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BETTESWORTHConstruction
due diligence

How to Compare Utility-Scale Solar Developers by Project Pipeline, Costs, and Returns

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The most reliable comparison of utility-scale solar developers is not a ranking by headline megawatts or a single return percentage. Build a project-level, date-stamped comparison that weights pipeline maturity and control, normalizes cost scope and AC/DC capacity, and separates project economics from equity returns. Then test every project’s offtake, grid position, permitting, financing and construction record against local conditions.

Start with a project-level comparison, not a corporate headline

A developer’s reported pipeline can combine operating plants, projects under construction, contracted projects, speculative early-stage sites, gross capacity shared with partners and storage paired with solar. Those categories have very different probabilities of reaching commercial operation. A 10-GW pipeline made mostly of early-stage, uncontrolled sites may be less valuable than a 2-GW portfolio with land, interconnection, permits, offtake and financing substantially secured.

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Set a snapshot date and require every developer to report capacity on the same basis. Record whether megawatts are gross project capacity or the developer’s net ownership, whether the figure is AC or DC, and whether battery capacity is included. Keep PV-only and PV-plus-storage projects separate. Do not compare a 2026 pipeline with another company’s 2024 snapshot without labeling the dates.

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Classify pipeline megawatts by maturity and control

Ask for capacity in five buckets. The labels below are a practical starting point, not a universal industry standard; each company can define them differently.

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Operating

Operating projects have reached commercial operation. They provide the strongest evidence of execution, realized output, operating cost and cash generation. Request commercial-operation dates, actual generation, availability, curtailment, ownership percentage and whether the plant was retained or sold.

Under construction

These projects have begun physical construction. Check notice-to-proceed date, major equipment delivery, the engineering, procurement and construction (EPC) contract, remaining contingency, expected completion date and the amount of construction debt or equity funded. A project can still face delay, cost escalation or interconnection work after construction starts.

Contracted or backlog

Backlog generally means a late-stage project expected to start construction within a stated period after passing a defined risk milestone. In a 2025 Canadian Solar SEC filing, backlog is described as late-stage work expected to begin construction within a stated horizon after a perceived risk-cliff milestone. Treat that as an example of a company-specific definition, not a standard definition. Confirm the milestone, expected start window, offtake contract and remaining conditions.

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Advanced development

Advanced projects may have secured interconnection or a high stated probability of securing it. Ask for the executed queue position or interconnection agreement, study results, upgrade scope, land rights, permits, environmental review, offtake status and financing plan. “High probability” is a management assessment unless supported by executed documents.

Early development

Early-stage projects may be controlled sites still pursuing interconnection rights. A site-control agreement alone does not establish a buildable project. Determine whether the developer owns, leases or has an option on the land, how long the option lasts, and what happens if interconnection or permitting fails.

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The same SEC filing warns that pipeline development is uncertain and projects may not be completed on schedule or deliver expected benefits. Consequently, calculate stage conversion, cancellations and schedule slippage over time rather than treating total gross MW as a forecast of operating capacity.

Measure pipeline quality with a repeatable scorecard

For each project, capture evidence rather than a marketing label. A useful worksheet includes the following fields:

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Field What to record Why it changes the comparison
Developer and project Legal entity, project name, partners and ownership percentage Prevents double counting and distinguishes gross from attributable capacity.
Region and market State, balancing authority, ISO/RTO and node or zone where available Prices, congestion, curtailment and permitting are local.
Capacity basis MWAC, MWDC, PV-only or PV plus storage; gross and net MW AC/DC ratios and battery duration can make nominal MW incomparable.
Stage and definition Operating, construction, backlog, advanced or early; company’s written definition Stage names have no consistent industry meaning.
Land control Owned, leased, optioned or merely identified; term and termination rights Weak site control can eliminate an apparently large pipeline.
Interconnection Queue position, executed agreement, study status, upgrade scope and cost Grid availability is often the critical schedule and capital risk.
Permits and environment Zoning, conditional-use, state and federal permits, wildlife and cultural reviews Unresolved approvals can delay or prevent construction.
Offtake PPA or other contract, tenor, price structure, buyer credit and merchant share Revenue certainty and market exposure differ sharply by project.
Schedule Expected construction start and commercial-operation date, with update history Repeated slips reveal execution risk and affect financing.
Financing readiness Tax equity or transferable-credit plan, debt commitments and construction funding A technically ready project may still lack investable capital.
Evidence date Date of each disclosure, study, contract and model Queue, equipment, prices and policies change quickly.

Use the same definitions for every company and preserve the underlying documents. Report conversion ratios such as early-stage-to-advanced, advanced-to-construction and construction-to-operation only when the cohorts and dates are comparable. Explain whether a project was sold, canceled, delayed or transferred to a partner rather than silently removing it.

Normalize costs before comparing developers

“Cost per watt” is meaningful only when the numerator and denominator describe the same thing. Normalize currency year, geography, project size, tracker or fixed-tilt configuration, module technology, AC/DC basis, storage duration and cost boundary.

Define the cost boundary

Separate at least these categories:

  • Installed system cost: equipment, construction and owner costs included in the stated benchmark or contract.
  • Development cost: site control, studies, permitting, interconnection work, legal work and development overhead.
  • EPC cost: the scope covered by the engineering, procurement and construction contract, including exclusions and allowances.
  • Grid and transmission cost: network upgrades, collector systems, substation work and transmission access.
  • Land and permitting cost: leases, easements, fees, mitigation and community commitments.
  • Financing during construction: interest, fees, hedging and capitalized financing costs.
  • Operating cost: fixed and variable operations and maintenance, insurance, property taxes, land rent and replacement reserves.
  • Storage capital: battery, power-conversion equipment, augmentation, fire protection and controls, shown separately from PV.

Ask whether taxes, owner’s costs, financing, contingency and grid upgrades are included. An EPC price that excludes interconnection and financing cannot be compared with a fully loaded installed cost.

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Use benchmarks as reference cases, not developer results

The U.S. Department of Energy and the National Renewable Energy Laboratory (NREL) publish representative PV-system cost benchmarks and techno-economic tools. They are modeled reference systems, not bids and not proof of a company’s realized cost. Match system size, mounting type, location, equipment assumptions and year before using a benchmark as a reasonableness check.

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Lawrence Berkeley National Laboratory’s Energy I-SPARK development description identifies site selection, landowner negotiations, permitting, grid connection, financing, EPC arrangement and offtake identification as parts of the development chain. That analysis cites an NREL estimate of development and EPC equal to roughly 4%–5% of total cost, varying by project size and mounting type. It is a historical reference from the cited analysis, not a current universal rule.

Use dated U.S. market figures only for context

The following figures come from Lawrence Berkeley National Laboratory’s 2024 edition of its Utility-Scale Solar report and largely describe U.S. projects completed in 2023. They are not company-specific forecasts.

Measure Reported value Scope and qualification
Capacity-weighted installed cost $1.43/WAC or $1.08/WDC 76 plants totaling 7.1 GWAC, projects completed in 2023.
Long-run cost decline 75% since 2010, about 10% annually on average Utility-scale plant-cost comparison in the 2024 report.
Median capacity factor 24% Reported plant-level sample range of 6%–36%.
Pre-incentive LCOE $46/MWh New projects in 2023, U.S. market context.
After-federal-incentive LCOE $31/MWh New projects in 2023; incentive treatment is part of the modeled result.
Newly signed long-term PPA price $35/MWh Average levelized in 2023 dollars.
Energy and capacity value $45/MWh average; $27/MWh in CAISO and $67/MWh in ERCOT U.S. 2023 values; regional averages, not a project bid.

Do not apply any of these numbers to a particular developer without matching its project vintage, location, technology, contract structure and incentive treatment.

Keep LCOE, market value and equity returns separate

LCOE answers a lifecycle cost question

Levelized cost of energy (LCOE) expresses lifecycle cost per unit of delivered energy. It can compare alternatives when calculation boundaries and assumptions match. NREL’s LCOE documentation cautions against comparing a real LCOE for one alternative with a nominal LCOE for another.

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For a fair comparison, align discount rate, inflation and currency basis, operating lifetime, expected output, degradation, operating costs, replacement assumptions, debt treatment, taxes and incentives. State whether output is AC energy delivered at the busbar or energy after storage losses. LCOE is not the project’s PPA price, market value, corporate profit or sponsor equity return.

Project returns describe the asset

Project IRR usually reflects the project’s cash flows before the sponsor’s ownership-level financing decisions. It is sensitive to capital cost, operating output, PPA or merchant revenue, taxes, incentives, debt and terminal value. Confirm the exact definition, hold period and whether the figure is modeled or realized.

Equity returns describe the investor’s capital structure

Equity IRR, return on invested capital and a realized sale gain can produce very different answers for the same plant. Normalize ownership share, leverage, interest rate, debt-service coverage ratio, construction financing, tax equity or transferable credits, distributions, sale assumptions and pre-tax versus after-tax treatment.

NREL’s 2025 Annual Technology Baseline presents modeled utility PV and PV-plus-battery cases that specify PPA sales, after-tax equity return, term-debt interest, debt-service coverage ratio, construction-equity return, construction-debt interest and leverage. These are benchmark modeling assumptions, not observed returns for any developer. Request the developer’s model inputs and reconcile them line by line before comparing percentages.

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Test revenue, siting and execution risk

Revenue and offtake

Record whether energy is sold under a long-term PPA, a hedge, a utility contract, a community arrangement or merchant exposure. Capture contract tenor, escalation, settlement point, congestion treatment, renewable-energy-credit ownership, curtailment compensation, credit support and termination rights. A high nominal PPA price may carry greater basis or curtailment risk than a lower price at a stronger node.

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Market value and congestion

Compare the project’s expected energy and capacity value with its contracted revenue and downside cases. Model transmission constraints, basis risk, negative pricing, curtailment and ancillary-service assumptions where storage is included. National averages cannot reveal a project’s nodal economics.

Site and community constraints

DOE siting research identifies land availability, interconnection cost, transmission access, topography, zoning, environmental impacts, host-community priorities and the power customer as relevant considerations. Review wildlife, wetlands, cultural resources, agriculture, water, visual impacts and local tax or community-benefit commitments. These factors affect schedule and cost as well as the probability of obtaining a permit.

Execution record

For operating and completed projects, compare original and actual commercial-operation dates, original and final cost, achieved capacity factor, availability, curtailment, change orders and warranty claims. For projects still in development, compare forecast dates with the developer’s historical slippage. A developer that repeatedly resets a pipeline may be reporting activity rather than durable progress.

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A step-by-step diligence process

  1. Set the comparison scope. Choose the geography, cutoff date, project vintage, PV-only or PV-plus-storage scope, AC or DC basis, ownership basis and currency year.
  2. Collect primary disclosures. Obtain filings, project lists, interconnection documents, permits, offtake summaries, financing announcements and operating data. Archive each document with its date.
  3. Rebuild the pipeline. Assign every project to an operating, construction, backlog, advanced or early-stage bucket using the developer’s written definition. Remove duplicate projects and show gross and net MW separately.
  4. Verify control. Check land rights, queue position, transmission access, permits, environmental review, offtake and financing readiness. Mark each item confirmed, pending or unsupported.
  5. Normalize costs. Convert currency years, reconcile AC/DC capacity, separate PV and storage, and map each disclosed amount to installed, development, EPC, grid, financing or operating cost.
  6. Rebuild the revenue case. Enter PPA terms, merchant exposure, curtailment, congestion, degradation, storage dispatch and incentive assumptions. Keep nominal and real dollars distinct.
  7. Recalculate returns. Reproduce project and equity cash flows with the same leverage, taxes, debt terms, ownership and exit assumptions. Label modeled, target and realized results.
  8. Measure outcomes. Calculate stage conversion, cancellation, delay, cost-overrun and operating-performance statistics for comparable cohorts.
  9. Stress unresolved risks. Run downside cases for interconnection upgrades, permitting delay, module or battery pricing, interest rates, curtailment, basis, lower output and delayed tax-credit monetization.
  10. Write a decision memo. State which projects are investable now, which require milestones, and which pipeline claims remain unverified. Include the snapshot date and the evidence behind every material figure.

Common comparison errors and how to correct them

  • Ranking by gross pipeline MW: replace it with net, controlled MW by maturity and conversion history.
  • Treating stage labels as universal: quote each company’s definition and identify the milestone behind the label.
  • Mixing AC and DC watts: show both bases or convert transparently using the project’s stated design ratio.
  • Combining PV and batteries: report PV MW, battery MW and battery duration separately, with storage capex identified.
  • Comparing an EPC quote with total installed cost: list exclusions for owner’s costs, taxes, financing, contingency and grid upgrades.
  • Using national benchmarks as bids: use them as dated reasonableness checks, then substitute project-specific costs.
  • Calling LCOE a return: keep lifecycle cost, project cash yield and equity IRR in separate columns.
  • Ignoring financing structure: normalize leverage, interest, debt-service coverage, tax-credit monetization and ownership.
  • Assuming a signed PPA eliminates risk: examine settlement node, curtailment, congestion, escalation, credit and termination provisions.
  • Using stale forecasts: attach a date to every pipeline, cost and return figure and record subsequent revisions.

What a defensible conclusion looks like

A strong comparison can say, for example, that Developer A has fewer net megawatts but a larger share in construction and operation, while Developer B has more early-stage capacity with unresolved interconnection and permitting. It can show that one project’s lower $/W reflects a DC denominator and excludes transmission upgrades, while another’s higher figure is fully loaded. It can explain that a higher equity IRR results from greater leverage or a sale assumption rather than superior plant economics.

The conclusion should identify the projects and risks that remain, not award a winner based on one corporate metric. A developer is more credible when its stage definitions are transparent, site and grid control are documented, costs are comparable, revenue assumptions are supportable, and historical forecasts convert into operating assets.

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