling, degradation, design defects or a slow warranty claim, and none of those losses is anyone’s contractual liability except the owner’s. An O&M contract buys availability and response, not revenue protection. Managing the rest is the asset manager’s job.

Asset management levers that O&M KPIs never show

SolarPower Europe’s asset management guidelines cover both technical and financial optimization ^[2]. Four levers matter most for the boundary question.

Cleaning and vegetation: the frequency is a price decision

Module cleaning is generally included in the O&M scope or offered as a priced option ^[1]. Executing it is O&M work; deciding how often is not. IEA PVPS Task 13 describes economic models for finding the cleaning schedule that minimizes revenue loss, and notes that lower electricity prices make cleaning less attractive because the recovered energy earns less ^[6]. The asset management guidelines list optimizing the timing of grass cutting and module cleaning among the interventions an asset manager should identify from monitoring data ^[2]. The right frequency moves with soiling rate and market price, so it belongs with the party that sees both. I work through the cleaning numbers in a separate article on module cleaning cost-benefit analysis.

Ongoing capex on tracker and bifacial plants

On single-axis tracker plants with bifacial modules, production depends on factors that no O&M KPI measures. An NREL-led team reports that bifacial modules on single-axis trackers add 4% to 15% to energy yield depending on module type and ground albedo, and their simulations suggest that smart tracking algorithms adjusting tilt under cloudy conditions can add more than 1% to annual yield ^[7]. That figure is modeled, not measured, so any tracker control upgrade needs a site-specific case. Tracker software updates, ground management for albedo and inverter or module revamping are investment decisions, and SolarPower Europe treats revamping and repowering as a commercial and financial re-investment case built on actual versus budgeted performance ^[2]. An availability guarantee is indifferent to all of them, so if nobody owns the business case, the upgrade never happens.

Route to market, balancing and curtailment in Hungary

This is where the boundary matters most in Central Europe. Under Hungary’s METÁR premium scheme, plants sell their electricity on the market themselves. The premium is the difference between the supported price and a reference market price, and if that difference turns negative, the producer pays it back ^[8]. The regulator described the scheme in 2019 as one in which the producer bears balancing costs, chooses its balancing group and agrees deviation penalties bilaterally with the balance responsible party ^[9]. Under MAVIR’s current premium contract template, no premium is paid for production during runs of at least six consecutive negative day-ahead settlement periods ^[10]. Older KÁT feed-in plants submit daily schedules, carry full balancing responsibility for their deviations, and have their scheduled output sold by MAVIR on the HUPX day-ahead market ^[8].

Negative prices are no longer rare. ACER data show that the Hungarian day-ahead price was negative 3.0% of the time in 2024, on 57 separate days ^[11]. That turns several questions into commercial decisions: whether to curtail, which trader or balancing group to use, how to forecast, and whether a power purchase agreement (PPA) should be fixed or variable price. The asset management guidelines give PPA tendering to the asset manager, assessing both price and coverage of imbalance costs and matching the fixed or variable choice to the investor’s risk appetite ^[2]. They also warn that corporate PPAs with minimum production obligations shift risk toward the owner and demand stricter response times from maintenance providers ^[2].

The O&M side of this boundary is execution: applying setpoints, acting as the grid operator’s first contact and planning outages for low-irradiance hours ^[1]. Owner-ordered output reduction is a standard exclusion from contractual availability ^[1], so commercial curtailment should be logged separately, never counted against the O&M contractor and never used to hide its downtime.

Warranty, insurance and penalties

The technical asset manager monitors the EPC performance warranty, typically two years after commercial operation, and presents equipment claims to suppliers, while the commercial and financial asset manager usually coordinates insurance claims with insurers, brokers and loss adjusters ^[2]. Where the O&M contract carries penalties, the asset manager calculates and invoices them ^[2]. An O&M contractor cannot be expected to invoice itself.

Conflicts of interest when one company does both

Integrated O&M and asset management can be efficient, and owners who run asset management in-house can avoid some duplicated analysis ^[2]. The risk is self-assessment. The O&M provider or technical asset manager usually calculates the KPIs, and SolarPower Europe advises that where warranties are in place, the liable party should not be the only one calculating them ^[1]. In a Delphi study with industry specialists, Rediske and colleagues found contractual availability to be the most complex O&M indicator to measure ^[12]. A complex, self-reported KPI that also sets LDs invites dispute. The O&M guidelines add that PR warranties are mostly given where the O&M and EPC contractors belong to the same group, so the O&M side carries its sister company’s technology risk ^[1].

The safeguards follow from the guidelines:

• Keep the owner’s direct access to raw monitoring data and recalculate KPIs from it, using IEC 61724-1 monitoring terminology and methods and the IEC TS 63019 time categories, rather than accepting a finished number ^{[4, 13]}.
• Hold periodic joint site visits with the O&M contractor and commission independent inspections such as aerial thermography, which the guidelines describe as a fast, low-cost check on O&M performance and asset health ^[2]. Drone inspection practice is covered in a separate article on AI thermal inspection and spot cleaning, so I only flag it here.
• Set authority limits for the asset manager on contract values and litigation, and require it to report its own contract compliance ^[2].
• My own addition: if one group provides both services, ring-fence the teams and give the owner, or the lender’s technical advisor, a contractual right to audit the availability calculation and its exclusions.

My position has limits. The split does not mean the O&M contractor has no influence on revenue. Vegetation control and cleaning quality affect PR ^[1], downtime in sunny hours costs more than downtime at dawn, which is why energy-based availability exists ^[1], and on a small portfolio a single provider may be the only economic option. The test is not who does the work, but whether each task has one owner and an independent check.

A practical boundary table

The table below is my synthesis of the SolarPower Europe O&M and asset management guidelines ^{[1, 2]}, adapted to a merchant or METÁR plant. “Lead” means responsible for doing and answering for the task.

O&M contractor KPIs (contractual, reported monthly)

• Contractual availability at inverter level, annual, with agreed exclusions; guarantee of 98% to 99% or more ^[1]
• Energy-based availability, so downtime in high-irradiance hours weighs more ^[1]
• Acknowledgement, intervention and response time per fault class ^[1]
• Schedule attainment for preventive maintenance, best practice above 90% ^[1]
• Preventive to corrective maintenance ratio by technician hours, best practice 80/20 ^[1]
• Reports delivered on time and complete ^[1]

Asset manager KPIs (reported to the owner)

• PR, temperature-corrected PR and energy performance index against budget, with losses attributed to downtime, curtailment, soiling and degradation ^{[1, 2]}
• Revenue against budget, verified against meter readings and offtaker invoices ^[2]
• OPEX against budget and contracts optimization rate ^[2]
• Reports compliance, invoicing compliance and timely response rates ^[2]
• O&M contractor compliance with its contractual obligations ^[2]
• My own additions for merchant and METÁR plants: imbalance cost per MWh, and energy produced during negative-price periods

Conclusion

The O&M contractor should be judged on what it controls: availability, response and maintenance done on time. The asset manager should be judged on what the owner actually needs: revenue, cost, risk and a contractor that delivers. Most of the money lost in this area is lost in the gap between the two roles, through curtailment counted the wrong way, cleaning done to a calendar instead of a price signal, upgrades nobody models and claims nobody files. Write the boundary into a DOR matrix before the O&M tender, keep KPI calculation independent, and make one party accountable for every euro of revenue risk that the O&M contract excludes.